United States Office of Water Environmental Protection Washington, DC 20460 September 2015 Agency



# Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category: EPA’s Response to Public Comments

Part 6 of 10Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 1 11. FGD Vapor
- Compression Evaporation System
Commenter Name: Paul Ling Commenter Affiliation: Kansas City Power & Light Company Document Control Number: EPA

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- A2 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: While EPA has not designated a proposed FGD wastewater limit based on thermal Zero Liquid Dis charge (ZLD) systems as a preferred option, the Agency has included this technology as the basis for its option 5. This technology basis and resulting limitations are not justified. ZLD systems are not demonstrated or technologically available for FGD was tewater. KCP&L agrees with EPA that Option 5 Chemical precipitation/co

- precipitation with ZLD should not be a preferred option. Based on KCP&L’s experience, which was witnessed by EPA during a site visit on April 28, 2010, employing ZLD to treat FGD wastew ater has been technologically challenging and continues to be a work in progress. ZLD technology is a relatively new approach to treat FGD wastewater so there is limited design and operating experience to reference. The complex chemistry involved has made keeping the system on

- line challenging even for the small bleed system that is being treated at KCP&L’s Iatan Generating Station. Costs of this treatment technology have been significant and continue to grow to achieve the necessary system reliability. Giv en the high costs and reliability issues, ZLD should not be considered Best Available Technology for FGD wastewater at this time. Comment Response: EPA disagrees with the commenter that the proposed or final rule establishes “FGD wastewater limit[s] based on thermal Zero Liquid Discharge (ZLD) systems.” The final rule does not establish zero liquid discharge limitations or standards applicable to FGD wastewater. The commenter also refers to proposed Option 5 (which is equivalent to Option F in the fin al rule). The technology basis for control of pollutants in FGD wastewater based on Option F is evaporation technology. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation syst em, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. The commenter does not support proposed Option 5 (equivalent to Option F in the final r ule) as the basis for BAT requirements in the final rule “[g]iven the high costs and reliability issues” associated with the technology basis for FGD wastewater discharges. EPA disagrees with the commenter regarding the reliability issues of the evaporatio n system, see response to DCN EPA

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- 4655, Excerpt Number 108, in Comment Code 11.a and DCN EPA

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EPA’s Response to Public Comments

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- 4655, Excerpt Number 119, in Comment Code 11.a. Additionally, regarding the experience at the Iatan plant, EPA notes that the plan t only operates a portion of the evaporation system technology basis. Iatan only operates a solids removal system (i.e., clarifier) and the brine concentrator. It does not operate a chemical precipitation system, a softening system, or a crystallizer. Addi tionally, EPA learned at the site visit that the plant had cycled the FGD wastewater in the system too much, which was causing problems with the operation of the system: “The evaporation system was designed for a TDS concentration of 15,000 ppm; however, a t the time of the visit, the TDS concentration was 70,000 ppm, which was causing issues with the evaporation system. The plant had been cycling the water in the FGD system to raise the chlorides level, but because the plant uses PRB coal, which generally has lower chlorides, the additional recirculation was causing a much higher buildup of TDS.” Final Iatan Site Visit Notes [DCN SE03727] EPA agrees with the commenter regarding the generally high costs associated with the evaporation technology basis for ex isting sources. EPA decided it would not be appropriate to identify evaporation as the basis for BAT limitations or PSES applicable to FGD wastewater discharges from all existing steam electric power generating units in part because of the high total cost of possible regulatory requirements based on evaporation for FGD wastewater at existing plants. See preamble section VIII.C.1 for additional details. The final rule does, however, establish a voluntary incentives program for plants that choose to comply wi th BAT limitations for FGD wastewater based on evaporation (see preamble Section VIII.C.13). Because plants may choose to participate in this voluntary incentives program, the costs to any participating plants are assumed to be affordable. In addition, the final rule establishes requirements for discharges of FGD wastewater from new sources (NSPS/PSNS) based on evaporation technology (Option F). EPA examined the possible impact of the final new source requirements (NSPS/PSNS) by comparing the incremental co sts of the Option F technologies to the costs of a hypothetical new generating unit. As explained in the preamble, the estimated incremental costs of the final rule do not pose a barrier to entry for new sources. EPA disagrees with the commenter that the t echnology basis for control of FGD wastewater discharges in the voluntary incentives program and from new sources is “not demonstrated or technologically available for FGD wastewater.” See responses to comments in comment code 11.a (in particular the respo nse to DCN EPA

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- 4655, Excerpt Number 108).

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 25 External Review Flag: No External Review Exter nal Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 3 Comment Excerpt: EPA Correctly Concluded Chemical Precipitation Plus Vapor
- Compression Evaporation is Not BAT for Existing Dischargers or New Sources. We Energies strongly supports EPA’s conclusion that chemical precipitation (“CP”) followed by vapor
- compression evaporation (“VCE”) is not the best available technology economically achievable for existing dischargers or new sources. EPA did not select Option 5 as its preferred option for BAT because of the high tot al industry cost for the option and because of preliminary indications that Option 5 may not be economically achievable. We Energies believes that EPA may have underestimated the total industry cost and overestimated the pollutant removals, which makes th e cost

- effectiveness or dollars per toxic weighted pound

- equivalent (“$/TWPE” or “$/lb

- eq”) even higher than EPA calculated. 1 This further supports the conclusion EPA reached: CP+VCE is not BAT.

1 The term toxic weighted pound

- equivalent (“TWPE”) is syno nymous with pound

- equivalent (“lb

- eq”) and the two terms are used interchangeably. Comment Response: The commenter states that “chemical precipitation followed by vapor

- compression evaporation is not the best available technology economically achievable for existing dischargers or new sources.” EPA agrees that the evaporation system is not BAT for FGD wastewater discharges from all existing steam electric generating units, for the reasons explained in preamble section VIII.C.1. See also response to DCN EP A

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- A2, Excerpt Number 10. For plants that choose to participate in the voluntary incentives program established by the final rule, however, BAT limitations for FGD wastewater discharges are based on evaporation (see preamble Section VII I.C.13 for more detail). EPA also disagrees with the commenter that the evaporation system is not the best available demonstrated technology for control of FGD wastewater discharges from new sources (NSPS/PSNS). See preamble sections VIII.D and F for a dis cussion of EPA’s rationale for selecting the evaporation system as the NSPS/PSNS technology basis for FGD wastewater discharges. See also response to DCN EPA

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- A2, Excerpt Number 10. EPA does not agree with the commenter that EPA has und erestimated the total industry cost and overestimated the pollutant removals for the final rule. The commenter offers no basis for these claims. Nonetheless, for the role of cost

- effectiveness in EPA’s decisions for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in C omment C ode 6.h.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 63Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA does not specify the cases in which the VCE distillate limits would apply for Option 5 of the draft ELG. In Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category , EPA states that
“Brindisi is operated as a zero discharge system with no wastewater being discharged to surface water or a POTW.” [EP A, 2013b, page 10

- 12, footnote 71] This statement appears to indicate that EPA’s definition of discharge and its proposed distillate limits may apply only to surface water and POTW discharges of the distillate. In contrast

— during the EPA Webcast on Steam Electric ELG Proposed Rule on August 20, 2013 [EPA, 2013c], question

- and

- answer period

— EPA indicated that if facilities used their VCE distillate in processes other than FGD, then the distillate would need to meet the proposed effluent limits. Setting VCE distillate limits may prevent plants from directly discharging the distillate when necessary. The discharge limits for VCE distillate shown in Table X

- 1 of the draft ELG [EPA, 2013a] are considerably lower than the discharge limits for chemical precipitati on and biological treatment options. Arsenic and selenium limits for chemical precipitation and VCE treatment (4 μg/L daily and 5 μg/L daily, respectively) are lower than the respective limits for chemical precipitation and biological treatment (8 μg/L dai ly and 16 μg/L daily, respectively). The mercury limit for chemical precipitation and VCE treatment (39 ng/L daily, 24 ng/L monthly) is an order of magnitude lower than the mercury limit for chemical precipitation and biological treatment (242 ng/L daily, 119 ng/L monthly). If plants cannot achieve these low limits, they would be prevented from directly discharging very clean distillate as well as using it in other processes. Ideally, power plants using a vapor

- compression evaporator as an alternative to b iological treatment would expect to meet the technology

- based nitrate/nitrite limit. However, Table 5

- 3 shows that the 3

- day average concentration of distillate from the Brindisi brine concentrator is greater than the proposed monthly limit of 0.13 mg/L fo r nitrate/nitrite [EPA, 2012].Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 5 Comment Response: The effluent limitations and standards for FGD wastewater discharges based on the evaporation system, which apply to new sources (NSPS/PSNS) and to existing plants electing to participate in the volunta ry incentives program (BAT), apply to discharges of the distillate/condensate to surface waters or POTWs. EPA had proposed an anti

- circumvention provision that would have required plants to demonstrate compliance with numeric limitations and standards prio r to reusing the wastewater (i.e., distillate/condensate) in any process other than the FGD system. However, the final rule does not establish an anti

- circumvention provision applicable to FGD wastewater (see preamble section VIII.G). EPA agrees with the c ommenter that, for dischargers subject to the final NSPS/PSNS or plants that elect to participate in the voluntary incentives program and be subject to the final BAT limitations for FGD wastewater discharges based on evaporation, “[i]f plants cannot achiev e these low limits, they would be prevented from directly discharging very clean distillate.” However, the final rule does not prevent plants from reusing their distillate/condensate in other processes. EPA acknowledges the commenter’s observation that the Brindisi distillate average nitrate/nitrite (as N) concentration was higher than the proposed nitrate/nitrite (as N) numeric BAT limitation based on chemical precipitation plus biological treatment. However, the final rule establishes an FGD wastewater ni trate/nitrite (as N) numeric BAT limitation of 2 mg/L, an order of magnitude higher than at proposal. As such, EPA determined that the evaporation system distillate/condensate would be able to meet the FGD wastewater BAT nitrate/nitrite (as N) limitation ( see TDD section 13 for more information on the limits in the final rule).

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 47 External Rev iew Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ZLD technology is extremely expensive. Ominously, EPA omits a concrete cost

- effectiveness value to implement this technology within the industry. The agency must do so before promulgating this technology as BAT, or, at the very least, must more robustly consider expected costs in order to complete its mandatory BAT analysis. Together, UWAG and NERA estimate an incremental cost

- effectiveness of $1,366/TWPE associat ed with implementing thermal ZLD technologies within the industry. See UWAGEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 6 Comments at Section VI, F. The incremental biological and thermal ZLD are clearly not cost effective using EPA’s high

- end range of $404/TWPE and therefore provide an additional bas is as to why this technology clearly cannot be imposed as BAT for FGD wastewaters. Comment Response: The commenter refers to “ZLD technology.” The proposed rule did not include “ZLD technology” as the technology basis for any limitations or standards, an d the final rule does not establish limitations or standards based on “ZLD technology.” EPA assumes that the commenter is using the term “ZLD technology” to refer to technology basis applicable to FGD wastewater in proposed Option 5 (Option F for the final rule), which is evaporation. EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology.” The technology basis for control of FGD wastewater discharges under these options is an evaporation system. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants woul d be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation system, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams ge nerated by the treatment system. EPA determined that evaporation is not BAT for control of FGD wastewater discharges from all existing steam electric generating units, for the reasons explained in preamble section VIII.C.1. See also response to DCN EPA

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- A2, Excerpt Number 10. For plants that choose to participate in the voluntary incentives program established by the final rule, however, BAT limitations for FGD wastewater are based on evaporation, for the reasons explained in preamble Se ction VIII.C.13. The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharges based on evaporation, for the reasons described in preamble sections VIII.D and F. EPA disagrees with the commenter’s quantification of the cost

- effectivene ss of the final rule. For discussion regarding the methodology and results of EPA’s cost

- effectiveness analysis, see preamble section XV. EPA disagrees with the commenter that EPA must provide a “concrete cost

- effectiveness value to implement [the evaporat ion system] within the industry.” For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h. . EPA notes that, as required by the Clean Water Act, EPA fully considered “cost” in establishing the final limitations, as discussed in the preamble. EPA found that the final rule is affordable to the industry as a whole, and does not pose a barrier to entry for new sources.

Commenter Name: Kevin D. Frizzell Comme nter Affiliation: Owensboro Municipal Utilities (OMU) Elmer Smith Station (ESS)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 7 Document Control Number: EPA

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- A2 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
8. Zero liquid discharge (ZLD) for FGD wastewater:
ZLD is not cost

- effective for small units such as those at OMU ESS. As previously stated, a small unit threshold is needed to address FGD discharges from small units. Comment Respo nse: The commenter discusses “ZLD” for FGD wastewater. The proposed rule did not propose ZLD as the technology basis for any limitations or standards, and the final rule does not establish limitations or standards based on “ZLD technology.” EPA assumes t hat the commenter is using the term “ZLD” to refer to technology basis applicable to FGD wastewater in proposed Option 5 (Option F for the final rule), which is evaporation. EPA disagrees with the commenter’s apparent equating of evaporation technology wit h “ZLD technology.” The technology basis for control of FGD wastewater discharges under these options is an evaporation system. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream tha t can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporat ion system, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. EPA determined that evaporation is not BAT for control of FGD wastewater discha rges from all existing steam electric generating units, for the reasons explained in preamble section VIII.C.1. See also response to DCN EPA

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- A2, Excerpt Number 10. For plants that choose to participate in the voluntary incentives progr am established by the final rule, however, BAT limitations for FGD wastewater discharges are based on evaporation (see preamble Section VIII.C.13 for more detail). The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharges based on e vaporation, for the reasons described in preamble sections VIII.D and F. The commenter states that the evaporation technology basis is not “cost effective.” However, the commenter does not specify what it believes the cost

- effectiveness of the technology i s, nor what would constitute a “cost

- effective” technology. Nonetheless, for the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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. Regarding the commenter ’s statement that “a small unit threshold is needed to address FGD discharges from small units,” the commenter does not specify what it means by “small” units.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 8 However, the final rule establishes differentiated requirements for certain discharges from exis ting steam electric generating units that are 50 MW or less in nameplate capacity for the reasons explained in preamble section VIII.C.12. The final rule does not establish differentiated requirements for certain discharges from new sources based on genera ting unit size for the reasons explained in preamble section VIII.D.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 28 External Review Flag: No External R eview External Review Incorporated into Response: No Comment Excerpt: Thus, EPA’s cost

- effectiveness calculation is $538/lb

- eq compared to EPRI’s calculation, $2121/lb

- eq. In developing the categorical treatment standards for metal product and machinery industries, EPA compared the selected technologies by comparing their cost

- per
- pound equivalents to those of the previous industrial categories. 3 These cost

- effectiveness factors, converted from 1999 dollars to 2010 dollars using the Engineering News Rec ord’s Construction Cost Index (“CCI”), range from $3 per pound equivalent to $997 per pound equivalent in 2010 dollars. 4
EPRI’s cost

- effectiveness calculation for implementing CP+VCE nationwide is more than twice as high as the cutoff EPA has traditionally used to set Effluent Limitations Guidelines. EPRI’s research provides strong evidence that vapor

- compression evaporation is not cost

- effective. See EPRI’s comments for additional details on cost and pollutant removals for CP+VCE.

3 United States Environ mental Protection Agency (USEPA). 2000. Cost

- Effectiveness Analysis of Proposed Effluent Limitations Guidelines and Standards for the Metal Products and Machinery Industry . EPA

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- 007. Washington, D.C

4 CH2M Hill, Evaluation of Treatment Technologies for Arsenic and Selenium Removal, Pleasant Prairie Power Plant , June 2013. Comment Response: EPA disagrees with the commenter’s quantification of the cost

- effectiveness of the final rule. For discussion regarding the methodology and results of EPA’s cos t

- effectiveness analysis, see preamble section XV. For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 9 See response to DCN EPA

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- A 1, Excerpt Number 47 and DCN EPA

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- A2, Excerpt Number 10.

Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 41 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Thermal ZLD Systems are Not Demonstrated or “Technologically Available” for FGD Wastewater; Nor are they Cost
- Effective. While EPA has not designated a proposed FGD wastewater limit based on thermal Zero Liquid Discharge (ZLD) systems as a “preferred option,” the Agency has included this technology as the basis for its option 5. ZLD systems are not demonstrated or “technologically available” for FGD wa stewater. As detailed in the UWAG Comments, only one U.S. plant and four Italian plants are currently operating this technology in an FGD wastewater application. A second U.S. plant is presently installing a vapor compression evaporation system to treat it s FGD wastewater. Furthermore, those in service demonstrate engineering difficulties and solid waste disposal challenges. As demonstrated by EPRI and UWAG’s analyses of ZLD system cost

- effectiveness, as well as their critiques of EPA’s flawed assumptions (e.g., regarding costs of disposal, parasitic load calculations, costs of climate controls) in the EPA cost

- effectiveness analysis, ZLD systems are not cost effective. Comment Response: EPA disagrees with the commenter that the proposed or final rule inc ludes FGD wastewater limitations or standards based on “thermal Zero Liquid Discharge (ZLD) systems.” The final rule does not establish zero discharge limitations or standards applicable to FGD wastewater. The commenter also refers to proposed Option 5 (wh ich is equivalent to Option F in the final rule). The technology basis for control of pollutants in FGD wastewater based on Option F is evaporation technology. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulato ry options based on the evaporation system, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 10 EPA disagrees with the commenter that the technology basis for control of FGD wastewater discharges in the voluntary incentives program or from new sources “is not demonstrated or technologically available.” See preamble sections VIII.C.13 and VIII.D, as well as the response to DCN EPA

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- 4655, Excerpt Number 108 in Comment Code 11.a. The commenter states that ZLD systems currently in service “demonstrate engineering difficulties and solid waste disposal challenges.” The commenter does not offer any basis for these generalized claims. Nonetheless, regarding the disposal of the solids generated from the evaporation system, see response to DCN EPA

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- A3, Excerpt Number 45, and regarding operational “challenges,” see response to DCN EPA

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- 4655, Excerpt Numb er 108 in Comment Code 11.a. For discussion regarding the methodology and results of EPA’s cost

- effectiveness analysis for the final rule, see preamble section XV.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DC N EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We support EPA's decision to forego proposed Option 5, which would establish effluent standards for FGD wastewater based upon zero liquid discharge technologies (i.e. vap or compression evaporation). EPA reaches its decision to forego Option 5 as one of its preferred regulatory options by concluding that the cost of treatment with vapor compression evaporation is disproportionate to the benefits. 78 Fed. Reg. 34473 col. 2

- 3 (June 7, 2013). We concur with EPA that the cost of vapor compression evaporation disqualifies this technology as a candidate upon which a national standard can be developed. We also note that vapor compression evaporation and other zero liquid discharg e technologies have not been sufficiently implemented in the United States electric power generation industry to be considered "proven" technology, in an industry where reliability and dependability are crucial to operations. Comment Response: EPA disag rees with the commenter’s apparent equating of evaporation with “zero liquid discharge technologies.” The technology basis for control of FGD wastewater discharges underEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 11 these options is an evaporation system. That technology basis does not necessarily ach ieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the syste m in a zero liquid discharge fashion, for regulatory options based on the evaporation system, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment syste m. EPA disagrees with the commenter that “EPA reaches its decision to forego Option 5 as one of its preferred regulatory options by concluding that the cost of treatment with vapor compression evaporation is disproportionate to the benefits.” EPA decided i t would not be appropriate to identify evaporation as the basis for BAT limitations for FGD wastewater discharges from all existing steam electric power generating units in part because of the high cost of potential regulatory requirements based on evapora tion for FGD wastewater discharges from existing units. See preamble section VIII.C.1 for additional details. The final rule does, however, establish a voluntary incentives program for plants that choose to comply with BAT limitations for FGD wastewater di scharges based on evaporation (see preamble Section VIII.C.13). Because plants may choose to participate in this voluntary incentives program, the costs to any participating plants are assumed to be affordable. In addition, the final rule establishes requi rements for discharges of FGD wastewater from new sources (NSPS/PSNS) based on evaporation technology (Option F). Moreover, EPA examined the possible impact of the final new source requirements (NSPS/PSNS) by comparing the incremental costs of the Option F technologies to the costs of a hypothetical new generating unit. As explained in the preamble, the estimated incremental costs of the final rule do not pose a barrier to entry for new sources. EPA partially agrees and partially disagrees with the commente r that “the cost of vapor compression evaporation disqualifies this technology as a candidate upon which a national standard can be developed.” EPA agrees with the commenter that the evaporation system is not BAT for all existing sources, as described abov e (see also response to DCN EPA

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- A2, Excerpt Number 10). However, EPA disagrees with the commenter because EPA has determined that the evaporation system is BAT for existing sources that opt into the voluntary incentives program, and th at the technology is the best available demonstrated technology for new sources, for the reasons described above and in the preamble. EPA disagrees with the commenter that the evaporation system has “not been sufficiently implemented in the United States e lectric power generation industry to be considered ‘proven’ technology, in an industry where reliability and dependability are crucial to operations.” See responses to comments in comment code 11.a (in particular the response to DCN EPA

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- 465 5, Excerpt Numbers 108 and 119, in Comment Code 11.a).

Commenter Name: Nysa Hogue Commenter Affiliation: Indianapolis Power & Light Company (IPL) Document Control Number: EPA

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- A2 Comment Excerpt Number: 11Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The proposed ELG includes limits on FGD zero liquid discharge (ZLD) 'discharge.' This limit is not in a preferred option for existing sources, but is in Option 5 which EPA may choose to impose. IPL requests that EPA eliminate limits on water quality of FGD ZLD 'discharge', or at least clarify that if the FGD clean water stream (evaporator distillate) will not have to meet discharge limits. An example of re

- use of FGD waste water evaporator distillate reuse is use for boiler feedwater. Having numerical limits on distillate may preclude this use if the system did not achieve compliance with the proposed preferred BAT limits. Instead the plant would be required to go to the e xtra expense of further treating this ultra

- pure water. Further, the reuse of the distillate can offset the use of other water in this need, so banning its use will hurt water conservation and energy reduction efforts. Comment Response: EPA disagrees wi th the commenter that the proposed or final rule “includes limits on FGD zero liquid discharge (ZLD).” The final rule does not establish zero discharge limitations or standards applicable to FGD wastewater. The commenter also refers to proposed Option 5 (w hich is equivalent to Option F in the final rule). The technology basis for control of pollutants in FGD wastewater based on Option F is evaporation technology. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulat ory options based on the evaporation system, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding the commenter’s opposition to propos ed Option 5 (or Option F for the final rule), see response to DCN EPA

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- A2, Excerpt Number 10. Regarding the commenter’s statements about re

- use of FGD wastewater, see response to DCN EPA

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- A1, Excerpt Number 63.

Com menter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number: EPA

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- A1 Comment Excerpt Number: 37 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 13 Comment Excerpt: In addition to a faulty evaluation and erroneous conclusion that biological treatment should receive consideration as BAT for the utility industry, EPA was wrong to have not dismissed ZLD as the potential BAT for FGD waste water. The technology basis for FGD waste water treatment in Option 5 of EPA’s proposed ELGs is chemical precipitation in combination with vapor compression evaporation, a thermal ZLD system. EPA seems unwilling to reject ZLD as BAT despite EPA’s own analy sis revealing that there are a number of primary concerns with this technology. In the end, the limited data EPA possesses at the few facilities in the world that utilize this technology cannot provide the support needed to justify imposition of this addit ional vapor compression technology as BAT for the industry. Comment Response: EPA disagrees with the commenter’s statement that the proposed or final rule includes “a thermal ZLD system” as the technology basis for proposed Option 5 (or Option F for the final rule). The technology basis for control of FGD wastewater discharges under these options is an evaporation system. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can b e discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation sys tem, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system.
The final rule does not establish BAT limitations or PSES for control of FGD wastewate r discharges from all existing steam electric generating units, for the reasons explained in preamble section VIII.C.1. See also response to DCN EPA

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- A2, Excerpt Number 10. For plants that choose to participate in the voluntary incentiv es program established by the final rule, however, BAT limitations for FGD wastewater are based on evaporation (see preamble Section VIII.C.13 for more detail). The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharges based on evap oration, for the reasons described in preamble sections VIII.D and F. The commenter states that “there are a number of primary concerns” with the evaporation technology. The commenter offers no basis, however, for this generalized claim. Nevertheless, se e responses to comments in code 11.a regarding the demonstration and performance of evaporation technology (in particular the response to DCN EPA

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- 4655, Excerpt Number 108, in Comment Code 11.a). The commenter also states that EPA only has “ limited data” regarding the evaporation technology, which cannot support EPA’s decisions to base final limitations or standards on the technology. The commenter does not specify what it regards as “limited.” Nonetheless, see response to DCN EPA

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- A1, Excerpt Number 33, in comment code 11.c.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 14 Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number: EPA

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- A1 Comment Excerpt Number: 40 External Revie w Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: As explained below, too many site

- specific factors even at the few facilities that have implemented this technology make the limited data the agency currently pos sesses grossly insufficient to attempt to establish it as the national standard. In short, there is insufficient evidence to support a regulatory finding that: (1) this technology is readily available (under the BAT factors); (2) this technology can effect ively be transferred from site to site; or (3) the associated effluent limits are technologically or economically reasonably achievable (as defined by the BAT factors) within the industry over the long term. Without sufficient data, EPA has not and cannot present evidence to justify a conclusion that a ZLD process is BAT. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD” technology, as discussed in the response to DCN EPA

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- A1, E xcerpt Number 37. Regarding the commenter’s statements about using data from a “few facilities” to “establish . . . national standard[s],” see response to DCN EPA

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- A1, Excerpt Number 33, in comment code 11.c. Regarding the commenter’s g eneralized and unsupported statements about technological availability and economic achievability, see preamble section VIII and response to DCN EPA

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- 4655, Excerpt Number 108, in Comment Code 11.a.

Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 19 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 3. Thermal ZLD Technology is Cost ProhibitiveEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 15 EPA fails to offer a concrete cost

- effectiveness value to implement ZLD technology within the industry. Because this is a required step in completing its mandatory BAT analysis, EPA must either offer this value or, at the very least, consi der expected costs more robustly. UWAG and NERA estimate an incremental cost

- effectiveness associated with implementing thermal ZLD technologies within the industry of $1,366/TWPE. If EPA’s high

- end range of $404/TWPE is used, the incremental biological and thermal ZLD are clearly not cost effective. This is additional evidence that ZLD technology cannot be imposed as BAT for FGD wastewaters. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD” tech nology, as discussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under these options is an evaporation system. That technology basis does not necessarily achieve zero liquid discharge because it g enerates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, f or regulatory options based on the evaporation system, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. EPA disagrees with the commenter’s q uantification of the cost

- effectiveness of the final rule. For discussion regarding the methodology and results of EPA’s cost

- effectiveness analysis, see preamble section XV. EPA disagrees with the commenter that EPA must provide a “concrete cost

- effective ness value to implement [the evaporation system] within the industry.” For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Bruce W . Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We strongly support EPA’ s conclusion that Chemical Precipitation plus Vapor
Compression Evaporation is not Best Available Technology Economically Achievable for Existing Dischargers or New Sources. Vapor

- compression evaporation (“VCE”) has a number of technological drawbacks (p arasitic energy load, corrosive nature, waste considerations) and it has not been a proven technology to consistently treat FGD wastewater. Further, its high cost relative to the incremental pollutant removal demonstrates that it is not cost

- effective.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 16 Co mment Response: Regarding the commenter’s statements that EPA should reject the evaporation system as the technology basis for control of FGD wastewater discharges from existing sources and new sources, see response to DCN EPA

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- A1, Ex cerpt Number 25. Regarding the commenter’s generalized statement about the “technological drawbacks” of evaporation technology and the statement that the technology has not been “proven,” see responses to comments in comment code 11.a (in particular, see responses to DCN EPA

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- A1, Excerpt Number 74 in Comment Code 11.b. Regarding the commenter’s reference to the “corrosive nature” of evaporation systems, see response to DCN EPA

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- A3, Excerpt Number 45 (comment code 11.a); DCN EPA

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- A1, Excerpt Number 18 (comment code 11.a); DCN EPA

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- A1, Excerpt Number 26 (comment code 11.a); and DCN EPA

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- A1, Excerpt Number 75 (comment code 11.d). Regarding the commenter’s statement about the “high cost” of evaporation systems,” see response to DCN EPA

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- A2, Excerpt Number 10. Regarding the commenter’s statement that evaporati on technology is not “cost

- effective” based on its “high cost” relative to “incremental pollutant removal,” see response to DCN EPA

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- 4655, Excerpt Number 27 (in comment code 6.h).

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
As discussed in more detail below in Secti on I.2., we agree with the EPA conclusion that zero liquid discharge technologies for FGD wastewater are not appropriate. Vapor compression evaporation technology as contemplated in Option 5 is an unproven technology for the retrofit ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 17 existing facilities . Further, this type of treatment is very costly in a retrofit scenario and is an uneconomical approach for FGD wastewater. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 10.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 76 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Chemical precipitation plus vapor

- compres sion evaporation is not BAT for FGD wastewater because it is not a commercially proven technology, and its high cost relative to the incremental pollutant removal demonstrates that it is not cost

- effective. Comment Response: Regarding whether the evapora tion system is a proven technology, see responses to comments in comment code 11.a (in particular, the responses to DCN EPA

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- 4655, Excerpts Numbers 108 and 119 in Comment Code 11.a). Regarding the commenter’s statement that evaporation techn ology is not “cost

- effective” based on its “high cost” relative to “incremental pollutant removal,” see response to DCN EPA

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- 4655, Excerpt Number 27 (in comment code 6.h).

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern C ompany Document Control Number: EPA

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- A1 Comment Excerpt Number: 88 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
The same is true for incremental thermal ZLD. In 1981 dollar s, the model plant approach yields costs of $1,238 to $6,533 (1981) per TWPE. In the industry

- wide analysis, the cost is $1,369 (1981) per TWPE.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 18 Comment Response: EPA disagrees with the commenter’s quantification of the cost

- effectiveness of the final ru le. For discussion regarding the methodology and results of EPA’s cost

- effectiveness analysis, see preamble section XV.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Number 2 7 in Comment Code 6.h

.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 127 External Review Flag: No External Review External Review Incorpo rated into Response: No Comment Excerpt:
The same is true for incremental thermal ZLD. In 1981 dollars, UWAG’s model plant approach yields costs of $1,238

– $6,533 per TWPE. In the industrywide analysis, the cost is $1,369 per TWPE. Comment Response: EPA disagrees with the commenter’s quantification of the cost

- effectiveness of the final rule. For discussion regarding the methodology and results of EPA’s cost

- effectiveness analysis, see preamble section XV.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Most importantly, the Company supports EPA’s critical determination that vapor

- compression evaporation is not BAT for FGD wastewater for e xisting dischargers or new sources.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 19 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 25.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Consequently, we do not support zero liquid discharge technologies for the treatment of FGD wastewaters and agree with EPA's decision to forego this technology. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 13.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Likewise, EPA has not proven that incremental vapor

- compression evaporation is cost

- effective or commercially available.
C omment Response:
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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. Regarding the commercial viability of evaporation systems, see responses to c omments in Comment Code 11.a (in particular, the response to DCN EPA

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- 20 Commenter Name: Raven Power Holdings, LLC Commenter Affiliation: Raven Power Holdings, LLC Document Control Number: EP A

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA has not proven the cost

- effectiveness or commercial viability of vapor

- compression evaporation. Comment Response:
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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. Regarding the commercial viability of evaporation systems, see responses to comments in Comment Code 11.a (in particular, the response to DCN EPA

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- 4655, Excerpt Number 108 in Comment Code 11.a).

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 61 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 5.11 The need for proposed numeric limits for VCE distillate is unclear
The draft ELG [EPA, 2013a] states that EPA visited the operating Italian Brindisi plant and collected data. EPRI understands that the Brindisi plant, like most Italian power plants, burns non
- U.S. coal of lower sulfur and chloride content than coals typically burne d at U.S. facilities. Therefore, metals concentrations in Brindisi FGD wastewater may not be representative of concentrations expected at most U.S. plants. During VCE operation, as metals cycle up the evaporator and crystallizer, there is some carryover in the mist through the mist eliminators. Thus, distillate metals concentrations observed at U.S. plants would likely be higher than those at Italian plants

—

potentially preventing the U.S. plants from meeting EPA’s proposed distillate limits.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 21 Comment Respon se: EPA established numeric limitations and standards based on evaporation technology that are applicable to the distillate/condensate from the evaporation system in order to ensure that plants maintain and operate the evaporation system effectively. EPA notes that any plant subject to limitations or standards based on evaporation for control of FGD wastewater discharges would not need to meet the numeric limitations or standards if the plant does not discharge the FGD wastewater. EPA agrees with the comm enter that “there is some carryover in the mist through the mist eliminators” which is why metals are present in the distillate/condensate stream. EPA also agrees with the commenter that the Brindisi plant burns non

- U.S. coal. However, the commenter offer s no data to support its claims that “metals concentrations in Brindisi FGD wastewater may not be representative of concentrations expected at most U.S. plants” and that “metals concentrations observed at U.S. plants” would “potentially prevent[] the U.S. plants from meeting” the final limitations and standards. The final limitations and standards are based on the best available data and EPA reasonably determined that the industry can achieve these limitations and standards (see TDD section 13). See the Sta tistics Support Document for Effluent Limitations (DCN SE05733). See also response to DCN EPA

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- A1, Excerpt Number 33 in Comment Code 11.c.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 32 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Duke Energy agrees with EPA’s assessment that chemical precipitation with vapor

- compression evapor ation should not be a model technology. Duke Energy contends this technology has not been demonstrated to be technical feasible on an industry

- level and the economic impacts would be too much for the industry to bear. Comment Response: Regarding the comm enter’s statement that evaporation technology “has not been demonstrated to be technical[ly] feasible,” see responses to comments in comment code 11.a (in particular, the response to DCN EPA

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- 4655, Excerpt Number 108 in Comment Code 11.a).
R egarding the commenter’s statements that the “economic impacts [associated with the evaporation technology] would be too much for the industry to bear,” see response to DCN EPA

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- A2, Excerpt Number 10.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 22 Commenter Name: Douglas J. Fulle Commenter Affiliation: Oglethorpe Power Corporation Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
For the zero
- discharge option, EPA has not proven that vapor compression

- evaporation systems are demonstrated and commercially available for the treatment of FGD wastewater. Comment Response: See responses to comments in comment code 11.a (in particular, the re sponse to DCN EPA

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- 23 11.a. FGD VCE

– Demonstration/Performance
Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: C. Thermal ZLD Systems are Not Technologically Available or Economically Achievable for FGD W astewater Treatment and are Not BAT EPA’s Proposed Rule concludes that ZLD technology is commercially available to the U.S. electric utility industry to effectively eliminate discharges of FGD wastewater. This false conclusion inappropriately relies upon l imited data from: (1) a handful of facilities in Italy which operate much smaller versions of this technology in drastically different technological and regulatory contexts; and (2) the only two United States plants that currently employ some form of a ZLD system to treat FGD wastewater. EPA’s conclusion also ignores some of the significant operational issues this technology presents. Further, EPA drastically underestimates the capital expenditures, operations and maintenance costs, and lost generation capa city related to ZLD. As demonstrated below, ZLD is not an available or appropriate technology to consider for FGD wastewater treatment. Therefore, EPA should not consider Option 5 or any other scenario which requires utilizing unproven ZLD technology.
1. A pplications of ZLD Systems are Extremely Limited and are Otherwise Not Useful in Evaluating the Availability of ZLD Technology Only a handful of ZLD systems for FGD wastewater treatment have ever been applied to coal

fired power plants at various points in time. They are simply not common in the electric utility industry. The only American utilities currently utilizing some form of ZLD system for FGD wastewater treatment are Public Service Company of New Hampshire’s Merrimack Station and Kansas City Power a nd Light’s (“KCPL”) Iatan facility. Furthermore, KCPL’s system does not actually achieve a “zero liquid discharge.” Instead, the concentrated wastewater exiting the ZLD treatment system is returned to Iatan’s fly ash treatment system in order to condition its fly ash before disposal in a landfill. In the Proposed Rule, EPA largely relies upon the data and operations of ZLD

- type technologies used in Italy to substantiate its assertions regarding the efficacy of this technology. These foreign systems, however , do not present a reasonable benchmark for what a coal

- fired plant in the United States could expect if forced to install a ZLD system. First, the Italian ZLD applications are much smaller in scale than what would be required to treat the FGD wastewater a t American facilities. Second, the Italian facilities are not dependent on the ZLD technology, but instead utilize them at their discretion, as applicable Italian laws provide the plants the alternative of transporting their wastewaters to a treatment plan t. Third, Italian disposal methods areEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 24 significantly different than American methods. Italian facilities cannot deposit solids in an on

site landfill, but must ship them elsewhere. Thus, Italian plants need not account for the additional solid waste stream and infrastructure that facilities in the United States would be required to manage if they employed both a ZLD system and a chemical precipitation treatment system. 2. Operational Challenges of ZLD Systems
EPA’s false conclusion that ZLD is a commerciall y available technology is also premised on an incomplete evaluation of the technical and operational issues associated with this technology. The relevant research and limited power industry experience reveal numerous problems associated with the operation of ZLD systems as well as numerous modifications to existing plant infrastructure required to accommodate such systems. Any reasonable consideration of the operational and logistical requirements and challenges associated with a ZLD system must lead t o the conclusion that ZLD is not a commercially available or technologically feasible technology. UWAG provides a thorough discussion of many of the known or inevitable operational issues the industry will face if ZLD is finalized as BAT for FGD wastewaters. Alabama Power supports and incorporates by reference UWAG’s extensive discussion regarding the shortcomings of this technology. Additionally, Alabama Power provides a summary of the issues it expects to encounter at its facilities if ZLD syste m retrofits are required.

 First, Alabama Power expects that the corrosive nature of FGD wastewater will inevitably cause the metal components of a ZLD treatment system to wear quickly, even where the system is operated without upsets, and where equipment i s made with high quality metals. FGD wastewater is inherently corrosive to metal, and the concentration levels of FGD effluent present in the waste stream varies depending on even slight differences in the coal burned in the boiler. As a result, Alabama Po wer expects significant additional capital, operating, and labor costs associated with the constant inspection, maintenance, and replacement of parts required for any ZLD treatment systems.

 Second, Alabama Power expects to generate another solid waste stre am of corrosive, highly soluble salts as a result of utilizing ZLD technology. ZLD systems require regular blow down to clear out salt formations from inside the piping and other components in order to avoid further operational problems. The waste streams created to deal with these solid salt formations will require an additional level of waste collection, handling, storage, and disposal. Because the salts produced in the ZLD treatment process are composed mainly of calcium chloride and magnesium chloride h ydrate, which tend to melt down quickly and may ultimately appear in landfill leachate and runoff, they are challenging to manage for disposal. This issue tends to be exacerbated in particularly humid regions like the Southeastern United States, including Alabama.

 Third, the regulatory status of this extra solid waste stream from ZLD blow down is unclear, and could expose Alabama Power to potential regulation under solid and/orEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 25 hazardous waste laws such as the Resource Conservation and Recovery Act (“RCRA”) , 42 U.S.C. § 6901 et seq. , as well as applicable state and local waste management regulation. Similarly, there are open questions related to the long

- term disposal and stabilization of these salts when used for such purposes as road repair, cement filler, or fly ash conditioning prior to disposal.

 Fourth, finding the most effective combination of components and settings to the crystallization process is critical for ensuring the overall success of FGD treatment. Crystallization is the final opportunity fo r the system operator to form the waste into crystals which are structurally compatible with the next phase of the ZLD process: dewatering. It is a constant challenge for operators to maintain the crystallizer with the number of constantly changing variabl es. The currently available installation data demonstrates that this process is simply not viable as a constantly reliable solution. Scrubber waste crystallization is a newer process that still presents operational uncertainties, including flow and circula tion rate variations, chemical composition variation due to coal usage, heat added to the system, and mechanical elements such as tank size, tank finish, and the most effective types of pumps to utilize.

 Fifth, the ZLD process requires an inordinate amount of expensive chemicals. For example, chemicals are required to begin precipitation, conditioning, and concentration of the FGD blow down slurry stream by reducing levels of calcium, magnesium, and other hardness

- producing ions before high temperature proc essing can occur. Moreover, because the ZLD process consumes such large quantities of lime and soda ash, some estimates suggest that multiple millions of dollars would be spent on obtaining those chemicals each year. The sludge byproduct produced by the li me and soda ash in the ZLD process must also be dewatered and disposed of properly.

 Sixth, the ZLD process may cause the release of vaporous mercury, selenium, boron, and/or ammonia into the ambient air. EPA cannot justify labeling ZLD technologies as BAT for the industry before conducting a thorough review of these potential emissions.

 Seventh, the ZLD process creates harsh conditions which tend to wear out equipment. In addition to the continuous need to replace filter presses, other equipment must be clo sely monitored by plant personnel to assess any present or potential threats to the process.

 Eighth, there are only two thermal ZLD system vendors, and neither is willing to guarantee more than 95% availability for the ZLD system. It is not currently clear how quickly systems can be repaired and brought back on line. Because the reliability of the nation’s electrical grid is dependent on the operation of the facilities being regulated under this rule, EPA must seriously consider the ramifications of requiri ng a technology still in its infancy.

 Ninth, as mentioned elsewhere in these comments, “footprint concerns” are also a material issue EPA must consider. Power plants have only limited space to house the control technologies required to comply with numerous other important air, land, and water regulations, Requiring ZLD technology will likely result in some of thatEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 26 infrastructure needing to be reconfigured, reclaimed, or eliminated altogether. This would present an extreme challenge to many facilities.
The i nsurmountable evidence demonstrates that EPA cannot rationally classify this technology as BAT for FGD without ignoring both the known and unknown problems and obstacles presented by ZLD technology. Comment Response:
The commenter’s statements focus on “ thermal ZLD systems” and “ZLD technology.” The proposed rule did not include “thermal ZLD systems” or “ZLD technology” as the technology basis for any limitations or standards, and the final rule does not establish limitations or standards based on “ZLD te chnology.” EPA assumes, based on other statements by the commenter, that the commenter is using the term “ZLD technology” to refer to technology basis applicable to FGD wastewater in proposed Option 5 (Option F for the final rule), which is evaporation. EP A disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology.” The technology basis for control of FGD wastewater discharges under these options is evaporation. That technology basis does not necessarily achieve zero li quid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. EPA agree s in part and disagrees in part with the commenter that evaporation technology is not BAT for control of FGD wastewater discharges. EPA determined that evaporation is not BAT for control of discharges of FGD wastewater from all existing steam electric gen erating units, for the reasons explained in preamble section VIII.C.1. For plants that choose to participate in the voluntary incentives program established by the final rule, however, BAT limitations for FGD wastewater are based on evaporation (see preamb le Section VIII.C.13 for more detail). The final rule also establishes NSPS/PSNS applicable to FGD wastewater based on evaporation. See preamble sections VIII.D and F for a discussion of EPA’s rationale for selecting the evaporation technology as the NSPS and PSNS technology basis for control of FGD wastewater discharges. Overall, EPA found that the final BAT limitations are economically achievable for the industry as a whole, and that the final NSPS do not pose a barrier to entry. Regarding the commenter’s statements relating to the technological availability of evaporation, “UWAG’s extensive discussion regarding the shortcomings of this technology,” the evaluation of the Italian plants, the corrosive nature of FGD wastewater, and maintaining the operation of the crystallizer, see response to DCN EPA

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- site landfill...[the] Italian plants need not account for the additional solid waste stream and infrastructure that facilities in the United States would be required to manage if they employed both a ZLD system and a chemical precipitation treatment system.” EPA notes thatEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 27 none of the plants in the United States are currently or would be required to handle the solids from the evaporation process in an on

- site landfill. Plants have the option to dispose of t he solids in off

- site landfills

. Regarding the commenter’s statement that EPA “underestimate[d]” the capital and O&M costs, see response to DCN EPA

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- A3, Excerpt Number 45. Additionally, regarding the regulation of the solid waste stream, the final rule does not establish BAT limitations applicable to FGD wastewater discharges based on the evaporation technology, except in cases whe re the plant elects to participate in the voluntary incentives program. In such cases, the plant should consider any applicable regulations for the solid waste stream during its evaluation of whether to participate in the program. Additionally, for NSPS an d PSNS, plants have the ability to consider any applicable regulations while developing plans for building and operating the new source. EPA agrees in part that the evaporation technology will require chemicals for operation, and chemical costs may be in t he “millions of dollars.” EPA has included the costs of these chemicals in its cost estimation methodology (see TDD for more details). EPA disagrees with the commenter regarding the types of chemicals needed. For the evaporation technology, EPA estimated c osts for soda ash to remove magnesium, polymer to enhance gravity settling within the physical

- chemical soda ash softening system, sulfuric acid and caustic to control wastewater pH prior to entering the evaporation unit, anti

- foam to reduce possible foami ng in the evaporator and anti

- scalant to reduce scaling in equipment such as heat exchangers. EPA disagrees with the comments that additional hydrated lime is needed for the softening system since lime is already added to the wastewater during chemical pre cipitation and this step would have removed carbonate alkalinity. Sludge generated from the soda ash softening process would need to be managed in a similar fashion as the sludge generated from the chemical precipitation system. EPA disagrees with the comm enter that mercury, selenium, boron, and/or ammonia could evaporate and be released to the ambient air during the evaporation and crystallization process. Evaporation and crystallization systems operate at approximately 110 o C and the FGD wastewater being treated is at neutral pH. Although elemental mercury can volatilize at the temperatures found in the evaporation system, the mercury in the FGD wastewater will be predominately inorganic mercury such as mercury chloride which is much less volatile than el emental mercury. Plants employing organosulfide in chemical precipitation system (as described in the BAT chemical precipitation basis) upstream of the evaporator will remove most of the mercury before it reaches the evaporator. Ammonia can be stripped fr om wastewaters at the temperatures found in the evaporator and crystallizer; however, the pH of the wastewaterEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 28 needs to be greater than 9.5 S.U. For boron, research has shown that only 0.5% is released during evaporation at 100 o C (see DCN SE05731)

. EPA a grees that selenium can be volatilized during combustion but this requires temperatures of more than 800 o C, which is far greater than the temperatures found in the evaporation and crystallization systems. Regarding the commenter’s statements about the numb er of vendors available and “footprint concerns” related to evaporation technology, see response to DCN EPA

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- 4655, Excerpt Number 117. Additi onally, EPA agrees with the commenter that the system “must be closely monitored by plant personnel to assess any present or potential threats to the process.” For this reason, EPA increased its labor requirements for the evaporation system in its cost est imates for the final rule. See response to DCN EPA

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- A1, Excerpt Number 106 in Comment Code 11.b.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Num ber: 45 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Zero Liquid Discharge (ZLD) Technologies Should not be Considered Commercially Available for Treating FGD Wastewater The technology EPA prop oses for FGD wastewater treatment in Option 5 is based on chemical precipitation in combination with vapor

- compression evaporation. There are currently only five plants using this technology for treating FGD wastewater, one in the U.S. and four in Italy. T he installation of a brine concentrator system at Duke Energy’s Mayo plant is still under construction.
As discussed in UWAG’s comments 5 , there have only been a few ZLD systems applied to coal

fired plants, however, all of these systems have been abandoned or shut down, mostly due to operational issues encountered. UWAG goes into additional detail concerning some the operational challenges encountered at the Italian facilities, as identified through EPRI site visits. In addi tion, UWAG outlines a number of installation constraints and operational issues encountered at the one U.S. plant that is currently operating this technology.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 29 The vapor

- compression evaporation technology is certainly not a “one size fits all” option and sh ould not be considered commercially available for treating FGD wastewater.
ZLD Systems are Extremely Expensive and Have High O&M Costs The ZLD technology requires the use of very expensive and exotic materials for construction of these systems due to the c orrosive nature of the process. In addition, the chemicals used in the process are estimated to cost $17 million annually 6 and would require several highly skilled operations and maintenance staff familiar with this technology. The estimated cost for a full thermal ZLD system is over $200 million with total O&M costs estimated around $19 million annually. A partial ZLD treatment system is under construction at Duke Energy’s Mayo Station. The cost for this partial system, which does not include the chemical precipitation pre

- treatment and does not evaporate the brine solution completely to crystals, is around $100 million in capital.
Vendor and Material Constraints Similar to biological treatment technologies and in contrast to c hemical precipitation, there are a limited number of technology providers that have successful vapor

- compression evaporation systems still in service for FGD wastewater. Currently, there are only two power plants in the United States operating with this ty pe of system, with one of them under construction at Duke Energy’s Mayo Station. These systems also require exotic (as expensive) materials such as Hastelloy and titanium due to the corrosive nature of the process. These exotic materials are in limited sup ply and even where the best metals are used, it is likely that corrosion will occur eventually. Due to vendor and material constraints, Duke Energy believes it would take significantly longer than 10 years for full implementation of this technology across the industry.
ZLD Systems Have a Large Parasitic Load The vapor

- compression evaporation technology generates a brine concentrate that may require up to 2 MW of parasitic load per 100 gpm treated. Duke Energy’s Mayo Station’s brine concentrator system, which is still under construction, is designed with an auxiliary electrical load and steam usage with an expected average total impact of 1.3 MW. The total impact can be as high as 3 MW at full capacity and design conditions. Further processing of the conc entrate through the crystallization process requires an even greater amount of power consumption. Parasitic loads not only add to the overall cost of removal, but require significant additional combustion of coal to maintain an equivalent net generation to meet customer needs. Disposal of Solids Generated The solid waste generated from ZLD systems can present challenging disposal issues. Depending on the design, some ZLD systems generate a hygroscopic salt which tends to melt down in a very short time perio d and absorb moisture from the air. This could result in chlorides, and other substances, ending up in leachate if this solid waste is landfilled without first stabilizing the chloride salts. Given the physical properties of the ZLD material, as well as lo ng
- term issues in the landfill, further research is needed to ensure that ZLD materials remain solid and are stableEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 30 in the landfill. The technology to permanently sequester or immobilize the constituents in the crystalline matrix is not well proven and no t economically viable at this juncture.

5 Utility Water Act Group (UWAG) Comments on the Proposed Revisions to the Steam Electric Effluent Limitation Guidelines, Section VI, L., September 20, 2013.

6 Id. Comment Response:
The commenter’s statements foc us on “Zero Liquid Discharge (ZLD) technologies.” The proposed rule did not include “ZLD technology” as the technology basis for any limitations or standards, and the final rule does not establish limitations or standards based on “ZLD technology.” EPA ass umes, based on other statements by the commenter, that the commenter is using the term “ZLD technology” to refer to technology basis applicable to FGD wastewater in proposed Option 5 (Option F for the final rule), which is evaporation. EPA disagrees with t he commenter’s apparent equating of evaporation technology with “ZLD technology.” The technology basis for control of FGD wastewater discharges under these options is evaporation. That technology basis does not necessarily achieve zero liquid discharge bec ause it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge f ashion, for regulatory options based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding the commenter ’s statements relating to the commercial availability of evaporation technology and the commenter’s reference to UWAG’s discussion of installation or operational “constraints” or “challenges” associated with the technology, see response to DCN EPA

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- 31 generation of hygroscopic materials and the issues associated with their disposal, which is why the evaporation technology basis evaluated by EPA included the chemical precipitation and softening pretreatment steps along with a c rystallizer. The pretreatment ensures that the calcium and magnesium present in the FGD wastewater is precipitated out of the solution as calcium carbonate, magnesium carbonate, or magnesium hydroxide. These constituents can then be removed prior to the br ine concentrator and crystallizer. The result of these pretreatment steps is that the primary salt generated by the evaporation system is sodium chloride, which does not have the disposal issues identified by the commenter. For these reasons, the evaporati on technology that forms the basis for the final limitations and standards (BAT limitations in the voluntary program and NSPS/PSNS) does not generate the hygroscopic material that the commenter is referring to, and EPA has accounted for the costs to crysta llize the solids as sodium chloride.

Commenter Name: Ron Shipman Commenter Affiliation: Georgia Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 26 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Zero Liquid Discharge (ZLD) Technologies Are Still Being Evaluated And May Create Disposal Issues. The technology basis for FGD wastewater treatment in Option 5 of EPA's Proposed ELGs is chemical precipitat ion in combination with vapor compression evaporation, a thermal ZLD system. EPA claims this technology is commercially available for treatment of FGD wastewater for the very stringent proposed limits. But thermal ZLD is not a fully demonstrated technolo gy and is not commercially available at this time to meet the proposed limits. Kansas City Power and Light's Iatan facility currently uses a ZLD system for FGD wastewater treatment. However, their system is not a zero discharge system because the wastewa ter effluent discharged from the system is used to condition the plant's fly ash before landfill disposal. 1 PSNH's Merrimack Station recently installed a full thermal ZLD system for FGD wastewater treatment. ZLD systems installed at other United States fa cilities

- Cayuga power plant, the Centralia Big Hanaford Plant, and Millikin Station

- have been abandoned or shut down. Also, the City of Springfield, Illinois never installed the ZLD equipment that it purchased for its Dallman Generating Station.
ZLD s ystem solid wastes can be challenging to manage for disposal. For instance, some ZLD treatment system designs produce a hygroscopic salt that is composed mainly of calcium chloride and magnesium chloride hydrate. Nebrig, H.A., Teng, Xinjun, and Downs, Da vid, Preliminary Assessment of a Thermal Zero Liquid Discharge Strategy for Coal

Fired Power Plants, presented at the International Water Conference, November 13

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- 32 (Nebrig eta!. 2011). Because these salts are hygroscopic, they tend t o melt down in a short time (minutes to hours), and, if they are landfilled, special equipment or procedures may be necessary. Depending on the type of coal burned and other factors, the salt generated by the ZLD process may have a high amount of selenium in the final solid generated. Treating and disposing of these solids could be technically difficult and very costly.

1 EPA is apparently referring to Iatan when it notes that a sampled plant, instead of having a crystallizer, "mixes the brine with fly a sh and sends it to the landfill for disposal." 78 Fed. Reg. at 34,488 col. 2. This type of partial ZLD system would be unworkable at many plants. Unless the plant is landfilling large amounts of ash, the partial ZLD system could produce more wastewater than could be used for ash conditioning. This is a particular concern for those facilities that sell ash for beneficial use. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “thermal ZLD technology,” as discussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid dischar ge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid disch arge fashion, for regulatory options based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding the dem onstration and availability of the evaporation technology, see response to DCN EPA

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- A3, Excerpt Number 45. The commenter also states that the salt generated from the evaporation process “may have a high amount of selenium in the final solid generated” and that disposing of the solids “could be difficult and very costly.” EPA notes that the commenter does not provide any data to support these speculative claims. In addition, the final rule does not establish BAT limitations for FGD wastewater discharges based on the evaporation technology (except in the voluntary program, where the plant would opt to be subject to these limitations). While the rule does establish NSPS/PSNS based on evaporation technology, plants can consider any factors that might lead to high selenium levels in the solids generated in planning for the design and ope ration of the new source.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 3 3 Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 119 External Review Flag: No External Review External Review Inco rporated into Response: No Comment Excerpt:

m. ZLD Technology for FGD Wastewater Treatment Is Not Reliable Enough For the Power Industry In practice, ZLD systems for FGD wastewater suffer from poor reliability and will affect the overall reliability of the power facility. For example, if each of the four major components of a ZLD system operates at 95% availability, the total availability for the system will drop to approximately 81%, which is unacceptable. Power plant operators typically seek and proc ure new pollution control process systems with availability guarantees greater than 98%. Neither of the two thermal ZLD system suppliers is likely to guarantee system availability at this level.

n. ZLD Process for FGD Wastewater is Not a Proven, Mature Technology In virtually every complex mechanical system, the initial versions proved to be maintenance

intensive and expensive. For use of ZLD technology for FGD wastewater, the equipment vendors claim a mature technology, but the data do not support tha t claim. Given the specifications for types of pumps, piping arrangement, strainers, volume of control tanks, heat transfer surfaces, and metallurgy among vendors of ZLD equipment, it is clear that each system is unique to its vendor. With the many variab les these systems must deal with, it would be a very poor decision for any industry to install a system that is not mature, robust, and reliable. Power systems in the United States are among the most reliable processes in the world. This was not accompli shed in a few years. It took many years to develop efficient turbines, boilers, and generators, and these are only the primary parts of the power station. Power plants use thousands of other systems to support, monitor, and operate this equipment. To ma nage ZLD for FGD wastewater

– considering all of the processes connected to these systems and the constant variables during power plant operation

– is simply not reasonable at this time.
4. Conclusion on ZLD It is true that some companies operate ZLD sy stems successfully, and this may be possible, for example, in a hot, dry climate where it is easier to evaporate wastewater. But that does not mean that ZLD can be accomplished at every or even most sites. Given the many difficulties of ZLDEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 34 systems (as a pplied to FGD wastewater) outlined above, EPA should not mandate this technology for any power plant. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology,” as discussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge because it generates a distil late/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory opt ions based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. EPA agrees in part with the commenter that the re liability of the evaporation system is currently reported to be 95 percent. For this reason, EPA’s cost estimates include costs to account for additional redundancy in the system for potential breakdowns and the need for periodic cleaning. Regarding the co mmenter’s statement that evaporation technology is not “proven,” see preamble Section VIII and the response to DCN EPA

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- fired power plants in Italy are treat ing FGD wastewater with vapor
- compression evaporation systems. Two other plants in Italy also installed evaporation systems but subsequently determined that off

- site disposal was more economical for those sites. Moreover, it is not the “maturity” of the te chnology that matters, but rather whether the technology is technologically available and achievable. As EPA has explained in the preamble and in these responses to comments, evaporation technology meets these requirements. EPA disagrees with the commente r’s statement that evaporation technology cannot be implemented across different sites, including those in climates that are not hot and dry. For example, the Merrimack Station in New Hampshire operates an evaporation system. Similar systems manufactured b y GE currently operate at oil and gas extraction sites in Canada. Evaporation technology based on seeded falling

- film evaporators are covered systems, unlike evaporation ponds used in hot, arid climates, and they do not depend on outside conditions to oper ate. Finally, despite the commenter’s statements, the final rule does not “mandate” the use of evaporation technology or any technology. The final rules establishes limitations and standards applicable to the discharge of pollutants from the steam electric power generating industry. While the final rules does not establish BAT limitations or PSES applicable to FGD wastewater discharges from all existing steam electric power generating units based on evaporation technology, the rule does establish BAT limit ations for plants who opt into theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 35 voluntary incentives program (see preamble Section VIII.C.13). The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharges based on evaporation technology, for the reasons explained in preamble Sect ions VIII.D and F.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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K. Zero Liquid Discharge (ZLD) Technologies Are Not Fully Demonstrated The technology basis for FGD wastewater treatment in Option 5 of EPA’s proposed ELGs is chemical precipitation in combination with vapor compress ion evaporation, a thermal ZLD system. One U.S. plant and four Italian plants are currently operating this technology in an FGD wastewater application. A second U.S. plant is presently installing a vapor

- compression evaporation system to treat its FGD wa stewater. EPA claims this technology is commercially available for treatment of FGD wastewater to the very stringent proposed limits. 78 Fed. Reg. at 34,452 col. 2; 2013 TDD at 13

- 19. But thermal ZLD is not a fully demonstrated technology and is not comm ercially available to meet the proposed limits. There are many operational issues associated with brine concentrators/evaporators when used to treat FGD wastewater. We discuss these operational issues below.
1. There Are Few ZLD Installations for FGD Wastewater ZLD systems for FGD are not common in the United States. Since 1970, only a few ZLD systems have been applied to coal

- fired power plants. Nebrig, H.A., Teng, Xinjun, and Downs, David, “Preliminary Assessment of a Thermal Zero Liquid Discharge Strategy for Coal

- Fired Power Plants,” presented at the International Water Conference, November 13

- 17, 2011 at 2 (Nebrig et al. 2011). One United States power plant, Kansas City Power and Light’s Iatan facility, is using a ZLD system for FGD wastewater treatment (though Iatan does not include a crystallization stage). Iatan’s system is not truly “zero liquid discharge” because the concentrated wastewater that exits the ZLD treatment system is used to condition Iatan’s fly ash before disposal in a landfi ll. 61 PSNH’s Merrimack Station recently installed a full thermal ZLD system for FGD wastewater treatment. While other United States facilities, such as the Cayuga power plant, the CentraliaEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 36 Big Hanaford Plant, and Millikin Station, operated ZLD systems fo r FGD wastewater in the past , all previous ZLD systems have been abandoned or shut down. The City of Springfield, Illinois, purchased thermal ZLD equipment for its Dallman Generating Station but never installed it. In Italy, there are a handful of so

- call ed ZLD systems used for FGD wastewater. Reportedly, some of the Italian facilities have had operational difficulties with their ZLD systems. Also, it is not clear to what extent the coal characteristics of the raw coal feedstock make a difference in the ability of the Italian facilities to manage their ZLD systems. The applications in Italy are small. Brindisi, the biggest Italian thermal ZLD, has a capacity of approximately 600 gpm (140 m 3 /hr). See Rao, M.N. and S. Donadono, “ZLD Systems Installed for ENEL Power Plants in Italy,” presented at the International Water Conference, Paper IWC

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- 2178 (Rao et al. 2008). The solid wastes from the ZLD treatment system are shipped to Germany for mine refill (Nebrig et al. 201 1).
2. Review of Italian Thermal ZLD Systems by EPRI In Italy, there are six softened FGD wastewater treatment systems, including Brindisi. EPRI has visited a number of these facilities. Aquatech designed five of these facilities, and the sixth was d esigned by HPD. Not all of the sites are in regular operation. Apparently, these facilities have some freedom in determining when and if to use the installed systems to treat FGD wastewater. Also, the capacity factors for these plants are relatively low

. For some plants, ENEL, the operator, has elected to transport the wastewater to industrial water treatment plants in lieu of operating the installed thermal ZLD system. We found only two sites that consistently and reliably treat their FGD wastewater wi th thermal ZLD systems: the Brindisi and Mon Falcone facilities. The Brindisi system as designed by Aquatech treats 628 gpm of FGD wastewater. HPD designed the Mon Falcone system, and it treats 35 gpm of FGD wastewater. Both sites have softening system s that desaturate and soften the FGD wastewater prior to evaporation/crystallization/pressure filtration to produce a more stable salt. Both plants bag the salt byproduct and transport it a great distance to be placed in a salt mine permitted for disposal of hazardous waste material. While indications are these two systems are performing as designed, no capital or operating costs have been reported. EPRI’s 2010 report noted that the physical/chemical equipment supporting these ZLD systems had gone through significant modifications in the years since the thermal ZLD equipment was first installed. These modifications were necessary to overcome challenges of scaling, corrosion, and other challenges specific to each site.
Given what EPRI and others within th e industry have learned through direct communications with thermal ZLD operators, UWAG is skeptical of any claims by system suppliers concerning the performance and reliability of thermal ZLD systems.
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- 37 Research on and experience with ZLD FGD treatment systems show they have many difficulties and operational uncertainties. Much of the uncertainty is due to the high variability in FGD wastewater constituents. A recent paper n otes: Scrubber effluent chemistry is complex in that a large number of elements are present and the effluent composition constantly varies with coal and limestone composition. Important process liquid characteristics that affect corrosivity of typical ZLD materials include chloride concentration, pH, dissolved oxygen, and fluoride concentration. Nebrig et al. 2011 at 10. Because FGD wastewater is so corrosive, engineers evaluating ZLD technology have to either choose exotic (and expensive) metal components or plan for continual replacement of parts and the associated downtime for repairs. Corrosion will eventually occur even where the best metals are used. Even when a ZLD system is operating without major upsets, it will require extensive and continual mai ntenance. As Nebrig et al. note: Both the brine concentrator and the crystallizer will scale. Calcium sulfate formation on the evaporation tubes in the brine concentrator is the primary scale in the brine concentrator. The formation of the scale reduces heat transfer and results in loss of capacity in the unit. . . . Most vendors recommend cleaning the brine concentrator at least once a year. More frequent cleaning may be necessary, but the down time will reduce the amount of water that can be processed

. Id. at 11. One UWAG member has installed a ZLD system consisting of an evaporator and crystallizers to treat a power station’s wet scrubber blowdown stream. Part of the new ZLD equipment had to be indoors, and space onsite for a new building was limited. The company hoped to use steam from the main unit to heat the evaporator and crystallizer; but, because of distance and cost, a small dedicated boiler had to be provided for the evaporations system in the new ZLD building. Because the fly ash sil o was near the generating unit with road access between the unit and the new ZLD building, all piping between the fly ash silo and ZLD building was installed in underground trenches or routed through new or existing buildings. The company discovered that p H required careful monitoring and control from the FGD system through ZLD at every point where it varied. Trace elements in the phys

- chem feed stream had to be understood and controlled, because upset conditions for these elements caused chemistry imbalan ces and operational upsets. It was important to understand the quantities of these elements in the fuel and trace them through the FGD, phys

- chem, and ZLD systems. Trace elements can greatly affect the pH of various ZLD process streams as well as create compounds in the ZLD system that can agglomerate and cause maintenance and operational upsets.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 38 The pH in the phys

- chem system’s second treated effluent tank needed to be controlled to reduce scaling potential in the ZLD equipment. This presented challenge s with the phys

- chem system. Getting enough mixing in the existing tank also proved challenging. The ZLD’s falling film evaporator experienced significant pH excursions at first. An anti

- foam agent turned into a soaplike material when pH was high. This created “volcanic” foam that permeated all equipment attached to the brine concentrator. The anti

- foam agent had to be replaced with a chemical not as sensitive to pH. Elements not properly controlled in the FGD or phys

- chem system also affected pH in the evaporation system. This required proper control of the caustic feed and addition of an online pH monitoring. The ZLD’s crystallizers also showed poor pH control, which was addressed by improving caustic feed and getting better indication of pH.
Salt ca ke quantity and quality presented more challenges that needed tighter process control, including a full plant material balance. Incoming fuel constituents, which vary significantly, drastically affected the quantity of salt cake generated. The quality an d quantity of salt cake affect the throughput of the indexing belt filter. This was addressed by generating a plant

- wide material balance with special attention to fuel constituents. A softening process was required to replace calcium salts with sodium ch loride salts (which have lower solubility than calcium chloride), which allows a lower moisture content dry cake. With the original lime feed system in place, a soda ash feed system was added to meet softening needs. Through continued operations, the sof tening process was found to be sensitive to fluctuations and quantities of sulfates in the wet FGD blowdown stream. Several modifications were performed, namely optimizing the FGD purge hydrocyclones to reduce variations in sulfate concentrations; modifyi ng the phys

- chem system’s upstream equalization tank to remove more calcium sulfate solids before softening; combining sludge precipitated in the equalization tank with clarification/softening sludge and dewatering it with the existing phys

- chem equipment; and modifying the reaction tank feed inlet from the equalization tanks to receive only equalization tank overflow, filter press filtrate, and phys

- chem building sump contents. Softening targets played a critical role in the quality of the salt cake. High calcium concentrations in the feed to the ZLD (resulting from low soda ash feed) produced salt cake of poor quality. Low levels of calcium (high soda ash feed) generated compounds that agglomerated in the ZLD equipment. Careful process control and proce ss targets were needed to solve these problems. Water balance was another challenge. Water balance required tight process control. The liquid purged from the wet FGD in the blowdown stream must be treated and returned as high

- quality makeup (in addition to chemical feed dilution water and seal water) to the wet FGD as makeup. To optimize the additional chemical feed dilution water, the pumps in both the phys

chem and ZLD systems were converted to a closed

- loop seal system to eliminate unnecessary flush w ater entering the process and requiring more treatment capacity. Cooled ZLD distillate from the evaporator and crystallizers was used as the cooling water source for a condenser.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 39 In short, making a ZLD system work at this plant required overcoming many ch allenges and required joint efforts by the operator, engineer, and equipment supplier. It is not the sort of “one size fits all” technology that can be applied to power plants generally.

a. Maintaining Scrubber Blowdown Consistency is Difficult Under So me Conditions Under some conditions related to the coal being used, the salts created in the ZLD process may require a blowdown to control the level of highly soluble, high boiling point salts. Brine concentrators and ultimately the crystallizers are very sensitive to chemistry. The release of higher than expected species, or changes in salt, may increase the equipment tube temperatures and foul the heat transfer surfaces of the brine concentrator. The brine concentrator must then be taken out of service and hydro

- blasted to clean the scale from the heat transfer surfaces to avoid tube overheating and failure.
b. Maintaining Crystallizers is Also Difficult Due to Many Operational Variables Crystallizers take the brine blowdown from the brine concentrato r, add heat via a heat exchanger using plant steam, and form crystals that are dewatered and sent to a landfill. Scrubber waste crystallization is a relatively new process. Again flow variations, chemical or constituent variation, the amount of heat adde d to the system, circulation rates, and numerous mechanical elements such as tank size, finish on the tank, internals, and the types of pumps that are utilized in the system can and will have serious impacts on the success of this final step. Thus, mainta ining the crystallizer with the number of variables that change constantly is very challenging.

61 EPA is apparently referring to Iatan when it notes that a sampled plant, instead of having a crystallizer, “mixes the brine with fly ash and sends it to th e landfill for disposal.” 78 Fed. Reg. at 34,488 col. 2. This type of partial ZLD system would be unworkable at many plants. Unless the plant is landfilling large amounts of ash, the partial ZLD system could produce more wastewater than could be used fo r ash conditioning. This is a particular concern for those facilities that sell ash for beneficial reuse. Comment Response: The commenter’s statements focus on “Zero Liquid Discharge (ZLD) technologies.” The proposed rule did not include “ZLD technolog y” as the technology basis for any limitations or standards, and the final rule does not establish limitations or standards based on “ZLD technology.” EPA assumes, based on other statements by the commenter, that the commenter is using the term “ZLD techno logy” to refer to technology basis applicable to FGD wastewater in proposed Option 5 (Option F for the final rule), which is evaporation. EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology.” The technology b asis for control of FGD wastewater discharges under these options is evaporation.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 40 That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve z ero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for any options evaluating the evaporation system, EPA included numeric effluent limitatio ns and standards that allow for the discharge of the distillate/condensate streams generated by the treatment system. EPA disagrees with the commenter that the evaporation system “is not a fully demonstrated technology and is not commercially available.” E PA has determined that the technology is available because there are three plants in the U.S. that have installed and are operating the technology, and one plant that is in the process of installing the technology. In addition, four Italian plants are curr ently operating this technology in an FGD wastewater application. While EPA has determined that the technology is available, EPA did not select the evaporation system as the BAT basis for treatment of FGD wastewater discharges from all existing steam elect ric power plants for the reasons described in preamble section VIII.C.1; however, the final rule does establish a voluntary incentives program under which steam electric power plants may choose to be subject to more stringent BAT limitations for FGD wastew ater discharges based on evaporation. The voluntary incentives program is described in more detail in preamble section VIII.C.13. Moreover, the final rule establishes NSPS/PSNS applicable to FGD wastewater discharges based on evaporation technology, for th e reasons described in preamble sections VIII.D and F. EPA agrees with the commenter that evaporation systems for FGD wastewater “are not common in the United States.” However, the fact that there are not many in operation does not mean that the system is not available or proven. EPA acknowledges the commenter’s claim that the Iatan system “is not truly ‘zero liquid discharge’ because the concentrated wastewater that exits the [evaporation] system is used to condition Iatan’s fly ash before disposal in a l andfill,” but EPA notes that regardless of how the system is classified, Iatan is meeting the final limitations based on evaporation technology because the plant does not discharge FGD wastewater. EPA also agrees with the commenter’s statement that Iatan’s FGD wastewater treatment system approach “would be unworkable at many plants.” However, the approach used at Iatan is different from the approach that EPA identified as the basis for the evaporation technology option. Additionally, EPA did not use the dat a from the Iatan plant to calculate the effluent limitations and standards for the final rule. EPA acknowledges that a few plants in the past have installed evaporation systems to treat FGD wastewater which have since abandoned or shut down those systems, but EPA notes that the industry’s and vendors’ knowledge of FGD wastewater has improved immensely since those systems were installed and design of the technology has improved to account for the difficulties experienced at those plants. Regarding the Dallma n plant, the evaporation system was not installed due to continued changes to the costs, not due to operational issues. EPA also notes that Duke Energy’s Mayo plant has also installed an evaporation system and Indiana Power & Light’s Petersburg plant is al so planning to install an evaporation system. EPA disagrees with the commenter’s assessment that the evaporation system “applications in Italy are small.” As the commenter points out, Enel’s Brindisi plant, which is the plant where EPA conducted its sampli ng episode, “has a capacity of approximately 600 pgm,” which is largerEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 41 than the FGD wastewater flow rate at most plants in the United States. Additionally, even if the flow rates were smaller, the fact that the technology can treat the FGD wastewater demon strates that the system is available, and the size of the system does not matter because the system design can be scaled and designed to accommodate different flow rates. EPA agrees with the commenter that “[f]or some plants, ENEL, the [Italian] operator, has elected to transport the wastewater to industrial water treatment plants in lieu of operating” the installed evaporation system. However, during EPA’s visit to Italy to conduct the sampling episode, EPA learned that Enel had decided to transfer the FGD wastewater to off

- site treatment instead of operating the evaporation system due to costs, not due to operational issues with the system. EPA notes that this practice is similar to plants in the United States who transfer wastewater to a Centralized Waste Treatment (CWT) facility.
The commenter states that it is “not clear to what extent the coal characteristics of the raw coal feedstock make a difference in the ability of the Italian facilities to manage” their evaporation systems. EPA notes that the comm enter has provided or referenced no data that demonstrates that U.S. facilities could not manage their evaporation systems in the same manner as Italian facilities because the coal feedstock might be different. The commenter states that the “physical/chemi cal equipment supporting these [Italian evaporation] systems had gone through significant modification in the years since the [evaporation] equipment was first installed.” EPA agrees that modifications were made to the system, as determined during EPA’s si te visits; however, EPA would not consider the modifications “significant” and considers the types of modifications similar to modifications it would expect plants to make to optimize the performance of a treatment system after initial installation/operati on. EPA agrees with the commenter that exotic alloys are needed in the construction of an evaporation system due to the corrosive nature of the FGD wastewater. Wetted parts of the system must be manufactured with titanium alloys to withstand high chloride concentrations in the concentrated FGD wastewater and these types of alloys can add capital expense to the system and also O&M costs associated with replacement parts needed for maintenance. Because of these issues, EPA revised its estimates for the annu al maintenance equipment and labor to be based on six percent of the total equipment cost. See the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Ca tegory (Cost & Loads Report) (DCN SE05831/SE05832) for additional discussion of EPA’s cost estimates. EPA acknowledges the commenter’s statement that the “brine concentrator and the crystallizer will scale.” However, EPA notes that the evaporation system t hat it considered in its cost estimates can be operated with a seeded slurry that provides nucleation seed crystals such that the salts will form on the seed crystals instead of on the heat transfer tubing. Using a seeded system will minimize the amount of blow downs required, but EPA agrees that some cleaning will still be required on an occasional basis. See TDD section 7 for additional details on the operation of the evaporation technology.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 42 The commenter provides several examples of changes, modifications, and “challenges” that arose for one of its members during the installation and operation of the evaporation system at a plant. EPA notes that none the items identified by the commenter were not resolved, and the plant is now operating the ev aporation system. EPA is also not surprised that the plant faced the identified “challenges.” While evaporation technology may not be simple, with proper design and operation, the system can be operated to treat FGD wastewater. EPA agrees with the commente r that the evaporation system is not a “one size fits all” technology and that each plant employing the technology would require that the system be designed for its specific operation. EPA does not contend that an evaporation system can simply be pulled of f the shelf and expected to perform at any given power plant. The system must be designed and operated to treat the specific wastewaters generated at the plant where it is installed. The commenter argues that “[u]nder some conditions related to the coal b eing used, the salts created in the [evaporation] process may require a blowdown to control the level of highly soluble, high boiling point salts.” This comment is too vague for EPA to respond; however, EPA notes that the evaporation system included as the technology basis includes chemical precipitation and softening pretreatment, which can be tailored to target specific salts, if they are present in the FGD wastewater at a specific plant. EPA agrees with the commenter that maintaining the crystallizer can be “challenging” based on the number of changing variables. Operating an evaporation system is more challenging, for example, than operating a settling pond because it is an active treatment system instead of a passive system. However, the system can be o perated, as demonstrated by the Merrimack plant and the Italian plants.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 64 Exter nal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: APPA recognizes that several public power utilities have ZLD technology at their plants and are very pleased with their own operating conditions. Several of these ZLD plants are more than twenty years old. Comment Response: EPA thanks the commenter for submitting this information. For further information regarding the technological availability of evaporation systems, which are not always “zero liquid dis charge,” see response to DCN EPA

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- 43 Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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1. Mechanical evaporation is technologically available. EPA states that although Option 5 is not a preferred option, “the technologies are all technologically available.” 187 We strongly agree. Mechanical evaporation has been used for over 30 years in many industries, including for treatment of cooling tower blowdown and coal gasification wastewaters. According to a 2007 industry study, vapor compression and fall ing film evaporators (also known as brine concentrators) “have been the workhorse for dealing with cooling tower blowdown and other power plant wastewaters.” 188 As of 2008, there were 146 mechanical evaporation installations in the United States. 189 As d escribed in the Synapse report, 190 there are several major manufacturers of zero liquid discharge systems, including Veolia, Aquatech, and GEA Processing Engineering, GE Power and Water, and numerous smaller vendors. These products have been applied acros s a large range of industries, showing the adaptability of these systems. While FGD wastewaters have some different characteristics than these wastewaters, the industry is quickly adapting the technology for use on FGD wastewaters. The different character istics of FGD wastewater require careful pretreatment, but they do not render mechanical evaporation infeasible. 191 The main pretreatment methods are physical/chemical treatment to reduce solids, and softening, which causes “magnesium and calcium ions [to ] precipitate out of the wastewater and [be] replaced with sodium ions, producing an aqueous solution of sodium chloride that can be more effectively treated with a forced

- circulation crystallizer.” 192 Alternatively, the softening step can be eliminated al together through the use of low

- temperature vacuum crystallization, which directly crystallizes the highly soluble salts found in FGD wastewater. 193 Such “cold crystallization is a common process in industrial salt crystallization, having been widely appl ied over the last half century.” Cold crystallization has capital and energy costs comparable to current evaporation and crystallization processes, but significantly reduces expenditures for chemicals and sludge disposal costs by eliminating the softening pre
- treatment step. Mechanical evaporation treatment systems for FGD wastewater are operating at no fewer than four plants in Italy and one plant in the United States. At least two more full

- scale systems are in planning or construction stages in the Un ited States. The systems in Italy have been operating for five to seven years without any significant problems. The Enel’s Federico II plant in Brindisi, Italy has a particularly strong record of performance with a vapor compression andEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 44 crystallization s ystem, and was selected by EPA as the leading plant for setting effluent limits based on this technology. 194 The record describes in detail two other Italian plants operating mechanical evaporation systems for FGD wastewater. The Monfalcone Power Station decided in 2007 to install a system manufactured by HPD/Veolia. 195 The Torrevaldaliga Nord plant comprises three 660 MW units burning bituminous coal, and equipped with baghouses, SCR, and limestone forced oxidation wet FGD scrubber. FGD blowdown occurs w ith solids at 15

- 18 percent, and chlorides at 15,000 to 25,000 parts per million, similar to practices at plants in the United States. Both the distillate and concentrate streams are recycled back into the scrubber resulting in a zero discharge system.
Th e Kansas City Power & Light Iatan plant in Missouri is a 2

- unit, 1520 MW plant that burns low sulfur coal and discharges to the Missouri River. The FGD wastewater treatment system was designed by Aquatech and began operating in March 2009. The FGD blowdo wn is pretreated with hydrocyclones to reduce TSS concentrations from 30,000 to 20 ppm, and then treated with caustic, an antifoaming agent, and seeded calcium sulfate to prevent scaling. 196 The wastewater then enters parallel brine concentrators, which p roduce a distillate that is 85 percent of the volume FGD blowdown water

— all of which is returned to the reclaim water system. 197 The evaporation system concentrates the brine by a factor of seven.” 198 However, because there is no softening pretreatment to remove calcium and magnesium, the plant does not operate a final drying/crystallization process. Instead, the concentrate from the brine process is combined with fly ash in a pugmill and landfilled. 199 In addition to these plants where mechanical evaporation systems are already operating, similar systems are in various stages of design and construction at two coal plants in the United States: Duke Energy’s Mayo Station in North Carolina, Duke Energy’s Roxboro Station in North Carolina, and Public S ervice Company of New Hampshire’s Merrimack Station.

187 78 Fed. Reg. at 34,477.

188 EPRI 2007, Docket No. EPA

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189 Summary of Zero Liquid Discharge Waste Management Installations, Docket No., EPA

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190 Synapse Report, Appendix A, at 49.

191 See EPRI 2007, Docket No. EPA

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- 3 (“Due to the more concentrated nature of FGD blowdown streams plus the presence of trace metals and other pollutants in reatively high concentrati ons, common evaporation systems and processes will have to be modified to accommodate the characteristics of the FGD waters.”).

192 TDD at 7

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- 45 193 Shaw, William A., Low Temperature Crystallization Process is the Key to ZLD Without Chemical Conditioning, IWC

- 10

- 39, at 479.

194 TDD at 13

- 19.

195 Press Release, Sept. 22, 2009, HPD awarded Flue Gas desulfurization (FGD) Effluent treatment for Monfalcone coal

- fired generating station. The system involves a clarification and softening pretreatment to remove sol ids, calcium, magnesium, and heavy metals followed by falling film evaporation, and brine crystallization. The plant burns a Russian bituminous coal with a sulfur content between 0.3 and 0.4 percent. Final Monfalcone Site Visit Notes, Docket No. EPA

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196 Iatan Final Site Visit Notes, Docket No. EPA

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197 See Written responses to EPA questions regarding the evaporation system for treating FGD wastewater [EPA

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198 Final Iatan Site Visit Notes , Docket No. EPA

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199 See Written responses to EPA questions regarding the evaporation system for treating FGD wastewater, Docket No. EPA

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- 0517, DCN 06287A4. The only operational problems identified with this syste m resulted from injecting water with over four times the design TDS value of 15,000 ppm. Comment Response: EPA agrees with the commenter that the evaporation system is technologically available, as further described in preamble Section VIII and in respon se to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 56 External Review Flag: No External Review E xternal Review Incorporated into Response: No Comment Excerpt: At Merrimack Station in New Hampshire, Public Service Company of New Hampshire (“PSNH”) chose to install an Aquatech zero liquid discharge (“ZLD”) system, even while EPA Region 1 was still co nsidering a biological treatment system to be BAT. 205 That PSNH did so is a testament to the proven technological feasibility of such systems. On November 17, 2010, PSNH hired Burns & Macdonald to provide technical assistance on the ZLD project, based onEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 46 that firm’s experience at the one other ZLD project in the United States, presumably the Iatan Station. 206 Burns & Macdonald “concluded the installation of a brine concentrator, crystallizer would reduce the liquid waste stream to between zero to five gpm, which may allow for re

- use and an additional crystallizer, and dewatering device will be installed to insure zero discharge.” 207 Once PSNH had decided to proceed with a ZLD system, the process moved quickly. A request for proposal for equipment was released in early January 2011, and by February 3, 2011, a purchase order had been opened with Aquatech. 208 An RFP fo r construction was released in spring 2011. 209 PSNH completed commissioning, testing, and performance demonstration of the zero discharge technology in June 2012, and the system went into service on June 21, 2012. This mechanical evaporation system has t herefore been in service for over a year. 210 This experience demonstrates that mechanical evaporation is technologically feasible for treatment of FGD wastewater. Not only is it in use at a half

- dozen plants, but the performance of the system at those pla nts has sufficiently impressed two other plants in the United States to install mechanical evaporation systems.

205 See Investigation of PSNH Installation and Cost Recovery of Scrubber Technology at Merrimack Station, Final Report of Jacobs Consultancy (2012), at 15

- 17. Merrimack Station is a two

- unit, 458 MW plant burning eastern bituminous coal.

206 See Jacobs Consultancy, Redacted New Hampshire Clean Air Project Due Diligence on Completed Portion (2011) at 67.

207 Id.

208 Id.

209 Id.

210 PSNH Progres s Report, Merrimack Station Scrubber Project, June 28, 2012, Docket No. DE 11

- 250, at 2, Exhibit FGD

- 21. Comment Response: EPA agrees with the commenter that the evaporation system is technologically available and feasible, as further described in preamb le Section VIII and in response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number: EPA

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- 47 Comment Excer pt Number: 38 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: PSNH’s Merrimack Station is one of only two facilities in the United States that utilizes some form of vapor compression technology to treat FGD effluent. 17 PSNH was left with no choice but to construct its reduced liquid secondary FGD waste water treatment system (“SWWTS”) at Merrimack Station in late 2011. Specifically, New Hampshire state law (RSA 125

- O:11 et seq.) required PSNH to in stall a scrubber at the facility by a date certain. In anticipation of this requirement, PSNH approached EPA Region 1 who directed PSNH to work with the New Hampshire Department of Environmental Services (“DES”) to analyze the discharge and determine wat er quality impacts. Working cooperatively with PSNH for over a year, DES completed an antidegradation review and submitted a detailed monitoring and compliance proposal to EPA. PSNH and DES met with EPA to determine permitting options based upon the DES pr oposal that would account for the station’s need to treat and dispose of the relatively minor volume of the FGD waste stream. Unfortunately, Region 1 chose not to work with DES and PSNH. This inaction by the agency forced PSNH to immediately develop an alt ernative option for disposing of the FGD waste stream. The only available technological option for handling the FGD waste water from Merrimack Station

— absent authority under an EPA

- issued NPDES permit

— was for PSNH to reduce or eliminate its FGD effluent vo lume significantly so that PSNH could then dispose of the effluent in a cost

- effective manner. The need for a supplemental system to the physical/chemical treatment process was critical given that PSNH’s customers would experience significant financial ram ifications if the start

- up of the scrubber was delayed and, most importantly, PSNH would be in violation of a state law with severe penalties if it failed to bring the scrubber into service in a timely manner. Accordingly, PSNH had no other choice but to i nstall the SWWTS.
17 Importantly, despite its common moniker, ZLD technologies still generate various waste streams that must be managed. Comment Response: As indicated by the installation and operation of the evaporation system at the Merrimack plant, the evaporation system is technologically available for the treatment of FGD wastewater. Additionally, the installation and operation of the system indicates that the system was also economically achievable specifically for the Merrimack plant. However, E PA has not selected evaporation as the basis for BAT limitations for FGD wastewater discharges from all existing steam electric power generating units for the reasons discussed in section VIII.C.1 of the preamble. The final rule does establish a voluntary incentives program for existing plants that choose to be subject to BAT limitations for FGD wastewater discharges based on evaporation (see section VIII.C.13 of the preamble). The final rule also establishes NSPS/PSNS for FGD wastewater discharges based o n evaporation, for the reasons described in sections VIII.D and F of the preamble.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 48 EPA agrees with the commenter that evaporation technology is not necessarily “zero liquid discharge” for reasons explained elsewhere in these responses to comments.

Commen ter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 73 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Zero Liquid Discharge (ZLD) Technologies Are Not Fully Demonstrated The technology basis for FGD wastewater treatment in Option 5 of EPA’s proposed ELGs is chemical precipitation in combination with vapor compression evaporation, a thermal ZLD system. One U.S. plant and four Italian plants are currently operating this technology in an FGD wastewater application. A second U.S. plant is presently installing a vapor

- compression evaporation system to treat its FGD wastewater. EPA claims this technology is comm ercially available for treatment of FGD wastewater to the very stringent proposed limits. 2013 TDD p. 13

- 5. However, thermal ZLD is not a fully demonstrated technology and is not commercially available to meet the proposed limits. There are many operationa l issues associated with brine concentrators/evaporators when used to treat FGD wastewater. We discuss these operational issues below.
a. There are Few ZLD Installations for FGD Wastewater ZLD systems for FGD are not common in the U.S. Since 1970, there ha ve only been a few ZLD systems applied to coal

- fired power plants. Nebrig, H.A., X. Teng, and D. Downs, Preliminary Assessment of a Thermal Zero Liquid Discharge Strategy for Coal

- Fired Power Plants, presented at the International Water Conference, Novembe r 13

- 17, 2011 at 2 (Nebrig et al. 2011). One United States power plant, Kansas City Power and Light’s Iatan facility, is using a ZLD system for FGD wastewater treatment (though Iatan does not include a crystallization stage). Iatan’s system is not truly “z ero liquid discharge” because the concentrated wastewater that exits the ZLD treatment system is used to condition Iatan’s fly ash before disposal in a landfill. 30 In addition, PSNH’s Merrimack Station recently installed a full thermal ZLD system for FGD w astewater treatment. While other United States facilities, such as the Cayuga power plant, the Centralia Big Hanaford Plant, and Millikin Station, operated ZLD systems for FGD wastewater in the past , all previous ZLD systems have been abandoned or shut dow n. The City of Springfield, Illinois, purchased thermal ZLD equipment for its Dallman Generating Station, but never installed it.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 49 In Italy, there are a handful of so

- called ZLD systems used for FGD wastewater. Reportedly, some of the Italian facilities hav e had operational difficulties with their ZLD systems. Also, it is not clear to what extent the coal characteristics of the raw coal feedstock make a difference in the ability of the Italian facilities to manage their ZLD systems. Brindisi, the biggest Ita lian thermal ZLD, has a capacity of approximately 600 gpm (140 m3/hr). See M.N. Rao and S. Donadono, “ZLD Systems Installed for ENEL Power Plants in Italy”, presented at the International Water Conference, Paper IWC

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- site disposal of the solids in a landfill is prohibited by the Italian government. The solid wastes from the ZLD treatment system are shipped to Germany for mine refill. (Neb rig et al. 2011). b. ZLD Systems Used for FGD Wastewater Treatment Create Operational Problems Research on and experience with ZLD FGD treatment systems show they have many difficulties and operational uncertainties. Much of the uncertainty is due to the h igh variability in FGD wastewater constituents. A recent paper notes: Scrubber effluent chemistry is complex in that a large number of elements are present and the effluent composition constantly varies with coal and limestone composition. Important process liquid characteristics that affect corrosivity of typical ZLD materials include chloride concentration, pH, dissolved oxygen, and fluoride concentration. Nebrig et al. 2011 at 10. Also, of particular consequence to thermal ZLD systems, the FGD wast ewater can still contain a significant amount of calcium sulfate or calcium sulfite. Because FGD wastewater is so corrosive, engineers evaluating ZLD technology have to either choose exotic (and expensive) metal components or plan for continual replacement of parts and the associated downtime for repairs. Even where the best metals are used, it is likely that corrosion will eventually occur. Even when a ZLD system is operating without major upsets, it will require extensive and continual maintenance. As Neb rig et al. note: Both the brine concentrator and the crystallizer will scale. Calcium sulfate formation on the evaporation tubes in the brine concentrator is the primary scale in the brine concentrator. The formation of the scale reduces heat transfer and results in loss of capacity in the unit. . . . Most vendors recommend cleaning the brine concentrator at least once a year. More frequent cleaning may be necessary, but the down time will reduce the amount of water that can be processed.
Id. at 11.
To date , the electric utility industry has had little operational experience with brine concentrator and evaporator systems. The issue of scaling during long

- term operation is not yet defined, much less solved technically. c. Maintaining Scrubber Blowdown Consist ency is Difficult Under Some ConditionsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 50 Under some conditions related to the coal being used, the salts created in the ZLD process may require a blowdown to control the level of highly soluble, high boiling point salts. This would be a new waste stream tha t may have to be managed as a hazardous waste at a large additional cost to the facility. Brine concentrators and ultimately the crystallizers are very sensitive to chemistry. The release of higher than expected species or change in salt may increase the e quipment tube temperatures and foul the heat transfer surfaces of the brine concentrator. The brine concentrator then must be taken out of service and hydro

- blasted to clean the scale from the heat transfer surfaces to avoid tube overheating and failure, w hich creates more liquid waste to deal with. d. Maintaining Crystallizers is Also Difficult Due to Many Operational Variables Crystallizers take the brine blowdown from the brine concentrator, add heat via a heat exchanger utilizing plant steam, and form c rystals that are dewatered and sent to a landfill. Scrubber waste crystallization is a relatively new process. Again flow variations, chemical or constituent variation, amount of heat added to the system, circulation rates, and numerous mechanical element s such as tank size, finish on the tank, internals, and the types of pumps that are utilized in the system can and will have serious impacts on the success of this final step. This is the last chance the operator has to form a crystal that is structurally compatible with the next phase of the ZLD process, which is dewatering. Maintaining the crystallizer with the number of variables that change constantly is challenging, and current installation data clearly show that this process is not viable for a consta nt reliable solution. Comment Response: See response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number: EPA

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- A1 Comment Excerpt Number: 41 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA claims thermal ZLD is commercially available for treatment of FGD waste water despite the fact that only six steam electric generating facilities on the planet currently utilize it to varying degrees. In actual fact, thermal ZLD is not a fully demonstrated technology for the industry as a whole. Accordingly, it cannot constitute BAT for the treatment of FGD w aste water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 51 In addition to Merrimack Station’s thermal ZLD system, only one United States power plant

— Kansas City Power and Light’s (“KCPL”) Iatan facility

— is currently using a ZLD system to treat FGD waste water treatment. 18 And even KCPL’s system doe s not actually achieve a “zero liquid discharge” because Iatan does not utilize a crystallizer and, instead, returns concentrated waste water exiting the ZLD treatment system to the plant’s fly ash treatment system in order to condition Iatan’s fly ash bef ore disposal in a landfill. Moreover, the Iatan facility and PSNH’s Merrimack Station are incredibly dissimilar and provide a preview of the issues that would occur within the industry if EPA tried to impose this technology as BAT. For instance, the Iatan Station has a 140 acre landfill on site and is authorized to dispose of 2,000 tons of fly ash and gypsum per day. Therefore, Iatan is able to dispose of large quantities of the brine concentrate/fly ash solid waste mixture generated by the FGD waste water thermal dewatering system. Merrimack Station does not have on

- site landfill capability to dispose of the ash based solid wastes generated by the SWWTS process. This means that PSNH, if it had in place a system like Iatan, would have to continuously fill tr ucks with the reduced liquid and dewatered solid material by

product and transport it for disposal. This implicates several BAT factors, including the cost of achieving the reduction and the engineering aspects of the application of this control technique. Iatan also uses Powder River Basin coal as its primary fuel source. This is significant, because Powder River Basin coal produces much more fly ash than Eastern Bituminous coal or similar coals. Because Iatan is the only other facility employing this tech nology, the fact that a different fuel source is used makes it exceedingly difficult for EPA to use information from Iatan and Merrimack Station to assess the feasibility of imposing this technological standard on the industry as a whole. In the end, there is simply insufficient evidence that this technology can effectively be transferred from site to site within the industry. Separately, EPA makes much of the small number of FGD treatment systems in Italy that utilize a version of the ZLD technology, but t hose Italian ZLD systems are not a reasonable benchmark for what utilities in the United States would face from cost, operational, and compliance perspectives. EPRI visited these Italian facilities in 2010 and UWAG outlines the significant EPRI discoveries from that investigation. See UWAG Comments at Section VI., L. Specifically, EPRI found that the Italian ZLD applications are much smaller in scale than those which would be required to treat the FGD waste water at U.S. coal

- fired plants. Additionally, not all of them are in regular operation, as the law of Italy permits plant operators some freedom as to when these systems must be online, and some facilities utilizing this technology have been shut down. Moreover, some of these facilities do not consistent ly treat their effluent with ZLD thermal systems. Instead, they transport the waste water to industrial water treatment plants. Lastly, these Italian facilities are subject to different waste disposal requirements than those applicable to facilities in the United States. They ship the solid byproduct to Germany for use as refill material for salt mines permitted for disposal of hazardous waste material. EPRI’s study provides compelling evidence that EPA should approach imposing thermal ZLD systems upon the industry with great skepticism. 18 Other United States facilities, such as the Cayuga power plant, the Centralia Big Hanaford Plant, and Millikin Station, operated ZLD systems for FGD wastewater at some point in the past. However, each such system has eith er been abandoned or shut down. Additionally, the City of Springfield, Illinois, purchased thermal ZLD equipment for its Dallman Generating Station butEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 52 never installed it.

Comment Response: See response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Af

filiation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 46 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
1. Applications of ZLD Sy stems are Extremely Limited and are Otherwise Not Useful in Evaluating the Availability of ZLD Technology ZLD systems for FGD wastewater treatment are not common in the electric utility industry. Only a handful of these systems have ever been applied to coal

- fired power plants at various points in time. In the United States, only Public Service Company of New Hampshire’s Merrimack Station and Kansas City Power and Light’s (“KCPL”) Iatan facility are currently using some form of ZLD system to treat FGD was tewater treatment. And even KCPL’s system does not actually achieve a “zero liquid discharge” because at Iatan, the concentrated wastewater exiting the ZLD treatment system is returned to the plant’s fly ash treatment system in order to condition Iatan’s f ly ash before disposal in a landfill.
A collection of ZLD

- type technologies have been installed in Italy, as well. EPA largely relies upon the data and operations of these foreign systems in the Draft Rule to substantiate its assertions regarding the effic acy of this technology. Unfortunately, for the reasons that follow, these foreign systems do not present a reasonable benchmark for what a coal

- fired plant in the United States could expect should it choose or be forced to install a ZLD system. The Italian ZLD applications are much smaller in scale than those that would be required to treat the FGDEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 53 wastewater at facilities within the United States. Also, the Italian facilities are free to utilize the ZLD technology at their leisure, as applicable laws provi de them the alternative to transport these wastewaters to a treatment plant. Their disposal methods differ, as well. Italian facilities may not deposit solids in an on

- site landfill. Instead, they must ship them elsewhere, meaning they do not need to accou nt for managing this additional solid waste stream and infrastructure that facilities in the United States would be required to manage should they employ a ZLD system along with a chemical precipitation treatment system.
2. Operational Challenges of ZLD Sy stems EPA’s conclusion that ZLD is a commercially available technology is also premised on an incomplete evaluation of the technical and operational issues associated with this technology. In fact, research and the limited experience the power industry has with ZLD systems reveals that there are a number of problems that an operator can expect to experience with ZLD systems, and numerous modifications to existing plant infrastructure will be necessary in order to accommodate the additional system. Had EPA g iven more than glancing consideration to the operating requirements and challenges associated with a ZLD system, it could not have reasonably concluded that this is a commercially available or technologically feasible technology. UWAG discusses at length t he known or inevitable operational issues the industry will face if ZLD as finalized as BAT for FGD wastewaters. See UWAG Comments at Section VI., L. PowerSouth supports and incorporates by reference UWAG’s extensive discussion about the shortcomings of th is technology and offers the following synopsis of the expected issues the Lowman Plant would face if forced to retrofit a ZLD system:

• FGD wastewater is inherently corrosive to metal, and the concentration levels of FGD effluent present in the waste stre am varies depending on even slight differences in the coal burned in the boiler. The corrosive nature of FGD wastewater will inevitably cause the metal components of a ZLD treatment system to wear quickly, even where the system is operated without upsets, and where equipment is made with high quality metals. The constant inspection, maintenance, and replacement of parts required for ZLD treatment systems will add capital, operating, and labor costs.

• ZLD systems require regular blowdown to clear out salt f ormations from inside the piping and other components in order to avoid further operational problems. This necessary blowdown creates another solid waste stream of corrosive, highly soluble salts. Like any waste stream, these solid salt formations will req uire an additional level of waste collection, handling, storage, and ultimately, disposal. ZLD wastes are challenging to manage for disposal. The salts produced in the ZLD treatment process are composed mainly of calcium chloride and magnesium chloride hyd rate, which tend to melt down quickly and may ultimately appear in landfill leachate and runoff. This issue tends to be particularly problematic in regions with humid climates, such as Alabama.

• The extra solid waste stream from ZLD blowdown could expose PowerSouth to potential regulation under solid and/or hazardous waste laws, including the Resource Conservation and Recovery Act (“RCRA”), 42 U.S.C. § 6901 et seq., as well as applicable state and local waste management regulation. Moreover, there remain u nanswered questions concerning long

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- 54 disposal and stabilization of these salts when used for such purposes as road repair, cement filler, or fly ash conditioning prior to disposal.

• Scrubber waste crystallization is a relatively new process and presen ts a number of operational uncertainties, including flow and circulation rate variations, chemical composition variation due to coal usage, amount of heat added to the system, and mechanical elements such as tank size, tank finish, and the most effective t ypes of pumps to utilize. Finding the most effective combination of components and settings to the crystallization process is critical, as the wrong balance will have serious impacts on the success on overall FGD treatment. Crystallization is the final opp ortunity for the system operator to form the waste into crystals which are structurally compatible with the next phase of the ZLD process, which is dewatering. Maintaining the crystallizer with the number of variables that change constantly is challenging, and current installation data clearly show that this process is not viable for a constant reliable solution.

• The ZLD process would require inordinate amounts of chemicals at a substantial cost. Specifically, chemicals would be required early in the phys ical

- chemical treatment process to begin precipitation, conditioning, and concentration of the FGD blowdown slurry stream to reduce levels of calcium, magnesium, and other hardness

- producing ions before high temperature processing could occur. Also, signif icant amounts of lime and soda ash would be necessary, as the ZLD process consumes large quantities of these chemicals. Some facilities have estimated it would cost multiple millions of dollars a year to obtain the lime and soda ash required. And, the use of this lime and soda ash in the ZLD process generates a sludge byproduct that must also be dewatered and disposed of properly.

• It is possible that mercury, selenium, boron, and/or ammonia could evaporate and be released to the ambient air during the ZLD process. A detailed review of these potential emissions would certainly be in order before EPA could justifiably label ZLD technologies as BAT for the industry.

• The overall harsh conditions within which the ZLD process is carried out take th eir toll on the associated equipment. Filter presses must often be replaced. Likewise, other equipment must be closely monitored by plant personnel to evaluate whether anything has, or is about to, threaten the process.

• The two thermal ZLD system vendors are unwilling to guarantee that the ZLD system will be available more than 95% percent of the time. This should be revealing to the agency. What happens when these systems break down? How quickly can they be brought back online? The infancy of this techno logy results in an inability to answer a number of these types of questions and could dramatically impact the reliability of a number of facilities imperative to their respective electric grid.

• Footprint concerns are also a material issue EPA must consid er. Facilities have gone to great lengths already to comply with a number of important air, land, and water regulations that often occupy substantial, and important, space at the site. Requiring ZLD technology will likely result in some of that infrastruct ure needing to be reconfigured, reclaimed, or eliminated altogether. This would present an extreme challenge to many facilities.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 55 Collectively, these known or expected problems, coupled with significant unknowns, about the ZLD technology present insurmounta ble evidence that EPA cannot rationally classify this technology as BAT for FGD wastewater. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology,” as discussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/conde nsate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding commenter’s statements relating to the technologi cal availability or feasibility of evaporation technology, “UWAG’s extensive discussion regarding the shortcomings of this technology,” the evaluation of the Italian plants, the corrosive nature of FGD wastewater, and maintaining the operation of the cryst allizer, see responses to DCN EPA

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- 56 system “equipment must be closely mo nitored by plant personnel to evaluate whether anything has, or is about to, threaten the process.” For this reason, EPA increased its labor requirements for the system in its cost estimates for the final rule. See response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 82 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ZLD Technology for FGD Wastewater Treatment Is Not Reliable Enough For the Power Industry In theory, a ZLD process may be able to meet the current EPA demands. However, in practice, until the processes mature and reliability of the equipment is greatly improved, the overall process will have very poor reliability and will greatly impact the reliability of the power facility. For example, if each of the four major components of a ZLD system oper ates at 95% availability, the total availability for the system will drop to approximately 81%, which is unacceptable. Power plant operators typically seek and procure new pollution control process systems with availability guarantees greater than 98%. Nei ther of the two thermal ZLD system suppliers has stated that it will be willing to guarantee system availability greater than 95%. In fact, it is unclear what level of availability the vendors would be willing to guarantee.
ZLD Process for FGD Wastewater i s Not a Proven, Mature Technology In virtually every mechanical system that has been developed over the years, the initial versions proved to be maintenance

- intensive and expensive. For use of ZLD technology for FGD wastewater, the equipment vendors claim a mature technology, but the data do not support that claim. Given the specifications for types of pumps, piping arrangement, strainers, and volume of control tanks, heat transfer surfaces, and metallurgy among vendors of ZLD equipment, it is clear that each system is unique to its vendor. With the many variables these systems must deal with, it would be a very poor decision for any industry to install a system that is not mature, robust, and reliable. Power systems in the United States are among the mos t reliable processes in the world. This was not accomplished in a few years. It took many years to develop efficient turbines, boilers, andEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 57 generators, and these are only the primary parts of the power station. Thousands of other systems are used to suppor t, monitor, and operate this equipment. To manage ZLD for FGD wastewater

– considering all of the processes connected to these systems and the constant variables during power plant operation

– is simply not reasonable at this time. Given the many difficult ies of ZLD systems outlined above, Southern agrees with EPA’s decision that a ZLD system (such as chemical precipitation followed by vapor compression and evaporation) is not “best available technology” for FGD wastewater treatment. Comment Response:
EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology,” as discussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the disti llate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. See responses to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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i. ZLD Footprint May be Hard to Accommodate At Some Facilities
Coal

- fired plants are undergoing years of modification to meet all current air and water quality requirements. Some of these projects occupy a substantial area of the power plant. Future water facilities will also require large areas of real estate. At some facilities, the real estate may have to be reclaimed or modified from its current use. At other facilities, there is very limited space available for new systems and the plant is surrounded by other infrastructure and cannot expand. Those plants whi ch seek to expand their sites to accommodate new systems will face zoning and permitting issues. EPA should consider all of these “footprint” issues andEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 58 provide appropriate exemptions for facilities that cannot accommodate major new systems like ZLD treat ment. j. Procurement of ZLD Systems Will be Time
- Consuming and Expensive If EPA were to mandate ZLD treatment, facilities seeking to procure ZLD systems would compete for services from the limited number of qualified vendors and inevitably prices would i ncrease. This was seen in the construction boom in the mid

- 2000s when just the basic components of systems were scarce or their price was greatly inflated. Any system involving complex fabrication and/or unique metallurgy were simply not available at a r easonable cost and within a reasonable lead time. There are only two commercially viable suppliers of thermal ZLD systems for FGD wastewater treatment, Aquatech and HPD. Therefore, it is highly likely that, if EPA were to mandate ZLD systems for FGD waste water treatment, prices for the equipment would rise and lead times for procuring and installing the equipment would be very long.
k. Construction of ZLD Systems will be Challenging for Existing Power Plants Access will be one of the most challenging asp ects of constructing a ZLD system. On a greenfield site access is virtually unrestricted. But on an existing power plant site, the contractor must consider all of the operating equipment, the power line location, and each system adjacent to the construct ion area. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD systems,” as discussed elsewhere in responses to this commenter. EPA disagrees with the commenter that there are “footprint concerns” associated with the evaporation system. These systems can be designed to fit into a relatively small area, as demonstrated by the configuration at the PSNH’s Merrimack plant. Additionally, the final rule does not establish BAT limitations applicable to FG D wastewater discharges based on evaporation except in the case of the voluntary incentives program. For plants opting into the voluntary incentives program, EPA assumes that they have considered any “footprint concerns” in their evaluation of whether or n ot to opt into the program. The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharges based on evaporation. New sources, unlike existing sources, have more flexibility in designing their operations. EPA disagrees with the commenter that “there are only two [evaporation] system vendors.” EPA is aware of at least four vendors in the market for evaporation systems. EPA agrees with the commenter that the equipment used to manufacture portions of the evaporation system use “unique metallu rgy.” The commenter also expresses concern that “if EPA were to mandate [evaporation] systems for FGD wastewater treatment, prices for equipment would rise and lead times for procuring and installing the equipment would be very long.” As explained in the response to DCN EPA

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- 59 “mandate” evaporation or any other technology. Moreover, the commenter offers no basis for its claim about increased prices and long lead times. Nonetheless, the final r ule does not establish BAT limitations applicable to FGD wastewater based on the evaporation technology except for plants that choose to participate in the voluntary incentives program, in which case EPA assumes that the plant has considered these factors in assessing whether or not to participate. The commenter states that “construction of [evaporation systems] will be challenging for existing pants.” EPA disagrees that it necessarily “will be” challenging for existing plants to install and operate evapora tion technology, but EPA agrees that it could be challenging for certain plants. Nonetheless, EPA is not establishing BAT limitations applicable to FGD wastewater discharges from all existing steam electric power generating units based on evaporation techn ology. Plants that choose to participate in the voluntary incentives program, and be subject to BAT limitations applicable to FGD wastewater discharges based on evaporation, are able to evaluate any potential challenges before opting into the program. EPA agrees with the commenter that “greenfield site access is virtually unrestricted.”

Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Zero Liquid Discharge (ZLD) Technologies Are Not Fully Demonstrated USEPA's proposed Option 5 for treatment of FGD wastewater is chemical precipitati on in combination with vapor compression evaporation, a thermal ZLD system. DP&L understands that a single U.S. plant and four Italian plants are currently operating this technology in an FGD wastewater application. Through its inclusion as a proposed tech nology in the ELG revisions, USEPA claims this technology is commercially available for treatment of FGD wastewater to the very stringent proposed limits. But with so few working installations, thermal ZLD is not a fully demonstrated technology and is not commercially available to meet the proposed limits. In addition to the dearth of commercially demonstrable ZLD installations, the technology itself presents significant challenges:

 ZLD systems used for FGD wastewater treatment experience operational issues ;

 Maintaining FGD blowdown consistency is difficult under some conditions;

 Maintaining crystallizers is difficult due to operational variables;

 ZLD systems have a large parasitic load;

 ZLD systems can present solid disposal issues;

 ZLD systems consume sig nificant quantities of chemicals;Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 60  ZLD systems produce significant quantities of sludge;

 ZLD systems present extremely high capital and O&M costs;

 ZLD system footprint may be difficult to accommodate and construction of ZLD systems will be challenging for e xisting power plants;

 Procurement of ZLD systems will be time

- consuming and expensive

 ZLD equipment is difficult to maintain;

 ZLD technology for FGD wastewater treatment is not sufficiently reliable for the electric power industry. Given the many difficult ies of ZLD systems (as applied to FGD wastewater) outlined above, USEPA should not mandate this technology for any power plant. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology,” as dis cussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge bec ause it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge f ashion, for regulatory options based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding the commenter ’s statements about the demonstration and availability of the evaporation system, “operational issues” of the system, “maintaining FGD blowdown,” and “maintaining crystallizers,” see response to DCN EPA

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- 61 Regarding the commenter’s statements about capital and O&M costs, see response to DCN EPA

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- 4655, Excerpt Number 119. EPA agrees with the commenter that the evaporation system produces a large amount of sludge compared to the chemical precipitation system and the biological treatment system, largely due to the additional sludge generation from the softening process. Nonetheless, EPA conclude d that this byproduct is manageable and EPA accounted for the disposal of all the solids in its cost estimates. Finally, despite the commenter’s statements, the final rule does not “mandate” the use of evaporation technology or any technology. The final ru les establishes limitations and standards applicable to the discharge of pollutants from the steam electric power generating industry. While the final rules does not establish BAT limitations or PSES applicable to FGD wastewater discharges from all existi ng steam electric power generating units based on evaporation technology, the rule does establish BAT limitations for plants who opt into the voluntary incentives program (see preamble Section VIII.C.13). The final rule also establishes NSPS/PSNS applicab le to FGD wastewater discharges based on evaporation technology, for the reasons described in preamble Sections VIII.D and F.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In Italy there appear to be four FGD wastewater treatment systems that employ vapor compression evaporation systems on some basis. Recent reviews by the Electric Power Research Institute (EPRI) and the Utility Water Group (UWAG) indicate that the Italian vapor compression systems face significant solid waste disposal challenges. Additionally, EPRI found that t he capacity factors for the Italian systems were well below the capacity factors at most facilities in the United States. The EPRI visits to Italy also found that in some cases the zero liquid discharge systems were not operated on a consistent basis. Ins tead, FGD wastewaters wereEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 62 sent to offsite industrial wastewater treatment works at some facilities. We believe that given the limited number of zero liquid discharge systems in operation around the world, there is not enough evidence to support the premi se that this technology could be used on a consistent and reliable basis at an electric generating facility. In most if not all cases, a wet FGD scrubber is a critical path for plant operations. If the FGD scrubber is shutdown, plant operations cease along with power production. Without a properly functioning wastewater treatment system, an FGD scrubber cannot keep up with plant operations which triggers unit shutdown. The proposed rulemaking points to three days of a sampling in a single month at a single zero liquid discharge system. This limited data set is not sufficient to discern whether these systems are reliable and dependable. Comment Response: Regarding the technological availability of the evaporation system and issues raised by the commenter pertaining to plants in Italy, see response to DCN EPA

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- A1, Excerpt Number 18; regarding the potential for high amounts of selenium in th e evaporation solids, see response to DCN EPA

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- A1, Excerpt Number 26; and regarding further research for the disposal of the solids generated in the evaporation system, see response to DCN EPA

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- A1, Excerpt Number 75 in Comment Code 11.d. EPA disagrees that the data set that EPA used to develop limitations and standards for FGD wastewater discharges based on evaporation is in any way too “limited” or “not sufficient” for this purpose. See the response to DCN EPA

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- A1, Excerpt Number 62 in Comment Code 31.c.iii, and Appendix A, Essay Section 3.2.1.1. Also see the Statistical Support Document for Effluent Limitations (DCN SE05733). See response to DCN EPA

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Commenter Name: Nancy A. Evans Commenter Affiliation: PPL Services Corporation Document Control Number: EPA

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- 63 E xternal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: However, it should not be assumed that zero liquid discharge (ZLD) is the answer to this concern. EPA claims that this technology is commercially avai lable treatment. The reality is that ZLD is not a fully demonstrated technology and is not commercially available to meet the very stringent proposed limits in the rule. Besides the cost of the equipment needed for ZLD, which the EPA has not properly evalu ated, the operational issues associated with ZLD are numerous and result in unusually high operation and maintenance costs which EPA has not taken into account at all. ZLD systems create a large volume of waste that can, at some facilities and under certai n conditions, be hazardous waste. The EPA has not taken the cost of disposal or even the availability of facilities that can take such a waste into account. Crystallizers are not reliable under constantly changing conditions. Significant quantities of chem icals are needed for ZLD operation and the footprint needed for such a system may not be available at all facilities. Finally, ZLD systems have a very large parasitic load, significantly impacting the efficiency of the plant, which is counter to EPA’s desi re to encourage energy efficiency in the context of global climate change. For these reasons, the EPA should not consider ZLD proper treatment technology for FGD wastewater. Comment Response: EPA disagrees with the commenter’s apparent equating of evapor ation technology with “ZLD technology,” as discussed elsewhere in these responses to comments. The technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to o perate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding the commenter’s statements about the demonstration and availability of the evaporation system, “operational issues” associated with the system, and the use of crystallizers under changing conditions, see response to DCN EPA

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- 4655, Excerpt Number 108. Regarding the commenter’s statements about the parasitic load of the evaporation system, see response to DCN EPA

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- 64 Regarding the commenter’s statement that evaporation systems consume “significant quantities of chemicals,” see r esponse to DCN EPA

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- A1, Excerpt Number 18. EPA disagrees with the commenter’s statement that EPA has not accounted for the cost of equipment or operation and maintenance associated with the evaporation technology. EPA’s costing methodol ogy for the evaporation technology basis is described in the TDD. The commenter offers no specific information regarding costs that it believes that EPA did not account for. See also response to DCN EPA

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- A2, Excerpt Number 66 in Commen t Code 11.b. Regarding the commenter’s statement about the “footprint” of the evaporation system, see response to DCN EPA

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- A1, Excerpt Number 26.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 79 External Review Flag: No External Review E xternal Review Incorporated into Response: No Comment Excerpt: ZLD Footprint May be Hard to Accommodate At Some FacilitiesEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 65 For years coal

- fired plants have been undergoing modifications to meet all current air and water quality requirements. Some of these projects occupy a substantial area of the power plant. Future water facilities will also require large areas of real estate. In addition, the real estate most likely will have to be reclaimed or modified from its current use. The complexity of reloca ting air and water equipment support systems would require tremendous preplanning and most likely lengthy outages and high construction costs before the construction of the ZLD equipment ever begins. A chemical precipitation treatment system and a biologic al treatment system installed at Georgia Power Company’s Plant Bowen would be the size of a football field or 54 yards wide by 100 yards in length. Associated plant support system relocations are complex and expensive, and would require several large plann ed outages during the construction phase. Procurement of ZLD Systems Will be Time
- Consuming and Expensive When such large programs are implemented with a limited number of qualified vendors, it is inevitable that the prices increase. This was seen in the construction boom in the mid

- 2000s where just the basic components of systems were scarce or greatly inflated. Any system involving complex fabrication and/or unique metallurgy were simply not available at a reasonable cost and lead time. The pressure on t he power industry to conform to the new standards will no doubt put the same pressure, if not more severe pressures, on this type of equipment due to its complexity. There are only two commercially viable suppliers of thermal ZLD systems for FGD wastewater treatment, Aquatech and HPD. Construction of ZLD Systems will be Challenging for Existing Power Plants There have been several publications attempting to calculate the cost of installing the ZLD equipment. Given the recent exposure to a large construction program of new technology, it is highly unlikely that many of the considerations were given any thought prior to the publishing of such numbers. Access will be one of the most challenging aspects of the job. On a greenfield site, access is typically unlim ited. On an existing power plant site, the contractor must consider all of the operating equipment, power line location, and each and every system adjacent to the construction area. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 115.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- 66 Comment Excerpt Number: 37 External Review Flag: No External Review External Review Incorporated into Response: No
Comm ent Excerpt: Disadvantages of Vapor
- Compression Evaporation Vapor

- compression evaporation is an energy intensive operation, which has significant economic disadvantages. VCE requires a significant amount of auxiliary power to run the equipment resultin g in an energy penalty to the site. Corrosion is likely to occur to VCE materials of construction due to the corrosive nature of FGD wastewater. The byproduct generated from the VCE technology is a salt cake that needs to be landfilled. It is possible me tals removed from the FGD wastewater through vapor

- compression evaporation would go back to solution in landfill leachate. Also, FGD wastewaters at plants that burn subbituminous coal, such as our Pleasant Prairie facility, contain higher concentrations o f sulfates and other salts than FGD wastewaters at plants burning Eastern Bituminous coal. These salts and sulfur

- based compounds can cause operational and maintenance concerns with evaporation/crystallization systems, including scaling and corrosion of eq uipment. 12

12 CH2M Hill, Evaluation of Treatment Technologies for Arsenic and Selenium Removal, Pleasant Prairie Power Plant , June 2013. Comment Response: Regarding the commenter’s statements about evaporation being “energy intensive” and requiring “a significant amount of auxiliary power,” see response to DCN EPA

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- compression evaporation would go back to solution in landfill leachate.” EPA notes that the c ommenter did not provide or reference any data or information to substantiate this speculative claim. Nonetheless, EPA acknowledges that there is a possibility for the metals present in the salt to leach out from a landfill and be collected as landfill lea chate. However, EPA is aware that at least one of the vendors is working on an approach for stabilizing the solids generated by the evaporation technology. Moreover, given that no plants would be required to meet any limitations and standards applicable to FGD wastewater discharges based on evaporation for at least a few years, there is time for plants to determine the most appropriate disposal method for the solids. Regarding the commenter’s statements about salts and sulfur

- based compounds causing “operat ional and maintenance concerns with the evaporation/crystallization systems, includingEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 67 scaling and corrosion of equipment,” see response to DCN EPA

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- 4655, Excerpt Number 108.

Commenter Name: Theresa Pugh Commenter Affiliation: American P ublic Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 68 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Procurement of ZLD Systems Will Be T ime
- Consuming and Expensive When such large programs are implemented with a limited number of qualified vendors, it is inevitable that prices increase. This was seen in the construction boom in the mid

- 2000s where just the basic components of systems were scarce or greatly inflated. Any technology system involving complex fabrication and/or unique metallurgy were simply not available at a reasonable cost and lead time. Construction of ZLD Systems Will Be Challenging for Existing Power Plants
There have been several publications attempting to calculate the cost of installing the ZLD equipment. Given the recent exposure to a large construction program of new technology, it is highly unlikely the many of the construction considerations were given any thought pr ior to the publishing of such numbers. Access will be one of the most challenging aspects of the job. On a greenfield site, access is presumably unlimited. On an existing power plant site, the contractor must consider all of the operating equipment, power line location, and each and every system adjacent to the construction area. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 115.

Commenter Name: Raven Power Holdings, LLC Commenter Affiliation: Raven Power Holdings, LLC Document Control Number: EPA

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- A1 Comment Excerpt Number: 23 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 68 Comment Excerpt: Raven Power agrees with EPA’s conclusion that vapor

- compression evaporation is not a preferred option. This technology is not cost

- effective and has a very limited positive experience base within the U.S. for treating FGD wastewater. The installed systems still in service are designed for only relatively low

- volume tr eatment capacities. For the existing systems, including those outside of the U.S., little documentation exists on the ultimate fate of volatile components such as mercury and boron. The capital cost of vapor

- compression evaporation systems is prohibitive. In fact, the cost to add one of these systems to Raven Power’s Brandon Shores facility could well exceed 50 percent of the total purchase price of the Raven Power fleet. The operating cost and parasitic load is also excessive when compared to other proven treatment technologies. It would be ironic if the total pollutant loading of a power plant would be increased due to the additional reported parasitic load of up to 2 MW per 100 gpm water treated. Comment Response: EPA disagrees with the commenter that e vaporation “is not a preferred option.” While the final rule does not establish BAT limitations for discharges of FGD wastewater from all existing steam electric power generating units based on evaporation technology, the rule does establish a voluntary i ncentives program with BAT limitations based on this technology for this wastestream (see preamble section VIII for details). The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharges based on evaporation technology, for the reasons described in preamble Sections VIII.D and F. The commenter states that evaporation technology is not “cost

- effective.” EPA disagrees with that the final rule is not cost

- effective. For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerp t Number 27 in Comment Code 6.h

. Regarding previous experiences using the evaporation system to treat FGD wastewater, see response to DCN EPA

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- emissions of mercury and boron, see response to DCN EPA

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- A1, Excerpt Number 74 in Comment Code 11.b.
Re garding the commenter’s statement that the cost of evaporation systems is “prohibitive,” EPA notes that, as required by the Clean Water Act, EPA fully considered “cost” in establishing the final limitations and standards, as discussed in the preamble. EPA found that the final rule is affordable for the industry as a whole, and it does not pose a barrier to entry for new sources.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 69 Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 71 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Questions about Whether ZLD Technology for FGD Wastewater Treatment Is Mature Enough for the Entire Power Industry APPA is aware of several excellent ZLD plants operated by public power utilities. These APPA members are very pleased with their ZLD plants. In theory, a ZLD process may be able to meet the current EPA demands given the additional “bells an d whistles” involved in the application of ZLD on coal plants with FGD and wet scrubber issues. APPA’s reticence about the application of ZLD is largely because of unknowns.
General Conclusion on ZLD It is true that some companies operate ZLD systems succe ssfully, and this may be possible, for example, in a hot, dry climate where it is easy to evaporate wastewater. But that does not mean that ZLD can be accomplished at most sites. Given the many questions about ZLD systems outlined above, EPA should not for ce this technology onto all power plants in its option selection to meet BAT. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “ZLD technology,” as discussed elsewhere in these responses to comments. T he technology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream t hat can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evapor ation technology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. Regarding the commenter’s statements about the “maturity” of the evaporat ion system, see response to DCN EPA

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- 4655, Excerpt Number 119. Finally, despite the commenter’s statements, the final rule does not “force” evaporation technology or any technology onto power plants. The final rules establishes limitations a nd standards applicable to the discharge of pollutants from the steam electric power generating industry. While the final rules does not establish BAT limitations or PSES applicable to FGD wastewater discharges from all existing steam electric power gener ating units based onEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 70 evaporation technology, the rule does establish BAT limitations for plants who opt into the voluntary incentives program (see preamble Section VIII.C.13). The final rule also establishes NSPS/PSNS applicable to FGD wastewater discharg es based on evaporation technology, for the reasons explained in preamble Sections VIII.D and F.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 43 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA Cannot Rationally Consider “Zero Liquid Discharge” as BAT for FGD Wastewater. In the Draft Rule, EPA claims that ZLD technology is co mmercially available to the U.S. electric utility industry to effectively eliminate discharges of FGD wastewater. EPA’s conclusion erroneously relies upon limited data from a handful of facilities in Italy which operate much smaller versions of this techno logy in drastically different technological and regulatory contexts and data from the only two United States plants that currently employ some form of a ZLD system to treat FGD wastewater. Moreover, EPA’s suggestion that ZLD is a viable option for treating FGD wastewater ignores a number of significant operational issues this technology presents. Comment Response: See response to DCN EPA

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Commenter Name: Theresa Pugh Commenter Affiliation: American Public Powe r Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 70 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ZLD Equipment and Maintenance Issues Will Pose Additional Uncertainties The salts from the crystallizer are sent to a filtering press and then to a landfill. There are many types of filter presses. Some use a vacuum to remove the final moisture, and others useEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 71 centrifugal force to accomplish the dryin g. In either case, until there is a change in the ZLD design, these pieces of equipment operate in a harsh environment. Such environments usually result in more maintenance challenges. Many of the instruments that are used for general makeup water for dem ineralizers or wastewater plants are not reliable for use in extreme or corrosive environments. Corrosive environments might include scrubber blowdown waste, hot and cold slurries. Comment Response: See response to DCN EPA

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Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 67 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ZLD Footprint May Be Hard to Accommodate at Some Facilities
Coal

- fired plants are undergoing years of modification to meet all current air and wa ter quality requirements. Some of these projects occupy a substantial area of the power plant. Future water facilities will also require large areas of real estate. In addition, the real estate most likely will have to be reclaimed or modified from its cur rent use. It took years to relocate support systems for the power plant for the air equipment just installed. The complexity of such a plan would require tremendous pre

- planning and most likely lengthy outages and high construction costs before the constru ction of the ZLD equipment ever begins. Comment Response: See response to DCN EPA

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Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- 72 Comment Excerpt: Hoosier agrees with UWAG's comments that a Zero Liquid Discharge system for FGD Wastewater is a very expensive option and not fully demonstrated. These systems require exotic alloys, as the water produced in the process is very corrosive. They are labor

- intensive to operate and tend to have frequent downtime. The salts generated are difficult to handle, given their hygroscopic nature, and may prove to be a hazardous waste. In addition, the material balances of certain volatiles are not closed, meaning that the ultimate fate of constituents such as boron and mercury are not known. Requiring su ch an unproven and unreliable system seems unreasonable. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with “Zero Liquid Discharge system,” as discussed elsewhere in these responses to comments. The tech nology basis for control of FGD wastewater discharges under proposed Option 5 (Option F in the final rule) is evaporation. That technology basis does not necessarily achieve zero liquid discharge because it generates a distillate/condensate stream that can be discharged, although it can achieve zero liquid discharge if operated to recycle the distillate/condensate. Because not all plants would be able to operate the system in a zero liquid discharge fashion, for regulatory options based on the evaporation t echnology, EPA considered numeric effluent limitations and standards that would allow for the discharge of the distillate/condensate streams generated by the treatment system. While EPA determined that the evaporation technology is available and demonstrat ed, EPA did not select the evaporation system as the BAT basis for treatment of FGD wastewater discharges from all existing steam electric power plants for the reasons described in preamble section VIII.C.1; however, the final rule does establish a volunta ry incentives program under which steam electric power plants may choose to be subject to more stringent BAT limitations for FGD wastewater based on evaporation. The voluntary incentives program is described in more detail in preamble section VIII.C.13. Mo reover, the final rule establishes NSPS/PSNS applicable to FGD wastewater discharges based on evaporation technology, for the reasons described in preamble sections VIII.D and F. Regarding the commenter’s statement that evaporation is “very expensive,” EPA notes that, as required by the Clean Water Act, EPA fully considered the “cost” in establishing the final limitations and standards, as discussed in the preamble. EPA found that the final rule is affordable for the industry as a whole, and it does not pos e a barrier to entry for new sources. Regarding the commenter’s statements about demonstration of the evaporation system, “exotic alloys” needed, and the corrosive nature of the process, see response to DCN EPA

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- 73 Regarding the potential generation of hazardous materials, see response to DCN EPA

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- emission of boron and mercury, see response to DCN EPA

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- intensive to operate and tend to have frequent d owntime,” see responses to EPA

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Commenter Name: Betsy Natz Commenter Affiliation: Institute of Clean Air Companies (ICAC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Finally, the EPA included only (1) vapor compression system which is not operating domestically, but i nstead in Brindisi, Italy. It is puzzling why the EPA did not include data from the (2) domestic vapor compression systems in their final analysis. ICAC feels a more expansive review by the EPA to include a broader population of FGD waste water treatment systems and waste water chemistries is not only necessary but responsible in developing standards that are not overreaching of the proposed technologies. Comment Response: Regarding the selection of the data used in EPA’s analyses, see response to DCN E PA

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- A1, Excerpt Number 33 in Comment Code 11.c. Regarding the technology bases for the final limitations and standards, see section VIII of the preamble.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 74 Comment Excerpt:
l. Some ZLD Equipment is Difficult to Maintain The salts pr oduced by the crystallizer in a ZLD system are sent to a filter press and then to a landfill. There are many types of filter presses. Some use a vacuum to remove the final moisture, and others use centrifugal force to accomplish the drying. In either ca se, these pieces of equipment are in a harsh environment and have constant maintenance issues. Comment Response: The commenter states that evaporation technology equipment operates “in a harsh environment and [has] constant maintenance issues.” EPA agrees that the evaporation process can be a harsh environment, but EPA disagrees that the associated equipment has “con stant maintenance issues.” If the equipment were to have “constant maintenance issues” that would mean that the system would never be able to operate. As an example, the Merrimack plant is able to operate with a crystallizer and filtration system to treat its FGD wastewater through evaporation. EPA acknowledges that there are likely maintenance requirements for the filtration system and that the system would be designed with appropriate redundancy to allow for maintenance to occur while the system continue s to operate. EPA included costs for maintenance of the system in its costs estimates, see the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Catego ry (Cost & Loads Report) (DCN SE05831/SE05832)

.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 4655, Exc erpt Number 117.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 75 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

- HQ

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- 4379

- A1 Comment Excerpt Number: 91 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For the “zero discharge” option, EPA has in addition failed to prove that vapor compression

evaporation systems are technically available. It is not a proven technology for FGD wastewater. The few plants that are operating t hese systems face challenges that include corrosion and scaling, stability of solids for disposal, and very large O&M expenses. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with zero discharge, as discu ssed elsewhere in responses to this commenter. Regarding the availability of the evaporation system, corrosive nature of the system, and the scaling in the system, see response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4655, Excerpt Number 108. Regarding the commenter’s statement that evaporation technology is not “proven,” see preamble Section VIII and the response to DCN EPA

- HQ

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- 4655, Excerpt Number 108. Regarding the stability of the solids generated by the evaporation technology, see response to DCN EPA

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- A1, Excerpt Number 37. Regarding the commenter’s statement about the “high O&M costs” associated with the evaporation technology, see response to DCN EPA

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- A1, Excerpt Number 106 in Comment Code 11.b.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 130 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For the “zero discharge” option, EPA has in addition failed to prove that vapor compression

evaporation systems are technically available. It is not a proven technology for FGDEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 76 wastewater. The few plants that are operating these systems face challenge s that include corrosion of pipes, stability of solids for disposal, and very large O&M expenses. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with zero discharge, as discussed elsewhere in responses to this commenter. Regarding the availability of the evaporation system, corrosive nature of the system, and the scaling in the system, see response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4655, Excerpt Number 108. Regarding the commenter’s statement that evaporation tec hnology is not “proven,” see preamble Section VIII and the response to DCN EPA

- HQ

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- 2009

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- 4655, Excerpt Number 108. Regarding the stability of the solids, see response to DCN EPA

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- A1, Excerpt Number 37. Regarding the commenter’s st atement about the “high O&M costs” associated with the technology, see response to DCN EPA

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- A1, Excerpt Number 106 in Comment Code 11.b.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Co ntrol Number: EPA

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- 4460

- A1 Comment Excerpt Number: 29 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Imposing ZLD on the industry would be unconscionable given the limited number of facilities that have utilized, or currently employ, this technology, coupled with the numerous challenges those users have faced and sometimes not overcome. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technol ogy with zero discharge, as discussed elsewhere in responses to this commenter. See response to DCN EPA

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- 4655, Excerpt Number 108.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 77 Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Cont rol Number: EPA

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- 5140

- A2 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Many “unknowns” about ZLD should be further researched before ZLD should be required. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with zero discharge, as discussed elsewhere in responses to this commenter. See response to DCN EPA

- HQ

- OW

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- 4655, Excerpt Number 108.

Com menter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- 5140

- A2 Comment Excerpt Number: 105 External Review Flag: No External Review External Review Incorporated into Respon se: No Comment Excerpt: Many “unknowns” about ZLD should be further researched before ZLD should be required. Comment Response: EPA disagrees with the commenter’s apparent equating of evaporation technology with zero discharge, as discussed elsewhere in responses to this commenter. See response to DCN EPA

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- 4655, Excerpt Number 108.

Commenter Name: Public Hearing Transcript Commenter Affiliation: Public Hearing Transcript Document Control Number: EPA

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- A1 Comment E xcerpt Number: 153 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 78 Comment Excerpt: I was at one power plant that had a ZLD. The ZLD building took approximately the size of this room, and it was three stories tal l. Not all power plants have that large of a

-- excuse me
-- not all power plants have that large of a physical space available to be used. We'd very much appreciate it if you'd consider that. Comment Response: EPA disagrees with the commenter’s appar ent equating of evaporation technology with zero discharge, as discussed elsewhere in these responses to comments. See response to DCN EPA

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- 4655, Excerpt Number 115.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 79 11.b. FGD VCE

– Costs
Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 106 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### A.3 Cost Estimating Summa ry for Chemical Precipitation with Vapor
Compression Evaporation/Atmospheric Crystallization Treatment of Flue Gas Desulfurization Wastewater
A.3.1 Summary The Electric Power Research Institute (EPRI) estimated the cost of chemical precipitation with vapo r
- compression evaporation/atmospheric crystallization (CP+VCE) treatment of flue gas desulfurization (FGD) wastewater to the steam electric industry. This technical memorandum describes the method for calculation of costs of CP+VCE treatment for an individ ual plant, the assumptions associated with the cost calculations, and the estimated costs for treatment to the steam electric industry. Table A

- 13 outlines the cost to the current industry to install CP + VCE treatment of FGD wastewater.



### A.3.2 Introduction The U.S. Environmental Protection Agency (EPA) is updating the Steam Electric Power Generating effluent limitation guidelines (ELGs) through a comprehensive information collection request (ICR) and sampling at FGD wastewater treatment systems. EPRI estimated the costs of three FGD wastewater treatment technologies for commenting on EPA’s draft ELG rule. The treatment technologies evaluated were (1) chemical precipitation, (2) biological, and (3) chemical precipitation with vapor

- compression eva poration/atmospheric crystallization (CP +Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 80 VCE). The technologies are discussed in separate Appendices A.1 thru A.3. The cost evaluation results were extrapolated industry

- wide. 

### A.3.3 CP + CVE Treatment Overview This evaluation focuses on a system that use s chemical precipitation (for example, softening pretreatment), evaporation, and atmospheric crystallization. Other zero liquid discharge (ZLD) treatment alternatives include brine concentration and evaporation/vacuum crystallization without chemical softe ning, but are not part of this evaluation. The softening pretreatment needed for atmospheric crystallization requires large quantities of chemicals and produces a large amount of sludge. It consists of cold lime and soda ash softening to remove calcium, ma gnesium, and silica, followed by neutralization using sulfuric acid. Neutralization is required to degas the wastewater in a deaerator before reaching the VCE processes. For the EPRI evaluation, the equipment selected included mix tanks, clarifiers, neutra lization tanks, and filter presses to remove the solids. Some recirculation of the softened water was used as make

- up water for the lime and soda ash feed slurries. CP + VCE alternatives do not produce liquid waste streams requiring discharge or landfillin g, and result in complete crystallization. Since calcium chloride and magnesium chloride salts cannot crystallize at a temperature that is readily achieved, atmospheric crystallization requires softening pretreatment to remove calcium and magnesium. This a tmospheric crystallization process produces a sodium chloride salt cake. Final residuals of atmospheric crystallization consist of softener sludge and salt cake solids requiring disposal in a lined landfill. These alternatives typically include primary and secondary VCE processes. For EPRI’s design the primary stage includes a vapor

- compression, falling film evaporator (brine concentrator) to compress the vapor (distillate) mechanically to heat the brine. This type of evaporator is most energy efficient bec ause the latent heat of evaporation energy is reused, thereby reducing energy requirements as compared to a steam

- driven brine concentrator, which was not considered for primary treatment. The vapor

- compression evaporator, however, cannot alone reach the c rystallization temperature required. A forced

- circulation, steam

- driven crystallizer is less energy efficient, but is typically used to meet the higher boiling requirements required as salinity increases. This combination of vapor

- compression evaporator fo llowed by steam

- driven atmospheric crystallizer provides a favorable cost and energy

- efficient design solution. Therefore, this evaluation focuses on a CP + VCE system (“The System”), providing chemical softening followed by evaporation and then atmospheri c crystallization to remove water from the softened FGD blowdown. A block flow diagram representing the configuration of The System assumed for cost estimating is shown in Figure A

- 4. The key aspects of this system are:

 Treatment objective

– Elimination of wastewater discharge by means of softener sludge and salt cake generation and landfill disposal. Softening pretreatment is required to reduce crystallizer operating temperature and corrosivity.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 81  Key equipment

– Equalization tank, softening reaction tank, s oftening clarifier, neutralization tank, evaporator feed tank, chemical feed systems, vapor

- compression evaporator system, atmospheric crystallizer, distillate tank, and filter presses.

 Wastes

– The final residuals are softener sludge and salt cake solids, both requiring disposal in a lined landfill.



### A.3.4 Conceptual Design Basis The design basis for the cost estimate is described in this section.
A.3.4.1 Flow Rate Basis Flow capacity is a key factor in the cost of many treatment components. Peak flow rat e is the main consideration in sizing equipment. Average flow rate has a large impact on operating cost elements such as chemical feed, waste disposal, and electricity. Costs were estimated for two case study sizes, a small model plant flow rate and a larg e model plant flow rate. These two sizes are:

 “Small flow rate” system = FGD blowdown flow rate of 300 gallons per minute (gpm)

 “Large flow rate” system = FGD blowdown flow rate of 600 gpm Conceptual design estimates were prepared for these two flow capaci ties. Estimates assumed installation of 2 identical trains at 100 percent capacity for all equipment.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 82 Capital cost cannot be calculated based on size of the power plant (in megawatts [MW]), because factors such as coal chloride concentration and water recy cling play a large role in determining FGD water flow rate. Therefore, costs were calculated for a theoretical treatment plant based on flow rate.
A.3.4.2 Feed Water Quality Characteristics Feed water chemistry used in this cost evaluation was assumed to b e the same for the small and the large systems, as shown in Table A

- 14. EPA’s reported feed water chemistry for a typical FGD physical/chemical treatment plant effluent [ERG, 2009] was assumed for the dissolved species in the original feed water chemistry basis. This evaluation assumes no pretreatment of FGD blowdown upstream of The System. Therefore, a total suspended solids (TSS) loading value of 6,050 milligrams per liter (mg/L) was assumed, based on EPA’s reported typical TSS in FGD scrubber purge [ERG, 2009]. EPRI used OLI Analyzer (a commercially available computer software program used to model aqueous systems) to evaluate the original water chemistry assumed in the EPA report. The revised feed water chemistry detailed below reflects the OLI Analyzer reconciled water quality, which varies from the original feed water quality primarily in dissolved calcium and sulfate concentrations; the model makes minor adjustments to other ion concentrations if needed. The model automatically lowered calcium and sulf ate concentrations because the original feed chemistry far exceeded the saturation point for gypsum (that is, the point at which gypsum solids would precipitate out of solution). The predicted oversaturation occurred because water chemistry averaged from s everal wastewater sources was used, instead of water chemistry from a single source. The OLI equilibrium predictions for dissolved calcium and sulfate concentrations cannot be manually adjusted. EPRI assumed a default temperature value of 77 degrees Fahren heit (°F) for the feed water. Based on the water chemistry input, the model calculated the pH of the feed water to be 6.6.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 83 

### A.3.5 Cost Development Methods
A.3.5.1 Equipment Cost Assumptions Evaporator and crystallizer equipment costs were provided by an equipment vendor with experience providing systems for similar applications. Using the dissolved feed chemistry provided in Table A

- 14 and an assumed TSS concentration in the softening clarifier overflow of 21 mg/L (the same TSS reported for chemical precipitation system effluent in ERG, 2009, Table 2

- 3), the vendor provided costs for each of the flow rate scenarios, assuming equipment installed in 2 trains at 100 percent capacity per train for each alternative. The evaporator/crystallizer ve ndor estimated “turnkey” operations that included all costs within battery limits of the equipment packages. This included all of the process and mechanical equipment, concrete foundations, interconnect piping, instrumentation, controls, and electrical wiring to the motor control center (MCC). The turnkey estimate also included all labor required to install, test, and commission the vendor’s evaporator/crystallizer system (2012, personal communication).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 84 Because the quoted evaporator/crystallizer system i s turnkey, most system

- wide cost factors used in the EPRI estimates (see Table A

- 15) were not applied to the evaporator/crystallizer equipment installed costs, with a few exceptions. Site work was not included in the turnkey quotation, so a cost factor was applied to the vendor package. Since only electrical wiring to the MCC was provided with the vendor quotation, an industry average electrical cost factor of 22 percent was applied for the entire wastewater treatment system, for each alternative, to accoun t for new electrical supply infrastructure costs. Similarly, an industry average cost factor of 20 percent was applied for the entire treatment system engineering to account for the higher costs of engineering for electrical infrastructure and coordination with the vendor’s design package. An industry average cost factor of 20 percent was applied for miscellaneous unidentified costs to remain consistent with other treatment technologies evaluated (chemical precipitation and biological). Upstream and downstr eam equipment from the evaporator and crystallizer system, including equalization equipment, evaporator feed handling equipment, chemical feed equipment, softening process equipment, solids dewatering system, and distillate storage systems, were not part o f the turnkey design and were estimated separately from the evaporator and crystallizer system costs. Therefore, all cost factors were applied to these support system equipment costs. A detailed explanation of the cost factors used for developing capital c ost estimates is provided in the Cost Model Factors subsection below. 

