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

EPA’s Response to Public Comments

4-1

6. Regulatory Options 

Commenter Name: R. W. Greene

Commenter Affiliation: Mercatus Center at George Mason University

Document Control Number: EPA-HQ-OW-2009-0819-3411-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

It is important to realize that the ELGs are not enumerated as emissions limits, but rather are 

listings of best practice technologies for handling particular effluents (see table 1-2 in the 

Regulatory Impact Analysis for the proposals).4 The cost and other impacts analyzed in the 

rulemaking stem from modeling estimations of the impact of applying these technologies.

4 US Environmental Protection Agency, "Regulatory Impact Analysis for Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category," EPA-821-R-13-005 (Washington: April2013): 1-3.

Comment Response: 

The commenter is referring to a table in the proposed RIA that specified the technologies that 

form the bases of the proposed regulatory options. See the final RIA for a similar table that 

reflects the final rule. The commenter is correct that the final rule does not establish numerical 

limitations for air emissions at is establishes nationally applicable technology based limitations 

for discharges of pollutants in certain wastestreams from steam electric power plants to surface 

waters. The commenter is correct that the final ELGs do not require application of a certain 

technology. For example, the final rule establishes numeric effluent limitations guidelines and 

standards for FGD wastewater and gasification wastewater. For these wastestreams, although 

EPA has based the numeric limitations and estimated costs and impacts on the performance of 

specific technology bases, the final rule does not prescribe a specific type of treatment.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 152

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

I think that the physical space is a critical issue because all of the technologies that EPA is 

looking at require physical space.

Comment Response: 

EPA agrees with the commenter that the technology options that form the bases of the final rule 

require physical space. However, EPA’s analyses have found that plants generally have available 

land to construct necessary wastestream controls. EPA based its costs estimates in part on 

responses provided by industry during the Steam Electric Survey.

In addition, EPA also confirmed survey responses through site visits and discussions with steam 

electric power plants representatives who have already implemented these technologies. EPA’s 

determination regarding land requirements for FGD wastewater treatment also appears to be 

supported by commenters. For example, the Electric Power Research Institute’s detailed Cost 

Estimating Summary for Chemical Precipitation of Flue Gas Desulfurization Wastewater (see 

Appendix A.1 of DCN EPA-HQ-OW-2009-0819-4499-A1) does not include estimated costs for 

acquiring land.

During the public comment period, EPA did receive comments from some specific plants that 

demonstrated space constraints to retrofit to a mechanical drag system (MDS) due to space 

constraints underneath the boiler. In these cases, EPA estimated bottom ash compliance costs 

associated with a remote MDS. See responses to DCN EPA-HQ-OW-2009-0819-4379-A1, 

Excerpt Number 45 in Comment Code 14.b and DCN EPA-HQ-OW-2009-0819-4655, Excerpt 

Number 53 in Comment Code 16.b for more discussion on EPA’s rationale regarding land costs 

for ash handling systems.

Commenter Name: M. Colburn

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4125-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A technique called annodic stripping could be use to remove contaminates in the water before 

discharging

Comment Response: 

EPA is not familiar with the use of anodic stripping for wastewater treatment, or its potential 

applicability to steam electric power plants generated wastestreams. Furthermore, the commenter 
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has not provided any information or data indicating its applicability or performance for steam 

electric power generation wastestreams for EPA’s use in evaluating this technology.

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: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In trying to set standards for flow from an FGD wastewater system, EPA states “Such effluent 

limitations shall not allow the quantity of pollutants in FGD wastewater to exceed the quantity 

determined by multiplying the flow of FGD wastewater times the concentration” and goes on to 

list the parameter and associated concentrations. Without defining the units of flow, this 

requirement is meaningless. Such multiplication would yield very different answers depending 

upon whether one multiplies gallons per minute or millions of gallons per minute.

Comment Response: 

EPA disagrees that its regulatory language is ambiguous. EPA’s regulations at 40 CFR § 

122.45(f)(1) stipulate that all pollutants limited in permits must have limitations, standards, or 

prohibitions expressed in terms of mass (with certain exceptions). Calculation of the allowable 

mass discharge (for example, lbs/day) can include any reasonable measure of flow determined by 

the permit writer (for example, millions of gallons per day) by incorporating the appropriate 

units conversion factors. The resulting calculated mass discharge does not vary by the type of 

measure of flow, provided use of appropriate units conversion factors. Note that the final 

regulation also provides permit authorities discretion in expressing the quantity of pollutant 

allowed to be discharged as concentration-based limits instead of mass-based limits. In this case, 

concentration limitations are those concentrations specified in the final rule. See EPA’s NPDES 

Permit Writer’s Manual.

Commenter Name: Lisa C. Messinger

Commenter Affiliation: Vectren Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4317-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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The rule should allow for the co-management of "like" waste waters in a single treatment 

system. Specifically, some plants, such as our A.B. Brown Station, have landfills that only 

accept FGD solids. The leachate from landfills that contain only FGD solids should be allowed 

to be co-managed with t h e FGD waste water for treatment in a single system. To meet 

discharge requirements in our current NPDES permit, we are in the process of installing a 

treatment system that will combine the waters from the landfill and FGD system to a single 

treatment system that will be operational in 20l4. Neither waste water flow was significant 

enough in volume to justify individual treatment systems. As described above, the scrubbers at 

our A.B. Brown plant are unique in the electric generating industry and do not have the same 

purge volumes that are typical in limestone based gypsum scrubbers.

Comment Response: 

The final rule does not prohibit comingling but requires that each wastestream meet the 

requirements of the rule. See preamble section VIII for a discussion of the anti-circumvention 

provision and the reuse of ash transport water. The final rule does not require internal monitoring 

to demonstrate compliance with certain numeric limitations and standards. See response to DCN 

EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 117 in Comment Code 26.d.

Commenter Name: Lisa C. Messinger

Commenter Affiliation: Vectren Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4317-A1

Comment Excerpt Number: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Misrepresentation of Treatment Costs and the Industry as a Whole --EPA must acknowledge the 

impact that air regulations and natural gas discoveries have and will continue to have on the coal 

fired utility industry between 2010-2017 and make proper adjustments to pollutant r emoval 

calculations and associated cost justification analysis.

In section 4.2 of the Technical Development Document EPA describes the demographics of the 

Electric Utility industry based on out of date information. The most recent ICR from which 

information was obtained included data which was relevant through 2009. Since then there have 

been significant numbers of coal fired generating units that are either retired or planned to be 

retired before the July 1, 2017 effective date of this rule, driven primarily by air regulations such 

as MATS, and the influx of low natural gas as a fuel source. By our analysis of various public 

sources of information on unit retirements, over 330 coal fired units have or will be retired or 

converted to a non-coal fuel source between 2010-2017. Many or these units are older and/or 

smaller units that can not justify the added cost or compliance for air regulations such as MATS. 

Additional regulations pertaining to ELG, 316(B) and CCRs are furthcr pulling into question the 

future of t he smaller, uncontrolled units. Those units that remain in service after 2017 will be 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

4-5

fully compliant under air regulations (or through a longer negotiated timeframe if under a 

Consent Decree) and will be the "cleanest" of the current coal fired fleet of generating units.

The tables in section 4.2 of the Technical Dcvclopment Document do not reflect the reality of the 

electric generating industry. The information in these tables is the basis for the various cost 

justification formulas in the "Incremental Costs and Pollutant Removals for the Proposed 

Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category". If the information going into the calculations is flawed, so will be the 

outputs. Particularly troubling, is statement by EPA in the Technical Development Document 

(pp 9- 10) that under the four preferred options (3, 3a, 3b, and 4), at most, only 200 facilities will 

require upgrades. The vast majority of coal fi red generating stations over 50 MWs could not 

meet all of the requirements of the preferred options without some modifications. Even the plants 

that were sampled during the EPA site visits h ave expressed concern with their a bility to 

consistently meet the requirements as described in the preferred options. The undercounting of 

facilities that will incur compliance costs and the inclusion of facilitics already destined for 

retirement or repowering to natural gas shows a lack of understanding by EPA of the current 

state of th e steam electric generating industry as a whole.

Comment Response: 

EPA agrees that the tables in Section 4 of the TDD from proposal do not reflect retirements, fuel 

conversions, and ash handling conversions that were not specified in responses to the Steam 

Electric Survey. However, that does not mean that EPA did not take them into account when 

conducting the analyses for this rulemaking, including costs and impacts. Throughout this 

rulemaking, EPA continued to revise its profile of the steam electric power generation industry 

to account for retired or announced and planned to be retired stream electric generating units, 

converted or planned conversions of units to a different fuel source, and altered or plans to alter 

wastewater treatment or ash-handling practices. To the extent possible, EPA adjusted its analyses 

of costs, pollutant loadings, non-water quality environmental impacts, environmental assessment, 

and benefits for the final rule to account for these actual and anticipated changes. EPA also made 

every effort to appropriately account for other rules in its many analyses for this rule. See 

preamble section V.

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: 14

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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USEPA should include additional compliance time and costs for land acquisition and landfill 

construction, given the potential for dry fly and/or bottom ash resulting from this proposed rule, 

along with the concerns expressed as to biological treatment technology.

Comment Response: 

See responses to Comment Code 26.b and 27.e regarding implementation timing and landfills 

with respect to dry handling ash transport systems. In addition, see responses to Comment Codes 

16.b and 14.b regarding costs for landfills associated with dry handling conversions. Also, see 

response to DCN EPA-HQ-OW-2009-0819-4466-A1, Excerpt Number 11 in Comment Code 

27.e. For more information, see preamble to the final rule.

Commenter Name: Mark Thoma

Commenter Affiliation: Otter Trail Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4446-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We are particularly concerned that the proposed changes could be applicable to internal effluents 

that are not discharged (including the proposal to impose Best Management Practices for surface 

impoundments); that the proposed rule does not differentiate between bottom ash and boiler slag; 

and that the rule is unclear with regards to combustion residual leachate.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 64 in Comment 

Code 27.e regarding BMPs for surface impoundments. See response to DCN EPA-HQ-OW2009-0819-4633-A1, Excerpt Number 46 in Comment Code 6.g.ix regarding bottom ash and 

boiler slag. See response to DCN EPA-HQ-OW-2009-0819-5406-A2, Excerpt Number 15 in 

Comment Code 18 regarding combustion residual leachate.

Commenter Name: Jacob G. Smeltz

Commenter Affiliation: Electric Power Generation Association (EPGA)

Document Control Number: EPA-HQ-OW-2009-0819-4450-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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EPGA members are concerned that the proposed standards are set too low and therefore, 

notwithstanding effort to comply, will result in non-compliance. Additionally, EPGA is 

concerned that even if compliance were achievable, the cost estimates provided by EPA are 

severely understated.

Comment Response: 

EPA disagrees that the limitations are too low and will result in non-compliance. See TDD 

Section 13 for the data sources, data selection, and statistical methodology used to calculate the 

limitations for the final rule. Also, see TDD section 13.5.3 for a discussion of EPA’s expectation 

that plants are capable of complying with the limitations at all times by properly operating and 

maintaining their processes and treatment technologies. Note that certain numeric limitations 

have been revised upward for the final rule based on additional data received since proposal.

EPA also disagrees that its compliance cost estimates are understated. As discussed in preamble 

section V.D, and in greater detail in the TDD, the final cost estimates reflect updates from 

proposal to account for specific comments, where appropriate, related to costs.

Commenter Name: Jacob G. Smeltz

Commenter Affiliation: Electric Power Generation Association (EPGA)

Document Control Number: EPA-HQ-OW-2009-0819-4450-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s use of such a limited data set and its failure to meet the requirements of the feasibility and 

availability of treatment options, as required under the Clean Water Act, should give rise to 

concerns about the many assumptions that the Proposal makes relative to compliance and 

cost. EPGA encourages EPA to seek additional information relative to these two important 

components so that the agency can be fully informed in its rulemaking and promulgate a final 

rule that can meet these statutory requirements.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4450-A1, Excerpt Number 1.

Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 23
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Preferred Options Relative to Risk

In its comments above, Consumers Energy commented on four wastestreams: fly ash transport 

water, bottom ash transport water, leachate, and nonchemical metal cleaning wastes. Our 

additional comments on the preferred options are limited to the options as they apply to these 

wastestreams only.

In general, the preferred options (3a, 3b, 3, and 4a) reflect a lower perception of risk as 

evidenced in the draft ELG EA than the level of risk anticipated in Options 4 and 5. We believe 

this is appropriate given the data presented in the draft ELG EA. However, as noted in our 

comments above, we feel that even this level of risk is overstated in the draft ELG EA, and we 

again urge EPA to appropriately assess this risk, and thereby provide a basis for the 

reconsideration of risk and benefit/cost and the determination of which options should be 

preferred.

Comment Response: 

The perception of risk referred to in this comment relates to another excerpt from this commenter 

(DCN EPA-HQ-OW-2009-0819-4452-A2, Excerpt Number 9 in Comment Code 6.a) regarding 

identification and selection of pollutants and source water contributions of pollutants. ELGs are 

nationally applicable technology based requirements to control pollutant discharges to surface 

waters. They reflect technologies that are available, affordable and have acceptable non-water 

quality environmental impacts, and they are not based on risk.

Unlike water quality-based effluent limitations, which are calculated to ensure that water quality 

standards for the receiving water are attained, technology-based limitations and standards are 

derived to reflect the performance of specific model technologies that EPA is required by statute 

to identify. In identifying these technologies, EPA is directed to consider several factors, 

including the process employed and the engineering aspects of applying various types of control 

techniques. See CWA Sections 304(b)(2)(B), 306(a)(1), 307(b) & (c). Indeed, EPA’s regulations 

must identify the degree of effluent reduction attainable through the application of BAT-level 

process and procedure innovations, operating methods, and other control measures and practices 

for the category or subcategory being regulated. CWA Section 304(b)(2)(A). Limitations 

established in this rule represent the degree of effluent reduction that EPA has determined is 

attainable by the BAT, NSPS, PSES, and PSNS model technologies. Thus, they are consistent 

with the long-recognized principle that technology-based limitations are intended to reflect, for 

each industrial category or subcategory, the “base level” of technology (including process 

changes) and to ensure that “‘in no case . . . should any plant be allowed to discharge more 

pollutants per unit of production than is defined by that base level.’” E.I. du Pont de Nemours & 

Co. v. Train, 430 U.S. 112, 129 (1977), quoting S. Rep. No. 414, 92d Cong., 1st Session 50, 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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reprinted in A Legislative History of the Water Pollution Control Act Amendments of 1972, at 

1468 (1973).

For the role of benefit-cost in EPA’s decisions for the final rule, see response to DCN EPA-HQOW-2009-0819-4464-A1, Excerpt Number 3 in Comment Code 6.e.

Commenter Name: Jessica Wicha

Commenter Affiliation: Gypsum Association

Document Control Number: EPA-HQ-OW-2009-0819-4456-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

VI.EPA SHOULD CONSIDER THE IMPACT OF THE CHOSEN ELG REGULATORY 

APPROACH ON FGD GYPSUM SUPPLY

The Gypsum Association is not taking a position on which of the eight proposed regulatory 

options EPA should select in this ELG rulemaking. However, because FGD gypsum is a 

significant raw material source, the Agency should take that fact into account in this rulemaking 

to ensure that there is an appropriate supply of material for FGD gypsum manufacturing going 

forward.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4456-A1, Excerpt Number 5 in Comment Code 

6.g.xi.

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: 19

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA presents eight options in the proposed rule, with four being identified as preferred. Each of 

the options contains treatment alternatives for seven different waste streams. EPA’s method of 

presenting the options makes it difficult to select a single option. To more accurately recommend 

a treatment option, Raven Power recommends the follow options for the seven waste streams:
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EPA’s Response to Public Comments

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o FGD Wastewater: Chemical Precipitation (as Proposed under EPA’s Option 1)

o Bottom Ash Transport Water: Wet Handling (as Proposed under EPA’s Options 1, 3a, 2, 

3b, and 3)

o Combustion Residual Leachate: Continue to classify as a low-volume waste.

o Nonchemical Metal Cleaning Waste: The definition should exclude nonchemical metal 

cleaning waste regulated as low volume waste sources defined at Section 423.11(b) that 

are currently regulated at Section 423.12(b)(3) and/or the proposed exemption should be 

applied to all nonchemical metal cleaning waste streams currently not subject to copper 

and iron limits.

Comment Response: 

See preamble section VIII for information related to the selected regulatory options for the final 

rule.

See response to DCN EPA-HQ-OW-2009-0819-4633-A1, Excerpt Number 32 in Comment 

Code 9 regarding FGD wastewater.

See response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 in Comment Code 

6.e regarding bottom ash transport water.

See response to DCN EPA-HQ-OW-2009-0819-5406-A2, Excerpt Number 15 in Comment 

Code 18 regarding combustion residual leachate.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 

22 regarding non-chemical metal cleaning wastewater.

Commenter Name: Jared Morrison

Commenter Affiliation: Westar Energy

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

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NUTRIENT TRADING

Another concern regarding the Proposed Effluent Guidelines is the complete lack of 

consideration or mention within the guidelines for any kind of water quality trading. EPA notes 

that “water quality trading is an innovative approach to achieve water quality goals more 

efficiently” (EPA website). EPA goes on to note that trading programs allow facilities with high 

costs of pollution control to comply with effluent regulations by instead, reducing pollutants at 
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4-11

other facilities that may be suitable for lower cost alternatives in pollutant reduction. EPA notes 

trading is most effective when the following conditions are met:

 There is a "driver" that motivates facilities to seek pollutant reductions, usually a Total 

Maximum Daily Load (TMDL) or a more stringent water quality-based requirement in an 

NPDES permit

 Sources within the watershed have significantly different costs to control the pollutant of 

concern

 The necessary levels of pollutant reduction are not so large that all sources in the 

watershed must reduce as much as possible to achieve the total reduction needed – in this 

case there may not be enough surplus reductions to sell or purchase

 Watershed stakeholders and the state regulatory agency are willing to try an innovative 

approach and engage in trading design and implementation issues

All of the above conditions are met in this case, making JEC an ideal candidate for participation 

in a trading program for nitrates/nitrites. Trading of nitrates/nitrites is of great interest to Westar 

Energy, given the significant farming industry in the State of Kansas. Our belief is we could 

partner with those in the agriculture industry to reduce nitrates/nitrites from others who are 

discharging into the Kansas River, at less cost than we could accomplish the same reduction at 

the Jeffrey Energy Center.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3922-A1, Excerpt Number 3 in Comment Code 

26.f.

Commenter Name: Jared Morrison

Commenter Affiliation: Westar Energy

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

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

 Water quality trading programs should be considered as a viable option to meet numeric 

limits.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3922-A1, Excerpt Number 3 in Comment Code 

26.f.
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Commenter Name: Thomas W. Curtis

Commenter Affiliation: American Water Works Association (AWWA)

Document Control Number: EPA-HQ-OW-2009-0819-4478-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

USEPA has a responsibility in crafting pollution control regulations to ensure that it does not 

create unacceptable risks. In finalizing the proposed effluent guideline, the Agency has a 

responsibility to craft standards that:

1. Guide steam electric power plants to use air pollution control technologies that do not 

produce wastewater high in bromide.

2. Ensure that power plants located upstream of drinking water supplies, employ wastewater 

treatment sufficient to protect downstream water systems from regulated contaminants, 

bromide, and other factors that exacerbate drinking water treatment challenges and create 

potential non-compliance with drinking water regulations.

Comment Response: 

The final ELGs are not based on the concentrations needed to protect drinking water. Instead, as 

required by CWA, they are based on the performance of well-designed and well-operated control 

and treatment technologies. As explained in Section IV.B of the final preamble, Congress passed 

the CWA to "restore and maintain the chemical, physical, and biological integrity of the Nation's 

waters." 33 U.S.C. 1251(a). In order to achieve this objective, the Act has, as a national goal, the 

elimination of the discharge of all pollutants into the nation’s waters. 33 U.S.C. 1251(a)(1). The 

CWA establishes a comprehensive program for protecting our nation’s waters. Among its core 

provisions, the CWA prohibits the discharge of pollutants from a point source to waters of the 

U.S., except as authorized under the CWA. Under section 402 of the CWA, 33 U.S.C. 1342, 

discharges may be authorized through a National Pollutant Discharge Elimination System 

(NPDES) permit.

Unlike water quality-based effluent limitations, which are calculated to ensure that water quality 

standards for the receiving water are attained, technology-based limitations and standards are 

derived to reflect the performance of specific model technologies that EPA is required by statute 

to identify. In identifying these technologies, EPA is directed to consider several factors, 

including the process employed and the engineering aspects of applying various types of control 

techniques. See CWA Sections 304(b)(2)(B), 306(a)(1), 307(b) & (c). Indeed, EPA’s regulations 

must identify the degree of effluent reduction attainable through the application of BAT-level 

process and procedure innovations, operating methods, and other control measures and practices 

for the category or subcategory being regulated. CWA Section 304(b)(2)(A). Limitations 

established in this rule represent the degree of effluent reduction EPA that has determined is 

attainable by the BAT, NSPS, PSES, and PSNS model technologies. Thus, they are consistent 

with the long-recognized principle that technology-based limitations are intended to reflect, for
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each industrial category or subcategory, the “base level” of technology (including process 

changes) and to ensure that “‘in no case . . . should any plant be allowed to discharge more 

pollutants per unit of production than is defined by that base level.’” E.I. du Pont de Nemours & 

Co. v. Train, 430 U.S. 112, 129 (1977), quoting S. Rep. No. 414, 92d Cong., 1st Session 50, 

reprinted in A Legislative History of the Water Pollution Control Act Amendments of 1972, at 

1468 (1973).

To serve as the basis for the technology-based controls, the CWA authorizes EPA to establish 

national technology-based effluent limitations guidelines and new source performance standards 

for discharges from categories of point sources (such as industrial, commercial, and public 

sources) that occur directly into waters of the U.S.

While the final rule does not reflect drinking water requirements, depending on site-specific 

conditions and applicable water quality standards, it may be appropriate for permitting 

authorities to establish water-quality based effluent limitations on bromide or TDS discharges, 

especially where steam electric power plants are located upstream from a drinking-water intake. 

See preamble section XVI for more discussion. In addition, the use of air pollution control 

technologies is outside the scope of the effluent guidelines program and the final rule.

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

New Discharge Limits. Revised BAT, BADCT (NSPS), PSES, and PSNS for the seven listed 

streams provide a treatment challenge that EPA has underestimated. The proposed limits and 

chosen BAT, etc., for some streams are not sustainable over the long term operations and 

variable nature of operations at a power plant combined with the recognized challenge of 

operating complex biological wastewater systems with highly variable wastestreams. This is 

complicated further because the rule prohibits the use of other wastestreams as part of the 

treatment process (e.g., for pH adjustment, thermal reduction). By disallowing commingling of 

select waste water streams, the rule significantly increases the cost of water treatment.

Comment Response: 

EPA disagrees that the limitations are not sustainable. For further information related to the data 

sources, data selection, and statistical methodology used to calculate the limitations for the final 

rule, see TDD Section 13. In addition, for a discussion of EPA’s expectation that plants are 

capable of complying with the limitations at all times by properly operating and maintaining 

their processes and treatment technologies, see TDD Section 13.5.3. Note that the numeric 
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limitations have been revised upward for the final rule based on the additional data received 

since proposal.

See preamble section VIII and response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt 

Number 107 in Comment Code 10.a regarding biological treatment and variability in plant 

operations and wastestream characteristics.

The final rule does not establish an anti-circumvention provision that would have required 

internal monitoring to demonstrate compliance with certain numeric limitations and standards. 

See preamble section VIII and response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt 

Number 117 in Comment Code 26.d.

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

There is also concern that physical/chemical systems will not be able to meet the low levels for 

Hg and As proposed for some of the wastestreams such as leachate and FGD blowdown.

The proposed discharge limits are tied to loadings that are based on flows for each selected 

wastewater stream that EPA identified and collected information about. Unfortunately, it appears 

the proposed regulation does not consider scenarios associated with stormwater runoff from CCR 

storage, coal pile run-off, or CCR management sites. The management of these flows could 

become very expensive in terms of property and impoundment storage capacity as well as 

managing biological treatment systems for selenium and having the system function properly.

Comment Response: 

EPA disagrees that the limitations for mercury and arsenic are not achievable. For further 

information related to the data sources, data selection, and statistical methodology used to 

calculate the limitations for the final rule, see TDD Section 13. In addition, for a discussion of 

EPA’s expectation that plants are capable of complying with the limitations at all times by 

properly operating and maintaining their processes and treatment technologies, see TDD section 

13.5.3. Note that the numeric limitations have been revised upward for the final rule based on the 

additional data received since proposal.

EPA focused this rulemaking on revisions to the effluent limitations guidelines and standards for 

specific wastestreams generated and discharged from steam electric power plants. EPA identified 

the specific wastestreams included in this rulemaking based on the results from its detailed study 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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that was completed in 2009. Low volume wastes such as stormwater runoff co-mingled with 

exposed CCR materials such as outdoor storage piles and coal pile runoff are not covered in this 

rulemaking and remain subject to the existing requirements for low volume waste.

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Consider daily loads and not concentration based permit conditions.

Comment Response: 

This comment is related to the commenter’s statement that EPA allows for commingling of 

wastestreams and that EPA’s proposal could set daily and monthly loads in permits, instead of 

requiring measurements of streams prior to commingling. See response to DCN EPA-HQ-OW2009-0819-4309-A1, Excerpt Number 8 regarding the use of load-based permit conditions.

The final rule does not establish an anti-circumvention provision that would have required 

internal monitoring to demonstrate compliance with certain numeric limitations and standards. 

See preamble section VIII and response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt 

Number 117 in Comment Code 26.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: 86

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For New Source Performance Standards, EPA proposes option 4 in Table VIII-1:

Wastestream Pollutant Proposed Limits

FGD Wastewater Arsenic, total 8 6
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

4-16

Mercury, total

Selenium, total

Nitrate/nitrate as N

242 119

16 10

0.17 0.13

Fly ash transport water No discharge

Bottom ash transport water No discharge

FGMC wastewater No discharge

Gasification wastewater

Arsenic, total

Mercury, total

Selenium, total

TDS

4

1.76 1.29

453 227

38 22

Combustion residual leachate

Arsenic, total

Mercury, total

8 6

242 119

Nonchemical metal cleaning wastes

TSS

Oil and grease

Copper, total

Iron, total

100.0 30.0

20.0 15.0

1.0 1.0

1.0 1.0

See 78 Fed. Reg. at 34,436 col. 2-3, 34,536 col. 3, 34,540. Thus EPA proposes biological 

treatment for FGD wastewater, dry handling for fly ash and bottom ash transport water and 

FGMC wastewater, and chemical precipitation for arsenic and mercury in combustion residual 

leachate.

EPA explains its rationale for this choice at 78 Fed. Reg. at 34,475 col. 2-3. EPA says five 

plants operate fixed-film anoxic/anaerobic biological treatment systems for FGD wastewater and 

one a suspended growth biological system for selenium. EPA says 83% of coal-fired plants built 

within the last 20 years do not discharge bottom ash transport waters. For leachate, EPA says 

chemical precipitation is a well-demonstrated technology. 78 Fed. Reg. at 34,476 col. 1. The 

cost of these technologies, EPA says, poses no barrier to entry, citing the case of installing the 

equipment and EPA’s Integrated Planning Model analyses. EPA also says that, since non-water 

quality impacts for option 4, in its analysis, are acceptable for existing sources, they should also 

be acceptable for new sources.

EPA’s rationale for new sources, in short, depends heavily on its analyses for existing sources 

(BAT). Because of the many problems and shortage of data for those BAT analyses, EEI does 
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4-17

not think they are reliable for BAT and thus are not reliable for NSPS either.

Comment Response: 

EPA agrees with the commenter that EPA’s rationale for new sources makes use of its analyses 

for existing sources. However, EPA disagrees with the commenter that there are many problems 

and a shortage of data for existing sources, making the data not reliable for new sources. 

Although EPA has made every effort to respond to specific comments on the steam electric 

effluent guidelines rulemaking, this comment notes that BAT analyses have “many problems and 

shortage of data” but no specific details were provided, making it too generalized; therefore, 

EPA cannot respond.

For information on the data used by EPA to characterize FGD wastewaters and its treatment, see 

response to DCN EPA-HQ-OW-2009-0819-4655-A2, Excerpt Number 20 in Comment code 8.c. 

Also, for information on the data used by EPA to characterize bottom ash, see response to DCN 

EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 50 in Comment Code 6.a and for 

information related to the data used by EPA to characterize gasification wastewaters and its 

treatment, see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 167 in 

Comment Code 23. Also, see preamble section VIII.

Commenter Name: Becky Hayat

Commenter Affiliation: Natural Resources Defense Council (NRDC)

Document Control Number: EPA-HQ-OW-2009-0819-4490-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Water is a major input in the generation of power at steam electric generating facilities. Besides 

cooling, large amounts of water are used by many steam electric power plants for handling solid 

waste, such as bottom ash and fly ash, and for operating wet flue gas desulfurization (FGD) 

scrubber systems. The demand for water by power plants can present a major challenge for water 

managers in regions with limited surface water resources, especially during times of drought. In 

the analysis supporting this proposed rule, EPA estimated the reductions in water use associated 

with each of the regulatory options. At the most stringent levels (Options 4 and 5), EPA 

calculated that power plants would reduce water use by 153 billion gallons per year, or about 419 

million gallons per day (MGD).1 Although power plant withdrawals of cooling water are 

substantially greater than this amount, the amount of process water that can be saved by these 

effluent guidelines is nearly as much water as is supplied to residential customers by all the water 

utilities in North Carolina2, and thus a significant amount of water to save with any single 

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

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Under Options 4 and 5, the recommended technology basis for discharge limits on water used for 

transporting fly ash is dry handling. With respect to bottom ash, the recommended technology 

basis under Options 4 and 5 is dry handling or a closed loop system.3 Dry handling of ash will 

significantly reduce or eliminate water use associated with current wet transport systems. The 

technology basis for FGD wastewater under Option 5 (chemical precipitation and vapor 

compression evaporation) will significantly reduce water use because the condensed vapor can 

be recycled back into the FGD process or used in other plant operations (explained further 

below).4In contrast, the technology treatment for handling FGD wastewater under Option 4 

would not be expected to reduce the amount of water used unless plants recycle FGD wastewater 

as part of their treatment system; however, as discussed further below, few plants are likely to 

recycle treated FGD wastewater, thus the potential for water savings under Option 4 is somewhat 

lower than the potential savings under Option 5.

Under Options 4 and 5, EPA would establish a zero discharge effluent limitation requirement for 

discharges of pollutants in fly ash transport water, based on the use of dry fly ash handling 

technologies.5 As a result, in order to comply with either option, plants that currently use wet 

transport systems to handle fly ash are likely to convert to dry handling methods, since the 

regulatory measure will prohibit all discharges of pollutants in fly ash transport water. Hence, 

significant reductions in water use will result when plants are no longer sending fly ash to 

surface impoundments.

.....

If plants were to comply with the zero discharge requirement pursuant to Options 4 and 5, they 

would most likely convert to dry handling methods, which may be entirely dry and avoid all use 

of water, or in some cases may include a water bath at the bottom of a boiler in which the bottom 

ash is dropped and cooled, from which the bottom ash is then mechanically dragged out of the 

boiler along a conveyor belt and deposited in a pile adjacent to the building housing the boiler.12 

Regardless of which method a plant employs, significant amounts of water will be saved as a 

result of the plants having to comply with the zero discharge standard under Options 4 and 5.

1 U.S. EPA, Technical Development Document for the Proposed Effluent Limitations Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category, 12-13 – 12-14 

(April 2013) (“TDD”).

2 Kenny, J.F., Barber, N.L., Hutson, S.S., Linsey, K.S., Lovelace, J.K., and Maupin, M.A., 2009, 

Estimated use of water in the United States in 2005: U.S. Geological Survey Circular 134, 

available at http://pubs.er.usgs.gov/publication/cir1344.

3 U.S. EPA, Proposed Rule, Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category, 78 Fed. Reg. 34,432, 34,461-34,462 (June 7, 2013) 

(“ELGs”).
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4 U.S. EPA, Incremental Costs and Pollutants Removals for the Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category, 6-

106 (April 2013) (“Incremental Costs and Pollutants Removals”).

5 ELGs at 34,461.

12 This residual water that collects in the storage area as the bottom ash continues to dewater is 

typically completely recycled back to the quench water bath. Moreover, EPA does not consider 

this wastewater to be transport water because the transport mechanism is the drag chain, not the 

water. See TDD, pg. 4-21.

Comment Response: 

EPA acknowledges reductions in water withdrawals resulting from the technology options that 

form the basis for the final rule. See preamble section XII and Section 12.4 of the TDD for 

EPA’s estimates for the final rule, which includes zero pollutant discharge requirements based on 

dry handling or closed-loop system for fly and bottom ash transport water.

EPA does not agree with the commenter that limits reflecting chemical precipitation plus 

evaporation versus limits reflecting chemical precipitation plus biological treatment will 

necessarily lead to reduced water withdrawals. 

EPA did not finalize a zero discharge of pollutant limitation for FGD wastewater. See response 

to DCN EPA-HQ-OW-2009-0819-4686-A1, Except Number 23 in Comment Code 6.i.iii.

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: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Exceptions provided for pH within the PSES and PSNS sections do not make sense for 

pretreatment because pH is not required to be monitored. These exceptions should either be 

clarified or removed to avoid any possible confusion. See 40 C.F.R. § 423.16(e)(2) with 

reference to 40 C.F.R. 423.16 § (e)(1); 40 C.F.R. § 423.16 (i)(2) with reference to 40 C.F.R. 

423.16 § (i)(1); 40 C.F.R. § 423.17(b)(6)(ii) with reference to 40 C.F.R. § 423.17(b)(6)(i); and 40 

C.F.R. § 423.17(b)(9)(ii) with reference to 40 C.F.R. § 423.17(b)(9)(i).

Comment Response: 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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The final rule does not require internal monitoring to demonstrate compliance with certain 

numeric limitations and standards. See preamble section VIII and response to DCN EPA-HQOW-2009-0819-4305-A3, Excerpt Number 117 in Comment Code 26.d. Because of this change, 

the proposed regulatory language referenced by the commenter, and its associated exceptions 

provided for pH, are not incorporated into the final rule.

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Although generally supportive of EPA's proposed ELG rule, IBB notes that EPA has proposed 

eight regulatory options that represent a range of treatment levels and associated costs. Some 

options will require significant infrastructure upgrades and installation of wastewater treatment 

systems, often at a considerable expense. For example, EPA has proposed zero discharge limits 

for fly ash, bottom ash, and FGMC. By contrast, other EPA regulatory options appear to 

optimize technology treatment capabilities and cost impacts, while greatly increasing 

environmental performance at the fleet of affected electric generating facilities.

This wide range of treatment levels and associate costs means that EPA must strike the correct 

regulatory balance in setting final ELGs for the seven wastewater streams at affected facilities. 

Some of the regulatory options proposed by EPA are significantly more appropriate and 

reasonable than others for a diverse national fleet of electric generating units with different 

designs and plant configurations . To maximize cost-effectiveness of the proposal, EPA should 

therefore focus the new ELG requirements on waste streams that are new or significantly 

changed and thus may not be well controlled by the current ELG standards. Notable examples 

where further controls may be appropriate include the treatment levels that would require:

 dry handling of fly ash;

 chemical precipitation for removing the solid particles, including mercury and other air 

toxic pollutants in the soluble form;

 surface impoundments for controlling the total suspended solids and other conventional 

pollutants in the bottom ash transport water; and

 surface impoundments for limiting the discharge of conventional pollutants from 

combustion residual leachate.

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

EPA’s Response to Public Comments

4-21

IBB urges EPA to carefully examine the benefits and costs of each control and adopt a balanced 

final regulatory program that allows for the continued delivery of low cost-electricity while 

protecting the environment.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that dry handling for control of fly ash transport water discharges and dry 

handling or closed-loop systems for control of bottom ash transport water discharges represent 

Best Available Technology Economically Achievable (except for discharges from “small” or oilfired generating units). For controlling discharges of combustion residual leachate, EPA 

determined that surface impoundments represent BAT. For controlling discharges of FGD 

wastewater (excerpt for discharges from “small” or oil-fired generating units), EPA determined 

that chemical precipitation and biological treatment represent BAT. These technologies are 

available and economically achievable (i.e., affordable) for the industry as a whole, and have 

acceptable non-water quality environmental impacts as required by the Clean Water Act (see 

preamble Section VIII).

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. However, EPA disagrees with 

the commenter’s suggestion to use cost-effectiveness as the sole basis for regulatory decisions.

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 dry handling of fly ash is an appropriate technology basis for fly ash transport 

water for units that are greater than 50 MW and that are not oil-fired. See preamble section VIII.

See response to DCN EPA-HQ-OW-2009-0819-4633-A1, Excerpt Number 32 in Comment 

Code 9 regarding EPA’s selected regulatory options for FGD wastewater.

See response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 in Comment Code 

6.e regarding EPA’s selected regulatory options bottom ash transport water.

See response to DCN EPA-HQ-OW-2009-0819-5406-A2, Excerpt Number 15 in Comment 

Code 18 regarding EPA’s selected regulatory operations for combustion residual leachate.
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EPA’s Response to Public Comments

4-22

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: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The UWAG analysis also demonstrates that such costs would be disproportionally borne by 

smaller units. (See Figures 2 and 3 below and UWAG comments section IV. EPA’s CostEffectiveness Analyses) and for specific waste streams (See especially UWAG comments 

section V. BAT for Bottom Ash Transport Water, section VI BAT for Flue Gas Desulfurization 

Wastewater, and section IX BAT for Fly Ash Transport Water.)

Figure 2: TWPE and $/TWPE Using UWAG Bottom Ash Transport Water Data4(Less the

Source Water Contribution)

*The highest TWPE removed is aluminum at 75% of the total TWPEs.

Figure 3: TWPE and $/TWPE Using Cardinal Fly Ash Transport Water Data5(Including 

Source Water Contribution6)
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

4-23

4 UWAG comments section V.J. UWAG’s Cost-Effectiveness Analysis for Bottom Ash)

5 UWAG comments section IX.F. UWAG’s Cost-Effectiveness Analysis for Fly Ash)

6 Fly ash transport water TWPEs should be adjusted to account for source water pollutants. 

Unfortunately, EPA did not collect source water samples, so source water contribution cannot be 

removed.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 96 in Comment 

Code 5.c and other responses to comments in Comment Code 5.c regarding regulatory relief for 

small units. See responses to Comment Code 6.h regarding cost-effectiveness.

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: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

LPPC has strong interest in EPA’s proposed regulatory approach in the ELG rule. The proposed 

rule would apply to wastewater discharges from steam generating electric facilities through 

incorporation into National Pollution Discharge Elimination Systems (NPDES) permits issued by

EPA or authorized states.2 The proposal considered a number of regulatory options for each of 

seven waste streams that may occur at steam EGUs: flue gas desulfurization (FGD) wastewater, 

fly ash transport water, bottom ash transport water, combustion residual leachate, flue gas 

mercury control (FGMC) wastewater, gasification wastewater, and nonchemical metal cleaning 

wastes. EPA’s proposed options include zero discharge limits for fly ash transport water, bottom 

ash transport water, and FGMC. It is likely that EGUs will be subject to several different 

standards based on which waste streams they possess, leading to significant increases in costs.

For existing units, EPA has proposed four preferred options (3a, 3b, 3, 4a), of which one (4a) is a 

“lead option” for which regulatory text is proposed. Presenting a range of options is helpful for 

examining the regulatory alternatives for the waste streams in question. However, some of the 

regulatory options proposed by EPA are more appropriate and reasonable for new units – where 

effluent controls can be part of original design and construction. For existing units, some waste 

streams may warrant consideration of additional control, while others remain well‐controlled 

with current practices and should not be subject to additional regulation. For existing units, EPA 

should focus the ELG revisions solely on waste streams that are new or significantly changed 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

4-24

and thus may not be well controlled by the current ELG standards. If EPA chooses to regulate 

waste streams that currently have adequate controls, EPA should consider the operational and 

cost considerations, and the recommendations provided below.

2 78 Fed. Reg. 34,432, 34,522 (June 7, 2013).

Comment Response: 

EPA carefully considered costs and operational considerations as demonstrated by the TDD and 

the supporting information for the rule. See preamble section VIII and response to DCN EPAHQ-OW-2009-0819-4557-A1, Excerpt Number 2.

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: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Some facilities have unique configurations, including an existing combined wastewater treatment 

system, that preclude upstream monitoring and may affect compliance achievement. Because of 

the significant expense of requiring these facilities to completely reconfigure their existing 

operations, the final rule should provide facilities with existing combined wastewater treatment 

with an alternative option for setting its effluent discharge limits.

Under this approach, a qualifying facility would have the option, at its election, to undertake a 

BPJ process with their state regulator to set the plant‐specific effluent limitations based on a 

number of factors, including the ELGs otherwise applicable to the facility and the unique 

operational and technical limits that preclude the facility to comply with the ELGs through the 

existing combined wastewater treatment system. The BPJ process would incorporate cost and 

cost‐effectiveness considerations to fashion a reasonable solution for plants with fundamentally 

different processes. It is our understanding that the number of facilities with this concern is quite 

small, and a BPJ option will provide an adequate process for addressing both monitoring and 

compliance concerns on a case‐by‐case basis, without imposing a significant additional burden 

on the permitting authority.

Sources with unique design considerations that affect compliance should be given an alternative 

BPJ process that would assist in finding the most reasonable compliance option.

