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 10
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EPA’s Response to Public Comments

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11. FGD Vapor-Compression Evaporation System 

Commenter Name: Paul Ling

Commenter Affiliation: Kansas City Power & Light Company

Document Control Number: EPA-HQ-OW-2009-0819-5406-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 

Discharge (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 wastewater.

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 wastewater 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. Given 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 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 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.

The commenter does not support proposed Option 5 (equivalent to Option F in the final rule) 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 evaporation system, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 108, in Comment Code 11.a and DCN EPA-HQ-
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EPA’s Response to Public Comments

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OW-2009-0819-4655, Excerpt Number 119, in Comment Code 11.a. Additionally, regarding the 

experience at the Iatan plant, EPA notes that the plant 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. Additionally, 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, at 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 existing 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 with 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 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 disagrees with the commenter that the technology 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 response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108).

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 25

External Review Flag: No External Review

External Review Incorporated into Response: No
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EPA’s Response to Public Comments

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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 total 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 the 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 synonymous 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 EPA-HQ-OW-2009-0819-5406-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 VIII.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 discussion 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-HQ-OW-2009-0819-5406-A2, Excerpt Number 10.

EPA does not agree with the commenter that EPA has underestimated 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 63
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EPA’s Response to Public Comments

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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.” [EPA, 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 precipitation 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 daily 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 biological 

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 for nitrate/nitrite [EPA, 2012].
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EPA’s Response to Public Comments

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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 voluntary 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 prior 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 commenter 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 achieve 

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 nitrate/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-HQ-OW-2009-0819-4460-A1

Comment Excerpt Number: 47

External Review 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 

associated with implementing thermal ZLD technologies within the industry. See UWAG 
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EPA’s Response to Public Comments

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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 basis 

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, and 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 would 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 generated 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-HQ-OW-2009-0819-5406-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 Section 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-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-effectiveness 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-HQ-OW-2009-0819-4655, 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

Commenter Affiliation: Owensboro Municipal Utilities (OMU) Elmer Smith Station (ESS)
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EPA’s Response to Public Comments

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Document Control Number: EPA-HQ-OW-2009-0819-4683-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 Response: 

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 that 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 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 would 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 generated 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-HQ-OW-2009-0819-5406-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 VIII.C.13 for more detail).

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.

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 is, 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-HQ-OW-2009-0819-4655, Excerpt 

Number 27 in Comment Code 6.h.

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. 
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6-8

However, the final rule establishes differentiated requirements for certain discharges from 

existing 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 generating unit size for the 

reasons explained in preamble section VIII.D.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 28

External Review Flag: No External Review

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 Record’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 Environmental Protection Agency (USEPA). 2000. Cost-Effectiveness Analysis of 

Proposed Effluent Limitations Guidelines and Standards for the Metal Products and Machinery 

Industry. EPA-821-B-00-007. 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 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.
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See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 47 and DCN EPAHQ-OW-2009-0819-4683-A2, Excerpt Number 10.

Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-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 wastewater. 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 its 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 includes 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 (which 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 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.
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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-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4305-A3, Excerpt Number 

45, and regarding operational “challenges,” see response to DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 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 DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-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. vapor 

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 discharge 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 disagrees with the commenter’s apparent equating of evaporation with “zero liquid 

discharge technologies.” The technology basis for control of FGD wastewater discharges under 
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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 would 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 generated 

by the treatment system.

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 it 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 evaporation 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 discharges 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). 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 commenter 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 above (see also response to DCN EPA-HQ-OW-2009-

0819-5406-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 that 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 electric 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-HQ-OW2009-0819-4655, 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-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 11
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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 wastewater 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 extra 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 with 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 (which 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 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.

Regarding the commenter’s opposition to proposed Option 5 (or Option F for the final rule), see 

response to DCN EPA-HQ-OW-2009-0819-5406-A2, Excerpt Number 10.

Regarding the commenter’s statements about re-use of FGD wastewater, see response to DCN 

EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 63.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Public Service Company of New Hampshire(PSNH)

Document Control Number: EPA-HQ-OW-2009-0819-4633-A1

Comment Excerpt Number: 37

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 analysis 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 additional 

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 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 system, 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 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-HQ-OW-2009-0819-5406-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 (see preamble Section VIII.C.13 for more detail). 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.

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, 

see responses to comments in code 11.a regarding the demonstration and performance of 

evaporation technology (in particular the response to DCN EPA-HQ-OW-2009-0819-4655, 

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-HQ-OW-2009-0819-4631-A1, Excerpt Number 33, in comment code 

11.c.
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Commenter Name: Tom DeLawrence

Commenter Affiliation: Public Service Company of New Hampshire(PSNH)

Document Control Number: EPA-HQ-OW-2009-0819-4633-A1

Comment Excerpt Number: 40

External Review 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 possesses 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 effectively 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-HQ-OW-2009-0819-4633-A1, Excerpt 

Number 37.

Regarding the commenter’s statements about using data from a “few facilities” to “establish . . . 

national standard[s],” see response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 

33, in comment code 11.c.

Regarding the commenter’s generalized and unsupported statements about technological 

availability and economic achievability, see preamble section VIII and response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 108, in Comment Code 11.a.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-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 Prohibitive
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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, consider 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” 

technology, 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 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 

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 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.

EPA disagrees with the commenter that EPA must provide a “concrete cost-effectiveness 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-HQ-OW-2009-0819-4655, Excerpt 

Number 27 in Comment Code 6.h.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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 VaporCompression Evaporation is not Best Available Technology Economically Achievable for 

Existing Dischargers or New Sources. Vapor-compression evaporation (“VCE”) has a number 

of technological drawbacks (parasitic 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.
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Comment 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-HQ-OW-2009-0819-4475-A1, Excerpt 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-HQOW-2009-0819-4655, Excerpt Numbers 108 and 119, in Comment Code 11.a).

Regarding the commenter’s reference to the “parasitic energy load” of evaporation technology, 

see response to DCN EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4655, Excerpt Number 108 in Comment Code 11.a.

Regarding the commenter’s reference to “waste considerations,” see responses to DCN EPAHQ-OW-2009-0819-4305-A3, Excerpt Number 45 (comment code 11.a); DCN EPA-HQ-OW2009-0819-4489-A1, Excerpt Number 18 (comment code 11.a); DCN EPA-HQ-OW-2009-0819-

4447-A1, Excerpt Number 26 (comment code 11.a); and DCN EPA-HQ-OW-2009-0819-4379-

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-HQ-OW-2009-0819-4683-A2, Excerpt Number 10.

Regarding the commenter’s statement that evaporation technology is not “cost-effective” based 

on its “high cost” relative to “incremental pollutant removal,” see response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 27 (in comment code 6.h).

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-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 Section 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 of 
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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-HQ-OW-2009-0819-5406-A2, Excerpt Number 10.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 76

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Chemical precipitation plus vapor-compression 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 evaporation system is a proven technology, see responses to comments in 

comment code 11.a (in particular, the responses to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpts Numbers 108 and 119 in Comment Code 11.a).

Regarding the commenter’s statement that evaporation technology is not “cost-effective” based 

on its “high cost” relative to “incremental pollutant removal,” see response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 27 (in comment code 6.h).

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 dollars, 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.
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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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 127

External Review Flag: No External Review

External Review Incorporated 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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 existing dischargers or new sources.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4475-A1, Excerpt Number 25.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-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-HQ-OW-2009-0819-4631-A1, Excerpt Number 13.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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.

Comment Response: 

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

EPA-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Regarding the commercial viability of evaporation systems, see responses to comments in 

Comment Code 11.a (in particular, the response to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 108 in Comment Code 11.a).
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Commenter Name: Raven Power Holdings, LLC

Commenter Affiliation: Raven Power Holdings, LLC

Document Control Number: EPA-HQ-OW-2009-0819-4467-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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Regarding the commercial viability of evaporation systems, see responses to comments in 

Comment Code 11.a (in particular, the response to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 108 in Comment Code 11.a).

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-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 burned 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.
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Comment Response: 

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 commenter 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 offers 

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 Statistics Support Document for Effluent Limitations (DCN 

SE05733). See also response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 33 in 

Comment Code 11.c.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 

evaporation 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 commenter’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-HQ-OW-2009-0819-4655, Excerpt Number 108 in Comment Code 11.a).

Regarding 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 EPAHQ-OW-2009-0819-5406-A2, Excerpt Number 10.
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Commenter Name: Douglas J. Fulle

Commenter Affiliation: Oglethorpe Power Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4449-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 response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 108 in Comment Code 11.a).
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11.a. FGD VCE – Demonstration/Performance 

Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-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 Wastewater 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 limited 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 capacity 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. Applications 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 coalfired 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 and 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 at 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 plant. Third, Italian disposal methods are 
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significantly different than American methods. Italian facilities cannot deposit solids in an onsite 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 commercially 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 to 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 system 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 is 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 Power 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 stream 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 hydrate, 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/or 
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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 for 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 variables. 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 circulation 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 processing 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 lime 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 closely 

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 requiring 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 that 
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infrastructure needing to be reconfigured, reclaimed, or eliminated altogether. This would 

present an extreme challenge to many facilities.

The insurmountable 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 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 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 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 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 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 generating 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 preamble 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-HQ-OW-2009-0819-4655, Excerpt Number 108.

EPA disagrees with the commenter’s assertion that because the Italian plants “cannot deposit 

solids in an on-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 that 
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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 the 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 106 in Comment 

Code 11.b.

Regarding the commenter’s statement that EPA “underestimate[d]” the “lost generation 

capacity,” EPA assumes the commenter is referring to the parasitic load related to evaporation 

technology. See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 74 in 

Comment Code 11.b.

Regarding the commenter’s statement about evaporation technology generating “another solid 

waste stream,” see response to DCN EPA-HQ-OW-2009-0819-4305-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 where 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 and 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 the “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 costs 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 foaming 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 precipitation 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 commenter 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 110oC 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 

elemental 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 from wastewaters at 

the temperatures found in the evaporator and crystallizer; however, the pH of the wastewater 
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needs to be greater than 9.5 S.U. For boron, research has shown that only 0.5% is released 

during evaporation at 100oC (see DCN SE05731). EPA agrees that selenium can be volatilized 

during combustion but this requires temperatures of more than 800oC, which is far greater than 

the temperatures found in the evaporation and crystallization systems.

Regarding the commenter’s statements about the number of vendors available and “footprint 

concerns” related to evaporation technology, see response to DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 115.

Regarding the commenter’s statement about the “95% availability” of the evaporation 

technology, see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 119.

Regarding the commenter’s statement about the “harsh conditions” of the evaporation system, 

which tend to “wear out equipment,” see response to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 117. Additionally, 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 

estimates for the final rule. See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt 

Number 106 in Comment Code 11.b.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 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 proposes 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. The 

installation of a brine concentrator system at Duke Energy’s Mayo plant is still under 

construction.

As discussed in UWAG’s comments5, there have only been a few ZLD systems applied to coalfired 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 addition, UWAG outlines a number of installation constraints and operational issues 

encountered at the one U.S. plant that is currently operating this technology.
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The vapor-compression evaporation technology is certainly not a “one size fits all” option and 

should 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 corrosive nature of the process. In addition, the chemicals used in the 

process are estimated to cost $17 million annually6and 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 chemical 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 type 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 supply 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 concentrate 

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 period 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 long-term issues in 

the landfill, further research is needed to ensure that ZLD materials remain solid and are stable 
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in the landfill. The technology to permanently sequester or immobilize the constituents in the 

crystalline matrix is not well proven and not 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 focus 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 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. 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 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 

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-HQOW-2009-0819-4655, Excerpt Number 108.

Regarding the commenter’s statements about the costs of the evaporation technology, see 

response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 106 in Comment Code 

11.b.

Regarding the commenter’s statement about “vendor and material constraints,” see response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 115.

Regarding the commenter’s statement about the “parasitic load” of the evaporation technology, 

see response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 74 in Comment Code 

11.b.

Regarding the commenter’s statements about solid waste from the evaporation process 

presenting “challenging disposal issues,” EPA agrees with the commenter that “some ZLD 

systems generate a hygroscopic salt.” During the rulemaking, EPA considered the potential 
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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 crystallizer. 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 brine 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 evaporation 

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 crystallize the solids as 

sodium chloride.

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-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 precipitation 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 technology 

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 wastewater 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 facilities - 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 system 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, David, 

Preliminary Assessment of a Thermal Zero Liquid Discharge Strategy for CoalFired Power Plants, presented at the International Water Conference, November 13-17, 2011 
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(Nebrig eta!. 2011). 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.

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 ash 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 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 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 demonstration and availability of the evaporation technology, see response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the disposal of solids generated as a result of evaporation technology, see response to 

response to DCN EPA-HQ-OW-2009-0819-4305-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 operation of the new 

source.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 119

External Review Flag: No External Review

External Review Incorporated 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 procure 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 maintenanceintensive 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, 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 most reliable processes in the world. This was 

not accomplished 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 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.

4. Conclusion on ZLD

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 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 ZLD 
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systems (as applied 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 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 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 reliability 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 commenter’s statement that evaporation technology is not “proven,” see preamble 

Section VIII and the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the commenter’s statement that the evaporation technology is not “mature,” EPA 

notes that evaporation systems have been used to treat FGD wastewater since at least 2009. 

Three other plants in the United States have installed, or are in the process of installing, this 

technology. Additionally, four coal-fired power plants in Italy are treating 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 technology 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 commenter’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 by 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 

operate.

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 limitations for plants who opt into the 
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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 Sections VIII.D and F.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 108

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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 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 commercially 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 

landfill.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 Centralia 
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Big Hanaford Plant, and Millikin Station, operated ZLD systems for 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-called 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 

m3/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-08-33, Oct. 2008, EPA-HQOW-2009-0819-2178 (Rao et al. 2008). The solid wastes from the ZLD treatment system are 

shipped to Germany for mine refill (Nebrig et al. 2011). 

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 

designed 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 with 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 systems 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 the 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.

3. ZLD Systems Used for FGD Wastewater Treatment Experience Operational Problems
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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 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.

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 maintenance. 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 silo 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 pH 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 

imbalances 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.
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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 challenges 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 cake 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 and 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 chloride 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 softening 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; modifying 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 process 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 physchem and ZLD systems were converted to a closed-loop seal system to eliminate unnecessary 

flush water 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.
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In short, making a ZLD system work at this plant required overcoming many challenges 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 Some 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 concentrator, 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 added 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, maintaining 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 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 reuse.

Comment Response: 

The commenter’s statements focus 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 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. 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 evaporation. 
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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 any options evaluating the evaporation system, 

EPA included numeric effluent limitations 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.” EPA 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 currently 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 electric 

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 wastewater 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 the 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 landfill,” 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 data 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 Dallman 

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 also 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 sampling episode, “has a capacity of approximately 600 pgm,” which is larger 
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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 demonstrates 

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 commenter 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/chemical 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 site 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/operation.

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 annual 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 Category (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 that 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.
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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 evaporation 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 

commenter 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 off 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 being 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 operated, 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-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 64

External 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 discharge,” 

see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 54

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 falling 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 described 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 across 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 characteristics 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 altogether 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 applied 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 United 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 and 
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crystallization system, 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 with 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.

The 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 blowdown 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 produce 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 Service Company of New Hampshire’s Merrimack Station.

187 78 Fed. Reg. at 34,477.

188 EPRI 2007, Docket No. EPA-HQ-OW-2009-0819-2168, at 4-3.

189 Summary of Zero Liquid Discharge Waste Management Installations, Docket No., EPA-HQOW-2009-0819-1224, Attachment 4.

190 Synapse Report, Appendix A, at 49.

191 See EPRI 2007, Docket No. EPA-HQ-OW-2009-0819-2168, at 4-3 (“Due to the more 

concentrated nature of FGD blowdown streams plus the presence of trace metals and other 

pollutants in reatively high concentrations, common evaporation systems and processes will have 

to be modified to accommodate the characteristics of the FGD waters.”).

192 TDD at 7-13.
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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 solids, 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-HQ-OW-2009-0819-1784.

196 Iatan Final Site Visit Notes, Docket No. EPA-HQ-OW-2009-0819-1889, at 1-5.

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

wastewater [EPA- HQ-OW-2008-0517].

198 Final Iatan Site Visit Notes, Docket No. EPA-HQ-OW-2009-0819-1889, at page 4.

199 See Written responses to EPA questions regarding the evaporation system for treating FGD 

wastewater, Docket No. EPA-HQ-OW-2008-0517, DCN 06287A4. The only operational 

problems identified with this system 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 response to DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 108.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 56

External Review Flag: No External Review

External 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 considering 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 on
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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 for 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 therefore 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 plants 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 Progress 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 preamble Section VIII and in response to DCN EPA-HQ-OW2009-0819-4655, Excerpt Number 108.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Public Service Company of New Hampshire(PSNH)

Document Control Number: EPA-HQ-OW-2009-0819-4633-A1
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Comment Excerpt 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 install 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 water 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 proposal 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 alternative 

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 volume 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 ramifications 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 install 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, EPA 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 on evaporation, for the reasons described in sections VIII.D and F 

of the preamble.
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EPA agrees with the commenter that evaporation technology is not necessarily “zero liquid 

discharge” for reasons explained elsewhere in these responses to comments.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 commercially 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 operational 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 have 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, 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 

landfill.30 In addition, 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 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 down. The City 

of Springfield, Illinois, purchased thermal ZLD equipment for its Dallman Generating Station, 

but never installed it.
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In Italy, there are a handful of so-called 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. Brindisi, the biggest Italian 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-08-33, Oct. 2008, EPA-HQ-OW-2009-0819- 2178 (Rao et al. 2008). 

The solid waste disposal in Italy is restricted because on-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. (Nebrig 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 high 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 

wastewater 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 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.

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 Consistency is Difficult Under Some Conditions
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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 that 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 equipment 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, which 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 crystals 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 

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. 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 constant reliable 

solution.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Public Service Company of New Hampshire(PSNH)

Document Control Number: EPA-HQ-OW-2009-0819-4633-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 waste 

water.
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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 does 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 before 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 trucks with the reduced liquid and dewatered solid material byproduct 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 technology, 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 those 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 consistently 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 either been abandoned or shut down. Additionally, the City of 

Springfield, Illinois, purchased thermal ZLD equipment for its Dallman Generating Station but 
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never installed it.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18 and response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the commenter’s comparison between the evaporation systems operating at 

Merrimack and Iatan, EPA notes that both plants operate systems that would achieve the final 

numeric limitations and standards EPA developed based on use of evaporation technology to 

control discharges of FGD wastewater. EPA also notes that either of those systems, or many 

other variations of the evaporation technology, could be employed at other plants to comply with 

the numeric limitations and standards. The ELGs do not prescribe a specific technology that 

must be installed, but rather plants may install any technology that meets the limitations and 

standards.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-A1

Comment Excerpt Number: 46

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

1. Applications of ZLD Systems 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 wastewater 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 fly 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 efficacy 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 FGD 
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wastewater at facilities within the United States. Also, the Italian facilities are free to utilize the 

ZLD technology at their leisure, as applicable laws provide 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 account 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 Systems

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 given 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 the 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 this 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 stream 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 formations 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 require 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 

hydrate, 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 unanswered questions concerning long-term 
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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 presents 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 types 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 opportunity 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 physical-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, significant 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 their 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 technology 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 consider. 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 infrastructure needing to be reconfigured, reclaimed, or eliminated altogether. 

This would present an extreme challenge to many facilities.
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Collectively, these known or expected problems, coupled with significant unknowns, about the 

ZLD technology present insurmountable 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/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 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 technological 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 crystallizer, see responses to DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 108 and DCN EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18.

Regarding the commenter’s statements about capital and O&M costs, see response to DCN EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 106 in Comment Code 11.b.

Regarding the commenter’s statements about solids generated in the evaporation process, see 

response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 45 and DCN EPA-HQOW-2009-0819-4489-A1, Excerpt Number 18.

Regarding the commenter’s statements about chemicals used in the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18.

Regarding the commenter’s statement about the “possible” release of mercury, selenium, boron, 

and/or ammonia to the ambient air, see response to DCN EPA-HQ-OW-2009-0819-4489-A1, 

Excerpt Number 18.

Regarding the commenter’s statements about the number of vendors available and the “footprint 

concerns” related to evaporation technology, see response to DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 115.

Regarding the commenter’s statement that evaporation systems are not “available more than 95% 

of the time,” see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 119.

Regarding the commenter’s statements about the “harsh conditions” of the evaporation system, 

which tend to “take their toll on the associated equipment,” see response to DCN EPA-HQ-OW2009-0819-4655, Excerpt Number 117. Additionally, EPA agrees with the commenter that the 
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system “equipment must be closely monitored 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-HQ-OW-2009-

0819-4499-A1, Excerpt Number 106 in Comment Code 11.b.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 operates 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%. Neither 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 is 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 most reliable processes in the world. This was 

not accomplished in a few years. It took many years to develop efficient turbines, boilers, and 
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generators, and these are only the primary parts of the power station. Thousands of other systems 

are used to support, 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 difficulties 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 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.

See responses to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 119 and Excerpt 

Number 108.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 115

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 which seek to expand their sites to accommodate new systems will 

face zoning and permitting issues. EPA should consider all of these “footprint” issues and 
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provide appropriate exemptions for facilities that cannot accommodate major new systems like 

ZLD treatment.

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 

increase. 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 reasonable 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 wastewater 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 aspects 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 construction 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 FGD 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 not 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 metallurgy.” 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-HQ-OW-2009-0819-4655, Excerpt Number 119, the final rule does not 
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“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 rule 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 evaporation 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 technology. 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-HQ-OW-2009-0819-4470-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 precipitation 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 technology 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 significant quantities of chemicals;
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 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 existing 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 difficulties 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 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 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 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-HQ-OW-2009-0819-4655, Excerpt 

Number 108.

Regarding the commenter’s statement about the parasitic load of the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 74 in Comment Code 

11.b.

Regarding the commenter’s statement that evaporation systems “can present solid waste disposal 

issues,” EPA notes that the commenter’s statements are too generalized and speculative to 

respond fully. Nonetheless, regarding the generation of hygroscopic salts in the evaporation 

system, see response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 45; regarding 

the potential regulation of the solids wastes from the evaporation system, see response to DCN 

EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18; regarding the potential for high 

amounts of selenium in the evaporation solids, see response to DCN EPA-HQ-OW-2009-0819-

4447-A1, Excerpt Number 26; and regarding further research for the disposal of the solids 

generated in the evaporation system, see response to DCN EPA-HQ-OW-2009-0819-4379-A1, 

Excerpt Number 75 in Comment Code 11.d.

Regarding the commenter’s statement that evaporation systems “consume significant quantities 

of chemicals,” see response to DCN EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18.
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Regarding the commenter’s statements about capital and O&M costs, see response to DCN EPAHQ-OW-2009-0819-5140-A2, Excerpt Number 66 in Comment Code 11.b.

Regarding the footprint and the procurement of the evaporation system, see response to DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 115.

Regarding the commenter’s statement that it is “difficult to maintain” the evaporation technology 

equipment, see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the reliability of the evaporation system, see response to DCN EPA-HQ-OW-2009-

0819-4655, 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 concluded 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 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 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 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-HQ-OW-2009-0819-4631-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 the 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. Instead, FGD wastewaters were 
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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 premise 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-HQ-OW-2009-0819-4655, 

Excerpt Number 108.

Regarding the reliability of the evaporation system, see response to DCN EPA-HQ-OW-2009-

0819-4655, Excerpt Number 119.

The commenter states that evaporation systems in Italy face “significant solid waste disposal 

challenges.” The commenter’s statements are too generalized to provide a complete response. 

Nonetheless, regarding the generation of hygroscopic salts in the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 45; regarding the 

potential regulation of the solids wastes from the evaporation system, see response to DCN EPAHQ-OW-2009-0819-4489-A1, Excerpt Number 18; regarding the potential for high amounts of 

selenium in the evaporation solids, see response to DCN EPA-HQ-OW-2009-0819-4447-A1, 

Excerpt Number 26; and regarding further research for the disposal of the solids generated in the 

evaporation system, see response to DCN EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4499-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-HQOW-2009-0819-4631-A1, Excerpt Number 33 in Comment Code 11.c and TDD section 3 on 

EPA’s data collection activities for the final rule.

Commenter Name: Nancy A. Evans

Commenter Affiliation: PPL Services Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4348-A2

Comment Excerpt Number: 10
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External 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 available 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 evaluated, 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 

certain 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 chemicals 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 desire 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 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 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 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-HQ-OW-2009-0819-4655, Excerpt 

Number 108.

Regarding the commenter’s statements about the parasitic load of the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 74 in Comment Code 

11.b.

Regarding the commenter’s statement about the “large volume of waste” generated by the 

evaporation technology, see response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt 

Number 4.
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Regarding the commenter’s statement that evaporation systems consume “significant quantities 

of chemicals,” see response to DCN EPA-HQ-OW-2009-0819-4489-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 methodology 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-HQ-OW-2009-0819-5140-A2, Excerpt Number 66 

in Comment Code 11.b.

Regarding the commenter’s statement about the “footprint” of the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 115.

Regarding the commenter’s statement about “energy efficiency,” see response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 110 (in comment code 11.d).