### A.3.6 Capital Cost Assumptions A.3.6.1 Classification of Estimate This memorandum presents Class 4 estimates, generally defined as study

- or feasibility

- level estimates, for total installed costs. A definition of cost estimate classifications is presented in Appendix A.1. 6.
Vendor

- developed costs were used for the major unit process systems (for example, evaporator and crystallizer systems), considering the assumptions indicated by the vendor quote. Support equipment items (not included with major systems) were estimated based on costs supplied from other equipment vendors, internal databases, and chemical suppliers. Vendor

- developed costs and support equipment costs were summed to calculate a purchased equipment cost (PEC).
A.3.6.2 Model Cost Factors System

- wide cost factors were applied to develop the cost estimate (Table A

- 15). Values within the suggested ranges in Table A

- 15 are typically used in estimating costs of wastewater tr eatment plants. The mid

- point of the suggested range for each cost factor was used to estimate costs for this evaluation; however, a 25 percent factor was applied for piping assuming high grade alloy would be installed (typical range of 6 to 8 percent is f or conveyance piping), and a 15 percent factor was applied for miscellaneous metals and finishes assuming fiberglass materials would be installed due to the corrosive environment.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 85 A.3.6.3 Major Assumptions Major cost assumptions used to develop estimates are presented in Appendix A.1.6. The following major assumptions are unique to this capital cost evaluation:

 Wastewater tie

- in piping of 1,000 linear feet will be installed above grade.

 Power plant has no existing pretreatment system for the FGD wastewate r.

 Installation of a full softening system using lime and soda ash will be required (as opposed to partial softening or lime used for desaturation only). 

### A.3.7 Operations and Maintenance Costs Assumptions
A.3.7.1 Cost ElementsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 86 Operations and maintenance (O &M) requirements for this estimate include the following cost elements:

 Chemicals

 Utilities (electricity, steam, cooling water)

 Residuals disposal

 Equipment maintenance

 Labor

 Compliance monitoring

 Mercury Analyzer

 Miscellaneous unidentified costs (contingencies) A.3.7.2 Major Assumptions Major cost assumptions used to develop estimates are presented in Appendix A.1.6. The following major assumptions are unique for this O&M cost evaluation:

 Labor: a total of 10 full

- time equivalent (FTE) operator s at $42/hour, one supervisor at $65/hour, and one chemical engineer at $78/hour were assumed to staff the treatment plant.

 Chemical dosage rates will be typical values. (Actual dosage rates could vary depending on FGD wastewater chemistry.) Chemical suppl y costs, presented in June 2010 dollars, will be (actual costs will vary by geography, delivery method, and chemical supplier):

o Sulfuric acid (93%)

- $1.19/gallon (gal)

o Caustic (50%)

- $2.72/gal

o Hydrated Lime

- $0.07/pound (lb)

o Soda Ash

- $0.12/lb

o Antisca lent

- $13.61/gal o Anti foam

- $13.61/gal o Polymer

- $28.43/gal

 Cooling water demand was calculated assuming the water vapor mass flow rate from the evaporator deaerator is 1.5 percent of evaporator feed flow rate. Cooling water demand for the crystalliz er was calculated assuming a cooling water temperature rise of 40 °F.

 Steam demand was provided by the vendor.

 A 20

- percent markup was applied to each O&M cost estimate for miscellaneous unidentified costs.
A.3.8 Cost Estimates Summary
The cost estimates for The System are provided in the following subsections. A.3.8.1 Capital Costs The total estimated capital costs for the two design cases are provided in Table A

- 16. The equipment costs are based on cost quotes provided by the equipment vendors. The cost model factors shown in Table A

- 15 were added to the installed equipment costs to obtain the total estimated capital costs for The System.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 87Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 88 A.3.8.2 Operations and Maintenance Costs and Quantities The total estimated O&M costs for The System are provided in Table A

- 17.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 89Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 90 Daily estimates for O&M quantities are presented in Table A

- 18. Annual estimates for O&M quantities assumed a 90 percent on

- line factor and are provided in Table A

- 19.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 91 A.3.8.3 Annualized CostsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 92 Capital cost estimates (Table A

- 16) and O&M cost estimates (Table A

- 17) were used to calculate total annualized costs for The System. Capital costs were annualized assuming an equipment lifetime of 20 years and 7 percent interest rate. Annualized costs are presented in Table A

- 20.



### A.3.9 In dustry Cost Extrapolation Industry costs were estimated for the current industry. Based on information from the “Questionnaire for the Steam Electric Power Generating Effluent Guidelines,” EPA identified 116 plants discharging FGD wastewater (after excludi ng oil

- fired units and units with a capacity of 50 MW or less). This value was used to extrapolate the total cost of CP + VCE treatment to the current industry. Assumptions used to recreate EPA’s list of 116 plants are presented in Appendix A.1.9.
A.3.9.1 Flow Rate Basis Assumptions for each power plant used to develop the industry cost extrapolation are presented in Appendix A.1.4. A.3.9.2 Solids Loading The TSS assumptions for each power plant used to develop the industry cost extrapolation are presented in Appendix A.1.4. A.3.9.3 Capital Costs EPRI calculated estimated CP + VCE capital costs for each of the 116 plants. The costs for the evaporator/crystallizer vendor package and support equipment were scaled from the conceptualEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 93 design case (Table A

- 16) ba sed on each plant’s design flow rate basis. After scaling equipment costs, the following cost adjustments were made:

 Dewatering equipment costs were adjusted from the conceptual design case of 6,050 mg/L feed TSS based on each plant’s actual solids loading

 Support equipment costs were adjusted based on the treatment in place for each plant:

o If a facility had an existing chemical precipitation plant (consisting of equalization, clarifiers, and dewatering processes), a capital cost credit was applied, assumi ng this infrastructure could be repurposed. Forty one plants had some type of credit applied.

o If a facility only had an existing equalization system, a lesser capital cost credit was applied, assuming these equalization tanks could also be reused. Six plan ts had this credit applied.

 One plant had constructed an evaporation/crystallization system; therefore EPRI assigned no cost for additional capital or O&M expenditures.

 This evaluation assumes a 2 x 100 percent redundancy for the CP + VCE system installed for all 116 plants.
A.3.9.4 O&M Costs EPRI calculated estimated O&M costs for each of the 116 plants by scaling from the conceptual design case (Table A

- 17) based on each plant’s design flow rate basis. After scaling O&M costs, the following cost adjustmen ts were made:

 If a facility had an existing pond, it was assumed that the pond would be replaced by a treatment system similar to that shown in Figure A

- 4. A total of 68 plants had FGD ponds, and an O&M credit was applied for ceasing operation of the pond. The cost of pond closure was not included in this estimate.

 Five facilities had existing biological treatment systems for FGD wastewater. Similarly, an O&M credit was applied for ceasing operation of the biological treatment system.

 Forty

- one facilities had existing chemical precipitation treatment. Similarly, an O&M credit was applied for the existing chemical precipitation operating costs incurred by these facilities.

 One plant had constructed an evaporation/crystallization system; therefore EPRI assign ed no cost for additional capital or O&M expenditures.
Table A

- 21 summarizes treatment costs to the current industry.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 94 Comment Response: As described in preamble section VIII, EPA did not select evaporation (also known as “vapor compression evaporation” or “VCE”) as the basis for BAT limitations for FGD wastewater at all steam electric power plants because of the high cost of possible regulatory requirements based on evaporation for FGD wastewater. For purposes of the final rule, EPA conducted a screenin g
level evaluation of the costs to treat FGD wastewater using an evaporation system costs and determined that the cost of limitations based on evaporation would be more than $800 million more expensive, on an annual social cost basis, for the industry as a whole than the cost of limitations based on chemical precipitation plus biological treatment. Given the high costs associated with the technology, and the fact that the steam electric industry is facing costs associated with several other rules in additio n to this rule, EPA decided not to establish BAT limitations for FGD wastewater based on evaporation for all steam electric power plants. Nevertheless, as described in Section VIII of the preamble, the final rule does establish a voluntary incentives progr am under which steam electric power plants can choose to be subject to more stringent BAT limitations for FGD wastewater based on evaporation. EPA’s approach for conducting the screening

- level analysis are described in DCN SE05730 (Memorandum to the Steam Electric Rulemaking Record: Plant

- Specific Compliance Cost Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed by Evaporation). EPA agrees with the commenter that indirect costs such as contingency should have been included i n the installed capital equipment cost estimate for the evaporation system. Contingency is added to cover costs for unforeseen issues such as equipment cost overruns, schedule delays, infrastructure changes such as rerouting of underground utilities (elec trical, water, communication, etc), specialized subcontractors (e.g., safety professionals), and improvements in technology or automation between design and purchasing. For the final rule, as recommended by the commenter, EPA derived its indirect capital c ost factor from typical engineering factors. EPA developed an indirect capital cost factor of 0.43, which accounts for engineering and supervision, construction expenses, contractor’s fee, and contingency, based on information provided in Peters and Timmer haus’ Plant Design and Economics for Chemical Engineers. This is the same indirect capital cost factor used for the chemical precipitation and biological treatment system costs estimated for the final rule. EPA agrees with the commenter that additional t reatment chemicals will be required for the evaporation system and that the dosage requirements for treatment chemicals can vary depending on the wastewater characteristics. According to the comments, chemicals required for the treatment system include so da ash, hydrated lime, polymer, sulfuric acid, sodium hydroxide (caustic), anti

- foam and anti

- scalant. The additional chemicals that EPA agrees should be included are polymer to enhance gravity settling within the physical

- chemical soda ash softening syst em, sulfuric acid and caustic to control wastewater pH prior to entering the evaporation unit, anti

- foam to reduce possible foaming in the evaporator, and anti

- scalant to reduce scaling in equipment such as heat exchangers. Because of the requirement for a dditional treatment chemicals, EPA also included capital costs to account for each additional chemical feed system in its cost estimates. Capital costs for the additional chemical feed systems associated with the evaporation system were estimated using th e chemical feed system cost equations associated with the FGD chemical precipitation system and the plant

- specific FGD wastewater flow rate.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 95 EPA disagrees with the commenter that additional hydrated lime is needed for the softening system since lime is already added to the wastewater during chemical precipitation and this step would have removed carbonate alkalinity. EPA agrees with commenter that redundancy should be included in the capital cost, however EPA disagrees that 2 x 100 percent redundancy is required. Instead, EPA applied the equivalent of a 50 percent redundancy to capital equipment to account for equipment within the softening/brine concentrator/crystallizer portion of the system that must be taken off

- line periodically for maintenance. Fo r screening

- level purposes, EPA estimated the costs to add a 50 percent redundancy by multiplying the equipment costs by 1.5. Evaporation systems are designed to concentrate corrosive constituents in the FGD waste stream using elevated temperatures and con centrating these constituents results in a brine solution that is high in dissolved solids, particularly chloride, that can deposit scale on wetted equipment including heat exchangers, pumps, piping and the internal surfaces of the evaporator and crystalli zer. In addition, the aggressive nature of the concentrated FGD wastewater can result in accelerated corrosion rates and, therefore, wetted equipment is designed using alloys such as titanium. These issues will require portions of the evaporation system to periodically be taken off

- line for periods for maintenance 1 and, therefore, some redundant equipment is included to allow continued processing of the FGD wastewater. To determine the amount of redundant equipment needed for continuous evaporation proce ssing of FGD wastewater, EPA reviewed engineering piping and instrumentation diagrams (P&IDs) from a steam electric generating facility using a brine concentrator system for FGD treatment. The review revealed the VCE system includes a redundant brine conc entrator. EPA’s experience at petroleum refineries and chemical manufacturing facilities has shown redundant heat exchangers are also generally provided since these units need to be taken off

- line periodically for inspection and cleaning. Finally, EPA th en contacted GE Water Systems who had provided original costs for the VCE system in 2009 to determine the amount of redundant equipment provided in their original estimates. According to GE Water, the original cost estimates did include some redundant equi pment such as “insurance spare parts” for rotating equipment, the clarifier, and solidification equipment, but did not include a redundant evaporator or crystallizer. Based on this information, EPA decided to add an additional 50 percent to the installed equipment costs to cover redundant equipment within the VCE system. EPA agrees with the commenter that additional operating labor is required for the VCE system; however, EPA disagrees that system experts such chemical engineers are needed to staff the sy stem, and that as many as 10 full time equivalent (FTE) operators are required. The evaporation system operates similar to processing units at chemical manufacturing plants and petroleum refineries, and based on EPA’s experience at these types of faciliti es, one board operator in the control room monitoring the system, one field operator making adjustments to the system as needed (opening/closing valves, monitoring pressures and temperatures, etc.) and one shift supervisor is needed at all times. These th ree operators are required on

- site 8,760 operating hours per year. Expertise from chemical engineers can be provided on an as

- needed part time basis.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 96 EPA generally agrees with the commenter that costs for maintenance equipment and labor were underestimate d for the proposed rule. Evaporation systems are more similar to a chemical processing unit at a chemical manufacturing facility than a traditional wastewater treatment system and, therefore, typical maintenance equipment and labor for wastewater treatmen t systems may not apply. Wetted parts of the system are manufactured with expensive alloys such as titanium alloys to withstand high chloride concentrations in the concentrated FGD wastewater and these types of alloys can add considerable expense for repl acement parts. The evaporation portion of the system will require additional inspection and cleaning to remove scale. The crystallizer portion will require much more frequent cleaning to remove scale. 1 Shutting down equipment components for cleaning will add considerable maintenance labor costs. Because of additional maintenance and the labor needed to conduct the maintenance, EPA estimated annual maintenance equipment and labor based on 6 percent of the total equipment cost. The 6 percent is based on li terature information for chemical plants [Perry’s Chemical Engineers Handbook, 6 th Edition, page 25

- 57, 1984]. The cost factor was not applied to the redundant equipment within the VCE system since this equipment only operates when the primary equipment is out of service.

1 Nebrig, H., Teng, J., and Downs, D., Preliminary Assessment of a Thermal Zero Liquid Discharge Strategy for Coal Fired Power Plants. IWC 11

- 36. Presented at the 72 Annual International Water Conference, 2011.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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Comment Excerpt: ZLD Systems Need Large Amounts of Chemicals As the FGD blowdown slurry stream reaches the first section of the physical

- chemical (P/C) equipment, the system operators add large amounts of chemicals to begin precipitation, conditioning, and conc entration of the blowdown stream. This step is essential for reducing the levels of calcium, magnesium, and other hardness

- producing ions, and to lower the scaling potential of the wastewater prior to higher temperature processing.
Each reaction in the P/C portion of the treatment system is sensitive to the process parameters of the system. Changes in temperature, concentrations, and flow rate pose difficult challenges to P/C performance. Variability of the parameters affects the P/C’s primary step in the P /C. This effect cascades through the P/C, changing the pH and the quantity of coagulants and polymers used to capture the metals.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 97 The process to soften the FGD wastewater consumes a large amount of lime and soda ash. In a study evaluating a ZLD system capa ble of treating 410 gpm FGD wastewater with 40,000 ppm chlorine in the water, it was estimated that 40 tons of lime and 80 tons of soda ash per day were needed to be fed to the system. The chemical cost was estimated to be approximately $17 million per yea r
. Based on calculations given to UWAG by an investor owned utility for its plant (410 gpm system), 40 tons of lime (app. $130/ton) and 80 tons of soda ash per day ($230/ton) are required to de

- saturate and soften the FGD wastewater prior to evaporation. T his is equivalent to approximately five to six trucks of lime and soda ash per day, assuming 25 tons per truck load. These chemicals require considerable physical space at power plants. Many public power utilities have power plants with very limited physic al space for these additives and lime or soda ash. APPA believes that these capital costs, operating concerns, and costs, along with questions about the ability for the salts to pass the TCLP test, demonstrate that ZLD is not the appropriate choice. Also, physical space needs may be enormous for ZLD. ZLD Systems Produce Large Amounts of Sludge The addition of lime and soda ash to treat FGD wastewater produces a large amount of byproduct sludge to be dewatered and disposed of offsite. APPA is aware, because of APPA’s membership in UWAG, that a utility has estimated that the amount of sludge produced by the de

saturation and softening process is 105 tons per day (at an approximate disposal cost of $3/ton). That unnamed utility (providing confidential informat ion to UWAG) also estimated that the number of daily truck loads will exceed five truckloads per day at 20 tons per truck load . This not only requires additional manpower onsite, but also adds to traffic congestion at the site. These manpower and transport costs were not in the EPA costs analysis. APPA points out that many existing coal

- fired power plants are not located off of major interstate highways. The transport costs could be higher per volume than this unnamed utility because some public po wer communities are located off two

- lane roads. And others are in rural locations where there are city or county ordinances that limit truck transport by size and/or frequency. The EPA cost analysis did not look into these issues for investor, co

- op, or co mmunity

- owned utilities. ZLD May Cause Extremely High Capital and Operating & Maintenance (O&M) Costs The need to use expensive metals and alloys in the concentrators, evaporators, and crystallizers drives up the capital cost of the ZLD option. Materials such as titanium, CD4Mcu, and Hastelloy C help reduce scaling and plugging of vessel internals, as well as corrosion. Due to the expected frequent outages, process redundancy will also be required, which will add significantly to the overall capital costs. Process redundancy costs were not in EPA’s cost assessment. For thermal ZLD systems, the concentrations of calcium and magnesium in the wastewater must be reduced to lower the scaling potential of the water at high temperature. Again using a 410 gpm syste m as an example, UWAG has estimated that chemicals used in the hardness reduction step will cost $17,000,000/year . In addition to the cost of these chemicals, theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 98 chemicals unloading will add to the manpower requirements and to the plant’s traffic congesti on. As pointed out earlier, transportation costs were not addressed by EPA. The operations and maintenance staff must be augmented at each plant at a significant cost. Each system will require a system expert, and most large system experts will likely need chemical engineers or be chemists familiar with the technologies. While some existing ZLD plants do not require these fulltime system staff experts, it is expected that the complexity of controlling selenium and other substances resulting from the FGD ope rations will result in more manpower. Many public power utilities do not employ chemical engineers on a full

- time basis. EPA has failed to address the manpower costs possibly associated with the sophisticated chemical management in this rulemaking. It is not possible for APPA to predict how many utilities with coal

- fired power plants would need to hire part

- time or full

- time chemical engineers or consulting chemical engineers. The total capital cost for a ZLD system is estimated to be extremely expensive, according to information received from a UWAG member. One utility (from UWAG’s survey) estimates that the capital cost for a full thermal ZLD design at its plant is between $203

- 238 million, with an O&M cost of $19.3

- 19.6 million annually. That utility has a capacity to treat 800 gpm FGD wastewater with 20,000 ppm chlorine (Cl) level. This same utility also stated that the labor needed to maintain the ZLD system is extremely high. Most expect several highly knowledgeable and well

- trained personnel would be needed to maintain the ZLD system. Comment Response: Regarding the materials of construction for the system, redundancy in the system, and staffing requirements, see response to DCN EPA

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- 99 EPA agrees with the commenter that additional sludge will be generated from the softening system prior to brine concentrator and handling of the sludge will increase manpower, transportation and disposal costs. However, EPA disagrees that these costs were not included in the EPA’s estimates at proposal because EPA did account for the transportation and disposal of all solids in its proposed costs. For the final rule, EPA estimated sludge generation rates from the soda ash softening system and the crystallizer. Based on a 410 gpm flow rate as suggested by one commenter, sludge generation could be as much as 105 tons/day. The plants that are currently using the evaporation technology for FGD wastewater have found that the residuals pass the TCLP test and therefore do not require disposal in a hazardous waste landfill. EPA did not identify any plants located in rural locations or elsewhere wher e there are city or county ordinances that limit truck transport by size and/or frequency. Commenters provided no such information for any plant, therefore, it is reasonable to assume, particularly given the large amount of car and truck traffic already as sociated with power plant operations, that plants will not be subject to such requirements limiting truck transport for raw materials or wastes associated with the evaporation treatment technology.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 74 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ZLD Systems Have a Large Parasitic Load The cryst allizer is the largest user of energy in the ZLD process because it must evaporate the brine concentrate from a concentrated solution to produce a slurry that can be dewatered (Nebrig et al. 2011 at 3). A ZLD project designed to concentrate 60 gpm of waste water with 95% recovery has been reported to require a 350 hp mechanical vapor compressor for operations. One of UWAG’s members estimated a power requirement for its brine concentrator/ crystallizer of 320 kW/100 gallons of treated scrubber blowdown. The m ember also reported that the equipment will increase carbon emissions per unit energy outputand the cost of station service will lead to lost annual revenue of $1 million. Comment Response: EPA acknowledges that the evaporation system does require more e lectrical energy to operate than the chemical precipitation system and the biological treatment system. However, EPA disagrees with the commenter that the power requirements for the evaporation system (brine concentrator/crystallizer) are 320 kW/100 gallon s. Using an industry

- wide average, EPAEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 100 estimates energy requirements for the evaporation system are approximately 110 kW/100 gallons treated, based on data obtained from vendors. EPA agrees with the commenter that, for a given facility assuming the fuel remains coal and the electrical power (MW

- hr) provided to the electric grid is unchanged, the operation of the evaporation system will increase carbon dioxide emissions at the plant because the technology has a higher power demand. However, EPA estimated N WQEIs for the voluntary incentives program, using the assumption that all existing plants will use evaporation, and even in that overly conservative scenario (i.e., overestimate of energy use and air emissions) found that the NWQEIs are acceptable.
Annual energy costs for specific steam electric facilities will depend on the volume of FGD wastewater treated per year. See the RIA for information on how the cost of operating FGD wastewater treatment systems and other technologies to implement the ELGs affect plant/entity revenues and economic achievability of the ELGs.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 80 External Review Flag: No External Re view External Review Incorporated into Response: No Comment Excerpt: He also has to consider those features affected by the underground work for system electrical, instrument and control, and all of the numerous water sources that transverse the power station site. Safety is paramount in the power generation industry. Installing all of the equipment intermingled with the existing plant systems and operations will be an extreme challenge. It will require an increase in safety professionals to keep the st aff and the construction crews safe. Comment Response: EPA agrees with the commenter that underground work should be considered in the cost estimate. As such, EPA developed an indirect capital cost factor that included a contingency to account for unfor eseen issues such as equipment cost overruns, schedule delays, infrastructure changes such as rerouting of underground utilities (electrical, water, communication, etc), specialized subcontractors (e.g., safety professionals), and improvements in technolog y or automation between design and purchasing. See response to DCN EPA

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- 101 (Memorandum to the Steam Electric Rulemaking Record: Plant

- Specific Compliance Cost Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed b y Evaporation) contain additional information.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 81 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Many of the instruments that are used for general makeup water for demineralizers or wastewater plants are not reliable for use in the extreme corrosive environments of scrubber blowdown waste, hot a nd cold slurries, and level indicators on the brine concentrators and crystallizers. This lack of automatic control puts the entire responsibility on the operator. Each operator must interpret data, make adjustments, and then process the changes to ensure the changes are making a positive effect on the equipment. Comment Response: EPA agrees with the commenter that instrumentation is not always reliable and, therefore, additional responsibility is put on the operator to ensure the equipment runs as design ed. However, EPA does not agree that the conditions of the evaporation treatment technology are such that there is a lack of automatic controls. Nevertheless, recognizing that the system is not passive, and the added operator attention associated with thi s technology, EPA decided to increase the number of operators for the evaporation system. See response to DCN EPA

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Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 69 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The utility also has to consider those features affected by the und erground work for system electrical, instrument and control, and all of the numerous water sources that transverse the power station site. APPA does not believe that EPA considered the costs if undergroundEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 102 construction is required. It is not possible for APPA to predict how many public power utilities would need underground construction because this is entirely site specific. Comment Response: See response to DCN EPA

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Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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U WAG provided an example of a ZLD system cost estimate of $203MM to $238MM for an 800 gpm FGD Wastewater Plant. While this is likely considerably larger than what Merom would need, the cost of a ZLD system for Merom is still likely in the $50

- 80MM range. A nnual chemical costs could be in the $7MM to $10MM range and the system could require from six to ten well

- trained personnel to operate the system. Comment Response: ERG agrees with the commenter that capital costs for smaller systems can range between $ 50 and $80 million, but EPA disagrees that annual costs for chemicals will be in the $7 to $10 million per year. EPA’s estimated annual costs for chemicals treating flows as high as 260 gpm were less than the range of chemical costs indicated by the comme nter. See the Costs & Loads Report and EPA’s updated evaluation of costs for treatment of wastewater with the evaporation technology option. Regarding the number of operators required for the system, see response to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 103 Comment Excerpt:

a. EPA’s estimated cost for mechanical evaporation is too high. EPA estimated the total capital cost for adding mechanical evaporation to 116 plants at $6.24 billion, or approximately $54 million per plant. 211 EPA’s estimate is higher than other publicly available information about the installation cost of these systems. 212 The Aquatech mechanical evaporation system at Merrimack has been estimated to between $23 million 213 and $37 million. 214 At the Torrevaldaliga Nord plan t in Italy, the cost of the wastewater treatment system was estimated at €10 million, which according to present conversion rates is between $13 and $14 million dollars. 215 Since Italian law prohibits discharges of FGD wastewater to the sea, the demand fo r zero
- liquid discharge systems has been substantial, which has likely lead to declining costs, much as would occur in the United States if EPA selected Option 5. EPA Region 1 estimated the operations and maintenance (O&M) costs for a mechanical evaporatio n system in its BAT determination for Merrimack Station. For that plant, where the FGD wastewater flow volume is estimated to be approximately 70,000 gallons per day, or 750 gallons per minute, 216 EPA calculated O&M costs of approximately $1.524 million. 2 17 By comparison, EPA’s estimate of average O&M costs in the proposed rule is approximately $8.8 million per facility. 218 There are several causes of inflation of EPA’s cost estimate for mechanical evaporation. First, the capital cost appears to include “ sludge disposal costs,” which is properly counted as an O&M cost. 219 Indeed, EPA also included “sludge disposal costs” as an O&M item, apparently double

counting this cost. Second, EPA’s cost estimates for mechanical evaporation include the cost of a for ced

- circulation crystallizer, 220 which is likely more expensive than the alternative methods to eliminate brine concentrate such as ash conditioning, in which the concentrate is mixed with fly ash to stabilize the material for landfilling. 221 Third, EPA’s industry

- wide cost estimate does not account for the many plants that could comply with these standards without installing any mechanical evaporation technology at all, but simply by adopting different design and operating practices. As discussed in Sectio n 7.1.6 of the TDD, and in even greater detail in EPA’s 2009 Detailed Study, there are at least five design and operating practices currently in use that can eliminate the discharge of FGD wastewater: (1) evaporation ponds, which are most effective in arid climates; (2) conditioning dry fly ash; (3) underground injection, (4) variations of complete recycle, and (5) operation of both wet and dry FGD scrubber systems, recycling the treated wastewater from the wet system into the dry one. 222 EPA’s data show th at almost one

- fifth of plants achieve zero discharge through these methods. 223 According to the 2009 Detailed Study, 38 percent of plants operating wet FGD systems already have zero liquid discharge of FGD wastewater, either through mechanical evaporation, or design/operating practices. 224 Despite this record, EPA’s cost analysis did not account for plants that are already achieving zero discharge for FGD wastewater; instead, it assumed that every plant with an FGD wastewater stream, other than the one plant already operating a mechanical evaporation system (Iatan), would have to install this technology. 225 By ignoring existing zero discharge systemsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 104 other than mechanical evaporation, EPA’s industry

- wide cost analysis is overstated. Moreover, EPA’s cost estimate ignores that many other plants would investigate whether one of these design and operating practice changes is feasible for their plant, and many would select these types of changes over installing a mechanical evaporation system. Thus, EPA did n ot account for potential implementation of these design and operating changes across the industry in its cost analysis. EPA’s estimate of the industry

- wide cost for Option 5

– $2.3 billion

– is EPA’s worst

- case cost estimate for Option 5. This is a pre

- ta x estimate, but EPA itself states that “after

- tax costs are a more meaningful measure of compliance impact on privately

- owned for profit plants,” 226 which account for 71.6 percent of the generating capacity subject to the rule. 227 EPA’s after

- tax estimate for Option 5 is only $1.548 billion. 228 If total industry cost were a relevant factor, which it is not, EPA should be using the after

- tax figure of $1.548 billion, rather than $2.3 billion.

211 TDD at 9

- 28.

212 These cost differences may reflect the volume of FGD flow being treated, but as plant

- by

plant information has been withheld as confidential, we are unable to fully investigate EPA’s cost assumptions.

213 See Expert Report of John H. Koon in the Matter of Comments on the NPDES Permit for PSNH’s Merrimack Station (2012) at 9 (In January 2011 project management personnel revised the project budget to include $20.2 million for the supplemental WWTS.”); see also id. at 10 (“The cost of VCE by itself was calculated to be $23,080,000 by subtracting th e cost for chemical precipitation from the EPA cost estimate for ‘Chemical Precipitation/Softening plus Evaporation.’”).

214 2012 Jacobs Consultancy Report, at Figure 8 ($32.6 million for secondary wastewater treatment system, plus $3.8 million for soda as h softening process). EPA’s own estimate for the capital cost was $27,949,000. U.S. EPA Region 1, Determination of Technology

- Based Effluent Limits for the Flue Gas Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire (Sept. 23, 2011) at 22. To put this cost into perspective, $23 million is only around 5% of the total project cost for installing the FGD system. Furthermore, the annual cost as a fraction of operating revenue for the plant was only 1.5%. Expert Report of John Koon, Merri mack, at Table 4. It has also been estimated that the capital cost of the mechanical evaporation system increases the value of the plant by between 1.4 and 4.7%, a critical fact relating to affordability for the large portion of the electric generating sec tor for which rates guarantee a certain rate of return on the value of these assets. Id. at 11 (“The capital cost of VCE would increase the value of the site facilities by 1.4 to 4.7%, depending on the basis for the comparison.”).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 105 215 Enel Site Visit Notes , Docket No. EPA

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216 Merrimack TBEL Determination at 18.

217 Id. at 22.

218 TDD at 9

- 28 (Table 9

- 3) (value is $1.03 billion divided by 116, the number of plants). Calculating average O&M costs is less than ideal, since O&M depends lar gely of FGD wastewater flow rates, but since EPA has withheld as confidential plant specific cost or flow information, this average is the only available plant

- based cost estimate.

219 TDD at 9

- 26.

220 Id. at 9

- 26.

221 Id. at Section 7.1.4.

222 Id. at 7.1. 6; see also 2009 Detailed Study, Docket No. EPA

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223 TDD at 7

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224 2009 Detailed Study, Docket No. EPA

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225 Incremental Cost and Loading, at 4

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226 RIA at 3

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227 Id. at Table 2

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228 Id. at t 3

- 6. Comment Response: EPA disagrees that EPA is double counting costs for the sludge disposal costs. EPA includes capital costs in its estimates for those plants that operate on

- site landfill. The capital costs are associated with the expansion of the landfill. EPA also includes O&M costs for those plants associated with the maintenance of the landfill. For plants with off

- site landfills, EPA only includes O&M costs for the sludge disposal costs. EPA agrees with the commenter that EPA ’s costs estimates “include the EPA agrees with the commenter that EPA’s costs estimates “include the cost of a forced

- circulation crystallizer.” As described, this is the technology basis that EPA selected for the rule because the crystallizer reduces iss ues associated with sludge disposal and it is the technology that all plants would be able to install and operate. For example, not all plants generate enough ash to be able to stabilize with the FGD brine concentrate and, therefore, EPA could not assume t hat all plants would beEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 106 able to operate with that approach. EPA agrees with the commenter that some plants would be able to comply with the rule using a different approach that achieves zero discharge; however, these alternative technologies and processes are not available to every wet

- scrubbed plant and EPA does not have sufficient information about the plants to determine which plants would be able to do so, or which approach they would take. Therefore, EPA uses the cost for the technology basis to estim ate the costs for the industry. EPA agrees that, at proposal, EPA estimated costs for some wet

- scrubbed plants that, although they generate FGD wastewater, they do not actually discharge the wastewater. EPA’s cost methodology approach at proposal was sound and correctly assumed that a number of plants operating wet scrubbers do not discharge FGD wastewater and therefore would not incur costs to comply with the proposed FGD effluent limitations. However, comments on the proposed rule showed that there were a dditional wet

- scrubbed plants that also do not discharge FGD wastewater and for which EPA had mistakenly estimated costs for. EPA’s analysis for the proposed rule correctly identified that the plants generate the FGD wastewater, but did not correctly accou nt for the fact that these additional plants do not discharge the wastewater. EPA updated its analyses for the final rule to correctly reflect that these additional wet

- scrubbed also would not incur costs to treat FGD wastewater since the wastewater is no t discharged. EPA agrees with the commenter that after

- tax costs are a more meaningful measure of compliance impact on privately

- owned for

- profit plants when looking at those impacts from the perspective of the owners, but notes that pre

- tax costs are the more relevant consideration when discussing the impacts of the regulation from a societal perspective. As discussed in Chapter 3 of the RIA for the proposed rule and again for the final rule, EPA accordingly uses either pre

- or after

- tax compliance costs i n different analyses, depending on the concept appropriate to each analysis ( e.g. , cost

- to

- revenue screening

- level analyses are conducted using after

- tax compliance costs). In their comments, the commenter is citing the social costs, which appropriately re flect the total expenditures as incurred by the plant owners (pre

- tax), irrespective of whether these costs in fact remain with the plant owner or transferred to customers or tax payers. The commenter implies that EPA looked strictly at the social costs to determine the impacts of the regulatory options, but as described in the preamble and discussed in the RIA, EPA’s conducted various analyses (using either pre

- tax or after

- tax costs as appropriate), including cost

- to

- revenue screening

- level analyses of fi nancial stress on plant owners conducted using after

- tax compliance costs (see Chapter 3 of the RIA f or the final rule). Also see the preamble for the final rule.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 107 Extremely High Capital and O&M Costs The need to use expensive metals and alloys in the concentrators, evaporators, and crystallizers drives up the capital cost of the ZLD option. Materials such as titanium, CD4MCu, and Hastelloy C help reduce scaling and plugging of vessel internals as well as corrosion, but does not prevent it from occu rring. In fact, process redundancy will be required due to the frequent outages to clean the equipment. Based on experiences from the Enel Brindisi plant in Italy 33 , as the scale begins to build up in the brine concentrator, the heat transfer to the liquid reaches a breaking point and the system has to be taken offline to remove the scale. The scaling and corrosion issues with this vapor

- compression system will add significantly to the overall capital and O&M costs. For thermal ZLD systems, the concentratio ns of calcium and magnesium in the wastewater must be reduced to lower the scaling potential of the water at high temperature. Again using a 410 gpm system as an example, Southern estimates that chemicals for use in the hardness reduction step will cost $8 .5 million per year. In addition to the cost of the chemicals, the chemicals unloading will add to the manpower requirements and add to the plant’s traffic congestion. Moreover, the solids bagging, transport and storage facilities needed to support this te chnology are very expensive. In addition, these support systems will require extra labor not currently covered in plant operations. The O&M staff must also be augmented at each plant at a significant cost. Each system will require a system expert, and most system experts will need to be chemical engineers or be chemists familiar with the technologies. In addition to the ZLD system itself, the O&M costs of the generation facility will be greatly impacted. All power plant systems will have to be cycled much m ore often than originally designed due to the unreliability of the ZLD equipment. That will greatly increase plant O&M costs. Every time the operator must start or stop a power facility, the equipment suffers fatigue. The heating and cooling process is ver y damaging to many of the high temperature systems, especially the boiler. Boilers that are designed for baseload operation that are then cycled on and off suffer accelerated damage to the boiler tubes and must be more frequently repaired or replaced.
The total capital cost for a ZLD system will be extremely expensive. For Southern’s Plant Bowen, the capital cost for a full thermal ZLD design at its plant is estimated to be between $203

- $238 million, with an O&M cost of $19.3

- 19.6 million annually. The sy stem would have a capacity to treat 400 gpm FGD wastewater at a 40,000 ppm chloride level. Also, the labor needed to maintain the ZLD system is extremely high. Approximately 10

- 12 highly knowledgeable and well

- trained personnel would be needed to maintain the ZLD system.

33 Donadona S., M. Di Blasi, and V. Cenci. 2009. “ENEL ZLD Systems for FGD Wastewaters First Operating Experience,” presentation at VGB Workshop on Flue Gas Cleaning, Rome, June 16

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- 108 Comment Response: EPA acknowledges that the evaporati on system is more costly than the other technologies considered for treating FGD wastewater. As described in preamble section VIII, EPA did not select evaporation as the basis for BAT limitations for FGD wastewater at all steam electric power plants becau se of the high cost of possible regulatory requirements based on evaporation for FGD wastewater. For purposes of the final rule, EPA conducted a screening

- level evaluation of the costs to treat FGD wastewater using an evaporation system costs and determine d that the cost of limitations based on evaporation would be more than $800 million more expensive, on an annual social cost basis, for the industry as a whole than the cost of limitations based on chemical precipitation plus biological treatment. Given th e high costs associated with the technology, and the fact that the steam electric industry is facing costs associated with several other rules in addition to this rule, EPA decided not to establish BAT limitations for FGD wastewater based on evaporation fo r all steam electric power plants. Nevertheless, as described in Section VIII of the preamble, the final rule does establish a voluntary incentives program under which steam electric power plants can choose to be subject to more stringent BAT limitations f

or FGD wastewater based on evaporation. However, EPA disagrees with the commenter that a VCE system designed to treat 400 gpm of FGD wastewater would have capital costs greater than $200 million and annual operating and maintenance costs greater than $19 m illion. EPA’s updated capital costs for the final rule estimate systems treating 410 gpm of FGD wastewater would have capital costs less than half the cost suggested by the commenter. EPA also disagrees that the cost for softening chemicals a 410 gpm sys tem would be $8.5 million. EPA’s estimated cost for softening chemicals for a 410 gpm system are less than $5 million. EPA recognizes that wetted parts of the system are manufactured with expensive alloys such as titanium alloys to withstand high chlorid e concentrations in the concentrated FGD wastewater and these types of alloys can add considerable expense for replacement parts. The evaporation portion of the system and the crystallizer will require additional inspection and cleaning to remove scale. Ad ditionally, the crystallizer portion will require more frequent cleaning to remove scale. This is accounted for in EPA’s cost assessment of technological availability and cost, including labor and maintenance costs. EPA does not agree with the commenter’s assertion that the evaporation technology is unreliable and that issues associated with the treatment system would force the plant to cycle and shut down the boiler (i.e., essentially the entire power plant) more frequently. The technology has sufficient r edundancy to ensure continuous operation throughout the times that the plant is generating FGD wastewater. EPA agrees in part with the commenter that additional chemicals will be required for the evaporation system. For the final rule, EPA included costs soda ash polymer, sulfuric acid, sodium hydroxide (caustic), anti

- foam and anti

- scalant to operate the system. EPA did not include costs for additional lime since the wastewater is treated by lime precipitation before entering the VCE system.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 109 Regarding th e number of operators required for the system, see response to DCN EPA

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- A1, Excerpt Number 106.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 63 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: APPA and other industry associations have been concerned about the unknown costs for coal ash or coal combustion residuals. This is another example of “the law of unintended consequences” where EPA should fully flesh out these issues before revising a standard that might result in salt requiring special disposal. APPA saw no attempt to calculate these cost s to any utilities in this rulemaking

— especially those that are smaller and not close to special landfills. Further the salt generated by the ZLD process can be categorized as a hazardous waste if the hazardous constituents are not effectively removed. For example, selenium is not successfully removed during the physical/softening pretreatment stage, and most is present in the final solid generated. It is possible for the solid to contain hundreds of parts per million (ppm) selenium and fail the Toxicity Ch aracteristic Leachate Procedure (TCLP) test. If the TCLP test under RCRA is failed, these chemicals could be categorized as hazardous waste (subtitle C), and treating and disposing these solids will be technically difficult and very costly. EPA never figu red these costs into its cost analysis for ZLD. Nor did EPA look at the environmental risks. Given the physical properties of ZLD materials, as well as potential long

- term issues in landfills, further research is needed to ensure that ZLD materials remain a solid and are stable in landfills. Technological development of additives and research on performance need to be conducted to ensure that ZLD materials can be permanently sequestered in a landfill. While research in this area is ongoing, little data exis t on how effectively ZLD materials can be stabilized. Additionally, if research eventually shows that stabilization of ZLD materials is required prior to disposal, there will be an associated cost that must be included into the overall economics of a ZLD t echnology. For example, if an additive such as cement has to be used, over 10 percent to as much as 50 percent, may need to be added to actually stabilize ZLD materials. The costs of such large volumes of additives (along with the indirect cost of lost lan dfill storage space due to the additional material) could make a given ZLD technology economically infeasible. To develop better stabilization technologies will require a significant amount of research and time. APPA did not see anything in the proposed ru le’s cost analysis about the use of additives or solidifiers or the hauling of these salts for any utilities. APPA believes that these costs, along with the cost ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 110 the ZLD, make the ZLD uneconomical for the purposes of regulating selenium and other pollut ants. APPA believes that EPA’s final rule should address all of these technical questions if any of EPA’s Options using ZLD is selected. Comment Response: Regarding the generation of hygroscopic salts in the evaporation system, see response to DCN EPA

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- A1, Excerpt Number 18 in Comment Code 11.a. The plants that are currently using the evaporation technology for FGD wastewater have found that the residuals pass the TCLP test and therefore do not require disposal in a hazardous waste landfill. Regarding the potential for high amounts of selenium in the evaporation sol ids, see response to DCN EPA

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- A1, Excerpt Number 75 in Comment Code 11.d.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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### 3.3 EPA underestimated the cost of chemical precipitation with vapor
compression evaporation/atmospheric crystallization (CP + VCE) treatment for the industry. EPRI’s annualized cost estimate is approximate ly twice EPA’s estimate. EPRI calculated the estimated cost of chemical precipitation with vapor

- compression evaporation/atmospheric crystallization (CP + VCE) treatment for the industry based on values shown in Table IX

- 3 of the Effluent Limitations Guide lines (ELG) [EPA 2013a]. Table 3

- 7 compares industry cost estimated by EPA with cost calculated independently by EPRI.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 111 The major differences between the estimates made by EPA and EPRI include the following:

 EPA assumed the same CP system installed as Opt ion 1 and did not modify that system for VCE pretreatment. This approach is inappropriate because additional pretreatment is necessary for VCE (see Section 3.3.1).

 Several costs are missing from EPA’s estimate, as previously discussed in EPRI’s comment on chemical precipitation treatment costs (Section 2.3.2).

 As in its approach to cost estimation for chemical precipitation and biological treatment, EPA did not use standard engineering cost factors when calculating the total installed cost from vendor estim ates. Thus, EPA’s cost estimates do not appropriately include all line items needed for developing estimates of total installed costs.

 Other factors, such as sludge generation and labor requirements, may contribute to cost underestimation by EPA. 

### 3.3.1 EPA underestimated CP + VCE costs because the CP system design was not modified for VCE pretreatment. EPA’s CP + VCE conceptual design assumes that the CP system installed as Option 1 would be used for VCE pretreatment. In Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category [EPA, 2013b, page 6

- 2], EPA indicates that the CP system for Option 1 includes lime addition to “a pH set po int of 8.5 S.U. to 9.2 S.U.” for desaturation only. However, EPRI found that a higher pH of approximately 10 to 11 would be needed to remove magnesium upstream of the VCE system based on water chemistry modeling results (see Appendix A.3). By omitting this pretreatment modification, EPA underestimates equipment sizes for lime storage, lime addition, and sludge removal as well as lime and sludge operating quantities. This leads to underestimated capital and O&M costs for the CP + VCE system. Figure 3

- 1 is a block flow diagram of the CP + VCE system assumed in EPRI’s conceptual design.



### 3.3.2 Several costs are missing from EPA’s CP + VCE estimate, as they were from its CP estimate.
EPA’s cost estimates for CP and for CP + VCE are lower than EPRI’s. In both c ases, the cost discrepancy reflects the following differences in approach:Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 112  EPA underestimated the cost factors used to calculate a total installed cost from the vendor estimates [EPA, 2013b]. Standard industry practice for developing budgetary cost estimat es uses cost factors that are more typical of an engineering estimate; these engineering cost factors should be used. (See Section 3.1.1)

 A contingency for miscellaneous unidentified costs was not included by EPA. EPRI applied a 20% contingency to its esti mate, which is standard industry practice.(See Section 3.1.2)

 Use of the mean

— instead of the median

— is statistically more appropriate when applying capacity factors to calculate peak flow rate from average flow rate. The mean is statistically appropriate, as the flow rates are used to calculate plant

- specific costs which are then summed to calculate an industry total. (See Section 3.1.3).

 Use of the peak flow rate

— instead of average flow rate

— is more appropriate for sizing equipment. Using peak flow rat e is standard wastewater treatment design practice when sizing all treatment equipment to ensure compliance. (See Section 3.1.4)

 EPA’s use of reduced flow rates, calculated for plants with flow rates greater than 1,000 gallons per minute (gpm), is likely t o be inappropriate. The evaluation EPA performed was incomplete and did not take into account additional costs beyond the cost of recycle conveyance. (See Section 3.1.5).

 EPA’s method of applying a median sludge factor to each plant to calculate the cost o f solids dewatering equipment is an indirect approach. A more direct and accurate approach would use the influent total suspended solids values supplied in EPA’s Steam Electric Technical Questionnaire Databse “Steam Electric Survey” [ERG, 2012] to calculat e the cost of solids dewatering equipment. (See Section 3.1.6) 

### 3.3.3 To properly estimate total installed costs, all standard engineering cost factors should be applied to VCE vendor cost quotations.
In Incremental Costs and Pollutant Removals for the Prop osed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category , it says “EPA assumes that other capital costs associated with buildings, site preparation, engineering and construction are included in the costs pr ovided by the vendors." [EPA, 2013b, page 6

- 107] EPA should include capital cost factors in addition to VCE vendor cost quotations. Quotations for the VCE vendor package were reportedly provided to EPA by GE and HPD, but costs were treated as confidential business information. Therefore, it is unclear what direct costs (for example, equipment costs) were included in these vendor quotations. EPRI also received vendor quotations to prepare its estimates. The quotations provided to EPRI were described as “turn key supply,” yet did not include several direct cost elements required for the system including buildings, site work, yard improvements, and electrical. Given this experience, EPRI suggests that EPA review its cost estimates to determine which direct cos t elements may be missing. EPA also has omitted several indirect costs for engineering, construction, and miscellaneous unidentified elements. EPA has not acknowledged the additional costs for power plant supportEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 113 engineering and construction services that would be required

— beyond the VCE vendor’s costs

— to install the VCE system. Further, as stated in Section 3.1.2, using zero contingency for a conceptual planning

- level estimate is not consistent with industry guidance; a contingency of at least 20 percent should be included in EPA’s estimate. 

### 3.3.4 Other factors, such as sludge generation and labor requirements, may contribute to cost underestimation by EPA. In several areas, EPA and EPRI made different cost assumptions that may have influenced their cost e stimates. Due to time constraints, EPRI was unable to evaluate the impact of these different cost assumptions in detail.

 The use of VCE sludge factors by EPA may result in cost underestimation: In Incremental Costs and Pollutant Removals for the Proposed E ffluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category , EPA states “According to HPD, softening sludge and crystallizer sludge are generated at rates of 51.43 lb/hr and 17.14 lb/hr for each gpm of FGD wastewate r flow [ERG, 2013; See Appendix 61]. Based on this information, EPA calculated sludge generation rates.” [EPA, 2013b, Section 6.3.7], Using this information, EPRI calculated the total sludge produced by the VCE system, based on EPA’s sludge generation rate s. EPRI estimates higher sludge production than EPA

— a difference potentially due to EPA’s underestimation of the volume of lime softening sludges produced by the VCE system.

 EPA’s labor costs are likely underestimated: In Incremental Costs and Pollutant Re movals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category, EPA states "Operating labor cost includes labor costs for plant staff to operate the vapor

- compression evaporation system. EP A assumed one operator, 24 hours per day is required to operate the system based on observations during a site visit to a U.S. plant operating a vapor

- compression evaporation system to treat FGD wastewater." [EPA, 2013b, page 6

- 109], This approach underest imates labor costs. A total of 5 full

- time employee (FTE) operators should be included for the CP system (as shown in Appendix A

- 1) and 10 operators for the CP + VCE system (as shown in Appendix A

- 3). Therefore, an additional 5 FTE operators would be requi red for the VCE system only. In addition, a Chemical Engineer would likely be required to assist VCE operations full time.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 114 Comment Response: EPA agrees with the commenter that additional pretreatment is needed for the evaporation system and for the final rule, EPA included both capital and annual operating costs for a soda ash softening system, which will remove the magnesium and calcium in the system. As such, EPA disagrees with the commenter that additional lime is needed in the chemical precipitat ion system. EPA agrees with the commenter that standard engineering cost factors should be used to derive the evaporation system cost estimates. As such, EPA updates the direct capital cost factor used in the estimates to use the same revised values used f or the chemical precipitation system. See response to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 9.b. EPA also agrees with the commenter that indirect costs such as contingency should have been included in the installed capital equi pment cost estimate for the VCE system. See response to DCN EPA

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- A1, Excerpt Number 106. Regarding the use of the mean instead of the median value, see response to DCN EPA

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- A1, Excerpt Number 26 in Comment Code 9 .b. Regarding the use of peak flow rate, see response to DCN EPA

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- A1, Excerpt Number 27 in Comment Code 9.b. Regarding the FGD wastewater flow reduction costs, see response to DCN EPA

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- A1, Excerpt Number 28 in Commen t Code 8. Regarding EPA’s sludge factor, see response to DCN EPA

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- A1, Excerpt Number 29 in Comment Code 9.b. EPA agrees with the commenter that underestimating labor requirements during the proposed rule may have underestimated costs. For the final rule, EPA decided to treat evaporation systems similar to processing unit at a chemical manufacturing plants and petroleum refineries, and revised the labor projections accordingly. See response to DCN EPA

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- A1, Excerpt Nu mber 106. Additionally, expertise from chemical engineers can be provided on an as
- needed part time basis but such expertise would not be needed to operate the treatment system on a daily basis.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- 115 Comment Excerpt: We Energies is a member of the Electric Power Research Institute (“EPRI”) 2 and supports EPRI’s evaluation of the CP+VCE technology. EPRI derived total cost estimates and pollutant removals if CP+VCE technology is installed industry

- wide to treat FGD wastewater. EPRI’s annualized cost estimate is approximately twice as high as EPA’s estimate. The major differences between estimates made by EPA and EPRI result from:

- EPA’s assumption that the same CP system installed as Option 1 would be used for Option 5. Contrary to EPA’s assumption, additional pretrea tment would be necessary for VCE.

- A contingency for miscellaneous unidentified costs was not included by EPA. EPRI applied a 20% contingency to its estimate, consistent with standard industry practice for developing an engineering estimate.

- EP RI used the peak flow rate

– rather than the average flow rate

– to size equipment. Using the peak flow rate is standard wastewater treatment design practice when sizing all treatment equipment to ensure compliance.

- EPRI used all standard engineering cost factors to derive the cost estimate, in addition to the VCE vendor cost quotations.

- Other factors, such as sludge generation and labor requirements, may contribute to cost underestimation by EPA. Thus, EPRI calculated the industry

- wide capital costs to be $19,700 million (all amounts are in 2010 dollars unless otherwise specified), compared to EPA’s calculation of $6,243 million. EPRI’s operating costs were also slightly higher compared to EPA’s costs ($1,500 million compared to $1,022 million). Therefore, EPRI’s annualized cost was calculated to be $3,400 million, about twice as high as EPA’s calculation of $1,609 million.

2 The Electric Power Research Institute, Inc. (EPRI) conducts research and development relating to the generation, deli very and use of electricity for the benefit of the public. An independent, nonprofit organization, EPRI brings together its scientists and engineers as well as experts from academia and industry to help address challenges in electricity, including reliabil ity, efficiency, health, safety and the environment. EPRI also provides technology, policy, and economic analyses to drive long

- range research and development planning, and supports research among emerging technologies. EPRI’s members represent more than 9 0 percent of the electricity generated and delivered in the United States, and international participation extends to 40 countries. EPRI does not advocate any regulatory or policy action. EPRI’s objective is simply to document the technical implications of the regulation or policy or the scientific/engineering information that supports such actions.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 116 Comment Response: See response to DCN EPA

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- wide capital costs are a pproximately $19,700 million. EPA’s estimated industry

- wide capital cost for the final rule is $6,190 million. EPA also disagrees with the commenter that the annual operating cost for the VCE system is $1,500 million. EPA estimated annual operating cost s to be approximately $660 million. Differences in costs provided by the commenter and those developed by EPA may be due to the reduction in the number of operating steam electric facilities from proposal to the final rule (116 facilities to 69 facilities ). See DCN SE05730 (Memorandum to the Steam Electric Rulemaking Record: Plant

Specific Compliance Cost Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed by Evaporation).

Commenter Name: Elizabeth E. Aldridge, Hunton & Wi lliams Commenter Affiliation: UWAG Document Control Number: EPA

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h. Extremely High Capital and O&M Costs The need to use expensive metals and alloys in the concentrators, evaporators, and crystallizers drives up the capital cost of the ZLD option. Materials such as titanium, CD4Mcu, and Hastelloy C help reduce scaling and plugging of vessel internals as well as corrosion. Due to the expected frequent outages, process redundancy will also be required, which will add significantly to the overall capital costs. For thermal ZLD systems, the concentrations of calcium and magnesium in the wastewat er must be reduced to lower the scaling potential of the water at high temperature. Again using a 410 gpm system as an example, we estimate that chemicals for use in the hardness reduction step will cost $8,500,000/year. In addition to the cost of the ch emicals, the chemicals unloading will add to the manpower requirements and add to the plant’s traffic congestion. A ZLD system for FGD wastewater treatment will require that operations and maintenance staff be augmented at a significant cost. Most system experts will need to be chemical engineers or be chemists familiar with the technologies. In addition to the ZLD system itself, the O&M costs of the generating facility will be greatly affected. All power plant systems will have to be cycled much more oft en than originallyEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 117 designed due to the unreliability of the ZLD equipment. This will greatly increase plant O&M costs. Every time the operator must start or stop a power facility, the equipment suffers fatigue. The heating and cooling process is very dam aging to many of the high temperature systems, especially the boiler. Boilers that are designed for baseload operation that are then cycled on and off suffer accelerated damage to the boiler tubes and must be frequently repaired or replaced. The total cap ital cost for a ZLD system is estimated to be extremely expensive, according to information received from a UWAG member. Member A estimates that the capital cost for a full thermal ZLD design at its plant is between $203

- $238 million, with an O&M cost o f $19.3

- 19.6 million annually. The system of Member A has a capacity to treat 800 gpm FGD wastewater with 20,000 ppm chloride (“Cl”) level. Member A also stated that the labor needed to maintain the ZLD system is extremely high. Approximately 10

- 12 know ledgeable and well

- trained personnel would be needed to maintain the ZLD system. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 78.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWA G Document Control Number: EPA

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e. ZLD Systems Need Large Amounts of Chemicals
As the FGD blowdown slurry stream reaches the first section of the physical

- chemical (P/C) equipment, the system operators add large amounts of chemicals to begin precipitation, conditioning, and concentration of the blowdown stream. This step is essential for reduc ing the levels of calcium, magnesium, and other hardness

- producing ions, and to lower the scaling potential of the wastewater prior to higher temperature processing. Each reaction in the P/C portion of the treatment system is sensitive to the process param eters of the system. Changes in temperature, concentrations, and flow rate pose difficult challenges to P/C performance. Variability of the parameters affects the P/C’s primary step. This effect cascades through the P/C, changing the pH and the quantity of coagulants and polymers used to capture the metals.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 118 The process to soften the FGD wastewater consumes a large amount of lime and soda ash (Nebrig et al. 2011 at 5). In a study evaluating a ZLD system capable of treating 410 gpm FGD wastewater with 40, 000 ppm chlorine in the water, it was estimated that 40 tons of lime and 80 tons of soda ash per day was needed to be fed to the system. The chemical cost was estimated to be approximately $8.5 million per year. Id. Based on calculations by a UWAG membe r for its plant (410 gpm system), 40 tons of lime (app. $130/ton) and 80 tons of soda ash per day (app. $230/ton) are required to de

- saturate and soften the FGD wastewater prior to evaporation. This is equivalent to approximately five to six trucks of lim e and soda ash per day, assuming 25 tons per truck load.
f. ZLD Systems Produce Large Amounts of Sludge The addition of lime and soda ash to treat FGD wastewater produces a large amount of byproduct sludge to be dewatered and disposed of offsite. UWAG m ember A estimated that the amount of sludge produced by the de

- saturation and softening process is 105 tons per day (at an approximate disposal cost of $3/ton). Member A also estimated that the number of daily truck loads will exceed five truckloads per d ay at 20 tons per truck load. This not only requires additional manpower onsite but also adds to traffic congestion at the site. Comment Response: See response to DCN EPA

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Commenter Name: Chris M. Hobson Com menter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 76 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ZLD Systems Need Large Amount s of Chemicals As the FGD blowdown slurry stream reaches the first section of the physical

- chemical (P/C) equipment, the system operators add large amounts of chemicals to begin precipitation, conditioning, and concentration of the blowdown stream. This st ep is essential for reducing the levels of calcium, magnesium, and other hardness

- producing ions, and to lower the scaling potential of the wastewater prior to higher temperature processing. Each reaction in the P/C portion of the treatment system is sensi tive to the process parameters of the system. Changes in temperature, concentrations, and flow rate pose difficult challenges to P/C performance. Variability of the parameters affects the P/C’s primary step in the P/C. ThisEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 119 effect cascades through the P/C, changing the pH and the quantity of coagulants and polymers used to capture the metals. The process to soften the FGD wastewater consumes a large amount of lime and soda ash (Nebrig et al. 2011 at 5). In a study evaluating a ZLD system capable of treating 410 gpm FGD wastewater with 40,000 ppm chlorine in the water, Southern estimated that 40 tons of lime (at approximately $130/ton) and 80 tons of soda ash (at approximately $230/ton) per day would be needed. Southern estimated the chemical cost to be appro ximately $8.5 million per year. Id. This is equivalent to approximately five to six trucks of lime and soda ash per day, assuming 25 tons per truck load. ZLD Systems Produce Large Amounts of Sludge
The addition of lime and soda ash to treat FGD wastewater produces a large amount of byproduct sludge to be dewatered and likely disposed of offsite. Southern estimates that the amount of sludge produced by the de

- saturation and softening process is 105 tons per day (at an approximate disposal cost of $3/ton) for the 410 gpm ZLD design. Southern also estimated that the number of daily truck loads will exceed five truckloads per day at 20 tons per truck load. This not only requires additional manpower onsite but also adds to traffic congestion at the site.
Comment Response: See response to DCN EPA

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- A2, Excerpt Number 66.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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c. ZLD Systems Have a Large Parasitic Load The crystallizer is the largest user of energy in the ZLD process because it must evaporate the brine concentra te from a concentrated solution to produce a slurry that can be dewatered. Nebrig et al. 2011 at 3. A ZLD project designed to concentrate 60 gpm of wastewater with 95% recovery has been reported to require a 350 hp mechanical vapor compressor for operati ons. One of UWAG’s members estimated a power requirement for its brine concentrator/ crystallizer of 320 kW/100 gallons of treated scrubber blowdown. The member also reported that the equipment will increase carbon emissions per unit energy output and th e cost of station service will lead to lost annual revenue of $1 million.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 120 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 74.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 118 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: many of the instruments that are used for general makeup water for de mineralizers or wastewater plants are not reliable for use in the extremely corrosive environments of scrubber blowdown waste, hot and cold slurries, and level indicators on the brine concentrators and crystallizers. This lack of automatic control means t he operator must be very vigilant. Each operator must interpret data, make adjustments, and then process the changes to ensure the changes are correcting the operational issue. These factors add to O&M costs. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 81.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 121 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 80.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 104 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: APPA’s comments explain that the economics are very different for coal plants with flue

- gas desulfurization (FGD) techn ologies that would need to be retrofitted with ZLD. Comment Response: As described in preamble section VIII, EPA did not select evaporation as the basis for BAT limitations for FGD wastewater at all steam electric power plants because of the high cost o f possible regulatory requirements based on evaporation for FGD wastewater.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- gas desulfurization (FGD) technologies that would need to be r etrofitted with ZLD. Comment Response: See response to DCN EPA

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- 122 Document Control Number: EPA

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- A1 Comm ent Excerpt Number: 44 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA drastically underestimates the costs of ZLD, in terms of capital expenditure, operations and maintenance, and lost generation capacity. Comment Response: EPA agrees with the commenter that the costs for the evaporation system were underestimated at proposal. In response to comments, EPA revised its costs estimates for this technology option for the final rule. See re sponse to DCN EPA

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- A1, Excerpt Number 106. Additionally, regarding lost generation capacity, see response to DCN EPA

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- A1, Excerpt Number 55 in Comment Code 8.c.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 55 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Under a consent decree with the state, Duke Energy has committed to constructing a zero liquid discharge system at its Mayo plant. 200 Duke Energy has selected a mechanical evaporation system designed and supplied by GEA Progress Engineering Inc., which will consist of a falling film evaporator, foll owed by a secondary forced circulation evaporator. The brine will be mixed with fly ash for on

- site landfilling, while the distillate water will be reused at the plant to reduce reshwater demand. 201 Duke Energy is also installing a mechanical evaporation system designed by GEA Processing Engineering at the Roxboro plant, to avoid violations drinking water standards for TDS and chloride in the small lake receiving its FGD wastewater. 202 As of November 2011, GEA was doing final equipment design and balance of plant design at both plants. 203 Although cost estimates are not public, the costs were “at the level that [the utility] [is] comfortable getting the job in at.” 204

200 North Carolina Department of Envt. And Nat. Resources, Special Order by Consent, Mayo Steam Electric Plant, June 26, 2012, ¶2.a(1).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 123 201 Zero

- Liquid Discharge System at Progress Energy Mayo Generation Station, EPA

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202 Deposition of Thomas E. Higgins, CH2M Hill, in Tennessee Clean Water Network v. Tenness ee Dept. of Envt. & Conservation, Case No. WPC10

- 0116 (Feb. 16, 2012), at 122, 134

- 35. Dr. Higgins was an expert witness for Tennessee Valley Authority with respect to the wastewater treatment at the Bull Run plant. Id. at 13, 52.

203 Id. at 123.

204 Id. a t 123

- 24. Comment Response: EPA agrees with the commenter that Duke Energy is installing an evaporation system at their Mayo plant. EPA has not confirmed whether Duke Energy is actually installing the evaporation system at the Roxboro plant.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 124 11.c. FGD VCE

– Pollutant Loadings
Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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9. EPA’s Use of Zero Concentration Values in the Baseline Cause Inflated TWPE Removals for Vapor
- Compression Evaporation Systems
EPA used zero as a concentration in the TWPE removal calculations if it did not hav e any data for that pollutant. For example, EPA did not have data for ammonia or hexavalent chromium for the baseline (settling pond effluent); therefore, the TWPE removals for these pollutants are negative values for chemical precipitation treatment. 20 13 TDD, Table 10

- 3 at 10

- 8. In this case, the negative TWPEs do not significantly impact the total TWPEs removed for chemical precipitation. However, EPA did not have data for hexavalent chromium or cyanide for the vapor

- compression evaporation distillate

. 2013 TDD at 10

- 14. Therefore, the Agency used zero for its concentrations in the TWPE calculations. This resulted in a false 8.5% TWPE removal by the vapor
- compression evaporation system. Comment Response: EPA did not calculate numeric pollutant removals in toxic

- weighted pounds for Regulatory Option F (equivalent to proposed Option 5), as described in the TDD. Option F is the only regulatory option described that would have established requirements applicable to discharges of FGD wastewater from existing sources based on evaporation technology. Because EPA did not calculate numeric pollutant removals in toxic

- weighted pounds for any options that included evaporation for FGD wastewater, the issue raised by the commenter is not relevant to the final rule. EPA did calculate baseline loadings for plants currently operating evaporation systems using the evaporation system concentrations presented in the TDD, but there were no pollutant removals estimated for those plants in any of the regulatory options evaluated for BAT.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- 125 Comment Excerpt: B.1.4.3 CP + VCE Influent and Effluent The benefit of VCE was calculated based on the current treatment in place. For plants that currently have settling ponds, the benefit of CP + VCE was calculated as the average settling pond effluent by coal type. For plants that currently have CP treatment, the benefit of CP + VCE was calculated as the average CP effluent by coal type. For plants that currently have biological treatment, the benefit of CP + VCE was calcu lated as the average biological effluent by coal type. This is because the CP + VCE was assumed to be a zero discharge system and therefore the effluent was assumed to have zero TWPE. Comment Response: See response to DCN EPA

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Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 33 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For vapor compression evaporation treatment (i.e. zero liquid discharge), the rule relies on data from a single facility located in Italy. The only sampling that took place at this facility occurred over just three days in April of 2011. We believe that this small sample size located in a foreign country is insufficient in the United States and does not take into consideration seasonal, climatic, and geographical variables necessary to establish national technology standar ds. Comment Response: EPA disagrees with the commenter that evaporation technology is the same as zero liquid discharge (see responses to comments in code 11 and 11.a). EPA also disagrees that EPA is not permitted to use data “from a single facility loca ted in Italy” and that the “small sample size located in a foreign country is insufficient ...to establish national technology standards.” BAT is to reflect the performance of “the single best performing plant,” and it can rely on data from a single plant, p ilot projects, foreign plants, or technology transfer. Ass’n of Pac. Fisheries v. EPA , 615 F.2d 794, 816 (9th Cir. 1980) (“The legislative history of the 1983 regulations indicates that regulations establishing [BAT] can be based on statistics from a singl e plant.”); Chemical Mfrs. Ass'n v. EPA , 870 F.2d 177, 226, 235 (5th Cir. 1989) (“Congress intended [BAT] limitations to be based on the performance of the single best performing plant in an industrial field.”); Am. Meat Inst. , 526 F.2d at 462

- 463 (“[BAT i s] to be based on a broader range of technologicalEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 126 alternatives, including techniques which exist in operation or which can be applied as a result of public and private research efforts. . . . [R]ather than establishing the range of levels in reference to the average of the best performers in an industrial category . . . the range should, at a minimum, be established with reference to the best performer in any industrial category.”) (citing legislative history) (internal quotations and citations omitted); A m. Frozen Food Inst. v. Train , 539 F.2d 197, 140 (D.C. Cir. 1976) (upholding EPA’s use of data from foreign plants); Kennecott Copper v. EPA , 780 F.2d 445, 447 (4th Cir. 1985) (“In setting BAT, EPA uses not the average plant, but the optimally operating pl ant, the pilot plant which acts as a beacon to show what is possible.”) (citing legislative history); Weyerhaeuser Co. v. Costle , 590 F.2d 1011, 1054 n.70 (D.C. Cir. 1978) (upholding EPA’s decision to use data from pilot plants); Reynolds Metals Co. v. EPA , 760 F.2d 549, 562 (4th Cir. 1985) (upholding EPA’s decision to use data from technology employed in another industry); Cal. & Hawaiian Sugar Co. v. EPA , 553 F.2d 280, 287 (2d Cir. 1977) (upholding EPA’s decision to use data from technology employed in an other industry). As explained in Section 13.1.2 of the TDD, the Brindisi plant in Italy was the only plant for which EPA had data that represented the full evaporation system that EPA was investigating as a potential technology basis for BAT. For the two plants operating in the United States, Iatan does not operate a full chemical precipitation system nor a softening system prior to the evaporator, and the Merrimack plant did not provide any data to EPA for use in its development of the effluent limitation s. EPA has used all available valid data in calculating the effluent limitations established by the ELGs and determined it was sufficient for developing the effluent limitations. See the response to DCN EPA

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- A1, Excerpt Number 62 in Com ment Code 31.c.iii, and Appendix A, Essay Section 3.2.1.1. Also see the Statistical Support Document for Effluent Limitations (DCN SE05733).
This is not the first time EPA has collected data from non

- U.S. plants to supplement data from U.S. plants, espec ially when characterizing best available technology (see EPA

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- 011 from EPA’s development of effluent limitations guidelines and standards for the Pulp, Paper, and Paperboard Category). Therefore, EPA is using the best data available to base the dev elopment of the effluent limitations.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- compliance loadings for the vapor compression

- evaporation option, EPA actually averaged two different waste streams

– brine concentrator distillate and crystallizer condensate

– at a single plant in Brindisi, Italy. EPA collected samples from this facility overEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 127 three days in April 2011. EPA’s baseline average concentrations for this system are contained in Table 10

- 6 of the 2013 TDD at 10

- 15. Comment Response: See response to DCN EPA

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Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 27 External Review Flag: No External Review External Review Incorporat ed into Response: No Comment Excerpt: When compared to EPRI’s calculations, EPA’s calculated pollutant removal estimate is approximately two times greater for treatment by CP+VCE. EPA’s pollutant removal estimate for installing CP+VCE is 2,990,000 TWPE per year and EPRI’s estimate is 1,603,000 TWPE per year. Comment Response: See response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- compliance loadings for the vapor compression evaporation option, EPA average d two different wastestreams

– brine concentrator distillate and crystallizer condensate

– at a single plant in Brindisi, Italy. EPA collected samples from this facility over three days in April 2011. EPA’s baseline average concentrations for this system are contained in Table 10

- 6 of the 2013 TDD at 10

- 15.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 128 Comment Response: See response to DCN EPA

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- 129 11.d. FGD VCE

– NWQI
Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 75 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Solid Disposal Problems for FGD Wastewater Treatment by a Thermal ZLD System Also, ZLD system wastes can be challenging to manage for disposal. For instance, some ZLD treatment system designs that do not apply softening process to save chemical cost, produce a hygroscopic salt that is composed mainly of calcium chloride and magnesi um chloride hydrate (Nebrig et al. 2011 at 8). Because these salts are hygroscopic, they tend to melt down in a short time (minutes to hours), and, if they are landfilled, special equipment or procedures may be necessary. Id. In regions of the country wher e there is significant humidity, salts are naturally hydroscopic and will readily absorb moisture from the air. Data indicate that, at typical summer temperatures and high humidity, a pound of calcium can absorb seventeen pounds or more of water from the a tmosphere. 31 For the case of calcium chloride, it could absorb ambient moisture to the point of liquefying and producing free water. Successful solidification of this material will be needed to landfill it. In addition, little research has been conducted o n transporting ZLD materials to onsite landfills which is a potential option for many utilities. Due to the moisture affinity of the material, the potential to clog silos and conveyance lines needs further investigation. Finally, due to the corrosive natur e of salts, selecting materials of appropriate construction will be very important and may add to the expenses of landfilling. Containing the salt

- laden leachate may necessitate special equipment or procedures at the landfill. Even with special equipment o r procedures, the ability to stabilize chloride salts in a landfill for the long

- term is unproven. We understand that the ZLD wastes generated in Italy have to be transported to Germany for disposal and that there are no proven treatment technologies that can effectively sequester the salts. In addition, depending on the type of coal burned and other factors, the salt generated by the ZLD process may have a high amount of selenium in the final solid generated. Treating and disposing of these solids could be technically difficult and very costly. Also, very little work has been performed throughout the industry to determine the effects of ZLD materials on landfill geotechnical properties. Questions regarding slope stability, compaction properties, and dusting all need to be explored. Additionally, if ZLD materials lead to leaching and production of higher TDS leachates, this could lead to scaling and clogging of leachate collection systems.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 130 Given the physical properties of ZLD materials as well as potential lo ng
- term issues in the landfill, further research is needed to ensure that ZLD materials remain a solid and are stable in the landfill. Technology development toward additives and research on performance need to be conducted on ZLD materials. While research in this area is ongoing, more data is needed on how effectively ZLD materials can be stabilized. Additionally, if research eventually shows that stabilization of ZLD materials is required prior to disposal, there will be an associated cost that must be in cluded into the overall economics of a ZLD technology. For example, if an additive such as cement has to be used, over 10% to as much as 50% may need to be added to stabilize ZLD materials. The costs of such large volumes of additives, along with the indir ect cost of lost landfill storage space due to the additional material, could make a given ZLD technology economically infeasible. To develop better stabilization technologies will require a significant amount of research and time. As a corollary to ZLD di sposal in landfills, in some instances wastewater as well as brine concentrator wastewater has been mixed with or used to condition fly ash before landfill disposal. However, there is apprehension within the industry with this approach. Much work has been performed by researchers in South Africa concerning the mixing of cooling water brines with fly ash. While data from that research at times shows that ash can sequester constituents from the wastewater in the ash, over time the brine migrates back out of t he ash and produces a higher TDS leachate. 32 Since the brine comes back out of the ash, this does not appear to be a true ZLD process.

31 Dow Chemical Company. 2003. Dow Calcium Chloride Handbook: A Guide to Properties, Forms, Storage and Handling (Augus t), p. 13.

32 Fatoba, O. O., L. F. Petrik, W. M. Gitari, and E. I. Iwuoha. 2011. “Fly Ash

- Brine Interactions: Removal of Major and Trace Elements from Brine.” Journal of Environmental Science and Health, Part A, 46 , 1648

- 1666. Comment Response:
The comme nter’s statements focus on “thermal ZLD systems” and “ZLD technology.” The proposed rule did not include “thermal ZLD systems” or “ZLD technology” as the technology basis for any limitations or standards, and the final rule does not establish limitations o r standards based on “ZLD technology.” EPA assumes, based on other statements by the commenter, that the commenter is using the term “ZLD technology” to refer to technology basis applicable to FGD wastewater in proposed Option 5 (Option F for the final rul e), which is evaporation. EPA notes that the evaporation system included as the technology basis includes chemical precipitation and softening pretreatment, which can be tailored to target specific salts, if they are present in the FGD wastewater at a spec ific plant.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 131 Regarding the generation of hygroscopic salts in the evaporation system and issues with containing the salts in a landfill, see response to DCN EPA

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- A3, Excerpt Number 45 in Comment Code 11.a. EPA disagrees that it has not c onsidered costs regarding corrosivity of salts and necessary materials of construction for the evaporation and costs for disposal of the waste solids, see responses to DCN EPA

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- A1, Excerpt Number 26 in Comment Code 11.a.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document C ontrol Number: EPA

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Possible Recontamination of the Environment The ZLD system may release volati le components such as mercury, selenium, boron, or ammonia to the environment from the brine concentrator’s deaerator or the crystalizer’s vacuum system. Mercury could be evaporated in the concentration and crystallization process under some conditions and then be re

- emitted to the ambient air or cycled up if the distillate is reused in the power plant. No current operating ZLD system is monitoring mercury emissions. As much as 80% of mercury could be volatized and condensed into the distillate or released out of the system by vacuum depending on the operating pH. Id. At 9. Another concern in some FGD wastewater is boron. Boron concentrations can be very hig h at some plants. Bromide exists in the coal or could be added to the coal as a method to enhance mercury removal from the flue gas. At low wastewater pH, boronic acid will be present, whereas at high pH boron is present as borate and not volatile. Boronic acid is volatile and will evaporate in the brine concentrator and crystallizer causing problems. Boron will accumulate within the system if the condensate is reused in the FGD. Boron might also be deposited in the mechanical compressor. To mitigate this p roblem, some suppliers include a boron scrubber. Nebrig et al. 2011 at 12. However, the boron scrubber introduces another wastewater stream that must beEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 132 treated. It is unclear whether bromide salt would finally crystallize, evaporate into the ambient air, or fall into distillate. To avoid such secondary contamination, more research is needed to understand the chemistry before installing these systems. Ammonia or ammonium in the FGD wastewater is possible from ammonia slip from the selective catalytic reduction, which uses ammonia to remove NOx in the flue gas. Id. If the brine concentrator or crystallizer is operated at a high pH, then ammonia evaporati on will increase, causing ammonia carryover to the distillate. Id. Comment Response: See response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliatio n: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 110 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: It is particularly unwise to require evaporating wastewater at a time when EPA is so concerned about “energy efficiency” in wastewater treatment systems. See EPA’s guide to Energy Efficiency in Water and Wastewater Facilities, http://r20.rs6.net/tn.jsp?e=001PS770itnYy4OdniWGv3jVur2cEAej3JiYS

ZZY_yUVfOylS8YP59Vob9iO5k

– Q_hKYA

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- U5dE

G3QkAGv88dXtMt__ZaBRd4iNXGUz8QL8FJvn6dAThMYr

- 3BzqliZXVbvEaVubD

. The President’s State of the Union address of February 12, 2013 set a goal of doubling the country’s energy efficiency by 2030. EPA’s n ew Administrator Gina McCarthy has asked state officials to adopt energy efficiency and renewable energy as an air pollution control strategy. “States, Advocates Advance Efforts to Boost Energy Efficiency in Air Plans,” Inside EPA Weekly Policy Report , Ma y 24, 2013. On June 10, 2013, a report by the International Energy Agency called for policies including targeted measures to increase energy efficiency. http://www.worldenergyoutlook.org/media/weowebsite/2013/energyclimatemap/RedrawingEner gyClimateMap.pdf

. Comment Response: As described in Section VIII of the final preamble, as part of the BAT for existing sources, the final rule establi shes a voluntary incentives program for plants that meet FGD wastewaterEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 133 limitations based on evaporation technology. Because EPA cannot know how many plants will elect this approach, for those plants that EPA determined would incur costs to comply with re gulatory option D, it estimated the non

- water quality environmental impacts including energy requirements assuming all plants would elect to install evaporation associated with the voluntary program. As described in DCN SE05940, while energy requirements are higher for evaporation than for chemical precipitation plus biological treatment, EPA found the difference acceptable. This is because EPA estimates that energy increase for evaporation would be less than 0.04 percent of the total electricity generate d by all electric power plants in 2009. Similarly, as described in Section VIII of the final preamble, the technology basis for NSPS and PSNS for FGD wastewater is evaporation. As explained there, EPA evaluated the non

- water quality environmental impacts including energy requirements associated with this technology and determined evaporation has acceptable non

- water quality environmental impacts. EPA assessed the possible impacts of the final NSPS/PSNS on new sources by comparing the incremental non

- water quality environmental impacts associated with the Option F technologies to those of hypothetical new generating units. While the results of the IPM analyses (see the RIA) do not predict any new coal units, EPA analyzed non

- water quality environmental impac ts for a couple of possible model plant/unit configurations. See DCN SE05942. As shown there, the incremental electrical energy and fuel usage associated with evaporation is higher than compared to the other technologies evaluated. However, simply because the values are higher does not mean they are not acceptable. Since there is nothing inherently different between an existing and new source, EPA’s analysis with respect to existing sources is instructive. And, as explained above, EPA found that even if all of the plants incurring costs to comply with BAT/PSES FGD wastewater requirements used evaporation, the increased energy impacts are acceptable. The same rationale applies to NSPS/PSNS, particularly in light of the few, if any, new coal fired plants/units predicted to come on line.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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Another BAT factor to be considered is non

- water

- quality environmental impacts. While operating a mechanical evaporation system does require more energy than a passive settling pond, the current inadequate treatment me thod in use at many plants, the amount of energy is negligible compared to the energy output of the power station. For the Merrimack plant, it was calculated that the evaporation system consumed only 0.8 percent of the energy generated by that station. 245 Moreover, there are energy savings associated with generation of a relatively clean distillate stream by the mechanical evaporation system, which represents water that doesEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 134 not have to be pumped from a nearby water body, treated, or transported long dist ances

— all of which consume energy. In addition, the mechanical evaporation system does generate a small amount of solid waste

— at the Merrimack plant, the volume attributable to the evaporation system was about 5,000 tons per year. To put this number is p erspective, the plant was also estimated to generate 187,000 tons per year of gypsum as a byproduct of the FGD system and 94,566 tons of ash per year. 246 Thus, the additional solid waste created by the ME system at Merrimack was less than 2 percent of the plant’s total solid waste. 247 Moreover, technologies like cold crystallization eliminate the solid waste produced through the softening pre

- treatment.

245 Expert Report of John Koon, Merrimack at p. 12 & Table 5.

246 Id. at 13.

247 Id. Comment Response : EPA agrees evaporation systems have acceptable non

- water quality environmental impacts. See DCN SE05940 and DCN SE0594.Also see response to DCN EPA

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Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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— particularly smaller systems not yet considered. For example, some ZLD treatment system designs produce a hygroscopic salt that is composed mainly of calcium chloride and magnesium chloride hydra te. Because these hygroscopic salts tend to melt down in a short time (minutes to hours), and, if they are landfilled, the chlorides and other substances might end up in the landfill leachate and runoff. APPAEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 135 wonders if this could result in unexpected cons equences in regions of the country where there is significant humidity. Data indicate that, at typical summer temperatures and high humidity, a pound of calcium can absorb seventeen pounds or more of water from the atmosphere. 23 For example, calcium chl oride will absorb ambient moisture to the point of liquefying and producing free water. Thus, research is needed to determine if ZLD byproducts in humid environments would be able to pass filter tests in order to be considered a solid waste. Beyond potenti al filter test issues, little research has been conducted on transporting ZLD materials to onsite landfills as many utilities would plan to do. Due to the moisture affinity of the material, its potential to clog silos and conveyance lines needs further inv estigation. Finally, due to the sale content and the corrosive nature of salts, selecting materials of appropriate construction will be very important and may add to the expenses of landfilling. Containing the salt

- laden leachate may necessitate special eq uipment or procedures at a landfill. Even with special equipment or procedures, the ability to stabilize chloride salts in a landfill over the long

- term is questionable. Through UWAG, APPA understands that the ZLD wastes generated in Italy have to be tran sported to Germany for disposal and that there are no proven treatment technologies that can effectively sequester the salts. It is very important that EPA consider the consequence of ZLD on the disposal side before finalizing the revisions to the industry ’s ELG that might result in an unintended consequence. Assuming that the material can be cost

- effectively transported and placed into a landfill, when considering disposal of ZLD materials, the largest unanswered issue is the long

- term fate of the material . As stated above, due to the high affinity for moisture, much research needs to be performed on whether ZLD byproducts will remain in a landfill over long timespans. As water infiltrates the landfill and comes in contact with the material, little data exi sts on whether the ZLD materials will remain in place or leach out . Also, given the affinity for ambient moisture, the potential for additional moisture collection from the air that could translate to additional landfill leachate exists. Also, very little work has been performed throughout the industry to determine the effects of ZLD materials on landfill geotechnical properties. Questions regarding slope stability, compaction properties, and dusting all need to be explored by EPA before the final ELG rule can be finalized. Additionally, if ZLD materials lead to leaching and production of higher leachates, this could lead to scaling and clogging of leachate collection systems. Additionally, EPA should request through a rulemaking, separate information on the landfilling of salts resulting from ZLD.

23 Dow Chemical Company, Calcium Chloride Handbook

– A Guide to Properties, Forms, Storage and Handling (August 2003), p. 13. Comment Response: See response to DCN EPA

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- 136 Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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d. Solid Disposal Problems Also, ZLD system wastes can be challenging to manage for disposal. For instance, some ZLD treatment system designs produce a hygroscopic salt that is composed mainly of calcium chloride and magnesium chlori de hydrate (Nebrig et al. 2011 at 8). Because these salts are hygroscopic, they tend to melt down in a short time (minutes to hours), and, if they are landfilled, the chlorides and other substances may end up in the landfill leachate and runoff. Id.
In regions of the country where there is significant humidity, salts are naturally hygroscopic and will readily absorb moisture from the air. Data indicate that, at typical summer temperatures and high humidity, a pound of calcium can absorb 17 pounds or mor e of water from the atmosphere. 62 Calcium chloride will absorb ambient moisture to the point of liquefying and producing free water. Therefore, for a humid environment, research is needed to determine if ZLD byproducts would be able to pass paint filter tests in order to be considered a solid waste. Beyond potential paint filter test issues, little research has been conducted on transporting ZLD materials to onsite landfills as many utilities would plan to do. Due to the moisture affinity of the materia l, the potential to clog silos and conveyance lines needs further investigation. Finally, because the salts are corrosive, selecting materials of appropriate construction will be very important and may add to the expense of landfilling. Containing the sal t

- laden leachate may necessitate special equipment or procedures at the landfill. Even with special equipment or procedures, the ability to stabilize chloride salts in a landfill for the long

- term is questionable. We understand that the ZLD wastes genera ted in Italy have to be transported to Germany for disposal and that there are no proven treatment technologies that can effectively sequester the salts. Assuming that the material can be cost effectively transported and placed into the landfill, when con sidering disposal of ZLD wastes, the largest unanswered issue is the long

- term fate of the material. As stated above, due to the high affinity for moisture, research needs to be performed on whether ZLD byproducts will remain in the landfill over long tim espans. As water infiltrates the landfill and comes in contact with the material, little data exist on whether the ZLD materials will remain in place or leach out. Also, given the affinity for ambient moisture, additional moisture collection from the air could translate into additional landfill leachate.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 137 62 Dow Chemical Company, Calcium Chloride Handbook

– A Guide to Properties, Forms, Storage and Handling (August 2003), p. 13. Comment Response: See response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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g. Possible Recontamination of the Environment The ZLD system may release volatile components such as mercury, selenium, boron, or ammonia to the environment from the brine concentrator’s deaerator or the crystalizer’s va cuum system. Mercury could be evaporated in the concentration and crystallization process under some conditions and then be re

- emitted to the ambient air or cycled up if the distillate is reused in the power plant. No current operating ZLD system is monit oring mercury emissions. As much as 80% of mercury is volatized and condensed into the distillate or released out of the system by vacuum depending on the operating pH. Id. at 9.
Another concern in some FGD wastewater is boron. Boron concentrations can be very high at some plants. Boron exists in the coal or could be added to the coal as a method to enhance mercury removal from the flue gas. At low wastewater pH, boronic acid will be present, whereas at high pH boron is present as borate and not volati le. Boronic acid is volatile and will evaporate in the brine concentrator and crystallizer causing problems. Also, boron will accumulate within the system if the condensate is reused in the FGD. Boron might also be deposited in the mechanical compressor

. To mitigate this problem, some suppliers include a boron scrubber. Id. at 12

. However, the boron scrubber introduces another wastewater stream that must be treated. It is unclear whether bromide salt would finally crystallize, evaporate into the ambi ent air, or fall into the distillate. More research is needed to understand the chemistry before installing these systems. Comment Response: See response to DCN EPA

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- 138 Commenter Name: H. Morriss Barney IV Commenter Affiliation: Texas Municipal Power Agency (TMPA) Document Control Number: EPA

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Comment E xcerpt: Zero Liquid Discharge (ZLD) system wastes can be challenging to manage for disposal. Disposing of salt

- laden leachate may necessitate special equipment or procedures at the landfill. Even with special equipment or procedures, the ability to stabi lize chloride salts in a landfill for the long

- term is questionable. The EPA needs to consider the consequence of ZLD on the disposal side before finalizing the revisions to the industry’s ELG to avoid any unintended consequences. Also, very little work ha s been performed throughout the industry to determine the effects of ZLD materials on landfill geotechnical properties. Questions regarding slope stability, compaction properties, and dusting all need to be explored by the EPA before the final ELG rule can be finalized. Additionally, if ZLD materials lead to leaching and production of higher TDS leachates, this could lead to scaling and clogging of leachate collection systems. APPA and other industry associations have been concerned about the unknown costs for coal ash or coal combustion residuals. This is another example of “the law of unintended consequences” where the EPA should fully flesh out these issues before revising a standard that might result in salt requiring special disposal methods.
Further th e salt generated by the ZLD process can be categorized as a hazardous waste if the hazardous constituents are not effectively removed. For example, selenium is not removed during the physical/softening pretreatment stage, and is present in the final solid generated. The solid could contain hundreds of ppm selenium and fail the Toxicity Characteristic Leaching Procedure (TCLP) test. If the TCLP test under RCRA is failed these chemicals might be categorized as hazardous waste (subtitle C), and treating and di sposing these solids will be technically difficult and very costly. The EPA never figured these costs into their cost analysis for ZLD. Nor did EPA look at the environmental risks. Given the physical properties of ZLD materials as well as potential long

- t erm issues in the landfill, further research is needed to ensure that ZLD materials remain stable in the landfill. Technology development toward additives and research on performance needs to be conducted to ensure that ZLD materials can be permanently seq uestered in a landfill. While research in this area is ongoing, little data exist on how effectively ZLD materials can be stabilized. Additionally, if research eventually shows that stabilization of ZLD materials is required prior to disposal, there will b e an associated cost that must be included into the overall economics of a ZLD technology. For example, if an additive such as cement has to be used, over 10% to as much as 50% may need to be added to stabilize ZLD materials. The costs of such large volume sEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 139 of additives, (along with the indirect cost of lost landfill storage space due to the additional material) could make a given ZLD technology economically infeasible. To develop better stabilization technologies will require a significant amount of resear ch and time. It is true that some companies operate ZLD systems successfully, and this may be possible, for example, in a hot, dry climate where it is easy to evaporate wastewater. But that does not mean that ZLD can be accomplished at most sites. Given th e many questions about ZLD systems outlined above, EPA should not force this technology onto power plants. Comment Response: See response to DCN EPA

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- 140 12. FGD Other Treatment Technologies
Commenter Name: Bets y Natz Commenter Affiliation: Institute of Clean Air Companies (ICAC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The proposed effluent limitation guidelines (ELG) includes a provision that encourages plants to eliminate discharges of all process wastewater to surface waters by adopting zero liquid discharge (ZLD) approaches. The provision allows plants that are w illing to achieve this high standard to extend the compliance time frame by 5 years to allow time to implement these solutions. This provision is applauded as a means to encourage the elimination of these wastewater streams while recognizing the substanti al time needed to plan and implement such an approach. In addition to the several ZLD approaches identified in information with the proposed ELG guidelines, another approach currently in practice in the US is evaporation of the wet FGD wastewater in a sp ray dryer. Beyond the above proposed provision for encouraging zero wastewater, the proposed rule currently addresses limiting FGD wastewater from larger plants discharging more than 1000 gpm, but the extent of “flow minimization” is not currently well des cribed. Reducing the quantity of FGD wastewater streams otherwise from plants would clearly provide the intended benefits of the proposed rule and should be included in the rule in a manner to encourage this path for the existing fleet of wet FGD systems. A number of currently available and proven approaches exist that would allow the reduction of the quantity of FGD wastewater including: selecting coals with lower chloride levels thus reducing the need for purging chlorides, installing spray dryers or ot her systems to partially evaporate the wastewater, installing a dry FGD system or other evaporator system on another boiler unit(s) at the same plant and evaporating/partially evaporating the FGD wastewater from that plant while the unit(s) with the system is operating, and installing dry sorbent injection systems that partially remove chloride upstream of a wet FGD system thus reducing the need to purge chlorides. We urge the EPA to encourage and incentivize the partial reduction of FGD wastewater streams through methods as identified here and other innovative approaches. The incentives should recognize the time frame needed to implement many of these improvements. Incentives that recognize substantial reduction in FGD wastewater on an annual basis should be included. The “Anti

- Circumvention Provisions” appear at this point to have sound intentions. If a plant chooses a plant

- wide ZLD approach, these rules do not apply. Also, it should be made clear that processes which take FGD wastewaters and evaporate all or part of the waste water stream, including those that produce a clean condensate, should not be considered as circumvention. These processes recycle and reuse the FGD wastewater. Once the wastewater stream is evaporated, the dissolved and suspended species from the wastewater stream are dried to a solid and collected with the dry fly ash. It should be noted that when the total dissolved solids (TDS)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 141 are dried and added to the fly ash, they may change the properties of the fly ash for disposal or ben eficial use purpose. It is known that TDS contains significant levels of halides. The dried halides are very soluble and thus can increase the halide leachability of the fly ash. Overall, these systems are eliminating or significantly reducing the FGD wast ewater stream that ends up in surface water and no other wastewater streams result from these processes. Likewise, a plant that equips one or more boiler unit with a system with the capability of evaporating the FGD wastewater from another unit should be clarified as not circumventing the provisions of the guidelines. Again the FGD wastewater steam is being reused, the total FGD wastewater ending up in surface water is either eliminated or significantly reduced, and no other wastewater streams are resulti ng from this practice. Technologies are being developed and have been implemented in countries such as Hungary and Romania and have been evaluated in the US that transport fly ash using a dense slurry rather than wet (thin slurry) or completely dry ash han dling. Fly ash from subbituminous coals is both pozzolonic and contains sufficient lime that it has inherent cementitious qualities. Supplements can be added to other types of fly ash to modify its characteristics. In the presence of water, the material will harden within minutes or hours and gain strength and harden over time. Additives can be combined with the ash to reduce the permeability, and thus the leachability of the stabilized solid. To the extent that plant waste water streams can be utilized as the water source for appropriate amendment of the ash, the ash can provide a mechanism to eliminate leachate from the ash impoundment through formation of a stable and impermeable solid. Any leachate from the impoundment can be reintroduced to the proc ess, making this potentially another approach to achieve zero discharge. We encourage EPA to retain language in the final rule that encourages development of innovative ZLD approaches beyond those described in the proposed rule. Comment Response: EPA ap preciates the commenter’s support for a voluntary incentives program in the final rule. The voluntary incentives program has been revised from the proposal. See Section VIII.C.13 of the preamble for a description of the voluntary incentives program that EP A is establishing in the final rule. While the voluntary incentives program establishes limitations based on evaporation technology, plants are free to use any technology they desire to meet the limitations, and thus the program encourages development of i nnovative approaches, as the commenter supports. EPA considered the commenter’s specific suggestion to “encourage and incentivize the partial reduction of FGD wastewater streams” but determined that it would be too difficult to develop the necessary criter ia to implement such an incentives program. Specifically, the commenter does not suggest how one would measure the partial reduction in flow (e.g., how to determine a “baseline” and how to determine a “reduction”), or how to prevent plants from increasing their FGD wastewater flow rate immediately following the publication of the rule to establish a higher baseline such that a reduction could be calculated without any “real” reduction in flow (i.e., reduction achieved by going back to “normal” operation). T herefore, EPA decided it would not be appropriate to establish an incentives program based on “partial reduction of FGD wastewater streams.”Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 142 The final rule does not include any anti

- circumvention provisions related to FGD wastewater. See preamble section VIII.G for more information. As such, the concerns raised by the commenter related to the proposed provisions are no longer applicable. EPA agrees with the commenter that the dense slurry system is capable of achieving the limitations and standards for fl y ash transport water and bottom ash transport water, but the operation of the system itself does not guarantee compliance with the limitations and standards. See response to DCN EPA

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- A2, Excerpt Number 5 in Comment Code 6.g.v. Furtherm ore, the final limitations and standards are based on model BAT technologies, but the rule does not prescribe a specific type of treatment. Therefore, power plants could install and use alternative technologies to achieve the effluent limitations and stand ards. See response to DCN EPA

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Commenter Name: Jared Morrison Commenter Affiliation: Westar Energy Document Control Number: EPA

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- A1 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: we are pleased to inform the United States Environmental Protection Agency (USEPA) of our recent success with a pilot

- scale constructed wetland for polishing of flue gas desulfurization (FGD) wastewater, and our plans moving forward with a full

- scale constructed wetland. The intent of these comments is to explain how the Constructed Wetland Treatment System (CWTS) technology fits into the USEPA’s intent to reduce steam ele ctric generators’ releases into our country’s lakes and waterways. We appreciate EPA’s dedication in this endeavor, and offer the following comments for consideration prior to finalization of the proposed rule.
INTRODUCTION Westar Energy’s largest generating station is the Jeffrey Energy Center (JEC), which is located approximately seven miles northwest of the city of Saint Mary’s in Pottawatomie County, Kansas. The plant owns 10,500 acres of land, much of which is available to the public for huntin g and fishing. The plant operates three 800 MW units fueled by low

- sulfur, Powder River Basin coal. Scrubber Upgrade Project Westar entered into a Consent Decree with the State of Kansas that required the reduction of sulfur oxides at JEC. By 2008, the u pgraded FGD scrubbers were put into operation on each of the station’s three units to be in compliance with the decree. At that time, Westar implemented treatment of the FGD wastewater through the use of hydrocyclones for solids separation, vacuumEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 143 filters for dewatering, clarifiers for solids concentration, and polishing with a chemical treatment system for mercury removal. The treated FGD wastewater was then mixed with the blowdown from the cooling towers and discharged into Lost Creek (which ultimately d ischarges into the Kansas River). The wastewater treatment system has been operating this way since 2008. Antidegradation Process The Kansas Department of Health and the Environment (KDHE) is allowing the discharge of the FGD wastewater and the discharge of cooling tower blowdown to Lost Creek to continue until June of 2014, at which time JEC will begin operation under a recently issued NPDES permit. The FGD wastewater is a new water stream that could affect water quality in the Kansas River. To evaluate whether this new discharge would impact the Kansas River quality, Westar conducted an antidegradation study (attached) in accordance with applicable State of Kansas regulations. As part of this report, Westar reviewed eleven FGD wastewater disposal alterna tives of which five were considered most favorable based on cost, implementation, and technical viability. The remaining six alternatives were evaluated but were determined to be unsuitable for the disposal of the FGD wastewater at the JEC. These options a re summarized below. The technically viable alternatives were:
1. Underground (injection well) injection 2. Process through falling film evaporators and crystallizer 3. Process through reverse osmosis (RO) and crystallizer 4. Process with falling film evaporators, usi ng the brine to condition fly ash for disposal in an on
- site landfill 5. Treatment with constructed wetland; comingle wetland effluent with cooling tower feed water
The other evaluated alternatives found to be unviable were:
1. Apply to agricultural land via irr igation 2. Reuse as dust control on the coal pile 3. Reuse into the make

- up/auxiliary lakes 4. Send to evaporation pond 5. Send to Topeka/Lawrence waste water treatment plant (WWTP) 6. Treatment by a reverse osmosis unit Constructed Wetland Treatment System As part of th e antidegradation study, Westar Energy concurrently elected to initiate, construct, and operate a pilot CWTS to evaluate the effectiveness of metals reduction in FGD wastewater. In early evaluations, the CWTS appeared to be the lowest cost option to meet t he CORMIX

modeled antidegradation limits that was both technically viable and environmentally desirable. The pilot project was implemented in order to validate these evaluations.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 144 The pilot CWTS spans a total wetland area of 2.1 acres and yields a hydrauli c residence time of approximately seven days. During the majority of the time since the start of operation, the CWTS pilot project has received a 50/50 blend of 18,000 gallons per day (GPD) of Kansas River water and 18,000 GPD of FGD wastewater effluent. The FGD wastewater received by the pilot has already been processed upstream with vacuum separation and physical/chemical treatment as previously discussed. Construction of the pilot project was completed in four and a half months at a cost of approximat ely $2.9 million. Kansas State University assisted with the project during the operational phase under a research contract. The University’s research included laboratory column studies of the ability of treatment soil to attenuate the constituents within the JEC FGD wastewater. Results from the pilot project are discussed later within this letter. Three different cell types were constructed in the pilot CWTS. These included free water surface (FWS), vegetated submerged bed (VSB), and vertical flow bed (VF B) systems. FWS cells function in a manner similar to that of a permanently

- flooded, emergent marsh with shallow water depth and a combination of emergent and rooted aquatic species such as cattail, bulrush, water lily and arrow head. VSB cells function s imilar to a fully

- saturated, emergent marsh with high groundwater levels and plant species such as switch grass, inland salt grass, and sedges. VFB cells are similar to VSB cells except incoming water is applied evenly over the surface of the cell, allowin g vertical infiltration instead of horizontal flow. The three different cell types were constructed as shown below.

In the layout shown above, water flows from east to west in two separate treatment lines. Line A consists of the four cells on the north side (top of the drawing), and Line B consists of the four cells on the south side. Both A and B are identical, with cells A1 and B1 (rightmost cells on the drawing) being FWS cells; A2, B2, A4, and B4 being VSB cells; and A3 and B3 being VFB cells. Additi onal photos and diagrams of each cell type are shown below.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 145 Local Public Stakeholder Involvement and Outreach Westar Energy regularly initiates engagement and is very involved with the local community stakeholders. We value the opinions and concerns of those who are ultimately affected by the treatment path chosen. Westar’s intent is to consider the environmental and social issues thatEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 146 matter most to local stakeholders. We’ve dealt with a variety of environmental groups while working through the anti degradation process and operation of the pilot CWTS. Westar has regularly communicated with local environmental organizations, including the Friends of the Kaw and the local chapter of the Sierra Club. Members of these organizations have visited the pilot CWTS site and been given opportunities to provide input on Westar’s FGD treatment plans throughout the process. The result has been a collaborative process that produced solutions not only cost effective for Westar’s customers but that also minimizes Wes tar’s environmental impact. The results of the pilot project and study ultimately lead to a selection of a full

- scale CWTS. This new wastewater treatment plan will not degrade the quality in the receiving water to a point where that water’s designated bene ficial uses are no longer supported. The unique application of this technology supports compliance with water quality based criteria.
PILOT PROJECT RESULTS The pilot project was operational in the design scenario described for approximately two years. Du ring this time, favorable results for metals removal were observed as expected. The results of the pilot project lead to the design and ongoing construction of a full

- scale CWTS at JEC. Constituent Reduction Summary The pilot was successful in the reduction of several priority pollutant metals. Reductions are reported in the table below (full results are included in the attached antidegradation study). Influent and effluent concentrations are that of a 50/50 mixture of FGD wastewater and Kansas Rive r water:

Ecological Risk Assessment Westar Energy completed an ecological risk assessment (ERA) to evaluate potential ecological risks to native flora and fauna. The purpose of the ERA was to evaluate the likelihood of adverse ecological effects that ma y occur as a result of the site

- specific constituentEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 147 concentrations in environmental media. The ERA was based on information and environmental media samples collected from the pilot treatment wetland system at JEC. The majority of the risks associated wi th this site were associated with ingestion of invertebrates by the marsh wren ( Cistothorus palustris ). Draft soil concentration goals for mercury (0.021 mg/kg) and selenium (0.85 mg/kg) were identified in the ERA. The design of the CWTS has provided assu rances that these concentration goals for the surface soil concentrations in the CWTS can be maintained. Full

- scale CWTS design elements that have been implemented restrict and control the uptake of selenium and mercury to the lower treatment soil layer ( located well below the rooting zone of the upper wetland, upper soils and vegetation) so that the risks of uptake are low. However, statistically

- valid surface soil sampling of the CWTS may be utilized ( e.g. , every 5 years) to compare the surface soil con centrations to the ERA

- based thresholds for mercury and selenium. This may be required towards the end of the system’s planned life. The ERA has been a useful tool to guide the full

- scale design. Pilot to Full Scale Design With the information gained from both the operation of the pilot, completion of the ERA, and Kansas State University research, the full scale CWTS design was completed. Several design factors were incorporated specifically as a result of these two projects. The pilot CWTS indicated sever al metals, including selenium and mercury could be effectively polished. The vertical flow bed and vegetative submerged beds in the pilot worked effectively. The free water surface wetland was effective, however this type of wetland represented the greate st ecological risk. Based upon the pilot and Kansas State University column studies, it was determined that a deep vertical flow bed would the most effective treatment design for a full scale CWTS. A vertical flow bed, which does not go through wetting a nd drying cycles, is also anticipated to result in a lower likelihood for constituent releases during these cycles. Considering these factors, the full

- scale design was developed to minimize ecological exposure by introducing the FGD wastewater into the su bsurface within a vertical flow bed (VFB). This design will greatly reduce constituent levels of concern before the wastewater reaches any surface exposure. Full Scale Design The constructed wetland treatment system is designed to have parallel treatment trains or lines so the system can remain operational during maintenance cycles. An equalization pond upstream of the cells will receive the FGD wastewater and normalize the flow into the CWTS cells. Stored FGD wastewater will be pumped from the equalizati on pond to one of two treatment lines. Each of the two treatment lines includes one VFB cell and one vegetated submerged bed (VSB) cell.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 148 Each VFB will be further split into four treatment cells. The VFB cells contain a two

- tiered system where a shallow t ier 1 soil is used for plant growth and the deeper and thicker tier 2 soil provides treatment in an up

- flow condition. The tier 1 soil also serves to isolate FGD pollutants from wildlife. From the VFBs, the wastewater will continue to be treated in the VS Bs. The VSBs have only one soil layer for plant growth and provide additional polishing treatment through the underlying gravel layer while the surface soil maintains acceptable concentrations of mercury and selenium. Once the wastewater has been treated, it may be pumped back to the plant for re

- use in the cooling towers or blended with the cooling tower blowdown before being discharged to the Kansas River. Treated wastewater can also be returned to the equalization pond for temporary storage or returned t o a VFB for additional treatment through the wetland system, if necessary, in a maintenance or upset condition. With the design described, FGD wastewater is actively controlled and monitored through the use of control valves and instrumentation. While con structed wetlands are known to be more passive systems than other treatment technologies, through this design, Westar is still able to maintain control of design flows through the system.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 149 The section view above shows a cut of both VFB cells, and one VSB cell from the west side of the site. All ponds and treatment beds will be lined with a composite liner. Each VSB and VFB cell will have an effluent distribution manifold, water control structure, and vegetated berms. The design treatment capacity of the s ystem will be 160 gallons per minute (gpm). The maximum design flow will be 250 gpm into the equalization ponds. Wetland treatment bed types developed for the system are designed to have little or no standing water to reduce the risk for bioaccumulation of toxic constituents in the food chain. Full Scale Construction/Operation Construction of the full scale CWTS began in May of this year. Earthwork will continue through December 2013. Mechanical and electrical installation will start in the fall of this y ear and will be completed in early 2014. Overall construction will continue through spring 2014, with planned completion and startup in March. At this time, Westar Energy plans to have the CWTS completely operational by April, with additional physical and chemical treatments to be operational shortly thereafter. Jeffrey Energy Center’s new NPDES permit will be effective in June of 2014.
CWTS
- MEETING THE PROPOSED GUIDELINE’S INTENT After reviewing the Proposed Effluent Guidelines, we believe Westar’s curre nt treatment plan meets the general intent of the EPA’s preferred treatment options, several of which include requirements for both physical/chemical and biological treatment of FGD wastewater. Physical/Chemical Treatment, with Biological Polishing
Three of the four preferred options for FGD wastewater treatment as identified by the EPA include a requirement for physical/chemical and biological treatments for FGD wastewaterEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 150 (Option 3b, 3, and 4a). It is our opinion Westar’s current treatment plan meets the intent of the effluent guidelines and should be considered as a suitable treatment path for FGD wastewater. The CWTS will biologically attenuate constituents within the treatment soil. Within the proposed guidelines, wetland systems are not discussed as a viable biological treatment option. While we understand the CWTS is not suitable in every situation, we contend that for JEC, the CWTS is a viable biological technology. Constructed wetlands were only discussed briefly within the guidelines, and the br ief discussion included a description of wetlands as “attractive nuisances that increase wildlife exposure to the pollutants contained in the systems (pg. 34440).” The attraction of wildlife can be mitigated through design however, as was done in the full

- scale CWTS design. This will be discussed in greater detail later in this document. Because of this, constructed wetlands, in this case, should be reconsidered as an acceptable technology in site

specific applications. Economically Feasible As previously noted, extensive work was completed to evaluate available treatment options for FGD wastewater at the Jeffrey Energy Center. As part of the antidegradation study completed for KDHE (and attached to this comment letter), eleven different treatment options were evaluated of which five were considered technically viable and were evaluated to determine the option that would be the best financial investment. A 15

- year Net Present Value (NPV) was calculated for each of these options. The costs were as follows :
FGD Wastewater Treatment Option 15 Year Net Present Value (NPV) Constructed Wetland Treatment System $52.1 Million Deep Well Injection

- Off Site $59.6 Million Brine Concentration with Fly Ash Conditioning $98.2 Million Reverse Osmosis/Crystallizatio n $128.1 Million Evaporation/Crystallization $150.1 Million The costs were prepared assuming that each system would treat 160

- 250 gpm of FGD wastewater. As shown above, the CWTS was more economically desirable than all of the other options evaluated. Mitigating Ecological Risk Westar Energy understood the importance of evaluating ecological risk from the very beginning or our early evaluations of CWTS technology. The design of the full

- scale CWTS was completed to reduce ecological risk as compared wit h other operating constructed wetlands. The equalization basin upstream of the wetland will have rotating beacons installed to discourage birds from landing there. FGD wastewater flowing to the wetland itself will be treated in the subsurface to minimize surface exposure risk. The two

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- 151 reside. Pollutant constituents in the surface water of the VSBs will already have been greatly reduced by having flowed up through the VFBs, and thus pose less risk than the direct exposure to untreated FGD wastewater.
NUMERIC LIMITS AS APPLIED TO FGD WASTEWATER Westar Energy has reviewed the numeric limits proposed in relation to FGD scrubber operation, and as they relate to CWTS pilot data.
Pilot Data The EPA has proposed numeric limits in some of the preferred treatment options for FGD wastewater for the following four constituents: arsenic, mercury, selenium, and nitrate/nitrite as N. While Westar recogn izes that nutrient trading and/or other treatment may be required for nitrates/nitrites, we offer the following comparison table of pilot results vs. the proposed numeric limits for arsenic, mercury, and selenium:

As foot

- noted above, many of the analyti cal results from the pilot study were non

- detect. In these cases, average values were calculated substituting the Method Detection Limit (MDL) for the non

- detections. Because of this, we contend that the CWTS achieved pollutant effluent averages lower th an those shown by the summary data. Comment Response: EPA appreciates the additional information the commenter provided about their plans for the treatment of FGD wastewater at Jeffrey Energy Center. During the rulemaking, EPA considered constructed wetl ands as a potential BAT technology for the treatment of FGD wastewater; however, EPA concluded that because of the extensive land requirements, potential cold

- climate issues associated with open

- air biological systems, up

- front dilution requirements, poten tial for significant dilution from rainfall and stormwater, and attractive nuisance issue, it was not an appropriate BAT technology at a national level. While EPA selected chemical precipitation followed by anoxic/anaerobic biological treatment as the basi s for the BAT effluent limitations and PSES for the treatment of FGD wastewater (except as applied to existing generating units that are oil

- fired or that are 50 MW or less in nameplate capacity), the rule does not prescribe aEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 152 specific type of treatment te chnology. Therefore, the ELGs do not prevent Westar Energy from using the constructed wetland system to achieve the requirements of the final rule. However, EPA notes that the final rule includes a nitrate/nitrite limit, which Jeffrey Energy Center may fi nd requires additional treatment of FGD wastewater to meet the limits. The proposed rule had included an anti

- circumvention provision that would have required that plants demonstrate compliance with FGD wastewater requirements prior to commingling with any other wastestreams. However, the final rule does not include an anti

- circumvention provision related to FGD wastewater. See preamble sections VIII.G and XVI.A.4 for more information.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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‐ fil m reactors without a subsequent polishing stage. Examples of the performance of the various types of reactors for Se removal from various types of wastewaters are given below. An evaluation of a pilot

‐ scale UASB reactor system treating agricultural drainag e water from the San Joaquin Valley, CA, showed removal of 90% of the influent Se (500 ppb) to produce an effluent containing 50 ppb Se. Inconsistent performance was observed, though this was likely caused by temperature variations in the un

‐ insulated pilo t
‐ plant reactors (State of California Department of Water Resources, 2004). Degremont, Inc. (IDI) has commercialized a patented suspended growth anoxic/ anaerobic Se removal system (Kelly et al., 2011) that is marketed under the name iBio®. A full

‐ scale sy stem was installed at the GenOn, Conemaugh Generating Station, in New Florence, Pennsylvania in early 2012 to treat hydroxide

‐ precipitated WFGD wastewater containing 60

‐ 280 ppb total Se. The anaerobic system is followed by an existing aerobic polishing tre atment unit. EarlyEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 153 performance data for the combined anaerobic/aerobic system showed that it produced an effluent total Se concentration in the range 20

‐ 230 ppb (Lau et al., 2012). An upflow fluidized bed biological Se removal technology has been developed by Envirogen Technologies, based in Kingwood, TX (Envirogen Technologies, 2012). This system consists of beds of either sand or granular activated carbon to which the wastewater, a carbon source, and nutrients are added. Biomass that sloughs off the suppo rt material is separated from the effluent by settling prior to discharge. Pilot plants applying the Envirogen technology have been operated on coal mining wastewaters. In one trial, dissolved Se was reduced from 22

‐ 27 ppb to values that did not exceed 4.7 ppb; in a second trial dissolved Se was reduced from 200

‐ 500 ppb to values that did not exceed 10 ppb. Comment Response: EPA appreciates the information provided by the commenter about the additional biological treatment systems for selenium removal. EPA was aware of the installation of the anoxic/anaerobic biological treatment system that consists of suspended growth flow

- through bioreactors (iBio®) at the Conemaugh Generating Station. EPA obtained additional information regarding a pilot stu dy using FGD wastewater that evaluated the Envirogen biological treatment system. See Section 7.1.3.2 of the TDD for additional information. EPA could not find any information describing the use of the UASB reactor system being tested with FGD wastewater a nd, therefore, EPA did not evaluate this technology further.

Commenter Name: Jared Morrison Commenter Affiliation: Westar Energy Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review E xternal Review Incorporated into Response: No Comment Excerpt:

 Constructed Wetland Treatment Systems that mitigate ecological risk through design should be given further consideration as a viable treatment technology for FGD wastewater. CWTS were not giv en thorough consideration by the EPA as a valid treatment option for FGD wastewater. Alternative technologies to what is recommended within the preferred alternatives should be considered.

 The proposed FGD wastewater treatment path for JEC meets the inten t of the proposed guidelines. Comment Response: See response to DCN EPA

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- 154 13. Fly Ash Transport Water
Commenter Name: Dennis Wene Commenter Affiliation: Alcoa Inc.'s Warrick Operations Document Control Number : EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The justification for the zero discharge element of this rule is also problematic in terms of "dissolved metals" and "nutrients". The argument of dissolved metals also fails as the pH is adjusted in the ashpond turning most dissolved metals back to their insoluble hydroxide form and those metals will precipitate out with the ash particles. Th e nutrients analysis doesn't appear plausible based on current data. Ammonia, nitrogen, and phosphorous are not constituents of flyash, which is primarily alumina silicate. The "nutrients" are associated with ammonia slip" from selective catalytic reducti ons units (SCRs). Phosphorous and nitrogen can also be derived from the vast amount of fish currently residing in our ashponds and testing revealed levels slightly above detection levels. Whether this was ash induced or biologically induced is speculativ e, however, at these low levels, the amounts of these pollutants are similar to the source and nature of the receiving water. Regulating for nutrients at these low levels as a justification for zero

- discharge does not make sense.
Therefore Alcoa

- Warrick r equests that the "zero

- discharge" element of the rule be removed and replaced with some mandate for dry

- flyash handling without the requirement for zero discharge of water to ensure that maintenance can be performed or in the event of planned or unplanned failures within the system. Comment Response: EPA disagrees that the “zero

- discharge element of the rule be removed” because of the reasons stated in preamble section VIII.C.2. Regarding the selection of dry fly ash handling as the basis for BAT for fly ash transport water, EPA made that decision based on the availability of the technology and its economic achievability. The final rule record indicates that most of coal and petroleum coke

- fired generating units at steam electric power plants are already a ble to meet the BAT effluent limitations by operating dry ash handling systems. See preamble for more information. See response to DCN EPA

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- 155 subject to zero discharge limitations. Based on EPA’s expanded ash characterization database, and as discussed in Section 6 of the TDD, nitrogen

- based parameters and phosphorus are identified as pollutants of concern in fly ash transport water. Further, EPA does not estimate fly ash compliance costs for Alcoa

- Warrick as it does not fall under the applicability of the final ru le. See DCN EPA

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- A1, Excerpt Number 2 in Comment Code 5.a for more information.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 26 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water: Allow wet sluicing as a backup with a limit of 5% usage annually. While the majority of Duke Energy’s coal units are currently handling fly ash using a dry method or have planned conversions to dry handling, a number of these units maintain wet sluicing as a backup during periods of startup and for unplanned ash handling system outages. The costs required to modify these systems t o eliminate the wet sluicing backup process and still maintain a consistent and reliable dry handling system far outweigh the negligible benefit. Therefore, Duke Energy encourages EPA, at a minimum, to allow a limited amount of wet sluicing for these activ ities. Duke Energy recommends allowing fly ash to be conveyed wet 5% of the total time fly ash is conveyed. For example, if fly ash is conveyed 20 days, one of those days fly ash could be conveyed wet. Comment Response: The final rule does not preclude t he use of any specific technologies (for example, wet sluicing systems) or require that specific technologies must be used. The final rule sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate we t sluicing systems; however, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater. For additional information regarding backup wet sluicing, see response to DCN EPA

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Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 156 Comment Excerpt Number: 85 External Review Flag: No External Review External R eview Incorporated into Response: No Comment Excerpt: Wet Fly Ash Sluicing Should Be Allowed on a Limited Basis for Existing Backup Systems Within the Duke Energy fleet, several stations have converted to primarily handling fly ash in a dry system; howev er, several of these stations rely on wet sluicing of fly ash during start

- ups and system malfunctions, also known as a hydroveyor backup. The Duke Energy coal stations that utilize this backup wet sluicing capability rely on oil for start

- ups. As the un it comes online, the oil is mixed with the fly ash, which affects the marketability and reuse of the fly ash, so this ash must be separated from the marketable ash. Therefore, these units were designed to handle fly ash wet during this initial start

- up per iod and then switch to dry fly ash handling following the start

- up sequence. In addition, several of the components for the dry fly ash systems are shared amongst other units at a site. The backup wet sluicing system enables the units to remain online and still maintain grid reliability if a malfunction occurs within the shared dry fly ash system. Comment Response: The final rule does not preclude the use of any specific technologies (for example, wet sluicing systems) or require that specific technologie s must be used. The final rule sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate wet sluicing systems; however, they must meet a zero discharge limitation for all pollutants in fly ash transp ort water, bottom ash transport water, and FGMC wastewater. Also, see response to DCN EPA

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- up and shutdown periods.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 157 Comment Excerpt: There would be minimal environmental risk with allowing the continued use of these existing backup systems and this analysis demonstrates that it is not cost

- effective to require conversion to 100% dry handling for these units. EPA should consider, at a minimum, allowing facilities to use this backup system for fly ash handling on a limited basis. A wet sluicing limit of no more than 5% of the total time fly ash is conveyed on an annual basis could be established. For example, if fly ash is conveyed 20 days, one of those days fly ash could be conveyed wet. This minimal amount of fly ash transport water would remain subject to the existing BPT effluent limits based on the technology of gravity settling in surface impoundments to remove suspended solids, similar to the “legacy” fly ash transport water. This requirement could easily be implemented, tracked and documented within the NPDES permit. Comment Response: The final rule does not preclude the use of any specific technologies (for example, wet sluicing systems) or require that specific technologies must be used. The final rul e sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate wet sluicing systems; however, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transpo rt water, and FGMC wastewater. For additional information regarding backup wet sluicing, see response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Coop erative Document Control Number: EPA

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- A1 Comment Excerpt Number: 60 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water. EPA has proposed in the Draft Rule to remove fly ash transport water for the definition of “low volume waste” and regulate it separately pursuant to one of two effluent limitation options based on: 1) continued use of surface impoundments or settling ponds (i.e. equal to the current BPT li mits); or 2) dry handling (i.e. zero discharge). EPA’s Options 1 and 2 would set TSS and oil and grease limits for this waste stream equal to existing BPT limits; whereas, Options 3, 3a, 3b, 4, 4a, and 5 (which include all of EPA’s preferred options) would not permit the discharge of any wastewaters associated with this waste stream to waters of the United States. PowerSouth supports regulatory Options 1 and 2. Alternatively, at the very least, PowerSouth requests thatEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 158 EPA allow (or authorize permit writers discretion to allow) facilities to continue to utilize a wet fly ash transport system as a back

- up option in times when the primary dry fly ash system is periodically offline due to inevitable system failures. Comment Response:
The final rule does not preclude the use of any specific technologies (for example, wet sluicing systems) or require that specific technologies must be used. The final rule sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate wet sluicing systems; however, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater. For additional information regarding backup wet sluicing, see response to DCN EPA

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- 4655, Excerpt Number 138 in Comment Code 14.a. The commenter is mistaken in stating that EPA proposed to remove fly ash transport water from the definition of low volume waste. Fly ash transport water is excluded from the definition of low volume waste in the previously promulgated ELGs.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 66 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: PowerSouth urges EPA to adopt regulatory Options 1 or 2 in its final rulemaking, or, in the alternative, include some standard that permits facilities like PowerSouth’s Lowman Plant to continue to employ a back

- up wet fly ash transport system in limited circumstances when the primary dry fly ash system is not available for service due to an unavoidable failure. Comment Response: EPA has selected dry fly ash handling as the BAT basis for fly ash transport water for reasons stated in preamble section VIII. The final rule does not require any specific technologies (for example, wet sluicing systems) that must be used by plants or preclude plants from the use of any technologies. EPA’s f inal rule only sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate wet sluicing systems; however, must meet the zero discharge requirement for fly ash transport water and bottom ash transport w ater established by the ELGs. For additional information regarding backup wet sluicing, see response to DCN EPA

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- 159 Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Contro l Number: EPA

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- A3 Comment Excerpt Number: 133 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Existing units with a wet handling backup system for fly ash should be allowed to operate for a limited amount of time annually. Comment Response: The final rule does not preclude the use of any specific technologies (for example, wet sluicing systems) or require that specific technologies must be used. The final rule sets specific e ffluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate wet sluicing systems; however, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transport water, and FGM C wastewater. For additional information regarding backup wet sluicing, see response to DCN EPA

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Commenter Name: Erin Bartlett Commenter Affiliation: The Large Public Power Council (LPPC) Do cument Control Number: EPA

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- A1 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA Should Maintain the Option to Impound Fly Ash Transport Water from Existing Units in Most Circumstances. Fly ash transport water is produced when the fly ash is gathered and moved after combustion. Under some of the proposed options, facilities will have to completely eliminate fly ash transport water impoundment because no discharge of wastewater pollutants from fly ash transport water would be allowed. 7 In the circumstance where activated carbon injection (ACI) mercury controls capture mercury as part of the fly ash particulate collection system (e.g. in an electrostat ic precipitator), “no discharge” may be an appropriate option. However, that option should not be universally required. When mercury adsorption systems do not result in the addition of soluble mercury to the fly ash waste stream, the chemistry of fly ash i s stable and impoundments provide adequate treatment for transport water. Indeed, as EPA’s lead treatment option for combustion residual (including fly ash) leachate is impoundment, it should also be adequate for transportEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 160 water because they contain the sa me chemicals of concern. Thus, with the exception of systems with ACI mercury controls that result in soluble mercury, impoundment is an appropriate control for transport water. EPA should also allow the use of wet handling of fly ash and impoundments for fly ash transport water in those cases where mercury adsorption systems do not generate soluble mercury in the fly ash, but rather result in stable mercury forms that are not soluble in water. In allowing for this flexibility EPA could, to the extent neede d to address any outstanding environmental concerns, set reasonable numeric limits for specific pollutants of concern present in discharges from fly ash transport water impoundments. Finally, if the final rule does require dry handling of fly ash, EPA shou ld consider providing an exemption for “backup” fly ash sluice systems. Many utilities currently use backup fly ash sluice systems and believe that their continued use of such systems as a backup system for limited periods of time is appropriate and most c ost
‐ effective, instead of installing backup dry handling systems.

7 78 Fed. Reg. 34,458, 34,535 (June 7, 2013). Comment Response: EPA disagrees with the commenter that surface impoundments provide treatment for fly ash transport water that represents the best available technology economically achievable (existing sources) or best available demonstrated control technology (new sources) as those terms are used in the CWA. EPA has selected dry handling rather than impoundment as the BAT basis for fly ash transport water discharged by existing and new sources for reasons stated in preamble section VIII. EPA also disagrees that “facilities will have to completely eliminate fly ash transport water impoundment.” The final rule does not preclude the use of any specific technologies (for example, wet sluicing systems) or require that specific technologies must be used. The final rule sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can operate wet sluicing sy stems; however, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater. For additional information regarding backup wet sluicing, see response to DCN EPA

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- 465 5, Excerpt Number 138 in Comment Code 14.a. Also, as described in preamble section VIII.C.8, “legacy wastewater” includes fly ash transport water generated prior to the date determined by the permitting authority that is as soon as possible beginning Novem ber 1, 2018, but no later than December 31, 2023. Under the final rule, legacy wastewater must comply with specific BAT limitations, which EPA is setting equal to the previously promulgated BPT limitations on TSS in fly ash and bottom ash transport water a nd low volume waste sources for the reasons stated in the preamble to this final rule.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 161 Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 55 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s flawed assumptions in assessing dry handling of fly ash are in turn factored into EPA’s cost

- effectiveness analysis for its proposa l. As a result, EPA’s cost

- effectiveness analysis significantly underestimates the cost of dry handling of fly ash. More specifically, EPA estimates this technology would cost only $27 per TWPE. TDD 8

- 34; accord, 78 Fed. Reg. 34,474. By comparison, UWAG ’s cost

- effectiveness technology for this same technology, with adjustments made in the analysis to address identified flaws in EPA’s assumptions, resulted in a cost estimate of $936 to $4,541 per plant $/TWPE in 1981 dollars. Thus, the $/TWPE for dry fly ash handling retrofits are much higher than the $/TWPE previously approved by EPA in past industry ELG rulemakings. Comment Response: See response to DCN EPA

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- effectiveness.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- fired facilities greater than 50 MW to handle fly ash dry, without discharging sluice water. For the reasons given below , this option cannot be justified based on the existing record, on a cost

- effectiveness basis. It might be that with more data, EPA could justify some treatment for fly ash transport water beyond the 1982 regulations. But EPA would have to reopen the record and collect data on the cost of dry handling.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 162 EPA’s Fly Ash Cost
- Effectiveness Analysis EPA estimates that dry handling of fly ash would cost only $27 per TWPE, as EPA says in the 2013 TDD: 26
EPA also calculated the cost

- effectiveness of particular controls for the wastestreams that would be controlled under the preferred options for existing direct dischargers. The cost

- effectiveness for zero discharge of fly ash transport and FGMC wastewater, as in Option 3a, is $27 per TWPE removed.
APPA notes th at UWAG has evaluated EPA’s cost

- effectiveness analysis for dry fly ash conversions, and it found many flaws, beginning with EPA’s chosen characterization data and running through the agency’s technology costing methodologies. UWAG found EPA’s cost

effecti veness analysis is flawed because it underestimates the costs and overestimates the pollutants attributable to the industry. UWAG’s comments describe in detail EPA’s TWPE and cost methodologies, and UWAG’s cost

- effectiveness analysis of wet

- to

- dry fly ash conversions.

26 2013 TDD at 8

- 34 (footnote omitted); accord, 78 Fed. Reg. at 34,474. Comment Response: EPA disagrees with the commenter that the basis for dry fly ash handling as BAT is not supported by the final rule record. For the reasons stated in pr eamble section VIII and the rulemaking record, EPA has determined that zero discharge of fly ash transport water is technologically available and economically achievable. Therefore, the final rule sets zero discharge of fly ash transport water as BAT for e xisting and new sources. For a summary of EPA’s fly ash transport water compliance costs and pollutant loadings, and ash characterization data, please see response to DCN EPA

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For further discussion on the sufficiency of EPA’s record to set zero discharge limitations for fly ash transport water, please see response to DCN EPA

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- A1, Excerpt 37 in Comment Code 1.c. Also, regarding reopening the record for public comment, p lease see response to DCN EPA

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Commenter N ame: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- 163 Comment Excerpt Number: 51 External Review Flag: No External Review External Review Incorporated into Response: No
Comm ent Excerpt: Other than options 1 and 2, EPA’s proposals for fly ash transport water do not meet the rulemaking objectives identified in section II.B above, and they do not meet the requirements of CWA section 304(b). As a result, EEI and its members do not support options other than options 1 and 2. Comment Response: EPA disagrees with the commenter’s assertion that selection of dry fly ash handling as BAT is not based on accurate, representative data and sound analyses. With respect to the commenter’ s statement that the BAT for fly ash transport water should include only cost

- effective requirements, EPA notes that cost

- effectiveness is not determinative for establishing BAT. The commenter states that the rule should provide for flexible implementation and reasonable compliance deadlines. See the preamble and TDD section 14 for information about implementation and the compliance deadline for the ELGs. See response to DCN EPA

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Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: DP&L believes that none of the options requiring dry handling of fly ash is supportab le either from an economic or an environmental improvement standpoint. Comment Response: See response to DCN EPA

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- 164 Commenter Name: Dorothy Kellogg and Michael Leitman Commenter Affiliation: National Rural Electric Cooperative Association (NRECA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Continued w et handling of fly ash in surface impoundments. EPA should also establish fly ash transport water limits based on treatment in surface impoundments and equal to current BPT limits for fly ash transport water (EPA’s Options 1 and 2). EPA’s record does not s upport dry fly ash handling as cost effective. Comment Response: See response to DCN EPA

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Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Continued wet handling of fly ash transport water. EPA should also establish fly ash transport water limits based on treatment in surface impoundments and equal to current BPT limits for fly ash transport water (EPA's Options 1 and 2). EPA's record does not support dry fly ash handling as cost effective. (See UWAG commen ts Section IX BAT for Fly Ash Transport Water.) Comment Response: See response to DCN EPA

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- 165 Commenter Name: Kevin D. Frizzell Commenter Affiliation: Owensboro Municipal Utilities (OMU) Elme r Smith Station (ESS) Document Control Number: EPA

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10. BAT for fly ash transport water:
EP A should use impoundment equal to BPT in fly ash transport water treatment. The proposed limits of total suspended solids and oil and grease can be met by settling ponds. Converting from the use of settling ponds to dry ash handling systems cannot be justi fied as cost

- effective. Comment Response: See response to DCN EPA

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Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdings Company Document Control Number: EP A

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- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA should adopt Option 1 or Option 2 to regulate fly ash transport water. In the eight proposed options for regulating fly ash transport water under the ELG rule, EPA presented two technologies that could be used to meet effluent standards. Under Options 1 and 2, the best available technology economically achievable ("BAT") for fly ash trans port water is set equal to the current best practicable control technology currently available ("BPT") effluent limitations, based on the use of surface impoundments to remove suspended solids. 15 Options 3a, 3b, 3, 4a, 4, and 5 require zero discharge throu gh the use of dry handling technologies. 16 MidAmerican believes that well designed and well operated surface impoundments can effectively remove suspended solids prior to discharging fly ash transport water. Indeed, EPA even recognizes the effective operat ion of surface impoundments, 17 and identifies surface impoundments as BPT for existing legacy fly ash transport water. Options 1 and 2 would allow industry to continue using a proven, effective method of treating fly ash transport water prior to discharge, while the other options would require facilities to incur unnecessary costs to retrofit to dry ash handling.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 166 15 78 Fed. Reg. at 34461.
16 Id

. 17 Id. Comment Response: See response to DCN EPA

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Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into R esponse: No Comment Excerpt: Given the current, effective practice of treating fly ash transport water through surface impoundments and the significant cost and operational challenges associated with retrofitting facilities for dry fly ash management, Mi dAmerican believes option 1 or 2 should be chosen for the regulation of discharges of fly ash transport water. These options offer the industry a flexible yet effective way of treating the fly ash transport water waste stream. Comment Response: See respo nse to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: PowerSouth believes the record supports the following best available technology options:Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 167 Fly Ash Transport Water

– Continued wet handling and treatment in sur face impoundments. Comment Response: See response to DCN EPA

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Commenter Name: Dean Ellis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA proposes two alternatives for fly ash transport water : (i) existing limits based on impoundments or (ii) zero discharge based on dry handling. Specifically, Options 1 and 2 would set total suspended solids (TSS) and oil and grease limits that can be met by a settling pond. All the other options (3a, 3b, 3, 4a, 4, and 5) would require dry handling of fly ash (i.e., zero discharge of fly ash transport water). Dynegy supports effluent limits for fly ash transport water based on settling in impoundments. Comment Response: See response to DCN EPA

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Commenter Name: Dorothy Kellogg and Michael Leitman Commenter Affiliation: National Rural Electric Cooperative Association (NRECA) Document Control Number: EPA

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NRECA also recommends: Continued wet handling of fly ash in surface impoundmentsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 168 Comment Response: See response to DCN EPA

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Commenter Name: P. J. Becker Commenter Affiliation: City Water, Light and Power (CWLP) Document Control Number: EPA

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- A2 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water CWLP agrees with USEPA technology options 1 and 2 for Fly Ash Transport wastewater effluent limits, which is impoundment. Comment Response: See response to DCN EPA

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Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 23 External Review Flag: No External Review External Review Incorporated into Resp onse: No Comment Excerpt: The state of the record, with the BAT options it supports, is as follows:
Table 2:

Wastestream Record Supports No More than This Option Fly ash transport water Option 1 ImpoundmentEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 169 Comment Response: See response to DCN EPA

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Commenter Name: Lisa Carty Commenter Affiliation: Xcel Energy Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water should utilize impoundment (equal to BPT) as the technology basis for its ELG. Comment Response: See response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 170 Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 101 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
C. NONE OF THE OTHER BAT FACTORS WEIGH S AGAINST DETERMINING THAT DRY HANDLING IS BAT FOR FLY ASH TRANSPORT WATER. The Clean Water Act requires consideration of factors other than technological availability and economic achievability, namely “the age of equipment and facilities involved, the pr ocess employed, the engineering aspects of the application of various types of control techniques, process changes, the cost of achieving such effluent reduction, non

- water quality environmental impact (including energy requirements),” and other factors EP A deems appropriate. 410 None of these factors alters the conclusion that the statute requires EPA to set effluent limits that eliminate the discharge of fly ash transport water because the technology is available and doing so is economically achievable. 41 1 EPA has considered the age of equipment and the age of the plants that would need to convert to dry fly ash handling; specifically, EPA considered the age of equipment and plants in determining the costs of retrofitting existing units. 412 Similarly, EPA considered the engineering aspects of dry vacuum, pressure, and combination systems, and found that they are widely used; EPA used dry vacuum systems as the basis of its cost estimates based in part on EPA's findings that dry vacuum systems can be enginee red for a wider variety of plants than pressure systems. 413 As explained above, the cost of dry fly ash handling can be reasonably borne by the industry. Turning to the final factor, dry fly ash handling has environmental benefits other than water quality. For example, it reduces water consumption. Even in areas of the country where water is not scarce, reducing water withdrawals reduces entrainment and impingement of aquatic organisms and ensures that more water remains in the ground and in surface flows for humans and wildlife. 414 Technologies are commercially available and have been widely used to dry handle fly ash. The cost of converting approximately 66 plants from wet systems to dry systems can be reasonably borne by the industry as a whole. None of the additional statutory factors weighs against determining that BAT for fly ash is dry handling. As a result, sections 1314(b)(2)(B) and 1311(b)(2)(B) of the Clean Water Act instruct EPA to set effluent limits for all steam electric plants that elimina te the discharge of fly ash transport water.

410 33 U.S.C. § 1314(b)(2)(B).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 171 411 See id. § 1311(b)(2)(B).

412 E.g. , Incremental Costs and Pollutant Removals at 7

- 1, 7

- 4; ERG Subcategorization Memo at 2

- 3.

413 TDD at 7

- 28.

414 EA at 6

- 48; Benefit and Cost Analysis at 2

- 11, 2

- 13, 9

- 1 to 9

- 2. Comment Response: For the reasons stated in preamble section VIII and the final rule record, EPA agrees with the commenter that zero discharge of fly ash transport water is technologically available and economically achievable. Therefore, the final rule sets zero discharge of fly ash transport water as BAT for existing and new sources. EPA agrees with the commenter that the environmental benefits of the final rule extend beyond improvements to water quality. See pream ble section XIII for additional information about the environmental improvements associated with the final rule.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 98 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
IV. DRY ASH HANDLING IS BAT FOR FLY ASH TRANSPORT WATER. BAT for fly ash is dry handling because eliminating the discharge of fly ash transport water is technologically and economically achievable. The Clean Water Act provides that, in setting BAT

- based effluent limitations, EPA “shall require the elimination of discharges of all pollutants” in a wastewater stream if EPA find s that it is technologically and economically achievable to do so. 381 The record indicates that technologies for dry handling of fly ash are widely available and the costs can be reasonably borne by the electric power industry. Accordingly, eliminating th e discharge of fly ash transport water is technologically and economically achievable and is BAT. Fly ash transport water is one of the highest volumes of wastewater generated by power plants, and contains high concentrations of toxic pollutants. The ave rage plant that generates fly ash transport water produces 2.4 million gallons of fly ash transport water per day. 382 The electric industry discharged 81.1 billion gallons of fly ash transport water to surface waters inEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 172 2009. 383 Given the volume of these toxic discharges, it is critical that EPA set BAT limits based on dry handling. Indeed, for over 30 years, Clean Water Act New Source Performance Standards have already required dry fly ash handling for new sources, 384 and companies have both built and re trofit hundreds of units that meet this standard. It is long since time that EPA require all existing facilities to do the same. All of the proposed options, except Options 1 and 2, would require dry handling.

381 33 U.S.C. § 1311(b)(2)(A).

382 78 Fed. Reg. at 34,449.

383 Id.

384 See 40 C.F.R. § 423.15(g). Comment Response: See response to DCN EPA

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- A1, Excerpt Number 101.

Commenter Name: Becky Smith Commenter Affiliation: Clean Water Action et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Our organizations support EPA’s proposal to require “zero discharge” of fly ash wastewater for all existing power plants. Wastewater treatment technologies that can drastically reduce or even eliminate discharges of toxic fly ash pollution are already in use at some power plants. Since 1982, new power plants have been required to dry handle their fly a sh, so industry has more than 30 years of experience installing systems that eliminate fly ash transport water. In fact, 80% of existing power plants have already completely eliminated discharges of fly ash wastewater. 7 The remaining 20% of plants that rely primarily on “settling ponds” to treat fly ash are decades behind upgrading to the best available technology. Settling ponds are ineffective at treating dissolved metals and nutrients and when plants discharge wastewater from ash settling ponds into s urface water they can impair water quality and cause ecological damage to aquatic systems. EPA has already documented dozens of cases where power plant water pollution has harmed aquatic ecosystems. 8Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 173 7 Id. at 34,439

8 EPA, Environmental Assessment for the Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating Point Source Category See Appendix A, Tables A

- 1, A

- 8, and A

- 10 Comment Response: See response to DCN EPA

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Commenter Name: Jamie Rhodes Commenter Affiliation: Environment Council of Rhode Island Document Control Number: EPA

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- A2 Comment Excerpt Number: 5 External Review Flag: No External Review External Rev iew Incorporated into Response: No Comment Excerpt: Our organizations support EPA’s proposal to require “zero discharge” of fly ash wastewater for all existing power plants. Wastewater treatment technologies that can drastically reduce or even eliminate discharges of toxic fly ash pollution are already in use at some power plants. Since 1982, new power plants have been required to dry handle their fly ash, so industry has mor e than 30 years of experience installing systems that eliminate fly ash transport water. In fact, 80% of existing power plants have already completely eliminated discharges of fly ash wastewater. 7 The remaining 20% of plants that rely primarily on “settlin g ponds” to treat fly ash are decades behind upgrading to the best available technology. Settling ponds are ineffective at treating dissolved metals and nutrients and when plants discharge wastewater from ash settling ponds into surface water they can impa ir water quality and cause ecological damage to aquatic systems.

7 Id . at 34,439 Comment Response: See response to DCN EPA

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Commenter Name: Becky Hayat Commenter Affiliation: Natural Resources Defense Cou ncil (NRDC) Document Control Number: EPA

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- 174 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Because most coal

- fired generating units are already uti lizing dry fly ash handling practices, we support EPA’s proposal to require zero discharge of fly ash transport water for all existing power plants. A zero discharge standard based on dry ash handling would not only be the most effective method at eliminat ing all discharges of pollutants from fly ash, but it will also eliminate water use associated with current wet sluicing operating systems for handling fly ash, and thereby yielding water savings of over 200 MGD. Comment Response: See response to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry Ash Handling is BAT for Fly Ash Transport Water. BAT for fly ash transport water is dry handling because eliminating the discharge of fly ash transport water is technologically and economically achievable. Fly ash transport water is one of the highest volumes of wastewater generated by power plants, and contains high concentrations of toxic pollutants. The average plant that generates fly ash transport water produces 2.4 million gallons of it ea ch day. The electric industry discharged 81.1 billion gallons of fly ash transport water to surface waters in 2009. Given the volume of these toxic discharges, it is critical that EPA set BAT limits based on dry handling. Indeed, for over 30 years, Clean Water Act New Source Performance Standards have already required dry fly ash handling for new sources, and companies have both built and retrofit hundreds of units that meet this standard. It is long since time that EPA requires all existing facilities t o do the same. Comment Response: See response to DCN EPA

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- 175 Commenter Name: J. Madras Commenter Affiliation: Missouri Department of Natural Resources Document Control Number: EPA

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- A1 Comm ent Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Department believes that Options Iand 2 do not provide enough control of fly ash transport discharges water because both o ptions would maintain the status quo of impoundments for this waste stream. Fly ash transport water is one of the largest volume flows of wastewater from coal

- fired power plants. Impoundments are an out of date technology that do not reflect achievable p ollution controls. Comment Response: See response to DCN EPA

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- 176 13.a. FA Transport Water

– General/Scope
Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A2 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Existing units with a wet handling backup system for fly ash should be allowed to operate for a limited amou nt annually. Comment Response: See response to DCN EPA

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- 177 13.b. FA Transport Water

– Profile
Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 62 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The wet transport system serves as a back

- up to the primary dry system. Spec ifically, the fly ash from Units 2 and 3 at the Lowman Plant can be transported to the ash ponds per the original system design using a sluicing system with hydroveyor exhausters. This system is currently used only as a backup system when the dry fly ash s ystem is not available for service. Unfortunately, the dry handling system is not available for service with some degree of regularity, meaning PowerSouth must often rely upon the back

- up wet system to handle fly ash. Comment Response:
The commenter doe s not provide any specifics related to the why the current dry handling system is not available for service “with some degree of regularity.” See response to DCN EPA

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.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 178 13.c. FA Transport Water

– Wastewater Characterization
Commenter Name: Betsy Natz Commenter Affiliation: Institute of Clean Air Companies (ICAC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Some utilities will choose dry sorbent injection (DSI) to control emissions of HCl for compliance with the Mercury and Air Toxics Standards (MATS). A DSI system is the injection of dry alkaline sorbents directly into combustion flue gas and the subsequen t collection of the sorbents, typically in the particulate control device or, less commonly, in the wet flue gas desulfurization scrubber. Dry sorbent injection sorbents can capture metals like selenium with the fly ash. 3 Whether the DSI reagent increases the capture of a specific gas phase metals or not, there are at least two new mechanisms that then impact the leachability of the metals present in the fly ash. 4 First, these alkaline sorbents increase the pH of the resulting fly ash when the latter is mi xed with water, resulting in the potential for increased leaching of certain trace elements (Se, As). 3, 5 The change in pH may cause previously sequestered metals to mobilize. This might be an issue for ash ponds or impoundments at plants firing bitumino us coal. For example, the addition of trona to bituminous coal ash has been shown to increase the pH of the fly ash from the range of 7 to 8 to more than 11. 4 Second, it should also be noted that since fly ash is a pozzolan, calcium DSI reagents have th e potential to encapsulate many of these same metals since they trigger cementitious reactions in the resulting mixture. In some fly ashes, this encapsulation mechanism can more than offset the impact of the higher pH resulting from the addition of alkali ne sorbents to the system. 6 In short, the impact of DSI reagents to the system on the fly ash should be considered as the leachability of metals will be impacted.