Comment Response: 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

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The final rule does not require internal monitoring to demonstrate compliance with certain 

numeric limitations and standards. See preamble section VIII and response to DCN EPA-HQOW-2009-0819-4305-A3, Excerpt Number 117 in Comment Code 26.d.

EPA generally does not rely on BPJ permitting where it has sufficient data to set uniform, 

nationally applicable limitations at plants across the nation. Assuming sufficient data to develop 

appropriate numeric limitations, EPA would generally prefer numeric limitations because BPJ 

permitting places a burden on permitting authorities, many of whom are states, to conduct a 

complex technical analysis that they may not have the resources or expertise to complete. Some 

states commented to this effect in this rulemaking.

BPJ permitting may also unnecessarily burden the regulated industry because of associated 

delays and uncertainty with respect to permits. See the response to DCN EPA-HQ-OW-2009-

0819-4383-A1, Excerpt Number 6 in Comment Code 6.j.i for more discussion on the use of BPJ.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 40

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I. New Option 6 Recommendation for Steam Electric ELGs

Based on the preceding comments and the currently EPA proposed alternatives, TVA is 

proposing that EPA consider another option and has designated it as Option 6 to minimize 

confusion. The proposed conditions are shown in Table II below:
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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Comment Response: 

See preamble Section VIIII for EPA’s option selection rationale and its basis for rejecting other 

regulatory options.

See preamble section XI and Section 13 of the TDD, and response to DCN EPA-HQ-OW-2009-

0819-4607-A1, Excerpt Number 12 in Comment Code 31.h for use of the 95th percentile upper 

confidence limit for developing limitations for FGD wastewater.

Regarding site-specific exemptions, see response to DCN EPA-HQ-OW-2009-0819-4460-A1, 

Excerpt Number 27 in Comment Code 8.

EPA agrees that dry handling of fly ash is an appropriate technology basis for fly ash transport 

water for units that are greater than 50 MW and that are not oil-fired. See preamble section VIII 

for more information.

Regarding bottom ash transport water, see response to DCN EPA-HQ-OW-2009-0819-4464-A1, 

Excerpt Number 3 in Comment Code 6.e.

Regarding flue gas mercury control waste, see response to DCN EPA-HQ-OW-2009-0819-4305-

A3, Excerpt Number 88 in Comment Code 21.a.

Regarding leachate, the final rule establishes a BAT limitation equal to previously established 

BPT limitation on TSS in low volume waste sources. See preamble Section VIII.

In addition, see responses to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 154 in 

Comment Code 22 for EPA’s rational regarding non-chemical metal cleaning waste and to DCN 

EPA-HQ-OW-2009-0819-5406-A2, Excerpt Number 15 in Comment Code 18 regarding 

combustion residual leachate.

Also, see response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt Number 92 in Comment 

Code 5.a for details about the applicability of the final rule to steam electric power plant retired 

units. For a summary and rationale of the final rule, see preamble section VIII.

Commenter Name: Pamela Ritger

Commenter Affiliation: Clean Wisconsin

Document Control Number: EPA-HQ-OW-2009-0819-4632-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Impacts of Steam Electric Power Generation Pollution on Human and Wildlife Health
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

EPA’s Response to Public Comments

4-27

In its detailed study of the steam electric power generating industry, conducted in 2005, the EPA 

found that the use of wet systems for flue gas desulfurization (FGD), and to transport fly ash and 

bottom ash all created significant levels of metals, including arsenic, selenium and mercury, as 

well as other pollutants.11 As coal-fired power plants are typically the largest source of each of 

the following toxic pollutants, strong federal standards on steam electric power plants could 

drastically reduce the amount of pollutants that are spewed into our nation’s waters and continue 

to accumulate year after year.12

11 III. Background, D. Steam Electric Detailed Study. Accessed August 21, 2013. Available at 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OW-2009-0819-0068.

12 Environmental Integrity Project et al., Closing the Floodgates: How the Coal Industry Is 

Poisoning Our Water and How We Can Stop It, p. 4 (July 2013). Available 

at http://www.environmentalintegrity.org/news_reports/documents/2013_07_23_ClosingTheFlo

odgates-Final.pdf

 

Comment Response: 

EPA notes it updated its estimates of pollutant discharge loadings from steam electric power 

plants to surface waters. See preamble Section III and the TDD.

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: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

It is not appropriate for EPA to deem a technology the best available technology (“BAT”) if the 

technology has not been proven successful at pollution removal or has not been in place for a 

sufficient length of time to determine whether it is effective or not. See, e.g., BP Exploration & 

Oil v. EPA, 66 F.3d 784, 802 (6th Cir. 1996). Moreover, if EPA evaluates data and technology 

from only one facility, EPA must demonstrate the effectiveness and applicability of the 

technology to the entire industry. See Ass’n of Pacific Fisheries v. EPA, 615 F.2d 794, 816– 19 

(9th Cir. 1980); BP Exploration & Oil, Inc., 66 F.3d at 802 (rejecting reinjection of drilling 

wastes as BAT in Alaska because even though an offshore oil platform used reinjection, “the 

technology is still experimental and is not yet available for application”). In essence, EPA must 

determine a technology is available to the industry as a whole. Ass’n of Pacific Fisheries, 615 

F.2d at 816-19. Once it has identified available technologies, EPA considers a number of factors 

to determine BAT, including: the age of equipment and facilities involved; the process 
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employed; the engineering aspects of the application of various types of control techniques; 

process changes; the cost of achieving such effluent reduction; and non-water quality 

environmental impacts (including energy requirements). 40 C.F.R. § 125.3(d)(3) (i) – (vi). 

Additionally, EPA takes into account: (1) “the appropriate technology for the category or class of 

point sources of which the applicant is a member, based upon all available information; and (2) 

[a]ny unique factors relating to the applicant.” 40 C.F.R. §§ 125.3(c)(2)(i)–(ii); 125.3(d)(3); 33 

U.S.C. § 1311(b)(2)(A).

EPA must consider each of the factors in 40 C.F.R. § 125.3(d)(3), and a failure to consider one 

factor deems EPA’s effluent limits arbitrary and capricious. See, e.g., Texas Oil & Gas Ass’n v. 

EPA, 161 F.3d 923, 934–35 (5th Cir. 1998) (noting that a failure to consider the age of the 

equipment and the facilities involved when determining BAT would constitute an abuse of 

discretion); Am. Iron & Steel Inst. v. EPA, 526 F.2d 1027, 1048 (3d Cir. 1975) (remanding 

effluent limits because EPA did not consider the age of the facilities involved and the impact that 

age would have on the cost and feasibility of retrofitting older facilities). Not one factor is 

determinative; instead, EPA must balance all of the factors in determining BAT. Moreover, it 

would be incorrect to assert that BAT must be based on the “best single performer” in the 

industry. “To the contrary, the [Clean Water Act’s (“CWA”)] requirement that EPA choose the 

‘best’ technology does not mean that the chosen technology must be the best pollutant removal. 

Obviously, BAT . . . must be acceptable on the basis of numerous factors, only one of which is 

pollution control.” BP Exploration & Oil, 66 F.3d at 796.

EPA’s analysis of the BAT factors and its determination that all BAT limits are economically 

and technologically achievable must be reasonable. Id. at 794. Further, EPA bears the burden of 

demonstrating a reasonable basis for its conclusion that the regulations are achievable, and a 

failure to do so renders the regulations arbitrary, capricious, and “not the result of reasoned 

decisionmaking.” Ass’n of Pac. Fisheries, 615 F.2d at 820; Chem. Mfr’s Ass’n v. EPA, 885 F.2d 

253, 265 (5th Cir. 1989). When EPA sets effluent guidelines based on BAT, the effluent limits 

“cannot stand” if they are “based on a flawed, inaccurate, or misapplied study.” Texas Oil & Gas 

Ass’n, 161 F.3d at 935. Likewise, if EPA fails to demonstrate the effectiveness of the chosen 

BAT, the effluent limitations must be remanded back to EPA for further consideration. Ass’n of 

Pac. Fisheries, 615 F.2d at 819; Chem. Mfr’s Ass’n, 885 F.2d at 265.

One BAT factor is the consideration of cost to implement and maintain the proposed technology, 

or attain the proposed effluent limits. Indeed, the CWA specifically recognizes that the BAT 

must be economically achievable, 33 U.S.C. § 1311(b)(2)(A)(i), and requires the “cost of 

achieving such effluent reduction,” 40 C.F.R. § 125.3(d)(3), be similarly evaluated. See Texas 

Oil & Gas Ass’n 161 F.3d at 934 (noting that cost refers to a consideration of the cost of the 

technology itself). Therefore, the cost determination is two-fold: cost must be considered in the 

six-factor BAT analysis, and the effluent limits must be economically achievable. See Ass’n of 

Pacific Fisheries, 615 F.2d at 819-20 (finding that EPA’s failure to adequately consider the cost 

of land acquisition in the determination of whether a technology is an achievable technology is 

an example of unreasonable decision-making). EPA must consider the costs of the technology 

and the benefits received from the technology because of the duty to consider all of the factors in 

the BAT analysis.
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Additionally, the final BAT limits that are established must be economically achievable for the 

source. Texas Oil & Gas Ass’n, 161 F.3d at 934. EPA cannot rely solely on the fact that a 

facility or the public can “afford” a treatment technology as a basis for determining whether it is 

cost-effective. It makes sense that cost is such an important factor in the BAT analysis given the 

very name of this standard: the best available technology economically achievable. Thus, EPA is 

permitted to “balance factors such as cost against effluent reduction benefits.” BP Exploration & 

Oil, 66 F.3d at 796. Indeed, courts have upheld EPA’s decision to reject a technology based on 

high economic impacts that might otherwise have been the most effective pollution control 

technology. See e.g. id. (rejecting a technology as BAT, in part, because of the cost of the 

technology).

Comment Response: 

EPA’s selection of BAT for the final rule was conducted in accordance with these requirements 

and factors. See preamble section VIII for a summary and rationale of the final rule. After a 

careful review of all of the information in the rulemaking record, EPA found that the technology 

bases for the final rule are technologically available, economically achievable and have 

acceptable non-water quality environmental impacts.

While EPA agrees ELGs must be affordable to the industry as a whole, 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. Also, see the RIA for details on how 

EPA determined that the final rule is affordable.

For the role of cost-benefit in EPA’s decisions for the final rule, see response to DCN- EPA-HQOW-2009-0819-4464-A1, Excerpt Number 3 in Comment Code 6.e.

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: 44

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

PSNH would be remiss if it did not at least point out the disparity between the metal effluent 

limitations advanced in the Proposed Rule and those imposed upon other point source categories 

developed or revised within the recent past. See, e.g., 40 C.F.R. Part 444 (2000) (Waste 

Combustors Point Source); 40 C.F.R. Part 445 (2000) (Landfills Point Source Category). EPA 

has provided no reasoning as to why such overly stringent effluent limitations have been offered 

in the Proposed Rule when it promulgated the aforementioned reasonable, and less controversial, 

limitations for the same pollutants not long ago. Has technology for the treatment of these related 

waste waters improved that much in the past decade? Perhaps, instead, EPA is attempting to 
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utilize its assertions that the steam electric power generating point source category purportedly 

accounts for over half of all pollutants discharged to surface waters as a mandate to attempt to 

impose more onerous standards on the industry. In truth, treatment technology has not advanced 

much since the aforementioned effluent standards were promulgated for these other point source 

dischargers and the more appropriate limitations set out in those regulatory standards only 

further highlight the faults and erroneous conclusions upon which the agency has based the 

proposed effluent limits set out in the Proposed Rule.

Comment Response: 

EPA developed the final rule in accordance with the statutory factors required by the CWA. The 

technology bases for the final rule are available, affordable to the steam electric power industry 

as a whole, and have acceptable non-water quality environmental impacts. The commenter 

correctly notes that it is quite common for EPA to establish different ELGs for the same pollutant 

depending on the industrial category. EPA derives effluent limitations for different industries 

based on the performance data for the technologies specified as the technology bases for the 

rule. The statistical methodology that EPA used in this rule is consistent with the methodology it 

has used in many effluent guidelines since the late 1980s and upheld in CMA v. EPA, 870 F.2d 

177 (5th Cir. 1989), National Wildlife Federation v. EPA, 286 F.3d 554 (D.C. Cir. 2002), and

Am. Coke & Coal Chemicals Inst. v. EPA, 452 F.3d 930 (D.C. Cir. 2006). See the TDD and 

preamble to the final rule.

EPA notes that, based on public comments, it revised the final effluent limitations. See preamble 

and the TDD.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 186

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For New Source Performance Standards, EPA proposes Option 4 in Table VIII-1. See 78 Fed.

Reg. at 34,458. The limits applying to this option are as follows:

Wastestream Pollutant Proposed Limits

FGD Wastewater

Arsenic, total 8 6

Mercury, total 242 119

Selenium, total 16 10

Nitrate/nitrite as N 0.17 0.13

Fly ash transport water No discharge
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Wastestream Pollutant Proposed Limits

Bottom ash transport water No discharge

FGMC wastewater No discharge

Gasification wastewater

Arsenic, total 4 

Mercury, total 1.76 1.29

Selenium, total 453 227

TDS 38 22

Combustion residual leachate Arsenic, total 8 6

Mercury, total 242 119

Nonchemical metal cleaning 

wastes

TSS 100.0 30.0

Oil and grease 20.0 15.0

Copper, total 1.0 1.0

Iron, total 1.0 1.0

See 78 Fed. Reg. at 34,536, 34,540. Thus EPA proposes biological treatment for FGD 

wastewater, dry handling for fly ash and bottom ash transport water and FGMC wastewater, and 

chemical precipitation for arsenic and mercury in combustion residual leachate.

EPA explains its rationale for this choice at 78 Fed. Reg. at 34,475 col. 2-3. EPA says five 

plants operate fixed-film anoxic/anaerobic biological treatment systems for FGD wastewater and 

one a suspended growth biological system for selenium. EPA says 83% of coal-fired plants built 

within the last 20 years do not discharge bottom ash transport waters. For leachate, EPA says 

chemical precipitation is a well-demonstrated technology. 78 Fed. Reg. at 34,476 col. 1. The 

cost of these technologies, EPA says, poses no barrier to entry, citing the case of installing the 

equipment and EPA’s Integrated Planning Model analyses. EPA also says that, since non-water 

quality impacts for Option 4, in its analysis, are acceptable for existing sources, they should also 

be acceptable for new sources.

EPA’s rationale for new sources, in short, depends heavily on its analyses for existing sources 

(BAT). Because of the many problems and shortage of data for those BAT analyses, UWAG 

does not think they are reliable for BAT and thus are not reliable for NSPS either.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt Number 86.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 225
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

XXXVIII. EPA’s Description of the Electric Utility Industry Should Be More Objective

In the preamble to the proposed rule, EPA emphasizes the environmental harm supposedly done 

by electric power plants, particularly those burning coal. Thus EPA starts by reporting “there are 

numerous documented instances of environmental impact associated with these power plant 

discharges, such as harm to human health, harm to aquatic life, contamination of sediment, and 

detrimental impacts to wildlife.” 78 Fed. Reg. at 34,435 col. 2; see also, id. 34,439-40, 

34,504. Similarly, EPA says discharges from steam electric power plants contribute 50 to 60% 

of the reported toxic-weighted pollutant loadings of the combined discharges of all industrial 

categories. 78 Fed. Reg. at 34,505 col. 2. EPA’s contractor, ERG, provides a short explanation 

of how it compared steam electric loadings to those of other industries in a memorandum on the 

record. EPA-HQ-OW-2009-0819-2232. See also page 3 of Attachment 28 (“more than half of 

all toxic pollutants ... linked to cancer, neurological damage, and ecological damages...”).

Not surprisingly, advocacy groups have picked up this theme and emphasized the amount of 

pollution allegedly created by the coal industry. See Waterkeeper Alliance et al., Closing the 

Floodgates: How the Coal Industry is Poisoning Our Water and How We Can Stop It

(2013).89 Early comments by environmental groups have taken advantage of EPA’s 

description. See Comments of Environment Council of Rhode Island, EPA-HQ-OW-2009-0819-

4034 (Sept. 11, 2013) at 1.

As explained earlier in these comments, however, UWAG’s analyses show that EPA has vastly 

overstated the amount of pollutants being discharged. As we have shown based on additional 

sampling and analysis (see Attachment 5 to these comments), sulfides are generally not present 

in ash pond discharges, so the huge amount of sulfide TWPEs that EPA figures into industry 

loadings should be removed.

Also, the loadings attributable to use of the old, unreliable 1970s data from the 1982 

Development Document should be removed and replaced with better quality data that actually 

reflects wastewater discharges at today’s plants. Based on our suggested corrections and use of 

better data, we calculated a revised total baseline loading of 1.97 million TWPEs. Substituting 

that value into EPA’s formulas90 for calculating the industry percentage produces the following:

Total TWPEs (all industries): 

1.97 million lb-eq/yr (steam electric) + 5.3 million lb-eq/yr (non steam electric)=7.27 million lb 

eq/yr total TWPEs. 

Steam electric percentage of total: 

1.97 million lb eq/yr (steam electric) ÷ 7.27 million lb eq/yr (total, all industries) = 27%
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UWAG has not been able to assess all the data underlying EPA’s industry loadings 

calculations. We suspect that EPA has used erroneous flow rates for ash pond discharges in 

many cases, but the relatively short comment period (particularly as to the loadings data which 

became available to UWAG only about a week before the comments were due) has not allowed 

us to develop full evidence of that discrepancy. Therefore, while use of UWAG’s present 

loadings numbers indicate that the steam electric industry produces no more than 27% of total 

TWPEs, it is very likely that the percentage is much lower than that.

There are additional factors which also affect the loadings calculations and assessment of their 

impact. Those factors include the following.

 When a pollutant is not detected, EPA assumes it is present at the highest possible level, 

given the detection limit.

 EPA assumes that exceeding a water quality criterion means that fish in the waterbody 

are harmed.

 EPA mischaracterizes scientific literature as proving harm to the environment when there 

was no evidence of damage.

 EPA relies heavily on old data, including data from before Clean Water Act requirements 

took effect.

 EPA used a faulty means of calculating pollutant loadings, making its estimate of 

loadings from ash ponds six times too high.

Details about these biases are found in the attachments to these comments by AKRF (Attachment 

1) and Gradient (Attachment 2).

In light of these shortcomings, EPA would do well, with the final rule, to describe the industry 

more objectively and avoid alarming descriptions of pollutant loadings. Since it appears EPA 

has overstated the percentage of TWPEs attributable to the steam electric industry by at least a 

factor of two, UWAG requests that EPA make every effort to correct the record on this point.

89 http://earthjustice.org/documents/report/pdf/closing-the-floodgates.

90 The formulas are presented in ERG’s memo of April 19, 2013 titled “Comparison of Steam 

Electric Industry Toxic Loadings to Other Industrial Dischargers.” EPA-HQ-OW-2009-0819-

2232. 

Comment Response: 

EPA notes that, in response to comments, it updated its estimates of pollutant loadings for the 

final rule. See preamble section III and the TDD.

See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 149 in Comment 

Code 6.h. In addition, regarding other specific comments raised in the commenter’s letter, such 

as issues raised in the attachments by AKRF (DCN EPA-HQ-OW-2009-0819-4655-A1) and 
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Gradient (DCN EPA-HQ-OW-2009-4655-A2)), see responses to comments in Comment Codes 

6.f, 25.b and 29.b in this comment response document.

Also, see response in DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment 

Code 15.d.

Commenter Name: Katherine Rubin

Commenter Affiliation: Los Angeles Department of Water and Power (LADWP)

Document Control Number: EPA-HQ-OW-2009-0819-4658-A2

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

From the proposed Rule, it appears that the USEPA prefers four out of eight options for handling 

wastewater of various types at generating stations that are primarily fueled by coal (although 

other types of generating stations are covered, such as natural gas fired). LADWP agrees with 

UWAG and LPPC's comments in that there may be different options appropriate for different 

situations, even those options not identified as "preferred." This is because existing generating 

stations have unique flow paths and other plant design considerations with process-related, 

feasibility, or economic issues.

Comment Response: 

The final rule establishes national effluent limitations guidelines and standards based on best 

available technologies economically achievable. EPA notes this commenter did not provide 

specific information on any unique flow paths or plant specific considerations that would 

demonstrate the selected technology bases are not available to them. Additionally, facilities are 

not required to use the selected technology bases. Rather, they are required to meet the 

limitations and standards. Facilities have the flexibility to determine their approach to comply 

with the final rule limitations and standards.

Commenter Name: Bradley Coyle

Commenter Affiliation: Big Rivers Electric Corporation (BREC)

Document Control Number: EPA-HQ-OW-2009-0819-4664-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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We urge EPA to conduct additional evaluation of the proposed rules and to collect additional 

data that is more reflective of the steam electric power generation industry in order to develop 

final ELGs. We believe that the proposed ELGs lack sound science and present operational 

impracticalities that many not be met by many utilities and thus cause a significant increase in 

the expenditures incurred by an utility – and thus resulting in additional and unnecessary costs 

being passed on to the end users.

Comment Response: 

For the final rule, EPA incorporated the use of additional data in its effluent limitations 

guidelines and standards development, pollutants of concern identification, and pollutant 

loadings estimates. EPA subjected the new data to its data quality acceptance criteria and, as 

appropriate, updated its analyses accordingly. See Section 3 of the TDD for additional 

information on the data sources used in the development of the final rule.

EPA disagrees that the ELGs lack sound science and present operational impracticalities and 

result in unnecessary additional costs. See preamble section VIII of the preamble for a summary 

and rationale of EPA’s final rule.

See response to DCN EPA-HQ-OW-2009-0819-4466-A1, Excerpt Number 9 in Comment Code 

27 regarding EPA’s evaluation of the cumulative effect of regulations on the electric power 

sector.

See responses to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 14 and DCN EPAHQ-OW-2009-0819-4348-A2, Excerpt Number 3 regarding legacy wastewaters, both in 

Comment Code 26.c.

For further information regarding coordination efforts between the CCR final rule and the ELGs, 

and their implementation timing, see responses in Comment Code 27.e.

See the response to DCN EPA-HQ-OW-2009-0819-4664-A2, Excerpt Number 4 in Comment 

Code 6.c for EPA’s response related to the selenium and mercury discharge standards.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 3

External Review Flag: Legal

External Review Incorporated into Response: No

Comment Excerpt: 

Although Options 4 and 5 would eliminate most toxic water pollution from coal plants, the 

proposed rule does not designate them as “preferred” options. Instead, the EPA’s proposal 
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includes so-called “preferred” options that would do next to nothing to curb dangerous pollution 

from FGD wastewater discharges and would leave other major waste streams unregulated–

including large amounts of toxic bottom ash waste.

It appears that the expressed preference for these weak options does not actually reflect the views 

of EPA. The White House’s Office of Management and Budget (“OMB”) took the highly 

unusual and improper step of writing new weak options into the draft rule prepared by the EPA’s 

expert staff during the inter-agency review process established by executive order.9 A redline of 

the rule, showing the original EPA version and OMB’s version reveals the changes: 

OMB refused to let EPA choose more protective options as “preferred” regulatory paths and 

inserted weaker options instead.10 The result is that EPA’s original two preferred options —

Options 3 and 4 —were replaced with four preferred options: Options 3a, 3b, 3, and 4a, three of 

which were created by OMB. OMB’s elimination of Option 4 as a preferred option represented a 

position directly contrary to the views of EPA staff.11 All of the preferred options that OMB 

inserted into the proposed rule are weaker than Option 4, meaning that OMB’s intervention 

shifted the proposal away from the stringent controls that EPA has repeatedly recognized to be 

available and critical to achieving the Clean Water Act’s goal of eliminating discharges.12 If 

EPA finalizes any of these weaker options (or is forced to do so by OMB), it will fail to control 

billions of pounds of pollution, possibly for decades to come. It will also fail to exercise the 

duty—delegated to EPA alone by Congress—to develop standards based on its own expertise 

and judgment.

9 EPA, Documentation of OMB Review Under Executive Order 12866 (June 2013), Docket No. 

EPA-HQ-LW-2009-0209 2237.

10 See generally id.

11 See id. at 137, 144, 213-214, 226-227; see also Environmental Integrity Project et al., Closing 

the Floodgates at 12-13.

12 78 Fed. Reg. at 34,458, 34,485-34,486.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that technologies in Regulatory Option D represent Best Available Technology 

Economically Achievable (except for discharges from “small” or oil-fired generating units) 

because they are available and economically achievable (i.e., affordable) for the industry as a 

whole, and have acceptable non-water quality environmental impacts as required by the Clean 

Water Act (see preamble Section VIII).
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Also, see responses to comments in Comment Codes 6.iii, 6.i.v and 6.i.viii.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 45

External Review Flag: Legal

External Review Incorporated into Response: No

Comment Excerpt: 

D. EPA MUST FINALIZE ELGS THAT REFLECT STATE-OF-THE-ART 

TECHNOLOGIES AND PROTECT PUBLIC HEALTH AND THE ENVIRONMENT BY 

MAY 22, 2014.

EPA signed the current proposal on April 19, 2013 as a condition of a consent decree to resolve 

litigation brought to compel the agency to undertake overdue revisions of the ELG s.120 EPA’s 

proposal to set critically needed standards contains multiple options, including strong standards 

that would require the elimination of the majority of coal plant water 

pollution using technologies that are available and affordable. The strongest of these options—

Option 5—would eliminate almost all toxic discharges, reducing pollution by more than 5 billion 

pounds a year. Option 4, the next strongest option, would eliminate new coal ash discharges and 

apply rigorous treatment requirements for FGD wastewater. By eliminating or significantly 

reducing toxic discharges from coal plants, a strong final rule would create hundreds of millions 

of dollars in benefits every year in the form of improved health and recreational opportunities for 

all Americans, in addition to the incalculable benefits of clean and healthy watersheds.121 EPA 

estimates that ending toxic dumping from coal plants would cost less than one percent of annual 

revenue for most coal plants and at most about two pennies a day in expenses for ordinary 

Americans, if the utilities passed some of the cleanup costs to consumers.122

Although Options 4 and 5 would eliminate most toxic water pollution from coal plants, the 

proposed rule does not designate them as “preferred” options. Instead, the EPA’s proposal 

includes so-called “preferred” options that would do next to nothing to curb dangerous pollution 

from FGD wastewater discharges and would leave other major waste streams unregulated–

including large amounts of toxic bottom ash waste.

EPA has recognized for years that the 1982 ELGs are not adequate to protect the public, 

especially because they fail to control toxic metals in FGD wastewater, among other wastewater 

streams .123 This recognition is directly at odds with the proposal of weak regulatory 

options, and it appears that the expressed preference for these options does not actually reflect 

the views of the agency. The White House’s Office of Management and Budget (“OMB”) took 

the highly unusual and improper step of writing new weak options into the draft rule prepared by 

the EPA’s expert staff during the inter-agency review process established by executive 

order.124 A redline of the rule, showing the original EPA version and OMB’s version reveals the 
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changes: OMB refused to let EPA choose more protective options as “preferred” regulatory 

paths going forward, and inserted weaker options instead.125 The result is that EPA’s original 

two preferred options — Options 3 and 4 —were replaced with four preferred options: Options 

3a, 3b, 3, and 4a, three of which were created by OMB. Through its revisions to the proposed 

rule, OMB eliminated Option 4 as a preferred option, taking positions directly contrary to those 

developed by EPA staff.126 All of the preferred options that OMB inserted into the proposed rule 

are weaker than Option 4, meaning that through OMB’s intervention the proposal has shifted 

away from the stringent controls that EPA has repeatedly recognized to be available and 

protective.127 If EPA finalizes any of these lesser options (or is forced to do so by OMB), it will 

fail to control billions of pounds of pollution, possibly for decades to come.

120 See Defenders of Wildlife v. EPA, No. 1:10-cv-01915-RWR (D.D.C. filed Nov. 8, 2010).

121 BCA at 12-2.

122 See 78 Fed. Reg. at 34,501, table XI-9 (noting that the average annual cost to ratepayers for 

the most stringent option is $6.46).

123 See, e.g., Memorandum from James Hanlon, EPA, Director of the Office of Wastewater 

Management to EPA Water Division Directors, Regions 1-10 & Attachment A: Technology 

Based Effluent Limits, Flue Gas Desulfurization (FGD) at Steam Electric Facilities (June 7, 

2010) (explaining that EPA is conducting a rulemaking to “address” this wastestream and that 

current controls are not adequate); 74 Fed. Reg. 55,837, 55,839 (Oct. 29, 2009).

124 U.S. Envtl. Prot. Agency, Documentation of OMB Review Under Executive Order 12866.

125 See generally EPA, Documentation of OMB Review Under Executive Order 12866 (June 

2013), Docket No. EPA-HQ-LW-2009-0209 2237.

126 See id. at 137, 144, 213-214, 226-227; see also Environmental Integrity Project et al., Closing 

the Floodgates, supra note 96, at 12-13.

127 78 Fed. Reg. at 34,458, 34,485-34,486.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 3.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 151
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The rulemaking record makes clear that compliance costs for Options 4 and 5 can be reasonably 

borne by the industry, notwithstanding EPA’s failure to select either option as preferred. EPA 

did not propose Option 4 as a preferred option “because of concerns expressed above associated 

with the projected compliance costs associated with zero discharge requirements for bottom ash 

for unit equal to or below 400 MW.”644 EPA rejected Option 5 on different grounds. EPA 

eliminated Option 5 from consideration at a very early stage of the rulemaking, based on 

screening-level analyses, and thus never conducted the full set of economic analyses for 

Option 5. “EPA did not select Option 5 as its preferred option for BAT because of the high total 

industry cost for the option ($2.3 billion/year annualized social cost) and because of preliminary 

indications that Option 5 may not be economically achievable.”645 Additionally, “certain 

screening-level economic impact analyses indicated that compliance costs may result in financial 

stress to some entities owning steam electric plants.”646

644 78 Fed. Reg. at 34,473. EPA rejected Option 4 for the additional reason that, in EPA's view, 

Option 4’s proposal to treat leachate with chemical precipitation is not warranted at this 

time. “Because of the relatively low level of pollutants in this way stream, and because EPA 

believes this is an area ripe for innovation and improved cost effectiveness, EPA is not putting 

forward this option as a preferred option.” Id.

645 Id.; see also id. at 34,477 (rejecting Option 5 as a preferred option for NSPS “because of its 

high costs, which are substantially higher than the costs for Option 4 and the other options 

evaluated for NSPS.”).

646 Id. at 34,473.

Comment Response: 

See the preamble to the final rule for an explanation of the reasons EPA selected the options 

contained in the final rule. See response to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt 

Number 15 and DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 46 in Comment 

Code 6.i.iv.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 22
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Dry handling of bottom ash transport water for units with capacities 400 MW or smaller, 

and chemical precipitation of combustion residual leachate

The selection of Option 4, as compared to Option 4a, would require plants with capacities equal 

to or less than 400 MW to implement zero‐discharge dry handling for bottom ash transport 

water. This one additional requirement impacts on conventional, toxic, and nonconventional 

pollutants (see Table 10). Option 4 also includes the addition (as compared to Option 4a) of 

chemical precipitation of combustion residual leachate. The greater stringency of Option 4, as 

compared to EPA’s preferred options, is demonstrated by its additional removal of pollutants 

over and above Option 4a. Option 4 removes 6,665 million lb‐eq whereas Option 4a removes 

only 5,092 million lb‐eq.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that technologies in Regulatory Option D represent Best Available Technology 

Economically Achievable (except for discharges from “small” or oil-fired generating units 

because they are available and economically achievable (i.e., affordable) for the industry as a 

whole, and have acceptable non-water quality environmental impacts as required by the Clean 

Water Act (see preamble Section VIII). For units that are greater than 50 MW and that are not 

oil-fired, BAT for bottom ash transport water is dry handling or closed loop systems.

EPA did not select chemical precipitation as BAT for combustion residual leachate for the 

reasons specified in preamble section VIII.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 24

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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The environmental controls eliminated with the exclusion of Options 4 and 5 are all 

technologically achievable.

Dry handling of bottom ash transport water for units with capacities 400 MW or smaller

The Federal Register directly states that dry handling of bottom ash transport water is 

technologically achievable for plants of any size:

[A]ll plants, regardless of size, are capable of installing and operating dry handling or closed‐

loop systems for bottom ash transport water, and the costs would be affordable for most 

plants...134

Chemical precipitation of combustion residual leachate

The Federal Register also states that chemical precipitation has been shown to be technologically 

achievable for the pollutants in combustion residual leachate, and for other industries with 

similar pollutants:

Physical/chemical treatment systems are capable of achieving low effluent concentrations of 

various metals and are effective at removing many of the pollutants of concern present in 

leachate discharges to surface waters. The pollutants of concern in leachate have also been 

identified as pollutants of concern for FGD wastewater, fly ash transport wastewater, bottom ash 

transport water, and other combustion residuals. This is to be expected since the leachate itself 

comes from landfills and surface impoundments containing the combustion residuals and those 

wastes are the source for the pollutants entrained in the leachate. Given the similarities present 

among the different types of wastewaters associated with combustion residuals, combustion 

residual leachate will be similarly amenable to chemical precipitation treatment. The treatability 

of pollutants such as arsenic and mercury using chemical precipitation technology is also 

demonstrated by technical information compiled for ELGs promulgated for other industry 

sectors.135

Vapor‐compression evaporation systems in Option 5

Vapor‐compression evaporation and other zero liquid discharge systems are technologically 

achievable. These systems are used in a variety of industrial applications, including electric 

generation, throughout the United States and around the world. In background documents to the 

proposed steam‐electric ELGs, EPA notes that:

Mechanical evaporators in combination with a final drying process can significantly reduce the 

quantity of wastewater pollutants and volume discharged from certain process operations at 

various types of industrial plants, including steam electric power plants, oil refineries, and 

chemical plants.136

Southwest states including Colorado, Arizona and California require some industrial facility’s 

waste streams to achieve zero liquid discharge.137 In most industrial settings this typically 
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requires a combination of technologies, commonly evaporation and crystallization units, but may 

also include thermal/evaporative processes, membrane processes, and spray driers.

The largest manufacturers of zero liquid discharge systems are Veolia, Aquatech, and GE Power 

and Water.138 Other vendors of zero liquid discharge technology include Siemens Water 

Technologies, 212 Resources, AGV Technologies, Aqua‐Pure, INTERVAS, and Total 

Separation Solutions.139 Veolia has installed zero liquid discharge in over 700 facilities 

worldwide across a large range of industries including: power generation, oil and gas, pulp and 

paper, metals and mining, ethanol/agricultural products/biofuel production, chemical processing, 

fertilizer manufacturing, salt production, chlor‐alkali production, and soda ash 

production.140 Aquatech—whose representatives were interviewed by EPA staff during the 

rulemaking process—has installed over 160 zero liquid discharge systems in of the same 

industries as Veolia as well as in a few additional industries including petrochemicals and 

pharmaceuticals.

According to Veolia Water Solutions & Technologies, electric generators have successfully 

applied evaporation and crystallization to achieve zero liquid discharge on “natural‐gas 

combined cycle cooling water, gasification wastewater, and FGD wastewater, and for integrated 

water and wastewater facilities and [nuclear wastewater] evaporation crystallization.”141

There are zero liquid discharge in use at power plants in at least three states, Arizona, Missouri, 

and Illinois. Three Arizona natural‐gas combined cycle (NGCC) plants use evaporation and 

crystallization units to achieve zero liquid discharge for their cooling water blowdown and 

wastewater systems: APS Redhawk Power Station in Arlington, Arizona (two NGCC units 

operating 1,060 MW total);142 Harquahala Generating Project in Tonopah, Arizona (totaling 

1,000 MW);143 and Duke Energy’s Arlington Valley Power station (570 MW), also in Arlington, 

Arizona.144 More recently, it was announced that two 758 MW NGCC plants in Texas—the 

Temple Power Plant in Bell County and the German Power Plant in Grayson County—would be 

retrofitted to achieve zero liquid discharge by 2014.145

All eight regulatory options of the proposed steam electric ELGs, required vapor‐compression 

evaporation systems for IGCC plants. As stated in the proposed ELGs, “EPA is aware of two 

plants that currently operated [IGCC] units in the United States, and a third plant is scheduled to 

begin operating an IGCC this year. All three of these plants currently treat or plan to treat the 

IGCC wastewaters with vapor‐ compression evaporation systems.”146 Overseas, zero liquid 

discharge technology is applied at a number of power plants including at IGCC and coal‐fired 

power plants. The ELCOGAS IGCC power plant in Puerollano, Spain (a 335 MW coal and 

petcoke facility) uses a number of process units, including evaporation and crystallization 

technologies, to achieve zero liquid discharge.147

In 2009, two U.S. coal‐fired electric generation units—Iatan Station 1 (670 MW) and Iatan 

Station 2 (850 MW) in Weston, Missouri—began treating FGD wastewater with a vapor‐

compression evaporation system.148 According to a case study released by a zero liquid discharge 

manufacturer, the Springfield, Illinois Dallman Power Station’s four coal‐fired units require the 

use of a falling film evaporator, vapor compressor, and spray dryer to meet Boron permit 

specifications for their FGD wastewater, resulting in achieving zero liquid discharge.149 As
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discussed by EPA, several coal‐fired power facilities in Italy have eliminated discharge of FGD 

wastewater using evaporation and crystallization units.150

134 78 Fed. Reg. at 34,471‐34,472.

135 78 Fed. Reg. at 34,454.

136 Technical Development Document, p.7‐3.

137 Global Water Intelligence. (2009, December). From zero to hero – the rise of ZLD. Global 

Water Intelligence, 10(12). http://www.globalwaterintel.com/archive/10/12/market‐insight/from‐

zero‐to‐hero‐the‐rise‐of‐zld.html.

138 Global Water Intelligence. (2009, December). From zero to hero – the rise of ZLD. Global 

Water Intelligence, 10(12). http://www.globalwaterintel.com/archive/10/12/market‐insight/from‐

zero‐to‐hero‐the‐rise‐of‐zld.html.

139 Colorado School of Mines. (2009). An Integrated Framework for Treatment and Management 

of Produced Water. RPSEA Project 07122‐12. p. 1 

http://aqwatec.mines.edu/produced_water/treat/docs/Tech_Assessment_PW_Treatment_Tech.pd

f.

140 Veolia Water. (2013). HPD Evaporation and Crystalization. Capabilities Report, Veolia 

Water Solutions & Technologies. http://www.veoliawaterst.com/vwst‐

northamerica/ressources/documents/1/32351,HPD‐EVAP‐6‐3.pdf.

141 Veolia Water. (2013). HPD Evaporation and Crystalization. Capabilities Report, Veolia 

Water Solutions & Technologies. http://www.veoliawaterst.com/vwst‐

northamerica/ressources/documents/1/32351,HPD‐EVAP‐6‐3.pdf.

142 Veolia Water. (n.d.). APS Redhawk Power Station Case Study, Veolia Water Solutions & 

Technologies. http://www.veolianorthamerica.com/info/redhawk.htm

143 Veolia Water. (n.d.). Power Generation Industry Project Profile: Harquahala Generating 

Project, LCC. Case Study, HPD.

http://www.veoliawaterst.com/hpdsystems/ressources/documents/1/2201,HPD‐HAR‐CS‐9‐3.pdf.

144 Aquatech. (n.d.). Duke Energy Selects HERO Membrane Process for ZLD Application. Case 

Study. http://www.aquatech.com/Portals/0/ProjectProfiles/02Arlington_HERO.pdf.

145 General Electric. (2013). GE to Provide Water Recycling Technology for Two Texas Power 

Plants. Press Release, GE Water & Process, Trevose. http://www.genewscenter.com/Press‐

Releases/GE‐to‐Provide‐Water‐Recycling‐Technology‐for‐Two‐ Texas‐Power‐Plants‐3d66.aspx.
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146 78 Fed. Reg. at 34454.

147 Veolia Water. (n.d.). ELCOGAS Chooses HPD's CoLDTM Process for Spain's First IGCC 

Power Plant to Attain Zero Liquid Discharge. Press Release, Veolia Water Solutions & 

Technologies, http://www.veoliawaterstna.com/news‐resources/press‐ releases/2011‐08‐

24,elcogashpdigcc.htm.

148 Aquatech. (n.d.). Aquatech Supplies Zero Liquid Discharge Treatment for FGD System at the 

Iatan Generating Station. Case Study. http://www.wateronline.com/doc/aquatech‐supplies‐zero‐

liquid‐discharge‐0001.

149 Aquatech. (n.d.). Coal Fired Power Plant Achieves ZLD for FGD Wastewater. Case Study. 

http://www.environmental‐expert.com/articles/coal‐fired‐power‐plant‐achieves‐zld‐for‐fgd‐

wastewater‐194733.

150 Global Water Intelligence. (2009, December). From zero to hero – the rise of ZLD. Global 

Water Intelligence, 10(12). http://www.globalwaterintel.com/archive/10/12/market‐insight/from‐

zero‐to‐hero‐the‐rise‐of‐zld.html. Veolia Water. (2013). FGD Scrubber Effluent Treatment ‐

ItalyZero Liquid Discharge (ZLD) System. Power Industry Case Study, Veolia Water Solutions 

& Technologies. http://www.veoliawaterst.com/vwst‐

northamerica/ressources/documents/1/32351,HPD‐ EVAP‐6‐3.pdf.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that technologies in Regulatory Option D represent Best Available Technology 

Economically Achievable (except for discharges from “small” or oil-fired generating units) 

because they are available and economically achievable (i.e., affordable) for the industry as a 

whole, and have acceptable non-water quality environmental impacts as required by the Clean 

Water Act (see preamble Section VIII). Except for discharges from “small” or oil-fired 

generating units, BAT for bottom ash transport water is dry handling or closed loop systems.