The commenter states that the waste generated by evaporation technology “can, at some facilities 

and under certain conditions, be hazardous” and that “EPA has not taken the cost of disposal or 

even the availability of facilities that can take such a waste into account.” EPA disagrees with the 

commenter that “EPA has not taken the cost of disposal or even the availability of facilities that 

can take such a [hazardous] waste into account.” EPA did account for the costs of disposal in its 

cost estimates. But as the commenter points out, only “at some facilities and under certain 

conditions, [will it] be hazardous.” As such, EPA cannot determine which plants would 

potentially generate hazardous wastes. Therefore, EPA did not account for the costs of disposal 

of any potential hazardous wastes in its cost estimates. However, the final rule does not establish 

BAT limitations or PSES for FGD wastewater discharges from all existing steam electric power 

generating units based on evaporation. Only new sources or existing sources electing to 

participate in the voluntary incentives program would need to comply with the numeric 

limitations and standards for FGD wastewater discharges based on the evaporation technology. 

Those plants have the ability to take into account any potential for hazardous waste disposal 

prior to electing to participate in the voluntary incentives program or prior to planning for the 

design and operation of the new source. See also response to DCN EPA-HQ-OW-2009-0819-

4447-A1, Excerpt Number 26.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 79

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

ZLD Footprint May be Hard to Accommodate At Some Facilities
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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 relocating 

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 biological 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 planned 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 the 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 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-HQ-OW-2009-0819-4655, Excerpt Number 115.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1
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Comment Excerpt Number: 37

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment 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 

resulting 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 metals 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 of 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 equipment.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-HQ-OW-2009-0819-4379-

A1, Excerpt Number 74 in Comment Code 11.b.

Regarding the commenter’s statements about the “corrosive nature of FGD wastewater” and 

corrosion of the evaporation technology, see response to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 108.

The commenter states that “it is possible metals removed from the FGD wastewater through 

vapor-compression evaporation would go back to solution in landfill leachate.” EPA notes that 

the commenter 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 leachate. 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 

“operational and maintenance concerns with the evaporation/crystallization systems, including 
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scaling and corrosion of equipment,” see response to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 108.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 Time-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 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 

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-HQ-OW-2009-0819-4655, Excerpt Number 115. 

Commenter Name: Raven Power Holdings, LLC

Commenter Affiliation: Raven Power Holdings, LLC

Document Control Number: EPA-HQ-OW-2009-0819-4467-A1

Comment Excerpt Number: 23

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 treatment 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 evaporation “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 incentives 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in 

Comment Code 6.h.

Regarding previous experiences using the evaporation system to treat FGD wastewater, see 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the potential re-emissions of mercury and boron, see response to DCN EPA-HQ-OW2009-0819-4489-A1, Excerpt Number 18.

Regarding the parasitic load of the evaporation system, see response to DCN EPA-HQ-OW2009-0819-4379-A1, Excerpt Number 74 in Comment Code 11.b.

Regarding 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.
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Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 and 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 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 the many questions about ZLD systems 

outlined above, EPA should not force 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. 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 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 the commenter’s statements about the “maturity” of the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4655, 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 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 
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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 discharges 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-HQ-OW-2009-0819-4460-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 commercially 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 technology 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-HQ-OW-2009-0819-4655, Excerpt Number 108.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 use 
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centrifugal force to accomplish the drying. 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 demineralizers 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-HQ-OW-2009-0819-4655, Excerpt Number 108, and the response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 117.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 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. 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 construction of the ZLD equipment ever begins.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 115.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4471-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 such 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 

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 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.

While EPA determined that the evaporation technology is available and demonstrated, 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 voluntary 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. Moreover, 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 pose 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-HQ-OW2009-0819-4655, Excerpt Number 108.

Regarding the generation of hygroscopic solids in the evaporation system, see response to DCN 

EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 45.
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Regarding the potential generation of hazardous materials, see response to DCN EPA-HQ-OW2009-0819-4348-A2, Excerpt Number 10.

Regarding the potential re-emission of boron and mercury, see response to DCN EPA-HQ-OW2009-0819-4489-A1, Excerpt Number 18.

Regarding the commenter’s statement that evaporation systems are “labor-intensive to operate 

and tend to have frequent downtime,” see responses to EPA-HQ-OW-2009-0819-4489-A1, 

Excerpt Number 18 and DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 119.

Commenter Name: Betsy Natz

Commenter Affiliation: Institute of Clean Air Companies (ICAC)

Document Control Number: EPA-HQ-OW-2009-0819-4549-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 instead 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 EPA-HQ-OW2009-0819-4631-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-HQ-OW-2009-0819-4655

Comment Excerpt Number: 117

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

l. Some ZLD Equipment is Difficult to Maintain

The salts produced 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 case, 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 “constant 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 continues 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 

Category (Cost & Loads Report) (DCN SE05831/SE05832).

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 169

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Some ZLD Equipment is Difficult to Maintain

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 

use centrifugal force to accomplish the drying. In either case, these pieces of equipment are in 

a harsh environment and have constant maintenance issues.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 117.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 compressionevaporation systems are technically available. It is not a proven technology for FGD wastewater. 

The few plants that are operating these 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 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 technology is not “proven,” see preamble 

Section VIII and the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the stability of the solids generated by the evaporation technology, see response to 

DCN EPA-HQ-OW-2009-0819-4475-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-HQ-OW-2009-0819-4499-A1, Excerpt 

Number 106 in Comment Code 11.b.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 compressionevaporation systems are technically available. It is not a proven technology for FGD 
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wastewater. The few plants that are operating these systems face challenges 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 technology is not “proven,” see preamble 

Section VIII and the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.

Regarding the stability of the solids, see response to DCN EPA-HQ-OW-2009-0819-4475-A1, 

Excerpt Number 37.

Regarding the commenter’s statement about the “high O&M costs” associated with the 

technology, see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 106 in 

Comment Code 11.b.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 technology with zero 

discharge, as discussed elsewhere in responses to this commenter.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 108.
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Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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-2009-0819-4655, Excerpt Number 108.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 105

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-2009-0819-4655, Excerpt Number 108.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

Document Control Number: EPA-HQ-OW-2009-0819-3920-A1

Comment Excerpt Number: 153

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 tall. 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 apparent equating of evaporation technology with zero 

discharge, as discussed elsewhere in these responses to comments.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 115.
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11.b. FGD VCE – Costs 

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 106

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A.3 Cost Estimating Summary for Chemical Precipitation with VaporCompression 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 

vapor-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 individual 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 evaporation/atmospheric crystallization (CP + 
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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 uses 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 softening, 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, magnesium, 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, 

neutralization 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 landfilling, 

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 atmospheric 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 because 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 

crystallization 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 followed 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 atmospheric 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.
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 Key equipment – Equalization tank, softening reaction tank, softening 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 rate 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 large 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 capacities. Estimates assumed 

installation of 2 identical trains at 100 percent capacity for all equipment.
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Capital cost cannot be calculated based on size of the power plant (in megawatts [MW]), because 

factors such as coal chloride concentration and water recycling 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 be 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 sulfate 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 several 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 

Fahrenheit (°F) for the feed water. Based on the water chemistry input, the model calculated the 

pH of the feed water to be 6.6.
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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 

vendor 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).
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Because the quoted evaporator/crystallizer system is 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 account 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 downstream 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 of 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 cost 

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 treatment 

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 for 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.
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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 wastewater.

 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 Elements
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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) operators 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 supply 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 Antiscalent - $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 crystallizer 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.3.8Cost 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.
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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.
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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.
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A.3.8.3 Annualized Costs
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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 Industry 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 excluding 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 conceptual 
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design case (Table A-16) based 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, assuming 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 plants 

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 adjustments 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 assigned 

no cost for additional capital or O&M expenditures.

Table A-21 summarizes treatment costs to the current industry.
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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 screeninglevel 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 addition 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 program 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 in 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 

(electrical, 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 cost 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 Timmerhaus’ 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 treatment 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 soda 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 

system, 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 additional 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 the chemical feed system cost equations associated 

with the FGD chemical precipitation system and the plant-specific FGD wastewater flow rate. 
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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. For 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 concentrating 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 crystallizer. 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 maintenance1and, 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 processing 

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 concentrator. 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 then 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 equipment 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 

system, 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 facilities, 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 three 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.
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EPA generally agrees with the commenter that costs for maintenance equipment and labor were 

underestimated 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 treatment 

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 replacement 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 literature information for chemical plants [Perry’s Chemical Engineers Handbook, 6th

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-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 66

External Review Flag: No External Review

External Review Incorporated into Response: No

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 concentration 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.
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The process to soften the FGD wastewater consumes a large amount of lime and soda ash. 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 were 

needed to be fed to the system. The chemical cost was estimated to be approximately $17 million 

per year. 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. This 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 physical 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 desaturation and softening process is 105 tons per day (at an approximate disposal cost of $3/ton). 

That unnamed utility (providing confidential information 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 power 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 

community-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 system 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, the 
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chemicals unloading will add to the manpower requirements and to the plant’s traffic congestion. 

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 operations 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 106.

ERG disagrees with the commenter that capital costs for an 800 gpm system are nearly $200 

million and annual O&M costs are approximately $19 million. EPA estimates capital costs for 

an 800 gpm system will range between $125 and $135 million, and annual O&M costs will range 

between $10 and $15 million per year (2010$). 

EPA agrees with the commenter that as much as 80 tons per day of soda ash could be needed for 

a 410 gpm treatment system based on the soda ash dosage value used in development of the 

costs. 

EPA disagrees with the commenter that additional space is required to store treatment chemicals 

such as soda ash for the softening system. Site visits to steam electric power plants found that 

most have very large areas around treatment or cooling ponds that could be used to house silos 

for bulk storage of soda ash. In addition, EPA’s review of Steam Electric Survey data did not 

identify that plants would lack adequate space for installation of FGD wastewater treatment 

equipment or other equipment that plants may need to install to comply with the ELGs (e.g., 

equipment associated with ash handling conversions such as remote mechanical drag systems 

and fly ash silos). Furthermore, EPA did not receive any comments on the proposed rule 

providing specific information for any plant demonstrating that it lacks adequate space to install 

the equipment and systems needed to implement the ELGs.
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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 where 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 associated 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-HQ-OW-2009-0819-4379-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 crystallizer 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 wastewater 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 member 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 electrical 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 gallons. Using an industry-wide average, EPA 
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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 NWQEIs 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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 80

External Review Flag: No External Review

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 staff 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 unforeseen 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 technology or 

automation between design and purchasing. See response to DCN EPA-HQ-OW-2009-0819-

4499-A1, Excerpt Number 106. 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 DCN SE05730 
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(Memorandum to the Steam Electric Rulemaking Record: Plant-Specific Compliance Cost 

Estimates for the Treatment of FGD Wastewater with Chemical Precipitation Followed by 

Evaporation) contain additional information.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 and 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 designed. 

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 this technology, EPA decided to 

increase the number of operators for the evaporation system. See response to DCN EPA-HQOW-2009-0819-4499-A1, Excerpt Number 106.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 underground 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 underground 
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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-HQ-OW-2009-0819-4379-A1, Excerpt Number 80.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4471-A1

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

UWAG 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. Annual 

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 commenter. 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-HQ-OW2009-0819-4499-A1, Excerpt Number 106.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 57

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 million213 and $37 

million.214 At the Torrevaldaliga Nord plant 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 for 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 

evaporation 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.217 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 doublecounting this cost. Second, EPA’s cost estimates for mechanical evaporation include the cost of 

a forced-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 Section 

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 that 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 systems 
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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 not 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-tax 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-byplant 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 the 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 ash 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, 

Merrimack, 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 sector 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.”).
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215 Enel Site Visit Notes, Docket No. EPA-HQ-OW-2009-0819-1795.

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 largely 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-HQ-OW-2009-0819-0387, at 4-

36.

223 TDD at 7-17.

224 2009 Detailed Study, Docket No. EPA-HQ-OW-2009-0819-0387, at 4-47, Fig. 4-9.

225 Incremental Cost and Loading, at 4-13.

226 RIA at 3-6.

227 Id. at Table 2-3.

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 issues 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 that all plants would be 
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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 estimate 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 additional 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 account 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 not 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 in 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 reflect 

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 financial stress on plant owners conducted using after-tax compliance 

costs (see Chapter 3 of the RIA for the final rule). Also see the preamble for the final rule.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 78

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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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 occurring. 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 Italy33, 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 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 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 technology 

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 more 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 very 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 system 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 

16-17.
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Comment Response: 

EPA acknowledges that the evaporation 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 because 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 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 addition 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 program 

under which steam electric power plants can choose to be subject to more stringent BAT 

limitations for 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 

million. 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 system 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 chloride 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. Additionally, 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 

redundancy 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.
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Regarding the number of operators required for the system, see response to DCN EPA-HQ-OW2009-0819-4499-A1, Excerpt Number 106.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 costs 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 Characteristic 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 

figured 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 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 be 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 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 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. APPA did 

not see anything in the proposed rule’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 of 
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the ZLD, make the ZLD uneconomical for the purposes of regulating selenium and other 

pollutants. 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-HQ-OW-2009-0819-4305-A3, Excerpt Number 45 in Comment Code 11.a.

Regarding the potential regulation of the solids wastes from the evaporation system, see response 

to DCN EPA-HQ-OW-2009-0819-4489-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 solids, see response to 

DCN EPA-HQ-OW-2009-0819-4447-A1, Excerpt Number 26 in Comment Code 11.a.

Regarding further research for the disposal of the solids generated in the evaporation system, see 

response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 75 in Comment Code 

11.d.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 36

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

3.3 EPA underestimated the cost of chemical precipitation with vaporcompression evaporation/atmospheric crystallization (CP + VCE) treatment for 

the industry. EPRI’s annualized cost estimate is approximately 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 Guidelines (ELG) [EPA 2013a]. Table 3-7 

compares industry cost estimated by EPA with cost calculated independently by EPRI.
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The major differences between the estimates made by EPA and EPRI include the following:

 EPA assumed the same CP system installed as Option 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 estimates. 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 point 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 cases, the cost 

discrepancy reflects the following differences in approach:
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 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 

estimates 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 estimate, 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 rate 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 to 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 of 

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 

calculate 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 Proposed 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 provided 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 

“turnkey 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 cost 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 support 
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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 estimates. 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 Effluent 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 wastewater 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 rates. 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 

Removals 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. EPA 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 underestimates 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 

required for the VCE system only. In addition, a Chemical Engineer would likely be required to 

assist VCE operations full time.
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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 precipitation 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 for the chemical precipitation system. See 

response to DCN EPA-HQ-OW-2009-0819-4499-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 equipment cost estimate for the VCE system. See response to 

DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 106. 

Regarding the use of the mean instead of the median value, see response to DCN EPA-HQ-OW2009-0819-4499-A1, Excerpt Number 26 in Comment Code 9.b.

Regarding the use of peak flow rate, see response to DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 27 in Comment Code 9.b.

Regarding the FGD wastewater flow reduction costs, see response to DCN EPA-HQ-OW-2009-

0819-4499-A1, Excerpt Number 28 in Comment Code 8.

Regarding EPA’s sludge factor, see response to DCN EPA-HQ-OW-2009-0819-4499-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-HQ-OW-2009-0819-4499-

A1, Excerpt Number 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-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

We Energies is a member of the Electric Power Research Institute (“EPRI”)2and 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 pretreatment 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.

- EPRI 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, delivery 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 reliability, 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 90 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 36.

EPA disagrees with the commenter that industry-wide capital costs are approximately $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 costs 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: PlantSpecific Compliance Cost Estimates for the Treatment of FGD Wastewater with Chemical 

Precipitation Followed by Evaporation).

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 114

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 wastewater 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 chemicals, 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 often than originally 
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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 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 frequently repaired or replaced.

The total capital 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 of $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 knowledgeable and well-trained 

personnel would be needed to maintain the ZLD system.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 78.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 112

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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. This effect 

cascades through the P/C, changing the pH and the quantity of coagulants and polymers used to 

capture the metals.
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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 member 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 lime 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 member 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 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-HQ-OW-2009-0819-5140-A2, Excerpt Number 66.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 76

External Review Flag: No External Review

External Review Incorporated into Response: No

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 concentration 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 
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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 approximately $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-HQ-OW-2009-0819-5140-A2, Excerpt Number 66.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 109

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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 wastewater 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 member also reported 

that the equipment will increase carbon emissions per unit energy output and the cost of station 

service will lead to lost annual revenue of $1 million.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 74.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 demineralizers 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 the 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 81.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 116

External Review Flag: No External Review

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 industry. Installing all of the equipment intermingled with the 

existing plant systems and operations will be an extreme challenge. It will require additional 

safety professionals to keep the staff and the construction crews safe.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 80. 

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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) technologies 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 of 

possible regulatory requirements based on evaporation for FGD wastewater.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 14

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) technologies that would need to be retrofitted with ZLD.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 104.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative
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Document Control Number: EPA-HQ-OW-2009-0819-4460-A1

Comment 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 response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 

106. Additionally, regarding lost generation capacity, see response to DCN EPA-HQ-OW-2009-

0819-4379-A1, Excerpt Number 55 in Comment Code 8.c.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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, followed 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).
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201 Zero-Liquid Discharge System at Progress Energy Mayo Generation Station, EPA-HQ-OW2009-0819-1443, at page 1.

202 Deposition of Thomas E. Higgins, CH2M Hill, in Tennessee Clean Water Network v. 

Tennessee 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. at 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.
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11.c. FGD VCE – Pollutant Loadings 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 103

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 have 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. 2013 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-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 111

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 calculated 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-HQ-OW-2009-0819-4655, Excerpt Number 103.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-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 standards.

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 located 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, pilot 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 single 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 is] to be based on a broader range of technological 
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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); Am. 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 plant, 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 another 

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 limitations. 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-HQ-OW-2009-0819-4499-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). 

This is not the first time EPA has collected data from non-U.S. plants to supplement data from 

U.S. plants, especially when characterizing best available technology (see EPA-821-R-97-011 

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 development 

of the effluent limitations.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 62

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

To estimate post-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 over 
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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-HQ-OW-2009-0819-4655, Excerpt Number 103.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 27

External Review Flag: No External Review

External Review Incorporated 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-HQ-OW-2009-0819-4655, Excerpt Number 103.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 91

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

To estimate post-compliance loadings for the vapor compression evaporation option, EPA 

averaged 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 103.
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11.d. FGD VCE – NWQI 

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 magnesium 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 where 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 

atmosphere.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 on 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 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 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 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.
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Given the physical properties of ZLD materials as well as potential long-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 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 volumes 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 research and time.

As a corollary to ZLD disposal 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 the 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 (August), 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 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 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 rule), 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 specific plant.
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Regarding the generation of hygroscopic salts in the evaporation system and issues with 

containing the salts in a landfill, see response to DCN EPA-HQ-OW-2009-0819-4305-A3, 

Excerpt Number 45 in Comment Code 11.a. EPA disagrees that it has not considered 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-HQ-OW-2009-0819-4655, 

Excerpt Number 108 in Comment Code 11.a and DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 106 in Comment Code 11.b.

Regarding the operational challenges related to managing the solids wastes from the evaporation 

system, see response to DCN EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18 in 

Comment Code 11.a.

Regarding the potential for “a high amount” of selenium in the evaporation solids, see response 

to DCN EPA-HQ-OW-2009-0819-4447-A1, Excerpt Number 26 in Comment Code 11.a.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 77

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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 high 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 problem, some suppliers include a boron scrubber. Nebrig et al. 

2011 at 12. However, the boron scrubber introduces another wastewater stream that must be 
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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 evaporation will increase, 

causing ammonia carryover to the distillate. Id.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4489-A1, Excerpt Number 18 in Comment 

Code 11.a.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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=001PS770itnYy4OdniWGv3jVur2cEAej3JiYSZZY_yUVfOylS8YP59Vob9iO5k–Q_hKYAEem2wKxdiIn5E2TfMHaytmSpqbU7Zf1AtxDdQpAyWy9CGFYvubcNJpm-U5dEG3QkAGv88dXtMt__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 new 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, May 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 establishes a voluntary incentives program for plants that meet FGD wastewater 
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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 

regulatory 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 generated 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 impacts 

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-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 61

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 method 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 does 
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not have to be pumped from a nearby water body, treated, or transported long distances—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 perspective, 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-HQ-OW-2009-0819-4655, 

Excerpt Number 110.

Regarding the solids generation for the evaporation system, EPA notes that the commenter’s 

estimate likely does not account for the solid waste generated in the chemical precipitation 

system and the softening process. These are part of the complete evaporation system evaluated as 

BAT.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 62

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

ZLD system wastes can be challenging to manage for disposal—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 hydrate. 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. APPA 
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wonders if this could result in unexpected consequences 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 chloride 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 potential 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 investigation. 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 equipment 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 transported 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 exists 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 75.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 111

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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, 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 more 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 material, 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 salt-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 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.

Assuming that the material can be cost effectively transported and placed into the landfill, when 

considering 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 timespans. 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.
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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-HQ-OW-2009-0819-4379-A1, Excerpt Number 75.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 113

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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 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 volatile. 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 ambient 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-HQ-OW-2009-0819-4489-A1, Excerpt Number 18 in Comment 

Code 11.a.
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Commenter Name: H. Morriss Barney IV

Commenter Affiliation: Texas Municipal Power Agency (TMPA)

Document Control Number: EPA-HQ-OW-2009-0819-4584-A1

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 stabilize 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 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 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 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 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 disposing 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-term 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 sequestered 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 be 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 volumes 
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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 research 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 the many questions about ZLD systems 

outlined above, EPA should not force this technology onto power plants.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 75.
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12. FGD Other Treatment Technologies 

Commenter Name: Betsy Natz

Commenter Affiliation: Institute of Clean Air Companies (ICAC)

Document Control Number: EPA-HQ-OW-2009-0819-4549-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 willing 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 substantial 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 spray 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 described. 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 other 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) 
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are dried and added to the fly ash, they may change the properties of the fly ash for disposal or 

beneficial 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 wastewater 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 resulting 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 handling. 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 process, 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 appreciates 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 EPA 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 innovative 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 criteria 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). Therefore, EPA decided it would not 

be appropriate to establish an incentives program based on “partial reduction of FGD wastewater 

streams.”
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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 fly 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-HQ-OW-2009-0819-5093-A2, Excerpt Number 5 in Comment Code 

6.g.v. Furthermore, 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 standards. See response to 

DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 5. 

Commenter Name: Jared Morrison

Commenter Affiliation: Westar Energy

Document Control Number: EPA-HQ-OW-2009-0819-4469-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 electric 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 

hunting 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 upgraded 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, vacuum 
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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 discharges 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 alternatives 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 are 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, using 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 irrigation

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 the 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 the CORMIXmodeled antidegradation limits that was both technically viable and environmentally desirable. 

The pilot project was implemented in order to validate these evaluations.
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The pilot CWTS spans a total wetland area of 2.1 acres and yields a hydraulic 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 approximately $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 (VFB) 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 similar 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, allowing 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. Additional photos and diagrams of each cell type are shown below.
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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 that 
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matter most to local stakeholders. We’ve dealt with a variety of environmental groups while 

working through the antidegradation 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 Westar’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 beneficial 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. 

During 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 River 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 may occur as a result of the site-specific constituent 
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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 with 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 assurances 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 concentrations 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 several 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 

greatest 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 and 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 subsurface 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 equalization pond to one of two treatment lines. Each 

of the two treatment lines includes one VFB cell and one vegetated submerged bed (VSB) cell.
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Each VFB will be further split into four treatment cells. The VFB cells contain a two-tiered 

system where a shallow tier 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 VSBs. 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 to 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 

constructed 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.
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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 system 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 year 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 current 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 wastewater 
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(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 brief 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 sitespecific 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/Crystallization $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 with 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-tier design of the VFBs should also 

minimize the seepage of any FGD wastewater into the upper tier, where wildlife may 
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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 recognizes 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 analytical 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 than 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 wetlands 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, potential 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 basis 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 a 
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specific type of treatment technology. 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 

find 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-HQ-OW-2009-0819-4702-A7

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Attached growth (or fixed film) reactors support the microbial culture on the surface of some 

type of solid support medium (e.g. sand, activated carbon) within the reactor. The wastewater is 

treated when it flows over the microbial culture attached to the support media. Attached growth 

systems can be either upflow or downflow. In downflow systems the wastewater is introduced at 

the top of the bed of fixed media and flows downward through the bed. In upflow reactors the 

wastewater flows upward though the fixed media bed which becomes expanded under the 

influence of the upward flow velocity. While upflow reactors require a subsequent polishing 

stage to remove suspended solids, downflow reactors may not. The systems evaluated by EPA as 

the technological basis for Se removal by biological treatment were downflow fixed‐film 

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 drainage 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 pilot‐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 system 

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 treatment unit. Early 
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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 support 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 study 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 

and, therefore, EPA did not evaluate this technology further.

Commenter Name: Jared Morrison

Commenter Affiliation: Westar Energy

Document Control Number: EPA-HQ-OW-2009-0819-4469-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External 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 given 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 intent of the proposed 

guidelines.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4469-A1, Excerpt Number 1. 
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13. Fly Ash Transport Water 

Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-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. The 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 reductions 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 

speculative, 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 requests 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 able to meet the 

BAT effluent limitations by operating dry ash handling systems. See preamble for more 

information.

See response to DCN EPA-HQ-OW-2009-0819-4382-A1, Excerpt Number 4 in Comment Code 

6.i.i regarding zero discharge limitations during upset conditions and DCN EPA-HQ-OW-2009-

0819-4655, Excerpt Number 138 in Comment Code 14.a regarding the operation of wet sluicing 

systems when the dry fly ash handling system is down due to maintenance, startup, or shutdown.