3 Dickerman, J.; Fitzgerald, H. HCl control by dry sorbent injection (DSI) with hydrated lime. Presented at Air Quality VIII, Arlington, VA, October 23

- 27, 2011. 4 Su, T.; Shi, H.; Wang, J. Impact of Trona

- Based SO2 Control on the Elemental Leaching Behavior of Fly Ash. Energy Fuels 2011, 25, 3514

- 3521. 5 Su, T.; Shi, H.; Wang, J. Impact of Trona

- Based SO2 Control on the Elemental Leaching Behavior of Fly Ash. Energy Fuels 2011, 25, 3514

- 3521. 6 Schantz, M: Sewell, M. The Growth of Dry Sorbent Injection(DSI) and the Impact on Coal Combustion Residue, Prese nted at AWMA Power Issues Conference, Chicago, IL, July 2013Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 179 Comment Response: EPA acknowledges the commenter’s recommendation that EPA should consider the impact of DSI reagents on the leachability of fly ash. However, the commenter states that “ [s]om e utilities will choose [DSI] to control emissions of HCl for compliance with the Mercury and Air Toxics Standards” (emphasis added), but the commenter does not identify any utilities that have installed or plan to install this technology. The final rule d oes not preclude the use of any specific technologies (for example, DSI) or require that specific technologies must be used. The final rule sets a zero discharge limitation for pollutants in fly ash transport water, based on dry handling. As such, EPA expe cts that most, if not all plants, will no longer transfer fly ash to impoundments for storage or disposal, mitigating the potential issues raised by the commenter. EPA acknowledges that the use of such technology could increase the concentrations of certai n pollutants in the combustion residual leachate from landfills containing fly ash; however, EPA determined there is not enough information provided in the comments to incorporate these potential changes into the final rulemaking analyses.

Commenter Name : Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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Comment Excerpt: EPA’s technical and related economic assumptions regarding dry handling of fly ash are flawed. For example, to calculate TWPEs for fly ash transport water, EPA used many of the same flawed sources and data points that it used to derive its bott om ash transport water concentrations. As with EPA’s bottom ash data, EEI believes many of the data points that EPA used to characterize fly ash transport water are invalid and do not reflect typical fly ash transport water. Comment Response: EPA disagr ees with the commenter that “EPA’s technical and related economic assumptions regarding fly ash dry handling are flawed” and that the data sources and data points “used to characterize fly ash transport water are invalid.” In regard to ash characterization data, following proposal, EPA expanded its fly ash and bottom ash characterization dataset in response to public comments. EPA used data collected during the detailed study, industry

- supplied data, and publicly available data sources, including data recei ved during public comment, to characterize pollutant discharge concentrations for ash transport water. See Section 6 of the TDD for a description of the characterization data used to identify POCs in fly ash transport water and bottom ash transport water, and Section 10 for a description of ash impoundment data. See theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 180 response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 191 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA made several major mistakes in developing characterization data for certain wastestreams, particularly bottom ash and fly ash transport water. Comment Response: EPA disagrees with the commenter that the EPA “made sever al major mistakes” in the development of a concentration dataset that is appropriate for characterization of fly ash transport water and bottom ash transport water. Following proposal, EPA expanded its fly ash and bottom ash characterization dataset in res ponse to public comments. EPA used data collected during the detailed study, industry

- supplied data, and publicly available data sources, including data received as part of this and other public comment submissions, to characterize pollutant discharge conc entrations for ash transport water. See Section 6 of the TDD for a description of the characterization data used to identify POCs in fly ash transport water and bottom ash transport water, and Section 10 for a description of ash impoundment data. See the r esponse to DCN EPA

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- 181 13.d. FA Transport Water

– Calculation of Baseline Loads
Co mmenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 71 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: C. EPA’s TWPEs for Fly Ash Transport Water are Grossly Inflated To calculate TWPEs for fly ash, EPA used many of the flawed sources it used to derive its bottom ash concentrations. They include:

 one fly ash effluent sample from the Card inal power plant (collected during EPA’s Detailed Study sampling program, October 2007),

 one fly ash effluent sample from the Mitchell power plant (collected during EPA’s Detailed Study sampling program, October 2007),

 three outfalls from the Form 2C datab ase, which includes permit application data from several power plants from 1994 to 2007, and

 data from the 1982 TDD (Tables V

- 33, plants 1, 2, 3, and 4). As with EPA’s bottom ash data, UWAG believes many of the data points that EPA used to characterize fly ash transport water are invalid and do not reflect typical fly ash transport water using up

- to

- date methods. As with its characterization of bottom ash transport water, EPA’s characterization of fly ash transport water is also badly skewed by EPA’s choice of old and unreliable data. To accurately characterize fly ash transport water, EPA’s many questionable data points should be removed from the analytical database. URS, UWAG’s consultant, reviewed the fly ash data points in detail and prepared the analy sis contained in Attachment 12. In this section, we summarize URS’s findings. EPA estimated total industrywide fly ash TWPEs of 2,521,986, while URS estimates 324,801 TWPEs. Below we explain how URS adjusted the TWPEs to arrive at a better estimate.
In a djusting the TWPEs, URS made several universal corrections. As already discussed, EPA calculated TWPEs from combined ash ponds based on the estimated average concentration of those ponds and then estimated that 86% of the TWPEs were due to fly ash in the combined ponds. URS, in contrast, did not use the concentrations and resulting loadings from the combined ash ponds. The concentrations in the combined ash ponds are inaccurate for fly ash because other wastewaters

– such as coal pile runoff

– often flow into the combined ash ponds. URS therefore assumed that 86% of the flow from the combined ponds was due to fly ash (using EPA’s assumption) but assigned TWPEs based on average concentrations derivedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 182 from fly ash ponds only. Since EPA reported a 262 MGD industrywide flow for combined ash ponds (2013 TDD p. 10

- 28), 86% of that would be 225 MGD. The 225 MGD would increase EPA’s reported daily flow for fly ash ponds to 287 MGD. Using this flow rate and average concentration values reflecting only the recen t fly ash data in EPA’s database, URS calculated a total fly ash TWPE of 324,801. The URS analysis also adjusted the TWPEs by accounting for parameters present in the source water. Estimates of source water values came from the UWAG bottom ash characteriz ation database. URS calculated the average concentration for each pollutant, after discarding high non
- detect and high outlier results, to determine a minimum concentration value of the constituents found in the source water. Clearly, EPA should not have attributed source water pollutants to industry facilities because, under the zero discharge of fly ash transport water option, the source water and its constituents remain in the source waterbody

. See Attachments 8 and 9. URS also removed all data points related to NPDES permit number MN0001007

- SD006 because the data reported as “fly ash transport water” is actually ash handling wastewater mixed with other wastewaters, including FGD wastewater. Therefore, it is inappropriate to use it to characterize fly ash transport water. URS removed all data points from the Mitchell plant sampling episode because, as EPA notes in the Sampling Episode Report, in addition to fly ash sluice water, the ash pond at Mitchell also receives wastewater from a coal washing prep aration plant and treated acid mine drainage. Mitchell Final Sampling Episode Report, EPA

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- 5 and Table 3

- 11, p. 3

- 23. For these reasons, the Mitchell pond should not be used to characterize fly ash transport water. Also, where n ecessary, URS removed any data points used by EPA that were based on nondetect values if the nondetects were high compared to detected values. For example, for silver, the lowest detected value was 0.0004 mg/L. But EPA included two nondetect values for s ilver based on Form 2C data: 0.005 and 0.01. URS excluded these nondetects because they were higher than any detected value. Table 8 below lists the top 10 contributors, according to EPA, of fly ash transport water TWPEs and contrasts them with UWAG’s re sults after reviewing EPA’s data. The table notes the major adjustments to each parameter.
Table 8: EPA’s Top 10 Contributors to Fly Ash Transport Water TWPE RemovalsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 183 As with the bottom ash transport water TWPEs, sulfides dominate EPA’s estimates, making up more than 60% of the total fly ash transport water TWPEs. Because of the problems with sulfide methods and new data showing that sulfides are not present in ash pond discharges (Attachment 5), URS removed all TWPEs attributable to sulfides.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 184 Foll owing similar procedures as those outlined above, URS reviewed all the remaining fly ash discharge data in EPA’s database and made adjustments for each analyte where necessary to remove 1982 Development Document data and other inappropriate data.
As a resu lt of these adjustments, URS calculated total TWPEs for fly ash transport water of 324,801, while EPA’s estimate is about 7.7 times higher, at 2,521,986 TWPEs. After URS corrected EPA’s database to better reflect today’s fly ash transport water discharges, it is clear the database grossly overestimates the TWPEs attributable to fly ash transport water.

26 This table does not reflect adjustments made because of high nondetect values. Those adjustments are documented in Attachment 12. Comment Response:
T he commenter calls into question the validity of data used to characterize typical fly ash transport water, citing an analysis prepared by the commenter’s consultant, URS (DCN EPA

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- A12). Regarding sulfides, source water, high non

- detect s, and the use of old data to determine the concentration of pollutants in fly ash ponds, see the response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d.
The commenter is confused about what EPA means when it refers to a combin ed ash surface impoundment. Where EPA uses the term combined impoundment, it refers to an impoundment that contains both bottom ash and fly ash transport water. A fly ash surface impoundment, a bottom ash surface impoundment, or a combined ash surface impo undment may contain other wastestreams as well. Many commenters did not understand this distinction and this resulted in them misrepresenting how EPA calculated loadings for each of these types of surface impoundments. For a response to EPA’s use of data t o estimate effluent from fly ash surface impoundments that are not from surface impoundments exclusively used to treat fly ash transport water, see the response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d. Combined ash ponds : As explained above, EPA defines a combined ash pond as a pond that contains both bottom ash transport water and fly ash transport water. As reported in the industry survey, some surface impoundments contain bottom ash transport water (and no fly ash tr ansport water), some contain fly ash transport water (and no bottom ash transport water) and some contain both fly ash and bottom ash transport water. EPA identified loadings, however, for bottom ash transport water and fly ash transport water separately. EPA accounted for the pollutant loadings in combined ash ponds or it would have underestimated its identification of loadings. See DCN EPA

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- A1 Excerpt Number 24 in Comment Code 4.b regarding the final rule ash characterization data, inc luding the use of combined fly ash andEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 185 bottom ash data, and the methodology used to separate the loadings for combined ash impoundments into fly ash loadings and bottom ash loadings. As explained in Section 10 of the TDD, to do this, EPA used data from the EPRI PISCES reports to estimate the breakout of the loadings among fly ash and bottom ash contributions. The PISCES reports include information from several plants operating impoundments receiving either fly ash or bottom ash transport water. The reports include a table presenting loadings associated with each stream entering the impoundment for several metal pollutants. EPA used the fly ash and bottom ash loadings presented in the reports to calculate a site

- specific percent loading for fly ash and bottom ash for each pollutant. EPA then calculated an average percent loading for fly ash and bottom ash using data from all available pollutants. EPA determined that, on average, pollutant contributions from fly ash account for 86 percent of combined ash loadin gs, with bottom ash contributing only 14 percent. Regarding the NPDES Permit Number MN0001007

- SD006 : EPA disagrees with the commenter that the results from NPDES permit number MN0001007

- SD006 should be excluded from the loadings analyses on the basis that the outfall also receives FGD wastewater. For the reasons explained in Section 10 of the TDD and in DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d, EPA characterized the concentration data as representative of fly ash impoundment e ffluent if the impoundment outfall receives at least 75% by volume of fly ash transport water and does not receive bottom ash transport water. The impoundment may also receive other types of wastewater, such as FGD wastewater. Based on the information gath ered in the Steam Electric Survey and the commenter

- provided Form 2C database, EPA determined that fly ash transport wastewater represents at least 75% of the volume discharged from this outfall and that it is appropriate to use data from this permit to ch aracterize fly ash impoundment effluent.
About comment related to Mitchell Plant : EPA agrees, in part, with the commenter that the data collected from Mitchell Plant should not be used to characterize fly ash impoundment effluent. Based on information in t he Steam Electric Survey and Sampling Episode Report, EPA determined that fly ash transport wastewater comprises less than 75% of the volume discharged from this outfall. EPA excluded all data representing this outfall from the final loadings analyses.
EPA updated its estimates of TWPE (cost

- effectiveness) for the final rule. See the RIA. Although not required by the CWA, and not a determining factor for establishing BAT/PSES or BADCT/PSNS, cost

- effectiveness analysis can be a useful tool for describing re gulatory options that address toxic pollutants. As presented in preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the selected regulatory option (Option D) have a cost

effectiveness ratio of $ 134 /lb

- eq ($1981). This cost

- ef fectiveness ratio is within the range of cost

- effectiveness ratios for BAT requirements in other industries. Also, see responses to Comment Code 6.h.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 186 Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 84 External Review Flag: No External Review External Revi ew Incorporated into Response: No Comment Excerpt:
EPA’s TWPE Evaluation Inappropriately Uses Undetectable Sulfide Data To calculate the TWPE removed under a “zero discharge” scenario for fly ash transport water, EPA first calculated the average fly ash effluent concentration for fly ash impoundment systems and from combined ash impoundments (fly and bottom ash). EPA relied on data collected from the following four sources 29 :

 EPA ash impoundment sampling data from the detailed study [U.S. EPA, 2009];

 Electric Power Research Institute (EPRI) Power Plant Integrated Systems

- Chemical Emissions Study (PISCES) Reports [EPRI, 1997

- 2001];

 Permit application data (Form 2C), as provided by member companies of the Utility Water Act Group (UWAG) [UWAG, 2008]; an d

 Development Document for Final Effluent Limitations Guidelines, New Source Performance Standards, and Pretreatment Standards for the Steam Electric Point Source Category, EPA 440

- 1

- 82

- 029, November 1982 (1982 TDD) [U.S. EPA, 1982]. However, EPA’s interpretation and use of this data set to calculate the average fly ash effluent concentration is not representative of the actual constituents within fly ash transport water. For example, EPA reported that 1,514,748 TWPE for sulfides would be removed und er a dry fly ash scenario, which accounted for 61% of total TWPE removed. EPA based this removal on the average effluent from a fly ash impoundment system. Upon further examination of the EPA’s database, sulfides were not detected in any of the fly ash tra nsport water samples as shown in Table 3

- 1 below.
Table 3
- 1. Sulfide Results from EPA’s Fly Ash Sluice Water Data

PLANT NAME ANALYTE UNITS NON
- DETECT INDICATOR AMOUNT

IL0000116

- 004 Sulfide (as S) mg/l < 2

WV0001074

- 001 Sulfide (as S) mg/l < 1Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 187 MN0001007

- SD006 Sulfide (as S) mg/l < 0.03
Average 1.01 30

EPA assumed sulfides were present at a concentration equal to the detection limit, which is the highest concentration possible, given the inability to detect sulfides at all, in these samples. EPA then averaged these overly conservative values to determine the effluent concentration. To supplement the very small sulfide data set for fly ash only transport water, EPA utilized data from combined ash impoundments (that contain fly ash and bottom ash transport water) for the calculation of TWPE removed with a “zero discharge” limit for fly ash transport water. For combined ash impoundments, EPA assumed that 86% of the total pollutant loadin g was attributed to fly ash and the other 14% was attributed to bottom ash 31

. However, this assumption is not appropriate for determining the pollutant loading solely from fly ash transport water, or solely from bottom ash transport water. Facili ties manage ash differently, which could affect the concentrations in the ash transport water. For example, the sulfide concentration in the effluent, which was the largest contributor to EPA’s TWPE calculation, is greatly influenced by how a facility hand les its iron pyrites. The additional data EPA used to calculate the TWPE removals was from NPDES permit application data (Form 2C) for combined ash impoundment systems from seventeen (17) facilities. Of the 17 facilities, only 3 reported detectable result s of sulfide in the effluent stream, while the other 14 observations were non

- detectable. Even though the number of non

- detects from the Form 2C data far exceeds the number of detected values, EPA still set these 14 non

detected values as the reporting lim it for their calculation 32 . EPA, also, provided no details of why these three facilities detected sulfides above the detection limit. Given the number of non

detectable results for sulfides, fourteen from combined ash ponds, two from fly ash ponds and 2 fr om bottom ash ponds, it is reasonable to assume these detections are associated with a wastestream or analytical error and are independent of the fly ash sluice water. Although EPA estimated that over half of the industry level TWPE loading was due to sulf ide, EPA failed to conduct sulfide analysis on any fly ash sluice water samples collected for the 2009 Detailed Study Report. Rather EPA used sulfide data reported in NPDES Form 2Cs, collected for regulatory compliance purposes that did not require the low detection limits that are needed for valid estimates of loadings. In addition, applicants do not have to specify what analytical method or methods they used to analyze the wastewater on the Form 2C. Since EPA has more than one approved method for most of the constituents measured at power plants, it is not possible to determine which method was used for each sample for comparison with the others.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 188 EPA stated that “there were more non

- detects than detected values for effluent data for sulfides” 33 and request s comment on whether this data set provides sufficient basis for estimating pollutant loadings for sulfides. Duke Energy contends that it does not, especially since sulfides accounted for a majority of EPA’s calculated TWPE removed (77% for fly ash impound ments and 55% for combined ash impoundments) 34 and were not listed by EPA as a pollutant of concern for ash transport water 35

.

29 78 Fed. Reg. at 34484 and TDD, Section 10.2.2, page 10

- 16 [EPA

- 921

- R

- 13

- 002]; See also Incremental Costs and Pollutant Remo vals document, Section 10.2.2, Page 10

- 13.

30 Average calculated by Duke Energy matches EPA’s average fly ash concentration value for Sulfide (as S) as reported in TDD, Section 10.2.2, Table 10

- 7, page 10

- 18 [EPA

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- 002] demonstrating EPA’s method fo r using nondetect values.

31 TDD Section 10.4.2, page 10

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- 002].

32 Id. at Section 10.2.2, page 10

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- 002]

33 78 Fed. Reg. at 34485

34 Technical Review of Statistical Methods and Data Used by EPA to Estimate Baseline Ash Impoun dment Loadings and TWPEs , AKRF, Inc.(September 2013)

35 TDD, Section 6.7.2, pages 6

- 28 &6

- 29 [EPA

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- 002] Comment Response: Many commenters questioned EPA’s identification of sulfide as a POC in ash transport water. As explained in the response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d, EPA did not identify sulfide as a POC for the final rule and as such did not include it in its identification of loadings. Also, see response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 44 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 189 Comment Excerpt: EPA’s TWPEs for Fly Ash Transport Water are Grossly Inflated To calculate TWPEs for fly ash, EPA used many of the flawed sources it used to derive its bottom ash concentrations. They include:

 one fly ash effluent sample from the Cardin al power plant (collected during EPA’s Detailed Study sampling program, October 2007),

 one fly ash effluent sample from the Mitchell power plant (collected during EPA’s Detailed Study sampling program, October 2007),

 three outfalls from the Form 2C databas e, which includes permit application data from several power plants from 1994 to 2007, and

 data from the 1982 TDD (Table V

- 33, plants 1, 2, 3, and 4). Many of the data points that EPA used to characterize fly ash transport water are invalid and do not refl ect typical fly ash transport water using up

- to

- date methods, as explained in Section V of these comments. As with its characterization of bottom ash transport water, EPA’s characterization of fly ash transport water is also badly skewed by EPA’s choice of old and unreliable data. To more accurately characterize fly ash transport water, EPA’s many questionable data points should be removed from the analytical database. URS, UWAG’s consultant, reviewed the fly ash data points in detail as explained in UWAG’s comments. Southern Company supports the adjustments to the EPA analytical database recommended by URS. As a result of these adjustments, URS calculated total TWPEs for fly ash transport water of 324,801, while EPA’s estimate is about 7.7 times higher, at 2,521,986 TWPEs. URS’s analysis of EPA’s demonstrates how the database grossly overestimates the TWPEs attributable to fly ash transport water. Therefore, Southern Company requests that EPA re

- evaluate the pollutant loadings it attributes to fly ash sluici ng. Comment Response: See response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- 190 Comment Excerpt: Like EPA’s data for bottom ash transport water, the agency similarly relied upon faulty information to justify its regulatory proposals for the m anagement of fly ash wastewater. Particularly, in developing TWPE values, as well as the costs per TWPE removed, EPA relied upon outdated data, as well as data that is either flawed and/or not representative for the industry. UWAG thoroughly outlines the s pecific problems with the data EPA has cited as support for its regulatory findings, along with the agency’s TWPE calculations based upon this imperfect data, which PowerSouth supports and incorporates by reference. See generally UWAG Comments at Section V II. Comment Response: See response to DCN EPA

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Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 8 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: DP&L understands that to calculate TWPEs for fly ash, USEPA used limited sources including :

 one fly ash effluent sample from the Cardinal power plant (collected during USEPA's Detailed Study sampling program , October 2007),

 one fly ash effluent sample from the Mitchell power plant (collected during EPA's Detailed Study sampling program, October 2007),

 three outfalls from the Form 2C database, which includes permit application data from several power plants from 1994 to 2007, and

 data from the 1982 TDD (Tables V

- 33, plants 1, 2, 3, and 4). DP&L believes the limited data points that USEPA used to characterize fly ash transport water are out of date and are not reflective of typical fly ash transport water. Consequently, the data do not support the agency's proposition that conversion of current fly ash transport water treatment from settling ponds to dry ash handling is justified.
Comme nt Response: See response to DCN EPA

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- 191 Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 75 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
3. UWAG’s TWPE Estimates for Dry Fly Ash Handling UWAG compiled non

- CBI fly ash sluice water flow rates from the 2010 ICR database for each unit discharging fly ash sluice water (Part C, Tables C

- 3 and C

- 19) and calculated median fly ash sluice water flow rates based on capacity

- based model plants at ≤ 500 MW, 501

- 1000 MW, 1001

- 1500 MW, 1501

- 2000 MW, 2991

- 2500 MW, and >2500 MWs. UWAG used median flow rates t o reduce the influence of several extreme flow rates (both high and low) reported in the ICR. These extreme flow rates are not representative of typical transport water flow rates. Using these median flow rates along with EPA’s fly ash transport water ch aracterization data for the Cardinal plant, UWAG estimated TWPEs for each model plant. We used the Cardinal fly ash pond effluent data (including the source water contribution) to estimate TWPEs because it represents the most recent data using modern anal ytical data for fly ash transport water. Comment Response: The commenter describes their process to calculate non

- CBI pollutant loadings using only non

CBI flow data reported in the Steam Electric Survey. The commenter calculated an industry

wide “non

- CB I” median fly ash transport water flow rate for several capacity

- based model plants, and eliminated the inclusion of “extreme flow rates” (as defined by the commenter) reported by the industry. EPA disagrees with this approach. As described in Section 4 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) , EPA used both CBI and non

- CBI plant

- specifi c wastewater flow rates as reported by the individual plants in response to the industry survey to estimate plant

- specific pollutant loadings. EPA used data from the Steam Electric Survey to identify those plants that discharge or have the potential to dis charge fly ash or bottom ash transport water. Based on the amount of ash transport water reported to be discharged, EPA calculated plant

specific ash impoundment discharge flow rates and plant

- specific ash impoundment discharge loadings. EPA determined tha t use of available, plant

- specific flow data (including data reported to be CBI) is a more accurate approach for estimation of plant

- specific pollutant loadings for fly ash transport water and bottom ash transport water than using non

- representative non

- CB I median flow rates based on capacity

- based model plants.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 192 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 48 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: TWPE Estimates for Dry Fly Ash Handling
Non

- CBI fly ash sluice water flow rates from the 2010 ICR database were compiled for each unit discharging fly ash sluice water (Part C, Tables C

- 3 a nd C

- 19) and calculated median fly ash sluice water flow rates based on capacity

- based model plants at ≤ 500 MW, 501

- 1000 MW, 1001

- 1500 MW, 1501

- 2000 MW, 2991

- 2500 MW, and > 2500 MWs. The industry analysis used median flow rates to reduce the influence of several extreme flow rates (both high and low) reported in the ICR. These extreme flow rates are not representative of typical transport water flow rates. Using these median flow rates along with EPA’s fly ash transport water characterization data for the Cardinal plant, TWPEs were estimated for each model plant. The Cardinal fly ash pond effluent data (including the source water contribution) was used to estimate TWPEs because it represents the most recent data using modern analytical data for fly ash tran sport water. Comment Response: See response to DCN EPA

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- specific wastewater flow rates in the loadings calculations rather than industry

- wide median flow ra tes based on capacity

- based model plants.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 193 14. Dry Fly Ash Handling
Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water:

 EPA has not justified 100% dry handling for fly ash transport water.

 At a minimum, existing units with a wet handling backup system for fly ash should be allowed to operate for a limited amount of time annually. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 49 for a summary of EPA’s fly ash transport water compliance costs and pollutant loadings. The record indicates that 45% of all plants with wet scrubbers are already able to meet the BAT effluent limitations. These plants either do not discharge their FGD wastewater or they have the BAT technology or more advanced technology that can meet the effluent limitations. See respon se to DCN EPA

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- 4655, Excerpt Number 138 in Comment Code 14.a for more information about backup wet sluicing systems.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 43 79

- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s preferred option for fly ash transport water is dry handling. However, EPA’s characterization data and cost i nformation for dry fly ash retrofits needs to be reevaluated, and therefore its cost effectiveness analysis is erroneous. The record is wholly inadequate to justify dry handling of fly ash as cost

- effective for existing facilities.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 194 Comment Response:
See response to DCN EPA

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Cost

- effectiveness is not determinative for establishing BAT. See the preamble, RIA and record for the final rule. For the role of cost

- effectiveness in EPA’s decisions for the final rule, see re sponse to DCN EPA

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.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: As to fly ash transport water, based on the current administrative record, Southern also finds it is not cost effective to further regulate this discharge based on t he record. Southern recommends that EPA gather more accurate characterization data, correct the errors in its fly ash retrofit cost model, and update its cost effectiveness analysis based on the new data. The new data and the new analysis should be made av ailable for review and comment. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 9. EPA explained elsewhere in the comment response document why it did not solicit another round of public comment on this rulemaking. See res ponse to DCN EPA

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- A1, Excerpt 114 in Comment Code 1.c. regarding reopening the record for public comment. EPA would add that for fly ash transport water, there are a high percentage, about 80%, of the generating units generating fly ash at steam electric power plants already meeting the limits or announcing that they are moving to dry handling and can meet the limits. See the TDD for more information.
For the role of cost

- effectiveness in EPA’s decisions for the final rule , see response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 43Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 195 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA estimates that dry handling of fly ash would cost only $27 per TWPE. EPA says in the 2013 TDD:
EPA also calculated the cost

- effectiveness of particular controls for the wastestreams that would be controlled under the preferred options for existing direct dischargers. The cost

- effectiveness for zero discharge of fly ash transport and FGMC wastewater, as in Option 3a, is $27 per TWPE removed.
2013 TDD at 8

- 34 (footnote omit ted); accord, 78 Fed. Reg. at 34,474 col. 1.
But EPA’s cost

- effectiveness analysis for dry fly ash conversions contains many flaws, beginning with its chosen characterization data and running through its technology costing methodologies. EPA’s fly ash cost

- effectiveness analysis is flawed because it underestimates the costs and overestimates the pollutants attributable to the industry. The following sections will describe EPA’s TWPE and cost methodologies and the industry’s cost

- effectiveness analysis of we t

- to

- dry fly ash conversions. Comment Response: See response to DCN EPA

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- A1, Excerpt Numbers 49 and 51.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Nu mber 27 in Comment Code 6.h.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 46 External Review Flag: No External Review External Review Incorporate d into Response: No Comment Excerpt: Industry Cost
- Effectiveness Analysis for Fly Ash Transport Water To analyze the cost effectiveness of dry fly ash retrofits, industry used EPA’s characterization data for the Cardinal plant (EPA

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EPA’s Response to Public Comments

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- 196 and screening level engineering design estimates of retrofits. The following sections provide more details on the capital cost estimate s and TWPE calculations for dry fly ash retrofits. Comment Response: See response to DCN EPA

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For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- Effectiveness Analysis Using a Model Plant Approach Using the industry capital cost curve, the O&M costs based on fly ash produced, and the TWPEs removed, the $/TWPE was calculated for each capacity

- based model plant (Table 10). The $/TWPE in 1981 dollars range from $936 to $4,541 per plant. Thus, the $/TWPE for dry fly ash handling retrofits are much higher than the $/TWPE previously approved by EPA in past industry ELG rulemakings.
Table 10 : TWPE and $/TWPE Using Cardinal Fly Ash Transport Water Data (Including Source Water Contribution)
Capacity (MW Range) FAS

Flow (MGY) Fly Ash Produced (TPY) TWPE/

Year Removed Annualized

Capital (2012 M$) Annual

O&M (2012 M$) $/TWPE Removed (2012$) $/TWPE

Removed (1981$) <500 64 26,556 277 1.50 1.81 $11,949 $4,541 501

- 1000 709 104,263 3,076 3.31 6.69 $3,252 $1,236 1001

- 1500 1,254 167,136 5,442 5.12 10.68 $2,904 $1,103 1501

- 2000 2,040 233,509 8,857 6.94 14.87 $2,463 $936 9 2001

- 2500 2,357 454,397 10,232 8.75 28.42 $3,633 $1,380 >2500 2,312 553,945 10,036 10.56 34.63 $4,503 $1,711

1981 Cost = 40.2% 2012 CostsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 197 Capacity

– Nameplate MW of plant served by dry fly ash conversion. FAS Flow (MGY)

– Million gallons per year of fly ash sluice water flow rate based on days of operation from the EPA ICR database for each size plant. Fly Ash Produced (Tons/Year)

– Median tons of fly ash produced per year from ICR database for each size plant.
TWPE/Year

– Annual toxic weighted pound equivalents removed. Calculations based on “Model” plant flows and average pollutant concentrations in fly ash pond effluent at AEP Cardinal (EPA SER data). Annualized Capital (Million$)

– Annual capital cost based on 15 year life at 7% interest plus the annual O&M cost for conveyance, transportation and disposal at an offsite landfill. Annual O&M (Million$)

- EPA’s methodology was used to calculate O&M costs for conveyance, transportation and disposal. 10 $/TWPE

– Annualized costs of capital and O&M per TWPE removed for dry f ly ash retrofit. These dollars per TWPE calculations should be understood in light of the following important qualifications:

 Unlike EPA’s estimates, the industry capital cost estimates for dry fly ash handling retrofits include the total capital cost to the plant, including major equipment installed, balance of plant (site work, concrete, piping, electrical, mechanical, and instrumentation and controls), engineering (design, SDC, and startup), profits and overhead (subcontractor and general contractor cos ts), and miscellaneous unidentified costs (contingency).

 The industry analysis used EPA’s O&M cost formulas to calculate the O&M cost for conveyance, intermediate storage, transportation, and disposal. 

 As we have shown, source water is a major contributo r of the TWPEs for bottom ash transport water. Fly ash transport water also would contain similar levels of source water pollutants. Therefore, any fly ash transport water TWPEs should be adjusted to account for source water pollutants. Unfortunately, EPA did not collect a source water sample from Cardinal during the October 2007 sampling event. Therefore, it is impossible to match that sample with an exact source water sample. Nonetheless, EPA should provide a credit for pollutants in the source water used for sluicing fly ash. Without the adjustment for pounds of pollutants present in the intake water, the TWPE calculation penalizes power plants for pollutants naturally occurring in the waterbody (such as iron and aluminum) and also for pollutants added by upstream users. The TWPE calculation is distorted by the significant amounts of intake pollutants. Furthermore, it is erroneous to count the source water pollutants as “removed” when the technology option is dry handling. Under this option, all the source water pollutants will remain in the source water, and there is no reduction of those pollutants in the environment. At a minimum,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 198 EPA should apply the same level of source water reductions documented by the UWAG bottom ash characterization database to the fly ash transport water TWPE calculations.

9 The dip in the cost per TWPE for the 1501

- 2000 MW model plant is due to a higher ratio of fly ash sluice rate to tons of fly ash produced compared to other capacity

- based model plants.

10 EPA’s methodology wa s used for estimating annual O&M costs for dry fly ash handling due to the short comment period. However, the industry is not endorsing EPA’s methodology. Instead, we believe a more precise analysis of the costs should be conducted by EPA. Comment Response : See response to DCN EPA

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- A1, Excerpt Number 47 in Comment Code 14.b for EPA’s review of the costs and capital cost curve submitted by industry. See response to DCN EPA

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- A1, Excerpt Number 15 in Comment Code 26.e for further information related to net cre dits. As described in the TDD and Cost & Loads Report, EPA calculated updated estimates for compliance costs and pollutant removals. Based on this information, as well as other data in the final rule record regarding technological availability and the exte nt to which dry fly ash handling is implemented in the industry, EPA determined that zero discharge of pollutants in fly ash transport water is technologically available and economically achievable. As described in the final rule TDD, EPA estimates that 80 % of the generating units generating fly ash in the point source category already meet the final rule limits, which indicated that the limit is technologically available and economically achievable for the industry as a whole. See preamble section VIII for more information on EPA’s selection of BAT for fly ash transport water, and Sections 9 and 10 of the TDD for more information on EPA’s costs and loads calculations.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 199 Comment Excerpt Number: 51 External Review Flag: No Ex ternal Review External Review Incorporated into Response: No Comment Excerpt: Dry Handling of Fly Ash Cannot Be Justified on a Cost
- Effectiveness Basis. Additionally, UWAG developed industry

- wide $/TWPE for dry fly ash retrofits using unit

specific flows and retrofit costs for those units discharging fly ash transport water. The resulting estimate for dry fly ash retrofits is:

Technology Industry Total Flow Rate (MGY) Industry Total

Capital Costs (million 2010$) Industry Total

Capital Costs (million 19 81$) Industry Cost
Effectiveness (1981$/TWPE) Dry Fly Ash Conversion 87,500 $1,989 $799 $591 Based on EPA’s mischaracterization of fly ash transport water and the cost errors and cost omissions for dry fly ash retrofits, EPA must reevaluate the cost

- effectiveness of dry fly ash handling for the industry. EPA overestimated the TWPEs for the industry by using old, unreliable data. In addition, the total industry

- generated capital costs for dry fly ash retrofits show that EPA underestimated the tota l costs to convert from wet

- to

- dry fly ash handling by not including all of the major cost elements associated with capital retrofit projects. Southern Company recommends that EPA revise their cost effectiveness analysis for wet

- to

- dry fly ash conversions by: (1) using modern

- day fly ash transport water data and correct to calculate TWPEs; (2) correcting the errors in the conveyance and intermediate costs formulas; (3) revising the engineering overhead cost factor, and (4) adding the missing cost elements ( balance of plant, profits, overheads, contingency) to its total capital cost estimates for these retrofits. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 49 regarding fly ash compliance costs and cost

- effectiveness.
In regard to ash characterization data, after proposal, EPA expanded its fly ash and bottom ash characterization dataset in response to public comments. EPA used data collected during the detailed study, industry

- supplied data, and publicly available data so urces, including data received during public comment, to characterize pollutant discharge concentrations for ash transport water. See Section 6.6.4 of the TDD for a description of the characterization data usedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 200 to identify POCs in fly ash transport water a nd bottom ash transport water, and Section 10.2.2 for a description of ash impoundment data. In addition, see response to DCN EPA

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- 4655, Excerpt Number 38 in Comment Code 4.b for a discussion of how EPA used the ash data to determine polluta nts of concern and ash impoundment discharge loads.

Commenter Name: David M. Fraley Commenter Affiliation: City Utilities of Springfield, Missouri (CU) Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Retrofitting dry ash handling systems to existing units would be a more complicated process than EPA estimates. This is true for both bottom ash and flyash waste han dling streams. CU successfully converted one of our power stations from wet to dry flyash handling several years ago and was able to do so in a cost

- effective manner. However, that project occurred in a different time, when the marketability of dry flyash helped defray the economic impact of the conversion project. We would proffer that most, if not all, of the conversion project cost data collected by EPA were similarly advantaged. However, EPA’s final EGU mercury rule and proposed coal combustion residual (CCR) rule have induced a chilling effect on the ash recycling market, as has doubtless been observed by comments filed under those rulemakings. In short, the cost

- effectiveness of future dry flyash conversion projects should in no way be gauged by compar ison to projects completed prior to the mercury MACT and CCR publication. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 45 in Comment Code 14.b for information regarding EPA’s revisions to the fly ash transport water c ost methodology. Also, EPA notes that there may be additional revenue associated with management of dry fly ash handling if plants are able to market dry fly ash. However, EPA’s methodology conservatively assumes that all plants will dispose of moisture

- co nditioned dry fly ash in an on

- site or off

- site landfill. As described in preamble section VIII, EPA’s analysis for the final BAT limitations demonstrates that they are economically achievable for the point source category as a whole, as required by CWA se ction 301(b)(2)(A). EPA performed cost and economic impact assessments using the Integrated Planning Model (IPM). The IPM accounts for impacts on industry, including other rulemakings. For more detail about economic impacts see the RIA.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 201 Regarding the marke tability of ash that is converted to dry handling, EPA notes that market forces have driven many companies to retire or convert fuels (or announce pending retirement or fuel conversion) for a large number of generating units. It is reasonable to expect tha t a number of these retired/retiring generating units marketed CCRs in the past. To the extent that units that were supplying a beneficial use market retire, that likely provides an opportunity for the plants converting their ash handling system. Thus, the plants converting their ash systems may actually have greater market opportunity than EPA considered in its analyses.

Commenter Name: J. Madras Commenter Affiliation: Missouri Department of Natural Resources Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Promulgation of an ELG that requires dry handling of fly ash provides the Department with significant leverage to eliminate this discharge in power plant permits. Elimination of fly ash pollutant discharge is a significant step toward achieving the fundamental goals of the Clean Water Act and Missouri Clean Water Law. Comment Response: EPA agrees with the commen ter and, as described in preamble section VIII, determined that zero discharge of fly ash transport water was both, technologically available and economically achievable for the final rule.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 27 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
3. Fly Ash Transport Water
EPA is proposing two alternatives for the treatment of fly ash transport water; 1) existing BPT limits, and 2) dry handling (78 FR at 34461). EPA Options 1 and 2 would establish TSS and oil and grease limits that can be met through the use of settling ponds. U nder Options 3a, 3b, 3, 4a,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 202 4, and 5, EPA would establish “zero discharge” effluent limitations and standards for discharges of pollutants in fly ash transport water based on the use of dry fly ash handling technologies. The agency’s preferred options (3a , 3b, 3, and 4a) all require dry fly ash disposal without the discharge of sluice water. EPA calculated the cost effectiveness of particular controls for waste streams that would be controlled under the preferred options for existing dischargers. As part o f these calculations, EPA provided a cost

- effectiveness value of $27/TWPE removed (1981$) for zero discharge of fly ash transport and FGMC wastewater, as proposed in Option 3a. This value cannot be supported by data obtained by AEP, demonstrating that this proposed technology option is not cost effective. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 49. For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 31 External Review Flag: No External Rev iew External Review Incorporated into Response: No Comment Excerpt: After adjusting for fully loaded costs, intake pollutants, a 15

- year service life and the costs associated with plant water balance changes, the $/TWPE for this particular plant rose fro m $312/TWPE to $514/TWPE (Table 4); a significant increase that exceeds the $404/TWPE threshold that EPA considers to be cost effective. As a result, a dry fly ash conversion is not cost effective for this facility. Using the same procedures as described above, AEP estimated the $/TWPE for a dry fly ash conversion at another of its power plants (Plant 2, Table 4). Using the same assumptions and methods described above, the $/TWPE calculated for this facility was $208. After adjusting for fully

- loaded cost s, intake pollutants, a 15

- year service life and the costs associated with plant water balance changes, which exceeded $17 million in 2010$, the $/TWPE for this particular plant increased from $208 to $383/TWPE; a significant increase that while not exceed ing the $404/TWPE threshold that EPA considers to be cost effective, clearly illustrates that EPA did not account for all of the costs associated with dry fly ash retrofits.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 203 Comment Response: EPA disagrees that there is a “$404/TWPE threshold that EPA considers to be cost effective.” See response to DCN EPA

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effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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. See response to DCN EPA

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- A1, Excerpt 30 for more information on the cost estimates provided by AEP. In addition, EPA uses a service life of 20 years as a typical planning period for wastewater treatment operations.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 65 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: UWAG separately analyzes the most recent and representative data (including data from the 2010 ICR init iative) that EPA utilized in its analyses to generate more accurate TWPE and $/TWPE

- removed numbers for this waste stream. These calculations support a conclusion that requiring dry handling of fly ash transport water in any final rule would be unreasonabl e and not in accordance with previously accepted cost

- to

- relative

- benefit analyses typically accepted by the agency in rulemakings of this kind. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 49.

Commenter Name: Paul Bailey Commenter Affiliation: American Coalition for Clean Coal Electricity (ACCCE) Document Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 204 Comment Excerpt: With respect to fly ash transport water, all of EPA’s preferred options would require dry handling, meaning “no discharge.”17 ACCCE supports Options 1 and 2, which would set TSS and oil and grease limits that can be satisfied by su rface impoundments.18 Similar to EPA’s use of data to characterize bottom ash, the data that EPA used to characterize fly ash transport water is old and unreliable and, therefore, does not represent current discharges of fly ash transport water. As stated in UWAG’s comments, industry’s analysis shows that dry handling of fly ash is not cost effective. Comment Response: See response to DCN EPA

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- A1, Excerpt Numbers 49 and 51.

Commenter Name: JoAnne Rau Commenter Affiliation: Dayton P ower & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Economic and Technical Analysis
USEPA es timates that dry handling of fly ash would cost only $27 per TWPE, as outlined in the 2013 Technical Development Document (TDD) and the preamble to the proposed rule:
EPA also calculated the cost

- effectiveness of particular controls for the wastestreams th at would be controlled under the preferred options for existing direct dischargers. The cost

- effectiveness for zero discharge of fly ash transport and FGMC wastewater, as in Option 3a, is $27 per TWPE removed.
2013 TDD at 8

- 34 (footnote omitted); 78 Fed. R eg. at 34,474.
UWAG has evaluated USEPA's cost

- effectiveness analysis for dry fly ash conversions and has uncovered many flaws. DP&L will not reiterate UWAG's detailed comments here but it is apparent that the agency underestimated the costs and overestim ated the pollutants attributable to the industry. Comment Response: See response to DCN EPA

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EPA’s Response to Public Comments

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- 205 Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: USEPA estimated total industry

- wide fly ash TWPEs of 2,521,986 while UWAG's consultan t (URS) reviewed the agency's approximations and determined that a value of 324,801 TWPEs was more appropriate. This discrepancy alone justifies a re

- evaluation of USEPA's methodology and bases for arriving at the BAT proposal conversion to dry fly ash handling. Additionally, UWAG developed its own industrywide $/TWPE for dry fly ash retrofits using unit

- specific flows and retrofit costs. The results of UWAG's work are included in a report by NERA Consulting, Inc. (included as part of UWAG's comments). UWAG's estimates for dry fly ash retrofits are:

Technology Industry Total

Flow Rate (MGY) Industry Total

Capital Costs (million 2010$) Industry Total

Capital Costs (million 1981$) Industry Cost

Effectiveness (1981$/TWPE) Dry Fly Ash Conversion 87,500 $1,989 $799 $599
These costs are significantly greater than the recognized value of $404/TWPE. Based on USEPA's mischaracterization of fly ash transport water and the cost errors and cost omissions for dry fly ash retrofits, the agency must re

- evaluate the cost

- effectiveness of dry fly ash handling as BAT for the industry and the environment. Comment Response: EPA disagrees that there is a “recognized value of $404/TWPE.” See response to DCN EPA

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Com menter Name: Dean Ellis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

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EPA’s Response to Public Comments

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- 206 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
For th e reasons explained by UWAG, dry handling/zero discharge of fly ash transport water cannot be justified on the existing record on a cost

- effectiveness basis. However, as noted in UWAG’s comments, it might be that with more data EPA could justify some treat ment for fly ash transport water beyond the existing ELG limits, but EPA would have to reopen the record and collect data on the cost of dry handling of fly ash. Comment Response: See response to DCN EPA

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Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry handling of fly ash is not cost

- effective when compared to the current effective treatment practice of using impoundments to remove total suspended solids (“TSS”) and oil and grease from fly ash transport water. Comment Response: See response to DCN EPA

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Commenter Name: Shellie Chard

- McClary Commenter Affiliation: Association of Clean Water Administrators (ACWA) Document Control Number: EPA

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EPA’s Response to Public Comments

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- 207 Comment Excerpt:
ACWA supports a Dry Handling standard for Fly Ash, as proposed in six of the eight options in the proposed ELG, including all four "preferred options." Comment Response: EPA agrees with the commenter and, as described in preamble section VIII, determined that zero discharge of fly ash transport water was both, technologically available and economically achievable for the final rule.

Commenter Name: Thomas N. Effinger Commenter Affiliation: South Carolina Electric & Gas (SCE&G) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water While the majority of SCE&G’s coal units are currently dry handling fly a sh, or have planned conversions to dry handling, some plants have/will maintain wet sluicing as a backup during periods of startup and for unplanned ash handling system outages. The costs required to modify these systems to totally eliminate the wet sluici ng backup process and still maintain a consistent and reliable dry handling system far outweigh the negligible benefit. Therefore, while SCE&G agrees with our member associations that the basis for determining dry fly ash handling is not justified based on the cost/benefit, we encourage EPA, at a minimum, to allow temporary wet sluicing for these activities. Comment Response: Although plants are free to continue to operate a backup wet system if they choose to do so, EPA does not agree that the ELG should allow for discharges resulting from the wet sluicing of ash. The BAT basis for discharge of pollutants in fly ash transport water is dry handling. EPA reviewed the processes in place at plants projected to be discharging fly ash transport water and includ ed costs, as appropriate, for these plants to cease operation of the wet system and handle all fly ash dry. See response to DCN EPA

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EPA’s Response to Public Comments

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- 208 Comment er Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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Comment Ex cerpt: EPA’s characterization data and cost information for fly ash retrofits need to be re

- evaluated, and therefore its cost effectiveness analysis is erroneous. The record is inadequate to justify dry handling as cost

- effective for existing plants. U WAG recommends that EPA reopen the rulemaking on fly ash transport water, collect additional characterization data, correct the errors in its fly ash retrofit cost model, and update its cost

- effectiveness analysis based on the new data. EPA should then ma ke the new data and analysis available for public comment. Comment Response: See response to DCN EPA

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- A1, Excerpt 114 in Comment Code 1.c. regarding reopening the record for public comment. See response to DCN EPA

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- A1, Excerpt 37 in Comment Code 1.c for further discussion on the sufficiency of EPA’s record to set zero discharge limitations for fly ash transport water. Although cost

- effectiveness is not determinative for establishing BAT, EPA updated the cost

effectiveness calculated for the ELGs, using its updated cost estimat es and pollutant removals for the final rule. See the RIA.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.

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Commenter Name: Elizabeth E. Al dridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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EPA’s Response to Public Comments

6

- 209 Comment Excerpt: Therefore, EPA is proposing in its “preferred” options to require all steam electric coal

- fired facilities greater than 50 MWs to handle fly ash dry, without discharging sluice water. For the reasons given below, this option cannot be justified, on the existing record, on a cost

effectiveness basis. It might be that, with more data, EPA could justify some treatment for fly ash transport water beyond the 1982 regulations. But EPA would have to reopen the record and collect data on the cost of dry handling.
Comment Response: See response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunto n & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 70 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: B. EPA's Fly Ash Cost
- Effect iveness Analysis EPA estimates that dry handling of fly ash would cost only $27 per TWPE, as EPA says in the 2013 TDD:
EPA also calculated the cost

- effectiveness of particular controls for the wastestreams that would be controlled under the preferred optio ns for existing direct dischargers. The cost

- effectiveness for zero discharge of fly ash transport and FGMC wastewater, as in Option 3a, is $27 per TWPE removed.
2013 TDD at 8

- 34 (footnote omitted); accord, 78 Fed. Reg. at 34,474 col. 1.
As we evaluated EP A’s cost

- effectiveness analysis for dry fly ash conversions, we found many flaws, beginning with its chosen characterization data and running through its technology costing methodologies. We found EPA’s cost

- effectiveness analysis to be flawed because it underestimates the costs and overestimates the pollutants attributable to the industry. TheEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 210 following sections will describe EPA’s TWPE and cost methodologies and UWAG’s cost

effectiveness analysis of wet

- to

- dry fly ash conversions. Comment Response:
Se e response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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F. UWAG’s Cost
- Effectiveness Analysis for Fly Ash To analyze the cost effectiveness of dry fly ash retrofits, UWAG used EPA’s characterization data for the Cardin al plant (October 2007, EPA

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- 0818) and median flow rates from the 2010 ICR. To estimate capital costs, UWAG used 15 data points it collected from members based on actual and screening

- level engineering design estimates of retrofits. The fo llowing sections provide more details on UWAG’s capital cost estimates and TWPE calculations for dry fly ash retrofits. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 49.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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4. UWAG’s Cost
- Effectiveness Analysis Using the UWAG capital cost curve, the O&M costs based on fly ash produced, and the TWPEs removed, UWAG calculated the total annualized cost per TWPE removed ($/TWPE) for eachEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 211 capacity

- based model plant (Table 13). The dollars per TWPE in 1981 do llars range from $936 to $4,541 per plant. Thus, the $/TWPE for dry fly ash handling retrofits are much higher than the $/TWPE that EPA approved in past industry ELG rulemakings.
Table 13: UWAG Estimated TWPE and $/TWPE Using Cardinal Fly Ash Transport W ater Data (Including Source Water Contribution) 29

1981 Cost = 40.2% of 2012 Cost Capacity

– Nameplate MW of plant served by dry fly ash conversion. FAS Flow (MGY)

– Million gallons per year of fly ash sluice water flow rate based on days of operation from the EPA ICR database for each size plant. Fly Ash Produced (Tons/Year)

– Median tons of fly ash produced per year from ICR database for each size plant.
TWPE/Year

– Annual toxic weighted pound equivalents removed. Calculations based on “Model” plant flows and average pollutant concentrations in fly ash pond effluent at AEP Cardinal (EPA SER data). Annualized Capital (Million$)

– Annual capital cost based on 15 yea r life at 7% interest plus the annual O&M cost for conveyance, transportation, and disposal at an offsite landfill. Annual O&M (Million$)

- EPA’s methodology was used to calculate O&M costs for conveyance, transportation, and disposal. 31 $/TWPE

– Annualize d costs of capital and O&M per TWPE removed for dry fly ash retrofit. These UWAG $/TWPE calculations must be understood in light of the following qualifications:Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 212  Unlike EPA’s estimates, UWAG’s capital cost estimates for dry fly ash handling retrofits inclu de the total capital cost to the plant, including major equipment installed, balance of plant (site work, concrete, piping, electrical, mechanical, and instrumentation and controls), engineering (design, services during construction, and startup), profits and overhead (subcontractor and general contractor costs), and miscellaneous unidentified costs (contingency).

 UWAG used EPA’s O&M cost formulas to calculate the O&M cost for conveyance, intermediate storage, transportation, and disposal.

 As we have shown, source water is a major contributor of the TWPEs for bottom ash transport water. Fly ash transport water would contain similar levels of source water pollutants. Therefore, any fly ash transport water TWPEs should be adjusted to account for source water pollutants. Unfortunately, EPA did not collect a source water sample from Cardinal during the October 2007 sampling event. Therefore, it is impossible to match that sample with an exact source water sample. Nonetheless, EPA should provide a credit for pollutants in the source water used for sluicing fly ash. Without the adjustment for pounds of pollutants present in the intake water, the TWPE calculation penalizes power plants for pollutants naturally occurring in the waterbody (such as iron and alumin um) and also for pollutants added by upstream users. The TWPE calculation is distorted by the significant amounts of intake pollutants. Furthermore, it is erroneous to count the source water pollutants as “removed” when the technology option is dry handl ing. Under this option, all the source water pollutants will remain in the source water, and there is no reduction of those pollutants in the environment. At a minimum, EPA should apply the same level of source water reductions documented by the UWAG bot tom ash characterization database to the fly ash transport water TWPE calculations.

29 See Attachment 36.

30 The dip in the cost per TWPE for the 1501

- 2000 MW model plant is due to a higher ratio of fly ash sluice rate to tons of fly ash produced than th e other capacity

- based model plants.

31 UWAG used EPA’s methodology for estimating annual O&M costs for dry fly ash handling due to the short comment period. However, UWAG is not endorsing EPA’s methodology. Instead, UWAG believes a more precise analysis would produce more accurate and possibly higher O&M costs. Comment Response: See response to DCN EPA

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- 213 Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Co ntrol Number: EPA

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- A2 Comment Excerpt Number: 30 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The wastestream that comes closest to having a cost

- effective technology is fly ash transport water. But the record is too sparse to justify dry handling as cost

- effective for existing plants. APPA recommends that EPA reopen the rulemaking on fly ash transport water with a Notice of Data Availability and collect additional data on this wastestream. APPA notes that UWAG has requested the opportunity to provide data for this purpose. APPA hopes that UWAG is allowed to provide further data following the closure of the comment period. Comment Response: See response to DCN EPA

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- A1, Excerpt 114 in Comment Code 1.c. regarding reopening the record for public comment.

Commenter Name: Paul Ling Commenter Affiliation: Kansas City Power & Light Company Document Control Number: EPA

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- A2 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: KCP&L’s believes that EPA’s analysis of the costs and benefi ts of dry fly ash handling for existing steam electric power plants is not adequate to justify additional controls beyond the 1982 regulations. KCP&L believes many of the data points that EPA used to characterize fly ash transport water are invalid and do not reflect typical fly ash transport water resulting in an overstated TWPE. EPA’s cost to convert to a dry handling system is underestimated. Consequently, the resulting $/TWPE understates the costs and overstates the benefit of converting to dry ash hand ling. As a result, KCP&L only supports options 1 and 2 unless more accurate information is used to calculate more reliable $/TWPE that would justify the dry handling option.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 214 Comment Response: See response to DCN EPA

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- A1, Excerpt Numb ers 49 and 51. EPA estimates that 80% of the generating units generating fly ash in the point source category already meet the final rule limits, which indicated that the limit is technologically available and economically achievable for the industry as a whole. See TDD Section 7 for more information.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: S. L. Phillips Commenter Affi liation: Louisiana Department of Environmental Quality Document Control Number: EPA

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- A2 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA is propo sing that the discharge of fly ash transport water pollutants at existing facilities be prohibited. It will require a conversion to dry fly ash handling systems at units that utilize wet sluicing. Many utilities use backup fly ash sluice systems and are concerned that they will not be able to continue using these systems. LDEQ suggests that back

- up fly ash systems be exempt from consideration under the guidelines revisions. Alternatively, additional standards should be crafted that would allow for treat ment and discharge as second option. Comment Response: Although plants are free to continue to operate a backup wet system if they choose to do so, EPA does not agree that the ELG should allow for discharges resulting from the wet sluicing of ash. The BA T basis for discharge of pollutants in fly ash transport water is dry handling. EPA reviewed the processes in place at plants projected to be discharging fly ash transport water and included costs, as appropriate, for these plants to cease operation of the wet system and handle all fly ash dry. See response to DCN EPA

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- 215 14.a. Dry Fly Ash Handling

– Demonstration/Performance
Commenter Name: Patrick O’Loughlin Commenter Affiliation: Buckeye Power, Inc. Document Control Number: EPA

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Secon d, EPA simply is trading perceived issues associated with management of fly ash transport wastewater for those associated with management of dry ash. The environmental issues associated with management of dry fly ash are significant: fugitive dust, increa sed traffic on state roads, engineering issues associated with retrofitting of existing emissions control systems, and ultimate disposition of the dry fly ash. Comment Response: EPA disagrees that there are “perceived issues” with the management of fly a sh transport water because those issues are documented in the rulemaking record. See preamble section XIII for more information on water quality issues associated with the discharge of fly ash transport water such as ground water contamination from surface impoundments containing fly ash transport water. Environmental impacts related to ash transport water are significant according to documented reports. Although technology

- based rules are based on what is technologically available and economically achievab le (according to factors specified in section 304 of the Act and not risk to human health or the environment, pursuant to the Executive Orders of Regulatory Review, EPA examines those impacts. EPA disagrees that unacceptable non water quality environmental impacts associated with fugitive dust will result from the management of dry fly ash. EPA’s cost estimates for dry fly ash handling include pugmills to moisture condition the ash in order to mitigate fugitive dust, and water trucks to control fugitive dus t around silos and onsite landfills while transporting the ash. Additionally, EPA notes that fugitive dust control issues may also be associated with the management of fly ash transport water, such as when some steam electric power plants stack dredged fly ash from surface impoundments and use it to construct roads at the plant. As part of the EPA’s consideration of non

- water quality environmental impacts, EPA estimated that the fuel consumption associated with the final rule is only 0.002 percent of the to tal fuel consumption by all motor vehicles in the United States (See Section 12 of the TDD). Therefore, EPA estimates that, similar to fuel consumption, the final rule will not increase truck traffic on state highways by a significant amount. In fact, truc k traffic on state highways existed with the management of fly ash in surface impoundments because not all steam electric power plants permanently dispose of fly ash in surface impoundments. Some steam electric power plants dredge the fly ash from the impo undment and then transport it to dispose of it elsewhere, for example on offsite landfills.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 216 EPA disagrees that there will be engineering issues associated with retrofitting existing emissions control systems for fly ash. As discussed in preamble section VI II, and supported by data from the Steam Electric Survey, plants can successfully convert to and operate dry fly ash handling systems. Further, as discussed in preamble section XIV, final disposition of dry fly ash in landfills reduces the impacts to water quality associated with surface impoundments, including reducing impoundment failures. Finally, the commenter did not provide any specific data to quantify these impacts associated with the management of dry fly ash. Therefore, EPA cannot provide further response to the comment.

Commenter Name: Lisa C. Messinger Commenter Affiliation: Vectren Corporation Document Control Number: EPA

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- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Fly Ash Transport Water

- For plants that already have dry fly ash systems installed and only use impoundments as a back

- up for limited period of times, the complete prohibition from discharging fly ash tra nsport water is unreasonable. The requirement in the four "preferred" opt ions to eliminate all fly ash transport water discharges by requiring dry handling does not allow for adequate flexibility or a lternatives. Both of our plants converted to dry fly ash systems 4 and 15 years ago and operate dry fly ash as the primary ash ha ndling option, but still use the pond as the backup option if the dry system is unavailable. Our fly ash ships via barge for beneficial reuse at a cement kiln, but the kiln, unlik e an electric generating plant, does not operate 365 days a year. There are maintenance and market driven outages 6

- 8 weeks per year as well as occasional low or high river level issues that restrict barge transportation. We do not have on site ash landfi lls, so during the times that the fly ash can not be recycled, it is wet sluiced to an ash pond. Furthermore, our A.B. Brown plant internally reuses much of its water, so the ash pond discharges, on average, less than 60 days per year. Finally, under our current NPDES permit, we are installing a chemical precipitation tank treatment system that will treat water that leaves the ash pond to meet rnercury limits at the outfall to the river as required under ORSANCO water quality limits. Comment Response:
S ee response to DCN EPA

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- 217 Electric Survey data for steam electric power plants that currently operate both dry and wet fl y ash handling systems, to determine whether additional equipment may be needed to eliminate reliance on the wet fly ash handling systems and eliminate discharge of pollutants from fly ash transport water. Where EPA determined that such changes to the plan t were necessary, EPA estimated the costs associated with ceasing use of the wet system and handling all fly ash dry. EPA determined that the changes it includes costs for would enable plants to meet the zero discharge standard and that the additional cost s, if any, were affordable. EPA disagrees that zero discharge is unreasonable. Based on information from the commenter, EPA revised cost estimates associated with the A.B. Brown plant to include a backup silo and pugmill, and assumed dry fly ash would be d isposed in a landfill at times when the fly ash was not marketable, in order to handle and dispose all fly ash at the plant dry. Under this scenario, EPA found that the zero discharge requirement was economically achievable for the industry as a whole as r equired by the Clean Water Act. EPA has analyzed costs for the ELGs under several scenarios. Under the scenario that does not take the CCR rule and CPP into account, the plant is expected to incur costs associated with transport and landfill disposal of t he portion of fly ash that would no longer be sent to the impoundment with the wet handling system. Under the scenario that takes the CCR rule into account, however, the plant is projected to replace the disposal impoundment with a storage impoundment, whe reby the plant would periodically dredge the wet

- sluiced fly ash and haul it to disposal (or beneficial use). In that “with CCR” scenario, since the plant’s new baseline operating condition would be to periodically haul the fly ash to disposal, costs for t hat activity would not be attributable to the ELGs. Costs to upgrade the dry fly ash handling system so that wet

- sluicing would cease (i.e., the backup silo and pugmill) would still be attributable to the ELGs. Under either scenario of cost estimates, EPA determined that the costs are affordable and the ELGs are economically achievable.

Commenter Name: Lisa C. Messinger Commenter Affiliation: Vectren Corporation Document Control Number: EPA

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- A1 Comment Excerpt Number: 29 External R eview Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Finally, we feel plants with existing installed dry fly ash systems should be allowed to continue use of wet sluicing as a back

- up with limited and documented discharges. Comment Response: See response to DCN EPA

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- 218 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 50 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Engineering Aspects of Retrofitting Dry Fly Ash Handling Southern Company engineers, as part of t heir review of the ELG Rule, have considered the timing and engineering aspects of retrofitting dry fly ash handling. Appendix C contains their summary of the conversion process, including design, construction, and implementation, and the engineering chall enges and limitations for several types of dry fly ash handling systems. Also, Appendix D contains a case study for the conversion of a four

- unit power plant to dry flyash handling describing engineering, costs, and timing concerns for retrofitting dry fly ash. Comment Response: EPA reviewed the timing and engineering aspects associated with retrofitting dry fly ash handling in Appendix C. EPA agrees that converting from wet sluicing of fly ash to dry handling can be done by installing a vacuum system, va cuum
- pressure system, pressure system, or mechanical system. EPA also agrees that each technology has different capital and O&M costs. However, EPA notes that these four technologies are not required by the final rule. The final rule does not preclude the use of any specific technologies or require that specific technologies must be used. The final rule sets specific effluent limitations and standards that apply to certain wastestreams. For fly ash transport water, the final rule establishes a zero discharg e limitation for all pollutants in fly ash transport water. EPA focused its review on the information provided for the vacuum system in Appendix C. While the other vacuum

- pressure, pressure, and mechanical systems are viable options, they were not EPA’s te chnology basis for estimating compliance costs for the final rule. EPA notes that steam electric power plants should install and operate the preferred technologies at their specific plant to meet the final rule limitations and standards.
EPA identified sev eral general issues raised by the commenter. Specifically, the commenter provided information suggesting that a dry fly ash vacuum system retrofit could not be successfully achieved at a steam electric power plant due to physical space constraints, availab le land, available electrical power, or the need for additional electrical power distribution equipment. EPA reviewed plant

- specific comments to identify whether any steam electric power plants that would be subject to the zero discharge requirement identi fied any of these specific engineering challenges associated with their locations converting to dry fly ash handling systems. Because EPA did not identify any plant

- specific comments, it did not make any plant

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- 219 specific adjustments to the compliance cost es timates. However, EPA did include contingency costs, as part of the indirect cost factor, to account for unforeseen complications associated with the dry fly ash handling conversion. As discussed in the commenter’s Appendix C, EPA agrees that “the intermed iate ash storage silo and the filter collectors can be installed while the generating unit is in operation, so an outage is not needed for that part of the work.” The additional scheduling considerations provided by the commenter, such as delivering the eq uipment, erecting the silo, and erecting the filter

- receivers, totals approximately two years. However, EPA notes that this is likely an overestimation because some of the equipment, like the silos or filter receivers, can be built at the same time. Regard ing timing of the final rule, as described in preamble sections VIII and XVI, “those limitations do not apply until a date determined by the permitting authority that is as soon as possible beginning November 1, 2018 (approximately three years following pr omulgation of this rule), but that is also no later than December 31, 2023 (approximately eight years following promulgation).” Therefore, plants should be able to complete the dry fly ash handling conversion by the time the fly ash transport water zero di scharge limitation is applicable. For further information, see responses related to Comment Code 26.b. EPA is unclear what the commenter is inferring by “The vacuum system allows for quick conversion to wet transport by operating only two isolation valves, one on the air/ash inlet of the filter collector and one on the air outlet of the filter collector.” Therefore, EPA cannot respond further to this comment. See response to DCN EPA

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Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Numb er: 54 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Also, facilities with dry systems typically still use wet handling for back

- up. During periods when the dry system is off

- line for maintenanc e, or dry ash disposal is interrupted because of transportation issues or end user outages, plant operators need an alternative method for handling the ash. This is especially true for plants that send their dry fly ash off

- site for recycling or disposal. A mine

- mouth plant, for example, is unlikely to have an on

- site landfill, and building a new landfill to accept limited quantities of waste for limited periods of time is uneconomical.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 220 Comment Response: See response to DCN EPA

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- A1, Excerpt 53 in Comment Code 14.b for more information on the construction of new landfills.

Commenter Name: Becky Hayat Commenter A ffiliation: Natural Resources Defense Council (NRDC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry handling of fly ash is a well

- established practice within the industry, and most coal

- fired plants that have come online since 1985 use dry handling for fly ash. 8 In fact, all of the newer electric generating units employ dry fly ash handling methods because the cu rrent New Source Performance Standards (NSPS), which were promulgated in 1982, prohibit the discharge of pollutants in fly ash transport water. In addition, many older generating units have also converted to dry fly ash handling systems that use air to tra nsport the fly ash to storage silos instead of using water to sluice the ash. 9 As a result, of the coal

- and petroleum coke

- fired steam electric generating units that generate fly ash, 66 percent already operate dry fly ash transport systems, while another 15 percent operate both wet and dry fly ash transport systems. The remaining 19 percent operate only wet fly ash transport systems, although not all of these plants discharge their fly ash transport water. 10

8 Bergesen and Hull, Environmental Directory of U.S, Power Plants, Edison Electric Institute, 1994.

9 ELGs at 34,439.

10 Id. at 34,449. Comment Response: EPA agrees with the commenter that dry fly ash handling is a well

- established practice within the steam electric power generation industry and that most coal

- fired steam electric power plants that have come online since 1985 use dry handling for fly ash. See the TDD for more details about percentages of the industry that now use dry handling.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 221 Commenter Name: Cathy S. Woollums Commenter Affiliati on: MidAmerican Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In many cases, it will be difficult to design and install a retrofitted dry fly ash handling system given the current physical layout of some facilities. Facilities having significant space constraints may not be able to physically or economically install new dry ash management ret rofit technologies. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 53 in Comment Code 14.b for more information on retrofitting dry fly ash handling systems and potential physical obstacles. EPA does not agree that any facility would be unable to convert to dry fly ash handling, based on the information in the record. EPA notes that the commenter did not provide specific examples in this comment, nor identify any specific facilities that the commenter believes would be u nable to convert to dry handling.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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XI. The ELG Rule Should Allow Temporary Wet Sluicing of Fly Ash and Bottom Ash as a Back
- up Some power plants that handle fly ash dry also have the ability to wet sluice ash occasionally when needed , such as during start

- up or malfunctions of the dry handling system. This limited use of wet sluicing makes sense from an operational standpoint and has very little impact on water quality. Moreover, we believe the incremental cost of eliminating this m inor use of wet sluicing where it is needed would be high in terms of dollars per TWPE. UWAG members have informed us that some power plants may use wet sluicing during start

- up before switching to dry handling, such as when it is necessary to handle fly a sh mixed with oil separately from fly ash that is marketable. Some plants have several units with a single dry flyEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 222 ash handling system, and the back

- up wet system may be needed to keep the units online if there is a malfunction in the shared dry fly ash s ystem.
Our members tell us that to eliminate this back

- up capability would require new mechanical exhausters, pressure blowers, additional valves and piping, at considerable cost, and also demolition costs. We believe these costs would be considerable. Accordingly, UWAG recommends that, even if the final ELG rule requires dry handling of fly ash, it should also allow wet sluicing to a limited extent. During this time, fly ash transport water should be subject to the existing BPT limits. Similarly, if (c ontrary to the evidence of low cost

- effectiveness presented above), EPA imposes a dry handling requirement on bottom ash, again wet sluicing of bottom ash should be allowed temporarily as a back

- up. Comment Response: The final rule does not preclude the use of any specific technologies or require that specific technologies must be used. The final rule sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, steam electric power plants can operate wet sluicing systems ; however, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater. The national goal of the CWA is the elimination of the discharge of all pollutants into the nation’s water s. Section 101(a). Section 301 of the CWA provides that, in setting BAT

- based effluent limitations, EPA shall require the elimination of discharges of all pollutants in a wastewater stream if EPA finds that it is technologically available and economically achievable to do so, after considering the factors specified in section 304(b) of the Act. EPA has determined that zero discharge of pollutants in fly ash transport water and bottom ash transport water is technologically available and economically achievab le considering the factors in section 304(b); therefore, EPA selected dry handling and closed

- loop technologies as the BAT basis for reasons stated in preamble section VIII. As well, the final rule record demonstrates that dry handling and closed

- loop syst ems are widely demonstrated throughout the steam electric power generating industry and are available to steam electric power plants and generating units of all sizes. See TDD Section 7 for more information on these technologies. EPA disagrees with the com menter that fly ash transport water and bottom ash transport water generated by limited use of wet handling systems would have “very little impact on water quality.” EPA has determined fly ash transport water and bottom ash transport water contain toxic me tals and other pollutants of concern as described in Section 6 of the TDD. Regardless, as required by the CWA, the rule is technology

- based and not based on risk to human health and the environment. Another provision of the CWA, section 301(b)(1)(C) estab lishes requirements for effluent limitations based on environmental impacts. Those limits are called Water Quality Based Effluent Limitations (WQBELs) and they are based on applicable water quality standards designed to protect against impacts of a partic ular discharge on a specific receiving stream. See Texas Oil & Gas Ass’n et al v. US EPA , 161 F.3d 923, 927 (5 th Cir. 1998)(“These limitations areEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 223 technology

- based rather than harm based; that is, they reflect the capabilities of available pollution contro l technologies to prevent or limit discharges rather than the impact that those discharges have on the waters.” Citing E.I. du Pont de Nemours & Co. v. Train , 430 U.S. 112, 130

- 31 (1977); Am. Petroleum Inst . 661 F.2d at 343

- 44.). Regarding fly ash, the c apital costs associated with EPA’s dry fly ash handling technology option, that is the dry vacuum fly ash handling system, include sufficient redundancy accounting for vacuum pumps and filter

receivers, so that plants incurring full conversion costs do not need to rely on backup wet sluicing systems. Further, EPA confirmed with vendors that the installation of a dry fly ash handling system does not require the demolition of the existing wet sluicing system. Based on responses to the Steam Electric Survey, o ver 65 percent of the fly ash handling retrofits in the industry operate without a backup wet sluicing system and did not report an unscheduled outage in 2009. The time frame provided in the rule also provides sufficient time to implement controls.
For steam electric power plants that currently operate both dry and wet fly ash handling systems, EPA agrees, in part, with the commenter that additional equipment may be needed to eliminate reliance on wet fly ash handling systems and eliminate discharge of pollutants from fly ash transport water in the event of planned or unplanned maintenance of the dry fly ash system, including during startup and shutdown, or when the fly ash is not marketable. EPA estimated compliance costs for steam electric power plants that reported operating both wet and dry fly ash handling systems by evaluating if a certain level of redundancy was necessary to avoid discharge of pollutants in fly ash transport water at plants that operate both wet and dry fly ash handling systems. EP A gathered and reviewed data submitted by vendors with extensive industry experience in wet

- to

- dry fly ash system conversions regarding what equipment is necessary for sufficient redundancy and the associated costs. EPA also gathered and reviewed data from industry, including responses to the Steam Electric Survey and public comments, to identify plants that would need additional redundancy or backup equipment to handle fly ash dry 100 percent of the time. EPA grouped into three subsets steam electric power plants asserting a need for additional redundancy related to installing dry fly ash handling systems and costed them as follow:
1. EPA determined that no additional equipment is required at plants that operate a wet sluicing system when an already existing d ry fly ash handling system is down due to maintenance. Maintenance outages for both wet sluicing and dry handling fly ash systems account for less than one percent of total generating unit operating time, based on responses to the Steam Electric Survey. Fo r these reasons, EPA did not include additional capital costs for this subset of plants for conversion to complete dry fly ash handling. 2. EPA determined that plants operating a wet sluicing system when the dry fly ash is not marketable, such as startup or s hutdown events, could potentially require additional silo and pugmill capacity. EPA reviewed Steam Electric Survey data to determine the number of existing storage silos at these plants and whether the silos have moisture conditioned unloading capabilities . Additionally, vendors stated that level indicators can be used in storage silos to differentiate fly ash associated with startup and shutdown events, allowing steam electric power plants to separate this ash from ash that is marketable. EPA determined th at some plants may need an additional storage silo, level indicator, andEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 224 moisture conditioned unloading equipment and included these capital costs for the final rule. 3. EPA determined that plants stating, in responses to the Steam Electric Survey, that some level of redundancy is the only change required to handle all fly ash completely dry may require specific pieces of conveyance equipment that provide redundancy for dry fly ash handling systems. Based on discussions with ash handling vendors, EPA included capital costs for the following pieces of equipment, based on the current type of dry fly ash handling system on the generating unit:

 Dry Vacuum: filter

- receiver and vacuum pump;

 Dry Pressure: pressure blower; and

 Combined Vacuum/Pressure: filter

- receiver, vacuum pump, and pressure blower. For all scenarios, EPA did not estimate O&M costs associated with the additional equipment because it is redundant and only operated when the primary system equipment, already in place at the steam electric power plant, i s offline. Additionally, EPA determined that there will be an O&M cost savings for steam electric power plants operating the dry system rather than operating the wet sluicing system. A detailed description of the fly ash cost methodology is provided in Sec tion 7 of the final rule Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) . See response to DCN EPA

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- A1, Excerpt Number 45 in Comment Code 14.b for more information regarding revisions to the fly ash cost methodologies, including the revised direct and indirect cost factors applied to the capital costs. Regarding bottom ash, the comm enter asserts that wet sluicing of bottom ash should be “temporarily allowed as a back

- up.” The final rule does not require plants to cease operation of wet bottom ash handling systems provided that there is zero discharge of pollutants from bottom ash tra nsport water. As the BAT basis for bottom ash transport water, EPA selected dry handling and closed loop systems. Generating units installing the dry technology basis would have to accommodate the bottom of the boiler with a mechanical drag chain conveyor, eliminating the capability to sluice bottom ash and eliminating the bottom ash wet sluicing system. Generating units installing the closed

- loop technology bases would continue to transport bottom ash using the same processes as a wet sluicing system, but instead of going to a surface impoundment, the bottom ash is sluiced to a remote mechanical drag system. Once there, a drag chain conveyor pulls the bottom ash out of the water on an incline dewatering the bottom ash, and the transport water is then recycl ed back to the bottom ash collection system, thereby recirculating all bottom ash transport water in a manner that avoids discharge. Based on responses to the Steam Electric Survey, EPA did not identify any generating units with a dry bottom ash handling h andling system (either original equipment or retrofit) that also operate a back up wet sluicing system. Additionally, EPA has identified plants in the industry that successfully operate closed

- loop bottom ash systems without discharging any bottom ash tran sport water. Regarding cost

- effectiveness, EPA disagrees that the “incremental cost of eliminating this minor use of wet sluicing where it is needed would be high in terms of dollars per TWPE.” As discussed in preamble section V, EPA has revised its cost e stimates and pollutant reductionsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 225 analyses, respectively, in response to comments received on the proposed rule. These revised estimates are used in the cost

- effectiveness analysis for the promulgated rule (see section preamble section XV). For further det ail on EPA’s evaluation of cost effectiveness for fly ash transport water and bottom ash transport water, see response to DCN EPA

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- A1, Excerpt Number 49 in Comment Code 14.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthju stice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 99 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
A. ELIMINATING THE DISCHARGE OF FLY ASH TRANSP ORT WATER IS TECHNOLOGICALLY ACHIEVABLE. As EPA notes, several technologies are widely available for existing power plants to convert to dry handling of their fly ash. The most widely used systems are dry vacuum, pressure, and combination systems (that us e both a vacuum and pressure system). 385 EPA based its cost estimates on dry vacuum systems for units other than oil units operating less than 100 days per year, 386 presumably because the majority of units that dry handle their ash use dry vacuum systems. 387 The availability of technologies for the dry handling of fly ash is unsurprising given that EPA in 1982 established New Source Performance Standards requiring new units to eliminate the discharge of fly ash transport water. 388 In 1982, EPA noted that “[a]lmost half of the existing plants already use dry fly ash systems.” 389 As a result of the 1982 effluent limitations guidelines, for over 30 years, new power plants have been installing these systems. Moreover, many existing u nits have converted from wet to dry systems. Since 2000, 115 units have converted from wet fly ash handling to dry systems. 390 Overall, the vast majority of existing units dry handle their fly ash. 66 percent of coal and coke units use a dry system only, and an additional 15 percent dry handle their fly ash but have a wet system as a backup. 391 Only 19 percent of coal and coke units rely exclusively on a wet system for handling fly ash. 392 Several vendors offer systems for dry handling of fly ash. 393 The widespread use of dry systems at new and existing units, combined with the existence of multiple vendors selling the technologies, confirms that technologies for dry handling of fly ash are available.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 2 26 385 TDD at 7

- 22 to 7

- 29.

386 Incremental Costs a nd Pollutant Removals at 7

- 1.

387 77 Fed. Reg. at 34,453.

388 47 Fed. Reg. 52,290, 52,296 (Nov. 19, 1982).

389 Id.

390 TDD at 4

- 22 to 4

- 23.

391 Id. at 7

- 23.

392 Id.

393 Incremental Costs and Pollutant Removals at 7

- 2 (noting that Clyde Bergemann Power Corp oration and United Conveyance Corporation market dry vacuum systems). Comment Response: See response to DCN EPA

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- A1, Excerpt Number 4.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 227 14.b. Dry Fly Ash Handling

– Costs
Commenter Name: Chris M. Hobson Commenter Affiliation: Sout hern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 45 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s Cost Methodology for Dry Fly Ash Retrofits
EPA estimated compliance costs for plants currently operating wet sluicing systems to convert to dry vacuum fly ash handling systems. EPA developed a costing approach for three separate portions of the dry fly ash handling system:

 Conveyance

– The mechanical e xhauster, piping, valves, and filter

- separators to pull and convey ash from the bottom of the hopper to the intermediate storage destination. EPA calculated these costs at the generating unit level.

 Intermediate Storage

– The silo, the vacuum equipment nec essary to receive the ash from the conveyance lines, and the unloading equipment necessary for moisture conditioning prior to transportation and disposal. EPA calculated these costs at the plant level.

 Transportation/Disposal

– The trucking equipment and o peration to move the dry fly ash to its final destination ( e.g. , on
- site or off

- site landfill). EPA calculated these costs at the plant level. EPA calculated total 2010 costs for each plant as the sum of the conveyance costs, intermediate storage costs, an d transportation and disposal costs for the conversion of wet to dry fly ash handling. The total capital cost formula is provided below: Total Capital Costs = Purchased Equipment Costs + Purchased Equipment Installation Costs + Plant Overhead Engineering C osts + Fly Ash Disposal Costs 2013 TDD p. 9

- 31. EPA’s Capital Cost Methodology EPA calculated the total capital costs for each plant as the sum of the purchased equipment costs, installation costs, plant overhead engineering costs, and fly ash disposal costs. For purchased equipment capital costs, EPA summed the costs of dry vacuum conveyance system(s), concrete or steel silo(s), silo aeration equipment, and pugmill(s). EPA calculated equipment costs for conveyance on a generating unit level and silo and pugmill equipment costs at a plant level. EPA estimated conveyance, silo, and pugmill equipment costs using aEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 228 relationship between capital costs and wet fly ash generation rates obtained from industry vendors. IC&PR p. 7

- 6. EPA estimated installation capi tal costs for the conveyance and intermediate storage equipment using installation factors supplied by industry vendors. EPA used a conveyance installation factor of two and an intermediate storage installation factor of two based on cost data from UCC. EP A estimated the installation capital costs for each plant by multiplying plant purchased equipment costs by these installation cost factors. IC&PR p. 7

- 12. EPA determined plant engineering overhead costs based on the 2010 ICR responses. From these response s, EPA calculated a median installation factor for the conveyance and for intermediate storage system elements. The conveyance overhead factor is 0.02454, and the intermediate storage overhead factor is 0.0082. EPA estimated the total engineering overhead costs by applying these factors to the total purchased and installation equipment costs. Id. at 7

- 14 to 7

- 15. EPA based fly ash disposal costs on moisture

- conditioned fly ash tonnage rates to be disposed of in a landfill. A summary of EPA’s methodology for calculating transportation and disposal costs is provided in the next section. EPA assumed zero land acquisition costs based on data from site visits and discussions with operators of plants that had already converted from wet to dry fly ash handling. IC& PR, p. 7

- 6. EPA also assumed that other capital costs, such as buildings, site preparation, engineering, and construction were included in the costs provided by the vendors. EPA’s Methodology for Calculating Conveyance and Storage O&M Costs
EPA estimated o perating and maintenance costs for each plant for the conveyance and storage equipment associated with the dry vacuum fly ash handling systems. These costs include operating labor, maintenance materials and outage, chemical purchase, and energy costs. EPA calculated total O&M costs as the sum of the conveyance O&M costs and the intermediate storage O&M costs. IC&PR, p. 7

- 16. EPA’s Methodology for Calculating Transportation and Disposal Costs EPA conservatively included costs for plants to transport all soli d waste to a landfill because not all plants have the means to market or give away fly ash. For plants with existing on

- site CCR landfills, EPA included costs for expanding the existing landfill or building a new landfill to accommodate the additional ash. For plants that do not have existing on

- site CCR landfills, EPA included costs for these plants to transport and dispose of the additional CCRs in an off

- site non

hazardous landfill. To estimate capital and O&M disposal costs for an on

- site landfill, EPA included the construction of the landfills, a liner, additional groundwater monitoring, a leachate collection system, and closures associated with the expansion of an existing landfill. EPA estimated off

- site disposal costs based on a tipping fee generally charged by off

- site landfills prior to accepting theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 229 solids waste. EPA estimated the tipping fees using state

- level tipping fees and data provided in response to the ICR. A summary of EPA’s transportation and disposal costs for both fly ash and bottom ash is provided in the following table. Table 6: Summary of EPA’s Transportation and Disposal Cost Factors

Location Type of ash Input Input Units Transportation Cost Factor (2010$) Disposal

Cost Factor (2010$) Total Cost

Factor (2010$) Onsite Fly ash Wet FA generated _tons year 3.713 43.2 46.9
Onsite Bottom ash BA generated _tons year 4.038 47.0 51.0
Offsite Fly ash Wet FA generated _tons year 10.53 46.73 57.3
Offsite Bottom ash BA generated _tons year 11.45 50.82 62.3

EPA Assumes No Costs for Plant Outages to Install Dry Fly Ash Systems Based on an evaluation of vendor and ICR survey information, EPA determined that retrofitting a dry fly ash handling system can be completed during regularly scheduled outages. EPA assumed the entire conveya nce and storage systems can be constructed and installed prior to a scheduled outage, and then tie

- in can occur during a regularly scheduled outage. Therefore, EPA assumes no costs for plant outages during installation of the dry fly ash handling system.
E PA Assumes Cost Savings for Ceasing Operation of Surface Impoundments Currently Receiving Coal Combustion Residuals EPA assumes that implementation of dry fly ash and possibly dry/closed

- loop bottom ash systems will reduce, and in some cases eliminate, the management of ash transport water and CCRs in on

- site surface impoundments. EPA expects plants will experience cost savings from ceasing to operate these impoundments. To calculate these cost savings, EPA estimated annual O&M and recurring costs associate d with managing these wastewaters and CCRs in on

- site impoundments. The types of O&M costs EPA evaluated in its assessment included costs associated with: wastewater transport system, general operation and inspections of the impoundment site, dredging of C CRs for reuse or disposal in a landfill, wastewater treatment system controls ( e.g. , pH control), and water recycle system at the impoundment (if applicable). Flaws in EPA’s Capital Cost Formulas for Dry Fly Ash Conveyance and Intermediate Storage
The form ulas in EPA’s IC&PR document for fly ash conveyance and intermediate storage costs are inconsistent (by a factor of 10) with other documents in the ELG record. EPA has confirmedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 230 that all three formulas used in its economic model to estimate the industry’s fly ash retrofit capital costs are incorrect. For each cost formula, the estimated cost is off by a factor of 10, underestimating the overall capital costs for dry fly ash retrofits for the industry. The following section describes the formula errors.
Unit
- Level Conveyance Capital Costs for Equipment Equation In the IC&PR (Chapter 7: Fly Ash Transport Water Cost Methodology, § 7.1.5.1, Equation 7

- 4 (p. 7

- 8)), EPA explains that it developed Equation 7

- 4 to estimate dry fly ash conveyance equipment costs as f

ollows:
Unit

- Level Dry Fly Ash Conveyance Equipment Capital Cost (2010$) = (9,791 × Recalculated Unit Wet Fly Ash Conveyance Rate + 23,372 ) × No. of Unit Vacuum Systems However, in EPA’s “NonCBI Fly Ash Conveyance Cost Equations and Factors” document ( EPA

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- 2888.21, DCN SE01825A70), Conveyance Equipment Worksheet, the “Dry Vacuum Cap Cost” figure has the equation: y = 9,791.9x + 233,721 Also, underneath the figure, the equation is transcribed incorrectly to: Cost (2010$) = (9,791 x Recalculated Unit Fly Ash Conveyance Rate, tph + 23,372 ) x Number of Unit Vacuum Systems EPA transcribed the number incorrectly from the cost curve to its economic model. The y

intercept is off by a factor of 10. Steel Silo Capital Cost Equation
EPA made a similar transcription error in the steel silo cost equation. In the IC&PR (Chapter 7: Fly Ash Transport Water Cost Methodology, § 7.1.5.2, Equation 7

- 10 (p. 7

- 10)), EPA states that it developed Equation 7

- 10 to estimate steel silo capital costs as follow s: Steel Silo Capital Cost (2010$) = (14.81 × Recalculated Steel Silo Size + 10,089 ) × Number of Steel Silos However, in EPA’s “NonCBI Fly Ash Intermediate Storage Cost Equation and Factors” document (EPA

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- 1959.22, DCN SE01825A71), p. 6 of 85, the figure used to estimate capital costs for a steel silo gives the formula as: y = 14.812 x + 100,890

. Again, EPA transcribed the number incorrectly from the cost curve to its economic model. The y - intercept is off by a factor of 10.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 231 Concrete Silo Capital Cost Equation For its concrete silo capital cost equation, there is also an error. In the IC&PR (Chapter 7, Fly Ash Transport Water Cost Methodology, § 7.1.5.2, Equation 7

- 14 (p. 7

- 10)), EPA explains that it developed Equation 7

- 14 to estimate concrete silo capital costs as follows: Concrete Silo Capital Cost (2010$) = [(0.005 × (Recalculated Concrete Silo Size)2) + (519.8 × Recalculated Concrete Silo Size) + 44,379 ] × Number of Concrete Silos But EPA’s “NonCBI Fly Ash Intermedi ate Storage Cost Equation and Factors” document (EPA

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- 1959.22, DCN SE01825A71), uses inconsistent numbers. The figure used to estimate capital costs for a concrete silo (pp. 14 and 19 of 85) reads: y =0.005x2 + 519.88x + 443,794

. Again, EPA transcribed the number incorrectly from the cost curve to its economic model. The C constant in the quadratic formula is off by a factor of 10. Also, the table used to develop the figure uses 2011 dollars, and Equation 7

- 14 (IC&PR p. 7

- 10) shows 2010 dollars as the output. Impact of Errors in Capital Cost Formulas for Dry Fly Ash Retrofits To determine the impact of the above errors, we applied corrected equations to six plants. The average increase in plant capital cost for conveyance and intermediate storage is 46% for this sample set. The size of the error increases with the number of units at each plant requiring a wet

to

- dry conversion. Table 7 below shows the effect of the errors on the fly ash capital cost estimates for the six plants.
Table 7: E ffect of EPA Transcription Errors on Capital Cost Estimates for Fly Ash Conveyance and Intermediate Storage

# Units with Wet FA Plant Total

MW (Rounded) Plant Total

Ash Produced (tpd) Fly Ash Conveyance and

Storage Total Capital Cost (M$) Percent Increase of Capital Costs EPA Reported Corrected 5 1800 700 7.9 12.2 54% 5 1400 1040 11.6 16.5 42% 2 1100 650 7.2 9.6 33% 7 1500 660 7.6 12.5 64% 2 600 400 5.2 6.9 33% 4 1100 540 6.4 9.4 47%
EPA must correct these errors and recalculate the total capital cost for wet

- to

- dry fly ash conversions for the industry.
EPA’s Balance of Plant Costs are UnderestimatedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 232 EPA used costs provided by CBPG and Marietta Silos to generate purchased equipment costs for conveyance and intermediate storage (silo and silo

- related equipment) of dry fly ash handling systems. EPA assumed the cost data supplied by the vendors include all BOP costs. However, the CBPG and Marietta Silos cost data do not include site preparation, concrete, electrical, upgra ded control systems, demolition/relocation, or structural modifications. These costs for BOP must be included in the total capital costs for any technology retrofit at an existing plant. EPA’s Engineering Overhead Cost Factors are Erroneous
EPA used cost d ata from the 2010 ICR to estimate engineering overhead costs for conveyance and intermediate storage. The Agency developed the cost factors by calculating the median ratio of engineering overhead costs to the total capital costs for conveyance and intermed iate storage. The cost factors for conveyance and intermediate storage are 0.02454 and 0.0082, respectively. Engineering overhead costs include engineering, project management, and construction management. Based on electric utility industry experience, an engineering overhead cost factor of 0.20 (or 20%) should be used for relatively easy retrofits. If retrofits are more difficult, then this cost factor would be higher. A case study involving the wet

- to

- dry conversion of a four

- unit plant is provided in App endix D. Engineering was developed based on the complexity of the design effort and the length of the project. The engineering overhead costs are estimated as a percentage of the construction costs 4 , excluding demolition. The engineering overhead cost fact or for this case study is approximately 22% of the total project costs 5

. EPA Did Not Include Costs for Profit and Overhead In estimating dry fly ash handling retrofit costs, EPA also did not include costs for profits and overhead for the general contractor or subcontractors for specialty work. Overhead in this case would include bonding and insurance. Large construction projects at power plants use contractors or subcontractors for many different functions. For example, contractors may be used for craft lab or during construction as well as to mobilize and demobilize temporary facilities during construction. These are major cost elements for any capital project and should be included in the total capital costs for dry fly ash retrofits. Based on electric util ity industry experience, profits and overhead are generally 10% of the contractor labor costs and 5% of the materials costs. For the case study provided in Appendix D, the profits and overhead costs are approximately 6% of the direct costs (subtotal) of th e project. EPA’s past practice has been to include overhead and profits in its cost estimates. For example, in the Airport Deicing ELG, EPA included $84,000 in overhead and profit for installing 10,000 feet of stormwater piping, plus $1,000 for performance bonds and $19,300 for insurance. Technical Development Document for the Final Airport Deicing Category, p. 124. In addition, EPA added in another $84,000 for contractor mark

- up, which it described as “handling, procuring, subcontracting, change orders, et c.” Id. In the Landfills ELG, EPA factored in 10% of the capital cost as general contractor overhead. Development Document for Final Effluent Limitations Guidelines and Standards for the Landfills Point Source Category, p. 9

- 37.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 233 EPA Did Not Include Miscell aneous Unidentified Costs EPA mistakenly assumed no costs for miscellaneous unidentified costs (contingency) for its screening

- level estimate. This is not consistent with industry guidance, nor is it consistent with EPA’s practice in other ELGs. A continge ncy of at least 20% should be included in EPA’s estimate. Contingency is defined as “an amount added to an estimate to allow for items, conditions, or events for which the state, occurrence, or effect is uncertain and that experience shows will likely resu lt, in aggregate, in additional costs.” 6 The level of contingency is based on the class of cost estimates and their relative accuracy. The accuracy of the cost estimate is generally a function of the amount of engineering completed at the time of the estim ate. Since EPA’s costs are, at best, screening level costs, with a small amount of project definition, contingency must be added to the total project costs to take into account unidentified costs. It is standard practice, based on the Project Management In stitute , to include contingency to cover within

- scope uncertainties. EPA should include a contingency in its estimates of 20% of the total project costs. For the case study provided in Appendix D, the contingency is 20% of the total project cost. In previo us ELGs EPA has routinely included contingency costs for engineering projects. See, e.g. , Development Document for Final Iron and Steel Manufacturing Category, p. 10

- 4; Development Document for the Final CWT Industry, p. 11

- 2; Development Document for the Final Metal Products and Machinery Category, p. 11

- 19.
EPA Did Not Include Costs for Land Purchases EPA assumed zero land acquisition costs based on data from site visits and discussions with operators of plants that had already converted from wet fly ash handling to dry fly ash handling. IC&PR, p. 7

- 6. This assumption underestimates the cost for dry fly ash retrofits, particularly if there is not enough space on

- site for locating silos and roads for trucks to haul the ash to on

- site or off

- site landfills. EPA should have evaluated the space availability at each facility based on data from the 2010 ICR to determine costs for purchasing land to accommodate the large storage silo(s) and roads for transporting the fly ash to on

- or off

- site landfills. EPA appar ently concluded that every facility that would have to retrofit fly bottom ash handling already had space available to accommodate the retrofit. But it is very unlikely that each and every facility has enough land for the retrofit. In other ELGs, EPA has c osted out land needed for new technologies. Development Document from the Final CWT Industry, p. 11

- 30; Technical Development Document for the Final Airport Deicing Category, p. 127 (including the opportunity cost of land use for both storage and treatment of ADF

- contaminated stormwater). EPA should have analyzed the land requirements for bottom ash, fly ash, and FGD retrofits. EPA Overestimated Cost Savings for Operation of Impoundments EPA assumes that implementation of dry fly ash and possibly dry/closed

- loop bottom ash systems will reduce, and in some cases eliminate, the management of ash transport water and CCRs in on

- site surface impoundments. To calculate these operational cost savings, EPAEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 234 estimated annual O&M and recurring costs associated with was tewater transport system, general operation and inspections of the impoundments, dredging of CCRs for reuse or disposal in a landfill, wastewater treatment system controls ( e.g. , pH control), and water recycle system at the impoundment (if applicable). How ever, some of these operations will continue to occur if the plant continues to operate impoundments for low volume waste treatment and potentially for bottom ash transport water treatment if an impoundment is selected as BAT for bottom ash transport water . Therefore, EPA has overestimated the cost savings for impoundment management, such as general operations and inspections, wastewater treatment system controls, and water recycle systems.

4 The construction costs for the case study are the sum of the ma terial, freight and sales tax, direct labor, indirect costs and subcontracts.

5 The total project costs for the case study do not include miscellaneous unidentified costs.

6 AACE International at 21. Comment Response: Based on a review of public comments and additional cost information from commenters, vendors, and literature, EPA revised the fly ash handling cost methodology to include several updates to both, the population of plants estimated to incur compliance costs and the estimates of costs to inst all and operate dry handling systems. A summary of these revisions are as follow: Capital Cost Formulas . EPA acknowledges the errors in the three capital cost equations (conveyance, steel silo, and concrete silo) that previously underestimated capital cost s. Based on public comments and a review of the data, EPA revised the equations as identified by the commenter in both the Costs & Loads Report documentation and the cost model used to estimate fly ash compliance costs. After updating these equations, the capital cost estimates associated with these components of the fly ash cost methodology increased for the final rule. Balance of Plant (BOP) Costs . According to the commenter, BOP costs include certain elements associated with equipment installation that s hould be included in the capital costs, such as site preparation, concrete, electrical, upgraded control systems, demolition or relocation, and structural modifications. At proposal, EPA included a factor of two to estimate installation costs, but did not specify each of the elements, such as any necessary buildings and site preparation costs, that were included in these costs. Therefore, EPA evaluated the costs provided by the commenter in Appendix D (the wet

- to

- dry conversion of a four

- unit plant), as wel l as other comments on the proposed rule and technical references that provide information related to estimating the costs for engineering projects. Based on this information, EPA determined that the total direct capital cost factor EPA used at proposal (i .e., a factor of two times the purchased equipment cost) is in fact a reasonable estimate of the costs associated with installation, including elements related to balance of plant costs. Furthermore, EPA determined that the cost factor it used is higher th an the factors used by industry to estimate total direct capital costs withEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 235 respect to the purchased equipment capital costs, including BOP costs. Thus EPA concluded its cost methodology and the commenter’s, in this regard, are similar and the cost factor EPA used is reasonable. Therefore, for the final rule, EPA used a total direct capital cost factor, using a factor of two, to account for installation, site preparation, and other BOP costs. EPA notes that the direct costs include updates to system logic f or integration into the plant’s existing digital control system (DCN SE05823). Indirect Capital Costs . Based on a review of the public comments on engineering overhead costs, profits and overhead, such as other contractors fees, and miscellaneous unidentif ied costs, such as contingency, EPA revised the engineering overhead cost factor into one indirect capital cost factor. The indirect capital cost factor, equal to 43 percent of the direct capital costs, was developed based on information from Peters and Ti mmerhaus’ Plant Design and Economics for Chemical Engineers to represent costs associated with engineering and supervision, construction expenses, contractor’s fees, and contingency (DCN SE05831/SE05832 )

. Land Costs . EPA did not include land costs associat ed with dry fly ash handling conversions. Based on data from site visits, discussions with operators of plants that had already converted from wet fly ash handling to dry fly ash handling, the responses to the Steam Electric Survey, and communications with vendors, EPA learned that it is very rare for steam electric power plants to incur land acquisition costs for dry fly ash conversions (DCN SE05823). In addition, EPA did not receive any specific comments from steam electric power plants that documented wh y they would need to acquire land to install a dry fly ash handling system. Furthermore, converting to dry ash handling provides opportunity for plants to repurpose the land area of the existing impoundment for other uses, such as to locate equipment assoc iated with dry handling if necessary (again, EPA has not identified any of the plants that would incur costs for the ELGs that would have such land availability constraints). This would be true even if the plant decided to continue operating the impoundmen t for non

- CCR wastes because it likely would be able to reduce the size of the existing impoundment to reflect the reduction in waste volumes that would be sent to the impoundment. In an extreme case of limited availability, plants could use the existing p arking lot for new equipment, and then repurpose the dewatered impoundment (or portion of the impoundment) to be used as a parking lot. Other approaches would certainly be available, too. See response to DCN EPA

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- 4655, Excerpt Number 53 in C omment Code 16.b for more information on EPA’s bottom ash methodology for land costs. Additionally, as described in Section 6 of EPA’s Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electr ic Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) , EPA did not include land acquisition costs for FGD treatment system based on cost information collected by the Steam Electric Survey. Storage Impoundments . EPA disagrees that it overestimated cost savings for operation of fly ash impoundments. The O&M cost savings estimates developed by EPA are savings based on tons of fly ash, bottom ash, or FGD wastewater solids only. These savings are only calculated for the fly ash, b ottom ash, or FGD tonnage estimated to be removed from operating ponds only, it does not represent other potential costs associated with a pond that may still be receiving other wastestreams, for example low volume wastes.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 236 Industry Fly Ash Conversion Case Study . The commenter references Appendix D in their comment letter, which is a case study of a conversion of a four

- unit power plant to dry fly ash handling. EPA reviewed the data provided in the case study and used the cost estimates to inform its decisio ns on direct and indirect capital cost factors. However, EPA notes that these costs are not comparable to the fly ash cost estimates for the final rule because the commenter’s estimates are based on a conversion to combination vacuum

- pressure systems, not dry vacuum systems. In addition to the revisions discussed previously, EPA also added capital costs for redundant conveyance equipment and backup silo or pugmills. Further, based on observations during EPA’s site visits and sampling events program, as well as communication with equipment vendors, EPA maintains that demolition of the existing wet sluicing system is unnecessary to install and operate a dry fly ash handling system. See EPA’s Incremental Costs and Pollutant Removals for the Final Effluent Limit ations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) for the updated fly ash handling cost methodology. Appendix D also states that steam electric power plants with both w et and dry fly ash handling systems may incur more costs to comply with the zero discharge fly ash standard. EPA agrees with the commenter that if the steam electric power plant wet sluices fly ash and the fly ash transport water is recycled rather than di scharged, no additional equipment is required to comply with the final rule requirements. However, EPA disagrees that if the fly ash transport water is discharged that additional lined storage ponds, tanks or return water pumps are required to meet the fin al rule requirements. This may be an option for some steam electric power plants, but EPA based the BAT compliance costs on a dry handling technology. EPA identified steam electric power plants that require redundancy to handle all fly ash dry, for example eliminating backup wet sluicing systems, and included costs associated with redundant conveyance equipment based on the type of dry fly ash handling system installed at the steam electric power plant. See response to DCN EPA

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- 4655, Excerpt Number 138 in Comment Code 14.a for more information on backup wet sluicing systems. Regarding comments on service life in Appendix D, EPA disagrees that it should use a service life of 15 years for dry fly ash handling systems because, as the commenter states, “the service life of a dry fly ash system can exceed 20 years.” EPA agrees that some components of the system have a service life much shorter than 20 years and will need repair or replacement on a regular basis. EPA accounts for these components i n the O&M cost estimates associated with maintenance materials such as routine replacement of materials and equipment due to consumption or wear and tear. Additionally, EPA compared the costs and estimated service life of the specific components identified for wet and dry fly ash handling and determined that replacement equipment associated with wet fly ash sluicing is more expensive than replacement equipment associated with dry fly ash handling (DCN SE05824). Other comments included in Appendix D focus on pond closure and new landfill construction. The final rule is not requiring steam electric power plants to close existing surface impoundments or construct new landfills. Therefore, these cost estimates are not included in the final rule costs.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 237 Commente r Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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Comment Ex cerpt:
D. EPA's Cost Methodology for Dry Fly Ash Retrofits EPA estimated compliance costs for plants that currently operate wet sluicing systems to convert to dry vacuum fly ash handling systems. EPA developed a costing approach for three separate por tions of the dry fly ash handling system:

 Conveyance

– The mechanical exhauster, piping, valves, and filter

- separators to pull and convey ash from the bottom of the hopper to the intermediate storage destination. EPA calculated these costs at the generati ng unit level.

 Intermediate Storage

– The silo, the vacuum equipment necessary to receive the ash from the conveyance lines, and the unloading equipment necessary for moisture conditioning prior to transportation and disposal. EPA calculated these costs a t the plant level.

 Transportation/Disposal

– The trucking equipment and operation to move the dry fly ash to its final destination ( e.g. , onsite or offsite landfill). EPA calculated these costs at the plant level.
EPA calculated total 2010 costs for each plant as the sum of the conveyance costs, intermediate storage costs, and transportation and disposal costs for the conversion of wet to dry fly ash handling. The total capital cost formula is provided below: Total Capital Costs = Purchased Equipment Cost s + Purchased Equipment Installation Costs + Plant Overhead Engineering Costs + Fly Ash Disposal Costs 2013 TDD p. 9

- 31. 1. EPA’s Capital Cost Methodology EPA calculated the total capital costs for each plant as the sum of the purchased equipment costs, installation costs, plant overhead engineering costs, and fly ash disposal costs. For purchased equipment capital costs, EPA summed the costs of dry vacuum conveyance system(s), concrete or steel silo(s), silo aeration equipment, and pugmill(s). EPA calcu lated equipment costs for conveyance on a generating unit level and silo and pugmill equipment costs at a plant level. EPA estimated conveyance, silo, and pugmill equipment costs using aEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 238 relationship between capital costs and wet fly ash generation rates obtained from industry vendors. IC&PR, p. 7

- 6. EPA estimated installation capital costs for the conveyance and intermediate storage equipment using installation factors supplied by industry vendors. EPA used a conveyance installation factor of two and an intermediate storage installation factor of two based on cost data from United Conveyor Corporation (UCC). EPA estimated the installation capital costs for each plant by multiplying plant purchased equipment costs by these installation cost factors. IC& PR, p. 7

- 12. EPA determined plant engineering overhead costs based on the 2010 ICR responses. From these responses, EPA calculated a median installation factor for the conveyance and for intermediate storage system elements. The conveyance overhead facto r is 0.02454, and the intermediate storage overhead factor is 0.0082. EPA estimated the total engineering overhead costs by applying these factors to the total purchased and installation equipment costs. Id. at 7

- 14 to 7

- 15. EPA based fly ash disposal co sts on moisture

- conditioned fly ash tonnage rates to be disposed of in a landfill. A summary of EPA’s methodology for calculating transportation and disposal costs is provided in the next section. EPA assumed zero land acquisition costs based on data from site visits and discussions with operators of plants that had already converted from wet to dry fly ash handling. IC&PR, p. 7

- 6. EPA also assumed that other capital costs, such as buildings, site preparation, engineering, and construction were included in the costs provided by the vendors. 2. EPA’s Methodology for Calculating Conveyance and Storage O&M Costs EPA estimated operating and maintenance costs for each plant for the conveyance and storage equipment associated with the dry vacuum fly ash handlin g systems. These costs include operating labor, maintenance materials and outage, chemical purchase, and energy costs. EPA calculated total O&M costs as the sum of the conveyance O&M costs and the intermediate storage O&M costs. IC&PR, p. 7

- 16.
3. EPA’s Methodology for Calculating Transportation and Disposal Costs EPA conservatively included costs for plants to transport all solid waste to a landfill because not all plants have the means to market or give away fly ash. For plants with existing onsite CC R landfills, EPA included costs for expanding the existing landfill or building a new landfill to accommodate the additional ash. For plants that do not have existing onsite CCR landfills, EPA included costs for these plants to transport and dispose of th e additional CCRs in an offsite nonhazardous landfill. To estimate capital and O&M disposal costs for an onsite landfill, EPA included the construction of the landfills, a liner, additional groundwater monitoring, a leachate collection system, and closures associated with expanding an existing landfill. EPA estimated offsite disposal costsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 239 based on a tipping fee generally charged by offsite landfills prior to accepting the waste. EPA estimated the tipping fees using state

- level tipping fees and data provi ded in response to the ICR. A summary of EPA’s transportation and disposal costs for both fly ash and bottom ash are provided the following table.
Table 9: Summary of EPA’s Transportation and Disposal Cost Factors

Location Type of

ash Input Input

Units Tr ansportation

Cost Factor (2010$) Disposal

Cost Factor (2010$) Total

Cost Factor (2010$)
Onsite Fly ash Wet FA

generated tons year 3.713 43.2 46.9

Onsite Bottom

ash BA generated tons year 4.038 47.0 51.0

Offsite Fly ash Wet FA

generated tons year 10.53 46.73 57.3

Offsite Bottom

ash BA generated tons year 11.45 50.82 62.3

4. EPA Assumes No Costs for Plant Outages to Install the Dry Fly Ash System Based on an evaluation of vendor and survey information, EPA determined that retrofitting the dry fly ash handling system can be completed during regularly scheduled outages. EPA assumed the entire conveyance and storage systems can be constructed and installed prior to a scheduled outage, and then tie

- in can occur during a regularly scheduled outage. Therefore, EPA assumes no costs for plant outages during installation of the dry fly ash handling system. 5. EPA Assumes Cost Savings for Ceasing Operation of Surface Impoundments Currently Receiving Coal Combustion Residuals
EPA assumes that implementation of dry fly ash and possibly dry/closed

- loop bottom ash systems will reduce, and in some cases eliminate, the management of ash transport water and CCRs in onsite surface impoundments. EPA expects plants will experience cost savings from cea sing to operate these impoundments. To calculate these cost savings, EPA estimated annual O&M and recurring costs associated with managing these wastewaters and CCRs in onsite impoundments. The types of O&M costs EPA evaluated in its assessment included t hose costs associated with wastewater transport system, general operation and inspections of the impoundment site, dredging of CCRs for reuse orEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 240 disposal in a landfill, wastewater treatment system controls ( e.g. , pH control), and water recycle system at th e impoundment (if applicable). E. Flaws in EPA’s Capital Cost Formulas for Dry Fly Ash Conveyance and Intermediate Storage The formulas in EPA’s IC&PR document for fly ash conveyance and intermediate storage costs are inconsistent (by a factor of 10) with other documents in the ELG record. On August 28, 2013, EPA confirmed on a conference call with UWAG that all three formulas used in its economic model to estimate the industry’s fly ash retrofit capital costs are incorrect. For each cost formula, the est imated cost is off by a factor of 10, underestimating the overall capital costs for dry fly ash retrofits for the industry. The following section describes the formula errors.
1. Unit
- Level Conveyance Capital Costs for Equipment Equation
In the IC&PR (Chapter 7: Fly Ash Transport Water Cost Methodology, § 7.1.5.1, Equation 7

- 4, p. 7

- 8), EPA explains that it developed Equation 7

- 4 to estimate dry fly ash conveyance equipment costs as follows:
Unit

- Level Dry Fly Ash Conveyance Equipment Capital Cost (20 10$) = (9,791 × Recalculated Unit Wet Fly Ash Conveyance Rate + 23,372 ) × No. of Unit Vacuum Systems However, in EPA’s “NonCBI Fly Ash Conveyance Cost Equations and Factors” document (EPA

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- 2888.21), Conveyance Equipment Worksheet, the “Dry V acuum Cap Cost” figure has this equation: y = 9,791.9x + 233,721 Also, below the figure, the equation is transcribed incorrectly as: Cost (2010$) = (9,791 x Recalculated Unit Fly Ash Conveyance Rate, tph + 23,372 ) x Number of Unit Vacuum Systems
EPA transc ribed the number incorrectly from the cost curve to its economic model. The y

intercept is off by a factor of 10. 3. Steel Silo Capital Cost Equation EPA made a similar transcription error in the steel silo cost equation. In the IC&PR (Chapter 7: Fly As h Transport Water Cost Methodology, § 7.1.5.2, Equation 7

- 10, p. 7

- 10), EPA states that it developed Equation 7

- 10 to estimate steel silo capital costs as follows: Steel Silo Capital Cost (2010$) = (14.81 × Recalculated Steel Silo Size + 10,089 ) × Number o f Steel SilosEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 241 However, in EPA’s “NonCBI Fly Ash Intermediate Storage Cost Equation and Factors” document (EPA

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- 1959.22), p. 6 of 85, the figure used to estimate capital costs for a steel silo gives the formula as: y = 14.812 x + 100,890

. Aga in, EPA transcribed the number incorrectly from the cost curve to its economic model. The y - intercept is off by a factor of 10. 3. Concrete Silo Capital Cost Equation There is also an error in EPA’s concrete silo capital cost equation. In the IC&PR (Chap ter 7, Fly Ash Transport Water Cost Methodology, § 7.1.5.2, Equation 7

- 14, p. 7

- 10), EPA explains that it developed Equation 7

- 14 to estimate concrete silo capital costs as follows: Concrete Silo Capital Cost (2010$) = [(0.005 × (Recalculated Concrete Silo Size) 2 ) + (519.8 × Recalculated Concrete Silo Size) + 44,379 ] × Number of Concrete Silos But EPA’s “NonCBI Fly Ash Intermediate Storage Cost Equation and Factors” document (EPA

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- 1959.22), uses inconsistent numbers. The figure used to estim ate capital costs for a concrete silo (pp. 14 and 19 of 85) reads: y =0.005x 2 + 519.88x + 443,794

. Again, EPA transcribed the number incorrectly from the cost curve to its economic model. The C constant in the quadratic formula is off by a factor of 10. Also, the table used to develop the figure uses 2011 dollars, whereas equation 7

- 14 (IC&PR, p. 7

- 10) shows 2010 dollars as the output. 4. Impact of Errors in Capital Costs Formulas for Dry Fly Ash Retrofits For its own calculations, UWAG corrected the erro rs listed above and applied the corrected equations to six plants. The average increase in plant capital cost for conveyance and intermediate storage is 46% for this sample set. The size of the error increases with the number of units at each plant requir ing wet

- to

- dry conversion. Table 10 below shows the effect of the errors at six different plants.
Table 10: Effect of EPA Transcription Errors on Capital Cost Estimates for Fly Ash Conveyance and Intermediate StorageEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 242 EPA must correct these errors and r ecalculate the total capital cost for wet

- to

- dry fly ash conversions for the industry.
5. EPA’s Balance of Plant Costs Are Underestimated EPA used costs provided by Clyde Bergemann Power Group (CBPG) and Marietta Silos to generate purchased equipment costs for conveyance and intermediate storage (silo and silo

related equipment) for dry fly ash handling systems. EPA assumed the cost data supplied by the vendors include all balance

- of

- plant costs. However, the CBPG or Marietta Silos cost data do not includ e site preparation, concrete, electrical, upgraded control systems, demolition/relocation, or structural modifications. These costs for BOP must be included in the total capital costs for any technology retrofit at an existing plant.
6. EPA Underestimated Engineering Overhead Costs EPA used cost data from the 2010 ICR to estimate engineering overhead costs for conveyance and intermediate storage. The Agency developed the cost factors by calculating the median ratio of engineering overhead costs to the tot al capital costs for conveyance and intermediate storage. The cost factors for conveyance and intermediate storage are 0.02454 and 0.0082, respectively. Engineering overhead costs include engineering, project management, and construction management. Base d on electric utility industry experience, an engineering overhead cost factor of 0.20 should be used for relatively easy retrofits. For more difficult retrofits this cost factor would be higher.
7. EPA Did Not Include Costs for Profits and Overhead
In estimating dry fly ash handling retrofit costs, EPA did not include costs for profits and overhead for the general contractor or subcontractors for specialty work, including bonding and insurance. For example, contractors may be used for craft labor durin g construction as well as to mobilize and demobilize temporary facilities during construction. These costs are major cost elements for any capital project and should be included in the total capital costs for dry fly ash retrofits.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 243 Based on electric utili ty industry experience, profits and overhead are generally 10% of the contractor labor costs and 5% of the materials costs. For the case study provided in Attachment 13, the profits and overhead costs are approximately 6% of the direct costs (subtotal) of the project. EPA says in the 2013 TDD (section 9) that capital cost elements “commonly include ... contingency.” 2013 TDD at 9

- 2. Thus EPA may have included contingency in its estimates for the steam electric industry. If so, it is not apparent from the record, and not documented according to EPA’s practice in other ELG rules. EPA says it “assumes” that certain capital costs (buildings, site preparation, engineering, and construction) are included in information supplied by vendors. IC&PR, p. 8

- 4. UWAG looked at the documents supplied by vendors but found no information on contingency, overhead, or profits. So even if EPA did include contingency or overhead or profit estimates, they cannot be reviewed or commented on. And based on UWAG’s own estimates, even if EPA did include these costs, its estimates were too low to be realistic.
8. EPA Did Not Include Costs for Miscellaneous Unidentified Costs UWAG believes EPA mistakenly assumed no costs for miscellaneous unidentified costs (contingency) for its scre ening

- level estimate. This is not consistent with industry guidance. A contingency of at least 20% should be included in EPA’s estimate. Contingency is defined as “an amount added to an estimate to allow for items, conditions, or events for which the sta te, occurrence, or effect is uncertain and that experience shows will likely result, in aggregate, in additional costs.” 27 The level of contingency is based on the class of cost estimates and their relative accuracy. The accuracy of the cost estimate is g enerally a function of the amount of engineering completed at the time of the estimate. Since EPA’s costs are, at best, screening level costs, with a small amount of defined project definition, contingency must be added to the total project costs to take into account unidentified costs. It is standard practice, based on the Project Management Institute, to include contingency to cover within

- scope uncertainties. EPA should include a contingency in its estimates of 20% of the total project costs.
9. EPA Di d Not Include Costs for Land Purchases EPA assumed zero land acquisition costs based on data from site visits and discussions with operators of plants that had already converted from wet fly ash handling to dry fly ash handling. IC&PR, p. 7

- 6. This assump tion underestimates the cost for dry fly ash retrofits, particularly if there is not enough space onsite for locating silos and roads for trucks to haul the ash to onsite or offsite landfills. EPA should have evaluated the space availability at each facil ity based on data from the 2010 ICR to determine costs for purchasing land to accommodate the large storage silo(s) and roads for transporting the fly ash to on

- or offsite landfills.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 244 27 AACE International 2013 at 21. Comment Response: See response t o DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 47 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Capital Costs for Dry Fly Ash Conversions UWAG conducted a survey of its membership to collect cost inf ormation for wet

- to

- dry fly ash conversions, including actual and engineering estimates. The total capital costs for each actual or planned retrofit were adjusted to 2012 dollars. Table 8 provides a summary of the cost information collected, including the capacity (MW) of the units retrofitted. Seven of the 15 data points are actual retrofit costs and the remaining eight data points are engineering cost estimates. Table 8: Capital Costs for Wet
- to - Dry Fly Ash Conversion Based on Survey Capacity MW (Rounded) Capital Costs, 2012 M$ Actual or Engineering Cost 600 7.6 Both 800 14.8 Actual 630 25.9 Eng. Estimate 950 31.7 Actual 1880 47.5 Both 1150 43.0 Actual 1460 34.8 Actual 1500 47.6 Actual 1630 105 Eng. Estimate 2600 111.9 Actual 390 11.1 Eng. Estimate 530 28.0 ActualEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 245 3200 94 Eng. Estimate 1240 70 Eng. Estimate 250 30.2 Eng. Estimate To generate a cost equation for estimating the total capital costs of a wet

- to

- dry fly ash conversion, the capacity (MW) of the units retrofitted were plotted versus the total capital costs (2012 dollars) in Figure 2. A linear equation based on the best R2 value (0.6715) was selected. The resulting total capital cost equation for retrofitting to dry fly ash handling is as follows: y = 0. 033x + 5.4272, where: x is the capacity (MW), and y is the total capital costs for the retrofit. Figure 2: Industry Capital Cost Curve for Fly Ash Retrofits (2012 dollars)

Using the cost curve in Figure 2, capital costs and annualized capital costs were calculated based on a 15

- year service life and 7% interest. 7 The results are provided in Table 9. Table 9: Total Capital and Annualized Costs for Dry Fly Ash Retrofits, Million $
Capacity (MW Range) MW Midpoint Total Capital Costs per Plant, M$ Annualized Total

Capital Costs per Plant, M$ <500 250 13.7 1.50 501

- 1000 750 30.2 3.31 1001

- 1500 1250 46.7 5.12 1501

- 2000 1750 63.2 6.94Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 246 2001

- 2500 2250 79.7 8.75 >2500 2750 96.2 10.56 O&M Costs for Dry Fly Ash Handling To develop O&M costs for dry fly ash handling, UWAG used EPA’s methodology8. The O&M costs associated with dry fly ash conveyance are based on actual O&M costs calculated by EPA for a sample of representative plants. Several industry members compared the EPA conveyance O&M to the cost

- curve generated capital costs. The average conveyance O&M is equal to approximately 10% of the annual capital cost. To generate overall cost factors for transportation and disposal O&M costs, industry used EPA’s formulas provided in Chapter 7 of the I C&PR. However, all of EPA’s equations were compiled into one formula to simplify calculating these costs for each plant. These factors are provided in Table 6, Summary of EPA’s Transportation and Disposal Cost Factors, p. 39

7 EPA uses 7% interest in its calculations for the rule, but a 20

- year service life. However, in many previous effluent limitations guidelines, EPA has used a 15

- year service life. A 15

- year service life is a better assumption overall and is consistent with EPA past practice.

8 UWAG used EPA’s methodology for estimating O&M costs for dry fly ash handling due to short comment period, but UWAG is not endorsing EPA’s methodology. Southern believes a more precise look at these costs should be investigated by EPA. Comment Response: EPA reviewed the actual and engineering cost estimates collected and provided by the industry; however, EPA was unable to use these data in revising the dry fly ash handling cost methodology because specific information, including the type of conversions, number of units, and system components included in the cost estimates, is absent from the cost estimates. Therefore, EPA cannot equate the actual or estimated capital costs with the methodology used for the final rule. The cost estimates from vendors that EPA used to develop the capital cost equations represent the costs for the equipment specific the BAT technology option and are defined for a specific input parameter (i.e., wet fly ash production in tons per hour). These costs were provided for a range o f inputs so that EPA could develop a cost curve to represent capital cost estimates for generating units with different fly ash production. The cost data that EPA used also have sufficient granularity that EPA was able to use it to estimate the costs for p lants that would need only certain modifications to existing ash handling systems (e.g., silo costs for additional storage, costs for selected equipment to add redundancy to the system). Additionally, EPA used data from the Steam Electric Survey to estimat e some O&M cost components. These data were used because the number of generating units at the plant (and corresponding data like capacity and type of fly ash handling system type) were known based on other survey responses. The collected data were uniform across the respondents because of the cost categories defined byEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 247 EPA (e.g., maintenance materials, maintenance labor, operating labor) in the Steam Electric Survey. EPA has used various service life estimates in previous rulemakings specifically based on the industry being evaluated. EPA notes that a 20

- year service life is a typical planning period, and responses to the Steam Electric Survey support that ash handling and treatment systems have a lifespan typical of this service life. See response to DCN E PA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 74 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 1. UWAG’s Capital Costs for Dry Fly Ash Conversions UWAG conducted a survey of its members to collec t cost information for wet

- to

- dry fly ash conversions, including actual and engineering estimates. The total capital costs for each actual or planned retrofit were adjusted to 2012 dollars. Table 11 is a summary of the cost information collected, includi ng the capacity (MW) of the units retrofitted. Seven of the 15 data points are actual retrofit costs, and the remaining eight data points are engineering cost estimates.
Table 11: Capital Costs for Wet
- to - Dry Fly Ash Conversion Based on UWAG Member Surve y Capacity MW (Rounded) Capital Costs, 2012 M$ Actual or Engineering Cost 600 7.6 Both 800 14.8 Actual 630 25.9 Eng. Estimate 950 31.7 Actual 1880 47.5 Both 1150 43.0 Actual 1460 34.8 Actual 1500 47.6 Actual 1630 105 Eng. Estimate 2600 111.9 ActualEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 248 Capacity MW (Rounded) Capital Costs, 2012 M$ Actual or Engineering Cost 390 11.1 Eng. Estimate 530 28.0 Actual 3200 94 Eng. Estimate 1240 70 Eng. Estimate 250 30.2 Eng. Estimate To generate a cost equation for estimating the total capital costs of a wet

- to

- dry fly ash conversion, UWAG plotted the capacity (MW) of the units retrofitted versus the total capital costs (in 2012 dollars) in Figure 5. UWAG selected a linear equation based on the best correlation coefficient (R 2 ) value (0.6715). The total capital cost equation for retrofitting to dry fly ash handling is as follows: y = 0.033x + 5.4272, where: x is the capacity (MW), and y is the total capital costs for the retrofit. Figure 5: UWAG Capital Cost Curve for Fly Ash Retrofits

Using the cost curve in Figure 5, UWAG calculated capital costs and annualized capital costs based on a 15

- year service life and 7% interest. 28 The results are provided in Table 12.
Table 12: Total Capital and Annualized Costs for Dry Fly Ash Retrofits, Million $Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 249 Capacity (MW Range) MW Midpoint Total Capital Costs per Plant, M$ Annualized Total

Capital Costs per Plant, M$ <500 250 13.7 1.50 501

- 1000 750 30.2 3.31 1001

- 1500 1250 46.7 5.12 1501

- 2000 1750 63.2 6.94 2001

- 2500 2250 79.7 8.75 >2500 2750 96.2 10.56 2. UWAG’s O&M Costs for Dry Fly Ash Handling
UWAG used EPA’s methodology to develop O&M costs for dry fly ash handling. The O&M costs associated with dry fly ash conveyance are based on actual O&M costs calculated by EPA for a sample of representative plants. Several UWAG members compared the EPA conveyance O&M to the UWAG cost

- curve
- generated capital costs. The average conveyance O&M is equal to approximately 10% of the annual capital cost. UWAG used EPA’s transportation and disposal O&M costs from the formulas EPA provided in Chapter 7 of the IC&PR. UWAG simpli fied EPA’s equations to generate overall cost factors for transportation and disposal O&M costs. These factors are provided in Table 9, Summary of EPA’s Transportation and Disposal Cost Factors, in these comments.

28 EPA uses 7% interest in its calculat ions for the rule, but a 20

- year service life. However, in many previous ELGs, EPA has used a 15

- year service life. UWAG believes a 15

- year service life is a better assumption overall and is consistent with EPA past practice. Comment Response: See resp onse to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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EPA’s Response to Public Comments

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- 250 As with bottom ash retrofits, Southern also developed screening level cost estimates for dry fly ash handling retrofits, which would be required under all of EPA’s preferred options. Southern estimated unit

- specific costs of retrofits for all units within the Southern fleet which generate fly ash transport water and do not already have dry handling systems. As with the bottom ash retrofits, we found that EPA’s estimates are unrealistically low. Table 24: Total Capital Cost Estimates for Retrofitting Dry Fly Ash Handling by Operating Company for All Units > 50 MW

Operating Company No. of Units

(EPA) EPA

Estimate (2010$) (M$) No. of Units

(Southern) 60 Southern

Estimate (2010$) (M$) Southern

In
- Service Estimate (M$) Alabama Power 16 $31 10 $89 $114 Georgia Power 12 $53 6 $31 $39 Mississippi Power 0 $0 0 $0 $0 Gulf Power 2 $4.6 2 $3.3 $4.2 Total 30 $89 18 $123 $157 EPA’s total capital cost for fly ash handling retrofits at Southern facilities (30 units) is $89 million in 2010$, while Southern’s estimate for 18 units is $123 million in 2010$. Again, EPA has left out major cost elements in their screening level cost es timates for dry fly ash handling. EPA does not include any BOP costs for site

- specific factors, such as electrical, upgraded control systems, and structural modifications. EPA has not included costs for profits and overheads for general contractor and su bcontractors or for miscellaneous unidentified costs (contingency).

60 Again, the difference between Southern’s number of units and EPA’s is due to scheduled retirements and gas conversions. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 45 for information regarding EPA’s revisions to the fly ash transport water cost methodology. EPA’s revisions to the dry fly ash handling cost methodology increased capital cost estimates for steam electric power plants incurring costs. However, EPA was unable to specifically evaluate the commenter’s estimates provided in Table 24 because specific information, including the type of conversions and system components included in the cost estimates, are absent from the capital cost es timates. See the response to DCN EPA

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- 251 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 163 External Revi ew Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry Fly Ash Retrofits The dry fly ash conversion was based on installing a vacuum

- pressure dry fly ash system on four units having the same generating capacity. The systems each have new filter collector with vacuum blowers and pressure blowers, transport piping and a new dry fly ash silo that includes ash conditioning equipment and dry silo unloading equipment. The equipment cost was based on a budgetary proposal prepared by Allen Sherman Hoff (A

- S

- H) in December 2010. Costs for the installation of the equipment and the infrastructure required by the equipment were developed using the following assumptions:

 Filter collectors and both sets of blowers will be locate d at grade near the existing precipitators.

 Dry fly ash silo will be located over 2,200 feet away from the boiler.

 Silo foundation estimated design assumed that the same geotechnical conditions existed at the new fly ash silo location were identical to the conditions encountered at a recently installed fly ash silo.

 Insufficient electrical power supply exists at the proposed locations for the silo and the filter collectors requiring additional power distribution equipment.(verified)

 No demolition is require d at the proposed location of the new fly ash silo. (verified)

 Installation of equipment outside of the boiler building will occur while the unit is operating.

 The filter collectors will serve one unit, with capability for back

- up on one adjacent unit. The fly ash silo was sized to serve four units based on ash production rate utilizing the current coal (no fuel switch to PRB coal).

 Adequate craft labor availability

– labor cost based on 50 hour work weeks.

 No disposal costs are included in the estimate.
Co mment Response: EPA understands that this comment, located in Appendix E of the commenter’s letter, is in reference to the case study provided in Appendix D and explains the assumptions the commenter made when developing its cost estimates. EPA reviewed costs associated with dry fly ash handling conversions provided by the commenter throughout their comment letter. See response to DCN EPA

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- 252 costs are not comparable to the fly ash cost estimates for the final rule because the commenter’s estimates are based on a conversion to combination vacuum

- pressure systems, not the dry vacuum systems that are the technology basis for BAT, as described in preamble. Thus, the commenter’s information about this ash handling system is for a different technology altogether, and one that is not the technology basis for BAT.

Commenter Name: Cari Boyce Commenter Aff

iliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 86 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Under EPA’s preferred regulatory options for the proposed ELGs, however, EPA only proposed 100% dry handling for fly ash transport water for existing facilities. This arrangement could create an unnecessary cost to upgrade the existing dry fly ash systems for these stations with redundant equipment and/or affect grid reliability, if a mechanism is not incorporated in the Final Rule to allow the use of an existing hydroveyor backup wet sluicing system on a limited basis. Even though EPA acknowledges that some units have both a dry and wet fly ash slui ce system, EPA did not include the additional costs that would be required to eliminate the need for the backup wet sluicing system for these facilities in their TWPE removal evaluation 36 . In some instances, EPA inferred that the wet systems are just a “legacy system that the plant has not decommissioned following retrofit with a dry system” 37 and subsequently assumed that they would not incur any costs to meet the BAT zero discharge requirement fo r fly ash transport water 38 . However, this assumption is incorrect, since some units were retrofitted with a dry system with the express intent to maintain the wet sluicing system as a backup for specific circumstances such as startup and malfunctions.
There are seven coal

- fired stations within the Duke Energy fleet which currently have, or will have, a dry fly ash system that have a hydroveyor backup system and rely on wet sluicing for backup. Duke Energy performed an evaluati on on these seven facilities to determine the additional equipment and components, along with their associated costs, that would be required to eliminate the backup wet system. Some of the items that would need to be addressed to eliminate the backup syste m include new mechanical exhausters, pressure blowers, additional valves and piping and demolition costs.
Table 3
- 2. Percentage of Cost Underestimated to meet “Zero Discharge” Standard for Duke Facilities

Station EPA Underestimated

the Costs ByEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 253 Asheville 89% Beckjord 41%

Belews Creek 86%

Cliffside 42%

Lee Steam 79%

Miami Fort 6 58%

Wabash River 80%

Allen (1) 100%

Roxboro (1) 100%
Mayo (1) 100%

Marshall (1) 100%

(1) These stations utilize a wet back

- up system to sluice fly ash during start

- up and malfunctions of the dry fly ash system. EPA did not assess any costs for these systems to convert to 100% dry fly ash handling. Utilizing EPA’s own average effluent pollutant concentration for fly ash impoundments, Duke Energy calculated a total TWPE removed and a cost per TWPE for upgrading these facilities with redundant equipment to eliminate the backup wet sluicing system. The results of this analysis are provided below in Table 3

- 3.
Table 3
- 3. Summary of Costs

Total Costs Total TWPE Removed Dollars per TWPE $22,176,000 20,319.89 $1,091.34 The $1,091.34 per TWPE is far more than EPA has ever required for BAT in other rulemakings. In addition, as mentioned earlier , using EPA’s calculated average effluent pollutant concentration overstates the total amount of TWPE removed;Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 254 therefore, the dollars per TWPE calculated above is conservative and most likely understated by a significant amount. Furthermore, EPA acknowledges that oil

- firing generates less ash than coal

- firing 39 , therefore, the pollutant loading during the startup periods firing oil would also be less than under normal, steady

- state coal operation.

36 In reviewing Duke Energy’s CBI data, the fol lowing facilities use a wet backup fly ash system; however, EPA included zero costs to meet the “zero discharge” limit: Allen, Marshall, Mayo, Roxboro. There are most likely additional units at other utilities where EPA did not include the costs required t o eliminate the need for the backup wet fly ash system.

37 TDD, Section 8.1.3, page 8

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39 78 Fed. Reg. at 34453 and 34474 Comment Response: See response to DCN EPA

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- 2 and determined that three plants announced that all generating units would be retiring or converting fuel sources. Additionally, Duke announced plans to end wet sluicing operations at steam electric power plants located in North Carolina, according to a company announcement made in June 2014, following the information provided in this comment l etter (DCN SE050 6 9). Therefore, EPA did not estimate compliance costs associated with these steam electric power plants because they will already be in compliance with the final rule requirements or will be retiring or converting fuel sources. For the one remaining steam electric power plant not noted as a retirement or handling conversion, EPA reviewed the Steam Electric Survey and determined that the steam electric power plant operates a dry fly ash handling system and did not specify any modifications to handle all fly ash dry. Therefore, because none of these facilities will incur costs to comply with the ELGs for the fly ash transport water, the comment regarding the cost

- effectiveness for the Duke facilities is not relevant. Furthermore, cost

- effective ness is not determinative for establishing BAT. See the preamble, RIA, and record for more information.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- 255 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
EPA’S POOR ASSUMPTIONS ABOUT PLANT OUTAGE TIME AND SURFACE IMPOUNDMENTS EPA Assumes No Costs for Plant Outages to Install the Dry Fly Ash System Based on an evaluation of vendor and survey information, EPA determined that retrofitting the dry fly ash handling system can be completed during regularly scheduled outages. EPA assumed the entire conveyance and storage systems can be constructed and installed prior to a scheduled outage, and then tie

- in can occur during a regularly scheduled outage. EPA assumes no costs for plant outages during installation of the dry fly ash handling system. EPA Assumes Cost Savings for Ceasing Ope ration of Surface Impoundments Currently Receiving Coal Combustion Residuals EPA assumes that implementation of dry fly ash and possibly dry/closed

- loop bottom ash systems will reduce, and in some cases eliminate, the management of ash transport water and CCRs in on

- site surface impoundments. EPA expects plants will experience cost savings from ceasing to operate these impoundments. To calculate these cost savings, EPA estimated annual O&M and recurring costs associated with managing these wastewaters and C CRs in on

- site impoundments. The types of O&M costs EPA evaluated in its assessment included those costs associated with: wastewater transport system, general operation and inspections of the impoundment site, dredging of CCRs for reuse or disposal in a la ndfill, wastewater treatment system controls ( e.g. , pH control), and water recycle system at the impoundment (if applicable). EPA Did Not Include Costs for Land Purchases for Public Power Utilities Municipal governments have often provided adjacent land to public power electric plants to other essential city functions leaving small surrounding buffer zones. Often these adjacent properties were given to other city departments or provided for parks, streets, city hospitals, etc. Unlike very large power plants with enormous buffer zones, most public power utilities have smaller footprints and have little capacity for using adjacent lands. EPA assumed zero land acquisition costs based on data from site visits and discussions with plants who had already converted from wet fly ash handling to dry fly ash handling. This assumption underestimates the cost for dry fly ash retrofits, particularly if there is not enough space on
- site for locating silos and roads for trucks to haul the ash to on

- site or off

- site landfill s. EPA should have evaluated the space availability at each facility based on data from the 2010 ICR to determine costs for purchasing land to accommodate the large storage silo(s) and roads for transporting the fly ash to on

- or off

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- 256 Comme nt Response: See response to DCN EPA

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Co mmenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 53 External Review Flag: No External Review External Review Incorporated into Response : No Comment Excerpt: Also, as explored in more detail in the UWAG Comments, other flaws in EPA’s analysis of dry handling of fly ash include grossly inflated TWPEs attributed to fly ash transport water and underestimation of costs and timing associated with plant conversion to dry handling technologies (e.g., Vacuum System, Vacuum

- Pressure System, Pressure System, and Mechanical System) as well as of operation and maintenance of the same. Examples of conversion challenges increasing costs and affecting timing include:

• Designing and installing the new system may have to deal with physical interferences with existing gas ducts, structural steel, or electrical raceways

• Providing electrical power from the existing electrical power distribution system may require a significant capital expenditure to add electrical equipment required by the system’s pressure blowers

• The complexity (and cost) of the new installation is driven by the space available near the existing electrostatic precipitator (ESP) for the new filter collectors and blowers

• Permitting and constructing a new landfill to accept the dry wastestream may be very time consumingEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 257 Comment Response: See response to DCN EPA

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- specific public comments to identify any plant

- specific challenges (for example, space constraints) and account for them in the dry fly ash handling compliance cost estimates, if applicable. EPA did not identify any plant

- specific comments documenting an inability to install the dry fly ash handling technology. EPA does include contingency costs as part of the indirect capit al cost factor to account for such unforeseen challenges. EPA is not requiring steam electric power plants to construct a new landfill as part of the final rule. EPA includes costs for onsite transport and disposal, including landfill expansions, for steam electric power plants that already operate an onsite CCR landfill. EPA estimates offsite transport and disposal for any plants that did not report an onsite CCR landfill in the Steam Electric Survey.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 30 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: As described in the ELG TDD, 22 “EPA estimated compliance costs for plants operating wet sluicing systems to convert to dry vacuum fly ash handling systems. For each generating unit with a wet sluicing system, EPA determined that the plants would likely c ontinue to use the existing valves and branch lines underneath the fly ash collection hoppers, but the plant would require new valves and piping to convey the ash to the silo(s). Additionally, EPA included costs for a mechanical exhauster to create the vac uum. EPA also included costs for the plant to install a new silo, including pugmills and wet unloading equipment. Finally, EPA included costs for the transport and disposal of all the additional ash that the plant is now handling with the dry vacuum system .” “EPA estimated capital, O&M, and 10

- year recurring costs associated with converting wet fly ash handling systems (specifically wet fly ash sluicing systems) to dry vacuum fly ash handling systems for steam electric generating units generating fly ash. To estimate compliance costs forEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 258 a fly ash handling conversion to a dry vacuum system, EPA developed a costing approach for three separate portions of the system:

 Conveyance. The portion of the fly ash handling system from the bottom of the collection hopp er to the intermediate storage destination that includes the mechanical exhauster, piping, valves, and filter

- separators necessary to pull and convey ash from the bottom of the hopper. EPA calculated conveyance costs at the steam electric generating unit level.

 Intermediate Storage . The destination to which the dry fly ash is conveyed from the bottom of the hopper. The intermediate storage includes the structure itself (e.g., the silo), including the vacuum equipment necessary to receive the ash from the c onveyance lines, and the unloading equipment necessary for moisture conditioning prior to transportation and disposal. 23 EPA calculated intermediate storage costs at the plant level.

 Transportation/Disposal . The trucking eq uipment and operation to move the dry fly ash to its final destination (e.g., on

- site or off

- site landfill). EPA calculated transport/disposal costs at the plant level. Based on the above assumptions, EPA determined that only 66 facilities would need to re trofit dry fly ash technologies at a total capital cost of $398 million in 2010$. 24 This translates to a cost of $6.3 million per facility (Table 3). Regardless of the confidence EPA may have in these estimates, they are ve ry much different and much lower than those estimated by AEP.

a. EPA has under
- estimated the cost to retrofit dry fly ash disposal systems and has over - estimated the cost effectiveness of this technology option.
AEP has two facilities that would be affected by a dry fly ash disposal requirement. The total capital cost to convert both of these facilities to dry disposal would be $198 million (2010$), which is nearly one

- half the total cost estimate that EPA obtained for all 66 facilities (Table 3). It is clear that EPA has grossly under

- estimated the cost to retrofit dry fly ash systems at power plants. On a per plant basis, the AEP cost is $99 million (2010$), a value that is nearly 16 times higher than that calculated by EPA (Table 3).

EPA has s eriously underestimated the cost to retrofit dry fly ash disposal systems. AEP can only speculate that the agency failed to account for costs related to the siting, designing, permitting, and construction of a landfill and the subsequent operating costs f or disposal. There are significant costs related to those activities. Establishing a new landfill costs tens of millions of dollars. Operations involve loading from silos, trucking, placing, spreading and compacting the fly ash. These costs vary, but the y are generally in the range of $3.50

- 6.00/ ton of conditionedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 259 fly ash. In addition to the actual disposal cost, AEP incurs monthly costs regardless of whether 1 ounce or 1000 tons of ash are moved in a month. EPA has inquired about the costs of transport ing and disposing fly ash in a privately owned facility and AEP has estimated that those costs are in the range of $20

- 30/ton. EPA should not assume that commercial landfill capacity is readily available for plants which must convert to dry handling. Due to hauling distances, associated transportation costs, and competition with other waste generators, many plants will be forced to construct their own captive landfills. EPA estimated that dry handling of fly ash would cost only $27/TWPE (78 FR at 34474). E PA based this estimate, in part, on fly ash samples collected from an AEP fly ash pond as part of the agency’s Detailed Study sample program, conducted during October 2007. 25 Using the same methods as EPA to determine $/TWPE removed for fly ash transport water, AEP calculated values very much different than those determined by the agency. Split samples were collected by UWAG at the same time as those collected by EPA during the Detailed Study program. These samples were analy zed separately for metals and inorganics using EPA methods 200.8 and 200.7 and the results were shared with AEP. Information on the frequency and duration of transport water flow was obtained from the EPA ELG ICR response. Using the cost data presented ab ove, which were adjusted from 2010$ to 1981$ using Engineering News Record’s Construction Cost Index (CCI) and annualized over a 20

- year period, AEP determined a $/TWPE value of $312 (Table 4); an estimate very much higher than the EPA $/TWPE value for thi s waste stream.