EPA did not select chemical precipitation as BAT for combustion residual leachate for the 

reasons specified in preamble section VIII.

EPA did not select chemical precipitation plus evaporation as BAT for FGD wastewater for the 

reasons specified in preamble section VIII. Also, see response to DCN EPA-HQ-OW-2009-

0819-4684-A1, Excerpt Number 15 and DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt 

Number 46 in Comment Code 6.i.iv.

Regarding zero pollutant discharge standards for FGD, see the preamble to the final rule and 

responses to Comment Code 6.i.iii.
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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: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposed rulemaking does not require any control of bottom ash transport waters at 

uncontrolled units in any option except 4a, 4 and 5. In preferred Option 4a, the proposed 

rulemaking requires zero discharge of bottom ash transfer water at units greater than 400 

MW. In not-preferred Options 4 and 5, zero discharge of bottom ash transport water is required 

at all units greater than 50 MW. Option 4 is identical to Option 4a, except Option 4 requires zero 

discharge for bottom ash at all units >50 MW while Option 4a requires zero discharge for bottom 

ash only for units >400 MW. 78 Fed. Reg. at 34,473.

Options 4 and 5 were not selected as "preferred" options due primarily to the claimed cost of 

zero discharge of bottom ash transport waters in Option 4 and the additional zero liquid 

discharge for FGD wastewater in Option 5.

Comment Response: 

In its selection of regulatory Option D for the final rule, EPA determined that dry handling for 

control of fly ash transport water discharges and dry handling or closed-loop systems for control 

of bottom ash transport water discharges represent Best Available Technology Economically 

Achievable (except for discharges from “small” or oil-fired generating units) because the 

technologies forming the bases for that option are available, affordable to the industry as a whole 

and has acceptable non-water quality environmental impacts. See preamble section VIII.

EPA did not select a final regulatory option that includes chemical precipitation and evaporation 

as BAT for FGD wastewater for the reasons stated in preamble section VIII.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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GEA EGI Contracting/Engineering Co., Ltd. (GEA EGI) is a company in partnership with 

United States-based companies. Collectively, this team designs, builds and installs important 

equipment for use in the electric power generation industry. One technology that has been 

successfully deployed (commercially) is the Circumix Dense Slurry System (DSS) technology. 

This technology is a unique mixing technology that is being successfully applied to solidify and 

stabilize coal combustion residuals and wastewater in a single process.

The Effluent Limitations Guidelines (ELG) and Coal Combustion Residuals (CCR) proposed 

rules contain wording that has created unanticipated and unintentional uncertainty in the industry 

regarding the regulatory classification of DSS. This regulatory uncertainty has fostered 

reluctance by industry to adopt the DSS technology despite the industry’s recognition of this 

technology’s ability to achieve the goals and objectives of both proposed rules. This reluctance is 

also despite the fact that costs for applying DSS are less than the benchmark technologies 

referenced by EPA.

The regulatory uncertainty referenced above is due to a lack of information about the DSS made 

available to the EPA at the time the proposed rules were written. This comment provides 

appropriate technical information about the DSS technology and data that serve to justify a 

revision of the proposed rules, the goal of which is to alleviate the above-referenced uncertainty 

and to recognize DSS as an appropriate and relevant technology capable of meeting the goals 

and objectives of the proposed rules.

Comment Response: 

EPA acknowledges the receipt of this additional information regarding the DSS technology and 

has considered it in its analyses for the final rule. For further details see Sections 7.2.2 and 7.3.2 

of the TDD.

The commenter proposes that dense slurry systems are one approach for steam electric power 

plants to achieve zero pollutant discharge limitations and standards. The final rule does not 

specify a technology, but rather the limitations on pollutant discharges that must be achieved. 

Therefore, plants can convey ash with dense slurry systems, provided they meet any applicable 

limitation in this final rule, including the zero discharge limitation for all pollutants in fly ash 

transport water, bottom ash transport water, and FGMC wastewater.

To the extent that plants elect to comply with the zero discharge limitation for all pollutants in 

fly ash transport water, bottom ash transport water, and FGMC wastewater using a dense slurry 

system, and to the extent that the dense slurry system is less expensive than the technologies 

EPA used as the bases for its cost estimates associated with the final limitations, EPA 

acknowledges that it may have overestimated compliance costs for these plants.

EPA notes, however, 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).); 
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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: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Technology Description

DSS is a high-intensity mixing process that mixes minimal quantities of water (including 

wastewater) with CCR’s to produce dense, pumpable slurry. This process maximizes the 

availability of reactive ions in ash products and results in near-stoichiometric use of the water 

contained in the slurry. Additives (while not necessary) may be employed to enhance end 

product performance depending upon the chemistry of the ash to be stabilized. Once discharged, 

the slurry hardens within 24 to 72 hours. Once cured, the product exhibits low hydraulic 

conductivity, high compressional strength, no wastewater discharge, little or no fugitive 

emissions and enhanced sequestration of contained metals.

In a single process, the DSS technology facilitates:

1. Effective combined stabilization of ash and wastewater.

2. Reduction of water use by 80% to 90%, as compared to traditional “lean slurry” practice.

3. Zero discharge of transport water.

4. Significant reduction of plant-wide wastewater volume destined for treatment and 

discharge.

5. Enhanced protection of ground water by virtue of low hydraulic conductivity (measured 

10-4 to 10-10 cm/sec) and enhanced metals sequestration exhibited by the end product.

6. Elimination of risk of catastrophic releases associated with dike failure and liquefaction 

due to the solid nature and high compressional strength of the end product.

7. Significant reduction of leachate volumes due to low hydraulic conductivity, high 

capillary retention, hydration reactions and the minimal amount of water used in the 

process.
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8. Significant reduction of fugitive dust emissions due to the initially wet nature, enclosed 

transport medium and later solid nature of the end product.

9. Enhanced land-use efficiencies for disposal sites because the high compressional strength 

of the end product facilitates elevated impoundments and landfills.

10. Reduction in the cost of managing CCRs and wastewater compared to “dry ash” 

management techniques and water treatment alternatives referenced by EPA in the 

proposed rules.

11. Reduced energy use and cost for pumping dense slurry compared to “dry ash” 

management, which typically requires pug mill mixing, hauling by truck and 

spreading/compaction by heavy equipment. Support services typically required for dry 

ash management are not needed (e.g., lighting, manned impoundment security, fuel 

handling, etc.)

12. Enhanced safety of operations and reduced noise levels, because the dense slurry can be 

pumped rather than transported by truck and manipulated with heavy equipment.

13. The process can mix fly ash, bottom ash, gypsum and waste water together.

In summary, DSS achieves the goals and objectives of the proposed ELG and CCR rules in a 

single process by converting wastewater and CCRs into an environmentally stable end product.

Historical Use

DSS is not new. It has been used for decades in Europe and since 2003 in the United States. 

Table 1 lists the coal-fired power plants currently employing or that have employed DSS 

technology, including pertinent data on the types and quantities of ash treated (per hour and 

total), when DSS processing was initiated, etc.

Comment Response: 

EPA agrees that dense slurry systems are an approach steam electric power plants may elect to 

use to comply with the final rule’s zero pollutant discharge limitations and standards. However, 

since the technology does use water as the transport mechanism, and therefore generates ash 

transport water, plants using this technology would still need to operate it in a manner that results 

in zero discharge of pollutants in ash transport water. See response to DCN EPA-HQ-OW-2009-

0819-5093-A2, Excerpt Number 1.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Referenced Plants

In EPA’s Final Detailed Study Report (EPA 821-R-09-008), reference is made to site visits and 

sampling activities from plants in the United States, including an evaluation of waste streams and 

processes associated primarily with coal ash handling operations and FGD air pollution control 

systems. EPA visited the JEA Northside Power Station in Jacksonville, FL and inspected the 

DSS system in use there. Information EPA collected in its evaluation of this plant is not reflected 

or mentioned in the proposed ELG rule preamble. The JEA Northside Power Station is the only 

plant in the U.S. where DSS is currently being employed. The presence of only one plant in the 

U.S. is the likely reason for this technology being omitted in the development of the proposed 

rule. The technology is, however, being utilized at multiple plants in other parts of the world 

where it has demonstrated compliance with strict EU environmental regulations.

Comment Response: 

EPA acknowledges investigating the only DSS operating in the United States, the Jacksonville 

Electric Authority Northside Generating Station (JEA Northside), during a site visit on April 8, 

2014, and has considered the information collected during the site visit in its analyses for the 

final rule. See Section 7.2.2 of the TDD.

See also response to DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 1.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Use and Reference of Foreign Technology

In the preamble of the proposed ELG rule (III, B, 3), EPA discusses Best Available Technology 

Economically Achievable (BAT). In EPA’s discussion, it is recognized that foreign plants may 

be referenced in part to define BAT. DSS has been used for a long time outside of the United 

States and has demonstrated favorable environmental performance. Because of this history of 

favorable performance, it is appropriate for EPA to consider the technical merits of DSS for 

wider deployment in the United States and to also consider it as a viable benchmark BAT 

technology for the management of wastewater by using the wastewater to stabilize coal 

combustion products.

Comment Response: 
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EPA acknowledges the receipt of this additional information regarding the DSS technology and 

has considered it in its analyses for the final rule. See Sections 7.2.2 and 7.3.2 of the TDD.

EPA did not select DSS as the technology basis for the final rule for the reasons discussed in the 

preamble to the final rule. DSS is a potentially viable technology for steam electric power plants 

to transport the ash to the disposal site; however, because the dense slurry process generates 

transport water, the plant must still meet the no discharge of wastewater pollutant limitations and 

standards. See response to DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 5 and 

DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 13 in Comment Code 6.g.v.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

BAT & BADCT Technology Reference

In the preamble of the proposed ELG rule (VIII, 1, 2), EPA identified a subset of treatment 

processes and operational practices that it deemed most promising as candidate BAT/BADCT 

options. It is clear that these options focus on a process termed “dry ash” management and 

enhanced water treatment techniques. It is important to note that “dry ash” management 

techniques discussed in the proposed rule are not truly dry. These techniques typically mix 15-

20% water with ash to control dust and to facilitate compaction and more is added later (often 

with sprinklers) at the disposal facility. Thus, the intent of EPA’s use of this “dry ash” 

terminology is not to imply that an ash management system uses no water. Instead, the intent of 

the use of the “dry ash” terminology refers to ash management techniques that do not produce 

wastewater requiring treatment or discharge.

DSS achieves zero discharge of transport water while producing a solidified ash product 

exhibiting properties that are clearly superior to the “dry ash” management techniques described 

in the preamble. In addition, DSS typically uses less energy than traditional “dry ash” 

management particularly with respect to ash transport and disposal.

In the final rule, DSS should be considered in EPA’s technology basis in defining BAT/BADCT 

technology. Such consideration is deserved because DSS: 1) is technically demonstrated and 

available; 2) is economically achievable; 3) is a relatively simple process; 4) is energy efficient; 

5) is capable of achieving target effluent standards; 6) can often utilize existing plant 

infrastructure; and 7) has less of an impact on other non-water quality environmental standards 

compared to traditional “dry ash” management systems. DSS should also be referred to as a “dry 

ash” management technique in the context of, and consistent with the intent of, the described 
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process. This is because DSS results in a solid product and because it exhibits zero discharge of 

transport water to the waters of the United States.

Comment Response: 

As discussed in preamble section VIII, for generating units that are greater than 50 MW and are 

not oil-fired, the final rule promulgates as BAT a zero discharge limitation for all pollutants in 

fly ash transport water based on use of a dry-handling system and for all pollutants in bottom ash 

transport water based on the use of a dry-handling system or a closed-loop system. A steam 

electric power plant with fly ash or bottom ash systems incorporating the DSS technology would 

use a dry vacuum or pressure system to convey the ash to a silo, but instead of using trucks to 

transport the ash to a landfill, the plant would mix the ash with a lower percentage of water 

compared to a wet sluicing system and pump the mixture to the landfill.

See the response to DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 5 and DCN EPAHQ-OW-2009-0819-5093-A2, Excerpt Number 13 in Comment Code 6.g.v regarding ash 

transport water as it relates to the DSS system.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Anti-Circumvention Provisions

EPA describes the proposed Anti-Circumvention Provisions in the ELG Preamble (page 34465). 

The intent of the proposed provision is to limit mixing of wastewaters in an effort to preclude the 

practice of diluting a waste stream or otherwise re-categorizing wastewater for purposes of more 

easily achieving compliance. DSS is an effective treatment method for FGD and other 

wastewater by virtue of stabilizing and immobilizing the water in hydration reactions, entraining 

and trapping suspended solids, and by enhanced sequestration of contained metals. The very low 

hydraulic conductivity and high capillary forces of the cured slurry product reduces leachate 

quantities and the enhanced sequestration of metals reduces their concentration in leachate (see 

Tables 5, 6, 9, &11).

The DSS practice of combining wastewaters for purposes of ash solidification and stabilization 

results in an overall reduction of water consumption and reduces the generation of wastewater 

destined for treatment and/or discharge. Thus, mixing wastewater for purposes of ash 

solidification and stabilization does not violate the intent of the Anti-Circumvention Provisions. 

In fact, this practice enhances the goals and objectives of the proposed rule.
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Comment Response: 

The final rule does not require internal monitoring to demonstrate compliance with certain 

numeric limitations and standards. See preamble section VIII and response to DCN EPA-HQOW-2009-0819-4305-A3, Excerpt Number 117 in Comment Code 26.d.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In June 2010, representatives of EPA visited the JEA Northside Generating Station in 

Jacksonville, Florida and observed the DSS system in operation there. The information collected 

during this visit and any details on the DSS technology being employed there are not reflected in 

the ELG or CCR proposed rules.
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The JEA plant (a fluidized bed petroleum coke plant) employs two DSS mixing systems that 

collectively process 120 tons per hour of fly ash and bed ash. Following mixing and discharge of 

the dense slurry, JEA interrupts the hydration process by excavating and drying the dense slurry. 

Following additional preparation steps, JEA markets this material for beneficial use as a road 

construction material with the trade name EZ Base. The JEA ash exhibits favorable chemistry for 

beneficial use and demonstrates the potential for beneficial use of other types of ash with or 

without additives designed to enhance end product performance.

EZ Base was tested in Florida as a road surfacing material (not an underlayment) and monitored 

to evaluate its environmental stability. Following baseline sampling and road construction using 

EZ Base paving material, the soil, ground water, storm water and surface water were monitored 

for two years by an independent engineering company. The results were reported in November 

2011. The results of this monitoring showed that there was no statistical change in any of these 

environmental media during the two-year monitoring period. This report is entitled: Year Two

Follow-up Investigation Report, Soil and Water Quality Evaluation, St. Mary’s Shoals Park

Roadway Improvements, Baker County, Florida. The report was prepared by Mechling 

Engineering & Consulting, Inc., Jacksonville, FL and can be obtained from the Florida 

Department of Environmental Protection.

Comment Response: 

EPA included this information in the record for this rulemaking. It continues to be in the docket 

for the final rule and EPA also included related information in the final TDD. See the response to 

DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 3 regarding information received 

during the JEA Northside site visit. See the response to DCN EPA-HQ-OW-2009-0819-5093-

A2, Excerpt Number 6 regarding use of the DSS process to achieve the zero discharge 

limitations for fly and bottom ash.

Commenter Name: name illegible

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5252-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The EPA's proposed regulations to strengthen controls on discharge from power plants must 

include language where technology will, on a reasonable basis, be re-evaluated to include the 

most protective option available.

Like any other scientific evaluation, we must learn inherently the ways of scientific method. We 

can't simply let red tape and regulatory processes dictate the timeliness of our future and safety. 
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Standards implemented must be strict and should take into consideration future growth and 

trends and increased discharge regulation.

Comment Response: 

EPA agrees with the commenter that wastewater discharges from industries, including the steam 

electric power generating industry, should be periodically re-evaluated for potential revision. In 

fact, the CWA requires EPA to review existing effluent guidelines annually. EPA reviews all 

point source categories subject to existing effluent guidelines and pretreatment standards to 

identify potential candidates for revision, consistent with CWA sections 304(b), 301(d), and 

304(g). Finally, EPA reviews industries consisting entirely or almost entirely of indirectdischarging facilities that are not currently subject to pretreatment standards to identify potential 

candidates for pretreatment standards development under CWA sections 307(b). This annual 

review precludes the need to include language requiring periodic reevaluation in the regulation.

Commenter Name: W. Creal

Commenter Affiliation: Michigan Department of Environmental Quality

Document Control Number: EPA-HQ-OW-2009-0819-5510-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For two of the wastestreams, flue gas desulfurization (FGD) and bottom ash transport water, the 

preferred alternatives vary in the level of control required to attain compliance with the proposed 

effluent limitations. After reviewing the proposed treatment controls expected and level of 

pollutants expected to be removed, Michigan has concerns about the proposed standards for 

these two wastestreams.

.....

Michigan has concerns that BAT standards that were set for FGD and bottom ash wastewaters 

may not have been sufficiently characterized and evaluated to determine the actual pollutant 

reduction and costs associated with implementing these standards industrywide.

Comment Response: 

For the final rule, EPA incorporated the use of additional data in its effluent limitations 

guidelines and standards development, pollutants of concern identification, and pollutant 

loadings estimates. EPA subjected the new data to its data quality acceptance criteria and, as 

appropriate, updated its analyses accordingly. See TDD Section 3 for additional information on 

the data sources used in the development of the final rule.
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EPA disagrees that the BAT standards for FGD wastewater and bottom ash transport water have 

not been sufficiently evaluated to determine pollutant reductions and costs associated with 

implementing the standards. As discussed in preamble section V.D, and in greater detail in 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

(Costs & Loads Report) (DCN SE05831/SE05832), EPA has revised its cost estimates in 

response to comments received on the proposed rule.
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6.a. Regulatory Options – Identification and Selection of Pollutants 

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: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

2. Nitrate/nitrite should not be included in the ELGs for FGD wastewater at this time. Such an 

inclusion could lead to unintended consequences in both implementation and enforcement of the 

proposed ELGs.

Comment Response: 

EPA selected nitrate/nitrite as regulated pollutants in FGD wastewaters to control their 

discharge. EPA notes that the commenter did not provide any specific reasons or data as to why 

limitations on nitrate/nitrite in FGD wastewater should not be included in the final rule. FGD 

wastewater pollution is controlled directly through numeric discharge limitations for arsenic, 

mercury, selenium, and nitrate/nitrite, and indirectly for many additional metals, including 

cadmium and lead, through regulation of the indicator pollutants arsenic, mercury, and selenium. 

See the memorandum FGD Wastewater Pollutants of Concern (POC) Analysis Methodology

[DCN SE05342] for a more detailed description of the pollutants of concern analysis. See 

response to DCN EPA-HQ-OW-2009-0819-3922-A1, Excerpt Number 3 in Comment Code 26.f 

regarding regulation of nitrate/nitrite in FGD wastewaters.

Commenter Name: Jennifer Peters

Commenter Affiliation: Clean Water Action (CWA)

Document Control Number: EPA-HQ-OW-2009-0819-3920-A21

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Clean Water Action is particularly concerned that none ofthe four "preferred" options for 

pretreatment standards or direct discharge standards would require power plants to control for 

bromide. Bromide in wastewater discharges upstream of drinking water intakes has been linked 

to the formation of trihalomethanes,or THMs, when it is exposed to disinfectant processes in 

water treatment plants. By EPA's own estimate, approximately 37% of all power plants are 

located near a drinking water intake for surface water.
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These disinfection byproducts are known to cause cancer and reproductive and developmental 

health affects, which is why Public Water Systems must comply with regulations to reduce these 

byproducts. If power plant wastewater contributes to the formation of disinfection byproducts in 

drinking water treatment plants, that can mean increased exposure and health risk to those 

drinking that water. This is by no means an abstract problem if you are a person drinking that 

water. It is also not an abstract matter to the Public Water System that has to figure out how to 

adjust treatment that has been thrown out of balance.

Of EPA's eight proposed options, only Option 5 would require power plants to control for 

bromides, boron and other Total Dissolved Solids. Clean Water Action believes that EPA should 

require power plants that discharge to POTWs or directly to surface water, to control for these 

pollutants in order to protect the quality of the public's drinking water sources. Technology exists 

to effectively eliminate nearly all water pollution from power plants, and it is time to end the 

power plant industries' unlimited permit to pollute, which stands in the way of cleaning up our 

rivers, streams and lakes.

Comment Response: 

EPA agrees with that bromides can be of concern in wastewater discharges upstream of drinking 

water intakes; however, EPA has not selected chemical precipitation followed by evaporation 

(proposed Option 5) as BAT/PSES for FGD wastewater for the reasons stated in Section VIII of 

the preamble and elsewhere in this record. However, as described in Section VIII.C.13 of the 

preamble, the rule establishes 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. In addition, as discussed in Section VIII.D of the preamble, EPA concluded that 

treatment using evaporation represents BADCT for FGD wastewater at steam electric power 

plants, and the final rule promulgates NSPS based on that technology (specifically, an 

evaporation step preceded by a chemical precipitation step using hydroxide precipitation, sulfide 

precipitation, and iron co-precipitation, as well as a softening step).

EPA also provides a discussion in preamble section XVI.D of the site-specific conditions where 

it may be appropriate for the permitting authority to establish water-quality based effluent 

limitations on bromide or TDS for existing steam electric power plants.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Clean Water Action is particularly concerned that none of the four preferred options for 

pretreatment standards or direct discharge standards would require power plants to control for 

bromide. Bromide in wastewater discharge is upstream of drinking water intakes, has been 

linked to the formation of trihalomethanes, or THMs, when it is exposed to disinfectants or 

processes in water treatment plants. By EPA's own estimate, approximately 37 percent of all 

power plants are located near a drinking water intake for surface water. These disinfection 

byproducts are known to cause cancer and reproductive and developmental health effects, which 

is why public water systems must comply with regulations to reduce these by products.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

If power plant wastewater contributes to the formation of disinfection byproducts in drinking 

water treatment plants, that can mean increased exposure and health risk to those drinking that 

water. This is by no means an abstract problem if you are a person drinking that water. It is also 

not an abstract matter to the public water system that has to figure out how to adjust treatment 

that has been thrown out of balance.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Of EPA's eight proposed options, only Option 5 would require power plants to control for 

bromide or other total dissolved solids. Clean Water Action believes that EPA should require 

power plants that discharge to POTWs or are directly discharging to surface water to control for 

these pollutants in order to protect the quality of the public's drinking water sources.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1.

Commenter Name: Jamie Rhodes

Commenter Affiliation: Environment Council of Rhode Island

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

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Most of the options proposed by EPA would require existing and new power plants to control 

scrubber wastewater with a combination of chemical and biological treatment. However, neither 

of those technological options effectively treat for bromide and other total dissolved 

solids. Bromide is of particular concern for plants that discharge near drinking water intakes beca

use it can create harmful byproducts when mixed with disinfectants used to treat drinking water. 

Vapor evaporation technology exists that can reduce scrubber discharges to near zero, the only 

way to eliminate this source of bromides from our drinking water supplies.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 135

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. Bromides Do Not Justify a ZLD Option for FGD Wastewater
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EPA suggests that bromide from FGD wastewater discharges upstream of drinking water intakes 

may cause formation of trihalomethanes (THMs) when it is exposed to disinfectant processes in 

water treatment plants. 78 Fed Reg. at 34,477 col. 1. The Agency further suggests that, although 

it did not designate the ZLD option (Option 5) for FGD wastewater as a preferred “New Source 

Performance Standard” option, “the technologies forming the basis of Option 5 are all 

technologically available and may be appropriate (individually or in totality) as the basis for 

water quality-based effluent limits in individual or general permits depending on site-specific 

conditions.” Id.

First, for the many reasons spelled out in these comments, UWAG strongly disagrees that the 

Option 5 technology, chemical precipitation followed by a vapor compression/evaporation 

system, is technologically available for FGD wastewater treatment. There are simply too many 

technological and operational issues associated with deploying this technology to treat FGD 

wastewater.

Second, we have also demonstrated that ZLD technology is not cost effective, using EPA’s own 

standards, and therefore it cannot be the basis of national limits. The level of costs associated 

with ZLD technology would likely render it an infeasible option for many individual power 

plants.

Third, the potential impact of bromide discharges on downstream drinking water systems is a 

very site-specific inquiry, and will depend on site-specific factors such as existing power plant 

treatment equipment and mode and timing of operation, size of the receiving waterbody, distance 

between the power plant and the drinking water intake, and natural constituents already present 

in the receiving waterbody, to name a few. Technology-based limits are not designed to address 

isolated site-specific circumstances. Not every issue is best addressed through application of 

national standards, and this is one that should be addressed at the individual plant level.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1, regarding EPA’s 

consideration of evaporation as a component of the technology bases for FGD wastewater for the 

final rule.

EPA disagrees that “there are simply too many technological and operational issues associated 

with deploying this technology to treat FGD wastewater.” See response to DCN EPA-HQ-OW2009-0819-4305-A3, Excerpt Number 45 in Comment Code 11.a.

Specific to the commenter’s statements about the impact of bromide discharges, steam electric 

power plant discharges occur close to more than 100 public drinking water intakes on rivers and 

other water bodies. However, EPA did not identify evaporation as the basis for BAT limitations 

for FGD wastewater at all steam electric power plants for the reasons stated in Section VIII of 

the preamble and elsewhere in this record. . EPA also provides an incentives program allowing 

more time for those who choose to meet FGD limitations based on evaporation (as was included 

in proposed Option 5). For existing sources, EPA provides a discussion in preamble section 

XVI.D of the site-specific conditions where it may be appropriate for the permitting authority to 
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establish water-quality based effluent limitations on bromide or TDS for existing steam electric 

power plants.

Commenter Name: James D. Taft

Commenter Affiliation: Association of State Drinking Water Administration (ASDWA)

Document Control Number: EPA-HQ-OW-2009-0819-4668-A2

Comment Excerpt Number: 3

External Review Flag: Envr Assess

External Review Incorporated into Response: No

Comment Excerpt: 

There are also recently emerging concerns in some power plant discharges, such as bromide, 

which need to be addressed. Bromide is of particular concern where power plants discharge 

wastewaters upstream of drinking water intakes because it can contribute to elevated disinfection 

byproducts (which are carcinogens) formation during drinking water treatment. The costs borne 

by local communities to manage disinfection byproducts are already substantial and the addition 

of significant upstream sources of elevated bromide from power plant discharges can 

substantially complicate disinfection byproduct control for numerous downstream water systems. 

The final effluent guidelines should ensure that power plants do not inadvertently create 

unintended consequences for downstream drinking water supplies.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4687-A10

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

3.0 Bromide and Coal-Fired Power Plants

Halogens (Cl, Br, I) are trace elements in coal, as mentioned above. Halogen-based disinfectants 

can also be found in various cleaning agents and anti-foulants used at power plants. Further, 

bromide addition, or the use of brominated sorbents, is a well-known application for mercury 

control in plants with flue-gas desulfurization units. The fate of these halogens in coal-fired 
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power plants depends significantly on process controls, most notably pollution control systems 

designed to remove sulfur dioxide from flue gas emissions.

Bromide in Coal

As noted above, bromide is present in coal at trace levels (<0.001 %). Bromide is likely 

associated with the organic fraction of the coal; however, association with clay minerals and iron 

oxides has also been reported (Swaine 1990). Coals vary in the concentration of bromide present 

(USGS 2006), with bituminous coals exceeding subbituminous and lignite. Halogen content is 

generally controlled by a source’s surrounding geochemistry, and thus, deeper mined coals 

generally contain more halogen salts (Bragg, Finkelman and Tewalt 1991). Details of bromide 

concentrations for U.S. coals are available in the U.S. Geological Survey Coal Quality 

(COALQUAL) Database (see http://energy.er.usgs.gov/products/databases/CoalQual/ ). For 

example, West Virginia coals generally contain 20-40 ppm bromide (μ=23.88, σ=11.47) 

with low bromide in Pittsburgh and Redstone coal and highest bromide in Sewell Coal (>50 

ppm). The USGS also maintains a World Coal Quality Inventory 

(see http://energy.usgs.gov/Coal.aspx). While many analyses have been generated from these 

databases and trace metals are routinely measured in coal samples, halogen data are less 

available [see for example:(Tewalt, Willett and Finkelman 2005; Hatch, Bullock and 

Finkelman 2006)]. Studies specifically focused on mercury removal (see below) have included 

careful analysis of bromide and chloride concentrations in coal, as this ratio (Br/Cl) affects 

mercury removal efficiency. An analysis by Kolker et al. (Kolker, Quick, Senior and Belkin 

2012) indicates that most coal-bromide concentrations are below 50ppm, while chloride 

concentrations are typically below 2000 ppm; an average Br/Cl ratio of 0.02 is reported.

Coal Combustion and Halogens

Chloride (Cl-) and bromide (Br-) ions present in the coal or added prior to combustion are 

reduced to chlorine (Cl2(g)) and bromine (Br2(g)) through reaction with oxygen at high 

temperatures during the combustion process. This converts the very soluble ions to gases, thus 

affecting their fate in the system. Chlorine that is formed in this process can be reduced back to 

chloride through a reaction with SO2, a reaction that is largely controlled by the concentration of 

SO2. Bromine is less susceptible to this reaction in the furnace; however, some bromine can be 

consumed in a similar reaction with SO2 that can take place at low temperature in wet flue gas 

desulfurization (FGD) systems.

Bromine and chlorine are strong oxidants that react with other reduced elements present in the 

coal, most notably mercury (Hg0). Bromine and chlorine can oxidize mercury to Hg2+, while 

being reduced themselves back to ionic form (Cl- and Br-). Again, this reaction alters the fate of 

the Cl and Br. The ionic forms are highly soluble, while the gas phase forms otherwise exit in the 

flue gases. Thus, the chemistry of oxidation and reduction reactions that take place in the furnace 

and in various pollution control units will control the mode of release of chloride and bromide 

originally present in the coal.

Fate of Bromide from Coal in Power Plant Residuals
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Coal combustion produces multiple residual streams, including: bottom ash, fly ash, gypsum, and 

flue gases. In general, after combustion, 99% of the halogens originally in ionic form in the coal 

are found as gaseous forms (chlorine, bromine) in flue gas (Klein, Andren, Carter, 

Emery, Feldman, Fulkerson, Lyon, Ogle, Talmi, VanHook and Bolton 1975; Germani and Zoller 

1988). Bottom ash and associated wastewaters from its wet handling do not contain significant 

halogen residuals. However, the installation of pollution control units for flue gas alters the 

chemistry of halogens and their ultimate fate in the system.

Flue gas desulfurization (FGD) systems are designed to convert gaseous SO2 to the soluble acid, 

H2SO4. Although the chemistry is more complex, and affected by the presence of metals 

(including Hg), the process has a similar effect on halogens, converting gaseous Cl2 and Br2 to 

their soluble ionic forms (Cl- and Br-). The result of this shift from gas to soluble phase is the 

capture of chlorine and bromine as chloride and bromide in the FGD wastewater rather than the 

release of the gases in the stack. A number of researchers have reported that wet and dry flue 

gas desulfurization (FGD) systems remove halogens in coal from the stack gas, and wet systems 

transfer them to FGD wastewaters [e.g.(Clare and Sloss 1992; Sloss 1992; Srivastava, 

Hutson, Martin, Princiotta and Staudt 2006)]. Thus, the addition of wet FGD will increase 

discharges of bromide in soluble form (Br-) from power plants to the environment, unless FGD 

wastewater treatment incorporates bromide removal.

Wastewater characterization at coal-fired steam electric utilities has been undertaken by a variety 

of industry and regulatory groups. The Electric Power Research Institute (EPRI) released a 

characterization of residuals in 1987 that included FGD sludge. Chloride and fluoride were 

measured, but bromide was not (EPRI 1987). EPRI released guidance for wastewater 

characterization in 2007 that identified 10 sampling locations, including FGD blowdown water, 

but sampling for bromide was not included (EPRI 2007). Although the preliminary results for 

FGD wastewater characterization (EPRI 2006) did not include bromide, the recommendations 

made for future research suggested that bromide should be included. Characterization for metals 

and other anions is reported by a number of sources, but bromide data are scarce.

Wilson et al. (Wilson, Wang et al. 2013), citing data (EPRI 2007; Frank 2011) for Pennsylvania, 

report values in effluent streams (type not identified) as 89 ± 37mg/L, as shown in Figure 1 

above. At a national level, EPRI conducted a number of studies for different locations associated 

with evaluation of co-management of low volume wastes with high volume coal combustion byproducts. The data for this are provided in Table 1 below, with bromide concentrations ranging 

from below detection limits (<0.1 mg/L) to 118 mg/L, with higher values always associated with 

FGD wastewaters. EPA (USEPA 2009) evaluated waste streams from power plants and reported 

concentration ranges of 43-96 mg/L for flue-gas desulfurization units, and 180-260 mg/L for 

chemical precipitation systems.

The data in Table 1 suggest that FGD wastewaters contain higher bromide levels than most other 

wastewaters reported from these sites. Further, FGD wastewaters are reported to 

have higher bromide to chloride ratios than other power plant wastewaters and higher ratios than 

naturally occurring groundwaters (EPRI 2007). The results indicate “the FGD system adds both 

chloride and bromide to the water, and the proportion of bromide to chloride added in the FGD 

system is greater than that added to the bottom ash and low-volume waste streams.”(EPRI 2007)
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Specific plant studies have looked at the fate of trace elements in coal-fired power plants with 

different air quality control devices (Meij 1989; Meij 1991; Meij 1994). Results confirm that 

bromine is present in the vapor phase in the flue gas exiting the furnace (not in the bottom ash), 

prior to air quality control systems. For example, Zevenhoven and Kilpinen (Zevenhoven 

and Kilpinin 2002) report 95% removal of bromide in FGD, with most of the halogen products in 

the FGD wastewater.

While not a focus of the analysis in the current regulatory rule-making, bromide concentrations 

measured in the FGD wastewater screening study (EPRI 2006) were used in load calculations 

(Finseth 2009). Bromide was reported as 67,300μg/L (67.3 mg/L) in FGD wastewater, and this 

was used to calculate a small model plant load value of 51,700 lbs/year and a large model plant 

load value of 177,000 lbs/year. No settling pond data were evaluated. An evaluation of a 

different plant using chemical precipitation treatment reported a concentration of 225 mg/L 

bromide, leading to loads of 173,000 lbs/year for the small model plant and 592,000 lbs/year for 

the large model plant. While these data are quite limited, a reasonable conclusion from them is 

that power plant treatment systems do not remove bromide, but rather will discharge it in 

wastewater effluent, which may pose a problem for downstream drinking water plants (see 

Section 4 below).

Table 1. Bromide Concentrations in Wastewater Effluent from Coal-Fired Power Plants in 

the U.S. (Most data from EPRI’s multi-year study of co-management of low volume wastes with 

high volume coal combustion by-products2).
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2 This study was not focused specifically on all liquid wastewater streams from power plants, and 

thus, most sites did not analyze cooling waters or cooling tower blowdown. Many sites did not 

have FGD systems or treat and manage FGD waste streams.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 64

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA acknowledges that only mechanical evaporation will address the high levels of boron, 

bromides, and TDS in FGD wastewater. Based on the mechanical evaporation technology, EPA 

has proposed an effluent limit for total dissolved solids, which is a category of pollutants that 

includes bromides, of 24 mg TDS per liter.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A21, Excerpt Number 1.

Commenter Name: Donald R. Carlson

Commenter Affiliation: Kansas Department of Health and Environment (KDHE)

Document Control Number: EPA-HQ-OW-2009-0819-3922-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The preamble of the proposed rule in the June 7, 2013, Federal Register does not discuss why the 

pollutant sulfate was not considered for regulation of the FGD wastewater. What is EPA's 
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rationale for not considering sulfate for regulation since it is a significant constitute of the FGD 

waste stream?

Comment Response: 

EPA did not select sulfate as a pollutant or concern or regulated pollutant for FGD wastewater 

for the final rule. According to EPA’s methodology for the final rule (see DCN SE05342), 

pollutants of concern are identified based on an assessment of whether they are detected at 

greater than or equal to 10 times the sample reporting limit in at least 10 percent of all untreated 

FGD wastewater samples. Using the sample reporting limit provides a direct comparison to the 

sample result because the reporting limit accounts for analytical adjustments made in the 

determination of the sample result. Additionally, using 10 times the sample reporting limit as a 

screening threshold can facilitate evaluations of treatment system performance and efficacy, 

since it ensures the influent concentrations are high enough to more readily quantify the degree 

of pollutant removal resulting from treatment processes such as chemical or biological treatment. 

Although sulfate was detected in 100% of untreated FGD wastewater samples, it was not present 

in any untreated FGD wastewater samples at a level of 10 times its sample reporting limit. 

Accordingly, sulfate was not selected as a pollutant of concern and was not considered in other 

analyses such as pollutant loadings and removals or for regulation. Even if EPA had selected 

sulfate as a pollutant of concern for FGD wastewater, it would not have selected it for regulation 

because regulation could interfere with its use as a treatment system additive in efforts to 

optimize treatment system operation.

Commenter Name: J. Madras

Commenter Affiliation: Missouri Department of Natural Resources

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

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

8. Sulfur and Sulfate

The proposed revision to the ELG does not include sulfate as a parameter. The flue gas 

desulfization equipment installed to meet the SOx requirements under the Clean Air Act, 

introduces sulfates into the wastewater streams. Chemical precipitation often includes the 

addition of ferric sulfate or another sulfur compound to reduce metal concentrations. Increased 

sulfate compounds expected in the waste streams could lead to a water quality issue, as sulfate is 

toxic to aquatic life. Options 3a and 3b require BPJ for removal of Flue Gas Desulfurization 

(FGD) wastewater. Option 3a requires BPJ for all facilities and 3b for facilities less than 2,000 

MW, leaving that the majority of Missouri's power plant permits require a BPJ decision for 

sulfate concentrations and controls. The Department believe that the ELG should include sulfate 

as a parameter of concern and discourages implementing BPJ for this parameter.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3922-A1, Excerpt Number 4 regarding EPA’s 

rationale for not selecting sulfate as a pollutant of concern or regulated pollutant for FGD 

wastewater. Even if EPA had selected sulfate as a pollutant of concern for FGD wastewater, it 

would not have selected it for regulation because regulation could interfere with its use as a 

treatment system additive in efforts to optimize treatment system operation.

As discussed in preamble section VIII.C.1, EPA decided not to promulgate BAT limitations that 

would require permitting authorities to establish limitations for FGD wastewater using sitespecific BPJ. See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 

6. EPA notes that permitting authorities could still apply water quality based effluent limits 

(WQBELs) for sulfate when appropriate, see preamble section XVI.D for more discussion on 

WQBELs.

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: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

With respect to baseline pollutant loadings for bottom and fly ash, over half of the pollutants 

(measured as toxic-weighted pounds equivalent or “TWPE”) that EPA asserts are being 

discharged to ash ponds are, at best, theoretical, and likely nonexistent. EPA’s analysis of fly ash 

and bottom ash transport water includes estimated TWPEs for sulfides based on reported values 

that were almost all below the detection limit. EPA interpreted those results using the limit of 

detection as the actual value, thus creating pollutant loadings that are not supported by the 

reported values. This plus other data manipulations discussed below resulted in an EPAdeveloped TWPE for ash ponds that is six times too large. Hence, any reliance on such an 

analysis is arbitrary and capricious.

Comment Response: 

Following proposal, EPA expanded its bottom ash and fly ash characterization datasets. See 

Section 6.6.4 of the TDD for a description of the characterization data used to identify POCs in 

ash and Section 10.2.2 for a description of ash impoundment data. As described in those sections 

and shown in Table 10-7, both fly ash and bottom ash transport water contains a variety of 

metals, as well as other pollutants such as nitrogen compounds, sulfate, and total dissolved 

solids.
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Regarding sulfides, EPA chose not to calculate loadings for sulfides in the analyses for the final 

rule.

For comments on TWPE calculations for ash transport water, see response to DCN EPA-HQOW-2009-0819-4499-A1, Excerpt Number 72 in comment code 15.d.

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: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Sulfur is likely to be a pollutant of concern in Publicly Owned Treatment Works (POTWs). 

ACWA recommends that EPA consider establishing PSES and PSNS limits on flue gas 

desulfurization wastewater discharges. Section 10.2.1 of EPA’s Technical Development 

Document mentions possible treatment standards for sulfate, but the proposed rule does not 

include any such limits for §§ 423.16-.17.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3922-A1, Excerpt Number 4.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 120

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

L. The Proposed Nitrate/Nitrite FGD Wastewater Limit Is Inappropriate

EPA based its FGD wastewater limits on effluent data from Allen and Belews Creek only. As 

we have shown, the nitrate/nitrite levels in Allen’s and Belews Creek’s influent is very low 

compared to levels at other plants.

Plants with higher nitrate/nitrite levels in the influent could not operate biological treatment 

systems in the same manner as Allen and Belews Creek. Because of the increased 
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nitrates/nitrites, these plants would be forced to either increase the size of the biological 

treatment system or increase retention time within the system. They would also have to increase 

the amount of nutrient feed added to the system.

EPA has not accounted for the additional costs of either sizing up the biological treatment system 

or increasing retention time within the system. It has also not demonstrated that a biological 

treatment system used to treat an influent with high nitrate/nitrite and selenium can meet the 

proposed limits. For these reasons, EPA should not set any nitrate/nitrite limits for FGD 

wastewater.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 20 in Comment 

Code 26.f regarding biological treatment of FGD wastewater containing higher nitrate/nitrite 

levels.