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in Comment 

Code 6.a for a discussion of EPA’s methodology to select pollutants of concern in wastestreams 
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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 rule. See DCN EPA-HQ-OW-2009-0819-4765-A1, Excerpt 

Number 2 in Comment Code 5.a for more information.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 to 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 

activities. 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 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-HQ-OW-2009-0819-4655, Excerpt 

Number 138 in Comment Code 14.a.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3
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Comment Excerpt Number: 85

External Review Flag: No External Review

External Review 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; however, 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 unit 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 period 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 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. Also, see response to DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 14.a for additional 

information regarding backup wet sluicing, including how EPA’s cost methodology accounts for 

additional capital costs that may be needed to eliminate reliance on the wet fly ash handling 

system when the fly ash is not marketable, such as start-up and shutdown periods.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 87

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 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-HQ-OW-2009-0819-4655, Excerpt 

Number 138 in Comment Code 14.a.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 

limits); 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 that 
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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-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4460-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 final 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 water 

established by the ELGs. For additional information regarding backup wet sluicing, see response 

to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 14.a.
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Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 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-HQ-OW-2009-0819-4655, Excerpt 

Number 138 in Comment Code 14.a.

Commenter Name: Erin Bartlett

Commenter Affiliation: The Large Public Power Council (LPPC)

Document Control Number: EPA-HQ-OW-2009-0819-4573-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.7In the circumstance where activated carbon injection (ACI) mercury controls 

capture mercury as part of the fly ash particulate collection system (e.g. in an electrostatic 

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 is 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 transport 
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water because they contain the same 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 needed 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 should 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 cost‐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 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-HQ-OW-2009-

0819-4655, 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 November 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 and 

low volume waste sources for the reasons stated in the preamble to this final rule.
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Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-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 proposal. 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 49 in Comment 

Code 14 regarding fly ash compliance costs and cost-effectiveness.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 75

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA is proposing, in its “preferred” options, to require all steam electric coal-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.
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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 that 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 costeffectiveness 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 preamble 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 existing 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-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 49 and 51 in Comment Code 14.

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-HQ-OW-2009-0819-4491-A1, Excerpt 37 

in Comment Code 1.c.

Also, regarding reopening the record for public comment, please see response to DCN EPA-HQOW-2009-0819-4487-A1, Excerpt 114 in Comment Code 1.c.

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 49 in Comment Code 14 for a 

discussion of the cost effectiveness related to dry fly ash handling.

Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-A1
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Comment Excerpt Number: 51

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment 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-HQ-OW2009-0819-4487-A1, Excerpt Number 126, in Comment Code 28.f for more information 

regarding how the final rule meets the three objectives proposed by the commenter.

For the reasons stated in preamble section VIII.C and the final rule 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 

existing and new sources.

Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-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 supportable either 

from an economic or an environmental improvement standpoint.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.
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Commenter Name: Dorothy Kellogg and Michael Leitman

Commenter Affiliation: National Rural Electric Cooperative Association (NRECA)

Document Control Number: EPA-HQ-OW-2009-0819-4565-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Continued wet 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 support dry fly 

ash handling as cost effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4471-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 comments Section IX BAT for Fly Ash Transport 

Water.)

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.
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Commenter Name: Kevin D. Frizzell

Commenter Affiliation: Owensboro Municipal Utilities (OMU) Elmer Smith Station (ESS)

Document Control Number: EPA-HQ-OW-2009-0819-4683-A2

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

10. BAT for fly ash transport water:

EPA 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 justified as cost-effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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 transport 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 through 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 operation 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.
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15 78 Fed. Reg. at 34461.

16 Id.

17 Id.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-A1

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: 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, MidAmerican 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 response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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:
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Fly Ash Transport Water – Continued wet handling and treatment in surface impoundments.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-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-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Dorothy Kellogg and Michael Leitman

Commenter Affiliation: National Rural Electric Cooperative Association (NRECA)

Document Control Number: EPA-HQ-OW-2009-0819-4565

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NRECA also recommends:

Continued wet handling of fly ash in surface impoundments
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: P. J. Becker

Commenter Affiliation: City Water, Light and Power (CWLP)

Document Control Number: EPA-HQ-OW-2009-0819-4349-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-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 23

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:

Table 2:

Wastestream Record Supports No More than This 

Option

Fly ash transport water Option 1 Impoundment
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-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-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Fly ash transport water

Option 1

Impoundment

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 77 in Comment 

Code 18.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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 WEIGHS 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 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 requirements),” and other factors EPA 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.411

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 engineered 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 eliminate the discharge of fly ash transport water.

410 33 U.S.C. § 1314(b)(2)(B).
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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 preamble 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-HQ-OW-2009-0819-4684-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 finds 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 the 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 average 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 in 
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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 retrofit 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-HQ-OW-2009-0819-4684-A1, Excerpt Number 101.

Commenter Name: Becky Smith

Commenter Affiliation: Clean Water Action et al.

Document Control Number: EPA-HQ-OW-2009-0819-4548-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 ash, 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 surface 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.8
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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-HQ-OW-2009-0819-4684-A1, Excerpt Number 101.

Commenter Name: Jamie Rhodes

Commenter Affiliation: Environment Council of Rhode Island

Document Control Number: EPA-HQ-OW-2009-0819-4034-A2

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 ash, 

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 surface water they can impair water quality and cause 

ecological damage to aquatic systems.

7

Id. at 34,439

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 101.

Commenter Name: Becky Hayat

Commenter Affiliation: Natural Resources Defense Council (NRDC)

Document Control Number: EPA-HQ-OW-2009-0819-4490-A1
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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 utilizing 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 eliminating 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-HQ-OW-2009-0819-4684-A1, Excerpt Number 101.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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 each 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 to do the same.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 101.
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Commenter Name: J. Madras

Commenter Affiliation: Missouri Department of Natural Resources

Document Control Number: EPA-HQ-OW-2009-0819-4383-A1

Comment 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 options 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 pollution controls.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 101.
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13.a. FA Transport Water – General/Scope 

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 amount annually.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 

14.a.
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13.b. FA Transport Water – Profile 

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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. Specifically, 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 system 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 does 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 EPAHQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 14.a regarding the operation 

of wet sluicing systems when the dry fly ash handling system is down due to maintenance, 

startup, or shutdown. In addition, EPA included specific costs for this facility to ensure 

redundancy for the dry handling system. See 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).
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13.c. FA Transport Water – Wastewater Characterization 

Commenter Name: Betsy Natz

Commenter Affiliation: Institute of Clean Air Companies (ICAC)

Document Control Number: EPA-HQ-OW-2009-0819-4549-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 subsequent 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 mixed 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 bituminous 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 the 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 alkaline 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,

Presented at AWMA Power Issues Conference, Chicago, IL, July 2013
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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]ome 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 does 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 expects 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 certain 

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-HQ-OW-2009-0819-4487-A1

Comment Excerpt Number: 52

External Review Flag: No External Review

External Review Incorporated into Response: No

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 bottom 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 disagrees 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 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 the 
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response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment Code 13.d 

for more information about the ash characterization data, including revisions made to the dataset 

after proposal.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 several 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 response 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 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 the response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment Code 13.d for more 

information about the ash characterization data, including revisions made to the dataset after 

proposal.
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13.d. FA Transport Water – Calculation of Baseline Loads 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 Cardinal 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 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).

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 analysis 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 adjusting 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 derived 
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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 recent 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 characterization 

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 preparation plant and treated acid mine 

drainage. Mitchell Final Sampling Episode Report, EPA-HQ-OW-2009-0819-0823, p. 2-5 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 necessary, 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 silver 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 results 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 Removals
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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.
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Following 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 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.

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: 

The 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 EPAHQ-OW-2009-0819-4655-A12).

Regarding sulfides, source water, high non-detects, and the use of old data to determine the 

concentration of pollutants in fly ash ponds, see the response to DCN EPA-HQ-OW-2009-0819-

4499-A1, Excerpt Number 72 in Comment Code 15.d.

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 and 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 misrepresenting 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 fly ash surface 

impoundments that are not from surface impoundments exclusively used to treat fly ash transport 

water, see the response to DCN EPA-HQ-OW-2009-0819-4499-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 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 separately. EPA accounted for the 

pollutant loadings in combined ash ponds or it would have underestimated its identification of 

loadings. See DCN EPA-HQ-OW-2009-0819-4379-A1 Excerpt Number 24 in Comment Code 

4.b regarding the final rule ash characterization data, including the use of combined fly ash and 
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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 

loadings, 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-HQ-OW-2009-0819-4499-A1, Excerpt 

Number 72 in Comment Code 15.d, EPA characterized the concentration data as representative 

of fly ash impoundment effluent 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 

gathered 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 characterize 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 the 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 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 costeffectiveness ratio of $134/lb-eq ($1981). This cost-effectiveness 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.
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Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 84

External Review Flag: No External Review

External Review 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 sources29:

 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]; and

 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 under 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 transport 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 < 1
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MN0001007 -

SD006 Sulfide (as S) mg/l < 0.03

Average 1.0130

 

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 loading was 

attributed to fly ash and the other 14% was attributed to bottom ash31. 

However, this assumption is not appropriate for determining the pollutant loading solely 

from fly ash transport water, or solely from bottom ash transport 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.

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 results 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 nondetected values as the reporting limit for their calculation32. EPA, also, provided no details of 

why these three facilities detected sulfides above the detection limit. Given the number of nondetectable results for sulfides, fourteen from combined ash ponds, two from fly ash ponds and 2 

from 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 sulfide, 

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.
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EPA stated that “there were more non-detects than detected values for effluent data for 

sulfides”33 and requests 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 impoundments 

and 55% for combined ash impoundments)34 and were not listed by EPA as a pollutant of 

concern for ash transport water35.

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 Removals 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-921-R-13-002] 

demonstrating EPA’s method for using nondetect values.

31 TDD Section 10.4.2, page 10-27 [EPA-921-R-13-002].

32 Id. at Section 10.2.2, page 10-17 [EPA-921-R-13-002]

33 78 Fed. Reg. at 34485

34 Technical Review of Statistical Methods and Data Used by EPA to Estimate Baseline Ash 

Impoundment Loadings and TWPEs, AKRF, Inc.(September 2013)

35 TDD, Section 6.7.2, pages 6-28 &6-29 [EPA-921-R-13-002]

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-HQ-OW-2009-0819-4499-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-HQ-OW-2009-0819-4655, Excerpt Number 71.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 44

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 Cardinal 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 database, 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 reflect 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 sluicing.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-A1

Comment Excerpt Number: 64

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 management 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 specific 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 VII.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71.

Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-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.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 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, 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 analytical data for fly ash transport 

water.

Comment Response: 

The commenter describes their process to calculate non-CBI pollutant loadings using only nonCBI flow data reported in the Steam Electric Survey. The commenter calculated an industrywide “non-CBI” 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-specific 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 discharge fly ash or bottom ash transport water. 

Based on the amount of ash transport water reported to be discharged, EPA calculated plantspecific 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.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 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. 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 transport water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 75 for further 

information about EPA’s rationale to use plant-specific wastewater flow rates in the loadings 

calculations rather than industry-wide median flow rates based on capacity-based model plants.
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14. Dry Fly Ash Handling 

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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-HQ-OW-2009-0819-4379-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 response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-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 information 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 9.

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 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 the 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 available for review and comment.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, 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 response to DCN EPA-HQ-OW-2009-0819-

4487-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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 43
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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 omitted); 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 

wet-to-dry fly ash conversions.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 46

External Review Flag: No External Review

External Review Incorporated 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-HQ-OW-2009-0819-0818) and median flow rates from the 

2010 ICR. To estimate capital costs, UWAG collected data from its members based on actual 
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and screening level engineering design estimates of retrofits. The following sections provide 

more details on the capital cost estimates and TWPE calculations for dry fly ash retrofits.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 49.

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

EPA-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 49

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Industry Cost-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 $9369

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 Costs
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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 fly 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 costs), 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 contributor 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, 
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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 was 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-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 in Comment 

Code 14.b for information regarding EPA’s revisions to the fly ash transport water cost 

methodology.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment Code 

13.d for more information on fly ash transport water pollutant loadings. See also the response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b regarding 

EPA’s use of source water data and the response to DCN EPA-HQ-OW-2009-0819-4283-A1, 

Excerpt Number 15 in Comment Code 26.e for further information related to net credits.

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 extent 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1
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Comment Excerpt Number: 51

External Review Flag: No External 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 unitspecific 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 1981$) 

Industry CostEffectiveness 

(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 total 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-HQ-OW-2009-0819-4379-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 sources, 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 used 
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to identify POCs in fly ash transport water and bottom ash transport water, and Section 10.2.2 for 

a description of ash impoundment data.

In addition, see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in 

Comment Code 4.b for a discussion of how EPA used the ash data to determine pollutants of 

concern and ash impoundment discharge loads.

Commenter Name: David M. Fraley

Commenter Affiliation: City Utilities of Springfield, Missouri (CU)

Document Control Number: EPA-HQ-OW-2009-0819-4382-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 handling 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 

comparison to projects completed prior to the mercury MACT and CCR publication.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 in Comment 

Code 14.b for information regarding EPA’s revisions to the fly ash transport water cost 

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-conditioned 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 section 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.
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Regarding the marketability 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 that 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-HQ-OW-2009-0819-4383-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 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: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-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. Under Options 3a, 3b, 3, 4a, 
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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 of 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 49. For the role of 

cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPA-HQ-OW2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-A1

Comment Excerpt Number: 31

External Review Flag: No External Review

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 

from $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 costs, 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 exceeding 

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.
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Comment Response: 

EPA disagrees that there is a “$404/TWPE threshold that EPA considers to be cost effective.” 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 49 for a summary of 

EPA’s fly ash transport water compliance costs and pollutant loadings. For the role of costeffectiveness in EPA’s decisions for the final rule, see response to DCN EPA-HQ-OW-2009-

0819-4655, Excerpt Number 27 in Comment Code 6.h..

See response to DCN EPA-HQ-OW-2009-0819-4448-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-HQ-OW-2009-0819-4460-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 initiative) 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 unreasonable 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 49.

Commenter Name: Paul Bailey

Commenter Affiliation: American Coalition for Clean Coal Electricity (ACCCE)

Document Control Number: EPA-HQ-OW-2009-0819-4466-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 surface 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-HQ-OW-2009-0819-4379-A1, Excerpt Numbers 49 and 51.

Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Economic and Technical Analysis

USEPA estimates 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 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 omitted); 78 Fed. Reg. 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 overestimated the pollutants attributable to 

the industry.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Numbers 49 and 51.
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Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-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 consultant 

(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 CostEffectiveness 

(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 EPAHQ-OW-2009-0819-4379-A1, Excerpt Numbers 49 and 51.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-A1

Comment Excerpt Number: 12
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For the 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 treatment 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-HQ-OW-2009-0819-4655, Excerpt Number 9.

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt 114 in Comment Code 1.c. 

regarding reopening the record for public comment.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 49.

Commenter Name: Shellie Chard-McClary

Commenter Affiliation: Association of Clean Water Administrators (ACWA)

Document Control Number: EPA-HQ-OW-2009-0819-4535-A2

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No
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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-HQ-OW-2009-0819-4593-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 ash, 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 sluicing 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 

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-HQ-OW-2009-0819-4655, Excerpt Number 138 in 

Comment Code 14.a for more information on backup wet sluicing systems.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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. UWAG 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 make the new data and analysis available for public comment.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Numbers 49 and 51 for a 

summary of EPA’s fly ash transport water compliance costs and pollutant loadings, and ash 

characterization data.

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt 114 in Comment Code 1.c. 

regarding reopening the record for public comment.

See response to DCN EPA-HQ-OW-2009-0819-4491-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 costeffectiveness calculated for the ELGs, using its updated cost estimates 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h..

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 68

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 costeffectiveness 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-HQ-OW-2009-0819-4655, Excerpt Number 9.

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt 114 in Comment Code 1.c. 

regarding reopening the record for public comment.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 70

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. EPA's Fly Ash Cost-Effectiveness 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 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); accord, 78 Fed. Reg. at 34,474 col. 1.

As we evaluated EPA’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. The 
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following sections will describe EPA’s TWPE and cost methodologies and UWAG’s costeffectiveness analysis of wet-to-dry fly ash conversions.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Numbers 49 and 51.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 73

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 Cardinal plant (October 2007, EPA-HQ-OW-2009-0881-0818) 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 

following 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 49.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 76

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 each 
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capacity-based model plant (Table 13). The dollars per 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 that EPA approved in past industry ELG rulemakings.

Table 13: UWAG Estimated TWPE and $/TWPE Using Cardinal Fly Ash Transport 

Water 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 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.31

$/TWPE – Annualized 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:
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 Unlike EPA’s estimates, UWAG’s 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, 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 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, 

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.

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 the 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 49.
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Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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-HQ-OW-2009-0819-4655, Excerpt Number 9.

See response to DCN EPA-HQ-OW-2009-0819-4487-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-HQ-OW-2009-0819-5406-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 benefits 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 handling. 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Numbers 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: S. L. Phillips

Commenter Affiliation: Louisiana Department of Environmental Quality

Document Control Number: EPA-HQ-OW-2009-0819-5509-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA is proposing 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 treatment 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 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 

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-HQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 

14.a for more information on backup wet sluicing systems.
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14.a. Dry Fly Ash Handling – Demonstration/Performance 

Commenter Name: Patrick O’Loughlin

Commenter Affiliation: Buckeye Power, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4183-A2

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Second, 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, increased 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 ash 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 achievable (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 dust 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 total 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, truck 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 impoundment and then transport it to dispose of it elsewhere, for 

example on offsite landfills.
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EPA disagrees that there will be engineering issues associated with retrofitting existing 

emissions control systems for fly ash. As discussed in preamble section VIII, 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-HQ-OW-2009-0819-4317-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 transport 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, unlike 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 landfills, 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: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 for more 

information on backup wet sluicing systems. EPA evaluated the characteristics and Steam 
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Electric Survey data for steam electric power plants that currently operate both dry and wet fly 

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 plant 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 costs, 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 disposed 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 required 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 the 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, whereby 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 that 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-HQ-OW-2009-0819-4317-A1

Comment Excerpt Number: 29

External Review 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-HQ-OW-2009-0819-4655, Excerpt Number 138 for more 

information on backup wet sluicing systems.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 their 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 challenges 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, vacuum-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 discharge 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 technology 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 several 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, available 

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 identified 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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specific adjustments to the compliance cost estimates. 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 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.” The additional scheduling considerations provided by the 

commenter, such as delivering the equipment, 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.

Regarding 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 promulgation 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 discharge 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 in Comment 

Code 14.b for more information on EPA’s changes to the fly ash cost methodology and review of 

Appendix D.

Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-A1

Comment Excerpt Number: 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 maintenance, 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 for more 

information on backup wet sluicing systems. Also, see response to DCN EPA-HQ-OW-2009-

0819-4487-A1, Excerpt 53 in Comment Code 14.b for more information on the construction of 

new landfills.

Commenter Name: Becky Hayat

Commenter Affiliation: Natural Resources Defense Council (NRDC)

Document Control Number: EPA-HQ-OW-2009-0819-4490-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.8In fact, all of the newer 

electric generating units employ dry fly ash handling methods because the current 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 transport 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. 
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Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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 retrofit 

technologies.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4487-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 unable to convert to dry handling. 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 138

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 minor 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 ash mixed with oil 

separately from fly ash that is marketable. Some plants have several units with a single dry fly 
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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 system.

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 (contrary 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 waters. 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 achievable 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 systems 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 commenter 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 metals 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) establishes 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 particular discharge on a specific receiving stream. See 

Texas Oil & Gas Ass’n et al v. US EPA, 161 F.3d 923, 927 (5th Cir. 1998)(“These limitations are 
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technology-based rather than harm based; that is, they reflect the capabilities of available 

pollution control 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 capital 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 filterreceivers, 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, over 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. EPA 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 dry 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. For 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 shutdown 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 that some plants may need an additional storage silo, level indicator, and 
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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, is 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 

Section 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-HQOW-2009-0819-4379-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 commenter 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 transport 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 recycled 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 handling 

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 transport 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 estimates and pollutant reductions 
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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 detail on EPA’s evaluation of cost effectiveness for fly ash 

transport water and bottom ash transport water, see response to DCN EPA-HQ-OW-2009-0819-

4379-A1, Excerpt Number 49 in Comment Code 14.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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 TRANSPORT 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 use 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 

units 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.
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385 TDD at 7-22 to 7-29.

386 Incremental Costs and 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 

Corporation and United Conveyance Corporation market dry vacuum systems).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4490-A1, Excerpt Number 4.
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14.b. Dry Fly Ash Handling – Costs 

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 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 generating 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 at the plant level.

 Transportation/Disposal – The trucking equipment and operation 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, 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 Costs + Purchased Equipment Installation Costs + 

Plant Overhead Engineering Costs + 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 a 
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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 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 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 operating 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 solid 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 nonhazardous 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 the 
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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 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.

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 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 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 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).

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. EPA has confirmed 
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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 follows:

 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-HQ-OW-2009-0819-2888.21, 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 yintercept 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 follows:

 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-HQ-OW-2009-0819-1959.22, 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.
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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 Intermediate Storage Cost Equation and Factors” document (EPAHQ-OW-2009-0819-1959.22, 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 wetto-dry conversion. Table 7 below shows the effect of the errors on the fly ash capital cost 

estimates for the six plants.

Table 7: Effect 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 Underestimated
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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, 

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.

EPA’s Engineering Overhead Cost Factors are Erroneous

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 total 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. 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 Appendix 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 costs4, 

excluding demolition. The engineering overhead cost factor for this case study is approximately 

22% of the total project costs5.

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 labor 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 utility 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 the 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, 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, p. 9-37.
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EPA Did Not Include Miscellaneous 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 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 state, occurrence, or effect is uncertain and that experience shows will likely 

result, 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 estimate. 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 Institute, 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 previous 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 apparently 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 costed 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, EPA 
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estimated annual O&M and recurring costs associated with wastewater 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). However, 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 material, 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 install 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 costs. 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 should 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 well 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 than the factors used by industry to estimate total direct capital costs with 
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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 for 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 unidentified 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 Timmerhaus’ 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 associated 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 

why 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 associated 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 impoundment 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 parking 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-HQ-OW-2009-0819-4655, Excerpt Number 53 in 

Comment 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 Electric 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, bottom 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.
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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 decisions 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 Limitations 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 wet 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 discharged, 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 final 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-HQ-OW-2009-0819-4655, 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 in 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.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 72

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 

portions 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 generating 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 at 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 Costs + 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 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 a 
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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 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.

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 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.

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 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 onsite CCR landfills, EPA 

included costs for these plants to transport and dispose of the 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 costs 
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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 provided 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

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

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 

ceasing 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 those costs associated with wastewater transport system, 

general operation and inspections of the impoundment site, dredging of CCRs for reuse or 
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disposal in a landfill, wastewater treatment system controls (e.g., pH control), and water recycle 

system at the 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 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.

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 (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-HQ-OW-2009-0819-2888.21), Conveyance Equipment Worksheet, the “Dry Vacuum 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 transcribed the number incorrectly from the cost curve to its economic model. The yintercept 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 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 follows:

Steel Silo Capital Cost (2010$) = (14.81 × Recalculated Steel Silo Size + 10,089) × Number of 

Steel Silos
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However, in EPA’s “NonCBI Fly Ash Intermediate Storage Cost Equation and Factors” 

document (EPA-HQ-OW-2009-0819-1959.22), 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.

Again, 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 (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 Intermediate Storage Cost Equation and Factors” document (EPAHQ-OW-2009-0819-1959.22), 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, 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 errors 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 requiring 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 Storage
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EPA must correct these errors and recalculate 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 silorelated 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 include 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 total 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. Based 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 during 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.
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Based on electric utility 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 screening-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 state, 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 generally 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 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 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 

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 offsite landfills.
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27 AACE International 2013 at 21.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for information 

regarding EPA’s revisions to the fly ash transport water cost methodology.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 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 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 Actual
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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 6.94
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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 IC&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 of 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 plants 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 estimate 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 by 
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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 EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for information 

regarding EPA’s revisions to the fly ash transport water cost methodology.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 collect 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, 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 11: Capital Costs for Wet-to-Dry Fly Ash Conversion Based on UWAG Member 

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
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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 (R2) 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 $ 
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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 simplified 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 calculations 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 response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 47.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 130

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Costs of Fly Ash Transport Water Retrofits
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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 estimates 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 subcontractors 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-HQ-OW-2009-0819-4379-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 estimates. See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 

47.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 163

External Review 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 located 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 required 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.

Comment 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for information regarding 

EPA’s revisions to the fly ash transport water cost methodology. However, EPA notes that these 
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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 Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 sluice 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 evaluation36. 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 for fly ash transport 

water38. 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 evaluation 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 system 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 By
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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; 
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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-firing39, 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 following 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 to eliminate the need for the backup wet fly ash system.

37 TDD, Section 8.1.3, page 8-25 [EPA-921-R-13-002]

38 Id. at page 8-26

39 78 Fed. Reg. at 34453 and 34474

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 

14.a for more information on backup wet sluicing systems.

EPA specifically reviewed the list of steam electric power plants provided in Table 3-2 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 letter (DCN SE05069). 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-effectiveness 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-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 76
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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 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 associated with managing these wastewaters and CCRs 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 landfill, 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 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for information 

regarding EPA’s revisions to the fly ash transport water cost methodology, including information 

on surface impoundment savings and land costs.

EPA agrees that it estimates no costs for steam electric power plant outages to install the dry fly 

ash system, based on data collected through the Steam Electric Survey and equipment 

vendors. The timeframe provided in the rule to meet the requirement supports this estimate. See 

the TDD and 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: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-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 

consuming
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for more 

information on EPA’s revisions to the fly ash handling cost methodology. As well, see response 

to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment Code 13.d for more 

information on fly ash transport water pollutant loadings.