Like EPA’s capital cost estimates, the AEP estimates include total costs to the plant, including major equipment installation, contractor’s costs, site work, concrete, piping, electrical, mechanical, engineering, as well as vendor overhea d and profit. Regardless, these are still all direct costs and do not include indirect and other costs associated with “fully loaded” estimates, which are the full costs that will be borne by the company’s customers. The $/TWPE values only include capital costs and do not include annual O&M expenses, transportation costs, disposal costs, etc., which can be substantial. The actual $/TWPE will be much higher.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 260 EPA also does not account for changes to the plant water balance due to the loss of the fly ash pond. Many fly ash ponds are used to treat other waste streams generated at a power plant. For example, low volume wastes, storm water runoff, treated FGD wastewaters, coal pile runoff and other waste streams are directed to fly ash ponds for further treatmen t through settling. AEP estimates to alter the water balance for the plant in question (Plant 1) are $10 million (2010$). This estimate is based on the assumption that all wastewater that would have been treated in the associated fly ash pond must now be treated with the technology equivalent of a municipal treatment plant (coagulation/flocculation, settling and filtration, less disinfection and specialty treatments, i.e. manganese removal or softening).

22 Id., at 9

- 30.

23 Plants may have a silo; howev er, they may need to install the equipment for moisture conditioning ash prior to unloading. Therefore, the intermediate storage costs are based on two cost indicators, one of the silo and one for the pugmill.

24 EPA Technical Development Document, April 2 013, Table 9

- 5.

25 Final Sampling Episode Report, Buckeye Power Company’s Cardinal Power Plant, Briliant, Ohio. Sampling Episode 6551. Prepared for USEPA by ERG, Inc., August 2008. Comment Response: EPA cannot comment on the estimates provided by the commenter for two AEP steam electric power plants because they do not provide any details of their cost elements and calculations, nor do they identify the specific plants in question. However, based on a review of public comments and additional cost infor mation (from commenters, vendors, and literature), EPA revised the fly ash handling cost methodology to include several updates to both the population of plants estimated to incur compliance costs and the estimates of costs to install and operate dry handl ing systems. See response to DCN EPA

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- 261 transport water (this is the wastewater generated prior to the date established by the permitting authority that is as soon as possible beginni ng November 1, 2018, but no later than December 31, 2023) is subject to BAT effluent limitations on TSS in such wastewater, which are equal to the existing BPT effluent limitations on TSS in fly ash transport water. See Section 14 of the TDD for more infor mation on legacy wastewater. Therefore, EPA did not make any updates to the fly ash cost methodology to account for re

- calculating the water balance or treatment to waste streams treated in settling ponds.
Cost

- effectiveness is not determinative for establ ishing BAT. For the role of cost effectiveness in EPA’s decisions for the final rule , see response to DCN EPA

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Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdi ngs Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA's economic assumptions regarding dry handling of fly ash are flawed because they don’t include the costs associated with managing the dry fly ash material, which was previously managed in surface impoundments. For example, EPA‟s assumptions do not include costs or time needed to permit and construct new or expanded landfills to handle fly ash. EPA‟s assumptions result in an underestimation of the costs associated with converting facilities to dry handling systems. Comment Response: See response to DCN EPA

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Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 262 Co mment Excerpt: EPA recognized that several stations with dry fly ash handling also use a wet system as a backup 28

. EPA, however, has not adequately addressed the necessity, on a dollars per TWPE basis, for existing facilities with a wet backup system to upgrade their equipment to enable 100% dry handling of fly ash. EPA should consider, at a minimum, continuing to allow existing facilities to use a wet sluice system as a backup to the dry system. This revision would avoid unnecessary costs to upgrade the existing dry fly ash system that provide little to no additional benefit to the environment.

28 78 Fed. Reg. at 34449, 34461 and TDD, Section 8.1.2.2, page 8

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- 4655, Excerpt Number 138 for more information on backup wet sluicing systems.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 63 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Should EPA’s final rule exclusively require dry handling (which, for the reasons stated below, it should not) PowerSouth would likely be forced to retrofit a redundant fl y ash dry handling system at the Lowman Plant or install additional lined storage ponds or tanks (possibly with installed return pumps) within the facility’s already tight footprint to capture and/or evaporate off sluice water when the back

- up system must be used, coupled with annually expending substantial additional operation and maintenance dollars to effectively operate the existing dry handling system at the facility to minimize the time this system is offline. Retrofits of this kind (including from

- sc ratch retrofit conversions from wet to dry handling systems) would cost millions of dollars for facilities within the industry, while providing little additional environmental benefit. Accordingly, EPA’s contemplated zero discharge option is untenable on a cost

- effectiveness basis. Comment Response: See response to DCN EPA

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- 263 Based on the feedback provided by the commenter, EPA re

- reviewed the S team Electric Survey and determined that redundant equipment was required to handle all fly ash dry at the Lowman plant. Therefore, EPA added to its overall cost estimates, costs for this plant associated with redundant equipment for the dry fly ash handli ng system already installed at the plant, including redundant filter

- receiver and vacuum pump, for the final rule. For the role of cost

- effectiveness in EPA's decisions for the final rule, see response to DCN EPA

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. For role of cost benefit analysis see DCN EPA

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Commenter Name: Dennis Wene Commenter Affiliation: Alcoa Inc.'s Warrick Operations Document Control Number: EPA

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Alcoa

- Warrick disagrees with zero discharge for fly ash as proposed in the rule. Requiring no wastewater discharge for a f lyash system would require a facility to have a duplicate system placed in reserve in the event of unplanned maintenance or catastrophic failure of the piping, pumping, mill, or flyash silo system. Because Alcoa

- Warrick Operations is an industrial facility that typically runs at peak load, the proposed rule could require a backup system at a cost of over $ 20,000,000. This is an expensive backup plan, when operationally, it makes sense that a targeted up time of 80

- 90 percent could be chosen to allow for pr eventative maintenance of the system as well as unplanned events. A catastrophic shutdown because flyash sluicing is not permitted for a period of time seems overly prescriptive and unnecessary and presents an undue hardship for manufacturing centers.
Com ment Response: See response to DCN EPA

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- 4655, Excerpt Number 138 in Comment Code 14.a for more information on backup wet sluicing systems. EPA disagrees that an entire duplicate system is required to operate in the event of unplanned maint enance or a catastrophic failure. Based on numerous steam electric power plants already operating without need of a backup system and conversations with equipment vendors regarding needed redundancy, EPA determined that specific pieces of equipment, such a s redundant vacuum pumps, pressure blowers, or filter

- receivers, provide sufficient redundancy. Further, EPA does not estimate fly ash compliance costs for Alcoa

- Warrick as it does not fall under the applicability of the final rule. See DCN EPA

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- 264 Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 109 Exter nal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA underestimated the costs of dry fly ash retrofits. The agency developed its own formulas for various pieces of the retrofitted technology. EPA confi rmed to UWAG that it applied erroneous formulas for dry fly ash conveyance equipment, steel silo capital costs, and concrete silo capital costs. When UWAG applied the proper EPA

- derived formulas to a sample set of six plants, it found an average increase of 46% in plant capital cost for conveyance and intermediate storage. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 45 for more information on EPA’s revisions to the fly ash handling cost methodology.

Commenter Name: J. Michael Brown Commenter Affiliation: Ohio Valley Electric Corporation (OVEC) Document Control Number: EPA

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- A2 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No
Comm ent Excerpt: EPA estimated the capital cost per plant for conversion to dry fly ash disposal to be $398 million in 2010 dollars (Table 9

- 5 TDD), for 66 facilities to retrofit to dry fly ash technologies. As a common industry theme, OVEC believes that these costs were grossly underestimated. OVEC uses fly ash transport water at one of our two power plants. Based on a preliminary engineering estimate we are currently developing, the cost to convert this Station to a dry fly ash system is in the $65

- 80 million range for this one facility. Yet, EPA’s estimate to convert 66 facilities is only $398 million. Given the above, OVEC encourages the EPA to reevaluate their capital cost assessment and adjust the cost per toxic

- weighted pounds

- equivalent ($/TWPE) based on comments supplied by EEI, UWAG, EPRI and AEP.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 265 Comment Response: See response to DCN EPA

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Commenter Name: Patrick O’Loughlin Commenter Affiliation: Buckeye Power, In c. Document Control Number: EPA

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- A2 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA's Requirement to Convert Wet Ash Handling Systems to Dry Fly Ash Handling Systems is Unreasonable Under Its Proposed Scheme

..... First, as comprehensively and clearly articulated in AEP's comments, EPA has grossly under estimated the cost to retrofit dry fly ash systems at power plants. Buckeye Power would be req uired to convert to a dry ash handling system at its Cardinal facility. AEP's per plant cost estimate, based on completed fly ash conversion projects, is nearly 16 times higher than EPA' s estimate ($98.9 million vs. $6.3 million). Comment Response:
See response to DCN EPA

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- A1, Excerpt Number 30 for more information on the cost esti mates provided by AEP.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- 266 External Review Flag: No External Review External Review I ncorporated into Response: No Comment Excerpt:

c. The construction of new landfills to account for the loss of fly ash ponds would be costly and time
- consuming. In order to accommodate the loss of fly ash ponds, new landfills will have to be built. The time to develop a landfill is site

- specific but based on AEP experience, a realistic time period to site, engineer/design, permit, and construct a landfill is on the order of four to six years, longer if land has to be acquired and/or public oppositio n is encountered. This includes six months for siting, 12 to 18 months for engineering/design, 18 to 30 months for permitting, and 12 to 36 months for construction of the first cell and agency approval to begin disposal. Comment Response: See response t o DCN EPA

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- A1, Excerpt Number 30 for more information on the construction of new landfills.

Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: At our Frank E. Ratts station, converting the wet fly ash system was estimated (in 2010) to cost approximately $20 MM to install for two units of approximately 140 MW each. This cost is exorbitantly high for a small generating station and would not even include the cost of a landfill for the facility to handle the dry product. Comment Response:
EPA identified the Frank E. Ratts generating units discharging fly ash sluice as retirements or fuel conversions (DCN SE050 6 9); therefore, EPA does not estimate compliance costs associated with this plant. Further, EPA determined that, based on the revisions to the population and revised cost methodologies; the final rule is both technologically available and economically achievable. See response to DCN EPA

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- 267 Commenter Name: Becky Hayat Commenter Affiliation: Natural Resources Defense Council (NRDC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External Review Flag: No External Review External Review Incorporated into Respo nse: No Comment Excerpt: Most plants that have converted from wet

- to

- dry fly ash handling did so in order to reduce costs. 21

21 Consumers Energy, a large public utility company located in Michigan, converted all of its fly ash handling systems to dry sys tems over the last decade. In addition to reduced water consumption, environmental benefits, and additional revenue from sale of dry ash to the construction industry, the company also noted that its conversion to dry ash handling resulted in significant co st savings to its customers by not having to landfill wet fly ash and/or bottom ash. These savings were estimated at more than $2 million annually. See Consumers Energy, Coal Combustion Byproducts Management, available at http://www.consumersenergy.com/upl oadedFiles/CEWEB/OUR_COMPANY/Corporate_Social _Responsibility/The_Environment/coal

- combustion

- byproducts

- management.pdf?n=3986. Comment Response: EPA agrees that converting from wet fly ash sluicing to dry fly ash handling can reduce water consumption and operating costs, including landfilling wet fly ash. EPA also agrees that there are added environmental benefits and that steam electric power plants can benefit from additional revenue from the sale of dry ash.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 268 14.c. Dry Fly Ash Handling

– Pollutant Loa ds
Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 82 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s TWPE evaluation for dry handling of fly ash transport water does not accurately reflect the amount of pollutants that would be removed under a “zero discharge” limit, which is directly due to EPA’s lack of recent fly ash sluice water data and EPA’s methodology for interpreting non
- detects. EPA should revise the database to accurately reflect the TWPE removed under a “zero discharge” scenario. Comment Response: EPA disagrees with the commenter that EPA’s “TWPE evaluation for dry handling of fly ash transport water does not accurately reflect the amount of pollutants that would be removed under a “zero discharge” limit.” In regard to ash characterization data, fol lowing proposal, EPA expanded its fly ash and bottom ash characterization dataset. See response to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b regarding EPA’s ash characterization data. See also the response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d and DCN EPA

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- detect results as one half the sample

- specific quantitation limit for all analytes in the loadings calculations. See also the response to DCN EPA

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- 269 14.e. Dry Fly Ash Handling

– Other Technology Options
Commenter Name: Elizabeth E. Ald ridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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G. The Rule Shou ld Allow “Dense Slurry” to Transport Fly Ash EPA should allow the use of the “dense slurry” option for transporting fly ash. This system uses of water to transport fly ash, but little, if any, transport water disposal is needed after the fly ash is transp orted to the impoundment or landfill. Whereas transport to traditional impoundments involves large volumes of water compared to ash (typically less than 6

- 10% ash), a dense slurry system uses advanced pumping systems to transport ash slurry with as high a s a 72

- 75% ash content. Due to the pozzolanic/cementitious properties of ash, potentially with minor additives such as lime to enhance the process, the transport water is consumed chemically in the reactions within 28

- 48 hours after the material is deposi ted. Using a dense transport system can achieve a dry impoundment somewhat like the pouring and curing of low

- strength cement/grout. Additionally, such a process can suppress fugitive dust and increase impoundment storage capacity, because it allows highe r stacking angles. Stormwater issues must still be addressed. But these are no different from what they would be for traditional FGD or dry fly ash landfills. Another advantage is that, due to the material setting up as a solid, the permeability and hyd raulic conductivity of the impoundment should be greatly reduced, discouraging water infiltration and minimizing landfill leachate. Dense slurry technologies are not new to the electric utility industry and are an accepted practice internationally. Facili ties that use dense ash management operate in Australia as well as at several European sites. Similar technologies and equipment are used in the mining industry for tailings and wastewater. Besides being beneficial for ash transport, a dense slurry system

– with further research and development

– could be useful for achieving zero liquid discharge of scrubber wastewater in the future and should not be subject to anti

- circumvention rules if employed correctly. With the development of effective stabilizatio n technologies for metals and other constituents in wastewater, it is possible that scrubber effluents could be incorporated as the transport fluid in a dense ash management system in which chemicals are added to minimize the leachability of constituents i n the stabilized product in the landfill.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 270 Comment Response: The commenter proposes that steam electric power plants should be permitted to operate dense slurry systems to convey fly ash. The final rule does not preclude the use of any specific technolo gy(ies) ( e.g. , dense slurry systems) or require that specific technology(ies) must be used. EPA’s final rule sets specific effluent limitations and standards that apply to certain wastestreams. Therefore, plants can convey ash with dense slurry systems; ho wever, they must meet a zero discharge limitation for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater. See the response to DCN EPA

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- A2, Excerpt Number 13. The commenter also suggests that dens e slurry technology could be useful for achieving zero liquid discharge of FGD scrubber wastewater and should not be subject to anti

- circumvention rules. The final rule does not restrict plants from using other wastestreams ( e.g. , FGD scrubber effluent) as the transport fluid in dense ash management systems; however, any fluid used to convey the ash is considered fly ash transport water and subject to the zero discharge requirements of the final rule. Since the ash transport water has the most stringent lim itation under the final rule, EPA does not perceive any violation of anti

- circumvention rules.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 52 Ext ernal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Rule Should Allow “Dense Slurry” to Transport Fly Ash or Bottom Ash Southern Company is studying the use of dense slurry technology to transport fly ash. This is a promising technology, and one with little impact to the environment. Southern urges EPA to ensure that the final ELG rule does not prevent the use of this technology for ash transport. Dense slurry systems use water to transport fly ash, but very little, if any, transport water disposal is needed after the fly ash is transported to the storage facility. Traditional wet fly ash sluicing involves large volumes of water compared to ash (typically less than 10% ash). In contrast, a dense slurr y system uses advanced pumping systems to transport ash slurry with as high as a 75% ash content. Due to the pozzolanic/cementitious properties of ash, the transport water is consumed chemically in the reactions within 28

- 48 hours after the material is dep osited. The system sometimes uses minor additives, such as lime, to enhance the process. Using a dense slurry transport system can achieve a dry storage facility somewhat like the pouring and curing of low

- strength cement/grout.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 271 Additionally, such a proces s can suppress fugitive dust and increase the facility’s storage capacity because it enables higher stacking angles. Increased storage capacity means that the facility’s overall footprint is minimized.
Stormwater issues must still be addressed. But these i ssues are no different from what they would be for traditional FGD or dry fly ash landfills. Another advantage is that, due to the material setting up as a solid, the permeability and hydraulic conductivity of the storage facility should be greatly reduced , discouraging water infiltration and minimizing landfill leachate. Dense slurry technologies are not new to the electric utility industry and are an accepted practice internationally. Facilities using dense slurry ash management operate in Australia as we ll as at several sites in Europe. Similar technologies and equipment are used in the mining industry for tailings and wastewater. Besides being beneficial for ash transport, a dense slurry system, with further research and development, could be useful for achieving zero liquid discharge of scrubber wastewater in the future and should not be subject to anti

- circumvention rules if employed correctly. With the development of effective stabilization technologies for metals and other constituents in wastewater, it is possible that scrubber effluents could be incorporated as the transport fluid in a dense ash management system in which chemicals are added to minimize the leachability of constituents in the stabilized product in the landfill. Comment Response: See response to DCN EPA

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Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 32 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
b. The ELG revisions should allow for a “dense slurry” option to transport fly ash. EPA should allow the use of the “dense slurry option” for transporting fly ash. Also known as the GEHO® High Concentration Slurry Disposal Process, this technology includes the use of a much higher ash:water ratio and specialized pumps to transport the fly ash to the disposal area. Due to the pozzolanic/cementitious properties o f the minor ash additives, such as lime, the transport water is consumed chemically and little, if any, transport wastewater is generated. Large ash ponds are not created when this technology is utilized as there is no free water emanating from the solidi fied ash. Storm water issues may still need to be addressed, butEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 272 they would be no different than those encountered with traditional dry fly ash landfills. In some situations, a roof would be installed over the ash dewatering areas to prevent the disruptio n of the stabilization process during rain events. After dewatering, the fly ash would be managed in the same manner as is done at traditional fly ash landfills. Comment Response: See response to DCN EPA

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Comment er Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 157 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Engineering Aspects of Retrofitting Dry Fly Ash Handling Southern Company engineers, as part of their review of the ELG Rule, have considered the timing and engineering aspects of installing dry fly ash handling. The sections below describe the steps to designing, constructing, and implementing a dry fly ash system, and the challenges and limitations of each type of system. Converting from wet sluicing of fly ash to dry handling can be done by installing any of four technologies. These technologies have d ifferent capital costs and also different operating and maintenance (O&M) costs. The most commonly

- used commercially available technologies for dry handling are:
1. vacuum system, 2. vacuum
- pressure system, 3. pressure system, and 4. mechanical system. Dry fly ash sy stems collect ash in filter collector vessels using filter bags to separate ash from the transport air. Ash collected on the outside of the bags is removed by pulses of compressed air. The ash falls into an intermediate storage silo on a vacuum system or i nto an airlock on a vacuum
- pressure system or pressure system. Vacuum System A vacuum system may be used if the intermediate storage facility can be physically located near the ash hoppers of an electrostatic precipitator, baghouse, economizer, or selecti ve catalyticEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 273 reduction (SCR) system. The transport air is produced by either a wet vacuum system or a dry vacuum system. A wet vacuum system uses the existing wet system hydrovactors and sluice water system to produce the transport air flow. Ash

- laden air is drawn into the filter collector and then flows out of the bags into the hydrovactor, where it mixes with the water. Air is separated from the water in the existing air separator tank. Water does not come into contact with the fly ash. A dry vacuum syste m uses mechanical blowers or vacuum pumps to create the transport air flow. Ash

- laden air is drawn into the filter collector and then flows out of the bags and into the atmosphere. The filter collectors are mounted atop the fly ash silo. Ash is discharged into the fly ash silo through air locks located at the outlet of the filter collector. The fly ash silo stores the ash before it is conditioned to prevent dusting on open

- top trucks, or the ash is placed in pressure tankers for disposal. Equipment at the s ilo includes ash aeration systems, vent filters for displaced volume in the silo, ash conditioners, and/or dry unloading systems. Depending on the design of the existing plant, the vacuum system presents the following engineering challenges:

 The primary challenge for the vacuum system is locating the intermediate storage silo close to the fly ash hoppers. This is difficult for a retrofit because road access is required for approach to the silo, exit from the silo, and under the silo.

 The vacuum system all ows for quick conversion to wet transport by operating only two isolation valves, one on the air/ash inlet of the filter collector and one on the air outlet of the filter collector.

 Vacuum blowers for a dry vacuum system require additional electrical power distribution equipment. For retrofit projects, this can require adding costly electrical equipment. Scheduling considerations for retrofitting a vacuum system include the following:

 Delivery of equipment takes 48

- 52 weeks after the manufacturer receives approval drawings from the customer. When the ELG or CCR Rule is promulgated, many plants across the country will need new equipment at the same time, and the delivery time will be longer.

 The intermediate ash storage silo and the filter collectors can be installed while the generating unit is in operation, so an outage is not needed for that part of the work.

 Erecting the silo (including the deep foundations, silo support steel, erecting the silo tank, installing the ash conditioners and the vent filter) w ill require eight (8) months of construction.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 274  Erecting the filter collectors (including foundations, support steel, access ladders and platforms and the collector filter vessels and piping) will require three (3) months of construction.
Vacuum
- Pressure Sy stem
A vacuum

- pressure system may be used when the intermediate storage silo cannot be physically located close to the ash hoppers. The “vacuum” part of system is the same as in the vacuum system (either wet or dry vacuum), but the filter collectors are l ocated between the ash hoppers and the silo. Ash collected on the bags falls into an airlock. The air lock separates the vacuum region of the system from the pressure region of the system. The airlock inlet and outlet isolation valves close, the airlock is pressurized, and the outlet valve is opened to transport the ash by transport air provided by pressure blowers. Once the airlock is empty, the outlet valve is closed, the airlock pressure is equalized with the filter collector, and the inlet valve is open ed to collect ash for the next transport cycle. The distance between the filter collector and the silo, the quantity of ash to be transported, and the size of the ash transport pipe (based in turn on air

- to

- ash ratio and transport velocity) combined determ ine the size of the pressure blowers required for the system.
A vacuum

- pressure system with dry vacuum will normally deploy two sets of mechanical blowers:

 Vacuum blowers to transport the ash from the ash hoppers to the filter collectors

– normally there w ill be three blowers, each with 100% capacity.

 Pressure blowers to transport the ash from the filter collectors to the silo

– normally there will be two blowers, each at 100% capacity. The fly ash silo stores the ash before it is conditioned to prevent du sting on open

- top trucks, or the ash is put into pressure tankers for disposal. Equipment at the silo includes ash aeration systems, vent filters for displaced volume in the silo, ash conditioners, and/or dry unloading systems. The cost of retrofitting a vacuum
- pressure system is affected by the distance to the silo, which can be over 5,000 feet from the filter collectors. For a retrofit, the electrical power required for such a long distance will require extensive additions to the plant’s power distributi on system. Engineering challenges in retrofitting a vacuum

- pressure system include the following:

 The intermediate ash storage silo will require truck access roads and about 0.5 to 1.0 acre of land. The location of the silo can greatly influence the cost o f the conversion.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 275  Ash pipe should be routed so as to limit the number of changes in direction, in order to minimize pipe and pressure blower sizes while still allowing for pipe maintenance over time. Scheduling considerations include the following:

 Delive ry and installation of the intermediate storage silo are the critical

- path activities. Manufacturing lead time is approximately 50

- 60 weeks after the plant owner returns approved drawings to the manufacturer.

 Installing the silo, beginning with foundations , can proceed in parallel with silo and support steel manufacture, while the generating unit remains in operation. A tie

- in outage will be required to connect the new piping system to the existing piping ahead of the wet system hydrovactors.

 The retrofit w ill take approximately 30

- 36 mouths, assuming that a new intermediate fly ash storage silo is required. Pressure System A pressure system does not use a vacuum for transporting the fly ash. Instead, it uses airlocks at each fly ash hopper combined with p ressure blowers to transport the ash from the collection point directly to the intermediate ash storage silo. This system is usually used where the number of fly ash hoppers is small compared to those for an electrostatic precipitator or a small generating unit. A pressure system normally uses one set of mechanical blowers, namely pressure blowers to transport the ash from the filter collectors to the silo, normally two blowers each with 100% capacity. The fly ash silo stores the ash before it is conditione d to prevent dusting on open top trucks or placed into pressure tankers for disposal. Equipment at the silo includes ash aeration systems, vent filters for displaced volume in the silo, ash conditioners, and/or dry unloading systems.
Cost will be affected by the distance to the silo, which can be over 5,000 feet away from the filter collectors. The electrical power required for such long distances will require extensive additions to the power distribution system at the plant. Engineering challenges in retro fitting a pressure system include the following:

 The intermediate ash storage silo will require truck access roads and approximately 0.5 to 1.0 acre of land. Location of the silo can greatly influence the cost of the conversion.

 Ash pipe routing should lim it the number of changes in direction to minimize pipe and pressure blower size, while still allowing for pipe maintenance over time.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 276 Scheduling considerations include the following:

 Delivery and installation of the intermediate storage silo are the criti cal

- path activities. Manufacturing lead time is approximately 50

- 60 weeks after return of approved drawings.

 Silo installation, beginning with foundations, can proceed in parallel with silo and support steel manufacture, while the generating unit remains in operation.

 Conversion from wet fly ash handling to a pressure

- type dry fly ash handling system will require a longer tie

- in outage than either a vacuum or a vacuum

- pressure system. Installing the airlocks at each fly ash hopper must be performed during the outage. Depending on the number of airlocks to be installed, the outage will require at least 4

- 6 weeks.

 Conversion will take approximately 27

- 30 months, assuming a new intermediate fly ash silo is required. Mechanical System A mechanical dry fly ash system uses enclosed drag chain conveyors to transport fly ash from the fly ash hoppers to a surge bin. From the surge bin, any of the three pneumatic dry fly ash systems can be used to transport the ash to the intermediate ash storage silo, depending on how near the silo is to the surge bin. Drag chain conveyors are particularly effective for economizer and selective catalytic reduction fly ash systems. The conveyors help break up the agglomerated ash commonly found in economizer hoppers and SCR hoppers, which tends to plug pneumatic transport systems. The drag chain conveyor layout must contain straight sections. Changes in direction require an additional conveyor section and conveyor drive unit. This makes it a challenge to retrofit an existing system.
E ngineering challenges in retrofitting a mechanical system include the following:

 The intermediate ash storage silo requires truck access roads and approximately 0.5 to 1.0 acre of land. Location of the silo can greatly influence the cost of the conversion.

 Conveyor routing should limit the number of changes in direction to minimize number of conveyor sections, while still allowing for conveyor maintenance over time. The schedule will be affected by the following:

 Delivery and installation of the intermedia te storage silo are the critical

- path activities. Manufacturing lead time is approximately 50

- 60 weeks after the approved drawings are returned to the manufacturer.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 277  Silo installation, beginning with foundations, can proceed in parallel with silo and suppor t steel manufacture, while the generating unit remains in operation.

 Conversion from a wet fly ash handling system to a mechanical (drag chain) dry system will require a longer tie

- in outage than either a vacuum or a vacuum

- pressure system. Installing the conveyor sections at each group of fly ash hoppers must be performed during the outage. Depending on the number of conveyors to be installed, the outage will require at least 4

- 6 weeks.

 The conversion project will take approximately 27

- 30 months, assuming a new intermediate fly ash storage silo is required. Comment Response: EPA appreciates the information provided by the commenter about the process of designing, constructing, and implementing dry fly ash systems, and the challenges and limitations of each dry fly ash handling technologies discussed ( i.e. , vacuum systems, vacuum

- pressure systems, pressure systems, and mechanical systems). EPA acknowledges the commenter’s recommendation that EPA should consider the specified timing and engineering aspect s of installing each of the four types of systems. As discussed in preamble section V and Section 9 of the TDD, EPA has gathered data regarding the technologies used in the industry from technology vendors and revised its cost estimates, in response to com ments received on the proposed rule. The vendors provided the following types of information for EPA’s analyses:

 The type of fly ash and bottom ash handling systems available for reducing and/or eliminating ash transport water;

 Equipment, modifications, an d demolition required to convert wet sluicing fly ash and bottom ash handling systems to dry ash handling or closed

- loop recycle systems;

 Equipment that can be reused as part of the conversion from wet to dry handling or in a closed

- loop recycle system;

 Ou tage time required to install or convert to the different types of ash handling systems;

 Maintenance required for each type of system;

 Operating data for each type of system;

 Purchased equipment, other direct, and indirect capital costs for fly ash and bot tom ash conversions;

 Specifications for the types of ash storage available (e.g., steel silos or concrete silos) for the different types of handling systems;

 Operating and maintenance cost for fly ash and bottom ash handling systems; and

 System energy requ irements.
See section 7 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) for more informati on on EPA’s cost methodology for the BAT basis for fly ash transport water. See also the response to DCN EPA

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- 278Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 279 15. Bottom Ash Transport Water
Commenter Name: Chas Spell Commenter Affiliation : Arizona Public Service Company Document Control Number: EPA

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- A2 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For bottom ash transport water BAT , EPA proposes to choose between treatment using (1) impoundments or (2) dry handling or closed

- loop (zero discharge options) treatment. Option 4a would require dry handling or closed

- loop only for large units above 400 MW and impoundments for others. Beca use of bottom ash transport water’s small contribution of toxics and high cost of treatment, on a $/TWPE basis, APS supports Options 3a and 3b, which would set bottom ash transport water limits attainable by treatment in a settling pond and equal to the cu rrent Best Practicable Control Technology Currently Available (BPT) limits. For decades EPA has recognized that the small amount of toxics in bottom ash transport water does not justify limits that would require dry handling or closed

- loop bottom ash syste ms. In 1980, EPA proposed to reject more stringent regulation of bottom ash because it found that, at most plants, the priority inorganic pollutants detected in bottom ash were less than the concentrations detected in the raw or intake water source. 45 Fed . Reg. 68,328, 68,338 col. 2 (Oct. 14, 1980). The Agency further found that partial to complete recirculation of bottom ash sluice water was technically feasible but decided the high costs and the inability to quantify pollutant reductions weighed against selecting this option. EPA confirmed its finding in the 1982 final rule, determining that “[a]nalysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control.” EPA, Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category (1982 Development Document), EPA

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- 2186 at 498. The same r easoning applies just as much today as it did in 1982. The low level of toxics in bottom ash transport water and the high costs of retrofitting bottom ash handling systems at existing facilities render any “zero discharge” approach unjustified. APS stron gly supports impoundment as BAT for bottom ash transport water. Comment Response: EPA disagrees that surface impoundments represent BAT for control of bottom ash transport water discharges from all existing steam electric power generating units. Except f or discharges from existing small (i.e., 50 MW or less) or oil

- fired units, the final rule establishes “zero discharge” BAT limitations for pollutants in bottom ash transport water discharges based on dry handling or closed

- loop systems. See response to DC N EPA

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- 280 As described in preamble section VIII and the TDD, zero discharge technologies for control of bottom ash transport water are technologically available, and uni ts of all sizes have installed dry handling and closed

- loop systems. Since the 1982 final rule, more plants have installed zero discharge technologies to manage their bottom ash. The record for the final rule demonstrates that steam electric power plants c an install and afford these dry and closed

- loop bottom ash technologies. The steam electric industry has been and continues to undergo transformation as plants respond to a changed market outlook, as well as a changed regulatory environment. As a result of changes in the industry, EPA estimates that, by the time plants would have to meet the final ELG requirements, and taking into account the effects of the Clean Power Plan (CPP), there will be 275 coal

- and petroleum coke

- fired plants operating in the Unit ed States. Of these 275 plants, EPA estimates that 172 (62.5%) either (1) they already operate in a manner that would comply with the zero discharge requirement for bottom ash in the final ELGs, (2) they have announced plant changes that they intend to mak e that will result in compliance with the final ELGs, or (3) EPA projects that they will make changes to comply with the CCR rule that will result in compliance with the final ELGs. EPA, therefore, estimates that of the 275 coal

- fired and petroleum coke

- fi red plants operating, only 103 plants (37.5%) would ultimately incur costs to comply with the zero discharge limitations and standards for bottom ash transport water in this final rule. EPA disagrees that “any zero discharge approach” is “unjustified” and that zero discharge technologies are too costly. EPA re

- evaluated the costs associated with the installation and operation of the BAT and NSPS technology bases after considering public comments and data received (see the Incremental Costs and Pollutant Rem ovals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category Report, DCN SE05831/SE05832). As described in preamble section IX, EPA evaluated the costs and associated impacts of the ELGs on existing steam electric power plants, and on new units to which the ELGs may apply in the future. EPA determined that these technologies are technologically available and economically achievable.
For the role of cost

- effectiveness in EPA's decisions for the final rule, see response to DCN EPA

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. EPA rejected establishing a zero discharge BAT limitation only for units above 400 MW, with BAT limitations based on impoundments for smaller units. See th e response to DCN EPA

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- MW threshold for purposes of bottom ash transport water requirements. See the response to DCN EPA

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- A1, Excerpt Number 9 (i n Comment Code 15.c) regarding bottom ash characteristics. For the final rule, based on public comments, EPA expanded its fly ash and bottom ash characterization dataset used in its estimates of ash impoundment effluent concentrations. See the response to DCN EPA

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- 281 Commenter Name: Thomas W. Easterly Commenter Affiliation: Indiana Department of Environmental Management (IDEM) Document Control Number: EPA

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- A2 Comment Excerpt Number: 5 External Re view Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Bottom Ash Transport Water Indiana believes that if EPA has enough data and analysis to support dry handling of the bottom ash as BAT, then it should be adopted in the final rule. Othetwise, if the environmental and cost/benefits analysis of zero discharge are not significant in compmison with surface impoundments as the treatment technology, then Indiana recommends that EPA allow the surface impoundments as the treatment teclmology. Comment Response: The final rule establishes zero discharge limitations and standards for pollutants in discharges of bottom ash transport water, based on dry handling or remote mechanical drag systems. See response to DCN EPA

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- A1, Excerpt Number 14 (in Comment Code 6.i.i) and preamble section VIII. See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) regarding the use of impoundments as BAT.
For the role of cost

- benefit analysis in EPA’s decisions on this final rule, see response to DCN EPA

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- A1, Excerpt Number 3 (in comment code 6.a).

Commenter Name: Doris Cooksey Commenter Affiliation: City Public Service of San Antonio (CPS Energy) Document Control Numbe r: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA is considering two options for bottom ash, settling ponds or dry handling. It's impor tant to note that the chemical composition of bottom ash has not changed since the last ELG in 1982. No new chemicals have been introduced to bottom ash streams and the current treatment of settling ponds provides adequate treatment for bottom ash which is inert and as samplingEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 282 indicates, non

- leachable.

Comment Response: EPA disagrees that is has “not justified zero discharge for bottom ash transport water” and that surface impoundments are BAT for control of pollutants in discharges of bottom ash tran sport water from all existing steam electric generating units. See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
B ottom Ash Transport Water:

 EPA has not justified zero discharge for bottom ash transport water.

 Surface impoundments shou ld continue as the basis for treatment technology for all units, regardless of size. Comment Response: EPA disagrees that is has “not justified zero discharge for bottom ash transport water” and that surface impoundments are BAT control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units. See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 283 Comment Excerpt:
Bottom Ash Transport Water: Wet handling (as proposed under EPA’s Options 1, 3a, 2, 3b, and 3) The options that dictate dry handling of bottom ash, even with the subcategorization for units over 400 MWs, will have a significant cost impact on the industry with very little benefit to the environment. Bottom ash transport water, poses little risk to t he environment or human health, and the pollutants of concern can be effectively treated and regulated with surface water impoundments. Comment Response: EPA disagrees that bottom ash transport water “poses little risk to the environment or human health and the pollutants of concern can be effectively treated and regulated with surface water impoundments.” See response to DCN EPA

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- A2, Excerpt Number 7. Moreover, EPA notes that the final rule, which is based in part on zero discharge li mitations and standards applicable to bottom ash transport water, is projected to result in substantial reductions in pollutant loadings to our nation’s rivers and streams. See preamble Section X.
For the role of cost

- benefit analysis in EPA’s decisions on this final rule, see response to DCN EPA

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- A1, Excerpt Number 3 (in comment code 6a).

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 68 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: It is encouraging that three of the four regulatory options preferred by EPA, Option 3, 3a, and 3b, propose BAT limits for bottom ash sluice water eq ual to the current BPT limits for all units. Based on Duke Energy’s evaluation and analysis, bottom ash transport water is fairly benign, poses little risk to the environment or human health, and the pollutants of concern can be effectively treated and reg ulated with surface water impoundments. Comment Response: EPA disagrees that bottom ash transport water is “fairly benign,” “poses little risk to the environment or human health,” and “can be effectively treatment and regulated with surface water impound ments.” See response to DCN EPA

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- 284 Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 72 External Review Flag: No Extern al Review External Review Incorporated into Response: No Comment Excerpt:
Based on a realistic average effluent pollutant concentration for bottom ash transport water, a realistic pollutant removal calculation under a zero discharge scenario and actu al costs for a remote MDS, establishing limits for bottom ash transport water equal to the current BPT limits based on surface impoundments for all units, regardless of their size (i.e. MWs), is the only logical alternative for EPA. Comment Response:
EPA disagrees that “establishing limits for bottom ash transport water equal to the current BPT limits based on surface impoundments for all units, regardless of their size (i.e. MWs), is the only logical alternative for EPA.” See response to DCN EPA

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- A2, Excerpt Number 7. EPA notes that it has revised the estimated costs and pollutant reductions attributable to the final rule. See the TDD.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 81 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
“Zero Discharge” Standard for Bottom Ash Sluice Water is Not Justified In conclusion, the EPA analysi s used a database that was not representative of the actual constituent concentrations within bottom ash transport water, and did not account for contributions from the source water. These errors resulted in an inaccurate average pollutant concentration fo r bottom ash transport water. Furthermore, the methodology in which non

detects were factored into the pollutant and TWPE removal calculations and coupled with the incorrect flow rates (especially for Mayo and Roxboro), resulted in an overestimated polluta nt removal for Regulatory Options 4a, 4 and 5. In addition, the analysis underestimates the actual cost of the installation of a remote mechanical drag system by a least one

- third.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 285 With the pollutant and TWPE removal overestimated and the costs underestima ted, the analysis has clearly misrepresented the dollar per TWPE for remote mechanical drag systems. Therefore, the only preferred alternative suitable for bottom ash sluice water is establishing limits based on impoundments equal to the current BPT limit s as proposed for Regulatory Options 1, 3a, 2, 3b, and 3. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. Also see the TDD and response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d for more information about EPA’s pollutant removal estimates, including the data used for this purpose. In addition, EPA revised cost estimates associated with bottom ash BAT technologies. See the response to DCN EPA

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- 4655, Excerpt Number 53, as well as EPA’s Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) , regarding EPA’s analysis of botto m ash costs. As described in preamble section VIII, EPA selected dry handling or closed

- loop systems as the BAT basis for control of pollutants in bottom ash transport water discharges from existing generating units that are greater than 50 MW and that are not oil

- fired. Regarding Roxboro and Mayo Generating Stations see response to DCN EPA

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- A3, Excerpt Number 77 in Comment Code 7.

Commenter Name: Leonard F. Hopkins Commenter Affiliation: Southern Illinois Power Cooperative (SIPC) Do cument Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 7) EPA should establish bottom ash transport water limits based on tr eatment in surface impoundments and equal to current BPT limits for bottom ash transport water (EPA’s Options 1

- 3, including EPA preferred options 3, 3a and 3b). EPA has not demonstrated that retrofitting existing systems to implement dry bottom ash handl ing is cost

- effective. Comment Response: See response to DCN EPA

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- 286 Commenter Name: Nancy A. Evans Commenter Affiliation: PPL Services Corporation Document Control Number: EPA

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- A2 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Further, EPA has always recognized that the small amount of toxics in bottom ash transport water does not justify limits that wou ld require dry handling or closed

- loop bottom ash systems. The justification remains the same and therefore EPA should not require dry handling or closed

loop systems for bottom ash transport water in the final ELG rule. Comment Response: See response t o DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: P. J. Becker Commenter Affiliation: City Water, Light and Power (CWLP) Document Control Number: EPA

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- A2 Comment Excerpt Number: 5 External Review Flag: No Exter nal Review External Review Incorporated into Response: No Comment Excerpt: Bottom Ash Transport Water CWLP agrees with USEPA technology options 1, 3a, 2, 3b, and 3 for Bottom Ash Transport wastewater effluent limits, which is impoundment. Also, CWLP agrees with the small unit exemption in option 4a for units of 400 MW or less, which also allows for impoundment. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Chris M. Hobson Commenter Affiliati on: Southern Company Document Control Number: EPA

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- 287 Comment Excerpt Number: 16 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Of the major wastestreams, retrofitting dry o r closed

- loop bottom ash handling is the least cost effective and often the most difficult technology to implement. Also, bottom ash is relatively inert and represents only about 15

- 20% of the ash generated at a coal

- fired plant. Southern believes that cur rent effluent limitations guidelines (ELG) limits for bottom ash transport water are appropriate and reflect a cost effective and environmentally protective approach. EPA has no basis for further regulation of bottom ash transport water and, because of its low pollutant loadings and relatively high retrofit costs, no further evaluation is justified. Comment Response: EPA disagrees that it “has no basis for further regulation of bottom ash transport water.” See response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 25 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Because of bottom ash transport water’s small contribution of pollutants and high cost of treatment, on a $/TWPE basis, Southern supports Options 1 through 3 (including 3a and 3b), which would set bottom ash transport water limits attainable by treatment in a settling pond and equal to the current BPT limits for bottom ash transport water. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Ron Shipman Commenter Affiliatio n: Georgia Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 3Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 288 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Impoundment should be the technology basis for bottom ash transport water. Other EPA

proposed options are not justified in the record, nor are they cost effective. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Ron Shipman Commenter Affiliation: Georgia Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Impoundment Should Be The Techn ology Basis for Bottom Ash Transport Water For Various Reasons, Including Consistency With The $/TWPE Criterion. EPA's proposed treatment options for bottom ash transport water are (1) impoundment or (2) dry handling or closed

- loop treatment (zero discharg e option). Option 4a in the Proposed Rule would require dry handling or closed

- loop only for large units above 400 MW and impoundments for others. Georgia Power supports impoundment as the technology basis for bottom ash transport water because of (1) it s small contribution of toxics and (2) the high cost of retrofitting dry bottom ash handling systems on a $/TWPE basis.
1. Bottom Ash Transport Water Contributes Small Amounts Of Toxics EPA has historically recognized that bottom ash transport water contai ns a small amount of toxics. For instance, in a 1982 rulemaking, EPA found that, at most plants, the priority inorganic pollutants detected in bottom ash transport water were less than the concentrations detected in the raw or intake water source. 45 Fed . Reg. 68,328, 68,338 col. 2 (Oct. 14, 1980). EPA further found that although partial to complete recirculation of bottom ash sluice water was technically feasible, the high costs and the inability to quantify pollutant reductions weighed heavily against s electing such an option. Id. at col. 3. In addition, in the 1982 final effluent guidelines rule, EPA determined that "[a]nalysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control." EPA,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 289 Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category (1982 Development Document), EPA HQ

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- 2186 at 498. The same reasoning that EPA applied in the 1982 effluent guidelines rulemaking applies today. Accordingly, a dry handling/closed loop approach is unjustified due to the small amount of toxics in bottom ash transport water and the high costs of retrofitting bottom ash handling systems at existing facilities. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Documen t Control Number: EPA

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- A1 Comment Excerpt Number: 35 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:

a. Bottom ash transport water limits that are attainable with treatm ent in a settling pond and are consistent with the current BPT limits, are cost effective and protective of the environment. Options 1 through 3, as well as Options 3a and 3b, which would establish bottom ash transport water limits that are attainable with treatment in a settling pond and would be consistent with the current BPT limits for this wastewater are cost effective and sufficiently protective of the environment. This conclusion is based on the small contribution of pollutants from this waste strea m and the high costs of treatment, based on $/TWPE removed. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Jerry Purvis Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 8 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 290 Comment Excerpt: Second, EPA has made clear in the proposal that continued use of surface im poundments is beneficial for additional polishing of treated FGD wastewater as well as for the primary treatment method for combustion residual leachate and low

- volume waste. In light of the fact that all preferred BAT alternatives would require dry han dling of fly ash, continued use of impoundments for bottom ash transport water treatment is justified. Also, as EPA notes in the record, metals that are associated with bottom ash transport water are generally in particulate (non

- dissolved) form, making th em readily amenable to settling in impoundments. Comment Response: EPA disagrees that it “made clear in the proposal that continued use of surface impoundments is beneficial for additional polishing of treated FGD wastewater as well as for the primary treatment method for combustion residual leachate and low

- volume waste.” Certainly, there is nothing in the ELG rule that prohibits plants from continuing to use surface impoundments in these ways, so long as the final limitations and standards are met, an d EPA acknowledges that surface impoundments are the most common type of system used to treat combustion residual leachate. EPA agrees that bottom ash transport water contains particulate metals that are amenable to settling in impoundments, but the trans port water also contains dissolved metals, which are not removed by surface impoundments. As EPA describes in the preamble, surface impoundments do not represent BAT for the control of pollutants in discharges of bottom ash transport water from all existin g steam electric generating units.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 49 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Bottom Ash Transport Water. In the Draft Rule, EPA has proposed two effluent limitation options for the regulation of bottom ash transport water as BAT based on: 1) continued use of surface impoundme nts or settling ponds (i.e. equal to the current BPT limits); or 2) required dry/closed

- loop handling (i.e. zero discharge). Notably, each of preferred options in the Draft Rule would permit PowerSouth’s Lowman Plant to continue to utilize surface impoundm ents. This includes EPA’s preferred Option 4a, which would authorize units with a capacity less than 400 MW to continue to utilize surface impoundments. While PowerSouth appears to be well positioned to comply with each of EPA’s preferred options for the r egulation of bottom ash transport water as BAT, PowerSouth nevertheless believes that continued use of surface impoundments should be permissible for allEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 291 facilities within the industry because bottom ash transport water contains few pollutants, the cost to remove this small amount of pollutants from the waste stream is excessive and cannot pass even the most relaxed cost

- effectiveness analysis of accurate and current data, and specific constraints make retrofitting any closed

- loop handling technology diffic ult and/or infeasible at many facilities in the industry. As such, PowerSouth specifically supports EPA’s Options 1, 2, 3, 3a, and 3b and offers the following specific comments in support of these regulatory options. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. Responses to other specific comments made by the commenter can be found elsewhere in this comment response document.

Commenter Name: John T. Graves Commenter Affiliation: Minnkota Power Company, Inc. Doc ument Control Number: EPA

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- A1 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA should establish bottom ash transport water limits based on treatme nt in surface impoundments and equal to current BPT limits for bottom ash transport water (EPA's Options 1

- 3, including EPA preferred options 3, 3a and 3b). EPA has not demonstrated that retrofitting existing systems to implement dry bottom ash handling is cost

- effective. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
MIDWEST GEN STRONGLY SUPPORTS EPA’S PROPOSED OPTIONS THAT ESTABLISH BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE (BAT)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 292 FOR BO TTOM ASH TRANSPORT WATER BASED ON THE PERFORMANCE OF GRAVITY SETTLING AT SURFACE IMPOUNDMENTS. Midwest Gen strongly supports all of EPA’s proposed options that deem the performance of gravity settling at surface impoundments as BAT for bottom ash transport water, including EPA’s preferred options 3a, 3b, and 3, 6 as well as EPA’s proposed options 1 and 2.

6 Midwest Gen supports option 4a to the extent that it adopts performance of gravity settling at surface impoundments as BAT for units rated less than o r equal to 400 MW. However, Midwest Gen opposes the adoption of dry handling or closed loop systems as BAT for units rated above 400 MW, as also proposed in option 4a, as discussed further in section II.B, below. Comment Response: See response to DCN EPA

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Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Re view External Review Incorporated into Response: No Comment Excerpt: EPA’s record supports the options that base BAT for bottom ash transport water on gravity settling in surface impoundments because the physical characteristics of this waste stream caus e it to be much more easily removed from transport water through gravity settling. As EPA notes in the Technical Development Document, bottom ash particles are heavier than fly ash, so they separate more easily from the sluice water. 16 Physically, fly a sh is a very fine powdery material and this physical characteristic makes gravity settling not as effective for fly ash. In contrast, bottom ash is very coarse, with grain sizes spanning from fine sand to fine gravel. Thus, EPA’s proposed options 1, 2, 3, 3a and 3b for bottom ash transport water BAT are logically supported in the record, given the physical characteristics of bottom ash.

16 See TDD at 4

- 24. Comment Response: See response to DCN EPA

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- 293 Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 16 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Excerpt: Surface impoundments also serve an important recycling function, allowing recycling of both bottom ash residuals and the treated sluice water. Midwest Gen’s impoundments are routinely dredged to remove accumulated solids, which are dewatered and re
- used for various beneficial purposes, including structural fill, snow and ice control, blast grit and roofing granules. This practice is not limited to Midwest Gen’s facilities. In 2007, approximately 40 percent of bottom ash nationwide was beneficia lly reused. 19 And for a majority of Midwest Gen’s stations, the treated bottom ash sluice water is recycled back into the plant water systems, decreasing overall water use. In addition to this important recycling function, the reuse of bottom ash residu als further illustrates the benign nature of bottom ash transport water. Finally, selecting gravity settling in surface impoundment as BAT for bottom ash transport water is appropriate in light of the statutory factors that EPA is directed to consider unde r the Clean Water Act, 33 U.S.C. § 1314(b)(2)(B)

— “age of equipment and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques, process changes, the cost of achieving such effluent reduct ion, non

- water quality environmental impact (including energy requirements), and such other factors as the Administrator deems appropriate.” In this case, the majority of these facilities have been operating for decades and they have developed sophisticat ed and effective processes for wet handling of bottom ash transport water. Each of these facilities has the engineering in place to continue to effectively control pollutants through gravity settling in the surface impoundments. Given previous investments in these wet handling technologies, these facilities can achieve substantial pollutant reductions in a cost

- effective manner, while avoiding additional air impacts (and other impacts) that might be caused by increased energy consumption from switching to other systems. EPA has not provided data that would suggest that significant changes to the processes that have been in place at these facilities, which would carry with it tremendous cost, engineering challenges, and space constraints, is supportable und er the statutory factors for BAT. As such, Midwest Gen strongly supports EPA’s proposed options that adopt gravity settling at surface impoundments as BAT for bottom ash transport water because they are: (1) consistent with EPA’s statutory obligations unde r the Clean Water Act; (2) protective of the environment; and (3) supported by the data and record before EPA.

19 See EPRI: Coal Ash: Characteristics, Management and Environmental Issues, 5 (Sept. 2009)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 294 Comment Response: EPA acknowledges the commen ter’s statement that “[s]urface impoundments also serve an important recycling function, allowing recycling of both bottom ash residuals and the treated sluice water.” In fact, the final BAT limitations for control of pollutants in bottom ash transport wat er (based on dry handling or closed loop technologies) do not preclude the use of surface impoundments, and a number of plants already operate closed

- loop recycle systems using surface impoundments. In addition, the BAT limitations do not prevent beneficia l use of bottom ash, and EPA included costs associated with additional equipment for dry ash conditioning prior to sale or beneficial use. The commenter mentions that “treated bottom ash sluice water is recycled back into the plant water systems, decreasi ng overall water use.” The final BAT limitations for bottom ash transport water will not increase overall water use at plants. Plants that install a dry handling or closed

loop bottom ash handling system will completely or dramatically reduce their water use for bottom ash handling because they will no longer discharge any bottom ash wastewater. Any bottom ash wastewater that was being reused in other plant processes would be replaced with river water; however, this will not increase net overall water us e because this increased use of river water is offset by the decreased use of river water for bottom ash transport. Additionally, the final rule accommodates certain reuse of bottom ash wastewater within the plant. See preamble section VIII. However, EPA d isagrees that surface impoundments represent BAT for control of pollutants in discharges of bottom ash transport water from all steam electric generating units. See responses to DCN EPA

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- A2, Excerpt Number 7 and DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e). Also see preamble section VIII. EPA notes that the final rule is technologically available and economically achievable (i.e., affordable) for the industry as a whole, and it has acceptable non

- water quality environmental impacts (including, as the commenter states, “air impacts (and other impacts) that might be caused by increased energy consumption”), as required by the Clean Water Act. See sections VIII, IX, and XII of the final preamble for more informat ion.

Commenter Name: Paul Bailey Commenter Affiliation: American Coalition for Clean Coal Electricity (ACCCE) Document Control Number: EPA

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- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For bottom ash transport water, EPA proposes two alternative requirements. Bottom ash transport water would be required to be treated by either (1) dry handling or closed

- loop (a “no discharge” limit), or ( 2) in surface impoundments (with limits on TSS and oil and grease).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 295 ACCCE urges EPA to set bottom ash transport water limits at the level that would be attainable by treatment in surface impoundments. This would be equal to the current Best Practicable Con trol Technology Currently Available (BPT) limits for bottom ash transport water. Surface impoundment is an appropriate technology basis for bottom ash transport water due to that technology’s ability to handle the small amount of toxics in this waste st ream. In a previous Effluent Guideline rulemaking, EPA acknowledged that the priority inorganic pollutants detected in bottom ash water are less than the concentrations detected in the raw or intake water source. 15 These findings were further acknowledged by EPA in a 1982 technical support document, in which EPA stated that “[a]nalysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of c ontrol.” 16 EPA must not depart from its rationale used in previous effluent guidelines rulemakings without adequate justification. As fully explained in UWAG’s comments, EPA has not developed adequate data to justify a departure. Comment Response:
See r esponse to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Raven Power Holdings, LLC Commenter Affiliation: Raven Power Holdings, LLC Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Bottom Ash Transport Water:

o Zero discharge of bottom ash transport water has not been shown by EPA to have any significant benefit.

o The basis of treatment should con tinue to be surface impoundments.

o Raven Power supports EPA’s rejection of Options 4 and 5, requiring dry bottom ash handling. Comment Response: EPA disagrees that “zero discharge of bottom ash transport water has not been shown by EPA to have any signifi cant benefit.” EPA evaluated the pollutants of concern and pollutant loadings associated with bottom ash transport water, as well as the reduction of the amount of waste entering surface impoundments and the risk and severity of structural failures and spi lls. ZeroEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 296 discharge of bottom ash transport water will substantially reduce the amount of pollutants discharged by power plants (see the TDD for details). As described in Section 12 of the TDD, EPA also estimates that the final rule has a positive impact o n water use, with steam electric power plants reducing the amount of water they use for bottom ash transport water by approximately 85 million gallons per day.
For the role of cost

- benefit analysis in EPA’s decisions on this final rule, see response to DCN EPA

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- A1, Excerpt Number 3 (in comment code 6a). EPA disagrees that the basis of control for discharges of bottom ash transport water from all existing steam electric generating units should continue to be surface impoundments. See resp onse to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Raven Power Holdings, LLC Commenter Affiliation: Raven Power Holdings, LLC Document Control Number: EPA

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- A1 Comment Excerpt Number: 29 External Review Flag : No External Review External Review Incorporated into Response: No Comment Excerpt: EPA is proposing BAT limits for bottom ash transport (sluice) water equal to the current BPT limits in three of the four preferred options (Options 3, 3a and 3b). Bottom ash sluice water poses little risk to the environment and may be effectively treated using surface impoundments. Raven Power supports the use of current BPT limits for this waste stream. EPA is also proposing Option 4a, requiring zero discharge for bottom ash sluice water for units greater than 400 MW using a mechanical drag system (MDS). Raven Power contends that EPA overestimated the TWPE of this waste stream and underestimated the total installed cost of these MDS systems. These estimating errors compou nd to significantly increase the effective cost per TWPE. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. For responses to specific comments regarding cost estimates and loadings (TWPE) for bottom ash wastewater, see comment codes 15.c, 15.d, 16.b, and 16.c. Also see the TDD and the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832)

.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 297 Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Continue wet handling of bottom ash in surface impoundments and hydrobins. EPA should establish bottom ash transport water limits based on treatment in surface impoundments and equal to current BPT limits for bottom ash transport water (EPA's Options 1

- 3, including EPA preferred options 3, 3a and 3b). Despite EPA's contention that bottom and fly ash should be handled the same because they contain the same constituents, the fact is that the concentra tion and ability to enter the environment is much different between bottom and fly ash. EPA has not demonstrated that retrofitting existing systems to implement dry bottom ash handling is cost

effective. (See UWAG comments Section V

- BAT for Bottom Ash T ransport Water.) Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. Responses to specific comments made by UWAG, referenced by the commenter, are located elsewhere in this comment response document.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Company also supports EPA’s decision to not require (for existing dischargers) dry handling/closed loop of bottom ash transport water at all facilities. Comment Response: See response to DCN EPA

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Commenter Name: Bruce W. Ramme Commenter Affiliation: We EnergiesEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 298 Document Control Number: EPA

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- A1 Comment Excerpt Number: 45 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For Existing Dischargers, EPA should make Impoundment BAT for Treating Bottom Ash Transport Water. Proposed Preferred Regulatory Options 3a, 3b, 3, and 4a (for units 400 MW or smaller) specify impoundment as best available technology economically achievable for bottom ash transpor t water. 17 We Energies believes that impoundment is BAT and supports EPA’s inclusion in the proposed preferred regulatory options. The low level of toxics in bottom ash transport water coupled with the high costs of retrofitting bottom ash handling syst ems at existing facilities render any “zero discharge” approach unjustified.

17 Regulatory Option 4a specifies dry handling or closed loop with “zero discharge” effluent limitations for units larger than 400 MW. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 46 External Review Flag: No External Review External Review Inc orporated into Response: No Comment Excerpt: EPA’s BAT Determination for Bottom Ash Transport Water in the 1982 Rulemaking. For decades, EPA has recognized that the small amount of toxics in bottom ash transport water does not justify the limits that wou ld require dry handling or closed

- loop bottom ash systems. In1980, EPA proposed to reject more stringent regulation of bottom ash because it found that, at most plants, the priority inorganic pollutants detected in bottom ash were less than the concentrat ions detected in the raw or intake water source. 45 Fed. Reg. 68,328, 68,338 col. 2 (Oct. 14, 1980). The Agency further found that partial to complete recirculation of bottom ash transport water was technically feasible but decided the high costs and the inability to quantify pollutant reductions weighed against selecting the option. 18 Id. col. 3. EPA confirmed its finding in the 1982 final rule, determining that “[a]nalysis of available wastewater sampling dataEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 299 did not indicate that a quantifiable redu ction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control.” 47 Fed. Reg. 52,290, 52,297 col. 1 (Nov. 19, 1982). EPA’s reasoning in 1982 should stand today, especially since limited (and flawed) data were used t o quantify the pollutant concentrations in bottom ash impoundment effluent.

18 The Preamble to the Proposed Rule indicated that many plants partially recirculate their bottom ash transport water utilizing a blowdown stream to control the buildup of dissolv ed solids. The only plants with complete recirculation are those in arid areas using evaporative ponds to eliminate final discharge. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. EPA disagrees that “plants require a blowdown stream to control the buildup of dissolved solids” and the “only plants with complete recirculation are those in arid areas using evaporative ponds to eliminate final discharge.” For example, South Carolina Electric & Gas Company’s Wateree Statio n, located in South Carolina, uses a remote mechanical drag system with complete recycle and does not require the use of evaporation ponds. EPA included costs for plants to ensure that the recirculating systems do not require a blowdown. See response to DCN EPA

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- A1, Excerpt Number 35 (in Comment Code 16.b).

Commenter Name: Michael G. Cashin Commenter Affiliation: Minnesota Power (MP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 19 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Proper bottom ash characterization. Minnesota Power supports UWAG’s. EEI’s and EPRI’s comments explaining how bottom ash has been mischaracterized by EPA. MP supports pr oposed regulatory options 3, 3a and 3b which cite Best Practicable Control Technology Currently Available (BPT) for bottom ash transport wastewaters (FR page 34436). Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. Re sponses to specific comments made by UWAG, EEI, and EPRI, referenced by commenter, are located elsewhere in this comment response document. EPA notes that the final rule does not revise the BPT limitations for any wastestream.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 300 Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 44 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s Proposed Options for Bottom Ash Transport Water and History of Regulation. The second of the seven “key wastestreams” for which EPA has proposed new requirements is bottom ash transport water. For the bottom ash transport water, EPA proposes to cho ose between treatment by impoundment and dry handling or closed

- loop treatment. EEI supports options 1 through 3 (including 3a and 3b), which would set bottom ash transport water limits equivalent to those attainable through treatment in a settling pond, and which is equivalent to the current BPT limits for bottom ash transport water. Bottom ash is relatively inert. For decades, EPA has recognized that the small amount of toxics in bottom ash transport water does not justify limits that would force implem entation of dry handling or closed

- loop bottom ash systems. See e.g., 45 Fed. Reg. at 68,338, col. 2 and 3 (Oct. 14, 1980); see also 1982 Technical Development Document (1982 TDD) (EPA

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- 2186, p. 498). The same reasoning continues to apply today. The low level of toxics in bottom ash transport water, as well as the high costs of retrofitting bottom ash handling systems at existing facilities as discussed below, render any “zero discharge” approach (i.e., closed loop system) to bottom ash tr ansport water unjustified. Furthermore, as demonstrated in the following sections, the record underlying the proposed bottom ash transport water technology options again exemplifies many of the underlying concerns that EEI and its members have with the pro posed rule as a whole, including insufficient data support, flawed assumptions, lack of transparency, and compounded flaws underlying proposed requirements. EPA’s proposed options 4, 4a, and 5 for bottom ash transport water do not meet the rulemaking obje ctives identified above and do not meet the requirements of CWA section 304(b). As a result, EEI and its members do not support those options. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. EPA notes that, as requir ed by the Clean Water Act, the final rule is technologically available, economically achievable, and has acceptable non

- water quality environmental impacts, as described in preamble sections VIII. IX, and XII. EPA disagrees with the commenter’s assertion t hat the final rule was based on “insufficient data support, flawed assumptions, lack of transparency, and compounded flaws underlying proposed requirements.” See response to DCN EPA

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EPA’s Response to Public Comments

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- 301 See response to DCN EPA

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- 4655, Excerpt Number 224 regarding transparency. Responses to other specific comments made by the commenter are located elsewhere in this comment response document.

Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Do cument Control Number: EPA

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- A1 Comment Excerpt Number: 2 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Proposed Rule contains two effluent limitation options for the reg ulation of bottom ash transport water as BAT. These options are based on either: the continued use of surface impoundments or settling ponds (i.e. equal to the current BPT limits); or mandated dry/closed

loop handling (i.e. zero discharge). Each of EPA’s preferred options, with the exception of Option 4a, would permit Alabama Power’s facilities to continue to utilize current surface impoundments. Alabama Power supports the five options that permit the continued use of these structures (Options 1, 2, 3, 3a, and 3b) because: (1) bottom ash transport water contains very few pollutants, (2) the costs associated with removing the small quantity of pollutants from the waste stream is excessive and unjustified by any realistic cost

- effectiveness analysis using acc urate and current data, and (3) the specific constraints associated with retrofitting any closed

- loop handling make that technology difficult and/or infeasible for many facilities within the industry. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. Regarding constraints of installing closed loop handling systems at existing plants, see responses in comment codes 16.a and 16.b. EPA does not agree that retrofitting closed

- loop handling is infeasible, nor that it is a dif ficult technology for power plants to implement. EPA determined that the technologies on which the final rule are based are available and demonstrated. See preamble section VIII and the TDD.

Commenter Name: Becky Hayat Commenter Affiliation: Natural R esources Defense Council (NRDC) Document Control Number: EPA

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- 302 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Options 4 and 5 are the only regulat ory alternatives that require zero discharge of pollutants from bottom ash transport water. While Option 4a also requires a zero discharge effluent limitation for bottom ash transport water, it only applies to individual generating units having a nameplate capacity greater than 400 MW. 15 EPA’s explanation for setting the 400 MW limitation is that the potential compliance costs with a zero discharge standard for bottom ash transport water would be “substantial” if applied to all facilities, and that units le ss than or equal to 400 MW are more likely to incur disproportionately higher costs than those incurred by larger units. 16 The notable increase in water savings from Option 3 (in which effluent limitations are set to the current BPT effluent limitations an d the recommended technology basis is surface impoundment) to Option 4a can be mainly attributed to the change in effluent limitations from the current BPT effluent limitations to a zero discharge standard for units more than 400 MW. Furthermore, the addit ional increase in water savings from Option 4a to Options 4 and 5 can be directly attributed to the elimination of the 400MW threshold.

15 ELGs at 34,469.

16 EPA noted that the average annualized cost of achieving zero discharge limits for bottom ash discharges per MW for a 200 MW unit is more than three times higher than the average cost for a 400 MW unit. See id. at 34,470. Comment Response: Although EPA d id not select the proposed Option 4 or 5 for the final rule, the final rule establishes zero discharge limitations and standards, as well as limitations and standards based on technologies more effective at removing toxic pollutants than surface impoundmen ts, as described in preamble sections III and section VIII. See preamble section VIII for an explanation of why EPA did not select Options 4 or 5 (or the specific suite of technologies represented by those options) for existing sources for the final rule. The final rule is based on EPA’s consideration of public comments and its determination that the final rule is technologically available and economically achievable, and has acceptable non

- water quality environmental impacts. As discussed in preamble secti on VIII, the final rule does not contain a threshold establishing different bottom ash transport water requirements for units below 400 MW (Option C or proposed Option 4a). See also the response to DCN EPA

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- MW threshold for purposes of bottom ash transport water requirements. EPA agrees that there are benefits associated with establishing zero discharge limitations. See the response to DCN EPA

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- 303 regarding the reuse of bottom ash wastewater in some in

- plant processes and water use reductions. See als o preamble section XII regarding non

- water quality environmental impacts associated with the final rule.

Commenter Name: Becky Hayat Commenter Affiliation: Natural Resources Defense Council (NRDC) Document Control Number: EPA

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- A1 C omment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Because most existing plants operate wet bottom ash handling systems, the number of plants that will convert to dry handli ng systems, should Options 4 or 5 be implemented, will be substantial, and as a result, the reductions in water use by these plants will also be quite significant. Based on the above analysis, we urge EPA to reject the unsupported 400 MW threshold proposed in Option 4a. We also urge EPA to select Option 5, or at a minimum Option 4, as the final rule. In addition to removing the most pollutants from steam electric power plant discharges 18 , Option 5 would also yield the greatest reductions in water use as a r esult of requiring zero discharge for bottom ash transport water.

18 ELGs at 34,473. Comment Response: See response to DCN EPA

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- plant processes and water use reductions.

Commenter Name: Dean Ellis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number : 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In summary, Dynegy supports establishing bottom ash transport water effluent limits that are attainable by treatment in a settling pond and equa l to the current limits for bottom ash transportEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 304 water (i.e., EPA Options 1, 2, 3, 3a and 3b). Dynegy opposes Options 4 and 5, which would prohibit discharge of bottom ash transport water, as well as EPA preferred Option 4a, which would prohibit discharge of bottom ash transport water from only those units larger than 400 MW. EPA has not shown that any treatment for bottom ash transport water beyond settling ponds is cost effective. Comment Response: See response to DCN EPA

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Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 22 External Review Flag: No External Review External Review Incorpor ated into Response: No Comment Excerpt: Surface impoundments should be allowed to continue providing adequate and effective treatment for bottom ash transport water. Therefore, MidAmerican supports the continued use of surface impoundments as BPT for all units, regardless of size, under options 1, 3a, 2, 3b, and 3 because the limits set for bottom ash transport water correspond to those achievable through treatment in surface impoundments and the current BAT limits. MidAmerican does not support Options 4 (including 4a) or 5. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. See also response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why surface impoundments do not represent BAT for control of pollutants in discharges of bottom ash transport water from all steam electric generating units.

Commenter Name: Stephen M. Frank Commenter Affiliation: NRG Energy, Inc. Document Control Number: EPA

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- A2 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 305 Comment Excerpt: Preferred Option 4a
- Bottom Ash Transport Water NRG does not support the alternative for BAT refer red to as Option 4a establishing ‘‘zero discharge’’ effluent limits for all pollutants in bottom ash transport water for generating units with a name plate capacity more than 400 MW Comment Response: See response to DCN EPA

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Commenter Name: Stephen M. Frank Commenter Affiliation: NRG Energy, Inc. Document Control Number: EPA

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- A2 Comment Excerpt Number: 24 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Treatment in Impoundments Can Be Effective Under Options 1, 3a, 2, 3b, 3, and 4a (for units less than or equal to 400 MW), effluent limitations and standards for bottom ash transport water would be set equal to the current BPT efflue nt limitations, based on the technology of gravity settling in surface impoundments to remove suspended solids. NRG supports establishing effluent limitations and standards equal to the current BPT effluent limitations. However, NRG believes it is appropri ate to include units greater than 400 MW as well under Option 4a. Specifically, we do not agree that impoundments cannot be effectively designed for removing dissolved metals. EPA determined that some of the metals are present primarily in the dissolved ph ase, and generally are not removed in the surface impoundments that are used to treat fly and bottom ash transport water. This is not the case for bottom ash transport water as previous summarized. When necessary to ensure the receiving stream does not exc eed water quality criteria, several alternatives are available and can be used to enhance the removal of dissolved phase constituents in impoundments. For minimal cost, wet bottom ash pond systems can be optimized by enhancements such as:

 Automated pH cont rols,

 Turbidity curtains,

 Filtration, and

 Use of polymers.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 306 The addition of other low volume wastewaters to bottom ash impoundment systems often facilitates precipitation and settling. For example:
1. Storm water runoff from limestone storage areas provides pH adjustment, 2. Clarifier underflow solids facilitate settling due to flocculent size and excess polymers present. 3. Coal pile runoff provides dissolved iron that oxidizes and promotes co

- precipitation of other inorganic metals. Chemical additives (e.g. , Klaraid and Polyfloc products, etc.) can be added economically to the influent to or overflow from dewatering bin facilitating the precipitation of dissolved metals in the dewatering bins and impoundments. In addition, for the many systems with partial r ecycle, only the portion of wastewater to be discharged could be treated. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. Regarding metals, the commenter did not provide data on dissolved metals to support their assertion that metals in bottom ash transport water are all in the particulate form. EPA’s record demonstrates otherwise. In addition, the commenter did not provide performance data for surface impoundments reflecting enhancements mentioned by the commente r, including the effect of adding other low volume waste sources. Therefore, EPA cannot respond to the commenter’s assertions. See response to DCN EPA

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- A1, Excerpt Number 8 (in Comment Code 6.a) for more discussion on dissolved metals.

Co mmenter Name: Becky Smith Commenter Affiliation: Clean Water Action et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Ex cerpt: Our organizations urge EPA to require “zero discharge” of bottom ash wastewater for all new and existing power plants, as proposed under Options 4 or 5. Approximately 42% of existing coal and coke units have also eliminated discharges of bottom a sh wastewater by using dry handling or closed

- loop systems. 9 Even though a large portion of the power plant sector has already moved away from discharging bottom ash wastewater, none of EPA’s “preferred” options would require all of the remaining 60% of plants to follow suit. Three “preferred” options would require NONE of those power plants to use dry handling or closed

- loop systems to eliminate their bottom ash wastewater discharges, and Option 4a would only require coal

burning boilers with a generatin g capacity above 400 MW to do so. 10 The remaining plantsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 307 under each of these options would still be allowed to use settling ponds asthe only treatment method, even though the Agency has repeatedly acknowledged that ponds are not effective at treating poll utants of concern. 11 The industry itself already recognizes that dry handling of bottom ash is technologically available and affordable, yet EPA’s “preferred” options for bottom ash handling ignores this trend.

9 78 Fed. Reg. at 34,470

10 Id. at 34,458 ( Table VIII

- 1)

11 Id. at 34,476 Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. EPA notes that the final rules establishes limitations and standards applicable to the discharge of pollutants from the steam electric industry. It does not require plant to use any particular technology to achieve the final limitations and standards.

Commenter Name: Cecile M. Conroy Commenter Affiliation: International Brotherhood of Boilermakers (IBB) Document Control Number: EPA

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- A1 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: By contrast, IBB urges EPA not to adopt some of the most stringent options that impose extremely o nerous control costs without achieving any corresponding environmental benefits. One good example of this is EPA's proposed regulatory option to set a zero discharge limitation for bottom ash. There is no real environmental need to require dry ash handling of bottom ash. Even the Agency has effectively recognized surface impoundments adequately control the combustion residual leachate by proposing surface impoundments in the preferred EPA regulatory option for electric generating units below 400 MW. Further more, unlike FGD and fly ash wastewaters, the chemical composition of bottom ash has not changed significantly since EPA issued the last set of ELGs for power plants in 1982. There are no new chemicals in bottom ash generated today; the characteristics of bottom ash

- inert, angular shaped, granular particles, and glass

- like surface structure

- results in a wide variety of beneficial uses, including aggregate for cement and road bases.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 308 Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. See also response to DCN EPA

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- A1, Excerpt Number 11, re garding the benefits of zero discharge limitations.

Commenter Name: Dorothy Kellogg and Michael Leitman Commenter Affiliation: National Rural Electric Cooperative Association (NRECA) Document Control Number: EPA

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NRECA also recommends: Continued wet handling of bottom ash in surface impoundments. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generati ng units.

Commenter Name: Dorothy Kellogg and Michael Leitman Commenter Affiliation: National Rural Electric Cooperative Association (NRECA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No Exter nal Review External Review Incorporated into Response: No Comment Excerpt: Continued wet handling of bottom ash in surface impoundments. EPA should establish bottom ash transport water limits based on treatment in surface impoundments and equal to curren t BPT limits for bottom ash transport water (EPA’s Options 1

- 3, including EPA preferredEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 309 options 3, 3a and 3b). EPA has not demonstrated that retrofitting existing systems to implement dry bottom ash handling is cost

- effective. Comment Response: See respo nse to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Erin Bartlett Commenter Affiliation: The Large Public Power Council (LPPC) Document Control Number: EPA

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- A1 Comment Excerpt Num ber: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ELGs Should Maintain the Option of Impounding Bottom Ash Transport Water for All Existing Facilities.
Of additional concern is the distinction the proposed rule makes between smaller units (≤ 400 MW) and larger units (> 400 MW) with regard to bottom ash transport water. EPA’s preferred option is to allow for the continued use of wet handling at smaller units, while requiring larger un its to convert to dry handling systems. For existing units, EPA should continue to allow the use of impoundments and wet sluicing of bottom ash regardless of unit size. EPA’s lead option (4a) would allow combustion residual leachate (generated from bottom and fly ash impoundments or landfills) to be controlled by a surface impoundment, while bottom ash transport water from units greater than 400 MW would have to use dry handling containment. There is no rationale for requiring dry handling of bottom ash whe n the Agency is clear that combustion residual leachate can be adequately controlled by an impoundment. 6 EPA has proposed that facilities sample and monitor the residual leachate from surface impoundments and landfills containing combustion residuals (inc luding bottom ash) to ensure these wastes are not adversely impacting the environment. As noted below, the composition of such wastes has not significantly changed since the regulations were last promulgated in 1982. If an impoundment provides appropriate treatment for combustion residual leachate, it will also provide appropriate treatment for bottom ash transport water. Consistent with preferred options 3a, 3b, and 3, EPA should therefore allow EGUs with units greater than 400 MW to sample and monitor bot tom ash transport water, as proposed for combustion residual leachate, rather than require conversion to a dry handling system.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 310 6 78 Fed. Reg. 34,463 (June 7, 2013). Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: John W. Myers Commenter Affiliation: Tennessee Valley Authority (TVA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 19 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: TVA supports EPA’s preferred options that allow discharges of bottom ash transport water (after treatment in an impoundment). Comment Response: EPA determined that surface impoundments do not represent BAT. See response t o DCN EPA

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Commenter Name: John W. Myers Commenter Affiliation: Tennessee Valley Authority (TVA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 26 External Review Flag: No External Review External Review Incorporate d into Response: No Comment Excerpt: TVA encourages EPA to allow continued discharges of bottom ash transport water and does not support tiered bottom ash transport discharge restrictions based on megawatt ratings.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 31 1 Comment Response: See response to D CN EPA

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- A1, Excerpt Number 40 (in Comment Code 5.c) for a discussion on the proposed 400

- MW threshold for purposes of the bottom ash transport water requirements.

Commenter Name: Pamela F. Faggert Commen ter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 16 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We support EPA's propose d options 1, 2, 3, 3a, and 3b for bottom ash transport water. These options maintain the existing bottom ash transport water limits for Total Suspended Solids (TSS) and oil and grease which are attainable using settling ponds for treatment. We cannot, howe ver, support EPA’s preferred options 4, 4a or 5, which propose to require zero discharge of bottom ash transport water by employing dry bottom ash handling or closed loop bottom ash water systems. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number: EPA

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- A1 Comment Excerpt Number: 45 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In the Proposed Rule, EPA has proposed two effluent limitation options for the regulation of bottom ash transport water as BAT based on: (1) continued use of surface impoundments orEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 312 settling ponds (i.e., equal to the current BPT limits); or (2) required dry/closed

- loop handling (i.e., ZLD). Notably, each of preferred options in the Proposed Rule would permit PSNH’s facilities to continue to utilize surface impoundments. This includes EPA’s pr eferred Option 4a, which would authorize units with a capacity less than 400 MW to continue to utilize surface impoundments. Accordingly, PSNH supports each of EPA’s preferred options for the regulation of bottom ash transport water as BAT and commends EPA for recognizing that dry handling is cost prohibitive and not necessary to further minimize the already minimal pollutants found in this waste stream. PSNH nevertheless believes that continued use of surface impoundments should be permissible for all faci lities within the industry under each of the proposed regulatory options because bottom ash transport water contains few pollutants, the cost to remove this small amount of pollutants from the waste stream is excessive and cannot pass even the most relaxed cost

- effectiveness analysis of accurate and current data, and specific constraints make retrofitting any closed

- loop handling technology difficult and/or infeasible at many facilities in the industry. As such, PSNH specifically supports EPA’s Options 1, 2 , 3, 3a, and 3b and offers the following specific comments in support of these regulatory options. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 3 Impoundmen t Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 313 Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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A. EPA’s Proposed Options for Bottom Ash Transport Water Range from Impoundments to Dry Handling For bottom ash transport water BAT, EPA proposes to choose between treatment using (1) impoundments or (2) dry handling or closed

- loop (zero discharge of transport water options) treatment. Option 4a would require dry handling or closed

- loop only for large units above 400 MW and impoundments for others.
B ecause of bottom ash transport water’s small contribution of toxics and high cost of treatment, on a $/TWPE basis, UWAG supports Options 1 through 3 (including 3a and 3b), which would set bottom ash transport water limits attainable by treatment in a settl ing pond and equal to the current BPT limits for bottom ash transport water.

Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Claire M. Olson Commenter Affiliation: Basin Electric Power Cooperati ve Document Control Number: EPA

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- A2 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Basin Electric opposes EPA's adoption of "Option 4a" of the proposed rule. While the options under EPA consideration in the proposed rulemaking are similar,Option 4a does not allow for the continued discharge of bottom ash transport water. All but one of Basin Electric's coal based generation fleet are zero discha rge facilities. The Leland Olds Station, however, is authorized under NDPDES 0025232 for the discharge of bottom ash transport water. EPA should not select Option 4a. However, if EPA does select Option 4a, it should allow facilities like Leland Olds Stati on to opt out when it can be demonstrated that bottom ashEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 314 transport water is not harmful to human health and the environment, such as having constituent levels below applicable levels, e.g., drinking water standards.
It would cost tens of millions of dollars to close the existing surface impoundment and to convert Leland Olds Station to include a dry bottom ash handling system. As indicated earlier, bottom ash transport water is generally not necessarily injurious to the environment. If Option 4 is to be selected for the EPA's final action, large sums of money would be expended to convert Leland Olds Station ash handling facilities with negligible environmental benefit. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7. EPA disagrees that it “should allow facilities like Leland Olds Station to opt out when it can be demonstrated that bottom ash transport water is not harmful to human health and the environment.” EPA has evaluated the entire industry and determined th at the zero discharge limitations are technologically available and economically achievable. See preamble section VIII for further discussion. Technology

- based limitations and standards, such as those in this final rule, are not based on the effects of di scharges on receiving waters. See responses to comments in comment code 6.c for the difference between technology

- based ELGs and water quality

- based effluent limitations.

Commenter Name: Kevin D. Frizzell Commenter Affiliation: Owensboro Municipal Uti lities (OMU) Elmer Smith Station (ESS) Document Control Number: EPA

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- A2 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
6. BAT for bottom ash t ransport water: Impoundments should be used for treatment of bottom ash transport water. EPA has recognized in the past that there are very small amounts of toxics in bottom ash transport water. Justification cannot be made by the EPA to require zero disch arge for bottom ash transport. The 1982 rule, EPA confirmed that the analysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of contr ol. The same reasoning applies with todays proposed rule and OMU ESS strongly agrees with the 1982 ruling that bottom ash transport water should be treated by impoundments.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 315 Comment Response: See response to DCN EPA

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- A2, Excerpt Numbe r 7.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No
Comme nt Excerpt: BAT for Bottom Ash Transport Water is Zero Discharge. EPA should also set BAT limits based on zero discharge of bottom ash transport water for all units. The record demonstrates that all plants can install and afford zero discharge systems such as mechanical drag systems, remote mechanical drag systems, or vacuum and pressure systems. The cost of converting to zero discharge systems can be reasonably borne by the industry, even using EPA's cost estimates. However, EPA significantly overest imated costs by ignoring economies of scale, counting units that will likely retire or convert regardless of this rule, overestimating operating and maintenance costs, and using an inappropriately high annualization factor. Moreover, EPA failed to base it s cost estimates on the cheapest options for achieving zero discharge

– the vacuum and pressure systems that use no water at all, reduce operating and maintenance costs, and improve boiler efficiency. If the more accurate, lower cost estimates are used, t he evidence that zero discharge systems are economically achievable is even more overwhelming. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 102.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 102 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
V. BAT FOR BOTTOM ASH TRANSPORT WATER IS ZERO DISCHARGE.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 316 EPA should set BAT limits based on zero discharge of bottom ash transport water for all units. EPA estimates that in 2009, power plants generated 255 billion gallons of bottom ash transport water, which amounts to 2.5 million gallons per day per plant, on average. 415 These transport waters poison our waterways with a host of toxic pollutants, including arsenic, cadmium, lead, mercury, and selenium. 416 However, affordable technologies can completely eliminate these discharges. EPA reviewed six separate methods for eliminating bottom ash transport water discharges; these systems can be divided between systems such as mechanical and remote mechanical drag systems that use water but recycle it, and systems such as vacuum and pressure systems that use no water at all. 417 EPA's analysis of the cost of meeting a zero discharge standard for bottom ash is based on mechanical and remote mechanical drag systems. 418 Options 4 and 5 would set BAT limits based on elimination of bottom ash transport water d ischarges; Option 4a would require only units greater than 400 MW to eliminate those discharges. 419 The record demonstrates that all plants can install and afford zero discharge systems such as mechanical drag systems, remote mechanical drag systems, or va cuum and pressure systems. As explained below, the cost of converting to zero discharge systems can be reasonably borne by the industry, even using EPA's cost estimates. However, EPA significantly overestimated costs by ignoring economies of scale, count ing units that will likely retire or convert regardless of this rule, overestimating operating and maintenance costs, and using an inappropriately high annualization factor. If the more accurate, lower cost estimates are used, the evidence that zero disch arge systems are economically achievable is even more overwhelming. The 1972 Clean Water Act amendments promised to eliminate water pollution, and it is time for EPA to make good on that promise. The Act instructs EPA to establish effluent limitations tha t “shall require the elimination of discharges of all pollutants if the Administrator finds . . . that such elimination is technologically and economically achievable.” 420 The record demonstrates that eliminating the discharge of bottom ash transport wate r is both technologically and economically achievable for all units and therefore the final guidelines must be based on a zero discharge standard for bottom ash transport water.

415 TDD at 6

- 9.

416 TDD at 10

- 18 to 10

- 19.

417 78 Fed. Reg. at 34,453

- 54.

418 Incremental Costs and Pollutant Removals at 8

- 1.

419 Id. at 34,458.

420 33 U.S.C. § 1311(b)(2)(A).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 317 Comment Response: The final rule establishes a “zero discharge” BAT limitation for discharges of bottom ash transport water, based on dry handling or c losed

- loop systems, for all generating units that are greater than 50 MW and that are not oil

- fired. EPA agrees that the record demonstrates that plants can install and afford these technologies, and EPA determined that the final BAT limitations represent reasonable further progress toward the Clean Water Act’s pollutant discharge elimination goal. See preamble section VIII for more discussion of EPA’s rationale. EPA disagrees that it overestimated costs associated with the final limitations on bottom ash t ransport water because, as stated by the commenter in another excerpt, it did not estimate costs based on the “cheapest options for achieving zero discharge

– the vacuum and pressure systems.” EPA reviewed various methods for eliminating bottom ash transpo rt water discharges, including mechanical and remote mechanical drag systems that use water as a quench bath only (not considered transport water) or use transport water but recycle it, and systems such as vacuum and pressure systems that use no water at a ll. EPA based the costs to comply with the rule on installation and operation of a mechanical drag system because it has been demonstrated to be available to the industry based on data collected through the survey and site visits.
EPA did not base costs on vacuum and pressure systems because, based on vendor data, there have been no new U.S. utility plants with pulverized coal boilers built with either pneumatic or vibratory technology in the last 25 years (DCN SE01825A80). EPA did not specifically evaluate the costs for dry vacuum or pressure bottom as handling systems; however, based on vendor information, the approximate equipment and installation cost for a conversion from a wet sluicing system to a pneumatic system is estimated to be more expensive than a mechanical drag system or remote mechanical drag installation (DCN SE01825A80). Moreover, EPA based the costs to comply with the final rule on installation and operation of a remote mechanical drag system as an alternative approach for achieving zero di scharge for steam electric power plants that may not have the headspace required for a mechanical drag system installation. The installation of the remote mechanical drag system eliminates potential issues with space constraints in the boiler house, as com pared to any other under the boiler installation, because the existing under the boiler equipment and bottom ash transport lines are used for the installation. EPA notes that the final rule enables plants to comply with the final limitations and standards using any technology or process they choose. EPA disagrees that it “significantly overestimated costs by ignoring economies of scale, counting units that will likely retire or convert regardless of this rule, overestimating operating and maintenance costs, and using an inappropriately high annualization factor.” For example, EPA did not include costs for units that are expected to retire or convert to dry handling before the date they would need to comply with the final ELGs, as discussed in Sections 4 and 9 of the TDD. Updating EPA’s analyses to reflect these changes in the industry enables a more accurate estimate of the cost for the industry to comply with the ELGs. The total cost for the industry to implement the requirements of the final ELGs is lower t han EPA estimated at proposal for similar requirements, due in large part to plant/unit retirements or fuel conversions, and completed or planned conversions of ash handling systems. In addition to reducing the estimatedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 318 compliance cost for the final rule, these changes in the industry also resulted in EPA revising its estimates of pollutant reductions and decreased water use attributable to implementation of the final rule. EPA did not incorporate economies of scale (i.e., costing one dry handling system to service multiple units) into its estimates of the costs for the final rule, and acknowledges that this may result in higher cost estimates for some steam electric power plants. EPA did not account for economies of scale because plant

- specific data are n ot available to accurately estimate a plant

specific design. For instance, a plant may only have two bottom ash transport water lines and operate five generating units resulting in the need for less remote mechanical drag systems to dewater the bottom ash transport water. However, EPA does not have the total number of bottom ash transport lines for each plant. Furthermore, EPA has insufficient information about the sluice piping arrangements for individual boilers and for the ash sluicing frequency and tim ing for individual boilers. Without such information, EPA is unable to determine the extent to which existing systems used shared or independent piping, nor the extent to which the ash sluice cycles can be adequately coordinated to enable the shared system s that would offer economies of scale. EPA notes that, under the Clean Water Act, it does not have to make a precise calculation of costs. See, e.g., CMA v. EPA , 870 F.2d 177, 237

- 38 (5th Cir. 1989); Kennecott Copper v. EPA, 612 F.2d 1232, 1238 (10th Cir . 1979); BASF Wyandotte Corp. v. Costle , 598 F.2d 637, 662 (1st Cir. 1979); BP Exploration & Oil Inc. v. EPA , 66 F.3d 784, 799

- 800 (6th Cir. 1995); NRDC v. EPA , 863 F.2d 1420, 1426 (9th Cir. 1988); W eyerhaeuser v. Costle , 590 F.2d 1011, 1045 (D.C. Cir. 1978). EPA disagrees that it used an “inappropriately high annualization factor.” Two factors determine the annualization factor: the discount rate and the time period. EPA used a 7 percent discount rate to annualize compliance costs, and both 3 percent an d 7 percent discount rates to annualize social costs and benefits, and assumed a 20

- year service life for the longest lasting equipment. EPA addressed the commenter’s concerns regarding the discount rate in response to DCN EPA

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- A1, Excerpt Number 109 (in comment code 28.b). EPA disagrees that it overestimated operating and maintena nce (O&M) costs. In response to comments received, EPA reevaluated the O&M costs for these systems, as described in Section 9 of the TDD, and the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the S team Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832)

.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 319 Comment Excerpt: As we explain elsewhere in these comments, the Clean Water Act does not authorize EPA to use cost

- effectiveness as the sole or primary basis of a BA T determination; the correct legal standard is whether costs can be borne by the industry as a whole. 444 However, if EPA considers cost

effectiveness, the Agency should find that a zero discharge standard for bottom ash transport water is cost

- effective, given that EPA has approved of cost

- effectiveness values higher than $107 in several other ELGs. This review of the various cost metrics demonstrates that under any of the cost analyses conducted by EPA in this rulemaking, a zero discharge standard for b ottom ash transport water is economically achievable for all plants.

444 See infra Section IX. Comment Response:
For the role of cost

- effectiveness in EPA's decisions for the final rule, see response to DCN EPA

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. EPA agrees that the final BAT limitations for bottom ash transport water based on dry handling or closed

- loop systems, along with the rest of the final rule, are technologically available and economically achievable. See preamble sectio n VIII for more discussion of EPA’s rationale. EPA also notes that the cost

- effectiveness of the final rule is within the range of cost

effectiveness values of ELGs established for other industries. See preamble section XV.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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C. THE OTHER BAT FACTORS DO NOT ALTER THE CONCLUSION THAT BAT LIMITS SHOULD BE BASED ON THE USE OF ZERO DISCHARGE SYSTEMS. The Clean Water Act requires consideration of factors other than technological availability and economic achievability, namely “the age of equipme nt and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques, process changes, the cost of achieving such effluent reduction, non

- water quality environmental impact (including energy re quirements),” and other factors EPA deems appropriate. 477 None of these factors alters the conclusion that the statute requires EPA to setEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 320 effluent limits eliminating the discharge of bottom ash transport water because zero discharge systems are technolog ically and economically achievable. 478 EPA has considered the age of equipment and the age of the plants that would need to convert to zero discharge systems; specifically, EPA considered the age of equipment and plants in determining the costs of retrofitting existing units. 479 Similarly, EPA considered the engineering aspects of mechanical drag, remote mechanical drag, vacuum, pressure, recycle, vibratory belt, and mechanical systems. 480 As explained above, the cost of meeting a zero discharge s tandard for bottom ash transport water can be reasonably borne by the industry. Turning to the final factor, zero discharge of bottom ash transport water has environmental benefits other than improved water quality. For example, it reduces water consumpt ion. Even in areas of the country where water is not scarce, reducing water withdrawals reduces entrainment and impingement of aquatic organisms and ensures that more water remains in the ground and in surface flows for humans and wildlife. 481

477 33 U. S.C. § 1314(b)(2)(B).

478 See id. § 1311(b)(2)(B).

479 E.g., Incremental Costs and Pollutant Removals at 8

- 1, 8

- 9; ERG Subcategorization Memo at 4

- 5.

480 78 Fed. Reg. at 34,453

- 54.

481 EA at 6

- 48; Benefit and Cost Analysis at 2

- 11, 2

- 13, 9

- 1 to 9

- 2.
Commen t Response: The final rule establishes a “zero discharge” BAT limitation for discharges of bottom ash transport water, based on dry handling or closed

- loop systems, for all generating units that are greater than 50 MW and that are not oil

- fired. EPA agr ees that the record demonstrates that the final BAT limitations are technologically available, economically achievable, and have acceptable non

- water quality environmental impacts. See preamble sections VIII, IX, and XII. EPA agrees that “zero discharge of bottom ash transport water has environmental benefits other than improved water quality” including reduced water consumption. See the response to DCN EPA

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- A1, Excerpt Number 11.

Commenter Name: Thomas Cmar Commenter Affiliation: Ea rthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 3Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 321 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The EPA has proposed eight options to control the se discharges by establishing effluent limitation guidelines (ELGs). 78 Fed. Reg. at 34,432. These include four options that are "preferred" (3a, 3b, 3, 4a) and four that are "not preferred" (1, 2, 4, 5) to satisfy Best Available Technology Economically Ac hievable or BAT standards for both existing and new sources. 78 Fed. Reg. at 34,458, Table VIII

- 1. This Report addresses only BAT for bottom ash transport water, which would potentially be controlled only under Options 4a, 4, and 5. Comment Response:
Se e preamble section VIII for an explanation of EPA’s decisions regarding the final BAT limitations applicable to bottom ash transport water.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 4704

- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The record in this case and an independent literature survey that I conducted do not identify any technical, economic, or environmental constraints to implementing zero discharge of bottom ash transport water at all units >50 MW. The failure to require zero discharge of bottom ash transport water in all options is based solely on cost. The EPA has failed to pro perly identify BAT for bottom ash transport waters, as it did not include zero discharge options in all eight regulatory options and used an excessively high exemption threshold (400 MW) for the only preferred option that includes bottom ash controls. The failure to propose adequate BAT requirements is primarily due to assumed costs which are overestimated due to: (1) failure to include true "dry" options; (2) ignoring economies of scale by evaluating costs on a per unit basis rather than a plant basis; (3 ) failure to account for all avoided costs; (4) including many units that would convert in the absence of this rulemaking; and (5) overestimating annual costs by using an excessively high interest rate and a short equipment lifetime. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 102.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 322 Commenter Name: Dennis Wene Commenter Affiliation: Alcoa Inc.'s Warrick Operations Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Fla g: No External Review External Review Incorporated into Response: No Comment Excerpt:
Alcoa

- Warrick supports the wet sluicing of bottom ash for units less than 400 MW. However, the requirements do pose a problem in the analysis of the rule. As noted in the rule, there are no real impacts with bottom ash sluicing wastewaters other than sulfides. Because the data would suggest that the sulfide levels were non

- detect, Alcoa believes there is no driver for this requirement. Moreover, there is a concern that the agency will move to require all bottom ash to move to dry handling systems and that would be problematic considering the negligible environmental impact. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.
EPA disagrees “there are no real impacts with bottom ash sluicing wastewaters other than sulfides.” EPA no longer includes sulfides in the pollutant loadings for bottom ash transport water, yet there are still substantial pollutant loadings associated with the discharge of this wastestream. See preamble section X and the TDD.

Commenter Name: Michael G. Cashin Commenter Affiliation: Minnesota Power (ALLETE) Document Control Number: EPA

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- A2 Comment Excerpt Number: 16 External Review Flag : No External Review External Review Incorporated into Response: No Comment Excerpt: MP supports proposed regulatory options 3, 3a and 3b which cite Best Practicable Control Technology Currently Available (BPT) for bottom ash transport wastewaters (FR pa ge 34436). Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 323 Commenter Name: Mark W. Metcalf Commenter Affiliation: Wisconsin Public Service Corporation (WPS) Document Control Number: EPA

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- 4770

- A2 Co mment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In the previous rulemaking, EPA concluded that “[a]nalysis of available wastewater sampling data did not indicate that a qua ntifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control.” As the majority of the bottom ash transport water data used to support this rulemaking came from the previous rulemaking and the supplemen tal data does not demonstrate a need for more stringent effluent limitations, one can only arrive at the same conclusion: the BAT for treating bottom ash transport water should be set equal to the existing BPT level. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- 5140

- A2 Comment Excerpt Number: 45 External Review Flag: No Exte rnal Review External Review Incorporated into Response: No Comment Excerpt: BAT for Bottom Ash Transport Water For bottom ash transport water BAT, EPA proposes to choose between treatment using (1) impoundments or (2) dry handling or closed

- loop (zero di scharge of transport water options) treatment. Option 4a would require dry handling or closed

- loop only for large units above 400 MW and impoundments for others. Because of bottom ash transport water’s small contribution of toxics and high cost of treatmen t, on a $/TWPE basis, APPA supports Options 1

.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 324 Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Patrick O’Loughlin Commenter Affiliation: Buckeye Power, Inc. Document Control Number: EPA

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- A2 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA Should Recognize Impoundments as BAT for Bottom Ash Wastes Buckeye Power supports designating impoundm ents as BAT. Buckeye Power sees no reasonable basis for requiring dry handling systems for management of bottom ash wastes. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 4305

- A2 Comment Excerpt Number: 2 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Surface impoundments should continue as th e technology basis for treating bottom ash transport water for all units, regardless of size. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 325 Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 4305

- A3 Comment Excerpt Number: 132 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Surface impoundments should continue as the technology basis for treating bottom ash transport water for a ll units, regardless of size. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges o f bottom ash transport water from all existing steam electric generating units.

Commenter Name: Joe L. Citta Commenter Affiliation: Nebraska Public Power District (NPPD) Document Control Number: EPA

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- 4310

- A1 Comment Excerpt Number: 8 E xternal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: ELGs Should Maintain the Option of Impounding Bottom Ash Transport Water for All Existing Facilities Comment Response: See response to DCN EPA

- HQ

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units

.

Commenter Name: Jerry Purvis Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 326 Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated i nto Response: No Comment Excerpt: Therefore, EKPC supports EPA's preferred alternatives that provide for continued use of surface impoundments as the basis for BAT effluent limits for bottom ash transport waters. Comment Response: See response to DCN E PA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generatin g units.

Commenter Name: Lisa Carty Commenter Affiliation: Xcel Energy Document Control Number: EPA

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- 4458

- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Excerpt: Bottom Ash Transport Water should utilize impoundment (equal to BPT) as the technology basis for its ELG. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for d iscussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative D ocument Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 327 Comment Excerpt: PowerSouth believes the record supports the following best available technology options: Bottom Ash Transport Water

– Continued wet handling and treatment in surface impoundments. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discuss ion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Docum ent Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: As indicated in the preamble to the Proposed Rule, gravity settling in s urface impoundments remains an effective means of removing particulate forms of metals and other pollutants. 7 It has been the predominant methodology for most of the coal

- fired power industry

— the vast majority of plants operate wet bottom ash handling sy stems. 8 EPA’s proposed options that set ELGs for bottom ash transport water equal to the current BPT effluent limitations

— based on that gravity settling in surface impoundment technology

— provide ample environmental protection, as supported in the data and administrative record before EPA, and are consistent with the statutory criteria for determining BAT.

7 See 78 Fed. Reg. at 34462. 8 See id. (noting that 80 percent of coal

- and petroleum coke

- fired power plants operate wet bottom ash transport syste ms).

Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units. The final rule is consistent with the Clean Water Act criteria for determiningEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 328 BAT, as it is technologically available, economically achievable, and has acceptable non

- water quality environmental im pacts. See preamble sections VIII, IX, and XII.

Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 30 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Midwest Gen respectfully requests that EPA:

• finalize a rule that recognizes the performance of gravity settling at surface impoundments as BAT for bottom ash transport water; Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing st eam electric generating units.

Commenter Name: Raven Power Holdings, LLC Commenter Affiliation: Raven Power Holdings, LLC Document Control Number: EPA

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- 4467

- A1 Comment Excerpt Number: 38 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Bottom ash sluice water limits should continue to be based on treatment by surface impoundments. Comment Response: See response to DCN EPA

- HQ

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- A1, Excerpt Number 3 (in Com ment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 329 Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: DP&L supports Options 1 through 3 (including 3 a and 3b), which would set bottom ash transport water limits attainable by treatment in a settling pond and equal to the current BPT limits for bottom ash transport water. Comment Response: See response to DCN EPA

- HQ

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- 4475

- A1 Comment Excerpt Number: 56 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Impoundment, which effectively removes suspended solids, should be BAT. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Jay Hudson Commenter Affiliation: Santee Cooper Document Control Number: EPA

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- A1 Comment Excerpt Number: 14Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 330 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In sum, because there will be little environmental benefit and significant costs affecting 80% of the existing coal

- and petroleum coke

- fired units, Santee Coo per requests that BAT limits on bottom ash transport water be set equal to the current BPT limitations based on surface impoundments for all units regardless of size. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units. EPA disagrees that there “will be little environmental benefit” a ssociated with limitations on bottom ash transport water. See response to DCN EPA

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- A1, Excerpt Number 11.

Commenter Name: Dean Ellis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

- HQ

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- 0819

- 4491

- A1 Comment Ex cerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA proposes to set effluent limits for bottom ash transport water based on (1) gravity settling in surface impoundments or (2) dry handling or closed

- loop technologies (zero discharge of bottom ash transport water). For several reasons, Dynegy supports setting bottom ash transport water effluent limits based on surface impoundment technology and equal to the current effluent limits f or bottom ash transport water. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 331 Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag : No External Review External Review Incorporated into Response: No Comment Excerpt: EPA should adopt bottom ash transport water effluent limitations and standards equal to current BPT limitations. Two treatment methods are considered under the eight pro posed alternatives for regulating bottom ash transport water under the proposed ELG rule. Under the majority of options (1, 3a, 2, 3b, 3, and 4a [for units less than or equal to 400 MW]), EPA proposes to set effluent limitations and standards equal to the current BPT limitations based on the current practice of using surface impoundments to remove suspended solids. 18 Zero discharge is proposed under options 4a (for units greater than 400 MW), 4, and 5. As stated above in the fly ash transport water discussi on, surface impoundments have proven effective at removing suspended solids prior to discharging wastewaters from well designed and well operated impoundments.
18 Id. at 34461

- 34462. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Paul Carpmone Commenter Af

filiation: Tampa Electric Company (TEC) Document Control Number: EPA

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- 4520

- A2 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Of the options offered by E PA, TEC supports the continued use of impoundments as the best practicable technology (BPT) for bottom ash trans port water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 332 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- 5140

- A2 Comment Excerpt Number: 24 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The state of the record, with the BAT options it supports, is as follows:
Ta ble 2:

Wastestream Record Supports No More than This Option Bottom ash transport water Options 1

- 3 Impoundment Comment Response: See response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) for discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Jamie Rhodes Commenter Affiliation: Environment Council of Rhode Island Document Control Number: EPA

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- 4034

- A2 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Our organizations urge EPA to require “zero discharge” of bottom ash wastewater for all new and existing power plants, as proposed under Options 4 or 5. Approximately 42% of existing coal and coke units have also eliminated discharges of bottom ash wastewater by using dry handling or closed

- loop systems. 9 Even though a large portion of the power plant sector hasEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 333 already moved away from discharging bottom ash wastewater, none of EPA’s “preferred” options would require all of the remaining 60% of plants to follow suit. Three “preferred” options would require NONE of those power plants to use dry ha ndling or closed

- loop systems to eliminate their bottom ash wastewater discharges, and Option 4a would only require coal

burning boilers with a generating capacity above 400 MW to do so. 10 The remaining plants under each of these options would still be a llowed to use settling ponds as the only treatment method, even though the Agency has repeatedly acknowledged that ponds are not effective at treating pollutants of concern. 11 The industry itself already recognizes that dry handling of bottom ash is techno logically available and affordable, yet EPA’s “preferred” options for bottom ash handling ignores this trend.

9 78 Fed. Reg. at 34,470

10 Id

. at 34,458 (Table VIII

- 1)

11 Id. at 34,476 Comment Response: See response to DCN EPA

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- A1, Exce rpt Number 3 (in Comment Code 6.e) and preamble section VIII for discussion of the final limitations and standards applicable to bottom ash transport water, including a discussion of why impoundments are not BAT for the control of pollutants in discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Joe L. Citta Commenter Affiliation: Nebraska Public Power District (NPPD) Document Control Number: EPA

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- 2009

- 0819

- 4310

- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA's preferred option (4a) to allow combustion residual leachate (generated from bottom and fly ash impoundment s or landfill s) to be controlled by a surface impoundment , while bottom ash transport water from units greater than 400 MW would have to use dry handling containment is not consistent. There is no rationale for requiring larger facilities to move to dry handling of bottom ash when the EPA is clear that combustion residual leachate can be adequately controlled by an impoundment. Currently, facilities sample and monitor the residual leachate from surface impoundments and landfills containing combustion residuals to ensure these wastes ar e not adversely impacting the environment. If an impoundment provides appropriate treatment forEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 334 combustion residual leachate, it will also provide appropriate treatment for bottom ash transport water. EPA should therefore allow EGUs with units greater than 400 MW to sample and monitor bottom ash transport water rather than require conversion to a dry handling system. Therefore EPA should maintain the surface impoundments treatment option for bottom ash transport water at all EGUs. Comment Response:
See re sponse to DCN EPA

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- A2, Excerpt Number 7.

Commenter Name: Shellie Chard

- McClary Commenter Affiliation: Oklahoma Department of Environmental Quality (DEQ) Document Control Number: EPA

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- 4181

- A2 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: If the data gathered and analysis performed by EPA supports a Dry Handling requirement for Bottom Ash treatment as part of a BAT standard, th en such a standard should be adopted in the final rule. Comment Response: The final rule establishes “zero discharge” limitations and standards for bottom ash transport water discharges, as described in preamble sections III and VIII. EPA determined that these technologies are technologically available, economically achievable, and have acceptable non

water quality environmental impacts, as required by the Clean Water Act. See also response to DCN EPA

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- 4464

- A1, Excerpt Number 3.

Comm enter Name: Chuck D. Barlow Commenter Affiliation: Entergy Corporation Document Control Number: EPA

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- 2009

- 0819

- 4519

- A2 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerp t: I. The requirements for Best Available Technology ("BAT") for bottom ash transport water need to be clarified .Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 335 In the ELG Proposed Rule, EPA identifies closed

- loop systems that recycle the sluice water as BAT for bottom ash transport , as these syste ms minimize the amount of pollutants discharged from ash handling activities. All three of Entergy's coal plants currently operate with this type of bottom ash handling system. However, while these are closed

- loop systems by design, there are some operatio ns and maintenance activities that will require intermittent discharge (such as lowering of pond levels to facilitate liner maintenance). The frequency and volume of these discharges will produce a waste stream that is insignificant and should be classifie d as low volume waste similar to the water drained from bunkers in a mechanical drag system (78 Fed. Reg. 34449, col.2). The cost to re

- engineer these systems to a completely zero liquid discharge ("ZLD") system would not pass the cost

- benefit test for suc h miniscule annual discharge volumes. Additionally, numerical limits for any parameters associated with this wastewater stream, other than existing permit conditions based on a permit writer's best professional judgment , are not warranted . Additionally, as EPA collected only one sample during its two

year program for metals analysis, the current administrative record does not support the establishment of numerical limits. Comment Response: EPA’s record demonstrates that there are plants managing closed

- loop systems for bottom ash transport water that do not require discharge during operation and maintenance activities. Nor do they require discharge for management of salts or fine solids. See TDD Section 7.3.9 for a discussion of complete recycle s ystems for bottom ash. Examples of management techniques that could be used to address the maintenance example proposed by the commenter, where a bottom ash impoundment is pumped down, include multi

- celled systems or the use of temporary impoundments to st ore wastewater while maintenance activities occur. EPA, therefore, does not agree that “intermittent” discharges of bottom ash transport water should be treated any differently from other discharges of bottom ash transport water for purposes of the final l imitations and standards. Such discharges are subject to the zero discharge limitations and standards established by the ELG. EPA notes that it included costs in its cost estimates for the final rule for a full conversion to dry handling for two of Entergy ’s plants that reported discharging in 2009, and included costs for bottom ash management for the third plant that reported no discharge in 2009 but has an emergency outfall. See also the response to DCN EPA

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- A2, Excerpt Number 7.
For t he role of cost

- benefit analysis in EPA’s decisions on this final rule, see response to DCN EPA

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- 0819

- 4464

- A1, Excerpt Number 3 (in comment code 6.a). EPA notes that it did not establish numerical limits on discharges of bottom ash transport wate r because it determined that zero discharge limitations and standards

– which control pollutants to the greatest degree

– were available and achievable.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 336 Commenter Name: Nysa Hogue Commenter Affiliation: Indianapolis Power & Light Company (IPL) Document Control Number: EPA

- HQ

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- A2 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The proposed ELG includes prohibition on bottom ash transport water for unit s with capacity at or greater than 400 MW in one of the four preferred options for existing sources (Option 4a). IPL is considering going to closed loop bottom ash transport water management, with bottom ash transport water being treated and reused. Howev er , maintaining the ability to discharge some bottom ash water would provide important flexibility needed to ensure compliance such as the need to discharge bottom ash water to blowdown salts or fine solids from the planned closed

- loop bottom ash system. IPL requests that EPA not prohibit the discharge of bottom ash water, and instead use the Impoundment requirements equal to BPT of Options 3a, 3b, and 3 as impoundment requirements are the more cost

- efficient approach. Comment Response: See responses to DCN EPA

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- A2, Excerpt Number 1 and DCN EPA

HQ

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- A1, Excerpt Number 51 (in Comment Code 15.b).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 337 15.a. BA Transport Water

– General/Scope
Commenter Name: Jerry Purvis Commenter Affiliation: East Kentucky Power Cooperat ive, Inc. (EKPC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Three of the four preferred alternatives for bottom ash transport water would establish BAT effluent limitations that are equivalent to BPT limitations for use of surface impoundments. For the reasons set forth below, EKPC supports EPA's options that would provide for continued use of surface impoundments for treatment and discharge of bottom ash transport water. Comment Response: For steam electric generating units that are greater than 50 MW and that are not oil

- fired, the final rule identifies dry handling or closed

- loop systems as the BAT basis for co ntrol of pollutants in discharges of bottom ash transport water. EPA disagrees that, for all units, the BAT basis for bottom ash transport water should be surface impoundments because the record demonstrates that zero discharge based on dry and closed

- loop bottom ash technologies is technologically available and economically achievable. See preamble section VIII for more discussion of EPA’s rationale, and the response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e). For generating units 50 MW or smaller or that are oil

- fired, the final rule establishes a BAT limitation on TSS in bottom ash transport water that is equal to the previously established BPT limitation on TSS. See the response to DCN EPA

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- A1, Excerpt Number 40 (in Comment Code 5.c).

Commenter Name: John C. Pozzo Commenter Affiliation: Ameren Energy Resources Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag: No External Review External Re view Incorporated into Response: No Comment Excerpt: The proposed requirements regarding the elimination of discharges of wastewater pollutants from bottom ash transport water (for units of any size) have not been sufficiently justified byEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 338 EPA and should not be finalized; instead authorization of existing management practices should be continued. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 6.

Commenter Name: John C. Pozzo Commenter Affiliation: Ameren Energy Resources Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 40 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In contrast to AER's position on the proposed BAT standards for fly ash management, we believe that there is no basis per § 423.13(k) for the proposed BAT "no discharge of bottom ash transport wastewater " standards for existing generating units. As discussed below our position is that the EPA has: ov erestimated bottom ash impacts; arbitrarily selected unit size criteria; and not provided an adequate administrative record. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 6. EPA disagrees that bottom ash impacts ha ve been overestimated. See the TDD and the response to DCN EPA

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- A1, Excerpt Number 40 (in Comment Code 5.c). EPA disagrees that it has “not provided an adequate administrative record.” EPA’s record demonstrates these dry and closed

- loop bottom ash technologies are technologically available and economically achievable, and have acceptable non

- water quality environmental impacts (seeEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 339 preamble sections VIII, IX, and XII). The record also shows s ignificant pollutant reductions associated with the final rule (see TDD section 10).

Commenter Name: Daniel K. Plath Commenter Affiliation: Northern Indiana Public Service Company (NIPSCO) Document Control Number: EPA

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- A2 Comment E xcerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: NIPSCO further recommends that, due to the inert nature of boiler slag, USEPA expressly allow the continued use of water

- based processes for the management of boiler slag. Finally, because USEPA’s information on the economics of zero liquid discharge specific to cyclone boilers has not been (nor can it be) substantiated, NIPSCO does not believe that it could reasonably be determin ed that Option 4a’s zero liquid discharge proposal concerning bottom ash water is economically achievable for power plants with cyclone boilers. We thus ask that cyclone boilers be expressly exempted from the requirement. Comment Response:
EPA collected information on all bottom ash handling systems evaluated as part of the rule. EPA notes that there is at least one cyclone boiler generating unit that currently operates a mechanical drag system (Kansas City Power & Light’s La Cygne Generating Station). Ad ditionally, the remote mechanical drag system can use the existing wet bottom ash transport system at a plant, which would then tie

- in to the new dewatering equipment for the remote mechanical drag system. There is nothing unique to cyclone boilers with re spect to separating the ash from the transport water. Thus, EPA disagrees that the dry handling or closed

- loop system BAT basis in the final rule is not economically achievable for plants with cyclone boilers. See the response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Docume nt Control Number: EPA

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- 340 Comment Excerpt: For decades EPA has recognized that the small amount of toxics in bottom as h transport water does not justify limits that would require zero discharge. In 1980, EPA proposed to reject more stringent regulation of bottom ash because it found that, at most plants, the priority inorganic pollutants detected in bottom ash water were less than the concentrations detected in the raw or intake water source. 45 Fed. Reg. 68,328, 68,338 col. 2 (Oct. 14, 1980). The Agency further found that partial to complete recirculation of bottom ash sluice water was technically feasible but that hig h costs and the inability to quantify pollutant reductions weighed against selecting the option. Id. col. 3. EPA confirmed its finding with the 1982 final rule, determining that “[a]nalysis of available wastewater sampling data did not indicate that a qua ntifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control.” “Development Document for Final Effluent Limitations Guidelines, New Source Performance Standards, and Pretreatment Standards for the Ste am Electric Point Source Category” (1982 Development Document) EPA

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Comment Response: See the response to DCN EPA

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- A2, Excerpt Number 7 (in Comment Code 15).

Commenter Name: Jim Weeks Commenter Affiliation: Mi chigan Municipal Electric Association (MMEA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 2 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Support EPA’s proposal to not set new BAT/PSES standards under Options 3a, 3b, 3 and 4a (for units less than 400MW) for bottom ash transport water requirements; Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 6.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 341 Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 46 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For decades EPA has recognized that the small amount of toxics in bottom ash transport water does not justify limits that would require zero discharge. In 1980, EPA proposed to reject more stringent regulation of bottom ash because it found that, at mos t plants, the priority inorganic pollutants detected in bottom ash water were less than the concentrations detected in the raw or intake water source. 12 EPA further found that partial to complete recirculation of bottom ash sluice water was technically f easible but that high costs and the inability to quantify pollutant reductions weighed against selecting the option. 13 EPA confirmed its finding with the 1982 final rule, determining that “[a]nalysis of available wastewater sampling data did not indicate t hat a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control. ”14 The same reasoning applies just as much today as it did in 1982.

12 45 Fed. Reg. 68,328, 68,338 col. 2 (Oct. 14, 1980).

13 Id. col. 3.

14 EPA, Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category (1982 Development Document), EPA

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- A2, Excerpt Number 7 (in Comment Code 15).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 342 15.b. BA Transport Water

– Profile
Commenter Name: John C. Pozzo Commenter Affiliation: Ameren Energy Resources Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We have one facility with only a single generating unit. This unit will certainly be difficult to retrofit due to the num erous obstacles (including structural) as stated during the EPA's site visit to this facility. Recently a bottom ash and low volume wastewater treatment facility was constructed that contains two cells for managing bottom ash and a polishing cell for decan t bottom ash wastewater and low volume wastewater treatment. This bottom ash and low volume wastewater treatment system features an impoundment constructed of 12" thick concrete overlaying a HDPE layer and compacted clay. The proposed ELGs would effectivel y render this robust treatment facility as useless solely due to the 400 MW unit generating threshold criteria. We believe that the proposed ELGs rulemaking is inherently unfair as it relates to bottom ash transport water at this particular facility.
Comme nt Response: EPA’s record demonstrates that the dry handling or closed

- loop systems identified as the BAT basis for control of pollutants in discharges of bottom ash transport water are technologically available and economically achievable for steam elec tric power plants. See section VIII of the preamble. Specifically for the plant referred to by the commenter, EPA estimated compliance costs based on the installation of a remote mechanical drag system. A remote system mitigates the effect of “obstacles” associated with a retrofit because the existing bottom ash transport system would be used to convey bottom ash to the remotely located conveyor. However, plants may choose any technology to comply with the final rule that meets the final limitations. See r esponse to DCN EPA

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- MW threshold for bottom ash transport water. EPA notes that the plant may continue using the i mpoundments mentioned by the commenter, provided that it does not result in a discharge of bottom ash transport water or that any reuse of bottom ash transport water meets the limitations in the final rule (see preamble section VIII). Alternatively, anothe r approach available to the plant is to send the bottom ash transport water to a remote mechanical drag system (without any transport water going to the treatment facility) and limit use of the treatment facility to handling low volume wastes. Regardless, EPA does not agree the ELG is “inherently unfair” as it relates to bottom ash transport water at that plant.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 343 Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Effluent Limitations Based On The Performance Of Gravity Settling At Surface Impoundments Are Environmentally Protective And Consistent With Clean Water Act Statutory Factors For BAT. Midwest Gen uses wet sluicing of bottom ash to temporary surface impoundments at all of its coal

- fired facilities with the exception Joliet 9. Midwest Gen’s ash impoundments are not like those of many other facilities, where bottom ash and fly ash, as well as other wastes, are combined and held on

- site for an extended duration. As noted above, Midwest Gen’s ash ponds are used exclusively for bottom ash. These lined ponds are cleaned out on a r egular basis, as noted in section I.B above, with solids removed and beneficially reused. Additionally, the majority of Midwest Gen’s facilities recycle or reuse at least a portion of the bottom ash transport water (after settling) either back to the cool ing pond, or to resupply the bottom ash transport system. Comment Response: EPA disagrees that “Effluent Limitations Based On The Performance Of Gravity Settling At Surface Impoundments Are Environmentally Protective And Consistent With Clean Water Act S tatutory Factors For BAT.” See preamble section VIII for more information on why surface impoundments are not BAT for control of discharges of bottom ash transport water from all existing steam electric generating units.
The data used to characterize botto m ash transport water for pollutant loadings is based on sampling data from impoundment that receives at least 75% by volume bottom ash transport water and does not receive fly ash transport water. Therefore, bottom ash wastewater characterization data are based on impoundments that only contain bottom ash transport water or contain a majority of bottom ash transport water by volume. The commenter does not provide any data showing that bottom ash transport water discharged from surface impoundments temporar ily storing bottom ash would have a different characterization than bottom ash transport water discharged from surface impoundments storing bottom ash for longer periods of time. The technology options considered as the basis for BAT would still permit the beneficial reuse of bottom ash. EPA notes that if plants installed the dry handling or closed

- loop BAT bases, the bottom ash could be loaded into trucks for beneficial reuse directly from the stack generated from the mechanical drag system or remote mecha nical drag system, eliminating the need to dredge the bottom ash from the impoundments.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 344 EPA notes that the plant will be able to continue using the impoundments mentioned by the commenter provided that that does not result in a discharge of bottom ash transport water or that any reuse of bottom ash wastewater meets the limitations in the final rule (see preamble section VIII).

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comm ent Excerpt Number: 49 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We Energies has a long history of researching and developing beneficial uses for our coal combustion products (“CCPs”) in an environmentally responsible and scientifically sound manner. We have collaborated with universities, consultants, and industry in developing beneficial uses of our CCPs, and we have worked closely with federal and state regulatory agencies to ensure that those uses are protective of human health and the environment and are carried out using established scientific principles and good engineering practices. In 2012, our beneficial use program had documented utilization rates of 99% of coal ash generated tha t year. Wisconsin has taken an approach to encourage to the maximum extent possible, consistent with the protection of public health and the environment and good engineering practices, the beneficial use of industrial byproducts in a nuisance

- free manner. The Wisconsin Department of Natural Resources encourages the beneficial use of industrial byproducts in order to preserve resources, conserve energy, and reduce or eliminate the need to dispose of industrial byproducts in landfills. Industrial byproducts must meet certain quality standards, as specified in Wisconsin NR 538 Beneficial Use of Industrial Byproducts, in order to be beneficially reused. We Energies samples and analyzes its CCPs on an annual basis, including performing a water leach test using ASTM D3987

- 85, the American Society for Testing and Materials “Test Method for Shake Extraction of Solid Wastes with Water.” Results from the last five years of sampling can be viewed in Appendix II. Generally, the testing demonstrates that chemical cons tituents found in bottom ash do not leach into water. Some constituents do leach, but at small quantities not posing threats to human health or the environment. Comment Response: EPA acknowledges the commenters efforts to promote beneficial reuse of bot tom ash. EPA notes that the technology options considered as the basis for BAT would still permit the beneficial reuse of bottom ash. EPA notes that if plants installed the dry handling or closed

- loop BAT technologies, the bottom ash could be loaded into trucks for beneficial reuse directly from the stack generated from the mechanical drag system or remote mechanical drag system, eliminating the need to dredge the bottom ash from the impoundments.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 345 Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 51 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Settling Ponds are an Effective Technology to Treat Bot tom Ash Transport Water We Energies operates several small settling ponds (which may be characterized as surface impoundments under EPA’s broad definition) to remove suspended solids from bottom ash transport water (and other low volume wastestreams) prior to discharge. Wet bottom ash is not directly transported to these ponds/impoundments; rather, it is sent to dewatering bins and a majority of the bottom ash transport water is recirculated back to the plant for reuse in the bottom ash transport system. A blowdown stream, however, is required to control the buildup of dissolved solids. At some plants, blowdown from the dewatering bins is sent to small wastewater treatment ponds for equalization and/or settling as part of a chemical precipitation treatment process. As EPA correctly indicated, effluents from impoundments treating bottom ash transport water generally contain low concentrations of Total Suspended Solids meaning any metals in the particulate form settle out with the solids and are not discharge d. As long as the residence time in the pond is acceptable to allow for adequate settling, the discharge meets the current Best Practicable Control Technology Currently Available (“BPT”) limits for Total Suspended Solids (“TSS”) and Oil and Grease (“O&G”)

. Effluent from We Energies OCPP settling ponds have been sampled during permit reissuance activities, and results have been reported to the permitting authority (WDNR). The permit reissuance sampling includes analyzing for metals and other potential poll utants of concern. The WDNR then evaluates the results against state water quality codes consistent with EPA’s Great Lakes Initiative regulation (40 CFR 132) to determine whether to assign water quality based effluent limits. 22 Oak Creek’s current Wisconsin Pollutant Discharge Elimination System (“WPDES”) permit requires mercury monitoring, and a phosphorus limit is in effect. The treatment system effluent was also required to undergo Whole Effluent Toxicity testing twice during the term of the per mit (both tests “passed”). Otherwise, the BPT Limits are specified for TSS, O&G, and pH. Based on a Water Quality

- Based Effluent Limitation memorandum prepared by the WDNR, an arsenic limit may be applied to the outfall in the reissued permit. 23 No addit ional water quality based effluent limits are required for the discharge. Based on data collected during our permit reissuance samplings and WDNR’s evaluation of the data, OCPP’s settling ponds adequately treat the bottom ash transport water to meet categ orical limits and most water quality based effluent limits.

22 NR 105 and 106, Wisconsin Administrative CodeEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 346 23 On August 1, 2013, We Energies submitted an application requesting a variance from the water quality standard for arsenic in connection with wat er quality based effluent limitations anticipated to be included in the reissued permit because naturally occurring arsenic concentrations prevent the attainment of the standard and because the standard, as applied to OCER, will cause substantial and wides pread adverse social and economic impacts in the area where this facility is located. Comment Response: See preamble section VIII for more information on why surface impoundments are not BAT for the control of pollutants in discharges of bottom ash trans port water from all existing steam electric generating units. The zero discharge effluent limitation does not distinguish between bottom ash transport water sent directly to a surface impoundment versus bottom ash transport water sent to a surface impoundm ent following bottom ash solids removal (e.g., by dewatering bins). The bottom ash transport water still combines with bottom ash directly underneath the boiler and is transported, using water as the transport medium, to the dewatering bin. Any overflow fr om the dewatering bin is considered bottom ash transport water. EPA disagrees that a blowdown stream is required to control dissolved solids in closed

- loop bottom ash handling systems. EPA included a one

- time bottom ash management cost for plants that rec ycle a majority of their bottom ash transport water but still have the option to discharge through an emergency outfall. Section 8.5 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam E lectric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832)

. Plants incurring bottom ash management costs did not report discharge bottom ash transport water in 2009, but they do operate an emergency outfall. EPA’s cost est imate for these plants for the final rule includes contractor labor and costs for two week

- long trips to the plant for a contractor to come on site and develop a plan for the plant to permanently eliminate the bottom ash transport water discharge. Addition ally, EPA estimated capital and O&M costs associated with chemical feed systems for all generating units at plants with bottom ash wet sluicing systems. EPA notes that most plants that already recycle a majority of their bottom ash transport water will not incur any capital costs to close their emergency outfall because they already have all of the equipment in place as part of their installed system. EPA estimated chemical feed systems for the minority of plants where the contractor determines that contro l of pH and fines is necessary. Plants that reported discharging any bottom ash transport water in 2009 were costed for a full bottom ash dry handling conversion. EPA notes that the plant will be able to continue using the impoundments mentioned by the co mmenter provided that that does not result in a discharge of bottom ash transport water or that any reuse of bottom ash wastewater meets the limitations in the final rule (see preamble section VIII). EPA disagrees that “low concentrations of Total Suspende d Solids” necessarily means that “any metals in the particulate form settle out with the solids and are not discharged.” As mentioned in Section 7 of the TDD, “in addition to TSS, surface impoundments can also reduce specific pollutants in the particulate form to varying degrees in the wastewater discharge.”Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 347 EPA establishes ELGs based on the performance of well

- designed and well

- operated control and treatment technologies. As explained in the preamble, BAT is intended to reflect the highest performance in t he industry. NSPS reflect “the greatest degree of effluent reduction” that is achievable based on the “best available demonstrated control technology.” CWA section 306(a)(1). As required by the CWA, the promulgated limitations are based on the performance of available control technology, which will differ from concentrations established in water quality based effluent limitations established to protect impacts on a specific receiving stream. See the response to DCN EPA

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Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment E xcerpt Number: 82 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Permit reissuance sampling data from We Energies power plants demonstrate that wastewater treatment settling ponds adequately trea t bottom ash transport water to meet most water quality based effluent limits. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 51.

Commenter Name: Daniel K. Plath Commenter Affiliation: Northern Indiana Public Service Company (NIPSCO) Document Control Number: EPA

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- A2 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Unlike flame combustion boilers, which burn pulverized coal resulting in bottom ash that is 20% to 30% of the total ash, cyclone combustion boilers burn coarse coal dust and crushed coal resulting in ash in the form of slag that is 70% to 80% of the total ash. In addition, cyclone combustion boiler s are operated at a higher temperature than flame combustion boilers; consequently the produced slag is in a molten (liquid) state that flows through a hole, is waterEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 348 quenched in the slag bath, and forms solid boiler slag. The resulting boiler slag is bo th physically and chemically different from bottom ash from flame combustion boilers. Boiler slag is a coarse, hard, angular, glossy material; it is not adsorptive and has low porosity as compared to bottom ash. Bottom ash tends to be silty

- clay to fine sand size, whereas cyclone boiler slag tends to be coarse to medium sand size. In addition, boiler slag is denser than bottom ash. Given the physical characteristics of low porosity and adsorption and higher density, management of materials from the slag bath to the storage ponds (i.e. transport to disposal to impoundments) is appropriately conducted utilizing water. Moreover, boiler slag is a highly sought after commodity that has multiple beneficial reuse applications including blasting grit, roofing gr anules, asphalt mineral filler, fill material for structural applications, concrete raw material, as well as snow and ice traction control material. In fact, NIPSCO currently beneficially reuses 100 percent of all of the boiler slag that it produc es. Comment Response: EPA notes that the BAT options considered still permit the beneficial reuse of bottom ash, including boiler slag. Additionally, the boiler slag could still be wet sluiced if the plant chooses to install a remote mechanical drag system. The commenter has provided no data or other information to suggest that a remote mechanical drag system could not be used for boiler slag. See response to DCN EPA

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- A2, Excerpt Number 4 (in Comment Code 15.a).

Commenter Name : John W. Myers Commenter Affiliation: Tennessee Valley Authority (TVA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 22 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Exce rpt: Bottom ash transport water is typically an intermittent stream and the bottom ash transport water flow rates are not as large as the fly ash transport water flow rates. EPA identified 870 generating units (345 plants) that wet sluice at least a por tion of their bottom ash. About 80% of coal

- and petroleum coke

- fired units generating bottom ash operate wet bottom ash transport systems, while approximately 20% operate systems that eliminate the use of transport water; as such, the number of plants pot entially impacted by elimination of bottom ash transport is significant. Comment Response: See the TDD for information about the number of plants and units that operate wet ash handling systems and dry ash handling systems, based on data collected by the Steam Electric Survey, asEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 349 well as information about how the industry has implemented additional dry ash handling systems since the time of the survey. Regarding the number of plants that would incur costs to comply with the zero discharge requirement, see the response to DCN EPA

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- A1, Excerpt Number 9, in comment code 16.a. EPA’s record demonstrates the BAT requirements for bottom ash transport water are technologically available and economically achievable for these plants, see preamble section VIII for additional discussion.

Commenter Name: Brian Brazil Commenter Affiliation: TransAlta Centralia Generation, LLC (TCG) Document Control Number: EPA

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- A2 Comment Excerpt Number: 6 External Review Flag: No External R eview External Review Incorporated into Response: No Comment Excerpt: Comments on Bottom Ash Quench and Transport Water The TransAlta plant uses bottom ash quench systems with dewatering bins and surge bins (clarifiers) to produce dry bottom ash and to recycle much of the wastewater from the bottom ash handling process back into the quench systems. However, some wastewater intermittently will overflow the surge bins during routine operation of these systems sending clarified wastewater to the plant waste water treatment systems. These overflows contain very low levels of suspended ash solids and therefore are not considered wet handling of the ash. These intermittent overflows can be difficult to avoid during process upsets and must be considered as part o f normal operation. Additionally, transporting bottom ash slurry several hundred feet from the bottom ash quench systems to the dewatering bins causes unavoidable wear on the piping which can result in leaks and pipe breaks that may discharge bottom ash an d ash wastewater to the plant sewers in upset conditions. These types of events are unavoidable and any ELGs that EPA develops must account for the release of some wastewater and/or bottom ash to the plant wastewater treatment system during these kinds of conditions. Comment Response: EPA disagrees that wastewater that intermittently overflows the surge bins during routine operation, containing low levels of suspended ash solids, is “not considered wet handling of the ash.” Any water that is used to trans port bottom ash from the boiler to dewatering and/or surge bins is considered bottom ash transport water, unless specifically defined otherwise. Because the TransAlta plant discharges bottom ash transport water, EPA estimated compliance costs associated wi th a bottom ash handling conversion. In addition, EPA included costs associated with 5

- year routine maintenance. EPA determined that all maintenance can be completed while the system contains bottom ash transport water (e.g., drag chain replacement) or whi le the bottom ash transport water is stored in tanks during the 5

- year routine maintenance.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 350 EPA notes that, under the definition of transport water in the final rule, transport water does not include low volume, short duration discharges of wastewater from minor leaks (e.g., leaks from valve packaging, pipe flanges, or piping) or minor maintenance events (e.g., replacement of valves or pipe sections)

. See 40 CFR 423.11(p), as well as the preamble and TDD for more information.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Ash is the non

- combust ible part of coal, the residue left after coal is burned to generate energy. Bottom ash is the fraction that is too heavy to be entrained in the flue gases and thus drops out of the bottom of the boiler. It is generally grey or black and is similar to san d or gravel in texture. See Figure 1.

In most boilers, hot bottom ash falls into a hopper filled with water and is then fed into a conveyor where it is diluted into a slurry, or is "sluiced" and pumped to an impoundment or dewatering bins, where the "transport water" is separated. Thus, bottom ash transport water isEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 351 the water used to transport ash that falls out of the bottom of the boiler and is sent to an ash pond or dewatering basin. This water is then typically discharged into waterways.

5 S.R. Shah, S. Rastogi, and O. Mathis, “Applications of Dry Bottom Ash Removal and Transport for Utilization, Fly Ash India 2005;” Available at: http://c

farm.org/006_TRANSPORT.pdf. Comment Response: See the text of the regulation at 40 CFR 423.11(p) for the definition of transport water.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporate d into Response: No Comment Excerpt: The EPA identified 870 units at 345 plants that wet sluice at least a portion of their bottom ash, amounting to over 65% of all the subject units. 7 78 Fed. Reg. at 34,453. These plants generate 286,000 MW or 87% of t he electricity generated by the subject units. TDD, Table 4

- 9. The balance of the units employs various methods to eliminate transport water, discussed elsewhere.

7 The TDD similarly reports that about 65% of the coal and coke plants subject to this rulema king, or 335 out of 516, operate wet bottom ash handling systems. TDD, Table 4

- 9. Comment Response: Regarding the number of plants that would incur costs to comply with the zero discharge requirement, see the response to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 352 Comment Excerpt: Bottom ash is the residue that is too heavy to be entrained in the flue gases and, thus, falls to the bottom of the furnace. About 10% to 30% of the total ash is bottom ash for most boilers. Wet

bottom bo ilers and cyclone

- fired boilers can generate 50% to 80% bottom ash, though these boilers are a minority of the fleet. TDD, p. 4

- 23. Approximately 76% of the coal and coke fired units (1,083 units at 510 plants) subject to this rulemaking operate only wet s luicing systems to handle their bottom ash. TDD, Fig. 7

- 10. In a wet sluicing system, the heavy bottom ash particles fall down the sloped sides of the boiler bottom into collection hoppers beneath the furnace that are filled with water. The hoppers are con nected directly to the boiler to prevent the escape of boiler gases. The ash is present at temperatures up to 2400 F, so it is first cooled to temperatures suitable for the ash handling equipment by quenching in the hoppers. When the hopper(s) are full, a gate opens, sending the wet ash to a grinder. The ground ash is then diluted to about 20% solids by weight and "sluiced" (i.e., a stream of water conveys the ash in a closed pipeline, with a jet pump providing the motive force) to a settling pond(s) or d ewatering bins, where the ash is separated from the water. 8 TDD, Sec. 6.2.3 and 7.3.1. Bottom ash is easily dewatered due to its large particle size.

8 See “Bottom and Fly Ash System Maintenance” for a description of the components in a wet sluicing syst em; Available at: http://fatdad94.com/index_htm_files/BOTTOM%20AND%20FLY%20ASH%20SYSTEM%20 MAINTEN ANCE.ppsx

. Comment Response: For the final rule, EPA updated its final rule analyses to reflect industry profile changes (e.g., generating units retirements, bottom ash handling conversions). See Section 7 of the TDD.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 353 15.c. BA Transport Water

– Wastewater Characterization
Commenter Name: John C. Pozzo Commenter Affiliation: Ameren Energy Resources Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 41 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
AER reviewed bottom a sh analyses for our energy centers and compared these to those provided in the Technical Development Document {TDD) per EPA

- 821

- R13

- 002. AER's coal

- fired generating facilities consist of both pulverized and cyclone boilers. It should be noted that there is a distinct difference between these two boiler technologies with respect to bottom ash. Regardless of the boiler technology that generates the ash, the effluent water quality of bottom ash transport water at our energy centers do not result in adverse imp acts in their receiving streams. A review of bottom ash analytical data from AER impoundments reveals that the only pollutant of concern is boron. Internal test results using a rigorous extraction (ASTM Method 03987) have confirmed that bottom ash is rel atively inert. As additional evidence, our ash pond effluents containing both fly ash and bottom ash have never exhibited any constituents above the applicable state water quality standards. Clearly the bottom ash characteristic data contained in the TDD d o not compare with AER facilities. Comment Response: EPA establishes ELGs based on the performance of well

- designed and well

- operated control and treatment technologies. As explained in preamble section IV.B.3, BAT is intended to reflect the highest perf

ormance in the industry. NSPS reflect “the greatest degree of effluent reduction” that is achievable based on the “best available demonstrated control technology.” CWA section 306(a)(1). As required by the CWA, the promulgated limitations are based on the performance of available control technology, which will differ from concentrations established in drinking water standards to protect human health and concentrations established in WQBELs to protect impacts of a particular discharge on a specific receiving stream. See the response to DCN EPA

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- 354 Regarding bottom ash from pulverized and cyclone boilers see response to DCN EPA

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- A2, Excerpt Number 4 (in Comment Code 15.a).

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 76 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Duke Energy collected samples from bottom ash sluice water from Marshall Steam Station, a 4

- unit 2,200 MW coal

- fired station, and Belews Creek, a 2

- unit 2,400 MW coal

- fired station. The samples of the bottom ash transport water were collected prior to mixing or comingling with any other wastestream or other waters. The sample was allowed to settle to simulate treatment from a surface water impoundme nt and samples of the supernatant were collected and analyzed. The bottom ash transport system at both Marshall and Belews Creek utilize lake water to sluice the ash to the surface impoundment; samples from the source water were also collected to account for the contribution from the source water to the total pollutant loading from bottom ash transport water. All samples were collected in accordance with Method 1669 “Sampling Ambient Water for Trace Metals at EPA Water Quality Criteria Levels”

. Very few pollutants of concern were detected within the bottom ash sluice water and several of the detected constituents could be attributed to the source water. The results and laboratory reports for the sampling efforts are provided in Appendix C. A comparison of the constituents that accounted for 88% of the TWPE removed under Regulatory Option 4(a) is presented in Table 2

- 8 below. The concentrations in the table below do not account for contribution from the source water, which would illustrate a greater differe nce in EPA’s reported average bottom ash concentration.
Table 2
- 8. Comparison of Recent Bottom Ash Transport Water Samples with EPA’s Reported Average Concentration

Analyte Units Belews Creek Bottom Ash Sluice Water* Marshall

Steam Station Bottom Ash S luice Water* EPA Reported

Average Bottom Ash Concentration

Arsenic mg/L 0.003 0.004 0.018Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 355 Cadmium mg/L <0.001 <0.001 0.008

Magnesium mg/L 3.5 2.3 97.3

Mercury mg/L 3.8E

- 07 8.0E

- 07 0.001

Sulfide mg/L <0.05 <0.05 0.51

Silver mg/L <0.001 <0.001 0.004

Thallium mg/L <0.001 <0.001 0.12

Tin mg/L <0.01 <0.01 0.34

* Source water contributions were not subtracted out. As shown in the table above, all of the average concentrations in bottom ash transport water reported by EPA are significantly greater than the concentrations detected at Belews Creek and Marshall Steam Station. A comparison of the average concentration for each analyte from bottom ash sluice water at Belews and Marshall and EPA’s average bottom ash sluice water concentration is provided below in Table 2

- 9. This clearly illustrates that EPA has over estimated the concentrations of these pollutants by approximately 75% to 100%. Due to this overestimation, EPA has grossly overestimated the TWPE removed for Regulatory Option 4(a), 4 and 5 and the environmental benefits associated with these three options.
Table 2.9. Comparison of Average Concentrations

Analyte Units Belews Creek

and Marshall Stations Average Bottom Ash EPA

Reported Average Bottom Ash Concentration Percent

DifferenceEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 356 Sluice Water Concentration

Arsenic mg/L 0.004 0.018 76%

Cadmium mg/L 0.001 0.008 88%

Magnesium mg/L 2.868 97.3 98%

Mercury mg/L 5.9 x 10

- 7 0.001 100%

Sulfide mg/L 0.05 0.51 90%

Silver mg/L 0.001 0.004 75%

Thallium mg/L 0.001 0.12 99%

Tin mg/L 0.010 0.34 97%

Comment Response: EPA disagrees with the commenter that the EPA’s ash transport water characterization dataset and methodology for calculating the pollutant loadings grossly overestimates the industry loadings associated with bottom ash transport water. See the response to DCN EPA

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- 4655, Excerpt Number 47 (in Comment Code 15.d) for more information about EPA’s ash characterization dataset and steps for calculating pollutant loadings in bottom ash transport water for the final rule, includi ng discussion of use of 1982 TDD data, use of combined ash impoundment data, source water pollutant contributions, handling of non

- detects, and sulfides.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 357 See the response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 51 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Regardless of these missteps by the agency, current, available data sufficiently demonstrates that limited pollutants are present in bottom ash transport waters

— a fact EPA recognized in 1980 and reco nfirmed in 1982. See 45 Fed. Reg. 68,328, 68,338 (Oct. 14, 1980) (noting that certain pollutants were present in bottom ash at lower concentrations than those detected in intake water supplies); EPA, Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category, EPA

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- 2186 at 498 (providing that “[a]nalysis of available wastewater sampling data did not indicate that a quantifiable reduction of pollutants would be achieved by requiring technologies beyond the BPT level of control”). Comment Response: EPA evaluated POCs for bottom ash transport water, considering data collected from multiple sources. See the response to DCN EPA

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- A1, Excerpt Number 50 (in Comment Code 6.a) and Bottom Ash and Fly Ash Pollutants of Concern Analysis Memo randum (DCN SE04745) for more details on EPA’s determination of POCs for ash transport water. These data support EPA’s analysis that there is a quantifiable reduction of pollutants associated with requiring zero discharge of wastewater pollutants. In addi tion, EPA has determined that the dry handling/closed loop BAT basis for bottom ash transport water included in the final rule is technologically available, economically achievable, and has acceptable non

- water quality environmental impacts. See preamble s ection VIII.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 358 Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External Review Flag: No External Review External Review Incorporated i nto Response: No Comment Excerpt: First, gravity settling in surface impoundments is appropriate BAT because bottom ash is relatively benign. The main constituent in bottom ash

— comprising almost 50 percent of its composition

— is silicon. 9 EPA did not i dentify silicon as a pollutant of concern for ash transport water. 10 The residual solids that remain after bottom ash transport water has settled in surface impoundments are often reused for other purposes, given their inert nature. This is consistent w ith the findings of a 2010 EPRI survey that showed that the typical (10th to 90th percentile) concentrations of arsenic in bottom ash are similar to that of United States average soil (see Figure 1 below). 11 Figure 1. Comparison of Arsenic Content of Vario us Coal Combustion Residuals (Including Bottom Ash) versus United States Soils and Other Common Materials

EPA’s record does not support a contrary conclusion. EPA determined wastewater characteristics and identified pollutants of concern for fly ash t ransport water, but did not do so for bottom ash transport water. For example, EPA collected one wastewater sample representing the influent to a fly ash impoundment and presented the analytical results to illustrate fly ash wastewaterEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 359 characteristics. 12 Similarly, while EPA has identified pollutants of concern for fly ash transport water, 13 EPA did not have data sufficient to separately determine pollutants of concern for bottom ash transport water. EPA speculated that the pollutants of concern for b ottom ash water should be the same as in fly ash transport water because both bottom ash and fly ash contain the constituents of coal. 14 But EPA did not provide any data supporting this conclusion. 15 Contrary to such a conclusion, there are significant physical and chemical differences in fly ash and bottom ash and the differences are relevant to determining BAT.