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: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Inclusion of nitrate/nittite in the Biological Treatment standard for FGD appears to be for use as 

an indicator of how the anaerobic treatment is performing. Inour state, this would be considered 

a control test but not a permit limit. This inclusion could lead to unintended consequences in 

both implementation and enforcement of a new ELG and could ultimately result in control tests 

for other industry sectors and municipalities to become permit conditions.

Comment Response: 

EPA did not include nitrate/nitrite is as “an indicator of how the anaerobic treatment is 

performing.” EPA selected nitrate/nitrite as regulated pollutants to control the discharge of 

nitrate/nitrite of these pollutants (see TDD Section 11).

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 20 in Comment 

Code 26.f regarding biological treatment of FGD wastewater containing higher nitrate/nitrite 

levels.
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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: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Additionally, the inclusion of nitrate/nitrite in the Biological Treatment standard for FGD 

appears to be included for use as an indicator of how the anaerobic treatment is 

performing. Such an inclusion could lead to unintended consequences in both implementation 

and enforcement of a new ELG.

Comment Response: 

EPA did not include nitrate/nitrite is as “an indicator of how the anaerobic treatment is 

performing.” EPA selected nitrate/nitrite as regulated pollutants to control the discharge of 

nitrate/nitrite of these pollutants (see TDD Section 11).

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 20 in Comment 

Code 26.f regarding biological treatment of FGD wastewater containing higher nitrate/nitrite 

levels.

Commenter Name: Paul Chu

Commenter Affiliation: Electric Power Research Institute (EPRI)

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

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The nitrate/nitrite pollutant removals are an incidental benefit of the selenium removal.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 20 in Comment 

Code 26.f regarding biological treatment of FGD wastewater containing higher nitrate/nitrite 

levels.
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Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 17

External Review Flag: Statistics

External Review Incorporated into Response: No

Comment Excerpt: 

In addition to our concerns about achieving parity with non-point sources, it is not clear in the 

record that these limits were correctly set or that the additional costs to meet the nitrate- nitrite 

limits were correctly calculated by EPA. Presumably, nitrate-nitrite limits would have to be met 

before selenium would be removed by biological treatment.

It appears that the nitrate-nitrite limits have been included solely as an indicator of how the biotreatment system is performing. This is insufficient justification for implementing a BAT limit. 

The TWPE loadings for nitrate-nitrite are relatively insignificant in comparison to the totals for 

FGD discharges. Based on EPA estimates, these chemical species account for less than 5% of the 

TWPE removed.

Comment Response: 

EPA did not include nitrate/nitrite is as “an indicator of how the biotreatment system is 

performing.” EPA selected nitrate/nitrite as regulated pollutants to control the discharge of 

nitrate/nitrite of these pollutants. EPA notes that TWPE removal is not a criterion for selecting 

regulated pollutants (see TDD Section 11).

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 20 in Comment 

Code 26.f regarding biological treatment of FGD wastewater containing higher nitrate/nitrite 

levels.

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

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

Comment Excerpt Number: 50

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Bottom Ash Transport Water Contains Few Pollutants and Requiring Conversion to Dry or 

Closed Loop Bottom Ash Handling in the Industry Fails Any Rational Cost-Effectiveness 

Analysis.
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At the outset, it is noteworthy that EPA erroneously concluded that the pollutants of concern are 

the same for both fly ash and bottom ash transport waters. EPA made this flippant conclusion 

without even analyzing available data for bottom ash transport water. Inexplicably foregoing this 

review, the agency instead made the bald assertion that the surrogate pollutants for both fly ash 

and bottom ash transport waters are the same because they are “primarily derived” from the type 

of coal burned, with presumably the same chemical constituents found in each of the wastewater 

streams. See ERG Pollutants of Concern Methodology Memorandum, EPA-HQ- OW-2009-

0819-2151, at 10. This assertion is squarely contradicted by EPA’s own data, however. UWAG 

provides a complete analysis of this discrepancy in its comments to the Draft Rule, which 

PowerSouth incorporates as if fully set out herein. See UWAG Comments at Section V., M. 

Suffice it to say, EPA’s decision to conflate the pollutants of concern for these two distinct waste 

streams was arbitrary and capricious and mars any additional analysis by the agency founded 

upon this flawed contention.

Further compounding this fallacy is that the agency did not even follow its established procedure 

for selecting pollutants of concern in this instance. EPA typically requires a pollutant to be 

detected in at least three samples before it can permissibly be labeled a pollutant of concern. See, 

e.g., 66 Fed. Reg. 424, 446 (Jan. 3, 2001) (“EPA reduced the list of 329” analyzed pollutants “to 

132 pollutants (referred to as pollutants of concern or POCs) for further consideration by 

retaining only those pollutants that met the following criteria: EPA detected the pollutant 

parameter in at least three samples collected during the MP&M sampling program”); EPA 

Development Document for Proposed Effluent Limitations Guidelines and Standards for the 

Landfills Point Source Category, EPA-821-R-97-022, at 7-2 (EPA applied the following criteria 

to develop a list of pollutants for further evaluation in each subcategory: 1. EPA determined 

“[a]ny pollutant detected three or more times in the influent at a concentration at or above 5 

times the minimum level”). Yet, EPA did not even collect three samples for its analysis of 

pollutants of concern for ash transport water. See ERG Pollutants of Concern Methodology 

Memorandum, EPA-HQ-OW-2009-0819-2151, Table 4-3 at 8-9. Thus, many of the 24 identified 

pollutants of concern for ash transport waters are erroneously based on scant data that do not 

even comply with EPA’s standard practices.

EPA also failed to account for, or properly subtract, minerals or treatment chemicals from its list 

of pollutants of concern when those markers are naturally occurring compounds found in water 

supply sources. The agency has typically done so in the past, see, e.g., EPA Development 

Document for Proposed Effluent Limitations Guidelines and Standards for the Landfills Point 

Source Category, EPA-821-R-97-022, at 7-2 (EPA excluded “[p]ollutants that are naturally 

occurring compounds found in soil or groundwater at landfill facilities or pollutants that are used 

as treatment chemicals in this industry were excluded from the pollutants of interest list”), and 

failed to provide a justifiable reason for its failure to do so in this Draft Rule.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment 

Code 15.d and response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in 

Comment Code 4.b.
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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: 47

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Erroneous Methodology Used to Classify Bottom Ash Pollutants of Concern.

We Energies objects to the methodology EPA used to classify the pollutants of concern for 

bottom ash transport water. As described in the TDD (emphasis added):

EPA did not collect data representing fly ash or bottom ash transport water entering an 

impoundment during the sampling program for the rulemaking. However, during EPA’s detailed 

study of the industry, EPA collected a wastewater sample representing the influent to a fly ash 

impoundment. 2013 TDD at 6-10.

EPA sampled untreated fly ash sluice at one plant during the steam electric detailed study. EPA 

reviewed the untreated fly ash transport water data from this plant (one sampling point and one 

sample) to identify POCs for fly ash transport water...[T]he criterion EPA used as a screening 

tool to identify pollutants of concern is less applicable in cases where the technology basis 

results in complete removal of all pollutants present, such as would occur under the technology 

options considered for fly ash transport water, bottom ash transport water, and FGMC 

wastewater. For these “zero discharge” technologies, confirmation that a pollutant is present 

in the wastestream at quantifiable levels may be sufficient to identify a pollutant as a pollutant of 

concern...

Constituents present in ash, and therefore ash transport water, are primarily derived from the 

type of coal/petroleum coke burned; therefore... EPA expects that the bottom ash transport 

water will have the same constituents that are found in the fly ash transport water. For this 

reason, the POCs for bottom ash transport water are identical to those of fly ash transport 

water. Id. at 6-28 – 6-29.

EPA only sampled one fly ash transport water sample from one plant to characterize ash 

transport water across the entire industry. Further, EPA states that they did not sample a bottom 

ash transport water sample and made an assumption that bottom ash transport water would have 

the same constituents found in fly ash transport water. Thus, EPA did not confirm that the 

pollutants in bottom ash transport water were present in the wastestream at quantifiable levels. 

We Energies believes the methodology EPA used to classify the pollutants of concern for bottom 

ash transport water was flawed. A better approach would be to take samples of bottom ash 

transport water from several sites across the industry (to ensure that the data is representative) 

and confirm pollutants are in the wastestreams at quantifiable levels.
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Comment Response: 

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

Code 6.a and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 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: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. Bottom Ash Transport Water Contains Few Pollutants and Requiring Conversion to 

Dry or Closed Loop Bottom Ash Handling in the Industry Fails Any Rational CostEffectiveness Analysis

EPA’s assumption that the pollutants of concern for bottom ash transport waters are the same as 

those for fly ash transport waters is erroneous. EPA made this assumption without analyzing 

available data for bottom ash transport water. Instead, the agency based its assumption on the 

premise that the surrogate pollutants for both fly ash and bottom ash transport waters must be the 

same because they are “primarily derived” from the type of coal burned, with presumably the 

same chemical constituents found in each of the wastewater streams. See Eastern Research 

Group, Inc.’s (“ERG”) Pollutants of Concern Methodology Memorandum, EPA-HQ-OW-2009-

0819-2151, at 10. This assumption is squarely contradicted by EPA’s own data, as UWAG 

demonstrates in in its comments to the Proposed Rule. See UWAG Comments at Section V., M. 

Alabama Power, therefore, incorporates those comments as if fully set out herein. EPA’s 

erroneous conflation of the pollutants of concern for two distinct waste streams is arbitrary and 

capricious and, consequently, undermines the agency’s analysis based upon this flaw.

Further undermining EPA’s analysis of this waste stream is the fact that the agency failed to 

follow its own, well-established procedure for selecting pollutants of concern. While EPA 

typically requires a pollutant to be detected in at least three samples before it can permissibly be 

labeled a pollutant of concern,1 EPA did not collect three samples for its analysis of ash 

transport water. See ERG Pollutants of Concern Methodology Memorandum, EPA-HQ-OW2009-0819- 2151, Table 4-3 at 8-9. Because many of the 24 pollutants of concern for ash 

transport waters were identified based on scant data that does not even comply with EPA’s 

standard practices, they cannot be considered.

Another flaw in EPA’s analysis is its failure to account for, or otherwise remove, those minerals 

or treatment chemicals on its list of pollutants of concern when those markers are naturally 
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occurring compounds found in water supply sources. While the agency has typically done this in 

the past,2it failed to provide a justifiable reason for its failure to do so in this Proposed Rule.

1 See, e.g., 66 Fed. Reg. 424, 446 (Jan. 3, 2001) ("EPA reduced the list of 329" analyzed 

pollutants "to 132 pollutants (referred to as pollutants of concern or POCs) for 

further consideration by retaining only those pollutants that met the following criteria: EPA 

detected the pollutant parameter in at least three samples collected during the MP&M sampling 

program”); EPA Development Document for Proposed Effluent Limitations Guidelines and 

Standards for the Landfills Point Source Category, EPA-821-R-97-022, at 7-2 (EPA applied the 

following criteria to develop a list of pollutants for further evaluation in each subcategory: 1. 

EPA determined “[a]ny pollutant detected three or more times in the influent at a concentration 

at or above 5 times the minimum level”).

2 See, e.g., EPA Development Document for Proposed Effluent Limitations Guidelines and 

Standards for the Landfills Point Source Category, EPA-821-R-97-022, at 7-2 (EPA excluded 

“[p]ollutants that are naturally occurring compounds found in soil or groundwater at landfill 

facilities or pollutants that are used as treatment chemicals in this industry were excluded from 

the pollutants of interest list”).

Comment Response: 

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

Code 6.a and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d.

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: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 19

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Constituent Concentrations Differ Greatly

It is concerning that EPA did not use readily available data for untreated bottom ash transport 

water in identifying the pollutants of concern and that EPA concluded incorrectly that the 

pollutants of concern for bottom ash transport water were identical to the pollutants of concern 
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identified for fly ash transport water. There were 91 facilities operating bottom ash 

impoundments. This information is contained in applications to renew NPDES permits and 

demonstrate that discharges of bottom ash transport water do not warrant the same level controls 

as discharges of fly ash transport water.

The 2009 Detailed Study indicates that the constituents present in ash, and therefore fly or 

bottom ash transport water, are primarily derived from the type of coal/petroleum coke burned; 

therefore, as discussed in Section 6.2.3, EPA expects that the bottom ash transport water will 

have the same constituents that are found in the fly ash transport water. For this reason, the 

pollutants for bottom ash transport water are “identical” to those of fly ash transport water. This 

is simply not accurate.

Generally, the primary pollutants included in the proposed ELG for fly ash and bottom ash 

include:

1. Arsenic (As),

2. Mercury (Hg),

3. Selenium (Se), and

4. Total nitrogen (TN).

It is widely known that the most volatile trace elements in coal during the combustion process 

are As, Hg, and Se. It is also widely known that the primary source of nitrogen compounds is 

added to the flue gas in the form of ammonia. Therefore, EPA should expect that these same 

constituents would be most prevalent in fly ash, not in bottom ash.

A comparison of the Toxicity Characteristic Leaching Procedure (TCLP) and other TN results 

for fly and bottom ash generated at three NRG stations in 2010, 2011, or 2012 does not support 

EPA’s expectations.

Fly & Bottom Ash Constituent Comparison

NRG

Plant

Fly Ash 

(mg/l)

Bottom 

Ash

(mg/l)

Fly Ash 

(mg/l)

Bottom 

Ash

(mg/l)

Fly Ash 

(mg/l)

Bottom 

Ash

(mg/l)

Fly Ash

(mg/l)

Bottom 

Ash

(mg/l)

As As Hg Hg Se Se TN TN

A 0.08 <0.02 <0.0002 <0.0002 <0.02 <0.02 ND ND

B 0.46 <0.02 <0.0002 <0.0002 <0.02 <0.02 ND ND

C 0.174 <0.02 0.0003 <0.0002 0.05 <0.02 3.7 ND
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Notes: Not detected (ND): Ammonia Nitrogen, Nitrate Nitrogen, & Nitrite Nitrogen. “Less than” 

values represent the laboratory quantitation limits.

The table below includes NRG data and data from Table 5-9 from the 2009 Detailed Study, 

which presented the pollutant concentrations representing the effluent from fly ash and bottom 

ash ponds collected during EPA’s sampling program. These plants and impoundments include:

 Widows Creek: combined fly ash and bottom ash pond system.

 Cardinal and Mitchell: fly ash pond systems.

 Homer City: bottom ash pond system.

 Cheswick and Avon Lake: bottom ash pond systems.

Ash Pond Effluent Concentrations

Analyte

Widows 

Creek (FA 

& BA)

Cardinal 

(FA)

Mitchell 

(FA)

Homer City 

(BA)

Cheswick 

(BA) Avon Lake (BA)

Flow 29.9 7.8 7.8 0.453 0.246 0.655

As 34.9 69.8 142 6.52 14 3.3

Hg 0.00157 0.00125 0.00212 0.00511 <0.1 0.002*

Se 17.1 45.8 191 5.74 <10 <4.11

(In MGD or μg/l) *Intake water from Lake Erie contributes an average of 0.0015 μg/l of mercury 

to the bottom ash transport water.

As calculated from the summary in the above table, the metals mass loading concentrations from 

fly ash pond systems are up to 600 times greater than the mass loading concentrations from 

bottom ash pond systems. Mercury concentrations are low in either case and can sometimes be 

associated with the surface water providing makeup water to the ash sluice system. The quality 

of these effluents from bottom ash systems may meet the proposed BAT for FGD wastewater.

The 2013 TDD noted that in recent years, physical/chemical treatment systems and other more 

advanced systems have become more widely used in FGD system as effluent limits for metals 

and other pollutants have been included in permits. As indicated, in nearly all cases this was 

driven by the need to use such technologies to meet WQBELs established to meet applicable 

water quality standards in the receiving waters. This same advancement in technologies has not 

occurred for discharges of bottom ash transport water most likely due to the relatively low 

concentrations.

EPA should carefully review this type of easily ascertainable data before equating bottom ash 

discharges to fly ash discharges. We believe that after such review, EPA would not seek to 

establish a zero discharge requirement for bottom ash transport water.

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

Code 6.a. See also Table 10-7 in the TDD for the average pollutant concentrations calculated for 

each type of ash impoundment using EPA’s updated dataset.

Also see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment 

code 15.d.

Commenter Name: Paul Carpmone

Commenter Affiliation: Tampa Electric Company (TEC)

Document Control Number: EPA-HQ-OW-2009-0819-4520-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Bottom Ash Data, Assumptions, and Analysis Flawed

For the purposes of this rulemaking, EPA has improperly characterized bottom ash transport 

water. EPA states that data for bottom ash was not readily available, but

"...because the pollutants found in bottom ash are constituents present in the coal . ..as is the 

case for fly ash, EPA concluded that the pollutants of concern for bottom ash transport water are 

identical to pollutants of concern identified for fly ash transport water." (78 Fed. Reg. at p. 

34,455 col 3)

This assumption is invalid since, although the constituents may be similar (not identical), they 

may exist in different chemical phases and in different concentrations. In general, bottom ash 

contains fewer pollutants of concern than fly ash and a greater percentage of inerts. Since the 

majority of the data that EPA used for rulemaking was taken from combined ash facilities, this 

assumption of identical constituents is convenient for the purposes of analysis, but incorrect.

On page 6-10 of the Technical Development Document for the Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category 

April2013 (Technical Development Document), EPA states that it took "a wastewater sample 

representing the influent to a fly ash impoundment...." No similar sample was taken to represent 

influent to a bottom ash impoundment during EPA's "detailed study of the industry" that 

occurred prior to the sampling period associated with the rulemaking. It is unlikely that a single 

sample is representative of fly ash ponds or bottom ash ponds industry-wide. EPA culled the rest 

of the data used for bottom ash from combined ash ponds, which also do not accurately reflect 

the characterization of bottom ash ponds and would prejudice the analyses used to establish these 

guidelines.
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Bottom ash differs from fly ash (and from combined ash) and to assume that the chemical and 

physical characteristics of the transport water are the same or that sampling results are equivalent 

is erroneous, as are the results of any analyses that use these data and assumptions.

The dubious assumptions and the flawed analytical procedures utilized for the proposed rule call 

into question the conclusions that EPA has reached and represents serious technical flaws. TEC 

urges EPA to revisit this portion of the proposed rule and to establish a protocol for obtaining 

more accurate data prior to moving forward.

Comment Response: 

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

Code 6.a. EPA disagrees that bottom ash impoundments contain fewer pollutants of concern; as 

described in Section 6.6.4 of the TDD, EPA identified 38 POCs for fly ash transport water and 

37 POCs for bottom ash transport water.

Also see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment 

code 15.d.

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: 47

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

At the outset, it is noteworthy that EPA concluded in error that the pollutants of concern are the 

same for both fly ash and bottom ash transport waters. EPA reached this conclusion without 

analyzing available data for bottom ash transport water. Inexplicably foregoing this review, the 

agency instead made the assertion that the surrogate pollutants for both fly ash and bottom ash 

transport waters are the same because they are “primarily derived” from the type of coal burned, 

with presumably the same chemical constituents found in each of the waste water streams. See 

ERG Pollutants of Concern Methodology Memorandum, EPA-HQ-OW-2009- 0819-2151, at 10. 

This assertion is squarely contradicted by EPA’s own data, however. UWAG provides a 

complete analysis of this discrepancy in its comments to the Proposed Rule, which PSNH 

incorporates as if fully set out herein. See UWAG Comments at Section V., M. Suffice it to say, 

EPA’s decision to conflate the pollutants of concern for these two distinct waste streams was 

arbitrary and capricious and mars any additional analysis by the agency founded upon this 

flawed contention.

To make matters worse, the agency did not even follow its established procedure for selecting 

pollutants of concern in this instance. EPA typically requires a pollutant to be detected in at least
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three samples before it can permissibly be labeled a pollutant of concern. See, e.g., 66 Fed. Reg. 

424, 446 (Jan. 3, 2001) (“EPA reduced the list of 329” analyzed pollutants “to 132 pollutants 

(referred to as pollutants of concern or POCs) for further consideration by retaining only those 

pollutants that met the following criteria: EPA detected the pollutant parameter in at least three 

samples collected during the MP&M sampling program”); EPA Development Document for 

Proposed Effluent Limitations Guidelines and Standards for the Landfills Point Source Category, 

EPA-821-R-97-022, at 7-2 (EPA applied the following criteria to develop a list of pollutants for 

further evaluation in each subcategory: 1. EPA determined “[a]ny pollutant detected three or 

more times in the influent at a concentration at or above 5 times the minimum level”). Yet, EPA 

did not even collect three samples for its analysis of pollutants of concern for bottom ash 

transport water. See ERG Pollutants of Concern Methodology Memorandum, EPA- HQ-OW2009-0819-2151, Table 4-3 at 8-9. Thus, many of the 24 identified pollutants of concern for 

bottom ash transport waters are erroneously based on scant data that do not even comply with 

EPA’s standard practices.

EPA also failed to account for, or properly subtract, minerals or treatment chemicals from its list 

of pollutants of concern when those markers are naturally occurring compounds found in water 

supply sources. The agency has typically done so in the past, see, e.g., EPA Development 

Document for Proposed Effluent Limitations Guidelines and Standards for the Landfills Point 

Source Category, EPA-821-R-97-022, at 7-2 (EPA excluded “[p]ollutants that are naturally 

occurring compounds found in soil or groundwater at landfill facilities or pollutants that are used 

as treatment chemicals in this industry were excluded from the pollutants of interest list”), and 

failed to provide a justifiable reason for its failure to do so in this Proposed Rule.

Comment Response: 

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

Code 6.a 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: 66

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

M. EPA Incorrectly Concludes that Bottom Ash Transport Water Pollutants of Concern 

Are the Same as Those for Fly Ash Transport Water

Moving beyond the cost-effectiveness analysis, we turn to EPA’s decisions on pollutants of 

concern for bottom ash transport water. Since pollutants of concern are those evaluated for the 
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setting of limits, it is important that EPA’s selection process be valid, and therefore it merits 

careful review.

EPA’s approach to identifying pollutants of concern for bottom ash transport water is arbitrary 

because it is not based on characterization data for bottom ash transport water. Although EPA 

had several sources of bottom ash transport water characterization data available to it (including 

its Homer City sample and the EPRI PISCES Site F data), EPA says it was “unable to obtain 

readily available data for untreated bottom ash transport water for use in identifying the 

pollutants of concern. . . .” 78 Fed. Reg. at 34,455 col. 3. EPA concludes that “the pollutants of 

concern for bottom ash transport water are identical to the pollutants of concern identified for fly 

ash transport water.” Id. EPA believes that the same 24 pollutants of concern it identified for fly 

ash transport water are appropriate to use as surrogate pollutants of concern for bottom ash. EPA 

explains this decision in two sentences:

Constituents present in ash, and therefore ash transport water, are primarily derived from the type 

of coal/petroleum coke burned; therefore, EPA expects that the bottom ash transport water will 

have the same constituents that are found in the fly ash transport water. For this reason, EPA 

assumed that the [pollutants of concern] for bottom ash transport water are identical to those of 

fly ash transport water.

ERG, Pollutants of Concern Methodology Memorandum, EPA-HQ-OW-2009-0819-2151 at 10.

This conclusion is unwarranted. Even a cursory glance at EPA’s own data shows that bottom 

ash transport water is very different from fly ash transport water. EPA published its 

characterization data for the Homer City power plant bottom ash sample and its sample of fly ash 

transport water from Cardinal power plant in its 2009 Final Detailed Study, EPA-HQ-OW-2009-

0819-0004, Table 5-9 (Detailed Study). As shown in the tables below, the Homer City bottom 

ash transport water sample and the Cardinal fly ash transport water sample are vastly different.

Analyte Method Homer City Bottom Ash 

Pond Effluent (ug/L)

Cardinal Fly Ash Pond 

Effluent (ug/L)23,24

Routine Metals – Total 

Antimony 200.7 NQ (20.0) 21.2

Arsenic 200.7 NQ (10.0) 77.6

Lead 200.7 ND (50.0) ND (50.0)

Mercury 245.1 ND (0.200) ND (0.200)

Molybdenum 200.7 19.7 361

Selenium 200.7 6.02 44.5

Vanadium 200.7 NQ (20.0) 104

Routine Metals – Dissolved

Antimony 200.7 NQ (20.0) 20.9

Arsenic 200.7 NQ (10.0) 74.6

Lead 200.7 ND (50.0) ND (50.0)
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Analyte Method Homer City Bottom Ash 

Pond Effluent (ug/L)

Cardinal Fly Ash Pond 

Effluent (ug/L)23,24

Mercury 245.1 ND (0.200) ND (0.200)

Molybdenum 200.7 20.2 352

Selenium 200.7 6.10 L 43.8

Vanadium 200.7 NQ (20.0) 99.9

L – Sample result between 5x and 10x blank result

The Cardinal fly ash transport water effluent is significantly higher in antimony, arsenic, 

selenium, molybdenum, and vanadium in both total and dissolved metals measured by routine 

methods, than the Homer City bottom ash transport water. For lead and mercury, the Homer 

City and Cardinal samples are non-detects for total and dissolved methods, using routine 

analytical methods.

Using low-level methods the result is similar: the Cardinal fly ash effluent is significantly higher 

in antimony, arsenic, and selenium for both total and dissolved metals than the Homer City 

sample. For lead and mercury, the results are low and fairly similar.25

Analyte Method Homer City Bottom Ash 

Pond Effluent (ug/L)

Cardinal Fly Ash Pond 

Effluent (ug/L)

Low-Level Metals – Total 

Antimony 1638 1.09 21.9

Arsenic 1638 6.52 69.8

Lead 1638 NQ (0.250) 0.420

Mercury 1631E 0.00511 0.00125

Selenium 1638 5.74 45.8

Low-Level Metals – Dissolved

Antimony 1638 0.990 22.4

Arsenic 1638 5.00 68.9

Lead 1638 NQ (0.250) NQ (0.250)

Mercury 1631E 0.00141 NQ (0.0005)

Selenium 1638 5.16 45.0

EPA has given no sound reason for neglecting to use the available bottom ash transport water 

data to determine pollutants of concern. Since there is bottom ash transport water available, 

substituting fly ash transport water is unjustified.

N. EPA Failed to Apply Its Traditional Criteria for Selecting Pollutants of Concern (POCs)

Besides ignoring the available bottom ash transport water data, EPA also deviated from its 

traditional criteria for selecting pollutants of concern (POCs) in bottom ash transport water.
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First, EPA normally requires that a pollutant of concern be detected in at least three 

samples. See 66 Fed. Reg. 424, 446 col. 3 (Jan. 3, 2001) (“EPA reduced the list of 329” 

analyzed pollutants “to 132 pollutants (referred to as pollutants of concern or POCs) for further 

consideration by retaining only those pollutants that met the following criteria: EPA detected the 

pollutant parameter in at least three samples collected during the MP&M sampling program”); 

EPA, “Development Document for Proposed Effluent Limitations Guidelines and Standards for 

the Landfills Point Source Category,” EPA-821-R-97-022 (January 1998) (Proposed Landfills 

TDD) at 7-2 (available at http://water.epa.gov/scitech/wastetech/guide/landfills/techdev.cfm) 

(EPA applied the following criteria to develop a list of pollutants for further evaluation in each 

subcategory: 1. EPA determined “[a]ny pollutant detected three or more times in the influent at 

a concentration at or above 5 times the minimum level...”).

For the ash transport water POC analysis, which EPA used to determine POCs for both bottom 

ash and fly ash transport water, EPA did not even collect three samples. As a result, EPA 

selected its POCs based on only two samples for 12 metals and only one sample for the 

remaining 26 pollutants. ERG POC Methodology Memorandum, EPA-HQ-OW-2009-0819-

2151, Table 4-3 at 8, 9. Even if EPA had not wanted to rely on its single sample of bottom ash 

transport water from Homer City, it seems illogical to use the EPRI PISCES Site F bottom ash 

transport water data to develop TWPEs but to ignore it for purposes of selecting POCs. And, as 

already noted, EPA could easily have collected additional bottom ash transport water samples if 

it had wanted to have three or more samples for purposes of the POC determination.

As a result, 15 of the 24 ash transport water POCs are based on detection in a single 

sample. Id. This is contrary to EPA’s own protocol, arbitrary, and provides a weak foundation 

for EPA’s POC decisions.

Second, in previous effluent guidelines EPA has been careful to remove any naturally occurring

non-toxic minerals or treatment chemicals from the POC selection. See, e.g., the Proposed 

Landfills TDD at 7-2 (EPA excluded “[p]ollutants that are naturally occurring compounds found 

in soil or groundwater at landfill facilities or pollutants that are used as treatment chemicals in 

this industry were excluded from the pollutants of interest list”). In the MP&M ELG, EPA 

excluded sodium, calcium, and total dissolved solids because they are found in water treatment 

chemicals. EPA also excluded cyanide when it was not from operations that used 

cyanide. Similarly chromium, hexavalent chromium, lead, and cadmium where excluded. EPA 

makes no such adjustments to the current ash transport water POCs.

Third, EPA apparently bases its POC for nitrate/nitrite on data only from the Cardinal fly ash 

transport water sample, as the reference for Table 4-3 in ERG’s POC Methodology 

memorandum is to the “Cardinal Sampling Data, [ERG, 2008].” EPA-HQ-OW-2009-0819-2151 

at 9. However, EPA failed to analyze the Cardinal nitrate/nitrite sample within the correct 

holding time. See Detailed Study, Table 5-9 at 5-20. Therefore 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. EPA should have thrown out that value rather than using it to establish a POC. Similarly, 

the Cardinal results for chromium (low-level metals total and dissolved) should not be used to 

establish a POC because EPA flagged those data points as “between 5x and 10x blank 

result.” Detailed Study, Table 5-9 at 5-20. This calls these data into question. Any questionable 
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EPA’s Response to Public Comments

4-85

data should be thrown out and not used for POC selection, particularly when the selection is 

based on only two samples.

23 We used Cardinal as the reference point for fly ash transport water because the other two 

plants EPA presents data for in Table 5-9 would be inappropriate to use. The results for Widows 

Creek are for a combined bottom ash and fly ash pond and thus not representative of fly ash 

transport water. The results for Mitchell would not be representative because Mitchell’s ash 

pond receives effluent from a coal washing facility and treated acid mine drainage. EPA Final 

Detailed Study at 5-16.

24 Homer City and Cardinal burn different types of coal. Homer City burns Eastern bituminous 

while Cardinal burns subbituminous. The coal type has an effect on trace metal concentrations 

in the ash; this is another reason why EPA should have collected more representative samples of 

bottom ash transport water and fly ash transport water.

25 The low-level metals analysis in the Final Detailed Study does not include molybdenum or 

vanadium values. See Detailed Study, Table 5-9.

Comment Response: 

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

Code 6.a. In addition, EPA removed the Cardinal data from the final dataset because it did not 

meet EPA’s requirement that sampling locations represent at least 75% fly ash or bottom ash 

transport water and not be represented by combined fly ash and bottom ash impoundments or 

impoundments diluted with other waste streams.

Also see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment 

code 15.d.

Commenter Name: Nancy A. Evans

Commenter Affiliation: PPL Services Corporation

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

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

It should be noted that EPA’s characterization of bottom ash transport water is completely 

inaccurate. EPA states in the preamble that bottom ash includes the same levels of toxics as fly 

ash. This is simply not supported by the data. The data EPA used to make this assumption does 

not reflect transport water that contained only bottom ash.
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Comment Response: 

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

Code 6.a and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 83

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Proposed Arsenic Limits are Inappropriate

EPA has proposed very stringent limits for arsenic based on chemical precipitation treatment. 

Those proposed limits are 6 μg/L monthly average and 8 μg/L daily maximum. EPA developed 

limits based on sampling data from three plants with chemical precipitation treatment -

Hatfield’s Ferry, Miami Fort and Keystone. Figure 6 provides the dissolved arsenic influent 

concentrations and the total arsenic effluent concentrations of the chemical precipitation 

treatment system for the three plants. The dissolved arsenic concentrations in the influent, 

ranging from < 4 to 11 μg/L, are very close, if not the same, as the total arsenic in the chemical 

precipitation effluent. In fact, in most instances (10 out of 12 data points), the dissolved arsenic 

influent is present at concentrations below the proposed limits of 6 and 8 μg/L.

Figure 6: Arsenic Concentrations in Selected Plants - Influent (Dissolved) and Chemical 

Precipitation Effluent (Total)
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EPA’s Response to Public Comments

4-87

In addition, the settled arsenic levels (baseline) in the influent to the treatment system is not a 

pollutant of concern (POC) based on EPA’s own POC criteria. 2013 TDD p. 6-24 to 6-28. In 

other words, the influent arsenic levels at the BAT plants are not present at high enough 

concentrations to evaluate the effectiveness of the chemical precipitation treatment system.

According to EPA34, it “reviewed the untreated FGD wastewater data for these 

seven plants35 (total of seven sampling points and 28 samples) to identify FGD wastewater 

POCs.” To identify POCs (i.e., pollutants that are present in sufficient concentrations to quantify 

the degree of pollutant removal resulting from treatment processes), EPA applied two criteria:

1. Eliminate from consideration any pollutants that were never detected in the untreated 

wastewater samples, and

2. Identify pollutants detected at greater than or equal to 10 times the basline value in at 

least 10 percent of all untreated wastewater samples.

EPA used a baseline value of 2.0 μg/L arsenic which is based on an MDL study conducted by 

EPA36. By applying the above criteria to untreated FGD wastewater from the seven plants (28 

data points) to a baseline value of 2.0 μg/L arsenic, EPA concluded that arsenic is a POC 

because 100% of the sample results are greater than 10 times the baseline value.37

However, based on Southern’s analysis of the same 28 arsenic data points using EPA’s own 

criteria, arsenic in FGD wastewater is not a POC. Table 18 provides the 28 data points for 

dissolved, total and settled arsenic in the influent to the chemical precipitation treatment systems. 

Both the dissolved and the settled arsenic concentrations in the influent do not meet the POC 

criteria. The settled influent represents the baseline for the industry (i.e., effluent from a settling 

pond). EPA mistakenly used the total arsenic influent data which represents FGD wastewater 

prior to treatment by a settling pond. Since plants currently treat FGD wastewater at a minimum 

with a settling pond, the removal of particulate arsenic by settling ponds should not have been 

included in EPA’s POC analysis. If settled arsenic influent data are used in the POC analysis, 

then arsenic would not qualify as a POC, and therefore, no limitations or standards would have 

been proposed. Because arsenic is not a POC by EPA’s own criteria, the proposed arsenic limits 

for FGD wastewater are invalid, because treatability of settled arsenic at the BAT plants or 

at any of the seven plants is not demonstrated.

Table 18: Arsenic Pollutant of Concern Analysis of FGD Wastewater Using EPA’s POC 

Methodology

Plant Name Sample 

SP-1 

Influent 

Dissolved

SP-1 

Influent 

Total

SP-1 

Influent 

Settled

≥ 10 Times 

the 

Baseline 

Dissolved

≥ 10 Times 

the 

Baseline 

Total

≥ 10 Times 

the 

Baseline 

Settled

Belews Creek Day 1 2

3

270 4.6 No Yes No

Belews Creek Day 2 2

3

230 3.4 No Yes No

Belews Creek Day 3 4.8 240 6.9 No Yes No

Belews Creek Day 4 4.3 200 6.6 No Yes No

Allen Day 1 8.7 120 10.6 No Yes No
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Allen Day 2 10 140 11.0 No Yes No

Allen Day 3 10 140 12.0 No Yes No

Allen Day 4 7.1 140 8.9 No Yes No

Dickerson Day 1 2

3

280 4.1 No Yes No

Dickerson Day 2 2

3

220 2.6 No Yes No

Dickerson Day 3 2

3

190 3.4 No Yes No

Dickerson Day 4 2

3

230 3.8 No Yes No

Miami Fort Day 1 4.4 937 6.1 No Yes No

Miami Fort Day 2 4.9 896 5.8 No Yes No

Miami Fort Day 3 6.6 1,310 8.6 No Yes No

Miami Fort Day 4 5.5 695 6.6 No Yes No

Hatfield’s 

Ferry Day 1 5.2 2,300 6.5 No Yes No

Hatfield’s 

Ferry Day 2 11 4,610 13.1 No Yes No

Hatfield’s 

Ferry Day 3 5.1 2,150 6.1 No Yes No

Hatfield’s 

Ferry Day 4 7.7 2,830 9.5 No Yes No

Pleasant 

Prairie Day 1 7.2 150 8.3 No Yes No

Pleasant 

Prairie Day 2 6.9 160 7.5 No Yes No

Pleasant 

Prairie Day 3 7.7 140 8.9 No Yes No

Pleasant 

Prairie Day 4 7 150 8.2 No Yes No

Keystone Day 1 2

3

3,080 5.6 No Yes No

Keystone Day 2 2

3

2,470 4.6 No Yes No

Keystone Day 3 2

3

2,720 6.1 No Yes No

Keystone Day 4 2

3

2,560 3.4 No Yes No

1 - All concentrations are in 

μg/L 

2 - Data source: EPA Sampling Episode Reports

3 - Non-detects = 0.5 μg/L

4 - Reference: EPA 2013 TDD, Section 6: Wastewater Characterization and Pollutants of 

Concern
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5 - EPA identified pollutants detected at greater than or equal to 10 times the baseline value in at 

least 10 percent of all untreated process water as POCs.

6 - EPA used a baseline value of 2.0 μg/L for arsenic based on EPA’s MDL Study.

The Proposed Nitrate/Nitrite Limit is Not Appropriate

The biological treatment systems that EPA evaluated as BAT – Belews Creek and Allen 

Stations – were designed for selenium removal. Nitrate removal is a precursor reaction that 

occurs prior to selenium removal in biological systems. Thus, some nitrate removal will occur 

within the bioreactor, but it is not understood how much will be removed and how that removal 

will be impacted by higher nitrate levels going into the bioreactors.

Also, there are very limited data to support EPA’s proposed nitrate-nitrite limits. As we have 

demonstrated, the nitrate/nitrite levels in FGD wastewater at Belews Creek and Allen are much 

lower than the levels in other FGD wastewaters. In addition, Belews Creek and Allen did not 

collect nitrate/nitrite data after the facilities completed the start-up modes of their treatment 

systems. Therefore, there is insufficient data from these two plants for EPA to develop national 

effluent limitations guidelines for nitrate/nitrite.

In addition, rainwater contains higher nitrate/nitrite level than the limits that EPA proposes. 

According to an online report38, 43 of 51 samples over 31 states in the United States contained 

nitrate, ranging from 0.13 mg/L to 8.16 mg/L nitrate-N.

When Southern conducted water conservation tests at Plant Bowen, it found the service water 

contained 0.07-0.12 mg/L nitrate-N (0.3-0.5 mg/L nitrate), which basically reflects the 

background of the river water nitrate-N level. This is based on a weekly sampling for 10 

weeks. Similarly, Wansley service water has nitrate-N range of 1.26-1.35 mg/L based on five 

samples collected in five consecutive days.

Given that similar background concentrations of nitrate/nitrite are likely ubiquitous, it is going to 

prove very difficult to meet the proposed limits, based only on typical intake concentrations.

34 ERG Memorandum to Steam Electric Rulemaking Record, “Pollutants of Concern 

Methodology Memorandum,” April 19, 2013, EPA-HQ-OW-2009-0819-2151.

35 The seven plants sampled by EPA include Belews Creek, Allen, Miami Fort, Pleasant Prairie, 

Hatfield’s Ferry, Keystone, and Dickerson.

36 Computer Sciences Corporation (CSC). 2013. Results of the ICP/MS Collision Cell Method 

Detection Limit Studies in the Synthetic Flue Gas Desulfurization Matrix (January 16), EPA-HQOW-2009-0819-2116.
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37 ERG Memorandum to Steam Electric Rulemaking Record, “Pollutants of Concern 

Methodology Memorandum,” April 19, 2013, EPA-HQ-OW-2009-0819-2151

38 Root, E., W. Jones, B. Schwarz, and J. Gibbons. 2004. Rainwater Chemistry Across the United 

States, available at 

http://www.people.carleton.edu/~bhaileab/environmentalgeology/RainWater.pdf. November 22

Comment Response: 

Regarding arsenic, see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 

56 in Comment Code 9.a.

Regarding nitrate/nitrite, see response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt 

Number 20 in Comment Code 26.f.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 50

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

There is no basis in the record to support EPA’s classification of pollutants of concern in bottom 

ash transport water.

Comment Response: 

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

Code 6.a 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: 122
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. Proposed Arsenic Limits are Inappropriate

EPA has proposed very stringent limits for arsenic based on chemical precipitation 

treatment. Those proposed limits are 6 μg/L monthly average and 8 μg/L daily maximum. EPA 

developed limits based on sampling data from three plants with chemical precipitation treatment 

– Hatfield’s Ferry, Miami Fort and Keystone. Figure 6 provides the dissolved arsenic influent 

concentrations and the total arsenic effluent concentrations of the chemical precipitation 

treatment system for the three plants. The dissolved arsenic concentrations in the influent, 

ranging from <4 to 11 μg/L, are very close, if not the same, as the total arsenic in the chemical 

precipitation effluent. In fact, in most instances (10 out of 12 data points), the dissolved arsenic 

influent is present at concentrations below the proposed limits of 6 and 8 μg/L.