Further, EPA agrees that some steam electric power plants may incur challenges associated with 

physical interferences or electrical power. However, EPA reviewed all plant-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 capital 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-HQ-OW-2009-0819-4448-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 continue 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 vacuum. 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 for 
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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 hopper 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 conveyance 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 equipment 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 retrofit 

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 very 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 seriously 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 for 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 they are generally in the range of $3.50-6.00/ ton of conditioned 
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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 

transporting 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). EPA 

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 analyzed 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 above, 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 this 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 overhead 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.
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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 treatment 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; however, 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 2013, 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 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 install and operate dry handling 

systems. See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for more 

information on EPA’s revisions to the fly ash handling cost methodology.

EPA is not requiring 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 steam electric power plants that did not report an onsite CCR landfill in the Steam 

Electric Survey. Based on the Steam Electric Survey, EPA determined that over 75 steam electric 

power plants dispose of fly ash in offsite landfills in 26 different states. There are no other data 

to suggest that states will stop accepting fly ash from steam electric power plants for offsite 

disposal. Therefore, EPA did not make any updates to the transport and disposal fly ash cost 

methodology.

Although the final rule is requiring zero discharge of pollutants in fly ash transport water, it is 

not requiring plants to close or stop operation of their surface impoundments. Legacy fly ash 
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transport water (this is the wastewater generated prior to the date established by the permitting 

authority that is as soon as possible beginning 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 information 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 establishing BAT. For the role of cost effectiveness in 

EPA’s decisions for the final rule, see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt 

Number 27 in Comment Code 6.h.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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-HQ-OW-2009-0819-4448-A1, Excerpt Number 30 in Comment 

Code 13.b.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 83

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

EPA recognized that several stations with dry fly ash handling also use a wet system as a 

backup28. 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 8-10 [EPA-921-R-13-002]

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 138 for more 

information on backup wet sluicing systems.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 fly 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-scratch 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-HQ-OW-2009-0819-4655, Excerpt Number 138 in Comment Code 

14.a for more information on backup wet sluicing systems.
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Based on the feedback provided by the commenter, EPA re-reviewed the Steam 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 handling 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-HQ-OW-2009-0819-4665, 

Excerpt Number 27 in Comment Code 6.h. For role of cost benefit analysis see DCN EPA-HQOW-2009-0819-4464-A1, Excerpt Number 3.

Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Alcoa-Warrick disagrees with zero discharge for fly ash as proposed in the rule. Requiring no 

wastewater discharge for a flyash 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 preventative 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.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, 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 

maintenance 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 as 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-HQ-OW-2009-0819-4765-A1, Excerpt 

Number 2 in Comment Code 5.a for more information.
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Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-A1

Comment Excerpt Number: 109

External 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 confirmed 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-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4182-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for more 

information on EPA’s revisions to the fly ash handling 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 because specific information, including the type of conversions and 

system components included in the cost estimates, are absent from the commenter’s capital cost 

estimates. See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 47.

Commenter Name: Patrick O’Loughlin

Commenter Affiliation: Buckeye Power, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4183-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 

required 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 45 for more 

information on EPA’s revisions to the fly ash handling cost methodology. Also, see response to 

DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 30 for more information on the cost 

estimates provided by AEP.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-A1

Comment Excerpt Number: 33
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External Review Flag: No External Review

External Review Incorporated 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 opposition 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 to DCN EPA-HQ-OW-2009-0819-4448-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-HQ-OW-2009-0819-4471-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 SE05069); 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-HQ-OW-2009-0819-4448-A1, Excerpt Number 30 for more 

information on the construction of new landfills.
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Commenter Name: Becky Hayat

Commenter Affiliation: Natural Resources Defense Council (NRDC)

Document Control Number: EPA-HQ-OW-2009-0819-4490-A1

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: 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 systems 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 cost 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/uploadedFiles/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.
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14.c. Dry Fly Ash Handling – Pollutant Loads 

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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, following proposal, EPA 

expanded its fly ash and bottom ash characterization dataset. See response to DCN EPA-HQOW-2009-0819-4379-A1, Excerpt Number 24 in Comment Code 4.b regarding EPA’s ash 

characterization data. See also the response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt 

Number 72 in Comment Code 15.d and DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 

38 in Comment Code 4.b for a discussion of how EPA used the 1982 TDD data to determine 

pollutants of concern and ash impoundment discharge loads, and the effect of detection limits on 

those analyses. As described in Section 12 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 

revised the loadings calculation. The revised calculation treats non-detect results as one half the 

sample-specific quantitation limit for all analytes in the loadings calculations.

See also the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment 

Code 13.d for more information about EPA’s ash characterization data, including revisions made 

after proposal.
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14.e. Dry Fly Ash Handling – Other Technology Options 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 77

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

G. The Rule Should 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 transported 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 as 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 deposited. 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 higher 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 hydraulic 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. Facilities 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 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.
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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 

technology(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; however, 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-HQ-OW-2009-0819-5093-A2, 

Excerpt Number 13.

The commenter also suggests that dense 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 limitation 

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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 52

External 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 slurry 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 deposited. 

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.
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Additionally, such a process 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 issues 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 well 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-HQ-OW-2009-0819-4655, Excerpt Number 77.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-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 of 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 solidified ash. Storm water issues may still need to be addressed, but 
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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 disruption 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-HQ-OW-2009-0819-4655, Excerpt Number 77.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 different 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 systems 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 into 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 selective catalytic 
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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 system 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 silo 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 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.

 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) will require eight (8) months of 

construction.
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 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 System

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 located 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 opened 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 determine 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 will 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 dusting 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 distribution 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 of the conversion.
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 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:

 Delivery 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 will 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 pressure 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 conditioned 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 retrofitting 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 limit the number of changes in direction to minimize pipe and 

pressure blower size, while still allowing for pipe maintenance over time.
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Scheduling considerations include the following:

 Delivery and installation of the intermediate storage silo are the critical-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.

Engineering 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 intermediate storage silo are the critical-path activities. 

Manufacturing lead time is approximately 50-60 weeks after the approved drawings are 

returned to the manufacturer.
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 Silo installation, beginning with foundations, can proceed in parallel with silo and 

support 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 aspects 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 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 recycle 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.

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 information on EPA’s cost methodology 

for the BAT basis for fly ash transport water. See also the response to DCN EPA-HQ-OW-2009-

0819-4379-A1, Excerpt Number 50 in Comment Code 14.a.
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15. Bottom Ash Transport Water

Commenter Name: Chas Spell

Commenter Affiliation: Arizona Public Service Company

Document Control Number: EPA-HQ-OW-2009-0819-4303-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. Because 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 

current 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 systems. 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-HQ-OW-2009-

0819-2186 at 498. The same reasoning 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 

strongly 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 for 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 DCN EPA-HQ-OW-2009-0819-4464-A1, 

Excerpt Number 3 (in Comment Code 6.e) and preamble section VIII.
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As described in preamble section VIII and the TDD, zero discharge technologies for control of 

bottom ash transport water are technologically available, and units 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 can 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 United 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 make 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-fired 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 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 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

EPA rejected establishing a zero discharge BAT limitation only for units above 400 MW, with 

BAT limitations based on impoundments for smaller units. See the response to DCN EPA-HQOW-2009-0819-4448-A1, Excerpt Number 40 (in Comment Code 5.c) regarding the proposed 

400-MW threshold for purposes of bottom ash transport water requirements.

See the response to DCN EPA-HQ-OW-2009-0819-4476-A1, Excerpt Number 9 (in 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-HQ-OW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQOW-2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d (in Comment Code 15.d) 

for more information about revisions to EPA’s ash characterization dataset and methodology for 

calculating pollutant loadings in bottom ash transport water.
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Commenter Name: Thomas W. Easterly

Commenter Affiliation: Indiana Department of Environmental Management (IDEM)

Document Control Number: EPA-HQ-OW-2009-0819-5553-A2

Comment Excerpt Number: 5

External Review 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-HQ-OW-2009-0819-4283-A1, Excerpt Number 14 (in Comment Code 

6.i.i) and preamble section VIII. See response to DCN EPA-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4464-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 Number: EPA-HQ-OW-2009-0819-4283-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 important 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 sampling 
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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 transport 

water from all existing steam electric generating units. See response to DCN EPA-HQ-OW2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Bottom Ash Transport Water:

 EPA has not justified zero discharge for bottom ash transport water.

 Surface impoundments should 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-HQ-OW-2009-

0819-4303-A2, Excerpt Number 7.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 25

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 the 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7. 

Moreover, EPA notes that the final rule, which is based in part on zero discharge limitations 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-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 (in comment code 6a).

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 equal 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 regulated 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 impoundments.” See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt 

Number 7. 
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Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 72

External Review Flag: No External 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 actual 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-HQ-OW-2009-0819-4303-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-HQ-OW-2009-0819-4305-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 analysis 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 for bottom ash transport water. Furthermore, the methodology in which nondetects 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 pollutant 

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.
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With the pollutant and TWPE removal overestimated and the costs underestimated, 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 limits as proposed for Regulatory Options 1, 3a, 2, 3b, 

and 3.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7. Also see the TDD 

and response to DCN EPA-HQ-OW-2009-0819-4499-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-HQ-OW-2009-0819-4655, 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 bottom 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-HQ-OW-2009-

0819-4305-A3, Excerpt Number 77 in Comment Code 7.

Commenter Name: Leonard F. Hopkins

Commenter Affiliation: Southern Illinois Power Cooperative (SIPC)

Document Control Number: EPA-HQ-OW-2009-0819-4309-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 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). EPA has not demonstrated that retrofitting 

existing systems to implement dry bottom ash handling is cost-effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.
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Commenter Name: Nancy A. Evans

Commenter Affiliation: PPL Services Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4348-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 would require dry handling or closed-loop bottom ash systems. 

The justification remains the same and therefore EPA should not require dry handling or closedloop systems for bottom ash transport water in the final ELG rule.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: P. J. Becker

Commenter Affiliation: City Water, Light and Power (CWLP)

Document Control Number: EPA-HQ-OW-2009-0819-4349-A2

Comment Excerpt Number: 5

External Review Flag: No External 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1
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Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Of the major wastestreams, retrofitting dry or 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 current 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 3
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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 EPAproposed options are not justified in the record, nor are they cost effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 14

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 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 discharge 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) its 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 contains 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 

selecting 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, 
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Development Document for Effluent Limitations Guidelines and Standards and Pretreatment 

Standards for the Steam Electric Point Source Category (1982 Development Document), EPA

HQ-OW-2009-0819-2186 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-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 treatment 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 

stream and the high costs of treatment, based on $/TWPE removed.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Jerry Purvis

Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC)

Document Control Number: EPA-HQ-OW-2009-0819-4455-A1

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Second, EPA has 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. In light of the fact 

that all preferred BAT alternatives would require dry handling 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 them 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, and 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 transport 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 existing steam electric generating units.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 impoundments 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 impoundments. 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 regulation of bottom ash transport water as BAT, PowerSouth 

nevertheless believes that continued use of surface impoundments should be permissible for all 
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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 difficult 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-HQ-OW-2009-0819-4303-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.

Document Control Number: EPA-HQ-OW-2009-0819-4462-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 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). EPA has not demonstrated that retrofitting 

existing systems to implement dry bottom ash handling is cost-effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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) 
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FOR BOTTOM 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 3,6as 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 or 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

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 cause 

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 ash 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.
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Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 beneficially 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 residuals 

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 under 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 reduction, 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 sophisticated 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 under 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 under 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)
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Comment Response: 

EPA acknowledges the commenter’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 

water (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 beneficial 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, decreasing 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 closedloop 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 use 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 disagrees 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7 and DCN EPA-HQ-OW-2009-

0819-4464-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 information.

Commenter Name: Paul Bailey

Commenter Affiliation: American Coalition for Clean Coal Electricity (ACCCE)

Document Control Number: EPA-HQ-OW-2009-0819-4466-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). 
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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 

Control 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 stream. 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 control.”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 response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Raven Power Holdings, LLC

Commenter Affiliation: Raven Power Holdings, LLC

Document Control Number: EPA-HQ-OW-2009-0819-4467-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 continue 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 significant 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 spills. Zero 
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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 on 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-HQ-OW-2009-0819-4464-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 

response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Raven Power Holdings, LLC

Commenter Affiliation: Raven Power Holdings, LLC

Document Control Number: EPA-HQ-OW-2009-0819-4467-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 compound to significantly increase the effective cost per 

TWPE.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-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).
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Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4471-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 concentration 

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 costeffective. (See UWAG comments Section V - BAT for Bottom Ash Transport Water.)

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-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-HQ-OW-2009-0819-4475-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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies
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Document Control Number: EPA-HQ-OW-2009-0819-4475-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 transport 

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 systems 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 46

External Review Flag: No External Review

External Review Incorporated 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 would 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 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 

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 data 
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did not indicate that a quantifiable reduction 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 to 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 dissolved 

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-HQ-OW-2009-0819-4303-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 

Station, 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-HQ-OW-0819-

4379-A1, Excerpt Number 35 (in Comment Code 16.b).

Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (MP)

Document Control Number: EPA-HQ-OW-2009-0819-4484-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 

proposed 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7. Responses 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.
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Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-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 choose 

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 implementation 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-HQ- OW-2009-

0819-2186, 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 transport 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 proposed 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 objectives 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7. EPA notes that, as 

required 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 that 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.
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See response to DCN EPA-HQ-OW-2009-0819-4655, 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

Document Control Number: EPA-HQ-OW-2009-0819-4489-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 regulation 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/closedloop 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 accurate 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-HQ-OW-2009-0819-4303-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 difficult 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 Resources Defense Council (NRDC)

Document Control Number: EPA-HQ-OW-2009-0819-4490-A1

Comment Excerpt Number: 7
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Options 4 and 5 are the only regulatory 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 less 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 and 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 additional 

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 did 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 impoundments, 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 section 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-HQ-OW-2009-0819-4448-A1, Excerpt 

Number 40 (in comment code 5.c), for a discussion of the proposed 400-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-HQ-OW-2009-0819-4467-A1, Excerpt Number 11. Also see preamble 

section VIII.G and response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 16, 
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regarding the reuse of bottom ash wastewater in some in-plant processes and water use 

reductions. See also 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-HQ-OW-2009-0819-4490-A1

Comment 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 handling 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 discharges18, Option 5 

would also yield the greatest reductions in water use as a result of requiring zero discharge for 

bottom ash transport water.

18 ELGs at 34,473.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4490-A1, Excerpt Number 7. Also see preamble 

section VIII.G and response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 16 

regarding the reuse of bottom ash wastewater in some in-plant processes and water use 

reductions.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-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 equal to the current limits for bottom ash transport 
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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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-A1

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

See also response to DCN EPA-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Preferred Option 4a - Bottom Ash Transport Water

NRG does not support the alternative for BAT referred 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-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 

effluent 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 appropriate 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 phase, 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 exceed 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 controls,

 Turbidity curtains,

 Filtration, and

 Use of polymers.
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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 recycle, 

only the portion of wastewater to be discharged could be treated.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-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 commenter, including the effect of 

adding other low volume waste sources. Therefore, EPA cannot respond to the commenter’s 

assertions. See response to DCN EPA-HQ-OW-2009-4765-A1, Excerpt Number 8 (in Comment 

Code 6.a) for more discussion on dissolved metals.

Commenter Name: Becky Smith

Commenter Affiliation: Clean Water Action et al.

Document Control Number: EPA-HQ-OW-2009-0819-4548-A1

Comment Excerpt Number: 6

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 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 coalburning boilers with a generating capacity above 400 MW to do so.10 The remaining plants 
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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 pollutants 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-HQ-OW-2009-0819-4303-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-HQ-OW-2009-0819-4557-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 onerous 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. Furthermore, 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

EPA disagrees that there “is no real environmental need to require dry ash handling of bottom 

ash.” See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7. See also 

response to DCN EPA-HQ-OW-2009-0819-4467-A1, Excerpt Number 11, regarding 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-HQ-OW-2009-0819-4565

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NRECA also recommends:

Continued wet handling of bottom ash in surface impoundments.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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: Dorothy Kellogg and Michael Leitman

Commenter Affiliation: National Rural Electric Cooperative Association (NRECA)

Document Control Number: EPA-HQ-OW-2009-0819-4565-A1

Comment Excerpt Number: 6

External Review Flag: No External 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 

current BPT limits for bottom ash transport water (EPA’s Options 1-3, including EPA preferred 
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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-HQ-OW-2009-0819-4464-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.

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Erin Bartlett

Commenter Affiliation: The Large Public Power Council (LPPC)

Document Control Number: EPA-HQ-OW-2009-0819-4573-A1

Comment Excerpt Number: 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 

units 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 when 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 (including 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 bottom ash 

transport water, as proposed for combustion residual leachate, rather than require conversion to a 

dry handling system.
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6 78 Fed. Reg. 34,463 (June 7, 2013).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-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 to DCN EPAHQ-OW-2009-0819-4464-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: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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.

See response to DCN EPA-HQ-OW-2009-0819-4448-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

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We support EPA's proposed 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, however, 

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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Public Service Company of New Hampshire(PSNH)

Document Control Number: EPA-HQ-OW-2009-0819-4633-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 or 
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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 preferred 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 facilities 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Bottom ash transport water

Options 1-3

Impoundment

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 25

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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.

Because 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 settling pond and equal to the 

current BPT limits for bottom ash transport water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Claire M. Olson

Commenter Affiliation: Basin Electric Power Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4666-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 discharge 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 Station to opt out when it can be demonstrated that bottom ash 
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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-HQ-OW-2009-0819-4303-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 that 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 discharges 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 Utilities (OMU) Elmer Smith Station (ESS)

Document Control Number: EPA-HQ-OW-2009-0819-4683-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

6. BAT for bottom ash transport 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 discharge 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 control. 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment 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 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. Moreover, EPA 

failed to base its 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, the evidence 

that zero discharge systems are economically achievable is even more overwhelming.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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.
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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 discharges; 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 vacuum 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, counting 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 

discharge 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 that 

“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 water 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).
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Comment 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 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 

transport 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 transport 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 all. 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 discharge 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 compared 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 than 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 estimated 
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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 not available to accurately estimate a plantspecific 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 timing 

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 systems 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); Weyerhaeuser 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 and 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 EPAHQ-OW-2009-0819-4684-A1, Excerpt Number 108 (in comment code 28.b). EPA addressed the 

commenter’s concerns regarding equipment life in the response to DCN EPA-HQ-OW-2009-

0819-4684-A1, Excerpt Number 109 (in comment code 28.b).

EPA disagrees that it overestimated operating and maintenance (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 Steam 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-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 106

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 BAT determination; the correct legal standard 

is whether costs can be borne by the industry as a whole.444 However, if EPA considers costeffectiveness, 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 bottom 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

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 section VIII for more discussion of EPA’s 

rationale. EPA also notes that the cost-effectiveness of the final rule is within the range of costeffectiveness values of ELGs established for other industries. See preamble section XV.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 112

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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 reduction, non-water quality 

environmental impact (including energy requirements),” and other factors EPA deems 

appropriate.477 None of these factors alters the conclusion that the statute requires EPA to set 
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EPA’s Response to Public Comments

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effluent limits eliminating the discharge of bottom ash transport water because zero discharge 

systems are technologically 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 standard 

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 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.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.

Comment 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 agrees 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-HQ-OW-2009-0819-4467-A1, Excerpt Number 11.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 3
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The EPA has proposed eight options to control these 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 Achievable 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: 

See 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-HQ-OW-2009-0819-4704-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 properly 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-HQ-OW-2009-0819-4684-A1, Excerpt Number 102.
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Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-A1

Comment Excerpt Number: 5

External Review Flag: 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-HQ-OW-2009-0819-4303-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-HQ-OW-2009-0819-4768-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 page 34436).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.
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Commenter Name: Mark W. Metcalf

Commenter Affiliation: Wisconsin Public Service Corporation (WPS)

Document Control Number: EPA-HQ-OW-2009-0819-4770-A2

Comment 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 quantifiable 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 

supplemental 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 45

External Review Flag: No External 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 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.

Because of bottom ash transport water’s small contribution of toxics and high cost of 

treatment, on a $/TWPE basis, APPA supports Options 1.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Patrick O’Loughlin

Commenter Affiliation: Buckeye Power, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4183-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 impoundments 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Surface impoundments should continue as the technology basis for treating bottom ash transport 

water for all units, regardless of size.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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.
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Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 all units, regardless of size.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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: Joe L. Citta

Commenter Affiliation: Nebraska Public Power District (NPPD)

Document Control Number: EPA-HQ-OW-2009-0819-4310-A1

Comment Excerpt Number: 8

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

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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)
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Document Control Number: EPA-HQ-OW-2009-0819-4455-A1

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into 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 EPA-HQ-OW-2009-0819-4464-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: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-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-HQ-OW-2009-0819-4464-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: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No
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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-HQ-OW-2009-0819-4464-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: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 surface 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 systems.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 systems).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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 determining 
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BAT, as it is technologically available, economically achievable, and has acceptable non-water 

quality environmental impacts. See preamble sections VIII, IX, and XII.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4464-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: Raven Power Holdings, LLC

Commenter Affiliation: Raven Power Holdings, LLC

Document Control Number: EPA-HQ-OW-2009-0819-4467-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-OW-2009-0819-4464-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.
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Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-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 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-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4475-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-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 14
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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 Cooper 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-HQ-OW-2009-0819-4464-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” associated with limitations on 

bottom ash transport water. See response to DCN EPA-HQ-OW-2009-0819-4467-A1, Excerpt 

Number 11.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-A1

Comment Excerpt 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 for bottom ash transport water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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.
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Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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 proposed 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 discussion, 

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-HQ-OW-2009-0819-4464-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 Affiliation: Tampa Electric Company (TEC)

Document Control Number: EPA-HQ-OW-2009-0819-4520-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Of the options offered by EPA, TEC supports the continued use of impoundments as the best 

practicable technology (BPT) for bottom ash transport water.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-5140-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:

Table 2:

Wastestream Record Supports No More than This 

Option

Bottom ash transport water Options 1-3 Impoundment

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4034-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 has 
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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 coalburning boilers with a generating capacity above 400 MW to do so.10 The remaining plants 

under each of these options would still be allowed 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 technologically available and affordable, yet EPA’s “preferred” options for 

bottom ash handling ignores this trend.

9

78 Fed. Reg. at 34,470

10Id. at 34,458 (Table VIII-1)

11Id. at 34,476

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt 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-HQ-OW-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 are not 

adversely impacting the environment. If an impoundment provides appropriate treatment for 
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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 response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

Commenter Name: Shellie Chard-McClary

Commenter Affiliation: Oklahoma Department of Environmental Quality (DEQ)

Document Control Number: EPA-HQ-OW-2009-0819-4181-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, then 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 nonwater quality environmental impacts, as required by the Clean Water Act. See also response to 

DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3.

Commenter Name: Chuck D. Barlow

Commenter Affiliation: Entergy Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4519-A2

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I. The requirements for Best Available Technology ("BAT") for bottom ash transport 

water need to be clarified .
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In the ELG Proposed Rule, EPA identifies closed-loop systems that recycle the sluice water as 

BAT for bottom ash transport , as these systems 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 operations 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 classified 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 such 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 twoyear 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 systems 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 store 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 limitations 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7.

For the role of cost-benefit analysis in EPA’s decisions on this final rule, see response to DCN 

EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 (in comment code 6.a).

EPA notes that it did not establish numerical limits on discharges of bottom ash transport water 

because it determined that zero discharge limitations and standards – which control pollutants to 

the greatest degree – were available and achievable.
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Commenter Name: Nysa Hogue

Commenter Affiliation: Indianapolis Power & Light Company (IPL)

Document Control Number: EPA-HQ-OW-2009-0819-4454-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 units 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. However , 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-HQ-OW-2009-0819-4519-A2, Excerpt Number 1 and DCN EPAHQ-OW-2009-0819-4475-A1, Excerpt Number 51 (in Comment Code 15.b).
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15.a. BA Transport Water – General/Scope 

Commenter Name: Jerry Purvis

Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC)

Document Control Number: EPA-HQ-OW-2009-0819-4455-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 control 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-HQ-OW-2009-0819-4464-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-HQ-OW-2009-0819-4448-A1, Excerpt 

Number 40 (in Comment Code 5.c).

Commenter Name: John C. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-A1

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review 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 by 
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EPA and should not be finalized; instead authorization of existing management practices should 

be continued.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4455-A1, Excerpt Number 6.

Commenter Name: John C. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-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: overestimated bottom ash impacts; arbitrarily selected unit size criteria; and 

not provided an adequate administrative record.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4455-A1, Excerpt Number 6.

EPA disagrees that bottom ash impacts have been overestimated. See the TDD and the response 

to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 47 (in Comment Code 15.d) for more 

information on EPA’s bottom ash pollutant loadings data and methodology and the response to 

DCN EPA-HQ-OW-2009-0819-4475-A1, Excerpt Number 54 (in Comment Code 16.c) for 

EPA’s response specific to bottom ash overestimating pollutant removals.