9 See EPRI: Coal Ash: Characteristics, Management and Environmental Issues, 4

- 5 (Sept. 2009) (noting that the range of silicon in bottom as h composition is 160,000

- 280,000 mg/kg and showing that this constitutes approximately 50 percent of its composition). 10 See EPA, Technical Development Document for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power G enerating Point Source Category, 6

- 29 (April 2013) (hereinafter “TDD”). 11 See EPRI, Comparison of Coal Combustion Products to Other Common Materials 9

- 5 (November 2010). 12 See TDD at 6

- 10 and 11. 13 See id. at 6

- 29. 14 See 78 Fed. Reg. at 34455; TDD 6

- 29. 15 See TDD at 6

- 9, 6

- 10, 6

- 29. Furthermore, one of EPA’s general assumptions regarding ash water characteristics

— that bottom ash transport water and fly ash transport water are generally comingled, see TDD at 6

- 9

— is not true for Midwest Gen’s facili ties, see supra section I.B. Comment Response: EPA disagrees that bottom ash transport water is “relatively benign.” EPA evaluated POCs for bottom ash transport water, considering data collected from multiple sources. EPA identified silica as a POC for b oth fly ash transport water and bottom ash transport water. See the response to DCN EPA

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- A1, Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII on why surface impoundments are not BAT for bottom ash transport water discharges from all existing steam electric generating units.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 360 See t he response to DCN EPA

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Commenter Name: J oAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: It is well established that bottom ash and as a result, bottom ash transport water is benign and contributes insignificant quantities of toxics to impoundment discharges. Comment Response: See the response to DCN EPA

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- A1, Excerpt N umber 13.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 48 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Regardless of the methodology EPA used to classify POC for bottom ash transport water, EPA did have an opportunity to compare effluent from a bottom ash pond to a fly ash pond. EPA published its characterization data in its 2009 Final D etailed Study (EPA

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- 5 and 5

- 9). A subset of the data collected from EME Homer City Generation L.P.’s Homer City Power Plant (“Homer City”) and Buckeye Power Company’s Cardinal Power Plant (“Cardinal”) can be found in Table 5 b elow. Bottom ash pond effluent was collected at Homer City and fly ash pond influent and effluent were collected at Cardinal. 19 The data EPA collected clearly shows that the characteristics of bottom ash transport water are different thanEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 361 fly ash trans port water. This further illustrates that substitution of fly ash transport water for bottom ash transport water to determine pollutants of concern is an unjustified approach.
Table 5: Ash Pond Characteristics 20

Analyte Method Unit Homer City

– Effluent from Bottom Ash Pond Cardinal

–

Influent to Fly Ash Pond Cardinal

–

Effluent from Fly Ash Pond Antimony, Total 1638 ug/L 1.09 33.1 21.9 Antimony, Dissolved 1638 ug/L 0.990 17.4 22.4 Arsenic, Total 1638 ug/L 6.52 519 69.8 Arsenic, Dissolved 1638 ug/L 5.00 80.7 68.9 Beryllium, Total 200.7 ug/L ND (5.00) 71.5 ND (5.00) Beryllium, Dissolved 200.7 ug/L ND (5.00) ND (5.00) ND (5.00) Chromium, Total 1638 ug/L ND (4.00) 569 4.64 L Chromium, Dissolved 1638 ug/L ND (4.00) ND (80.0) 4.49 L Lead, Total 1638 ug/L ND (0.250) 260 0.420 Lead, Dissolved 1638 ug/L ND (0.250) ND (0.500) ND (0.250) Mercury, Total 1631E ug/L 0.005511 1.16 0.00125 Mercury, Dissolved 1631E ug/L 0.00141 0.000550 ND (0.000500) Molybdenum, Total 200.7 ug/L 19.7 333 361 Molybdenum, Dissolved 200.7 ug/L 20.2 243 352 Selenium, Total 1638 ug/L 5.74 ND (200) 45.8 Selenium, Dissolved 1638 ug/L 5.16 21.2 45.0 Titanium, Total 200.7 ug/L ND (10.0) 24,900 12.6 Titanium, Dissolved 200.7 ug/L ND (10.0) ND (10.0) ND (10.0) Vanadium, Total 200.7 ug/L ND (20.0) 2,340 104 Vanadium, Dissolved 200.7 ug/L ND (20.0) 70.7 99.9 Yttrium, Total 200.7 ug/L ND (5.00) 521 ND (5.00) Yttrium, Dissolved 200.7 ug/L ND (5.00) ND (5.00) ND (5.00)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 362 L

– Sample result between 5x and 10x blank result.
ND

– Not detected (number in parenthesis is the report limit). Bottom ash exhibits different characteristics than fly ash. The exact composition of bottom ash varies somewhat according to the type of coal being burned and the combustion conditions

. Bottom ash is relatively inert and generally contains only small amounts of toxic pollutants. In water it does not readily leach elevated concentrations of toxic pollutants. The leaching potential of fly ash is higher than bottom ash due to the exponen tially higher total surface area available in samples of the same mass. 21

19 It should be noted that the coal type burned at these plants differ. Homer City burns Eastern Bituminous coal and Cardinal burns subbituminous coal. The coal type has an effect on the trace metal concentrations in the coal combustion products.

20 US EPA, Steam Electric Power Generating Point Source Category: Final Detailed Study Report , EPA

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– 5

- 20, October 2009.

2 1 Ramme, B. and M. Tharaniyil. We Energies Coal Combustion Products Utilization Handbook . 2nd ed. Milwaukee: Wisconsin Energy Corporation, 2004. Comment Response: See the response to DCN EPA

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Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 81 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Bottom ash is relatively inert and generally contains only small amounts of toxic pollutants. Comment Response: See the response to DCN EPA

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- 363 Commenter Name: Jay Hudson Commenter Affiliation: Santee Cooper Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Bottom Ash The proposed rule includes a zero discharge limitation for bottom ash in three of the eight options. This would require installation of dry handling systems or systems that do not discharge bottom ash transport water3. EPA estimates that this would affect 80% of the coal

- and petroleum coke

- fired units. Either of these o ptions would require difficult retrofits imposing significant cost for existing facilities and would have a major impact on the electric generating industry. Unlike FGD wastewater, the chemical composition of bottom ash transport water has not changed sign ificantly since the 1982 rulemaking. Further, since impoundments used for treatment of bottom ash wastewater typically receive other wastewaters (e.g. boiler blowdown and low volume wastewater including non

- chemical cleaning waste and FGD wastewater), when some or all of these other waste streams are pretreated prior to being combined in a surface impoundment or removed from the waste stream pursuant to other rule changes, the discharge from bottom ash impoundments will contain less dissolved solids and in particular, less metals, as more and more of these other waste streams are further treated and/or no longer mixed in bottom ash impoundments. Comment Response: EPA evaluated POCs for bottom ash transport water, considering data collected from multiple so urces. See the response to DCN EPA

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- 364 Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Do cument Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Even setting aside these errors, the current, available data sufficien tly demonstrates that only limited pollutants are present in bottom ash transport waters

— a fact EPA has recognized since the early 1980s. 3 Since that time, EPA collected little additional bottom ash wastewater data to demonstrate any increase in poll utant

- loading in this waste stream.

3 See 45 Fed. Reg. 68,328, 68,338 (Oct. 14, 1980) (noting that certain pollutants were present in bottom ash at lower concentrations than those detected in intake water supplies); EPA, Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category, EPA

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- 2186 at 498 (providing that “[a]nalysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control”). Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 9.

Commenter Name: Dean Ellis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Bottom ash transport water contains low levels of pollutants of con cern. Bottom ash and bottom slag consist of vitrified or heat fused ash particles from the bottom of a coal

- fired boiler. Bottom ash and bottom slag are large in size, heavy with respect to specific gravity, and glass

- like in appearance. Pollutants do not readily leach from bottom ash and bottom slag. Because of their size and weight, bottom ash and bottom slag settle rapidly in impoundments. In fact, in 1980, EPA proposed to reject more stringent regulation of bottom ash because it found that, at most plan ts, the priority inorganic pollutants detected in bottom ash water were less than theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 365 concentrations detected in the raw or intake water source. 45 Fed. Reg. 68,328, 68,338 (Oct. 14, 1980). Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 9.

Commenter Name: Cathy S. Woollums Commenter Affiliation: MidAmerican Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 19 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA has historically and accurately recognized that bottom ash does not contain significant amounts of metals that would justify dry management of bottom ash transport water. 19 The same reasoning sh ould apply to bottom ash under the current ELG proposal. The low levels of constituents of concern within the bottom ash transport water, in addition to the high costs of retrofitting bottom ash management systems at existing facilities, does not support a ny of EPA’s alternatives for “zero discharge” limits for bottom ash transport water. 19 EPA Technical Development Document, 1982. EPA

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- 2186. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 9. EPA disagrees with the commenter’s claim that zero discharge technologies are too costly; EPA re

evaluated the costs associated with the installation and operation of the BAT and NSPS technology bases of dry handling or closed

- loop systems after considering pu blic comments and data received ( Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category report, DCN SE05831/SE05832). As described in preamble secti on IX, EPA evaluated the costs and associated impacts of the ELGs on existing steam electric power plants, and on new units to which the ELGs may apply in the future. EPA determined that, for existing sources, these technologies are technologically availa ble and economically achievable, and in addition, for new sources, such technologies are demonstrated and do not present a barrier to entry (see preamble section VIII).

Commenter Name: Daniel K. Plath Commenter Affiliation: Northern Indiana Public Serv ice Company (NIPSCO)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 366 Document Control Number: EPA

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- A2 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: NIPSCO recommends that USEPA clearly distinguis h, via their data compilation, the characteristics of water used for the management of boiler slag generated by cyclone combustion furnaces (boilers) from the characteristics of the water used to manage bottom ash generated by flame combustion boilers. NIP SCO believes that, upon review of the characteristics of boiler slag and the associated transport and disposal water, USEPA will find a significant difference as compared to bottom ash associated waters, demonstrating and highlighting the inert nature of b oiler slag.
USEPA has inappropriately combined bottom ash transport and disposal with boiler slag transport and disposal; in effect asserting that they are one and the same, with no consideration of the significant differences in the physical nature of the se materials. Transport waters sampling summarized by USEPA did not distinguish between those facilities utilizing flame combustion boilers versus those utilizing cyclone boilers. In fact, based on our review of information publically available, it appears USEPA did not sample transport waters, settling ponds, or disposal impoundments at facilities using cyclone boilers. Hence, USEPA’s conclusions on the environmental impact of bottom ash waters are supported only by data specific to bottom ash ma nagement, not cyclone boiler slag management. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 4 in Comment Code 15.a. As noted there, EPA used data from at least two plants with impoundments receiving boiler slag (e.g., Kyger Creek, Kammer) in its bottom ash baseline loadings analyses. Therefore, the data used to characterize bottom ash loadings in the analysis are representative of both bottom a sh and boiler slag. EPA has determined the final BAT requirements for bottom ash transport water based on dry handling or closed

- loop technologies for units greater than 50 MW and that are not oil

- fired are technologically available and economically achiev able for units that are greater than 50 MW and that are not oil

- fired, including for plants that use cyclone boilers (see preamble section VIII). Thus, the definition of bottom ash in the final rule specifically includes “boiler slag.”

Commenter Name: Stephen M. Frank Commenter Affiliation: NRG Energy, Inc.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 367 Document Control Number: EPA

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- A2 Comment Excerpt Number: 18 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Bottom As h and Fly Ash Transport Water Do Not Contain Similar Pollutant Loadings Quantity of Ash Generated Differs Greatly According the 2009 Detailed Study that was used as the basis for the April 2013 TDD, as much as 70 to 80 percent of the ash from a pulverized coal furnace consists of fly ash. The remaining 20 to 30 percent is bottom ash. Because bottom ash particles are heavier than fly ash particles, they more easily separate from the sluice water. In addition to the greater quantity generated, fly ash particl es are smaller and have a greater surface area leading to a greater leaching potential as demonstrated below. Discharge Flow Rates Differ Greatly As summarized in the April 2013 TDD, EPA “found that the fly ash and bottom ash transport waters generated fro m wet systems at coal

- fired power plants are created in large quantities and contain significant concentrations of metals, including arsenic, selenium and mercury.” Addressing fly ash and bottom ash transport waters together is very misleading. While many of the facts appear true for fly ash transport waters, this is not the case for bottom ash transport water, and inconsistent with the findings in the 2009 Detailed Study. According to the 2009 Detailed Study, the average daily flow rate of bottom ash per p lant is 40 percent less than the average fly ash transport water flow rate. Bottom ash transport water is also an intermittent stream from steam electric units. According to the 2013 TDD, Table 6

- 6 presents the amount of fly ash and bottom ash wastewater d ischarged in 2009. On average, a single plant discharges approximately 2.39 MGD of fly ash transport water and approximately 1.76 MGD of bottom ash transport water. Comment Response: EPA evaluated POCs for bottom ash transport water, separate from fly as h transport water, considering data collected from multiple sources. See the response to DCN EPA

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- 368 Number 72 in Comment Code 15.d for more information about EPA’s ash characterization dataset and steps for calculating pollutant loadings in bottom ash transport water. In response to the comm enter’s comparison of fly ash transport water characteristics to bottom ash transport water characteristics, this is not relevant to EPA’s final BAT determination. Furthermore, EPA’s analysis projects significant pollutant reductions as a result of the ze ro pollutant discharge requirements (BAT/BDCAT) on bottom ash transport water (see preamble section XII).

Commenter Name: Erin Bartlett Commenter Affiliation: The Large Public Power Council (LPPC) Document Control Number: EPA

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- A1 C omment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: unlike FGD wastewater and some wet fly ash handling, the chemical compositions of bottom ash have not changed significantly since the last ELG was issued in 1982. There are no new chemicals in the bottom ash transport water that the current impoundment systems do not adequately treat. The characteristics of bottom ash

– inert, angular shaped, granular particles, and glass

‐ lik e surface structure

– results in its multiple industrial uses, such as aggregate in light weight cement, a feedstock for cement, shingles, and aggregate in road bases. These beneficial uses were developed with bottom ash mined from surface impoundments and should continue. Comment Response: See the response to DCN EPA

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Commenter Name: John W. Myers Commenter Affiliation: Tennessee Valley Authority (TVA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 23 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: While the constituents of bottom ash and fly ash are similar, the concentrations, solubility/leachability, mass loading ( due to lesser flows), and resultant discharge impact potential are significantly less for bottom ash transport water. As EPA has described in theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 369 proposed rule, bottom ash is a combustion residual of heavier ash particles collected at the bottom of a boile r. Fly ash consists of very fine particles (0.001 to 0.1 millimeter (mm)) while the particle size of bottom ash is much greater (1.0 mm to 1 centimeter (cm)). As a result, the bottom ash settles almost immediately when discharged to ponds/impoundments. EPA acknowledges that surface impoundments can be effective at removing particulate forms of metals and other pollutants, but EPA states that ponds are not effective at removing other pollutants of concern such as dissolved metals. Numerous EPRI and industry reports have concluded that the solids associated with bottom ash readily settle out in a pond (see EPRI Technical Update 1005567

- 2005). And as mentioned earlier, pond processes are much more complex than just providing settling and dilution as documented in other EPRI documents. (See Guidelines for Integrated Management of Multiple Constituents in Ash Ponds, EPRI, Palo Alto, CA: 2006. 1010123, Integrated Fly Ash Pond Management: A Field Study of Five Central United States Pond Systems, EPRI, Palo Alto, CA :2009. 1020365) Comment Response: See the response to DCN EPA

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Commenter Name: Kim Mireles Commenter Affiliation: Luminant Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 Ext ernal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:

 EPA inappropriately assumes that bottom ash transport water pollutants are the same as the pollutants from Flue Gas Desulfurization (FGD) waste water. Comment Response: EPA disagrees that it “assumes that bottom ash transport water pollutants are the same as the pollutants from Flue Gas Desulfurization (FGD) waste water.” At proposal, EPA identified bottom ash transport water POCs based on POCs identif ied for fly ash transport water. However, for the final rule, in response to public comments, EPA evaluated POCs for bottom ash transport water, considering data collected from multiple sources. See the response to DCN EPA

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- 370 EPA’s ash characterization dataset and steps for ca lculating pollutant loadings in bottom ash transport water.

Commenter Name: Kim Mireles Commenter Affiliation: Luminant Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Data used by EPA to Characterize and Evaluate Bottom Ash Transport Water has Significant Flaws that Undermine the Technical Bases for the Rule EPA's proposal for dry handling of bottom ash is not justified by an adequate collection of representative data demonstrating a need for additional controls. EPA used old data sets instead of recent and representative data. Despite a collection of recent samples, EPA's proposal is based to a large extent on pre
- 1982 data and data collected/analyzed with outmoded methods. Further, EPA compounded its errors by making a number of unusual and unsound assumptions about concentrations below the detection limit, as explained below. EPA appears to base its evaluatio n of Bottom Ash Transport Water on a single sample of bottom ash transport water collected from one site during the six plus years of data collection from 68 site visits. The one sample was used in combination with nine data sets collected over 30 years ag o and additional information previously collected through National Pollutant Discharge Elimination System (NPDES) permit applications. Much of the data from the nine data sets were collected before the industry had fully implemented the 1974 and 1982 effl uent limitations guidelines which provide limited applicability for the purposes of this rule. Additional data from NPDES application Form 2Cs used by EPA was compiled by the Utility Water Act Group, at EPA's request, from 1994

- 2007. For evaluation of bottom ash, EPA used Form 2C data from three outfalls from bottom ash

- only ponds. Thus, for bottom ash

- only data (as distinguished from data for combined fly ash and bottom ash ponds, discussed below), EPA had the one 2007 sample, nine bottom ash

- only data sets from the 1982 Technical Development Document (TDD), and information provided for only three outfalls from bottom ash ponds in the Form 2C data. Luminant maintains that the information from the pre

- 1982 TDD data and the Form 2C data cannot be used to justify dry

- handling of bottom ash because of significant flaws in this data. As already noted, most of the data (the 1982 TDD data) were from before 1982, when theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 371 wastestreams were unregulated or only partially regulated. Luminant believes that the data used to support the need for additional controls is inadequate and misused as noted below. Comment Response: EPA disagrees with the commenter that the EPA’s ash transport water characterization dataset and methodology is inappropriate for calculating po llutant loadings associated with bottom ash transport water due to the reasons stated by the commenter. See the response to DCN EPA

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- detects, and sulfides. See response to DCN EPA

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Commenter Name: Kim Mireles Commenter Affiliation: Luminant Document Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Review Exte rnal Review Incorporated into Response: No Comment Excerpt: 

### EPA's broad assumption that the "pollutants of concern" (POC) for bottom ash transport water are identical to those for fly ash transport water 6 

### is erroneous and inappropriate.
For this rulemaki ng, EPA abandoned its traditional method of identifying POC. Ordinarily EPA requires a POC to be detected in at least three samples. See 66 Fed. Reg. 424,446 col. 3 (Jan. 3, 2001). However, in the current rulemaking EPA did not use three samples. EPA selec ted pollutants of concern based on only two samples for 12 metals and one sample for the other 26 pollutants. ERG POC Methodology memorandum, EPA

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- 3 atEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 372 8

- 9. Of the total 38 pollutants evaluated, EPA selected 24 POC of which 15 are based on detection in a single sample. In addition, based on the TDD for the Landfills category, EPA ordinarily removes naturally occurring nontoxic minerals and treatment chemicals from the POCs. EPA did not do this for the steam electric proposed EL Gs. The inclusion of naturally occurring constituents misrepresents what constituents actually result from the process being evaluated. The regulated source could become responsible for meeting an effluent limitation and for the removal of naturally occurr ing constituents that were also not generated within the process. EPA chose nitrate/nitrite as POC based on a fly ash transport water sample from a power plant in Ohio. See EPA

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- 2151 at 9. EPA did not analyze this nitrate/nitrite sample with in the correct 48 hour holding time. See Detailed Study, Table 5

- 9 at 5

- 20. Thus EPA's only value for establishing nitrate/nitrite as a POC for both fly ash and bottom ash transport water is not a valid result. Given that the determination of nitrate/nitri te as a POC was not borne of a valid observation, this determination contravenes the EPA's and administration's stated commitment to "follow the science" in its development of regulations that could impact almost every power plant in the United States, ev en those that do not use coal or oil as their primary fuel.

6 ERG, Pollutants of Concern Methodology Memorandum, EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 373 Comment Excerpt Number: 29 External Review Flag: No External Review External Review Incorpora ted into Response: No Comment Excerpt:
C. Many of EPA’s Bottom Ash Transport Water Data Are Invalid and Inappropriate for Determining TWPEs The characterization data EPA has assembled for bottom ash transport water are a mixed bag of a few generally vali d samples along with data of questionable quality from as long as 40 years ago. EPA has not collected enough bottom ash transport water samples to justify new, more stringent limitations. Comment Response: EPA disagrees with the commenter that the EPA’s ash transport water characterization dataset and methodology is inappropriate for calculating pollutant loadings associated with bottom ash transport water due to the reasons stated by the commenter. See the response to DCN EPA

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- detects, and sulfides. See section 12 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards f

or the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) for more information on how EPA determined pollutant concentrations for use in calculating baseline pollutant loadings and pollutant reductions under t he final rule.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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E. UWAG’s Bottom Ash Transport Water Data: Development and Results When UWAG realized that EPA was not going to collect an adequate number of bottom ash transport water samples, we decided to fill the information gap by collecting our ownEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 374 characterization data and retrofit cost data. We did this through a series of member surveys and data requests.
1. Bottom Ash Characterization Data Beginning in October 2011 and continuing throughout 2012 and 2013, UWA G asked its members to provide data characterizing their bottom ash transport waters. In requesting data, UWAG was careful to specify that the data should meet the following criteria:
1. The bottom ash transport water should not be comingled with other waste streams, such as fly ash transport water, FGD wastewater, or cooling water. 2. If possible, the average annual discharge flow from the bottom ash pond should be included. 3. If possible, the data should include an analysis of the pollutants in the source water ( i.e ., river water) used to sluice the bottom ash. 4. The water samples should be analyzed using sensitive methods, such as Method 200.8 or 200.7 for metals and Method 1631E for mercury. 5. For facilities that do not have separate bottom ash ponds, the sample sho uld be collected before the water enters the pond where it comingles with other wastewater and then be allowed to settle an hour before drawing off the supernatant for analysis. 6. Laboratory reports or certificates of analysis should be provided for all char acterization data. UWAG received many responses. We did not use any data for samples that reflected comingled bottom ash and fly ash samples, and we did not use any samples in which water from other processes was used as sluice water. We used only samples sluiced with water from the source waterbody. We also rejected any mercury data that were not analyzed by the prescribed low

level method (Method 1631E) or an equivalent method. Where a member provided more than one sample for the same outfall, w e averaged those samples to obtain the pollutant concentration. To be conservative, UWAG used the detection level (MDL) as the concentration for pollutants that were not detectable. This virtually guarantees that the assumed concentrations are higher tha n the actual ones. After entering the data into the UWAG bottom ash characterization database, we proofread each data point in the database against the actual certificates of analysis or Form 2Cs from which they were transcribed. The characterization data used included all pollutants on EPA’s analyte list that have TWFs (aluminum, antimony, arsenic, barium, beryllium, boron, cadmium, calcium, chromium, cobalt, copper, iron, lead, magnesium, manganese, mercury, molybdenum, nickel, selenium, silver, sodium, thallium, tin, titanium, vanadium, zinc, chloride, sulfate, nitrate/nitrite as N, and ammonia as N), except cyanide, fluoride, and sulfide. The resulting UWAG bottom ash transport water characterization database includes data from 21 facilities. Much of the data

– unlike EPA’s bottom ash transport water data that include 1982 Development Document data

– are fairly recent. The UWAG database samples date from 2001 to 2013, with most of the samples from 2010 to 2013. The database is included as Attachment 7Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 375 to these comments. Attachments 8 and 9 contain the supporting documentation for the database (certificates of analysis or Form 2Cs). Comment Response: EPA used data collected during the detailed study, industry

- supplied data, and publicly available da ta sources, including data received during public comment, to develop the analytical dataset used to characterize bottom ash transport water and estimate the industry’s pollutant loadings. Throughout the development of the effluent limitations guidelines a nd standards (ELGs), EPA communicated with UWAG, an industry trade association representing 198 individual energy companies and three trade associations of energy companies. As part of this communication, UWAG provided EPA with several bottom ash analytica l datasets for EPA’s consideration and use in the characterization of bottom ash transport water. Consistent with EPA’s POC and loadings acceptance criteria (DCN SE05567), EPA used the data submitted by UWAG unless:

 Effluent from the ash impoundment sample d was comprised of less than 75 percent ash transport water.

 Data were duplicative of other accepted data.

 Plants were not identified. For such plants, EPA could not confirm whether the samples met all the acceptance criteria because it did not have suffic ient information about the sources and volumes of wastewater managed by the impoundment (i.e., EPA could not verify that the effluent to the ash impoundment sampled was at least 75 percent ash transport water). Additionally, the lack of plant identificatio n precluded EPA from evaluating whether the UWAG data were for impoundments already included in EPA’s Steam Electric Analytical Database.

 Samples did not represent actual effluent from an impoundment. EPA excluded data submitted by UWAG that attempted to s imulate impoundment effluent, using samples that were collected prior to the ash pond and settled in a sampling container prior to analysis. In regards to the last bullet, in response to EPA’s questions about the representativeness of UWAG’s settled bottom ash sluice pipe samples, UWAG presented a comparison of settled sluice pipe samples to near

- effluent discharge point samples at each of the six plants sampled as part of UWAG’s November 2014 communication with EPA. UWAG concluded that “whether viewed from the individual facility perspective or as averaged across the six facilities, it is clear that the settled bottom ash sluice pipe samples substantially overestimate bottom ash effluent pollutant loadings” (DCN SE05597). For the final rule, EPA supplemente d its fly ash and bottom ash characterization dataset and revised its estimates of ash impoundment effluent concentrations. See the response to DCN EPA

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- 376 See response to DCN EPA

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Commenter Name : Claire M. Olson Commenter Affiliation: Basin Electric Power Cooperative Document Control Number: EPA

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Comment Excerpt: One of the driving concerns of EPA is the assumption that ash transport wastewaters contain pollutants that can have detrimental impacts on the environment. All coal ash and associated wastewaters are not the same. Bottom ash clearly does not ha ve the same characteristics as fly ash or FGD waste. In fact.bottom ash is classified as an "inert waste" under North Dakota regulations because it does "not generally contaminate water or form a contaminated leachate...."
Basin Electric monitors bottom as h transport water from the Leland Olds Station for a variety of parameters, including arsenic, cadmium, lead, and selenium. Monitoring data for these constituents over the past ten years have always been below Safe Drinking Water Act Maximum Contaminant Le vels (MCLs). Even though Safe Drinking Water Act standards are not applicable, this demonstrates how inappropriate it would be to impose additional requirements on water that has come in contact with bottom ash at Leland Olds Station. Further, concentrati ons of the aforementioned parameters are generally below detection limits. If bottom ash transport water meets Safe Drinking Water Act standards, EPA should not prohibit its discharge. Comment Response:
See DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 377 Comm ent Excerpt: Bottom ash transport water is one of the major sources of toxic pollutant loadings from this source category, contributing 21% of POCs and 33% of TWPEs from all sources. TDD, Tables 10

- 13, 10

- 18. 6

6 From Tables 10

- 13 and 10

- 18: for POCs: (16 60+44.9)/5500 = 0.21. For TWPE: (2420+295)/8320 = 0.33. Comment Response: EPA agrees with the commenter that bottom ash transport water is a source of toxic pollutants and is establishing zero discharge standards for bottom ash transport waters for this regulation (see preamble section VIII). EPA notes that it updated its estimates of pollutant loadings for the final rule. See the final TDD. EPA also updated its estimates of TWPE (cost

effectiveness). See the final RIA.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 49 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Many of EPA’s Bottom Ash Transport Water Data Are Invalid and Inappropriate for Determining TWPEs The characterization data EPA has assembled for bottom ash transport water are a mixed bag of a few generally valid samples along with data of questionable quality from as long as 40 years ago

. EPA has not collected enough bottom ash transport water samples to justify new, more stringent limitations. Comment Response: EPA disagrees with the commenter that the EPA’s ash transport water characterization data set and methodology is inappropriate for calculating pollutant loadings associated with bottom ash transport water due to the reasons stated by the commenter. See the response to DCN EPA

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- detects, and sulfides. See section 12 of theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 378 Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) for more information on how EPA determined pollutant concentrations for use in calculating baseline pollutant loadings and pollutant reductions under the final rule.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 379 15.d. BA Transport Wa ter

– Calculation of Baseline Loads
Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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### 1. Old Data, Insufficient Data Points, Nondetects, Sulfides, and Source Water Pollutants Biased the TWPE Calculations The table below, which addresses both data for Form 2Cs and data from the 1982 Develo pment Document, lists the top 10 contributors to bottom ash transport water TWPEs, according to EPA, and contrasts them with results UWAG has derived after reviewing EPA’s data. UWAG’s consultant, URS, made several critical adjustments to EPA’s TWPE calculations. For example, URS removed the data points associated with old and unreliable data from the 1982 Development Document. URS also adjusted the TWPEs by accounting for parameters present in the source water. URS used estimates of source water v alues from the UWAG bottom ash characterization database (Attachment 7). URS calculated the average concentration for each pollutant, after discarding high non

- detect and high outlier results, to determine a minimum concentration value of the constituents found in the source water. Clearly, EPA should not have attributed source water pollutants to industry facilities because, if the zero discharge of bottom ash transport water option is selected, the source water and its constituents would remain in the so urce waterbody.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category: EPA’s Response to Public Comments

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### 2. Sulfides Should Not Be Attribut ed to Bottom Ash Transport Water Sulfides clearly dominate EPA’s estimates, maki ng up more than 58% of EPA’s total bottom ash transport water TWPEs after data points attr ibutable to combined ash discharge ponds are removed. This very large per centage is based on only two da ta points from the Form 2C database. Given the many problems UWAG has id entified above with sulfide methods and EPA’s very small data set, UWAG reiterates that EPA should remove all sulfide data attributed to bottom ash transport water. Also, the ot her EPA sampling program pond data have been completely overwhelmed by the questionabl e, very old, and not representative 1982 Development Document data. Because of analytical methods with EPA-approve d methods for measuring sulfides, described in the attached report by URS Corporation (Attach ment 5), UWAG undertook its own sampling and analysis for sulfides at several facilities. The re sults are presented at page 7 and in Table 1 of the URS report.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 381 The UWAG sampling found high dissolved oxygen in all samples associated with the ash transport process; nondetected sulfides in titration and colorimetric analyses; no detections of sulfides above the laboratory quantitation limit even with the co lorimetric analysis; and the same “J” flagged detections for upstream river water. The UWAG sampling conclusively refutes EPA’s estimate of average concentrations of sulfide up to one mg/L being consistently discharged from ash ponds. See Attachment 5 fo r details of UWAG’s sampling and analysis for sulfides. 

### 3. When the TWPE Calculations Are Corrected, They Fall Significantly After sulfides, the next highest contributor to EPA’s TWPEs is cadmium. EPA’s database contains 14 data points for cadmium, but ni ne of these are 1970s data from the 1982 Development Document. After removing the 1982 Development Document data from the set, cadmium drops from 207,960 TWPEs to 10,240 TWPEs. Adjusting for cadmium in the intake source water, this drops further to only 3,413 TWPEs. For thallium, URS adjusted EPA’s database by removing two non

- detect values that were higher than 0.002 mg/L. This is justified because no sample contained thallium as high as the non

detect values. This simple adjustment of non

- detects redu ces the thallium TWPEs from 129,352 to 2,055. This drops further to 1,171 TWPEs after adjusting for source water. For mercury, EPA has 14 data points, nine of which are 1982 Development Document data. After removing those data points, EPA’s TWPEs drop fr om 114,951 to 5,189, and to 4,912 when adjusted for source water. For tin, three of four bottom ash values from Form 2C were non

- detects. The fourth value is from EPA’s Homer City sample and is listed as “detected” in EPA’s database, but it was flagged “U ” in the Homer City SER, so it should be treated as a non

- detect as well. Therefore, UWAG removed all TWPEs for tin, since EPA has no valid detected values. For lead, EPA collected 14 data points, including nine from the 1982 Development Document and one from a mixed bottom ash/FGD wastewater discharge point. URS removed these data points. Although the remaining data set includes two non

- detects from recent data, URS used the non

- detects at face value, since all recent samples had relatively low detectio n limits, and some detected results were higher than the highest detection limits. With these corrections, the total TWPEs drop from 88,343 to 1,627, or down to zero when adjusted for source water. For magnesium, EPA used four detected data points. Howev er, URS eliminated one data point because it included FGD wastewater. For silver, URS removed the data point for PA0002895

- 004 because the pond contains FGD wastewater and therefore is not appropriate for characterizing bottom ash transport water. URS als o screened out unreasonably high non

- detects. Based on these corrections, the TWPEs drop from 84,389 to 3,154.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 382 For arsenic, URS removed nine 1982 Development Document values out of a total of 14 data points. URS also removed a data point for bottom ash t hat also contained FGD wastewater. After these corrections, TWPEs for arsenic were reduced from 82,222 to 14,361, or 10,493 after making source water adjustments. For aluminum, EPA used five data points, all from fairly recent data. Again URS removed the data point combined with FGD wastewater and recalculated, resulting in 26,843 TWPEs rather than EPA’s 42,440. Source water

- adjusted, this would be reduced to 11,611. 

### 4. UWAG’s Corrections Show 65,342 TWPEs for Bottom Ash Transport Water Instead of 2,716, 059 Following procedures similar to those outlined above, UWAG reviewed all the remaining bottom ash discharge data in EPA’s database for an additional 24 analytes and made adjustments for each analyte where necessary to remove 1982 Development Document da ta and other inappropriate data (for example, bottom ash transport water combined with FGD). EPA also calculated TWPEs from combined ponds based on the average concentration from those ponds and then estimated that 14% of that TWPE was due to bottom ash in the combined ponds. UWAG, in contrast, did not use the concentrations and resultant loadings from the combined ash ponds. UWAG thinks the concentrations in the combined ash ponds were inflated due to fly ash and likely other wastewater operations going into the combined ponds. UWAG therefore assumed that 14% of the flow from the combined ponds was due to bottom ash (similar to EPA’s assumption) but judged it more appropriate to assign TWPEs based on average concentrations derived from bottom ash ponds o nly. Since EPA reported a 262 MGD industrywide flow for combined ash ponds, 2013 TDD at 10

- 28, 14% of that would be 36.7 MGD. The 36.7 MGD would increase the EPA reported daily flow for bottom ash ponds from 327 to 363.7 MGD. The increased flow factor f or bottom ash ponds when incorporating bottom ash in combined ponds would therefore be 363.7/327, a factor of 1.112. UWAG therefore increased the TWPE value obtained from the bottom ash pond data alone by this factor. UWAG also adjusted the TWPEs by accou nting for parameters present in the source water. Estimates of source water values came from UWAG’s own bottom ash pond database. UWAG calculated the average concentration for each pollutant, after discarding high non
- detect and high outlier results, to calculate a minimum concentration value of the constituents found in the source water. URS’s analysis is attached to these comments as Attachment 6. As a result of these adjustments, UWAG calculates total TWPEs for bottom ash transport water of 65,342 (co rrected for source water pollutants), while EPA’s estimate is a staggering (and highly unrealistic) 2,716,059.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 383 Comment Response: The commenter calls into question the validity of data used to characterize typical bottom ash transport water, citing an a nalysis prepared by the commenter’s consultant, URS (see DCN EPA

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- A6). Regarding sulfides, source water, high non

- detects, and the use of old data to determine the concentration of pollutants in bottom ash ponds, see the response to DCN EPA

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- A1, Excerpt Number 72.
The commenter is confused about what EPA means when it refers to a combined ash surface impoundment. Where EPA uses the term combined impoundment, it refers to an impoundment that contains both bottom ash an d fly ash transport water. A fly ash surface impoundment, a bottom ash surface impoundment, or a combined ash surface impoundment may contain other wastestreams as well. Many commenters did not understand this distinction and this resulted in them misrep resenting how EPA calculated loadings for each of these types of surface impoundments. For a response to EPA’s use of data to estimate effluent from bottom ash surface impoundments that are not from surface impoundments exclusively used to treat bottom ash transport water, see the response to DCN EPA

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- A1, Excerpt Number 72. EPA also notes that conditions present in some surface impoundments can create chemical conditions that convert particulate forms of metals to soluble forms. EPRI (a technical research organization funded by the electric power industry) has reported that adding FGD wastewater to surface impoundments used to treat ash transport water may reduce the settling efficiency in the impoundments due to gypsum particle dissoluti on. EPRI also reported that the FGD wastewater includes high loadings of volatile metals which can increase the solubility of metals in surface impoundments, thereby leading to increased levels of dissolved metals and resulting in higher concentrations of metals in the surface impoundment discharge. This co

- management of wastestreams can lead to increased pollutant discharges associated with ash transport water. Therefore, EPA believes it is appropriate to represent these combined ash impoundments in the da taset. To ensure the wastestreams are representative of ash transport water, EPA established the data acceptance criteria described in Section 10 of the TDD and in response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d, ensurin g that at least 75% of the impoundment volume is comprised of ash transport water. Combined ash ponds : As explained above, EPA defines a combined ash pond as a pond that contains both bottom ash transport water and fly ash transport water. As reported in the industry survey, some surface impoundments contain bottom ash transport water (and no fly ash transport water), some contain fly ash transport water (and not bottom ash transport water) and some contain both fly ash and bottom ash transport water. 1 E PA identified loadings, however, for bottom ash transport water and fly ash transport water, as EPA evaluated requirements for bottom ash and fly ash transport water separately. EPA wanted to account for the pollutant

1 That is not to say they don’t contain other wastewaters as well. It is common for plants to combine wastestreams other than ash transport water in surface impoundments. See response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 384 loadings in combined ash ponds or it would have underestimated its identification of loadings. Some commenters stated that EPA should not include any pollutant loadings from combined ash ponds in its estimation of bottom ash transport water loadings because they assert that bottom ash has few pollutants and that any pollutant present in combined ash ponds are likely from fly ash. EPA disagrees. EPA’s final analysis demonstrates that bottom ash transport water and fly ash transport water contain many of the same pollutants. The question befor e EPA was to determine how to apportion the pollutant concentrations in the combined ash ponds to bottom ash and fly ash transport water loadings. See DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b regarding the final rule ash chara cterization data, including the use of combined fly ash and bottom ash data, and the methodology used to separate the loadings for combined ash impoundments into fly ash loadings and bottom ash loadings. As explained there and in TDD Section 10, for combin ed ash impoundments, EPA did not assume that 86% of the total pollutant loading was attributed to fly ash and the other 14% was attributed to bottom ash as stated by the commenter. As described in the response cited above, EPA calculated a pollutant

- specif

ic percentage of the pollutant loading associated with bottom ash transport water versus fly ash transport water in combined ash surface impoundments. EPA also disagrees with the commenter’s re

- estimation of bottom ash pollutant loadings from combined ash ponds, in which the commenter “assumed that 14% of the flow from the combined ponds was due to bottom ash (similar to EPA’s assumption).” As described above, EPA did not assign the bottom ash percent contribution to flow but rather to loadings . The use of a 14% factor attributed to flow is meaningless

– this is not based on any data collected by EPA. Because the commenter then went on to conclude that it was “more appropriate to assign TWPEs based on average concentrations derived from bottom ash ponds onl y,” the commenter compounded their error by assigning bottom ash concentrations to this incorrectly derived flow rate. Therefore, EPA determined the approach suggested by the commenter did not appropriately capture pollutant loadings associated with combin ed ash ponds. See “Break Out of Combined Ash Loadings Methodology Memorandum” (DCN SE05586).
NPDES Permit Number PA0002895

- 004 : EPA disagrees with the analysis prepared by the commenter’s consultant, URS, in which the commenter states that the results from NPDES permit number PA0002895

- 004 should be excluded from the loadings analyses on the basis that the outfall also receives FGD wastewater. As described in Section 10 of the TDD and earlier in this response, EPA characterized the concentration data as rep resentative of bottom ash impoundment effluent if the impoundment/outfall receives at least 75% by volume bottom ash transport water and does not receive fly ash transport water. The impoundment may also receive other types of wastewater, such as FGD waste water. Based on the information in the Steam Electric Survey and the commenter

- provided Form 2C database, EPA determined that bottom ash transport wastewater represents at least 75% of the volume discharged from this outfall and that it is appropriate to u se data from this pond for use in characterizing bottom ash impoundment effluent. EPA updated its estimates of TWPE (cost

- effectiveness) for the final rule. See the RIA. Although not required by the CWA, and not a determining factor for establishing BAT/P SES or BADCT/PSNS, cost

- effectiveness analysis can be a useful tool for describing regulatory options that address toxic pollutants. As presented in preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the selected regulatory option (Option D) have a cost

-Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 385 effectiveness ratio of $134/lb

- eq ($1981). This cost

- effectiveness ratio is well within the range of cost

- effectiveness ratios for BAT requirements in other industries. Also, see responses to comment code 6.h.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 74 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Aside from EPA’s misuse of combined ash pond effluent data, the EPA database and EPA’s interpretation of the data misrepresents the pollutant loading from bottom ash sluice water and causes the pollutant loadings to be grossly overestimated. Based on Duke Energy’s assessment, the majority of constituents that accounted for EPA’s total TWPE removal under Regulatory Op tion 4(a), approximately 88% or 1,389,167, are constituents that are not actually present in bottom ash sluice water at levels indicated by EPA 23

. Under Regulatory Option 4 and 5, these constituents accounted for approximately 2,389,940 of the total TWPE removed. A summary of these constituents and issues contributing to the inaccuracy of EPA’s results for the average effluent concentration and TWPE evaluation are provided below in Table 2

- 1. The major issues associated with EPA’s database and the re asons for the artificial estimates of concentrations and pollutant removal for bottom ash sluice water are primarily due to the following:

 The assumption that there is no pollutant contribution from the source water,

 The misinterpretation of non

- detec ts in EPA’s existing bottom ash sluice water database, and

 The use of data collected as part of the 1982 revisions to the ELG and presented in the 1982 Technical Development Document (TDD), specifically the analytical method and sample collection methods u sed for this data collection effort.
Table 2
- 1. Summary of Inaccuracies in TWPE Removed for Bottom Ash Constituents

Parameter TWPE

Removed Percent

Contribution to the TWPE Removed Calculation IssuesEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 386 Arsenic 47,672 3% Relied on poor data reported in the 1982 TDD

Cadmium 120,583 8% Relied on poor data reported in the 1982 TDD

Magnesium 49,771 3% Did not account for contributions in the source water

Mercury 65,261 4% Relied on poor data reported in the 1982 TDD

Sulfide 919,429 58% Poor methodology evaluating non

detects

Silver 48,681 3% Poor methodology evaluating non

detects

Thallium 75,321 5% Poor methodology evaluating non

detects

Tin 62,449 4% Poor methodology evaluating non

detects
TOTAL 1,389,617 88%

Source Water Contributions To accurately assess pollutants within bottom ash sluice water, EPA needs to include contributions from the source water. Several of the constituents EPA reported as being in bottom ash sluice water could have originated from the source water, such as boron, calcium, iron, magnesium, manganese, and sodium, with little to no input from the bottom ash sluice water. The lack of incorporating contributions from the source water questions the validity of any of the d ata EPA relied upon to determine the average concentrations within bottom ash sluice water and subsequent pollutant reduction from a zero discharge option for bottom ash handling. As discussed below, Duke Energy conducted sampling of the bottom ash sluice water at Belews Creek and Marshall Steam Station. As part of Duke Energy’s bottom ash sampling effort, source water samples were also collected. A summary of the bottom ash sample results and source water contribution is provided in Appendix B. Of particul ar importance are the source water contributions for magnesium (refer to Table 2

- 2 below). For samples collected at both stations, magnesium was detected in the source water at concentrations very close to or higher than the concentrations detected in the bottom ash sluice water.
Table 2
- 2. A Comparison of Magnesium ConcentrationsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 387

Station Source Water Magnesium

Concentration (mg/L) Bottom Ash Sluice Water Magnesium Concentration

(mg/L)

Belews Creek Steam Station 3.6 3.5 Marshall Steam Station 4.5 2.3
It is, therefore, reasonable to assume that all the contributions for magnesium can be contributed to magnesium in the source water. It is also important to note that magnesium accounted for approximately 3%, 49,771, of the total TWPE removed by under Regulatory Option 4a 24

. Without accounting for contributions from the source water, EPA has not determined the actual pollutant loading contribution strictly from bottom ash transport water and therefore, has not accurately portrayed the pollutant removal or the dollar per TWPE removed under a zero discharge scenario.
Poor Methodology Evaluating Non
- Detects The method EPA used to interpret non

- detects misleadingly skews the results to indicate a higher pollutant loading removal for a zero discharge option for bottom ash sluice water. To determine the concentrations within bottom ash sluice water, EPA relied on four data sets: 1) one sample collected for the 2010 detailed study; 2) information submitted on the Form 2Cs, 3) EPRI PISCES Study, and 4) samples e valuated for the 1982 revisions to the ELGs. All of the non

detects reported on the Form 2Cs and EPRI PISCES study were included in the evaluation as being “detected” at the reported detection value. This method grossly overestimates the pollutant loading s from bottom ash sluice water. As an example, sulfide within bottom ash sluice water was reported by EPA at an average concentration of 0.51 mg/L and sulfide accounted for approximately 58%, 919,429, of the total TWPE removed under Regulatory Option 4a 25

. To determine the average sulfide concentrations in bottom ash sluice water, EPA relied on only two results reported on Form 2Cs for two facilities; sulfide, however, was not detected above the reported detection value in any of the samples (see Table 2

- 3 below). EPA erroneously assumed sulfides are present at concentrations equal to the analytical detection limit. Under EPA”s analysis, the sulfide loading is merely due to the laboratory’s ability or inability to detect sulfides at low concentrations and no t necessarily due to sulfides being present in bottom ash sluice water. Data from three of the seventeen facilities used to calculate the average sulfide concentration from combined ash impoundments reported detectable sulfides in the effluent, but EPA fai led to document whether these detections are actually associated with bottom ash or fly ash sluice water. Since fourteen of the seventeen facilities used to calculate the average sulfide effluent concentration for combined ash ponds and the two facilities used to calculated the average sulfide effluent concentration were all non

detectable for sulfide, these three detectable sulfide concentrations could easily be due to analytical error or a wastestream, such as iron pyrites, that is independent of bottom a sh sluice water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 388 Table 2
- 3. Sulfide Concentrations Used by EPA to Calculate the Average Concentration for Bottom Ash Sluice Water

Plant Name Analyte Units Non
- Detect Indicator Value
KY0004219

– 001 Sulfide (as S) mg/L < 0.02 OIB00005*LD

- 001 Sulfide (as S) mg/L < 1 Average 0.51
Sulfides are generally not in bottom ash sluice water and if present, are generally associated with the sluicing of iron pyrites. As part of Duke Energy’s bottom ash sluice water sampling effort, samples collected at Belews Creek, Marshall and Cliffside Steam Stations and Cayuga Generating Station were analyzed for sulfides. All results were reported as non

- detect at a MDL of 0.05 mg/L. Given all of EPA’s samples and all of Duke Energy’s samples were non

- detect for sulfides, it is reasonable to assume sulfides are not present in bottom ash sluice water. It is, therefore, unreasonable for EPA to justify a zero discharge limit for bottom ash transport water, in which the largest contributor to the TWPE removed per year is for a parameter that was not detected in any of the bottom ash sluice water data evaluated by EPA or detected in any recent sampling events. EPA stated that “there were more non

- detects than detected values for effluent data for sulfides” 26 and requests comment on whether this data set provides sufficient basis for estimating pollutant loadings for sulfides. Based on Duke Energy’s analysis, the data set does not provide sufficient basis for estimating pollutant loading for sulfides. EPA’s errors in evaluating no n
- detects were also replicated for silver, thallium and tin. Only two of the five samples evaluated for silver had detected values, only one of the five samples for thallium reported a detected value, and only one of the four samples for tin reported a det ected value (see Tables 2

- 4, 2

- 5 and 2

- 6 below).
Table 2
- 4. Silver Concentrations Used by EPA to Calculate the Average Concentration for Bottom Ash Sluice Water

Plant Name Analyte Units Non
- Detect Indicator Value Homer City

– 6548

- 70423 Silver mg/L D 0.00025
KY0004219

– 001 Silver mg/L < 0.0001 OIB00005*LD

- 001 Silver mg/L D 0.0004 PA0002895

- 004 Silver mg/L < 0.011 Site F Silver mg/L < 0.01 Average 0.004Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 389 Table 2
- 5. Thallium Concentrations Used by EPA to Calculate the Average Concentration for Bottom Ash Sluice Water

Plant Name Analyte Units Non
- Detect Indicator Value Homer City

– 6548

- 70423 Thallium mg/L D 0.00132
KY0004219

– 001 Thallium mg/L < 0.002 OIB00005*LD

- 001 Thallium mg/L < 0.5 PA0002895

- 004 Thallium mg/L < 0.1 Site F Thallium mg/L < 0.002 Average 0.12

Table 2
- 6. Tin Concentrations Used by EPA to Calculate the Average Concentration for Bottom Ash Sluice Water

Plant Name Analyte Units Non
- Detect Indicator Value Homer City

– 6548

- 70423 Tin mg/L D 0.015
KY0004219

– 001 Tin mg/L < 0.05 OIB00005*LD

- 001 Tin mg/L < 0.5 PA0002895

- 004 Tin mg/L < 0.8 Average 0.34
In all, these constituents accounted for 70% of the total TWPE calculated from bottom ash transport water, even through these constituents were rarely detected in bottom ash sluice water and when detected were at levels significantly lower than the average concentration reported by EPA.

23 ERG Memo Steam Electric Pollutant

- Level Loadings and Removals for Each Wastestream and Regulatory Option , April 1 9, 2013.

24 ERG Memo Steam Electric Pollutant

- Level Loadings and Removals for Each Wastestream and Regulatory Option, April 19, 2013.

25 Id.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 390 26 78 Fed. Reg. at 34485. Comment Response: EPA disagrees with the commenter that the EPA’s ash transport water characterization dataset and its approach for calculating the pollutant loadings grossly overestimates the industry loadings associated with bottom ash transport water due to the reasons stated by the commenter. See the response to DCN EPA

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- 4655, Excerpt Number 47 for more information about revisions to EPA’s ash characterization dataset and its approach for calculating pollutant loadings in bottom ash transport water, including discussio n of use of 1982 TDD data, use of combined ash impoundment data, source water pollutant contributions, handling of non

- detects, and sulfides. EPA evaluated the data submitted by Duke Energy against its acceptance criteria outlined in the Quality Assurance Project Plan for the Steam Electric Effluent Guidelines Rulemaking (DCN SE02951) and accepted all of the Duke data for use in identifying pollutants of concern (POCs) and a subset of the data for use in the loadings calculations (see DCN SE05567). EPA did not accept data submitted by Duke for the Belews Creek and Marshall plants for use in the loadings calculations because the data do not represent actual effluent from an impoundment. Rather, Duke submitted simulated effluent that settled in the sampling c ontainer prior to analysis. EPA excluded sample results that attempted to simulate impoundment effluent, using samples that were collected prior to the ash pond and settled in a sampling container prior to analysis. This approach is also supported by analy ses conducted by UWAG, an industry trade association. In a November 2014 letter, UWAG presented a comparison of settled sluice pipe samples to near

effluent discharge point samples and acknowledged that “whether viewed from the individual facility perspect ive or as averaged across the six facilities, it is clear that the settled bottom ash sluice pipe samples substantially overestimate bottom ash effluent pollutant loadings” (DCN SE05597). EPA did use all simulated effluent analytical data in a sensitivity analysis for pollutant loadings (see DCN SE05831/SE05832). Additionally, EPA evaluated all other data submitted during the public comment period, previous rulemakings, and the detailed study in the same manner as the data submitted by Duke and used all acc eptable data to determine POCs in ash transport waters and calculate pollutant loadings. EPA estimated average pollutant concentrations in bottom ash transport water using accepted effluent analytical data that represent all operations.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 391 Comment Excerpt: K. UWAG’s Bottom Ash Transport Water Characterization Data Are Consistent With EPRI’s and Homer City’s Characterization Data To check the reasonableness of UWAG’s $/TWPE estimates, UWAG compared its bottom ash transport water characterization data to thre e other sources of characterization data:

 EPRI’s PISCES bottom ash transport water data, 19

 EPA’s Homer City bottom ash effluent sample, and

 UWAG’s split of the Homer City bottom ash pond effluent sample. UWAG made this comparison by using its cost

- effectiveness model and holding all values constant except the characterization data. For instance, UWAG applied the same median flow rates for each model plant (derived from EPA’s ICR database) as were used in the other TWPE calculations. As shown in Table 6 below, the $/TWPE using the EPRI PISCES data and the Homer City $/TWPE are comparable to UWAG’s $/TWPE.
Table 6: Comparison of UWAG $/TWPE with $/TWPE Using the EPRI PISCES Data and Homer City Bottom Ash Pond Effluent Data 20

MW Range UWAG Data

$/TWPE* EPRI PISCES

$/TWPE Homer City

(UWAG Split of EPA’s Sample) $/TWPE Homer City

(EPA Sample) $/TWPE <50 MW $16,492 $19,775 $20,335 $14,008 50

- 100 MW $5,597 $6,711 $6,901 $4,754 100

- 150 MW $3,106 $3,725 $3,830 $2,638 150

- 200 MW $2,056 $2,465 $2,535 $1,746 200

- 300 MW $1,780 $2,134 $2,195 $1,512 300

- 400 MW $1,635 $1,961 $2,016 $1,389 400

- 500 MW $1,954 $2,343 $2,409 $1,660 500

- 700 MW $1,694 $2,031 $2,088 $1,439 700

- 900 MW $1,902 $2,280 $2,345 $1,615 >900 MW $3,146 $3,772 $3,879 $2,672 Top TWPE Aluminum

– 51% Aluminum

– 52% Aluminum

– 20% Nitrate/nitrite

– 48% *UWAG’s $/TWPEs in this table include the contribution from source water. As noted earlier, EPA’s sample of Homer City’s bottom ash pond effluent was the only bottom ash transport water sample EPA collected during this rulemaking. This sample, which was analyzed using low

- level methods for metals and mercury, is more representative of bottom ash transport water than the old data EPA used to calculate TWPEs. Because EPA’s nitrate

- nitriteEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 392 concentration is believed to be in error, EPA, as a result, has overestimated the TWPEs and underestimated the $/TWPE, as explained below. Aluminum is the highest TWPE for all sources except EPA’s Homer City data. Aluminum is 51% of the total TWPEs in th e UWAG data, 52% of the total TWPEs in the EPRI PISCES data, and 20% of the total TWPEs in the UWAG Homer City data. EPA’s Homer City data are an exception only because EPA’s Homer City nitrate/nitrite concentration is likely incorrect. 21 The aluminum in the source water more than likely comes from clay minerals in the river soil due to mineral weathering of feldspars.
UWAG also evaluated the bottom ash effluent data in the Form 2C database. Permittees generated most of the Form 2C data using older analyt ical methods with higher detection limits than current methods. For its TWPE calculations, UWAG selected all the bottom ash effluent data (16 outfalls) that were not combined with fly ash transport water, FGD wastewater, or cooling water. Many of these da ta points (40%) were non

- detects. To be conservative, UWAG used the MDL value to estimate TWPEs for pollutants that were not detected in the samples. The resulting $/TWPE for Form 2C bottom ash effluent ranged from $113 to $1,135. If the non

- detect valu es were removed, the TWPEs would be much lower and the $/TWPE much higher. For the Form 2C bottom ash data, the highest TWPE is for sulfides at 93% (using the full MDL value for data less than the MDL) and 89% (using one

- half the MDL for data less than the MDL). As described earlier in these comments, the sulfide is highly unlikely to be present in ash pond effluent. Due to the amount of dissolved oxygen in most effluents, sulfide should not be present. A comparison of the $/TWPE using Form 2C data is in Table 7 below showing the alternative calculations with non

- detects (1) set at the MDL, (2) set at one

- half the MDL, and (3) set at zero. The $/TWPE for both UWAG and Form 2C include the contribution from source water. The $/TWPE for the non

- detect data set at zero range from $3,292 to $33,197, which is similar to the $/TWPE ranges for Homer City, PISCES, and the UWAG bottom ash data.
Table 7: Comparison of UWAG and Form 2C $/TWPEs Using Alternative Calculations for Non
- Detects* 22

MW Range UWAG Data

$/TW PE Form 2C Data

(<MDL=0) $/TWPE Form 2C Data

(<MDL=1/2 MDL) $/TWPE Form 2C Data

(<MDL=MDL) $/TWPE <50 MW $16,492 $33,197 $2,181 $1,135 50

- 100 MW $5,597 $11,267 $740 $385 100

- 150 MW $3,106 $6,253 $411 $214 150

- 200 MW $2,056 $4,139 $272 $142 200

- 300 MW $1,780 $3,583 $235 $123Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 393 MW Range UWAG Data

$/TW PE Form 2C Data

(<MDL=0) $/TWPE Form 2C Data

(<MDL=1/2 MDL) $/TWPE Form 2C Data

(<MDL=MDL) $/TWPE 300

- 400 MW $1,635 $3,292 $216 $113 400

- 500 MW $1,954 $3,933 $258 $134 500

- 700 MW $1,694 $3,409 $224 $117 700

- 900 MW $1,902 $3,828 $252 $131 >900 MW $3,146 $6,332 $416 $217 Highest TWPE Aluminum

–

51% Aluminum

–

30% Sulfide

– 89% Sulfide

– 93%
*$/TWPEs in this table include the contribution from the source water. In short, UWAG’s bottom ash transport water characterization data and the resulting TWPEs are reasonably consistent with all datasets except EPA’s bottom ash transport water database, which includes highly suspect sulfide values and very old, averaged 1982 Development Document data. Since UWAG’s characterization data are reasonably consistent with the EPRI PISCES data and the Homer City data (when corrected for EPA’s likely erroneous nitrite/nitrate value), EPA should use the UWAG characterization data as the basis for its bottom ash transport water TWPE calculations.

19 In the mid

- 1990s, EPRI collected and analyzed settled bottom ash sluice water samples at several sites. EPRI collected its samples at the end of the bottom ash sluice pipe prior to entering the settling pond. See Attachment 30.

20 See Attachments 29, 30, 31, and 32.

21 UWAG collected a split sample of EPA’s Homer City bottom ash transport water sample. UWAG’s nitrite/nitrate value for the sample is 5.92 ppm, while EPA’s is 37 ppm. UWAG’s value is more in line with EPRI’s PISCES values for nitrates/nitrit es in bottom ash transport water, and therefore UWAG believes EPA’s nitrate/nitrite value for Homer City is erroneous.

22 See Attachments 29, 33, 34, and 35. Comment Response: See responses to DCN EPA

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- 394 EPA reviewed the bottom ash transport water data collected from Homer City and determined that there was no supportable reason to exclude this sample fr om the database. Nitrate

- nitrite loadings make up less than 2% of TWPE associated with bottom ash transport water in the final rule. The commenter’s approach for evaluation of cost

- effectiveness of dry bottom ash handling calculates non

- CBI pollutant loa dings using only non

- CBI flow data reported in the Steam Electric Survey. The commenter calculated an industry

- wide median bottom ash transport water flow rate for several capacity

- based model plants. EPA disagrees with this approach. As described in Secti on 4 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) and Section 10 of the TDD, EPA used b oth CBI and non

- CBI plant

- specific wastewater flow rates as reported by the individual plants to estimate plant

- specific pollutant loadings. EPA used data from the Steam Electric Survey to identify those plants that discharge or have the potential to disch arge fly ash or bottom ash transport water. Based on the amount of ash transport water reported to be discharged, EPA calculated plant

- specific ash impoundment discharge flow rates and plant

- specific ash impoundment discharge loadings. EPA determined that use of available, plant

- specific flow data (including data reported to be CBI) is a more accurate approach for estimation of plant

- specific pollutant loadings for fly ash transport water and bottom ash transport water than using non

representative non

- CBI median flow rates based on capacity

- based model plants.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 26 External Review Flag: No External Review E xternal Review Incorporated into Response: No Comment Excerpt: Using its database of primarily old and inaccurate data, EPA then characterized bottom ash transport water estimating pollutant loadings and converting those loadings into TWPEs. Because of a ll the flaws in EPA’s data, however, the resulting TWPEs are also invalid. EPA’s many questionable data points should be removed from the analytical database to reach a more appropriate TWPE analysis. Southern worked closely with UWAG to provide a thorough analysis of the EPA data points for bottom ash transport water and a recalculation of the TWPEs. Our comments below rely on this analysis and are detailed in UWAG’s comments. EPA estimates total industry

- wide bottom ash TWPEs as 2,716,059, while the indus try analysis estimates only 65,342 TWPEs. The reasons for the difference between the two estimates are numerous, as we will explain below.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 395 Table 1 below lists the top 10 contributors to bottom ash transport water TWPEs, according to EPA, and contrasts them with results derived after reviewing EPA’s data. These values are in part lower than EPA’s because the TWPEs attributable to source water have been removed from the analysis. Clearly, EPA should not have attributed source water pollutants to industry faci lities, because under the zero discharge of bottom ash transport water option the source water and its constituents in fact remain in the source waterbody. Table 1: Top Ten Contributors to Bottom Ash Transport Water TWPE Removals

Analytes EPA TWPE/yr UWAG Revised TWPE/yr (source water corrected) Reason for Adjustments

Sulfide (as S) 1,587,993 0 Sulfide analytical methods often result in interferences. The two data points for sulfides that EPA chose are not a sufficient basis for finding that sulfides are present in bottom ash transport water.

Cadmium 207,960 3,413 Removed 1982 Development Document data, which comprised nine of 14 cadmium values.

Thallium 129,352 1,171 Removed two non

- detects higher than 0.0002 since no sample was detected as high as that value.
Mercury 114,951 4,912 Removed 1982 Development Document data, which comprised nine of 14 mercury values.

Tin 107,375 0 All data points were non

detects, so they should not be considered as supporting any pollutant loadings.

Lead 88,343 0 Removed one Form 2C data point containing FGD wastewater and removed 1982 Development Document data. Magnesium 85,379 5,543 Removed one Form 2C data point containing FGDEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 396 wastewater. For the remaining three data points, UWAG subtracted outsource water contributions of magnesium.

Silver 84,389 3,154 Removed one Form 2C data point containing FGD wastewater. Also removed one non
- detect value because no sample was actually detected in that range.

Arsenic 82,222 10,493 Removed one Form 2C data point contai ning FGD wastewater. Also removed nine data points from the 1982 Development Document.
Aluminum 42,440 11,611 Removed one Form 2C data point containing FGD wastewater. Sulfides clearly dominate EPA’s estimates, making up more than 58% of the total bottom ash transport water TWPEs after data points attributable to combined ash discharge ponds are removed. This very large percentage is based on only two data points from the Form 2C database. There are many problems with sulfide test methods. Given these pro blems and EPA’s very small data set, EPA should remove all sulfide data attributed to bottom ash transport water. Also, the more recent EPA sampling program data have been completely overwhelmed by the questionable, very old, and not representative 1982 De velopment Document data. EPA’s use of the sulfide data, in its current form, for the purpose of BAT decision

- making would be considered arbitrary as it does not reflect sound science and is not factually supportable. After sulfides, the next highest contri butor to EPA’s TWPEs is cadmium. EPA’s database contains 14 data points for cadmium, but nine of these are 1970s data from the 1982 Development Document. After removing the 1982 Development Document data from the set, cadmium drops from 207,960 TWPEs to 10 ,240 TWPEs. Adjusting for cadmium in the intake source water, this drops further to only 3,413 TWPEs. For thallium, EPA’s database was adjusted by removing two non

- detect values that were higher than 0.002 mg/L. This is justified because no sample containe d thallium as high as the non

- detect values. This simple adjustment of non

- detects reduces the thallium TWPEs from 129,352 to 2,055. This drops to 1,171 TWPEs after adjusting for source water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 397 For mercury, EPA has 14 data points, nine of which are 1982 Dev elopment Document data. After removing those data points, EPA’s TWPEs drop from 114,951 to 5,189, and to 4,912 when adjusted for source water. As for tin, three of four bottom ash values from Form 2C were non

- detects. The fourth value is from EPA’s Homer C ity sample and is listed as “detected” in EPA’s database, but it was flagged “U” (meaning the result was below the method detection limit) in the Homer City Sampling Episode Report (SER), so it was actually a non

- detect as well. Therefore, the industry ana lysis removed all TWPEs for tin, since EPA has no detected values. For lead, EPA collected 14 data points, including nine from the 1982 Development Document and one from a mixed bottom ash/FGD wastewater discharge point. These data points were removed. Alt hough the remaining data set includes two non

- detects from recent data, the non

detects were used at face value, since all recent samples had relatively low detection limits, and some detected results were higher than the highest detection limits. With the se corrections, the total TWPEs drop from 88,343 to 1,627, or down to zero when adjusted for source water. For magnesium, EPA used four detected data points. However, one data point was eliminated because it included FGD wastewater. For the other three dat a points, the source water concentrations of magnesium were subtracted out and then recalculated the TWPEs. With these adjustments, magnesium TWPEs drop from EPA’s 85,379 to 5,543 TWPEs. For silver, EPA estimated 84,389 TWPEs. The industry estimate was onl y 3,154 TWPEs, after removing a data point that included FGD wastewater and removing one non

- detect value because no sample was actually detected in that range. For arsenic, nine 1982 Development Document values out of a total of 14 data points were remove d. Also removed was a data point containing FGD wastewater. After these corrections, TWPEs for arsenic were reduced from 82,222 to 14,361, or 10,493 after source water adjustments. As for aluminum, EPA used five data points, all from fairly recent data. Ag ain the data point with FGD wastewater was removed and recalculated, resulting in 26,843 TWPEs rather than 42,440. Source

- adjusted, this would be 11,611. Following similar procedures as those outlined above, all the remaining bottom ash discharge data in E PA’s database were reviewed for an additional 24 analytes and made adjustments made for each analyte where necessary to remove 1982 Development Document data and other inappropriate data. Comment Response: See the response to DCN EPA

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- 398 transport water, inc luding discussion of use of 1982 TDD data, use of combined ash impoundment data, source water pollutant contributions, handling of non

- detects, and sulfides.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 34 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 3. EPA Used “MQC” Values at Face Value to Estimate Loadings, Which Has the Effect of Overestimating Loadings As explained above, EPA used combined ash discharge summary data, reported in Table V

- 33 of the 1982 Development Document, to calculate TWPEs associated with bottom ash transport water in combined ash streams. In calculat ing the average concentrations, EPA substituted a value equal to the minimum quantifiable concentration (MQC) when the reported value was less than the MQC. 1982 Development Document at 154. It is not appropriate to use these derived MQC values to repres ent the concentration of pollutants in bottom ash transport water. First, as far as can be determined, the term “MQC” has no specific definition in environmental analytical chemistry, and the 1982 Development Document glossary provides no definition. In general, “quantitation” (or quantification) limits imply a prescribed level of certainty as to quantitative results ( i.e., precision and accuracy) that is separate from, and occurs at a concentration level higher than, a detection limit. However, as discu ssed later in these comments, levels of detection and quantitation were not yet defined for environmental analyses in the 1970s. Presumably EPA meant “MQC” to indicate the results from the tables that had a “less than” (<) indicator before the numeric val ue. But, according to EPA, the original analytical data have been destroyed, and it is impossible to know how this marker was defined by the laboratory that used it. Moreover, EPA has taken values that are not detectable and used them at face value as if they were detections, a practice that essentially manufactures pollutants that are not present. Some of the pollutants, in fact, were not detected or rarely detected in any ash pond sample or else mostly detected only in either fly ash or bottom ash pond s but not both. Using combined ponds can assign fly ash pollutants to bottom ash flows and vice

- versa. Comment Response: EPA notes that for the final rule, it used 1⁄2 the sample specific detection value in place of non

detected values for all data source s. In addition, EPA notes that it has removed the data reportedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 399 in Table V

- 33 from the 1982 TDD from the dataset for the final rule. For further discussion, see response to DCN EPA

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EPA assumes that the commenter is referring to sample

- specific detection levels in its comments about MQCs. EPA disagrees that the sample

- specific detection level cannot be used to estimate pollutant loadings see response to DCN EPA

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- A1, Excerpt Number 72. EPA disag rees that values with a “less than” (<) indicator in the data that EPA used from the 1982 TDD cannot be interpreted as reporting the sample specific detection level for non

- detected values. Where analytical results did not specify if the non

- detect value was a quantitation limit or a method detection limit, EPA considered it reasonable to use the value provided as if it is less than the quantification limit. Practically, whether the value is actually a quantitation limit or the method detection limit would have little effect on the resulting numbers (especially since EPA assigns 1⁄2 of the value). EPA disagrees that its method of interpreting non

- detected values in the data that it used from the 1982 TDD can bias the loadings results high. Despite the asserti on that the 1982 TDD data (which now only includes data from Appendix A from TVA plants) are fraught with elevated non
- detected values that bias the pollutant removal reduction calculations, many of the 1982 TDD data are actually detected values. See DCN E PA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Contro l Number: EPA

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- 400 Comment Excerpt: In using the average bottom ash transport water concentration data from Table V

- 33, EPA misrepresents its own dataset. For example, Table V

- 33 presents three mercury values, as set forth in the table below. Hg, Minimum 0.4 ppb Hg, Maximum 1.7 ppb Hg, Average 0.8 ppb EPA then ignores the minimum and maximum values and uses the average of 0.8 ppb for each of the nine hypothetical bottom ash transport water discharges in the database. EPA uses this approach because it originally derived the average from samples from nine facilities. EPA used the same approach for the combined ash data. EPA used average concentrations from Table V

- 33 for 20 plants. This process, however, causes the 1982 Development Document values to dominate the analytical database. Nine of 14 bottom ash data points are from the 1982 Development Document; 41 of 55 co mbined ash data points are from the 1982 Development Document. Overall, 72% of the data points used to derive TWPEs for bottom ash transport water are from the 1982 Development Document. Since EPA collected only one recent bottom ash transport water samp le (at Homer City) and counts that datum, reasonably, as only one data point, the 1982 data

– which are questionable for all the reasons set out above

– are overweighted in the database. In essence, EPA took the oldest, least reliable data and gave them t he greatest weight. In the 2013 TDD, EPA suggests the TVA and Table V

- 33 data from the 1982 Development Document underestimated concentrations because those ponds “may include other wastestream[s] ( e.g. , cooling water).” 2013 TDD at 10

- 17. There is no do cumentation in the 1982 Development Document whatsoever about what types of wastewaters or cooling waters went into any of the sampled ponds and no basis for the assumption that the 1970s concentrations of pollutants in other types of wastewater would be l ower than that from the ash ponds. In fact, in the 1982 Development Document, EPA arrives at the opposite conclusion for the TVA data: The average was calculated by substituting a value equal to the minimum quantifiable concentration (MQC) when the report ed value was less than the MQC. Thus, the average may be biased upward if there is a significant number of values less than the MQC. Those elements most likely affected are As, Ba, Be, Cd, Cr, Pb, Hg, Ni, and Se. 1982 Development Document at 154 (emphasi s added). The TVA data from Appendix A to the 1982 Development Document indicate that for most of these high

- toxicity metals, 50 to 99% of the results are below the MQC. EPA is making more out of the 1982 Development Document data than is warranted.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 401 Comm ent Response: In response to public comments, EPA expanded its fly ash and bottom ash characterization dataset following proposal. For the final rule, EPA used data collected during the detailed study, industry

- supplied data, and publicly available data sources, including data received as part of this and other public comment submissions, to characterize pollutant discharge concentrations for ash transport water. See Section 6 of the Technical Development Document for the Effluent Limitations Guidelines a nd Standards for the Steam Electric Power Generating Point Source Category ( TDD ) (DCN SE05409) for a description of the characterization data used to identify POCs in fly ash transport water and bottom ash transport water, and Section 10 for a description of ash impoundment data. EPA notes that it did not use the data reported in Table V

- 33 and Table V

- 34 from the 1982 Technical Development Document (1982 TDD) from the dataset for the final rule for the reasons explained in response to DCN EPA

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- A1, Excerpt Number 72. Therefore, comments specific to that data are not relevant for the final rule. The commenter purports that “EPA took the oldest, least reliable data and gave them the greatest weight.” EPA disagrees with the commenter that th ese 1982 TDD data are “questionable” for use in the ash loadings analysis or that they have the greatest weight as the 1982 TDD is just one of the data sources EPA used to characterize ash transport water for the final rule. In addition, because EPA remove d data in Table V

- 33 and V

- 34, the contribution of the 1982 TDD data to ash pond concentrations in the final rule is overstated. For additional discussion of the 1982 data, see response to DCN EPA

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Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- 402 Comment Excerpt: EPA’s Method of Calculating Bottom Ash Pollutant Loading Is Biased High
UWAG conducted a technical review of sections of the 2013 TDD that describe th e method and data EPA used to estimate industry pollutant loadings and TWPEs from ash impoundment effluent. The results of the review are provided in a report by AKRF, Inc. entitled Technical Review of Statistical Methods and Data Used by EPA to Estimate B aseline Ash Impoundment Pollutant Loadings and TWPEs , Attachment 1 of the UWAG comments. A summary of the report’s conclusions is provided below. Over half of EPA’s estimated baseline TWPE for ash impoundment effluent is attributable to EPA’s invalid estim ates of sulfide concentrations in ash impoundment effluent: 59% for bottom ash impoundments, 77% for fly ash impoundments and 55% for combined ash impoundments. Sulfide data from 22 impoundments were included in EPA’s Form 2C compilation

– 2 bottom ash imp oundments, 3 fly ash impoundments, and 17 combined ash impoundments. None of the impoundments for bottom ash or fly ash found sulfides above the quantification limit (reporting limit), and only 3 combined ash impoundment found sulfides above reporting limi ts. The three effluent data points above the reporting limits also have the same amounts, or close to it, as the intake source water. Interestingly, none of the sampling programs that EPA relied on in the 1982 TDD and the 2009 Detailed Study Report analyze d impoundment effluent samples for sulfide. Also, EPA did not analyze for sulfides in their 2010

- 11 Sampling Program during this rulemaking. In addition to the invalid sulfide data, EPA’s statistical formulation for estimating industry baseline TWPE loadin gs is fundamentally biased high (by a factor of 2.41) because the ash transport data demonstrate the following conditions: (1) Pollutant concentrations and ash transport water flows are negatively correlated, (2) The transport water flow rates are highly v ariable among impoundments, and (3) The pollutant concentrations are highly variable among impoundment, the bias is positive and large. In summary, EPA’s inclusion of invalid TWPE estimates for sulfide combined with EPA’s biased method for estimating loadings likely caused EPA’s baseline TWPE estimates to be too high by a factor of six. Comment Response: Many commenters questioned EPA’s identification of sulfide as a POC in bottom ash transport water. As explained in the response to DCN EPA

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- 403 See response to DCN EPA

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### 7. EPA Uses Data from Form 2C in a Way that Artificially Increases TWPEs for Bottom Ash and Fly Ash Ponds
In 2007

- 08, EPA requested that UWAG provide a summary of Form 2C da ta, focusing on FGD wastewater and ash handling characterization data. UWAG, believing that coordination with EPA was best for everybody, asked its members to provide copies of their Form 2Cs. Using those forms, UWAG created a database of information fol lowing instructions from EPA. 9 That database is included in the record as EPA

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- 1237.1. By reviewing Form 2Cs (ranging in date from 1994 to 2007) for 86 facilities, UWAG entered characterization data for outfalls that received bottom ash, fly ash, and FGD wastewater, as requested by EPA. UWAG did not evaluate the data, and EPA did not ask UWAG to do any data evaluation. Form 2C data are not ideal for developing regulations for several reasons. First, since the Form 2C applications that UWAG used are from a long time range (1994 to 2007, or 13 years), it is most likely that analytical methods among the forms vary. Second, most Form 2C data reflect only one or two samples, so the Form is, at best, a “snapshot” of the facility’s discharges on o ne or two days. As such, it does not reflect the ordinary variability of the wastewater for most pollutant parameters. Third, applicants do not have to specify what analytical method or methods they used to analyze the wastewater. Since EPA has more than one approved method for most of the constituents measured at power plants, it is impossible in most cases to know what methods were used. Fourth, when analyzing non

- detects, it is impossible to determine whether the applicants were reporting results that were less than the quantitation limit, less than the MDL (detection limit), or some other value. Without this information, it is impossible to interpret the non

- detects accurately. 10 Despite the lack of specificity in the non

- detects, EPA decided to inte rpret all non

- detects on the Form 2Cs at their full face value. IC&PR, p. 10

- 14. There are many “less than” values in the three Form 2C outfalls EPA selected to represent bottom ash pond discharges. For all threeEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 404 outfalls, concentrations for antimony, b eryllium, cadmium, cobalt, mercury, molybdenum, sulfide, thallium, and tin are below the detection limit. Those data points are difficult to evaluate because the methods used for analysis are not specified on the forms. For these constituents, the averag e of the non

- detects from the Form 2C data far exceeds the average concentrations or even any of the detected values that EPA used in the analytical database. In addition, EPA used seven Form 2C combined fly ash and bottom ash outfalls to calculate TWPEs f or bottom ash discharges. In addition to the loadings being unlike fly ash or bottom ash wastestreams, many of these data points are “less than” values. Four pollutants (beryllium, silver, sulfide, and sulfite) are less than the detection limit in six of the seven combined ash outfalls, and tin is not detected in all outfalls in the EPA database. 11 Also, lead, mercury, nickel, and thallium are less than the detection limit for four out of the seven outfalls.
EPA’s use of detection limit values for the Form 2C outfalls overestimates the average concentrations both for bottom ash and for the TWPEs calculated for the baseline (settling pond discharges). This is a major problem, because many of the non

- detect values reported for the Form 2C data are betwee n 10 and 1,000 times higher than any detected value for that parameter in the EPA database.

9 See UWAG’s database transmittal letter for a summary of EPA’s instructions (June 6, 2008), EPA

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10 EPA acknowledges this problem: “For the other data sets (i.e., EPRI, 1982 TDD, and Form 2C), EPA could not confirm whether the non

- detect results were presented as less than the quantitation limit or less than the MDL (or some other value); therefore, EPA set the non

- detects equal to the value provided.” IC&PR, p. 10

- 14.

11 EPA took one

- half of the tin non

- detect value from its four ash pond SER samples and incorrectly labeled it a detection in its database. Comment Response: EPA disagrees with the commenter that the Form 2C permit data, whic h were provided by the commenter at EPA’s request, are “not ideal for developing regulations” as they are data that were submitted as part of their NPDES permit. Furthermore, as explained in the response to DCN EPA

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- 2C (Application Form 2C

– Wastewater DischargeEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 405 Information) requires that plants applying for NPDES permits “must use test methods promulgated in 40 CFR Part 136” for analysis of sampl es; therefore, EPA deemed that the Form 2C data met the analytical method acceptance criteria. EPA’s acceptance criteria did not require all samples to be analyzed with the same analytical method as long as all methods were approved in 40 CFR Part 136; the refore, EPA did not reject any Form 2C data on the basis of variance among methods used. Uncertainty of Non

- Detect Value: Where analytical results did not specify if the non

- detect value was a quantitation value or a method detection limit, EPA considered it reasonable to use the value provided as if it is less than the quantitation limit. Practically, whether the value is actually a quantitation limit or the method detection limit would have little effect on the resulting numbers (especially since EPA ass igns 1⁄2 of the value). As described in response to DCN EPA

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- detect results as one half the sample

- specific quantitation limit for all analytes in the loadings calculations. See also the response to DCN EPA

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- A1, Excerpt Number 72 in this comment code (Comment Code 15.d) and DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b regarding EPA’s ash characterization data, including the use of Form 2C data and non

- detects in this dataset.
Varia bility in Form 2C Data: The commenter purports that the Form 2C data do not reflect “ordinary variability” of the wastewater discharged because most Form 2C data reflect only one or two samples. EPA disagrees with the commenter that these permit data are n ot representative of typical plant discharge because EPA Form 3510

- 2C (Application Form 2C

– Wastewater Discharge Information) requires that the “time when [the applicant] sample[s] should be representative of [the applicant’s] normal operation, to the ext ent feasible, with all processes which contribute wastewater in normal operation, and with [the applicant’s] treatment system operating properly with no system upsets.” Furthermore, while EPA acknowledges that the pollutant loadings in untreated ash transp ort water may vary with the operational conditions employed at the plant, ash pond impoundments represented by the plants in this dataset have long residence times and effluent from these impoundments is relatively consistent.
The commenter states that “mo st Form 2C data reflect only one or two samples.” This is similarly true of much of the data from the other sources of available data on ash transport water concentrations. EPA did not use the ash pollutant concentration data to estimate numeric limitation s, because the BAT limitation is zero discharge (i.e., “no discharge”) of wastewater pollutants based on dry handling. For the reasons stated throughout this response and elsewhere in the comment response document, and because EPA was determining presence of the pollutant instead of demonstrating a long term average performance level, EPA’s use of the ash characterization data is appropriate and reasonable. EPA did not use the Form 2C dataset to characterize FGD wastewater or to calculate pollutant loadings in FGD wastewater. The commenter also states that for certain constituents, “the average of the non

- detects from the Form 2C data far exceeds the average concentrations or even any of the detected values that EPAEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 406 used in the analytical database.” See re sponse to DCN EPA

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- A1, Excerpt Number 72. The commenter also questions EPA’s use of data from combined fly ash and bottom ash ponds to estimated loadings for bottom ash ponds. See response to DCN EPA

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Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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7.2.2.1 Sulfide values are primarily non

- detects and should be excluded from the benefits calculations, as sulfide is unlikely to be present in bottom ash sluice water. The use of the method detection limit leads to sulfide representing the majority of EPA’s calculated benefits According to EPA’s calculated pollutant reductions, 58% come from from sulfide reduction (Figure 7

- 1 and Table 7

- 5). EPA’s calculati ons are based on very limited data, most of which are not quantified. As described by the Eastern Research Group (ERG) in the memo to the Steam Electric Rulemaking Record [ERG, 2013], the overall pollutant reductions associated with zero discharge of botto m ash sluice water are very dependent on how these non

- quantified, limited data on sulfide in bottom ash water are used. The effects of sulfide data use on EPA’s benefit calculations are summarized in Table 7

- 6.

The data that EPA used to calculate sulfid e reduction are shown in Table 7

- 7. As was shown in Table 7

- 5, most (nearly 90%) of EPA’s calculated pollutant reduction comes from Bottom Ash Only ponds. The EPA calculations for sulfide reduction in such ponds were based solely on twoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 407 data points

—

both of which were non

- detect values (one at a very high detection limit level of 1 mg/L, or 50 times greater than the other). The Combined Ash ponds sulfide data included 17 data points, 14 of which were non

- detects.
The source water used to sluice the bottom as h (“source water”) at each plant from these 17 samples further show sulfides are not added. These source water sulfide values are shown in Table 7

- 7. The average sulfide in the source water (computed using EPA’s methodology) is the same or greater than the average sulfide in the ash sluice waters. And the three detected values in the sluice water are also detected values in the source water (near or above the bottom ash water concentration), which could indicate analytical issues such as interferences with the method. More detail on netting out the source water from bottom ash data is provided in Section 7.2.4. For these reasons, EPRI disagrees with EPA’s use of the detection limit for non

- detect values, as this approach is not based on actual data and has a disproportionately large impact on the calculated benefit.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 408 EPRI does not expect that bottom ash sluice water will contain sulfides in quantifiable amounts. A comparison of the measured bottom ash sulfide concentrations with the sulfide levels in the so urce water indicate very similar measured values. Bottom ash ponds that receive sluice water containing pyrite (coal mill rejects) may get sulfides from the pyrites. Pyrites and bottom ash are often sent to ponds identified by plants as “bottom ash ponds.” Pyrites are the hard solids rejected from the coal pulverizer. These solids are sluiced and can be disposed of in bottom ash ponds. However, pyrites are not part of any bottom ash system. Further, it should be noted that any sulfide typically appears in p yrites as an insoluble particulate (iron sulfide) and, therefore, is not biologically available. Comment Response: As discussed in preamble section V, EPA has revised its cost pollutant loadings and reductions analyses in response to comments received on the proposed rule. Where analytical results did not specify if the non

- detect value was a quantitation limit or a method detection limit, EPA considered it reasonable to use the value provided as if it is less than the quantification limit. Practically, w hether the value is actually a quantitation limit or the method detection limit would have little effect on the resulting numbers (especially since EPA assigns 1⁄2 of the value). As described in response to DCN EPA

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detect results as one half the sample

- specific quantitation limit for all analytes in the loadings calculations. See response to DCN EPA

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- detects in the ash characterization dataset. Many commenters questioned EPA’s identification of sulfide as a POC in bottom ash transport water. As explained in the response to DCN EPA

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Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- 409 Comment Excerpt : 

### 7.2.2 EPA’s calculation approach includes discharges of cadmium, thallium, mercury, tin, and sulfides, which would be reduced with industry
- wide conversion to zero discharge of bottom ash sluice water. These compounds are not expected to be found in bo ttom ash sluice waters in significant quantities.
Table 7

- 5 compares the results of EPRI’s and EPA’s pollutant reduction calculations, using supporting documents from the docket that combine the benefits from Bottom Ash Only ponds and Combined Ash ponds in to a single set. EPA results indicate that sulfides represent 58% of the pollutant reduction loading with zero discharge of bottom ash sluice water

— with cadmium, thallium, mercury, and tin representing over 20%. Unlike EPA’s results, EPRI’s calculations in dicate that cadmium and mercury discharges are minor contributors to the total pollutant reduction, representing about 2,000 TWPE per year each, while thallium is estimated to be 341 TWPE per year, and tin virtually nonexistent. As discussed in this sectio n, EPRI believes that sulfides are unlikely to be present, especially not in a bioavailable form, and that their discharge is significantly overestimated due to the use of detection limit levels in calculations for the non

detects reported for the majorit y of the measurements.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 410Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 411 Comment Response: Many commenters questioned EPA’s identification of sulfide as a POC in bottom ash transport water. As explained in the response to DCN EPA

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- A1, Excerpt Number 72, EPA did not identify sul fide as a POC for the final rule and as such did not include it in its identification of loadings.

Commenter Name: Jay Hudson Commenter Affiliation: Santee Cooper Document Control Number: EPA

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- 412 Externa l Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Another miscalculation of toxic loadings is found in EPA's calculations for mass loadings from ash impoundments, which resulted in a gross overestimate of T oxic Weighted Pound Equivalents (TWPEs). These inaccuracies resulted in corresponding errors for economic analysis calculations (dollars per TWPE) . It is inappropriate to advance a rule with such far reaching consequences on the basis of inadequate sampl ing and invalid calculations.
The characteristics of bottom ash

- inert, angular shaped, granular particles, are very different from fly ash, which is a light, powdery substance . As noted by EPA,bottom ash particles are heavier than fly ash particles and more easily separate from sluice water. 7 More importantly, trace metal concentrations are much lower in bottom ash than in fly ash, a fact that EPA does acknowledge in Section 10.2.2 of the 2013 Technical Development Document (TDD), EPA

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- 002 . It i s interesting to note that in 1980, EPA proposed to reject more stringent regulation of bottom ash water because it found that, at most plants, the priority inorganic pollutants detected in bottom ash sluice water were less tha n the concentra tions detected in the raw or intake water source. 8 Further, also acknowledged by EPA, the flow rates associated with bottom ash transport waster are lower than those associated with fly ash transport. EPA then determined that, on average, pollutant contrib utions from fly ash account for 86 percent of combined ash loading,with bottom ash contributing only 14 percent. 9 Consequently, the pollutant loading from bottom ash is much less than estimated by EPA. As an example, in Table 10

- 7 of the 2013 TDD, EPA ind icates arsenic concentrations of 0.042 mg/I in fly ash transport water and 0.018 mg/I in bottom ash transport water, while information complied by AECOM shows arsenic levels in fly ash to range from 22

- 261 mg/kg and 2.6

- 21 mg/kg in bottom ash 10 roughly 10 times less. This indicates that bottom ash is no more toxic than common soil. Further, our data shows that bottom ash is consistently below detection limits and/or environmental thresholds (e.g., MCLs) for leachable arsenic and other constituents of co ncern.

7 Section 4.3.2 of the 2013 TDD,EPA

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8 45 FR 68328 (October 4, 1980).

9 Section 10.4.2 of the 2013 TDD, EPA

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10 Is Coal Ash Toxic?

- A presentat ion by Lisa Jn Bradley, Ph.D., DABT in Denver Colorado on May 10, 2011. Comment Response: For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised its approach for determining the ash impoundment effluent concentrations. EPA used data collected during the detailed study, indu stry

- supplied data, and publicly available data sources,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 413 including data received during public comment, to characterize pollutant discharge concentrations for ash transport water. See Section 6 of the TDD for a description of the characterization data used to identify POCs in fly ash transport water and bottom ash transport water, and Section 10 for a description of ash impoundment data. See DCN EPA

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- 4655, Excerpt Number 47. EPA disagrees that “the pollutant loading from bottom ash is much less than estimated by EPA” based on the reasons laid out by the commenter. Simply because bottom ash has different properties than fly ash, and that less pollutant loadings are attributed to bottom ash transport water compared to fly ash transport water, does not support the as sertion that EPA overestimated pollutant loadings associated with bottom ash transport, nor that there would not be a need to further control bottom ash transport water discharges compared to conclusions drawn in 1980. In addition, the commenter compares p ollutant concentrations in fly ash transport water and bottom ash transport water that EPA calculated for the proposed rulemaking to results of an AECOM study on fly ash and bottom ash. EPA does not agree that the commenter’s assertion that “bottom ash is no more toxic than common soil” is applicable to decisions regarding the discharge of bottom ash transport water. The final rule restricts discharge of pollutants in bottom ash transport water from steam electric power plants; therefore, EPA only estimated the pollutant loadings in bottom ash transport water and did not quantify the concentrations in bottom ash. EPA updated its estimates of TWPE (cost

- effectiveness) for the final rule. See the RIA. Although not required by the CWA, and not a determining factor for establishing BAT/PSES or BADCT/PSNS, cost

- effectiveness analysis can be a useful tool for describing regulatory options that address toxic pollutants. As presented in preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the selected regulatory option (Option D) have a cost

effectiveness ratio of $134/lb

- eq ($1981). This cost

- effectiveness ratio is well within the range of cost

- effectiveness ratios for BAT requirements in other industries. Also, see responses to comm ent code 6.h.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institu te (EPRI)Effluent Limitations Guidelines and Standards for the St eam Electric Power Generating Point Source Category: EPA’s Response to Public Comments

6-414 Document Control Number: EPA-HQ-OW-2009-0819-4499-A1 Comment Excerpt Number: 72 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:



### 7.1The discrepancy between EPRI a nd EPA estimated pollutant reductions results from differences in data used, and in how non-detect values are treated. The discrepancy in pollutant reductions calcula ted by EPRI and EPA is attributed to the differences in approach shown in Table 7-2. The principal disparity appear s to be in analytical concentrations, as EPRI used the same toxi c weighting factors as EPA and matched EPA’s bottom ash flow rate (157 billion gallons per ye ar for units larger than 50 MW). The pollutant reductions are expressed in TWPE, calculated as a function of three vari ables: bottom ash water quality (concentration of toxics), flow rate of bottom ash sluice water, and the toxic weighting factor (TWF) of each toxic. Details of EPRI’s bottom ash pollutant reduction calculations are available in Appendix D.

EPA calculated pollutant reductions as the sum of (a) pollutant reductions from Bottom Ash Only ponds plus (b) pollutant reductions from a bottom ash component of Combined Ash ponds (ponds that receive both fly and bottom ash) . EPA’s calculated pollutant reductions come primarily (nearly 90%) from Bottom Ash Only ponds (see Table 7-3). Parts (a) and (b) were calculated differently; therefore, EPRI is commenting separately on the two parts of the pollutantEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 415 reduction calculation and focusing primaril y on EPA’s Bottom Ash Only pond data, which account for most of EPA’s estimated pollutant reductions.



### 7.2.1 The old data with very high detection limits used by EPA are not representative of current operations. Results from EPA’s recent sampling campaign at Homer City agree more closely with newer EPRI and industry data. In its bottom ash pollutant reduction estimate, EPRI used bottom ash water quality data collected from industry as part of the EPRI PISCES program and from data aggregated by the Utility W ater Act Group (UWAG). This data set is shown in Appendix D, Table D

- 3. The PISCES data set included bottom ash water sampled before it entered a pond. The samples were allowed to settle for approximately 1 hour before the liquid was collected for analys is. The UWAG data set included bottom ash sluice water samples that were collected in the same fashion as the PISCES samples, and bottom ash effluent data from ponds that do not receive significant amounts of other wastestreams. EPA used pond effluent data from a variety of sources, as shown in Table 7

- 4. Per pages 10

– 16 of EPA’s Technical Development Document (TDD) [EPA, 2013b]: “During this rulemaking effort, EPA relied on publicly available data sources to characterize the effluent stream from ash impoun dments at steam electric power plants; these sources are listed below:

 EPA ash impoundment sampling data from the detailed study [EPA, 2009] [EPRI note: contains one site for Bottom Ash Only ponds, Homer City station];

 Electric Power Research Institute (EP RI) Power Plant Integrated Systems

- Chemical Emissions Study (PISCES) Reports [EPRI, 1997a,b; EPRI, 1998; EPRI, 1999a,b; EPRI, 2000; EPRI, 2001] [EPRI note: contains one site for Bottom Ash Only ponds, PISCES Site F pond];

 Permit application Form 2C data, as provided by UWAG member companies [UWAG, 2008] [EPRI note: contains three sites for Bottom Ash Only ponds], and;

 Development Document for Final Effluent Limitations Guidelines, New Source Performance Standards, and Pretreatment Standards for the Steam E lectric Point Source Category . EPA 440

- 1

- 82

- 029, November 1982 (1982 TDD) [EPA, 1982].” [EPRI note: nine sites were used for Bottom Ash Only ponds; however EPA shows only the average of the sites and then counts this average nine times in computing an aver age of these sites with the sites from the other data sources, if these TDD data include data for a given parameter.]Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 416 It should be noted that for most of the key parameters in the TWPE calculations (such as those for aluminum and arsenic), EPA’s recent sampling results from Homer City agree much more closely with sampling results from EPRI’s PISCES Site F

— and both have lower concentrations than those found in the older data from the Form 2C database and the 1982 TDD. The bottom ash data from Homer City h ave no non
- detect values, showing that the analytical methods were sensitive enough to provide measurable sample values. In contrast, the three data points from the Form 2C database have varying MDLs, which may lead to higher averages when the limit is use d in calculations. Unfortunately the EPA and EPRI data sets do not contain sulfide data, so the two values from Form 2C data (both non

- detects, at high detection limits) cannot be compared.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 417Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 418 Figure 7

- 1 shows differences in TWPE estimates calculated by EPRI and EPA. To help understand the impact of differences in water quality, each pollutant’s concentration was multiplied by its TWF to derive its TWPE. For example, a large difference in water quality between EPA and EPRI for a pollutant with a very sma ll TWF will have a small impact on the difference in the two calculated benefit values. EPA’s water quality values are from the TDD, Table 10

- 7. EPA presents separate data sets for Bottom Ash Only ponds and Combined Ash ponds. EPA then estimates the contri bution of toxics from bottom ash in Combined Ash ponds as a fraction (14%) of the total. EPRI used EPA’s TWF values from Technical Support Document for the Annual Review of Existing Effluent Guidelines and Identification of Potential New Point Source Categ ories [EPA, 2009].

Comment Response: Multiple commenters questioned EPA’s calculation of ash loadings, particularly bottom ash loadings, as it relates to the identification of pollutants of concern (POC) or EPA’s loadings and pollutant reduction analyses. In particular, they questioned the data and assumptions EPA made primarily in determining the average concentration of each pollutant in bottom ash and fly ashEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 419 transport water exiting surface impoundments. These values are used in combination w ith plant

specific bottom ash and fly ash transport water discharge flows to ultimately calculate baseline pollutant loadings for bottom ash and fly ash transport water and pollutant loading reductions associated with zero discharge of pollutants in bottom ash and fly ash transport water for the industry. EPA uses this approach to estimate pollutant loadings and effluent reductions in pounds per year resulting from application of BAT. To the extent that a regulation would lead to reductions for a broader set of pollutants than the POCs, the effluent reduction estimate is an underestimate as EPA generally estimates only the reductions of POCs. EPA also uses the effluent reduction analysis to determine effluent reductions in toxic weighted pound equivalents (TWPE) for what it calls a cost

- effectiveness analysis. See the RIA for a discussion of how EPA calculates TWPE from pounds. For more information on EPA’s methodology for calculating baseline pollutant loadings and reductions for ash transport water, see Section 10 of the Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD) (DCN SE05409) and the Incremental Costs and Pollutant Removals for the Final Effluen t Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832)

. EPA selected dry handling or closed loop technologies as the basis for BAT limitations for bottom ash and fl y ash transport water for units greater than 50 MW and that are not oil

- fired because, as the statute requires, these technologies are available, economically achievable (affordable to the industry as a whole), and have acceptable non

- water quality environ mental impacts. In particular, industry actions demonstrate that dry handling technology or closed

- loop systems for bottom ash transport water is clearly available and economically achievable, since 80% of plants built in the last 20 years have adopted dr y bottom ash handling systems. In addition, EPA found that more than half of the entities that would be subject to BAT requirements for bottom ash transport water are already employing zero discharge technologies (dry handling or closed

- loop wet ash handl ing) or planning to do so in the near future. Similarly, dry handling for fly ash transport water is clearly available and economically achievable. All new generating units built since the ELGs were last revised in 1982 have been subject to a zero discharg e standard for pollutants in fly ash transport water. Based on data collected in the industry survey, EPA estimates that approximately 80 percent of coal

- and petroleum coke

- fired generating units operate dry fly ash handling systems. Since the survey, com panies have continued to upgrade, or announce plans to upgrade, their ash handling systems at generating units. See Section 4.5 of the TDD . Furthermore, as detailed in the RIA, the projected overall impacts of the rule on steam electric generating capacity is minimal as EPA projects a net effect of only two units or one plant might retire due to the costs associated with the final rule. Therefore, even if EPA’s pollutant loadings estimates are higher or lower than estimated, it would not have affected EPA’s selection of the technology basis for BAT for bottom ash transport water or fly ash transport water. Legal Requirements under the Clean Water Act While EPA received comments about its loadings analysis and pollutant reduction estimates, which in turn fee d into the cost

- effectiveness analysis, technically, these analyses are notEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 420 required for BAT. For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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. h. In establishing effluent limitations guidelines at the BAT and BADCT level of control, EPA is to “identify, in terms of amounts of constituents and chemical, physical, and biological characteristics of pollutants, the degree of effluent reduction attainable... .” CWA section 304(b)(2)(A). The D.C. Circuit has held that the very same language in section 304(b)(1)(A) requires nothing more than identifying pollutants [of concern] for regulation and establishing the limits for the pollutants. “We think this is a reasonable response to the statutory requirements and we reject the contention that EPA is also required to furnish data as to the pollution reduction which can be expected from the technologies which comprise the 1977 BPCTCA standard. . . . However we do not believe that the above

- quoted portion of section 304(b)(1)(A) dictates to the Administrator that in adopting one or the other of these two methods he must also estimate how much reduction in pollution will be achieved as a result of the enunciated sta ndard.” American Paper Inst. v. Train , 543 F.2d 326342 (D.C. Cir. 1976). The U.S. Court of Appeals for the Fifth Circuit rejected a challenge to an effluent guideline for the coastal oil and gas point source category based on an allegation that the Agency had a faulty basis for its pollution reduction estimates. There the court held that “We need not address Texas Petitioners’ individual criticisms of the 10

- facility Study because even if every one of the criticisms were accurate we still could not revers e or remand the produced water limit on that basis. The EPA only used the 10

- facility study to estimate pollution reduction benefits that would result from the zero discharge limit. Whatever value such benefit estimates have, they are not required as part of the BAT determination.” TOGA v. EPA , 161 F.3d 923, 936 (5 th Cir. 1998). Nevertheless, EPA’s loading reduction estimates in this rule are reasonable based on the available data in the record. Texas Oil & Gas Ass’n et al v. US EPA , 161 F.3d 923, 935 (5 th Cir. 1998) (“An agency’s choice to proceed on the basis of ‘imperfect information’ is not arbitrary and capricious unless ‘there is simply no rational relationship’ between the means used to account for any imperfections and the situations to which t hose means are applied. Am. Iron & Steel Inst. v. EPA , 115 F.3d 797, 1004 (D.C. Cir. 1997)(citation omitted).””)
Identification of POCs The Clean Water Act section 301(b) directs EPA to eliminate the discharge of all pollutants where it is technologically available and economically achievable (after a consideration of the factors specified in section 304(b) of the Act). The first step in such an analysis is typically to identify POCs

– or the pollutants to be potentially regulated in the effluent guideli ne. 2 To identify POCs, EPA identifies what pollutants are present in the wastestream at some frequency in amounts that are treatable by the technology basis for any candidate effluent limitation or standard. For this rule, any pollutant would be treated b y a zero discharge standard (fly ash transport water/bottom ash transport water/FGMC wastewater). EPA would also look to whether the pollutant is treatable by, for example, chemical precipitation and biological treatment or evaporation (FGD wastewater). EPA refers to this analysis as its POC analysis. In response to comments, EPA reviewed its analysis identifying POCs for bottom ash and fly ash transport water. See TDD Section 6.6.4. EPA reevaluated all of the available data at the time of the proposal a s well as additional data received from public commenters to use in its POC

2 For zero pollutant discharge limitation s and standard, all pollutants (not just POCs) are regulated.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 421 analysis. These data include additional industry

- submitted ash transport water characterization and source water data. These data were collected between November 2001 and March 201 4. EPA subjected all of the available data to its data quality acceptance criteria and updated its analyses accordingly. In summary, EPA’s analysis for the final rule addresses the concerns raised by the commenters related to the identification of POCs for ash transport water in the following ways:

 EPA supplemented the data it used at proposal, and for the final rule, analyzed an expanded dataset;

 For analysis of fly ash transport water for the final rule, EPA used data from sampling locations comprised of at least 75% fly ash transport water and that do not receive any bottom ash transport water; for analysis of bottom ash transport water for the final rule, EPA used data from sampling locations comprised of at least 75% bottom ash transport water and that do not receive any fly ash transport water;

 EPA confirmed that pollutants of concern are all present in at least 10 percent of the plants for which EPA had data on untreated ash transport water samples; and

 EPA confirmed that the energy production process itself is contributing to the quantity of the pollutant present in ash transport water rather than simply the source water by reviewing paired source water and ash transport water, where available, to identify pollutants detected at greater than or equal t o two times the concentration of the source water at 10 percent or more of all plants with paired samples.
Presence . EPA received comments suggesting that the Agency use a particular methodology for identifying POCs other than the one it used in this rule. (For example some argued EPA should identify POCs where the pollutant occurred in three wastewater samples because that was done in another rulemaking.) The POC analysis is not an exact science. EPA uses its best engineering judgment based on the facts at issue for the point source category under analysis rather than using the same formula for each industry. Among the key factors EPA considers are the frequency and amount of times the pollutant is detected, the amount of data the Agency has, and what EP A knows about the industry and what likely pollutants from that industrial process are. For this rule, EPA identified a pollutant as a POC where the pollutant was present in at least one sample at 10 percent or more of the plants of the ash transport wate r samples. This approach is reasonable for this industry, and was adopted over the approach suggested by commenters regarding use of an absolute number of samples (such as the three samples suggested by the commenter) because EPA has a fair amount of data but a varying amount of data for each pollutant. In particular, many commenters questioned EPA’s identification of sulfide as a POC in ash transport water. For the final rule, EPA’s POC analysis did not identify sulfide as a POC. See the TDD for additiona l information. Treatability
. Another key factor is whether the levels of pollutants are treatable by candidate technologies. For ash transport water, all pollutants would be treated by a “zero discharge” requirement based on dry handling/closed

- loop tech nology.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 422 Comparison of Paired Source and Ash Transport Water Data
. Also, where available, EPA compared paired source water data with ash transport water data to estimate whether the pollutant is coming solely from the source water. EPA disagrees with the commenter’s statement that it typically “subtracts minerals or treatment chemicals from its list of POCs when those markers are naturally occurring compounds found in water supply sources” because such subtraction is clearly inappropriate where, as here, E PA has paired data indicating that certain pollutants of concern are present to a greater degree in the ash transport water than in the source water. For this rule, EPA confirmed that the energy production process itself is contributing to the quantity of the pollutant present in ash transport water, rather than simply the source water, by reviewing paired source water and ash transport water, where available, to identify pollutants detected at greater than or equal to two times the concentration of the so urce water in at least 10 percent or more of all plants with paired samples. In this way, EPA confirmed the underlying process ( i.e., burning fuel to generate electricity, with the resulting ash being mixed with water and sluiced to a surface impoundment or other ash disposal mechanism) is contributing to the amount of pollutant present in the untreated wastewater. See TDD Section 6.6, as well as the “Bottom Ash and Fly Ash Transport Water Pollutants of Concern (POC) Analysis Methodology” (DCN SE04745). Where EPA did not have paired source water data, it was unable to perform this analysis and did not make any adjustment to its POC analysis based on source water because concentrations of pollutants in source water can vary considerably from one water body to the next and even within the same waterbody. Estimate of Pollutant Loadings and Reductions Once EPA has identified a pollutant as a pollutant of concern, it typically calculates baseline loadings associated with that pollutant (meaning, the quantity of pollutant discharged by the industry in the absence of any new ELG requirements under consideration). In the case of ash transport water, recognizing that the industry typically treats ash transport water in surface impoundments or handles the ash dry or manages the ash transport water in a closed loop system, EPA estimated baseline loadings for effluent from ash surface impoundments to surface waters. 3 Where industry already handles ash dry or manages ash transport water in a closed loop system, baseli ne effluent loadings are zero. In response to comments on ash transport pollutant loadings and reductions, for the final rule, EPA supplemented its data set so that it consisted of data collected during the detailed study, industry

- supplied data, and data from publicly available sources, including data received as part of public comment submissions, in order to characterize pollutant discharge concentrations for ash transport water. EPA evaluated all of the data available at the time of the proposal, as wel l as additional data received from public commenters to use in its loadings (and reductions) analysis. EPA subjected all of the available data to its data quality acceptance criteria (See DCN SE05567) and updated its analyses accordingly. In summary, as ex plained further below, EPA’s

3 As detailed in Section 10 of the TDD, where ash transport water is discharged to a POTW, EPA adjusted the loadings to account for removals at the POTW.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 423 revised analysis addresses the concerns raised by the commenters related to the estimation of loadings (and reductions) for ash transport water. 4 The following addresses the overarching comments EPA received on the data it use d to estimate average pollutant concentrations for estimating baseline loadings and effluent reductions resulting from zero discharge of pollutants in ash transport water.
Use of 1982 Data : Commenters assert the use of data from EPA’s 1982 Technical Devel opment Document (1982 TDD ) is inappropriate primarily because it is old, much of it is reported as an average of multiple plants, the detection limits at that time were much higher than they are today, the data are not representative for characterizing today’s wastewater discharges , and the Agency no longer has any of the supporting QA/QC documentation for the 1982 Development Document data. Averages : Some commenters noted that some of the data from the 1982 TDD are an average of multiple facilities rather than plant

- specific data and that it is not appropriate to use such data for the final rule. These comments also directed EPA to Appendix A of the 1982 TDD, noting that for some of the averaged data for multiple facilities, Appendix A presents the individual sample results for ea ch of the facilities. EPA agrees that it should not use data that represents averages of multiple facilities for this rulemaking because it has plant

- specific data. As such, for the final rule, EPA applied a data acceptance criterion to screen out such da ta in its loading calculations. The effect of this criterion is that the estimates of loadings and reductions from the final rule do not use the data that represent an average of multiple facilities from the 1982 TDD (Table V

- 33). In addition, EPA did not use the data used from Table V

- 34 of the 1982 TDD, which were plant

- specific average concentrations, and instead used the sample

- specific results presented in Appendix A of the 1982 TDD. Older Data in EPA’s Record is Representative of the Content of Ash Tr ansport Water Discharged to Surface Waters : EPA disagrees that “old” data is inherently not representative and further disagrees that it is not representative for characterizing today’s wastewater discharges of ash transport water from the steam electric industry. EPA notes that the 1982 data used for the final rule is all TVA data. First, simply because data are older does not mean they are not representative. These older data were viewed as sufficiently reliable to be used as the basis for the 1982 eff luent limitations guidelines and that rulemaking, like this one, was subject to notice and comment procedures. As such, while EPA may no longer have the underlying QA/QC data, the 1982 data, contrary to the other data sources, were fully vetted during that rulemaking. Second, in general, in establishing effluent guidelines, the Agency seeks to use as much data as it can but is sometimes limited as a result of the fact that certain pollutants are not yet controlled by regulation or in existing NPDES permits, and dischargers need not provide such data. Given that

4 Unless specified otherwise, where EPA uses the term ash transport water in its loadings discussions, it refers to bottom ash surface impoundments, fly ash surface impoundments, and combined ash surface impoundments, unless specified otherwise.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 424 the composition of coal has not changed in millions of years, boilers have not changed significantly in ways that would affect bottom ash composition since 1982, wet sluicing processes and surface im poundments remain virtually unchanged over the last 40 years and many of the same systems remain in operation, and air pollution controls do not affect the composition of bottom ash, there is no reason to find that the 1982 data do not represent those basi cally unchanged processes today. The same holds true for fly ash, with the exception of additional air pollution controls. Air pollution controls would have an effect on the pollutants present (and their concentration) in the resulting fly ash or would ad d new pollutants and/or increase the concentration of pollutants present in the resulting fly ash. For example, where plants inject activated carbon into the flue gas after combustion upstream of the primary particulate removal system, then the mercury co ntaining carbon (FGMC waste) is often collected and handled in the same way as, and together with, the fly ash.
Non

- Detects in the 1982 Data: Commenters assert the pollutant concentrations presented in the 1982 TDD were measured with older, less sensitive analytical methods and as a result produce higher sample

- specific non

- detect values than more modern sensitive methods. They claim that the non
- detect data in the 1982 TDD reflect higher sample

- specific detection values that are biasing the loadings calculations upward (and the resulting cost

- effectiveness values downward). EPA disagrees that non

- detects in the 1982 data bias the pollutant co ncentrations high. Where there is a non

- detect value in the reported 1982 data, the actual amount of pollutant is unknown because the actual amount could not be detected in the particular sample with the particular analytical method. For the purpose of ca lculating pollutant loadings under this rulemaking, EPA handled non

- detect values in the reported data using its traditional approach: by replacing them with a value of one

- half of the detection value for the observation that yielded the non

- detect result. EPA’s approach for handling non

- detects in this rulemaking is consistent with Clean Water Act assessment and permitting, Safe Drinking Water Act compliance monitoring, Resource Conservation and Recovery Act and Superfund programs, and with previous ELGs. Admittedly, this approach could overestimate or underestimate pollutant loads because the actual quantity of pollutant present in a particular sample may range from zero to the sample

- specific non
- detect value. EPA’s statistical convention, nevertheless, has the policy benefit of encouraging regulated entities to use analytical methods with sensitive detection limits. Despite the assertion that the 1982 TDD data (which, as described above, now only includes data from Appendix A from TVA plants) are fraught with elevated non

- detected values that bias the pollutant removal calculations, many of the 1982 TDD data are actually detected values, as shown in Table 1. Furthermore, for many POCs for which EPA has 1982 data, most of the 1982 data indicate that one

- h alf of the detection value is well within the range of detected values represented in the complete dataset used by EPA to characterize ash transport water. This is true for many of the pollutants of concern (e.g., selenium, arsenic, mercury, and cadmium). For example, for selenium, EPA has 25 data points; 6 of which were detect values and 19 which were non
- detect values for bottom ash effluent from surface impoundments containing bottom ash transport water. Detected values range from 1

- 56 u g/L. Here, EPA values most non

- detects at 1 u g/L. Clearly, this is within the range of the detected values, and in this case, is lower thanEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 425 all of the detected values except one. The same holds true for the other POCs shown in Table 1 including arsenic, mercury, and ca dmium. Table 1. Summary of 1982 TDD Data for Example Pollutants

Use of Data from Ash Impoundments that Contain Other Wastes: Commenters questioned EPA’s use of data to estimate effluent from bottom ash surface impoundments (or fly ash surface impoundments) that are not from surface impoundments exclusively used to treat bottom ash (or

5 Because non

- detect values are specific to the sa mple, EPA presents the minimum and maximum sample specific non

- detect value for the data sets. Pollutant: Arsenic Cadmium Mercury Selenium Type of Ash Impoundment: Fly

Ash Bottom Ash Fly

Ash Bottom Ash Fly

Ash Bottom Ash Fly

Ash Bottom Ash Count of Detections 22 13 20 9 9 7 12 6 Count of Non

- detects 6 13 8 18 18 20 14 19 Minimum ND Value 5 2.5 0.25 0.5 0.5 0.1 0.1 0.5 0.5 Maximum ND Value 2.5 2.5 0.5 0.5 0.1 1.3 1 2

Detected Values (ug/L) 220 60 57 10 12 42 64 56 85 50 52 4 5.6 2.6 30 14 70 15 51 2 1 2.1 25 10 65 15 49 2 0.6 0.8 22 4 65 10 41 2 0.6 0.6 19 2 55 10 38 1 0.4 0.4 18 1 50 8 37 1 0.2 0.2 7 35 5 37 1 0.2 7 23 5 36 1 0.2 4 15 5 30 4 10 5 25 2 10 5 25 2 10 2 25 10 23 10 10 8 7 5 2 5 2 5 1 5 1 5 5Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 426 fly ash) transport water. In particular, they questioned the use of data from impou ndments that also contain, for example, FGD wastewater. EPA disagrees that EPA’s use of such data is inappropriate. EPA used data reflecting industry practices. As steam electric power plants commonly use surface impoundments to treat more than a single wastestream, the vast amount of available data to characterize either effluent from bottom ash (or fly ash) surface impoundments includes at least some contributions from another wastestream such as low volume wastes, FGD wastewater, coal pile runoff, or o ther wastestreams. Depending on the other wastestream (pollutants and pollutant concentrations) and the volume of the other wastestream compared to volume of bottom ash transport water (or fly ash) in the surface impoundment, this could increase or decreas e the concentration of a pollutant in the surface impoundments as compared to an impoundment containing only bottom ash (or fly ash) transport water. In an effort to use much of the available data on ash transport water impoundment effluent while minimizi ng the possible effect another wastestream may have on the measured concentrations, EPA used the following criteria: 6

 Fly ash impoundment: An impoundment/outfall that receives at least 75% by volume fly ash transport water and does not receive bottom ash transport water. The impoundment may also receive other types of wastewater (e.g., low volume wastewaters, cooling water).

 Bottom ash impoundment: An impoundment/outfall that receives at least 75% by volume bottom ash transport water and does not receive f ly ash transport water. The impoundment may also receive other types of wastewater (e.g., low volume wastewaters, cooling water). Furthermore, following application of this criteria, EPA notes that the majority of the data used to estimate bottom ash (or f ly ash) surface impoundment effluent reflect surface impoundments that consist of over 90% bottom ash (or fly ash) as shown below (that is to say six of 10 impoundments for bottom ash and 3 of 4 impoundments for fly ash.). Count of Ash Surface Impoundments Meeting Ash Contribution Thresholds

Surface Impoundment Type Count of Surface Impoundments Meeting Ash Contribution Criteria

>75% >80% >85% >90% Bottom Ash 10 9 9 6 Fly Ash 4 4 4 3 Use of Data from “Combined Ash” Surface Impoundments: In estimating pollutant concentrations in effluent from bottom ash (or fly ash) surface impoundments, EPA also used data from “combined ash surface impoundments.” These are surface impoundments that contain both fly ash and bottom ash transport water and for which the combination of fly ash and bottom

6 EPA applied similar criteria and approaches for estimating pollutant concentrations in combined ash ponds, described below.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 427 ash transport water comprises at least 75% by volume of the total flow. As reported in the industry survey, some surface impoundments contain bottom ash transport water (and no fly ash transport water), some contain fly ash transport water (and no bottom ash transport water) and some contain both fly ash and bottom ash transport water. EPA identified loadings, however, for bottom ash transport water and fly ash transport water as EPA evaluated requirements for bottom ash and fly ash transport water separately. EPA accounted for the pollutant loadings in combined ash ponds or it would have underestimated its identification of loadings. Commenters objected to the use of the data from the combined ash surface imp oundments primarily because they disagreed with the approach EPA used to apportion the data from the “combined ash ponds” to either bottom ash or fly ash surface impoundments. See response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4655, Excerpt Number 71 in Comment Code 13.d for response to comments on EPA’s apportionment of combined ash loadings. Source Water Contribution in Pollutant Loadings : Commenters asserted that “EPA should not have attributed source water pollutants to industry facilities because, if the zero discharge of bottom ash transport water option is selected, the source water and its constituents would remain in the source waterbody.” EPA did not adjust the estimated pollutant loadings or pollutant reductions based on possible source water contributio ns as suggested by commenters. First, as explained earlier in EPA’s identification of POCs, in this final rule, EPA confirmed the underlying process (i.e., burning fuel to generate electricity, with the resulting ash being mixed with water and sluiced to a surface impoundment or other ash disposal mechanism) is contributing to the amount of pollutant present in the untreated wastewater. Second, where a pollutant is identified as a POC, few, if any, of the existing ELGs for other industrial point source adju sted loadings to account for source water. Third, in order to adjust the pollutant loadings based on possible source water contributions, EPA would have needed paired data comparing source water pollutant concentrations to treated effluent pollutant concen trations for a range of process streams, plants, and plant locations. EPA does not have such data, for use in making these calculations. While industry did provide such data for some specific plants, it cannot be used to characterize source water for other plants because concentrations of pollutants in source water can vary considerably from one water body to the next and even within the same waterbody. Even with such data, it would be difficult if not impossible to assess what impact the source water had on the effluent discharges after treatment on a national basis

– and technology

based effluent limitations, such as those established in this rule, are industry

- wide, nationally applicable regulations. EPA notes that 40 CFR Part 122.45(g) allows facilitie s to request, on a case

- by

- case basis, a specific permit adjustment to an effluent standard based on the presence of a pollutant in their intake.
Non
- detects in All Data (not just the 1982 Data): As explained above, for the purpose of calculating pollutant loadings under the final rule, EPA’s analysis first handled non

- detect values in the reported data by replacing them with a value of one

- half of the detection level for the observation that yielded the non

- detect (method 1). The sample

- specific detection values for the ash data vary in sensitivity between samples for a given analyte at individual plants and from one plant to another. This is to be expected since pollutant discharges from ash transport water are currently unregulated (except for TSS and oil and grease) in most NPDES permits, and,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 428 therefore, are not required to use sufficiently

- sensitive EPA

- approved methods. Furthermore, EPA notes that its concern about dissuading dischargers from benefiting by presenting data using methods with higher detec tion values is before the Agency in this rulemaking. For example, for thallium, the highest sample

- specific non

- detect value in EPA’s dataset is industry

- submitted data from 2005 (for fly ash transport water) and 2012 (for bottom ash transport water), not using the most sensitive method. If EPA were to exclude such values, this could encourage the regulated industry to use less sensitive methods for purposes of characterizing pollutant concentrations for pollutants not regulated in their current NPDES permi t because the pollutant is less likely to be detected and identified as a POC. This is particularly relevant for pollutants that have caused documented cases of environmental impacts such as selenium, mercury, and cadmium. In their comments on the proposed rule, commenters raised the general concern that, for some pollutants, the loadings calculations (particularly for bottom ash transport water) were biased high as a result of high non

- detected values in the reported data. The view was expressed that, shou ld the non

- detects fall significantly outside of the range of detected values for such cases, assigning them one

- half of the detection level could result in a misestimate of the averaged pollutant loadings and in the associated cost

- effectiveness of the ru le. To assess this concern and provide further transparency for this rulemaking, in addition to method 1 described above, EPA also implemented a second method of treating non

- detects in order to place an upper bound on the effect of non

- detects on the poll utant loading and cost

- effectiveness calculations. EPA’s decision to incorporate this second approach for this rulemaking reflects the exceptional circumstance in this case where, for less than 0.5 percent of the sample results in the ash dataset (bottom ash, fly ash, and combined ash), there are few detected observations in combination with wide variability in sample

- specific detection values for the non

- detected observations. EPA found that this second method of treatment of non

- detects affects the aver aged pollutant concentrations for 10 out of the 44 analytes, alters pollutant loadings slightly, and decreases identified TWPE loadings and reductions in comparison to method 1. 7 EPA also calculated the cost

- effectiveness for the bottom ash wastestream usi ng the averaged pollutant concentrations derived from method 2, and found, in comparison to method 1, the method 2 analysis changed the cost

- effectiveness value from $314/TWPE to $457/TWPE for bottom ash transport water and it changed the cost

- effectivenes s of the full rule from $136/TWPE to $149/TWPE. For a full discussion of the analysis method and results for bottom ash transport water, see Section 10.2.2 of the TDD and the RIA. Where appropriate in the TDD, RIA, BCA, and certain other documents for t he rule, EPA has reflected the results for pollutant loadings and cost effectiveness of the rule under both of these approaches. EPA’s determination of BAT for bottom ash and fly ash transport water, and the standards and rationale supporting that determi nation, are discussed in Section VIII of the preamble; the differences in loadings and cost effectiveness associated with incorporating this second approach to addressing uncertainty related to non

- detects do not alter that determination.

7 In the preamble to the final rule , EPA presents similar information. However, the information in the preamble is specific to bottom ash transport water only.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 429 Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

- HQ

- OW

- 2009

- 0819

- 4499

- A1 Comment Excerpt Number: 115 External Review Flag: No External Review External Review Incorporated into Response: No
Comment E xcerpt:


### D APPENDIX: BOTTOM ASH HANDLING POLLUTANT LOADING REDUCTION METHODOLOGY
D.1 EPRI’s Calculations of Bottom Ash Transport Water Treatment Benefits In this Appendix, pollutant reductions are referred to as benefits, expressed in toxic

- weighted pounds

- equivalent (TWPE). The overall cost

- effectiveness of pollutant reduction reflects the cost per TWPE removed. 

### D.1.1 Summary The Electric Power Research Institute (EPRI) estimated the benefits (that is, reduction of pollutants) of eliminating discharge of bottom ash (BA) transport water from the steam electric industry. This appendix describes the method for calculation of benefits, the assumptions associated with the benefits calculations, and the estimated incremental benefits of no BA water discharge (that is, “zero discharge”) to the steam electric industry. This is compared to EPA’s estimate of the benefits, as shown in the draft Effluent Limitation Guidelines (ELG). Option 4A of the ELG bans discharge of BA transport water from units greater than 4 00 MW. Because the potential exists for EPA to ban discharge from all units (though this is not in any of the four “preferred” alternatives) the benefit of such a ban is also discussed in this memo.
Table D

- 1 summarizes the “zero discharge” (reductions) be nefits of BA treatment to the industry. The calculations of these benefits are provided below.



### D.1.2 IntroductionEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 430 The U.S. Environmental Protection Agency (EPA) is updating the Steam Electric Power Generating ELG. As part of setting the ELG, EPA conducted a comprehensive information collection request (ICR) and wastewater sampling at power plants. EPA is proposing to revise or establish Best Available Technology Economically Achievable (BAT), New Source Performance Standards (NSPS), Pretreatment S tandards for Existing Sources (PSES) and Pretreatment Standards for New Sources (PSNS) that apply to discharges of pollutants found in bottom ash transport water. Under a preferred alternative for BAT (referred to as Option 4a in the draft proposal), the r ule would establish “zero discharge” effluent limits for all pollutants in bottom ash transport water, with the exception of all generating units with a nameplate capacity of 400 MW or less (for those generating units that are less than or equal to 400 MW, the proposed rule would set BAT equal to the current Best Practicable Control Technology Currently Available (BPT) for discharges of pollutants found in the bottom ash transport water). [EPA, 2013a, page 34436]. 

### D.1.3 Calculation Methodology D.1.3.1 Benef

it Calculation Overview For this analysis, the benefits were defined as the incremental amount of pollutants removed from BA transport water. For each pollutant, the net BA discharge was calculated by subtracting out the source water concentration from the BA transport water concentration. The incremental benefits of “zero discharge” were calculated as toxic

- weighted pound equivalents (TWPE). TWPE factors are used by EPA to express the relative toxicity of pollutants. Use of TWPE provides a relative measure comparing the potential toxicity of different pollutants. EPRI used the average net BA discharge from its data set, estimated BA transport water flow rate, and toxic weighting factors (TWF) published by EPA to calculate total TWPE per year removed. The TW Fs used in this evaluation were published in Technical Support Document for the Annual Review of Existing Effluent Guidelines and Identification of Potential New Point Source Categories [EPA, 2009b]. D.1.3.2 Defined Terms
Terms used in this evaluation incl ude:
Source water

— Water that will be used to transport the bottom ash (before it is in contact with bottom ash).
BA transport water

— Water used to transport bottom ash (during contact with bottom ash). Incremental benefit of “zero discharge”

— The incremental amount removed is estimated by subtracting out the source water pollutants loading from BA transport water pollutants loading. D.1.3.3 Summary of Data Used for the Benefits EvaluationEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 431 As part of the effort to estimate the benefits (that is, reduction of p ollutants) of “zero discharge,” EPRI used BA transport water and source water data from the voluntary submission of data by 20 power plants to the Utility Water Act Group (UWAG), and a set of data from 5 power plants representing samples that EPRI had prev iously collected for the PISCES project in the 1990s. The samples were analyzed for metals 2 , nutrients, and major ions. However, not all samples included all analytes. When data were reported below the method detection limit (MDL) or were not detected, EP RI used one

- half the method detection limit to calculate benefit. In some cases, the concentration of certain pollutants in the source water was higher than the concentration in the BA transport water. For example, the sodium concentration for plant #1 dec reased slightly from 8,200 ug/L in source water to 8,000 ug/L in BA settled water. For the purposes of this estimate, EPRI assumed zero removal rather than “negative removals.” 

### D.1.4 Benefits (Reduction of Pollutants) Calculation
D.1.4.1 Water Flow Rate
EP A estimated that the steam electric industry discharged a total of 157 billion gallons (BG) in 2009 [EPA, 2013a, page 34449]. This value is used in EPRI’s calculations of benefits at this time.
From the data in EPRI’s ICR Sections C3

- 3 and A6

- 1, EPRI estim ated that approximately 54% of the flow rate is from units greater than 400 MW. This 54% was estimated from the unredacted flow rates in EPRI’s ICR database of 213.3 BG per year from all units, and 115 BG per year from units greater than 400 MW.
D.1.4.2 Water Quality Characterization The pollutant concentrations of source water and BA transport water from each power plant are summarized in Table D

- 3 (at end of memo). For each pollutant, the net BA discharge (that is, incremental benefit of “zero discharge ”) was calculated by subtracting out the source water concentration from BA transport water concentration. The mean and median concentration of each parameter was calculated. D.1.4.3 Benefits EPRI estimated benefit (TWPE per year removed) by multiplying the mean and median concentration of each parameter by the assumed flow rate for the industry (157 BG per year from EPA in ELG), and 8.34 factor to convert flow rate*concentration to mass flow rate. The benefits of eliminating bottom ash transport water di scharge are summarized at the end of Table D

- 4 (at end of memo). Estimates for both mean and median are provided. As seen in Tables D

- 3 and D

4, aluminum and arsenic are the primary contributors when represented by TWPE per year.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 432 The average (mean) benefit estimates are summarized in Table D

- 2. These are the values EPRI is presenting in our comments. The median value benefits are even smaller (see Table D

- 4).

2 Aluminum, antimony, arsenic, barium, beryllium, boron, cadmium, calcium, chromium, hexavalent chromium, cobalt, copper, iron, lead, magnesium, manganese, mercury, molybdenum, nickel, selenium, silica, silver, sodium, thallium, tin, titanium, vanadium, yttrium, and zinc Comment Response: For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised its approach for determining the ash impoundment effluent concentrations. As compared to the commenter’s analysis, EPA’s final analysis incorporates the use of one half the detection level for non

- detected va lues, but disagrees with the use of more general flow rate data rather than plant

- specific flow rates used in EPA’s analysis. EPA also evaluated the data submitted by UWAG and the PISCES data against its revised data acceptance criteria, and not all plant data were used in EPA’s final analysis (see DCN SE05567). Finally, EPA used paired source water data, where available, to identify pollutants of concern in bottom ash transport water, but EPA did not adjust the loadings calculations to account for source water data, since source water data were not available on a plant

- specific basis.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 433 See the response to DCN EPA

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- 4655, Excerpt Number 47 for more information about revisions to EPA’s ash c haracterization dataset and approach for calculating pollutant loadings in bottom ash transport water, including discussion of use of 1982 TDD data, use of combined ash impoundment data, source water pollutant contributions, handling of non

- detects, and su lfides.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 45 External Review Flag: No External Review External Review Incorporated into Resp onse: No Comment Excerpt: 

### 10. EPA’s Rounding of Numbers Overstates Mercury Loading Values There are also problems with EPA’s manipulation of its bottom ash transport water data. In some instances, EPA inappropriately rounded up the average values of the data for highly toxic parameters. For mercury in bottom ash transport water, the calculated numeric average of all data is actually 0.00063 mg/L. However, in the IC&PR document, EPA reports the average bottom ash transport water concentration as 0.001 mg /L. IC&PR, p. 10

- 35. All other concentrations in the list of EPA pond averages are reported to at least two or three significant figures, so there is no reason for EPA to round off mercury to 0.001. The 0.00063 mg/L value should be used instead. Because mercury has a high toxic weighting factor (117.1), small overstatements

– such as those caused by rounding

– make a big difference. In this case, the rounding causes a false inflation of the bottom ash transport water concentration and thus misleadingly increases the estimated mercury TWPE in bottom ash transport water by almost 60%. Comment Response: EPA acknowledges that it rounded the bottom ash transport water average concentration of mercury rather than reporting it to the same level of significan t figures as other pollutants in the proposed Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category report. For the final rule, EPA presents the information for all the bottom ash transport water average concentrations for all pollutants to the same level of significant figures in the final Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) . EPA disagrees with the commenter that this rounding errorEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 434 “misleadingly increased the estimated TWPE in bottom ash transport water.” While EPA rounds to a s pecific number of significant figures for presentation in final documentation, the pollutant loadings calculations use the appropriate numeric average of all accepted data; therefore, the estimated mercury TWPE in bottom ash transport water was calculated using the appropriate value at proposal and at final.
For the role of cost

- effectiveness in EPA’s decisions for the final rule, see response to DCN EPA

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Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 78 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Utilizing the results from the bottom ash sampling efforts at Belews Creek and Marshall and the only bottom ash sluice water sample EPA collected, Homer City, Duke Energy calculated an average concentration for bottom ash sluice water. Using this average concentration and the representative flow rates for each station, Duke Energy calculated a TWPE removed for each Duke Energy station under Regulatory Option 4a (zero discharge limit for bottom ash sluice water for units >400 MW) and compared the calculated TWPE removed with EPA’s estimated TWPE re moved. As illustrated in Table 2

- 11 below, EPA has grossly overestimated the TWPE removed under Regulatory Option 4a by approximately 80%. This overestimate is even greater for Regulatory Option 4 and 5 (zero discharge limit for bottom ash transport water for all units). Furthermore, how sulfides are accounted for in the evaluation greatly affects the TWPE removal calculation. Sulfides were not detected in any of the samples above the detection level of 0.05 mg/L. Sulfides, however, accounted for approximat ely 51 to 57% of the total TWPE removed at each station when using the detection level in the calculation. These results clearly illustrate that EPA’s analysis has grossly overestimated the pollutants removed under Regulatory Option 4a.
Table 2
- 11. Summary of Bottom Ash TWPE Removed

Station TWPE Removed

(Assuming Sulfides are present at the Detection Level) TWPE Removed

(Assuming Sulfides are not present) EPA’s Estimated

TWPE Removed

Cliffside 1,292 658 6,590Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 435 Beckjord 2,432 1,240 8,940

Cayuga 814 462 4,490

Marshall 1,607 912 2,000

East Bend 267 152 2,010

Mayo (1) 790 449 6,010

Miami Fort 634 360 9,080

Belews Creek 1,476 838 3,340

Roxboro(1) 2,216 1,258 16,858

Total 11,528 6,329 199,050

(1) EPA’s estimated TWPE removed was re

- calculated using the correct flow rate. Comment Response: For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised its approach for determining the ash impoundment effluent concentrations. See the response toEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 436 DCN EPA

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- A3, Excerpt Number 74 in Comment Code 15.d. EPA reviewed the pollutant removals presented by the commenter; however, EPA was unable to use these data in its final analysis beca use specific information (including the “representative flows” the commenter used for each station, average pollutant concentrations calculated, and calculated baseline pollutant loadings) is absent from the removal estimates. As discussed in the response to DCN EPA

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- A3, Excerpt Number 74, EPA did not include data submitted by Duke for Belews Creek and Marshall for its final loads calculations because the data do not meet the data acceptance criteria because they do not represent actual effluent from an impoundment. Because of these reasons, there are significant differences in the underlying concentration datasets used by the commenter and EPA and EPA cannot completely evaluate and compare the removal estimates. Many commenters questione d EPA’s identification of sulfide as a POC in bottom ash transport water. As explained in the response to DCN EPA

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- A1, Excerpt Number 72, EPA did not identify sulfide as a POC for the final rule and as such did not include it in its ide ntification of loadings.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 69 External Review Flag: No External Review External Review Incorporated into Response : No Comment Excerpt: One of EPA’s preferred options (Option 4a), however, proposes zero discharge (dry handling or closed

- loop process) for bottom ash transport water for units greater than 400 MW based on the installation of a remote mechanical drag sy stem (MDS). Duke Energy contends that EPA’s pollutant removal estimate under this option was based on a flawed data set and EPA’s cost methodology does not reflect the true cost of the technology. EPA’s flawed data set grossly overestimates the average eff luent pollutant concentration for bottom ash transport water and, thus, the pollutant loading from the discharge of bottom ash transport water. This error further created an inaccurate TWPE removal for this option and a misleading dollar per TWPE removed f or the technology. In addition, EPA used incorrect flow data for at least two Duke Energy facilities to calculate the TWPE removed under Option 4a, which further increased the overestimation. Duke Energy collected samples from bottom ash sluice water at tw o facilities, and estimated a TWPE removed under EPA’s Option 4a scenario. This analysis clearly illustrates EPA’s gross overestimation of the effluent concentrations in bottom ash sluice water and EPA’s estimated TWPE removal.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 437 Comment Response:
As disc ussed in preamble section V, EPA has revised its cost and pollutant loadings and reductions estimates in response to comments received on the proposed rule. For the final rule, EPA expanded its fly ash and bottom ash characterization dataset for determinin g the ash impoundment effluent concentrations. See the response to DCN EPA

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- A3, Excerpt Number 74. The commenter asserts that EPA overestimated pollutant removals by using incorrect flow data for two Duke Energy facilities. The commenter identified these plants as Roxboro and Mayo Generating Stations. EPA identified that the five generating units operating at the Roxboro and Mayo Generating Stations converted their wet fly ash and bo ttom ash sluicing systems to dry fly ash and bottom ash handling systems (DCN SE050 6 9). Therefore, EPA did not estimate pollutant loadings or compliance costs associated with these generating units.
EPA notes that it does not calculate cost

- effectiveness ( TWPE) on a plant specific basis. See responses to comment code 6.h.

Commenter Name: Kim Mireles Commenter Affiliation: Luminant Document Control Number: EPA

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- A1 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Baseline loadings for bottom ash transport water were incorrectly calculated. EPA also miscalculated the baseline ash impoundment pollutant loadings. See TDD at 10

- 22,

- 26,

- 27. EPA calculated the average concentration for all the ponds, calculated the average flow for all the ponds, and multiplied the average concentration times the average flow to get an average loading for all ponds. Instead, EPA should have weighted e ach pond's concentration by that pond's flow by multiplying the concentration for each pond by the flow for each pond and then averaging all the pond loadings. The product of averages is not the same as the average of products, which is the correct way to calculate average loadings. Where pollutant concentrations correlate negatively with flow, EPA's method produces estimates that are biased high.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 438 Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 4 in Comment Code 6.f regard ing the commenter’s statement that EPA’s method for estimating pollutant loadings is “biased high.”

Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Exc erpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: USEPA's Determination of Bottom Ash Transport Water TWPEs is Flawed As detailed in UWAG's comments, USEPA has not collected enough b ottom ash transport water samples to justify new, more stringent limitations. During its 68 power plant site visits, stretching from December 2006 to February 2013, USEPA collected only one sample of bottom ash transport water

- in August 2007 at the Homer City power plant in Pennsylvania. Over the next six years until the proposed rule was published, USEPA never collected another bottom ash transport water sample, although it visited dozens of plants that sluiced bottom ash. One sample is not enough to re gulate an industry. While USEPA relied upon other sources of data and methodologies, these data and methods had significant shortcomings including:

 Data from combined ash ponds (i.e., ponds receiving both bottom ash and fly ash transport water) to characterize bottom ash transport water. It is well recognized in the industry that these two wastewater streams are not similar;

 USEPA estimated the contribution of bottom ash transport water and fly ash transport water to the combined ash pond TWPEs;

 To calculate industrywide TWPEs for bottom ash alone, USEPA calculated TWPEs for the ''true"bottom ash transport water ponds and then added the percent of TWPEs from the combined ash ponds attributable to bottom ash transport water according to EPA's calcula tions. In addition, as detailed in UWAG's comments , both the data in the 1982 Development Document and the Form 2C data used for both ''true" bottom ash ponds and combined ash ponds are problematic for several reasons and do not support the proposed strin gent technologies potentially required for bottom ash transport water specified in Options 4, 4a and 5.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 439 As a result of these defects, USEPA's overall TWPE values for bottom ash are grossly overstated . USEPA estimates total industry

- wide bottom ash TWPEs a s 2,716,059, while UWAG calculates only 65,342. Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 47 in Comment Code 15.d. EPA also disagrees that it does not have en ough data on bottom ash transport water to justify the final limitations based on dry handling or closed

- loops systems. The commenter tries to support its statement by saying EPA collected only one sample. Yet the commenter failed to identify all of the o ther sources of data EPA has for bottom ash transport water. For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised its approach for determining the ash impoundment effluent concentrations. EPA used data collected during the detailed study, industry

- supplied data, and publicly available data sources, including data received during public comment, to characterize pollutant discharge concentrations for ash transport water. See Section 6 of the TDD for a description of the characterization data used to identify POCs in fly ash transport water and bottom ash transport water, and Section 10 for a description of ash impoundment data.

Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute ( EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 47 External Review Flag: Statistics External Review Incorporated into Response: No Comment Excerpt: EPA’s cost effectiveness analysis for bottom ash transport water technologies is unsound because the underlying analyses are flawed. EPA’s bottom ash pollutant loading calculations suffer from methodological biases. EPA’s assessment of bottom ash TWPE also has significant data and methodological deficiencies. As they did for FGD wastewaters, EPRI and UWAG developed their own TWPE estimates addressing the significant data and methodological flaws identified in EPA’s TWPE. The results of this analysis are telling. Whereas EPA estimates total industry

- wide bottom ash tran sport water TWPE as 2,716,059, UWAG estimates it as 65,342. More specifically, EPA’s estimates of industry

- level ash impoundment pollutant loadings are severely biased high due to the formulation EPA chose for calculating loadings. EPA’s formulation is bas ed on the product of averages. As described in detail in the UWAG Comments, this formulation will generate estimates that are biased high if pollutantEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 440 concentrations are inversely correlated with ash transport flow rates. The bias will be severe if the c oefficient of variation for pollutant concentrations and the coefficient of variation for transport flow rates are high among impoundments. All of these conditions appear to be present in the bottom ash impoundment loadings data. Furthermore, this issue o f bias, due to EPA’s method for estimating loadings, may extend beyond bottom ash impoundment pollutant loadings to any of EPA’s estimates of pollutant loadings that were calculated as the product of averages.

Comment Response: See the response to DCN EPA

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For the role of cost

- effectiveness in EPA's decisions for the final rule, see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6. h. See response to DCN EPA

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- 4655, Excerpt Number 4 in Comment Code 6.f regarding alleged bias associated with EPA’s method for estimating pollutant loadings.

Commenter Name: Dennis Leonard Commenter Affiliation: DTE Energy Company Docume nt Control Number: EPA

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- A2 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The ELG proposal includes a ban on the discharge of bottom ash sluice wate r at units greater than 400 MWs, effectively requiring the complete recirculation of sluice water for units greater than 400 MW. The justification for this proposed ban is based on a severe mischaracterizations of the pollutant concentrations associa ted with bottom ash sluice water. During the data collection process which preceded this proposal, EPA gathered effluent data from only a single bottom ash basin containing only bottom ash sluice water. EPA gathered effluent data on many other basins whi ch contained both bottom ash and other wastewater, but made no effort to sort out the pollutant contribution from only bottom ash sluice water. There were negligible pollutant concentrations associated with the single basin EPA sampled which only contained bottom ash sluice water. The absence of any significant pollutant concentrations from the single bottom

- ash

- only basin is not surprising, since bottom ash is an inert material that differs markedly from other coal combustion residuals. Bottom ash is a gla ssy material, and unlike fly ash does not have any condensable pollutants adsorbed onto its surface. The proposed ELG mischaracterized the pollutant concentration of bottom ash sluice water in at least 3 fundamental ways.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 441  As described above, the pollutants in mixed waste basins were wrongly associated with bottom ash.