Figure 6: Arsenic Concentrations at Selected Plants - Influent (Dissolved) and Chemical 

Precipitation Effluent (Total)

In addition, the settled arsenic levels (baseline) in the influent to the treatment system is not a 

pollutant of concern (POC) based on EPA’s own POC criteria. 2013 TDD p. 6-24 to 6-28. In 

other words, the influent arsenic levels at the sampled plants are not present at high enough 

concentrations to evaluate the effectiveness of the chemical precipitation treatment system or the 

biological treatment system.

According to EPA,63 it “reviewed the untreated FGD wastewater data for ... seven plants (total 

of seven sampling points and 28 samples) to identify FGD wastewater POCs.” 64
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To identify POCs (i.e., pollutants that are present in sufficient concentrations to quantify the 

degree of pollutant removal resulting from treatment processes), EPA applied two criteria:

(1) Eliminate from consideration any pollutants that were never detected in the untreated 

wastewater samples, and

(2) Identify pollutants detected at greater than or equal to 10 times the baseline value in at least 

10 percent of all untreated wastewater samples.

EPA used a baseline value of 2.0 μg/L arsenic which is based on a method detection limit 

(MDL) study conducted by EPA.65 By applying the above criteria to untreated FGD wastewater 

from the seven plants (28 data points) to a baseline value of 2.0 μg/L arsenic, EPA concluded 

that arsenic is a POC because 100% of the sample results are greater than 10 times the baseline 

value.66

However, based on UWAG’s analysis of the same 28 arsenic data points using EPA’s own 

criteria, arsenic in FGD wastewater is not a POC. The table below provides the 28 data points 

for dissolved, total and settled arsenic in the influent to the chemical precipitation treatment 

systems. Both the dissolved and the settled arsenic concentrations in the influent do not meet the 

POC criteria. The settled influent represents the appropriate baseline for the industry (i.e., 

effluent from a settling pond). EPA mistakenly used the total arsenic influent data which 

represents FGD wastewater prior to treatment by a settling pond. Since plants currently treat 

FGD wastewater at a minimum with a settling pond, the removal of particulate arsenic by 

settling ponds should not have been included in EPA’s POC analysis. If settled arsenic influent 

data are used in the POC analysis, then arsenic would not qualify as a POC, and therefore no 

arsenic limits would have been proposed. Because arsenic is not a POC by EPA’s own criteria, 

the proposed arsenic limits for FGD wastewater are invalid, because treatability of settled arsenic 

at the sampled plants has not been demonstrated.

Table 17: Arsenic Pollutant of Concern Analysis of FGD Wastewater Using EPA’s POC 

Methodology
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1- All concentrations are in μg/L.

2- Data source: EPA Sampling Episode Reports, EPA-HQ-OW-2009-0819-0736, -0790, -0798, 

-0773, -0813, -0755, and -0808.

3- Non-detects = 0.5 μg/L.

4- Reference: EPA 2013 TDD, Section 6: Wastewater Characterization and Pollutants of 

Concern.

5- EPA identified pollutants detected at greater than or equal to 10 times the baseline value in at 

least 10 percent of all untreated process water as POCs.
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6- EPA used a baseline value of 2.0 μg/L for arsenic based on EPA’s MDL Study.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 56 in Comment 

Code 9.a.

Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Failure to Allow Credit for Intake Pollutants Results in an Overestimate of Risk, a 

Practice That Will Continue Under the Proposed Rules

EPA does not take source water contributions into account when applying ELG permit limits, 

nor will it under this proposed rule for Pollutant of Concern assessments, even though it is 

allowed in 40 CFR 122.44 and 122.45 (g). This is problematic for steam electric generating 

plants generally because many of the pollutants that are regulated or are proposed for regulation 

are common in the earth’s crust and the watersheds that provide cooling and process water to 

generating plants and can be present in intake water at concentrations that have regulatory 

consequence. The discharges of plants that use once-through cooling are especially subject to 

mischaracterization because the large volumes of water in conjunction with substantial intake 

concentrations yield large loadings. For example, Consumers Energy monitored and reported 

zinc in the discharge of its J.R. Whiting plant for several years and reported zinc in the Toxic 

Release Inventory (TRI) until monitoring of the intake demonstrated that all the zinc was passthrough. We submit that a large portion of the contaminants discharged from power plants are 

actually attributable to the intake water.

In Michigan, the inability to “net” is especially important with regard to mercury, which is 

generally present in intake water at concentrations greater than the 1.3 ng/l standard. At 

Consumers Energy we can demonstrate, through many years of low level mercury monitoring in 

both the intake and the discharges of our once-through power plants that the mercury discharged 

is attributable to intake concentrations and not actual discharges from the plant. The mercury 

data provided in Attachment 1 for intake and discharge of the D.E. Karn and J.C. Weadock 

power plants is instructive. These data clearly show the intake to be the source of mercury and 

actually demonstrate that there is a small but statistically-significant sequestration of mercury by 
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the plant due to the settling of mercury with dissolved solids in the small, process portion of the 

flow, while the once-through flow has no treatment.

The inability to “net” mercury at this plant has several consequences:

1. The mercury data are reported to the State and EPA as if they were generated from the 

Plants

2. Because of the large volumes of water involved, loadings are significant, and steam 

electric generating plants are recognized as the principal industrial source of waterdischarged mercury in the state TMDL.

3. Inability to net mercury results in the need to maintain a “pollutant minimization plan” 

for mercury when there is really nothing that can be done to treat or minimize mercury in 

the once-through source water.

4. The mercury data from the Michigan Discharge Monitoring Reports (DMRs) are reported 

to EPA, which not only perpetuates the myth that these steam electric generating plants 

are the principal source of mercury discharges, but then multiplies the loadings by a 

factor of 117 Toxic Weighted Pounds Equivalent (TWPE) in its Discharge Monitoring 

Report Pollutant Loading Tool. This further exaggerates the impact of steam electric 

plant discharges, when in reality these once-through cooling plants are simply reporting 

mercury in source water passing through the plants and may, as in the case of Consumers 

Energy plants, actually be sequestering mercury.

These data on mercury are instructive of the overestimation and consequences attendant to the 

reporting and regulation of naturally-occurring water quality parameters generally. By requiring 

the reporting of naturally occurring and background water quality parameters that are simply 

passed through a plant or process, the EPA grossly distorts the truth relative to discharges by 

industry into waters of the United States. It’s time for honesty and transparency in governmentthese ELG rules should provide for the consideration of source water and the reporting of “net” 

as opposed to gross concentrations and loadings at steam electric generating plants. There should 

not be the expectation that naturally-occurring and background concentrations of pollutants in 

the source water should be treated at the steam electric generating plant’s expense.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4283-A1, Excerpt Number 15 in Comment 

Code 26.e Regulatory Implementation – Net Credits.

Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

EPA then concluded that the pollutants of concern (POCs) for bottom ash transport are identical 

to those of fly ash transport water.6 This is inappropriate due to major differences in fly ash and 

bottom ash as discussed below.

In addition, as noted by APPA, EPA made questionable analytical judgments for samples 

analyzed at the non-detect level. These calculations, from a mixed bag of data from as long as 40 

years ago, resulted in overestimates of bottom ash transport water toxicity. 

Comment Response: 

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

Code 6.a. See also response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in 

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

concern and discharge loads, and the effect of detection limits on those analyses.

Also see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment 

code 15.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: 49

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Failed to Apply its Traditional Criteria for Selecting Pollutants of Concern for 

Bottom Ash.

In addition to relying on inappropriate bottom ash transport water data, EPA also deviated from 

its traditional criteria for selecting pollutants of concern for bottom ash transport water. For 

example, EPA normally requires that the pollutant be detected in at least three samples. For the 

“ash transport water” pollutants of concern analysis, which EPA used to determine pollutants of 

concern for both bottom ash and fly ash transport water, EPA did not collect three samples. As a 

result, EPA selected its pollutants of concern based on only two samples for 12 metals and only 

one sample for the remaining 26 pollutants. ERG Pollutants of Concern Methodology 

Memorandum, EPA-HQ-OW-2009-0819-2151, Table 4-3, pp. 8-9. Furthermore, EPA incorrectly 

concluded that bottom ash transport water pollutants of concern are identical to those for fly ash 

transport water. In fact, fly ash and bottom ash have distinctly different physical and chemical 

properties that EPA needs to recognize. Also, to give another example, in previous effluent 

guidelines, EPA has been careful to remove any naturally- occurring non-toxic minerals or 
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treatment chemicals from the pollutants-of-concern selection, but EPA has made no such 

adjustments to the ash transport water pollutants of concern.

Comment Response: 

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

Code 6.a and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d.

Commenter Name: Erik Silvola

Commenter Affiliation: Great River Energy (GRE)

Document Control Number: EPA-HQ-OW-2009-0819-4572-A1

Comment Excerpt Number: 9

External Review Flag: Statistics

External Review Incorporated into Response: No

Comment Excerpt: 

Pretreatment Standards

GRE believes the limits for both existing and new sources are too low for a number of reasons 

and we reference UWAG comments. A big issue for us is the lack of considering source 

water. Our Spiritwood Station uses the treated waste water from a local municipality for cooling 

and then sends blow down back to the City. Under some of the options we would have to install 

expensive pretreatment systems just to use this water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4283-A1, Excerpt Number 15 in Comment 

Code 26.e Regulatory Implementation – Net Credits.

Commenter Name: G. Alderson

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4424-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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We want power plants to apply the best available technology to reduce pollution. This should be 

a strict requirement. It should ban the introduction of arsenic, lead, mercury and selenium into 

our waterways.

Please put this rule into final form and make it effective as soon as possible.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4668-A2, Excerpt Number 2 in Comment Code 

6.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: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

It must be noted that there is a significant difference in the level of pollutants associated with 

bottom ash discharges in comparison to fly ash transport water and EPA’s assumption of 

similarities is incorrect.

Comment Response: 

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

Code 6.a and DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d.

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Many other metals and metals compounds were identified in the Preamble as being present in 

wastewaters generated by the different processes at power plants. Metals such as boron, 

cadmium, thallium, and vanadium were reported to be found during EPA’s study. EPA has 
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suggested that these metals would not be directly monitored in the regulations because the 

BAT/BPT for Se, As, and Hg will also remove the other metals. This broad generalization is not 

necessarily substantiated by the research. Vendors of anaerobic biological treatment systems are 

certainly not making these claims. Such broad claims by EPA can be misconstrued as factual or 

research-based, and can be used by regulatory agencies to justify low permit limits for those 

metals and possibly anaerobic biological systems as BAT for metals such as vanadium and 

boron. State agencies could apply this to facilities not covered 40 CFR part 423 because the 

proposed rule gives them a misguided perception that there is a risk and an effective means to 

mitigate it.

CIBO strongly suggests that EPA re-consider how it presents its ideas of how to control metals it 

says are present in wastewater but for which there are not specifically identified control limits or 

technologies. The rule suggests they can be removed by the BAT and BPT for Se, As, and Hg 

and that those compounds are suitable surrogates for the additional metals listed. However, the 

assertions need more scientific basis than EPA has provided as the basis for its rule and in the 

final rule EPA should not overstate the performance capabilities of technologies.

Comment Response: 

EPA disagrees with the commenter that it has not specifically identified control technologies for 

metals determined to be adequately controlled through the regulation of indicator pollutants 

arsenic, mercury, and selenium in FGD wastewater. TDD Table 11-1 specifically identifies those 

pollutants EPA determined are directly regulated or controlled by regulation of another 

parameter, as well as those EPA determined are not effectively treated by the FGD wastewater 

technology basis. Specific to the pollutants identified by the commenter, EPA determined that 

cadmium, thallium, and vanadium are controlled by regulation of indicator pollutants, while EPA 

determined that boron is not effectively treated.

As discussed in TDD Sections 10.2.1.2 and 10.2.1.3, EPA conducted an analysis to evaluate the 

pollutant-specific treatment effectiveness of the chemical precipitation and biological treatment 

technologies, respectively. For chemical precipitation, EPA reviewed pollutant concentrations 

from the four plants operating this technology basis, Hatfield’s Ferry, Miami Fort, Keystone, and 

Pleasant Prairie; for chemical precipitation followed by biological treatment, EPA reviewed 

pollutant concentrations from the two plants operating this technology basis, Allen and Belews 

Creek. To ensure that the treatment effectiveness could be evaluated, EPA performed an analysis 

to identify pollutants present at acceptable levels in the treatment system influent. Where specific 

pollutants were identified at acceptable levels, EPA calculated plant-specific percent removals 

across the treatment technology and performed an evaluation to determine whether the pollutant 

was effectively treated with the treatment technology. As shown in TDD Table 10-4, EPA 

determined that chemical precipitation effectively treats many metals pollutants, including 

cadmium, thallium, and vanadium. As shown in TDD Table 10-5, EPA determined that only 

three metals (mercury, nickel, and selenium) are effectively treated by biological treatment. See 

the memorandum FGD Wastewater Pollutants of Concern (POC) Analysis Methodology [DCN 

SE05342] for a more detailed description of these analyses.
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Numeric limitations, and associated compliance monitoring, for all pollutants determined to be 

controlled by the regulatory technology basis are not necessary to ensure that FGD wastewater 

pollution is adequately controlled, since many of the pollutants originate from similar sources, 

have similar treatabilities, and are expected to be removed by the same mechanisms and treated 

to low levels.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 24

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In addition to the physical differences, there are numerous factors that make bottom ash much 

more inert than fly ash. There are multiple reasons for this, including that the elements present in 

the coal (calcium, barium, magnesium, sodium, potassium, beryllium, antimony, boron, 

manganese, copper, zinc, nickel, silver, chromium, cobalt, aluminum, cadmium, titanium, 

silicon, iron, and lead) partition after combustion primarily to fly ash. With the exception of 

fluorine, barium, strontium and manganese, the median values of multiple studies have shown 

that the concentrations of most of these elements are typically an order of magnitude greater in 

fly ash than bottom ash. This is because the volatile and semi-volatile elements such as arsenic, 

selenium, mercury, lead and zinc tend to vaporize in the boiler and subsequently condense on 

particles of fly ash. As a result, the fly ash transport water is a key source of most metals in 

utility ash ponds where it is not collected dry. It should also be noted that a significant portion of 

mercury, arsenic and selenium are carried as vapor with the flue gas and captured in the FGD 

systems and are therefore not available for transport with bottom ash.

Finally multiple leaching studies have documented that the metal contaminants in fly ash, as 

determined by toxicity characteristic leaching procedure (TCLP), are much more susceptible to 

extraction (typically 3 to 10 times higher in extract concentrations and in some cases even 100 

times higher) than in bottom ash. This is due to the incorporation and binding of the metals into 

the bottom ash mineral matrix rather than condensation on surfaces typical of fly ash.

EPRI, TVA, and many utilities have data that support the above differences in bottom ash and fly 

ash with regard to metals/TCLP characteristics.

Comment Response: 

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

Code 6.a. In addition, to identify pollutants of concern, EPA evaluated pollutants detected in 

untreated ash transport water samples. In some cases, where it lacked sufficient data, EPA also 

evaluated pollutants detected in partially treated ash transport water samples to identify 
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pollutants of concern. EPA did not use leaching studies to identify pollutants of concern in ash 

transport water. Rather, as EPA typically does, it used characterization data for ash transport 

water. See the TDD.

Commenter Name: James D. Taft

Commenter Affiliation: Association of State Drinking Water Administration (ASDWA)

Document Control Number: EPA-HQ-OW-2009-0819-4668-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For instance, five contaminants for which there are existing Safe Drinking Water Act maximum 

contaminant levels (MCLs) (i.e., arsenic, cadmium, lead, mercury, and selenium), all of which 

are regularly found in the wastewater streams from some of the facilities covered under this 

guideline, are not currently regulated. The final effluent guidelines should support National 

Pollutant Discharge Permit (NPDES) permit requirements that include measures, where 

appropriate, to protect downstream water supplies from contamination by systems generating 

wastestreams with these pollutants.

Comment Response: 

The heavy metals listed by the commenter are identified as pollutants of concern in multiple 

steam electric power generation wastestreams, including fly and bottom ash transport water, 

FGMC wastewater, FGD wastewater, gasification wastewater, and combustion residual leachate. 

See TDD Section 6.

For fly ash transport water, bottom ash transport water, and FGMC wastewater, EPA is 

promulgating zero discharge effluent limitations and standards based on use of a dry-handling 

system, which will eliminate discharges of heavy metals from these discharges. For gasification 

wastewater, EPA is promulgating ELGs based on treatment by an evaporation system, which 

will control discharges of heavy metals either directly through numeric limits for arsenic, 

mercury, and selenium, or indirectly through regulation of these three indicator pollutants and 

TDS.

FGD wastewater pollution is controlled directly through numeric discharge limitations for 

arsenic, mercury, selenium, and nitrate/nitrite, and indirectly for many additional metals, 

including cadmium and lead, through regulation of the indicator pollutants arsenic, mercury, and 

selenium. See response to DCN EPA-HQ-OW-2009-0819-4486-A2, Excerpt Number 12 for 

additional information.

For combustion residual leachate, few steam electric power plants currently employ technologies 

other than surface impoundments. EPA considered technologies in place for treatment of other 
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wastestreams at steam electric power plants and wastestreams generated by other industries, 

including chemical precipitation. However, EPA lacks sufficient information on the cost, 

pollutant reduction, and effectiveness of chemical precipitation and alternative approaches to 

treat combustion residual leachate to finalize BAT/PSES limitations for combustion residual 

leachate based on chemical precipitation. See Section VIII.C.6 and VIII.E of the preamble for 

additional information. EPA is, however, promulgating numeric standards based on chemical 

precipitation as NSPS/PSNS on mercury and arsenic in discharges of combustion residual 

leachate, and indirectly controlling other heavy metals pollutants of concern through regulation 

of these indicator pollutants.

As required by the Clean Water Act, EPA’s effluent limitations guidelines and standards are 

based on the performance of well-designed and well-operated control and treatment 

technologies. In establishing technology-based standards, EPA does not take into consideration 

the factors such as drinking water standards.

Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-A1

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The next issue with the proposed rule is that it regulates total metals rather than dissolved metals. 

As demonstrated by the data most of the metals will precipitate to total metals and likely settle in 

the ash pond. However, the rule is asking for total metals to be applied. The test method for total 

metals requires that the sample is dissolved in acid to leach out all metal and then analyzed. In so 

doing, the test thus makes metals contained normal material such as dirt or ash, which is not 

biologically available and then making the determination that those metals are biological 

available, thus overstating the potential toxicity of the discharge stream. A better method of 

administering the limits for this proposal would be to limit "dissolved metals" as those are the 

metals that are biologically available. And, as the data would suggest, once the pH is adjusted, 

the wastewater from non-chemical metal cleaning wastes is not hazardous to aquatic life and 

therefore should not be regulated.

Comment Response: 

Metals in steam electric power plant wastewater discharges are present in both soluble (i.e., 

dissolved) and particulate (i.e., suspended) form. For example, a review of EPA sampling data 

collected for FGD wastewater in support of the Steam Electric ELGs shows that some metals 

such as arsenic are present mostly in particulate form while other pollutants such as selenium and 

boron are present mostly in soluble form.
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This is a technology-based rule and is based on the goal of eliminating pollutants where 

elimination is technological available and economically achievable (considering the factors 

specified in section 304(b) of the Act. It is not based on the effects of the discharge on receiving 

water. See for example the many court decisions rejecting notions that BPT or BAT should be 

based on effects on the receiving water. American Frozen Food Inst. v. TrainAssn of Pacific 

Fisheries v. EPA

EPA regulates total metals for several reasons. First, establishing limits on dissolved pollutants 

would not control particulate forms, thus total metals is more appropriate and necessary to 

control both forms. Second, the form of pollutants can change while in the environment, thus a 

pollutant that is discharged in particulate form can be transformed under conditions in the 

receiving water body such as reducing conditions in sediments. Third, sampling for total metals 

is much easier for plant staff because the dissolved metal analysis requires filtering the sample in 

the field before filling the sample bottle. In contrast, for a total metals analysis they just fill the 

bottle without the complicated (and many industry folks would say burdensome) prefiltration 

step. The laboratory analysis cost for total and dissolved metals is identical. EPA also notes that 

NPDES permitting regulations require that permit limits for metals be expressed as the total 

recoverable form (see 40 CFR 122.45(c)).

Commenter Name: K. Mauro

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5030-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Every year, these plants dump billions of pounds of arsenic, lead, mercury, selenium (also check 

on strontium!) into surface waters.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4668-A2, Except Number 2.

EPA did not have data to identify strontium as a pollutant of concern. However, as discussed in 

the Environmental Assessment for the Effluent Limitations Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category (EA Report) (DCN SE04527), 

“Multiple studies show that wildlife living near steam electric surface impoundments exhibit 

elevated levels of arsenic, cadmium, chromium, lead, mercury, selenium, strontium, and 

vanadium.”
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EPA is promulgating zero discharge effluent limitations and standards for fly ash and bottom ash 

transport water and FGMC wastewater based on use of dry handling/closed-loop systems, which 

will eliminate all pollutant discharges.

Commenter Name: A. Brightwell

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5259-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I do not want any more toxic heavy metal pollution. I do not want fluoride, an industrial toxic 

waste, in my water. 

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4668-A2, Excerpt Number 2.

Fluoride was identified as a pollutant of concern in fly ash transport water and FGMC 

wastewater. See TDD Section 6. EPA is promulgating zero discharge effluent limitations and 

standards for these wastestreams based on use of a dry-handling system, which will eliminate 

these fluoride discharges.

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: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

4) The total dissolved solids limit for coal gasification water is ridiculously low. Tap water will 

be higher than 38 milligrams per liter!

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 6 in Comment Code 23.
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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: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

7. Boron, Molybdenum, and Other Metals

During renewal of coal-fired power plants, the Department has been conducting a technology 

based determination for the parameters identified in EPA's 2009 Steam Electric Power 

Generating Point Source Category: Final Detailed Study Report (EPA821- R-09-008) and in the 

Department's Utility Waste Landfill Sampling Program 

(http://dnr.mo.gov/env/swmp/gdwtrsub.htm). During those technology reviews the Department 

identified boron and molybdenum as the parameters that require further study.

Boron is extremely mobile in water and is difficult to remove from water with conventional 

treatment (coagulation, sedimentation, and filtration). Advanced treatment, such as reverse 

osmosis, electrocoagulation, ion exchange, and vapor compression evaporation can remove some 

boron, although it is not complete and the advanced treatment creates additional wastestreams to 

process. However, chemical precipitation and pH manipulations can allow molybdenum to 

flocculate and drop out of the water.

If boron and molybdenum were the parameters subject to the guideline, the reduction of other 

metals would still occur. Given the two parameters are identified by EPA's 2009 Steam Electric 

Power Generating Point Source Category: Final Detailed Study Report (EPA821-R-09-008) and 

the presence in the wastestream, the Department believes these parameters should be addressed 

in the ELG.

Comment Response: 

Boron and molybdenum were identified as pollutants of concern in multiple steam electric power 

generation wastestreams, including fly ash transport water, bottom ash transport water, FGMC 

wastewater, FGD wastewater, and combustion residual leachate. For fly and bottom ash transport 

water and FGMC wastewater, EPA is promulgating zero discharge effluent limitations and 

standards based on use of dry handling/closed-loop systems, which will eliminate discharges of 

boron and molybdenum for these discharges. For gasification wastewater, EPA is promulgating 

ELGs based on treatment by an evaporation system, which will control discharges of boron and 

molybdenum.

For FGD wastewater and combustion residual leachate, EPA evaluated several of the treatment 

controls listed by the commenter (chemical precipitation and chemical precipitation followed by 

biological treatment). EPA found small removals of boron associated with chemical 

precipitation. EPA also determined that molybdenum is effectively treated by chemical 
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precipitation, when present at treatable concentrations, as demonstrated by the plant-specific data 

presented in the Steam Electric Analytical Database (SE05359). Because not all steam electric 

power plants have molybdenum present at treatable concentrations, EPA chose not to calculate 

removals associated with chemical precipitation.

EPA agrees that its evaluated technology option of chemical precipitation followed by vapor 

compression evaporation would control boron and molybdenum, but EPA has not selected this 

technology option as BAT/PSES for these wastestreams for the reasons stated in Section VIII of 

the preamble and elsewhere in this record. However, as described in Section VIII.C.13 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. In addition, as discussed in Section VIII.D of the preamble, EPA identified 

treatment using evaporation for NSPS for the final rule (specifically, an evaporation step 

preceded by a chemical precipitation step using hydroxide precipitation, sulfide precipitation, 

and iron co-precipitation, as well as a softening step).

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 143

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

One of the pollutants of concern for gasification wastewater is cyanide, which is found in 

different forms, such as selenocyanate.606 The Edwardsport IGCC is planning to use cyanide 

destruction in addition to evaporation, but because it had not yet begun commercial operation at 

the time EPA drafted the proposed rule, EPA asserts there are not sufficient data regarding 

cyanide removal to set limits “based on the performance of cyanide treatment as part of a 

BAT/BADCT (NSPS) regulatory option.”607

The proposed technology for cyanide destruction is neither new nor untested. The Edwardsport 

plant will treat the distillate and condensate effluent with bleach and provide sufficient residence 

time for the bleach to react with the cyanide.608 EPA has proposed several means of dealing with 

the lack of data, including transferring cyanide limits from another sector, or revisiting the 

standard after data are available from the Edwardsport facility.609 The Edwardsport 

facility began operation in June 2013,610 so effluent data sufficient for EPA to set a limit should 

be available prior to May 2014, when this rule will be finalized.

606 TDD at 7-43.
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607 78 Fed. Reg. at 34,464.

608 TDD at 7-43; 78 Fed. Reg. at 34,464.

609 Id.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5489-A2, Excerpt Number 7 in Comment Code 

23.a.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4724-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B.EPA does not regulate all pollutants from power plants that cause adverse health impacts 

if consumed.

EPA’s rationale for failing to monetize health benefits arising from cleaner drinking water 

assumes that all power plant pollution risk is addressed by SDWA standards. However, EPA has 

not established a drinking water standard for all pollutants from power plants which present 

public health risks. In past rulemakings, EPA has acknowledged the need to account for health 

impacts from pollutants discharged from the point source category that do not have an 

MCL.38 EPA should do the same here.

Two common power plant pollutants demonstrate this point. Vanadium and boron pose public 

health risks and there are no MCLs for these contaminants to date.

38 See U.S. Envtl. Prot. Agency, Economic, Environmental, and Benefits Analysis of the Final 

Metal Products & Machinery Rule (EPA-821-B-03-002) 13-8 (Feb. 2003) (“EPA assumed 

drinking water treatment systems will reduce concentrations to below adverse effect thresholds 

for all chemicals for which EPA has published a drinking water criterion. Therefore, pollutants 

examined in the MP&M drinking water analysis include only six carcinogens for which current 

drinking water criteria are not available.”).

Comment Response: 
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EPA assessed the benefits of the rule to the extent it could based on available data.

See responses to DCN EPA-HQ-OW-2009-0819-4668-A2, Excerpt 2 and DCN EPA-HQ-OW2009-0819-4486-A2, Excerpt Number 12 regarding control of heavy metals, including boron and 

vanadium.

Commenter Name: Kelly Jean Heffner

Commenter Affiliation: Pennsylvania Department of Environmental Protection

Document Control Number: EPA-HQ-OW-2009-0819-4811-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should describe in the ELG (in addition to the basis document) the metals for which arsenic 

serves as a surrogate, as well as a summary of the technical basis. This would assist us in 

addressing several issues that the regulated community in Pennsylvania and other states have 

raised.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4486-A2, Excerpt Number 12.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 65

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Needs to Clarify PSES for Landfill Leachate.

EPA is inconsistent in the preamble and proposed regulatory text when describing the proposed 

Pretreatment Standards for Existing Sources for Landfill Leachate. In the Preamble, EPA 

indicates that PSES will be established for landfill leachate (emphasis added):

As explained above in Section III.B.5, in selecting the PSES technology basis, the Agency 

generally considers the same factors as it considers when setting BAT, including economic 

achievability. Typically, the result is that the PSES technology basis is the same as the BAT 
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technology basis. This proposal is no exception. After considering all of the technology options 

described in Section VIII.A.2, as is the case for BAT, EPA is proposing four preferred 

alternatives for PSES (i.e., Options 3a, 3b, 3, and 4a).

With the exception of oil-fired generating units and small generating units (i.e., 50 MW or 

smaller), the proposed rule under Option 3a would...Establish BAT effluent limits for bottom 

ash transport water and leachate that are equal to the current BPT effluent limits for these 

discharges (i.e., numeric effluent limits for TSS and oil and grease). Id. at 34,477 col. 1.

The Preamble does not specify PSES for landfill leachate under preferred Regulatory Options 3b, 

3, or 4a. The regulatory text for the Proposed Rule does not include PSES for landfill leachate. 

Therefore, We Energies believes that EPA does not intend to issue PSES for landfill leachate 

under proposed Regulatory Options 3, 3a, 3b, and 4a. We Energies believes that a PSES is not 

warranted for landfill leachate under the preferred regulatory options. We Energies asks EPA to 

clarify its position.

Comment Response: 

The final rule does not establish PSES for combustion residual leachate see preamble section 

VIII.E.

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: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NPPD urges EPA to focus the ELG standards on wastewater streams where there are new 

chemical components of concern since the last ELG were issued. The rule should only update the 

ELG requirements for effluents that produce new soluble pollutants not amenable to treatment 

through settling and impoundment.

Comment Response: 

The reasons EPA identified pollutants of concern are explained elsewhere in the record for the 

rule. Similarly, EPA established limits based on the performance of the treatment technology, as 

described elsewhere in this rule.

See also Section VIII of the preamble for a summary and rationale of EPA’s final rule.
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Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 24

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Consumers Energy specifically suggests: Making the technical corrections necessary to recharacterize these waste streams, using the comments of UWAG and the AKRF and Gradient 

technical reports attached to the UWAG comments as a guide.

Comment Response: 

Responses to the documents cited are addressed elsewhere in this comment response document.

Commenter Name: Patrick Finigan

Commenter Affiliation: Omaha Public Power District (OPPD)

Document Control Number: EPA-HQ-OW-2009-0819-4529-A1

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

OPPD urges EPA to focus the ELG standards on wastewater streams where there are new 

chemical components of concern since the last ELG were issued. The rule should only 

update the ELG requirements for effluents that produce new soluble pollutants not amenable 

to treatment through settling and impoundment.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4310-A1, Excerpt Number 15. The reasons EPA 

identified pollutants of concern are explained elsewhere in the record for the rule. Similarly, 

EPA established limits based on the performance of the treatment technology, as described 

elsewhere in this rule.

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: 24
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

LPPC urges EPA to focus the ELG standards on wastewater streams where there are new 

chemical components of concern since the last ELG standards were issued. The rule should only 

update the ELG requirements for effluents that produce new soluble pollutants not amenable to 

treatment through settling and impoundment.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4310-A1, Excerpt Number 15. The reasons EPA 

identified pollutants of concern are explained elsewhere in the record for the rule. Similarly, 

EPA established limits based on the performance of the treatment technology, as described 

elsewhere in this rule.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We are also concerned that some of the historic pollutant and cost data used in the proposed 

rulemaking does not align with modern pollutant characteristics. 

Comment Response: 

If the commenter is referring to 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 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.

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: 27
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Lastly, influent dissolved arsenic concentrations at Miami Fort, Hatfield’s Ferry, and Keystone 

are too low to analyze the effectiveness of biological treatment systems. Specifically, dissolved 

concentrations at these plants range between 4 to11 μg/L, which in most instances are below the 

proposed limits of 6 μg/L monthly average and 8 μg/L daily maximum. If these numbers are 

representative of FGD waste waters for the industry as a whole, arsenic could not properly be 

considered a pollutant of concern pursuant to EPA’s established standards. 2013 TDD at 6-25.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 56 in Comment 

Code 9.a.

Commenter Name: Jerry Schwartz

Commenter Affiliation: American Forest & Paper Association (AF&PA)

Document Control Number: EPA-HQ-OW-2009-0819-4656-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Utility Water Act Group (UWAG) is filing detailed comments today that raise numerous 

substantive concerns with the Proposal. The UWAG comments highlight significant 

deficiencies, including the protocols for identifying pollutants of concern; reliance on old or very 

limited data; and assumptions that pollutants were present in concentrations equal to the high 

detection or quantification limits associated with very old data. These and other deficiencies 

(including censoring data to remove high cost measurements) resulted in significantly 

underestimated costs for the limits included in the Proposal.

Comment Response: 

Other specific comments raised in the commenter’s letter are addressed elsewhere in this 

comment response document.

If the commenter is referring to 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 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.
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6.b. Regulatory Options – EPA Pass-Through Analysis

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 60

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA needs to clarify PSES for Bottom Ash Transport Water.

EPA is inconsistent in the preamble and proposed regulatory text when describing the proposed 

Pretreatment Standards for Existing Sources (PSES) for bottom ash transport water. In one part 

of the Preamble, EPA specifies that it is not proposing to establish pretreatment standards for 

discharges of bottom ash transport water (emphasis added):

For discharges from existing sources to POTWs, EPA is proposing to establish PSES that are 

equal to the proposed BAT, with the following exceptions...Under Options 3a, 3b, and 3 for 

PSES, EPA is not proposing to establish pretreatment standards for discharges of bottom ash 

transport water. Under Option 4a, EPA is not proposing to establish pretreatment standards for 

discharges of bottom ash transport water for generating units with a nameplate capacity of 400 

MW or less... 78 Fed. Reg. at 34,436 col. 2.

EPA partially reverses this position in Section VIII.A.5 of the Preamble (emphasis added)24:

As explained above in Section III.B.5, in selecting the PSES technology basis, the Agency 

generally considers the same factors as it considers when setting BAT, including economic 

achievability. Typically, the result is that the PSES technology basis is the same as the BAT 

technology basis. This proposal is no exception. After considering all of the technology options 

described in Section VIII.A.2, as is the case for BAT, EPA is proposing four preferred 

alternatives for PSES (i.e., Options 3a, 3b, 3, and 4a).

With the exception of oil-fired generating units and small generating units (i.e., 50 MW or 

smaller), the proposed rule under Option 3a would...Establish BAT effluent limits for bottom 

ash transport water and leachate that are equal to the current BPT effluent limits for these 

discharges (i.e., numeric effluent limits for TSS and oil and grease). Id.at 34,477 col. 1.

The regulatory text for the Proposed Rule indicates that EPA does not intend to issue a PSES for 

bottom ash transport water under Regulatory Options 3a, 3b, 3, and 4a (units 400 MW or 

smaller) (emphasis added):

423.16 Pretreatment standards for existing sources (PSES).
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(g) For any electric generating unit with a total nameplate generating capacity of more than 400 

megawatts and that is not an oil-fired unit, there shall be no discharge of wastewater pollutants 

from bottom ash transport water generated on or after a date determined by the control 

authority that is as soon as possible beginning July 1, 2017. Whenever bottom ash transport 

water is used in any other plant process or is sent to a treatment system at the plant, the resulting 

effluent must comply with the discharge prohibition in this paragraph.

Note to (g): All proposed revisions to section 423.16(g) reflect proposed Option 4a, only. For 

proposed Option 3, Option 3a, and Option 3b, the regulations would not specify a PSES for 

bottom ash transport water. Id. at 34,541 col. 2.

We Energies believes that a PSES is not warranted for landfill leachate under the preferred 

regulatory options. We Energies asks EPA to clarify its position.

24 A PSES for bottom ash transport water is specified for Option 3a; however, no PSES for 

bottom ash transport water are specified for Options 3b, 3, or 4a (units 400 MW or smaller) in 

Section VIII.A.5 of the Preamble.

Comment Response: 

As described in preamble section VIII.E, for PSES, the final rule establishes: (1) standards on 

arsenic, mercury, selenium and nitrate-nitrite as N in FGD wastewater; (2) a zero discharge 

standard on all pollutants in fly ash transport water; (3) a zero discharge standard on all 

pollutants in bottom ash transport water; (4) a zero discharge standard on all pollutants in FGMC 

wastewater; (5) standards on mercury, arsenic, selenium, and TDS in gasification wastewater. 

The final rule does not establish PSES for combustion residual leachate because TSS and the 

pollutants that can be components of TSS do not pass through POTWs.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 144

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Additional flaws in the proposed PSES requirements are as follows:

The POTW Pass-Through Analysis is Incomplete

EPA did not perform its traditional pass-through analysis for bottom ash. 78 Fed. Reg. at 34,457 

col. 1. EPA’s reasoning is that the proposed standard is a no-discharge standard and therefore 

pass-through will not occur. But this reasoning fails to consider that each of EPA’s preferred 
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regulatory options allows for discharge of bottom ash, thereby necessitating a comparison of the 

POTW removal efficiencies with that of the proposed PSES and PSNS standards.

The POTW Removal Percents are Obsolete

EPA used the 1982 50 POTW study when determining POTW removal efficiencies for arsenic 

and mercury. This study is outdated and does not account for the advanced level of treatment 

now occurring at the nation’s POTWs.

Moreover, EPA’s suggested removal efficiency for arsenic differs significantly from previous 

ELG rulemakings. In developing its 1998 effluent limitations for the Centralized Waste 

Treatment category, EPA determined that the arsenic removal efficiency of a well-operated 

POTW is 91%, as opposed to the 66% cited in this rulemaking.

The BAT Removal Percentages are Inaccurate

EPA compared the removal percentages for well-operated POTWs with the removal percentages 

of the technology associated with the proposed FGD wastewater BAT limitations. This analysis 

is flawed because of obsolete POTW data, as described above, and also because of inflated BAT 

removal efficiencies that over-estimate the performance of the physical-chemical- biological 

treatment systems.

Comment Response: 

The POTW Pass-Through Analysis is Incomplete (not conducted for bottom ash transport 

water). Although EPA’s proposed BAT and NSPS for bottom ash transport water included 

options that authorized discharges, EPA’s final rule is “no discharge of pollutants.” See 40 CFR 

§423.13(k)(1)(i). As discussed in Section 11.2 of the TDD, EPA did not conduct its traditional 

pass-through analysis for bottom ash transport water because limitations for direct dischargers 

consist of zero discharge of wastewater pollutants to waters of the U.S. Thus, BAT/NSPS 

achieve 100 percent removal of all pollutants, and no further removal could occur at POTWs. 

For this reason, EPA determined the pollutants would pass through the POTW for bottom ash 

transport water. Also see Section VIII of the preamble for the final rule.

The POTW Removal Percents are Obsolete. See response to EPA-HQ-OW-2009-0819-4379-

A1, Excerpt Number 139.

Also, the commenter asserts that EPA’s pass-through analysis is flawed because the POTW % 

removals EPA used do not reflect current performance. They argue that, as reported by EPA’s 

CWNS, since the time of the 1982 50 POTW study there has been a 101% increase in people 

served by advanced wastewater systems. The commenter assumes, without basis, that “advanced 

wastewater treatment” increases removals of pollutants regulated by PSES. This is not the case. 

The CWNS 2008 report to Congress defines advanced treatment as:

A level of treatment that is more stringent than secondary treatment or that produces a significant 

reduction in nonconventional or toxic pollutants present in the wastewater treated by a facility. A 
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facility is considered to have Advanced Wastewater Treatment if its permit includes one or more 

of the following:

 biochemical oxygen demand (BOD) less than 20mg/L;

 nitrogen removal;

 phosphorus removal;

 ammonia removal;

 metal removal;

 synthetic organic removal.

 

POTWs classified as “advanced treatment” typically have treatment to reduce ammonia or 

nutrients (nitrogen and phosphorus). Very few POTWs have metal removal technology. 

According to EPA’s DMRLoadings Tool (http://cfpub.epa.gov/dmr/), of the 15,549 POTWs, the 

number of facilities with monitoring requirements and effluent limits for the metals regulated by 

PSES are:

Mercury: 832/15,549 or 5.4%

Arsenic: 81/15,549 or 0.5%

Selenium: 150/15,549 or 1.0%

EPA notes that the POTWs nationwide are unlikely to have treatment technology effective for 

removing mercury, arsenic, or selenium unless they have NPDES permit monitoring 

requirements and effluent limitations. Further, even with such limits, the POTWs may employ 

non-treatment strategies for meeting their discharge limits (e.g., controlling silver-mercury 

amalgam releases from dental offices). For this reason, EPA concludes that the removal 

efficiencies for arsenic and mercury calculated using data from the 50-POTW study adequately 

represent the current performance of U.S. POTWs.

Further, for selenium, EPA calculated POTW removal efficiency using data from NRMRL 

Treatability Database, Version 5.0, February 2004. The commenter provides no basis for their 

assertion that POTWs have improved selenium removal since the time data were collected for 

the NRMRL treatability database. As noted previously, only 1% of U.S. POTWs have NPDES 

permit monitoring requirements and effluent limitations for selenium. POTWs are unlikely to 

employ selenium removal technologies without limits and monitoring requirements.

For nitrate/nitrite, the percent removal was calculated during development of the 2002 

amendments to effluent guidelines for the iron and steel category. EPA calculated this removal 

efficiency by analyzing data from POTWs that receive steel mill wastewater. See Development 
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Document for Final Effluent Limitations Guidelines and Standards for the Iron and Steel 

Manufacturing Point Source Category, April 2002, EPA-821-R-02-004, Table 11-3. For TDS, 

EPA’s assumption of zero percent removal is not based on the 50-POTW Study or the NRMRL 

Treatability Database, but on information provided in standard wastewater treatment textbooks 

and engineering judgment. Because the commenter provided no data demonstrating that POTWs 

remove TDS, EPA has no reason to change this assumption.