Additionally, EPA disagrees that it “arbitrarily selected unit size criteria.” See the preamble for 

EPA’s rationale for establishing a 50 MW threshold for purposes of the final rule’s requirements 

for existing sources (including requirements for bottom ash transport water). The final rule does 

not establish a 400 MW threshold for purposes of the bottom ash transport water requirements 

for existing sources, for the reasons described in preamble Section VIII.C.3. See also the 

response to DCN EPA-HQ-OW-2009-0819-4448-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 (see 
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preamble sections VIII, IX, and XII). The record also shows significant 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-HQ-OW-2009-0819-4508-A2

Comment Excerpt 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 

determined 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). Additionally, 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 respect 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-HQ-OW-2009-0819-4633-A1, Excerpt Number 46 (in Comment Code 6.g.ix) for 

more information on cyclone boilers, the technologies evaluated for BAT, and wastewater 

characterization.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 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 high 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 quantifiable 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 Steam Electric Point Source Category” (1982 Development 

Document) EPA-HQ-OW-2009-0819-2186 at 498.

The same reasoning applies just as much today as it did in 1982. The low level of toxics in 

bottom 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-HQ-OW-2009-0819-4303-A2, Excerpt Number 7 (in Comment 

Code 15).

Commenter Name: Jim Weeks

Commenter Affiliation: Michigan Municipal Electric Association (MMEA)

Document Control Number: EPA-HQ-OW-2009-0819-4767-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-HQ-OW-2009-0819-4455-A1, Excerpt Number 6.
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Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 most 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 feasible 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 that 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-HQ-OW-2009-0819-2186 at 498.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 7 (in Comment 

Code 15).
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15.b. BA Transport Water – Profile 

Commenter Name: John C. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-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 numerous 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 decant 

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 effectively 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.

Comment 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 electric 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 response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 40 (in 

Comment Code 5.c) and preamble section VIII for more information on EPA’s evaluation of the 

400-MW threshold for bottom ash transport water.

EPA notes that the plant may continue using the impoundments 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, another 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.
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Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 regular 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 cooling 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 

Statutory 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 bottom 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 

temporarily 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 mechanical drag system, eliminating the need to 

dredge the bottom ash from the impoundments.
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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-HQ-OW-2009-0819-4475-A1

Comment 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 that 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 constituents 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 bottom 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.
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Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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 Bottom 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 discharged. 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 pollutants 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 permit (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 additional 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 categorical limits and most 

water quality based effluent limits.

22 NR 105 and 106, Wisconsin Administrative Code
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23 On August 1, 2013, We Energies submitted an application requesting a variance from the 

water quality standard for arsenic in connection with water 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 widespread 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 transport 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 impoundment 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 from 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 recycle 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 Electric 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 estimate 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. Additionally, 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 control 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 

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).

EPA disagrees that “low concentrations of Total Suspended 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.”
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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 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 water quality 

based effluent limitations established to protect impacts on a specific receiving stream. See the 

response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61 (in Comment Code 

6.c) for discussion of the difference in the function and basis of ELGs and water quality 

standards.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt 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 treat bottom ash transport water to meet most water quality 

based effluent limits.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4475-A1, Excerpt Number 51.

Commenter Name: Daniel K. Plath

Commenter Affiliation: Northern Indiana Public Service Company (NIPSCO)

Document Control Number: EPA-HQ-OW-2009-0819-4508-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 boilers 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 water 
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quenched in the slag bath, and forms solid boiler slag. The resulting boiler slag is both 

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 granules, 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 produces.

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-HQ-OW-2009-0819-4508-A2, Excerpt Number 4 (in Comment 

Code 15.a).

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 portion 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 potentially 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, as 
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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-HQ-OW-2009-0819-4310-

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-HQ-OW-2009-0819-4665-A2

Comment Excerpt Number: 6

External Review Flag: No External Review

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 wastewater 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 of 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 and 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 transport 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 with 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 while the 

bottom ash transport water is stored in tanks during the 5-year routine maintenance.
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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-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Ash is the non-combustible 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 sand 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 is 
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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://cfarm.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-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated 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.778 Fed. Reg. at 34,453. These plants generate 

286,000 MW or 87% of the 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 

rulemaking, 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-HQ-OW-2009-0819-4310-A1, Excerpt Number 9, in 

comment code 16.a.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No
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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. Wetbottom boilers 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 sluicing 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 

connected 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 dewatering 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 system; Available at: 

http://fatdad94.com/index_htm_files/BOTTOM%20AND%20FLY%20ASH%20SYSTEM%20

MAINTENANCE.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.
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15.c. BA Transport Water – Wastewater Characterization 

Commenter Name: John C. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-A1

Comment Excerpt Number: 41

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

AER reviewed bottom ash 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 impacts 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 relatively 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 do 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 performance 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-HQ-OW2009-0819-4305-A3, Excerpt Number 61 in Comment Code 6.c for discussion of the difference 

in the function and basis of ELGs and water quality standards.

EPA evaluated pollutants of concern (POCs) for bottom ash transport water, considering data 

collected from multiple sources. EPA disagrees that the only POC for bottom ash transport water 

is boron. See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 (in 

Comment Code 6.a) and Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum

(DCN SE04745) for more details on EPA’s determination of POCs for ash transport water.
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Regarding bottom ash from pulverized and cyclone boilers see response to DCN EPA-HQ-OW2009-0819-4508-A2, Excerpt Number 5 (in Comment Code 15.b) and response to DCN EPAHQ-OW-2009-0819-4508-A2, Excerpt Number 4 (in Comment Code 15.a).

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 impoundment 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 difference 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 

Sluice Water*

EPA Reported

Average

Bottom Ash 

Concentration

Arsenic mg/L 0.003 0.004 0.018
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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

Difference
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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-HQ-OW2009-0819-4655, 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, including discussion of use of 1982 TDD data, use of 

combined ash impoundment data, source water pollutant contributions, handling of non-detects, 

and sulfides.
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See the response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 74 (in Comment 

Code 15.d) for EPA’s evaluation of 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).

EPA evaluated POCs for bottom ash transport water, considering data collected from multiple 

sources. See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 (in 

Comment Code 6.a) and Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum

(DCN SE04745) for more details on EPA’s determination of POCs for ash transport water.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 

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-HQ-OW-2009-0819-

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-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 (in 

Comment Code 6.a) and Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum

(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 addition, 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 section VIII.
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Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-A1

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into 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 identify 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 

with 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 Various 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 transport 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 wastewater 
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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 bottom 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 ash 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 Generating 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 facilities, 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 both fly ash transport water and bottom ash transport water. See the response 

to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 (in Comment Code 6.a) and 

Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum (DCN SE04745) for more 

details on EPA’s determination of POCs for ash transport water.

For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised 

its estimates of ash impoundment effluent concentrations. See the response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 72 in Comment Code 15.d for more information about to EPA’s ash 

characterization dataset and steps for calculating pollutant loadings in bottom ash transport water 

for the final rule.

See the response to DCN EPA-HQ-OW-2009-0819-4464-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.
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See the response to DCN EPA-HQ-OW-2009-0819-4476-A1, Excerpt Number 12 (in Comment 

Code 15.d) regarding data comparing bottom ash to “average soil.”

In response to the commenter’s comparison of fly ash transport water characteristics to bottom 

ash transport water characteristics, this is not relevant to EPA’s BAT determination. Further, 

EPA’s analysis projects significant pollutant reductions as a result of the zero pollutant discharge 

requirements (BAT/BDCAT) on bottom ash transport water.

Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-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-HQ-OW-2009-0819-4464-A1, Excerpt Number 13.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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 Detailed Study (EPA-HQ-OW-2009-0819-

0004, Tables 5-5 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 below. 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 than 
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fly ash transport 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 Characteristics20

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)
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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 exponentially 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- HQ-OW-2009-0819-0004, Table 5-5 at 5-7 – 5-10 and Table 5-9 at 5-17 – 5-20, 

October 2009.

21 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-HQ-OW-2009-0819-4464-A1, Excerpt Number 13.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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-HQ-OW-2009-0819-4464-A1, Excerpt Number 13.
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Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-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 options 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 significantly 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 

sources. See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 (in 

Comment Code 6.a) and Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum

(DCN SE04745) for more details on EPA’s determination of POCs for ash transport water.

EPA agrees with the commenter that “the chemical composition of bottom ash transport water 

has not changed significantly since the 1982 rulemaking”; as such, the characterization data from 

the 1982 TDD continue to be valid for use in estimating pollutant loadings associated with 

bottom ash transport water. However, EPA disagrees that the same technology basis (i.e., surface 

impoundments) is BAT for all existing units 30 years later. See the response to DCN EPA-HQOW-2009-0819-4464-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.
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Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-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 sufficiently 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 pollutant-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-HQ-OW-2009-0819-2186 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-HQ-OW-2009-0819-4476-A1, Excerpt Number 9.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-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 concern. 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 

plants, the priority inorganic pollutants detected in bottom ash water were less than the 
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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-HQ-OW-2009-0819-4476-A1, Excerpt Number 9.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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 should 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 any of EPA’s 

alternatives for “zero discharge” limits for bottom ash transport water.

19 EPA Technical Development Document, 1982. EPA-HQ-OW-2009-0918-2186.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4476-A1, Excerpt Number 9. EPA 

disagrees with the commenter’s claim that zero discharge technologies are too costly; EPA reevaluated the costs associated with the installation and operation of the BAT and NSPS 

technology bases of dry handling or closed-loop systems after considering public 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 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, for existing sources, these 

technologies are technologically available 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 Service Company (NIPSCO)
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Document Control Number: EPA-HQ-OW-2009-0819-4508-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NIPSCO recommends that USEPA clearly distinguish, 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. NIPSCO 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 

boiler 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 these 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 management, not cyclone boiler slag management.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4633-A1, Excerpt Number 46 in Comment 

Code 6.g.ix and EPA-HQ-OW-2009-0819-4508-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 

ash 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 achievable 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.
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Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Bottom Ash 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 particles 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 from 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 plant 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 discharged 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 ash transport water, 

considering data collected from multiple sources. See the response to DCN EPA-HQ-OW-2009-

0819-4460-A1, Excerpt Number 50 in Comment Code 6.a and Bottom Ash and Fly Ash 

Pollutants of Concern Analysis Memorandum (DCN SE04745) for more details on EPA’s 

determination of POCs for ash transport water.

For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and its 

estimates of ash impoundment effluent concentrations. See the response to DCN EPA-HQ-OW2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt 
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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 commenter’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 zero 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-HQ-OW-2009-0819-4573-A1

Comment 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‐like 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-HQ-OW-2009-0819-4476-A1, Excerpt Number 9.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-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 the 
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proposed rule, bottom ash is a combustion residual of heavier ash particles collected at the 

bottom of a boiler. 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-HQ-OW-2009-0819-4510-A2, Excerpt Number 18.

Commenter Name: Kim Mireles

Commenter Affiliation: Luminant

Document Control Number: EPA-HQ-OW-2009-0819-4614-A1

Comment Excerpt Number: 4

External 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 identified 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-HQ-OW2009-0819-4460-A1, Excerpt Number 50 (in Comment Code 6.a) and Bottom Ash and Fly Ash 

Pollutants of Concern Analysis Memorandum (DCN SE04745) for more details on EPA’s 

determination of POCs for ash transport water.

For the final rule, EPA expanded its fly ash and bottom ash characterization dataset and revised 

its estimates of ash impoundment effluent concentrations. See the response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 47 (in Comment Code 15.d) for more information about 
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EPA’s ash characterization dataset and steps for calculating pollutant loadings in bottom ash 

transport water.

Commenter Name: Kim Mireles

Commenter Affiliation: Luminant

Document Control Number: EPA-HQ-OW-2009-0819-4614-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 evaluation 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 

ago 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 effluent 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 the 
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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 pollutant loadings associated with bottom ash 

transport water due to the reasons stated by the commenter. See the response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt 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 

for the final rule, including discussion of use of 1982 TDD data, use of combined ash 

impoundment data, source water pollutant contributions, handling of non-detects, and sulfides. 

See response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 14 regarding EPA’s 

collection of “a single bottom ash sample.” See section 12 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 on how EPA determined pollutant concentrations for 

use in calculating baseline pollutant loadings and pollutant reductions under the final rule.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 41 in Comment Code 

15.d regarding Form 2C data.

See response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 14 in Comment 

Code 15.d regarding EPA’s collection of a “single” bottom ash sample.

Commenter Name: Kim Mireles

Commenter Affiliation: Luminant

Document Control Number: EPA-HQ-OW-2009-0819-4614-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

External 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 water6is erroneous 

and inappropriate.

For this rulemaking, 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 selected 

pollutants of concern based on only two samples for 12 metals and one sample for the other 26 

pollutants. ERG POC Methodology memorandum, EPA-HQ-OW-2009-0819-2151, Table 4-3 at 
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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 ELGs. 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 occurring 

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-HQ-OW-2009-0819-2151 at 9. EPA did not analyze this nitrate/nitrite sample 

within 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/nitrite 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, even those that do not use coal or oil as their primary 

fuel.

6ERG, Pollutants of Concern Methodology Memorandum, EPA-HQ-OW-2009-0819-2151 at 10.

Comment Response: 

EPA disagrees that, for the final rule, it “abandoned is traditional method of identifying POCs.” 

EPA evaluated POCs for bottom ash transport water, considering data collected from multiple 

sources. See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 (in 

Comment Code 6.a) and Bottom Ash and Fly Ash Pollutants of Concern Analysis Memorandum

(DCN SE04745) for more details on EPA’s determination of POCs for ash transport water. 

Regarding EPA’s approach for identifying POCs for ash transport water, see response to DCN 

EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d.

For the final rule, EPA supplemented its fly ash and bottom ash characterization dataset for 

determining the ash impoundment effluent concentrations. Based on this dataset, EPA identified 

nitrate/nitrite as a POC for bottom ash transport water. See the response to DCN EPA-HQ-OW2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt 

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.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655
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Comment Excerpt Number: 29

External Review Flag: No External Review

External Review Incorporated 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 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 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-HQOW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt 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, including discussion of use of 1982 TDD data, use of combined ash impoundment data, 

source water pollutant contributions, handling of non-detects, and sulfides. See section 12 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 on how EPA determined pollutant 

concentrations for use in calculating baseline pollutant loadings and pollutant reductions under 

the final rule.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 49

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 own 
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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, UWAG 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 wastestreams, 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 should 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 characterization 

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 lowlevel method (Method 1631E) or an equivalent method. Where a member provided more than 

one sample for the same outfall, we 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 than 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 7 
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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 

data 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 and 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 analytical 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 sampled 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 sufficient 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 identification 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 simulate 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 supplemented its fly ash and bottom ash characterization dataset and 

revised its estimates of ash impoundment effluent concentrations. See the response to DCN EPAHQ-OW-2009-0819-4655, 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.
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See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 41 in Comment Code 

15.d for further discussion regarding the use of Form 2C data.

Commenter Name: Claire M. Olson

Commenter Affiliation: Basin Electric Power Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4666-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

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 have 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 ash 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 Levels (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, 

concentrations 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-HQ-OW-2009-0819-4464-A1, Excerpt Number 13.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment 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: (1660+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 (costeffectiveness). See the final RIA.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 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-HQOW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 72 in Comment Code 15.d and for more information about EPA’s ash 

characterization dataset and steps 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 sulfides. See section 12 of the 
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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.
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15.d. BA Transport Water – Calculation of Baseline Loads

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 47

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 Development 

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 values 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 source waterbody.
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2. Sulfides Should Not Be Attributed to Bottom Ash Transport Water 

Sulfides clearly dominate EPA’s estimates, making up more than 58% of EPA’s 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. Given the many problems UWAG has identified 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 other EPA sampling program pond data have been 

completely overwhelmed by the questionable, very old, and not representative 1982 

Development Document data. 

Because of analytical methods with EPA-approved methods for measuring sulfides, described in 

the attached report by URS Corporation (Attachment 5), UWAG undertook its own sampling and 

analysis for sulfides at several facilities. The results are presented at page 7 and in Table 1 of the 

URS report. 
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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 colorimetric 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 for 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 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, 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 nondetect values. This simple adjustment of non-detects reduces 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 from 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 detection 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. However, 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 

also screened out unreasonably high non-detects. Based on these corrections, the TWPEs drop 

from 84,389 to 3,154.
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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 that 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 data 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 only. 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 for 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 accounting 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 (corrected for source water pollutants), while EPA’s estimate is a staggering (and 

highly unrealistic) 2,716,059.
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Comment Response: 

The commenter calls into question the validity of data used to characterize typical bottom ash 

transport water, citing an analysis prepared by the commenter’s consultant, URS (see DCN EPAHQ-OW-2009-0819-4655-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-HQ-OW-2009-

0819-4499-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 and 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 misrepresenting 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-HQ-OW-2009-0819-4499-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 dissolution. 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 

dataset. 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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d, ensuring 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 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 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in 

Comment Code 15.d.
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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 before 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-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 24 in Comment Code 4.b regarding the final rule ash characterization 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 combined 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-specific 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 only,” 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 combined 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 representative 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 wastewater. 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 use 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/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-
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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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 

Option 4(a), approximately 88% or 1,389,167, are constituents that are not actually present in 

bottom ash sluice water at levels indicated by EPA23. 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 reasons 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-detects 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 used 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

Issues
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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 nondetects

Silver 48,681 3%

Poor methodology evaluating nondetects

Thallium 75,321 5%

Poor methodology evaluating nondetects

Tin 62,449 4%

Poor methodology evaluating nondetects

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 

data 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 particular 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 Concentrations
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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 4a24. 

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 evaluated for the 1982 revisions to the ELGs. All of the nondetects 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 

loadings 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 4a25. 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 not 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 failed 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 nondetectable 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 ash sluice 

water.
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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 non-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 detected 

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 0.004
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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 19, 2013.

24

 ERG Memo Steam Electric Pollutant-Level Loadings and Removals for Each Wastestream 

and Regulatory Option, April 19, 2013.

25 Id.
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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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, 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 discussion 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 container 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 analyses conducted by UWAG, an industry trade association. In a 

November 2014 letter, UWAG presented a comparison of settled sluice pipe samples to neareffluent discharge point samples and acknowledged 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). 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 acceptable 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-HQ-OW-2009-0819-4655

Comment Excerpt Number: 60

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 three 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 Data20

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-nitrite
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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 the 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 analytical 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 data 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 values 

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

$/TWPE

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 $123
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MW Range

UWAG Data

$/TWPE

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.

20See Attachments 29, 30, 31, and 32.

21UWAG 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/nitrites 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 47 and other responses in this comment code 

(Comment Code 15.d).
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EPA reviewed the bottom ash transport water data collected from Homer City and determined 

that there was no supportable reason to exclude this sample from 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 loadings 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 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) and Section 10 of the TDD, 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 identify 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-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 nonrepresentative non-CBI median flow rates based on capacity-based model plants.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 26

External Review Flag: No External Review

External 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 all 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 industry analysis 

estimates only 65,342 TWPEs. The reasons for the difference between the two estimates are 

numerous, as we will explain below.
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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 

facilities, 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 nondetects, 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 FGD 
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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 containing 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 problems 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 Development 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 contributor 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 contained 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.
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For mercury, EPA has 14 data points, nine of which are 1982 Development 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 City 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 analysis 

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. Although the remaining data set includes two non-detects from recent data, the nondetects 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 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. However, one data point was eliminated 

because it included FGD wastewater. For the other three data 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 only 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 

removed. 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. Again 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 EPA’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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47 for more information about revisions to 

EPA’s ash characterization dataset and approach for calculating pollutant loadings in bottom ash 
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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 sulfides.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 calculating 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 represent 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 discussed 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 value. 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 ponds 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 nondetected values for all data sources. In addition, EPA notes that it has removed the data reported 
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in Table V-33 from the 1982 TDD from the dataset for the final rule. For further discussion, see 

response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72.

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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72. 

EPA disagrees 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 assertion 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 EPA-HQ-OW-2009-0819-4499-A1, Excerpt 

Number 72 for more information.

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 (in this comment 

code, 15.d) and DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in Comment Code 4.b 

for a discussion of how EPA used the 1982 TDD data to determine pollutants of concern and ash 

impoundment discharge loads, and the effect of detection limits on those analyses. See the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 33 in Comment Code 4.b for 

a discussion of the specific data used from the 1982 TDD, and its use in the rulemaking.

See the response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47 for more information about EPA’s ash 

characterization dataset and approach for calculating pollutant loadings in bottom ash transport 

water, including discussion of use of combined ash impoundment data.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 40

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 combined 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 sample (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 the 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 documentation 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 lower 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 reported 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 (emphasis 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.
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Comment 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 and 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-HQ-OW-2009-0819-4499-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 these 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 removed 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in this comment 

code (Comment Code 15.d) and DCN EPA-HQ-OW-2009-0819-4655, Excerpt Numbers 33 and 

38 in Comment Code 4.b and elsewhere in this comment response document.

For comments related to EPA’s use of data from ash impoundments that contain other 

wastestreams, see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72.

For comments related to ponds that contain both fly and bottom ash transport water, see DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 34 for more information 

regarding EPA’s use of values reported as “MQC” in the 1982 TDD.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 30

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 the 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 Baseline 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 estimates 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 impoundments, 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 limits. 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 analyzed 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 loadings 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 variable 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-HQ-OW-2009-0819-4499-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 identification of loadings.
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See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 4 in Comment Code 6.f 

regarding bias associated with EPA’s method for estimating pollutant loadings.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 41

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 data, 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 following instructions from EPA.9 That 

database is included in the record as EPA-HQ-OW-2009-0819-1237.1.

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 one 

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 interpret 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 three 
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outfalls, concentrations for antimony, beryllium, 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 

average 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 for 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 between 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-HQ-OW-2009-0819-1237.

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, which 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72, just because data are older does not 

mean they are not representative of today’s conditions.

Uncertainty of Methods/Variance of Methods: As described in Section 12 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 evaluated all data used for the final rule for inclusion based on 

analytical method. EPA accepted analytical methods approved in 40 CFR Part 136 at the time 

the sample was collected. EPA Form 3510-2C (Application Form 2C – Wastewater Discharge 
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Information) requires that plants applying for NPDES permits “must use test methods 

promulgated in 40 CFR Part 136” for analysis of samples; 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; therefore, 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 assigns 1⁄2 of the value). As described in response to DCN EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, and Section 12 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 treated non-detect results as one half the sample-specific quantitation 

limit for all analytes in the loadings calculations. See also the response to DCN EPA-HQ-OW2009-0819-4499-A1, Excerpt Number 72 in this comment code (Comment Code 15.d) and DCN 

EPA-HQ-OW-2009-0819-4379-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.

Variability 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 not 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 extent 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 transport 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 “most 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 

limitations, 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 EPA 
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used in the analytical database.” See response to DCN EPA-HQ-OW-2009-0819-4499-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-HQ-OW-2009-0819-4499-

A1, Excerpt Number 72 and response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 

47.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 75

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 calculations 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 bottom 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 sulfide 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 two 
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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 ash (“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.
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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 

source 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 pyrites 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, 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). As 

described in response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in 

Comment Code 15.d and Section 12 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 treated nondetect results as one half the sample-specific quantitation limit for all analytes in the loadings 

calculations. See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in 

this comment code (Comment Code 15.d) and DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 24 in Comment Code 4.b regarding EPA’s ash characterization data and handling of 

non-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-HQ-OW-2009-0819-4499-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.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 73

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 bottom 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 into 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 

indicate 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 section, 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 nondetects reported for the majority of the measurements.
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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-HQ-OW-2009-0819-4499-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 identification of loadings.

Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 12
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External 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 Toxic 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 sampling 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-821-

R-13-002 . It is 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 concentrations 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 contributions 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 indicates 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 ash10 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 concern.

7 Section 4.3.2 of the 2013 TDD,EPA-821-R-13-002 (April 2013).

8

45 FR 68328 (October 4, 1980).

9 Section 10.4.2 of the 2013 TDD, EPA-821-R-13 -002.

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, industry-supplied data, and publicly available data sources, 
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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-HQ-OW-2009-

0819-4499-A1, Excerpt Number 72 in Comment Code 15.d and DCN EPA-HQ-OW-2009-0819-

4460-A1, Excerpt Number 50 in Comment Code 6.a, as well as the Bottom Ash and Fly Ash 

Pollutants of Concern Analysis Memorandum (DCN SE04745) for more details on EPA’s 

determination of POCs for ash transport water. See the response to DCN EPA-HQ-OW-2009-

0819-4499-A1, Excerpt Number 72 in Comment Code 15.d and DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 39 in Comment Code 4.b regarding EPA’s use of source water data.

EPA did not assume that “on average, pollutant contributions from fly ash account for 86 percent 

of combined ash loading, with bottom ash contributing only 14 percent” for all pollutants in 

combined ash ponds, see response to DCN EPA-HQ-OW-2009-0819-4655, 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 assertion 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 pollutant 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 costeffectiveness 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)
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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 and EPA estimated pollutant reductions 

results from differences in data used, and in how non-detect values are treated. 

The discrepancy in pollutant reductions calculated by EPRI and EPA is attributed to the 

differences in approach shown in Table 7-2. The principal disparity appears to be in analytical 

concentrations, as EPRI used the same toxic weighting factors as EPA and matched EPA’s 

bottom ash flow rate (157 billion gallons per year for units larger than 50 MW). The pollutant 

reductions are expressed in TWPE, calculated as a function of three variables: 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 pollutant 
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reduction calculation and focusing primarily on EPA’s Bottom Ash Only pond data, which 

account for most of EPA’s estimated pollutant reductions.