 The proposed ELG also used effluents that were comprised solely of fly ash sluice water to estimate bottom ash sluice water based on an incorrect assumption that fly ash and bottom ash have id entical pollutants. Comment Response: EPA disagrees with the commenter that EPA mischaracterized the pollutant loadings of bottom ash transport water. As discussed in preamble section V, EPA has revised its cost pollutant loadings and reductions estimate s in response to comments received on the proposed rule. See response to DCN EPA

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- A1, Excerpt Number 14 regarding EPA’s collection of “a single bottom ash sample”.
Also See DCN EPA

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- 4655, Excerpt Number 47 for more information about revisions to EPA’s ash characterization dataset and its approach for calculating pollutant loadings in bottom ash transport water.

Commente r Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into Response: No
Com ment Excerpt: EPA’s estimated pollutant reductions for zero discharge of bottom ash transport water appear to be high by a factor of 10 because of the following differences:

o Differences in data used; the old data with very high detection limits used by E PA are not applicable to current operations.

o EPA’s calculation approach for the use of non

- detect values, that is, using the value of the method detection limit.

o EPA’s calculation approach includes reductions in discharges of cadmium, thallium, mercury, ti n, and sulfides with industry

- wide conversion to zero discharge of bottom ash sluice water. These compounds are not expected to be found in bottom ash sluice waters in significant quantities.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 442 o The source water contribution should be subtracted to properly a ccount for the bottom ash contribution to pollutants, and therefore the calculated pollutant reductions. Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 31 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: One sample is not enough to regulate an industry, and EPA turned to other sources of data, but these data had shortcomings. First, EPA added data from combined ash ponds (i.e., ponds receiving both bottom ash and fly ash transport water, as well as other wastestreams) to characterize bottom ash transport water. EPA’s analytical database (EPA

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- 0733.1) contains 14 data sets of bottom ash transport water effluent and another 55 data sets of combined ash pond effluent.
The table below lists the sources of EPA’s data from bottom ash

- only ponds: EPA’s 2007 Homer City sample 1 data set

1982 TDD, Table V

- 33 EPA averaged 9 data sets of metal concentrations derived from DMR data collected by various EPA regional offices Form 2C Database 3 outfalls EPRI Water PISCES Field Study 1 data set, Site FEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 443 Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 52 External Review Flag: No External Review External Re view Incorporated into Response: No Comment Excerpt: To calculate TWPEs for bottom ash transport water, EPA used concentrations of pollutants in bottom ash transport water from four sources:

 one bottom ash effluent sample from Homer City power plant (collected during EPA’s Detailed Study sampling program, August 2007);

 EPRI’s PISCES Report, Site F, which includes three 24

- hour composite samples of bottom ash pond effluent data;

 extensive data from the 1982 Development Document (discussed above); and

 a s discussed earlier, EPA also used data from the Form 2C database, which includes permit application data from several power plants from 1994 to 2007. EPA used three bottom ash effluent samples from this database. As discussed in these comments, many of t he data points EPA used to characterize bottom ash transport water are invalid and do not reflect typical bottom ash transport water. UWAG’s data are more recent and were measured with up

- to

- date methods. UWAG’s data compare well to EPA’s Homer City data and to EPRI’s PISCES bottom ash sluice data, while EPA’s own characterization data, taken as a whole, do not. Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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EPA’s Response to Public Comments

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- 444 Memorandum (DCN SE04745), for more details on EPA’s determination of POCs for ash transport water. EPA notes that, where UWAG’s data met EPA’s data acceptance criteria, it incorporated it into its final analysis.

Comm enter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 28 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The industry analysis also adjusted the TWPEs by accounting for parameters present in the source water. Estimates of source water values came from the UWAG bottom ash characterization database. The average concentration for each pollutant was calculated , after discarding high non

- detect and high outlier results, to determine a minimum concentration value of the constituents found in the source river water. See UWAG’s comments and Attachment No. 6 of its comments. As a result of these adjustments, total T WPEs for bottom ash transport water of 65,342 were calculated, while EPA’s estimate is 41.5 times higher, an astronomical and unrealistic 2,716,059 TWPEs. Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings and r eductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Ge neration, LLC. Document Control Number: EPA

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EPA’s Response to Public Comments

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- 445 Comment Excerpt: Furthermore, the differences in these waste streams are illustrated by EPA’s comparison of the average pollutant loadings in the evaluated waste streams in its Environmental Assessment for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Categor y. One point of comparison, the toxic weighted pound equivalent (TWPE), showed significant differences between average plant fly ash discharges and bottom ash discharges. 17 For example, the TWPE of arsenic in the average plant fly ash discharge was 1,940 lb

- eq/yr compared to 279 lb

- eq/yr in bottom ash discharge. The TWPE of mercury in the average plant fly ash discharge was 1,010 lb

- eq/yr compared to 390 lb

- eq/yr in bottom ash discharge. And the TWPE of selenium in the average plant fly ash discharge was 289 lb

- eq/yr compared to 50.2 lb

- eq/yr in bottom ash discharge. 18

17 See EPA, Environmental Assessment for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category, 3

- 19 (Table 3

- 4). 18 See id.

Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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Commenter Name: Elizabeth E. Aldr idge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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D. EPA’s Overall TWPE Values, in Light of Data and Methodology Issues, Are Grossly Overstated for Both Fly Ash and Bottom Ash Pond DischargesEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 446 EPA estimates total industrywide bottom ash TWPEs as 2,716,059, while UWAG calculates only 65,342. The reasons for the difference between the two estimates are numerous, as we will explain below. Comment Response: See the response to DCN EPA

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Commenter Name: Paul Chu Commenter Affilia tion: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 77 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Eliminating the sul fide data would reduce the calculated pollutant reduction by half. This approach can be justified by the lack of usable data and the lack of reasonable basis for sulfide to be present in bottom ash water. Comment Response: Many commenters questioned EPA’ s identification of sulfide as a POC in bottom ash transport water. As explained in the response to DCN EPA

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- A1, Excerpt Number 72, EPA did not identify sulfide as a POC for the final rule and as such did not include it in its identific ation of loadings.

Commenter Name: Ron Shipman Commenter Affiliation: Georgia Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Re sponse: No Comment Excerpt: EPA Failed To Collect Sufficient, Current, Valid Data To Support Its TWPE Determination For Bottom Ash Transport Water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 447 The data that EPA used to support its determinations of the TWPE for bottom ash transport water is not sta tistically valid. During EPA's numerous plant site visits, EPA only collected one sample of bottom ash transport water. Georgia Power believes, and scientific convention supports, that one sample is simply inadequate to characterize the entire coal

- fired power plant industry. Many factors

- including boiler design, coal type, coal variations, and the size of treatment equipment and settling ponds

- could affect ash pond water characteristics. Proposing a completely new and costly technology to handle botto m ash for an entire industry based on one sample has no statistical basis, and as such, the characterization of bottom ash transport water in the 1982 rulemaking (that dry

- handling is unjustified) is more valid. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 72 and DCN EPA

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- 4655, Excerpt Number 47. Also see response to DCN EPA

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- A1, Excerpt Number 14. For the reasons stated in preamble sections VIII.C and E, and elsewhere in the reco rd, EPA has determined that dry handling for control of fly ash transport water discharges is technologically available and economically achievable for units that are greater than 50 MW and that are not oil

fired; therefore, the final rule establishes zero discharge BAT limitations and PSES based on this technology for fly ash transport water. As described in preamble sections VIII.D and F, EPA also determined that dry handling for control of fly ash transport water discharges is well

demonstrated and pres ents no barrier to entry for all new sources; therefore, the final rule establishes zero discharge NSPS/PSNS based on this technology.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 53 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: UWAG anticipated this void of current data related to bottom ash transport water. Accordingly, it developed relevant data for this waste stream over the past few years, which are provided as an attachment to the association’s comments. Unlike EPA’s jumbled data, UWAG properly subtracts TWPEs attributable to naturally occurring minerals in water supply sources and further limits its analysis to data of only non

- recycled, isolated bottom ash wastewater utilizing sluice water originating from a source waterbody. UWAG’s TWPE numbers are therefore considerably lower and provide a more representative depictio n of the kind and amount of constituents found in this waste stream, and PowerSouth endorses these data, as well as the association’s analyses based thereon.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 448 Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings an d reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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- A1, Excerpt Number 50 in Com ment Code 6.a. Also see response to DCN EPA

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- A1, Excerpt Number 14. EPA notes that, where UWAG’s data met EPA’s data acceptance criteria, it incorporated it into its final analysis.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 38 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: There are many reasons why t he EPA $/TWPE estimates do not reflect the true cost of dry bottom ash retrofits. Many of these have been highlighted in the UWAG comments 27 and include reliance on a single bottom ash transport water sample, use of data from the 1982 Development Document, which are not representative of today’s bottom ash wastewaters and were obtained using outdated analytical techniques, the use of questionable Form 2C data, the use of sulfide data that are likely “false positives,” and the inappropriate rounding up of mercury data. AEP endorses the UWAG comments and urges EPA to carefully consider them.

27 UWAG ELG Comments, September 20, 2013. Comment Response: As discussed in preamble section V, EPA revised its cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a. Also see response to DCN EPA

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- A1, Excerpt Number 14.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 449 For the role of cost

- effectiveness in EPA’s decisions for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in C omment C ode 6.h.

Comm enter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 62 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA used invalid data to calculate bottom ash loadings and TWPEs, including the 1982 Development Document data and the Form 2C data, especially the sulfides data. Comment Response: As discussed in preamble section V, EPA revised its co st pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a. Many commenters questioned EPA’s identification of sulfide as a POC in bottom ash transport water. As explained in the response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d, EPA did not i dentify sulfide as a POC for the final rule and as such did not include it in its identification of loadings.

Commenter Name: John C. Pozzo Commenter Affiliation: Ameren Energy Resources Company Document Control Number: EPA

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- A1 Com ment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Furthermore, we find it of interest that the EPA apparently utilized data from a single facility to conclude that bottom ash transport water discharge has substantial environmental impact. Based on these considerations it does not appear that EPA has developed the necessary record to satisfy the threshold justification for the proposed bottom ash management revisions.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 450 Comment R esponse: EPA disagrees that it based its analysis of bottom ash transport water on data from only one plant, either at proposal or for the final rule. As discussed in preamble section V, EPA revised its cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a.
Also see r esponse to DCN EPA

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- A1, Excerpt Number 14.

Commenter Name: Michael G. Cashin Commenter Affiliation: Minnesota Power (MP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 23 External Review Flag: No Exte rnal Review External Review Incorporated into Response: No Comment Excerpt: EPA proposed BAT and treatment goals for bottom ash are based on risk assessments formulated from samples of fly ash. FR page 34455. Minnesota Power supports the comments UWAG, E EI and EPRI that fly ash constituents differ significantly from bottom ash constituents and subsequently, that the use of fly ash data as a basis for rule

- making related to bottom ash is inappropriate. Comment Response: See the response to DCN EPA

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- A2, Excerpt Number 21.

Commenter Name: Michael G. Cashin Commenter Affiliation: Minnesota Power (ALLETE) Document Control Number: EPA

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- A2 Comment Excerpt Number: 21 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 16. EPA proposed BAT and treatment goals for bottom ash are based on risk assessments formulated from samples of fly ash. FR page 34455. Minnesota Power supports the comments UWAG, EEI and EPRI that fly ash constituents differ significantly from bottom ash constituentsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 451 and subsequently, that the use of fly ash data as a basis for rule

- making related to bottom ash is inappropriate. Comment Response: EPA disagrees with the commenter that EPA establishes BAT for bottom ash transport water “based on risk assessments from samples of fly ash.” For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised its approach for determining the ash impoundment efflue nt concentrations. EPA used data collected during the detailed study, industry

- supplied data, and publicly available data sources, including data received from the commenter during public comment, to characterize pollutant discharge concentrations for ash transport water. See Section 6 of the TDD for a description of the characterization data used to identify POCs in fly ash transport water and bottom ash transport water, and Section 10 for a description of ash impoundment data. See section 12 of the Increm ental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) for more information on EPA’s revised approachfor deter mining pollutant concentrations used in calculating baseline pollutant loadings and pollutant reductions under the final rule. See the response to DCN EPA

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Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Numbe r: EPA

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- A1 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: bottom ash transport water control technologies beyond impoundment are not supported by s ufficient data and analysis. We believe there are errors in the bottom ash data used for this rulemaking which overestimate pollutant concentrations and loadings in bottom ash water. Comment Response: As discussed in preamble section V, EPA revised it s cost pollutant loadings and reductions estimates in response to comments received on the proposed rule. See responses to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 452 See also the response to DCN EPA

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- A1, Excerpt Number 3 and preamble section VIII for discussion of why surface impoundments are not BAT for discharges of bottom ash transport water from all exi sting steam electric generating units.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 453 16. Zero Discharge Bottom Ash
Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 36 External Review Flag: No Exte rnal Review External Review Incorporated into Response: No Comment Excerpt:
EPA’s $/TWPE for MDS or RMDS Retrofits for Bottom Ash Based on EPA’s data and costs, described above, EPA estimates a cost of $106 per TWPE for zero discharge of bottom ash trans port water for all coal units greater than 50 MW. For Option 4a, which includes zero discharge of bottom ash transport water for coal units greater than 400 MW, EPA estimates $99 per TWPE. EPA

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UWAG’s Cost
- Effectiveness Analysis for Bo ttom Ash Instead of relying on EPA’s flawed bottom ash transport water characterization data, UWAG collected 21 bottom ash transport water characterization data sets from its members. Southern endorses UWAG’s characterization study. The results are documen ted in UWAG’s comments and Attachment 7 to its comments. UWAG’s data are more recent than EPA’s and were measured with up

- to

- date analytical methods. To analyze the cost effectiveness of dry or closed

- loop bottom ash retrofits, UWAG used its own characteri zation data and median flow rates from the 2010 ICR database to calculate TWPEs. To estimate capital costs, UWAG used 13 data points it collected from members based on actual costs and conceptual engineering design estimates of retrofits, as shown in the t able below. Only one of the 13 data points was adjusted to 2012 dollars. The other 12 data points either occurred or were estimated between 2009 and 2012, and therefore these costs were not adjusted. Comment Response:
The final rule establishes BAT limitations and PSES applicable to discharges of bottom ash transport water based on dry handling or closed

- loop technologies, except for discharges from generating units smaller than or equal to 50 MW or units that are oil

- fired. As described in preamble Section VIII, EPA selected dry handling or closed loop systems as the technology bases for control of bottom ash transport water discharges because they are available, they are economically achievable (i.e., affordable) for the industry as a whole, and th ey have acceptable non
- water quality environmental impacts. For the reasons explained in preamble section VIII.C.3, EPA did not select surface impoundments as the BAT basis for control of bottom ash transport water discharges from all existing steam elect ric generating units. Most importantly, they would not result in reasonable further progress toward the national goal of eliminating theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 454 discharge of all pollutants, particularly toxic pollutants (see CWA section 301(b)(2)(A)). See also response to DCN E PA

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- A1, Excerpt Number 3. See response to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a and the “Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum” (DCN SE04745) for more information on the identi fication of pollutants of concern for bottom ash transport water. See the response to DCN EPA

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EPA evaluated the data submitted by UWAG against its acceptance criteria outlined in the Quality Assurance Project Plan for the Steam Electric Effluent Guidelines Rulemaking (DCN SE02951) and accepted some of the data for use in identifying pollutants of conce rn (POCs) and for use in the loadings calculations (see DCN SE05567). EPA did not accept data, for example, where the samples do not represent actual effluent from a surface impoundment. In some cases, UWAG submitted simulated effluent that settled in the sampling container prior to analysis. EPA excluded sample results that attempted to simulate surface impoundment effluent, using samples that were collected prior to the ash pond and settled in a sampling container prior to analysis. EPA’s approach is also supported by other analyses conducted by UWAG, as documented in their November 2014 letter to EPA, in which it presented a comparison of settled sluice pipe samples to near

- effluent discharge point samples and acknowledged that “whether viewed from the in dividual facility perspective or as averaged across the six facilities, it is clear that the settled bottom ash sluice pipe samples substantially overestimate bottom ash effluent pollutant loadings” (DCN SE05597). EPA did use all simulated effluent analyti cal data in a sensitivity analysis for pollutant loadings. See the response to DCN EPA

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EPA notes that the cost

- effect iveness of the final rule is within the range of cost

- effectiveness values for ELGs established in other industries. See preamble section XV. For the role of cost

effectiveness in EPA’s decision for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: J. Michael Brown Commenter Affiliation: Ohio Valley Electric Corporation (OVEC) Document Control Number: EPA

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- A2 Comment Excerpt Number: 5 External Review Flag: No Exter nal Review External Review Incorporated into Response: No Comment Excerpt:Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 455 OVEC supports EPA’s assertion that units which produce less than 400 MW should be set equal to the Best Practicable Control Technology Currently Available (BPT); however, due to t he low level of pollutant loading in bottom ash transport water, the $/TWPE does not appear to be cost

effective at any MW level. Consequently, we ask that the EPA re

- evaluate the economic justification using current data and accurate flow profiles as we believe it will show that dry bottom ash handling is not cost

- effective for units larger than 400 MW as well. Comment Response: See response to DCN EPA

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- loop systems should only apply to units above 400 MW, with limitations based on surface impoundments for those units that are smaller than or equal to 400 MW. See the response to DCN EPA

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- A1, Excerpt Number 40 in Com ment Code 5.c regarding the 400

- MW threshold.

Commenter Name: Chas Spell Commenter Affiliation: Arizona Public Service Company Document Control Number: EPA

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- A2 Comment Excerpt Number: 4 External Review Flag: No External Review Ext ernal Review Incorporated into Response: No Comment Excerpt: UWAG performed its own analysis of $/TWPE for bottom ash and found ranges from $1,730 to $17,446 (in 1981 dollars). Even the low

- end of the UWAG range exceeds the cost per TWPE ceiling that EPA has traditionally used for effluent guidelines. As EPA points out, its BAT cost

effectiveness range is less than $1/TWPE to $404/TWPE. 78 Fed. Reg. at 34,504 col. 1

- 2. UWAG’s range is 4.3 to 43 times greater than EPA’s $404/TWPE. By EPA’s own standards, then, dry handling or closed

- loop retrofit of bottom ash is not cost

- effective. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Co ntrol Number: EPA

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- A1 Comment Excerpt Number: 11Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 456 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For bottom ash transport water, one of EPA’s preferred options would require dry handling or closed

- loop systems for units greater than 400 MWs. However, EPA has not shown any treatment beyond settling ponds to be cost

- effective. The industry analysis of c ost effectiveness, which uses more recent characterization data, finds that requiring dry handling of bottom ash for any units is not cost effective. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 29 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
After co rrecting EPA’s database to more accurately reflect today’s bottom ash transport water discharges, it is clear there is no scenario under which it is cost effective for EPA to further regulate bottom ash transport water. Southern supports UWAG’s analysis of EPA’s analytical database and urges EPA to acknowledge that regulation of bottom ash transport water is not cost effective, as discussed in the following sections. Comment Response: See response to DCN EPA

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Commenter Name: Paul Nazaryk Commenter Affiliation: BHP Navajo Coal Company (BNCC) and San Juan Coal Company (SJCC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 457 Comment Excerpt: As stated by the Utility Water Act Group (UWAG),the cost associated with retrofitting bottom ash handling systems at existing power plants to meet Option 4a or the other options is not cost effective. This determination is based upon a preliminary analysis of bottom ash toxic weighted pounds equivalent (TWPEs) removed, the required capital costs, and removal costs per TWPE. As UWAG states, the costs range from $2,214 to $39,596 in 2012 dollars per pound rem oved. Such costs cannot be justified at existing power plants. See Letter from Donna B. Hill, UWAG to the Cortney Higgins and James A. Laity of the U.S. Office of Management and Budget (OMB), in which EPA was copied (April 1, 2013). Comment Response:
See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Ron Shipman Commenter Affiliation: Georgia Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag: No Externa l Review External Review Incorporated into Response: No Comment Excerpt: Georgia Power supports UWAG's cost

- effectiveness analysis. To analyze the cost effectiveness of dry handling, UWAG used its own characterization data and median flow rates from the industry questionnaire (ICR) database to calculate TWPEs. To estimate capital costs, UWAG used 13 data points it collected from members based on actual c osts and conceptual engineering design estimates of retrofits. Unlike EPA's costs, UWAG's capital costs include total capital cost to the plant, including major equipment installed, balance of plant (site work, concrete, piping, electrical, mechanical, and instrumentation and controls), engineering (design, services during construction, and startup), overhead and profit (subcontractor and general contractor costs), and miscellaneous contingency (unidentified costs). Using this more realistic cost estimating methodology, UWAG determined that zero discharge of bottom ash transport water would range from $4,710 to $16, 121/TWPE for small units and from $4,878 to $9,061/TWPE for units larger than 400 MW (in 1981 dollars). By way of comparison (and we recognize EPA's cost analysis did not include all appropriate costs), EPA's analysis concluded that zero discharge of bottom ash transport water would cost $106/TWPE for small units and $99/TWPE for units larger than 400 MW (in 1981 dollars). Based on these comparis ons, EPA has failed to justify proposed options that would require dry bottom ash handling, and therefore should continue BPT (i.e., impoundment) for bottom ash transport water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 458 Comment Response: See response to DCN EPA

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- A1, Excerpt N umber 36. See response to DCN EPA

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Commenter Name: Douglas J. Fulle Commenter Affiliation: Oglethorpe Power Corporation Document Control Number: E PA

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- A1 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Oglethorpe Power is concerned with some of the approaches EPA is taking in the proposal for exi sting discharges. As a general matter, EPA should adopt only those technologies that are justifiable under the Agency's established criterion for highest cost per Toxic Weighted Pounds Equivalent ("$/TWPE"). See 75 Fed. Reg. 34,432, 34,504 (June 7, 2013) (maximum of $404/lb

eq in 1981 dollars). When correctly applying that criterion, options that would require dry bottom ash handling have not been justified, and the current Best Practicable Control Technology Currently Available (BPT) for bottom ash tran sport water should be adopted as BAT. EPA's proposed analysis of dry bottom ash handling lacks adequate sampling and analysis of bottom ash transport water and fails to account for the full costs of dry handling. Comment Response: See response to DCN E PA

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- A1, Excerpt Number 36.

Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Rev iew External Review Incorporated into Response: No Comment Excerpt: In addition, conversion to dry handling and the associated high cost of treatment, on a $/TWPE basis, do not justify any option requiring dry handling/closed loop for bottom ash.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 459 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For Existing Dischargers, Dry Handling/Closed Loop is not Best Available Technology Economically Achievable. The low level of toxics in bottom ash transport water coupled with the high costs of retrofitting bottom ash handling systems at existing facilities render any “zero discharge” approach unjustified. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Bru ce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 80 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry handling/closed loop is not BAT for treating bottom ash transport water because the low level of toxics in bottom ash transport water coupled with the high costs of retrofitting equipment renders any “zero discharge” approach unjustified. Comment Response: See response to DCN EPA

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EPA’s Response to Public Comments

6

- 460 Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 83 External Review Flag: No External Review Externa l Review Incorporated into Response: No Comment Excerpt:
UWAG’s calculated cost

- effectiveness for managing bottom ash transport water via dry handling/closed loop is much greater than EPA’s estimate because EPA underestimated the costs and significantly overestimated the pollutant removal estimates. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Winslow Sargeant Commenter Affiliation: U.S. Small Business Administration, Office of Advocacy Docume nt Control Number: EPA

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- A1 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
B. The Industry Data Demonstrates that Regulating Bottom Ash Wastewater i s Not Cost Effective The most costly portion of this regulation under serious consideration is the requirement to eliminate bottom ash wastewater discharges, and force those existing facilities to switch to a dry bottom ash handling system. The bottom ash costs account for $719 million of the total of $1.37 billion annual costs in Option 4. As discussed above, this requirement is expected to be particularly burdensome for the smaller facilities. This is especially true when there is a large capital cost involved. Further, we believe that the industry comments demonstrate that this requirement does not significantly reduce pollutant loadings for any plants, and is likely to be very cost

- ineffective. Given the extensive industry database supplying the bott om ash pollutant data, we have more confidence relying on that data in lieu of EPA’s much older and smaller sample of data. If EPA had completed its plan to go forward with a SBREFA panel, we believe that EPA would have revised its analysis to rely on the more recent industry data, contributing to more sound EPA determinations.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 461 The industry analysis, after adjusting EPA’s costs and pollutant loadings, as stated earlier, would place this requirement at thousands of dollars/PE, more than twenty times higher than the historical standard used by EPA. In the future, EPA should study the applicability of a less expensive alternative to dry handling, such as employing chemical precipitation technology on the bottom ash impoundment. We support consideration of a new technology option to address this small amount of pollution, and this may well be the better solution for these surface water impoundments containing bottom ash. Comment Response: See response to DCN EPA

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EP A did evaluate chemical precipitation costs for bottom ash transport water and determined that capital costs for chemical precipitation are higher than capital costs for dry handling on a plant

by

- plant basis (DCN SE05654). See other responses to this comm enter regarding the impacts on small entities under this rule, particularly responses in Comment Code 28.e.

Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Without such additional data, EPA simply cannot justify requiring dry handling or closed

- loop bottom ash systems at this time. 4 No r can the agency justify setting effluent limits based on the proposed technology in light of the low level of pollutants in bottom ash transport water and the high costs of retrofitting dry bottom ash handling systems at existing facilities.

4 The agenc y’s historical data, as well as the modest data it has collected or borrowed for purposes of this rulemaking, are flawed, misapplied, and/or are not representative of constituents currently contained in this waste stream and therefore cannot provide a foun dation upon which EPA can reasonably justify effluent limits equivalent to dry or closed

- loop handling. UWAG discusses at length the myriad issues with the data EPA has cited as support for its regulatory findings, along with the agency’s TWPE calculations based upon this imperfect data. See UWAG Comments at Section V., C

- D.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 462 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Erik Silvola Commenter Affiliation: Great River Energy (GRE) Document Control Number: EPA

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- A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Based on the overestimation of constituents in bottom ash sluice discharges and an u nderestimation of the cost to convert to dry handling we believe there is no justification any of the option requiring dry handling. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: John W. Myers Co mmenter Affiliation: Tennessee Valley Authority (TVA) Document Control Number: EPA

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- A1 Comment Excerpt Number: 21 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
the benefits of eliminating this wastestream are not justified by the significant costs to be incurred as was EPA’s determination in the previous steam electric ELG rulemaking. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

C ommenter Name: John W. Myers Commenter Affiliation: Tennessee Valley Authority (TVA) Document Control Number: EPA

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EPA’s Response to Public Comments

6

- 463 Comment Excerpt Number: 25 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: it is not believed necessary or justified on a cost per TWPE removed to retrofit existing wet bottom ash handling systems to dry systems. The potential reduction in pollutant loading from ceasing bottom ash sluicing as compared to the d irect and indirect costs required to retrofit do not warrant such actions. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Documen t Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The overestimation of pollutants produces incorrect calculations of cost and cost effectiveness for both dry bottom ash handling and closed

- loop bottom ash water systems. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commente r Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 8 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The record is best developed for bottom ash transp ort water, and for that wastestream EPA has not shown any treatment beyond settling ponds to be cost

- effective. UWAG calculates costs ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 464 dry handling bottom ash ranging from a very high $1,635 to $16,492/TWPE in 1981 dollars, using TWPEs removed that are consistent with EPRI data and data from the Homer City plant, the only plant where EPA took a bottom ash transport water sample for this rulemaking. EPA’s lower costs per TWPE resulted from using pre

- 1982 data, counting sulfides that were almost certainly false positives, using data from bottom ash transport water combined with fly ash transport water, assuming undetected pollutants were present at relatively high concentrations, counting intake pollutants, and underestimating the costs of retrofitting bot tom ash dry handling. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 51 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
F. EPA’s Cost
- Effectiveness Estimates for Bottom Ash Transport Water Are Far Too High EPA establishes TWFs for pollutants of concern. To calculate “toxic

- weighted pounds

equivalent,” the weighting factors are multiplied by the pounds of pollutant in a wastewater. EPA lists the TWFs for pollutants of concern in this rulemaking in the Regulatory Impact Analysis (EPA

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- 2239 (RIA), Appendix D: Cost Effectiveness, Table D

- 1 at D

- 3). UWAG used these EPA

- generated TWFs in all of UWAG’s TWPE calculations.
In its cost

- effectiveness analysis for this rulemaking, EPA did not present its results for individual wastestre ams but only as a sum of all the wastestreams for a given regulatory option. 78 Fed. Reg. at 34,504. However, in a document called Cost Effectiveness of Removing Toxic Pollutants for Direct Dischargers at a Wastestream/Technology Level (EPA

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- 2255), EPA provides dollars per TWPE for some of the individual wastestreams, as summarized in Table 1 below.
Table 1: EPA’s Cost
- Effectiveness by Wastestream

Wastestream Technology Option Cost Effectiveness (1981$/TWPE) Fly Ash Transport Water and Flue Gas Hg Control Waste (coal units >50 MW) Dry Handling/Closed Loop $27Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 465 FGD Wastewater Chemical Precipitation $69 FGD Wastewater Chemical Precipitation and Biological $60
FGD Wastewater Chemical Precipitation and Vapor

Compression Evaporation Not provided Bottom Ash Transport Water Dry Handling/Closed Loop (50 MW threshold) $106 Bottom Ash Transport Water Dry Handling/Closed Loop (400 MW threshold) $99 *Combustion Residual Leachate Chemical Precipitation >$1000 *Combustion Residual Leachate Co

- treatment with FGD wastewater Not providedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 466 *$/TWPEs for Combustion Residual Leachate are provided in the 2013 TDD at 8

- 34. Since EPA has previously found a cost of $404 per TWPE acceptable, the numbers in Table 1 appear to be cost

- effective, since they are below $404. But they are misleading because of the methods EPA used for the calculations. Particularly for bottom ash transport water, EPA has estimated costs too low and pollutants removed too high, resulting in inflated estimates of dollars per TWPE. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 57 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
I. EPA’s $/TWPE for MDS or RMDS Retrofits for Bottom Ash Based on EPA’s data and costs, described above, E PA estimates a cost of $106 per TWPE for zero discharge of bottom ash transport water for all coal units greater than 50 MW. For Option 4a, which includes zero discharge of bottom ash transport water for coal units greater than 400 MW, EPA estimates $99 p er TWPE. EPA

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J. UWAG’s Cost
- Effectiveness Analysis for Bottom Ash Instead of relying on EPA’s flawed bottom ash transport water characterization data, UWAG collected 21 bottom ash transport water characterization data sets from its m embers. To analyze the cost effectiveness of dry or closed

- loop bottom ash retrofits, UWAG used its own characterization data and median flow rates from the 2010 ICR database to calculate TWPEs. See Attachment 10, UWAG’s Methodology for Calculating Dollar s Per TWPE for Bottom Ash, Fly Ash, and FGD Wastewater. To estimate capital costs, UWAG used 13 data points it collected from members based on actual costs and conceptual engineering design estimates of retrofits, as shown in the table below. Only one of the 13 data points was adjusted to 2012 dollars. The other 12 data points either occurred or were estimated between 2009 and 2012, and therefore these costs were not adjusted.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 467 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 61 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: As we have shown, EPA’s estimate of $107/TWPE for bottom ash retrofits is erroneous for several reasons: Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 65 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: UWAG’s $/TWP E for bottom ash ranges from $1,635 to $16,492 (in 1981 dollars). Even the low

- end of the UWAG range exceeds the cost per TWPE ceiling that EPA has traditionally used for effluent guidelines. As EPA points out, its historical BAT cost

- effectiveness range is less than $1/TWPE to $404/TWPE. 78 Fed. Reg. at 34,504 col. 1

- 2. UWAG’s $/TWPE range is 4.0 to 41 times greater than $404/TWPE. By EPA’s own standards, then, dry handling or closed

loop retrofit of bottom ash is not cost

- effective. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 468 Commenter Name: Raymond L. Evans Commenter Affiliation: FirstEnergy Corp. Document Control Number: EPA

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- A2 Comment Excerpt Number: 1 External Review Flag: No E xternal Review External Review Incorporated into Response: No Comment Excerpt: A. EPA's Proposed Options for Bottom Ash Transport Water Must Be Reevaluated Utilizing Accurate $/TWPE Information EPA's proposed Best Available Technology (BAT) for bottom as h transport water provides two treatment options, (1) impoundments or (2) dry handling or closed

- loop (zero discharge of transport water options) treatment. (Option 4a would require dry handling or closed

- loop only for large units above 400 MW and impoun dments for others.) FirstEnergy supports Options 1 through 3 (including 3a and 3b) for bottom ash transport water which maintains the current Best Practicable Control Technology Currently Available (BPT) limits. FirstEnergy opposes Option 4a which is inc onsistent with EPA's recognition over many decades that bottom ash transport water does not justify limits that would require dry handling or closed

- loop bottom ash systems. Bottom ash transport water has a small contribution of taxies and a very high cost of treatment on a dollar per toxic weighted pound equivalents ($/TWPE) basis. In this proposed rule, EPA's calculation of the $/TWPE for bottom ash transport water is erroneous as documented by AKRF, Inc.'s report and explained further in the UWAG comme nts. EPA used old data and assumed the sampling detection limit as the data values for results that were below detection limits. This along with manipulation of the averaging method of the data resulted in very high toxic weighted amounts. The overly in flated TWPE amounts were then utilized along with underestimated costs of retrofitting bottom ash dry handling (see EPRI technical comments) to justify the cost effectiveness in the calculation of a biased $/TWPE. EPA needs to collect and evaluate more re cent data, revise the underestimated costs of retrofitting bottom ash dry handling (see EPRI technical comments); and then re

- evaluate cost effectiveness. Proper analysis will demonstrate that "zero discharge" for bottom ash transport water is unjustified

. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36. See response to DCN EPA

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- 4655, Excerpt Number 4 in Comment Code 6.f for more information on EPA’s statistical methodology for calculating pollutant loa dings.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 469 Document Control Number: EPA

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- A2 Comment Excerpt Number: 29 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The record is best developed for bottom ash transport water, and for that wastestream. EPA has not shown any treatment beyond settling ponds to be cost

- effective. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36.

Commenter Name: S. L. Phillips Commenter Affiliation: Louisiana Department of Environmental Quality Document Control Number: EPA

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- A2 Comment Excerpt Number: 4 External Review Flag: N o External Review External Review Incorporated into Response: No Comment Excerpt: The existing guidelines only regulate the discharge of total suspended solids (TSS) and oil & grease (O&G) for this wastewater. The Option 4a proposal would change this requirement and prohibit the discharge of pollutants from bottom ash transport water from units > 400 MW although it illogically exempts quenching water at the bottom of boilers. Should Option 4a be adopted, it will require the installation of dry bottom ash handling technologies , such as drag chains and hydro

- bins, at most coal

- fired facilities. The agency has over

- estimated the cost effectiveness of bottom ash control systems. Bottom ash sluice water does not contribute a significant mass of pollutant s to the environment. Option 3a would allow continued use of wet bottom ash transport systems. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36. EPA disagrees with the commenter that it “illogically exempts quenching w ater at the bottom of boilers.” Quench water at the bottom of boilers is not used as the mechanism to transport the bottom ash from the bottom of the boiler to intermediate storage or final disposal; therefore, is not considered bottom ash transport water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 470 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 39 External Review Flag: No External Review External Review Incorporated into Response: No
Comment E xcerpt: Using the formula from the UWAG capital cost curve and the UWAG bottom ash transport characterization data, the cost per TWPE was calculated for each capacity

- based model plant. Table 4 provides the $/TWPE using the UWAG bottom ash transport wate r data and including the contribution from the source water. Table 4: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data (NoAdjustment for Source Water Contribution)

MW Range Bottom Ash Median

Plant Flow Rate (Million Gallons/Year) Annual TWPE

Re moved* Per Plant 1981$/TWPE

Removed Per Plant <50 MW 9.4 16 $16,492 50

- 100 MW 30.2 52 $5,597 100

- 150 MW 63.8 110 $3,106 150

- 200 MW 110 191 $2,056 200

- 300 MW 152 263 $1,780 300

- 400 MW 200 347 $1,635 400

- 500 MW 197 341 $1,954 500

- 700 MW 278 482 $1,694 700

- 900 MW 308 534 $1,902 >900 MW 223 386 $3,146 *Highest TWPE removed is aluminum at 50% of the total TWPEs. These UWAG $/TWPE calculations are more realistic than EPA’s, but are still too low, for the following reasons:

 The UWAG $/TWPE include only capital costs. They do not include annual operating and maintenance costs, which would be large. Therefore, the actual $/TWPE will be much larger than shown in the UWAG tables.

 Source water is a major contributor of the TWPEs f or bottom ash transport water. The UWAG data represent plants that use river water for sluicing bottom ash. For bottomash, then, a large part of the “pounds removed” is already present in the river water and not added by the power plant. The total pounds r emoved are much larger than the pounds added by the power plant itself. Without the adjustment for pounds of pollutants presentEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 471 in the intake water, the TWPE calculation penalizes power plants for pollutants naturally occurring in the waterbody (such as ir on and aluminum) and also for pollutants added by upstream users. For the above reasons, subtracting out the source water pollutants is warranted, and the $/TWPE are even higher, as shown in Table 5 below: Table 5: TWPE and $/TWPE Using UWAG Bottom Ash Tr ansport Water Data (Less the Source Water Contribution)

MW Range Bottom Ash Median

Plant Flow Rate (Million Gallons/Year) Annual TWPE

Removed* Per Plant 1981$/TWPE

Removed Per Plant
<50 MW 9.4 6 $47,500 50

- 100 MW 30.2 18 $16,121 100

- 150 MW 63.8 38 $8,947 150

- 200 MW 110 66 $5,922 200

- 300 MW 152 91 $5,127 300

- 400 MW 200 120 $4,710 400

- 500 MW 197 119 $5,628 500

- 700 MW 278 167 $4,878 700

- 900 MW 308 186 $5,477 >900 MW 223 134 $9,061 *The highest TWPE removed is aluminum at 75% of the total TWPEs. As shown in more detail in UWAG’s comments on this ELG proposal, using the UWAG characterization data, which is more recent and more representative of actual bottom ash transport water than the data EPA uses to characterize bottom ash transport water, fu rther regulation of bottom ash transport water is simply not cost effective

. Southern supports UWAG’s TWPE and cost per TWPE estimates and concludes that a BAT determination of zero discharge of bottom ash transport water, at any MW range, by EPA would be arbitrary because of the flawed science and data.

Comment Response: See response to DCN EPA

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EPA’s Response to Public Comments

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- 472 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 145 External Review Flag: No Externa l Review External Review Incorporated into Response: No Comment Excerpt: Dry or Closed
- Loop Bottom Ash Handling is not Cost
- Effective As for direct discharges, the prohibition on discharges of bottom ash is based on limited and outdated data. EPA perfor med its test for cost

- effectiveness based on very limited bottom ash characterization data, no consideration of pollutants already present in source water, and unrealistically low costs for engineering dry conversions. Using more accurate data would result in a higher cost for each toxic

- weighted pound

- equivalent removed. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36. For more information on EPA’s source water analysis for bottom ash transport water, see the response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 54 External Revi ew Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Shortcomings in EPA’s pollutant data for bottom ash transport water render its subsequent cost

effectiveness analysis wholly inaccurate. EPA’s assertion that it w ould cost the industry a mere $107 (1981 $) per TWPE removed to retrofit all existing facilities with greater than 50 MW capacity for facilities with dry or closed

- loop bottom ash handling systems is grossly devalued by the agency’s inflated TWPE numbers a nd deflated capital and operation and maintenance cost calculations. EPA’s $99 calculation per TWPE removed if the final rule requires only units with greater than 400 MW capacity to retrofit dry handling technology (Option 4a) is flawed for these same rea sons. Like its analytical data for bottom ash transport water, UWAG’s cost

- effectiveness analysis provides a true representation of the actual cost compared to relative benefits expected ifEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 473 EPA were to require existing facilities to retrofit dry handling t echnologies for bottom ash wastes. UWAG’s estimate of costs per TWPE removed ranges from $1,635 to $16,492 (1981 $). 10 See UWAG Comments at Section V., J. This range of values far exceeds any accepted as reasonable by EPA in any previous rulemaking. Indeed , as mentioned above, the highest $/TWPE ratio the agency has previously accepted as reasonable in the recent past is $404/TWPE. See 78 Fed. Reg. at 34,504. UWAG’s range of $/TWPE ratios is 4.3 to 43 times greater than this highest ratio accepte d by the agency and adequately demonstrates that requiring existing facilities to retrofit dry or closed

- loop bottom ash handling systems is not cost

- effective.

10 These numbers are dramatically higher if TWPEs attributable to source water are remov ed from the equation and associated O&M costs for implementing and maintaining the dry handling technology are included in the analysis. UWAG estimates the costs per TWPE removed would range from $4,710 to $47,500 (1981 $) if these additional factors were considered. See UWAG Comments at Section V., J. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 55 External Review Flag: No External Revie w External Review Incorporated into Response: No Comment Excerpt: Because EPA’s cost estimates are underestimated and the pollutant removals are overestimated, EPA’s cost

- effectiveness calculation ($/lb

- eq) is flawed. EPA presents cost

- effectiveness val ues ranging from $99/lb

- eq

– $106/lb

- eq (1981 dollars). When the costs and pollutant removals are more accurately estimated, as was done by UWAG, the cost

- effectiveness calculations range from $1,635/lb

- eq

– $16,492/lb

- eq (1981 dollars) for no adjustment of source water contributions to $4,710/lb

- eq

– $47,500/lb

- eq (1981 dollars) for adjustment of the source water contribution. Since the cost

- effectiveness is well over EPA’s standard threshold of $404/TWPE, conversion to dry handling/closed loop is not cos t

- effective. Comment Response: See response to DCN EPA

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EPA’s Response to Public Comments

6

- 474 For more information on EPA’s source water analysis for bottom ash transport water, see the response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 48 External Review Flag: No External Review External Review Inco rporated into Response: No Comment Excerpt: Due to the deficient data and methodological flaws, EPA’s analysis of cost

- effectiveness for bottom ash retrofits results in an estimate of $106 per TWPE for zero discharge of bottom ash transport water for all coal units greater than 50 MW. For option 4a, which includes zero discharge of bottom ash transport water for coal units greater than 400 MW, EPA estimates $99 per TWPE. EPA

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UWAG’s cost

- effectiveness analysis for the same option s, based on TWPE modified to address flaws identified in EPA’s approach, resulted in an estimated range of $1,635 to $16,492 (in 1981 dollars) as follows.

MW Range Bottom Ash Median Plant Flow Rate (Million Gallons/Year) Annual TWPE Removed* Per Plant 1981 $/TWPE

Removed Per Plant 13 <50 MW 9.4 16 $16,492 50

- 100 MW 30.2 52 $5,597 100

- 150 MW 63.8 110 $3,106 150

- 200 MW 110 191 $2,056 200

- 300 MW 152 236 $1,780 300

- 400 MW 200 347 $1,635 400

- 500 MW 197 341 $1,954 500

- 700 MW 278 482 $1,694Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 475 700

- 900 MW 308 534 $1,902 >900 MW 223 386 $3,146
*Highest TWPE removed is aluminum at 50% of the total TWPEs. Furthermore, after subtracting source water pollutants, the $ per TWPE are even higher, as follows:

MW Range Bottom Ash Median Plant Flow Rate (Million Gallons/Year) Annual TWPE Removed* Per Plant 1981$/TWPE

Removed Per Plant <50 MW 9.4 6 $47,500 50

- 100 MW 30.2 18 $16,121 100

- 200 MW 63.8 38 $8,947 150

- 200 MW 110 66 $5,922 200

- 300 MW 152 91 $5,127 300

- 400 MW 200 120 $4,710 400

- 500 MW 197 119 $5,628 500

- 700 MW 278 167 $4,878 700

- 900 MW 308 186 $5,477 >900 MW 223 134 $9,061
*The highest TWPE removed is aluminum at 75% of the total TWPEs.
Even the low

- end of the UWAG range far exceeds the cost per TWPE threshold that EPA has traditionally used for effluent guidelines. As EPA points out, its BAT cost

- effectiveness range is less than $1/TWPE to $404/TWPE. 78 Fed. Reg. at 34,504, col. 1

- 2. By EPA’s own standards, then, dry handling or closed

- loop retrofit of bottom ash is not cost effectiv e.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 476 13 UWAG’s cost

- effectiveness analysis only includes capital costs. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36. For more information on EPA’s source water analysis for bottom ash transport water, see the response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 8 2 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry or Closed
- loop Bottom Ash Handling is Not Cost
- Effective. As for direct discharges, the prohibition on discharges of bottom ash transport water is based on limited and outdated data. EPA performed its test for cost

- effectiveness based on very limited bottom ash characterization data, no consideration of pollutants already present in source water, and unrealistically low costs for engineering dry conversions. Using more accurate data would result in a higher cost for each toxic

- weighted pound

- equivalent removed. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Document Control Number: EPA

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EPA’s Response to Public Comments

6

- 477 Comment Excerpt: EPA’s subsequent cost

- effectiveness analysis is rendered ineffectual by these shortcomings in its pollutant data for bo ttom ash transport water. The agency’s assertion that it would cost the industry only $107 (in 1981 dollars) per TWPE removed to retrofit all existing facilities with greater than 50 megawatt (“MW”) capacity for facilities with dry or closed

- loop bottom as h handling systems is undermined by the agency’s inflated TWPE numbers and deflated capital and operation and maintenance cost calculations. The same is true for the agency’s estimate of $99 per TWPE removed if the final rule requires only units with gre ater than 400 MW capacity to retrofit dry handling technology (Option 4a). UWAG’s cost

- effectiveness analysis, like its analytical data for bottom ash transport water, provides a true representation of the actual cost compared to relative benefits expecte d from EPA’s requiring existing facilities to retrofit dry handling technologies for bottom ash wastes. UWAG’s estimate of costs per TWPE removed ranges from $1,635 to $16,492 (in 1981 dollars). 5 This range of values is far too high and greatly exceeds any costs accepted as reasonable by EPA in previous rulemakings. The highest $/TWPE ratio the agency has recently accepted as reasonable is $404/TWPE. 6 The range of $/TWPE ratios offered by UWAG is 4 to 40 times greater than this highest ratio accepted by the agency. This adequately demonstrates that requiring existing facilities to retrofit dry or closed

- loop bottom ash handling systems is not cost

- effective.

5 These numbers are dramatically higher if TWPEs attributable to source water are removed from the equation and associated O&M costs for implementing and maintaining the dry handling technology are included in the analysis. UWAG estimates the costs per TWPE removed would range from $4,710 to $47,500 (in 1981 dollars) if these additional factors were c onsidered.

6 See 78 Fed. Reg. at 34,504 (providing that “[a] review of approximately 25 of the most recently promulgated or revised BAT limitations shows BAT cost

- effectiveness ranging from less than $1/lb

- eq (Inorganic Chemicals) to $404/lb

- eq (Electrical and Electronic Components), in 1981 dollars”). Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number: EPA

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EPA’s Response to Public Comments

6

- 478 External Review F lag: No External Review External Review Incorporated into Response: No Comment Excerpt: Shortcomings in EPA’s pollutant data for bottom ash transport water render its subsequent cost

effectiveness analysis ineffectual. EPA’s assertion that it would cost the industry a mere $107 (in 1981 dollars) per TWPE removed to retrofit all existing facilities with greater than 50 MW capacity for facilities with dry or closed

- loop bottom ash handling systems is grossly devalued by the agency’s inflated TWPE numbers a nd deflated capital and O&M cost calculations. EPA’s $99 calculation per TWPE removed if the final rule requires only units with greater than 400 MW capacity to retrofit dry handling technology (Option 4a) is flawed for these same reasons. Like its analyti cal data for bottom ash transport water, UWAG’s cost

- effectiveness analysis provides a true representation of the actual cost compared to relative benefits expected if EPA were to require existing facilities to retrofit dry handling technologies for botto m ash wastes. UWAG’s estimate of costs per TWPE removed ranges from $1,635 to $16,492 (1981 dollars). 21 This range of values far exceeds any accepted as reasonable by EPA in any previous rulemaking. Indeed, the highest $/TWPE ratio the agency has previously accepted as reasonable in the recent past is $404/TWPE. See 78 Fed. Reg. at 34,504 (providing that “ [a] review of approximately 25 of the most recently promulgated or revised BAT limitations shows BAT cost

effectiveness ranging from less than $1/lb

- eq (Inorganic Chemicals) to $404/lb

- eq (Electrical and Electronic Components), in 1981 dollars”). UWAG’s ra nge of $/TWPE ratios is 4 to 40 times greater than this highest ratio accepted by the agency and adequately demonstrates that requiring existing facilities to retrofit dry or closed

- loop bottom ash handling systems is not cost

- effective.

21 These numbers are dramatically higher if TWPEs attributable to source water are removed from the equation and associated O&M costs for implementing and maintaining the dry handling technology are included in the analysis. UWAG estimates the costs per TWPE removed would range from $4,710 to $47,500 (1981 dollars) if these additional factors were considered. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Numbe r: 59Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 479 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Using the formula from the UWAG capital cost curve and the UWAG bottom ash transport characterization data, the cost per TWPE was calculated f or each capacity

- based model plant. Table 4 provides the $/TWPE using the UWAG bottom ash transport water data and including the contribution from the source water.
Table 4: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data (No Adjustment for So urce Water Contribution) 17

*Highest TWPE removed is aluminum at 50% of the total TWPEs.
These UWAG $/TWPE calculations are more realistic than EPA’s, but are still too low, for the following reasons:

 The UWAG $/TWPE include only capital costs. They do not include annual O&M or disposal costs, which would be large. Therefore, the actual $/TWPE will be much larger than shown in either of the UWAG tables.

 Source water is a major contributor of the TWPE estimates for bottom ash transport water. The UWAG data represent plants that use river water for sluicing bottom ash. For bottom ash, then, a large part of the “pounds removed” is already present in the river water and not added by the power plant. The total pounds removed are much larger than the pounds added by the power plant itself. Without the adjustment for pounds of pollutants present in the inta ke water, the TWPE calculation penalizes power plants for MW Range Bottom Ash Median

Plant Flow Rate (Million Gallons/Year) Annual TWPE

Removed*
Per Plant 1981$/TWPE

Removed
Per Plant <50 MW 9.4 16 $16,492 50

- 100 MW 30.2 52 $5,597 100

- 150 MW 63.8 110 $3,106 150

- 200 MW 110 191 $2,056 200

- 300 MW 152 263 $1,780 300

- 400 MW 200 347 $1,635 400

- 500 MW 197 341 $1,954 500

- 700 MW 278 482 $1,694 700

- 900 MW 308 534 $1,902 >900 MW 223 386 $3,146Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 480 pollutants naturally occurring in the waterbody (such as iron and aluminum) and also for pollutants added by upstream users. For the above reasons, subtracting out the source water pollutants is war ranted, and the $/TWPEs are even higher, as shown in Table 5 below:
Table 5: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data (Less the Source Water Contribution) 18

MW Range Bottom Ash Median

Plant Flow Rate (Million Gallons/Year) Annual TWPE

Removed* Per Plant 1981$/TWPE

Removed Per Plant <50 MW 9.4 6 $47,500 50

- 100 MW 30.2 18 $16,121 100

- 150 MW 63.8 38 $8,947 150

- 200 MW 110 66 $5,922 200

- 300 MW 152 91 $5,127 300

- 400 MW 200 120 $4,710 400

- 500 MW 197 119 $5,628 500

- 700 MW 278 167 $4,878 700

- 900 MW 308 186 $5,477 >900 MW 223 134 $9,061 *The highest TWPE removed is aluminum at 75% of the total TWPEs. Using the UWAG characterization data, which is more recent and more representative of actual bottom ash transport water than the data EPA uses to characterize bottom ash transport water, further regulation of bottom ash transport water is simply not cost effective.

17 See Attachment 29.

18 See Attachment 29. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 481 Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Af

filiation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 182 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
4. Dry or Closed
- Loop Bottom Ash Handling Is Not C ost - Effective As for direct discharges, the prohibition on discharges of bottom ash transport water is based on limited and outdated data. EPA performed its test for cost

- effectiveness based on very limited bottom ash characterization data, no considerati on of pollutants already present in source water, and unrealistically low costs for engineering dry conversions. Using more accurate data would result in a higher cost for each toxic

- weighted pound

- equivalent removed. Comment Response: See response to D CN EPA

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- A1, Excerpt Number 36. For more information on EPA’s source water analysis for bottom ash transport water, see the response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 55 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: APPA points out that in using the formula from the UWAG capital cost curve and the UWAG bottom ash transport characterization data, the cost per TWPE was calculated for each capacity

based model plant. Table 4 provides the $/TWPE using the UWAG bottom ash transport water data and including the contribution from the source water. Table 4: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data (No Adjustment for Source Water Contribution)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 4 82 MW Range Bottom Ash Median

Plant Flow Rate (Million Gallons/Ye ar) Annual TWPE

Removed* Per Plant 1981$/TWPE

Removed Per Plant <50 MW 9.4 16 $16,492 50

- 100 MW 30.2 52 $5,597 100

- 150 MW 63.8 110 $3,106 150

- 200 MW 110 191 $2,056 200

- 300 MW 152 263 $1,780 300

- 400 MW 200 347 $1,635 400

- 500 MW 197 341 $1,954 500

- 700 MW 278 482 $1,694 700

- 900 MW 308 534 $1,902 >900 MW 223 386 $3,146 *Highest TWPE removed is aluminum at 50% of the total TWPEs. These UWAG $/TWPE calculations are more realistic than EPA’s, but are still too low, for the following reasons:

 The UWAG $/TWPE include only capital costs . They do not include annual operation and maintenance (O&M) costs, which would be large. Therefore, the actual $/TWPE will be much larger than shown in either of the UWAG tables; and

 Source water is a major contri butor of the TWPE estimates for bottom ash transport water. The UWAG data represent plants that use river water for sluicing bottom ash. For bottom ash then, a large part of the “pounds removed” is already present in the river water and not added by the po wer plant. The total pounds removed are much larger than the pounds added by the power plant itself. Without the adjustment for pounds of pollutants present in the intake water, the TWPE calculation penalizes power plants for pollutants naturally occurring in the waterbody (such as iron and aluminum) and also for pollutants added by upstream users. For the above reasons, subtracting out the source water pollutants is warranted, and the $/TWPEs are even higher. To further illustrate the point, APPA borrows f rom UWAG the table below: Table 5: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data (Less the Source Water Contribution)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 483 MW Range Bottom Ash Median

Plant Flow Rate (Million Gallons/Year) Annual TWPE

Removed* Per Plant 1981$/TWPE

Removed Per Plant

<50 MW 9.4 6 $47,500

50

- 100 MW 30.2 18 $16,121

100

- 150 MW 63.8 38 $8,947

150

- 200 MW 110 66 $5,922

200

- 300 MW 152 91 $5,127

300

- 400 MW 200 120 $4,710

400

- 500 MW 197 119 $5,628

500

- 700 MW 278 167 $4,878Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 484 700

- 900 MW 308 186 $5,477

>900 MW 223 134 $9,061

*The highest TWPE removed is aluminum at 75% of the total TWPEs. Using the UWAG characterization data, which is more recent and more representative of actual bottom ash transport water than the data EPA uses to characterize bottom ash transport water, further regulation of bottom ash transport water is simply not cost effective . APPA appreciates UWAG’s ability to run these numbers to point out that the costs per TWPE are dramatically higher than the standard $404 per TWPE as in prior rulemakings in other industries that underwent revisions to their ELG. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 36. For more information on EPA’s source water analysis for bottom ash transport water, see the response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 37 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:

c. AEP’s $/TWPE removal estimates demonstrate that the regulation of bottom ash transport water, as proposed in the agency’s effluent guidelines revisions, is n ot cost effective. EPA performed a cost

- effectiveness analysis for all the proposed technologies and in the case of bottom ash transport water, estimated $/TWPE removed values of $107 and $99 (1981$). 26 Since EPA has found, and AEP agrees, that a cost of $404 (1981$) per TWPEEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 485 removed is acceptable, these values appear to be reasonable, however, they are misleading because they are unrealistically low. Using the same methods as EPA to determine $/TWPE removed for bottom ash transport water, AEP calculated values which are very much different than those determined by the agency. Water samples were collected from two AEP system bottom ash ponds and the source of ash transport water for each facility. No other waste streams ent er either pond. The samples were analyzed for metals and inorganics using EPA methods 200.8 and 200.7. Information on the frequency and duration of transport water flow was obtained from the EPA ELG ICR response. AEP adjusted the compliance costs from 201 0$ to 1981$ using Engineering News Record’s Construction Cost Index (CCI). EPA also used a 7% interest value and assumed a 20

- year service life when annualizing costs estimates. AEP did likewise to make the cost comparisons equivalent, but notes that use of a 15

- year service life would be more appropriate. Based on these data and using an annualized direct capital costs in 1981$ for a plant retrofit, AEP determined a $/TWPE value of $16,007 (Table 6); an estimate two orders of magnitude higher than any of the EPA $/TWPE values for this waste stream. The fully

- loaded estimated based on a 15

- year annualization period is even higher, exceeding $23,000.

A blend of bituminous and sub

- bituminous coals is burned in sub

- critical cyclone

- fired wet bottom boilers at the plant in question, so the ash generated by this facility is primarily boiler slag. When the molten slag contacts the quenching water at the bottom of the boiler, it crystallizes, fractures, and forms pellets that have a smooth, glassy appearance. B oiler slag is a very inert material, more so than bottom ash, and contributes very few pollutants to the transport water. As a result, very few TWPEs are removed following a dry bottom ash retrofit and the $/TWPE values are very high. Regardless, EPA has not distinguished between various bottom ash types and should Options 4a, 4, or 5 be adopted, a dry bottom ash conversion would be required for this facility at a cost that is well above that which has been determined by the agency to be reasonable. Addi tionally, AEP presents costs on a direct basis in these comments for comparison purposes, but a more accurate portrayal of expected compliance costs would be to “fully load” the direct costs with indirect costs, such as company overheads, as well as Allowa nce for Funds Used During Construction (AFUDC). Fully

- loaded costs represent the total amount that will be borne by utility customers as a result of this rule. To provide another example of the unacceptable cost of dry bottom ash retrofits, AEP provides i nformation collected from a second facility. A bituminous coal is burned at this facility in a sub

critical wet

- bottom boiler. Using the same methods as those used to determine $/TWPE removedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 486 for the prior facility, values very much different than those de termined by the agency were again obtained. Water samples were collected from the bottom ash pond discharge and the source of the transport water. Again, no other waste steams enter the pond. The samples were analyzed for metals and inorganics using EPA m ethods 200.8 and 200.7. Information on the frequency and duration of transport water flow was recorded on the day of the sampling. Based on these data and using a 20

- year annualization period, AEP estimated a $/TWPE value of $4,961 (1981$); an estimate ve ry much higher than any of the EPA $/TWPE values determined for this waste stream (Table 6). The fully loaded estimate based on a 15

- year annualization period is even higher, exceeding $7,200.

26 Cost Effectiveness of Removing Toxic Pollutants for Direct Dischargers at a Waste Stream/Technology Level, EPA

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- 2255. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 39 in Comment Code 4.b. EPA determined that the dry handling and closed

- loop systems that are the BAT basis for control of pollutants in bottom ash transport water are available for cyclone boilers. EPA notes that there is at least one cyclone boiler generating unit that currently operates a mechanical drag system (Kansas City Power & Light’s La Cygne Generating Station). Additionally, the remote mechanical drag system uses the existing wet bottom ash transport system with a different dewatering process. See the response to DCN EPA

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- A1, Excerpt Number 46 in Comment Code 6.g.ix for more information on cyclone boilers, the technologies evaluated for BAT, and wastewater characterizatio n. EPA cannot evaluate the cost data provided by the commenter due to the lack of specific information about the conversion estimates. For example, the commenter did not provide the plant identification, type of bottom ash handling conversion, the number o f generating units at each steam electric power plant, or any other system

- specific information that could be used to evaluate the costs provided.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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6-487 Comment Excerpt: 

### 8.1 EPA’s calculated cost/TWPE ratio for eliminating discharge of bottom ash transport water is lower than EPRI’s.
EPRI calculated the cost/TWPE ratio that the industry would experience for elimination of bottom ash sluice water via mechanical drag systems (MDSs) or remote MDS. Table 8-1 summarizes these cost/benefit ra tios for a 2010 basis year, as well as a 1981 basis year. EPA’s cost/benefit ratio for each technology is lower than EPRI’s cost/benefit ratio. A summary of EPRI’s bottom ash treatment polluta nt reduction estimates is provided in Section 7, while a summary of bottom ash treatment cost estimates is provided in Section 8.2. In addition, EPRI provides techni cal comments on EPA’s methodology to assist the Agency in its Effluent Guidelines rulemaking. Details of EPRI’s bottom ash costs calculation are available in Appendix E.

Comment Response: See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36. See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 117 in Comment Code 16.b for more information on EPA’s review of the commenter’s cost methodology submitted in Appendix E of the their public comment letter.

Commenter Name: Doris Cooksey Commenter Affiliation: City Public Service of San Antonio (CPS Energy) Document Control Number: EPA-HQ-OW-2009-0819-4283-A1 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 488 Based on our participation in several industry groups, CPS Energy believes EPA cost estimates fall short of the actual costs utilities will incur and the cost per t oxic

- weighted pollutant equivalent (TWPE) is significantly greater than EPA estimates. Additionally, even using EPA estimates under this proposed rule the costs per TWPE exceed any EPA has considered reasonable in a cost benefit analysis. Therefore, bas ed on the lack of cost benefit evidence and the relatively small health benefits gained, the dry handling option should not be chosen as BAT and EPA should continue to allow the use of wet bottom ash settling ponds at existing sites. Comment Response:
S ee response to DCN EPA

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- A1, Excerpt Number 36. See the response to DCN EPA

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- 4655, Excerpt Number 53 in Comment Code 16.b for more information on EPA’s bottom ash compliance costs. Additionally, EPA’s record demonstrates t hat plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water. EPA disagrees that there are relatively small health benefits gained with the elimination of bottom ash transport water discharge. See preamble sections XIII and XIV for more information on EPA’s environmental assessment and benefits analysis.

Commenter Name: Dennis Leonard Commenter Affiliation: DTE Energy Company Document Control Number: EPA

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- A2 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA Should Not Ban Bottom Ash Sluicing The assumptions in the ELG regarding bottom ash sluice water po llutant concentrations should be corrected and should properly reflect the negligible pollutant concentrations of this waste water. UWAG has described in its comments the enormous, multimillion, dollar costs associated with retrofitting an existing 400 MW unit with bottom ash recirculation systems. Since the cost of recirculation is enormous and recirculation provides little to no environmental benefit, the final ELG should not ban the discharge of bottom ash sluice water. EPA should allow the continued dis charge of bottom ash sluice water at all units, and not just units less than 400 MWs. Comment Response: See response to DCN EPA

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- 489 Commenter Name: Patrick O’Loughlin Commenter Affiliation: Buckeye Power, Inc. Document Control Number: EPA

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- A2 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Buckeye Power, and many other regulated parties, generate little or no bottom ash wastewater discharges. The high costs of implementing dry bottom ash systems, as detailed in AEP's comments, cannot be justified in light of the minimal incremental benefit derived from the conversion. Comment Response:
The Final rule rec ord demonstrates that steam electric power plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water (see preamble sections VIII and XIX). EPA disagrees that ther e are minimal incremental benefits associated with eliminating the discharge of bottom ash transport water. See preamble sections XIII and XIV for more information on EPA’s environmental assessment and benefits analysis.

Commenter Name: Tom DeLawrence C ommenter Affiliation: Alabama Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 52 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For example, EPA proposes under Option 4 to require dry handling for bottom ash waste. However, EPA has recognized for decades that bottom ash (and therefore bottom ash transport water) is relatively inert and generally contains only small amounts of toxic pollutants. For instance, in 1980, EPA proposed to reject more stringent regulations of bottom ash because it found that, at most plants, the priority inorganic pollutants detected in bottom ash were less than the concentrations detected in the raw or int ake water source. 45 Fed. Reg. 68,328, 63,338 (Oct. 14, 1980). EPA concluded that the high costs associated with recirculating bottom ash sluice water made the option unjustified because of the inability to quantify pollutant reductions. Id. In confirming this finding in 1982, EPA determined that the “[a]nalysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT control level.” EPA, Development D ocument forEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 490 Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category, EPA

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- 2186 at 498 (1982 Development Document). The same reasoning applies today. The low level of toxics in bot tom ash transport water and other similar wastewaters, and the high costs of retrofitting bottom ash handling systems and other similar systems at existing facilities, renders any “zero discharge” approach unjustified. Comment Response: See the response to DCN EPA

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- A2, Excerpt Number 7 in Comment Code 15.
For the role of cost

- effectiveness in EPA’s decision for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Dean E llis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 8 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The high cost of treatment, on a dollars per TWPE basis, does not justify zero discharge limits for bottom ash transport water. EPA previously found that high costs and the inability to quantify pollutant reductions did not support partial to complete recirculation of bottom ash slu ice water, determining that “analysis of available wastewater sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control.” EPA, Development Document for Efflu ent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category (1982 Development Document), EPA

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- 2186, at 498. That same reasoning applies today. The low level of pollutants of concern in bot tom ash transport water and the high cost of retrofitting bottom ash handling systems make “zero discharge” of bottom ash transport water unjustified. Comment Response: See the response to DCN EPA

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- A2, Excerpt Number 7 in Comment Code 15.
For the role of cost

- effectiveness in EPA’s decision for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 491 Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hamps hire(PSNH) Document Control Number: EPA

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- A1 Comment Excerpt Number: 48 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Regardless of the aforementioned points of contention, c urrent available data sufficiently demonstrates that limited pollutants are present in bottom ash transport waters

— a fact EPA recognized in 1980 and reconfirmed in 1982. See 45 Fed. Reg. 68,328, 68,338 (Oct. 14, 1980) (noting that certain pollutants were present in bottom ash at lower concentrations than those detected in intake water supplies); EPA, Development Document for Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric Point Source Category, EPA

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- 2186 at 498 (providing that “[a]nalysis of available waste water sampling data did not indicate that a quantifiable reduction of toxic pollutants would be achieved by requiring technologies beyond the BPT level of control”). The low level of polluta nts in bottom ash transport water and the high costs of retrofitting dry bottom ash handling systems at existing facilities render any effluent limitations based on this technology unjustified. The fact that EPA has collected little bottom ash waste water data since the 1980s to demonstrate any increase in pollutant

- loading in this waste stream exigently necessitates a conclusion that requiring dry handling or closed

- loop bottom ash systems is indefensible at this time. 20

20 What is more, the agency’s historical data, as well as the modest data it has collected or borrowed for purposes of this rulemaking, are flawed, misapplied, and/or are not representative of constituents currently contained in this waste stream and therefore cannot provide a foundati on upon which EPA can reasonably justify the imposition of effluent limits equivalent to dry or closed

- loop handling. UWAG discusses at length the myriad issues with the data EPA has cited as support for its regulatory findings, along with the agency’s TW PE calculations based upon this imperfect data. See UWAG Comments at Section V., C

- D. PSNH supports these specific comments by the industry association and incorporates same as if fully set out herein.

Comment Response: See the response to DCN EPA

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- 492 Commenter Name: Paul Ling Commenter Affiliation: Kansas City Power & Light Company Document Control Number: EPA

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Because of bottom as h transport water’s small contribution of toxics and high cost of treatment, on a $/TWPE basis, KCP&L supports Options 1 through 3 (including 3a and 3b), which would set bottom ash transport water limits attainable by treatment through a settling pond. For decades EPA has recognized that the small amount of toxics in bottom ash transport water does not justify limits that would require zero discharge. In 1980, EPA proposed to reject more stringent regulation of bottom ash because it found that, at most plan ts, the priority inorganic pollutants detected in bottom ash water were less than the concentrations detected in the raw or intake water source. The Agency further found that partial to complete recirculation of bottom ash sluice water was technically feas ible but that high costs and the inability to quantify pollutant reductions weighed against selecting the option. The same reasoning applies just as much today as it did in 1980. The low level of toxics in bottom ash transport water and the high cost of re trofitting bottom ash handling systems make zero discharge of bottom ash transport water unjustified. EPA’s current cost effectiveness analysis for bottom ash control technology is unsound because the underlying analyses are flawed. EPA’s bottom ash pollut ant loading calculations suffer from methodological biases. EPA’s assessment of bottom ash TWPE also has significant data and methodological deficiencies. Comment Response: See the response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative D ocument Control Number: EPA

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- 493 Comment Excerpt:
The low level of pollutants in bottom ash transport water and the high costs of retrofitting dry bottom ash handling systems at existing facilities render any effluent limitations based on this technology unjustified. The fact that EPA has collected little bottom ash wastewater data since the 1980s to demonstrate any in crease in pollutant

- loading in this waste stream exigently necessitates a conclusion that requiring dry handling or closed

- loop bottom ash systems is indefensible at this time. 9

9 What is more, the agency’s historical data, as well as the modest data it has collected or borrowed for purposes of this rulemaking, are flawed, misapplied, and/or are not representative of constituents currently contained in this waste stream and therefore cannot provide a foundation upon which EPA can reasonably justify the imposition of effluent limits equivalent to dry or closed

- loop handling. UWAG discusses at length the myriad issues with the data EPA has cited as support for its regulatory findings, along with the agency’s TWPE calculations based upon this imperfect data . See UWAG Comments at Section V., C

- D. PowerSouth supports these specific comments by the industry association and incorporates same as if fully set out herein. Comment Response: See the response to DCN EPA

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Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s Proposed Options That Establish “Zero Discha rge” Effluent Limitations Are Cost Prohibitive And Infeasible. Midwest Gen strongly opposes EPA’s option to adopt dry handling or closed loop systems as BAT for bottom ash transport water in options 4a (for units rated over 400 MW), 4 and 5 because the co nversion of Midwest Gen’s facilities to dry handling or closed loop systems wouldEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 494 be cost prohibitive, would create feasibility issues for certain facilities and, most importantly, is not necessary or justified to achieve the environmental objectives of th is rule. The current volume of water necessary for wet sluicing operations ranges from 270 thousand to over 10 million gallons per day, per unit

— most of which is treated by gravity settling in designated impoundments and reused at the stations, or discharg ed in compliance with existing NPDES permit requirements. Replacing this volume of water with systems that use mechanical means to move bottom ash or with closed loop systems would require significant and costly infrastructure changes at each affected sta tion and could result in increased energy usage, space constraints, and maintenance issues, as described more fully below. Comment Response: The final rule record demonstrates that steam electric power plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water (see preamble sections VIII and IX). EPA also adjusted compliance cost estimates for specific plants that provided comment on specific feasibility issues (for example, space constraints) to install a remote mechanical drag system, which uses the existing sluicing equipment and a mechanical drag system located away from the boiler. See preamble sections XIII and XIV for more information on EPA’s environmenta l assessment and benefits analysis and how eliminating the discharge of bottom ash transport water achieves environmental objectives of this rule. EPA disagrees that installing systems that use mechanical means to move bottom ash or closed

loop systems re sults in “increased energy usage, space constraints, and maintenance issues.” First, the installation of a mechanical drag system, if space underneath the boiler allows, has been shown to result in an O&M cost savings. The installation of these systems sho uld not have impact on space constraints because the mechanical drag system is located directly underneath the boiler or located remotely, utilizing the wet sluicing system that is already in place. Finally, EPA determined that maintenance for the mechanic al drag systems, either located under the boiler or remotely, can be completed during routine maintenance outages as long as the chains are maintained appropriately, for example, replacing chain links or flight bars. See also preamble section XII regarding the non

- water quality environmental impacts associated with the rule.

Commenter Name: Paul Bailey Commenter Affiliation: American Coalition for Clean Coal Electricity (ACCCE) Document Control Number: EPA

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- 495 Comment Excerpt: A zero discharge limit for bottom ash transport water cannot be justified by the significant costs associated with retrofits. Comment Respons e: The final rule record demonstrates that steam electric power plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water (see preamble sections VIII and IX).

Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 22 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Significant Costs Of Imposing Zero Discharge Limitations Vastly Outweigh The Potential Environmental Benefit. Given the benign nature of bottom ash transport water and the past success that surface impoundments have demonstrated i n removing pollutants, the zero discharge proposal, which would be a drastic change in handling practices for bottom ash, would not result in an environmental benefit that is meaningful or commensurate with its costs. Thus, adopting a zero discharge limit would not be sound public policy. Midwest Gen fully endorses EPA’s proposed options 1, 2, 3, 3a and 3b, which would allow for the continuation of the current regulatory requirement for bottom ash handling, which is wet sluicing with storage in designated impoundments. With appropriate measures and practices in place to assure continued integrity of the impoundments, these options are the most cost effective and they also remain sufficiently protective of the environment. Comment Response:
The rule ident ifies dry handling or closed

- loop systems as the BAT basis for control of pollutants in bottom ash transport water discharges from existing steam electric generating units that are greater than 50 MW and that are not oil

- fired. The record demonstrates that plants can install and afford these dry and closed

- loop bottom ash technologies. See preamble section VIII for more discussion of EPA’s rationale, and response to DCN EPA

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- 496 For the role of cost

- effectiveness in EPA's decision for the final rule , see response to DCN EPA

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Commenter Name: Thomas N. Effinger Commenter Affiliation: South Carolina Electric & Gas (SCE&G) Document Control Number: EPA

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- A1 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Bottom Ash Transport Water While SCE&G’s coal units currently utilize either dry hand ling of bottom ash or utilize a recirculated wet system, the cost/benefit for requiring dry ash handling of bottom ash is truly not justified, especially considering the limited data set EPA used. In addition, relative to fly ash, bottom ash has a substan tially smaller associated pollutant load, but regardless, SCE&G believes that 100% recycle of recirculated wet systems is not feasible and does not account for plant upsets, the accumulation of fines, significant storm events for outdoor systems, and other unknown variables. The costs required to modify these systems to totally eliminate all discharges from wet recirculated systems would be significant and was not adequately considered. Therefore, while SCE&G agrees with our member associations that the ba sis for requiring dry bottom ash handling is not justified based on the cost/benefit, and that ponds are adequate treatment, we encourage EPA, at a minimum, to allow temporary discharges from recirculated wet systems to ponds to account for potential unkno wns such as those listed above. Comment Response: The final rule record demonstrates that plants can install and afford the dry handling or closed

loop systems selected as the BAT basis for control of pollutants in bottom ash transport water (see preambl e sections VIII and IX). EPA also included costs for a chemical feed system to control pH for all remote mechanical drag system installations, should that become necessary to prevent scaling within the system. However, information in the record indicates t hat few, if any, plants are likely to need to use such systems. Additionally, data in the record indicate that there are plants in the industry that achieve complete recycle of bottom ash transport water, with no discharge. EPA has not received any specifi c data suggesting that upsets, accumulation of fines, significant storm events for outdoor systems, or other unknown variables contribute to the inability for plants to completely recycle bottom ash transport water. See response to DCN EPA

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- 497 Commenter Name: Basil G. Constantelos Commenter Affiliation: Midwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Zero Discharge Limitations For Bottom Ash Transport Water Are Not Cost

- Effective.
Midwest Gen urges EPA to reconsider its cost

- effectiveness analysis for the installation of dry handling or closed loop systems for bottom ash transport. [[Confidential Business Information Redacted]] Midwest Gen does not believe that EPA’s record regarding its cost

- effectiveness determinations or its record regarding potential pollutant reductions adequately supports its p roposed options that would base BAT for bottom ash transport water on dry handling or closed looped systems. Midwest Gen incorporates by reference the more detailed comments of Edison Electric Institute (EEI) in support of this point. Comment Response: See response to DCN EPA

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.

Commenter Name: Paul Carpmone Commenter Affiliation: Tampa Electric Company (TE C) Document Control Number: EPA

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- A2 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Cost of Retrofitting to Dry Handling Bottom Ash Not Proportional to Perceived Benefit EPA states that the primary pollutants of concern are total suspended solids (TSS) and heavy metals. However, these are the very pollutants that are most like to settle out in ponds or impoundments. At Big Bend TEC currently sends bottom ash and transport water to two ponds or CCR impoundments that are lined with 80

- mil high

- density polyethylene. From these ponds,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 498 the bottom ash is recovered and sold for beneficial reuse. As discussed previously, the bottom ash transport water is typically returned for additional bottom ash transport or, when necessary, commingled in the Recycle Water System and returned to the plant for reuse, including makeup water for the FGD scrubber. The only means of discharge of the Recycle Water is through the chloride purge from the FGD system. This purge stream is treated by chemical precipitation and the effluent is monitored for TSS and metals prior to discharge into cooling water . Electing a "zero discharge" option for this transport water or requir ing dry handling of bottom ash would require TEC to install a fully

- redundant bottom ash dry

- handling system as the proposed rule does not allow for any downtime for maintenance. The retrofit of dry handling system on an existing power plant would present a unique set of engineering and operational challenges. Not only would this retrofit would be a great expense, but would offer little benefit and actively hinder water reuse and conservation as well as create an additional parasitic load, thereby increasi ng monthly operations and maintenance (O&M) costs. Comment Response: EPA estimated compliance costs associated with a full bottom ash handling conversion to eliminate the discharge of bottom ash transport water. EPA’s record demonstrates that plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water. EPA disagrees that a retrofit would “hinder water reuse and conservation.” By installing dry handling or closed

- lo op bottom ash handling system, the plant will be reducing the amount of intake or make up water required for sluicing operations and will completely recycle bottom ash transport water. If the plant installs a mechanical drag system, data show that operatio n and maintenance costs will actually decrease.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 16 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In my opinion, if a dry system had been evaluated (and the errors in EPA's cost analyses discussed elsewhere were corrected), it would have resulted in zero discharge of bottom ash sluicing waters be ing included in all options as dry handling is more cost

- effective and has many more environmental benefits than wet options.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 499 Comment Response: EPA’s record demonstrates that plants can install and afford the dry handling or closed

- loop systems select ed as the BAT basis for control of pollutants in bottom ash transport water. EPA encourages the use of completely dry bottom ash handling systems and acknowledges potential savings due to ceasing wet sluicing operations. Additionally, some dry systems coul d result in coal consumption savings and CO2 emission reduction. EPA notes that the installation of the mechanical drag system does eliminate the discharge of bottom ash transport water and can reduce operation and maintenance costs.
EPA selected the mecha nical drag system as a BAT basis based on the number of plants installing and converting bottom ash handling systems from 2000 through 2009. EPA included the remote mechanical drag system as a BAT basis based on the knowledge that some plants do not have t he space available underneath the boiler to accommodate a mechanical drag system conversion. Based on vendor data, there have been no new U.S. utility plants with pulverized coal boilers built with either pneumatic or vibratory technology in the last 25 ye ars (DCN SE01825A80). Also, see response to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 19 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Other dry systems, such as the Magaldi MAC, have similar cost benefits compared to the wet MDS systems, but their more favorable costs were apparently not considered by the EPA. The benefits are demonstrated in Table 4, which compares O &M costs for a retrofit from a wet sluice system to both a dry MAC and a typical wet SCC (EPA's mechanical drag system) at a 500 MW plant in Florida (in 1993!). 50 As discussed elsewhere in this Report, EPA failed to account for the substantial cost and env ironmental benefits of a true dry system.

50 Barsin 1996, Tables 1

- 4 (These costs, reported in 1995 dollars, can be converted to 2010 dollars by multiplying by 1.45). Comment Response: See response to DCN EPA

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- 500 Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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Comment Excerpt:

The O&M costs for true dry systems are substantially lower and the environmental benefits substantially higher than for the wet recycle systems costed and evaluated by EPA as the cost basis for BAT for several reasons. First, dry systems allow more efficient boiler operation (from reduction in loss of carbon, latent heat and radiation). Second, dry systems eliminate makeup water costs, corrosion or blockages due to ash deposition or need for chemical addition. Third, dry systems require nearly zero maintenance (as the system runs autonomously without need forEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 501 continuous operator attention). Fourth, dry systems do not cause forced outages. If EPA had considered these factors, it would have seen a sharp drop in O&M costs associated with conversio n to dry ash handling. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 16. EPA acknowledges that a completely dry bottom ash handling system can eliminate make up water costs and corrosion or blockages due to ash deposit ion and eliminate the need for chemical addition. The installation of a mechanical drag system would also eliminate the need for chemical precipitation. Additionally, EPA determined that maintenance associated with the technology options selected as the ba sis for BAT can be completed during normally scheduled boiler outages (DCN SE01825A80).

Commenter Name: Shellie Chard

- McClary Commenter Affiliation: Association of Clean Water Administrators (ACWA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: If the data gathered and analysis performed by EPA supports a Dry Handling requirement for Bottom Ash treatment as part o f a BAT standard, then such a standard should be adopted in the final rule. As noted in comment 2, ACWA generally supports adopting BAT standards under this rule, unless circumstances warrant otherwise. Comment Response:
The final rule establishes BAT li mitations and PSES applicable to discharges of bottom ash transport water based on dry handling or closed

- loop technologies, except for discharges from generating units smaller than or equal to 50 MW or units that are oil

- fired. As described in preamble S ection VIII, EPA selected dry handling or closed loop systems as the technology bases for control of bottom ash transport water discharges because they are available, they are economically achievable (i.e., affordable) for the industry as a whole, and they have acceptable non
- water quality environmental impacts. See also response to DCN EPA

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- 502 16.a. Zero Discharge Bottom Ash

– Demonstration/Performance
Commenter Name: Patrick O’Loughlin Commenter Affiliation: Bu ckeye Power, Inc. Document Control Number: EPA

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- A2 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Furthermore, Buckeye Power has the practical prob lem of a lack of physical space to fit a dry bottom ash transport system on at least one of its units. Comment Response: EPA confirmed that a full bottom ash handling conversion would not be necessary for the commenter’s plant to eliminate bottom ash tra nsport water based on data provided in the Steam Electric Survey; therefore, physical space constraints are not an issue for meeting the final limitations applicable to bottom ash transport water. The commenter did not report discharging bottom ash transpo rt water in 2009, although it does have the ability to discharge through an emergency outfall. EPA determined that those plants that were able to operate an entire year without discharging bottom ash transport water (based on Survey data) would be able to continue doing so in the future. Furthermore, these plants very likely could continue doing so without any additional cost. However, for those zero discharge plants that have an emergency outfall authorized in their NPDES permits, EPA determined it was rea sonable to include bottom ash management costs to account for taking steps to completely eliminate the potential for discharge of bottom ash transport water. EPA notes that steam electric power plants may choose whatever technology they prefer to comply wi th the final rule requirements. They are not required to use the specific technology basis, i.e., mechanical drag system or remote mechanical drag system, used by EPA to estimate costs. See response to DCN EPA

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Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 503 Comment Excerpt: EPA has failed to acknowledge that MDS are not truly zero discharge systems. These systems must be drained prior to conducting any maintenance or inspections on the system. Comment Response: As described in Section 7 of the TDD, a mech anical drag system (MDS) is an under

- boiler system that collects bottom ash from the bottom of the boiler in a water filled trough. This water bath quenches the hot bottom ash as it falls from the boiler and seals the boiler gases. The bottom ash is then d redged from the water filled trough up an incline by a drag chain. Because the trough has a water bath, the MDS does generate some wastewater (i.e, residual water that collects in the storage area as the bottom ash continues to dewater). EPA does not consi der this wastewater to be bottom ash transport water because the transport mechanism is the drag chain (rather than hydraulic action of the water itself). Therefore, the MDS does eliminate bottom ash transport water. Additionally, EPA confirmed with an ash handling vendor that maintenance on the MDS can be completed while it is filled with water (for example, chain maintenance such as replacing chain links or crossbars) (DCN SE05823).

Commenter Name: Joe L. Citta Commenter Affiliation: Nebraska Public P ower District (NPPD) Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In the proposed rule, three of the eight option s (Options 4, 4a, and 5), including the lead option for regulating bottom ash, propose to set a zero discharge limitation for bottom ash. This will likely require the use of a dry handling technology that will obviate the use of transport water for bottom ash. The alternative to meeting this zero discharge limitation would involve the installation of technology for "managing a wet sluicing bottom ash handling system so that it does not discharge bottom ash transport water or pollutants associated with the b ottom ash transport water." Approximately 80 percent of the affected plants that generate bottom ash use water to transport the bottom ash to a surface impoundment or dewatering bins. Discharges occur from the surface impoundments or from blowdown from the water reused in the sluicing process. At some locations, these discharges are sent to an on

- site wastewater treatment facility.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 504 Therefore, EPA's adoption of a zero discharge limit for this wastewater stream would have a major impact on the electric power industry by requiring the conversion to dry handling of coal ash or other technology to eliminate the discharge of any pollutant s from the discharge of the bottom ash transport water. These options would impose significant cost on the industry because ret rofits of new material handling equipment in the limited space underneath existing boilers is complex and expensive. Comment Response: The record for the final rule record demonstrates that steam electric power plants can install and afford these dry and closed

- loop bottom ash technologies (see preamble sections VIII and IX). The steam electric industry has been and continues to undergo transformation as plants respond to a changed market outlook, as well as a changed regulatory environment. As a result o f changes in the industry, EPA estimates that, by the time plants would have to meet the final ELG requirements, and taking into account the effects of the Clean Power Plan (CPP), there will be 275 coal

- and petroleum coke

- fired plants operating in the Uni ted States. Of these 275 plants, EPA estimates that 172 (62.5%) either (1) already operate in a manner that would comply with the zero discharge requirement for bottom ash in the final ELGs, (2) have announced plant changes that they intend to make that wi ll result in compliance with the final ELGs, or (3) they are projected to make changes to comply with the CCR rule that will result in compliance with the final ELGs. EPA, therefore, estimates that of the 275 coal

- fired and petroleum coke

- fired plants oper ating, only 103 plants (37.5%) would ultimately incur costs to comply with the zero discharge limitations and standards for bottom ash transport water in this final rule. To be more specific, the 172 plants are as follows:

 76 Plants

– Based on their respon se to the Steam Electric Survey, these plants do not operate any wet sluicing systems for bottom ash for any of their generating units.

 64 Plants

– Already in compliance with the zero discharge requirement because of the following reasons (or combination o f reasons): complete recycle of all bottom ash transport water, generating units are at or under the 50 MW threshold, and/or partial retirements (meaning that the plant continues to operate, but all units with wet bottom ash are retiring).

 16 Plants

– Proj ected to convert the bottom ash handling system to implement the CCR rule.

 16 Plants

– Identified as bottom ash conversions from company announcements or survey data. Based on the reported dates, 13 plants already completed conversions, and 3 are still pla nned. (Note that these 16 plants represent 9% of the “already in compliance” population of 172 plants, or less than 6% of the total population of 275 coal plants). Also note that these plants do not reflect all announced conversions that were made in the m onths preceding promulgation (i.e., after August 2014), thus, there are additional planned conversions EPA was not able to take into account in its analyses (See DCN SE05069). EPA has also estimated costs for the ELG by using projections that assume the CP P rule has no effect on the number of plants that will be operating when plants will have to meet the finalEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 505 ELGs. For that scenario, EPA identified up to 313 generating units and 141 steam electric power plants that discharge bottom ash transport water and would incur costs to comply with the ELG. See the TDD and Costs & Loads Report for more details about that analytical scenario. The final rule identifies dry handling or closed

- loop systems as the BAT basis for control of pollutants in bottom ash transpo rt water discharges from existing generating units that are greater than 50 MW and are not oil

- fired. EPA identified two technologies, mechanical drag system and remote mechanical drag system, as the BAT basis for bottom ash transport water because of pote ntial space constraints at some steam electric power plants’ boilers. EPA adjusted compliance cost estimates for steam electric power plants that provided public comments specifically stating that they could not install a mechanical drag system due to spac e constraints. In these cases, EPA included costs associated with the remote mechanical drag system conversion. The remote mechanical drag system uses the existing wet sluicing equipment with the mechanical drag system located away from the boiler.

Comme nter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 34 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s Selection of Lowest Cost Option for Each Plant is Inappropriate For each plant requiring conversion from wet bottom ash handling to dry/closed

- loop bottom ash handling, EPA evaluated the costs for both the MDS and the RMDS technologies and then selected the technology with the lowest total annualized costs. This assump tion is not appropriate for many facilities. Some facilities do not have space to retrofit a MDS under the boiler. Some boilers were constructed sub

- surface while others are only several feet above the surface. In addition, some plants do not have space to locate a remote dewatering conveyor near the boiler due to nearby air pollution control equipment or equipment from other units. Therefore, EPA’s assumption that no costs will occur for land or space constraints is not correct. Many facilities will have t o relocate equipment or buildings to accommodate the new bottom ash handling equipment or purchase land nearby and purchase addition piping to reach it. In summary, EPA’s methodology for selecting the lowest cost of the two systems for each plant is flawed because it does not take into account site

- specific issues. Comment Response: EPA acknowledges that not all steam electric power plants will be able to retrofit generating units with a mechanical drag system due to space constraints such as the headspace underneath the boiler. However, EPA does not have information on the space available in the boiler blockEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 506 available from the Steam Electric Survey or other publicly available data sources for all steam electric power plants. Therefore, EPA selecte d two bottom ash technologies, mechanical drag system and remote mechanical drag system, as the basis for BAT. Commenters had an opportunity to tell EPA about any space constraints specific to their plant operations. In response to comments, EPA adjusted i ts cost estimates for the final rule to reflect space limitations identified by commenters for specific plants. For those plants that provided public comment specifically stating that they could not install a mechanical drag system due to space constraints , EPA based compliance costs on converting the bottom ash handling to a remote mechanical drag system. EPA did not receive any specific public comments on the inability to install a remote mechanical drag system at plants. For instance, plants did not spec ifically state that additional land or the relocation of equipment and buildings were necessary for the installation. EPA’s approach is reasonable given the amount of land available to plants based on the responses to the Steam Electric Survey, as well as visual observations during the many site visits EPA conducted over the course of the detailed study and rulemaking. In addition, many plants may decide to close or shrink the size of an existing ash impoundment since it may no longer be needed when wet dis posal of ash ceases (or the plant could decide that a smaller impoundment would suffice). Although the ELG does not require the impoundment to close and the CCR rule allows the impoundment to continue operating if it continues to receive non

- CCR wastes (su bject to other requirements established by the CCR rule), EPA notes that repurposing some or all of that land is an option available to plants. A simple way that a space

- constrained plant (if any plants were in such situation, which EPA has not identified, nor have commenters provided such information to EPA about) could implement this approach for repurposing the land occupied by an impoundment is to locate a remote MDS in a plant parking lot or designated staging area, and then after shifting the bottom a sh stream to the remote MDS the plant could take the steps needed to dewater and close the impoundment (or a portion of the impoundment). Based on the final rule compliance costs, EPA estimates that over 90 percent of the steam electric power plants identi fied as full bottom ash conversions will install remote mechanical drag systems. This estimate is even more conservative than the approach taken by EPRI in its industry cost estimates (DCN EPA

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- A1, Appendix E), which assumes that 25 per cent of the industry would install mechanical drag systems and 75 percent would install remote mechanical drag systems.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Commen t Excerpt Number: 40 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Engineering Aspects of Retrofitting Dry Bottom Ash HandlingEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 507 In reviewing the proposed ELG Rule, Southern Company engineers inve stigated possible technologies for dry bottom ash handling. Their summary of the conversion process for each type of dry bottom ash handling system is presented in Appendix A to these comments. As Appendix A makes clear, each of the four typical dry bottom ash handling systems has its own challenges and limitations, as well as its own engineering considerations. Dry bottom ash retrofits are not “off the shelf” technologies, but must be engineered to fit the particular site. Also, whatever technology is chos en, the time just to manufacture and deliver the components will be long. Southern’s engineers estimate that the equipment to retrofit a dry bottom ash hopper will be delivered 42

- 52 weeks after the manufacturer receives approved drawings; for a wet bottom ash hopper with a submerged flight conveyor, the equipment would require 52

- 56 weeks for delivery after the manufacturer receives approved drawings. Manufacturing lead time for either a remote ash hopper

- submerged flight conveyor or for hydrobins and su rge tanks would be approximately one year. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 155 in Comment Code 16.e for more information on EPA’s response to the information provided by the commenter in Appendix A.
S ee the response to DCN EPA

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Commenter Name: David M. Fraley Commenter Affiliation: City Utilities of Springfield, Missouri (CU) Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: A similar argument can be made for bottom ash and slag markets following the CCR rule proposal, but there is a fundamental difference at work. Fly ash must be collected in a dry form to have any value in the material recovery market; the zero

- discharge environmental benefit accrues naturally from what is (or used to b e) an economically attractive project. For bottom ash, the conversion is from one wet technique

– ash sluicing

– to another wet technique

– e.g., submerged flight conveyor

– with only minimal impact on ash marketability. In this case it is the technologica l challenge of the conversion project itself that renders the mandate unsuitable for retrofit on existing units. While the Agency asserts that all units, regardless of size, would be able to affordably convert to dry handling or closed loop systems, we wou ld posit that the space restrictions would preclude such conversion in a number of cases. This would especially be true for plants housing more than two units. The addition of the required mechanisms to medially located units would be sterically constraine d, resulting in systems that are unworkable,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 508 unserviceable, and unaffordable. These obstacles can be overcome when designing a drag conveyor for a new unit, but we respectfully suggest that the Agency did not fully consider the impact of these space consid erations when evaluating the universal availability of this option in a retrofit application. For the above reasons, we believe it is unreasonable and unworkable to require existing units to retrofit zero
- discharge ash handling systems. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 34.

Commenter Name: Jerry Purvis Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 9 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The record also does not contain analysis relating to pollutants of concern or unacceptable water quality impacts associated with use of impound ments solely for bottom ash transport water treatment (separate from combined fly ash transport water or FGD wastewater treatment). For example, in the Technical Development Document relating to the ash transport water characteristics, EPA notes that it d id not collect analytical data representing the characteristics of bottom ash transport water entering an impoundment during the sampling program for the rulemaking. (Page 6

- 10). While data was collected relating to fly ash transport water characteristics, the lack of data on the characteristics of bottom ash transport waters prior to impoundment discharge, separate and apart from analysis of combined fly ash transport and FGD wastewaters, makes consideration and evaluation of BAT factors for alternative d ry handling of bottom ash transport water incomplete. Comment Response: EPA disagrees that the “lack of data on the characteristics of bottom ash transport waters prior to impoundment discharge, separate and apart from analysis of combined fly ash transp ort and FGD wastewaters, makes consideration and evaluation of BAT factors for alternative dry handling of bottom ash transport water incomplete.” After proposal, EPA reviewed bottom ash transport water characterization data submitted by industry through p ublic comments and available through other publicly available sources. See the response to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a and “Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum” (DCN SE04745) for more information on the identification of pollutants of concern for bottom ash transport water. See the response to DCN EPA

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- 509 2009

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- A1, Excerpt Number 3 in Comment Code 6.e for discussion of why surface impoundments are not BAT for discharges of bottom as h transport water from all existing steam electric generating units. For the difference between technology

- based effluent limitations and water quality

- based effluent limitations, see responses to comments in Comment Code 6.c.

Commenter Name: John C. Po zzo Commenter Affiliation: Ameren Energy Resources Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
We believe that the installation of submerged flight conveyor bottom ash handling retrofits at most of our generating units would be difficult, if not infeasible, due to substantial interferences from other plant equipment and exterior space constraints from transformers and air pollution control equipment. In addition, the EPA notes in the TDD that mechanical drag systems "may not be suitable for all boiler configurations", obviously recognizing that there are site

- specific issues with retrofits (TDD page 7

- 3 4). An alternative dry

- handling retrofit would be a remote mechanical drag system, although only a single system of this type is operating in the United States. Therefore ,there is simply extremely limited experience within the industry and monitoring and treatment for scaling properties is apparently a potential issue. Per references cited in the TDD, cyclone boilers cannot use mechanical drag system retrofits (Clyde Bergmann Delta Oucon, "Bottom Ash Conversion Options and Economics") and state that "Con ventional Farm Dewatering can be utilized". If the discharge of bottom ash transport water is prohibited, we believe that it is imperative that the final ELGs contain provisions for intermittent blow down of bottom ash transport wastewater to effectively manage water inventory that will likely accumulate with the use of a conventional farm dewatering system, based upon our experience. We also believe that EPA has neglected to consider the additional maintenance incurred with pump impellors and piping base d on our prior experience with operation of these systems with cyclone boilers. Comment Response: EPA’s compliance cost estimates for the final rule for Ameren Energy Resources Company plants are based on remote mechanical drag systems. Therefore, potent ial space constraints under the boiler should not impact the ability of these plants to meet the final limitations and standards.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 510 See the response to DCN EPA

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- A1, Excerpt Number 34 for more information on space constraints associated wi th the mechanical drag system and EPA’s compliance cost methodology. The remote mechanical drag system has been in operation as a completely closed

- loop system at Wateree Station for 3 years without any operational difficulties, demonstrating that the tech nology is demonstrated in the industry. In addition, a number of other plants have installed or are currently in the process of installing the system. The industry is rapidly moving to implement changes to bottom ash handling systems, and the remote mechan ical drag system is the technology being selected in most instances. See the TDD and the record for more details about the ash system conversions that have been completed or are planned. EPA does not agree that the ELG needs to include provisions allowing plants to intermittently discharge a portion of the bottom ash transport water. Plants can effectively manage the water balance for a bottom ash handling system so that they do not need to discharge excess water. In fact, the system always has some water l osses due to evaporation or water leaving the system as moisture content on the removed ash. Furthermore, plants do not need to discharge a portion of the transport water in a closed

- loop system to prevent buildup of fines, nor to prevent corrosion or scal ing. EPA’s compliance cost methodology includes costs for a chemical feed system to control pH to prevent scaling or corrosion, should that become necessary to prevent scaling within the system. Information in the record indicates that few, if any, steam e lectric power plants are likely to need to use such systems. However, because EPA could not conclusively determine which steam electric power plants might actually need to add chemicals to control pH of the recirculating system, nor which of the steam elec tric power plants might likely need the system, costs were included for all steam electric power plants. Fines will be removed from the system along with other larger ash particles. However, should a plant determine it wanted to ensure fines remain at a lo w level, it could periodically add polymer to the remote MDS, which would flocculate the fines into larger particles to ensure they settle and are removed along with the other ash. Since adding chemicals for pH control will not be necessary for most plants , polymer addition would likely be accounted for by the costs for chemical addition included in EPA’s cost estimate. However, even if a plant were to add chemicals for both fines and pH control, EPA’s cost estimate would not change significantly because th e polymer addition would be a small fraction of the total system cost (on the order of $50,000 capital cost for polymer injection equipment). EPA determined that the dry handling and closed

- loop systems that are the BAT basis for control of pollutants in b ottom ash transport water are available for cyclone boilers. EPA notes that there is at least one cyclone boiler generating unit that currently operates a mechanical drag system (Kansas City Power & Light’s La Cygne Generating Station). EPA notes that the remote mechanical drag system is also available for cyclone boilers. The remote mechanical drag system uses the existing wet bottom ash transport system with a different dewatering process. See the response to DCN EPA

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- A1, Excerpt Numbe r 46 in Comment Code 6.g.ix for more information on cyclone boilers and the technologies evaluated as part of this rulemaking. Based on information from vendors and data provided in the Steam Electric Survey, there are steam electric power plants in the in dustry successfully operating completely closed

loop bottom ash handling systems without discharges.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 511 EPA does not agree that EPA’s costs do not account for maintenance to pumps or piping. EPA’s compliance cost methodology takes into account annual maintena nce material costs. These costs are associated with replacing equipment due to routine wear and tear, which would include pumps and piping. These costs were developed based on cost data reported in the Steam Electric Survey. See Section 9 of TDD and Sectio n 8 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) for more information.

Commenter Name : Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 55 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Excerpt: In Addition to the Substantial Costs, Conversion to Closed

- Loop Systems Would Require Arduous Investments of Time, Space, and Manpower for Many Facilities in the Industry. The admittedly low

- levels of pollutants found in bottom

- ash, and the gen eral lack of data concerning its impacts, do not justify installation of the available retrofit technology. Plants have limited space in which to achieve the maximum environmental benefit from control technologies. The dry

- handling retrofits proposed in th is rule are not only expensive (as discussed above), but cumbersome, requiring significant investments of space and potentially requiring the reconfiguration of other interrelated facilities. Such retrofits will necessarily exclude other technologies from occupying the same space. The available retrofit technology will also require significant investment of time to design, install, and operate. Nothing in the record justifies this significant investment of various plant resources. Generally, there are fo ur retrofit technologies available for modifying a plant to dry bottom ash handling: (1) dry bottom ash hoppers, (2) wet bottom ash hoppers, (3) remote ash hoppers, (4) decanting silos. Each of these poses significant reconfiguration and space issues and m ay be completely infeasible for a particular facility depending on its layout and size. Dry bottom ash hoppers may be incompatible with a boiler depending on the configuration of its structural steel bracing and the space between the boiler and the floor. Dry bottom ash hoppers also require ready access to outside walls for discharge of ash. Wet bottom hoppers (submerged flight conveyors) generally require a boiler house with a floor at grade because the required incline of the conveyor prevents the hopper from being located too far underground. They also require access to an outside wall. Remote ash hoppers (submerged flight conveyors) require significant foundations and large land area. In addition, they may require the relocation of existing piping. Final ly, decant silos require enough space for truck access and surge tank installation and significant foundations.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 512 Comment Response: EPA’s record demonstrates that plants can install and afford the dry handling or closed

- loop systems selected as the BAT bas is for control of pollutants in bottom ash transport water discharges from existing generating units that are greater than 50 MW and are not oil

- fired (see preamble sections VIII and IX). See preamble sections XIII and XIV for more information on EPA’s env ironmental assessment and benefits analysis. See response to DCN EPA

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- A2, Excerpt Number 7 in Comment Code 15, regarding the basis for EPA’s bottom ash transport water characterization. EPA acknowledges that not all steam electric power plants will be able to retrofit generating units with a dry bottom ash handling system (mechanical drag system or dry mechanical conveyor) due to space constraints such as headspace underneath the boiler. However, EPA does not have information on the spac e available in the boiler block of every plant based on either the Steam Electric Survey or other publicly available data sources. Therefore, EPA selected two bottom ash technologies (mechanical drag system and remote mechanical drag system) as the basis f or BAT. EPA adjusted compliance cost estimates for plants that provided public comment specifically stating that they could not install a mechanical drag system due to space constraints to reflect the remote mechanical drag system conversion.
EPA identifie d seven technologies available for modifying a plant to dry or closed

- loop bottom ash handling (excludes the wet sluicing and dense slurry systems). These technologies are described in detail in Section 7 of the TDD. Plants may choose the technology of the ir preference to comply with the final rule. They are not required to use the specific technology basis used by EPA to estimate costs. See the response to DCN EPA

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 58 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The time required to get a closed

- loop system into operation is also significant. After a study is undertaken to determine what technology is the best fit for the particular boiler, engineers must c reate facility

- specific designs that integrate the technology into the preexisting systems at the unit. After drawings are approved and submitted to a manufacturer, the period before delivery can span up to a year. This period is likely to increase substan tially if EPA mandates dry ash handling, as the demand for such control equipment will increase while the companies able toEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 513 supply the systems would remain relatively static. Once delivered, a system can require 16 weeks of outage time to install. Since bo th the demands of the electrical grid, as well as the availability of qualified technicians, would require a company to stagger such outages, it is reasonable to assume that a number of years might pass before a closed

- loop retrofit was actually installed and running. Comment Response: Based on information from the vendor, the outage time required for an under

- boiler mechanical drag system installation is approximately six to eight weeks. For the remote mechanical drag system, the majority of the constru ction can be completed while the generating unit is still online and only requires a few days to tie into the piping to the previously used surface impoundment or tank. Therefore, the installation for both of these systems can be completed during a normall y scheduled maintenance outage. See the response to DCN EPA

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Commenter Name: Basil G. Constantelos Commenter Affiliation: M idwest Generation, LLC. Document Control Number: EPA

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- A1 Comment Excerpt Number: 21 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Midwest Gen also notes that replacing the l arge volume of transport water with systems that use mechanical means to move bottom ash or closed loop systems would present serious feasibility and operational concerns. Midwest Gen would face space constraints, and the installation of the mechanical sy stems as well as developing onsite storage would present engineering and logistical challenges. Converting to these systems could also increase energy use, especially if blowers are used. Finally, the dry handling systems could result in increased road t raffic for hauling the bottom ash. Comment Response: EPA’s compliance cost estimates for the final rule for the Midwest Gen plants are based on remote mechanical drag systems. Therefore, potential space constraints should not impact the ability of these plants to meet the final limitations and standards. See the response to DCN EPA

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The final rule does not require steam electric power plants to develop onsite storage. Based on data reported in the steam electric survey, EPA determined whether plants have and operate aEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 514 CCR landfill. If they do have and operate an onsite CCR landfill, EPA estima ted costs for an expansion of onsite storage for purpose of the final rule. If they do not have and operate an onsite CCR landfill, EPA estimated offsite disposal costs for purposes of the final rule. EPA notes that if a mechanical drag system or other dry bottom ash handling system is installed (for example, a dry mechanical conveyor) the steam electric power plant operation and maintenance costs are likely to decrease. Additionally, increased road traffic may be a result of hauling bottom ash; however, ro ad traffic may also be decreased from the elimination of dredging bottom ash from surface impoundments and hauling it offsite.
EPA considered the non

- water quality environmental impacts associated with the final rule, and determined that they are acceptabl e. See preamble sections VIII.C.10 and XII.

Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 7 External Review Flag: No Exte rnal Review External Review Incorporated into Response: No Comment Excerpt: Finally, if EPA should choose dry bottom ash handling as BAT, the agency should recognize discharges resulting from maintenance and outage activities for some dry ash systems as low

volume wastes subject to BPT limits. EPA has considered bottom ash hoppers with dewatering bins, remote submerged flight conveyors and mechanical chain and drag systems as non

discharging. However, maintenance and outage activities can require that these systems be drained for repairs or inspections. Comment Response: EPA disagrees with the commenter that bottom ash hoppers with dewatering bins are considered “non

- discharging.” Only complete recycle systems (either with dewatering bins and a sur face impoundment or tank

- based systems) that eliminate the discharge of bottom ash transport water are non
- discharging. Based on information from vendors and data provided in the Steam Electric Survey, there are steam electric power plants in the industry successfully operating completely closed

- loop bottom ash handling systems

– i.e., non

- discharging systems. See the response to DCN EPA

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- A3, Excerpt Number 70 for more information on the quench water and maintenance associated with the M DS.
EPA estimated 5

- year recurring costs to account for rental tanks during remote MDS maintenance, specifically maintenance on the wear plate at the bottom of the remote MDS. These rental tanks would allow steam electric power plants to empty and temporar ily store the bottomEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 515 ash transport water in the remote MDS system. See TDD Section 9 and Section 8 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Sou rce Category (Cost & Loads Report) (DCN SE05831/SE05832) for more information. EPA confirmed with vendors that all other maintenance can be completed without draining the conveyor, including drag chain maintenance.

Commenter Name: Bruce W. Ramme Comment er Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 52 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Concerns with Assumptions EPA Made for Proposed Technologies for Dry Handling/Closed Loop We Energies also has concerns regarding EPA’s assertion that the proposed technology for dry handling/closed loop will result in a post

- compliance discharge loading of zero. In the Preamble, EPA indicate d that water draining from the bunker of submerged mechanical drag conveyors (Mechanical Drag System or “MDS”) would be low volume waste, not bottom ash transport water, yet EPA was silent regarding the water used to transport bottom ash to remote drag cha in conveyors (Remote Mechanical Drag System or “Remote MDS”). 78 Fed. Reg. at 34,449 col. 2. According to the TDD, overflow water from the Remote MDS is reused in the bottom ash handling system, but some plants may have to install a pH adjustment system t o treat the overflow prior to recycle to prevent scaling and fouling in the system. 2013 TDD at 7

- 35. We Energies is concerned that the bottom ash transport water, which becomes “overflow” from the Remote MDS, would not be able to be discharged under Reg ulatory Options 4a (for units larger than 400 MW), 4, and 5. While the overflow should be able to be recirculated and recycled in the bottom ash transport system, the wastewater may need to be blown down from time to time to prevent corrosion from the sal ts which concentrate in the wastewater. Comment Response: Based on information from vendors and data provided in the Steam Electric Survey, there are steam electric power plants in the industry successfully operating completely closed

- loop bottom ash han dling systems without discharges. As described in Section 7 of the TDD, wastewater that is collected in the storage area and that continues to dewater from the mechanical drag system is not bottom ash transport water. In the mechanical drag system, the tra nsport mechanism is the drag chain, not the water. The water associated with the remote mechanical drag system is ash transport water because it is merely another form of wet

- sluicing system, whereby water is the transport mechanism that moves the bottom a sh away from the hoppers.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 516 Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 8 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
B. Conversion to Closed
- Loop Systems Would Require Arduous Investments of Time, Space, and Manpower for Many Facilities in the Industry Installation of the cumbersome retrofit technology proposed by EPA is not justifie d by the admittedly low

- levels of toxicity related to bottom

- ash or the general lack of data concerning its impacts. Because a given facility only has a limited amount of space to hold all environmental control technologies, each piece of equipment “compet es” for space in a very real sense. There are four retrofit technologies generally available for modifying a plant to dry bottom ash handling: (1) dry bottom ash hoppers, (2) wet bottom ash hoppers, (3) remote ash hoppers, and (4) decanting silos. Each pos es significant and unique reconfiguration and space issues and may be completely infeasible for a particular facility depending on its layout and size. Dry bottom ash hoppers may be incompatible with a boiler depending on the configuration of its structura l steel bracing and the space between the boiler and the floor. Dry bottom ash hoppers also require ready access to outside walls for discharge of ash. Wet bottom hoppers (submerged flight conveyors) generally require a boiler house with a floor at grade b ecause the required incline of the conveyor prevents the hopper from being located too far underground. They also require access to an outside wall. Remote ash hoppers (submerged flight conveyors) require significant foundations and large land areas. In ad dition, they may require the relocation of existing piping. Finally, decant silos require enough space for truck access and surge tank installation, as well as significant foundations. Once a facility installs the technology compatible with its facilities, it will be precluded from using that same space for other valuable environmental control technologies in the future. The time required to get a closed

- loop system into operation is also significant. After a study is undertaken to determine what technology is the best fit for the particular boiler, engineers must create facility

- specific designs that integrate the technology into the preexisting systems at the unit. After drawings are approved and submitted to a manufacturer, the period before delivery can span up to a year. This period is likely to increase substantially if EPA mandates dry ash handling, as the demand for such control equipment will increase while the number of companies able to supply the systems would likely remain static. Once delivered, a system can require 16 weeks of outage

- time to install. Since both the demands of the electrical grid, as well as the availability of qualified technicians, would require a company to stagger such outages, it is reasonable to assume that a number of year s might pass before a closed

- loop retrofit was actually installed and running.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 517 As the relevant data demonstrates, the dry

- handling retrofits proposed in this rule are not only expensive, but require significant investments of space and, potentially, the re configuration of other interrelated facilities. Because such retrofits are expensive, prevent other control technologies from occupying the same space, and require significant investment of time to design, install, and operate, they are simply not justifie d by the currently available data. Comment Response: See the response to DCN EPA

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loop bottom ash handling. See the response to DCN EPA

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- A1, Excerpt Number 58 for more information on timing. EPA does not agree that a plant would need 16 weeks of outage time to convert the bottom ash handling system and, in fact, determined that it can done w ithout adding any additional time to routine plant maintenance outages. See the TDD for a discussion of the amount of outage time that would be needed to convert a bottom ash handling system.

Commenter Name: Cathy S. Woollums Commenter Affiliation: Mid American Energy Holdings Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 20 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Similar to dry handling retrofits to handle fly ash, it is costly to retrofit facilities that are already experiencing space constraints. Comment Response: The final rule record demonstrates that steam electric power plants can install and afford the dry handling or closed

- loop systems s elected as the BAT basis for control of pollutants in bottom ash transport water discharges from existing generating units that are greater than 50 MW and are not oil

- fired. See preamble section VIII. See response to DCN EPA

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- 518 Commenter Na me: Stephen M. Frank Commenter Affiliation: NRG Energy, Inc. Document Control Number: EPA

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- A2 Comment Excerpt Number: 27 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Pred ictions that Facilities will Choose to Convert Sluicing Operations to Dry Ash

- handling Systems As described in the preamble to the proposed ELGs, EPA is predicting that some facilities will choose to convert their sluicing operations to dry ash

- handling sy stems. While some facilities will likely choose to convert to dry ash

- handling systems, this decision needs to be made near the end of the useful life of the existing sluicing systems, not by a predetermined date as proposed. Expediting this process throug h regulation, will likely cause facilities to choose to convert the existing sluice systems to 100% recycling systems or deactivate the facilities. Unintended consequences of the proposed ELG would be the premature closing of facilities or conversion of mo re sluice systems to 100% recycling systems that utilize existing dated infrastructure and impoundments that are more prone to malfunction and have an increased risk of releases to the environment. Comment Response:
Based on data in the Steam Electric Su rvey and obtained from vendors or announced by plants, there are many steam electric power plants currently converting from bottom ash wet sluicing to dry or closed

- loop bottom ash handling. Some of these conversions may eliminate the use of surface impoun dments and may decrease the annual operation and maintenance costs associated with the bottom ash handling system. As described in preamble section VIII, where BAT limitations in the final rule are more stringent than previously established BPT limitations , those limitations do not apply until a date determined by the permitting authority that is as soon as possible beginning November 1, 2018 (approximately three years following promulgation of this rule), but that is also no later than December 31, 2023 (a pproximately eight years following promulgation). Therefore, steam electric power plants have time to evaluate all bottom ash handling options and the appropriate retrofit. Steam electric power plants may choose the technology they prefer to comply with th e final rule. They are not required to use the specific technology basis used by EPA to estimate costs. EPA also evaluated whether steam electric power plants might choose to retire older generating units rather than install retrofits to comply with the re vised ELGs, but did not find that to be theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 519 likely outcome. EPA analyzed the impacts that the ELGs may have on the steam electric industry using the Integrated Planning Model (IPM) and estimated that the requirements associated with the ELG would have litt le effect on steam electric generating capacity in terms of retirements. See the preamble and RIA. The installation of a dry or closed

- loop bottom ash handling technology would reduce or eliminate the amount of bottom ash sluiced to a surface impoundment, reducing the risk of failures and ash pond releases to the environment.

Commenter Name: Erin Bartlett Commenter Affiliation: The Large Public Power Council (LPPC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In the proposed rule, three of the eight options (Options 4, 4a, and 5); including the lead option for regulating bottom ash, propose to set a zero discharge limitation for bottom ash. This will likely require the use of a dry handling technology that will obviate the use of transport water for bottom ash. 3 The alternative to meeting this zero discharge limitation would involve the installation of technology for “managing a wet sluicing bottom ash handling system so that it does not discharge bottom ash transport water or pollutants associated with the bottom ash transport water.” 4 Approximately 20 percent of affected plants that generate bottom ash use a dry handling technology or other system that eliminates the use of the transport water. The remaining 80 percent of the plants use water to transport the bottom ash to a surface impoundment or dewatering bins. 5 Discharges occur from the surface impoundments o r from blowdown from the water reused in the sluicing process. At some locations, these discharges are sent to an on

‐ site central wastewater treatment facility. Therefore, EPA’s adoption of a zero discharge limit for this wastewater stream would have a maj or impact on the electric power industry. Specifically, it would require 80 percent of the current coal fleet to convert to dry handling of coal ash or other technology for eliminating the discharge of any pollutants from the discharge of the bottom ash tr ansport water. These options would impose significant cost on the industry: retrofits of new material handling equipment in the limited space underneath existing boilers are complex and expensive.

3 78 Fed. Reg. 34,462 (June 7, 2013).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 520 4 Id

. 5 Id

. Comment Response: As a result of changes in the industry, the number of plants that are estimated to incur compliance costs for the final ELG is smaller than EPA estimated at proposal. See the response to DCN EPA

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- A1, Excerpt Number 9 . EPA’s analysis shows the ELG would have little impact on coal

- fired electricity generating capacity. See preamble sections VIII and IX, and the RIA.

Commenter Name: Erin Bartlett Commenter Affiliation: The Large Public Power Council (LPPC) Document C ontrol Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: industry experience indicates that converting existing EGU’s bottom ash handli ng systems to dry handling systems is extremely costly and has minimal health and environmental benefits. Retrofitting dry collection would require long unit outages and substantial associated replacement power costs during the outages. In addition, the co nstruction required for dry collection would occur in the section of the facility that is most congested, which will further increase the cost and technical challenges of completing such retrofits. Therefore, because there will be little environmental bene fit and significant costs, EPA should maintain the surface impoundments treatment option for bottom ash transport water at all EGUs regardless of unit size. Comment Response: The final rule record demonstrates that steam electric power plants can instal l and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water discharges from existing generating units that are greater than 50 MW and are not oil

- fired (see preamble sections VIII a nd IX). See preamble sections XIII and XIV for more information on EPA’s environmental assessment and benefits analysis for bottom ash transport water. See the response to DCN EPA

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- A1, Excerpt Number 58 for more information on outage ti me associated with mechanical and remote mechanical drag installations. In particular, EPA does not agree that converting to a remote MDS would require a plant toEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 521 extend the duration of a regularly scheduled maintenance outage, nor that a maintenance outag e specifically for the conversion would be necessary. See the TDD for more information. See preamble section VIII and response to DCN EPA

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- A1, Excerpt Number 3 in Comment Code 6.e for discussion of why surface impoundments are not BAT f or discharges of bottom ash transport water from all existing steam electric generating units.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Numbe r: 19 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Additionally, dry bottom ash handling is highl y dependent on the availability of landfill space. We are concerned that the lack of availability of existing landfill sites and the long lead times required to permit and construct new landfills may affect compliance with the ELG Rule. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 21.
See also the response to DCN EPA

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- A1, Excerpt Number 11 in Comment Code 27.e regarding landfill capacity and timing. It is important to note that converting the ash handling system does not create new volumes of solid waste. It merely affects the l ocation where the disposal will occur, for plants currently using impoundments for disposal, or the form of the ash (i.e., wet or dry). For plants that use their impoundments as storage impoundments, rather than disposal impoundments, the ELG would have no effect on the ash disposal. A plant using a storage impoundment temporarily sends the ash to the impoundment, and then periodically dredging the ash from the impoundment and hauls it to a landfill or for beneficial use. For plants using impoundments for d isposal, EPA’s cost estimates account for those plants already operating onsite landfills to send the bottom ash from the newly converted handling system to that landfill. For plants that do not have an onsite landfill, costs are based on hauling the ash t o an off

- site landfill. EPA concludes that such landfills are available, consistent with the approach used for the CCR rule. This is a reasonable judgment given how many generating units are retiring due to economic and other factors. As a result, there wi ll be less competition for landfill disposal capacity. In fact, because of these many retirements, there likely will be more opportunities for the remaining plants to market their ash for beneficial use rather than disposing of it in a landfill. Thus, EPA’ s cost estimate likely overestimates the actual compliance cost for the ELG.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 522 It should also be noted that once ash plants cease using the impoundment for ash disposal, they may choose to dewater the impoundment and convert it to onsite landfill capacity. That is one management outcome envisioned by the analyses for the CCR rule. Once no longer used for disposing of ash, the impoundment provides plants with a large area of plant property than can be repurposed as landfill capacity.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 43 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
The ab ility for a facility to convert to dry bottom ash and to continue operations into the future is dependent upon the availability of acceptable landfill space. We are concerned that the lack of availability of existing landfill sites may affect compliance w ith the ELG Rule requirements. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 21. Also see response for EPA

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- A1, Excerpt Number 19. See also the response to DCN EPA

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- A1, Excerpt Number 11 in Comment Code 27.e regarding landfill capacity and timing.

Commenter Name: Pamela F. Faggert Commenter Affiliation: Dominion Resources, Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 46 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Closed Loop Bottom Ash Transport Water System Option 4a requires units at greater than 400 MW to have closed loop bottom ash transport water systems. Option 4a, however, makes no provisions to allow for the discharge of transport water for chloride control or for maintenance. Treatment systems based on filtration and chemical precipitation on the closed loop cannot remove chlorides. Therefore, chlorides will concentrateEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 523 as they traverse the closed loop and cause unacceptable system corrosion leading to operational failures of the closed loop system. Operational failures of the closed loop system will then lead to forced outages of the associated boiler. It is essential that the bottom ash transport water be reliable for the boiler itself to remain reliable. For these reasons, Dominion supports the continued use of impoundments for treatment of bottom ash transport water for all units, regardless of size. Lik ewise, Dominion does not support closed loop bottom ash transport water systems. Comment Response: The buildup of chlorides has not been demonstrated to occur in the closed

- loop bottom ash handling systems that have operated for years in the industry (DC N SE05916). EPA has not identified any plants where this has been an issue, nor have commenters provided any data to support the assertion. For example, the Wateree Station has operated a closed

- loop remote MDS for approximately 3 years and no buildup of c hlorides has been observed. Commenters have not provided data for Wateree or other closed

- loop installations showing that chlorides will concentrate. It is not surprising that chlorides are not building up in closed

- loop systems because there are always wa ter losses that occur with these systems (e.g., due to evaporation or entrainment with the ash hauled away). Water losses for a remote MDS average approximately 9% of the system volume each day. As water is lost from the system when the ash is hauled away, a portion of the chlorides that may be present would be removed. Then, as fresh water is added to the system to make up for the losses, any chlorides remaining in the system would be diluted. See the response to DCN EPA

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- A1, Excerpt Nu mber 7 for more information on the bottom ash transport water and maintenance associated with the remote MDS. See preamble section VIII and response to DCN EPA

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- A1, Excerpt Number 3 in Comment Code 6.e for discussion of why surface impo undments are not BAT for the control of bottom ash transport water discharges from all existing steam electric generating units.

Commenter Name: Tom DeLawrence Commenter Affiliation: Public Service Company of New Hampshire(PSNH) Document Control Number : EPA

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- A1 Comment Excerpt Number: 50 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The admittedly low

- levels of toxicity related to bottom

- ash, and the general lack of data concerning its impacts, do not justify installation of the retrofit technology. Plants have limited space in which to achieve the maximum environmental benefit from control technologies. TheEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 524 dry

- handling retrofits proposed in this rule are not only expensi ve (as discussed above), but cumbersome, requiring significant investments of space and potentially requiring the reconfiguration of other interrelated facilities. Such retrofits will necessarily exclude other technologies from occupying the same space. Th e available retrofit technology will also require significant investment of time to design, install, and operate. Nothing in the record justifies this significant investment of various plant resources. Generally, there are four retrofit technologies availa ble for modifying a plant to dry bottom ash handling: (1) dry bottom ash hoppers, (2) wet bottom ash hoppers, (3) remote ash hoppers, (4) decanting silos. Each of these poses significant reconfiguration and space issues and may be completely infeasible for a particular facility depending on its layout and size. Dry bottom ash hoppers may be incompatible with a boiler depending on the configuration of its structural steel bracing and the space between the boiler and the floor. Dry bottom ash hoppers also req uire ready access to outside walls for discharge of ash. Wet bottom hoppers (submerged flight conveyors) generally require a boiler house with a floor at grade because of the required incline of the conveyor prevents the hopper from being located too far u nderground. They also require access to an outside wall. Remote ash hoppers (submerged flight conveyors) require significant foundations and large land area. In addition, they may require the relocation of existing piping. Finally, decant silos require eno ugh space for truck access and surge tank installation and significant foundations. In addition to these facility

- specific issues, all closed

- loop system retrofits will impact a plant’s water management practices. Overall, water demand may decrease but sla g sluice water would need to be managed for pH, with a periodic blow down of that stream to remove impurities. Additionally, sometimes as much as one million gallons of boiler slag transport water can be generated in one day and is typically used as a make up supply for the FGD system. If forced to recycle slag waste water, another structure or device would need to be implemented to provide this one million gallons per day of water to the FGD system. The time required to get a closed

- loop system into operati on is also significant. After a study is undertaken to determine what technology is the best fit for the particular boiler, engineers must create facility

- specific designs that integrate the technology into the preexisting systems at the unit. After drawin gs are approved and submitted to a manufacturer, the period before delivery can span up to a year. This period is likely to increase substantially if EPA mandates dry ash handling, as the demand for such control equipment will increase while the companies able to supply the systems would remain relatively static. Once delivered, a system can require 16 weeks of outage time to install. Since both the demands of the electrical grid, as well as the availability of qualified technicians, would require a company to stagger such outages, it is reasonable to assume that a number of years might pass before a closed

- loop retrofit was actually installed and running. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 55 for more in formation on the bottom ash handling systems available for modifying a steam electric power plant to dry or closed

- loop bottom ash handling.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 525 See the response to DCN EPA

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- boiler MDS will not require a 16

- week outage to accomplish. See the TDD for more infor mation about outage requirements associated with the zero discharge requirement.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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e
. EPA’s Selection of Lowest Cost Option for Each Plant is Inappropriate For each plant requiring conversion from wet bottom ash handling to dry/closed

- loop bottom ash handling, EPA evaluated the costs for both the MDS and the Remote MDS technologies and then selected the technology with the lowest total annualized costs. This assumption is not appropriate for all facilities. Some facilities do not have spa ce to retrofit a MDS under the boiler. Some boilers were constructed sub

- surface while others are only several feet above the surface. In addition, some plants do not have space to locate a remote dewatering conveyor near the boiler due to nearby air pol lution control equipment or equipment from other units. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 34.

Commenter Name: Julia M. Blankenship Commenter Affiliation: American Municipal Power, Inc. (AMP) Document Control Number: EPA

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- A2 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry handling / close loop system for bottom ash transport water : AMP is concerned that this aspect of EPA’s preferred Option 4a (and also of Options 4 and 5) would, if adopted, present difficult retrofit issues, particularly for older coal plants.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 526 Comment Response: The final rule record demonstrates that steam electric p ower plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water discharges from existing generating units that are greater than 50 MW and are not oil

- fired (see pr eamble sections VIII and IX). EPA also confirmed that some of the generating units that reported retrofitting to a mechanical drag system in the Steam Electric Survey have been operating for more than 40 years. EPA did not find that age of a generating uni t would affect the technical feasibility for converting the bottom ash handling system. EPA also determined that the ELG is economically achievable (see preamble sections VIII and IX and the RIA).

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 103 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
A. ELIMINATING THE DISCHARGE OF BOTTOM ASH TRANSPORT WATER IS TECHNOLOGICALLY ACHIEVABLE. Based on the number of plants operating zero discharge systems and the number of vendors that commercially market such systems, it is undisputed that mechanical and remote mechanical drag systems are avai lable. For the purposes of BAT limits, a technology is available even if it is used at only the single, best

- performing plant. 421 A technology is available if it has been studied and demonstrated to work, such as through the use of pilot studies; the tec hnology need not be in commercial use to be considered available. 422 This contrasts with the less

- stringent BPT guidelines, which are based on the average of the best

- performing plants. 423 Ninety

- five coal and coke units operate mechanical drag systems. 4 24 More than 80 percent of coal

- burning units built in the last 20 years have installed zero discharge bottom ash handling systems. 425 In addition to the existing plants operating zero discharge systems, 74 units at 19 plants plan on converting from wet to dry handling of bottom ash. 426 Clyde Bergemann and United Conveyor Corp. market mechanical drag and remote mechanical drag systems; Allen

- Sherman

- Hoff markets a recirculation system. 427 United Conveyor Corporation, a vendor of dry bottom ash handling s ystems, advised EPA that 98 percent of plants could convert from wet to dry systems such as mechanical or remote mechanical drag systems. 428 The large number of plants operating mechanical drag and remote mechanical drag systems, and the number of vendors offering such systems, confirms EPA's conclusion that “all plants, regardless of size, are capable of installing and operating dry handling or closed

- loop systems for bottom ash transport water.” 429Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 527 Zero discharge systems that use no water at all, such as vacuum and pressure systems, are also technologically achievable, as demonstrated by the plants operating the systems and the vendors offering them commercially. In the United States, 66 plants have installed dry vacuum systems and 11 plants have installe d dry pressure systems. 430 Magaldi offers the Magaldi Ash Cooler (MAC) system, and Clyde Bergemann offers the DRYCON system. 431 Both systems use air, rather than water, to cool the hot bottom ash, and transport the ash without using water. Id.

421 Chem . Mfrs. Ass'n v. EPA , 870 F.2d 177, 226 (5th Cir. 1989) (“Congress intended these [BAT] limitations to be based on the performance of the single best

- performing plant in an industrial field.”); see also NRDC v. EPA, 863 F.2d 1420, 1426 (9th Cir. 1988).

422 See Kennecott , 780 F.2d at 448 (“In setting BAT, EPA uses not the average plant, but the optimally operating plant, the pilot plant which acts as a beacon to show what is possible.”); Am. Petroleum Inst. , 858 F.2d at 265 (for BAT, “a process is deemed ‘av ailable’ even if it is not in use at all”); FMC Corp. , 539 F.2d at 983

- 84 (upholding BAT for chemical oxygen demand based on performance data from a single pilot plant).

423 Chem. Mfrs. Ass'n , 870 F.2d at 207

- 08.

424 TDD at 7

- 31.

425 78 Fed. Reg. at 34,470

.
426 TDD at 7

- 30 to 7

- 31.

427 Fox Report, Appendix E, at 5

- 8.

428 EPA, Notes from USEPA

- UCC Conference Call with United Conveyor Corporation at 3 (Jan. 6, 2010), Docket No. EPA

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429 78 Fed. Reg. at 34,470.

430 78 Fed. Reg. at 34,454.

431 Fox Report, Appendix E, at 9. Comment Response: EPA agrees with the commenter that mechanical and remote mechanical drag systems are technologically available for the steam electric power generating industry. After proposal, EPA updated the industry profile information based on known changes in the industry (e.g., generating unit retirements, bottom ash handling conversions). After these updates, EPA determined that 84 generating units operate mechanical drag systems and that even moreEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 528 generating unit s are identified as converting to dry or closed

- loop bottom ash handling (see Industry Profile Changes Memo (DCN SE05069)). See the response to DCN EPA

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- A1, Excerpt Number 17 in Comment Code 16.e regarding dry vacuum and pressure bottom ash handling systems.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 12 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Zero Discharge Bottom Ash Handling Methods The EPA identified six methods to eliminate the transport water: (1) mechanical drag systems (TDD, Sec. 7.3.2); (2) remote mechanical drag systems (TDD, Sec. 7.3.3); (3) dry vacuum or pressure systems (TDD, Sec. 7.3.4); (4) vibratory belt systems (TDD, Sec. 7.3.5); (5) mechanical systems (TDD, Sec. 7.3.6); and (6) complete recycle systems (TDD, Sec. 7.3.7). 9 78 FR 34453/54. These cover the range of methods commercially available t o eliminate transport water from systems that handle the ash wet, but recycle water back to the boiler to systems that handle the ash dry without using any water at all. In this Report, the term "dry" is used to indicate systems that handle the ash without any water. My review confirms that these six methods are technically feasible for the subject units, commercially available, and cost effective. Commercial versions of each of these are briefly reviewed below and their relative merits are summarized to p rovide a framework for this Report. One or more of these methods is applicable to all of the units subject to this rulemaking, depending upon water availability, boiler house corridor availability (i.e., space constraints), unit operating characteristics, and other considerations. The EPA only analyzed the first two

– the mechanical drag systems and the remote mechanical drag systems, even though they are not the dominant technology in the market nor the most cost effective, efficient, and environmentally beneficial. The technical considerations for choosing among these options are summarized below, based on information published by their vendors 10 and summarized by EPRI and others. 11 These methods are briefly described below. Wet Zero Discharge Systems
Th e EPA identified three systems that handle the bottom ash wet with no transport water discharge: (1) mechanical drag system; (2) remote mechanical drag system; and (3) recirculation system. The two major vendors of these systems in the United Stated are U nited Conveyor Corp.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 529 (UCC) and Clyde Bergemann. The EPA only evaluated the first two wet systems. Each of these systems is briefly overviewed below and its distinguishing characteristics are identified. Mechanical Drag System (SSC, SFC) These systems coll ect bottom ash from the bottom of the boiler, route it to a water

- filled trough for cooling, and dewater it using an inclined drag chain system. TDD, Sec. 7.3.2. There are two commercially available drag chain systems, the SCC and SFC, described below. T he distinguishing characteristics of these technologies relative to wet sluicing are:

 No changes to the boiler, but requires direct path from under boiler

 Uses existing hopper and wet sluicing equipment

 Dewatering equipment located under boiler

 Reduced wat er consumption

 Reduced power consumption

 An economical choice

 Simple solution if space is available

 20 to 30 day outage to install The Clyde Bergemann Submerged Scraper Conveyor (SSC 12 ) is the basis of EPA's costs for the mechanical drag system. 13 Other vendors also offer this technology. 14 The SSC is used for continuous removal when high ash rates and large lumps are expected. A heavy duty chain conveyor is submerged in a water trough below the furnace which quenches hot ash as it falls from the combusti on chamber and continuously removes the ash on a de

watering slope. Dewatered ash is discharged onto mechanical conveyors or directly to storage silos. The United Conveyor Corp.'s Submerged Flight Conveyor (SFC 15 ) collects ash from the boiler into a water

- filled trough where it quenches and cools the ash. It consists of chain

- mounted flight bars that continuously travel through a water impounded trough. Overflow water is cooled and recirculated. This has been the industry standard on new units for se veral decades. According to UCC, the SFC system has proven to be the industry leader for performance and reliability, with over 100 applications worldwide. It is well suited for applications where water and headroom are limited. Remote Mechanical Drag Sys tem (ASHCON, CDR) Remote mechanical drag systems use the same operations and equipment as existing wet sluicing systems at the bottom of the boiler, but instead of sluicing to a pond, the slurry is pumped to a remote mechanical drag system, allowing the de watering equipment to be located away from in

plant congestion. TDD, Sec. 7.3.3. The two major vendors of these systems in the United Stated are United Conveyor Corp. (UCC) and Clyde Bergemann. The distinguishing characteristics of these technologies, rel ative to wet sluicing, are:

 No changes to the boilerEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 530  Uses existing hopper and wet sluicing equipment

 Dewaters ash with mechanical drag system

 Reduced water consumption

 Reduced power consumption

 Dewatering equipment is located away from the boiler, which is good where there are space or other limitations present at the bottom of the boiler

 Requires less maintenance than mechanical drag system, as ash has been ground and equipment is located away from boiler

 May require chemical treatment to control scaling, fouling and corrosion

 Can service multiple boilers

 No outage or very short outage to switch to new system

 Higher equipment maintenance, and power consumption The Clyde Bergemann ASHCON TM system is a remote submerged scraper conveyor technology. 16 This te chnology was selected by EPA for its remote MDS option. 17 It intercepts the pipelines leading to the ash ponds and diverts the slurry flow to an ASHCON remote submerged scraper conveyor (RSSC). This system is a good option for existing plants that do not have access and headroom to retrofit other systems directly under older boilers. Other remote systems require the retrofit of tall dewatering bins, settling tanks, and surge tanks in the field beyond the boiler island, which requires changing existing jet pumps and water supply pumps for much higher water pressure and motor horsepower to address the higher dynamic head. The ASHCON RSSC can be installed in the field while the boiler is on

- line and only a few days are needed to tie in the pipeline, requirin g very little outage time. The ASHCON can serve multiple existing units, usually receiving ash from one unit at a time as they are already grouped together in common pipelines. 18 As I will discuss further below, the EPA estimated costs on a unit

- by

unit b asis, thus significantly overestimating them. The United Conveyor Corp.'s Continuous Dewatering and Recirculation System (CDR) is a remote mechanical drag system. It mates with existing sluice conveying lines, diverting bottom ash slurry to a remote dewate ring conveyor outside the boiler house. It is easily incorporated into existing bottom ash hoppers, and it also requires no changes and only minimal outage time. The ash dewatering and removal conveyor is located outside of the boiler area. It can service one or more operating units, making it one of the most cost

- effective conversion alternatives available. It requires a significant increase in horsepower to lift the ash slurry to the top of the dewatering bins, which can be avoided by installing a low

- to

- the

- ground ASHCONTM remote submerged scraper conveyor. Recycle Systems (UCC Recirculation, HydrobinTM) Complete recycle bottom ash systems transport bottom ash with water, using the same process and equipment as used in wet sluicing systems. But, instead of being discharged, the sluice water, minus any losses from evaporation and water retained in the ash, is returned to the head end of the system and used as makeup. TDD, Sec. 7.3.7. The distinguishing characteristics of these technologies, relative to we t sluicing, are:

 No changes under boilerEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 531  Replaces ash pond with dewatering bins

 Uses existing hopper and wet sluicing equipment

 Reduced water consumption

 Reduced power consumption

 May require chemical treatment to control scaling, fouling and corrosion

 Can handle multiple boilers

 Shortest outage time for conversion

 Can be configured to accommodate conveying distances up to 12 miles and ash rates up to 150 ton/hr

 Higher equipment maintenance and power consumption The United Conveyor Corp. offers a closed

- loo p recirculation system that converts a wet sluice system into a zero discharge ash system without change to the existing bottom ash hoppers and, hence, with a minimal outage time. It replaces the ash pond with dewatering bins that separate the water and as h, a clarifying (settling) tank, and a surge (storage) tank. The ash is unloaded from the dewatering bins into transport vehicles for disposal. In a typical system, two dewatering bins are required. One bin fills while the other is dewatered and unloaded into trucks or rail cars. Water overflows to the settling tank and then into the surge tank. In the settling tank, a large percentage of the fine ash carryover settles to the bottom and is returned to the dewatering bin. Water leaving the settling tank goe s to the surge tank where recirculation pumps return it to the existing bottom ash sluice system. 19
Allen

- Sherman

- Hoff (A

- S

- H) offers the HydrobinTM Closed

- Loop Recirculation System design, claimed to be "the industry standard for efficiency and reliabilit y. This proven design is known for its effectiveness in quickly removing drain water from solid materials in slurry form." 20 The key components of this system include the hopper to collect the ash, the bottom ash gate housing to control material flow in to the grinder, the PowerASHTM single

- roll grinder or double

- roll grinder to properly size the material, the Hydro

- ejectorTM jet pumps to quickly move the water and solid granular material through the pipeline, the HydrobinTR dewatering bin to dewater the ash for disposal, the settling tank to receive the drained water and further remove fines, the surge tank to store the clarified water, and pumps to return the water to the system. 21

9 See also descriptions in: Babcock & Wilcox, Steam: Its Generation and U se, 40th Ed., Chapter 23 and 41st Ed., Chapter 24.

10 See, e.g., Magaldi Group, “Hot Bulk Material Handling and Dry Bottom Ash Extraction Systems;” Available at: http://w ww.power
- technology.com/contractors/materials/magaldigroup; Craig H. Fleming and Gary D. Mooney, “Bottom Ash Conversion Options and Economics, Clyde Bergemann, Post Power

- Gen Version,” 2011, (hereinafter “Fleming and Mooney 2011”). Available at: http://www.gerrardassociates.com/images/CBDD_Bottom_Ash_Conversion_Paper_

- _Post_Electric_Power_Version.pdf

.
11 “Electric Power Research Institute (EPRI), Bottom Ash System Maintenance Guide,” October 2000, Section 3.2; Russell Ray, “Coal Ash Handling & Storage: Shifting Direction, PowerEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 532 Engineering,” February 1, 2013; Available at: http://www.power

- eng.com/articles/print/volume

117/issue

- 2/abma

- special

- section/coal

- ash

- handling

- storage

- shifting

- direction.html

.
12 “Clyde Bergemann, Materials Handling and Air Pollution Control Solutions; ” Available at: http://www.anthonyross.com/_upload/CBD_Power_Brochure_Mar09_comp.pdf.

13 “Non CBI Bottom Ash MDS Capital Costs,” Docket No. EPA

- HQ

- OW

- 2009

- 0819

- 2888; and E PA, “Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category,” Docket No. EPA

- HQ

- OW

- 2009

- 0819

- 2256, April 2012, at p. 8

- 4, Eqn. 8

- 2. Referred to i n this report as the "Cost Analysis Report" or CAR.

14 “Alstom Power, Submerged Scraper Conveyor (SSC) System;” Available at: http://www.apcompower. com/_media/external/brochures/Submerged%20Scraper%20Conveyor %20System .pdf.

15 United Conveyor Corp., “Mechanical Systems;” Available at: http://unitedconveyor.com/mechanical/.

16 “Email from Gary Mooney to Elizabeth Sabol,” Re: ‘EPA/ERG Ash Handling Data Request,’ November 17, 2010, Attachment: Delta Ducon Ash Handling Attachment 11.10 GDM Responses.pdf, p. 2.

17 “Non CBI Bottom Ash Remote MDS Capital Costs,” EPA

- HQ

- OW

- 2009

- 0819

- 2888; CAR, Eqn. 8

- 39.

18 “Clyde Bergemann News, January 2011, ASHCONTM

- Remote Submerged Scraper Conveyor Technology Unveiled;” Available at: http://www.clydebergemanneec.com/_pdf/CBPG%20Newsle tter%2001

- 11.pdf; Fleming and Mooney 2011, pp. 10, 12.

19 United Conveyor Corp., “Recirculation Systems;” Available at: http://unitedconveyor.com/recirculation/.

20 Diamond Power, “HydrobinTR Dewater ing Bin,” 2007; Available at: http://www.diamondpower.com/Resources/Hydrobin_Product_Sheet.pdf.