Finally, EPA notes that the commenter provided no data demonstrating that any POTWs 

removed different percents of any pollutant.

POTW removal used in development of Centralized Waste Treatment pretreatment standards. 

The commenter asserts that the POTW removal percent for arsenic differs significantly from the 

removal percent used for the development of pretreatment standards for the Centralized Waste 

Treatment category. This is not correct. Development Document for Effluent limitations 

Guidelines and Standards for the Centralized Waste Treatment Industry – Final. August 2000. 

EPA-821-R-00-020, Table 7-5, lists the removal for arsenic as 65.77, based on the 50-POTW 

study. With rounding, this is the same removal percent used for the steam electric pretreatment 

standards (65.8%).

The BAT Removal Percentages are Inaccurate. For comments about the removal efficiencies and 

“performance of physical-chemical-biological treatment systems,” see response to comment 

DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 95.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 139

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

POTW Pollutant Pass-through Analysis

The preamble (78 Fed. Reg. at 34,456-57) and sections 11-10 through 11-15 of the 2013 TDD 

discuss how EPA determined POTW pass-through for each of the different waste streams. EPA’s 

methodology essentially compares POTW removal efficiencies to the removal efficiencies 

estimated for the treatment technologies for the proposed ELG. EPA compares the percentage of 

a pollutant removed by well-operated POTWs performing secondary treatment to the percentage 

removed by the proposed BAT/NSPS treatment systems. If the BAT/NSPS percent removal is 

greater than a typical POTW percent removal, the pollutant is deemed to pass through and is 

proposed for regulation in the ELG Rule.
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There is an obvious flaw in this methodology which is not unique to the steam electric ELG 

rulemaking. The POTW removal efficiency is based on a 1982 study of 50 well-operated 

POTWs performing secondary treatment. Without question, a study of 50 well-operated POTWs 

in 2013 would yield significantly higher removal efficiencies and therefore an increased 

likelihood that a pollutant receives greater treatment by a POTW than it would by a BAT/NSPS 

treatment system. In fact, since 1982 there has been a 101% increase in the number of people 

served by advanced wastewater treatment systems in the U.S., and advanced (beyond secondary) 

treatment is now predominant nationwide. See EPA Clean Watersheds Needs Survey 2008 

Report to Congress, EPA-832-R-10-002.

EPA also assumed that the pollutants of concern in bottom ash were the same as those in fly ash, 

due to the common fuel source. This assumption is a concern for both direct and indirect ELG 

proposals, but the issue of POTW pass-through assessment compounds the concern from a 

PSES/PSNS viewpoint. EPA set the proposed Technology-Based Effluent Limitation (TBEL) 

removal efficiency at 100% for those waste streams required to meet non-discharge status. This 

rationale is appropriate for all waste streams other than bottom ash transport water, which is 

authorized for discharge under each of EPA’s preferred options.

Below is a summary of the POTW pass-through analysis:

Treatment Option Pollutant 

POTW 

Removal % 

1* 2*

BAT/ NSPS 

Removal % 

Pass 

Through? 

Chemical precipitation for FGD / 

CRL

Arsenic 65.8 90.9 99.5 Yes

Mercury 90.2 90.2 99.9 Yes

Chemical precipitation followed by 

biological treatment for FGD / CRL

Arsenic 65.8 90.9 99.5 Yes

Mercury 90.2 90.2 99.9 Yes

Nitrate-Nitrite 90.0 - 99.6 Yes

Selenium 34.3 34.3 99.9 Yes

Mechanical Vapor Compression Arsenic 65.8 90.9 99.5 Yes

Evaporation for FGD

Mercury 90.2 90.2 99.9 Yes

Selenium 34.3 34.3 99.9 Yes

TDS 0 - 99.7 Yes

Mechanical Vapor Compression 

Evaporation for IGCC

Arsenic 65.8 90.9 99.5 Yes

Mercury 90.2 90.2 99.9 Yes

Selenium 34.3 34.3 99.9 Yes

TDS 0 - 99.7 Yes

Nonchemical Metal Cleaning Waste Copper - 84.1 1982 Rule Yes

*1 - Technical Development Document for the proposed effluent limitation guidelines and 

standards for the steam electric power generating point source category. EPA-821-R-13-002

*2 - Development Document for proposed effluent limitation guidelines and standards for the 

centralized waste treatment industry. EPA-R-98-020
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The data supporting the POTW removal percents are somewhat obsolete, and therefore a 

modification of the ELG Rule to allow for an updated local demonstration would be desirable. 

The Rule could allow for a site-specific, real-time comparison of POTW design removal 

efficiencies with that of the finalized BAT/NSPS technologies. If a POTW is able to treat these 

wastes to a higher degree than what costly additional treatment installations at a power plant 

could achieve, this should be considered. This change would benefit both water and electricity 

utility rate payers and encourage partnerships between power companies and water utilities for 

both source water and wastewater handling options.

Comment Response: 

For comments about the pollutant pass through analysis, including the POTW removals and 

analysis of pass through of bottom ash transport water, see the response to DCN EPA-HQ-OW2009-0819-4379-A1, Excerpt Number 144 in Comment Code 6.b.

In terms of the commenter’s general critique of how the EPA has always done pretreatment 

standard analysis, EPA disagrees. Section 301 of the Act and its legislative history indicate that 

pretreatment is to be analogous to BAT as this means the polluter rather than the public pays to 

control discharges. (The public would be either the POTW or the drinking water plant that 

would need to treat water before discharging it or providing it to customers). EPA disagrees with 

the commenter that “a study of 50 well-operated POTWs in 2013 would yield significantly 

higher removal efficiencies.” First, while the commenter cites information on the increase in 

POTWs that employ advanced treatment, the national standard is still secondary treatment. 

Therefore on a national basis, that is the appropriate basis for comparison. Second, even with the 

increase in advanced treatment, the fact remains that activated sludge continues to be the most 

commonly found treatment process at secondary plants (source: 2008 CWNS survey). Third, 

even though there is evidence that many POTWs employing secondary treatment today (as 

opposed to the time of the 50 POTW Study) are achieving lower effluent levels of BOD and 

TSS, that does not necessarily translate to better removal of priority pollutants. For example, as 

explained in the final preamble, many of the pollutants in steam electric power plant wastewater 

are soluble (such as dissolved metals) and to the extent that there is improvement in BOD and 

TSS removals, these would not be significantly affected by these processes. As another example, 

not all organic pollutants, such as those comprised of bigger, more complex, molecules, will be 

biodegraded with an activated sludge system Fourth, in EPA’s 50 POTW study, the final

removals were 90% for BOD and 91% for TSS. EPA eliminated low influent concentration 

levels, thereby minimizing the possibility that low POTW removals may simply reflect the low 

influent concentrations. Further, POTWs operating well below capacity do not give a fair 

representation of priority toxic pollutant removal or treatment. The average capacity in the 50 

POTW study was 74%. The average unused capacity was about 52% in 2014, making the 

average used capacity about 48%. This makes comparison of the 1982 POTW study to current 

national databases extremely difficult. Lastly, EPA notes that commenters did not provide any 

data to support their assertion that POTWs today are more efficient than POTWs at the time of 

the 50 POTW Study. This, is why it is reasonable for EPA to continue to use the 1982 data on 

secondary treatment. See e.g., Reynolds Metals Co. v. EPA, 760 F.2d 549, 553 (4th Cir. 

1985)(Legislative History indicates that pretreatment is to be analogous to BAT. Court interprets 

this as meaning that the combined treatment by indirect and POTW should be equivalent to what 
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a direct discharger achieves.). See also CMA v. EPA, 870 F.2d at 243, 249 (5th Cir. 1989) which 

rejected a challenge to an effluent guidelines rule based on the argument that EPA must take 

into account the performance of actual POTWs. (“In 1977, when Congress amended the CWA to 

strengthen the provisions for controlling toxic pollutants, Congress provided that ‘an indirect 

discharger . . . had to ‘pretreat’ its waste waters so as to achieve, together with the [POTW] that 

treated the waste before final discharge . . . the same level of toxics removal as was required of a 

direct discharger.” Citing NRDC v. EPA, 790 F.2d 289, 292 (3rd Cir. 1986). Categorical 

pretreatment standards are technology-based and analogous to the BAT effluent-limitation 

guidelines for the removal of toxic pollutants – that is, they are intended to represent the best 

available technology that is economically achievable by indirect dischargers.” Citing H.R. Rep. 

No. 830, U.S. Code Cong. & Admin. News 1977, reprinted in 1977 Leg Hist at 271, 342, 

403). Moreover, where certain POTWs may provide additional treatment of pollutants in steam 

electric power plant wastewater, dischargers can benefit by using the removal credit regulations, 

a regulatory mechanism by which industrial users can discharge a pollutant in quantities that 

exceed what would otherwise be allowed under an applicable categorical pretreatment standard 

because it has been determined that the POTW to which the industrial user discharges 

consistently treats the pollutant. See 40 CFR § 403.7.

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment 

Code 15.d and response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in 

Comment Code 4.b for a discussion about EPA’s methods to identify pollutants of concern in fly 

ash and bottom ash transport water.

EPA has not modified 40 CFR§423 to account for individual POTW pollutant treatment 

capabilities because such a program already exists. See 40 CFR § 403.7. As explained in 

preamble Section XVI.C.4, CWA Section 307(b)(1) establishes a discretionary program for 

POTWs to grant “removal credits” to their indirect dischargers. Removal credits are a regulatory 

mechanism by which industrial users can discharge a pollutant in quantities that exceed what 

would otherwise be allowed under an applicable categorical pretreatment standard because it has 

been determined that the POTW to which the industrial user discharges consistently treats the 

pollutant. EPA has promulgated removal credit regulations as part of its pretreatment regulations. 

See 40 CFR § 403.7. These regulations provide that a POTW can give removal credits if 

prescribed requirements are met.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 143

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Summary of Flaws in the Proposed PSES and PSNS Limitations
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The proposed PSES and PSNS share some of the shortcomings of the proposed direct discharge 

BAT and NSPS revisions. The lack of data to characterize bottom ash transport water is an 

important flaw for PSES and PSNS just as it is for direct discharges. The assumption that bottom 

ash has the same pollutants of concern as fly ash makes the lack of a POTW pass-through 

analysis for fly ash transport water a significant flaw in the proposed PSES and PSNS.

Unfortunately, the proposed rule would require the same level of treatment of direct discharges 

as it does for indirect discharges, even though indirect discharges undergo significant additional 

treatment at a POTW. This is inappropriate, even if it is consistent with recent ELG updates.

Comment Response: 

For comments about the analysis of pass through of bottom ash transport water, see the response 

to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment 

Code 15.d and response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 38 in 

Comment Code 4.b for a discussion about EPA’s methods to identify pollutants of concern in fly 

ash and bottom ash transport water.

The promulgated PSES/PSNS are equivalent to BAT/NSPS, meaning that the same level of 

treatment is required by steam electric power plants that discharge to POTWs as or plants that 

discharge directly. Categorical pretreatment standards are technology-based and are analogous to 

BPT and BAT effluent limitations guidelines, and thus the Agency considered the same factors 

in promulgating PSES as it considered in promulgating BAT. See final preamble VIII.E. and 

VIII.F.

Certain POTWs may provide additional treatment of pollutants in steam electric power plant 

wastewater. Dischargers can use this additional treatment by using the removal credit 

regulations, a regulatory mechanism by which industrial users can discharge a pollutant in 

quantities that exceed what would otherwise be allowed under an applicable categorical 

pretreatment standard because it has been determined that the POTW to which the industrial user 

discharges consistently treats the pollutant. See 40 CFR § 403.7.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 140

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Local Limit Sufficiency
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The following table summarizes a survey of local limits for Georgia POTWs, subject to stateapproved industrial pretreatment programs. The table compares the proposed PSES/PSNS limits 

to the local limits of 14 different Georgia POTWs of different sizes. The survey is limited to 

Georgia, but the development of local limits is a uniform practice, and the Georgia local limits 

are likely similar nationwide.

ARSENIC 

μg/L 

MERCURY 

ng/L 

SELENIUM 

μg/L 

NITRATE 

mg/L 

COPPER 

mg/L 

PSES/PSNS for FGD 

and PSNS for CRL 8 242 16 0.17

PSES/PSNS for 

NCMCW 1.0

PSES/PSNS for 

Gasification 

Wastewater

4 1.76 453

POTW A 16 200 109 3.1

POTW B 281 1400 252 150* 0.31

POTW C 52 1000 21 605* 0.76

POTW D 120 2000 30* 2.6

POTW E 30 2100 93 19* 0.1

POTW F 60 2100 89 12* 0.11

POTW G 200* 3

POTW H 10,000 20 50* 0.6

POTW I 40 250 20 0.37

POTW J 1250 2000 16 75* 0.15

POTW K 74 300 103 0.23

POTW L 190 4700 120 244* 0.4

POTW M 350 500 70 0.11

POTW N 20 33,200 70 20* 2.07

* Local Limits is for Ammonia

A – City of Atlanta; B – Clayton County; C – Cobb County; D – DeKalb County; E – North 

Fulton County; F – South Fulton County; G – Gwinnett County; H – City of Dalton; I – City of 

Gainesville; J – City of Cornelia; K – Peachtree City; L – Cherokee County; M – Athens-Clarke 

County; N – Douglas County.

The Georgia local limits for copper are typically lower than the limit being proposed in the ELG 

Rule. This is a result of the type of biological treatment being used by the POTW and an 

assessment of the copper inhibition levels on the wastewater treatment microorganisms. As such, 

discharges to POTWs of NCMCWs will likely be determined by the local limit instead of the 

TBEL.
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Another issue identified by this survey is the typically higher local limits for arsenic, mercury 

and selenium. While having either a water quality-based effluent limit (for direct discharges) or a 

local limit (for indirect discharges) does not relieve an entity from meeting the minimum 

standards for treatment under the ELGs, it does indicate the present-day sophistication of 

municipal wastewater treatment plants. As discussed above, modern municipal wastewater 

treatment plants have been significantly upgraded since 1982 to deal with numerous factors 

including more stringent water quality-based limits.

The final point for comparison in the survey is the TBEL for nitrate-nitrite. The 0.17 mg/l limit is 

extremely low and would require significant and costly treatment before discharge to a sanitary 

sewer.

Comment Response: 

For comments about the pollutant pass through analysis, including the POTW removals, see the 

response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.

Although EPA proposed numerical limits for copper discharges in nonchemical metal cleaning 

wastes (NCMCWs), EPA did not promulgate the proposed limits. EPA agrees with the 

commenter that limits on discharges of NCMCWs to POTWs should and will be determined by 

local limits.

EPA’s final standards for FGD wastewater for nitrate/nitrite are 12.5 mg/L for the daily 

maximum limitation and 3 mg/L for the monthly average limitation, more than an order of 

magnitude greater than the proposed limits. See preamble section VIII.C.1 for more discussion of 

the final BAT effluent limits for FGD wastewater. EPA is not setting nitrate/nitrite standards for 

gasification or combustion residual wastewaters. For fly ash and bottom ash transport waters and 

FGMC wastewater, BAT is set at zero discharge and there would be no discharge of 

nitrates/nitrites for these waste streams. See preamble Section IX for EPA’s analysis of the costs 

and economic impact of the final rule.

EPA also notes that there are no indirect dischargers in the state of Georgia affected by this rule.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 138

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Pretreatment Standards (PSES and PSNS)
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Southern is also concerned about potential pretreatment standards, especially those proposed for 

leachate. In general, our analysis indicates that EPA’s pretreatment analysis is flawed, largely 

because it is based on obsolete data.

Pretreatment permits are required for industries discharging to a POTW that are determined to be 

Significant Industrial Users (SIU). An industry is considered an SIU if it meets any of the 

following:

 is subject to categorical pretreatment standards,

 discharges 25,000 gallons per day or more of process wastewater,

 contributes process wastewater to the POTW which makes up 5% or more of the 

hydraulic capacity,

 contributes process wastewater to the POTW which makes up 5% or more of the organic 

capacity, or

 has a reasonable potential for adversely affecting the wastewater treatment plant.

Most power plants’ cooling water is not discharged to a POTW; in many cases, this is prohibited 

due to cooling waters being too dilute. Discharges of FGD wastewater would likely meet 

a number of the SIU definitions above. Discharges of low volume waste (LVW) would also 

likely meet a number of the SIU definitions. Discharges of CMCW and NCMCW and possibly 

combustion residual leachate would likely meet only the criterion of categorical status.

The proposed revisions to 40 C.F.R. Part 423 create a number of concerns specific to indirect 

dischargers. Concerns related to the proposed modifications of the PSES and Pretreatment 

Standards for New Sources (PSNS) are as follows:

1. POTW pollutant pass-through analysis,

2. local limit sufficiency,

3. Jordan memorandum exception, and

4. PSNS applicability.

Comment Response: 

For comments about POTW pollutant pass-through analysis, see response to DCN EPA-HQOW-2009-0819-4379-A1, Excerpt Number 144 in Comment Code 6.b. For comments about 

local limit sufficiency, see response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 139 in Comment Code 6.b. The final rule does not establish PSES for combustion 

residual leachate because TSS and the pollutants that they represent do not pass through POTWs. 

EPA would continue to reserve BAT/NSPS/PSES/PSNS for non-chemical metal cleaning waste, 

as the previously established regulations do so comments related to pass through of leachate or 

not relevant to the final rule.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149 in Comment Code 

6.g.vii regarding new sources.
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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: 81

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The POTW Pass-through Analysis is Incomplete.

As stated at 78 Fed. Reg. 34,457 col. 1, EPA did not perform its traditional pass- through 

analysis for bottom ash. EPA’s reasoning is that the proposed standard is a no- discharge 

standard and therefore the pass-through of pollutants from POTWs to receiving streams will not 

occur. But this reasoning fails to consider that each of EPA’s preferred regulatory options allows 

for discharge of bottom ash, thereby necessitating a comparison of the POTW removal 

efficiencies with that of the proposed PSES and PSNS standards.

The POTW Removal Percentages are Obsolete.

EPA used a 50-POTW study from 1982 in determining POTW removal efficiencies for arsenic 

and mercury. This study is outdated and does not account for the advanced level of treatment 

now occurring at the nation’s POTWs.

Moreover, EPA’s suggested removal efficiency for arsenic differs significantly from previous 

ELG rulemakings. The 1998 development of effluent limitations for the Centralized Waste 

Treatment category determined that the arsenic removal efficiency of a well-operated POTW is 

91%, as opposed to the 66% cited in this rulemaking.

The BAT Removal Percentages are Inaccurate.

EPA compared the removal percentages for well-operated POTWs with the removal percentages 

of the technology associated with the proposed FGD wastewater BAT limitations. This analysis 

is flawed because of obsolete POTW data, as described above, and also because of inflated BAT 

removal efficiencies that over-estimate the performance of the physical- chemical-biological 

treatment systems.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.

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: 80

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Pretreatment Standards (PSES and PSNS)

The National Pretreatment Program is a cooperative effort of federal, state, and local 

environmental regulatory agencies. EPA regulations governing the industrial pretreatment 

program are in 40 C.F.R. Part 403. Categorical effluent limitations are provided for a number of 

industries; those associated with the proposed update to 40 C.F.R. Part 423 are discussed below. 

The proposed revisions to 40 C.F.R. Part 423 create a number of concerns specific to indirect 

dischargers.

Like the proposed BAT options, EPA’s proposed pretreatment standards and their development 

are flawed in further ways exemplifying many of the underlying concerns EEI and its members 

have with the proposed rule as a whole, including an impenetrable record, insufficient data to 

support the proposed limits, significantly flawed assumptions, and resulting compounded flaws 

in analysis and conclusions reached.

The proposed pretreatment standards for existing sources (PSES) and PSNS share many of the 

shortcomings of the proposed direct discharge BAT and NSPS revisions. As discussed in detail 

in the BAT context above, the lack of data to characterize bottom ash transport water is an 

important flaw for PSES and PSNS just as it is for direct discharges. Similarly, the assumption 

that bottom ash has the same pollutants of concern as fly ash makes the lack of a POTW passthrough analysis for fly ash transport water a significant flaw in the proposed PSES and PSNS.

Additionally, the proposed rule requires the same level of treatment for indirect discharges as it 

does for direct discharges, even though indirect discharges undergo significant additional 

treatment at a POTW. This is inappropriate, even if it is consistent with recent ELG updates.

Comment Response: 

For comments about pass through analysis for bottom ash transport water see response to DCN 

EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144. For comment about the level of 

treatment required by PSES see response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 143.

Commenter Name: Cynthia A. Finley

Commenter Affiliation: National Association of Clean Water Agencies (NACWA)

Document Control Number: EPA-HQ-OW-2009-0819-4507-A2

Comment Excerpt Number: 2
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4-127

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA used the 1982 50 POTW Study to determine POTW removal efficiencies for arsenic and 

mercury. However, the 50 POTW Study is now over 30 years old, and the removal efficiencies 

in the Study are no longer valid. Treatment technologies at most POTWs have improved since 

the Study was completed, and pretreatment programs have significantly reduced concentrations 

of pollutants, which impact treatment plant removal efficiency values. NACWA has 

communicated with EPA in the past about the need to update the 50 POTW Study and to allow 

POTWs to calculate removal efficiencies rather than use the outdated information in the Study, 

and copies of these communications can be provided to EPA if requested. For the proposed ELG 

and other ELGs that are developed in the future, EPA should use a different basis for 

determining removal efficiencies rather than relying on the outdated 50 POTW Study.

Comment Response: 

For comments about the POTW removals used in EPA’s pass through analysis, see response to 

DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.

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: 62

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA has proposed four preferred regulatory options for its contemplated PSES. PSNH is 

specifically interested in the PSES potentially applicable to FGD waste waters and disagrees 

with each of EPA’s proposed regulatory options for this waste stream. For FGD waste water, 

Options 3, 3b and 4a would establish PSES equivalent to the chosen BAT limits EPA proposed 

for this waste stream in the Proposed Rule, with Option 3b deferring to publicly owned treatment 

works (“POTWs”) the development of local limits for pollutants found in FGD waste water that 

cause pass through interference at their respective facilities for facilities with a total wetscrubbed capacity of less than 2,000 MW. Option 3a would defer the development of local limits 

for FGD pollutants to POTWs for all steam electric generating facilities regardless of wetscrubbed capacity.26 EPA’s proposed regulatory options are semantic and PSNH disagrees with 

each of them. EPA must first conduct a proper analysis of current POTW data before 

determining even Option 3a is necessary, as explained in detail below.
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To supposedly determine whether PSES are needed as a part of this rulemaking, EPA undertook 

a pass-through analysis. EPA’s methodology for this analysis essentially consisted of a 

comparison of POTW removal efficiencies to the removal efficiencies estimated for the 

treatment technologies for the proposed ELG. Specifically, EPA compared the percentage of a 

pollutant removed by well-operated POTWs performing secondary treatment to the percentage 

removed by the proposed BAT/NSPS treatment systems. If the industry-median BAT/NSPS 

percent removal is greater than the median POTW percent removal, the pollutant is deemed to 

pass through and is proposed for regulation in the ELG rule. This analysis by the agency was 

flawed. It relied upon a comparison of removal efficiencies between current industry treatment 

options and POTW treatment analyses from a 1982 study of 50 well-operated POTWs 

performing secondary treatment. There have been substantial, nationwide improvements in waste 

water treatment systems in the last 30 years. In fact, a predominant number of individuals in the 

United States are served by advanced waste water treatment systems (i.e., beyond secondary 

treatment). See EPA, Clean Watersheds Needs Survey 2008 Report to Congress, EPA-832-R-10-

002. Thus, it is without question that a comparison of the current removal efficiencies of POTWs 

would result in a finding that a pollutant receives greater treatment by a POTW than it would by 

a BAT/NSPS treatment system.

EPA must collect and consider more recent removal percentage data from POTWs in order to 

carry out a true apples-to-apples comparison prior to establishing any PSES in any final 

rule. Alternatively, the agency could allow for a site-specific, real-time comparison of POTW 

design removal efficiencies with that of the finalized BAT/NSPS technologies, or simply defer 

all determinations as to the need for such standards to local POTWs. Regardless of how EPA 

proceeds, it is without question that if a POTW is able to treat these wastes to a higher degree 

than what costly additional treatment installations at a power plant could achieve, the agency is 

required to consider and accept that such PSES are not necessary. This change would benefit 

both water and electricity utility rate payers and encourage partnerships between power 

companies and water utilities for both source water and waste water handling options.

26 Because the PSES considered by EPA in this Proposed Rule are premised on the same 

analyses and agency findings as the proposed BAT standards, they suffer from the same 

shortcomings. PSNH has thoroughly discussed the flaws in EPA’s proposed BAT determinations 

in these comments and hereby makes reference to them as applicable to the agency’s proposed 

PSES. PSNH also incorporates by reference as if fully set out herein UWAG’s comments and 

critiques to EPA’s proposed PSES.

Comment Response: 

For comments about the POTW removals used in EPA’s pass through analysis, and the POTW 

removal for arsenic used in development of the Centralized Waste Treatment pretreatment 

standards, see response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.
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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: 177

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. POTW Pollutant Pass-Through Analysis

The preamble (78 Fed. Reg. at 34,456-57) and sections 11-10 through 11-15 of the 2013 TDD 

discuss how EPA determined POTW pass-through for each of the different wastestreams. EPA’s 

methodology essentially compares POTW removal efficiencies to the removal efficiencies 

estimated for the treatment technologies for the proposed ELG. EPA compares the percentage of 

a pollutant removed by well-operated POTWs performing secondary treatment to the percentage 

removed by the proposed BAT/NSPS treatment systems. If the BAT/NSPS percent removal is 

greater than a typical POTW percent removal, the pollutant is deemed to pass through and is

proposed for regulation in the ELG rule.

There is an obvious flaw in this methodology which is not unique to the steam electric ELG 

rulemaking. The POTW removal efficiency is based on a 1982 study of 50 well-operated 

POTWs performing secondary treatment. Without question, a study of 50 well-operated POTWs 

in 2013 would yield significantly higher removal efficiencies and therefore an increased 

likelihood that a pollutant receives greater treatment by a POTW than it would by a BAT/NSPS 

treatment system. In fact, since 1982 there has been a 101% increase in the number of people 

served by advanced wastewater treatment systems in the U.S., and advanced (beyond secondary) 

treatment is now predominant nationwide. See EPA “Clean Watersheds Needs Survey 2008 

Report to Congress,” EPA-832-R-10-002.

EPA also assumed that the pollutants of concern in bottom ash were the same as those in fly ash, 

due to the common fuel source. This assumption is a concern for both direct and indirect ELG 

proposals, but the issue of POTW pass-through assessment compounds the concern from a 

PSES/PSNS viewpoint. EPA set the proposed TBEL removal efficiency at 100% for those 

wastestreams required to meet non-discharge status. This rationale is appropriate for all 

wastestreams other than bottom ash transport water, which is authorized for discharge under each 

of EPA’s preferred options.

Below is a summary of the POTW pass-through analysis:

Treatment Option Pollutant

POTW 

Removal

%

BAT/ NSPS 

Removal %

Pass 

Through?

Chemical precipitation for FGD / 

CRL

Arsenic 65.8 99.5 Yes

Mercury 90.2 99.9 Yes
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Chemical precipitation followed 

by biological treatment for FGD / 

CRL

Arsenic 65.8 99.5 Yes

Mercury 90.2 99.9 Yes

Nitrate-Nitrite 90.0 99.6 Yes

Selenium 34.3 99.9 Yes

Mechanical Vapor Compression Arsenic 65.8 99.5 Yes

Evaporation for FGD

Mercury 90.2 99.9 Yes

Selenium 34.3 99.9 Yes

TDS 0 99.7 Yes

Mechanical Vapor Compression 

Evaporation for IGCC

Arsenic 65.8 99.5 Yes

Mercury 90.2 99.9 Yes

Selenium 34.3 99.9 Yes

TDS 0 99.7 Yes

Nonchemical Metal Cleaning 

Waste Copper - 1982 Rule Yes

*1 - Technical Development Document for the proposed effluent limitation guidelines and standards for the steam 

electric power generating point source category. EPA-821-R-13-002.

*2 - Development Document for proposed effluent limitation guidelines and standards for the centralized waste 

treatment industry. EPA-R-98-020.

The data supporting the POTW removal percents are obsolete, and therefore a modification of 

the ELG rule to allow for an updated local demonstration would be desirable. The Rule could 

allow for a site-specific, real-time comparison of publicly-owned treatment work (POTW) design 

removal efficiencies with that of the finalized BAT/NSPS technologies. If a POTW is able to 

treat these wastes to a higher degree than what costly additional treatment installations at a 

power plant could achieve, this should be considered. This change would benefit both water and 

electricity utility rate payers and encourage partnerships between power companies and water 

utilities for both source water and wastewater handling options.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 180

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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E. Summary of Flaws in the Proposed PSES and PSNS Limitations

The proposed PSES and PSNS share some of the shortcomings of the proposed direct discharge 

BAT and NSPS revisions. EPA’s use of flawed data to characterize bottom ash transport water 

is as important for PSES and PSNS as it is for direct discharges. The assumption that bottom ash 

transport water has the same pollutants of concern as fly ash transport water makes the lack of a 

POTW pass-through analysis for fly ash transport water a significant flaw in the proposed PSES 

and PSNS.

The proposed rule would require the same level of treatment of direct discharges as it does for 

indirect discharges, even though indirect discharges undergo significant additional treatment at a 

POTW. This is inappropriate, even if it is consistent with recent ELG updates.

Comment Response: 

For comment about the pass through analysis for bottom ash transport water, see response to 

DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144. For comment about the level of 

treatment required by PSES, see response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 143.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 181

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

additional flaws in the proposed PSES requirements are as follows.

1. The POTW Pass-Through Analysis Is Incomplete

EPA did not perform its traditional pass-through analysis for bottom ash transport water. 78 Fed. 

Reg. at 34,457 col. 1. EPA’s reasoning is that the proposed standard is a no-discharge standard 

and therefore pass-through will not occur. But this reasoning fails to consider that each of EPA’s 

preferred regulatory options allows for discharge of bottom ash, thereby necessitating a 

comparison of the POTW removal efficiencies with that of the proposed PSES and PSNS 

standards.

2. The POTW Removal Percents Are Obsolete
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EPA used the 1982 50 POTW study when determining POTW removal efficiencies for arsenic 

and mercury. This study is outdated and does not account for the advanced level of treatment 

now occurring at the nation’s POTWs.

Moreover, EPA’s suggested removal efficiency for arsenic differs significantly from previous 

ELG rulemakings. In developing its 1998 effluent limitations for the CWT category, EPA 

determined that the arsenic removal efficiency of a well-operated POTW is 91%, as opposed to 

the 66% cited in this rulemaking.

3. The BAT Removal Percentages Are Inaccurate

EPA compared the removal percentages for well-operated POTWs with the removal percentages 

of the technology associated with the proposed FGD wastewater BAT limitations. This analysis 

is flawed because of obsolete POTW data, as described above, and also because of inflated BAT 

removal efficiencies that over-estimate the performance of the physical-chemical-biological 

treatment systems.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 229

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. Local Limits

The following table summarizes a survey of local limits for Georgia POTWs, subject to stateapproved industrial pretreatment programs. The table compares the proposed PSES/PSNS limits 

to the local limits of 14 different Georgia POTWs of different sizes. The survey is limited to 

Georgia, but the development of local limits is a uniform practice, and the Georgia local limits 

are likely similar nationwide.
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* Local Limit is for Ammonia

A – City of Atlanta; B – Clayton County; C – Cobb County; D – DeKalb County; E – North Fulton County; F –

South Fulton County; G – Gwinnett County; H – City of Dalton; I – City of Gainesville; J – City of Cornelia; K –

Peachtree City; L – Cherokee County; M – Athens-Clarke County; N – Douglas County.

The Georgia local limits for copper are typically lower than the limit being proposed in the ELG 

rule. This is a result of the type of biological treatment being used by the POTW and an 

assessment of the copper inhibition levels on the wastewater treatment microorganisms. As

such, discharges to POTWs of nonchemical metal cleaning wastes will likely be determined by 

the local limit instead of the TBEL.

Another issue identified by this survey is the typically higher (indeed, considerably higher) local 

limits for arsenic, mercury and selenium. While having either a water quality-based effluent 

limit (for direct discharges) or a local limit (for indirect discharges) does not relieve an entity 

from meeting the minimum standards for treatment under the ELGs, it does indicate the presentday sophistication of municipal wastewater treatment plants. As discussed above, modern 

municipal wastewater treatment plants have been significantly upgraded since 1982 to deal with 

numerous factors including more stringent water quality-based limits.

The final point for comparison in the survey is the TBEL for nitrate-nitrite. The 0.17 mg/L limit 

is extremely low and would require significant and costly treatment before discharge to a 

sanitary sewer.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 140.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 176

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposed revisions to 40 C.F.R. Part 423 create a number of concerns specific to indirect 

dischargers. Concerns related to the proposed modifications of the PSESs and PSNSs are as 

follows:

1. POTW pollutant pass-through analysis,

2. local limit sufficiency,

3. Jordan memorandum policy, and

4. PSNS applicability.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 138 in Comment 

Code 6.b.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 162

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA's pass through analysis, we think is flawed, mostly because EPA used POTW removal 

efficiencies from the 1982 study of 50 well operated POTWs, and since then, there has been a 
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great increase in the number of people served by advanced wastewater treatment, which has far 

greater treatment efficiency.

So, for example, EPA used a 66 percent removal efficiency for arsenic; whereas, the 1998 

development document for the Centralized Waste Treatment Category found that the arsenic 

removal efficiency of a well operated POTW is 91 percent. It may sound trivial, but it goes to 

the heart and soul of what the pretreatment standard should require.

Comment Response: 

For comments about the POTW removals used in EPA’s pass through analysis, and the POTW 

removal for arsenic used in development of the Centralized Waste Treatment pretreatment 

standards, see response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 144.
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6.c. Regulatory Options – Technology Versus Water Quality Based Limitations

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 61

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Proposed Limits are Lower Than Safe Drinking Water and Water Quality-Based 

Limits

The proposed technology-based limits are well below the Safe Drinking Water Act (SDWA) 

limits as well as certain Water Quality Based Effluent Limits (WQBELs). For example, the 

proposed arsenic BAT limit of 8 μg/L (daily max.) and monthly average limit of 6 μg/L are both 

below the primary arsenic drinking water standard of 10 μg/L. Likewise with mercury, selenium 

and nitrate/nitrite, the monthly averages are 94%, 80% and 98% lower that the primary SDWA 

maximum contaminant levels, respectively, for these constituents.

The proposed BAT limits are also lower than WQBELs in several instances. For example, the 

Florida Class III Marine water quality standard for total arsenic (62-302.530 F.A.C.) is 50 μg/L 

(36 μg/L for trivalent arsenic), which is several times greater than the proposed BAT limit. The 

same is true for selenium, which has a Class III Marine WQBEL of 71 μg/L compared to the 16 

μg/L (daily max.) and 10 μg/L monthly average values proposed for FGD wastewater.

It is inconceivable that a facility could theoretically meet a WQBEL limit for arsenic and/or 

selenium, but yet exceed a technology-based limit.

Comment Response: 

As explained in preamble section IV.A, the CWA prohibits the discharge of pollutants from a 

point source to waters of the U.S., except as authorized by a National Pollutant Discharge 

Elimination System (NPDES) permit. In addition, it is the goal of the CWA that the discharge of 

toxic pollutants be eliminated.

To achieve these ends, the CWA establishes two basic approaches for controlling the discharge 

of pollutants in NPDES permits - technology-based effluent limitations issued under Effluent 

Limitations Guidelines (ELGs) and water quality-based effluent limitations (WQBELs). These 

two types of pollutant limitations, required by the CWA, are derived for different purposes and 

with different methods, and in permits, the technology-based limitation serves as the first level of 

control. Technology-based controls, such as Best Available Technology (BAT), are required 

that establish a national level of performance for all dischargers. EPA establishes technologybased controls using 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 best 
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performance that is technologically available and economically achievable by the industry. New 

Source Performance Standards (NSPS) reflect “the greatest degree of effluent reduction” that is 

achievable based on the “best available demonstrated control technology” (CWA section 

306(a)(1)) -- see preamble section II.

The final ELGs for the discharge of steam electric wastewater do include numeric limitations as 

the commenter points out. For example, the BAT limitations and NSPS for FGD wastewater 

include numeric limitations for four pollutants: arsenic (total), mercury (total), selenium (total), 

and nitrate/nitrite as N. These limits were calculated from measured discharges from wastewater 

treatment units designed and operated to control the identified pollutants. As described in final 

TDD Section 13.1.2, to develop the limitations for selenium and nitrate/nitrite, EPA used data 

from two plants using a chemical precipitation system followed by anoxic/anaerobic biological 

treatment operated to remove selenium. As also described in final TDD Section 13.1.2, to 

develop the limitations for arsenic and mercury, EPA used data from four plants using chemical 

precipitation systems employing both hydroxide and sulfide precipitation and iron coprecipitation.

Water quality-based effluent limitations are used to ensure the discharge of pollutants meets 

applicable state water quality standards and are applicable only if the technology based controls 

are insufficient to meet applicable water quality standards. In contrast to ELGs, water qualitybased effluent limitations are based on applicable water quality standards that take into account 

the potential impacts on the actual receiving waters of the permitted discharge. For example, 

water quality standards upon which WQBELs are based account for the size and type 

of waterbody (e.g., fresh water, saltwater), the aquatic life present, and the magnitude, duration, 

and frequency of the discharge.

On the other hand, the Safe Drinking Water Act (SDWA) authorizes EPA to establish minimum 

standards to protect tap water and requires all owners or operators of public water systems to 

comply with these primary, health-related, standards. Drinking water standards are based on risk 

to human health through exposure to the water and feasibility. They do not account for 

bioaccumulation in fish. Many of the pollutants discharged by coal-fired steam electric power 

plants, such as mercury, arsenic and selenium, are bioaccumulative and will accumulate in fish 

tissue posing health risks to humans, birds and other wildlife that consume the fish. Eliminating 

the discharge of pollutants is explicitly one of the objectives of section 301 of the Act. Since 

the ELGs, WQBELs, and drinking water standards each use different approaches for protecting 

human health and the environment, and they are developed using different criteria as required by 

law (CWA or SDWA), ELGs, WQBELs, and drinking water standards can, and frequently 

do, differ.

Thus, as required by the CWA, the promulgated limitations are based on the performance and 

economic achievability of available control technology, taking into account a number of factors 

such as costs and non-water quality environmental impacts, which may differ from 

concentrations established in drinking water standards or from concentrations established in 

WQBELs to protect impacts of a particular discharge on a specific waterbody.
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Commenter Name: Jeffrey A. McNelly

Commenter Affiliation: Anthracite Region Independent Power Producers Association 

(ARIPPA)

Document Control Number: EPA-HQ-OW-2009-0819-4453-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

While the execution of the rule is tied to loadings, the water quality standards have been 

established based on concentrations (mg/l or ug/l) to protect uses.

Comment Response: 

For an explanation of the difference in the statutory basis, the purpose, the derivation, and the 

implementation in NPDES permits, of effluent guideline limitations (as promulgated under this 

final rule) as opposed to water quality standards, the commenter should see the response to DCN 

EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61.

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: 27

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA did not account for discharge into non-fresh water bodies when proposing BAT based 

limits, yet EPA recognizes different water quality based limits for fresh and salt water bodies.

Raven Power recommends that an exception from the proposed BAT technology-based limits be 

allowed for discharges to tidal waters. Permit limits for discharges to tidal waters should be 

based on site-specific water quality based effluent limits.

Comment Response: 

EPA is not required to consider receiving water quality in setting technology-based effluent 

limitations. See, e.g., American Frozen Food Inst. v. Train, 539 F.2d 107,121 (D.C. Cir. 

1976)(The determination of BPT is not to be based upon the quality of the receiving waters.). 

Assn of Pacific Fisheries v. EPA, 615 F.2d 794 (9th Cir. 1980)(EPA is not supposed to 

demonstrate the incremental effect on receiving water quality). Consolidated Coal Co. v. Costle, 

604 F.2d 239, 245 (4th Cir. 1979)(Receiving water quality is nota basis for settling BPT effluent 
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or FDF). Weyerhaeuser Co. v. Costle, 599 F.2d 1011, 1028, 1042 (D.C. Cir. 1978)(Impact on 

receiving water quality not a factor. The use of receiving water as a waste treatment system is 

unacceptable. Legislative History of the Water Pollution Control Act Amendments of 1972, 93 

Cong. 1st Sess. at 1425.(Comm. Print 1973).

For an explanation of the difference in the statutory basis, the purpose, the derivation, and the 

implementation in NPDES permits, of effluent guideline limitations (as promulgated under this 

final rule) as opposed to water quality standards, the commenter should see the response to DCN 

EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61.

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: 37

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Exceptions should be considered for BAT limits at facilities discharging into tidal waters.

Comment Response: 

EPA is not required to consider receiving water quality in setting technology-based effluent 

limitations. See, e.g., American Frozen Food Inst. v. Train, 539 F.2d 107,121 (D.C. Cir. 

1976)(The determination of BPT is not to be based upon the quality of the receiving waters.). 