7.2.1The 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 

Water 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 analysis. 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 impoundments 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 (EPRI) 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 Electric 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 average of these sites 

with the sites from the other data sources, if these TDD data include data for a given 

parameter.]
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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 have 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 

used 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.
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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 small 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 contribution 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 Categories [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 ash 
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transport water exiting surface impoundments. These values are used in combination with plantspecific 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 Effluent 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 fly 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 environmental 

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 dry 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 handling) 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 

discharge 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, companies 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 feed into the cost-effectiveness analysis, technically, these analyses are not 
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required for BAT. For the role of cost-effectiveness in EPA’s decisions for the final rule, see 

response to DCN EPA-HQ-OW 2009-0819-4655, Excerpt Number 27 in Comment Code 6.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 

standard.” 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 reverse 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 (5th 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 (5th 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 those 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 guideline.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 by 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 as well as additional data received from public commenters to use in its POC 

 

2 For zero pollutant discharge limitations and standard, all pollutants (not just POCs) are regulated.
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analysis. These data include additional industry-submitted ash transport water characterization 

and source water data. These data were collected between November 2001 and March 2014. 

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 to 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 EPA 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 water 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 additional 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 technology.
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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, EPA 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 source 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, 

baseline 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 well 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 explained 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.
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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 used 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 Development 

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 each 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 data 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 Transport 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 effluent 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.
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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 impoundments 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 

basically 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 add 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 containing 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 concentrations 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 calculating 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-half 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 ug/L. Here, EPA values most non-detects 

at 1 ug/L. Clearly, this is within the range of the detected values, and in this case, is lower than 
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all of the detected values except one. The same holds true for the other POCs shown in Table 1 

including arsenic, mercury, and cadmium.

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 sample, 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 Value52.5 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

5
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fly ash) transport water. In particular, they questioned the use of data from impoundments 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 other 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 decrease 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 

minimizing 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 fly 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 fly 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.
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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 impoundments 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 contributions 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 adjusted 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 concentrations 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 technologybased 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 facilities 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, 
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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 detection 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 permit 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, 

should 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 rule. 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 pollutant 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 averaged 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 using 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-effectiveness 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 the 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 determination, 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.
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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 Excerpt: 

D APPENDIX: BOTTOM ASH HANDLING POLLUTANT LOADING 

REDUCTION METHODOLOGY

D.1EPRI’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.1.1Summary

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 400 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) benefits of BA treatment to the 

industry. The calculations of these benefits are provided below.

D.1.2 Introduction
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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 Standards 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 rule 

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 Benefit 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 

TWFs 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 include:

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 Evaluation
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As part of the effort to estimate the benefits (that is, reduction of pollutants) 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 previously collected for the PISCES project in the 1990s.

The samples were analyzed for metals2, 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, EPRI 

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 

decreased 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

EPA 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 estimated 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 discharge 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 D4, aluminum and arsenic are the primary contributors when represented by TWPE per year.
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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 values, 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.
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See the response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47 for more information about revisions to 

EPA’s ash characterization 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 sulfides.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 45

External Review Flag: No External Review

External Review Incorporated into Response: 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 significant 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 error 
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“misleadingly increased the estimated TWPE in bottom ash transport water.” While EPA rounds 

to a specific 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-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 removed. 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 approximately 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 6,590
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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 to 
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DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN EPA-HQ-OW-2009-

0819-4305-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 because 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-HQ-OW-2009-0819-4305-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 questioned EPA’s identification of sulfide as a POC in bottom ash transport 

water. As explained in the response to DCN EPA-HQ-OW-2009-0819-4499-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 identification of loadings.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 system (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 effluent 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 

for 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 two 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.
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Comment Response: 

As discussed 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 determining the ash 

impoundment effluent concentrations.

See the response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4305-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 bottom ash sluicing systems to dry fly 

ash and bottom ash handling systems (DCN SE05069). 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-HQ-OW-2009-0819-4614-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 each 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 4 in Comment Code 6.f 

regarding 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-HQ-OW-2009-0819-4470-A1

Comment Excerpt 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 bottom 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 regulate 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 

calculations.

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 stringent technologies 

potentially required for bottom ash transport water specified in Options 4, 4a and 5.
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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 as 2,716,059, while UWAG 

calculates only 65,342.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47 in Comment Code 15.d.

EPA also disagrees that it does not have enough 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 other 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-HQ-OW-2009-0819-4487-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 transport 

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 based on the product of averages. As described in detail in the UWAG 

Comments, this formulation will generate estimates that are biased high if pollutant 
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concentrations are inversely correlated with ash transport flow rates. The bias will be severe if 

the coefficient 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 of 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47.

For the role of cost-effectiveness in EPA's decisions for the final rule, see response to DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h. See response to 

DCN EPA-HQ-OW-2009-0819-4655, 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

Document Control Number: EPA-HQ-OW-2009-0819-4517-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 water 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 associated 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 which 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 glassy 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.
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 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 identical 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 estimates in response to comments received on the proposed rule. 

See response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 14 regarding EPA’s 

collection of “a single bottom ash sample”.

Also See DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in this comment code 

(Comment Code 15.d) and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a, as well as the Bottom Ash and Fly Ash Pollutants of Concern Analysis 

Memorandum (DCN SE04745), for more details on EPA’s determination of POCs for ash 

transport water. See the response to DCN EPA-HQ-OW-2009-0819-4655, 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.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment 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 EPA 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, tin, 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.
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o The source water contribution should be subtracted to properly account 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQOW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, 

Excerpt Number 50 in Comment Code 6.a, as well as the Bottom Ash and Fly Ash Pollutants of 

Concern Analysis Memorandum (DCN SE04745), for more details on EPA’s determination of 

POCs for ash transport water.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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-HQ-OW-2009-0819-

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 F
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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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a, as well as the Bottom Ash and Fly Ash Pollutants of Concern Analysis 

Memorandum (DCN SE04745), for more details on EPA’s determination of POCs for ash 

transport water.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 52

External Review Flag: No External Review

External Review 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

 as 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 the 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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a, as well as the Bottom Ash and Fly Ash Pollutants of Concern Analysis 
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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.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 TWPEs 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 reductions 

estimates in response to comments received on the proposed rule. See responses to DCN EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a, as well as the Bottom Ash and Fly Ash Pollutants of Concern Analysis 

Memorandum (DCN SE04745), for more details on EPA’s determination of POCs for ash 

transport water.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-A1

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 Category. 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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a.

EPA agrees that there are differences in the pollutant loadings associated with bottom ash 

transport water and fly ash transport water. Simply because less pollutant loadings are attributed 

to bottom ash transport water compared to fly ash transport water does not support the assertion 

that EPA should not further regulate bottom ash transport water.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 46

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

D. EPA’s Overall TWPE Values, in Light of Data and Methodology Issues, Are Grossly 

Overstated for Both Fly Ash and Bottom Ash Pond Discharges
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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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 77

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Eliminating the sulfide 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-HQ-OW-2009-0819-4499-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 identification of loadings.

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Failed To Collect Sufficient, Current, Valid Data To Support Its TWPE Determination For 

Bottom Ash Transport Water.
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The data that EPA used to support its determinations of the TWPE for bottom ash transport water 

is not statistically 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 bottom 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 47.

Also see response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 14.

For the reasons stated in preamble sections VIII.C and E, and elsewhere in the record, 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 oilfired; 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 welldemonstrated and presents 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-HQ-OW-2009-0819-4460-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 depiction 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.
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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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a.

Also see response to DCN EPA-HQ-OW-2009-0819-4470-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-HQ-OW-2009-0819-4448-A1

Comment Excerpt Number: 38

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

There are many reasons why the EPA $/TWPE estimates do not reflect the true cost of dry 

bottom ash retrofits. Many of these have been highlighted in the UWAG comments27 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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a.

Also see response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 14.
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For the role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 cost pollutant loadings and reductions 

estimates in response to comments received on the proposed rule. See responses to DCN EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-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-HQ-OW-2009-0819-4499-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.

Commenter Name: John C. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-A1

Comment 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.
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Comment Response: 

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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72, 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-

4460-A1, Excerpt Number 50 in Comment Code 6.a.

Also see response to DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 14.

Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (MP)

Document Control Number: EPA-HQ-OW-2009-0819-4484-A1

Comment Excerpt Number: 23

External Review Flag: No External 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, EEI 

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-HQ-OW-2009-0819-4768-A2, Excerpt Number 21.

Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (ALLETE)

Document Control Number: EPA-HQ-OW-2009-0819-4768-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 constituents 
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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 effluent 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 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 EPA’s revised approachfor determining pollutant concentrations used in 

calculating baseline pollutant loadings and pollutant reductions under the final rule. See the 

response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 and DCN EPA-HQOW-2009-0819-4655, Excerpt Number 47 for more information about revisions to EPA’s ash 

characterization dataset and approach for calculating pollutant loadings in bottom ash transport 

water.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-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 

sufficient 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 its cost pollutant loadings and reductions 

estimates in response to comments received on the proposed rule. See responses to DCN EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72, DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 47 and DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in 

Comment Code 6.a.
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See also the response to DCN EPA-HQ-OW-2009-0819-4464-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 existing steam electric generating units.
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16. Zero Discharge Bottom Ash

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 36

External Review Flag: No External 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 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-HQ-OW-2009-0819-2255.

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 members. Southern 

endorses UWAG’s characterization study. The results are documented 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 

characterization 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 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.

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 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 progress toward the national goal of eliminating the 
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discharge of all pollutants, particularly toxic pollutants (see CWA section 301(b)(2)(A)). See 

also response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3.

See response to DCN EPA-HQ-OW-2009-0819-4460-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 identification of pollutants of concern for bottom 

ash transport water. See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 

47 in Comment Code 15.d for more information on the data and methodology used to calculate 

bottom ash baseline loadings.

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 concern (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 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). EPA did use all simulated effluent analytical data in a sensitivity 

analysis for pollutant loadings.

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 in Comment Code 

16.b for more information on EPA’s bottom ash compliance costs for the final rule.

EPA notes that the cost-effectiveness 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 costeffectiveness in EPA’s decision for the final rule, see response to DCN EPA-HQ-OW-2009-

0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: J. Michael Brown

Commenter Affiliation: Ohio Valley Electric Corporation (OVEC)

Document Control Number: EPA-HQ-OW-2009-0819-4182-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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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 the low 

level of pollutant loading in bottom ash transport water, the $/TWPE does not appear to be costeffective 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

EPA disagrees that zero discharge limitations based on dry handling or closed-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-HQ-OW2009-0819-4448-A1, Excerpt Number 40 in Comment Code 5.c regarding the 400-MW 

threshold.

Commenter Name: Chas Spell

Commenter Affiliation: Arizona Public Service Company

Document Control Number: EPA-HQ-OW-2009-0819-4303-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External 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 costeffectiveness 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 11
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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 cost 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 29

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

After correcting 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Paul Nazaryk

Commenter Affiliation: BHP Navajo Coal Company (BNCC) and San Juan Coal Company 

(SJCC)

Document Control Number: EPA-HQ-OW-2009-0819-4380-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 

removed. 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 18

External Review Flag: No External 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 costs 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 comparisons, 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 60 in Comment Code 

15.d on the commenter’s use of median flow rates.

Commenter Name: Douglas J. Fulle

Commenter Affiliation: Oglethorpe Power Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4449-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 

existing 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/lbeq 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 transport 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 EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-A1

Comment Excerpt Number: 11

External Review Flag: No External Review

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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.
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Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 83

External Review Flag: No External Review

External 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Winslow Sargeant

Commenter Affiliation: U.S. Small Business Administration, Office of Advocacy

Document Control Number: EPA-HQ-OW-2009-0819-4477-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 is 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 bottom 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.
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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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

EPA 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 plantby-plant basis (DCN SE05654).

See other responses to this commenter 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-HQ-OW-2009-0819-4489-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 Nor 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 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 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Erik Silvola

Commenter Affiliation: Great River Energy (GRE)

Document Control Number: EPA-HQ-OW-2009-0819-4572-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 

underestimation 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1
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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 direct and indirect costs required to retrofit do 

not warrant such actions.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 transport water, and for that wastestream EPA has 

not shown any treatment beyond settling ponds to be cost-effective. UWAG calculates costs of 
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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 bottom ash dry handling.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 poundsequivalent,” 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-HQ-OW-2009-0819-2239 (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 wastestreams 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-HQ-OW2009-0819-2255), 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 $27
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FGD Wastewater Chemical Precipitation $69

FGD Wastewater Chemical Precipitation and 

Biological $60

FGD Wastewater Chemical Precipitation and VaporCompression 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 provided
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*$/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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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, EPA 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 per TWPE. EPA-HQ-OW-2009-0819-2255.

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 members.

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 Dollars 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.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 65

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

UWAG’s $/TWPE 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 closedloop retrofit of bottom ash is not cost-effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.
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Commenter Name: Raymond L. Evans

Commenter Affiliation: FirstEnergy Corp.

Document Control Number: EPA-HQ-OW-2009-0819-4677-A2

Comment Excerpt Number: 1

External Review Flag: No External 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 ash 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 impoundments 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 inconsistent 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 comments. 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 inflated 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 recent 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 4 in Comment Code 6.f 

for more information on EPA’s statistical methodology for calculating pollutant loadings.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)
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Document Control Number: EPA-HQ-OW-2009-0819-5140-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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

Commenter Name: S. L. Phillips

Commenter Affiliation: Louisiana Department of Environmental Quality

Document Control Number: EPA-HQ-OW-2009-0819-5509-A2

Comment Excerpt Number: 4

External Review Flag: No 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 pollutants to the environment.

Option 3a would allow continued use of wet bottom ash transport systems.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

EPA disagrees with the commenter that it “illogically exempts quenching water 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.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 39

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 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 

(NoAdjustment for 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 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 for 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 removed are much larger than the pounds 

added by the power plant itself. Without the adjustment for pounds of pollutants present 
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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 $/TWPE 

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)

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, further 

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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 145

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 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-A1

Comment Excerpt Number: 54

External Review 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 costeffectiveness analysis wholly inaccurate. EPA’s assertion that it would 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 and 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 reasons. 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 if 
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EPA were to require 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 (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 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.

10 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 $) if these additional 

factors were considered. See UWAG Comments at Section V., J.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 55

External Review Flag: No External Review

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 values 

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 cost-effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.
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For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-A1

Comment Excerpt Number: 48

External Review Flag: No External Review

External Review Incorporated 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-HQ-OW-2009-0819-2255.

UWAG’s cost-effectiveness analysis for the same options, 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 

Plant13

<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 $1,694
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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 effective.
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13 UWAG’s cost-effectiveness analysis only includes capital costs.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-A1

Comment Excerpt Number: 82

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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

EPA’s subsequent cost-effectiveness analysis is rendered ineffectual by these shortcomings in its 

pollutant data for bottom 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 ash 

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 greater 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 expected 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 considered.

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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4633-A1

Comment Excerpt Number: 49
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External Review 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 costeffectiveness 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 and 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 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 if EPA 

were to require 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 (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 costeffectiveness ranging from less than $1/lb-eq (Inorganic Chemicals) to $404/lb-eq (Electrical and 

Electronic Components), in 1981 dollars”). UWAG’s range 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 59
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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 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)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 intake 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 $3,146
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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, 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-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 capacitybased 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)
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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 $3,146

*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 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 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 from UWAG the table below:

Table 5: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data (Less the 

Source Water Contribution)
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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
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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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 4.b.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-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 not 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 TWPE 
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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 enter 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 2010$ 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. Boiler 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. Additionally, 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 Allowance 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 

information collected from a second facility. A bituminous coal is burned at this facility in a subcritical wet-bottom boiler. Using the same methods as those used to determine $/TWPE removed 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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for the prior facility, values very much different than those determined 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 methods 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 very 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.

26Cost Effectiveness of Removing Toxic Pollutants for Direct Dischargers at a Waste 

Stream/Technology Level, EPA- HQ-OW-2009-0819-2255.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For more information on EPA’s source water analysis for bottom ash transport water, see the 

response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4633-A1, Excerpt 

Number 46 in Comment Code 6.g.ix for more information on cyclone boilers, the technologies 

evaluated for BAT, and wastewater characterization.

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 of 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-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 80

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 ratios 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 pollutant 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 technical 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: 
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EPA’s Response to Public Comments

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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 toxic-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, based 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: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 in Comment Code 

16.b for more information on EPA’s bottom ash compliance costs. Additionally, 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 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-HQ-OW-2009-0819-4517-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 pollutant 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 discharge of bottom ash sluice water at all units, and not just units less than 400 MWs.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4283-A1, Excerpt Number 5.
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Commenter Name: Patrick O’Loughlin

Commenter Affiliation: Buckeye Power, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4183-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 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 XIX). EPA disagrees that there 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

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-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 intake 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 Document for 
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Effluent Limitations Guidelines and Standards and Pretreatment Standards for the Steam Electric 

Point Source Category, EPA-HQ-OW-2009-0819-2186 at 498 (1982 Development Document).

The same reasoning applies today. The low level of toxics in bottom 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-HQ-OW-2009-0819-4303-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 EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-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 sluice 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 Effluent Limitations Guidelines and 

Standards and Pretreatment Standards for the Steam Electric Point Source Category (1982 

Development Document), EPA-HQ-OW-2009-0819-2186, at 498. That same reasoning applies 

today. The low level of pollutants of concern in bottom 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-HQ-OW-2009-0819-4303-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 EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.
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Commenter Name: Tom DeLawrence

Commenter Affiliation: Public Service Company of New Hampshire(PSNH)

Document Control Number: EPA-HQ-OW-2009-0819-4633-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, current 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-HQ-OW-2009-0819-2186 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 

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 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 

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. 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-HQ-OW-2009-0819-4303-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 EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.
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Commenter Name: Paul Ling

Commenter Affiliation: Kansas City Power & Light Company

Document Control Number: EPA-HQ-OW-2009-0819-5406-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Because of bottom ash 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 plants, 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 feasible 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 

retrofitting 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 pollutant 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-HQ-OW-2009-0819-4303-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 EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-A1

Comment Excerpt Number: 52

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 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.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-HQ-OW-2009-0819-4303-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 EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 Discharge” 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 conversion of Midwest Gen’s facilities to dry handling or closed loop systems would 
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be cost prohibitive, would create feasibility issues for certain facilities and, most importantly, is 

not necessary or justified to achieve the environmental objectives of this 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 discharged 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 station 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 environmental 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 closedloop systems results 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 should 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 mechanical 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-HQ-OW-2009-0819-4466-A1

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

A zero discharge limit for bottom ash transport water cannot be justified by the significant costs 

associated with retrofits.

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).

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 in 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 identifies 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-HQ-OW-2009-0819-4464-A1, 

Excerpt Number 3 in Comment Code 6.e.
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For the role of cost-effectiveness in EPA's decision for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Thomas N. Effinger

Commenter Affiliation: South Carolina Electric & Gas (SCE&G)

Document Control Number: EPA-HQ-OW-2009-0819-4593-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 handling 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 substantially 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 basis 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 unknowns such as those listed above.

Comment Response: 

The final rule record demonstrates that plants can install and afford the dry handling or closedloop systems selected as the BAT basis for control of pollutants in bottom ash transport water 

(see preamble 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 that 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 specific 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 EPAHQ-OW-2009-0819-4459-A1, Excerpt Number 3.
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Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 proposed 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 36.

For EPA’s full response to information submitted as confidential business information, see DCN 

SE05925.

Commenter Name: Paul Carpmone

Commenter Affiliation: Tampa Electric Company (TEC)

Document Control Number: EPA-HQ-OW-2009-0819-4520-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, 
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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 requiring 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 increasing 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-loop 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 operation and maintenance costs will actually decrease.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-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 being included in all options as dry handling is more cost- effective and has many 

more environmental benefits than wet options.
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Comment Response: 

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 

encourages the use of completely dry bottom ash handling systems and acknowledges potential 

savings due to ceasing wet sluicing operations. Additionally, some dry systems could 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 mechanical 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 the 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 years (DCN 

SE01825A80). Also, see response to DCN EPA-HQ-0819-4684-A1, Excerpt Number 102 in 

Comment Code 15.

For the role of cost-effectiveness in EPA’s decision for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-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 environmental 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-HQ-OW-2009-0819-4704-A1, Excerpt Number 16.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

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 for 
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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 

conversion to dry ash handling.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4704-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 deposition 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 basis 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-HQ-OW-2009-0819-4535-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 of 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 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 they have acceptable 

non-water quality environmental impacts. See also response to DCN EPA-HQ-OW-2009-0819-

4464-A1, Excerpt Number 3.
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16.a. Zero Discharge Bottom Ash – Demonstration/Performance 

Commenter Name: Patrick O’Loughlin

Commenter Affiliation: Buckeye Power, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4183-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 problem 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 transport 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 transport 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 reasonable 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 with 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-HQ-OW-2009-0819-4183-A2, Excerpt Number 11 

in Comment Code 16.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 70

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 mechanical 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 dredged 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 

consider 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 Power District (NPPD)

Document Control Number: EPA-HQ-OW-2009-0819-4310-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 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. 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."

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.
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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 

retrofits 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 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 United 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 will 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 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. To be more 

specific, the 172 plants are as follows:

 76 Plants – Based on their response 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 of 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 – Projected 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 

planned. (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 

months 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 CPP rule has no 

effect on the number of plants that will be operating when plants will have to meet the final 
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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 transport 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 

potential 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 space 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.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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 assumption 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 to 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 block 
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available from the Steam Electric Survey or other publicly available data sources for all steam 

electric power plants. Therefore, EPA selected 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 its 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 specifically 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 disposal 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 (subject 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 ash 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 identified 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-HQ-OW-2009-0819-4499-A1, 

Appendix E), which assumes that 25 percent 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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 40

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Engineering Aspects of Retrofitting Dry Bottom Ash Handling
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In reviewing the proposed ELG Rule, Southern Company engineers investigated 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 chosen, 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 surge tanks would 

be approximately one year.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4379-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.

See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 126 in Comment 

Code 26.b for more information on timing of the final rule’s requirements.

Commenter Name: David M. Fraley

Commenter Affiliation: City Utilities of Springfield, Missouri (CU)

Document Control Number: EPA-HQ-OW-2009-0819-4382-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 be) 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 

technological 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 would 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 constrained, resulting in systems that are unworkable, 
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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 considerations 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 34.

Commenter Name: Jerry Purvis

Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC)

Document Control Number: EPA-HQ-OW-2009-0819-4455-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 impoundments 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 did 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 dry 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 transport 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 public comments and available 

through other publicly available sources. See the response to DCN EPA-HQ-OW-2009-0819-

4460-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-HQ-OW-
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2009-0819-4655, Excerpt Number 47 in Comment Code 15.d for more information on the data, 

including data collected and evaluated, and methodology used to calculate bottom ash baseline 

loadings. See preamble section VIII and response to DCN EPA-HQ-OW-2009-0819-4464-A1, 

Excerpt Number 3 in Comment Code 6.e for discussion of why surface impoundments are not 

BAT for discharges of bottom ash 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. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-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 7-34). 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 "Conventional 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 based 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, potential space constraints under 

the boiler should not impact the ability of these plants to meet the final limitations and standards. 
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See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 34 for more 

information on space constraints associated with 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 

technology 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 mechanical 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 losses 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 scaling. 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 electric 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 electric 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 low 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 the 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 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). 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-HQ-OW-2009-0819-4633-A1, Excerpt Number 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 industry successfully operating completely closedloop bottom ash handling systems without discharges.
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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 maintenance 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 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) for more 

information.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 general 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 this 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 four 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 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 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. 

Finally, decant silos require enough space for truck access and surge tank installation and 

significant foundations.
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Comment Response: 

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 

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 environmental assessment and benefits analysis. See response to DCN EPA-HQ-OW2009-0819-4303-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 space 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 for 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 identified 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 their 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 126 in Comment 

Code 26.b for more information on timing of the final rule’s requirements.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 

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 companies able to 
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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: 

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 construction 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 normally 

scheduled maintenance outage. See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, 

Excerpt Number 126 in Comment Code 26.b for more information on timing of the final rule’s 

requirements.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-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 large 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 systems 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 traffic 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 EPAHQ-OW-2009-0819-4379-A1, Excerpt Number 34 for more information on space constraints 

associated with the mechanical drag system and EPA’s compliance cost methodology.

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 a 
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CCR landfill. If they do have and operate an onsite CCR landfill, EPA estimated 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, road 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 acceptable. See preamble sections VIII.C.10 and XII.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4471-A1

Comment Excerpt Number: 7

External Review Flag: No External 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 lowvolume 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 nondischarging. 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 surface 

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-HQ-OW-2009-0819-4305-A3, Excerpt Number 70 for more 

information on the quench water and maintenance associated with the MDS.

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 temporarily store the bottom 
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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 Source 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

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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 indicated 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 chain 

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 to 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 Regulatory 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 salts 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 handling 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 transport 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 ash away from the hoppers.
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Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-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 justified 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 “competes” 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 poses 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 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 areas. In addition, 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 years might pass before a closed-loop retrofit was actually 

installed and running.
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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 reconfiguration 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 justified by the currently available data.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 55 for more 

information on the bottom ash handling systems available for modifying a plant to dry or closedloop bottom ash handling.

See the response to DCN EPA-HQ-OW-2009-0819-4460-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 without 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: MidAmerican Energy Holdings Company

Document Control Number: EPA-HQ-OW-2009-0819-4495-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 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 section VIII. See response to DCN EPA-HQ-OW-2009-0819-4655, 

Excerpt Number 53 regarding the cost basis for bottom ash transport water.

See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 34 for more 

information on space constraints associated with the MDS and EPA’s compliance cost 

methodology.
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Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 27

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Predictions 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 systems.

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 through 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 more 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 Survey 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 impoundments 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 (approximately 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 the 

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 revised ELGs, but did not find that to be the 
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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 little 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-HQ-OW-2009-0819-4573-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 or 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 

major 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 transport 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).
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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-HQ-OW-2009-0819-4310-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 Control Number: EPA-HQ-OW-2009-0819-4573-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 handling 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 construction 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 benefit 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 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 preamble sections VIII and 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-HQ-OW-2009-0819-4460-A1, Excerpt Number 58 for more 

information on outage time associated with mechanical and remote mechanical drag installations. 