21 Diamond Power, “Bottom Ash

- Handling Systems & Components: HydrobinTR Closed

- Loop Recirculation System;” Available at: http://www.diamondpower.com/ProductsServices/HYDROBINClosedLoopRecirculationSystem. aspx. Comment Response: EPA disagrees with the commenter that it “identified six methods to eliminate the transport water.” EPA identified seven bottom ash handling technologies that eliminate the discharge ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 533 bottom ash transport water. Some of these systems (e.g., the remote me chanical drag system, complete recycle) still use water to transport ash from the bottom of the boiler to intermediate storage or final disposal. These systems are described in Section 7 of the TDD and do not include the wet sluicing or dense slurry system s. One additional technology added to Section 7 of the TDD after proposal is the dry mechanical conveyor (the Clyde Bergemann’s DRYCONTM and Magaldi’s MAC

– Magaldi Ash CoolerTM). This system completely eliminates bottom ash transport water from the bottom a sh handling system. EPA notes that the remote mechanical drag system only eliminates that discharge of bottom ash transport water if it is operated as a complete recycle (i.e., closed

- loop) system. EPA’s compliance cost estimates associated with the remote mechanical drag system include the costs to achieve complete recycle, including additional piping, pumps, and chemical feed system. Regarding economies of scale, see response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4684

- A1, Excerpt Number 102. See the response to DCN EPA

- HQ

- OW

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- 4684

- A1, Excerpt Number 111 in Comment Code 16.e for more information on EPA’s technology basis for bottom ash transport water.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 4704

- A1 Comment Excerpt Number: 14 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Evaluation Of Zero Discharge Systems The major vendors, whose products are reviewed above, have eva luated the relative merits of these various systems. United Conveyor Corp. (UCC) compared requirements for their zero

discharge bottom ash handling systems, as summarized in Table 1.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 534 Similarly, Clyde Bergemann compared key impacts and costs of their zer o
- discharge bottom ash technologies, as summarized below in Table 2.
Table 2 : Clyde Bergemann Bottom Ash Handling Features Comparison 29Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 535 These Methods Satisfy BAT One or more of these methods is technically feasible for all of the units subject to this r ulemaking. They are currently widely used to handle bottom ash at numerous power stations around the world. In fact, 283 units at 194 plants subject to this rulemaking currently use these methods to eliminate transport water, amounting to about 30% of coa l and coke

- fired plants that handle bottom ash. 78 Fed. Reg. at 34,454, 34470 and TDD, Fig. 7

- 10. Further, 83% of the coal

fired units built in the last 20 years (50 units) installed dry bottom ash handling systems. 78 Fed. Reg. at 34,470, 34475. Finally, 10 to 30 additional units have announced retrofits by 2020. 78 Fed. Reg. at 34,453. 30 Numerous other power stations outside of the United States have used these methods for many years. European regulations promulgated in the early 1990s forced closure of most ash ponds, leading to installation of many zero discharge systems. 31 Magaldi, an Italian vendor, dominated the dry bottom ash handling business for many years and has the largest portfolio of publiclyEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 536 disclosed dry applications. 32 Its MACTM system ha s been installed at over 179 plants, 33 including both new and retrofit projects on many different boiler types and makes in a wide range of operating conditions around the world. Magaldi is represented in the U.S. by Allen

Sherman

- Hoff (A

- S

- H), a division of Diamond Power International, Inc, 34 soon to be announced as a division of Babcock & Wilcox, the largest boiler vendor in the world. Chinese vendors have developed a Magaldi

- look

- alike dry bottom ash handling system and have reportedly installed it at more units than in the Magaldi portfolio. 35 China handles all of its bottom ash dry, Europe handles about 50% of its bottom ash dry, and India about 10%. 36 More recently, Clyde Bergemann 37 and United Conveyor 38 have emerged as important new players in the U.S. market for dry bottom ash handling systems. United Conveyor claims "hundreds of installations and nearly 90 years of experience" with dry bottom ash systems .39 United Conveyor claims over 75 installation s of its recirculation system, over 100 submerged flight conveyor systems, and over 200 pneumatic ash extractors. 40 Others report that over 500 coal

- fired units, from <25 MW to 1000 MW, use dry bottom ash systems. 41 This large portfolio of successful installations of a wide range of zero discharge systems from multiple vendors indicates that zero discharge bottom ash handling is unquestionably technically feasible. Further, this huge experience base also clearly indic ates that the conversion from wet to zero discharge is economically achievable, as it is being widely achieved in practice, often driven by the need to reduce costs. These technologies are commercially available from at least four vendors in the U.S. (Clyd e Bergemann, United Conveyor Corp., A

- S

- H, Alstom); they are mature technologies, with over 25 years of operating history; and they are reliable, efficient, and safe. United Conveyor, who has 50% to 60% of the market for ash handling systems in North Ameri ca, 10% to 15% in Europe, and 5% in India, advised the EPA that ". . . nearly all (98+ percent) of plants should be able to convert a sluicing bottom ash system to a SFC, PAX, or VAX system (UCC trademark systems). Those plants unable to make the conversio n would be able to convert a pond

- based system to a recirculating system that employs dewatering bins." 42 Finally, the lead time to design, build, and install these units is typically 1 to 2 years ,43 well within the time allotted by the proposed rulemak ing (See, e.g., Table 1, "lead time"). The EPA concluded that all the technologies comprising Option 4a, a preferred BAT regulatory option, are "technologically available, economically achievable, and have acceptable non

- water quality environmental impacts ." The EPA also concluded all technologies comprising Option 4a "are well

- demonstrated and have been employed at subsets of existing power plants." 78 Fed. Reg. at 34,469. I agree with these conclusions, based on an independent review of the record and ot her publicly available material, but disagree with the 400

- MW exemption, for the reasons discussed elsewhere in this Report.

28 United Conveyor Corp. 2009, pdf 30

- 33; See “Wet

- to

- Dry Conversion,” supra note 26.

29 Fleming and Mooney 2011, Figure 16.

30 I a m only able to describe the number of additional units that have announced retrofits as a range because the exact number has been withheld as confidential business information.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 537 31 Joseph A. Barsin, Coal Fired Power Boiler System for Bottom Ash Removal With out Water, 1996 Joint Power Generation Conference, Vol. 1, ASME 1996, pp. 287

- 294.

32 See “Magaldi, Hot Bulk Material Handling,” supra note 10. See also: “Magaldi Dry Bottom Ash Tags;” Available at: http://www.magaldi.com/en/tags/Dry

- Bottom

- Ash/14,3.

33 Magaldi Group, “Magaldi Experience List;” Available at: http://www.magaldi.com/en/our_experie nce/power?l_code=&st=8&c_code=&s_cat=0&s_val=.

34 Allen

- Sherman

- Hoff, MACTM, “Magaldi Ash Cooler, Dry Bottom Ash System;” Available at: http://www.diamondpower.com/Resources/MAC_Brochure .pdf.

35 See, for example: (1) “Bottom Ash Removal System;” available at: http://www.longking

pcd.com/english/prod/Bottom.asp , and installed at http://www.longking

pcd.com/english/zhc/yj.as p; (2) “Dry Bottom Ash Handling System of Futong Company of China Electric Power Research Institute Achieved Great Breakthrough in Indian Market;” available at: http://gdft.sg epri.sgcc.com.cn/html/newsinfor589.shtm?cid=589; (3) Beijing Farthest Technology Co., Ltd., “Dry Bottom Ash Handling Systems;” available at: http://www.chinahsd.com/en/search.asp.

36 “ERG Memorandum fro m Kurt Blohm and Sarah Holman to Ron Jordan,” Docket No. EPA

HQ

- OW

- 2009

- 0819

- 0421, January 6, 2010, Re: Notes from EPA Conference Call with United Conveyor Corporation, p. 3.

37 See “Clyde Bergemann, Materials Handling,” supra note 12.

38 See, e.g., Unite d Conveyor Corp., “Dry Bottom Ash Handling Options & New Technology,” World of Coal Ash Conference 2009; Available at: http://www.flyash.info/2009/Charhut

WOCA2009

- plenary.pdf; See also, “Clyde Bergemann, Materials Handling,” supra note 12.

39 See United Conveyor Corp., “Wet

- To

- Dry Conversion, Bottom Ash & Fly Ash Systems,” supra note 26.

40 See id.

41 Qian Yu, “The Application of Air

- cooled Dry Bottom Ash Handling Technology at Coal Fired Power Plant, Proceedings of the IV Scientific and Practical Workshop: ‘Ashes from TPPs: Removal, Transport, Processing, Landfilling,’” 2012, p. 163

- 167; Available at: http://osi.ecopower.ru/en/full

- content.html.

42 See ERG Memorandum from Kurt Blohm and Sarah Holman, supra note 36, p. 2.

43 Dennis Del Vecchio and Robert G. Walsh, “Wet to Dry Bottom Ash Disposa l Conversion Project

- BL England Station, Power

- Gen, December 2011,” February 2008

- February 2010; Available at: http://www.naes.com/sites/defa ult/files/documents/delvecchio_speaker10835_session1236_2.pdfEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 538 ; “Dry Bottom Ash System Installation Unit NR IV of Ptolemaida Power Station,” (Project duration 8/1/94 to 8/31/96); Available at: http://cordis.europa.eu/opet/fiches/ff

- 20.htm; See also: “Email from Bret Renfroe,” December 15, 2003, Re; KIF Dry Fly Ash Collection (24 mo. install time for similar dry fly ash system); Available at: Fly Ash, http://www.tva.com/kingston/tdec/pdf/TVA

- 00013864.pdf Comment Response: EPA agrees with the commenter that plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water discharges from existing generating units that are greater than 50 MW and are not oil

- fired. See the response to DCN EPA

- HQ

- OW

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- 4448

- A1, Excerpt Number 40 in Comment Code 5.c for more information on EPA’s considerati on of the 400 MW threshold for bottom ash transport water.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 4704

- A1 Comment Excerpt Number: 21 External Review Flag: No External Revie w External Review Incorporated into Response: No Comment Excerpt: Dry Systems Have Lower Space Requirements The feasibility of MDS and remote MDS systems depend on adequate space available near the boiler. 51 Space availability is frequently a constrain t in many retrofit situations. A dry system eliminates dewatering bins, settling tanks, water circuits, and other equipment, thus saving space and resulting in a smaller footprint, a significant advantage in congested plants.

51 “ERG Telephone Call Record of Conference Call on April 21, 2011 between ERG, EPA, and UCC”, Docket No. EPA

- HQ

- OW

- 2009

- 0819

- 2190, Re: ‘Conversion from Wet to Dry Ash Handling Systems

- Fly Ash and Bottom Ash,’ pp. 14

- 15. Comment Response: See the response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4684

- A1, Excerpt Number 111 in Comment Code 16.e for more information on EPA’s technology basis for bottom ash transport water. EPA acknowledges that not all steam electric power plants will be able to retrofit generating units with a m echanical drag system due to space constraints (such as headspace underneath the boiler). Therefore, EPA selected two bottom ash technologies, mechanical drag system and remote mechanical drag system, as the basis for BAT. The remote mechanical drag systemEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 539 utilizes the existing bottom ash wet sluicing system and the conveyor is located away from the boiler. No other equipment except the remote conveyor, sump, and chemical feed system are required for the remote mechanical drag system installation.

Comment er Name: William Matthews Commenter Affiliation: Cleco Corporation Document Control Number: EPA

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- 5550

- A1 Comment Excerpt Number: 2 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Comment II

– Maintenance of closed loop systems may require intermittent discharge events A closed loop system where all the sluice water or blow

- down is recycled back to the equipment for use may occasionally require some type of maintenance or operatio nal activity resulting in an intermittent discharge. For example, maintenance on a pump might require water level in a bottom ash impoundment to be lowered for adequate access. The frequency and volume of such a discharge would be expected to produce a was te stream that is insignificant and should be classified as low volume waste similar to the water drained from bunkers in a mechanical drag system (78 Fed Reg, 34449, col.2). Comment Response: EPA does not agree that a closed

- loop system needs to periodi cally discharge for maintenance or other purposes. The technology bases for the zero discharge requirement is an under

- boiler MDS or remotes MDS. Neither of these systems require a discharge of ash transport water. See response to DCN EPA

- HQ

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- 4305

- A3, Excerpt Number 7.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 540 16.b. Zero Discharge Bottom Ash

– Costs
Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

- HQ

- OW

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- 4655 Comment Excerpt Number: 53 External Review Flag : No External Review External Review Incorporated into Response: No Comment Excerpt:
G. EPA's Bottom Ash Capital Costs 1. Methodology Evaluating EPA’s cost

- effectiveness analysis requires knowing the cost of the treatment technology (both capital and op erating and maintenance (O&M)) and the number of pounds of pollutant removed (adjusted for toxicity, so that removing a pound of a highly toxic chemical counts for more pound

- equivalents than removing a pound of a low

- toxicity chemical). To understand EPA ’s capital cost estimates for dry/closed

- loop bottom ash retrofits, the following section provides a summary of EPA’s cost methodology. EPA evaluated two technology options for bottom ash transport water: mechanical drag systems (MDS) and remote mechanica l drag systems (RMDS). EPA selected these two systems as the basis for the dry and closed

- loop recycle systems, respectively, based on system operation data from vendors and operation data from the 2010 ICR. EPA calculated capital costs for each plant as the sum of purchased and installed conveyance equipment costs for the MDS (including intermediate storage), plant

- level engineering costs, and bottom ash disposal costs, as described in the equation below. Capital Costs (2010$) = Conveyance & Intermediate Storage Equipment Costs + Plant Overhead Engineering Costs + Bottom Ash Disposal Costs EPA developed conveyance and intermediate storage equipment costs for both the MDS and RMDS using data provided by a single vendor, Clyde Bergemann Power Group (CBPG). See EPA

- HQ

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- 0819

- 2007. CBPG provided costs, including conveyance and intermediate storage costs, to EPA for the following MDSs.
1. ASHCON TM Remote Submerged Scraper Conveyor : The continued collection of bottom ash in water

- impounded hoppers, and the added integration of a hybrid Remote Dewatering Conveyor with a closed

- loop water system; no costs were provided for a treatment system (pH adjustment). 2. DRYCON TM System (sub
- boiler retrofit) : The collection, crushing, air cooling and mechanical conveying of bottom ash without the need for water quenching.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 541 3. Submerged Scraper Conveyor (SSC) (sub
- boiler retrofit) : The collection, water quenching and mechanical conveying of bottom ash with a closed

- loop cooling water system. Table 2 provides the costs that CB PG provided to EPA for the three systems described above. According to CBPG, the pricing “reflects fully erected and commissioned systems including equipment, controls, foundations, and field labor.” CBPG notes that the pricing for the ASHCON TM system does not include any wastewater treatment costs for the closed

- loop system.
Table 2: Bottom Ash Conversion Capital Costs Provided by Clyde Bergemann Power Group, $ in Millions*

Unit Capacity (MW) Remote MDS

(ASHCON TM ) Dry System

(DRYCON TM ) MDS

(SSC) <150 $4 $6 $7 150 to 300 $6 $8 $9 300 to 500 $9 $12 $13 500 to 700 $11 $15 $17 700 to 900 $15 $20 $22 * The pricing for ASHCON TM does not include any wastewater treatment costs for the closed loop system. EPA generated a cost formula for the MDS (SSC) and the Remote MDS (ASHCON TM ) systems, including the costs for conveyance and intermediate storage, based on unit capacity. EPA used the upper MW bounds ( i.e. , 150, 300, 500, 700, and 900 MW) versus capital costs to generate cost equations to es timate capital costs based on unit MW. EPA selected the following linear equations, based on the best R value, to estimate the retrofit costs for the MDS and the Remote MDS systems:
For MDS Conveyance Unit Capital Costs: Unit Costs (2010$) = 20,083 x Capa city (MW) + 3,000,000 Where Capacity = Generating unit capacity
For Remote MDS Conveyance Unit Capital Costs: Unit Costs (2010$) = 14,227 x Capacity (MW) + 2,000,000 Where Capacity = Generating unit capacity The capital costs for these two systems do not include the costs for buildings or land because EPA assumed zero land costs based on data from site visits and discussions with plants whoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 542 already have converted from wet to dry or closed

- loop recycle bottom ash handling. IC&PR, p. 8

- 4. 15 In addition, EP A does not include any costs for profits and overheads (contractor and subcontractor costs and insurance) or miscellaneous unidentified costs (contingency) even though their cost estimates are considered “screening level” costs. To estimate engineering ove rhead costs, EPA developed a factor from 2010 ICR Question C3

- 39 (conveyance) and Question C3

- 47 (intermediate storage). EPA compared the engineering overhead costs to the total capital costs for both conveyance and for intermediate storage. The median p ercentage for intermediate storage was 0%; therefore, EPA used the median percentage for the conveyance engineering costs, which was 1.765% or a factor of 0.01765. EPA’s factor for estimating engineering costs does not accurately estimate engineering cost s. Since CBPG cost estimates did not include pH conditioning systems for the MDS or Remote MDS system, EPA estimated the costs of a recycle pump and chemical feed system for the Remote MDS. EPA did not include pH conditioning for the MDS system even thoug h EPA assumed that this system would be closed

- loop. According to CBPG, the MDS or SSC system would require pH conditioning to achieve the “zero discharge” water limit. CBPG says “[i]n order to minimize corrosion, water treatment for pH control and heat exchangers may need to be included as part of the total system. This adds additional capital cost and operating cost.” Craig Fleming and Gary Mooney, Clyde Bergemann Delta Ducon, Bottom Ash Conversion Options and Economics, Brochure, EPA

- HQ

- OW

- 2009

- 0819

- 2075 at 8. As part of the capital cost formula, EPA included the cost of dry bottom ash transportation and disposal. The costs were based on 2010 ICR responses on bottom ash generation rates and the number of days each generating unit operated in 2009 wit h adjustments for moisture content. EPA also included recurring costs for both the MDS and remote MDS. EPA assumed that the drag chain for both the MDS and Remote MDS would need to be replaced every three and five years, respectively. Based on cost info rmation provided by United Conveyor Corporation (UCC), EPA estimated the drag chain replacement costs at $175,000 per unit, including labor and materials. IC&PR, p. 8

- 32. For each plant requiring conversion from wet bottom ash handling to dry or closed

- lo op bottom ash handling, EPA evaluated the costs for both the MDS and the Remote MDS technologies and then selected the technology with the lowest total annualized costs. EPA selected a 7% discount rate and a 20

- year time frame for operational life of the technologies. EPA did not provide information or supporting documentation for the 20

- year time frame. 2. EPA’s Capital Costs are Underestimated
a. Balance of Plant Costs are Low EPA depends exclusively on CBPG for balance of plant (BOP) costs. Even though CBPG states that its cost “reflects fully erected and commissioned systems,” their cost documentation makes no mention of electrical, mechanical (except for tie

- in of pipeline that previously went to the ash pond), upgraded control systems, boiler m odifications, upgraded piping (more erosive

- resistant material), demolition/relocation or structural modifications. CBPG notes that “[t]he estimatedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 543 prices are approximate as each plant site will vary in layout.” EPA

- HQ

- OW

- 2009

- 0819

- 2007, p. 6. In fact, when EPA requested the cost data from CBPG, EPA asked that the cost data “assume average industry operating conditions and no special circumstances ( e.g. , headroom below the boiler).” EPA

- HQ

- OW

- 2009

- 0819

- 2073, p. 4. EPA recognizes that costs will vary fr om plant to plant based on boiler configuration, capacity, conveyance distance, and number of units, but does not include any additional costs or contingency to cover these expenses. EPA

- HQ

- OW

- 2009

- 0819

- 2888.20. Therefore EPA’s capital costs for conveyan ce and intermediate storage are underestimated because they do not consider all of the BOP costs and costs associated with site

- specific issues. b. EPA Underestimated Engineering Overhead Costs EPA’s factor for estimating engineering overhead does not accu rately reflect these costs. Engineering costs include multiple phases of engineering, such as conceptual design, services during construction (SDC), project management, startup and operator training. EPA developed a factor of 1.765% of the total capital costs from 2010 ICR responses by calculating the median ratio of engineering overhead costs to the total capital costs for conveyance and intermediate storage. EPA assumed that the engineering costs incurred for these retrofits also include the owner’s ov erhead engineering costs. Based on UWAG’s bottom ash cost survey results, which include capital costs broken out by the major cost elements, the engineering overhead costs averaged 11.9% of the total costs or a factor of 0.1186. This amount seems very re asonable considering the conceptual design phase of engineering could take as long as one to two years.
c. EPA Does Not Include Costs for Profit and Overhead EPA did not include costs for general contractor and subcontractor profit and overhead, including bonding and insurance. These costs are major elements for any capital project and should be included in the total costs for these technologies. EPA’s past practice has been to include overhead and profits in its cost estimates. For example, in the Airpor t Deicing ELG, EPA included $84,000 in overhead and profit for installing 10,000 feet of stormwater piping, plus $21,000 for performance bonds and $19,300 for insurance. Airport Deicing TDD, p. 124. In addition, EPA added in another $84,000 for contracto r mark

- up, which it described as “handling, procuring, subcontracting, change orders, etc.” Id. In the Landfills ELG, EPA factored in 10% of the capital cost as general contractor overhead. EPA’s “Development Document for Final Effluent Limitations Guid elines and Standards for the Landfills Point Source Category,” EPA

- 821

- R

- 99

- 019 (Jan. 2000) (Final Landfills Development Document), p. 9

- 37.
d. EPA Does Not Include Costs for Miscellaneous Unidentified Costs EPA mistakenly assumed no costs for miscellaneou s unidentified costs or contingency. 16 This is not consistent with industry practice, nor is it consistent with EPA’s practice in other ELGs. Since EPA’s estimates are, at best, screening level costs with a small amount of projectEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 544 definition, contingency must be added to the total project costs to take into account miscellaneous unidentified costs. The accuracy of the cost estimate is generally a function of the amount of engineering completed at the time of the estimate. Some project risk factors includ e quantity variations (design is not complete), material unit price variations, labor productivity variations, labor rates variations, subcontract unit price variations, contractor indirect costs, poor scope definition, and market pressures (escalation, su pply shortages, unusual demand, etc.). It is standard practice, based on the Project Management Institute , to include contingency developed for the defined scope of work ( i.e. , class of cost estimates) to cover within

- scope uncertainties. Because of the undefined definition of the retrofit project and the risk factors listed above, EPA should include a minimum of 20% of the project direct costs in its cost formula for total capital costs. In previous ELGs EPA has routinely included contingency costs for e ngineering projects. See, e.g. , “Development Document for Final Effluent Limitations Guidelines and Standards for the Iron and Steel Manufacturing Point Source Category,” EPA

- 821

- R

- 02

- 004 (April 2002) (I&S Development Document), p. 10

- 4; CWT 2000 Developm ent Document, p. 11

- 2; MP&M Development Document, p. 11

- 19.

15 EPA apparently concluded that every facility that would have to retrofit dry bottom ash handling already had space available to accommodate the retrofit. But it is very unlikely that each an d every facility has enough land for the retrofit. In other ELGs, EPA has costed out land needed for new technologies. EPA’s “Development Document for the Effluent Limitations Guidelines and Standards for the Centralized Waste Treatment Industry

- Final,” EPA

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- 30; EPA’s “Technical Development Document for the Final Effluent Limitations Guidelines and New Source Performance Standards for the Airport Deicing Category,” EPA

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- 005 (April 2012) (Airport Deicing TDD), p. 127 (including the opportunity cost of land use for both storage and treatment of ADF

contaminated stormwater). EPA should have analyzed the land requirements for bottom ash, fly ash, and FGD retrofits.

16 Contingency can be defi ned as “an amount added to an estimate to allow for items, conditions, or events for which the state, occurrence, or effect is uncertain and that experience shows will likely result, in aggregate, in additional costs.” AACE International, AACE Internation al Recommended Practice No. 10S

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– Cost Engineering Terminology: TCM Framework: General Reference (Rev. April 25, 2013) (AACE International 2013). Comment Response: Based on a review of public comments and additional cost information (from commenters, vendors, and literature), EPA revised its cost estimates associated with the bottom ash transport water requirements in the final rule to account for updates to the population of steam electric power plants estimated to incur compliance costs, as well as adjustments to estimated costs for installing and operating dry or closed

- loop bottom ash handling systems. EPA identified twoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 545 technologies, mechanical drag system (MDS) and remote MDS, as the BAT basis for bottom ash transport water because of potential s pace constraints at some steam electric power plants’ boilers. EPA adjusted compliance cost estimates for steam electric power plants based on public comments specifically indicating that certain plants could not install a mechanical drag system due to spa ce constraints; in these cases, EPA estimated costs associated with the remote mechanical drag system conversion. In addition for the final rule, EPA also estimated 5

- year recurring costs to account for rental tanks during remote MDS maintenance, specifica lly maintenance on the weir plate at the bottom of the remote MDS. These rental tanks would allow steam electric power plants to empty and temporarily store the bottom ash transport water in the remote MDS system. Section 8 EPA’s Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) contains more information on the bottom ash handl ing cost estimates for the final rule. The following paragraphs summarize revisions made based on industry comments. Buildings. The final rule accounts for costs of constructing a building for remote MDS installations in climates known to have a mean daily minimum temperature of less than or equal to 32 ̊F. EPA applied a factor of 0.1875 to the purchased equipment costs to account for the cost of a building for the remote MDS installation. Section 8 of EPA’s Costs & Loads Report

. Indirect Capital Costs . Base d on a review of the public comments on engineering overhead costs, profits and overhead (other contractors fees), and miscellaneous unidentified costs (such as site

- specific issues, contingency estimates), the final rule uses an indirect capital cost fact or equal to 43 percent of the direct capital costs, which was developed based on information from Peters and Timmerhaus’ Plant Design and Economics for Chemical Engineers to represent costs associated with engineering and supervision, construction expenses , contractor’s fees, and contingency. Section 8 of EPA’s Costs & Loads Report.
Land Costs . For the final rule, EPA determined there is no need to include land costs associated with dry bottom ash handling conversions. Based on data from site visits, discus sions with operators of steam electric power plants that had already converted from wet bottom ash handling to dry bottom ash handling, the responses to the Steam Electric Survey, and vendors, EPA learned that it is very rare for plants to incur land acqui sition costs for dry bottom ash conversions (DCN SE05823). In addition, EPA did not receive any specific comments from steam electric power plants that stated they would need to acquire land to install a dry or closed

loop bottom ash handling system. Furth ermore, EPA notes that EPRI’s bottom ash handling cost methodology, submitted as part of public comments (DCN EPA

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- A1. Appendix E) also do not include costs for land acquisition. See EPA’s response to DCN EPA

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- A1, Ex cerpt Number 45 in Comment Code 14.b for more information on EPA’s fly ash methodology for land costs. pH conditioning

. For the final rule, EPA determined there is no need to include costs for a chemical feed system for MDS installations. The overflow from the MDS does not fall within the definition of bottom ash transport water, unlike the overflow from remote MDS, which does fallEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 546 within the definition of bottom ash transport water. Overflow from the MDS does not, therefore, need to meet the zero discharge requirements in the final rule. See Section 7 of the TDD for more information on overflow and other excess water (for example, water that drains off the bottom ash as it is further dewatered) from the MDS and remote MDS.
20

- year time frame. EPA used a tim e frame of 20 years based on the expected operational life of the dry and closed

- loop recycle bottom ash handling technology. EPA acknowledges that some components of the system have a service life much shorter than 20 years and will need repair or replace ment on a regular basis. EPA accounts for these components in the O&M cost estimates associated with maintenance materials (routine replacement of materials and equipment due to consumption or wear and tear). Twenty years is a typical planning period for w astewater treatment operations. Balance of Plant Costs
. In the documentation provided by the vendor CBPG, the bottom ash conversion estimates included the following note: “prices given reflect fully erected and commissioned systems including equipment, con trols, foundations, and field labor.” After reviewing public comments, EPA contacted CBPG to determine if the cost elements included the specific items identified by the commenter, including: “electrical, mechanical (except for tie

- in of pipeline that pre viously went to the ash pond), upgraded control systems, boiler modifications, upgraded piping (more erosive

- resistant material), demolition and relocation or structural modifications.” CBPG confirmed that electrical, mechanical, upgraded control systems, required demolition, and boiler modifications (specifically to the lower seal plate area, the portion requiring modification) are included in the cost estimates. CBPG also confirmed that cost estimates for the remote MDS (ASHCONTM) include upgraded piping t o a more erosive

- and corrosive

- resistant material. EPA notes that upgraded piping is not required for the MDS because the water in the trough does not fall within the definition of bottom ash transport water, and thus does not need to meet the final zero discharge requirements. Finally, CBPG confirmed that the cost estimates include costs for new structural modifications (DCN SE05823).

Commenter Name: Chas Spell Commenter Affiliation: Arizona Public Service Company Document Control Number: EPA

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 EPA has underestimated the costs of retrofitting bottom ash dry handling or closed

- loop systems.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 547 Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 71 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA’s cost estimate methodology for a MDS only accounts for approximately two

- thirds of the actual cost of the installation. Costs for auxiliary power, controls, construction management, and consulting engineering were not included in the EPA’s estimate. This miscalculation further creates a misleading dollar per pound of pollutant removed under a zero discharge sc enario. Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule, including with respect to indirect costs.

Commenter Name: Cari Boyce Commenter Affiliation: Duke En ergy Document Control Number: EPA

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EPA’s Cost Estimate Methodology Underestimates True Costs
EPA’ s cost analysis for this wastestream grossly underestimates the actual cost of the installation of a remote mechanical drag system. Using the methodology presented by EPA to calculate the cost of a known remote mechanical drag system installation, the resu lt yields a cost estimate that is about two

- thirds of the actual cost of the installation. Given the limited amount of information on how the costs were derived, it appears that items such as auxiliary power, controls, construction management, and consult ing engineering were not included in the estimate. Also, plants in northern climates will require a building for freeze protection.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 548 EPA states its “cost estimates include the following key cost components: capital costs (one

- time costs); annual operating a nd maintenance costs (which are incurred every year); and other one

time or recurring costs. Capital costs comprise the direct and indirect costs associated with the purchase, delivery, and installation of pollution control technologies. Capital cost eleme nts are specific to the industry and commonly include purchased equipment and freight, equipment installation, buildings, site preparation, engineering costs, construction expenses, contractor’s fees, and contingency.” 27 Equipment vendors, however, are not likely to be able to provide reliable cost estimates for these items listed or for foundation and balance

- of

- plant costs, as it is not within their core business. These items will vary quite a bit between sites based on the layout, geology and topology of the site. In addition, the methodology yields an engineering cost that is less than 2% of the installation cost which, by rule of thumb, is very low. For the known installation mentioned above, the cost for these engineering items, using EPA’s methodology , is only $230,000. This amount would not cover the utility’s internal engineering costs, much less, any outside consultants. Duke Energy conducted a comparison of the estimated costs provided by EPA and Duke Energy’s internal estimated costs to install a remote mechanical drag system at the each applicable station. The percentage by which the analysis underestimated the expected actual costs for each station is provided in the Table 2

- 12 below. On average, the analysis underestimated the costs by 47% for R egulatory Option 4a and by 36% for Regulatory Option 4 and 5.
Table 2
- 12. Summary of Percent Difference in EPA’s Estimated Remote Mechanical Drag System Installation Costs versus Duke Energy’s Estimate

Station EPA Underestimated the Costs By

Option 4a Option 4 & 5 Allen (1) 0% 32% Asheville (1) 0% 23% Belews Creek 41% 41% Cayuga 37% 37% Cliffside 63% 63% East Bend 65% 65% Gallagher (1) 0% 44% Marshall 56% 24% Miami Fort 41% 22% Roxboro 27% 27% Wabash River (1) 0% 12%
(1) All units are less than 400 MW. No costs would be incurred for Reg. Option 4a.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 549 Duke Energy Costs can be provided upon request. All costs will be classified as confidential business information (CBI).

27 TDD Section 9.1, page 9

- 2 Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule related to indirect costs and balance of steam electric power plants costs. Because the commenter did not provide details associated with its cost analysis, EPA was not able to evaluate Duke’s estimated steam electric power plant costs or compare Duke’s estimated costs to EPA’s cost estimates for the final rule.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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1. Remote Mechanical Drag System (MDS) Not Truly Zero Discharge
EPA assumes a re mote MDS is a zero discharge system, when in actuality these systems need to discharge water periodically. Overtime, constituents within the system accumulate in the water, therefore, affecting the performance of the system. This water will have to be peri odically replaced, similar to any closed cycle system to ensure performance and integrity of the components. In addition, maintenance and inspections will need to periodically occur to ensure the system operates properly. In order to conduct any inspection s or maintenance activities, the water will have to be removed. The amount of water will be dependent upon the individual station, but for a 500 MW unit, one MDS will contain approximately 112,000 gallons of water. If the piping between the boiler and a re mote MDS needs repair or inspection, the piping would also have to be emptied, which could add another 15,000 to 30,000 gallons depending on length. An approximate total volume of water, therefore, for a 500 MW unit that will have to be removed from the MD S to complete maintenance and inspection activities is approximately 140,000 gallons. EPA has not provided or discussed any means or costs on how this water can or should be handled under a zero discharge scenario.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 550 Comment Response:
The final rule record demonstrates that there are steam electric power plants managing closed loop systems currently that do not require discharge during operation and maintenance activities. For example, see TDD Section 7.3.9 for a discussion of complete recycle systems for bottom ash. EPA also added 5

- year recurring costs to account for rental tanks during remote MDS maintenance, specifically maintenance on the wear plate at the bottom of the remote MDS. These rental tanks would allow plants to empty and temporarily sto re the bottom ash transport water in the remote MDS. EPA confirmed with vendors that no other maintenance requires discharge from the remote MDS (DCN SE05823) and that complete recycle can be achieved either with the remote MDS or with a conventional close d

- loop system (DCN SE05916). EPA has also determined that there is no need to periodically discharge water from a closed

- loop system to prevent the build

- up of constituents in the bottom ash transport water.

Commenter Name: Chris M. Hobson Commenter Aff

iliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 32 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA evaluated two technology options fo r bottom ash transport water: mechanical drag systems (MDS) and remote mechanical drag systems (RMDS). EPA selected these two systems as the basis for the dry and closed

- loop recycle systems, respectively, based on system operation data from vendors and op eration data from EPA’s, Questionnaire for the Steam Electric Power Generating Effluent Guidelines , EPA

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- 0655.9 (May 20, 2010) (2010 ICR). EPA calculated capital costs for each plant as the sum of purchased and install ed conveyance equipment costs for the MDS (including intermediate storage), plant

- level engineering costs, and bottom ash disposal costs, as described in the equation below. Capital Costs (2010$) = Conveyance & Intermediate Storage Equipment Costs + Plant Overhead Engineering Costs + Bottom Ash Disposal Costs EPA developed conveyance and intermediate storage equipment costs for both the MDS and RMDS using data provided by a single vendor, Clyde Bergemann Power Group (CBPG). See EPA

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- 2007. CB PG provided costs, including conveyance and intermediate storage costs, to EPA for the following MDSs. (1) ASHCON TM Remote Submerged Scraper Conveyor : The continued collection of bottom ash in water impounded hoppers, and the added integration of a hybrid Remote Dewatering Conveyor with a closed

- loop water system; no costs were provided for a treatment system (pH adjustment).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 551 (2) DRYCON TM System (sub
- boiler retrofit) : The collection, crushing, air cooling and mechanical conveying of bottom ash without the n eed for water quenching. (3) Submerged Scraper Conveyor (SSC) (sub
- boiler retrofit) : The collection, water quenching and mechanical conveying of bottom ash with a closed loop cooling water system. Table 2 provides the costs that CBPG provided to EPA for th e three systems described above. According to CBPG, the “pricing given reflects fully erected and commissioned systems including equipment, controls, foundations, and field labor.” CBPG notes that the pricing for the ASHCON TM system does not include any wa stewater treatment costs for the closed

- loop system. Table 2: Bottom Ash Conversion Capital Costs Provided by Clyde Bergemann Power Group, $ in Millions* Unit Capacity (MW) Remote MDS

(ASHCON TM ) Dry System (DRYCON TM ) MDS

(SSC) <150 $4 $6 $7 150 to 300 $6 $8 $9 300 to 500 $9 $12 $13 500 to 700 $11 $15 $17 700 to 900 $15 $20 $22 * The pricing for ASHCON TM does not include any wastewater treatment costs for the closed loop system. EPA generated a cost formula for the MDS (SSC) and the Remote MDS (ASHCONTM ) systems, including the costs for conveyance and intermediate storage, based on unit capacity. EPA used the upper MW bounds ( i.e., 150, 300, 500, 700, and 900 MW) vs. capital costs to generate cost equations to estimate capital costs based on uni t MW. EPA selected the following linear equations, based on the best R value, to estimate the retrofit costs for the MDS and the Remote MDS systems:
For MDS Conveyance Unit Capital Costs: Unit Costs (2010$) = 20,083 x Capacity (MW) + 3,000,000 Where Capaci ty = Generating unit capacity
For Remote MDS Conveyance Unit Capital Costs: Unit Costs (2010$) = 14,227 x Capacity (MW) + 2,000,000 Where Capacity = Generating unit capacityEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 552 The capital costs for these two systems do not include the costs for buildings or land because EPA assumed zero land costs based on data from site visits and discussions with plants who have already converted from wet to dry or closed

- loop recycle bottom ash handling. Incremental Costs & Pollutant Removals for the Proposed Effluent Limi tations Guidelines and Standards for the Steam Electric Power Generating Point Source Category, EPA

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- 2256 (IC&PR), p. 8

- 4. 1 In addition, EPA does not include any costs for profits and overheads (contractor and subcontractor costs and insuran ce) or miscellaneous unidentified costs (contingency) even though their cost estimates are considered “screening level” costs. To estimate engineering overhead costs, EPA developed a factor from 2010 ICR Question C3

- 39 (conveyance) and Question C3

- 47 (inte rmediate storage). EPA compared the engineering overhead costs to the total capital costs for both conveyance and for intermediate storage. The median percentage for intermediate storage was 0%; therefore, EPA used the median percentage for the conveyance engineering costs, which was 1.765% or a factor of 0.01765. EPA’s factor for estimating engineering costs does not accurately estimate engineering costs. Since CBPG cost estimates did not include pH conditioning systems for the MDS or Remote MDS, EPA estim ated the costs of a recycle pump and chemical feed system for the Remote MDS. EPA did not include pH conditioning for the MDS even though EPA assumed that this system would be closed

- loop. According to CBPG, the MDS or SSC system would require pH condition ing to achieve the “zero discharge” water limit. CBPG says “[in] order to minimize corrosion, water treatment for pH control and heat exchangers may need to be included as part of the total system. This adds additional capital cost and operating cost.” (Cr aig Fleming and Gary Mooney, Clyde Bergemann Delta Ducon, Bottom Ash Conversion Options and Economics, Brochure).

1 EPA concluded that every facility that would have to retrofit dry or closed

- loop bottom ash handling already had space available to accomm odate the retrofit. But it is very unlikely that each and every facility has enough land for the retrofit. In other ELGs, EPA has costed out land needed for new technologies. Development Document for Final Effluent Limitations Guidelines and Standards for the Centralized Waste Treatment Industry

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- 005 (April 2012), p. 127 (including the opportunity cost of land use for both storage and treatment of ADF

- contaminated stormwater). EPA should have analyzed the land requirements for bottom ash, fly ash, and FGD retrofits. Comment Response: See the respons e to DCN EPA

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- 553 Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt N umber: 33 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: As part of the capital cost formula, EPA included the cost of dry bottom ash transportation and disposal. The costs were based on the amou nt of bottom ash generation rates and the number of days each generating unit operating in 2009 from the ICR with adjustments for moisture content. EPA also included recurring costs for both the MDS and remote MDS. EPA assumed that the drag chain for both the MDS and Remote MDS would need to be replaced every three and five years, respectively. Based on cost information provided by United Conveyor Corporation (UCC), EPA estimated the drag chain replacement costs at $175,000 per unit, including labor and mat erials. IC&PR at 8

- 32. For each plant requiring conversion from wet bottom ash handling to dry or closed

- loop bottom ash handling, EPA evaluated the costs for both the MDS and the Remote MDS technologies and then selected the technology with the lowest tot al annualized costs. EPA selected a 7% discount rate and a 20

- year time frame for operational life of the technologies. EPA does not provide information to supporting documentation for the 20

- year time frame. EPA’s Capital Costs are Underestimated
a. Balan ce of Plant Costs are Low EPA depends exclusively on CBPG for balance of plant (BOP) costs. Even though CBPG states that their cost “reflects fully erected and commissioned systems,” their cost documentation makes no mention of electrical, mechanical (exce pt for tie

- in of pipeline that previously went to the ash pond), upgraded control systems, boiler modifications, upgraded piping (more corrosive

resistant material), demolition/relocation or structural modifications. CBPG notes that “[t]he estimated prices are approximate as each plant site will vary in layout.” EPA

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- 2007, p. 6. In fact, when EPA requested the cost data from CBPG, EPA asked that the cost data “assume average industry operating conditions and no special circumstances (e.g., he adroom below the boiler).” EPA recognizes that costs will vary from plant to plant based on boiler configuration, capacity, conveyance distance, and number of units, but does not include any additional costs or contingency to over these expenses. EPA

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- 2888.20. Therefore, EPA’s capital costs for conveyance and intermediate storage are underestimated because they do not consider all of the BOP costs and costs associated with site

- specific issues. b. EPA’s Engineering Overhead Cost Factor is Wro ng EPA’s factor for estimating engineering costs does not accurately estimate engineering costs. Engineering costs include multiple phases of engineering, such as conceptual design, servicesEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 554 during construction (SDC), project management, startup and operat or training. EPA developed a factor of 1.765% of the total capital costs from 2010 ICR responses by calculating the median ratio of engineering overhead costs to the total capital costs for conveyance and intermediate storage. EPA assumed that the engineer ing costs incurred for these retrofits also include the owner’s overhead engineering costs. Based on UWAG’s bottom ash cost survey results, which include capital costs broken out by the major cost elements, the engineering overhead costs averaged 11.9% of the total costs or a factor of 0.1186. This amount seems very reasonable considering the conceptual design phase of engineering could take as long as one to two years.
c. EPA Does Not Include Costs for Profit and Overhead EPA did not include costs for gene ral contractor and subcontractor profit and overheads, including bonding and insurance. These costs are major cost elements for any capital project and should be included in the total costs for these technologies. EPA’s past practice has been to include ov erhead and profits in its cost estimates. For example, in the Airport Deicing ELG, EPA included $84,000 in overhead and profit for installing 10,000 feet of stormwater piping, plus $21,000 for performance bonds and $19,300 for insurance. Technical Developm ent Document for the Final Airport Deicing Category, p. 124. In addition, EPA added in another $84,000 for contractor mark

- up, which it described as “handling, procuring, subcontracting, change orders, etc.” Id. In the Landfills ELG, EPA factored in 10% of the capital cost as general contractor overhead. Development Document for Final Effluent Limitations Guidelines and Standards for the Landfills Point Source Category, EPA

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d. EPA Does Not Include Costs for Miscellaneou s Unidentified Costs In addition, it appears that EPA assumed no costs for miscellaneous unidentified costs or contingency. EPA’s costs for MDS and remote MDS systems came from estimates provided by CBPG. Based on information in the docket, contingency was not included in CBPG’s estimated costs “fully erected and commissioned systems.” 2 This is not consistent with industry practice, nor is it consistent with EPA’s practice in other ELGs. Contingency is defined as “an amount added to an estimate to allow fo r items, conditions, or events for which the state, occurrence, or effect is uncertain and the experience shows will likely result, in aggregate, in additional costs.” 3 Since EPA’s estimates are, at best, screening level costs with a small amount of projec t definition, contingency must be added to the total project costs to take into account unidentified costs. The accuracy of the cost estimate is generally a function of the amount of engineering completed at the time of the estimate. Some project risk fact ors include quantity variations (design is not complete), materialunit price variations, labor productivity variations, labor rates variations, subcontract unit price variations, contractor indirect costs, poor scope definition, and market pressures (escal ation, supply shortages, unusual demand, etc.). It is standard practice, based on the Project Management Institute , to include contingency developed for the defined scope of work ( i.e., class of cost estimates) to cover within scope uncertainties. Because of the undefined definition of the retrofitEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 555 project and the risk factors listed above, EPA should include a minimum of 20% of the project direct costs in their cost formula for total capital costs. In previous ELGs, EPA has routinely included contingency c osts for engineering projects. See, e.g. , Development Document for Final Effluent Limitations Guidelines and Standards for the Iron and Steel Manufacturing Point Source Category, EPA

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- 2; Development Document for the Final Effluent Limitations Guidelines and Standards for the Metal Products and Machinery Point Source Category, EPA

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2 EPA

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3 AACE International. 2013. AACE International Recommended Practice No. 10S

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EPA Estimated One
- Time Costs for Plants That Recycle 90% of Bottom Ash Transport Water EPA determined that some plants recycle a majority of their bottom ash sluice water but still discharge a small portion as emergency discharges or via other plant operations (e.g., reused and discharged with FGD wastewater). For those plants recycling the majority of their bottom ash sluice, EPA assumed t hat a one

- time engineering cost would be appropriate to completely close the bottom ash sluice recycle loop to eliminate the discharge of bottom ash transport water. To determine the plants that should receive the one

- time bottom ash management cost, EPA r eviewed bottom ash sluice recycle and discharge amounts reported in 2010 ICR Part C, Section 3.1, along with the water balance diagrams provided in the ICR. EPA identified the plants thatEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 556 should receive the one

- time bottom ash management costs as those pla nts recycling more than 90% of their sluice or only discharging bottom ash sluice through emergency outfalls. Based on industry knowledge and contractor fees, EPA developed an estimate for a contractor to come on site and develop a plan for the plant to cl ose up the bottom ash discharge. EPA assumed that the contractor will require a total of 200 hours to complete the plan, including two week

- long trips to the plant. EPA estimates that the total one

- time costs for a plant to hire a contractor to close the d ischarge of a bottom ash recycle system would be $22,422. This estimate assumes no capital improvements. IC&PR p. 8

- 31. There are two problems with EPA’s analysis of plants that recycle 90% of their bottom ash sluice water. First, it is not technically fea sible to recycle this wastewater without major modifications or complete retrofit of the wet bottom ash handling system. Our engineering staff believes that because of fines and scaling issues, a blowdown of this type of system is required. Second, a one
- t ime cost of $22,422 is an underestimate for a contractor to design a closed

- loop system. But even more surprising, EPA did not provide any capital dollars for the retrofit to a 100% recycle system. Addition of a bottom ash sluice recycle system will requir e capital expenditures. For example, a remote submerged flight conveyor bottom ash hopper (SFC

- BAH) will require the addition of low pressure pumps to refill the existing wet bottom ash hopper, medium pressure pumps to supply water to the suction of the ex isting ash sluice transport pumps and high pressure pumps to supply water to the existing wet bottom ash hopper flush nozzles (hopper slope and clinker grinder inlet). Electrical power to operate these pumps represents new load on the distribution system t hat will require expansion of the system (typically power transformers, switchgear, motor control centers, cable, conduit , cable trays, underground electrical duct banks, electrical equipment enclosures, etc.). The plant control system must be modified to control the operation of this equipment. Piping to deliver this recycled water must be installed. The cost for this piping will vary with the distance between the remote SFC

- BAH and the boiler(s). Installation cost will include pipe supports and roadway b ridges over this pipe (installed at grade). All of the hardware mentioned above will also have to be installed, adding construction labor, contractor profit and construction management labor. Therefore, EPA has grossly underestimated the capital costs for these plants and for the industry as a whole, potentially by hundreds of millions of dollars. Comment Response: Based on public comments, for the final rule, EPA revised its cost estimates for plants that recycle 90% of their bottom ash transport water. EPA estimated full ash system conversion costs for any steam electric power plant that reported discharging any amount of bottom ash transport water in 2009, even those previously given only bottom ash management costs. Although steam electric power plants that currently recycle 90% or more of their bottom ash transport water mayEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 557 not need to convert to a dry ash handling system, EPA included these costs to cover other capital improvements that might be necessary to convert their system to zero discharge.
Th e final cost estimates account for bottom ash management costs for those plants that did not report discharging bottom ash transport water in 2009, but have emergency outfalls. Section 8.5 of the Incremental Costs and Pollutant Removals for the Final Effl uent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) contains additional details

. Also see the response to DCN EPA

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- A2, Excerpt Number 12.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 38 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Exce rpt: The MWs vs. the capital costs were plotted, in Figure 1 below, to generate a cost equation to estimate capital costs (2012 dollars) of retrofitting based on a unit’s MW. A linear equation based on the best correlation coefficient (R2) value (0.63). The cost curve equation is as follows: y = 0.0239x + 5.2354, where x = MW served by retrofit, and y = capital cost. Figure 1: UWAG Capital Cost Curve for Bottom Ash Retrofits (2012 dollars)Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 558 Unlike EPA’s costs, UWAG’s capital costs (both actual costs and conceptual engineering design estimates) include total capital cost to the plant, including major equipment installed, balance of plant (site work, concrete, piping, electrical, mechanical, and instrumentation and controls (I&C)), engineering (design, serv ices during construction, and startup), overhead and profit (subcontractor and general contractor costs), and miscellaneous contingency (unidentified costs). Using this more realistic cost curve, capital costs were calculated and annualized capital costs b ased on a 15

- year service life and 7% interest for the capacity

- based model plants. Southern believes 15 years better represents the service life of the equipment and is consistent with EPA’s past practice. See Development Document for Final Effluent Limit ations Guidelines and Standards for the Landfills Point Source Category, p. 9

- 9 (capital costs amortized using a 7% interest rate over 15 years); Development Document for the Final Metal Products and Machinery Category, p. 11

- 19 (Agency assumed a 7

- percent discount rate over an estimated 15

- year equipment life). The results are provided in Table 3. Table 3: Bottom Ash Retrofit Annualized Capital Costs, Million Dollars

MW Range MW Used

(Midpoint) Bottom Ash

Retrofit Total Capital Cost, Million Dollars Bottom Ash Retrofit

Annualized Capital Costs, Million $/Plant (assumed 15

- year life of system and 7% interest) <50 MW 50 6.4 0.71 50

- 100 MW 75 7.0 0.77 100

- 150 MW 125 8.2 0.90 150

- 200 MW 175 9.4 1.03 200

- 300 MW 250 11.2 1.23 300

- 400 MW 350 13.6 1.49 400

- 500 MW 450 16.0 1.76 500

- 700 MW 600 19.6 2.15 700

- 900 MW 800 24.4 2.67 >900 MW 1000 29.1 3.20Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 559 Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule. EPA disagrees that “15 years better represents the service life of the equipment and is consistent with EPA’s best practice.” Although the commenter references one effluent guideline where EPA used 15 years as the basis, this is not a standard value, nor does it represent “best practice.” For this industry, and based on available data, EPA used 20 years.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Num ber: 41 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Appendix B contains case studies describing the retrofitting process and its costs for two types of dry bottom ash handling systems: a dry b ottom ash hopper and a remote submerged flight conveyor system. Based on the specifics of a single >850 MW plant, the case studies predict a total cost of $33,655,011 for the dry bottom ash hopper and $29,123,683 for a remote submerged flight conveyor syst em. Comment Response: EPA reviewed the two cost estimates provided by the commenter in its Appendix B. The commenter’s cost estimate for dry bottom ash hopper installation is not relevant for comparison to EPA’s cost estimate because that technology was not selected as a BAT basis for control of pollutants in bottom ash transport water. EPA focused its review on the data provided for the remote mechanical drag system (such as the remote submerged flight conveyor system) conversion at a single 850 MW plant

. Based on a review of the case study, EPA evaluated the potential need for additional surge capacity (for example, water surge tank). EPA contacted the vendor UCC and determined that an additional surge tank is not required for the remote mechanical drag system to operate closed loop (i.e., without discharge). However, EPA did identify that there is maintenance on the wear plate of the remote mechanical drag system that requires the system to be drained every five years. Therefore, EPA estimated 5

- year cos ts associated with tank rentals for additional surge capacity during this maintenance. These rental tanks would allow steam electric power plants to empty and temporarily store the bottom ash transport water in the remote MDS system. Additionally, EPA completed a comparison between the cost estimates provided in Appendix B and the compliance cost estimates based on the cost methodology described in Section 8 of theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 560 Incremental Costs and Pollutant Removals for the Final Effluent Limitat ions Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) . The costs provided by the commenter are difficult to interpret due to the description and cost of the procured material ($8,049,700) and the footnote on the total project cost (“4 The Remote Ash Hopper

- SFC, recirculation water piping, and surge tank account for $3,550,000 or 16 % of the total direct project costs. This may not be typical of all Remote Ash Hopper

- SFC additi ons because the costs of the infrastructure improvements and recirculation.”). There is a large difference between the two values and EPA’s costs are comparable (and actually higher) to the value provided in the footnote. Additionally, as a result of this and other comments, EPA re

- evaluated the costs included for indirect capital costs, including engineering overhead costs, profits and overhead (other contractors fees), and miscellaneous unidentified costs (contingency)). See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding estimates used for indirect costs based on a review of multiple data sources (including this comment letter, other public comments, other rulemakings, and literature). EPA determined that demolition is not requir ed for the installation of the remote mechanical drag system. This system uses the already existing wet sluicing system. Additionally, the final rule does not require steam electric power plants to construct a new landfill. EPA accounted for costs for onsi te transport and disposal (including landfill expansions) for steam electric power plants that already operate an onsite CCR landfill. EPA estimates offsite transport and disposal for any steam electric power plants that did not report an onsite CCR landfi ll in the Steam Electric Survey.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 129 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Costs of Bottom Ash Retrofits Southern also developed its own estimates for bottom ash handling retrofits using dry handling or closed

- loop systems based on preferred option 4a, which would require dry or closed

- loop bottom ash retrofitting for units greater than 400 MWs. Using engineering estimates from one facility with multiple units, and using various scenarios for retrofitting a dry system and a remote submerged scraper conveyor system, plant

- specific retrofit costs were estimated for all Southern plants greater than 400 MWs generating bottom ash transport water. Again, comparing Southern’s estimates to EPA’s demonstrates that EPA has grossly underestimated compliance costs.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 561 We first compare plant

- spec ific bottom ash retrofit costs for all Georgia Power facilities to the plant

- specific costs EPA generated (Table 22). Table 22: Comparison of EPA’s and Southern’s Plant
- Level Total Capital Cost Estimates for Retrofitting Bottom Ash Retrofits

Plant Namepl ate EPA Estimate (2010$), M$ Southern Estimate

(2010$) M$ Southern In
Service Estimate, M Bowen 1

- 4 3160 $65 $118 $150 Hammond 4 500 $16 $23 $30 Scherer 1

- 4 3272 $65 $118 $150 Wansley 1

- 2 1730 $34 $59 $75 Total 11 units $180 $318 $405
Next, we compare EPA and Southern bottom ash retrofit costs at the operating company level in Table 23. Table 23: Total Capital Cost Estimates for Retrofitting Dry Bottom Ash Handling by Operating Companies for All Units > 400 MW

Operating Company No. of Units

(EPA ) EPA Estimate

(2010$), (M$) No. of Units

(Southern) 59 Southern

Estimate (2010$) (M$) Southern In
Service Estimate (M$) Alabama Power 7 $125 7 $206 $262 Georgia Power 13 $181 11 $317 $404 Mississippi Power 3 $31 2 $59 $75 Gulf Power 1 $1 1 $10 $12 Total 24 $338 21 $592 $753 EPA’s total estimate for bottom ash retrofits under Option 4a at Southern facilities, like its estimate for FGD wastewater treatment, is a gross underestimate. EPA’s estimate is for 24 units at $338 million in 2010$, while Southern’s estimate is $592 million for 21 units, or $254 million more than EPA’s estimate. EPA’s capital costs, which are considered screening level costs by the Project Management Institute , are underestimated. Again, the BOP costs are well underestimat ed and EPA does not include any costs for profits and overheads for the general contractor and subcontractors or for miscellaneous unidentified costs (contingency). EPA also underestimates engineering overhead costs based on information obtained from South ern Company cost engineering staff.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 562 EPA relied exclusively on cost estimates from CBPG for balance of plant costs. Even though CBPG states that their costs “reflects fully erected and commissioned systems,” their cost documentation provided in the ELG dock et makes no mention of costs for electrical, mechanical (except for a pipeline that previously went to the ash pond), upgraded control systems, boiler modification, upgraded piping (more corrosive

- resistant material), demolition or structural modifications . Because of all of these cost element omissions, EPA’s costs for dry (or closed

loop) bottom ash retrofit at Southern plants are underestimated by a factor of two.

59 Southern costs out 21 units

– rather than the 24 units EPA costed out

– because of th e retirement of Plant Branch and the planned gas conversion of Unit 4 at Plant Watson. Comment Response: EPA reviewed the actual and engineering cost estimates collected and provided by the steam electric power generating industry; however, EPA was unab le to use these data in revising the dry bottom ash handling cost methodology because specific information (including the type of conversions, and system components included in the cost estimates) is absent from the cost estimates. Therefore, EPA cannot co mpare the actual or estimated capital costs with EPA’s methodology. See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 131 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Costs of Additional Landfills for Dry Ash Disposa l In addition to the capital costs associated with retrofitting dry fly ash and bottom ash handling, Southern would incur substantial costs for disposal of the ash in landfills. Southern will need to expand existing landfills and construct new landfills a t plants that do not have landfills to accommodate the expected amount of new dry ash generated. EPA’s estimated costs for disposal assumes that a facility without an existing landfill will dispose of the new dry fly ash and bottom ash off

- site at approxim ately $47 and $51 per ton, 61 respectively. For plants with existing landfills, EPA assumes the existing landfill can be expanded at approximately $43 and $47 per ton 62 for fly ash and bottom ash, respectively. UsingEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 563 EPA’s assumptions and costs, the costs f or ash disposal at Southern Company facilities is $ 116 million annually or $ 2.3 billion over 20 years. EPA’s estimated costs for these facilities may be appropriate on an industry

- wide basis. However, additional costs for leachate treatment, suitable off

- site property, landfill permitting hurdles, site

- specific issues and any future regulatory requirements for coal combustion residual disposal will likely increase the cost for ash disposal.

61 Southern rolled up EPA’s multiple cost formulas for off

- site ash disposal to provide the total cost per ton for both fly ash and bottom ash disposal. EPA’s formulas for fly ash and bottom ash disposal costs are provided in IC&PR, Chapters 7

- 8, respectively.

62 Southern rolled up EPA’s multiple cost formulas for on - site ash disposal to provide the total cost per ton for both fly ash and bottom ash disposal. EPA’s formulas for fly ash and bottom ash disposal costs are provided in IC&PR, Chapters 7

- 8, respectively Comment Response: The final rule does not require ste am electric power plants to construct a new landfill. EPA accounted for costs for onsite transport and disposal (including landfill expansions) for plants that already operate an onsite CCR landfill. EPA estimates offsite transport and disposal for any ste am electric power plants that did not report an onsite CCR landfill in the Steam Electric Survey. EPA conservatively determined costs for steam electric power plants to dispose of combustion residuals requiring disposal in a landfill to comply with the ELG s. To the extent steam electric power plants are able to market or sell these residuals, these costs for disposal are overestimated and do not account for revenue associated with other options. See section 5.4 of the Incremental Costs and Pollutant Removal s for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832)

.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 162 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry Bottom Ash RetrofitEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 564 The dry bottom ash hopper retrofit was based the r eplacement of the existing wet ash hopper and transport system with a new dry ash hopper, a new pneumatic ash transport system and a new dry ash silo with an ash conditioner and dry unloading equipment. The equipment cost was based on a budgetary proposal prepared by Allen Sherman Hoff (A

- S

- H) in 2010. Costs for the installation of the equipment and the infrastructure required by the equipment were developed using the following assumptions:

 Sufficient space exists between the furnace throat headers and the foundation to install the new ash hopper. (verified)

 Sufficient space exists near the boiler to install the ash conveyors, surge hoppers and blowers for the transport system.

 Dry bottom ash silo will be located over 1,200 feet away from the boiler.

 Silo fo undation estimated design assumed that the same geotechnical conditions existed at the new bottom ash silo location were identical to the conditions encountered at a recently installed fly ash silo.

 Insufficient electrical power supply exists at the silo r equiring additional power distribution equipment.(verified)

 No demolition is required at the proposed location of the new bottom ash silo. (verified)

 Installation of equipment outside of the boiler building will occur while the unit is operating. Installat ion of the dry bottom ash hopper, transport conveyors, surge bins and blowers will require a scheduled outage.

 The dry bottom ash hopper will serve only one unit. The bottom ash silo was sized to serve only one unit based on ash production rate utilizing t he current coal (no fuel switch to PRB coal).

 Adequate craft labor availability

– labor cost based on 50 hour work weeks.

 No disposal costs are included in the estimate. Closed Loop Bottom Ash Retrofit The closed loop bottom ash retrofit was based on the installation of a remote submerged flight conveyor bottom ash hopper (SFC

- BAH) with recirculation pumps, clarifier and surge tank. The existing wet bottom ash system will remain in place with the sluice piping discharging into the SFC

- BAH. The equipment cost was based on a budgetary proposal prepared by Clyde Bergemann Delta Ducon (CBDD) in 2011. Costs for the installation of the equipment and the infrastructure required by the equipment were developed using the following assumptions:

 Remote SFC

- BAH will be located over 1,200 feet away from the boiler.

 Existing ash sluice pumps will not require replacement to discharge the ash slurry into the remote SFC

- BAH.

 Silo foundation estimated design assumed that the same geotechnical conditions at the new bottom a sh silo location will be identical to the conditions encountered at a recently installed fly ash silo nearby.

 Space required for the remote SFC

- BAH, clarifier and surge tank plus an adjoining intermediate ash storage area is approximately 110 ft x 225 ft

 I nsufficient electrical power supply exists at the silo requiring additional power distribution equipment (verified).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 565  No demolition is required at the proposed location of the remote SFC

- BAH.

 Installation of equipment outside of the boiler building will occ ur while the unit is operating. A tie

- in outage of short duration will be required to complete the conversion to the remote SFC

- BAH.

 Remote SFC

- BAH was sized to handle an incoming slurry rate of 20 tons per hour.

 Adequate craft labor availability

– labor c ost based on 50 hour work weeks.

 No disposal costs are included in the estimate Comment Response: See response to DCN EPA

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- A1, Excerpt Number 41 regarding industry submitted cost estimates for a dry bottom ash hopper retrofit and a closed loop bottom ash retrofit. The commenter’s costs for the dry bottom ash hopper installation are not directly relevant to EPA’s cost estimate for the ELG because it was not selected as a BAT basis for control of pollutants in bottom ash transport wate r. EPA focused its review on the data provided for the remote mechanical drag system (such as the remote submerged flight conveyor system) conversion at a single 850 MW plant. EPA notes the following key differences in the cost estimates provided by the co mmenter and EPA’s cost methodology described in Section 8 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN S E05831/SE05832) :

 EPA’s compliance cost estimates are based on the bottom ash being conveyed from the remote mechanical drag system to an outdoor pile where it will further dewater prior to disposal. Therefore, costs for a bottom ash silo and associated fou ndation are not needed.

 EPA confirmed that a clarifier or additional surge tank is not necessary to achieve complete recycle, therefore costs for these elements are not necessary. Additionally, note that EPRI stated in public comments that “not all facilit ies will install equipment for fines management (surge tanks, chemical feed systems, thickeners) and not all facilities will choose to include redundancy” (DCN EPA

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- A1, Appendix E). EPA’s bottom ash compliance cost methodology does incl ude chemical feed system costs for all remote mechanical drag installations.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 164 External Review Flag : No External Review External Review Incorporated into Response: No Comment Excerpt: New Landfill and Landfill Expansion AssumptionsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 566 Landfill estimates are based on a recent landfill construction, which averaged $650,000 per acre. Stack heights were ass umed to be 60 feet and the area was assumed to be a square. Sufficient area is assumed to be available. This includes construction in accordance with Subtitle D landfill requirements ( i.e. , lined landfills with leachate collection). New landfills are sized for a 20

- year life based on 2010 ash production quantities, assuming no bottom ash sales. In addition, Southern included costs for expansions of existing landfills to accommodate the addition of new dry solids. The landfill expansion was sized for 20 years of storage. The costs for expansion are the same as for the design, permitting, and construction of a new landfill: $650,000 per acre. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 131. Additionally, EPA comp ared the landfill expansion costs provided by the commenter to EPA’s methodology described in Section 5.4 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Po int Source Category (Cost & Loads Report) (DCN SE05831/SE05832) . EPA used information from a 2009 planning

- level cost estimate prepared by CH2MHILL for construction, operation, and closure costs associated with a 7

- acre expansion of an existing landfill in Hilo, HI for 328,000 tons of solid waste. EPA used the cost estimate from the CH2MHILL study because it includes the most recent data in the most useful format. Based on the information provided in the report, EPA calculated a cost per ton basis ($29.39 p er ton in 2010$). EPA’s onsite landfill capital costs include the construction of the landfill, liner, groundwater monitoring wells, leachate collection systems, and closures. Based on the commenter’s estimate, the capital costs include the design, permitt ing, and construction of the landfill “in accordance with Subtitle D landfill requirements (i.e., lined landfills with leachate collection).” It is unclear if the commenter’s capital cost estimates include groundwater monitoring wells or closures; therefor e, EPA cannot compare the specific estimates provided by the commenter to EPA’s methodology presented in Section 5.4 of the Costs & Loads Report. Additionally, EPA’s capital costs are based on tonnage, not acreage.

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 36 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
b. EPA has underestimated the cost of dry bottom ash conversions.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 56 7 For the proposed revisions to the steam electric effluent guidelines, EPA performed a cost

effectiveness analysis, but did not present the results on an individual waste stream basis. Instead, the results were presented as a sum of all the waste streams for a given regulatory option ( 78 FR at 34504). However, EPA did use data provided by a single vendor, Clyde Bergemann Power Group to develop bottom ash retrofit costs (see EPA

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- 2007) . EPA generated a cost curve for three different mechanical drag systems; a remote submerged scraper conveyor system, a completely dry, sub

- boiler ash system, and a sub

- boiler bottom ash system that only uses water for quenching bottom ash. Based on the c osts for these three systems, EPA developed a linear equation to estimate retrofit costs for bottom ash handling: Unit costs (2010$) = 20,083 x capacity (MW) + 3,000,000 AEP compared its costs to retrofit dry bottom ash systems with those estimated by EPA. Twelve AEP facilities were included in the evaluation and each was assigned to one of three groups based on gross MW capacity (>2000, 1000 to 2000, < 1000). Within each group, the direct capital cost to retrofit a dry bottom ash system was estimated in 2 010$ using both the EPA linear equation above and an AEP estimated retrofit cost of $31.54/kW (2011$) for the installation of a remote submerged chain conveyor or a recirculation system utilizing dewatering bins. The direct cost estimates include contingen cies to cover difficult installation with limited acreage for installing equipment. Contingencies also cover “known unknowns,” such as deviations from projected inflation or currency exchange rates, abnormal seasonal weather affecting construction schedule s, and variances in commodity prices. AEP’s price estimate includes all equipment needed for the installation; tanks, pumps, piping and valving. Fully

- loaded costs were also estimated for each group. Based on the EPA equation, such a retrofit was estima ted to cost $57.2 million (2010$) for a plant greater than 2000MW, a value well belowAEP’s direct cost estimate of $82.7 million (Table 5). On a fully

- loaded basis, the AEP estimate for this size power plant is $105.34 million, almost double the EPA estim ate.

* Assumes no 400 MW per unit threshold exemptionEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 568 Comparisons between the MW groupings further illustrate the large discrepancy between the AEP and EPA cost estimates (Table 5). On average, AEP’s cost estimates are 23% to 44% higher than those of EPA on a direct cost basis and 54% to 84% higher on a fully

- loaded basis. These differences are significant and compromise any conclusions regarding the cost effectiveness of dry bottom ash retrofits. Comment Response: EPA cannot comment on the estimates pr ovided by the commenter because the commenter did not provide any details about how they arrived at its estimates, including cost elements and calculations (for example, type of conversion, equipment included), nor did they identify the specific plants use d in the analysis. However, based on a review of public comments and additional cost information (from commenters, vendors, and literature), EPA revised its cost estimates associated with the bottom ash transport water requirements in the final rule to acc ount for updates to the population of steam electric power plants estimated to incur compliance costs, as well as adjustments to estimated costs for installing and operating dry or closed

- loop bottom ash handling systems. See response to DCN EPA

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- 4655, Excerpt Number 53 for a detailed explanation of EPA’s revised compliance costs, which use an indirect capital cost factor to account for overhead costs, profits and overhead (other contractors fees), and miscellaneous unidentified costs (contin gency).

Commenter Name: John McManus Commenter Affiliation: American Electric Power System (AEP) Document Control Number: EPA

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- A1 Comment Excerpt Number: 39 External Review Flag: No External Review External Review Incorporated in to Response: No Comment Excerpt: AEP’s $/TWPE removal estimates , as well as those of UWAG, demonstrate that the regulation of bottom ash transport water, as proposed in the agency’s effluent guidelines revisions, is not cost effective. However, the lac k of a justifiable cost

- benefit analysis is not the only reason to reconsider this proposal. For example, some state regulatory agencies require that ash ponds be closed once wet sluicing is discontinued and the ponds serve no further purpose. For some AEP facilities, the schedule for pond closure would be accelerated, putting further pressure on company budgets that are already stressed. Additionally, some AEP bottom ash retrofits will be tank

- based and will not require the use of bottom ash ponds. Since there would be no further use for these particular ponds, the proposed CCR rules will take regulatory precedence. Under these proposed rules, closure of the unused ponds must begin within 30 days of the last receipt of CCR material and be completed within 180 days of the start of closure activities; an unreasonable time requirement that needs to be addressed under the CCR rule.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 569 Loss of these ponds, due to either the proposed effluent guideline revisions or the proposed CCR rule, will have ancillary effects

. Most bottom ash ponds are also used to treat low volume wastes through pH control, settling, precipitation, etc. Closure of the ponds due to the proposed effluent guideline and CCR rule changes will require that these ponds be replaced with similar po nds that will not receive coal combustion byproducts. The construction of such ponds will necessitate changes to plant water balances, at significant cost. For example, loss of the bottom ash pond at Plant 2 would require water balance changes in excess o f $25 million in direct capital costs (2010$) and over $31.25 million in fully

- loaded costs (2010$). At a larger AEP plant, required water balance changes would cost in access of $90 million in direct capital costs (2010$) and over $111 million in fully lo aded costs (2010$). At yet another AEP facility, required water balance changes would cost over $95 million in direct capital costs (2010$) and over $118 million in fully

- loaded costs (2010$). For the company as a whole, these costs would exceed $931 mill ion (2010$) in direct capital costs and over $1.2 billion in fully

- loaded costs (2010$). Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule. Also, for the role of c ost

- effectiveness in EPA’s decision for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h. Although the final rule requires zero discharge of pollutants in bottom ash transport water for units that are grea ter than 50 MW and that are not oil

- fired, it does not require steam electric power plants to close or stop operation of their surface impoundments. “Legacy” bottom ash transport water is subject to a BAT effluent limitation on TSS, which is equal to the p reviously established BPT effluent limitation on TSS in bottom ash transport water. See preamble section VIII and Section 14 of the TDD for more information on legacy wastewater. The final CCR rule generally allows impoundments to remain in operation after they stop receiving CCR wastes, subject to other requirements imposed by that rule, if the impoundment continues to receive non

- CCR wastes. See 80 FR 21302 (Apr. 17, 2015). Thus, the zero discharge requirement in the ELG will not result in plants building new impoundments or other systems to treat non

- CCR wastes.

Commenter Name: Nysa Hogue Commenter Affiliation: Indianapolis Power & Light Company (IPL) Document Control Number: EPA

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- 570 Comment Excerpt: IPL requests that EPA re

- evaluate the cost

- effectiveness evaluation of banning bottom ash discharge for units with capacity at or greater than 400 MW as EPA 's estimated costs of conversion to closed loop ash water management system is extremely underestimated. IPL has performed cost estimates of conversion to closed loop ash water management at one of our facilities (unit greater than 400 MW), and is providing this analysis for EPA's consideration. Below is a summary of the conclusions of our cost

- effective analysis:

 It appears that EPA 's cost estimating did not include the storage that will be needed to hold water during maintenance of either the submerged fli ght conveyance system (SFC) or the tanks in the bottom ash sluicing system itself. This storage tank also provides water during system re

- start and suction head for pumps that return water to the power block: The storage during maintenance is the largest o f the volume needs, so defines the tank size and cost. Increasing storage to accommodate this maintenance increased our cost estimate by roughly $1,000,000 at each of affected our facilities.

 EPA did not include costs to provide redundant remote bottom ash solids treatment such as SFCs. The SFCs, and similar systems, are mechanical equipment which will require periodic downtime and will be subject to unplanned outages. IPL believes a redundant system is required to avoid outages during these planned and u nplanned downtimes of the SFCs. The SFCs are the major equipment costs associated systems. Therefore, these costs should be included in EPA's cost estimates. IPL estimates the need for a redundant SFC at each of our affecte d facilities at a cost of $8,00 0,000 per facility.

 Sulfide is the biggest contribution according to EPA' s data set. It represented roughly 55% of the calculated benefits. We consider this a significant problem with the EPA's calculation, as it is based nearly entirely on non

- detect val ues from old data being used as if sulfide was present at the detection limit. We do not expect sulfide to be present in BA water based on its water chemistry. EPRI and UWAG comments will also note that sulfides are not present in bottom ash water.

 The EPA considers cost effectiveness as cost per toxic weighting factors (TWF). TWPE factors are used by the EPA to express the relative toxicity of pollutants. Use of TWPE provides a relative measure comparing the potential toxicity of different pollutants. Ann ual cost is a sum of annualized capital and operating costs. In past ELG setting, EPA has used as a criteria $400/TWPE (in 1981 dollars, which is roughly $1000/TWPE now) as a reasonable upper bound for cost effectiveness. For this analysis, the benefits we re defined as the incremental amount of pollutants removed from BA transport water. The incremental benefits of "zero discharge" were calculated as TWPE. We used the average net BA discharge from our data set, the estimated BA transport water flow rate, an d toxic weighting factors (TWP) published by EPA to calculate total TWPE/year removed. The TWFs used in this evaluation were published in Technical Support Document for the Annual Review of Existing Effluent Guidelines and Identification of Potential New P oint Source Categories (EPA, 2010). As shown in the table below, the cost/benefit ratio for bottom ash discharge ban at the IPL Station evaluated ($4,400/TWPE in current dollars, or roughly $1,800/TWPE in 1981 costs) isEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 571 much worse than this criteria. Addi ng the increased O&M costs (such as electrical and maintenance) would make this cost effectiveness even worse.

Benefits Summary of Bottom Ash Discharge Ban at Example IPL Station Benefit (TWPE/year) Capital Cost

($) Annualized

Capital Cost 1 ($/Year) Cost/ Benefit

($/TWPE) 447 $21,000,000 $1,980,000 $4,400 1 Assumed annualized over 20 years, at 7% interest, as was done by EPA in their ELG calculation.

The following differences of calculation between our calculations versus the EPA's methods are noted:

1. In our calculation, for each pollutant, the net BA pollutant load was calculated by subtracting out the source water concentration from the BA transport water concentration. Netting

- out source water was not done by EPA in their estimate of benefits. EPRI and UWAG also have provided comments regarding the appropriateness of netting out the source water to more accurately estimate the true benefit of eliminating bottom ash water discharge. 2. Water quality characterization data differed between our calculations and EPA's: The EPA used in appropriate data, some decades old, of bottom ash pond effluent. It is published in EPA's TDD for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (EPA, 201 3), Table 10

- 7. To compare to IPL's calculations, we used the EPA's bottom ash water quality data, multiplied by the bottom ash transport water flow at the IPL stations. Based on the above analysis, IPL believes EPA should eliminate no discharge of bottom ash as BAT. Comment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule. EPA’s compliance cost estimates include 5

- year recurring costs to account for rental tanks during r emote MDS maintenance, specifically maintenance on the weir plate at the bottom of the remote MDS. These rental tanks would allow plants to empty and temporarily store the bottom ash transport water in the remote MDS system. This 5

- year maintenance is the only maintenance identified by EPA that requires the system to be emptied. In addition, pump suction is provided in the system by pumps taking suction at the sump for theEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 572 remote MDS. Alternatively, the system could be operated so that the suction is drawn from the dewatering tank itself. Additionally, EPA’s cost estimate is based on every generating unit at the plant being retrofitted for a remote mechanical drag system. This methodology does not incorporate economies of scale such as costing one remote MDS to service multiple units into the cost basis of the final rule, and acknowledges that approach may result in higher cost estimates for some steam electric power plants. See response to DCN EPA

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- A1, Excerpt Number 102, regarding econom ies of scale. EPA also confirmed with a vendor that this system will not require an outage for service. The system design includes provisions for maintenance while the generating unit is online. Furthermore, any internal maintenance can be performed during normally scheduled boiler outages (DCN SE01825A80). EPA disagrees with the commenter that “The EPA considers cost effectiveness as cost per toxic weighting factors (TWF).” EPA defines cost effectiveness as cost per toxic weighted pound equivalents (TWPE). The TWF is the individual factor multiplied by the loading (pounds) to calculate TWPE. See the response to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a and “Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum” (DCN S E04745) for more information on the identification of pollutants of concern for bottom ash transport water. See the TDD and the response to DCN EPA

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- 4655, Excerpt Number 47 in Comment Code 15.d for more information on the data and methodolog y used to calculate bottom ash baseline loadings. In addition, EPA chose not to calculate loadings for sulfide. EPA cannot comment on the cost estimates provided by the commenter for the example IPL plant because the commenter did not provide any details o f its cost elements and calculations, nor did it identify the specific plant characteristics (for example, generating unit number or capacity).
For the role of cost

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Commenter Name: Jerry Purvis Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC) Document Control Number: EPA

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- 573 Comment Excerpt: First, the cost of conversion to dry handling for bottom ash at small utilities is prohibitive. Preliminary engineering estimates conducted by EKPC for its Spurlock St ation indicate that conversion to a dry handling system for bottom ash for Unit 2 would have a capital cost of $55 million to $70 million. Annual O&M costs are projected to range from $2 million to $5 million. As noted above, these costs, in addition to o ther ELG costs, would result in excessively high capital and operating costs compared to plant revenues. Additionally, EKPC's estimated cost to convert Spurlock Unit 2 from a wet to a dry handling system for bottom ash substantially exceeds those estimate d by EPA for similarly sized generating units. Using Equation 8

- 2 at page 8

- 4 of the "Incremental Costs and Pollutant Removals for the Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Generating Point Source Category" (April 20 13) and the capacity of Spurlock Unit 2 (555 MW), EKPC calculated that EPA' s estimated capital costs to convert to a dry handling system for this unit would be $14 million. This is at least 4 times lower than the cost estimated by EKPC for this Unit.
Com ment Response: See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule. EPA cannot evaluate or respond to the costs presented by this commenter for Spurlock Station Unit 2 because the com menter did not provide any specific information regarding the conversion associated with the cost estimate (for example, type of conversion, cost elements, equipment included).

Commenter Name: Jerry Purvis Commenter Affiliation: East Kentucky Power C ooperative, Inc. (EKPC) Document Control Number: EPA

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- A1 Comment Excerpt Number: 10 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The Utility Water Group ("UWAG") has provid ed EPA with data to show that the costs of retrofitting and operating for dry bottom ash handling systems cannot be justified based upon the questionable and limited reduction in pollutants discharged on toxic

- weighted basis. EKPC concurs with and supports UWAG's analysis. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6.a and “Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum” (DCN SE04745) for more information on the identification of pollutants of concern for bottom ash transport water. See the response to DCN EPA

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- 574 Comment Code 15.d for more information on the data and methodology used to calculate bottom ash baseline loadings

. See the response to DCN EPA

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- 4655, Excerpt Number 53 for more information on the estimation of compliance costs associated with the final bottom ash transport water requirements.
For the role of cost

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Commenter Name: Tom DeLawrence Commenter Affiliation: PowerSouth Energy Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 57 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: In addition to these facility

- specific issues, all closed

- loop system retrofits will impact a plant’s water management practices. For ins tance, additional large storage tanks may need to be installed at the Lowman Plant to accept wastewaters currently routed to the facility’s surface impoundment in order to perform the flow equalization function currently achieved by this structure. Similar structures will likely be needed at other facilities in the industry in order to store and distribute these recycled waters to various plant processes as needed. Comment Response: Although the ELG is requiring zero discharge of pollutants in bottom ash transport water, it is not requiring plants to close or stop operation of their ponds. See response to DCN EPA

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Commenter Name: JoAnne Rau Commenter Affiliation: Dayton Power & Light Company (DP&L) Document Control Number: EPA

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- A1 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: USEPA's Calculation of Bottom Ash Dry Handling Capital Costs are Underestima tedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 575 USEPA's capital costs for conversion to bottom ash dry handling are underestimated for the following reasons:

 Balance of plant costs are low since they do not account for electrical, mechanical (except for tie

- in of pipeline that previously went to th e ash pond), upgraded control systems, boiler modifications, upgraded piping (more erosive

- resistant material), demolition/relocation or structural modifications;

 USEPA 's engineering overhead cost factor of 1.765% is low. Engineering overhead costs can b e as high as 12% of the total capital costs;

 USEPA did not include costs for general contractor and subcontractor profit and overhead, including bonding and insurance;

 USEPA did not include miscellaneous or contingency costs which are generally in the rang e of 20% of a project 's direct costs;

 USEPA 's selection of lowest cost option is inappropriate since it does not take into account site

- specific issues. Based on USEPA's data and costs, the agency estimates a cost of approximately $106 per TWPE for zero discharge of bottom ash transport water for all coal units greater than 50 MW. For Option 4a, which includes zero discharge of bottom ash transport water for coal units greater than 400 MW, the agency estimates $99 per TWPE. UWAG performed an assessment t o determine a more accurate value for the $/TWPE for bottom ash BAT which ranges from $1,635 to $16,492 (in 1981 dollars). Even the low

- end of the UWAG range exceeds the cost per TWPE ceiling that USEPA has traditionally used for effluent guidelines. As the agency points out, its historical BAT cost

- effectiveness range ranges from less than $1/TWPE to $404/TWPE. By USEPA's own standards, dry handling or closed

- loop retrofit of bottom ash is clearly not cost

effective. In addition to the lack of justifica tion for requiring dry handling/closed loop as BAT for bottom ash transport water based on environmental or economic reasoning, retrofitting to dry handling of bottom ash would be complex, long and expensive. Such conversions would take several years of e ngineering, design and implementation effort costing tens of millions of dollars. For example, at one of DP&L's steam electric generating stations, there is a single bottom ash/fly ash pond system and it is estimated that conversion to dry ash handling wo uld cost in the range of $27 million and present significant operational issues in designing, engineering and implementing the conversion while continuing to operate the station. Dry ash conversion costs at another of DP&L's coal fired stations are estimat ed to be $44 million. Neither of these cost estimates include closure of the impoundments. Comment Response: EPA disagrees that there is a “lack of justification for requiring dry handling/closed loop as BAT for bottom ash transport water based on environmental or economic reasoning.” As discussed inEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 576 preamble section VIII, EPA has found the BAT basis for control of bottom ash transport water discharges to be technologically available and economically achievable. Regarding the pollutant contribution association with bottom ash transport water, see the response to DCN EPA

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ication of pollutants of concern for bottom ash transport water. See the response to DCN EPA

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- 4655, Excerpt Number 47 in Comment Code 15.d for more information on the data and methodology used to calculate bottom ash baseline loadings.
See t he response to DCN EPA

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- A1, Excerpt Number 34 in Comment Code 16.a regarding the commenter’s statement that EPA selected “the lowest cost option” for bottom ash handling.
For the role of cost

- effectiveness in EPA’s decision for the final rule , see response to DCN EPA

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- 4655, Excerpt Number 27 in Comment Code 6.h.
EPA cannot comment on the cost estimate s provided by the commenter for the two DP&L plants because the commenter did not provide any details about how it arrived at its cost estimates, including cost elements and calculations, nor did it identify the specific plant characteristics (e.g., genera ting unit number or capacity). See response to DCN EPA

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- A1, Excerpt Number 39 for more information on surface impoundment closures. The ELG does not require impoundments to close and the CCR rule generally allows them to continue operat ing if they are receiving non

- CCR wastes. See 80 FR 21302 (Apr. 17, 2015).

Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Hoosier Energy owns and operates the Merom Generating Station in Sullivan Indiana, with two units each rated at approximately 500 MW. Merom curren tly sluices bottom ash to hydrobins for dewatering where a polymer is added to aide in settling of solids. The system was designed to be a net consumer of water. However, the system does discharge excess water to the plant's wastewater treatment plant. Several steps would be necessary to ensure no water is discharged from the bottom ash system. First, the water balance would have to be tightened up by makingEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 577 piping changes and adding filtration to remove solids from water that will be used for seal water

. This could cost approximately $1MM to $2MM, including engineering costs. A surge tank would be needed, as there are times during outages that all of one unit's system must be drained and this water would not be able to be discharged. Another 500,000 ga llon tank with associated pumps and piping should be around $1MM. Also with this system operating in a closed loop regime, dissolved constituents are likely to become concentrated, leading to either scaling or corrosion concerns. A treatment system for it s makeup water, either softening, deionization, or reverse osmosis, may be needed at a cost of $1MM to $2MM. Total costs to ensure no discharge of bottom ash transport water could be in the range of $3MM to $5MM. This is an unnecessary cost when chemica l precipitation is currently available to treat bottom ash sluice water after commingling with other waste waters. Comment Response: The final rule record demonstrates that steam electric power plants can install and afford the dry handling or closed

- loo p systems selected as the BAT basis for control of pollutants in bottom ash transport water discharges from existing steam electric generating units that are greater than 50 MW and that are not oil

- fired. Furthermore, EPA’s compliance cost estimates for th e final rule account for full conversions at plants that discharge any bottom ash wastewater. Therefore, EPA’s estimated compliance costs exceed the range of costs provided by the commenter at the Merom Generating Station. EPA determined that the technolo gy bases for the final rule are both available and economically achievable (i.e., affordable) for the industry as a whole.

Commenter Name: Michalene Reilly Commenter Affiliation: Hoosier Energy Rural Electric Cooperative Document Control Number: EPA

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- A1 Comment Excerpt Number: 8 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA did not consider the costs of providing storage capacity to hold and return drained ash tr ansport water to these systems and should not consider them as fully zero discharge technologies. Comment Response: See the response to DCN EPA

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- 578 Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 53 External Review Flag: No External Review External Review Inc orporated into Response: No Comment Excerpt: Additionally, a document in the Rulemaking Record, “Bottom Ash Conversion Options and Economics (EPA

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- 2075)”, describes conflicting information regarding what water treatment is required for the overflow water from the Remote MDS. When describing the Remote Submerged Scraper Conveyor technology on page 9, the authors specify the following: “The overflow water is handled by traditional or more state

- of

- the art water clarifiers.” Yet, on page 16, when the authors compare various bottom ash conversion technologies in a table, the Remote Submerged Scraper Conveyor is portrayed as a “zero discharge” closed loop system with pH conditioning required. The pricing information from the support document “ Bottom Ash Handling Conversion Cost Data (EPA

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- 2007)” specifically indicates “Water treatment system is not included” for the ASHCONTM or remote drag chain conveyor technology option . EPA did include the cost of pH conditioning equipment wh en estimating the costs for installation of Remote Mechanical Drag Systems, but EPA did not include the cost of clarifiers. EPA costed the addition of hydrochloric acid (HCl) to the sump to decrease the pH of the overflow to neutral (7 S.U.). (Not all sys tems will require chemical addition for pH control to operate as complete recycle; however EPA estimated this cost for all remote MDS system installations.) EPA did not include costs for installing a clarifier, assuming that any solids generated by pH adju stment will eventually be removed by the remote MDS conveyor

. IC&PR at 8

- 21. While We Energies agrees that including costs for pH conditioning is appropriate, EPA should also include costs for the other treatment equipment (e.g., clarifiers, reaction tank and mixer, polymer feed system, sludge

- handling equipment, and pumps) needed to make the Remote MDS a completely closed loop. This is especially necessary since the vendors indicated that this water treatment is required and they did not provide cost esti mates for a water treatment system. We Energies also has concerns regarding EPA’s assertion that bottom ash transport water systems currently recycling a majority of their bottom ash transport water could be able to become completely closed to eliminate th e discharge of bottom ash transport water. Based on information We Energies received from EPA detailing the compliance cost estimates and pollutant reductions for our owned/operated power plants, the lowest cost option for two of We Energies coal

- fired po wer plants (as used in EPA’s industry

- wide cost estimate) is for “bottom ash management” technology, transitioning from a partially recycled system to a completely recycled system. EPA developed a one

- time cost estimate ($22,422) for a contractor to come on site and develop a plan for the plant to close up the bottom ash discharge, yet the estimate assumes no capital improvements

. Id. at 8

- 30

– 8

- 31. In the 1980 proposed rule EPA indicatedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 579 that many plants partially recirculated their bottom ash transpor t water with a blowdown stream to control the buildup of dissolved solids, and the only identified plants with complete recirculation were in arid areas using evaporation ponds to eliminate the final discharge. 45 Fed. Ref. 68,328, 68,338 col. 3 (Oct. 14, 1980). In the current rulemaking, EPA provides no technological basis as to how sites with partial recirculation can convert their system to a completely recycled system through “bottom ash management.” Blowdown is still required for these systems to pr event the buildup of dissolved solids which cause scaling. Without explaining how partially recycled systems can be converted to completely recycled systems, EPA is oversimplifying the scope of such a project and not truly accounting for the costs needed for achieving complete recirculation. EPA should estimate the capital costs required to install treatment equipment to treat the blowdown from a Remote MDS or partial recirculation system to an acceptable level for complete recirculation in the bottom ash transport system. Without the inclusion of these costs, the industry

- wide total cost for the dry handling/closed loop option is underestimated. An alternative solution would be to allow for the blowdown from a Remote MDS or a partial recirculation system to be routed to a settling pond or clarifier system subject to the current BPT limitations for low volume waste. Dry Handling/Closed Loop Costs Underestimated. EPA identified a subset of the plants (27 plants, corresponding to 53 generating units) which could manage their bottom ash transport water by converting partially recycled systems to completely recycled systems. IC&PR at 4

- 11. This amounts to approximat ely 10% of the plants and generating units EPA identified as discharging bottom ash transport water. As discussed in the previous section, EPA only included a one

- time cost ($22,422) for these plants to hire a consultant to develop a plan for the plant to convert to complete recirculation; however, the estimate assumes no capital improvements

. Yet, capital improvements would be required to invest in a treatment technology which would remove dissolved solids and allow the system to completely recycle witho ut scaling. EPA has not adequately accounted for the true cost to convert partially recycled systems to complete recycle systems. We Energies believes EPA either needs to include capital costs for this subset of plants or costs should be estimated by ins talling Mechanical Drag Systems or Remote Mechanical Drag Systems to derive the industry cost estimates. The capital costs for these plants and for the industry as a whole have been grossly underestimated, potentially by tens of millions of dollars.
UWAG provides a thorough analysis comparing the cost estimates EPA derived for bottom ash retrofit technologies to actual conversion costs from industry members. The UWAG cost curve is similar to EPA’s cost curve (with linear fit trend), though the UWAG curve projects higher costs. Unlike EPA’s costs, UWAG’s capital costs (both actual costs and conceptual engineering design estimates) project total capital cost to the plant, including major equipment installed, balance of plant (site work, concrete, piping, el ectrical, mechanical, and instrumentation and controls), engineering (design, SDC, and startup), overhead and profit (subcontractor and general contractor costs), and miscellaneous contingency (unidentified costs). UWAG’s cost curve equation is y = 0.0239 x + 5.2354, where x is the unit MW capacity and y is the capital cost in millions of dollars. EPA’s cost curve equation for Mechanical Drag Systems is y = 0.020083x +Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 580 3, where x is the unit MW capacity and y is the capital cost in millions of dollars. EP A’s cost curve for Remote Mechanical Drag Systems is y = 0.014227x + 2, where x is the unit MW capacity and y is the capital cost in millions of dollars. Comment Response: Based on all the information gathered by the bottom ash vendors, and data in the S team Electric Survey, EPA determined that steam electric power plants can operate closed

- loop bottom ash handling systems, including remote mechanical drag systems, without clarification. Additionally, EPA’s compliance cost methodology includes costs for a chemical feed system to control pH, should that become necessary to prevent scaling within the system. Information in the final rule record indicates that few, if any, steam electric power plants are likely to need to use such chemical feed systems. Howev er, because EPA could not conclusively determine that none of the steam electric power plants would need the chemical feed system to control pH of the recirculating system, nor which ones might likely need the system, EPA estimated costs associated with su ch a system for all steam electric power plants. EPRI also stated in public comments that “not all facilities will install equipment for fines management (surge tanks, chemical feed systems, thickeners) and not all facilities will choose to include redunda ncy,” suggesting that this treatment can be added; however, is not necessary (see DCN EPA

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- A1, Appendix E). Should they choose to do so, however, the coagulated fines (which would now be denser) would settle along with other ash in the remote MDS and be removed from the system by the drag chain conveyer. A clarifier or thickener would not be needed. Based on information from vendors and data provided in the Steam Electric Survey, there are steam electric power plants that are successfull y operating completely closed

- loop bottom ash handling systems without discharging. Therefore, EPA determined that there is no need for a blowdown stream, nor for any resulting costs to treat such a stream from a Remote MDS. See the response to DCN EPA

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Commenter Name: Jay Hudson Commenter Affiliation: Santee Cooper Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 581 Comment Excerpt: In addition, convert ing existing generating units' wet bottom ash handling systems to dry handling is very costly. In fact, EPA states that approximately half of Option 4 costs and approximately one third of the Option S costs would be due to a zero discharge standard for dis charges of bottom ash transport water. 11 Retrofitting to dry ash collection systems would require long unit outages and substantial associated replacement power costs during the outages. In addition, the construction required for dry ash collection retrofi tting would occur in a section of the facility that is congested, which will further increase the cost and technical challenges of completing such retrofits. It is particularly noteworthy that EPA's capital cost estimate did not consider all of the "Balan ce of Plant" costs and the costs associated with site

- specific issues.

11 78 FR 34470 (July 7,2013). Comment Response: The final rule record demonstrates that steam electric power plants can install and afford the dry handling or closed

- loop systems sele cted as the BAT basis for control of pollutants in bottom ash transport water discharges from existing steam electric generating units that are greater than 50 MW and that are not oil

- fired. See the TDD and response to DCN EPA

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Commenter Name: Quinlan J. Shea III Commenter Affiliation: Edison Electric Institute (EEI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 111 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For bottom ash retrofits at plants that recycle a majority of their bottom ash sluice water, EPA assumed a one

- time engineering consultation cost of $22,422 for work on a method of completely closing the system, but pro vided no capital expenditures at all. This oversight is a gross underestimate of retrofit costs.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 582 Comment Response: See response to DCN EPA

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Commenter Name: Dean Ellis Commenter Affiliation: Dynegy Inc. Document Control Number: EPA

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- A1 Comment Excerpt Number: 7 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
I n addition, conversion to zero discharge of bottom ash transport water/retrofitting to dry handling of bottom ash involves significant cost and time. UWAG has provided a detailed analysis regarding conversion of an existing plant from wet sluicing to dry h andling of bottom ash. That analysis shows it would take 30

- 36 months to convert from a wet bottom ash hopper to a dry bottom ash hopper for a large unit and cost over $24 million. Another case study in that analysis shows that adding a remote wet ash hop per and submerged flight conveyor would take 27

- 33 months and cost over $21 million. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 41 for EPA’s comments on the case studies for bottom ash retrofits submitted by both UWAG and Southern Company (DCN EPA

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- 4655

- A11 and DCN EPA

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- A1). See the response to DCN EPA

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- A1, Excerpt Number 126 in Comment Code 26.b for more information on timing of the requirements in the final rule.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 16 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Key Comments on Bottom Ash Handling Cost
- Effectiveness EvaluationEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 583 EPA potentially underestimated the cost of conversion from wet to dry bottom ash handling for the industry. The EPRI annualized cost estimate is approximately twice as high as the EPA estimate. The sources for this discrepancy include:

o Spatial constraints on installation of a mechanical drag system (MDS) beneath the boiler were not considered by EPA when completing its cost estimate.

o Many facilities may require additional outages to complete an under

- the

- boiler installation.

o Many facilities may be unable to stage a remote MDS in close proximity to the boiler.

o Buildings will be required in climates where remote MDS installations will need protection from adverse weather conditions.

o Many facilities will need to install clarification to manage fines for MDSs.

o The cost to permit and construct new on

- site landfills will be incurred by some facilities.

o Plants that recycle 90% of their bottom ash sluice water will likel y incur additional capital costs to fully eliminate discharge. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 34 in Comment Code 16.a for more information on EPA’s approach for estimating compliance costs for a mech anical drag system and remote mechanical drag system (taking into account the fact not all plants may have the space for a particular installation). See the response to DCN EPA

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- A1, Excerpt Number 58 in Comment Code 16.a for more inform ation on outage time required for installation. See the response to DCN EPA

- HQ

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule, including estimates to account for buildings at plants located in cold weather clima tes. See the response to DCN EPA

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- A1 , Excerpt Number 53 for more information on clarification to manage fines. See the response to DCN EPA

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- A1, Excerpt Number 131 for more information on the construction of new landf ills. See the response to DCN EPA

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- A1, Excerpt Number 35 for more information on EPA’s bottom ash management cost methodology for the final rule.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPR I) Document Control Number: EPA

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EPA’s Response to Public Comments

6

- 584 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2 EPA potentially underestimated the cost of conversion from w et to dry bottom ash handling for the industry. EPRI’s annualized cost estimate is approximately twice as high as EPA’s estimate.
Table 8

- 2 shows a comparison of EPA’s and EPRI’s estimated costs to the industry for conversion from wet to dry bottom ash handling in the ELG [EPA, 2013a].

The major differences between estimates made by EPA and EPRI include the following, each of which is discussed in more detail in the subsections below:

 Spatial constraints beneath the boiler were not considered by EPA when completing its cost estimate. EPRI projected that 75% of the industry would construct remote MDSs, while 25% of the industry would construct under

- the

- boiler MDSs.

 Buildings will be needed in climates where remote MDSs require protec tion from adverse weather conditions. EPA did not include this cost.

 EPRI projected that 50% of the industry will elect to install equipment to manage fines to prevent premature piping and pump wear and failure. EPA did not include this cost.

Comment Res ponse: See the response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4379

- A1, Excerpt Number 34 in Comment Code 16.a for more information on EPA’s approach for estimating compliance costs for a mechanical drag system and remote mechanical drag system (taking into account the fact not all plants may have the space for a particular installation). See the response to DCN EPA

- HQ

- OW

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule, including estimates to account for buildings at plants lo cated in cold weather climates.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 585 See the response to DCN EPA

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- 4475

- A1 , Excerpt Number 53 for more information on clarification to manage fines.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Docu ment Control Number: EPA

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- A1 Comment Excerpt Number: 82 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.1 Spatial constraints beneath the boiler were not considered by EPA when completing its cost estimate. A major factor in determining whether a facility can install an MDS beneath its existing boiler is whether there is available room beneath the boiler for such an installation. For many facilities, retrofitting an existin g boiler to install an MDS will be impossible due to spatial constraints. EPA estimated bottom ash conversion costs by evaluating, plant by plant, whether an MDS or remote MDS would be installed. EPA chose the technology corresponding to the lowest annuali zed cost [EPA, 2013c]. However, spatial constraints were not taken into account in this analysis. United Conveyor Corporation (UCC), a major bottom ash handling vendor, estimated that 75% of the industry will install remote MDSs, while 25% will install und er
- the

- boiler MDSs [UCC, 2013]. Based on UCC’s market research, EPRI assumed that 25% of the industry would install under

the

- boiler MDSs. EPA’s cost table is redacted, so it is unclear from the available docket information what percentage of the industry EPA assumed will install under

- the

- boiler MDSs. Costs may be underestimated by EPA because spatial considerations were not taken into account, and some plants that EPA assumed could install under

- the

- boiler MDSs would instead need to install higher

- cost r emote MDSs. Comment Response: See the response to DCN EPA

- HQ

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- A1, Excerpt Number 34 in Comment Code 16.a for more information on EPA’s approach for estimating compliance costs for a mechanical drag system and remote mechanical drag syste m (taking into account the fact not all plants may have the space for a particular installation).

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Exc erpt Number: 83Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 586 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.2 Many facilities may require additional outages, and thus incur additional costs, to complete an under
- the
- boiler installation. EPA assumed that most MDS and remote MDS installations can be completed during regularly scheduled outages [EPA, 2013c]. EPA estimated bottom ash conversion costs by evaluating, plant by plant, whether an MDS or remote MDS was the lower

- cost option. Howev er, EPA did not include any additional costs related to installation during an outage (when labor rates are driven up by demand) or installation of an under

- the

- boiler MDS that extends beyond an outage timeframe. Many facilities may be unable to commit the 6

– 8 weeks of consecutive outage time required to complete an under

- the

boiler installation. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 58 in Comment Code 16.a for more information on outage time required for i nstallation. EPA did not receive any specific public comments about steam electric power plants being unable to commit six to eight weeks of consecutive unscheduled outage time. The overwhelming majority of units that reported mechanical drag system conver sions completed the conversion during regularly scheduled outages. Section 8 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & L oads Report) (DCN SE05831/SE05832) . Furthermore, as discussed in the TDD, conversion to a remote MDS can be accomplished without any effect on regularly scheduled maintenance outages.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 84 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.3 Many facilities may be unable to st age a remote MDS in close proximity to the boiler.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 587 EPA underestimated cost to the industry by assuming that a remote MDS can be staged just outside of the power block [EPA, 2013c]. How far the MDS would be staged from the boiler was not specified by EPA. T his distance should be evaluated. For MDS installations, the capital expenditure and operating costs will increase as distance from the boiler increases. Costs for piping, pumping, running electrical to the remote unit, etc., will increase capital cost. Fo r example, the installed cost of an above

- ground 10

- inch basalt

- lined carbon steel pipe with pipe supports is approximately $200 per linear foot, so the cost of piping will be significant if the remote MDS must be located more than a few hundred yards from the boiler. Operating costs will increase as pumping requirements increase. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 34 in Comment Code 16.a for more information on EPA’s approach for estimating compliance co sts for a mechanical drag system and remote mechanical drag system (taking into account the fact not all plants may have the space for a particular installation). EPA’s compliance cost estimates for the remote mechanical drag system reflect the complete sy stem from the discharge of an existing bottom ash transport water line. EPA acknowledges that the distance of the remote mechanical drag system from the boiler at each steam electric power plant may differ. EPA’s compliance costs are based on the average d istance determined by the vendor from the boiler to the remote mechanical drag system. For those plants that have a longer

- than

- average distance between the boiler and the remote MDS, EPA’s costs may be under or overestimated depending on the distance at a specific plant. EPA notes, however, that its compliance costs are based on average conditions for other elements where plant

- specific data were unavailable. For example, EPA is including the costs of a chemical feed system for all remote mechanical drag s ystems, although not all plants will actually require chemical addition to control pH. Additionally, EPA did not have the data to incorporate possible cost

- savings as a result of economies of scale, such as costing one dry handling system to service multi ple units, into the cost basis of the final rule. Overall, however, EPA’s cost estimates are based on available and representative data, and they are a reasonable prediction of the overall compliance costs to industry as a result of this rule. EPA notes, m oreover, that the Clean Water Act does not require EPA to make a precise calculation of costs. See, e.g., CMA v. EPA , 870 F.2d 177, 237

- 38 (5th Cir. 1989) (“The Act requires the EPA to ‘take into account’ the costs of BAT; it does not require a precise ca lculation. The EPA ‘need make only a reasonable cost estimate in setting BAT’; it is sufficient if the EPA develops ‘a rough idea of the costs the industry would incur’” (citation omitted).); Kennecott Copper v. EPA, 612 F.2d 1232, 1238 (10th Cir. 1979) (E PA has “wide leeway in its analysis of costs”); BASF Wyandotte Corp. v. Costle , 598 F.2d 637, 662 (1st Cir. 1979) (upholds using averages in estimating costs); BP Exploration & Oil Inc. v. EPA , 66 F.3d 784, 799

- 800 (6th Cir. 1995) (“The CWA does not requir e a precise calculation of BAT and NSPS costs” (citation omitted).); NRDC v. EPA , 863 F.2d 1420, 1426 (9th Cir. 1988) (“[T]he Act does not require a precise calculation of BAT costs.”); W eyerhaeuser v. Costle , 590 F.2d 1011, 1045 (D.C. Cir. 1978) (“[Congre ss] left EPA with discretion to decide how to account for the consideration factors, and how much weight to give each factor.”).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 588 Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 85 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.4 Buildings will be required in climates where remote MDS installations will need protection from adverse weather conditions. EPA did not include cost of buildings in their calculation [EPA, 2013c]. EPRI examined climate maps from the National Oceanic and Atmospheric Administration’s (NOAA’s) National Climate Data Center for mean daily minimum tempera tures across the nation. Figure 8

- 1 illustrates the mean daily minimum temperature in various regions of the United States. Using this information, EPRI determined that plants would require a building to house the remote MDS in the following states, where adverse weather conditions occur: Maine, New Hampshire, Vermont, New York, Michigan, Wisconsin, Minnesota, North Dakota, South Dakota, Montana, Wyoming, Colorado, and Idaho. EPA underestimated capital costs of remote MDSs by not including the cost of build ings in their calculations. EPRI included building costs for 30% of the plants on which the industry cost is based.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 589 Comment Response: See the response to DCN EPA

- HQ

- OW

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- 0819

- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule, including estimates to account for buildings at steam electric power plants located in cold weather climates.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 86 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.5 EPA has potentially underestimated costs by not including factors typical of engineering estimates.
EP A’s costs for MDS and remote MDSs came from estimates provided by The Clyde Bergemann Power Group (CBPG) [EPA, 2013c]. CBPG’s estimate states that “Pricing given reflects fully erected and commissioned systems including equipment, controls, foundations and field labor” [EPA, 2013b] It is unclear from this statement whether the cost factors typical of engineering estimates at this early stage of design, as provided in Table 8

- 3, are included in the estimates provided by CBPG. If they are not included, EPA li kely underestimated the total capital cost to the industry of the MDS and remote MDSs. Table 8

- 3 provides approximate cost factor ranges to apply to vendor estimates. The cost factors used will vary, based on specific conditions at a facility.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 590 Comment Re sponse: See the response to DCN EPA

- HQ

- OW

- 2009

- 0819

- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule, including information about the estimated indirect capital cost factor.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 87 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.6 Some facilities will need to install water treatment to manage water quality in closed loop MDSs.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 591 EPA assumed that fines will be managed solely with precipitation by acid addition, and that clarification beyond the MDS will not be required [EPA, 2013c]. Although many faci lities will choose not to remove fines, some facilities will elect to remove fines using clarification. Reducing the fines will result in longer life and lower maintenance costs for pumps and piping. In developing a $/MW unit cost, EPRI projected

— for the e stimated 75% of the industry that will install remote MDSs

— that 50% will employ some type of fines management and 50% will not. EPRI used this projection to determine a $ per MW unit cost. Treatment equipment that would be used for fines management include s the following:

 Clarifier

 Reaction tank and mixer

 Chemical feed system

 Polymer feed system

 Sludge holding tank and mixer

 Filter press

 Pumps For example, installation of a 2,500 gpm system would add $10 million in treatment equipment costs for a facility. In addition to fine particulate matter removal, select facilities may need to further treat bottom ash water to prevent scaling and / or corrosion in their bottom ash handling equipment. Scaling, which is typically caused by the presence of calcium and/or magnesium, would have to be removed by softening. Corrosion, driven by the presence of chlorides, would require the implementation of reverse osmosis membranes or thermal evaporation equipment. While this equipment would not be necessary at all facilities, at facilities that require chlorides removal the equipment could potentially to add significant cost and complexity. Comment Response: See the response to DCN EPA

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- A1 , Excerpt Number 53 for more information on clarification to manage fines. Clarification would only be needed, if at all, if plants opt to use clear water pumps to return the water back to the sluicing system. Such pumps are typically rated for 100 ppm maximum TSS. EPA’s cost estimates, however, are based on using slurry pumps for this purpose. Slurry pumps are rated to 400 ppm TSS; the TSS in the return water from the remote MDS will be well below that value.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Numb er: EPA

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EPA’s Response to Public Comments

6

- 592 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 8.2.7 Plants that recycle 90% of their bottom ash sluice water will likely incur additio nal treatment costs to fully eliminate discharge. For those plants currently recycling the majority (more than 90%) of their bottom ash sluice water, EPA assumed that a one

- time engineering cost would be sufficient to completely close the recycle loop and eliminate the discharge of bottom ash transport water. EPA assumed that the one
- time engineering cost of $22,422 per plant would be incurred to develop a plan to close the recycle loop [EPA, 2013c]. EPRI assumed that these plants discharge 10% of their flo w because their current systems (typically dewatering bins) do not remove fine solids from the bottom ash sluice water. These fines build up over time in the closed loop system; if the system’s blowdown is eliminated, the fines will require some type of ma nagement. EPRI included costs for additional treatment equipment for these facilities. The additional treatment equipment includes the following:

 Clarifier

 Reaction tank and mixer

 Chemical feed system

 Polymer feed system

 Sludge holding tank and mixer

 Filter press

 Pumps The annualized cost to the industry of including this additional treatment equipment at the facilities that largely recycle their bottom ash sluice water is $21 million per year. This cost represents the annualization of $90 million capi tal cost and $13 million in operations and maintenance (O&M) costs. Some facilities may need to upgrade their current solids dewatering systems (for example, dewatering bins) to a MDS or remote MDS. If facilities that currently recycle 90% or more of their bottom ash sluice water were to construct remote MDSs, the annualized cost would be $68 million per year. (This cost represents the annualization of $352 million capital cost and $31 million in O&M costs.) Thus, to completely close the loop on partial rec irculation systems that mainly recycle bottom ash sluice water, EPRI estimates an annualized cost to the industry of $21 to $68 million (2010 dollars).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 593 Comment Response: See the response to DCN EPA

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- 4379

- A1, Excerpt Number 35 for more in formation on EPA’s bottom ash management cost methodology for the final rule.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 117 Ex ternal Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### E.1 Cost Estimating Summary for Conversion of Wet to Dry Bottom Ash Handling
E.1.1 Summary The Electric Power Research Institute (EPRI) estimated the cost of conversion of wet to dry bottom ash handling for the steam electric industry. This appendix describes the method for calculation of the cost of conversion of wet to dry bottom ash handling for an individual plant, the assumptions associated with th e cost calculations, and the estimated costs for the steam electric industry. Table E

- 1 outlines the cost to the current industry to convert from wet to dry bottom ash handling.



### E.1.2 Treatment Equipment Overview EPRI evaluated the following two technolo gy options that EPA evaluated for bottom ash transport water:

 Mechanical drag system

 Remote mechanical drag systemEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 594 E.1.2.1 Mechanical Drag System The Mechanical Drag System (MDS) for which costs were developed consists of chain mounted flight bars submerge d in a water trough below the boiler in place of the existing bottom ash hoppers. The ash drops directly into the water trough and settles down into the water and onto the MDS. The ash is evacuated mechanically on a continuous basis so there is no long

- ter m storage in the water trough beneath the boiler. Water in the MDS is pumped continuously into the trough for makeup and cooling water. From there the bottom ash is conveyed up a dewatering slope at an angle suitable for dewatering the ash down to 20% mois ture content. The bottom ash then enters into a transfer chute and then into a clinker grinder/crusher to rid the ash of any large binded material. The clinker grinder then deposits the bottom ash into a collection pit. A front end loader can then be utili zed to remove and load the dewatered ash into a transportation truck for on

- site or off

- site landfill storage.
E.1.2.2 Remote Mechanical Drag System
The remote MDS is much like the under

- the

- boiler MDS, except for the fact that the remote MDS equipment is located outside the plant and away from the bottom of the boiler. The bottom ash falls into the bottom ash hoppers and moves through the clinker grinders. Existing or new bottom ash sluice pumps and bottom ash sluice piping remove the bottom ash from the e xisting bottom ash hoppers under the boiler. The ash is then conveyed via the ash sluice piping to the remote location of the MDS. The piping deposits the bottom ash into the trough area and it settles down through the water onto the submerged flight chain conveyor. From here the bottom ash is slowly conveyed up a dewatering slope at an angle suitable for dewatering the ash down to 20% moisture content. The bottom ash then enters into a transfer chute and is deposited down into a storage area in a building enclosure or an outdoor concrete storage area. A front end loader can then be utilized to remove and load the dewatered ash into a transportation truck for on

- site or off

- site landfill storage. Water is collected below the dewatering conveyor and returned to the trough. Water is then re

circulated back to the bottom ash hoppers via recirculation pumps. Makeup water is also tied into the system and can be water taken from other plant systems that would normally discharge into the existing ash ponds. The rem ote MDS removes bottom ash intermittently. 

### E.1.3 Overview of Cost Methodology Capital and operating costs were developed for both the under

- the

- boiler MDS and remote MDS technologies. EPRI assumed that approximately 75% of the industry would install remote MDSs and 25% of the industry would install the under

- the

- boiler MDSs, based on input from United Conveyor Corporation (UCC). UCC is one of the leading providers of systems used to convert from wet to dry bottom ash handling. UCC stated that if the only op tions considered are MDS or remote MDS (no other dry handling technologies), roughly 75% of the industry is predicted to install remote MDS and 25% of the industry is predicted to install MDS. Capital and operating costs were adjusted for mid

- 2010 dollars.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 595 E.1.3.1 Remote MDS Cost Overview
E.1.3.1.1 Remote MDS Capital Cost Development per Plant EPRI spoke with UCC to develop capital and operating cost estimates. The capital costs developed were based on total engineering, procurement, and construction (EPC) costs project examples for two plants. One of the plants employed two remote MDS units and equipment included related pumps and piping. The other facility would include redundant remote submerged flight conveyor units, surge tanks, and thickeners for remo ving fine solids from the wastewater that are entrained in the remote MDS overflow. These two types of facilities represent the spectrum of equipment that a facility would install if installing remote MDS because not all facilities will install equipment for fines management (surge tanks, chemical feed systems, thickeners) and not all facilities will choose to include redundancy. EPRI normalized the costs for each plant based on a dollar

- per
- megawatt basis and assumed that 50% of the industry would employ the less

- expensive option of just the remote MDS and 50% of the industry would prefer to have fines management equipment in place. EPRI used this to develop a normalized, average

- dollars

- per
- megawatt (MW) plant capacity to calculate capital costs based on the EPC costs provided by UCC. In addition, EPRI added the plant engineering factor of 0.01765 that EPA used for the plant’s own engineering to the vendor EPC cost to estimate a total capital cost. To calculate a plant’s remote MDS capital cost, the total plant capacity (MW) for units greater than 50 MW was calculated per plant and the dollar per megawatt was used to calculate capital costs per plant. E.1.3.1.2 Remote MDS Operations and Maintenance Cost Development per Plant Annual labor, energy, chemicals , maintenance, and disposal costs were calculated per plant to determine a facility’s operations and maintenance (O&M) cost. The major assumptions used in calculating these estimated O&M costs were:

 Costs are presented in June 2010 dollars. Construction Co st Index values, as published by Engineering News Record (ENR), were used to de

- escalate costs from more recent information to June 2010 pricing.

 Labor: a total of one incremental full

- time equivalent (FTE) operator at $46.36/hour was assumed to staff the remote MDS in addition to the staff currently employed at the facility in charge of wet sluicing operations. The $/hr operator cost was obtained from Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards fo r the Steam Electric Generating Point Source Category [EPA, 2013a]. Since remote MDS operations are intermittent, it is assumed that the system would operate a total of 6 hours per day at each facility.

 Chemicals: The only chemical assumed is addition of f erric chloride as a coagulant to aid in settling of fines. A dosage rate of 50 parts

- per
- million (ppm) of ferric chloride was assumed. The unit cost of ferric chloride (35 percent) used in this estimate is $1.55/gallon. Based on EPRI experience, this chemi cal is more applicable to aid precipitation of fine solids than EPA’s assumed acid addition.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 596  Disposal: All solids will be Resource Conservation and Recovery Act (RCRA) nonhazardous solids with a disposal unit cost of $42.76 per dry ton. The disposal cost
w as developed as a weighted average using on

- site and off

- site disposal costs provided in Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category [EPA, 2 013a]. EPRI assumed 75% of plants would use on

- site disposal facilities at $40.41 per dry ton, and 25% of plants would use off

- site disposal facilities at $49.82 per dry ton.

 Energy: Electrical costs were estimated using the value used by EPA, $0.0405/kilo watt

hour (kWh), corrected for 2010 dollars, which is the unit cost provided in Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category [EPA, 2013a].

 En ergy: The following electrical equipment were used to calculate the total horsepower (hp) requirement to calculate electrical costs:

o Hydraulic power unit to operate drag chain

- 75 hp

o Chemical feed pump

- 0.5 hp

o Low pressure recirculation pump

- 200 hp o Hig h pressure recirculation pump

200 hp o Sump pump with motor

- 20 hp

o Overflow return pump with motor

- 50 hp

 Maintenance: Annual equipment maintenance costs will be 5.0 percent of the total equipment costs for the facility. 

### E.1.4 MDS Cost Overview
E.1.4.1 MD S Capital Cost Development per Plant EPRI developed the cost curve shown in Figure E

- 1 for EPC cost for the under

- the

- boiler MDS technology based on input from UCC.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 597 In addition, EPRI added the plant engineering factor of 0.01765 that EPA used for the plant’s own engineering to the vendor EPC cost to estimate a total capital cost. Capital costs were calculated for each under

- the

- boiler MDS unit and summed for facility total. E.1.4.2 MDS Operations and Maintenance Cost Development per Plant Annual labor, energy, chemicals, maintenance and disposal costs were calculated per plant to determine a facility’s O&M cost. The major assumptions used in calculating these estimated O&M costs for the MDS were:

 Costs are presented in June 2010 dollars. Construction Co st Index values, as published by Engineering News Record (ENR), were used to de

- escalate costs to June 2010 pricing.

 Labor: it was assumed that no incremental labor would be needed over that used for existing wet sluicing operations.

 Energy: Since MDS ope rations are continuous, it is assumed that the system would operate a total of 24 hours per day at each facility.

 Chemicals: No chemicals were assumed for the MDS.

 Disposal: All solids will be Resource Conservation and Recovery Act (RCRA) nonhazardous soli ds with a disposal unit cost of $42.76 per dry ton. The disposal cost was developed as a weighted average using on

- site and off

- site disposal costs provided in Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and St andards for the Steam Electric Generating Point Source Category [EPA, 2013a]. EPRI assumed 75% of plants would use on

- site disposal facilities at $40.41 per dry ton, and 25% of plants would use off

- site disposal facilities at $49.82 per dry ton.

 Energy: El ectrical costs were estimated using the value used by EPA, $0.0405/kilowatt

hour (kWh), corrected for 2010 dollars, which is the unit cost provided in Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards f

or the Steam Electric Generating Point Source Category [EPA, 2013a].

 Energy: The following electrical equipment were used to calculate the total horsepower (hp) requirement to calculate electrical costs:

o Hydraulic power unit used to operate drag chain

- Un it Capacity <=500 MW = 50 hp

o Hydraulic power unit used to operate drag chain

- Unit Capacity >500 MW = 75 hp

 Maintenance: Annual equipment maintenance costs will be 5.0 percent of the total equipment costs for the facility.

 Wet sluicing credit: A wet sluici ng credit for maintenance and energy costs was applied to each facility to subtract the cost of wet sluicing operations from each O&M estimate. The wet sluicing credit was developed based on EPA’s cost assumptions for maintenance and energy costs cited in Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category [EPA, 2013a]. 

### E.1.5 Recurring CostsEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 598 EPRI used the same assumptions as EPA for recurring costs fo r drag chain replacement. The drag chain replacement would cost $175,000 and would occur every 3 years for the under

- the

boiler MDS and every 5 years for the remote MDS. 

### E.1.6 Annualized Costs
EPRI assumed a 20

- year life and 7 percent interest rate to dev elop annualized capital costs for each facility’s system. Annualized costs for each facility were developed by taking the annualized capital cost, annual operating cost, and annualized recurring cost to calculate a total annualized cost for each facility. 

### E.1.7 Plant Adjustment Factor EPRI used the EPA plant adjustment factors for each facility cited in Table A

- 1 of Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG Regulatory Option 4a [EPA, 2013b] to calculate the facility co sts for Option 4a, for plants with generating units with a capacity greater than 400 MW. EPA calculated the plant adjustment factor using the following methodology: “To calculate these adjustment factors, EPA started with the list of generating units incur ring a bottom ash cost as identified by the cost input table for bottom ash); however, EPA excluded all oil

- fired units and those with a capacity of 50 MW or less. EPA then calculated the total wet produced bottom ash tonnage per year for the plant for all remaining units in the list. Next, EPA calculated the percentage of the total wet produced bottom ash tonnage per year for each unit identified as incurring a cost (using the total wet produced bottom ash tonnage calculated in the previous step as the den ominator). These percentages represent the percent of plant

- level cost or pollutant removal associated with each generating unit. EPA then summed the percentages for all units with a capacity greater than 400 MW on a plant level to calculate the total perc entage of wet bottom ash tonnage that will still receive a cost under Option 4a.” [EPA, 2013b] Comment Response: EPA reviewed the commenter’s bottom ash cost calculations provided in Appendix E of its comment letter. Based on the final compliance costs, EPA estimates that over 90 percent of the steam electric power plants identified as full bottom ash conversions will install remote mechanical drag systems. This estimate is more conservative than the approach taken by EPRI, which assumes that 25 percent o f the industry would install mechanical drag systems and 75 percent would install remote mechanical drag systems. EPA cannot evaluate or provide a response to the remote mechanical drag system capital cost development used in the commenter’s analysis becau se the actual costs are not provided. However, EPA notes that the commenter assumed that only 50 percent of the industry would install equipment for fines management and that not all steam electric power plants will choose to include redundancy. As explain ed in other comment responses in this comment code, EPA based certain elements of its compliance costs on average conditions where plant

- specific data were unavailable. EPA included costs for a chemical feed system to control pH for all remoteEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 599 mechanical d rag system installations, should that become necessary to prevent scaling within the system. However, information in the final rule record indicates that not all steam electric power plants are likely to need to use such systems. Because EPA could not conc lusively determine that none of the plants would need the chemical feed system to control pH of the recirculating system, nor which of the plants might likely need the system, EPA included such costs for all plants. This likely overestimates the compliance costs for most plants; however, the cost for chemical addition is relatively small in relation to other costs for the remote MDS. Additionally, EPA included costs for a remote mechanical drag system for each generating unit identified as discharging botto m ash transport water at the plant, which may have the effect of overestimating costs because it does not account for economies of scale, such as costing one dry handling system to service multiple units. However, EPA did not have data to incorporate possi ble cost

savings related to economies of scale, and it wanted to ensure that the costs covered sufficient redundancy for the plant. Overall, EPA’s cost estimates are based on available and representative data, and they are a reasonable prediction of the ov erall compliance costs to industry as a result of this rule. See, e.g., CMA v. EPA , 870 F.2d 177, 237

- 38 (5th Cir. 1989) (“The Act requires the EPA to ‘take into account’ the costs of BAT; it does not require a precise calculation. The EPA ‘need make only a reasonable cost estimate in setting BAT’; it is sufficient if the EPA develops ‘a rough idea of the costs the industry would incur’” (citation omitted).); Kennecott Copper v. EPA, 612 F.2d 1232, 1238 (10th Cir. 1979) (EPA has “wide leeway in its analysis of costs”); BASF Wyandotte Corp. v. Costle , 598 F.2d 637, 662 (1st Cir. 1979) (upholds using averages in estimating costs); BP Exploration & Oil Inc. v. EPA , 66 F.3d 784, 799

- 800 (6th Cir. 1995) (“The CWA does not require a precise calculation of BAT and NSPS costs” (citation omitted).); NRDC v. EPA , 863 F.2d 1420, 1426 (9th Cir. 1988) (“[T]he Act does not require a precise calculation of BAT costs.”); W eyerhaeuser v. Costle , 590 F.2d 1011, 1045 (D.C. Cir. 1978) (“[Congress] left EPA with discretion to dec ide how to account for the consideration factors, and how much weight to give each factor.”). For the remote mechanical drag system operation and maintenance costs, the commenter used several factors and assumptions from EPA’s proposed cost methodology. Fo r the final rule, EPA used chemical costs associated with hydrochloric acid for pH control and estimated onsite versus offsite disposal costs based on plant

- specific landfill data provided in the Steam Electric Survey. EPA estimated energy costs associated the remote mechanical drag system using horsepower ratings obtained from vendors and calculated maintenance material costs using a ratio of total operation and maintenance costs obtained from the Steam Electric Survey data. EPA cannot evaluate or respond to the commenter’s mechanical drag system capital cost development because the system specifics associated with the cost estimates are not provided. However, EPA notes that the cost curve for estimating capital costs for a mechanical drag system for the fi nal rule generates comparable costs to the cost curve provided in the comment. In fact, EPA’s cost curve has a steeper slope resulting in higher cost estimates associated with higher capacities. For the mechanical drag system operation and maintenance esti mates, the commenter used several factors and assumptions from EPA’s proposed cost methodology. For the final rule, EPA estimated onsite versus offsite disposal costs based on plant

- specific landfill data provided in the Steam Electric Survey.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 600 The cost est imates associated with the final rule reflect EPA’s responses to public comments. See the response to DCN EPA

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Commenter Name: Daniel K. Plath Commenter Affil iation: Northern Indiana Public Service Company (NIPSCO) Document Control Number: EPA

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- A2 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
In additio n, in presenting the cost for compliance for Option 4a, USEPA appears to have focused on zero liquid discharge for bottom ash at facilities with a nameplate capacity of greater than 400 MW. USEPA did not explicitly evaluate conversion approaches for cyclon e boilers, that is, an option to handle a molten liquid. It is not apparent that the bottom ash conversion options and economics presented by USEPA would be applicable to the dry management of cyclone boiler slag. Therefore, the Option 4a costs of com pliance, and resulting regulatory impact, for facilities utilizing cyclone boilers, appear to be inaccurate. Comment Response: EPA determined that the dry handling and closed

- loop systems that are the BAT basis for control of pollutants in bottom ash tr ansport water discharges from units that are greater than 50 MW and that are not oil

- fired are available for cyclone boilers. EPA notes that there is at least one cyclone boiler generating unit that currently operates a mechanical drag system (Kansas City Power & Light’s La Cygne Generating Station). Additionally, the remote mechanical drag system uses the existing wet bottom ash transport system with a different dewatering process. See the response to DCN EPA

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- A1, Excerpt Number 46 in C omment Code 6.g.ix for more information on cyclone boilers, the technologies evaluated for BAT, and wastewater characterization.

Commenter Name: Stephen M. Frank Commenter Affiliation: NRG Energy, Inc. Document Control Number: EPA

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- 601 Comment Excerpt: Separating Low Volume Wastewater from Bottom Ash Transport Water is Impractical and Not Accounted For in the Econom ics EPA did not account for the separation and treatment of Low Volume Waste from bottom ash transport water when considering the zero discharge requirements. According to the 2009 Detailed Study, the OSWER data identified 211 plants operating a total of 4 17 surface impoundments containing bottom ash. Ninety

- one of these ponds contain only bottom ash. For the fly and bottom ash ponds reported in response to the data request, waste streams other than ash transport water ranged from 3 to 93 percent of the tot al pond influent flow in 2006. The major types of influent, other than ash transport water, included:

 Cooling tower blowdown,

 FGD wastewater, and

 Various types of low

- volume wastes (including nonchemical metal cleaning wash waters). A zero discharge requirement means that some plants will be required to close impoundments in accordance with state requirements (e.g., 25 Pennsylvania Code Article IX [Residual Waste Management] requires the closure of bottom ash impoundments within one year from when the last quantity of waste was added). Other plants will be required to redirect flow from up to 326 impoundments to achieve 100% recycle of the transport water. In many cases, flow cannot be easily redirected because existing wastewater treatment facilities do not have the excess capacity to handle these flows. Comment Response: The final rule does not require the “separation and treatment of low volume waste from bottom ash transport water.” See response to DCN EPA

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Commenter Name: Stephen M. Frank Commenter Affiliation: NRG Energy, Inc. Document Control Number: EPA

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- 602 Comment Excerpt: EPA’s costs do not account for the decommissioning of the dewatering bins, impoundments, and other associated equipment or the years of useful life lost for this equipment. EPA should assess the extent of these significant costs and include the m in the economic evaluation before requiring zero discharge. Comment Response: See response to DCN EPA

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EPA confirmed with vendors that the e xisting equipment at the steam electric power plant does not need to be demolished or removed for the operation of the mechanical or remote mechanical drag systems. In addition, abandonment in place is the approach plants typically use for obsolete systems . EPA notes that the costs associated with the mechanical drag system do include demolition costs under the boiler because new equipment would need to be installed in that location. Additionally, plants may choose whatever technology they prefer to comply with the final limitations and standards. They are not required to use the specific technology basis used by EPA to estimate costs. Plants could use existing infrastructure (e.g., dewatering bins) as part of a zero discharge system to meet the final rule’s requirements. Regarding concerns with respect to the remaining useful life of installed technology that may be decommissioned, see response to related issues regarding the impacts of using shorter annualization periods in response to DCN EPA

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- A1, Excerpt Number 70 in Comment Code 28.b, which addresses the concern from the perspective of upgrades to generating units having a relatively short remaining life.

Commenter Name: Mike Roddy Commenter Affiliation: Seminole Electric Cooperat ive, Inc. (SECI) Document Control Number: EPA

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- A2 Comment Excerpt Number: 3 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry Bottom Ash In its proposed rule, the EPA has pr oposed dry handling for bottom ash in all of its proposed options. SECI believes that part of that evaluation was based on a field visit EPA representatives made to our Seminole Generating Station in Palatka Florida. SECI has recently installed a dry botto m ash system and provided EPA with information and a site tour. SECI wants to go on record as stating that while we have found the conversion from wet to dry handling to beEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 603 beneficial and cost

- effective, the ability to install these systems is very site s pecific and other facilities may see much greater costs for dry handling installation than SECI. SECI does not support EPA requiring dry bottom ash handling for all facilities and believes they have not properly evaluated the cost of installation for facil ities that do not have the available space for installation. Much of SECI's success in converting from wet to dry handling in a cost effective manner was based on the original design of our boilers, which provided ample space below the boiler system for th is specific system. Facilities that are not fortunate enough to have this space will be required to create it by digging out areas. This need for space will make the conversion significantly more expensive, if possible at all.
The EPA should re

- evaluate it s requirement for dry handling by visiting sites that do not fit the criteria for dry handling. These sites would give EPA a more proper analysis of cost than a site such as SECI's. Comment Response: As described in Section 9 of the TDD, EPA estimated co mpliance costs for mechanical and remote mechanical drag systems for the industry as the BAT technologies for control of pollutants in bottom ash transport water discharges from units that are greater than 50 MW and that are not oil

- fired. EPA did not base compliance cost estimates on a dry mechanical conveyor installation. See the response to DCN EPA

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Commenter Name: Erik Silvola Commenter Affiliation: Great River Energy (GRE) Document Control Number: EPA

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- A1 Comment Excerpt Number: 4 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We also believe that EPA underestimated the cost of conversion from wet to dry bottom ash handling. Not o nly are there the costs provided by EPRI, there is also the stranded investment in the existing bottom ash ponds and related handling systems. Comment Response: See the response to DCN EPA

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- 604 See response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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### 2. Bottom Ash Cost and Engineering Information Survey On November 5, 2012, UWAG distributed an e lectronic survey to its members regarding cost and engineering information for conversions from wet bottom ash handling systems to dry bottom ash handling or closed

- loop, recycling systems. Examples of the types of conversions UWAG requested information o n included under

- furnace submerged conveyors, remote submerged drag chain conveyors with dewatering equipment, and wet sluicing to dewatering bins, as well as completely dry systems such as dry vacuum systems and dry sealed conveyors. The survey asked mem bers to provide actual retrofit cost data or conceptual engineering design estimates for retrofits. UWAG followed up this survey with a supplemental request for retrofit cost and characterization data in April 2013. As discussed in the next sections, UWAG ’s bottom ash transport water TWPE and $/TWPE calculations produced results that are quite different from EPA’s results. Comment Response: See the response to DCN EPA

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For the role of cost

- effectiveness in EPA’s decision for the final rule , see response to DCN EPA

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Commenter N ame: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 605 Comment Excerpt Number: 55 External Review Flag: No External Review External Review Incorporated into Response: No
Comment Excer pt: Therefore, EPA’s assumption that no costs will occur for land or space constraints is not correct. Many facilities will have to relocate equipment or buildings to accommodate the new bottom ash handling equipment or purchase nearby land and purchase additional piping to reach it. In summary, EPA’s methodology for selecting the lowest cost of the two systems for each plant is flawed because it does not take into account site

- specific issues. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 34 in Comment Code 16.a for more information on EPA’s approach for estimating compliance costs for a mechanical drag system and remote mechanical drag system (taking into account the fact not all plants may have the space for a particular installation). EPA does not agree that plants will need to acquire land to install systems to comply with the ELG, nor that they will have to relocate buildings or equipment.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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H. EPA Estimated One
- Time Costs for Plants That Recycle 90% of Bottom Ash Transport Water EPA determined that some plants recycle a majority of their bottom ash sluice water but still discharge a small portion of it as emergency discharges or via other plant operations ( e.g. , re
used and discharged with FGD wastewater). For those plants recycling the majority of their bottom ash sluice, EPA assumed that a one

- time engineering cost would be appropriate to completely close the bottom ash sluice recycle loop to eliminate the discharge of bottom ash transport water. To determine the plants that should receive the one

- time bottom ash management cost, EPA reviewed bottom ash sluice r ecycle and discharge amounts reported in 2010 ICR Part C, Section 3.1, along with the water balance diagrams provided in the ICR. EPA identified the plants thatEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 606 should receive the one

- time bottom ash management costs as those plants recycling more than 90 % of their sluice or only discharging bottom ash sluice through emergency outfalls. Based on industry knowledge and contractor fees, EPA developed an estimate for a contractor to come on site and develop a plan for the plant to close up the bottom ash dis charge. EPA assumed that the contractor will require a total of 200 hours to complete the plan, including two week

- long trips to the plant. EPA estimates that the total one

- time costs for a plant to hire a contractor to close the discharge of a bottom ash recycle system would be $22,422. This estimate assumes no capital improvements. IC&PR, p. 8

- 31. There are two problems with EPA’s analysis of plants that recycle 90% of their bottom ash sluice water. First, it is not technically feasible to recycle thi s wastewater without major modifications or complete retrofit of the wet bottom ash handling system. Because of fines and scaling issues, a blowdown of this type of system is required. Second, a one

- time cost of $22,422 is an underestimate for a contract or to design a closed

- loop system. But even more surprising, EPA did not provide any capital dollars for the retrofit to a 100% recycle system. Addition of a bottom ash sluice recycle system will require capital expenditures. For example, a remote submer ged flight conveyor bottom ash hopper (SFC

- BAH) will require the addition of low pressure pumps to refill the existing wet bottom ash hopper, medium pressure pumps to supply water to the suction of the existing ash sluice transport pumps, and high pressure pumps to supply water to the existing wet bottom ash hopper flush nozzles (hopper slope and clinker grinder inlet). Electrical power to operate these pumps represents new load on the distribution system that will require expansion of the system (typicall y power transformers, switchgear, motor control centers, cable, conduit, cable trays, underground electrical duct banks, electrical equipment enclosures, etc.). The plant control system must be modified to control the operation of this equipment. Piping to deliver this recycled water must be installed. The cost for this piping will vary with the distance between the remote SFC

- BAH and the wet bottom ash hopper. All of the hardware mentioned above will also have to be installed, adding construction labor, contractor profit, and construction management labor. Therefore, EPA has grossly underestimated the capital costs for these plants and for the industry as a whole, potentially by hundreds of millions of dollars. Comment Response: See the response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAGEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 607 Document Control Number: EPA

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- 4655 Comment Excerpt Number: 64 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA has underestimated the costs of retrofitting bottom ash dry handling or closed

- loop systems. UW AG’s estimate of capital costs alone exceeds EPA’s entire costs for bottom ash retrofits. UWAG’s estimate does not include O&M costs or disposal costs, which will increase $/TWPE. Comment Response: EPA reviewed all of the cost comments submitted by UWAG. See the response to DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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Attachment 11 to these comment s describes the modifications that would have to be made to an existing plant to convert it from wet sluicing to dry handling of bottom ash. In the case study presented in the attachment, it would take 30

- 36 months to convert from a wet bottom ash hopper t o a dry bottom ash hopper for a large unit and cost over $24 million ($24,803,358 plus $8,851,653 for contingency, escalation, and operating company overheads). Another case study for adding a remote wet ash hopper and submerged flight conveyor would take 27

- 33 months and cost $24,803,358 plus over $8,800,000 for contingency, escalation, and operating company overhead. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 41 for EPA’s comments on the case studies for bottom ash retrofits submitted by both UWAG and SouthernEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 608 Company (DCN EPA

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 226 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: UWAG plotted the MWs versus the capital costs, in Figure 4 below, to generate a cost equation t o estimate capital costs (2012 dollars) of retrofitting based on a unit’s MW. UWAG selected a linear equation based on the best correlation coefficient (R 2 ) value (0.63). The cost curve equation is as follows: y = 0.0239x + 5.2354, where x = MW served by retrofit, and y = capital cost. Figure 4: UWAG Capital Cost Curve for Bottom Ash Retrofits

The UWAG cost curve is similar to EPA’s cost curve, though the UWAG curve has higher costs. Unlike EPA’s costs, UWAG’s capital costs (both actual costs and con ceptual engineering design estimates) include total capital cost to the plant, including major equipment installed, balance of plant (site work, concrete, piping, electrical, mechanical, and instrumentation and controls (I&C)), engineering (design, service s during construction, and startup), overhead and profit (subcontractor and general contractor costs), and miscellaneous contingency (unidentified costs).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 609 Using this more realistic cost curve, UWAG calculated capital costs and annualized capital costs base d on a 15

- year service life and 7% interest for the capacity

- based model plants. UWAG has found that 15 years better represents the service life of the equipment and is consistent with EPA’s past practice. See Final Landfills Development Document at 9

- 9 (capital costs amortized using a 7% interest rate over 15 years); MP&M Development Document, p. 11

- 19 (Agency assumed a 7

- percent discount rate over an estimated 15

- year equipment life). The results are provided in Table 3.
Table 3: UWAG Bottom Ash Retro fit Annualized Capital Costs, Million Dollars

MW Range MW Used

(Midpoint) Bottom Ash Retrofit

Total Capital Cost, Million $/Plant Bottom Ash Retrofit

Annualized Capital Costs, Million $/Plant (assumed 15
- year life of system and 7% interest) <50 MW 50 6.4 0.71 50

- 100 MW 75 7.0 0.77 100

- 150 MW 125 8.2 0.90 150

- 200 MW 175 9.4 1.03 200

- 300 MW 250 11.2 1.23 300

- 400 MW 350 13.6 1.49 400

- 500 MW 450 16.0 1.76 500

- 700 MW 600 19.6 2.15 700

- 900 MW 800 24.4 2.67 >900 MW 1000 29.1 3.20 Comment Response: EPA reviewed all of the cost comments submitted by UWAG. See the response to DCN EPA

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Commenter Name: Kevin D. Frizzell Commenter Affiliation: Owensboro Municipal Utilities (OMU) Elmer Smith Station (ESS) Document Control Number: EPA

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- 610 Comment Excerpt: OMU ESS would incur extensive costs if required to retrofit to dry handling of bottom ash. The conversion to a dry bottom ash handling system would be a very long and extensive renovation. ESS Unit 1 is a cyclone unit which produces bott om ash in the form of slag. Water is inherent in the process of cooling and breaking up the slag into smaller particles. Cyclone slag is a very hard, glassy material with extremely low leaching characteristics. The cost to convert this process to a dry pro cess is extremely high and there would be no environmental benefit. Plants should be given the opportunity to demonstrate that converting to dry handling of bottom ash transport water would not be cost effective. Comment Response: See response to DCN EPA

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- A2, Excerpt Number 6 for more information on cyclone boilers.

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- A1 Comment Excerpt Number: 104 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
B. ELIMINATING THE DISCHARGE OF BOTTOM ASH TRANSPORT WATER IS ECONOMICALLY ACHIEVABLE. A technology is economically achievable if the costs of the tech nology can be reasonably borne by the industry as a whole. 432 The record indicates that the steam electric industry can reasonably bear the costs of converting all units to zero discharge systems. EPA estimated the cost of converting to a zero discharge system based on mechanical drag and remote mechanical drag systems. While these two systems are economically achievable, dry vacuum and pressure systems are also economically achievable, and may have even lower costs. The record reflects that the industry as a whole can reasonably bear the cost of installing and operating the many systems capable of meeting a zero discharge standard for bottom ash transport water. EPA calculated the cost of meeting a zero discharge standard for bottom ash based on the inst allation and operation of mechanical drag and remote mechanical drag systems. EPA estimates that requiring all units greater than 50 MW to meet a zero discharge standard would require retrofits at 240 plants with a capital cost of $4.5 billion and annual O&M costs of $494 million. 433 On average, each plant would incur $17 million in capital costs and $2 million in annual O&M costs. Since 240 plants will incur compliance costs, 434 and there are a total of 1079Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 611 plants, 435 only 22% of all plants would incur compliance costs. Put differently, 78% of plants in the industry would have zero compliance costs as a result of a zero discharge standard for bottom ash transport water. 436 The costs can be reasonably borne by the industry, when judged by any of the cos t metrics EPA employs: total costs; impact on retirements and generation; cost

- to

revenue ratio; and cost

- effectiveness.

432 Waterkeeper Alliance v. EPA, 399 F.3d 486, 516 (2d Cir. 2005); Chem. Mfrs. Ass’n v. EPA , 870 F.2d 177, 262 (5th Cir. 1989).

433 TDD at 9

- 40.

434 Id.

435 78 Fed. Reg. at 34,447.