Assn of Pacific Fisheries v. EPA, 615 F.2d 794 (9th Cir. 1980)(EPA is not supposed to 

demonstrate the incremental effect on receiving water quality). Consolidated Coal Co. v. Costle, 

604 F.2d 239, 245 (4th Cir. 1979)(Receiving water quality is nota basis for settling BPT effluent 

or FDF). Weyerhaeuser Co. v. Costle, 599 F.2d 1011, 1028, 1042 (D.C. Cir. 1978)(Impact on 

receiving water quality not a factor. The use of receiving water as a waste treatment system is 

unacceptable. Legislative History of the Water Pollution Control Act Amendments of 1972, 93 

Cong. 1st Sess. at 1425.(Comm. Print 1973).

For an explanation of the difference in the statutory basis, the purpose, the derivation, and the 

implementation in NPDES permits, of effluent guideline limitations (as promulgated under this 

final rule) as opposed to water quality standards, the commenter should see the response to DCN 

EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61.

Commenter Name: Jared Morrison

Commenter Affiliation: Westar Energy

Document Control Number: EPA-HQ-OW-2009-0819-4469-A1
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Comment Excerpt Number: 3

External Review Flag: Statistics

External Review Incorporated into Response: No

Comment Excerpt: 

Source Water Contribution

EPA specifically requested comments on source water contribution as applicable to the proposed 

FGD wastewater guidelines. This raises concern for Westar considering the fact that all of the 

numeric limits proposed for FGD wastewater are significantly lower than the federal maximum 

contaminant levels (MCLs) for drinking water. The proposed limits for nitrates/nitrites and 

mercury are actually more than an order of magnitude lower than they are for drinking water.

Specifically, in Westar’s experience with FGD scrubber operation and review of the pilot data, 

we have concerns on this topic in regards to mercury. The JEC’s main water source is the Kansas 

River. The Kansas water quality criterion for aquatic life for mercury is 770 ng/L, and the 

criteria for food procurement and domestic water supply are 146 and 140 ng/L, respectively 

(KDHE 2004). The EPA proposed numeric limit for mercury, in some of the preferred options, 

requires a daily average of 119 ng/L, which is lower than even the most stringent water quality 

criterion for the Kansas River. Under the proposed effluent limits, the possibility exists that 

Westar Energy would be required to treat incoming raw water to reduce mercury, or at a 

minimum, treat the effluent to a level that exceeds the most stringent Kansas water quality 

criterion. Requiring a more stringent standard for the power industry than what is required for 

publicly used water bodies within the State of Kansas seems unreasonable. Westar Energy could 

face a major hurdle if the numeric limits, as proposed, are set into place. Considering the 

plant uses around 24,000 gpm of raw water, treatment of source water, if required, would be 

expensive and complex and could adversely impact rate payers with no appreciable benefit to the 

environment.

Comment Response: 

For an explanation of the difference in the statutory basis, the purpose, the derivation, and the 

implementation in NPDES permits, of effluent guideline limitations (as promulgated under this 

final rule) as opposed to water quality standards and drinking water MCLs, the commenter 

should see the response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61.

EPA notes that as required by the CWA, the promulgated limitations are based on the 

performance and economic achievability of available control technology, which may be lower 

than concentrations established in drinking water standards and concentrations established in 

WQBELs to protect against impacts of a particular discharge on a specific receiving stream.

The commenter should also recognize that many of the pollutants discharged by coal-fired steam 

electric power plants, such as mercury, arsenic and selenium, are bioaccumulative and will 

accumulate in fish tissue posing health risks to humans, birds and other wildlife that consume the 

fish. Reducing the loading to the environment of these bioaccumulative pollutants as much as 
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possible using the best available technology that is economically achievable, is consistent with

the Clean Water Act, which calls in section 301 for the elimination of the discharge of pollutants. 

EPA’s investigation of steam electric power plant wastewater demonstrates that it is reasonable 

to treat FGD wastewater to reduce mercury concentrations. EPA notes that it found that 

untreated FGD wastewater concentrations of total mercury are higher than the Kansas water 

quality criterion for aquatic life described by the commenter. As discussed in final TDD section 

10.2.1, EPA found that most steam electric power plants treat FGD wastewater using only 

surface impoundments and found that the average surface impoundment effluent concentration 

for total mercury was 7.78 ug/L (7,780 ng/L) about 10 times higher than the Kansas water 

quality criterion for aquatic life described by the commenter (770 ng/L).

EPA points out, that in special circumstances, for some facilities the mercury discharge limits 

promulgated at 40 CFR part 423 may be less than the concentrations of the facility's intake 

water. For these circumstances, permit writers may adjust the effluent standard for the presence 

of mercury in the intake water, following the procedures set out in 40 C.F.R.§129.6. These 

provisions allow effluent limitations to be adjusted to reflect credit for toxic pollutants present in 

the facility’s water supply if two criteria are met: 1) the source of the water supply is the same 

waterbody into which the discharge is made and 2) it is demonstrated that the toxic pollutants 

present in the water supply will not be removed by the wastewater treatment system designed to 

meet effluent standards in the absence of the toxic pollutants in the water supply.

Commenter Name: Peter A. Tennant

Commenter Affiliation: Ohio River Valley Water Sanitation Commission (ORSANCO)

Document Control Number: EPA-HQ-OW-2009-0819-4512-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Mercury contamination is a cause of fish consumption advisories in the Ohio River 

Basin. ORSANCO and its member States have discharge limits ranging from 51 ng/L to 12 ng/L. 

All of the proposed options (3a, 3b, 3, 4) have mercury discharge limits far in excess of the 

current limits. Because mercury is a bio-accumulative chemical there is a need to reduce 

loadings as much as possible. These limits should be re-evaluated and brought more into line 

with standards already in place.

Comment Response: 

As explained in preamble section IV.A, the CWA prohibits the discharge of pollutants from a 

point source to the waters of the U.S., except as authorized by a National Pollutant Discharge 

Elimination System (NPDES) permit. The CWA establishes a two-part approach for deriving 

limits for the allowable discharge of pollutants if authorized in these permits; technology-based 

controls that establish a minimum national level of performance for all dischargers based on the 
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best available control technology that is economically achievable; and water quality-based 

effluent limitations (WQBELs) if needed to meet applicable state water quality standards at a 

specific location in specific waterbodies.

The mercury discharge limits identified by the commenter are specific to the needs of the 

particular discharge location (the Ohio River). The mercury effluent limitations ELGs that EPA 

has promulgated are technology-based controls that establish a national level of performance for 

all dischargers. As needed to meet applicable water quality standards at a specific location, the 

permit writer may include more stringent discharge limitations in the permit.

For more explanation of the difference in the statutory basis, the purpose, the derivation and the 

implementation in NPDES permits of effluent guideline limitations (as promulgated under this 

final rule) as opposed to water quality standards, the commenter should also see the response to 

DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61.

Commenter Name: Peter A. Tennant

Commenter Affiliation: Ohio River Valley Water Sanitation Commission (ORSANCO)

Document Control Number: EPA-HQ-OW-2009-0819-4512-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

ORSANCO supports the reduced arsenic limit as this is more protective of the drinking water 

use of the Ohio River.

Comment Response: 

EPA notes that the arsenic effluent limitations that EPA has promulgated are technology-based 

controls that establish a national level of performance for all dischargers.

Commenter Name: Bradley Coyle

Commenter Affiliation: Big Rivers Electric Corporation (BREC)

Document Control Number: EPA-HQ-OW-2009-0819-4664-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Proposed Selenium and Mercury discharge standards are impractical.
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The standards proposed by the ELGs provide near impracticality with regards to various 

constituents that are found in the water discharges from a steam electrical generation facility. 

Selenium standards to be set at a limit of 5 parts per billion (ppb or microgram per liter) are at 

the edge of existing technology for the detection of such a parameter. Additionally, the standard 

of mercury to a limit of 242 nanograms per liter – a standard which is two times less than the 

allowable maximum contamination limit (MCL) established by the Clean Drinking Water Act –

is simply unnecessary, impractical and offers little benefit to human health and the environment. 

With an established MCL of 2 ppb and the notion that no one will be directly consuming effluent 

from a steam-fired plant, a limitation of 242 ng/l is simply nonsensical and provides little in the 

way of protecting the environment. Additionally, a ‘one size fits all’ approach is nearly 

impossible from the standpoint of grounded and accepted science in that the effluent that would 

need to meet the aforementioned goals will be ever changing depending on fuel quality and/or 

operational aspects of the facility. BREC feels strongly that these particular aspects lack just 

reason for implementation to such a nearly unachievable level of removal of these particular 

constituents.

Comment Response: 

With regard to the commenter's contention that the proposed ELGs are impractical, EPA 

established ELGs that include numeric limitations for mercury for three wastestreams and for 

selenium for two wastestreams. As discussed in preamble section XI and further documented in 

Section 13 of the TDD, these numeric limitations are based on measured pollutant concentrations 

in the effluent of well-operated wastewater treatment plants. As further discussed in preamble 

section IX, EPA concluded that these ELGs are economically achievable.

With regard to the commenter's comparison of ELGs to drinking water standards, the commenter 

should see response to DCN EPA-HQ-OW-2009-0819-4305-A3 Excerpt Number 61. Making 

such comparisons is invalid.

With regards to the commenter's allegation of a “One size fits all” approach, the ELGs are 

performance based. That is, although they are based on an evaluation of the performance of 

certain control technologies, the regulated facilities may meet their NPDES permit discharge 

limits using any effective control technology that appropriately “fits” their facility’s specific 

conditions.

EPA also notes that the technologies identified as BAT include flexibility to accommodate 

changing facility conditions. For example, for FGD wastewater, as discussed in Section 8.3.1 of 

the TDD, the BAT and NSPS technology basis is chemical precipitation (hydroxide and 

organosulfide) followed by biological treatment (anoxic/anaerobic fixed-film biological 

treatment system designed to remove heavy metals, selenium, and nitrates). To accommodate 

plant operational variability, an equalization tank with a 24-hour residence time is part of this 

treatment train. In addition, biological treatment includes an ORP monitor which identifies the 

need to add reducing agents (e.g., sodium bisulfite) to mitigate high concentrations of free 

oxidants and protect the biological treatment system. (See Section 9.6 of the TDD for elements 

included in costed BAT for FGD wastewater.)
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As discussed in Section 3.4 of the TDD, EPA collected data to characterize treatment 

performance of the systems used to treat the FGD scrubber purge wastewaters. EPA selected 

plants to represent a variety of characteristics, including the type of coal and various plant 

operational conditions, and conducted on-site sampling activities over 4 consecutive days. EPA 

also required a subset of plants to collect additional characterization data over a four- to fivemonth period. Lastly, EPA supplemented the field sampling program data with long-term plant 

self-monitoring data. See Section 13 of the TDD.

With respect to the comment on changing fuel quality, EPA reviewed available data on fuel type 

for the facilities that are the basis of the limitations and found that a well-designed well-operated 

plant will be able to achieve effluent limitations in the final rule see the Variability in Flue Gas 

Desulfurization Wastewater: Monitoring and Response Memorandum (DCN SE05846).

Because of the BAT elements that allow the treatment to accommodate variations in untreated 

wastewater resulting from “fuel quality and/or operational aspects of the facility,” and because 

facilities that implement the control technologies can consistently treat wastewater to the BAT 

effluent limitation concentrations, EPA concludes that the promulgated selenium and mercury 

discharge standards are not only best available technology economically achievable.
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6.d. Regulatory Options – NPDES Program Provisions 

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Variance from the Final ELGs

Conemaugh Generating Station has a suspended growth biological treatment system that targets 

the removal of selenium in a more concentrated FGD wastewater. The system at Conemaugh 

was designed to reduce selenium concentrations to a monthly average effluent limit of 0.25 mg/l 

and daily maximum of 0.5 mg/l from more concentrated FGD wastewater than what is used as 

EPA model technology. The relatively higher chloride concentrations inhibit biological activity. 

To facilitate higher levels of selenium removal, Conemaugh may need to dilute their FGD 

wastewater to between 3,200 and 8000 ppm chloride (EPA model), which is not possible because 

the WWTP would be hydraulically overloaded. To date, the reduction of selenium is sufficient to 

meet the WQBELs in the station’s NPDES permit. Because the Conemaugh Generating Station 

has already installed controls that target selenium and the NPDES WQBELs are protective of the 

receiving stream, NRG requests a variance from the final ELGs for selenium for FGD 

wastewater under Section 301 due to fundamentally different factors. Other plants that satisfy 

WQBELs should also be provided a variance from the final ELGs as well.

Comment Response: 

EPA identified chemical precipitation followed by biological treatment as the technology basis 

for the final BAT limitations for FGD wastewater. More specifically, the technology basis for 

BAT is a chemical precipitation system that employs hydroxide precipitation, sulfide 

precipitation (organosulfide), and iron coprecipitation, followed by an anoxic/anaerobic fixed 

film biological treatment system designed to removed heavy metals, selenium, and nitrates (see 

preamble Section VIII.C.1). The technology basis for the biological treatment portion of the 

BAT system is demonstrated to manage FGD wastewater with chlorides concentrations of up to 

30,000 mg/L. EPA considered but did not select a suspended growth biological treatment 

system, such as the one at the Conemaugh plant referenced by the commenter, as part of the 

technology basis for the final rule (see TDD section 7).

As noted by the commenter, the plant’s current wastewater treatment system is designed to meet 

a “monthly average effluent limit of 0.25 mg/l and daily maximum of 0.5 mg/l,” which are 

higher than those in the final steam electric ELGs. EPA used discharge monitoring report data 

from the plant to determine whether the current wastewater treatment system can meet the final 

limitations and determined that the plan would need to install additional treatment (see Section 

6.2.3 of the Costs and Loads Report). EPA’s compliance cost estimates for the final rule took 
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into account that the Conemaugh plant would install a biological treatment system that matches 

the model technology serving as part of the basis for BAT, which would operate in conjunction 

with Conemaugh’s existing chemical precipitation system, in order to meet the BAT 

limitations. Based on the untreated FGD purge data that the Conemaugh Generating Station 

submitted in response to B6-2 of the Steam Electric Survey, the purge concentrations for 

selenium and arsenic do not exceed the average untreated FGD wastewater concentrations 

presented in Table 6-3 of the TDD, indicating the wastewater is consistent with the FGD 

wastewater from plants used as the basis for BAT. The rationale for the limits in the rule are 

described in Section 13 of the TDD.

Under section 301(n) of the Clean Water Act, FDF variance requests with all supporting 

information and data must be received by the permitting authority within 180 days of publication 

of the final effluent limitations guidelines and standards for which a variance is sought. The 

specific regulations covering the requirements for and the administration of FDF variances are 

found at 40 CFR 122.21(m)(1) and 40 CFR part 125, subpart D (see Section XVI.D.1 of the 

preamble).

With regard to the commenter's comparison of ELGs to WQBELs, the commenter should see 

response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Dilution is not a Practical Alternative for Meeting Applicable WQBELs

EPA states in Section 8.1.2.1 (FGD Wastewater) of the TDD that “it is common for plants to 

commingle the surface impoundment FGD effluent with wastestreams of significantly higher 

flows (e.g., ash transport water and cooling water) because the higher-flow wastestreams dilute 

the FGD wastewater so that the resulting pollutant concentrations in the combined wastestream 

do not exceed the applicable water quality-based effluent limitations.”

This is misleading because the pollutant loading on a stream does not change simply due to 

dilution of the discharge. The pollutant loadings associated with higher flows and lower 

concentrations are equivalent to low flows and high concentrations. Furthermore, the 

requirement for using sufficiently sensitive methods to detect constituents at concentrations 

less than water quality criteria in the ppb to ppt range would address EPA’s concern in this 

regard.
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Comment Response: 

EPA’s final rule is a national effluent guidelines rule establishing technology-based effluent 

limitations and standards; it does not establish water quality-based effluent limitations 

(WQBELs). The discussion in Section 8 of the TDD cited by the commenter was not intended to 

describe how plants could or should meet applicable WQBELs. Rather, the TDD discussion 

cited by the commenter is merely a description of one current industry practice (commingling 

FGD surface impoundment effluent with high flow wastestreams, such as ash transport water), 

along with EPA’s understanding of the possible purpose for that practice (to reduce pollutant 

concentrations to meet water quality-based effluent limitations). EPA describes this practice 

because, as explained in Section 13 of the TDD, in order to characterize wastewater treatment 

performance, EPA selected data from those plants where the commingled wastewaters were not 

influenced by substantial dilution, along with other criteria.

Finally, the final steam electric ELG rule does not itself contain a requirement to use sufficiently 

sensitive methods (see Section VIII.G of the preamble) because, in August 2014, EPA published 

a separate rule requiring the use of sufficiently sensitive analytical test methods when completing 

any NPDES permit application. Moreover, the NPDES permit authority must prescribe that only 

sufficiently sensitive methods be used for analyses of pollutants or pollutant parameters under an 

NPDES permit where EPA has promulgated a Clean Water Act method for analysis of that 

pollutant. That rule clarifies that NPDES applications and permittees must use EPA-approved 

analytical methods that are capable of detecting and measuring the pollutants at, or below, the 

applicable water quality criteria or permit limits.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 47

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Ash Transport Water Portion of the Rule Necessitates Emergency Upset, Bypass and Shut 

Down Language During Unscheduled Outages

A number of the options in the proposed standards require zero discharge of ash transport water 

that will require installation of new ash handling systems. As noted by EPA, some facilities have 

converted from wet ash sluicing to dry ash handling, but have retained the wet system as a 

“backup” system. Operating problems can occur more easily with a retrofitted system than with 

an originally designed system, which can result in un-scheduled outages and additional costs. 

Therefore, APPA requests that EPA provide an exemption that would allow the use of wet 

systems at facilities that retrofit to a no discharge handling system for limited periods of time in 
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emergency situations. This language under upset and bypass (and perhaps in other areas) should 

be clear to allow that the power plant is allowed to still function during emergencies.

Comment Response: 

EPA disagrees with the commenter and, for the final rule, has not included an “exemption that 

would allow the use of wet systems at facilities that retrofit to a no discharge handling system for 

limited periods of time in emergency situations,” as the commenter requests. As explained in 

Section VIII of the preamble, EPA has determined that it is technologically and economically 

achievable for the steam electric industry to meet zero discharge limitations and standards for fly 

ash transport water and bottom ash transport water. The commenter provides no data to support 

its claim that “operating problems can occur more easily with a retrofitted [ash handling] system 

than with an originally designed system, which can result in un-scheduled outages and additional 

costs.” The final rule does not prohibit the use of wet-handling or any other systems. Rather, the 

final rule establishes limitations and standards based on technologies that EPA has determined 

represent Best Available Technology Economically Achievable. In the case of fly ash transport 

water, EPA’s technology basis for BAT is a dry handling system, and in the case of bottom ash 

transport water, EPA’s technology basis is a dry handling system or a closed-loop system (see 

preamble Section VIII.C. 2 and 3). See also the response to DCN EPA-HQ-OW-2009-0819-

4655, Excerpt Number 138.

Finally, EPA’s existing and unchanged regulations concerning bypass and upset for direct 

dischargers – which are available to steam electric power plants that meet the requirements – are 

set forth at 40 CFR § 122.41(m) and (n) and for indirect dischargers at 40 CFR §§ 403.16 and 

403.17. A “bypass” is an intentional diversion of wastestreams from any portion of a treatment 

facility. An “upset” is an exceptional incident in which there is unintentional and temporary 

noncompliance with the technology-based permit effluent limitations because of factors beyond 

the reasonable control of the permittee. EPA did not propose to add to or modify the language in 

EPA’s existing bypass and upset regulations as part of the steam electric ELG rulemaking.
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6.e. Regulatory Options – Ponds/Impoundments Used for Treatment

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.

Document Control Number: EPA-HQ-OW-2009-0819-4464-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Midwest Gen strongly supports EPA’s proposed options that recognize the performance of 

gravity settling at surface impoundments as best available technology economically achievable 

(BAT) for bottom ash transport water, including EPA’s preferred options 3a, 3b, and 3, as well 

as EPA’s proposed options 1 and 2. This technology is environmentally protective, its 

effectiveness for treating bottom ash transport water is well-documented, it is the technology 

used by a majority of facilities, and it is entirely supported by the statutory factors EPA must 

consider in establishing BAT. In contrast, EPA’s options that would establish dry handling or 

closed loop systems as BAT for bottom ash transport water is cost-prohibitive, presents 

significant feasibility concerns, and would not result in benefits that would outweigh or justify 

the significant costs.

Comment Response: 

The final rules 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. EPA disagrees with 

the commenter that surface impoundments represent BAT for control of bottom ash transport 

water discharges. 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 as they are affordable to 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. 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)).

EPA disagrees with the commenter that BAT limitations based on dry handling or closed loop 

systems are “cost-prohibitive.” The final rule is economically achievable as it is affordable to 

the industry as a whole, as required by the Clean Water Act. See sections VIII.C.9 and IX.C of 

the preamble and Chapter 5 of the RIA.

EPA disagrees with the commenter that BAT limitations based on dry handling or closed loop 

systems present “feasibility concerns,” especially in light of the significant amount of the 

industry that already employs these technologies. See preamble section VIII.C.3, the TDD, and 

responses to comments in comment code 16.a.
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Finally, the commenter states that the zero discharge limitations and standards applicable to 

bottom ash transport water discharges “would not result in benefits that would outweigh or 

justify the significant costs.” As the preamble discussion makes clear, EPA’s decisions on the 

final rule are based on the factors specified by Sections 301, 304, and 306 of the Clean Water 

Act – most importantly, the technologies selected in the final rule are “available” and 

“demonstrated” and the final rule is “economically achievable” for the industry as a whole. 

EPA’s decisions on the final rule are not based on a benefits analysis, which EPA conducts 

pursuant to Executive Order. The Clean Water Act does not direct EPA to weigh benefits 

against costs in establishing effluent limitations based on Best Available Technology 

Economically Achievable (“BAT”), and multiple judicial decisions have noted that BAT, unlike 

Best Practicable Technology (“BPT”), is to be established without reference to cost-benefit 

analysis. See EPA v. Nat’l Crushed Stone Ass’n, 449 U.S. 64, 70-71 (1980) (“[I]n assessing 

BAT[,] total cost is no longer to be considered in comparison to effluent reduction benefits.”); 

Ass’n of Pac. Fisheries v. EPA, 615 F.2d 794, 818 (9th Cir. 1980) (“The conspicuous absence of 

the comparative language contained in section 304(b)(1)(B) leads us to the conclusion that 

Congress did not intend the Agency or this court to engage in marginal cost-benefit 

comparison.”); Am. Iron & Steel v. EPA, 526 F.2d 1027, 1051-52, 1053 n.54 (3d Cir. 1975) 

(“there should be no cost-benefit analysis” for BAT); Nat’l Ass’n of Metal Finishers v. EPA, 719 

F.2d 624, 659 (3d Cir. 1983) (“BPT is designed to eliminate inefficient discharges, i.e., where 

the benefits of pollutant reduction exceed the costs. . . . BAT assumes that inefficient discharges 

have been eliminated . . . [and] require[es] the remaining dischargers to eliminate ‘efficient’ 

discharges, [including] where the costs outweigh the benefits of pollutant reduction.”).

Nonetheless, even if EPA were to consider the relationship between costs and benefits as a 

decision factor for the final rule, the result would be unchanged. As detailed in the Benefit Cost 

Analysis, prepared pursuant to Executive Order, the estimated annual social cost of the final 

steam electric rule is $480 million. EPA calculated that the final rule will reduce pollutant 

discharges by 1.4 billion pounds per year (see Section X of the final rule preamble). EPA notes 

that its pollutant reductions estimates only account for pollutants that EPA identified as 

“pollutants of concern.” Where the final rule establishes zero discharge limitations and standards 

(such as for pollutants in fly ash transport water, bottom ash transport water, and FGMC 

wastewater), the rule eliminates the discharge of all pollutants present in the wastewater, not only 

pollutants of concern. Nonetheless, the estimated degree of pollutant discharge reductions in this 

rule is significant, it represents a large portion of the remaining discharges of toxic pollutants to 

the nation’s waters by any point source category, and given the Clean Water Act’s ultimate goal 

of pollutant discharge elimination (see 33 U.S.C. § 1251(a)(1)) it is a benefit that alone justifies 

the cost of the rule.
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In addition, EPA was able to monetize some, although not all, of the social benefits associated 

with the final rule. In EPA’s experience, monetization of the benefits of environmental rules, 

particularly effluent limitations guidelines, is much more difficult than monetization of costs, due 

in large part to a lack of relevant data.1 Nevertheless, of the benefits that were monetized, EPA 

estimated $451 to 566 million annually. The human health benefits from surface water quality 

improvements and the benefits associated with improvements in ecological conditions from 

decreased pollutant loadings amount to $40 to $147 million annually. EPA calculated $411 to 

418 million annually in “ancillary” benefits associated with avoided impoundment failures and 

increased ash marketing, as well as human health benefits from air quality improvements and 

climate-change related benefits. These ancillary benefits represent valid social benefits of the 

action that are reasonably foreseeable, and not speculative. Just as the Act requires EPA to take 

into account the non-water quality environmental impacts of its effluent limitations guidelines, it 

follows that if EPA were to consider costs and benefits, EPA would be permitted to consider, to 

the extent possible, monetized benefits beyond those immediately associated with pollutant 

discharge reductions to the nation’s waters. EPA further found that low-income and minority 

populations would disproportionately benefit from the rule, and this consideration of equity 

should also be taken into account (see the RIA).2In addition, there are many categories of 

benefits that EPA could not monetize for the final rule, including expected reductions in adverse 

human health effects (non-cancer effects) from exposure to pollutants through fish consumption, 

reductions in adverse human health effects (cancer and non-cancer effects) from exposure to 

pollutants through recreation in and on the water, reductions in drinking water treatment costs 

that are mainly borne by the public, increased tourism, and increased property values (see 

preamble Section XIV.D, the Environmental Assessment, and the Benefit and Cost Analysis for 

a listing and discussion of these and other non-monetized benefits). Together, the expected 

benefits able to be monetized, along with the recognition of those that were not, justify the costs 

of the final rule.

 

1

In general, the costs borne by regulated entities tend to be easier to ascertain than the benefits to broad 

populations. See, e.g., Frank Ackerman & Lisa Heinzerling, “Priceless: On Knowing the Price of Everything and 

the Value of Nothing,” p. 40 (2004) (“[M]ost cost-benefit analyses could more accurately be described as ‘complete 

cost-incomplete benefit’ studies. Most or all of the costs are readily determined market prices, but many important 

benefits cannot be meaningfully quantified or priced . . . .”); David M. Driesen, “Is Cost-Benefit Analysis Neutral?,” 

77 U. COLO. L. REV. 335, 339–42 (2006) (explaining that costs are often relatively easy to quantify using market 

data but that these estimates tend to be too high, while benefits can be “extraordinarily difficult” to quantify and 

monetize); Robert H. Frank, “Why Is Cost-Benefit Analysis So Controversial?,” 29 J. LEGAL STUD. 913, 928 

(2000) (indicating that cost-benefit analysis can be controversial because costs are much easier to quantify than 

benefits, particularly in the environmental and health fields). And, Executive Order 13563 recognizes that “some 

benefits and costs are difficult to quantify.”

2 E.O. 13563 specifically recognizes that “equity” and “fairness” should be taken into account. This is applicable 

here, where the final rule addresses externalities, i.e., pollution that a few entities generate on the waters enjoyed by 

all.
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Although not equivalent to an analysis of social costs and social benefits, EPA also analyzed the 

cost3per toxic-weighted pound4of pollutant removals attributable to the final rule, which the 

Agency calls a “cost-effectiveness” analysis. Like cost-benefit analysis, this analysis enables one 

to quantify a measure of something that is gained (pollutant reductions) in exchange for a cost 

imposed. EPA uses a cost per pound analysis when establishing BPT, and the courts and caselaw 

have recognized that EPA may use a “limited” cost-benefit balancing test when establishing 

BPT, sometimes called the “wholly disproportionate” test. See EPA v. Nat’l Crushed Stone 

Ass’n, 449 U.S. 64, 71 n.10 (1980); E.I. du Pont de Nemours & Co. v. Train, 430 U.S. 112, 129-

30 (1977). This means that, for BPT, EPA may impose costs as long as they are not wholly 

disproportionate to the effluent reductions achieved. For BAT (and the analogous pretreatment 

standards for existing sources, PSES) or Best Available Demonstrate Control Technology 

(“BADCT”) (and the analogous pretreatment standards for new sources, PSNS) levels of control, 

EPA did not base the final rule on its cost-effectiveness analysis because the statute does not 

direct EPA to consider cost in relation to pounds of pollutant removals. EPA views a costeffectiveness-type analysis as more appropriate for use in establishing limitations reflecting BPT 

rather than BAT, based on the different language used in the Act to describe these separate 

technology-forcing steps. 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.). If, however, EPA were to base its decisions on the final steam electric rule on an analysis 

of cost per toxic-weighted pound of pollutant removals, it would also make the same decisions.

Collectively, the final BAT requirements have a cost-effectiveness ratio of $134 per poundequivalent (“lb-eq.”). This cost-effectiveness ratio is well within the range of cost-effectiveness 

ratios for BAT requirements in other industries. 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 addition, collectively, the final PSES, which are analogous to BAT limitations, have a cost 

effectiveness of $1,228/lb-eq. This ratio is higher than the cost-effectiveness of PSES in other 

industries, which range from less than $1/lb-eq. (Inorganic Chemicals) to $380/lb-eq. 

(Transportation Equipment Cleaning), based on a review of approximately 25 of the most 

recently promulgated or revised categorical pretreatment standards. Nonetheless, there are very 

few plants (three) that are indirect dischargers, and the cost-effectiveness for one of the three 

indirect dischargers significantly elevates the average value for all three combined. EPA 

calculated costs for this plant based on a full conversion of its bottom ash handling system to dry 

handling. It is more likely, however, that this plant would choose to implement modifications 

that would enable it to completely recycle its bottom ash transport water in order to meet the zero 

discharge standard, rather than undertake a full conversion. In that event, the costs to this 

 

3 Here, the costs are the estimated annualized incremental pre-tax costs to comply with alternative regulatory 

options, stated in 1981 constant dollars. The annual costs include the annualized capital outlays for equipment and 

recurring expenses for operating and maintaining compliance equipment and meeting monitoring requirements.

4 Pollutants differ in their toxicity. EPA thus adjusts the estimated reductions in discharges, or pollutant removals, 

associated with a regulatory option by multiplying the estimated removal quantity for each pollutant by a 

normalizing toxic weight (toxic-weighting factor, or “TWF”). The use of TWFs allows the removals of different 

pollutants to be expressed on a constant toxicity basis. In the case of indirect dischargers, the removal also accounts 

for the effectiveness of treatment at Publicly Operated Treatment Works (“POTWs”). See the Regulatory Impact 

Assessment for more details about how EPA accounts for differences in toxicity of pollutants of concern through the 

use of TWFs.
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indirect discharger – and consequently the cost-effectiveness value for all indirect dischargers, 

combined – would be lower. Moreover, it is critical to establish PSES at the same level as BAT 

in this rule to avoid creating an unintended incentive for plants to start sending their wastewater 

to POTWs in an attempt to avoid the requirements of the final rule. Therefore, although EPA did 

not base its BAT/PSES/BADCT/PSNS decisions in the final steam electric rule on “costeffectiveness,” even if it did, based on the considerations presented here, EPA would conclude 

that the cost per toxic-pound equivalent of pollutant removals for its final steam electric rule is 

justified.

Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

BAT for Bottom Ash Transport Water

Consumers Energy is supportive of EPA’s determination, for preferred options 3a, 3b, 3, that 

Best Available Technology (BAT) for bottom ash is the same as “Best Practical Control 

Technology Currently Available” (BPT), namely, a surface impoundment. However, we see no 

reason not to extend this BPT as BAT to Option 4a for units over 400 MW.

Bottom ash generally is an inert material or nearly so. EPA has no technical basis for assuming 

that the bottom ash waste stream includes the same pollutants of concern present in other CCR 

waste streams. We agree with UWAG’s analysis that the toxicity of the bottom ash transport 

water expressed in toxic weighted pounds equivalent (TWPEs) in this proposed rules document 

has been overestimated by more than an order of magnitude. As such, we see no reason not to 

extend the BAT/BPT determination for wet bottom ash handling and surface impoundments to 

units larger than 400 MW, or to deviate from EPA’s long-standing position that the small amount 

of toxics in bottom ash transport water does not justify dry handling or a closed-loop system, 

regardless of unit size. There certainly is no compelling benefit/cost argument for requiring 

existing units of any size to spend several tens of millions of dollars per unit to convert to a dry 

or zero liquid discharge system. We urge EPA to adopt the surface impoundment and wet 

transport BPT as BAT for all options.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3.

EPA disagrees that bottom ash is “an inert material or nearly so.” Following proposal, EPA 

expanded its bottom ash characterization dataset, based on responses to public comments. See 
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Section 6.6.4 of the TDD for a description of the characterization data used to identify POCs in 

bottom ash and Section 10.2.2 for a description of ash impoundment data. As described in those 

sections and shown in Table 10-7, bottom ash transport water contains a variety of metals, in 

many cases at levels similar to fly ash transport water, as well as other pollutants such as 

nitrogen compounds, sulfate, and total dissolved solids.

See Section 10.4.2 of the TDD for a discussion of ash transport pollutant loads and TWPE.

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: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The two trade associations representing smaller entities, the National Rural Electric Cooperative 

Association (NRECA) and the American Public Power Association (APPA) generally agree that 

there should be no additional regulation of existing bottom ash or fly ash impoundments, and that 

flue gas desulfurization (FGD) impoundments would face new regulation above a specified 

design flow.

Comment Response: 

For comments on the identification of dry handling or closed loop system operations as BAT for 

bottom ash transport water, see response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt 

Number 3.

For the reasons set out in preamble section VIII.C, except for discharges from existing 

generating units that are less than or equal to 50 MW or that are oil-fired, EPA did not select 

surface impoundments as the technology basis for BAT limitations applicable to discharges of 

FGD wastewater, fly ash transport water, or bottom ash transport water.

In addition, EPA decided not to promulgate BAT limitations that would require permitting 

authorities to establish limitations for FGD wastewater using site-specific BPJ because it has 

sufficient data to set uniform, nationally applicable limitations on FGD wastewater at plants 

across the nation. See preamble section VIII.C.1 for further information.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2
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Comment Excerpt Number: 23

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Impoundments Used for Settling Should be Excluded

EPA found that surface impoundments (i.e., ash ponds and FGD ponds) can vary substantially in 

size, capacity, and age. According to a survey conducted by EPRI, pond surface areas ranged 

from 5 acres to 1,500 acres, with a median of 91 acres. Disposal capacities ranged from 100,000 

cubic yards to 63 million cubic yards, with a median of 3.4 million cubic yards.

Smaller relatively shallow impoundments are:

 Less prone to turnover/upsets caused by thermal stratification,

 Easier to maintain, and

 Can be modified more economically to enhance precipitation and settling of dissolved 

metals.

Therefore, bottom ash surface impoundments, which are smaller in size (e.g., <10 acres) and 

used for only settling and not permanent disposal should be excluded from the proposed ELG.

Comment Response: 

The commenter states that “bottom ash surface impoundments, which are smaller in size (e.g. 

<10 acres and used only for settling and not permanent disposal should be excluded from the 

final rule.” The final rule establishes effluent limitations and standards applicable to the 

discharge of pollutants in particular wastestreams (including fly ash transport water, bottom ash 

transport water, and FGD wastewater) from steam electric power generating units. The final rule 

does not directly regulate the impoundments in which the wastewater may be held or treated. 

As described in preamble section VIII, except for discharges from existing generating units that 

are less than or equal to 50 MW or that are oil-fired, the final rule identifies chemical 

precipitation followed by biological treatment as the BAT basis for control of pollutants in FGD 

wastewater discharges, dry handling as the BAT basis for control of pollutants in fly ash 

transport water discharges, and dry handling or closed-loop systems as the BAT basis for control 

of pollutants in bottom ash transport water discharges. However, steam electric power plants

may use whatever technology or practice they choose to meet the effluent limitations.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 132
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

All of the options except Options 4 and 5 identify impoundment as the BAT technology and 

propose to set BAT limits equal to current BPT limits.575 Yet EPA has repeatedly made clear 

that “surface impoundments are not designed for, nor are they effective at, removing . . . 

dissolved metals” from combustion residual leachate.576

575 78 Fed. Reg. at 34,458.

576 See, e.g., TDD at 8-13; U.S. Envtl. Prot. Agency, Steam Electric Point Source Category: Final 

Detailed Study Report (EPA-821-R-09-008) xiii (Oct. 2009), available at 

http://water.epa.gov/scitech/wastetech/guide/steam- electric/upload/Steam-Electric_DetailedStudy-Report_2009.pdf.

Comment Response: 

The final rule establishes BAT limitations and PSES for discharges of combustion residual 

leachate based on surface impoundments, for the reasons explained in Section VIII.C.6 of the 

preamble. While EPA agrees that surface impoundments are not designed for, nor are they 

effective at removing dissolved metals from combustion residual leachate, the amount of total 

metals and other pollutants collectively discharged in combustion residual leachate by steam 

electric power plants is a very small portion of the pollutants discharged collectively by all steam 

electric power plants. Because dissolved metals are a portion of the total metals, the amount of 

dissolved metals in combustion leachate relative to other wastestreams is even smaller. Given 

this, and the fact that the final rule regulates the wastestreams representing the three largest 

sources of pollutants from steam electric power plants, including by setting a zero discharge 

standard for two out of the three wastestreams, EPA decided that the final rule represents 

reasonable further progress toward the Clean Water Act’s goals, in accordance with Section 

301(b)(2)(A) of the Act. See Ass’n of Pac. Fisheries v. EPA, 615 F.2d 794 F.2d 818 (9th Cir. 

1980); Am. Petroleum Inst. v. EPA, 787 F.2d 965, 972 (5th Cir. 1986); Am. Petroleum Inst. v. 

EPA, 858 F.2d 261, 265-66 (5th Cir. 1988), amended by 864 F.2d 1156, 1156-57 (5th Cir. 1989).

Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

BAT for Coal Combustion Residual Leachate

Consumers Energy supports EPA’s determination that the low volume waste BPT limits should 

apply as BAT to CCR leachate. The application of low volume waste BPTs-pH, TSS, oil and 

grease, are appropriate for all preferred options.

Comment Response: 

With respect to discharges of combustion residual leachate from existing steam electric 

generating units, for the reasons described in preamble section VIII.C.6, the final rule establishes 

BAT limitations equal to the previously established BPT limitation on TSS for discharges of low 

volume waste sources.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 55

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

And I want to make this point to you. It is criminal to me that we have power plants in this 

country whose sole means of treatment is to dump their scrubber sludge, their coal ash waste, 

and their other processed water in a hole in the ground. That is not best available 

technology. That is 1950s old school, no treatment, ridiculous kind of way to treat toxic heavy 

metals, and it is time for it to stop. It is time for us to stop poisoning our waterways with heavy 

metals.

Comment Response: 

The final rule establishes limitations and standards that are based in many cases on technologies 

(including completely dry handling practices) that are more advanced than surface 

impoundments. See preamble Section VIII for a description of the final rule, including the 

technologies selected as the bases for the final limitations and standards. See also preamble 

Section X for an estimate of the reductions in pollutant discharges associated with the final rule.

Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-A1
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Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Finally, by reviewing the system as a whole, Alcoa-Warrick has a significant population of fish 

in the ashpond system; the population is likely over 20,000, with nearly all species of the 

receiving water represented. Accordingly, evidence supports that our discharge is not harming 

the receiving stream. Indeed, the eco-life of the ashpond system is still strong.

Comment Response: 

For a discussion of the difference in the function and basis of technology-based effluent 

limitations guidelines and standards, such as those established in this final rule, and limitations 

based on water quality standards, see the response to DCN EPA-HQ-OW-2009-0819-4305-A3, 

Excerpt Number 61 in Comment code 6.c. Technology-based controls establish a national floor 

of pollutant control performance for all dischargers based on, for example, “best available 

technology economically achievable” or “best available demonstrated control technology” and 

are not based on the quality of the receiving water into which the pollutants are 

discharged. Indeed, the technology-based provisions in the Clean Water Act were enacted in 

response to the failure of previous approaches to control water pollution that were predicated on 

having to demonstrate the environmental effects of control on receiving waters. See

Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1042 (D.C. Cir. 1978).
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6.f. Regulatory Options - General Methodology

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

III. Evaluation of Data and Statistical Method

A. Ash Impoundment Effluent Concentration Data

The greatest contribution to the overall TWPE for ash impoundment effluent is from 

sulfides. Sulfides account for the largest contribution to the TWPE for each ash impoundment 

type: 59% for bottom ash impoundments, 77% for fly ash impoundments and 55% for combined 

ash impoundments (see Tables 3, 4 and 5).

Remarkably, none of the impoundment effluent sampling programs that EPA relied on in the 

1982 TDD and the 2009 Detailed Study Report analyzed impoundment effluent samples for 

sulfides. The only sulfide data came from 22 impoundments included in the UWAG From 2C 

compilation – 2 bottom ash impoundments, 3 fly ash impoundments and 17 combined ash 

impoundments. Furthermore, none of the impoundments for bottom ash or fly ash found sulfides 

above reporting limits, and only 3 combined ash impoundments found sulfides above reporting 

limits.

Therefore, 59% of EPA’s calculated TWPE for bottom ash impoundments and 77% of EPA’s 

calculated TWPE for fly ash impoundments are based on no actual data. The calculated values 

were based exclusively on reporting limits from 5 samples. For combined ash impoundments 

55% of EPA’s calculated TWPE is based on only three measured values and 14 reporting limits.