In particular, EPA does not agree that converting to a remote MDS would require a plant to 
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extend the duration of a regularly scheduled maintenance outage, nor that a maintenance outage 

specifically for the conversion would be necessary. See the TDD for more information.

See preamble section VIII and response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt 

Number 3 in Comment Code 6.e for discussion of why surface impoundments are not BAT for 

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-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 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-HQ-OW-2009-0819-4464-A1, Excerpt Number 21.

See also the response to DCN EPA-HQ-OW-2009-0819-4466-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 location 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 disposal, 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 to 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 will 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.
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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-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 43

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The ability 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 with the ELG Rule requirements. 

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 21. Also see 

response for EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 19.

See also the response to DCN EPA-HQ-OW-2009-0819-4466-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-HQ-OW-2009-0819-4631-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 concentrate 
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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. Likewise, 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 (DCN 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 chlorides 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 water 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-HQ-OW-2009-0819-4471-A1, Excerpt Number 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-HQ-OW-2009-0819-4464-A1, Excerpt 

Number 3 in Comment Code 6.e for discussion of why surface impoundments 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-HQ-OW-2009-0819-4633-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. The 
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dry-handling retrofits proposed in this 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 four 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 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 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 of 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. 

Finally, decant silos require enough 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 slag 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 makeup 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 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 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-HQ-OW-2009-0819-4460-A1, Excerpt Number 55 for more 

information on the bottom ash handling systems available for modifying a steam electric power 

plant to dry or closed-loop bottom ash handling.
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See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 58 for more 

information on timing. EPA does not agree that it will be necessary for operators to extend a 

regularly scheduled maintenance outage to convert bottom ash handling systems if using a 

remote MDS. An under-boiler MDS will not require a 16-week outage to accomplish. See the 

TDD for more information about outage requirements associated with the zero discharge 

requirement.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 54

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 34.

Commenter Name: Julia M. Blankenship

Commenter Affiliation: American Municipal Power, Inc. (AMP)

Document Control Number: EPA-HQ-OW-2009-0819-4670-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.
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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 existing generating units that are greater than 50 MW and are 

not oil-fired (see preamble 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 

unit 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-HQ-OW-2009-0819-4684-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 available. 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 technology 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.424 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 systems, 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.”429
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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 installed 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 ‘available’ 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-HQ-OW-2009-0819-0422.

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 more 
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generating units 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-HQ-OW-2009-0819-4704-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-HQ-OW-2009-0819-4704-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).978 FR 

34453/54. These cover the range of methods commercially available to 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 provide 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 vendors10

and summarized by EPRI and others.11 These methods are briefly described below.

Wet Zero Discharge Systems

The 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 United Conveyor Corp. 
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(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 collect 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. The 

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 water 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 (SSC12) 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 combustion chamber and continuously removes the ash on a dewatering slope. Dewatered ash is discharged onto mechanical conveyors or directly to storage 

silos.

The United Conveyor Corp.'s Submerged Flight Conveyor (SFC15) 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 several 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 System (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 dewatering equipment to be located away from inplant 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, relative to wet sluicing, are:

 No changes to the boiler
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 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 ASHCONTM system is a remote submerged scraper conveyor 

technology.16 This technology 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, requiring 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-byunit basis, 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 dewatering 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 wet sluicing, are:

 No changes under boiler
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 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-loop 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 ash, 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 goes 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 reliability. 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 into 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 Use, 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://www.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, Power 
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Engineering,” February 1, 2013; Available at: http://www.power-eng.com/articles/print/volume117/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 

EPA, “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 in 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%20Newsletter%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 Dewatering 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 of 
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bottom ash transport water. Some of these systems (e.g., the remote mechanical 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 systems. 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 ash 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-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.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-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 evaluated the relative merits of 

these various systems. United Conveyor Corp. (UCC) compared requirements for their zerodischarge bottom ash handling systems, as summarized in Table 1.
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Similarly, Clyde Bergemann compared key impacts and costs of their zero- discharge bottom ash 

technologies, as summarized below in Table 2.

Table 2: Clyde Bergemann Bottom Ash Handling Features Comparison29
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These Methods Satisfy BAT

One or more of these methods is technically feasible for all of the units subject to this 

rulemaking. 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 coal and coke-fired plants that 

handle bottom ash. 78 Fed. Reg. at 34,454, 34470 and TDD, Fig. 7-10. Further, 83% of the coalfired 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 publicly 
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disclosed dry applications.32 Its MACTM system has 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 AllenSherman-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 Bergemann37 and United Conveyor38 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 installations 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 indicates 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. (Clyde 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 

America, 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 conversion 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 rulemaking (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 

other 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 am 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.
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31 Joseph A. Barsin, Coal Fired Power Boiler System for Bottom Ash Removal Without 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_experience/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.longkingpcd.com/english/prod/Bottom.asp, and installed at http://www.longkingpcd.com/english/zhc/yj.asp; (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.sgepri.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 from Kurt Blohm and Sarah Holman to Ron Jordan,” Docket No. EPAHQ-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., United Conveyor Corp., “Dry Bottom Ash Handling Options & New Technology,” 

World of Coal Ash Conference 2009; Available at:http://www.flyash.info/2009/CharhutWOCA2009-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 Disposal Conversion 

Project - BL England Station, Power-Gen, December 2011,” February 2008 - February 2010; 

Available at: 

http://www.naes.com/sites/default/files/documents/delvecchio_speaker10835_session1236_2.pdf
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; “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-2009-0819-4448-A1, Excerpt Number 40 in Comment 

Code 5.c for more information on EPA’s consideration of the 400 MW threshold for bottom ash 

transport water.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 21

External Review Flag: No External Review

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 constraint 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 mechanical 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 system
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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.

Commenter Name: William Matthews

Commenter Affiliation: Cleco Corporation

Document Control Number: EPA-HQ-OW-2009-0819-5550-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 operational 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 waste 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 periodically 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-OW-2009-0819-4305-A3, Excerpt Number 7.
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16.b. Zero Discharge Bottom Ash – Costs 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 operating 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 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 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-OW-2009-0819-2007. CBPG provided costs, including conveyance and intermediate 

storage costs, to EPA for the following MDSs.

1. ASHCONTM 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. DRYCONTM System (sub-boiler retrofit): The collection, crushing, air cooling and 

mechanical conveying of bottom ash without the need for water quenching.
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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 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 

ASHCONTM 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

(ASHCONTM)

Dry System

(DRYCONTM)

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 ASHCONTM 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) versus capital costs to generate 

cost equations to estimate 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 Capacity (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 who 
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already have converted from wet to dry or closed-loop recycle bottom ash handling. IC&PR, p. 

8-4.15 In addition, EPA 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 overhead 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 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 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 though 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 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 materials. IC&PR, p. 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 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 modifications, upgraded piping (more erosive-resistant 

material), demolition/relocation or structural modifications. CBPG notes that “[t]he estimated 
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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 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 cover these expenses. EPA-HQ-OW-2009-0819-2888.20. 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 Underestimated Engineering Overhead Costs

EPA’s factor for estimating engineering overhead does not accurately 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 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 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 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. Airport Deicing TDD, 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. EPA’s “Development Document for Final Effluent Limitations Guidelines 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 miscellaneous 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 project 
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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 include 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, 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 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 engineering 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 Development 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 and 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-R-00-020 

(August 2000) (CWT 2000 Development Document), p. 11-30; EPA’s “Technical Development 

Document for the Final Effluent Limitations Guidelines and New Source Performance Standards 

for the Airport Deicing Category,” EPA-821-R-12-005 (April 2012) (Airport Deicing TDD), 

p. 127 (including the opportunity cost of land use for both storage and treatment of ADFcontaminated stormwater). EPA should have analyzed the land requirements for bottom ash, fly 

ash, and FGD retrofits.

16 Contingency can be 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 result, in aggregate, in additional costs.” AACE International, AACE International 

Recommended Practice No. 10S-90 – 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 two 
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technologies, mechanical drag system (MDS) and remote MDS, as the BAT basis for bottom ash 

transport water because of potential space 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 space 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, specifically 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 handling 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. Based 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 factor 

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, discussions 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 acquisition 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 closedloop bottom ash handling system. Furthermore, EPA notes that EPRI’s bottom ash handling cost 

methodology, submitted as part of public comments (DCN EPA-HQ-OW-2009-0819-4499-A1. 

Appendix E) also do not include costs for land acquisition. See EPA’s response to DCN EPAHQ-OW-2009-0819-4379-A1, Excerpt 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 fall 
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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 time 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 

replacement 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 wastewater 

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, controls, 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 previously 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 to 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-HQ-OW-2009-0819-4303-A2

Comment Excerpt Number: 3

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.
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-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 scenario.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, 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 Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 79

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 result 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 consulting engineering were not included in the estimate. Also, 

plants in northern climates will require a building for freeze protection.
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EPA states its “cost estimates include the following key cost components: capital costs (one-time 

costs); annual operating and maintenance costs (which are incurred every year); and other onetime or recurring costs. Capital costs comprise the direct and indirect costs associated with the 

purchase, delivery, and installation of pollution control technologies. Capital cost elements 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 Regulatory 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.
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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-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 80

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

1. Remote Mechanical Drag System (MDS) Not Truly Zero Discharge

EPA assumes a remote 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 periodically 

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 inspections 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 remote 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 MDS 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.
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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 store 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 closed-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 Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 32

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA evaluated two technology options for 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 operation data from EPA’s, Questionnaire for the Steam Electric Power 

Generating Effluent Guidelines, EPA-HQ-OW-2009-0819-0655, -0655.1 through -0655.9 (May 

20, 2010) (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-OW-2009-0819-2007. CBPG provided costs, including conveyance and intermediate 

storage costs, to EPA for the following MDSs.

(1) ASHCONTM 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).
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(2) DRYCONTM System (sub-boiler retrofit): The collection, crushing, air cooling and 

mechanical conveying of bottom ash without the need 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 the 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 

ASHCONTM 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 

(ASHCONTM)

Dry System 

(DRYCONTM)

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 ASHCONTM 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 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 Capacity (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
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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 Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category, EPA-HQ-OW-2009-0819-2256 

(IC&PR), p. 8-4.1In addition, EPA 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 overhead 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 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 estimated 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 

conditioning 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.” (Craig 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 accommodate 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 – Final, EPA-821-R-00-020 (August 

2000), p. 11-23; Technical Development Document for the Final Effluent Limitations Guidelines 

and New Source Performance Standards for the Airport Deicing Category, EPA-821-R-12-005

(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 response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule.
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Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 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 amount 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 

materials. 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 total 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. Balance 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 (except for tie-in of pipeline that previously went to 

the ash pond), upgraded control systems, boiler modifications, upgraded piping (more corrosiveresistant material), demolition/relocation or structural modifications. CBPG notes that “[t]he 

estimated 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 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-HQ-OW-2009-0819-2888.20. 

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 Wrong

EPA’s factor for estimating engineering costs does not accurately estimate engineering costs. 

Engineering costs include multiple phases of engineering, such as conceptual design, services 
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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 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 general 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 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 $21,000 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, 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-821-R-99-

019 (January 2000), p. 9-37.

d. EPA Does Not Include Costs for Miscellaneous 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 for 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 project 

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 factors 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 (escalation, 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 retrofit 
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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 costs 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-821-R-02-004 (April 2002), p. 10-4; 

Development Document for the Final CWT Industry, p. 11-2; Development Document for the 

Final Effluent Limitations Guidelines and Standards for the Metal Products and Machinery Point 

Source Category, EPA-821-B-03-001 (February 2003), p.11-19.

2 EPA-HQ-OW-2009-0819-1959.24, EPA-HQ-OW-2009-0819-1959.25, and EPA-HQOW2009-0819-1959.29.

3 AACE International. 2013. AACE International Recommended Practice No. 10S-90 –Cost 

Engineering Terminology: TCM Framework: General Reference. Rev. April 25.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 35

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 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 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 that 
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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 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 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 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-time 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 require 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 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 (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 bridges 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 may 
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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.

The 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 Effluent 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-HQ-OW-2009-0819-4183-A2, Excerpt Number 12.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 38

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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)
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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, services 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 

based 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 Limitations 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 3.20
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 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 bottom 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 system.

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 costs 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 the 
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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). 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 additions 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-HQ-OW-2009-

0819-4655, 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 required 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 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 

steam electric power plants that did not report an onsite CCR landfill in the Steam Electric 

Survey.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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.
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We first compare plant-specific 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 Nameplate EPA Estimate 

(2010$), M$

Southern Estimate 

(2010$) M$

Southern InService 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 InService 

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 underestimated 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 Southern Company cost engineering staff.
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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 docket 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 closedloop) 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 the 

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 unable 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 compare the actual or estimated capital costs with EPA’s 

methodology. See the response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-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 Disposal

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 at 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 approximately $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 ton62 for fly ash and bottom ash, respectively. Using 
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EPA’s assumptions and costs, the costs for 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 steam 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 

steam 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 ELGs. 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 Removals 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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 162

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Dry Bottom Ash Retrofit
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The dry bottom ash hopper retrofit was based the replacement 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 foundation 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 requiring 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. Installation 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 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.

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 ash 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

 Insufficient electrical power supply exists at the silo requiring additional power 

distribution equipment (verified).
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 No demolition is required at the proposed location of the remote SFC-BAH.

 Installation of equipment outside of the boiler building will occur 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 cost based on 50 hour work weeks.

 No disposal costs are included in the estimate

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-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 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.

EPA notes the following key differences in the cost estimates provided by the commenter 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 SE05831/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 foundation 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 facilities will install equipment for fines 

management (surge tanks, chemical feed systems, thickeners) and not all facilities will 

choose to include redundancy” (DCN EPA-HQ-OW-2009-0819-4499-A1, Appendix E). 

EPA’s bottom ash compliance cost methodology does include chemical feed system costs 

for all remote mechanical drag installations.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 164

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

New Landfill and Landfill Expansion Assumptions
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Landfill estimates are based on a recent landfill construction, which averaged $650,000 per acre. 

Stack heights were assumed 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 131.

Additionally, EPA compared 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 

Point 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 ($29.39 per ton in 2010$). 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, permitting, 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; therefore, 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-HQ-OW-2009-0819-4448-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.
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For the proposed revisions to the steam electric effluent guidelines, EPA performed a costeffectiveness 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-HQ-OW-2009-0818-

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 costs 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 2010$ 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 contingencies 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 

schedules, 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 estimated 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 estimate.

* Assumes no 400 MW per unit threshold exemption
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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 provided 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 used 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 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. See response to DCN EPA-HQ-OW-2009-0819-4655, 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 (contingency).

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-A1

Comment Excerpt Number: 39

External Review Flag: No External Review

External Review Incorporated into 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 lack 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.
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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 

ponds 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 of $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 $111 million in fully loaded costs (2010$). 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 $931 million (2010$) in direct capital costs and over $1.2 billion in fully-loaded 

costs (2010$).

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule. Also, for the role of cost-effectiveness in EPA’s decision for 

the final rule, see response to DCN EPA-HQ-OW-2009-0819-4655, 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 greater 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 previously 

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-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 flight 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 of 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 unplanned 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 $8,000,000 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 values 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. 

Annual 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 were 

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, and 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 Point 

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) is 
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much worse than this criteria. Adding 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 Cost1

($/Year)

Cost/Benefit 

($/TWPE)

447 $21,000,000 $1,980,000 $4,400

1Assumed 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, 2013), 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-HQ-OW-2009-0819-4655, 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 remote 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 the 
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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-HQ-OW-2009-0819-4684-A1, Excerpt Number 102, 

regarding economies 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-HQ-OW-2009-0819-4460-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 TDD and the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt 

Number 47 in Comment Code 15.d for more information on the data and methodology 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 of 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-effectiveness in EPA’s decision for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Jerry Purvis

Commenter Affiliation: East Kentucky Power Cooperative, Inc. (EKPC)

Document Control Number: EPA-HQ-OW-2009-0819-4455-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 Station 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 other 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 estimated 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 2013) 

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.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, 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 commenter 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 Cooperative, Inc. (EKPC)

Document Control Number: EPA-HQ-OW-2009-0819-4455-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 provided 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-HQ-OW-2009-0819-4460-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-HQ-OW-2009-0819-4655, Excerpt Number 47 in 
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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-HQ-OW-2009-0819-4655, 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-effectiveness in EPA’s decision for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

Document Control Number: EPA-HQ-OW-2009-0819-4460-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 instance, 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-HQOW-2009-0819-4448-A1, Excerpt Number 39.

Commenter Name: JoAnne Rau

Commenter Affiliation: Dayton Power & Light Company (DP&L)

Document Control Number: EPA-HQ-OW-2009-0819-4470-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 Underestimated
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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 the 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 be 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 

range 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 to 

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 costeffective.

In addition to the lack of justification 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 engineering, 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 would 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 estimated 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 in 
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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-HQOW-2009-0819-4460-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-HQ-OW-2009-0819-4655, Excerpt Number 47 in Comment Code 15.d for more 

information on the data and methodology used to calculate bottom ash baseline loadings.

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule.

See the response to DCN EPA-HQ-OW-2009-0819-4379-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 EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

EPA cannot comment on the cost estimates 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., generating unit number or capacity).

See response to DCN EPA-HQ-OW-2009-0819-4448-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 operating 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-HQ-OW-2009-0819-4471-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 currently 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 making 
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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 gallon 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 its 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 chemical 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-loop 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 the 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 technology 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-HQ-OW-2009-0819-4471-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 

transport water to these systems and should not consider them as fully zero discharge 

technologies.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4471-A1, Excerpt Number 7 in Comment 

Code 16.a for more information on storage capacity required for drained bottom ash transport 

water.
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Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 53

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Additionally, a document in the Rulemaking Record, “Bottom Ash Conversion Options and 

Economics (EPA-HQ-OW-2009-0819-2075)”, 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-HQ-OW-2009-0819-2007)” 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 when 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 systems 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 adjustment 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 estimates 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 the 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 power 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 indicated 
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that many plants partially recirculated their bottom ash transport 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 prevent 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 approximately 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 without 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 

installing 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, electrical, 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 = 0.0239x + 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 + 
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3, where x is the unit MW capacity and y is the capital cost in millions of dollars. EPA’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 Steam 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. However, 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 such 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 

redundancy,” suggesting that this treatment can be added; however, is not necessary (see DCN 

EPA-HQ-OW-2009-0819-4499-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 successfully 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-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule. See the response to DCN EPA-HQ-OW-2009-0819-4379-

A1, Excerpt Number 35 for more information on EPA’s bottom ash management cost 

methodology.

Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

In addition, converting 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 

discharges 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 retrofitting 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 "Balance 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 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. See the TDD and response to DCN EPA-HQ-OW-2009-0819-

4460-A1, Excerpt Number 58 in Comment Code 16.a for more information on outage time 

associated with mechanical and remote mechanical drag installations. See the response to DCN 

EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom ash cost estimates for the 

final rule.

Commenter Name: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

Document Control Number: EPA-HQ-OW-2009-0819-4487-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 provided no capital expenditures at all. This oversight is a 

gross underestimate of retrofit costs.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 35 for more 

information on EPA’s bottom ash management cost methodology.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4491-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In 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 handling 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 hopper and submerged flight conveyor would take 

27-33 months and cost over $21 million.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4655-A11 and DCN EPA-HQ-OW-2009-0819-4379-

A1).

See the response to DCN EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4499-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 Evaluation
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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 likely incur additional 

capital costs to fully eliminate discharge.

Comment Response: 

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-2009-0819-4460-A1, Excerpt Number 58 in Comment 

Code 16.a for more information on outage time required for installation.

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule, including estimates to account for buildings at plants located 

in cold weather climates.

See the response to DCN EPA-HQ-OW-2009-0819-4475-A1, Excerpt Number 53 for more 

information on clarification to manage fines.

See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 131 for more 

information on the construction of new landfills.

See the response to DCN EPA-HQ-OW-2009-0819-4379-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 (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 81
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

8.2 EPA potentially underestimated the cost of conversion from wet 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 protection 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 Response: 

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-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule, including estimates to account for buildings at plants located 

in cold weather climates.
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See the response to DCN EPA-HQ-OW-2009-0819-4475-A1, Excerpt Number 53 for more 

information on clarification to manage fines.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-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 existing 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 annualized 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 under-the-boiler MDSs [UCC, 2013]. 

Based on UCC’s market research, EPRI assumed that 25% of the industry would install underthe-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 remote MDSs.

Comment Response: 

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).

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 83
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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. However, 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-theboiler installation.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 58 in Comment 

Code 16.a for more information on outage time required for installation. 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 conversions 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 & Loads 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-HQ-OW-2009-0819-4499-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 stage a remote MDS in close proximity to the 

boiler.
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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. This 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. For 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-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).

EPA’s compliance cost estimates for the remote mechanical drag system reflect the complete 

system 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 distance 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 systems, 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 multiple 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, moreover, 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 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.”); Weyerhaeuser 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.”).
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Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-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 temperatures 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 

buildings in their calculations. EPRI included building costs for 30% of the plants on which the 

industry cost is based.
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4499-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.

EPA’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 likely 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.
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Comment Response: 

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-HQ-OW-2009-0819-4499-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.
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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 facilities 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 estimated 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 includes 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-HQ-OW-2009-0819-4475-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 Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 88
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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 

additional 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 flow 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 management. 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 capital 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 recirculation systems that mainly recycle bottom 

ash sluice water, EPRI estimates an annualized cost to the industry of $21 to $68 million (2010 

dollars).
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4379-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 (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 117

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

E.1Cost Estimating Summary for Conversion of Wet to Dry Bottom Ash 

Handling

E.1.1Summary

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 the 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 technology options that EPA evaluated for bottom ash 

transport water:

 Mechanical drag system

 Remote mechanical drag system
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E.1.2.1 Mechanical Drag System

The Mechanical Drag System (MDS) for which costs were developed consists of chain mounted 

flight bars submerged 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-term 

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% moisture 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 utilized 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 existing 

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 recirculated 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 remote 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 options 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.
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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 removing 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 Cost 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 for 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 ferric 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 chemical is more applicable to aid 

precipitation of fine solids than EPA’s assumed acid addition.
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 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 

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 Standards 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: Electrical costs were estimated using the value used by EPA, $0.0405/kilowatthour (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].

 Energy: 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 High pressure recirculation pump200 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 MDS 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.
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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 Cost 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 operations 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 solids 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 Standards 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: Electrical costs were estimated using the value used by EPA, $0.0405/kilowatthour (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].

 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- Unit 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 sluicing 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 Costs
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EPRI used the same assumptions as EPA for recurring costs for drag chain replacement. The 

drag chain replacement would cost $175,000 and would occur every 3 years for the under-theboiler 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 develop 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 costs 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 incurring 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 denominator). 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 percentage 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 of 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 because 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 explained 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 remote 
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mechanical drag 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 conclusively 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 bottom 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 possible costsavings 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 overall 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.”); Weyerhaeuser 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.”).

For the remote mechanical drag system operation and maintenance costs, the commenter used 

several factors and assumptions from EPA’s proposed cost methodology. For 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 final 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 estimates, 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.
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The cost estimates associated with the final rule reflect EPA’s responses to public comments. 

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule.

Commenter Name: Daniel K. Plath

Commenter Affiliation: Northern Indiana Public Service Company (NIPSCO)

Document Control Number: EPA-HQ-OW-2009-0819-4508-A2

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In addition, 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 cyclone 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 compliance, 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 transport 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-HQ-OW-2009-0819-4633-A1, Excerpt Number 46 in Comment 

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-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 20

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Separating Low Volume Wastewater from Bottom Ash Transport Water is Impractical and Not 

Accounted For in the Economics

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 417 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 total 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-HQ-OW-2009-0819-4448-A1, Excerpt Number 

39 regarding pond closure and legacy wastewater. In addition, under the final ELG, steam 

electric power plants may continue to operate ponds, along with other waste streams, as long as 

the plant complies with the applicable final limitations and standards.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 them in the economic evaluation before requiring 

zero discharge.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 39 for more 

information on the decommissioning of surface impoundments.

EPA confirmed with vendors that the existing 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-HQ-OW-2009-0819-4448-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 Cooperative, Inc. (SECI)

Document Control Number: EPA-HQ-OW-2009-0819-4518-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 proposed 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 

bottom 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 be 
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beneficial and cost-effective, the ability to install these systems is very site specific 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 facilities 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 this 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 its 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 compliance 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-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).

Commenter Name: Erik Silvola

Commenter Affiliation: Great River Energy (GRE)

Document Control Number: EPA-HQ-OW-2009-0819-4572-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 only 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 117 for more 

information on EPA’s review of the commenter’s cost methodology submitted in Appendix E of 

the their public comment letter.
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See response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 39 for more 

information on the decommissioning of surface impoundments.

See response to DCN EPA-HQ-OW-2009-0819-4510-A2, Excerpt Number 22 for more 

information on the decommissioning of related handling systems.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 50

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

2. Bottom Ash Cost and Engineering Information Survey

On November 5, 2012, UWAG distributed an electronic 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 on 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 members 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-HQ-OW-2009-0819-4655, 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-effectiveness in EPA’s decision for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655
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Comment Excerpt Number: 55

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule. See also 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). 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-HQ-OW-2009-0819-4655

Comment Excerpt Number: 56

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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., reused 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 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 that 
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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 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 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 this 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 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 require 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 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 (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 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 35 for more 

information on EPA’s bottom ash management cost methodology for the final rule.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG
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Document Control Number: EPA-HQ-OW-2009-0819-4655

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. UWAG’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 EPAHQ-OW-2009-0819-4379-A1, Excerpt Number 53 regarding bottom ash cost estimates for the 

final rule.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 67

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

O. Retrofitting to Dry Handling of Bottom Ash Would Be Long and Expensive

Attachment 11 to these comments 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 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).