436 At the unit level, EPA estimates that these 240 plants consist of 634 units that would incur compliance costs, Incremental Costs and Pollutant Removals at 8

- 2, out of 2195

- 2230 units in the industry, 78 Fed. Reg. at 34,448. As a result, 28% of all units would face compliance costs. 72% of units in the industry would have no costs to comply with a zero discharge standard for bottom ash transport water. Comment Response: EPA agrees that the costs of the final rule, including the costs associated with a zero discharge BAT limitation for steam electric generating units that are greater than 50 MW and that are not oil

- fired, are affordable and can be reasonably borne by the industry (see preamble sections VI II and IX). See the response to DCN EPA

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2. The actual costs of a zero discharge standard are far lower than EPA calculated.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 612 A zero discharge standard for bottom ash transport water for all units greater than 50 MW is economically achievable

– even if one uses EPA's cost numbers. But EPA has inflated the cost of botto m ash retrofits. As explained in detail in the accompanying expert report by Dr. Phyllis Fox, 445 EPA overestimated the cost of converting to zero discharge of bottom ash transport water in several ways. Specifically, EPA: (1) did not account for economie s of scale in designing and installing retrofits; (2) included units that are likely to convert to dry bottom ash handling for reasons other than compliance with this rule; (3) overestimated operating and maintenance costs; and (4) used a shorter equipment lifetime and higher interest rate, leading to a higher annualization factor. If some or all of these items were addressed, the total cost to industry and the per

- unit costs of a zero discharge standard would decrease dramatically. EPA appears to have calculated costs at the unit level, and then summed those costs to arrive at the total cost for the industry. 446 This methodology overestimates compliance costs because there are economies of scale when retrofitting multiple units at the same plant or mult iple units at different plants owned by the same company. 447 There are several reasons why retrofitting multiple units at the same plant would cost less than retrofitting each unit individually. A bottom ash handling system can be designed to take advant age of bottom ash being an intermittent waste stream; a transport system can service multiple units that have offset the timing of the ash dump at each boiler. 448 Silos used to temporarily house the ash can serve multiple units. In addition, there are ca pital and labor savings, including multiple

- unit discounts, when retrofitting multiple units together, rather than individually. 449 EPA acknowledges that summing the per

- unit costs overestimates compliance costs, 450 and information in the record corroborat es EPA's statement. Site visits show that two 750 MW units at a single plant converted to dry bottom ash handling for $25 million in capital costs, whereas EPA's cost methodology would suggest the costs should have been $35 million, or nearly 40% more tha n the actual costs. 451 Moreover, vendors stated that there are economies of scale to retrofitting multiple units at a single plant. 452 United Conveyor Corp. stated that “there [are] savings associated with remote MDS conversions at plants where there are multiple units.” 453 UCC estimated that a remote mechanical drag system servicing three or four units at a plant would have costs 30 to 50 percent lower than the per

- unit cost to retrofit each unit individually. 454 In short, there is ample evidence in the record that EPA's methodology overestimated costs by ignoring economies of scale. Second, the total industry cost includes costs at several units that are likely to shut down or convert to zero discharge systems even in the absence of this rule. Companie s have announced the retirement of 88 units that are included in EPA's calculation of the units that will incur compliance costs. 455 Moreover, over several years, zero discharge systems save money compared to systems that rely on wet sluicing of bottom as h. Vendors report a trend toward converting wet sluicing systems to zero discharge systems, and this trend is likely to continue because of economic and environmental considerations independent of this rule. 456 Removing units that already intend to retir e or convert to zero discharge systems from the list of units that would incur compliance costs would significantly lower the total industry cost of a zero discharge standard.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 613 EPA's estimates of the per

- unit operating and maintenance costs are higher than the actual costs incurred by plants. In fact, EPA's calculations have it backwards; zero discharge systems ultimately reduce O&M costs, rather than increase them. 457 Zero discharge systems reduce operating and maintenance costs because of several factors , including: lower auxiliary power usage; improve reliability which reduces the frequency of outages; reduced ash disposal costs; and no or lower water usage, which reduces associated costs. 458 For example, when Seminole Electric Cooperative converted two units to zero discharge systems, the company reported saving approximately $3 million per year in operating and maintenance costs. 459

445 See Appendix E.

446 Incremental Costs and Pollutant Removals at 8

- 4; Fox Report, Appendix E, at 29

- 30.

447 Id. at 29

- 32.

448 Id. at 30.

449 Id. at 30.

450 Incremental Costs and Pollutant Removals at 8

- 20 to 8

- 21 “(Note that this may overestimate compliance costs for the proposed rule because multiple units at a plant could use the same remote MDS which would result i n lower overall costs.).”

451 Fox Report, Appendix E, at 31.

452 Fox Report, Appendix E, at 32

- 33.

453 EPA, Non

- CBI Ash Handling Conversion Data and Bottom Ash Conversion Costs at 1, Attachment DCN SE01825A80 to Docket No. EPA

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- 2888. Additi onally, UCC stated that “any successful cost model would need to take into account the appropriate economies of scale. For example, power plants converting multiple generating units to dry fly ash handling systems would not necessarily need more silos than that for one generating unit. UCC noted that a plant will likely have two ash storage silos if it is operating four generating units. UCC stated that similarly, power plants installing dewatering bins for multiple generating units could install one large dewatering bin rather than multiple ones. As an example, UCC mentioned that the Kingston plant installed a dewatering bin system for its nine generating units because it was more cost

- effective than installing individual dry bottom ash handling systems on each of the nine generating units.” EPA, Notes from USEPA

- UCC Conference Call with United Conveyor Corporation at 6 (Jan. 6, 2010), Docket No. EPA

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454 Id. at 27.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 614 455 See List of Announced Retirements Included in EPA’s Cost Calculations, submitted by Commenters as an exhibit to this letter.

456 Fox Report, Appendix E, at 36.

457 Fox Report, Appendix E at 33

- 35.

458 Id.

459 Fox Report, Appendix E, at 39. Comment Response: EPA agrees with the commenter that there is evidence to suggest cost savings associated with economies of scale, decreased requirements for operating and maintenance, and potential marketing of dry bottom ash. Based on the technologies selected as the basis for BAT, EPA did not quantify these savings as part of the compliance cost estimates. EPA selected the mechanical and remote mechanical drag systems based on information from the Steam Electric Survey on recent trends in the industry and vendors. EPA encourages the use of completely dry bottom ash handling system and recognizes that steam electric power plants may want to consider these handling options to benefit from cost savings associated with the operating of completely dry systems. To the extent that some plants may choose lower

- cost methods for meeti ng the final limitations and standards, including by installing and operating completely dry systems, EPA’s compliance costs may be overestimated. However, EPA notes that the Clean Water Act does not require EPA to make a precise calculation of costs. Se e, e.g., CMA v. EPA , 870 F.2d 177, 237

- 38 (5th Cir. 1989) (“The Act requires the EPA to ‘take into account’ the costs of BAT; it does not require a precise calculation. The EPA ‘need make only a reasonable cost estimate in setting BAT’; it is sufficient if the EPA develops ‘a rough idea of the costs the industry would incur’” (citation omitted).); Kennecott Copper v. EPA, 612 F.2d 1232, 1238 (10th Cir. 1979) (EPA has “wide leeway in its analysis of costs”); BASF Wyandotte Corp. v. Costle , 598 F.2d 637, 662 (1st Cir. 1979) (upholds using averages in estimating costs); BP Exploration & Oil Inc. v. EPA , 66 F.3d 784, 799

- 800 (6th Cir. 1995) (“The CWA does not require a precise calculation of BAT and NSPS costs” (citation omitted).); NRDC v. EPA , 863 F.2d 1420, 1 426 (9th Cir. 1988) (“[T]he Act does not require a precise calculation of BAT costs.”); W eyerhaeuser v. Costle , 590 F.2d 1011, 1045 (D.C. Cir. 1978) (“[Congress] left EPA with discretion to decide how to account for the consideration factors, and how much weight to give each factor.”). See the response to DCN EPA

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- 615 applicable. For example, the mechanical drag system does not require the operation of the existing wet sluicing equipment, so EPA subtracted the estimated operation and maintenance costs associated with operating wet sluicing equipment from the operation and maintenance costs associated with operating the mechanical drag system. The remote mechanical drag system uses the existing wet sluicing system; therefore, EPA did not subtract operation and maintenance costs associated with the wet sluicing system fr om the remote mechanical drag system compliance cost estimates. EPA did not specifically evaluate the difference between ash disposal costs for completely dry bottom ash and dewatered bottom ash. However, EPA notes that completely dry bottom ash would requ ire moisture conditioning prior to landfilling for dust control adding to the total weight requiring disposal. See the response to DCN EPA

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- year useful life.

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3. Zero discharge systems that use no water are cheaper than the mechanical drag and remote mechanical drag systems EPA used for calculating costs. While EPA acknowledges that many systems for handling bottom as h eliminate the discharge of transport water, EPA based its cost estimates on only the mechanical drag and remote mechanical drag systems. 466 Both of these systems use water, but recycle rather than discharge the water. Other zero discharge systems use n o water at all. These other systems are more cost

effective over the long run, as explained in detail in the accompanying expert report by Dr. Phyllis Fox. 467 As a result, the true cost of converting to a zero discharge system is lower than EPA estimate d in the proposed rule. EPA should revise its cost estimates to reflect the lower costs of bottom ash handling systems that do not use water, such as dry vacuum and dry pressure systems. Dry vacuum and dry pressure systems are economically achievable. Wh ile dry vacuum and pressure systems may have higher upfront capital costs than remote mechanical drag systems, 468 they have lower operating and maintenance costs. On a lifecycle basis, dry vacuum and dry pressure systems cost less than the mechanical and remote mechanical drag systems EPA costed. 469Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 616 The cost savings come in part from recovering some of the heat energy from the ash. In mechanical and remote mechanical drag systems, the hot bottom ash is cooled by water, such that the heat energy in the bo ttom ash is wasted

– it is used to evaporate the water, which then exits the system. The unburned carbon in the ash is not used to generate energy, but instead becomes solid waste. 470 However, in a dry vacuum or dry pressure system, the air used to cool the ash burns additional carbon, releasing additional thermal energy, which is returned to the boiler. 471 That, in turn, reduces the amount of fuel needed and the associated fuel costs. Vendors informed EPA that this improved efficiency results in lower c osts for dry vacuum and dry pressure systems compared to mechanical drag systems. For example, United Conveyor Corp. stated that “this added efficiency makes completely dry technologies generally more cost

- effective than SFC systems [mechanical drag syste ms that use water] in the long

- term, although the payback period may be several years.” 472

466 Incremental Costs and Pollutant Removals at 8

- 1.

467 Fox Report, Appendix E, at 21

- 28.

468 However, dry vacuum and pressure systems may have lower capital costs than mechanical drag systems. EPA calculated that Clyde Bergemann’s DRYCON system, which uses no water, has lower installed capital costs than its SSC (mechanical drag) system. Indeed, the DRYCON system is between $1 million and $2 million cheaper to install than the SSC mechanical drag system, depending on the size of the unit. EPA, Non CBI Bottom Ash MDS Capital Costs, at Tab “MDS Capital Cost,” DCN SE01825A74, attachment to EPA

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469 Fox Report, Appendix E, at 22, 24.

470 Fox Report, Appendix E, at 26.

471 Fox Report, Appendix E, at 9, 26.

472 EPA, Notes from USEPA

- UCC Conference Call with United Conveyor Corporation at 6

- 7 (Jan. 6, 2010), Docket No. EPA

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- A1, Excerpt Number 107 for more information on the savings associated with dry bottom ash handling technologies. EPA agrees that dry bottom ash handling systems may have lower operation and maintenance costs, could result in coal consumpt ion savings, and CO2 emission reduction. EPA notes that the water associated with the mechanical drag system is not considered bottom ash transport water because the drag chain is the mechanism that moves the bottom ash, not water. Therefore, the overflow is not considered bottom ash transport water.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 617 Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 116 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The 400 MW threshold is arbitrary for the additional reason that it is based on cost estimates that are greatly exaggerated. As explained above, EPA overestimated the cost of converting units to ze ro discharge systems for handling bottom ash. In calculating the costs of units converting to zero discharge systems for bottom ash handling, EPA failed to account for economies of scale; included costs for units that will retire or convert in the absence of the rule; overestimated operating and maintenance costs; and used an artificially high annualization factor. Given that the costs of meeting a zero discharge standard are substantially lower than EPA has estimated, the impacts to smaller units will al so be far less than EPA has estimated. EPA assumes that there are 125 units equal to or less than 400 MW that would cost $1.9 billion in capital and $239 million per year to convert to zero discharge systems

– this is an average of $23 million in capital co sts and $2.1 million in operating and maintenance costs per year, which is inconsistent with real world experience. 500 Those figures are closer to the costs for retrofitting a plant with two units just under the 400 MW threshold. For example, when the Wa teree plant retrofit two 372 megawatt units, each unit was converted to a zero discharge bottom ash system for $11.25 million in capital costs and between $800,00 and $1.5 million per year in operating costs, well below EPA's estimates. 501 Several other u nits equal to or smaller than 400 MW have converted to zero discharge systems, suggesting that the cost of meeting a zero discharge standard can be borne by plants equal to or less than 400 MW. South Carolina Electric & Gas Company retrofit two 125 MW uni ts in 2008; the BL England station retrofit a 125 MW, 155 MW, and 170 MW units in 2010; 2012, the Coronado generating station retrofit two 400 MW units in 2012. 502

500 Fox Report, Appendix E, at 16.

501 EPA, Final Draft of Wateree Site Visit Notes at 5, 8, Docket No. EPA

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502 Fox Report, Appendix E, at 19

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- 618 Comment Response: See the response to DCN EPA

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- MW threshold for bo ttom ash transport water.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 157 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dr. Fox explained that EPA overestimated the cost of converting to zero discharge systems for handling bottom ash in five ways. Specifically, EPA (1) ignored economies of scale when installing controls at multiple unit s at the same plant or multiple plants in the same fleet; (2) calculated compliance costs for units that are likely to convert to zero discharge systems for handling bottom ash or to retire for reasons unrelated to this rule; (3) overestimated operating an d maintenance costs; (4) omitted increased sales of bottom ash from zero discharge systems; and (5) used an inappropriately high annualization factor and an inappropriately short assumed equipment lifetime. 692

692 Id. at 22

- 39. Moreover, while EPA’s cos t analyses focused on pre

- tax compliance costs, EPA acknowledges elsewhere that after

- tax costs are a more accurate measure of the economic impact of the rule. As a result, EPA’s focus on pre

- tax compliance costs overestimates the economic impacts of the r ule. This bias affects the cost analyses for all waste streams for all proposed options. Comment Response: See the response to DCN EPA

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- 619 for BAT, costs associated with economies of scale, and “units that are likely to convert to dry bottom ash handling for reasons other than compliance with this rule.” Additionally, see the response to DCN EPA

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- site or off

- site landfills. Plant

- specific marketing information was not available to accurately estimate savings as sociated with the potential marketing of the stacked bottom ash from the mechanical or remote mechanical drag systems. EPA notes that, under the Clean Water Act, EPA’s cost estimates of BAT do not have to be precise. See, e.g., CMA v. EPA , 870 F.2d 177, 23 7

- 38 (5th Cir. 1989) (“The Act requires the EPA to ‘take into account’ the costs of BAT; it does not require a precise calculation. The EPA ‘need make only a reasonable cost estimate in setting BAT’; it is sufficient if the EPA develops ‘a rough idea of th e costs the industry would incur’” (citation omitted).); Kennecott Copper v. EPA, 612 F.2d 1232, 1238 (10th Cir. 1979) (EPA has “wide leeway in its analysis of costs”); BASF Wyandotte Corp. v. Costle , 598 F.2d 637, 662 (1st Cir. 1979) (upholds using averag es in estimating costs); BP Exploration & Oil Inc. v. EPA , 66 F.3d 784, 799

- 800 (6th Cir. 1995) (“The CWA does not require a precise calculation of BAT and NSPS costs” (citation omitted).); NRDC v. EPA , 863 F.2d 1420, 1426 (9th Cir. 1988) (“[T]he Act does not require a precise calculation of BAT costs.”); W eyerhaeuser v. Costle , 590 F.2d 1011, 1045 (D.C. Cir. 1978) (“[Congress] left EPA with discretion to decide how to account for the consideration factors, and how much weight to give each factor.”).

Comm enter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 11 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The water used to transport the bottom ash is called "transport water" in this rulemaking. Options 4a, 4 and 5 propose to eliminate this "transport water" by using a dry or closed

- loop bottom ash handling system. TDD, Sec. 4.3.2 and 78 Fed. Reg. at 34,4 49, 34453. The EPA considered chemical precipitation for the treatment of transport water, but eliminated it based on capital and O&M costs compared to dry handling or close

- loop recycle technologies. TDD, p. 7

- 29. However, as discussed below, while the E PA recognizes "dry" handling as feasible, it did not evaluate "dry" handling in its costs and other analyses.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 620 Comment Response: See the response to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 15 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA Failed To Evaluate the Costs of Dry Bottom Ash Handling Systems The EPA only quantitatively evaluated the costs and benefits of two technologies to eliminate bottom a sh transport water: (1) a mechanical drag system and (2) a remote mechanical drag system. Both of these options handle the bottom ash "wet". Neither is a true "dry" bottom ash system, which, based on my review, are the most efficient, lowest cost, and mos t environmentally beneficial options. The true dry systems include: MAC TM ; DRYCON TM ; VAX TM ; and PAX TM

. 44 The EPA's selection of a 400 MW threshold in preferred Option 4a and its failure to include zero discharge of bottom ash transport water in preferred O ptions 3a, 3b, and 3 were due solely to analyses based on its cost analysis of wet zero discharge systems, even though it conceded the requirements of the proposed BAT limits could be met with a dry system. The 400 MW threshold is discussed in Section V. While it may not be feasible to convert 100% of the subject units to dry systems (as it is likely not feasible to convert 100% of subject units to MDS or remote MDS), the EPA should have evaluated dry options to bound the range of costs and impacts, or sho uld have assumed that a portion of the fleet would convert to dry, perhaps based on the fraction of recent retrofits in the U.S. (64%) or the fraction of retrofits in Europe that are dry, weighted by unit size.

44 See Shah et al., supra note 5.
Comment Res ponse: See the response to DCN EPA

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- 621 Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 18 External Review Flag: No Ex ternal Review External Review Incorporated into Response: No Comment Excerpt: Dry Systems Are More Cost Effective The zero discharge wet systems that EPA evaluated rely on existing equipment, which may be at the end of its useful life and, thus, result i n higher O&M costs than a system that replaces all of the key components, such as a dry system. The EPA should have evaluated and costed a wider range of options that included at least one true "dry" technology. As I will explain below, the literature on c onversion from wet to zero discharge bottom ash handling systems indicates dry bottom ash handling systems pay for themselves in a very short period, as they significantly reduce the O&M costs of bottom ash handling, offsetting the capital investment. In a ddition, they generate an ash stream that is much more marketable than a wet bottom ash stream. Further, while some wet recycle systems may have the lowest initial capital cost, as they can reuse existing equipment, they rarely have the lowest life

- cycle c osts, O&M costs, or environmental impacts. Moreover, the repurposed existing equipment is often near the end of its useful life and, thus, has high O&M costs and a shorter lifetime, requiring replacement costs. The EPA estimated installed capital costs of two wet zero discharge systems: (1) SSC and (2) ASHCON using data provided by their vendors. However, the vendors' own analyses of conversion costs, summarized in Figure 2 and Table 3, indicate that dry systems such as DRYCON and MAC are the lowest cost o ptions

– not nothe wet zero discharge systems that EPA used as the cost basis for BAT.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 622 Costs provided by Clyde Bergemann, and relied upon by EPA to estimate installed capital costs for the MDS and remote MDS systems, indicate that installed capital cost of a fully dry system (DRYCONTM) is slightly lower than the wet MDS systems that EPA costed, 47 while the O&M costs of DRYCON are substantially lower than for the wet option. Table 3 shows that the life cycle O&M costs of a conventional wet ash handling sys tem can be more than three times greater than for a dry system. Recent installations of DRYCON around the world have confirmed these estimates and have been successful. 48

46 Fleming and Mooney 2011, Figure 17.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 623 47 UCC installed cost for the DRYCONTM and SCC systems differ by only $1 million to $2 million for units from <150 MW to 900 MW, with the higher costs for SCC, the wet recycle option selected by EPA. Excel Spreadsheet: “Bottom Ash Clyde Bergemann Costs of MD S: Non CBI Bottom Ash MDS Capital Costs,” Docket No. EPA

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48 See, e.g., “Case Study, Efficient Dry Bottom Ash Handling with DRYCONTM at Heyuan Power Plant, China,” (19 total units ranging from 120 MW to 800 MW with 5 t/hr to 90 t/h of bottom ash); Available at: http://www.cbpg.com/_upload/Heyuan __DRYCON_case_study_rev3.pdf; “Dry Bottom Ash Handling System Cuts Plant Carbon Emissions,” Power Engineer, May 2011 (800 MW coal

fired unit in Germany installs DRYCON due to lower life

- cycle costs); Available at: http://www.engineerlive.com/content/22605

49 See Bergemann, Materials Handling, supra note 12.
C omment Response: See the response to DCN EPA

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- A1 Comment Excerpt Number: 22 External Review Flag: No External Review External Re view Incorporated into Response: No Comment Excerpt: To establish the cost range for BAT, EPA should have included an option(s) that does not have boiler access issues. True dry systems have fewer space constraints than MDS or remote MDS. The vast majori ty of plants, for example, have the vertical space required to retrofit a boiler with a "dry" ash handling system, such as DRYCON. 52

52 “ERG Telephone Call Record of Conference Call on January 28, 2010 between Elizabeth Sabol and Sarah Holman and Craig Fle ming, Delta Ducon,” Docket No. EPA

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- 624 Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 16 in Comment Code 16 for EPA’ s response to completely dry bottom ash handling system retrofits and the selection of the BAT basis.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 24 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Wet Systems Produce Harder

- to

- Manage and Less Valuable Wet Ash As EPA is aware, bottom ash can either be landfilled or beneficially reused. In both circumstances, wet ash has two disadvantages compared to dry ash. First, the cost of transporting and landfilling wet ash, which contains 20% to 30% water, is high due to the added weight of the water. Eliminating 20% water content, for example, would reduce disposal costs by about 20%. 56 Thus, by costing only wet ash handling systems, EPA has significantly overestimated ash disposal costs compared to a true dry system. This overestimation of cost was compounded by EPA’s assumption, contrary to experi ence, that 100% of the ash would be landfilled. CAR, Sec. 5.3. Second, as discussed elsewhere in this Report (Sec. IV.D), the sales potential of dry bottom ash is much higher than that of wet ash with 20% to 30% water, as it has many uses and requires litt le preparation. The use of wet systems eliminates or reduces an important revenue stream from ash sales for coal

- burning power plant operators.

56 “Email from Gary Mooney, Delta Ducon, to Elizabeth Sabol,” June 27, 2011, EPA

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- Followup, In: Bottom Ash Handling Costs’ at pdf 3. This email notes that for 6 ton/hr of ash, about 6 gpm of water is carried out with the ash and with evaporation, the typical overflow average is 35 to 50 gpm. Comment Response:
See th e response to DCN EPA

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- 625 Additionally, see the response to DCN EPA

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- A1, Excerpt Number 107 regarding additional information on dry bottom ash handling systems and operation and mai ntenance costs. See the response to DCN EPA

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- A1, Excerpt Number 157 regarding the sale of bottom ash.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comm ent Excerpt Number: 25 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry Systems Have Lower O&M Costs Dry systems would have lower O&M costs compared to the wet mechanical drag systems evaluated by EPA. First, a dry system would have no water

- based erosion and corrosion problems, which would significantly reduce O&M costs. Second, the chain conveyors used in mechanical drag systems depend on the reliability of rings in a single chain, which decli nes as the chain length increases. Typically, chain conveyors must be replaced every four years, with yearly replacements of short sections. The conveyance systems used in dry systems avoid chain conveyors, significantly reducing O&M costs. The DRYCON sys tem, offered by Clyde Bergemann, conveys the ash on top of pans that move on externally mounted rollers, reducing the footprint of the conveyor and reducing O&M costs. 57 The friction losses of the DRYCON tray system are significantly reduced, reducing ene rgy consumption and wear compared to SSC. 58 Further, "[t]he conveyor pans can be removed and replaced separately as necessary, rather than replacing the entire chain." 59 The MAC system, offered by Magaldi, uses a steel mesh belt conveyor coupled with o verlapping steel plates to convey ash. The Magaldi system (Superbelt) has demonstrated 10 years of continuous running without boiler outages for belt maintenance. 60 Compliance Costs Are Overestimated The EPA estimated the cost to convert from wet sluicing to (1) a mechanical drag system (MDS) and (2) a remote mechanical drag system (RMDS) for 253 plants (CAR, Sec. 8), comprising 634 units. CAR, p. 8

- 2. As discussed above, both of these systems handle wet ash and generate a low volume wastewater stream that is removed when the ash is dewatered. Thus, neither is a true dry bottom ash system. Dry systems are more cost

- effective as explained elsewhere. This section focuses on assumptions that EPA used when estimating costs for these wet systems that overestima te their costs.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 626 First, EPA ignored economies of scale, by using unit costs rather than assessing costs at the plant as a whole. Second, EPA overestimated the number of units that are subject to the rulemaking by including those that are likely to retrofit with zero discharge or dry ash handling for economic reasons notwithstanding this rulemaking. Third, EPA overestimated O&M costs. Fourth, EPA did not consider bottom ash sales. Finally, EPA overestimated annual costs by using a short lifetime and high int erest rate. The costs for these two options were generated from a series of computerized cost models developed from data collected from survey responses, site visits, sampling episodes, individual power plants, and equipment vendors. TDD, Sec. 9.4; CAR, Se c. 8. Most all of this data has been claimed to be confidential, including all of the appendices of the Cost Analysis Report and supporting Excel spreadsheets that contain the actual calculations, 61 precluding comprehensive review of estimated costs. The r ecord contains only general discussions of how costs were estimated. TDD, Chapter 9; CAR, Chapters 5 & 8. This Report is, thus, likewise general as they address only the available summaries without access to underlying data and calculations.
The EPA esti mated the costs and benefits for plants operating wet sluicing systems to convert to systems that eliminate the discharge of bottom ash transport water. The costs for these two options are incremental. They account for only additional costs beyond those th e plant already incurs (TDD, p. 9

- 6) and reductions in costs that would no longer be needed. TDD, p. 9

- 7. These calculations indicate that conversion to zero discharge of bottom ash transfer water under Options 4 and 5 (for units >50 MW) would require re trofits at 240 plants for a total capital cost of $4.5 billion and annual O&M costs of $494 million per year. TDD, Table 9

- 6. If the conversion threshold is increased to units greater than 400 MW, 115 plants would require retrofits at a total capital cost of $2.6 billion and annual O&M costs of $255 million per year. TDD, Table 9

- 7. EPA’s cost estimates for converting to dry ash handling are too high, for the reasons set out below.

57 Angela Neville, “The Better Environmental Option: Dry Ash Conversion Te chnology,” Power, July 2011.

58 Bullock 2010, supra note 54.

59 “Notes from Site Visit at Seminole Electric Cooperative on January 23, 2013,” Docket No. EPA

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60 Cianci 2007, supra note 54, p. 53.

61 See also in the docket, e.g., “CBI Bottom Ash Wet Sluicing O&M Costs,” “Non CBI Bottom Ash Remote MDS Capital Costs,” and “CBI Bottom Ash MDS Conveyance O&M Costs,” EPA

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- 2888 ("All data has been removed from this file as a result of CBI sanitization. All data used to d etermine the cost factors for the bottom ash MDS wet sluicing O&M costs is considered CBI or CBI deducible.").Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 627 Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 107 regarding additional information on dry bottom ash handling systems and operation and maintenance costs. EPA disagrees with the commenter that “the record contains only general discussions of how costs were estimated.” The TDD provides specific information about EPA’s costing approach and estimates, and the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Po int Source Category (Cost & Loads Report) (DCN SE05831/SE05832) contains specific documentation of the calculations used by EPA and the cost model inputs used to estimate bottom ash compliance costs.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 26 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Multiple Unit Synergies Should Have Been Consi dered The EPA estimated costs to convert existing wet sluicing systems to wet recycle systems on a per generating unit basis, rather than a plant basis. CAR, Sec. 8.1. For example, the Cost Analysis Report states: "EPA estimated unit

- level capital costs f or purchase and installation of equipment to convert a wet sluicing system to a MDS [mechanical drag system]. EPA then summed these unit

- level costs to calculate plant

- level conveyance and intermediate storage capital costs." CAR, p. 8

- 4. Elsewhere, "EP A calculated the plant

- level MDS conveyance capital cost by summing the unit

- level costs at each plant..." CAR, p. 8

- 5. There are similar references to calculating costs on a "unit

- level" throughout Sections 8.1 and 8.2 of the Cost Analysis Report.
Estim ating plant level costs by summing unit

- level costs significantly overestimates costs, as the costed options can service multiple units (TDD, pp. 7

- 35, 7

- 37) or use shared equipment, 62 which results in economies of scale, reducing costs. Several issues aff ect the cost when multiple units are involved. Further, vendors offer multi

- unit discounts, which were also ignored in EPA's cost analysis.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 628 First, bottom ash is generally produced intermittently, typically once or twice per 8

- hour shift. This means ash ha ndling equipment is only utilized part of the time when a bottom ash handling system is dedicated to a single unit. This downtime between dumps can be effectively used by designing the system to serve multiple boilers. Most plants have multiple units and, thus, most retrofits serve multiple units to assure full time equipment use. The EPA explicitly recognizes this in the Cost Analysis Report but makes no attempt to take it into consideration in its cost analyses, viz. , "EPA costed individual conveyor syste ms with a semi

- dry bottom ash storage silo for each generating unit. (Note that this may overestimate compliance costs for the proposed rule because multiple units at a plant could use the same remote MDS which would result in lower overall costs.)". CAR, pp. 8

- 20/21. Second, there are many economies involved in designing, procuring, and installing multiple similar units, as exist at many plants. Capital and labor costs are reduced by combining units, e.g., a dewatering station or truck loadout station. Co sting two separate units essentially doubles the balance of plant labor and increases capital costs. Common facilities should have been designed and costed. The per

- unit cost of a given piece of equipment drops as the capacity increases. This relationship, known as the "six

- tenth

- factor rule," results in lower capital costs for larger pieces of equipment. In fact, large utilities generally seek fleet

- wide solutions as they significantly lower their per

- unit cost. Vendors, for example, offer substantial disc ounts for multiple unit contracts. These well known economies were not factored into EPA's estimates as costs were developed on a unit

- by

- unit basis. We suggest that EPA obtain estimates from the vendors who assisted them in developing its costs for two cases: (1) multiple units at the same plant and (2) system

- wide retrofits for a large utility, such as AEP or Duke. The potential impact of this failure to consider multiple unit synergies on installed capital costs can be estimated from cost data supplied by Clyde Bergemann to EPA, summarized in Table 5. This table shows that the capital cost per MW for both options that EPA evaluated (ASHCON and SCC) drop significantly as the MW served increases. For example, the capital cost per MW for the mechanical dra g chain option (SCC) drops by a factor of two for a 900 MW unit compared to a 150 MW unit. Thus, for example, if a facility has nine 100

- MW units, EPA's approach would yield a unit cost for ASHCON of 9 x $26,667/MW x 100 MW = $24,000,300 while estimating the cost on a plant basis would yield 1 x $16,667/MW x 900 MW = $15,000,300 , or 60% more based on unit costs just for the equipment capital costs.
Table 5 : Cost Comparison of Clyde Bergemann Bottom Ash Handling Systems 63 ($/MW)

MW ASHCON DRYCON SCC <150 26,667 40,000 46,667 150 to 300 20,000 26,667 30,000 300 to 500 18,000 24,000 26,000 500 to 700 15,714 21,429 24,286 700 to 900 16,667 22,222 24,444Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 629 The unit

- by

- unit approach EPA used greatly overestimates costs. This can be illustrated by an example from information included in the docket. Notes from a site visit at Seminole Generating Station in Florida indicate it converted its wet bottom ash sluicing system on two 715

- MW units to completely "dry" DRYCONTM systems in April 2012. The combined tota l cost to convert both units at Seminole was approximately $25 million, including engineering, equipment, installation, removal, and other activities (plus significant system "overdesign to account for emergency situations"). 64 If the cost of this convers ion is estimated on a per

- unit basis using EPA's approach and Clyde Bergemann's cost data provided to EPA (Table 5) for DRYCON, it would yield a cost of $33 million, 65 which is 33% higher than the actual cost.
This data in EPA’s files demonstrates that it has significantly overestimated the cost of eliminating bottom ash transport water, by first, picking options that are more expensive, have higher O&M costs, and fewer environmental benefits, and second, by greatly overestimating the costs by calculating t hem on a per

- unit basis. Correspondence with vendors in the docket indicates that the EPA was advised that multiple units could be serviced by single systems. Clyde Bergemann noted with respect to ASHCON TM , the remote MDS system that EPA evaluated:
"Since multiple Boiler Units can send their slurry to one ASHCON TM , another "limit" is up to four to five Boiler Units per ASHCON TM since most Boiler Units convey bottom ash in one or two hour cycle. Most plants design around an 8 hour shift schedule so 4 to 5 Un its would sequence one at a time into one continuously operating ASHCON TM ." 66 United Conveyor Corp (UCC) gave EPA similar advice: 67 UCC stated that any successful cost model would need to take into account the appropriate economies of scale. For example, power plants converting multiple generating units to dry fly ash handling systems would not necessarily need more silos than that for one generating unit. UCC noted that a plant will likely have two ash storage silos if it is operating four generating unit s. UCC stated that similarly, power plants installing dewatering bins for multiple generating units could install one large dewatering bins rather than multiple ones. As an example, UCC mentioned that the Kingston plant installed a dewatering bin system fo r its nine generating units because it was more cost effective than installing individual dry bottom ash handling systems on each of the nine generating units. In summarizing conversations between EPA and UCC, ERG wrote: "UCC stated that there [sic] saving s associated with remote MDS conversions at plants where there are multiple units. At these plants, one remote MDS is designed to handle bottom ash from multiple generating units (referred to as multiple unit synergies)." 68 United Conveyor even provided estimates of multiple unit synergies for the remote SFC that EPA costed: "Multiple unit synergies examples, Remote SFCEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 630  single unit plant as a minimum should have (1) remote SFC. But it could be possible to design three or even four unit plant with two or three remove SFC potentially reducing system cost by 30% to 50% Multiple unit synergies examples, Combination Vacuum/Pressure System

 single unit plant as a minimum should have (1) Combination Vacuum/pressure System But it could be possible to design two unit plant with two vacuum system but only with one pressure system (common for both units) potentially reducing system cost by 15% to 25%." 69 Many of the subject units are in plants with multiple units. Considerable savings are achieved in capital costs, installation labor, O&M costs, and design engineering by designing, manufacturing, constructing, and operating all units at a plant as a whole rather than as a sum of parts. Many Units Would Voluntarily Convert The cost estimates were performed assuming al l units with wet bottom ash sluicing systems that had either not announced plans to convert voluntarily or plans to shutdown by December 31, 2014 would convert to zero discharge systems to comply with this rulemaking. This estimate was subsequently updated to include a few additional announcements. TDD, p. 9

- 44. Thus, EPA attributed 100% of the conversion cost of unannounced conversions to this rulemaking. However, it is likely that many currently unannounced units would voluntarily convert anyway, regard less of this rulemaking, due to economic benefits, pond capacity issues, or other regulatory issues, such as State NPDES requirements.
Zero

- discharge bottom ash systems are used in virtually all new plants and in many recent retrofits. There are many fact ors driving the conversion from wet to zero

- discharge bottom ash handling, not related to this rulemaking. First, dry systems have lower O&M costs than wet sluicing systems and improve the efficiency of the boiler, resulting in less coal burned and, thus , less air emissions and other environmental impacts. Second, ash ponds have capacity constraints and plants have land constraints. Third, water availability for ash transport is an issue in many areas, particularly the arid west. Fourth, there is a growin g demand for the reuse of ash, which generates a revenue stream for the plant. Fifth, many wet systems are at the end of their useful life and O&M costs to sustain them are very high. Sixth, spare parts for old wet sluicing systems are becoming increasingl y difficult and expensive to obtain. Since 2000, 12 to 15 plants (15 to 20 units) have converted to zero

- discharge bottom ash handling with a capacity of 6,500 to 7,500 MW. Of these, 60% installed mechanical drag systems, 20% installed dry vacuum systems, and the balance installed other types. TDD, pp. 4

- 26 & Table 4

- 10. Power companies have reported plans to convert an additional 67 units to dry or closed

- loop recycle bottom ash handling systems by the year 2020. TDD, p. 4

- 26. Elsewhere, EPA reports that o perators have announced retrofits of 10 to 30 generating units (a range is reported due to CBI issues). 78 Fed. Reg. at 34,453.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 631 The TDD suggests that "additional changes" were made to its list of voluntary conversions since December 31, 2014 (without identifying what they might be), reducing annualized compliance costs for Option 4 from $1,373.2 million to $1,252.9 million or by about 9%. However, EPA does not point to where these revised estimates might be found, identify which additional bottom ash c onversions, if any, are included in this revised estimate, and if any bottom ash conversions are included, how much of this reduction is due to them. TDD, p. 9

- 44. It appears EPA included units in its cost estimates that it knew or should have known 70 were planning to convert, independent of this rulemaking. The docket, for example, indicates that EPA was aware that some plants included in its cost analysis 71 were in the process of converting one or more bottom ash handling systems that are not identified i n its "Changes to Industry Profile" memo. These include Progress Energy's Mayo plant (converting to a PAX in 2013), South Carolina Electric & Gas's Wateree plant (converted to an SFC in October 2012 72 ), Duke Energy's Gibson (evaluating converting to dry), and AEP's Mitchell. 73 Regardless, the long operating history of wet sluicing systems (whether recycle or ponds) indicates that they are unreliable and expensive to operate, so voluntary conversions can be anticipated to address these problems. They have s ignificant operational problems, including high water use; high power consumption; need for manual operation (e.g., unplugging blockages); worker safety issues; forced boiler outages; rapid wear and corrosion, erosion, scaling, and plugging of equipment, r esulting in premature failure; high cost for and limited availability of replacement parts; energy loss from unburned carbon and radiation heat loss at boiler throat, resulting in high O&M costs; and poor market options for the ash, among other problems. 74 Further, many impoundments are at capacity and land to expand is not available, and wet disposal practices pose environmental liabilities. Operators of standard wet systems report numerous operational problems, including "huge water consumption, high ma intenance costs due to corrosion and clogging, environmental issues due to leakages of contaminated water and loss of boiler efficiency, and negative effects on boiler operation due to the low reliability and poor maintainability of wet systems." 75 Notes from an EPA site visit to a plant that converted its wet sluicing system to DRYCON in April 2012 reported that it "[chose] to retrofit their wet bottom ash sluicing system because it was labor intensive, energy intensive, and vendors were starting to phas e out required replacement parts." In addition, "[t]he plant ultimately decided to convert to the dry handling system because of the benefits resulting from an economic analysis completed in 2007, which included less maintenance and labor, safety benefit s, and energy savings." 76 Thus, existing wet bottom ash sluicing systems are a major source of operational problems and cost for the current coal

- fired fleet. Many voluntary conversions can be reasonably anticipated to cure these problems.
It is extrem ely rare for wet sluicing bottom ash systems to be installed today. EPA reports that 83% of coal

- fired units built in the last 20 years installed dry bottom ash handling systems. 78 Fed. Reg. at 34,470. Clean Water Act NSPS have required zero discharge o f fly ash transport water for new plants since 1982. See 40 C.F.R. Sec. 423.15(g). Retrofit and new installations are predominately dry or mechanical drag systems. 77 Voluntary conversions are accelerating due in part to reliability and high O&M costs and to increasingly stringent state and federal regulatory programs. Recent regulation of greenhouse gas emissions (GHGs), for example, requires bestEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 632 available control technology (BACT) to control GHGs. For coal

- fired power plants, this most commonly requires efficiency improvements to satisfy BACT. For a major modification at an existing plant, these might include, for example, conversion to dry bottom ash handling. Vendors of dry systems report: "The vast majority of existing wet bottom ash handling systems is [sic] already slated to eventually convert to dry systems." 78 Elsewhere, United Conveyor notes that "We expect that the vast majority of existing wet bottom ash handling systems will convert to dry systems in the coming years. In fact, several utility c ompanies have already begun exploring dry conversion options and are collaborating on the optimal solution for their specific plant needs." 79 Similarly, Clyde Bergemann in 2007 noted "increasing interest in dry systems, both new build and retrofit applic ations. Among the drivers are environmental issues, growing concerns about water scarcity and increasing awareness of the overall cost savings that dry systems can deliver." Neil Ford, sales director of Clyde Bergemann Materials Handling, noted in November 2006 that the company's UK office was receiving two to three enquiries per day about dry bottom ash handling. 80 Thus, before this rulemaking was under way, vendors were aware that a movement was underway in the industry to upgrade their wet sluicing sys tems due to high O&M costs and other issues. Further, recent high profile incidents involving ash pond failures such as Martins Creek and TVA Kingston have subjected coal

- fired power plants to heightened environmental and public scrutiny of ash handling pr actices. Many power companies seek to avoid the financial risk associated with the clean

- up of an ash pond failure by voluntarily converting. For example, AEP is likely installing a dry system at its Mitchell plant to avoid impoundment failures like the on e at TVA’s Kingston plant. 81 Further, a larger market is currently available for usable ash product for road bed and concrete additives, increasing the economic incentive to convert. 82 Additionally, the majority of wet handling systems are over 30 years old and, thus, at the end of their useful life. Clean Air Markets Data indicate that 86% of the fleet was constructed prior to 1980. Analyses by others summarized in Figure 3 indicate 86% of the existing 1,105 coal

- fired units are at least 30 years old, 69 % are at least 40 years old, and 23% at least 60 years old. Similar results are reported by EPA using EIA data. EPA reported 697 units (63%) with an age of 30 years or greater and 516 units (47%) with an age of 40 years or greater. 83 Equipment in coal

- fire d power stations, such as bottom ash handling systems, is typically designed for a 30

- year life. 84 Bottom ash handling systems, in particular, operate under severe conditions. Thus, many existing bottom ash handling systems are near the end or beyond th eir useful lives, either due to equipment failure, or at

- capacity ponds or both. Upgrades may be triggered, for example, by the need for larger ponds in areas without available land, especially in urban areas, resulting in greater distances to transport a sh waste; or water shortage issues, such as in the western U.S.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 633 As explained by Ron Grabowski, Vice President of Sales at Clyde Bergemann Delta Ducon: "Because a large percentage of wet bottom ash systems are near the end of their projected life span, pl ants are faced with the decision of rebuilding or replacing them. A dry bottom ash system may be the best economical solution to this system." 86 Thus, the majority of plants with 30

- year
old wet bottom ash handling systems are likely considering replacing them with dry systems due to significant savings in operational and maintenance costs. These replacements would occur without the proposed rulemaking. In sum, without this rulemaking, it is likely that many of the plants that are assumed by EPA to incur c ompliance costs to convert would convert anyway, though perhaps on a slower time table. The actual cost of this rulemaking should be based on the number of units that would be forced to prematurely convert. This would likely be units that are 20 to 30 yea rs old or about 15% of the fleet. In further support of voluntary conversions, I note that EPA decided not to include impoundment closure costs in compliance cost estimates for impoundments as they are expected to close anyway. "EPA determined that it was not necessary to include impoundment closure costs as part of the proposed ELG compliance costs because plants will dewater and close these impoundments eventually, even in the absence of the proposed rule." 87 The same reasoning applies to the conversion of wet bottom ash sluicing systems. The writing is on the wall. The plants will either retire as they have reached the end of their useful life, or they will upgrade their bottom ash sluicing systems to reduce O&M costs. Thus, EPA's cost estimate should be based on a smaller number of units, those that would be forced to comply with BAT.

62 “Ash Handling Conversion Data and Fly Ash Cost Data,” Docket No. EPA

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- 15; “Bottom Ash Handling: Why the Outlook is Dry,” Modern Power Systems, March 1, 2007; Available at:Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 634 http://www.modernpowersystems.com/features/featurebottom

- ash

- handling

- why

- the

- outlook

- is

dry.

63 Calculated from data in tab: "MDS Capital Cost" in Excel spreadsheet: “Non CBI Bottom Ash MDS Capital Costs Docket,” No. EPA

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- 2888, ‘Bottom Ash Clyde Bergemann Costs of MDS.’ See also: Capital cost equations 8

- 2 and 8

- 39 in Docket No. EPA

HQ

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- 2888, attachment 7 (the Cost Analysis Report is based on this data).

64 See Seminole Site Visit Notes, supra note 59, pp. 1, 3, 6 (overdesign).

65 I developed a cost equation from Clyde Bergemann's capital cost data provided to EPA for DRYC ON TM using the same method EPA used to develop its capital cost equations for SCC and remote SCC. This yielded the cost equation (y=18,481 x MW +3,000,000), which is the DRYCON TM equivalent of CAP Eqn. 8

- 2 (which is for SCC). Thus, capital cost for one 715 MW unit using revised CAP Eqn. 8

- 2 for DRYCON: 18,481*715+3,000,000 = $16,213,915. The unit engineering costs for one 715 unit using CAP Eqn 8

- 5 = ($16,213,915)*0.01765) = $286,176. The total plant cost, using EPA's method, is: 2 x ($16,213,915 + $286,176 ) = $33,000,181

.
66 See Email from Gary Mooney, supra note 56, Attachment 7, Re: ‘Bottom Ash Handling

- Followup.’ See also: Craig H. Fleming and Gary D. Mooney, Clyde Bergemann, “Bottom Ash Conversion Options and Economics,” pdf 7 ("For multiple unit conv ersions, ASHCON TM may exhibit some Capital cost benefits if multiple units can be discharged to single ASHCON TM system."), pdf 10 ("The ability to retrofit to multiple existing Units and remove the ash pond disposal without interfering with the boiler isla nds. Multiple Units can use one ASHCON TM ."); Available at: http://www.gerrardassociates.com/images/CBDD_Bottom_Ash_Conversion_Paper_

- _Post_Electric_Power_Version.pdf

67 See ERG Memorandum from Kurt Blohm and Sarah Holman, supra note 36, Attachment 1, p.6, Re: ‘Notes from EPA Conference Call with United Conveyor Corporation.’

68 See ERG Telephone Call Record, supra note 51, Re: ‘Conversion from Wet to Dry Ash Handling Systems

- Fly Ash and Bottom Ash,’ pp. 1

- 2. See also: UCC website at http://unitedconveyor.com/cdr/ ("The CDR system installation requires no modification to existing ash handling equipment beneath the boiler and can accept slurry discharge from one or more operating units.").

69 “Email from Michael Kipnis, United Conveyor, to Jezebele Alicea, EPA”, EPA

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- EPA Call with UCC, May 10, 2011,’ Attached File und er "Additional Topics", Item #4, pdf 27.

70 As all of the calculations are claimed as CBI, I cannot confirm which units were actually included and must rely on what is reported in non

- CBI material.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 635 71 Not identified as excluded in: “ERG Memorandum from T. J. Finseth and Danielle Lewis,” Docket EPA

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- 2149, January 28, 2013, Re: ‘Changes to Industry Profile for Steam Electric Generating Units for the Steam Electric Effluent Guidelines Proposed Rule.’

72 “Final Notes from Site Visit at South Car olina Electric & Gas Company's Wateree Station on January 24, 2013,” Docket No. EPA

- HQ

- OW

- 2009

- 0819

- 1917; “Catawab/Wateree Coal Ash Removal in South Carolina Ahead of Schedule;” Available at: http://www.southernenvironment.org/newsroom/press_releases/catawba_wateree_coal_ash_rem oval_in_so uth_carolina_ahead_of_schedule/

73 “ERG Telephone Call Record, EPA and ERG with UCC,” EPA

- HQ

- OW

- 2009

- 0819

- 05 80, May 24, 2012, Re: ‘Ash Handling Conversions in the Industry.’

74 See, e.g., Neville 2011, Fig. 3; Cianci 2007, p. 49; Vincenzo Quattrucci and others, “Dry Bottom Ash Technology Improves Coal Fired Boiler Operations,” Docket No. EPA

- HQ

- OW

2009

- 0819

- 0419 , pp. 2, 5; Qian Yu, “Air Cooling Dry Bottom Ash Handling System for Coal Fired Power Station,” The International Conference on Electrical Engineering, 2009; Available at: http://www.icee

- con.org/papers/2009/pdf/4.04_I9CP0180_E.Pdf

75 Vincenzo Cianci, “We t vs Dry Bottom Ash Handling Compared: One Plant's Experience, Modern Power Systems,” June 2007; Available at: http://www.modernpowersystems.com/features/featurewet

- vs
- dry

- bottom

- ash

- handling

compared

- one
- plant

- s
- experience

76 See Seminole Site Visit Notes, supra note 59, p. 3.

77 “ERG Telephone Call Record, T. J. Finseth, ERG, to Mark Aron, Black & Veatch, December 19, 2011,” Docket No. EPA

- HQ

- OW

- 2009

- 0819

- 1997, Re: ‘Bottom Ash Installation Costs and Bottom Ash Wet Sluicing Installation.’

78 United Conveyor Corp., “Environmental Challenges Accelerate Industry Shift from Wet

- to

Dry Bottom Ash Solutions,” Energy

- Tech, March 2011, p. 2; Available at: http://www.energy

tech.com/article.cfm?id=30944&PageNum=2

79 Dan Charhut, “EPA Regulations Acce lerate Industry Shift from Wet to Dry Bottom Ash Solutions,” Coal Power, December 2010; Available at: http://www.coalpowermag.com/plant_design/EPA

- Regulations

- Accelerate

- Industry

- Sh ift

- from

Wet

- to

- Dry

- Bottom

- Ash

- Solutions_299.html

80 “Bottom Ash Handling: Why the Outlook is Dry, Modern Power Systems,” March 1, 2007; Available at: http://www.modernpowersystems.com/features/featurebottom

- ash

- handling

- why

the

- outlook

- is

- dry

81 See ERG Telephone Call Record, supra note 73.

82 See Charhut, supra note 79.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 636 83 “ERG Memorandum from Elizabeth Sabol and Thomas Finseth,” Docket No. EPA

- HQ

- OW

2009

- 0819, April 19, 2013, Re: ‘Steam Electric Effluent Guidelines

- Evaluation of Potential Subcategorization Approaches.’

84 See, e.g., Neville 2011, p. 57; Michael P. Bahor and Ken L. Ogle, “Economic Analysis of Wet Versus Dry Ash Disposal Systems,” Report EPA

- 600/7

- 81

- 013, January 1981, Table A

- 1.

85 Robert Peltier, “Predicting U.S. Coal Plant Retirements,” Power, May 1, 2011, Figure 1; Available at: http://w ww.powermag.com/coal/Predicting

- U

- S

- Coal

- Plant

Retirements_3632.html.

86 Neville 2011, p. 57.

87 “ERG Memorandum from T. J. Finseth to Steam Electric Rulemaking Record,” Docket No. EPA

- HQ

- OW

- 2009

- 0819

- 1811, April 19, 2013, Memo Re: ‘Discussion of Costs an d Cost Savings Associated with Impoundment Operation.’ Comment Response: See the response to DCN EPA

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- 4684

- A1, Excerpt Number 102 in Comment Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis f or BAT, costs associated with economies of scale, and “units that are likely to convert to dry bottom ash handling for reasons other than compliance with this rule.” EPA did not receive any information on “multi

- unit discounts” from the vendors and used th e cost information provided and documented in Section 8 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE0 5831/SE05832)

. However, EPA agrees that costs may have been overestimated because multiple unit synergies were not taken into account. EPA agrees that because of the intermittent bottom ash transport water pulls from generating units that one remote mechan ical drag system (or other dry bottom ash handling system) can accommodate multiple units. However, EPA lacked the detail on physical plant layouts to properly model this. In addition, EPA did not estimate multiple unit synergies to provide sufficient redu ndancy for the plant. EPA also agrees that it may have overestimated operation and maintenance costs by estimating labor costs for each mechanical or remote mechanical drag installation. However, these costs were estimated and implemented into EPA’s cost m ethodology on a per system basis. Furthermore, under the Clean Water Act, EPA’s cost estimates do not have to be precise. See, e.g., CMA v. EPA , 870 F.2d 177, 237

- 38 (5th Cir. 1989) (“The Act requires the EPA to ‘take into account’ the costs of BAT; it do es not require a precise calculation. The EPA ‘need make only a reasonable cost estimate in setting BAT’; it is sufficient if the EPA develops ‘a rough idea of the costs the industry would incur’” (citation omitted).); Kennecott Copper v. EPA, 612 F.2d 1232, 1238 (10th Cir. 1979) (EPA has “wide leeway in its analysis of costs”); BASF Wyandotte Corp. v. Costle , 598 F.2d 637, 662 (1st Cir. 1979) (upholds using averages in estimating costs); BP Exploration & Oil Inc. v. EPA , 66 F.3d 784, 799

- 800 ( 6th Cir. 1995) (“The CWA does not require a precise calculation of BAT and NSPS costs” (citation omitted).); NRDC v. EPA , 863 F.2d 1420, 1426 (9th Cir. 1988) (“[T]heEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 637 Act does not require a precise calculation of BAT costs.”); W eyerhaeuser v. Costle , 590 F. 2d 1011, 1045 (D.C. Cir. 1978) (“[Congress] left EPA with discretion to decide how to account for the consideration factors, and how much weight to give each factor.”). EPA also agrees that there are several steam electric power plants converting to dry bo ttom ash handling systems to lower operation and maintenance costs or to reduce water use. However, EPA only incorporated known retirements and conversions into the industry profile population, as described in Sections 4 and 9 of the TDD. At proposal, EPA did complete a sensitivity analysis of those conversions announced after EPA’s compliance costs were updated.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 27 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
Zero

- Discharge Would Reduce O&M Costs The EPA estimated O&M costs for the mechanical drag system (MDS) as the difference between the O&M costs to operate the MDS and the existing wet sluicing system. CAR, p. 8

- 6, Eqn. 8

- 7. Because the remote mechanical drag system (remote MDS) requires continued operation of the existing wet sluicing equipment, the O&M costs associated with wet sluicing were not subtracted from O&M costs as a savings. CAR, p. 8

- 25, Eqn. 8

- 25. In reporting costs for zero discharge bottom ash handling, EPA selected the technology with the lowest annualized cost for the combined system conversion at a plant level. TDD, p. 9

- 34. Using this procedure, the EPA reported significant net increases in O&M costs. These increases are inconsistent with the experience of vendors and operators of these systems. We cannot determine the cause as the calculations have been claimed as CBI. The operators of wet and recycle bottom ash handling systems report overall reductions in O&M costs when they convert from conventional wet sluicing systems to zero discharge systems. In fact, the reduction in O&M costs is so significant that the capital i nvestment can be recovered in 2 to 3 years. 88 The EPA, on the other hand, reports increases in O&M costs of $494 million per year to convert 240 bottom ash systems (Options 4 and 5 for 50 MW cutoff), which amounts to an increase of about $2 million per yea r for an average plant. A 10

- year recurring cost reduction of $84 million was reported for pond operations or about $35,000 per year, a de minimus reduction compared to actual experience. TDD, Table 9

- 6. Similarly, for Option 4a, which would require conve rsion for only units larger than 400 MW, EPA reports increases in O&M costs of $255 million per year to convert 115 bottom ash systems, or about $2.2 million per year for an average plant. A 10

- yearEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 638 recurring cost reduction of $36 million or about $30,000 year for an average plant is also reported. TDD, Table 9

- 7. Recurring costs are those that are not incurred on an annual basis and apparently were only calculated for pond operations. CAR, Chapter 5. These huge increases in O&M costs are not consistent with reported experience using these systems. The proposed retrofits should reduce O&M costs compared to existing wet sluicing systems for system operation, transport and disposal, and impoundment costs, which EPA used as its baseline. CAR, pp. 8

- 6, 8

- 25

. Seminole Electric Cooperative, for example, advised EPA that it achieved $3 million per year in savings when it replaced conventional wet sluicing systems at its two 750

- MW units with DRYCONTM systems. The per

- unit savings were reported as: (1) electric power of $495,000/yr; (2) $300,000/yr for reduced maintenance; (3) $216,000/yr for reduced need for spare parts; (4) $68,000/yr for reduced water makeup; and (5) $400,000/yr for recovered thermal energy. Improved boiler efficiency is not included in these estimates and would further reduce station O&M costs. 89 The projected savings from replacing a wet sluice system with a MAC at a 500

- MW plant, in 1995 dollars, was $577,300/yr, or about $1 million per year in 2010 dollars. 90 The savings were reported as (adjusted to 2010$): (1) $54,800/yr for improved boiler efficiency; (2) $66,300 for reduced auxiliary power consumption; (3) $86,700 for reduced system maintenance; (4) $90,300 for improved reliability; and (5) $536,200 for reduced ash disposal costs. 91 Significant reductions in O&M costs were also demonstrated for a dry MAC compared to a wet SCC, one of the options EPA evaluated (Table 4). 92 The conversion from a conventional wet sluicing system to a zero discharge system significantly reduces O&M costs by avoiding entire categories of costs and reducing many others, depending on the handling option that is selected. The only cost that may increase would be off

- site disposal if bottom ash is not beneficially used. On balance, overall O&M costs should decr ease as costs associated with all aspects of bottom ash handling would decrease (water, power, forced outages, maintenance, etc.) or be avoided (impoundment operation). The reduced and avoided costs for zero discharge bottom ash handling include:

 water

 wat er treatment

 electrical power

 monitoring

 spare parts

 reduction in forced outages

 maintenance

 operation

 fuel

 impoundment operation and maintenance However, the discussion of cost estimation methodology in the TDD does not identify any avoided costs associated with operating the ash handling system itself. 93 TDD, Sec. 9.7.2. The Cost Analysis Report, on the other hand, does indicate that EPA subtracted some, but not all, ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 639 the wet sluicing O&M costs from the mechanical drag option. CAR, Sec. 8.1.5, p. 8

- 6, Eqn. 8

- 10. However, the section on the remote mechanical drag option does not identify any reduction in O&M costs of the wet sluicing system. CAR, Sec. 8.2. While the wet sluicing system would still be required for the remote MDS systems, its O&M costs would be reduced. Costs that were conspicuously absent from both options include avoided costs of supplying and treating water and forced outages (significantly reduced with MDS and remote MDS). Further, EPA assumed no revenue from bottom ash sale s, only costs from its disposal. It is well known that plants that use wet sluicing systems have very high O&M costs due to high water consumption, high power demand for water circulation pumps, high maintenance cost due to corrosion and clogging, and loss of boiler efficiency. These costs are reduced or avoided (in dry systems) when a wet sluicing system is replaced with a recycle or dry bottom ash handling system as water pumps, ash slurry pumps, water treatment, and related equipment that requires mainte nance is removed. Some of these offsets (energy, water use) are acknowledged and estimated in the non

- water quality environmental impacts analysis. TDD, Sec. 12. However, there is no evidence that all of these were included in the cost analyses. An example of the cost benefits of converting from a wet system to a dry system is illustrated in Figure 4.

The fact that EPA calculated a large net increase in O&M costs when the retrofits would reduce O&M costs compared to existing unreliable wet sluicing system s with well know high O&M costs is a clear indication that EPA’s O&M cost analyses are incomplete and overestimated. The precise cause of EPA's overestimation of O&M costs cannot be determined without the cost spreadsheets which have been claimed as CBI.
Bottom Ash Sales One of the benefits of converting from wet sluicing to zero discharge and especially dry bottom ash handling is the resulting bottom ash has greater commercial value and can be sold or otherwise used, rather than disposed, eliminating disp osal costs while generating a revenue stream. A major vendor of dry bottom ash handling systems reports: "The reusable market value of fly and bottom ash will increasingly become a new or more significant source of revenue for coal

- fired power generation p lants." 95 While 100% of the bottom ash likely could not beEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 640 beneficially reused due to the location of the reuse market, the EPA should have made assumptions about the fraction that could be beneficially reused; i.e., from plants located near major metropo litan areas or near industrial facilities that could use it. Beneficial reuse of bottom ash has many advantages besides reducing disposal costs. It reduces energy demand, emissions, and other impacts from making materials from scratch, saving both natural resources and disposal space. For example, aggregate used in the construction industry can be mined from a quarry or river bed, damaging sensitive habitat. This aggregate could also be generated from specific size fractions of bottom ash, eliminating thes e environmental impacts. The use of bottom ash in this instance would conserve raw aggregate from the quarry, avoiding the environmental impacts of mining it and reduce the land area required to dispose of the ash. 96 The cost analyses assume that all botto m ash would be disposed. TDD, p. 9

- 16. Regardless of whether the recovered bottom ash is wet or dry, it can be beneficially used. Thus, EPA overestimated disposal costs and failed to account for revenue that could be generated by selling the bottom ash, of

fsetting O&M costs. TDD, p. 9

- 17. Bottom ash is used chiefly where its larger particle size is an advantage, such as in structural and engineering fill, aggregate for concrete and asphalt products, general reclamation, blasting grit or roofing shingle gran ules. Its size and drainage characteristics also make bottom ash an excellent sub

- base material for buildings and parking lots. 97 Bottom ash is easily dewatered due to its large particle size, which makes it a cost effective aggregate replacement. It is a lso used as aggregate in concrete and asphalt applications, granular base in pavements, and as fill material for engineered embankments. 98 It can be milled and mixed with fly ash to reduce its carbon content 99 for use in the cement industry. Or, if produc ed from a dry system, it can be used in concrete. The Monfalcone plant in Italy, for example, markets its dry bottom ash for preparation of concrete or cement in substitution of natural pozzolans. 100 A 2011 survey indicated that about 6.1 million tons o f bottom ash or 37% of the reported total produced in the U.S. was being beneficially used as summarized in Table 6: 101Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category: EPA’s Response to Public Comments

6-641 A common market for bottom ash is as lightweig ht aggregate. The first commercial-scale bottom ash beneficiation system to recover light weight aggregate from stored bottom ash was installed in 1997 at Winyah Generating Stat ion. Since then, several other bottom ash beneficiation plants have been inst alled to produce lightweight aggregate. 103 The bottom ash from dry systems that use air to c ool the ash is more marketable than bottom ash generated by water cooling as the carbon content of the ash is lower and the material is dry, reducing handling costs. However, both are ma rketable. Many U.S. power stations currently market their bottom ash, such as the Cinergy st ations in the Cincinnati area. Wateree, for example, sells almost 100% of its dewatered bott om ash collected from remote SFCs to concrete and block/pipe fabrication companies. 104 The bottom ash can also be recycled into the boilers and used as fuel to make us e of its residual carbon content. 105 Various beneficiation processes can be used to enhance the marketability of bottom ash. For graded aggregate, lightweight aggregate, and as phalt components, which are the principal uses of bottom ash, the primary option is screening to the appropriate size for the end use. 106 Processes are available to convert bottom ash into a product that can be used to make cement, which is generally the most lucrative market. The MAR-Magaldi Ash Recycling system recycles dry bottom ash from a MAC TM back into the combustion chamber, converting it into fly ash. 107 The bottom ash can be pulverized and mixedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 642 with fly ash. 108 Other beneficiation processes can be used to lower carbon content to make bottom ash attractive to the ready

- mix concrete market, such as Carbon BurnOut (CBO) and electrostatic separation. South Carolina Electric & Gas has had a CBO unit running at its Wateree station since early 1999 and brought a CBO unit on line at Winyah in 2003. 1 09 These beneficiation methods could be applied to bottom ash from other facilities covered by this rulemaking to improve the quality and attractiveness of bottom ash for sale into the cement market, which would not only lower costs but also result in sign ificant environmental benefits. They were not considered by the EPA.

88 See Alstom Power, supra note 14; Cianci, 2007, p. 49 and Table 1; and Quin Yu, “Air Cooling Dry Bottom Ash Handling System for Coal Fired Power Station,” The International Conference on Electrical Engineering 2009; Available at: http://www.icee

con.org/papers/2009/pdf/4.04_I9CP0180_E.Pdf.

89 See Seminole Site Visit Notes, supra note 59, pp. 7

- 8.

90 Costs adjust ed using the CESPI indices for 1995 (381.1) and 2010 (550.8), as reported in Chemical Engineering

.
91 Barsin 1996, Table 2.

92 Barsin 1996, Table 4.

93 Avoided costs (cost savings) associated with operating the impoundment used to collect the ash handling water were included. CAR, Sec. 5.5.

94 See Neville, supra note 57, Figure 2; Available at: http://www.powermag.com/coal/The

Better

- Environmental

- Option

- Dry

- Ash

- Conversion

- Technology_3799_p3.html

.
95 See United Conveyor Corp., supra note 78.

96 John Groppo, Thomas Robl and James C. Hower, “The Beneficiation of Coal Combustion Ash,” Energy, Waste, and the Environment: A Geochemical Perspective, Geological Society, London, Special Publications, v. 236, 2004, pp. 247

- 262.

97 EPRI, “Coal Ash: Its Origin, Disposal, Use, and Potential Health Issues,” 1998; Available at: http://www.uswag.org/epri

- coal_ash

- origin

- disp

- use.pdf; NETL, “Com mercial Use of Coal Utilization By

- Products and Technology Trends;” Available at: http://www.netl.doe.gov/technologies/coalpower/ewr/coal_u tilization_byproducts/pdf/coal_util.p df; and Shah et al. 2005.

98 Wei

- Hsing Huang, “Joint Transportation Research Program, Purdue University, The Use of Bottom Ash in Highway Embankments, Subgrades, and Subbases,” 1990; Available at: http://docs.lib.purdue.edu/cgi/viewcontent.cgi?article=1782&context=jtrp; Gavin P. GautreauEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 643 and others, “Bottom Ash Test Section Evaluation,” Erwinville, LA; Available at: http://www.ltrc.lsu.edu/pdf/2009/tar_08_3ta.pdf

99 Carbon ash contents >5% are not acceptable for cement. Bottom ashes typically have more unburned carbon than 5%, unless they are produced by a dry system s uch as the MAC, which improves boiler efficiency by burning the carbon in the bottom ash.

100 Notes from Site Visit at A2A's Centrale di Monfalcone on April 1, 2011, Docket No. EPA

HQ

- OW

- 2009

- 0819

- 1784; and supra note 33.

101 ACAA, “2011 Coal Combustion P roduct (CPP) Production & Use Survey Report;” Available at: http://www.flyashdirect.com/browse_file.asp?ak_id=31&FileType=20

102 See id. (**=These numbers are derived from pre vious, current and applicable industry

- wide available data, including EIA Reports 923 and 860 and other outside sources).

103 Groppo et al. 2004, p. 249.

104 See Wateree Site Visit Notes, supra note 72, pp. 3, 7.

105 See, e.g., McIlvaine, Utility Fax Alert , February 9, 2001 (" Wisconsin Electric (WE) and the Wisconsin Department of Natural Resources signed an Environmental Cooperative Agreement. WE will reclaim fly and bottom ash from company landfills. WE is planning to remove the ash from the landfills and burn it in the Pleasant Prairie 4 boiler. Finally, the resulting combustion products can be sold for beneficial use and not landfilled.")

106 Groppo et al. 2004, p. 252.

107 M. Bertolino and others, “Recirculation of Bottom Ash into the Fly Ash Handling P rocess and an Overview on Coal Ash Reutilization. A Case Study: Fiume Santo Power Station, Proceedings of the IV Scientific and Practical Workshop,” Ashes from TPPs: Removal, Transport, Processing, Landfilling, 2012, p. 163

- 167; Available at: http://osi.ecopower.ru/en/full

content.html.

108 Cianci 2007, p. 51; Shah et al. 2005, p. 6.4.

109 Brian K. Schimmoller, “Coal Ash and Ash Handling: In Search of Cost Savings,” Power Engineering; Available at: http://www.power

- eng.com/articles/print/volume

- 107/issue

4/features/coal

- and

- ash

- handlingin

- search

- of

- cost

- savings.html

. Comment Response: See the respons e to DCN EPA

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- A1, Excerpt Number 107 regarding estimation of operation and maintenance costs. EPA agrees that plants that install dry bottom ash handling systems may experience operation and maintenance cost savings (for example, Semino le’s DRYCONTM installation). However, EPA did not quantify these savings as part ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 644 the rule. EPA did estimate operation and maintenance costs associated with mechanical and remote mechanical drag systems. The majority of the operation and maintenance costs were developed from cost data reported in the Steam Electric Survey for mechanical drag systems and bottom ash wet sluicing systems. As stated by the commenter, EPA did subtract wet sluicing operation and maintenance costs from the mechanical drag system costs to account for these savings. EPA did not evaluate costs associated the reduction in supplying and treating water for a conventional wet sluicing system or forced outages potentially resulting in the overestimation of some operation and maintenance c osts. EPA notes that some of the estimated increases in operation and maintenance costs may be associated with offsite transport and disposal, not the specific system operation. See the response to DCN EPA

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- A1, Excerpt Number 157 regard ing bottom ash sales.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 28 External Review Flag: Economics/Benefits External Review Incorporated into Response: No Comment Excerpt:
Annualization Method Underestimates Costs The EPA evaluated costs for both the MDS and remote MDS technologies and then selected the technology with the lowest total annualized costs. The EPA also used annualized costs to es tablish cutoff thresholds for applicability of its proposed ELGs 110 and to evaluate social costs. 78 Fed. Reg. at 34,493. Option 5, for example, was eliminated as a preferred option for BAT because of the high total industry cost at $2.3 billion/year annua lized social cost. 78 Fed. Reg. at 34,473. However, the annualization method EPA used significantly overestimates these costs. Capital costs were annualized assuming a 7% discount rate and 20

- year equipment lifetime, using the method laid out in the Cost A nalysis Report, Section 8.8 and 78 Fed. Reg. at 34,492. These input assumptions are unreasonable and overestimate annual costs, making these technologies look less economic than they really are. First, EPA stated that it relied on the real (i.e., inflatio n rate factored out) cost of capital as estimated by the U.S. Office of Management and Budget, citing OMB 2003. 111 CAP, p. 8

- 32. However, the cited document actually states that "For regulatory analysis, you should provide estimates of net benefits using both 3 percent and 7 percent." It goes on to give an example for a 1998 rulemaking similar to this one that sets both effluent limits for wastewater discharges and air toxic emission limit for pulp and paper mills, using a range of 3% to 7% over a 30

- year life. Interest rates have plummeted since the 2003 OMB guidance. The most recentEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 645 OMB information reports that the real treasury interest rate, the basis of the original range, has fallen, and as of 2010, it was 2.7% for a 30

- year term. 112 Second, the EPA estimated annual costs assuming an equipment lifetime of 20 years. Capital equipment in coal

- fired power plants is typically designed for a lifetime of at least 30 years. 113 Further, as shown by the Magaldi experience list in footnote 33, there are dry bottom ash systems in Italy that have been operating for nearly 30 years. Zero

- discharge wet cycle systems have been used in the U.S. and elsewhere for much longer. Finally, it is not reasonable to assume a 20

- year lifetime when certain "recurring costs" t o replace equipment at 3

- , 5

- , 6

- , and 10

- yr fixed intervals are already factored into the estimate. CAR, Sec. 8.7, TDD, Table 9

- 10, and RIA, 114 p. 3

- 3. The revised annualization factor, estimated assuming an interest rate of 2.7% and an equipment lifetime of 30 years, is 0.0491. 115 This is nearly a factor of two lower than the value EPA used to annualize capital costs (0.0943/0.0491 = 1.9). Thus, EPA overestimated annual costs by about a factor of two due to just this single factor. As discussed e lsewhere in this Report, there are many other overestimations. This issue also applies to EPA's cost estimates for other control costs, including for the treatment of wet flue gas desulfurization (WFGD) wastewaters by biological and zero liquid discharge m ethods. In sum, EPA has significantly overestimated the cost of converting from wet sluicing bottom ash handling systems to zero liquid discharge systems. First, EPA ignored economies of scale and multiple unit discounts by estimating costs for individual units rather than for plants or even utilities as a whole. Second, EPA overestimated the number of units that would retrofit zero liquid discharge systems by assuming that all units that have not announced conversion or shutdown plans would be forced by this rulemaking to convert. Third, EPA overestimated O&M costs by failing to include all cost savings and avoided costs when converting from wet to zero liquid discharge bottom ash handling. Fourth, EPA did not consider the revenue generated from bottom a sh sales. Finally, EPA overestimated annual costs for all wastewater streams by using a short lifetime and high interest rate. Cost would be even lower if EPA had included a true dry bottom ash handling system in its calculations. While I cannot precisely estimate the degree of overestimation, it falls within the range of a factor of two (due to annualization alone) to a factor of four.

110 See ERG Memorandum from E. Sabol and T. Finseth, supra note 83, Re: ‘Steam Electric Effluent Guidelines

- Evaluation o f Potential Subcategorization Approaches,’ Figures 3 and 4.

111 U.S. Office of Management and Budget, September 2003; Available at: http://www.whitehouse.gov/omb/circulars_a004_a

- 4/#d

.
112 Budget Assumptions, December 6, 2012; Available at: http://www.whitehouse.gov/sites/default/files/omb/assets/a94/dischist

- 2013.pdf

113 See Neville 2011, su pra note 84.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 646 114 EPA, Regulatory Impact Analysis for the Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category, Report EPA

- 821

- R

13

- 005, April 2013.

115 Using CAP Eqn. 8

- 68, the annualization f actor for a 30 year life and 2.7% interest rate is (0.027/{1

- [1/(1+0.027)30]} = 0.0491

. Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 102 in Comment Code 15 for EPA’s response on the annualization factor.
See the response to DCN EPA

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- 4655, Excerpt Number 53 regarding bottom ash cost estimates for the final rule, including EPA’s use of a 20

- year useful life.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APP A) Document Control Number: EPA

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EPA selected a 7% discount rate and a 20

- year time frame for the operational life of the technologies. EPA did not provide information or supporting documentation for the 20

- year time frame. Comment Response: See the response to DCN EPA

- HQ

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- 4655, Excerpt Number 53 for information on the 20

- year time frame

.

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 54 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 647 Comment Excerpt:
APPA Endorses the Consideration of the UWAG Bottom Ash Retrofit Annualized Cost Analysis APPA does not have the economic resources that UWAG has to independently gather data or review EPA’s hundreds of pages of data for thi s rulemaking. But as a member of UWAG, we are struck by the costs that UWAG has projected as the more likely costs given that the EPA has exaggerated the actual pollutant pound equivalent and the costs per pound. Most of APPA’s member utilities have single baseload coal

- fired plants <300 MW (although a few have multiple units <200 MW). These costs raise serious concerns about whether the EPA adequately reviewed the real costs for smaller entities

. The following data strongly suggest that retrofit costs are disproportionately higher for small utilities. Table 3: Bottom Ash Retrofit Annualized Capital Costs, Million Dollars

MW Range MW Used

(Midpoint) Bottom Ash

Retrofit Total Capital Cost, Million $/Plant Bottom Ash

Retrofit Annualized Capital Costs, Million $/Plant (assumed 15
- year life of system and 7% interest)

<50 MW 50 6.4 0.71

50

- 100 MW 75 7.0 0.77

100

- 150 MW 125 8.2 0.90

150

- 200 MW 175 9.4 1.03Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 648 200

- 300 MW 250 11.2 1.23

300

- 400 MW 350 13.6 1.49

400

- 500 MW 450 16.0 1.76

500

- 700 MW 600 19.6 2.15

700

- 900 MW 800 24.4 2.67

>900 MW 1000 29.1 3.20

Comment Response: The final rule record demonstrates that steam electric power plants can install and afford the dry handling or closed

- loop systems selected as the BAT basis for control of pollutants in bottom ash transport water discharges from generating units that are greater than 50 MW and that are not oil

fired (see preamble sections VIII and IX). See the response to DCN EPA

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- A1, Excerpt Number 50 in Comment Code 6. a and “Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum” (DCN SE04745) for more information on the identification of pollutants of concern for bottom ash transport water. See the response to DCN EPA

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- 4655, Excerpt Number 47 i n Comment Code 15.d for more information on the data and methodology used to calculate bottom ash baseline loadings.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 649 See the response to DCN EPA

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- 4655, Excerpt Number 53 for more information on the estimation of compliance costs associated w ith the final bottom ash transport water requirements. EPA evaluated costs associated with generating units with smaller capacities. See preamble section VIII for more details on EPA’s rationale for establishing different limitations for existing “small” g enerating units (50 MW or less).

Commenter Name: Theresa Pugh Commenter Affiliation: American Public Power Association (APPA) Document Control Number: EPA

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- A2 Comment Excerpt Number: 56 External Review Flag: No External Review Ext ernal Review Incorporated into Response: No Comment Excerpt: Retrofitting to Dry Handling of Bottom Ash Would Be Long and Expensive UWAG’s comments present a case study asserting that it would take 30

- 36 months to convert from a wet bottom ash hopper to a dry bottom ash hopper for a large unit and cost over $24 million ($24,803,358 plus $8,851,653 for contingency, escalation, and operating company overheads). APPA does not know if this first case study is applicable for many APPA member utilities. But we do believe that this case study, along with the UWAG second case study, should be considered. The second case has a wet ash hopper and submerged flight conveyor requiring 27

- 33 months and cost $21,623,683 plus over $7,500,000 for contingency, escalation, and operating company overhead. These two UWAG case studies show that EPA’s projected costs are far off the mark. APPA finds that retrofit costs are often higher for smaller utilities than larger utilities because of the fact that many public power utilities have one base

- load plant with smaller natural gas combined cycle (NGCC) units used for peaking. It is almost always the case that the smaller utility is, the more expensive its retrofit or the construction costs are because the units are smaller , have more limited physical space, and also have only one base

- load plant on which to call upon. This usually means the utility with one baseload unit often must buy power off the market during these planned outages for construction. Comment Response:
S ee response to DCN EPA

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- A1, Excerpt Number 41 for EPA’s comments on the case studies for bottom ash retrofits submitted by both UWAG and Southern Company (DCN EPA

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- A11 and DCN EPA

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- A1).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 650 EPA evalua ted costs associated with generating units with smaller capacities. See preamble section VIII for more details on EPA’s rationale for establishing different limitations for existing “small” generating units (50 MW or less).Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 651 16.c. Zero Discharge Bottom Ash

– Pollutant Loads
Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 54 External Review Flag: No External Review External Revie w Incorporated into Response: No Comment Excerpt: Dry Handling/Closed Loop Pollutant Removals are Overestimated. We Energies believes EPA vastly overestimated the pollutant removals for conversion of bottom ash to dry handling/closed loop across the whol e industry and even for units 400 MW or larger. We Energies supports EPRI’s and UWAG’s evaluation of bottom ash transport water. EPRI conducted an evaluation of bottom ash transport water effluent from settling ponds using their Power Plant Integrated Sys tems

– Chemical Emission Study (“PISCES”) data and permit application data, as provided by member companies of UWAG. EPRI concluded that the toxic weighted pound

- equivalents removed per year were only a fraction (8%) of the EPA estimates. UWAG’s calculati ons were even smaller (65,342 lb

- eq compared to EPA’s estimate of 2,716,059 lb

- eq). We Energies believes both EPRI’s and UWAG’s evaluation of the data is more accurate than EPA’s evaluation because EPA used old data analyzed with less sensitive methods (r esulting in higher method detection limits and quantification limits). Therefore, EPA may have artificially inflated the toxicity estimates through their treatment of non

- detect data. Further, EPA evaluated combined ash ponds and estimated a percentage of the pollutants contributed by the bottom ash transport water; yet EPRI conducted its analysis using only settled bottom ash transport water. Both UWAG and EPRI specify that source water contributions should be considered and subtracted. Therefore, we bel ieve EPRI’s and UWAG’s dataset and analysis are more accurate. Comment Response: See response to DCN EPA

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- A1, Excerpt Number 72 in comment code 15.d. EPA excluded data using settled ash transport water see response to DCN EPA

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- A3, Excerpt Number 74 in Comment Code 15.d.

Commenter Name: Tom DeLawrence Commenter Affiliation: Alabama Power Company Document Control Number: EPA

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- 652 External Review Flag: No External Re view External Review Incorporated into Response: No Comment Excerpt: Knowing that EPA’s current data related to bottom ash transport water would be insufficient, UWAG developed its own data for this waste stream and is providing it to EPA along with the association’s comments. In contrast with EPA, UWAG properly subtracts toxic

- weighted pound equivalents (“TWPEs”) attributable to naturally occurring minerals in water supply sources from its data and further limits its analysis to only non

- recycled, isola ted bottom ash wastewater utilizing sluice water originating from a source waterbody. The resulting UWAG TWPE numbers are, not surprisingly, considerably lower and provide a more representative depiction of both the kind and amount of constituents actually found in this waste stream. Alabama Power endorses that data and UWAG’s analyses thereof. Comment Response: EPA supplemented its dataset for the final rule, including with UWAG data. See response to DCN EPA

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- A1, Excerpt Number 72 in comment code 15.d.

Commenter Name: Bruce W. Ramme Commenter Affiliation: We Energies Document Control Number: EPA

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- A1 Comment Excerpt Number: 58 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We Energies believes that the methodologies used to estimate plant

- specific pollutant removals of bottom ash transport water should be consistent across different plants. Sites discharging bottom ash transport water after chemical pr ecipitation treatment should be given “credit” for their treatment. Pollutant removal estimates for these sites should be more accurate and should not be calculated using the average concentrations from impoundment effluent. A better, more accurate metho dology would be to gather data from sites treating bottom ash transport water through chemical precipitation to determine the average effluent concentrations and thus what the pollutant reduction would be if dry handling/closed loop technologies are requir ed for BAT. Comment Response: Regarding plants that this commenter claims have chemical precipitation for ash transport water see response to DCN EPA

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- A1 Excerpt Number 57 in Comment Code 7.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 653 For the final rule, EPA reviewed the botto m ash impoundment effluent data in the ash characterization analytical database and determined that, for a majority of the samples, EPA did not have sufficient information to determine whether chemical addition occurred upstream of the sample point during the sample collection period. As part of this review, EPA identified two datasets from public comments that specified whether chemical additives were introduced upstream of the sample collection site. EPA determined that one of these two datasets includes effluent pond data from plants that employ chemical addition. Both of these datasets include data from plants that do not employ chemical addition. EPA determined that the ash characterization dataset represents both practices and is appropriate for calcul ation of industry

- level loadings.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 58 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: UWAG based the median flow rates for each model plant on the wastewater flows that EPA compiled from the ICR. Using all non

- CBI flow rates in the record for the rulemaking (EPA

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- 2070), UWAG sorted the flow rates into MW “bins” of its 10 model plants (ranging from <50 MWs to >900 MWs) and then identified the median flow rate for each bin. UWAG used median flow rates to reduce the influence of several extreme flow rates reported in the ICR

. These extreme flow rates are not representative of typical bottom ash transport water flow rates. Comment Response: The commenter describes their process to calculate non

- CBI pollutant loadings using only non

CBI flow data reported in the Steam Electr ic Survey. The commenter calculated an industry

wide “non

- CBI” median bottom ash transport water flow rates for several capacity

- based model plants to reduce the influence of “extreme flow rates” (as defined by the commenter) reported by the industry. EPA disagrees with this approach. As described in Section 10 of the TDD and in detail in Section 4 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) , EPA used both CBI and non

- CBI plant

- specific wastewater flow rates as reported by the individual plants to estimate plant

specific pollutant loadings. EPA used data from the Steam Electric Survey to ide ntify those plants that discharge or have the potential to discharge fly ash or bottom ash transport water. Based on the amount of ash transport water reported to be discharged, EPA calculated plant

specific ash impoundment discharge flow rates and plant

- s pecific ash impoundment discharge loadings. EPA determined that use of available, plant

- specific flow data (including data reportedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 654 to be CBI) is a more accurate approach for estimation of plant

- specific pollutant loadings for fly ash transport water and b ottom ash transport water than using non

- representative non

- CBI median flow rates based on capacity

- based model plants.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Commen t Excerpt Number: 37 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The median flow rates for each model plant were based on the wastewater flows that EPA compiled from the 2010 ICR. Using all no n
- CBI flow rates in the record for the rulemaking (EPA

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- 2070), the flow rates were sorted into MW “bins” of its 10 model plants (ranging from <50 MWs to >900 MWs) and then the median flow rate was identified for each bin.
Median flow rates were used to reduce the influence of several extreme flow rates reported in the 2010 ICR. These extreme flow rates are not representative of typical bottom ash transport water flow rates. Comment Response: See response to DCN EPA

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- 4655, Excerp t Number 58 for information for why EPA used plant

- specific wastewater flow rates in the loadings calculations rather than industry

- wide median flow rates based on capacity

- based model plants using only non

- CBI data.

Commenter Name: Paul Chu Commenter A ffiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 71 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: 

### 7.1 EPA’s est imated pollutant reductions by converting to zero discharge of bottom ash sluice water appear to be high by about a factor of 10.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 655 A comparison of EPRI’s and EPA’s estimates for the pollutant reductions by converting to zero discharge of bottom ash sluice water is shown in Table 7

- 1. The pollutant reductions are for installing the technology basis for units 50 MW or more and for units 400 MW or more. The pollutant reductions are expressed in terms of toxic

- weighted pounds

- equivalent (TWPE) of pollutants not discharged per year.

Comment Response: For the final rule, EPA supplemented its fly ash and bottom ash characterization dataset and revised its estimates of ash impoundment effluent concentrations. See response to DCN EPA

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- A1, Exce rpt Number 72 in comment code 15.d.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 656 16.e. Zero Discharge Bottom Ash

– Other Technology Options
Commenter Name: Gary D. Mooney Commenter Affiliation: Clyde Bergemann Power Group (CBPG) Document Control Number: EPA

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- A1 Comment Excer pt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We are dismayed that our equally viable technology for a totally dry mechanical conveyor underneath a boiler was overlooked and omitted from the list of bottom ash handling technologies. We know that the EPA and ERG are both aware of our very successful installation in Florida of our DRYCONTM Dry Bottom Ash Conveyors and wonder why this option did not receive more support in your Proposed Rule? In Section 7 of the Technical Development Document (page 7

- 30) and then in Section VI of the Proposed Rule (Page 34453) the list of available technologies for bottom ash handling systems includes:

- Mechanical Drag Systems,

 Water

- filled trough type, such as our Submerged Scraper Conveyor, SSC

- Remote Mechanical Drag Systems,

 This description applies to our ASHCONTM Remote SSC design,

 Reference is made to one operating and one soon to be operating system in the USA, by Others, which we acknowl edge

- Dry Vacuum or Pressure System,

 This description starts out by describing a DRYCONTM type design: “These systems transport bottom ash from the boiler to a dry hopper without using any water. The system percolates air through the ash to cool it and combust unburned carbon.”
Our DRYCONTM dry conveyors do exactly that as proven by two 650+ MW operating units in Florida. If the reports can acknowledge the few Remote Mechanical Drag Systems, we request the addition of our DRYCONTM installation and the t wo other operating installations by our competitors in the USA. It is not necessary to then use a pneumatic conveying system to convey the ash to a storage destination but a pneumatic system can certainly be used at the discharge of a DRYCONTM

. As a b rief reminder, the two boiler Units in Florida with DRYCONTM conveyors under themEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 657 came back on line in April and November of 2012 after less than 22 day outages to remove the entire wet ash systems. The two 650+ MW Units are now operating at full load with the added benefits in 2013 that:

 The use of water to operate the entire bottom ash and economizer ash handling systems has been totally eliminated

 The power consumption to operate the bottom ash and economizer ash handling systems has been greatly reduce d

 The amount of unburned carbon in the ash, also referred to as loss

- on
- ignition, LOI, has been significantly reduced as verified by field measurements

 The bottom ash temperature is significantly reduced between the boiler throat opening and the end of the conveyor.

 The plant has experienced significantly reduced operating and maintenance costs. We believe this installation validates the many reasons why our DRYCONTM Dry Bottom Ash Conveyor should be added to the list of available and viable technologie s for new and existing bottom ash handling systems. Please add this option in future versions of your various reports on this important subject.

Comment Response: EPA agrees with the commenter that the dry mechanical conveyor (such as DRYCONTM) should have been included in the list of viable technologies for bottom ash handling in the proposed rule report. See Section 7 of the TDD for a description of the completely dry bottom ash handling technology. Additionally, EPA recognizes that this technology el iminates the use of water; therefore, plants could use the technology to meet the zero discharge requirements in the final rule, and this can result in cost savings associated with reduced operation and maintenance costs and reduced coal consumption.

Com menter Name: Fulvio Bassetti Commenter Affiliation: Magaldi Power Document Control Number: EPA

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- A5 Comment Excerpt Number: 1 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: We point out to the Environmental Protection Agency (EPA) and the Eastern Research Group Inc. (ERG) that our “fully

- dry” technology, the MAC
- Magaldi Ash Cooler TM based on a mechanical extractor underneath a solid fuel boiler, was overlooked and omitted f rom the list of bottom ash handling technologies.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 658 The MAC
- Magaldi Ash Cooler TM “fully

- dry” technology was invented and developed by the Magaldi Group as an alternative solution to the conventional wet bottom ash handling systems. Since its first applica tion in 1985 in an Italian power plant, the MAC system has been installed underneath more than 150 boilers worldwide, ranging from 20 to 1,000 MW with a total installed capacity of more than 59,000 MW and more than 9,000,000 hours of cumulative operation ( as per September 2013).
We assume that the EPA and ERG are both aware of our MAC
- Magaldi Ash Cooler TM installations in Florida, in operation since 1993 under a 500+ MW class

- boiler, and in Wyoming, in operation since 2011 under a 385+ MW class

- boiler. Ne vertheless, the above option did not receive a specific support in your Proposed Rule. In Section 7 of the Technical Development Document (page 7

- 30) and then in Section VI of the Proposed Rule (Page 34453 and 34454) the list of available technologies for bottom ash handling systems includes:

 Mechanical Drag Systems

⇒ Water

- filled trough type, such as our Submerged Scraper Conveyor, SSC

 Remote Mechanical Drag Systems

⇒ Remote SSC design

 Dry Vacuum or Pressure System

⇒ This description starts out by describ ing a MAC
- Magaldi Ash Cooler TM design:

“ These systems transport bottom ash from the boiler to a dry hopper without using any water. The system percolates air through the ash to cool it and combust unburned carbon.” This is part of the basic design concept of the MAC
- Magaldi Ash Cooler TM , that uses only air instead of water for ash cooling. The bottom ash is extracted from underneath the boiler and transported to the storage silo by means of the MAC Extractor, a stu rdy steel belt conveyor able to withstand high temperatures and heavy shock loads. The handling and cooling processes of the bottom ash is realised continuously, 24/24 h, without use of water. It is not necessary to then use a pneumatic conveying system to convey the ash to a storage destination, but a pneumatic system can certainly be used at the discharge of a MAC
- Magaldi Ash Cooler TM

. We kindly request the addition of our MAC
- Magaldi Ash Cooler TM references to the list of operating installations in t he USA. A plus downstream the MAC system can be the innovative MAR
- Magaldi Ash Recycling TM , to recycle the dry bottom ash back to the boiler and transform it into saleable fly ash.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 659 Depending on the plant layout and operation needs, different configuratio ns of the MAC TM and the MAR TM systems can be designed in order to achieve the greatest environmental benefits and to eliminate costs associated with the bottom ash ponding / landfilling. As witnessed by the number of installations worldwide, among which on e in Florida has been in operation since 1993, the MAC
- Magaldi Ash Cooler TM “fully

- dry” technology provides the following outstanding benefits:

 Zero water usage. No water treatment systems required.

 Effective environmental risk mitigation. No need for bo ttom ash storage ponds.

 The Magaldi conveyors ensure continuous ash removal, low wear, low power demand, long service

- life, low O&M costs, safe operation, high system dependability.

 Boiler efficiency improvement, due to recovery of energy from unburned fue l (also referred to as loss

- on
- ignition LOI) in bottom ash, ash sensible heat and flame radiation through the boiler throat. This leads to coal consumption savings and CO2 emission reduction.

 Improved quality of bottom ash (dry and low

- carbon) means maximu m potential for valuable marketing. The two installations already in operation in the USA and all the others worldwide (more than 150 in all 5 continents with a cumulative experience of more than 9,000,000 hours) testify the performance and the relevant be nefits of the MAC
- Magaldi Ash Cooler TM “fully

- dry” technology. Due to the outstanding results of the several existing MAC installations worldwide and the global acceptance of our MAC technology, both by all major Boiler Manufacturers and End Users, we be lieve that our MAC
- Magaldi Ash Cooler TM “fully

- dry” bottom ash handling system should be added to the list of available and viable technologies for new and existing bottom ash handling systems. Magaldi Power S.p.A. respectfully request to add this option in future versions of your various reports on this important subject. Attached to this letter you will find also a description both of the MAC
- Magaldi Ash Cooler TM and of the MAR
- Magaldi Ash Recycling TM , the MAC TM reference list, some technical papers presented at International Conferences and/or published in selected sector magazines. Comment Response: EPA agrees with the commenter that the dry mechanical conveyor (such as MAC

– Magaldi Ash CoolerTM) should have been included in the list of viable technologies for bottom ash handling in the proposed rule report. See Section 7 of the TDD for a description of the completely dry bottom ash handling technology. Additionally, EPA recognizes that this technology eliminates the use of water and would enabl e a plant to meet the zero discharge requirements in the finalEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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- 660 rule. Additional benefits include cost savings associated with reduced operation and maintenance costs and reduced coal consumption.

Commenter Name: Chas Spell Commenter Affiliation: Arizon a Public Service Company Document Control Number: EPA

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- A2 Comment Excerpt Number: 5 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: APS encourages EPA to consider lower cost technologies for the proposed rule. Dry handling of fly ash and bottom ash are expensive technologies to implement at existing facilities where other, much lower cost alternatives offer a commensurate level of environmental benefit. For example, APS oper ates a facility where impoundment has proven to be an effective means of treatment for bottom ash transport water. Comment Response: The final rule establishes BAT limitations and PSES applicable to discharges of bottom ash transport water based on dry h andling or closed

- loop technologies, except for discharges from generating units smaller than or equal to 50 MW or units that are oil

- fired. As described in preamble Section VIII, EPA selected dry handling or closed loop systems as the technology bases fo r control of bottom ash transport water discharges because they are available, they are economically achievable (i.e., affordable) for the industry as a whole, and they have acceptable non
- water quality environmental impacts. For the reasons explained in preamble section VIII.C.3, EPA did not select surface impoundments as the BAT basis for control of bottom ash transport water discharges from all existing steam electric generating units. Most importantly, they would not result in reasonable further progr ess toward the national goal of eliminating the discharge of all pollutants, particularly toxic pollutants (see CWA section 301(b)(2)(A)). See also response to DCN EPA

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- A1, Excerpt Number 3. EPA notes that steam electric power plants m ay choose to comply with the final limitations and standards using any technology they choose that meets the zero discharge requirements.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 155 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 661 Comment Excerpt:
APPENDIX A: Engineering Aspects of Retrofitting Dry Bottom Ash Handling In reviewing the proposed ELG Rule, Southern Company engineers investigated possible technologies for dry bottom ash handling. The following sections evaluate the available technologies. Converting from wet bottom ash handling to dry handling can be done with several technologies. These tec hnologies have differing capital costs as well as operating and maintenance (O&M) costs. The most common commercially available technologies are:
1. Dry Bottom Ash Hopper 2. Wet Bottom Ash Hopper

- Submerged Flight Conveyor 3. Remote Ash Hopper

- Submerged Flight C onveyor 4. Decant Silo (or Hydrobin) In addition, dewatering by manual means (sumps and settling ponds with manual ash excavation) can produce a result similar to the engineered equipment systems listed above. Replacing an existing wet bottom ash hopper will create reconfiguration issues. Alternate technologies that retain the wet bottom ash hopper and insert a dewatering system will also encounter configuration issues that are different from technology to technology. Dry Bottom Ash Hopper Installing a dry b ottom ash hopper requires removing the existing wet bottom ash hopper, clinker grinders, sluice water piping, and ash piping. The dry hopper has a modular design and is erected beneath the boiler on steel support columns independent of the boiler. Boiler s eal is provided by a high

- temperature expansion joint. No water is used for conveying ash collected in the hopper. Instead, this system combines conveyors and a pneumatic transport piping system to collect the ash and convey it to an intermediate storage s ilo disposal. Ash falls into the hopper and onto a conveyor that carries the still

- burning particles to an inclined conveyor that empties into surge bins. Coal crushers mounted along the inclined conveyor break up any agglomerated ash into particles capabl e of being pneumatically conveyed to intermediate storage (usually a silo) prior to disposal. Access platforms and stairs are provided for maintenance. Pressure blowers provide the convey air that transports the ash from the surge bins to the intermediate storage silo. Retrofitting a dry hopper presents the following engineering challenges:

 The primary challenge is potential interference between the existing boiler building structural steel bracing and the inclined conveyor.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 662  The amount of space between the furnace and the building floor may prevent installing the dry hopper without excavating a pit below the boiler for its entire width, if no pit exists.

 For generating plants with the ash hopper located below grade, the complexity of the ash transport pipe routing can increase the power requirements of the convey air pressure blowers. Scheduling considerations include the following:

 Based on our experience with similar projects, delivery of the equipment will occur 42

- 52 weeks after the manufacturer receiv es approved drawings from the customer. If the final ELG Rule and CCR Rule require major modifications, delivery times will increase because of the limited number of suppliers and engineers.

 The time required to demolish the wet ash hopper and then erect t he new dry ash hopper and ancillary equipment (inclined conveyor, surge bins, etc.) can require a plant outage of up to 16 weeks.

 The intermediate ash storage silo and the pneumatic ash conveying piping can be installed while the generating plant is in ope ration. Wet Bottom Ash Hopper
- Submerged Flight Conveyor For the wet bottom ash hopper with submerged flight conveyor, water is used to collect bottom ash in a hopper underneath the boiler. A chain conveyor with submerged flights removes ash from the wat er
- filled section of the hopper to an inclined conveyor that rises to an elevated location. The ash is ejected from the conveyor into a storage bunker or truck for disposal. The hopper and inclined conveyor are watertight. The hopper section is supported o n steel rails embedded in the boiler house floor. The inclined conveyor and access platforms are supported on steel columns from the boiler house floor. Water is required to replenish the hopper section due to losses from evaporation in the boiler and resi dual water carried over in the ash discharged from the conveyor. Water also may be required to provide hopper and boiler seal refractory cooling depending on the manufacturer’s design. The amount of water in the ash may be higher than with other technologi es that depend on decanting water from the ash due to the shorter time available. (Decanting occurs only on the inclined conveyor with this equipment.) The wet bottom ash hopper with submerged flight conveyor is less suitable at some plants for the following reasons:

 This technology is best suited to a boiler house with a floor at grade. The angle of conveyor inclination limits the depth below grade at which the hopper section can be located.

 To discharge ash into a storage bunker or truck requires a ccess to an outside wall. A generating plant with more than two adjacent generating units will find it difficult to install this technology without exterior walls adjacent to the boiler.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 663 Other challenges in installing this technology are as follows:

 Exist ing equipment that is located around the furnace throat may prevent the installation of the inclined conveyor section.

 The amount of space between the furnace and the building floor may prevent installation of the hopper section without excavating a pit be low the boiler over its entire width, if there is no pit to begin with.

 Access to a point along the exterior wall of the boiler building for either a storage bunker or a truck may not be possible, especially for a rail car. Scheduling considerations includ e the following:

 Based on experience with similar projects, delivery of equipment requires 52

- 56 weeks after the manufacturer receives approved drawings from the customer. This time period is likely to be longer once the ELG Rule or CCR Rule requires ret rofits.

 The time required to demolish the wet ash hopper and then erect the new hopper section and inclined conveyor can require a plant outage of 16 weeks or longer.

 Support rails must be installed during the installation outage.

 Alignment of the conveyor between the inclined section and the hopper section is critical. All the installation must occur during the plant outage. Remote Ash Hopper
- Submerged Flight Conveyor A remote ash hopper with submerged flight conveyor allows the existing wet bottom ash hopper, clinker grinders, sluice water piping, and ash sluice piping to remain in place. A new hopper is installed at a location remote from the boiler. The existing ash sluice piping is rerouted to discharge into the hopper section above the submerged fl ight conveyor (SFC). Ash particles settle to the bottom of the hopper and are moved to the inclined conveyor section where the dewatering occurs. Ash is discharged into a storage bunker, truck, or additional conveyor to the disposal location.
Ash sluice wa ter is pumped back to the boiler house either directly or from a surge tank, thereby creating a closed

- loop recirculating water system. Water from the storage bunker and any overflow from the hopper are collected in a local sump and pumped back into the ho pper (or to an alternate drain system). The availability of the remote ash hopper with submerged flight conveyor is limited by the manufacturing capacity for these systems. Manufacturing lead time is currently averaging one year, and this is before promulg ation of the final ELG and CCR Rule. Engineering challenges are the following:

 Location of the SFC must not materially change the ash sluice piping hydraulics if the existing high pressure ash sluice water pumps are to be retained. Significant changes in p iping will require new pumps and motors.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 664  Depending on soil conditions, foundation requirements for a large SFC can be substantial and expensive.

 Criteria for site selection will require a large land area for a SFC with enough capacity to separate ash from sluice water and dewater the ash produced by a large generating unit (> 400 MW). Scheduling considerations are as follows:

 As stated above, the manufacturing lead time is approximately one year.

 The SFC and foundations, sumps, surge tanks, and water return piping can be installed while the generating unit remains in operation. Construction of the site facilities can proceed in parallel with the system fabrication and delivery.
Decant Silo A decant silo dewaters the bottom ash by gravity using remotely loc ated vertical silos (commonly called hydrobins) instead of an SFC. This technology allows the existing wet bottom ash hopper, clinker grinders, sluice water piping, and ash sluice piping to remain in place. The high

- pressure ash sluice water pumps and moto rs generally will have to be replaced because of the significant change in system hydraulics due to the height of the hydrobin. Two hydrobins are normally used, one actively receiving ash sluice water and the other dewatering the ash. A hydrobin can receiv e ash from several generating units. The ash is stored in the hydrobin and discharged into a truck, a rail car, or a conveyor for disposal. Water decanted from the ash is collected in a surge bin and either pumped or returned by gravity to the generating u nits, thus creating a closed

- loop recirculating system. Water is needed to replenish the ash hopper due to losses from evaporation into the boiler and residual water carried over in the ash discharged from the hydrobin, as well as refractory cooling, ash h opper wall flushing, and boiler seal. One limitation on using a decant silo is limited power for new high

- pressure ash sluice water pumps and motors. Engineering challenges include the following:

 The site for the hydrobins near the ash sluice piping must h ave enough space for both truck access and surge tank installation.

 Foundation design requirements for hydrobins are extensive. Scheduling concerns are the following:

 The hydrobins and foundations, sumps, surge tanks, and water return piping can be install ed while the generating unit is operating. Constructing the site facilities can proceed in parallel with system fabrication and delivery.

 Manufacturing lead time is approximately one year for the hydrobins and surge tanks, including the support steel requi red for both.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 665 Comment Response: EPA has evaluated the information provided by the commenter regarding designing, constructing, and implementing dry or closed

- loop bottom ash handling systems, and the challenges and limitations of each technology discussed (dry bottom ash hopper, wet bottom ash hopper

– submerged flight conveyor, remote ash hopper

– submerged flight conveyor, and decant silos or hydrobins). EPA acknowledges the commenter’s recommendation that EPA should consider the detailed constr aints related to timing and engineering aspects of installing each of the systems. As described in Sections 7 and 9 of the TDD, EPA has gathered data regarding the technologies used in the industry from technology vendors and revised its costs estimates, i n response to comments received on the proposed rule. The vendors provided the following types of information for EPA’s analyses:

 The type of fly ash and bottom ash handling systems available for reducing and/or eliminating ash transport water;

 Equipment, modifications, and demolition required to convert wet sluicing fly ash and bottom ash handling systems to dry ash handling or closed

- loop recycle systems;

 Equipment that can be reused as part of the conversion from wet to dry handling or in a closed

- loop r ecycle system;

 Outage time required to install or convert to the different types of ash handling systems;

 Maintenance required for each type of system;

 Operating data for each type of system;

 Purchased equipment, other direct, and indirect capital costs for fly ash and bottom ash conversions;

 Specifications for the types of ash storage available (e.g., steel silos or concrete silos) for the different types of handling systems;

 Operating and maintenance cost for fly ash and bottom ash handling systems; and

 System energy requirements.
Section 8 of the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) con tains more information on EPA’s cost methodology for the BAT basis for bottom ash transport water.

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- 666 Comment Excerpt: Clyde Bergemann recently wrote to EPA expressing its surprise that EPA had neglected zero discharge systems that do not use water. Clyde Bergema nn explained the cost savings from a recent installation of its DRYCON system, which uses air pressure, rather than water, to convey bottom ash away from the boiler. [T]wo boiler Units in Florida with DRYCONTM conveyors under them came back on line in April and November of 2012 after less than 22 day outages to remove the entire wet ash systems. The two 650+ MW Units are now operating at full load with the added benefits in 2013 that:

 The use of water to operate the entire bottom ash and economizer ash hand ling systems has been totally eliminated.

 The power consumption to operate the bottom ash and economizer ash handling systems has been greatly reduced.

 The amount of unburned carbon in the ash, also referred to as loss

- on
- ignition, LOI, has been significan tly reduced as verified by field measurements.

 The bottom ash temperature is significantly reduced between the boiler throat opening and the end of the conveyor.

 The plant has experienced significantly reduced operating and maintenance costs.
We believe th is installation validates the many reasons why our DRYCONTM Dry Bottom Ash Conveyor should be added to the list of available and viable technologies for new and existing bottom ash handling systems. 473 Dry vacuum and pressure systems have additional cost savings. Since these systems use no water at all, the resulting ash is dry, which is more easily marketed. 474 If the ash is not sold, the landfill costs for dry ash are lower than the cost for wet ash. 475 Finally, dry vacuum and pressure systems have fe wer operating and maintenance problems because they do not use the metal chain systems used in mechanical and remote mechanical drag systems. 476

473 Letter from Gary Mooney, Clyde Bergemann, to EPA at 2 (June 26, 2013), Docket No. EPA

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474 Fox Report, Appendix E, at 27.

475 Id.

476 Id. at 27

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- 667 Comment Response: See the response to DCN EPA

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- A1, Excerpt Number 1 for more information on EPA’s response to Clyde Bergemann’s DRYCONTM system. EPA disagrees that it neglected to consider systems that do not use any water as the basis for possible bottom ash transport water discharge limitations. EPA reviewed various methods for eliminating bottom ash transport water discharges, including mechanical and remote mechani cal drag systems that use water as a quench bath only (not considered transport water) or use transport water but recycle it, and systems such as vacuum and pressure systems that use no water at all. EPA agrees that dry vacuum and pressure systems are viab le options for dry bottom ash handling. However, EPA selected the mechanical drag system and remote mechanical drag system based on information presented in the Steam Electric Survey and from technology vendors. See the response to DCN EPA

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- A1, Excerpt Number 102. In addition, after proposal, EPA updated the industry profile information based on known changes in the industry such as generating unit retirements or bottom ash handling conversions, for example. After these updates, EPA det ermined that 37 percent of the dry bottom ash handling systems are mechanical drag systems. Based on these data, and information provided by vendors, EPA selected the mechanical drag system as the bottom ash technology basis for BAT. Because EPA is aware o f the potential issues with space constraints underneath the boiler, a second technology option, the remote mechanical drag system, was incorporated into EPA’s compliance cost methodology. For more information about the final rule BAT for dry bottom ash ha ndling see preamble section VIII. EPA notes that plants are free to choose any technology or process they want to comply with the final rule requirements. Steam electric power plants are not required to use the specific technology basis used by EPA to esti mate costs of the final rule. EPA agrees that dry bottom ash may be more easily marketed, but notes that there is also a market for moisture conditioned bottom ash based on data reported in the Steam Electric Survey. Further, prior to landfilling the dry a sh, it must be moisture conditioned to control dust, which may have an impact on the ash disposal costs. EPA has not compared the operating and maintenance associated with dry vacuum and pressure systems to mechanical and remote mechanical drag systems. Th erefore, EPA cannot provide a response to this specific comment. However, EPA did determine that steam electric power plants can maintain the drag chains and avoid maintenance outages by performing regular maintenance (for example, replacing the links). EP A confirmed that this maintenance can be completed without the systems being drained.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 668 Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 13 External R eview Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Dry Systems The EPA identified two types of systems that handle the bottom ash without any water: (1) dry vacuum or pressure systems and (2) vibratory belt sys tems. While identified as viable technologies by EPA, none was evaluated for this rulemaking even though 39% (118 units) of the zero discharge systems operating in the United States are dry. 78 Fed. Reg. at 34,454. Dry Vacuum or Pressure System (PAX, MAC, DRYCON) Dry vacuum or pressure bottom ash handling systems transport bottom ash from the bottom of the boiler into a dry hopper without using any water. Air percolates into the hopper to cool the ash and combust unburned carbon, improving boiler efficienc y. The ash is periodically dumped into a crusher and then conveyed by vacuum or pressure to an intermediate storage facility. The distinguishing characteristics of these technologies, relative to wet sluicing, are:

 No water

 Reduces carbon in bottom ash, im proving boiler efficiency

 Enhances potential sale of dry, low carbon ash

 Returns heat back to boiler, improving efficiency

 Reduces maintenance

 Reduced power consumption

 Can service multiple boilers

 Requires sufficient space/height directly under boiler hopper(s)

 Requires 20 to 30 day outage In the United Conveyor Corp.'s Pneumatic Ash Extractor (PAX TM ), bottom ash is collected in refractory

- lined hoppers under the boiler. Percolating air promotes combustion of unburned carbon, which releases additional thermal energy, cools the ash, and protects ancillary equipment from high ash temperatures. At the appropriate time, grid doors at the hopper bottom open to allow ash and clinkers to pass into a crusher and are fed to the vacuum system for transport to the dry storage silo or ash transfer truck. 22 These systems are rare due to high temperatures at the boiler exit and large size of bottom ash particles. A competing vendor, Clyde Bergemann, has noted that these systems are not suitable for many units due to ash temperature concerns. 23 The Magaldi Ash Cooler (MAC TM ) consists of an extractor, crusher, post cooler, and silo. The extractor is connected to the boiler throat through a refractory

- lined hopper or transition chute. Bottom ash falls onto a Superbelt en closed inside the sealed casing of the extractor. Ash isEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 669 cooled by a small, controlled amount of ambient air that flows by the furnace negative pressure, i.e., by natural draft. This reduces unburned carbon, releasing additional thermal energy. Cooled as h is discharged into a crusher and conveyed to a silo, either through a mechanical or pneumatic conveyor. The MAC (and its knockoffs) is the world's most widely used dry bottom ash handling system for utility and industrial boilers of any size, burning any kind of fuel with hundreds of installations worldwide, including in the United States (i.e., the Crystal River Unit 2 and Dry Fork Unit 2). 24
DRYCON TM (DRY ash CONveyor) is Clyde Bergemann's dry bottom ash handling system and is a relatively new entrant i nto the bottom ash handling arena. The DRYCON system is sealed to the bottom of the boiler. It is a continuous plate conveyor system that uses air rather than water cooling. Ash drops onto the continuous plate conveyor system, and negative pressure inside the boiler sucks air into the DRYCON system. This air moves countercurrent to the ash along its surface, burning carbon on the ash. This reduces unburned carbon, releasing additional thermal energy. The fine ash is sucked with the air back into the boile r and discharged as flyash. 25 The first U.S. DRYCON system, installed on two 650 MW units at Seminole Generating, went on line in 2012. Vibratory Belt System (VAX) These systems feed bottom ash by gravity from the bottom of the boiler directly to a vibra tory conveyor trough supported by coil springs. This reduces the stress of falling bottom ash. Forced air enters through the vibratory conveyor deck to cool, suspend, and oxidize unburned carbon. TDD, Sec. 7.3.5. The distinguishing characteristics of these technologies are:

 No water

 Lowest power consumption

 No moving or hinged joints, decreasing maintenance & unscheduled outages

 Returns heat back to boiler, improving efficiency

 Continuous removal of bottom ash This is UCC's most recent dry ash handling tech nology. It uses vibrating conveyors to continuously remove ash from under the boiler. Cooling air is forced up from under the vibrating deck, combusting any unburned bottom ash. The vibrating conveyor deck creates a fluidized bed of ash. 26 I am not awar e of an installation of this specific technology in the U.S. However, vibratory conveying technology has proven itself in extreme temperature, abrasive, heavy

- duty applications for over 50 years in other industries, where there are more than 1,000 installa tions in over 35 countries. There are multiple mass burn bottom ash installations using similar vibratory conveying that have been in operation for over 30 years and running continuously for over 7 years. 27

22 United Conveyor Corp., “PAX Pneumatic Ash Extr actor;” Available at: http://unitedconveyor.com/PAX/.

23 See “Email from Gary Mooney,” supra note 16, pp. 2, 5.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 670 24 “Magaldi Solutions for Ash Handling;” Available at: http://www.magaldi.com/en/magaldi_solutions_for/Ash

- Handling

- Mac 9_11.php.

25 See “Clyde Bergemann, Materials Handling,” supra note 12; Jeff Hudson, Rafael Moreno Rueda, and Craig Fleming, “DRYCON Dry Bottom Ash Removal, ” Power

- Gen International, 2009.

26 United Conveyor Corp., “Wet

- To

- Dry Conversion, Bottom Ash & Fly Ash Systems;” Available at: http://unitedconveyor.com/uploadedFi les/Systems/UCC_Wet

- To

Dry_Brochure.pdf.

27 See: UCC, FAW "Is the vibratory technology proven and reliable?" Available at: http://unitedconveyor.com/vax/; and See “Wet

- To

- Dry Conversion”, supra note 26.
Com ment Response: See the response to DCN EPA

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Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 17 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Many Dry Systems Are Successfully Operating The EPA indicates that 111 dry v acuum systems have been installed at 66 plants and 13 dry pressure systems at 13 units in 11 plants in the U.S. 78 Fed. Reg. at 34,454. The first U.S. dry bottom ash system was a Magaldi MACTM, retrofit on the 500 MW Crystal River Unit #2 in December 1993. 45 It is still operating.

45 Barsin, supra note 31. Comment Response: After proposal, EPA updated the industry profile information based on known changes in the industry (for example, generating unit retirements, bottom ash handling conversions). After these updates, EPA determined that 35 percent of the coal

- and petroluem coke

- fired generating units operate dry vacuum or dry pressure systems for handling bottom ash. EPA disagrees that the first dry bottom ash handling system was a Magaldi MACTM. EPA con firmed with technologyEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 671 vendors that many of the older, industrial generating units utilize dry pneumatic conveyance and that in the last 25 years no new U.S. steam electric power plants with pulverized coal boilers have been built with either pneumatic or vibratory technology (DCN SE01825A80).

Commenter Name: Thomas Cmar Commenter Affiliation: Earthjustice, et al. Document Control Number: EPA

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- A1 Comment Excerpt Number: 23 External Review Flag: Economics/Benefits External Review In corporated into Response: No Comment Excerpt: Dry Systems Save Energy
In coal

- fired boilers, a significant amount of energy crosses the boiler throat as radiation from furnace flames, sensible heat of the bottom ash, and energy contained in unburned carb on on the bottom ash. In a system that uses water to quench the ash, such as the two mechanical drag systems evaluated by EPA, this energy is completely lost when the ash is quenched. The heat is used to evaporate the water, which leaves the system with th e exhaust gases. Further, unburned carbon on the bottom ash leaves with the ash. Wet quenching and transport, thus, reduce boiler efficiency, requiring that more coal be burned to make a unit of electricity. This increases the associated emissions (CO2, NO x, SO2, etc.) and O&M costs. In systems that use air for cooling (e.g., MAC, PAX, VAX, DRYCON 53 ), about 70% to 80% of this otherwise lost heat is returned to the boiler with the cooling air, improving its efficiency by 0.15% to 0.7% 54 (See Tables 3

- 4). Im proved boiler efficiency means less coal to produce the same amount of electricity, reducing emissions of CO2 and other pollutants emitted into the air. Coal is the major operating cost of a coal

- fired power plant. Less energy is also required to operate the pulverizers and other electrical equipment, reducing the auxiliary power demand of the station. United Conveyor explained to EPA that "[t]his added efficiency makes completely dry technologies generally more cost

- effective than SFC systems [evaluated b y EPA] in the long

- term, although the payback period may be several years." 55

53 MAC = Magaldi Ash Conveyor; PAX = UCC Pneumatic Ash Extractor; VAX = Vibratory Ash Extractor, DRYCON = Clyde Bergemann dry conveyor system.

54 Alan Bullock, Ash handling: Why Dry Bottoms Are Better Than Wet Bottoms, Power Engineering, Intl. (Jan. 5, 2010); Vicenzo Cianci, Dry Ash Collection at Coal Fired Power Plants and Potential For WTE Facilities, 15th North American Waste to Energy Conference (2007), p. 51 (0.196% at 314

- MW units in Portugal); F. Bassetti and others, “Coal Plants Generation Cost Reduction, Post

- Combustion of Carbon Residues from Co

- Firing of Biomass and RDF During Dry Ash Removal;” Available at: http://pennwell.websds.net/2013/vienna/pge/papers/T4S4O4

- paper.pdf; Quattrucci et al., p. 17 (0.25% at 552 MW Los Barrios); Elisabetta Carrea and others,Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 672 “Dry Bottom Ash Removal

– Ash Cooling vs. Boiler Efficiency Effects,” Docket No . EPA

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- 0417, 1998, International Joint Power Generation Conference, FACT

- Vol. 22, 1998, pp. 501

- 505 (0.29%

- 0.72% based on field test at 500 MW MAC

- equipped Monfalcone Unit #2); See ERG Memorandum, supra note 36, p. 6 (0.15%

- 0.5%); E. Car rea and M. Graziadio, “Bottom Ash Carbon Content Reduction by Means of MAC Dry Extraction System,” Docket No. EPA

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- 0413, A Thermie Project, (full scale tests demonstration 0.7%); See Magaldi Solutions for Ash Handling, supra note 24, (0.1%

- 0.6%).

55 See Memorandum from Kurt Blohm and Sarah Holman, supra note 36, p. 7. Comment Response: EPA agrees with the commenter that dry bottom ash handling systems can save energy, resulting in reduced coal consumption and reduced emissions of CO 2 . See the response to DCN EPA

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- 673 17. Combined Ash Transport Water

– Wastewater Characterization
Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 134 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: For some Southern plants, EPA misc alculated fly ash transport water and bottom ash transport water flow rates. EPA appears to have used the total ash pond influent flow rate, rather than the bottom ash and fly ash sluice rates. Since other types of wastewaters such as stormwater, coal pile runoff, and low volume wastes are also directed to the ash ponds, use of the influent flow rate as the equivalent of the ash sluice flow rate overstates the ash sluice rates. Overstating the flow rates means that EPA also overstated the pollutant loadings attributable to these wastewaters. EPA appears to have made this mistake for a number of facilities within the industry, thereby rendering its industry pollutant loading analysis invalid.

..... EPA’s TWPE Removals for Southern Company Plants Need to Be Re vised At our request, EPA provided a CD 64 to Southern, containing site

- specific information for each Southern plant, including flow rates and associated pollutant loadings. EPA used this information in its pollutant loadings analysis of the industry. South ern reviewed the information for each of its plants and determined that, in some cases, EPA used the wrong flow rates for fly ash and bottom ash transport water to calculate pollutant loadings (TWPEs). This section provides a summary of EPA’s methodology u sed to determine flow rates for each plant, and Southern’s corrections to EPA’s fly ash and bottom ash sluice flow rates for its plants. EPA used data from the 2010 ICR to identify plants that wet sluice fly ash and bottom ash and to calculate pounds of p ollutants and TWPE discharged from fly ash and bottom ash transport water. EPA determined the ash transport water flow rates by identifying all surface impoundments that receive ash transport water and discharge to surface water. EPA then labeled them as e ither bottom ash only, fly ash only, or combined ash ponds using ICR responses in Part D, Table D

- 3. If the pond discharged 100% of the influent, EPA chose the flow rate for ash transport water discharged based on responses from the ICR using the following hierarchy:
1. Influent flow rates in Part D (Table D

- 3), 2. Sluice flow rates in Part C (Tables C

- 3 and C

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- 674 For ponds that do not discharge all of the influent ( i.e., recycle part of it), EPA used information from Part A, C, and D of the 2010 ICR in addition to the water balance diagrams submitted with the ICRs to determine the percentage of ash transport water discharged to surface waters.
EPA normalized the flow rate s to have all plants on the same basis of discharging over 365 days. For example, EPA multiplied the flow rate in gallons per day times the number of days of generation divided by 365 days. Southern’s responses to Part C, Tables C

- 3 and C

- 19, are the most accurate flow rates for the fly ash and bottom ash conveyance systems. Part D, Table D

- 3, asked for influent flow rates to the surface impoundment. These flow rates are not representative for Southern plants because the ash pond’s influent may contain othe r flows, such as stormwater, low volume waste, or coal pile runoff. EPA did not ask a question in the ICR related to recycling of the surface impoundment water. This was an oversight on EPA’s part because some of Southern’s plants recycle ash pond water fo r fly ash and bottom ash sluicing. Instead, EPA had to estimate the recycle rate based on responses from Parts A, C and D, including the water balance diagram. In some cases, the recycle rated calculated by EPA is not correct. EPA should make every effort to obtain accurate flow rates for each plant that discharges fly ash and bottom ash transport water to surface waters. For some plants, EPA has overestimated the flow rates and therefore overestimated the pollutant loadings and TWPEs for these wastestream s. Accurate flow rate estimates must be used by EPA to calculate TWPEs for the industry. As stated earlier, EPA must reevaluate the cost

- effectiveness of the proposed BAT for fly ash and bottom ash transport water by using correct flow rates, taking into a ccount recycle rates where appropriate, and using more accurate and up

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- date characterization data.

64 EPA letter and disc from Jezebele Alicea Virella to Donna B. Hill, Confidential Business Information , July 31, 2013. Comment Response: Flow rates for Southern plants. The commenter states that EPA did not use the appropriate flow rates for Southern’s plants during the cost and loading analyses. They believe that EPA’s use of flow rate data from responses to Part D of the Steam Electric Survey (rather than use of flow rate data from Part C) resulted in increased flow estimates for Southern’s plants. EPA used the surface impoundment influent flow rate data from responses to Part D of the survey to determine the amount of ash transport water discharged fr om each surface impoundment, accounting also for recycle flows (discussed below). EPA notes that it specifically used only influent flow rates designated in the survey response as “fly ash sluice,” “bottom ash sluice,” or “combined ash sluice.” EPA did not use the total influent flow rate to the surface impoundment (i.e., EPA used the influent flow rate of ash transport water, excluding flows from other sources, such as stormwater and low volume waste). EPA determined that this method is most representative of the ash transport water discharge flow rate. EPA prioritized the Part DEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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- 675 influent for the ash sluice flow rate because it represents the flow from the wet sluicing system(s) to the surface impoundment (to ultimately be discharged). This flow rate specif ically accounts for any water recycle back to the wet sluicing system(s) prior to being directed to the surface impoundment, or water loss due to evaporation. Further, this flow rate represents the total ash transport flow entering the pond at the plant le vel, as some units might share some components of a wet sluicing system. This approach avoids double counting flows provided in response to Part C of the survey if some plants repeated the sluice flows for each generating unit. The commenter does not expl ain why the ash sluice flow rates they provided in response to Part C of the survey differ from the ash sluice flow rate entering the impoundment. The Part D flows were specifically reported as “fly ash sluice,” bottom ash sluice,” or “combined ash sluice” and, therefore, should not have included any other sources of wastewater (e.g., stormwater). Regardless, EPA acknowledges that Southern believes the Part C flow rates to be the more representative discharge flow rates for their plants. EPA, however, did n ot adjust the flow rates for Southern’s plants in the final rule, partly because Southern indicates this change is only “in some cases,” but does not elaborate on the specific cases. Because it is unclear why two different values are provided and for which plants Southern believes the Part C data should be used, EPA retained the use of the Part D flow rates for all Southern plants. As a bounding exercise, EPA did evaluate the effect of using Part C versus Part D flow rates for all of Southern’s plants on th e overall industry pollutant loads associated with fly ash transport water and bottom ash transport water. Overall, EPA found that, at most, the bottom ash transport water loadings in TWPE would be reduced by 2 percent and the fly ash transport water load ings in TWPE would be reduced by 5 percent. Recycle rate. The commenter contends that there was an oversight in the Steam Electric Survey related to recycling of surface impoundment water. EPA disagrees with the assertion that the survey did not account for or collect information on surface impoundment recycle water. EPA requested recycle rate data in Parts C and D of the Steam Electric Survey and in the water balance diagram. EPA accounted for recycle flows from each surface impoundment by subtracting t he reported 2009 recycle flow rate from the influent flow rate, but only when the recycle flow is directed back to the ash transport system or to a non

- discharging process. Up

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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 32 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 676 Comment Excerpt: The following table sets forth the sources for the 55 data sets of combined fly ash and bottom ash pond discharge data:

EPA calculated average pollutant concentrations from the 55 data sets for combined ash discharges. EPA says it used flow rates from its Questionnaire for the Steam Electric Power Generating Effluent Guidelines, EPA

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- 0655 (including attachme nts 1 through 9) (the 2010 ICR), also available at http://water.epa.gov/scitech/wastetech/guide/steam

electric/questionnaire.cfm , for both fly ash transport water and bottom ash transport water 5 and calculated total TWPEs for combined ash ponds. Next EPA estimated the contribution of bottom ash transport water and fly ash transport water to the combined ash pond TWPEs: ...EPA separated the loadings for combined ash impoundments into fly ash loadings and bottom ash loadings. To do this, EPA used data from the EPRI PISCES reports to estimate the breakout of the loadings among fly ash and bottom ash contributions. The PISCES reports include information from several pl ants operating impoundments receiving either fly ash or bottom ash transport water. The reports include a table presenting loadings associated with each stream entering the impoundment for several metal pollutants. EPA used the fly ash and bottom ash loa dings presented in the reports to calculate a site

- specific percent loading for fly ash and bottom ash for each pollutant. EPA then calculated an average percent loading for fly ash and bottom ash using data from all available pollutants. EPA determined that, on average, pollutant contributions from fly ash account for 86 percent of combined ash loadings, with bottom ash contributing only 14 percent. Therefore, EPA assumed fly ash and bottom ash account for 86 and 14 percent, respectively, of all combine d ash loadings[.] [F]or those pollutants for which a specific value could not be calculated using the EPRI data, EPA then used these percentages to break out the combined ash loadings into associated fly ash and bottom ash loadings.
2013 TDD at 10

- 26 to 10

- 27. 1 982 TDD, Table V

- 32 11 plants. EPA used data compiled by various EPA

regional offices for ash pond overflows with TSS less than 30 mg/L. 1982 TDD, Table V

- 33 20 plants. EPA used summary DMR data provided by

various EPA regional offices for combined ash discharges. 1982 TDD, Table V

- 34 10 plants. EPA used summary TVA data (averages)

collected quarterly from 1973 to 1975 for combined ash discharges. Form 2C Database 7 outfalls EPRI PISCES Sites A

- G 7 plants. EPRI collected samples at the combined ash

discharge outfall for each of these plants during the 1990s.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 677 To calculate industrywide TWPEs for bottom ash alone, EPA calculated TWPEs for the “true” bottom ash transport water ponds and then added the percent of TWPEs from the combined ash ponds attributable to bottom ash transport water according to EPA’s ca lculations. EPA erred by using data from combined fly ash and bottom ash ponds to characterize pollutants in fly ash and bottom ash transport water separately. It is well recognized in the industry that these two wastestreams are not similar. EPA should have collected adequate samples of the separate fly ash and bottom ash transport water wastestreams and used only those data to characterize the two very different wastestreams. EPA’s methods for splitting up the pollutant contributions between fly ash a nd bottom ash from a combined ash pond are not scientifically or technically defensible or well

- documented. The manipulation of data from combined ash discharges was unnecessary and most probably led to inaccurate bottom ash estimates of TWPE.
In particular, EPA does not explain how it used EPRI’s PISCES data to develop a ratio between fly ash and bottom ash contributions. What table from the PISCES reports did EPA use? Where in the record are the plant

- specific loadings that EPA calculated for t he PISCES combined ash ponds? Without more information, UWAG cannot comment fully on EPA’s TWPE calculations for bottom ash, fly ash, and combined ash discharges.

5 “Incremental Costs and Pollutant Removals for the Proposed Effluent Limitations Guidelin es and Standards for the Steam Electric Power Generating Point Source Category” (IC&PR), EPA

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- 2256 at 4

- 4. Comment Response: EPA disagrees that it “erred by using data from combined fly ash and bottom ash ponds to characterize pollutants i n fly ash and bottom ash transport water separately.” See the comment response to DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d and DCN EPA

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- A1, Excerpt Number 72 in comment code 15.d regarding EPA’s rationale for the inclusion of combined ash data in the characterization dataset. In addition, see the comment responses to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b and DCN EPA

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- 4499

- A1, Excerpt Number 72 in comment code 15. d, regarding EPA’s ash characterization data for the final rule, including the use of combined fly ash and bottom ash data, and the methodology used to separate loadings for combined ash impoundments into fly ash loadings and bottom ash loadings.

Comment er Name: Elizabeth E. Aldridge, Hunton & Williams Commenter Affiliation: UWAG Document Control Number: EPA

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- 4655 Comment Excerpt Number: 63 External Review Flag: No External Review External Review Incorporated into Response: NoEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 678 Comment E xcerpt: EPA erroneously used combined fly ash and bottom ash pond data, mostly from the 1982 Development Document, to estimate TWPEs associated with bottom ash transport water in the combined ash discharges. Comment Response: See response to DCN EPA

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- 4655, Excerpt Number 32 regarding EPA’s use of combined fly ash and bottom ash pond data. In addition, see the responses to DCN EPA

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- 4655, Excerpt Number 38 in Comment Code 4.b and DCN EPA

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- A1, Excerpt Numbe r 72 in comment code 15.d for a discussion of how EPA used the 1982 TDD data to determine pollutants of concern and ash impoundment discharge loads.

Commenter Name: W. Creal Commenter Affiliation: Michigan Department of Environmental Quality Document C ontrol Number: EPA

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- 5510

- A2 Comment Excerpt Number: 6 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: Michigan does not believe that the potential for pollutants to be discharged i n bottom ash wastewater was sufficiently evaluated. The methods of data collection and wastewater characterization did not appear to isolate the discharge of bottom ash wastewaters from other settling basin wastewaters. Since settling basins are typically used to treat fly ash and low volume wastestreams in addition to bottom ash wastewaters and may also include historical contamination, discharges from many of these basins may not be appropriate to characterize bottom ash wastewaters. It appears that in the limited data set USEPA used, only one facility provided data specific to bottom ash wastewater and that data demonstrated a negligible pollutant concentration from this wastestream. Michigan believes that before the USEPA can determine whether the lev el of pollutant reduction actually achieved by adopting the proposed standard is worth the cost of implementing it, the USEPA should more fully characterize the wastewaters associated with bottom ash systems. Comment Response: The dataset that EPA analyz ed for ash characterization when developing the final rule includes data submitted during public comments and other industry

- submitted data, as well as data from previous rulemakings. See responses to DCN EPA

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- A1, Excerpt Number 24 in C omment Code 4.b DCN EPA

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- A1, Excerpt Number 72 in comment code 15.d, and DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d regarding EPA’s ash characterization data, including the use of combinedEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 679 fly ash and bottom as h data and the use of Form 2C data. See also the response to DCN EPA

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- 4460

- A1, Excerpt Number 50 in Comment Code 6.a regarding EPA’s identification of pollutants of concern in ash transport water. Also see response to DCN EPA

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- A1, Excerpt Number 14 in Comment Code 15.d regarding “one facility’s data.”

Commenter Name: Kim Mireles Commenter Affiliation: Luminant Document Control Number: EPA

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- 4614

- A1 Comment Excerpt Number: 12 External Review Flag: No Ext ernal Review External Review Incorporated into Response: No Comment Excerpt: EPA used data fram combined bottom ash and fly ash streams to characterize bottom ash transport water. In order to use the data sets from combined ash ponds, EPA had to allocate pollutants between fly ash and bottom ash to calculate the cost of removing a toxic

- weighted pound

- equivalent from the bottom ash transport water. EPA used the Electric Power Research Institute (EPRI) PISCES data base to allocate pollutants between fly a sh and bottom ash, but EPA does not explain their methodology. Whatever method EPA used to divide pollutants between fly ash and bottom ash, it is not likely to be representative because most of the combined ash data (41 plants) were from the 1982 TOO and the operation of ash ponds has changed dramatically since 1982. The quality of ash pond discharges was changed by the Best Practicable Control Technology Currently Available (BPT) standards set by the 1974 and 1982 regulations. Comment Response:
See the comment response to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b and DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d regarding EPA’s ash characterization data, including the use of combined fly ash and bottom ash data, and the approach used to separate loadings for combined ash impoundments into fly ash loadings and bottom ash loadings. See also the responses to DCN EPA

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- 4655, Excerpt Number 38 in Comment Code 4.b and DCN EPA

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- A1, Excerpt Number 72 in comment code 15.d for a discussion of EPA’s use of the 1982 TDD data.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 680 Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- 4305

- A3 Comment Excerpt Number: 23 External Rev iew Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: The revised analysis should, at a minimum:

 Reevaluate the inappropriate use of transport water data from combined ash systems, since the characteristics of fly a sh transport water are different than the characteristics for bottom ash transport water and facilities manage these wastestreams differently (i.e. handling of pyrites). Comment Response: See the comment response to DCN EPA

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- A3, Excer pt Number 73.

Commenter Name: Cari Boyce Commenter Affiliation: Duke Energy Document Control Number: EPA

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- A3 Comment Excerpt Number: 73 External Review Flag: No External Review External Review Incorporated into Response: No
Commen t Excerpt: Because EPA considered regulatory options that would establish different effluent requirements for fly ash and bottom ash, EPA separated the loadings from combined ash impoundments and assumed fly ash and bottom ash account for 86 and 14 perce nt, respectively, for all combined ash loadings. This assumption, however, is not appropriate for determining the pollutant loading solely from solely from bottom ash sluice water. Facilities manage ash differently, which could affect the concentrations in the ash transport water. For example, the sulfide concentration in the effluent, which was the largest contributor to EPA’s TWPE calculation, is greatly influenced by how a facility handles its iron pyrites. Comment Response: EPA agrees that the concent rations in the ash transport water can be affected by the method in which plants manage their ash. Based on data collected in the Steam Electric Survey, over 200 plants reported generating mill rejects and the majority report that those mill rejects are py ritic. In addition, most of these plants dispose of the pyritic mill rejects in a pond, most oftenEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 681 disposing of them in bottom ash ponds and combined ash ponds, and rarely in fly ash ponds. Therefore, it is reasonable to assume that the presence of pyrites is not atypical, and is appropriate to include in the ash baseline discharge characterization dataset. However, for the reasons explained in EPA’s response to DCN

- EPA

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- A1, Excerpt Number 14 in Comment Code 6.a, EPA did not include load ings estimates for sulfide in the final rule for ash transport water. See the comment response to DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d regarding the inclusion of combined ash data in the characterization dataset. In addition , see the responses to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b and DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d regarding EPA’s ash characterization data, including the use of combined fly ash and b ottom ash data, and the methodology used to separate loadings for combined ash impoundments into fly ash loadings and bottom ash loadings. EPA did not assume that “fly ash and bottom ash account for 86 and 14 percent, respectively, for all combined ash loa dings.” See response to DCN EPA

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- A1, Excerpt Number 27.

Commenter Name: Chris M. Hobson Commenter Affiliation: Southern Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 27 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt: EPA also calculated TWPEs from combined ponds based on their average concentrations and then estimated that 14% of that TWPE was due to bottom ash in the combined ponds. T he industry estimate, in contrast, did not use the concentrations and resulting loadings from the combined ash ponds. The concentrations in the combined ash ponds were inflated due to fly ash and possibly other wastewater operations going into the combined ponds. UWAG therefore assumed that 14% of the flow from the combined ponds was due to bottom ash (similar to EPA’s assumption) but assigned TWPEs based on average concentrations derived from bottom ash ponds only. Since EPA reported a 262 MGD industry

- wid e flow for combined ash ponds (Technical Development Document, EPA

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- 2257(2013 TDD), p. 10

- 28), 14% of that would be 36.7 MGD. The 36.7 MGD would increase EPA’s reported daily flow for bottom ash ponds from 327 to 363.7 MGD. The increased flo w factor for bottom ash ponds when incorporating bottom ash in combined ponds would be 363.7/327, a factor of 1.112. Therefore, the TWPE value obtained from the bottom ash pond data alone was increased by this factor.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 682 Comment Response:
The commenter mischaracterizes EPA’s approach to calculate pollutant loads using combined ash pond data. EPA did not estimate that 14% of the loadings in TWPE from a combined ash pond was due to bottom ash, nor did EPA assume that 14% of the flow from combined ponds was due to bottom ash. Therefore, the calculations presented by the commenter are not relevant to the final rule. As discussed in the response to DCN EPA

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- A1, Excerpt Number 24, as well as in the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (Cost & Loads Report) (DCN SE05831/SE05832) , EPA performed a plant

- specific and pollutant

spe cific estimate of pollutant loads associated with combined ash ponds, using the combined ash effluent dataset presented in Section 10 of the TDD along with the plant’s specific combined ash flow rate. For each pollutant, EPA estimated a percentage of that pollutant’s loadings that are attributed to bottom ash transport water versus fly ash transport water. These percentages varied by pollutant. For pollutants in which EPA lacked specific data, EPA assigned an average percentage of 14% of the loading associ ated with bottom ash transport water and 86% of the loading associated with fly ash transport water. See also the comment response to DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d regarding EPA’s the inclusion of combined ash data in the characterization dataset.

Commenter Name: Ron Shipman Commenter Affiliation: Georgia Power Company Document Control Number: EPA

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- A1 Comment Excerpt Number: 16 External Review Flag: No External Review External Review Incorpora ted into Response: No Comment Excerpt: Any analysis that combines bottom ash transport water with fly ash transport water is not a valid analysis of bottom ash transport water. The pollutants in bottom ash transport water and fly ash transport water are not at all comparable. Comment Response: See the comment response to DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d regarding the inclusion of combined ash data in the characterization dataset. In addition, see the responses to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b regarding EPA’s expanded ash characterization data, including the use ofEffluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 683 combined fly ash and bottom ash data, and the approach used to separate loadings for combined ash impoundments into fly ash loadings and bottom ash loadings.

Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 74 External Review Flag: No External Revi ew External Review Incorporated into Response: No Comment Excerpt: EPA’s approach to calculating bottom ash pollutant reductions included Combined Ash pond parameter concentrations. EPA’s methodology states that a ratio of 86% fly ash to 14% bottom ash ( by volume) was applied to Combined Ash pond loadings. This ratio was based on data from various PISCES sites. EPA stated that this ratio was also applied to pollutants for which data were unavailable [EPA, 2013c]. EPRI disagrees with EPA’s logic that the s ame 86/14 percent split between fly ash and bottom ash can be applied to all trace metals measured in the sluice water, because partitioning of the source between fly ash and bottom ash differs among trace metals. Further, like Bottom Ash Only pond data, C ombined Ash pond data have several parameters that apparently are overestimated due to the use of non

- detect data. Comment Response: EPA determined that the data from various PISCES sites represents the best available data to reasonably estimate fly ash and bottom ash transport water pollutant loads associated with combined ash systems. EPA notes that commenters have not provided any additional data for use in estimating such loads. EPA acknowledges that portioning between fly ash and bottom ash may vary depending on various characteristics; however, the commenter did not provide data to demonstrate that the ratio used is inappropriate, nor did it suggest alternate methodology. Therefore, for the final rule, EPA retained its approach for estimating pollut ant loads associated with combined ash systems. See the comment response to DCN EPA

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- 4655, Excerpt Number 71 in Comment Code 13.d regarding the inclusion of combined ash data in the characterization dataset. In addition, see the comment response to DCN EPA

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- A1, Excerpt Number 24 in Comment Code 4.b regarding EPA’s ash characterization data, including the use of combined fly ash and bottom ash data, and the approach used to separate loadings for combined ash impoundment s into fly ash loadings and bottom ash loadings. See the response to DCN EPA

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- 4655, Excerpt Number 38 in Comment Code 4.b and DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d for a discussion of the effect of detection limits on EPA’s ash transport water loadings analyses.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 684 Commenter Name: Paul Chu Commenter Affiliation: Electric Power Research Institute (EPRI) Document Control Number: EPA

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- A1 Comment Excerpt Number: 78 External Review Flag: No External Review External Review Incorporated into Response: No Comment Excerpt:
7.2.3 Other non
- detects: Use of the method detection limit overestimates the pollutant reduction in EPA’s calculations. In contrast to EPA’s method, EPRI treated all non

- dete ct values in its data set as one

- half of the method detection limit. EPRI did not use any parameters that had only non

- detects reported in EPRI’s data set for that parameter. In addition to sulfide, other non

- detect values for various pollutants may be dri ving EPA’s pollutant reduction calculation higher than EPRI’s. According to the ERG memo appendix to the Steam Electric Rulemaking Record [ERG, 2013], pollutants such as silver, thallium, and tin contribute about 12% of EPA’s estimated pollutant reduction (in TWPE per year) when combined. Nearly all of the data for these pollutants are non
- detect values. As shown in Table 7

- 8, for Bottom Ash Only ponds, the majority of data points were non

- detects. The small data set had non

- detects in 3 of 5 silver s amples, 4 of 5 thallium samples, and 3 of 4 tin samples.
Some of the non

- detects were reported at concentrations much higher than any detected values, so EPA’s use of the detection limit increased the average significantly. An example is two silver non
- det ects reported by EPA as < 0.01 mg/L, while the only detected values (two) were 0.0001 mg/L and 0.00025 mg/L, or 40 to 100 times lower than the value used by EPA. For Combined Ash ponds, 26 of 32 data points for silver were non

- detects, 12 of 25 for thalliu m were non
detects, and 17 of 18 for tin were non

- detects. Therefore, pollutant reductions for each metal would be reduced by 48%, 50%, and 49%, respectively, if the non

- detects were treated as one

half of the reported value.
EPRI also notes that EPA’s r ecent sample values are typically an order of magnitude lower than earlier averages derived from the Form 2C data.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 685Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 686 The effect of how these, and other, non

- detect values are used in EPA’s estimate is shown in Table 7

- 9. In contrast to EPA’s method, EPR I treated all non

- detect values in its data set as one

half of the method detection limit. Further, EPRI did not use any parameters that had only non

detects reported in the EPRI data set.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

6

- 687 Comment Response: See response to DCN EPA

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- A1, Excerpt Number 72 in Comment Code 15.d. For the reasons explained in EPA’s response to DCN

- EPA

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- A1, Excerpt Number 14 in Comment Code 6.a, EPA did not include loadings estimates for sulfide in the final rule for ash transport water.