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-HQ-OW-2009-0819-4379-A1, Excerpt Number 41 for EPA’s 

comments on the case studies for bottom ash retrofits submitted by both UWAG and Southern 
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Company (DCN EPA-HQ-OW-2009-0819-4655-A11 and DCN EPA-HQ-OW-2009-0819-4379-

A1).

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 

to estimate capital costs (2012 dollars) of retrofitting based on a unit’s MW. UWAG selected 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 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 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, services during construction, and startup), overhead and 

profit (subcontractor and general contractor costs), and miscellaneous contingency (unidentified 

costs).
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Using this more realistic cost curve, UWAG calculated capital costs and annualized capital costs 

based 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 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 1.03

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 EPAHQ-OW-2009-0819-4379-A1, 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.”

Commenter Name: Kevin D. Frizzell

Commenter Affiliation: Owensboro Municipal Utilities (OMU) Elmer Smith Station (ESS)

Document Control Number: EPA-HQ-OW-2009-0819-4683-A2

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 bottom 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 process 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-HQ-OW-2009-0819-4508-A2, Excerpt Number 6 for more 

information on cyclone boilers.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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 technology 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 

installation 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 1079 
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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 cost metrics EPA employs: total costs; impact on retirements and generation; cost-torevenue 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 VIII 

and IX). See the response to DCN EPA-HQ-OW-2009-0819-4704-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-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 107

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

2. The actual costs of a zero discharge standard are far lower than EPA calculated.
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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 bottom 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 economies 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 multiple 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 advantage 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 capital 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 corroborates 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 than 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. Companies 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 ash. 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 retire 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.
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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 in 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-HQ-OW-2009-0819-2888. Additionally, 

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-HQ-OW-2009-0819-0422.

454 Id. at 27.
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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 meeting 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. 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.”); Weyerhaeuser 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-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

for BAT, costs associated with economies of scale, “units that are likely to convert to dry bottom 

ash handling for reasons other than compliance with this rule,” and the annualization factor.

EPA agrees with the commenter that dry bottom ash handling systems may reduce operation and 

maintenance costs, specifically associated with reduced auxiliary power (for example, no 

pumping required for the sluicing system) and lower water usage. As for the technologies EPA 

evaluated as the basis for BAT, EPA did account for operation and maintenance savings where 
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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 from 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 require moisture conditioning prior to landfilling for dust control adding to the total 

weight requiring disposal.

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 regarding bottom 

ash cost estimates for the final rule, including EPA’s use of a 20-year useful life.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 110

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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 ash 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 no water at all. These other systems are more costeffective 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 estimated 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. While 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.469
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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 bottom 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 costs 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 systems 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-HQ-OW-2009-0819-2888.

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-HQ-OW-2009-0819-0422.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-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 consumption 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. 
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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 

zero 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 also 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 costs 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 

Wateree 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 units 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 units 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-HQ-LW-2009-0819-

1917.

502 Fox Report, Appendix E, at 19-20.
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

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-HQ-OW-2009-0819-4684-A1, Excerpt Number 107 

regarding additional information on dry bottom ash handling systems and operation and 

maintenance costs.

See the response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 40 in Comment 

Code 5.c regarding the 400-MW threshold for bottom ash transport water.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4684-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 units 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 

and 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 cost 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 rule. This bias affects the cost analyses for all waste streams for all proposed 

options.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 
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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-HQ-OW-2009-0819-4684-A1, Excerpt Number 107 

regarding additional information on dry bottom ash handling systems and operation and 

maintenance costs.

EPA agrees that there are added environmental benefits to zero discharge systems and that plants 

can benefit from additional revenue from the sale of dry ash. However, as a conservative 

approach, EPA estimated that all plants would dispose of bottom ash in on-site or off-site 

landfills. Plant-specific marketing information was not available to accurately estimate savings 

associated 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, 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.”); Weyerhaeuser 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.”).

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-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 34,449, 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 EPA recognizes "dry" handling as feasible, it did not 

evaluate "dry" handling in its costs and other analyses.
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4704-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-HQ-OW-2009-0819-4704-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 ash 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 most 

environmentally beneficial options. The true dry systems include: MACTM; DRYCONTM; 

VAXTM; and PAXTM.

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 Options 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 should 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 Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

for BAT. Also, see the response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 

40 in Comment Code 5.c regarding the 400-MW threshold.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 18

External Review Flag: No External 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 in 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 conversion 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 addition, 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 costs, 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 options – not nothe wet zero discharge systems that 

EPA used as the cost basis for BAT.
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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 system 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.
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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 MDS: Non 

CBI Bottom Ash MDS Capital Costs,” Docket No. EPA-HQ-OW-2009-0819-2888, Tab: 

"Remote MDS Capital Cost".

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 coalfired 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.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

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-HQ-OW-2009-0819-4684-A1, Excerpt Number 107 

regarding additional information on dry bottom ash handling systems and operation and 

maintenance costs.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review 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 majority 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 Fleming, Delta Ducon,” Docket No. EPA-HQ-OW-2009-

0819-1202-0419, Re: ‘Potential Changes to the Ash Handling Part of the Steam Electric ICR.’
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4704-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-HQ-OW-2009-0819-4704-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 experience, 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 

little 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-HQ-OW2009-0819- 2888, Re: ‘Bottom Ash Handling - 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 the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

for BAT, costs associated with economies of scale, “units that are likely to convert to dry bottom 

ash handling for reasons other than compliance with this rule.”
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Additionally, see the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 107 

regarding additional information on dry bottom ash handling systems and operation and 

maintenance costs. See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt 

Number 157 regarding the sale of bottom ash.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment 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 declines 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 system, 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 

energy 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 overlapping 

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 

overestimate their costs.
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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 interest 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, Sec. 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 record 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 estimated 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 the 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 retrofits 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 Technology,” 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-HQ- OW-2009-0819-1891, p. 5.

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,” EPAHQ-OW-2009- 0819-2888 ("All data has been removed from this file as a result of CBI 

sanitization. All data used to determine the cost factors for the bottom ash MDS wet sluicing 

O&M costs is considered CBI or CBI deducible.").
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

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-HQ-OW-2009-0819-4684-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 Point 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-HQ-OW-2009-0819-4704-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 Considered

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 for 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, "EPA 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.

Estimating 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 affect the cost when multiple units 

are involved. Further, vendors offer multi-unit discounts, which were also ignored in EPA's cost 

analysis.
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First, bottom ash is generally produced intermittently, typically once or twice per 8-hour 

shift. This means ash handling 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 systems 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. Costing 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 discounts 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 drag 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 Systems63 ($/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 24,444
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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 total 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 conversion 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 them 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 ASHCONTM, 

the remote MDS system that EPA evaluated:

"Since multiple Boiler Units can send their slurry to one ASHCONTM, another "limit" is up to 

four to five Boiler Units per ASHCONTM 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 Units would sequence 

one at a time into one continuously operating ASHCONTM."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 

units. 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 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.

In summarizing conversations between EPA and UCC, ERG wrote: "UCC stated that there [sic] 

savings 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 SFC
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 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 all 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, 

regardless 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 factors 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 growing 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 increasingly 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 operators have announced retrofits of 10 to 30 generating units (a range is 

reported due to CBI issues). 78 Fed. Reg. at 34,453.
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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 conversions, 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 known70 were

planning to convert, independent of this rulemaking. The docket, for example, indicates that EPA 

was aware that some plants included in its cost analysis71 were in the process of converting one 

or more bottom ash handling systems that are not identified in 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 201272), 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 significant 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, resulting 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 maintenance 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 phase 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 benefits, 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 extremely 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 of 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 best 
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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 companies 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 applications. 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 systems 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 practices. 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 one 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-fired 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 their 

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 ash waste; or water shortage issues, such 

as in the western U.S.
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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, plants 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-yearold 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 compliance 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 years 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-HQ-OW-2009-

0819-2888, EPA Conservations with Clyde Bergemann Power Group, pdf 12 (silos shared by at 

least 2 units)(one ASHCONTM can serve multiple units, e.g., TVA project), 14-15; “Bottom 

Ash Handling: Why the Outlook is Dry,” Modern Power Systems, March 1, 2007; Available at: 
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http://www.modernpowersystems.com/features/featurebottom-ash-handling-why-the-outlook-isdry.

63 Calculated from data in tab: "MDS Capital Cost" in Excel spreadsheet: “Non CBI Bottom Ash 

MDS Capital Costs Docket,” No. EPA-HQ-OW-2009-0819-2888, ‘Bottom Ash Clyde 

Bergemann Costs of MDS.’ See also: Capital cost equations 8-2 and 8-39 in Docket No. EPAHQ-OW-2009-0819-2888, 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 

DRYCONTM 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 

DRYCONTM 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 conversions, ASHCONTM may 

exhibit some Capital cost benefits if multiple units can be discharged to single ASHCONTM

system."), pdf 10 ("The ability to retrofit to multiple existing Units and remove the ash pond 

disposal without interfering with the boiler islands. Multiple Units can use one ASHCONTM."); 

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-HQ-OW2009-0819- 2888, Attachment 80, ‘Re: Action Items - EPA Call with UCC, May 10, 2011,’ 

Attached File under "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.
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71 Not identified as excluded in: “ERG Memorandum from T. J. Finseth and Danielle Lewis,” 

Docket EPA- HQ-OW-2009-0819-2149, 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 Carolina 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-2009-0819-0580, 

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-OW2009-0819-0419, 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, “Wet 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-handlingcompared-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-toDry Bottom Ash Solutions,” Energy-Tech, March 2011, p. 2; Available at: http://www.energytech.com/article.cfm?id=30944&PageNum=2

79 Dan Charhut, “EPA Regulations Accelerate 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-Shift-fromWet-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-whythe-outlook-is-dry

81 See ERG Telephone Call Record, supra note 73.

82 See Charhut, supra note 79.
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83 “ERG Memorandum from Elizabeth Sabol and Thomas Finseth,” Docket No. EPA-HQ-OW2009-0819, 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://www.powermag.com/coal/Predicting-U-S-Coal-PlantRetirements_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 and Cost 

Savings Associated with Impoundment Operation.’

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the selection of the bottom ash handling technologies as the basis 

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.”

EPA did not receive any information on “multi-unit discounts” from the vendors and used the 

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 SE05831/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 mechanical 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 redundancy 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 methodology 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 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 
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Act does not require a precise calculation of BAT costs.”); Weyerhaeuser 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 bottom 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-HQ-OW-2009-0819-4704-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 investment 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 year 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 conversion 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-year 
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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 decrease 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

 water 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, of 
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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 sales, 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 

maintenance 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 systems 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 disposal 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 plants." 95 While 100% of the bottom ash likely could not be 
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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 metropolitan 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 these 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 bottom 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, offsetting 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 granules. 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 also 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 content99 for use in the cement industry. Or, if produced 

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 of bottom ash or 37% of the 

reported total produced in the U.S. was being beneficially used as summarized in Table 6:101
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A common market for bottom ash is as lightweight aggregate. The first commercial-scale 

bottom ash beneficiation system to recover lightweight aggregate from stored bottom ash was 

installed in 1997 at Winyah Generating Station. Since then, several other bottom ash 

beneficiation plants have been installed to produce lightweight aggregate.103

The bottom ash from dry systems that use air to cool 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 marketable. Many U.S. power stations currently 

market their bottom ash, such as the Cinergy stations in the Cincinnati area. Wateree, for 

example, sells almost 100% of its dewatered bottom 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 use 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 asphalt 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 MACTM back into the 

combustion chamber, converting it into fly ash.107 The bottom ash can be pulverized and mixed 
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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 2003.109

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 significant 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.iceecon.org/papers/2009/pdf/4.04_I9CP0180_E.Pdf.

89 See Seminole Site Visit Notes, supra note 59, pp. 7-8.

90 Costs adjusted 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/TheBetter- 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, “Commercial Use of Coal 

Utilization By- Products and Technology Trends;” Available at: 

http://www.netl.doe.gov/technologies/coalpower/ewr/coal_utilization_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. Gautreau 
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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 such 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. EPAHQ-OW- 2009-0819-1784; and supra note 33.

101 ACAA, “2011 Coal Combustion Product (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 previous, 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 Process 

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/fullcontent.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/issue4/features/coal-and-ash- handlingin-search-of-cost-savings.html.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-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, 

Seminole’s DRYCONTM installation). However, EPA did not quantify these savings as part of 
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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 costs. 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-HQ-OW-2009-0819-4684-A1, Excerpt Number 157 regarding 

bottom ash sales.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-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 

establish cutoff thresholds for applicability of its proposed ELGs110 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 annualized 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 Analysis 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., inflation 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 recent 
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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" to 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 elsewhere 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 methods.

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 ash 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 of 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, supra note 84.
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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-R13-005, April 2013.

115 Using CAP Eqn. 8-68, the annualization factor 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-HQ-OW-2009-0819-4684-A1, Excerpt Number 102 in Comment 

Code 15 for EPA’s response on the annualization factor.

See the response to DCN EPA-HQ-OW-2009-0819-4655, 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 (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 51

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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-OW-2009-0819-4655, 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-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 54

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 this 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 1.03
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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 oilfired (see preamble sections VIII and IX).

See the response to DCN EPA-HQ-OW-2009-0819-4460-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-HQ-OW-2009-0819-4655, Excerpt Number 47 in Comment Code 

15.d for more information on the data and methodology used to calculate bottom ash baseline 

loadings.
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See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 for more 

information on the estimation of compliance costs associated with 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” generating units (50 MW or less).

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2

Comment Excerpt Number: 56

External Review Flag: No External Review

External 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: 

See response to DCN EPA-HQ-OW-2009-0819-4379-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-HQ-OW-2009-0819-4655-A11 and DCN EPA-HQ-OW-2009-0819-4379-

A1).
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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” generating units (50 MW or less).
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16.c. Zero Discharge Bottom Ash – Pollutant Loads 

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-A1

Comment Excerpt Number: 54

External Review Flag: No External Review

External Review 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 whole 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 Systems – 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 calculations 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 (resulting 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 believe EPRI’s and UWAG’s dataset and 

analysis are more accurate. 

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d.

EPA excluded data using settled ash transport water see response to DCN EPA-HQ-OW-2009-

0819-4305-A3, Excerpt Number 74 in Comment Code 15.d.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-A1

Comment Excerpt Number: 6
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External Review Flag: No External Review

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, isolated 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-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 15.d.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

Document Control Number: EPA-HQ-OW-2009-0819-4475-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 precipitation 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 methodology 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 required for BAT.

Comment Response: 

Regarding plants that this commenter claims have chemical precipitation for ash transport water 

see response to DCN EPA-HQ-OW-2009-0819-4475-A1 Excerpt Number 57 in Comment Code 

7.
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For the final rule, EPA reviewed the bottom 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 calculation of industry-level loadings.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

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 (EPAHQ-2009-0819-2070), 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 nonCBI flow data reported in the Steam Electric Survey. The commenter calculated an industrywide “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 plantspecific pollutant loadings. EPA used data from the Steam Electric Survey to identify 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 plantspecific 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 
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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-HQ-OW-2009-0819-4379-A1

Comment 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 non-CBI flow rates in the record for the rulemaking 

(EPA-HQ-2009-0819-2070), 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-HQ-OW-2009-0819-4655, Excerpt 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 Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 71

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

7.1 EPA’s estimated pollutant reductions by converting to zero discharge of 

bottom ash sluice water appear to be high by about a factor of 10.
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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 EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 15.d.
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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-HQ-OW-2009-0819-2927-A1

Comment Excerpt 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 acknowledge

- 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 two 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 brief reminder, the two boiler Units in Florida with DRYCONTM conveyors under them 
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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 reduced

 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 technologies 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 eliminates 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.

Commenter Name: Fulvio Bassetti

Commenter Affiliation: Magaldi Power

Document Control Number: EPA-HQ-OW-2009-0819-4177-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 CoolerTM based on a 

mechanical extractor underneath a solid fuel boiler, was overlooked and omitted from the list of 

bottom ash handling technologies.
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The MAC - Magaldi Ash CoolerTM “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 application 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 CoolerTM 

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. Nevertheless, 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 describing a MAC - Magaldi Ash CoolerTM 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 CoolerTM, 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 sturdy 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 CoolerTM.

We kindly request the addition of our MAC - Magaldi Ash CoolerTM references to the list of 

operating installations in the USA.

A plus downstream the MAC system can be the innovative MAR - Magaldi Ash RecyclingTM, 

to recycle the dry bottom ash back to the boiler and transform it into saleable fly ash.
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Depending on the plant layout and operation needs, different configurations of the MACTM and 

the MARTM 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 one in Florida has been in 

operation since 1993, the MAC - Magaldi Ash CoolerTM “fully-dry” technology provides the 

following outstanding benefits:

 Zero water usage. No water treatment systems required.

 Effective environmental risk mitigation. No need for bottom 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 fuel (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 maximum 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 benefits of the MAC - Magaldi Ash CoolerTM “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 believe that our MAC - Magaldi Ash CoolerTM “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 

CoolerTM and of the MAR - Magaldi Ash RecyclingTM, the MACTM 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 enable a plant to meet the zero discharge requirements in the final 
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rule. Additional benefits include cost savings associated with reduced operation and maintenance 

costs and reduced coal consumption.

Commenter Name: Chas Spell

Commenter Affiliation: Arizona Public Service Company

Document Control Number: EPA-HQ-OW-2009-0819-4303-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 operates 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 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 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 progress 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-HQ-OW-2009-0819-4464-A1, Excerpt Number 3.

EPA notes that steam electric power plants may 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-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 155

External Review Flag: No External Review

External Review Incorporated into Response: No
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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 technologies 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 Conveyor

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 bottom 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 seal 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 silo 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 capable 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.
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 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 receives 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 the 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 operation.

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 water-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 on 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 

residual 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 technologies 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 access 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.
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Other challenges in installing this technology are as follows:

 Existing 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 below 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 include 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 retrofits.

 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 flight 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 water 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 hopper (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 promulgation 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 

piping will require new pumps and motors.
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 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 located 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 motors 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 receive 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 units, 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 hopper 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 have 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 

installed 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 required for both.
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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 constraints 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, in 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 recycle 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) contains 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-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 111

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Clyde Bergemann recently wrote to EPA expressing its surprise that EPA had neglected zero 

discharge systems that do not use water. Clyde Bergemann 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 handling 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 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 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 fewer 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. EPAHQ-OW-2009-0819-2927.

474 Fox Report, Appendix E, at 27.

475 Id.

476 Id. at 27-28.
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Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-2927-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 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 all. EPA agrees that dry vacuum and pressure systems are viable 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-HQ-OW-2009-0819-4684-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 determined 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 of 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 handling 

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 estimate 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 ash, 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. Therefore, 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). EPA confirmed that this maintenance can be completed 

without the systems being drained.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 13

External Review 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 systems. 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 efficiency. 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, improving 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 (PAXTM), 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 (MACTM) 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 enclosed inside the sealed casing of the extractor. Ash is 
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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 

ash 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

DRYCONTM (DRY ash CONveyor) is Clyde Bergemann's dry bottom ash handling system and 

is a relatively new entrant into 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 boiler 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 vibratory 

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 technology. 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 aware 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 installations 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 Extractor;” Available 

at:http://unitedconveyor.com/PAX/.

23 See “Email from Gary Mooney,” supra note 16, pp. 2, 5.
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24 “Magaldi Solutions for Ash Handling;” Available 

at:http://www.magaldi.com/en/magaldi_solutions_for/Ash-Handling-Mac9_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/uploadedFiles/Systems/UCC_Wet-ToDry_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.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 111 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-HQ-OW-2009-0819-4704-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 vacuum 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 confirmed with technology 
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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-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 23

External Review Flag: Economics/Benefits

External Review Incorporated 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 carbon 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 the 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, NOx, SO2, etc.) and O&M costs.

In systems that use air for cooling (e.g., MAC, PAX, VAX, DRYCON53), 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). Improved 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 by 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, 
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“Dry Bottom Ash Removal – Ash Cooling vs. Boiler Efficiency Effects,” Docket No. EPA-HQOW-2009-0819-0417, 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. Carrea and M. 

Graziadio, “Bottom Ash Carbon Content Reduction by Means of MAC Dry Extraction System,” 

Docket No. EPA-HQ-OW-2009-0819-0413, 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 CO2. See the response to DCN EPA-HQOW-2009-0819-4684-A1, Excerpt Number 111 for more information on EPA’s technology basis 

for bottom ash transport water.
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17. Combined Ash Transport Water – Wastewater Characterization 

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 134

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For some Southern plants, EPA miscalculated 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 Revised

At our request, EPA provided a CD64 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. Southern 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 used 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 pollutants 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 either 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-19), or

3. Percent contribution to an outfall in Part A.
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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 rates 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 other 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 

for 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 wastestreams. 

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 account recycle rates where 

appropriate, and using more accurate and up-to-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 from 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 D 
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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 specifically 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 level, 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 explain 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 not 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 the 

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 loadings 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 the 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-to-date characterization data. See responses to DCN EPA-HQ-OW-2009-0819-4379-A1,

Excerpt Number 24 in Comment Code 4.b and DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 72 in Comment Code 15.d.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 32

External Review Flag: No External Review

External Review Incorporated into Response: No
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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-HQ-OW-2009-0819-0655 (including attachments 1 

through 9) (the 2010 ICR), also available at http://water.epa.gov/scitech/wastetech/guide/steamelectric/questionnaire.cfm, for both fly ash transport water and bottom ash transport water5

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 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 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 combined 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.

1982 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.
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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 calculations.

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 and 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 the 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 Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category” (IC&PR), EPAHQ-OW-2009-0819-2256 at 4-4.

Comment Response: 

EPA disagrees that it “erred by using data from combined fly ash and bottom ash ponds to 

characterize pollutants in fly ash and bottom ash transport water separately.” See the comment 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment Code 13.d 

and DCN EPA-HQ-OW-2009-0819-4499-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-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 24 in Comment Code 4.b and DCN EPA-HQ-OW-2009-0819-4499-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.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655

Comment Excerpt Number: 63

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

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-HQ-OW-2009-0819-4655, Excerpt Number 32 regarding EPA’s use 

of combined fly ash and bottom ash pond data. In addition, see the responses to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 38 in Comment Code 4.b and DCN EPA-HQ-OW-2009-

0819-4499-A1, Excerpt Number 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 Control Number: EPA-HQ-OW-2009-0819-5510-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 in 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 level 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 analyzed 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-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 24 in Comment Code 4.b DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 

in comment code 15.d, and DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in 

Comment Code 13.d regarding EPA’s ash characterization data, including the use of combined 
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fly ash and bottom ash data and the use of Form 2C data. See also the response to DCN EPAHQ-OW-2009-0819-4460-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-HQ-OW-2009-0819-4470-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-HQ-OW-2009-0819-4614-A1

Comment Excerpt Number: 12

External Review Flag: No External 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 ash 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 24 in 

Comment Code 4.b and DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4655, Excerpt Number 38 in Comment 

Code 4.b and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d for a discussion of EPA’s use of the 1982 TDD data.
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Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 23

External Review 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 ash 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-HQ-OW-2009-0819-4305-A3, Excerpt Number 73.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OW-2009-0819-4305-A3

Comment Excerpt Number: 73

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment 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 percent, 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 concentrations 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 pyritic. 

In addition, most of these plants dispose of the pyritic mill rejects in a pond, most often 
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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-HQ-OW-2009-0819-4487-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.

See the comment response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 24 

in Comment Code 4.b and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in 

Comment Code 15.d regarding EPA’s ash characterization data, 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.

EPA did not assume that “fly ash and bottom ash account for 86 and 14 percent, respectively, for 

all combined ash loadings.” See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 27.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OW-2009-0819-4379-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. The 

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-wide flow for combined ash ponds 

(Technical Development Document, EPA-HQ-OW-2009-0819-2257(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 flow 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.
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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-HQ-OW-2009-0819-4379-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 pollutantspecific 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 associated with bottom ash transport water and 86% of the 

loading associated with fly ash transport water.

See also the comment response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated 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-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-A1, Excerpt Number 24 

in Comment Code 4.b regarding EPA’s expanded ash characterization data, including the use of 
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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-HQ-OW-2009-0819-4499-A1

Comment Excerpt Number: 74

External Review Flag: No External Review

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 same 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, Combined 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 pollutant loads associated 

with combined ash systems.

See the comment response to DCN EPA-HQ-OW-2009-0819-4655, 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-HQ-OW-2009-0819-4379-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 impoundments into fly ash loadings and bottom ash loadings. See the response to 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in Comment Code 4.b and DCN 

EPA-HQ-OW-2009-0819-4499-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.
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Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

Document Control Number: EPA-HQ-OW-2009-0819-4499-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-detect 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 driving 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 samples, 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-detects 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 thallium were nondetects, 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 onehalf of the reported value.

EPRI also notes that EPA’s recent sample values are typically an order of magnitude lower than 

earlier averages derived from the Form 2C data.
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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, EPRI treated all non-detect values in its data set as onehalf of the method detection limit. Further, EPRI did not use any parameters that had only nondetects reported in the EPRI data set.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment 

Code 15.d.

For the reasons explained in EPA’s response to DCN-EPA-HQ-OW-2009-0819-4487-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.