B. Statistical Method for Estimating Loadings

EPA’s statistical method for estimating the average loading (lbs/year) per impoundment was to 

multiply the average concentration (the average over impoundments) times the average transport 

water flow rate (the average over impoundments). EPA then multiplied its estimate of the 

average loading per impoundment times the number of impoundments to estimate the industry 

level loadings.

The actual industry-level loading for a pollutant is the sum of the impoundment- specific 

loadings, which alternatively can be viewed as the number of impoundments times the average 

loading per impoundment. For each impoundment, the loading is the product of the 

concentration times the transport water flow rate. In general the average of products (i.e., the 
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proper way to calculate average loadings) is not equal to the product of averages (i.e. EPA’s 

formulation). This fact is at the heart of the statistical theory of correlations (Lindgren, 1976).

If pollutant concentrations are correlated with transport water flow rates, then EPA’s formulation 

for estimating average loading per impoundment are biased. In general the direction and 

magnitude of bias depends on: 1) the magnitude and sign of the correlation between 

concentrations and transport water flow rates, and 2) the coefficient of variation (i.e., the ratio of 

standard deviation to the mean) for pollutant concentrations among impoundment and for 

transport water flow rates among impoundment (see Appendix A). If pollutant concentrations 

are negatively correlated with transport water flow rates, then EPA’s formulation will produce 

estimates that are biased high.

In the next section, several simple, hypothetical examples are presented that compare properly 

calculated estimates of average loadings to estimates of average loading calculated using EPA’s 

formulation. The examples illustrate the presence of bias and the effects of correlation and 

coefficients of variation on bias. In addition, the next section includes a discussion of the general 

algebraic relationship between correlation, coefficients of variation and bias.

1. Illustrative Examples of Bias

In each example in this section, a hypothetical average annual pollutant loading is calculated 

using the proper method of calculation (i.e., the average of products) and compared to the 

estimate calculated using EPA’s formulation (i.e., the product of averages). The underlying 

correlation between pollutant concentrations and transport water flow rates and the underlying 

coefficients of variation differ among examples to illustrate the effects of those factors on bias.

Example 1 illustrates the calculations for the extreme case in which pollutant concentrations 

have a perfect negative correlation with flow rates.

Example 1. Correlation between pollutant concentrations and transport water flow rates = -

1. Coefficient of variation for concentration = 0.71, and coefficient of variation for flow = 0.35.
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In Example 1, the true average pollutant loading is 150 lbs/yr per impoundment. However, the 

estimated average pollutant loading based on EPA’s method would be the average concentration 

(i.e., 10) time the average flow rate (i.e., 20), which equal 200. Therefore, for this example, 

EPA’s method would overestimate loadings by a factor of 1.33 (i.e., 200/150).

For any degree of correlation, the magnitude of bias depends on the size of the coefficients of 

variation for concentrations and flows. A larger coefficient of variation will cause the bias to be 

larger. The next hypothetical example (Example 2) illustrates this fact with the coefficient of 

variation for flow roughly doubled in comparison to Example 1. For Example 2, the average 

concentration and flow, and the correlation between concentration and flow are the same as in 

Example 1.

Example 2. Correlation between pollutant concentrations and transport water flow rates = -

1. Coefficient of variation for concentration = 0.71, and coefficient of variation for flow = 0.67.

In Example 2, the true average pollutant loading is 105 lbs/yr per impoundment. However, the

estimated average pollutant loading based on EPA’s method would still be 200 (i.e., the average 

concentration times the average flow rate). Therefore, for this example, EPA’s method would 

overestimate loadings by a factor of 1.90 (i.e., 200/105).

Examples 1 and 2 illustrate the extreme case of perfect correlation between concentrations and 

flows. The next example (Example 3) illustrates the fact that when the correlation is zero, EPA’s 

method is not biased. For Example 2, the average concentration and flow again are the same as 

in Example 1, and the coefficients of variation are roughly the same as in Example 2.

Example 3. Correlation between pollutant concentrations and transport water flow rates = 

0. Coefficient of variation for concentration = 0.71, and coefficient of variation for flow = 0.72.
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In Example 3, the true average pollutant loading is 200 lbs/yr per impoundment. The estimated 

average pollutant loading based on EPA’s method is also 200 (i.e., the average concentration 

times the average flow rate). Therefore, for this example, EPA’s method would not introduce a 

bias (i.e., the bias factor is 200/200 = 1.00 indicating no bias).

The next example (Example 4) illustrates the fact that if concentrations and flows are negatively 

correlated, but not perfectly correlated as was the case for Examples 1 and 2, EPA’s method will 

still produce biased estimates of pollutant loadings. For Example 4, the average concentration 

and flow again are the same as in Example 1; however, the correlation between concentrations 

and flows is -0.33. The coefficients of variation for concentrations is the same as in Examples 1-

3, but the coefficient of variation for flow is increased to 1.25 for Example 4.

Example 4. Correlation between pollutant concentrations and transport water flow rates = -

0.33. Coefficient of variation for concentration = 0.71, and coefficient of variation for flow = 

1.25.
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In Example 4, the true average pollutant loading is 142 lbs/yr per impoundment. However, the 

estimated average pollutant loading based on EPA’s method would still be 200 (i.e., the average 

concentration times the average flow rate). Therefore, for this example, EPA’s method would 

overestimate loadings by a factor of 1.41 (i.e., 200/142).

2. Algebraic Formulation to Describe Bias

In general, the effect on bias of the correlation between concentrations and flows, and the effect 

of the coefficients of variation for concentrations and flows are described by the following 

relationship (see Appendix A):

where þ is the correlation between pollutant concentrations and transport water flow rates, 

CV(concentration) is the coefficient of variation for concentration, and CV(concentration) is the 

coefficient of variation for flow.

To demonstrate the use of this general relationship, the correlation and coefficients of variation 

from Examples 1-4 are inserted into equation (1) below:

For each example, the bias factor calculated using equation (1) matches1the bias factor 

computed from the two estimates of average pollutant loading.

In the following section, data from responses to the ICR are examined to estimate: 1) correlations 

between pollutant concentrations and flow in bottom ash transport to impoundments, and 2) 

coefficients of variation for pollutant concentrations and flow. Those estimates are used in 

conjunction with equation (1) above, to assess the likely magnitude of bias in EPA’s estimates of 

bottom ash impoundment pollutant loadings.

3. Magnitude of Bias in EPA’s Estimates of Ash Impoundment Loadings
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A. Method for Assessing Magnitude of Bias

This assessment of the likely magnitude of bias is based on data included in the ICR response 

database provided on CD by EPA. Specifically, data from the files (included in the ICR 

response database) listed below were used for the assessment.

1. Bottom ash sluicing flows reported by plant and steam electric unit in the file 

“btm_ash_sluicing”.

2. Weight of wet bottom ash (dryweight) produced per and steam electric unit reported in the file 

“btm_ash_system”.

3. Impoundment destination of bottom ash from each plant and steam electric unit reported in the 

file “btm_ash_storage_dest”.

4. Fly ash sluicing flows reported byplant and steam electric unit in the file “fly_ash_sluicing”.

5. Weight of wet fly ash (dry weight) produced per plant and steam electric unit reported in the 

file “fly_ash_system”.

6. Impoundment destination of fly ash from each plant and steam electric unit reported in the file 

“fly_ash_storage_dest”.

7. Nameplate generation capacity(MW) for each plant and steam electric unit 

reportedinthefile“se_units_operating”.

8. Percent of total BTUs produced with coal as fuel reported in the file “fuel_useage”.

The data files were merged by plant, steam electric unit and impoundment. Data on plants and 

steam electric units that reported bottom ash or fly ash production, sluicing flows, nameplate 

generation capacity, and 50% or more of BTUs produced by coal were included in the 

assessment. Plants and steam electric units that had relevant data redacted as confidential 

business information were excluded from the assessment. A total of 202 impoundments reported 

in the data files satisfied these criteria.

A separate assessment was conducted for impoundments that received bottom ash (but not fly 

ash), for impoundments that received fly ash (but not bottom ash), and for impoundments that 

received both bottom ash and fly ash.

Data on ash transport sluice flow rates were available in the responses to the ICR. Accordingly, 

estimates of the coefficients of variation for ash transport water flow rates could be calculated 

directly from the ICR database.

A systematic list of pollutant concentrations associated with ash transport sluice water, or 

impoundment discharges, was not included in the ICR responses. Therefore, it was not possible 

to directly calculate impoundment-specific pollutant concentrations on which to base the 
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required estimates of correlation and coefficient of variation of concentration. However, data on 

ash concentrations can be used as surrogates under the assumption that the mass of pollutants 

produced in the ash transport water was proportionate to the mass of ash produced. In that case, 

the concentration of ash in the transport water would be proportionate to the concentration of 

pollutants.

Both of the parameters (i.e., correlation and coefficient of variation) in equation (1) that involve 

pollutant concentration are unit-less quantities. The correlation coefficient, bounded on the 

interval -1 to 1, is automatically scaled to the two variables addressed. The coefficient of 

variation is a ratio in which the units of measurement in the numerator and denominator 

cancel. Accordingly, under the assumption that the mass of pollutant produced is proportionate 

to the mass of ash produced, the correlation coefficient between concentration and flow is the 

same for pollutants and for ash. Similarly, the coefficient of variation is the same for pollutants 

and for ash. Therefore, data on ash concentrations in the ash transport water were used to assess 

the likely bias in estimates of pollutant loadings using equation (1).

b. Results of Assessment of Magnitude of Bias

For each plant and impoundment that satisfied the criteria listed above, the reported pounds of 

ash sluiced to the impoundment per year, and the reported gallons per year of sluicing flow were 

taken from the ICR response data files. The associated ash concentration in the ash transport 

water (in lbs/gal) then was calculated as the ratio of the annual pounds of ash sluiced to the 

annual gallons of sluicing flow. These data (i.e., ash concentration, sluicing flow and ash weight) 

for impoundments receiving bottom ash, receiving fly ash and receiving both bottom ash and fly 

ash are listed in Appendix B Tables B1, B2, and B3, respectively.

For each of the three ash impoundment types the correlation between ash transport water flow 

and ash (pollutant) concentration is negative, and the coefficients of variation are greater than 1 

(see Table 6). The bias factors, calculated using equation (1), are 3.155 for bottom ash 

impoundments, 1.662 for fly ash impoundments, and 2.149 for combined ash impoundments.

As an additional illustrative example, estimates of average ash loadings (lbs/yr) per 

impoundment were calculated from the ICR data using EPA’s method (i.e., the product of the 

average flow times the average concentration) and directly by averaging the reported load per 

impoundment (see Table 7). For bottom ash impoundments, the actual average is 94,922,923 and 

the estimate using EPA’s method is 299,516,816 (3.16 times too high). For fly ash 

impoundments, the actual average is 312,035,846 and the estimate using EPA’s method is 

518,475,075 (1.66 times too high). For combined ash impoundments, the actual average is 

183,022,135 and the estimate using EPA’s method is 393,251,302 (2.15 times too high).

IV. Effects on Invalid Data and Flawed Methods on Estimates of Loadings and TWPEs

A. Excluding Invalid Average Sulfide Concentrations

As noted above, the TWPE estimates for sulfide ranged from 55% (for combined ash 

impoundments) to 77% (for fly ash impoundments) of the total TWPE. Excluding the estimates 
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of sulfide concentration from the total TWPE estimates reduces the total TWPE (summed over 

the three impoundment types) 60%, from 5,240,000 to 2,121,609 (Table 8).

B. Adjusting for Likely Bias in EPA Estimation of Average Loadings

The likely biases in loading estimates due to EPA’s statistical method range from 1.66 for fly ash 

impoundments to 3.16 for bottom ash impoundments. Adjusting each estimate to account for the 

likely bias factor reduces the estimated total loadings (summed over the three impoundment 

types) by 63% from 2,182,900,000 to 801,786,870 (Table 9). Similarly, adjusting each estimate 

of TWPE to account for the likely bias in loadings due EPA’s statistical method reduces the total 

TWPE by 59% from 5,233,000 to 2,169,828.

V. Discussion

A. Invalid Sulfide Concentrations and Contribution to TWPEs

EPA’s estimates of TWPEs for sulfides in bottom ash and fly ash impoundments are simply 

baseless and have no scientific justification. Furthermore, EPA’s estimate of TWPE for sulfides 

in combined ash impoundments, based on three observations above reporting limits and 14 

observations set to reporting limits, is inadequate. Accordingly, inclusion of EPA’s estimates of 

TWPEs for sulfides in EPA’s industry level baseline TWPE for ash impoundment effluents leads 

to invalid results that are severely biased high.

Although EPA estimated that over half of the industry level TWPE was due to sulfide, none of 

the sampling programs EPA relied on in its 1982 TDD for Steam Electric Effluent Guidelines 

(EPA 1982) or in its 2009 Detailed Study (EPA 2009) reported monitoring for sulfide. For its 

loading estimates, EPA used no sulfide data actually collected for the purpose of calculating 

valid estimates of pollutant loadings. 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.

B. Bias in Loadings and TWPE Estimates

EPA’s estimates of Industry-Level Ash Impoundment Pollutant Loadings are likely to be 

severely biased high due to the formulation EPA chose for calculating loadings. As described 

above, EPA’s formulation will generate estimates that are biased high if pollutant concentrations 

are negatively correlated with ash transport flow rates. In addition 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 all 

three ash impoundment types: bottom ash, fly ash and combined ash.

The ICR data clearly show that the variance of transport flows is large. Under the assumption 

that the weight of pollutants produced is proportionate to the weight of ash produced, the data 

also show: 1) a negative correlation between pollutant concentrations and transport flows, and a 

very large coefficient of variation for pollutant concentrations. These conditions combine to 
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indicate that EPA’s estimate of industry level baseline TWPE for ash impoundment pollutant 

loadings of 5,233,000 (TDD Table 10-13) is likely to be 2.41 times too high.

This assessment of bias assumes that EPA’s estimates of average pollutant concentrations are 

unbiased, and only addresses biases due to the statistical method EPA chose for estimating ash 

impoundment pollutant loadings. Biases due to errors in EPA’s estimates of average pollutant 

concentrations would be compounded with these biases as discussed below.

It should be noted that this issue of bias, due to EPA’s method for estimating loadings, may 

extend beyond ash impoundment pollutant loadings to any of EPA’s estimates of pollutant 

loadings that were calculated as the product of averages.

C. Compounding of Errors

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 (see Table 10). Computing the total TWPE without the invalid sulfide data reduces the 

baseline TWPE from 5,240,000 to 2,121,609. Adjusting that estimate to account for the likely 

bias in loading estimates due to EPA’s biased formulation further reduces the baseline TWPE to 

859,686. Therefore, the combined effect of EPA’s invalid estimates of sulfite concentrations and 

EPA’s biased statistical method is likely to produce an estimate of total TWPE that is 6 times too 

high.

1 The minor discrepancy in Example 2 is due to round-off error with 2 significant digits.
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Appendix A

Algebraic Characterization of Bias in EPA’s Formulation of Annual Loadings

EPA’s method for calculating Baseline Ash Impoundment Loadings (pounds per year) has four 

steps:

1. Estimate industry-level average pollutant concentration (pounds per million gallons)

2. Estimate impoundment-specific ash transport water flow rates (million per gallons per day)

3. Estimate impoundment-specific loadings based on the industry-average pollutant 

concentration and impoundment-specific transport water flow rates

4. Estimate the industry-level loadings as the sum of impoundment-specific loadings estimates.

This method is can introduce large biases to the results. The source of these biases can be seen 

by expressing annual loadings algebraically in terms of plant-specific concentrations (Ci) and 

flow rates (Fi). The actual annual total pollutant load (T) over N plants is:
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Appendix B

Ash Transport Water Data from ICR Response Data Files
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Comment Response: 

For general information regarding the statistical analyses conducted for the final rule see DCN 

SE05733 and Appendix.

Regarding sulfide data and pollutant loadings: For the reasons explained in EPA’s response to 

DCN-EPA-HQ-OW-2009-0819-4487-A1, Excerpt Number 14, EPA did not include loadings 

estimates for sulfide in the final rule for ash transport water, so related comments are outside the 

scope of the final rule.

Regarding statistical bias in pollutant loadings: EPA notes that the statute simply requires EPA 

identify pollutant reductions resulting from application of BAT. EPA has done so (in terms of 

pounds and TWPE) and its approach is reasonable, particularly in consideration of the data 

available to EPA.
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EPA notes that the commenter’s analysis of the method that EPA used to calculate loadings is 

incorrect. The commenter states that “EPA’s statistical method for estimating the average 

loading (lbs/year) per impoundment was to multiply the average concentration (the average over 

impoundments) times the average transport water flow rate (the average over 

impoundments).” EPA did not use the “average transport water flow rate (the average over 

impoundments).” EPA calculated baseline pollutant loadings and post-compliance loadings for 

each plant discharging an evaluated wastestream using the plant-specific wastewater flow for the 

wastestream and average pollutant concentration of the specific wastestream. EPA then sums the 

plant-specific loadings to calculate the industry-level loadings. See TDD section 10 for 

additional discussion on the loadings calculation methodology. EPA did use average pollutant 

concentrations when calculating loadings; however, EPA could not have calculated the product 

of concentration and flow rate for each impoundment as commenter suggests because 

impoundment-specific pollutant concentration data were not available to EPA for all 

impoundments at steam electric power plants nor was the commenter able to provide such 

data. EPA generally agrees that “average of products ... is not equal to the product of averages,” 

however the commenter has mischaracterized EPA’s methodology for calculating loadings. The 

commenter may confused by the use of normalized, generating unit-level fly discharge flow rates 

that EPA calculated to account for the fact that most generating units do not discharge 365 days 

per year. See Section 10.3 of the TDD for further discussion on the calculation of normalized 

flow rates.

EPA disagrees with the commenter’s assertions that ash effluent loadings (and more generally 

any estimates of pollutant loadings) are biased due to the method in which EPA calculated the 

loadings. The commenter provides no actual data to support the numerous assumptions made in 

their theoretical calculations, such as the assumption that pollutant concentrations are correlated 

with transport water flow rates, the assumption that the weight of pollutants produced is 

proportionate to the weight of ash produced, and the assumption that the concentration of ash in 

the transport water would be proportionate to the concentration of pollutants. This is surprising 

as the commenter submitted several datasets from multiple plants related to bottom ash transport 

water, but neglected to provide sample-specific flow rates, the mass of pollutants in collected 

samples, the mass of ash produced related to the specific sample, or the concentration of “ash” in 

the sample.

Instead the commenter relies on assertions that, by themselves, will result in the conclusion 

purported by the commenter.

EPA evaluated all datasets in which both sample-specific flow and effluent pollutant 

concentration were available, including FGD wastewater, bottom ash transport water, and fly ash 

transport water. In its review, EPA generated plots of the available datasets (See DCN SE04409). 

Review of the data demonstrates that none of the assumptions made by the commenter were 

valid.

 Pollutant concentrations may be correlated with transport water flow rates at specific 

plants, or for specific periods of time, but EPA found that there was no overall correlation 

when reviewing the full dataset available.
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 EPA was not able to assess whether the mass of pollutants present in impoundment 

effluent is proportional to the mass of ash produced due to the variation in impoundment 

performance, coal quality, and other factors.

 EPA was not able to assess whether the concentration of “ash” discharged is proportional 

to the concentration of pollutants discharged, as data are unavailable on the concentration 

of “ash.”

Because an evaluation of the data invalidates the assumptions made by the commenter, EPA 

disagrees with the commenter’s conclusion that “EPA’s formulation will produce estimates that 

are biased high.” EPA notes that if no correlation between pollutant concentration and flow rate 

exists then the “bias” mentioned by the commenter is nonexistent. EPA contends that its 

approach provides a reasonable estimate of the loadings and reductions based on actual data for 

ash transport wastewater.

The Bias Factor purposed in Equation (1) of the comment is a correction factor developed in the 

comment that “corrects” a situation that the comment constructed (using simulated data and a 

calculation methodology attributed to EPA that is in fact never performed). This is a case of 

using a specific instance (and possibly not even a realistic instance) to devise a general solution. 

The commenter offers no evidence that the purposed Bias Factor will perform consistently and as 

intended across the range of real-world data. EPA notes that there are no academic references or 

published materials supporting the purposed Bias Factor. The commenter also states that the 

presence of negative correlation makes the Bias Factor a necessary correction, however EPA has 

observed that there is no convincing evidence of negative correlation.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 43

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

9. The Form 2C Sulfide Data, Showing Sulfides that Are Not Actually Present in 

Ash Pond Discharges, Inflated Ash Pond TWPEs

EPA used sulfides in its TWPE calculation for bottom ash and fly ash discharges due to three 

detected sulfide results out of 22 analyzed samples in the EPA database. The rest of the samples 

were all non-detect, but many had a very high detection limit of 1 mg/L.

EPA failed to take into account that for all three detected sulfide results, there were 

corresponding source water data in the Form 2Cs that indicated sulfide was also present in the 

river water at essentially the same concentrations. Since sulfide is formed only under anoxic 
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conditions, the intake results were most likely false positives, probably due to some kind of 

analytical interference that is also present in pond discharge results.

The occurrence of sulfide in river water would be extremely rare and would only occur when 

dissolved oxygen in the river was very low. Upstream samples taken from a flowing river will 

not contain measurable sulfide concentrations unless the dissolved oxygen has fallen to 

essentially zero and remained in that state long enough for anaerobic bacteria to become active 

and form sulfides. Therefore, the similar intake water results likely indicate that all the sulfide 

results (both intake and effluent) are interferences, resulting in false positives.

Furthermore, most plants aerate their discharges at outfalls to further increase the oxygen content 

of the water before discharging it to surface waters. This is accomplished by contacting the 

wastewater with air by means of cascades, rock riprap, diffusers, turbulence, or mixing. Rock 

cascades and riprap are common means of aerating outfalls prior to discharge. This increased 

oxygen content of the water will prevent sulfides from being discharged by oxidizing them to 

sulfates in the very unlikely event sulfides were present in the first place.

As we explain below, measuring sulfide requires attention to the method details and very careful 

quality control. All these methods are highly susceptible to interferences that can produce false 

positive results.

Comment Response: 

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. 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 210

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

XXIV. The Benefit and Cost Analysis Is Based on Inaccurate Data

EPA’s BCA is based on EPA’s underlying work on costs, as spelled out in the TDD and the 

IC&PR, and EPA’s work on predicted environmental impacts in the Environmental 

Assessment. As we have demonstrated, there are numerous significant issues with both EPA’s 

work on costs and its assessment of environmental impacts. Therefore, the BCA cannot be 

accurate because the inputs to it are not accurate.
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Turning to costs, we have described the following major flaws in EPA’s analysis.

1. EPA underestimated the costs of dry fly ash retrofits. It developed its own formulas for 

estimating the costs of various pieces of the retrofitted technology. During a conference call on 

August 28, 2013, EPA confirmed to UWAG that it applied erroneous formulas for dry fly ash 

conveyance equipment, steel silo capital costs, and concrete silo capital costs. The transcription 

errors that led to these mistakes are described, above, in these comments. When UWAG applied 

the proper EPA-derived formulas to a sample set of six plants, we found an average increase of 

46% in plant capital costs for conveyance and intermediate storage.

2. EPA also underestimated costs for balance of plant, engineering overhead, and profits and 

overhead for both fly ash and bottom ash retrofits.

3. For both fly ash and bottom ash retrofits, EPA failed to provide for contingency. A standard 

level of contingency would be 20% of the capital costs.

4. EPA also did not include costs for any land acquisition to provide space for the retrofitted fly 

ash and bottom ash handling systems. This assumes that all sites have adequate space for the 

equipment already, which is not accurate.

5. 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.

6. For FGD wastewater retrofits, EPA understated costs by using “typical” FGD purge flow 

rates instead of maximum design flow rates. When constructing a new treatment system, 

engineers must use the maximum design flow rate rather than an average or typical flow 

rate. Therefore, it is inappropriate to base construction costs on an average or typical flow rate.

7. Also, EPA did not include any contingency costs for FGD wastewater retrofits. A standard 

level of contingency would be 20% of the capital costs for a relatively uncomplicated retrofit, 

and could be higher for a more complex retrofit.

EPA has also vastly overstated the potential environmental benefits of the rule. We have 

identified the following major issues with EPA’s loadings information.

1. For both bottom ash and fly ash transport water, EPA’s analytical database contains old,

unreliable data from the 1982 Development Document and other sources. These data are 

inappropriate for characterizing today’s wastewater discharges, and they serve to grossly 

overstate pollutant loadings for both wastewaters.

2. EPA’s acceptance of high non-detects as actual values from these old data sources 

compounds the overstatement. EPA not only assumed undetected pollutants were present at the 

detection limit but also used 1970s-era detection limits that were much higher than today’s.
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3. Based on EPA’s representations to UWAG, the Agency no longer has any of the supporting 

documentation for the 1982 Development Document data, such as lab reports and the like. It is 

entirely inappropriate to base a rule on unsubstantiated data.

4. EPA’s estimates of sulfides in fly ash and bottom ash transport water are incorrect. As 

UWAG has demonstrated, sulfides are generally not present in these wastewaters.

Based on these and other flaws in the Environmental Assessment, EPA’s inputs to the BCA are 

inaccurate; therefore, the entire BCA is too flawed to serve any purpose in this 

rulemaking. Aside from any methodological problems with the BCA, its conclusions must fail 

because the starting point of the analysis is badly flawed.

Comment Response: 

Ash Handling Costs. Regarding fly ash transport water, see response to DCN EPA-HQ-OW2009-0819-4379-A1, Excerpt Number 45 in Comment Code 14.b for more specific discussion 

regarding EPA’s revisions to the fly ash transport water cost estimates including updates to cost 

equations, balance of plant (BOP) costs, engineering overhead, profits and overhead, 

contingency, and land for the final rule.

Regarding bottom ash transport water, see response to DCN EPA-HQ-OW-2009-0819- 4655, 

Excerpt Number 53 in Comment Code 16.b for more specific discussion regarding EPA’s 

revisions to the bottom ash transport water cost estimates, including BOP costs, engineering 

overhead, profits and overhead, contingency, and land for the final rule.

EPA disagrees with the commenter’s assertion that EPA did not include capital expenditures for 

plants recycling a majority of their bottom ash transport water. EPA did. As discussed in 

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

(Costs & Loads Report) (DCN SE05831/SE05832), 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. These plants did not report discharge 

bottom ash transport water in 2009 but 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 close up the 

bottom ash transport water discharge. Additionally, EPA estimated capital and O&M costs 

associated with chemical feed systems for all generating units at the plant with bottom ash wet 

sluicing systems. EPA notes that most plants that already recycle a majority of their bottom ash 

transport water will not require any capital costs to close the 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 handling conversion.

FGD Wastewater Costs. EPA agrees with the commenter that using “typical” FGD purge flow 

rates instead of maximum design flow rates would underestimate costs. However, EPA did not 
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use average FGD purge flow rates instead of maximum design flow rates in its costs estimates 

for the final rule. Instead, EPA calculated the maximum design flow rate for each plant by 

multiplying the plant-specific average flow rate by the capacity factor (capacity factor derived as 

described in response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 26). See 

response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 27 in Comment Code 

9.b.

EPA’s cost estimates for FGD wastewater in the final rule include contingency costs. For the 

final rule, 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. See Section 

6.2.5.7 (Indirect Capital Cost) of the Incremental Costs and Pollutant Removals for the Final 

Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category (Costs & Loads Report) (DCN SE05831/SE05832) for additional information.

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Numbers 24 and 30 in 

Comment Codes 9.b and 10.b respectively for more specific discussion regarding EPA’s 

revisions to the FGD wastewater cost estimates.

EPA disagrees that is has vastly overstated the potential environmental benefits of the final rule. 

See the BCA for further discussion. See below for discussion on the issues raised by the 

commenter related to the 1982 TDD data and sulfides.

1982 Data: For the final rule, EPA revised its estimates of pollutant loadings for ash transport 

water in response to public comments. See Costs and Loads Report. EPA’s analysis is a 

reasonable estimate of the pollutant reductions associated with BAT in light of the available data 

and as such disagrees with the commenter’s assertion that the final EA is flawed, See response to 

DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 15.d.and 

responses to comment code 13.d for a response to the commenter’s concerns regarding the use of 

1982 data to estimate pollutant loadings for ash transport water.

Sulfides: For the reasons explained in EPA’s response to DCN-EPA-HQ-OW-2009-0819-4487-

A1Excerpt Number 14 in Comment Code 6.a, EPA did not include loadings estimates for sulfide 

in the final rule for ash transport water. 

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 69

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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2. Compliance Costs

The EPA’s estimates of technology costs were determined from information received via survey 

responses, site visits, sampling episodes, individual power plants, and equipment vendors. The 

Agency used this information as inputs to the models employed to determine whether a specific 

facility would require a technology retrofit to comply with the criteria in the proposed ELG 

rule. The modeling alone introduces two potential degrees of error in the analysis. The accuracy 

of the model output is directly dependent upon: 1) how well the model replicates the system or 

process being modeled; and 2) the accuracy of the data inputs. In Section IX.B.5, the EPA 

acknowledges its uncertainty with the validity of the data inputs by soliciting additional data or 

information on pollutant loadings that would corroborate or correct the data used in its analysis, 

including data or information relating to the pollutants of concern identified in the ELG proposed 

rulemaking. The EPA also questions how the data should be analyzed based on: age; treatment 

of non-detects; treatment of pollutants in source water; and calculation of toxic- weighted 

pollutant equivalents. These specific requests for review and comment on the most fundamental 

input to the analysis for evaluating whether a compliance technology is needed at a facility calls 

into question all of EPA’s conclusions outlined in the proposed rule.

EPA superficially assumes that only incremental costs will be incurred by power plant owners 

requiring a technology retrofit for compliance, without any site-specific examination to assess if 

any existing treatment technology is optimally operating and/or has the capacity to accommodate 

the additional pollutant loadings required for compliance with this proposed ELG rule. This will 

potentially lead to the further underestimation of the costs of these guidelines. EPA asserts that 

the costs developed in their assessment are site-specific, but this position is based on data 

provided in surveys for which the Agency is also asking owners to verify post-use in its 

determination of compliance costs. Even if one considers that the survey information provided is 

valid, the approach employed by EPA to determine an initial cost estimate for an individual 

facility falls far short of one that would pass muster for an owner to go forward with a retrofit 

project. Making these general assumptions and escalating costs to reflect the ELG impact to the 

entire electric utility industry is misleading and doing so introduces amplified error and 

exacerbates the underestimate of cost to comply with the ELG rule. AEP’s costs for compliance 

with the rule, however, provide a more appropriate basis for economic evaluation, in that it 

includes specific plant data (presented herein) in addition to cost estimates derived from 

completed installations. Thus, AEP’s costs for compliance with the proposed rule give a 

more realistic site-specific estimate at each of AEP’s power plant facilities that would be affected 

by the rule for compliance with Option 4.

The EPA’s cost estimates of compliance with each of the options outlined in the proposed ELG 

rulemaking are further inherently flawed as they are expressed as a single value, when it would 

be more reasonable – and believable – to express as a cost with a range of variability indicative 

of the level of certainty in the estimate – i.e. plus or minus a percentage of the estimate (e.g. +/-

50%). Expressing costs in this manner would also be consistent with the principles and process 

standards outlined by the Project Management Institute46 in the Project Management Body of 

Knowledge (PMBOK), which is an industry standard used for executing technology retrofit 

projects of the magnitude expected for compliance with the ELG rulemaking. The PMBOK is a 

collection of processes and knowledge areas generally accepted as best practices within the 
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project management discipline. It is an internationally-recognized project management standard, 

providing the fundamentals of project management for all types of projects, including 

construction projects.

Using PMBOK, projects are executed using a phased management process through which each 

project will progress from initiation to closeout and include the following activities: project 

initiation, project planning, preliminary engineering and design, procurement needs, detailed 

engineering and design, work planning, scheduling, procurement, construction contracts 

awarded, project implementation, project closeout. The accuracy of a project’s estimate 

logically improves as the execution proceeds through the phases as follows, with the band range 

shown representing the accuracy at the beginning of the phase: Phase 1 – 50%, Phase 2 – 25%, 

and Phase 3 – 10%.

EPA fails to provide any such accuracy ranges, giving the false notion that the costs of the rule 

for each option as presented are all inclusive. As can be deciphered in the PMBOK phased 

process, many variables exist that will ultimately affect the scope and cost of any project and 

decision to retrofit. Instead of acknowledging the inherent uncertainty in estimating and 

including appropriate ranges of accuracy in compilation of its costs, EPA relies on survey data to 

extrapolate an estimate from a technology vendor based on a single project, which introduces an 

unknown level of uncertainty in each and every estimate included in the summation of the total 

for compliance with each of EPA’s options.

To illustrate this point that the estimated costs in the proposed rulemaking for industry 

compliance are highly questionable, consider that AEP’s estimated compliance with Option 4 for 

its operating subsidiaries alone will result in the company incurring costs estimated at 

approximately $3.1 billion (2010$) ($3.9 billion fully-loaded 2010$) on a pre-tax direct-cost 

basis. As noted in the TDD, EPA estimates that under Option 4, the capital compliance cost for 

the entire industry exceeds $8 billion dollars. As AEP’s estimated costs are nearly 40% (50% if 

fully-loaded costs are considered) of EPA’s estimated compliance cost for the industry, EPA’s 

estimate has to be highly questioned, considering AEP only owns approximately 4% of the 1,079 

plants EPA considered in this rulemaking.

AEP is also concerned that in its examination of the proposed rule and its technical documents, 

that there is a lack of transparency in the costs estimated in EPA’s analysis from the perspective 

of quantification and delineation of costs by specific direct cost categories. EPA maintains that:

“EPA’s 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 one-time or 

recurring costs. Capital costs comprise the direct and indirect costs associated with the purchase, 

delivery, and installation of pollution control technologies. Capital cost 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.” (Emphasis added) 47

EPA does not definitively state that these items are included in their cost estimates, but merely 

states that these are the common items that comprise capital cost estimates. For example, 
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contingencies included in the direct cost estimation in the EPA analysis are a 

concern. Contingency is an allowance for costs that a company knows it will need but for which 

it lacks enough detailed planning or engineering information to identify or quantify. It addresses 

“known unknowns” which are a legitimate cost in any project activity. Even if one accepts that 

EPA included contingency and/or general contractor profits and overhead in its analysis the 

legitimacy of their inclusion is questionable because the items appear not to be quantified and 

delineated in vendor quotes or in EPA’s technical documents, as has been the Agency’s past 

practice.

Further, the amount of contingency is a reflection of the cost estimate and its accuracy. Since, 

EPA gives no accuracy ranges as explained above, AEP cannot fully comment about the amount 

of contingency embedded in the agency’s cost estimates. For example, if the amount of 

contingency included in the EPA cost estimation is small, then the EPA supposes a high degree 

of accuracy in its cost estimation for compliance costs associated with the rule. This is a position 

that AEP strongly disagrees with given the disparity of its cost estimates compared to the 

agency’s coupled with the agency’s lack of transparency.

Additionally, EPA assessments of compliance costs do not account for several other integral cost 

considerations, such as the costs associated with and necessary for obtaining jurisdictional 

regulatory approval, where applicable. EPA also fails in its analysis to account for any 

equipment or material that would have to be retired or rendered obsolete in response to this 

rule. Any remaining depreciable balance of these assets would have to be accounted for along 

with consideration for removal, where necessary.

46 PMBOK® Guide and Standards, from http://www.pmi.org.

47 EPA Technical Development Document, April 2013, at 9-2.

Comment Response: 

EPA disagrees with the commenter’s assertion that “specific requests for review and comment 

on the most fundamental input to the analysis for evaluating whether a compliance technology is 

needed at a facility calls into question all of EPA’s conclusions outlined in the proposed 

rule.” As required by the APA, EPA provides opportunity for public review and comment of its 

rules including the underlying data and methodologies. 

EPA disagrees with the commenter’s overarching assertions that its approach to estimating costs 

will potentially lead to an underestimation of costs. EPA also disagrees that its methodology 

makes “general assumptions” and escalates “costs to reflect the ELG impact to the entire electric 

utility industry.” The commenter asserts that EPA’s plant specific cost estimates are flawed 

because it did not conduct “any site-specific examination to assess if any existing treatment 

technology is optimally operating and/or has the capacity to accommodate the additional 

pollutant loadings required for compliance with this proposed ELG rule.” EPA disagrees. EPA’s 

assessment of plant specific costs is based on plant specific information that each individual 
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plant provided to EPA in response to EPA’s industry survey. Each of the plants certified that 

their responses were accurate so EPA’s assessment is based on the best information available to 

EPA. EPA notes the commenter’s statement that “even if one considers that the survey 

information provided is valid” calls into question the validity of the survey information, but the 

commenter provides no data or information to indicate the information is not valid. See the TDD 

for details on the industry survey. In estimating compliance costs, EPA looked at the plant 

specific information on its current wastewater handling approaches. Based on data in the record 

on the efficacy of such technologies across the industry, EPA assessed whether the plant would 

likely incur costs to comply with the final limitations. This is consistent with the approach EPA 

has historically used to estimate plant specific costs from questionnaire responses. Contrary to 

the commenter’s assertion that this approach likely underestimates costs for a particular plant, it 

is just as likely that EPA has overestimated costs for a particular plant because a plant could just 

as easily be operating their technology better than EPA estimated. These cost estimates are not 

intended to be used by an individual facility to “go forward with a retrofit project” but are 

intended to provide a reasonable estimate the industry-level impact of the rule. As such, EPA’s 

estimated compliance costs may, in some cases, under or overestimate costs at a specific plant, 

but they still provide a reasonable estimate of the cost to a plant and entity, and thus a reasonable 

basis for determining that the rule is economically achievable. 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”); 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”);.

EPA acknowledges AEP’s submitted cost estimates, but notes that insufficient details were 

provided by the commenter to support these estimates. In addition, EPA questions the 

commenter’s logic in determining that EPA’s cost estimates are highly questionable. AEP did 

not provide documentation for their costs, yet cites their estimates as proof that EPA’s estimates 

are incorrect. In addition, AEP states that their plants account for 40% of the costs (based on 

their estimates) but only own approximately 4% of the 1,079 plants; however, in assessing 

economic achievability, EPA looks to the impacts on the point source category as a whole. See, 

e.g., Texas Oil & Gas Ass’n v. EPA, 161 F.3d 923, 936 (5th Cir. 1998) (EPA may prescribe 

effluent limitations guidelines . . . just as long as the BAT determination remains economically 

feasible for the industry as a whole.). See Section 9 of the TDD for more information on EPA’s 

final compliance cost estimates.

Although it is not necessary to establish a specified level of uncertainty associated with a cost 

estimate, EPA uses the best information available for equipment costs, installation costs, and a 

number of other costs (e.g., engineering design, etc.) associated with the activities plants will 

undertake to comply with the ELGs, including engineering projects to install or replace 

wastewater treatment systems and ash handling systems. Because retrofitting equipment can 

involve add some degree of complexity to a project, such as the need to route piping around 
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existing obstacles, EPA used survey data where it could to refine the cost estimates to the extent 

possible to reflect conditions present at steam electric power plants. Where such data were not 

available from the survey, EPA used other valid data such as vendor equipment and chemical 

cost data and standard engineering cost factors. EPA disagrees that the cost estimates were 

extrapolated from “an estimate from a technology vendor based on a single project.” Cost curves 

provided by vendors or developed by EPA based on cost data received from vendors reflect 

multiple projects designed and/or implemented by vendors for the technology. In addition, 

EPA’s cost estimates include a contingency factor to account for potential unanticipated costs. 

These contingency costs are intended to cover unexpected costs that may arise during the 

project. See the Incremental Costs and Pollutant Removals for the Final Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(Costs & Loads Report) (DCN SE05831/SE05832) for details on the contingency included by 

EPA in its cost estimates.

EPA disagrees with the commenter’s assertion that “there is a lack of transparency in the costs 

estimated in EPA’s analysis.” Similar to proposal, EPA provides a detailed description of the 

cost methodologies used to estimate compliance costs for each technology option evaluated in 

the Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (Costs & Loads 

Report) (DCN SE05831/SE05832). EPA clearly lays out the cost elements included for both 

capital and operation and maintenance costs. EPA acknowledges, however, that due to the 

confidential business information claimed, EPA has to redact some elements of the costs from 

the public non-confidential record. At proposal, upon request, EPA provided companies with the 

specific cost estimates for their plants to allow for more specific review and comment. See 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 224 in Comment Code 1.c 

regarding transparency and plant-specific cost estimates.

Since proposal, as described in Section 9 of the TDD, EPA has updated its cost methodologies in 

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

Number 45 in Comment Code 14.b for more specific discussion regarding EPA’s revisions to the 

fly ash transport water cost estimates including updates to cost equations, BOP costs, 

engineering overhead, profits and overhead, contingency, and land. See response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 53 in Comment Code 16.b for more specific 

discussion regarding EPA’s revisions to the bottom ash transport water cost estimates, including 

BOP costs, engineering overhead, profits and overhead, contingency, and land. See response to 

DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Numbers 24 and 30 in Comment Codes 9.b 

and 10.b respectively for more specific discussion regarding EPA’s revisions to the FGD 

wastewater cost estimates.

EPA disagrees with the commenter’s assertion that EPA did not account for costs associated with 

jurisdictional regulatory approval and that EPA also fails to account for any equipment that may 

be retired or rendered obsolete. As discussed in Section 5.1 of the Incremental Costs and 

Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category (Costs & Loads Report) (DCN 

SE05831/SE05832), EPA includes costs associated with indirect capital costs. Indirect capital 

costs include construction expenses among other elements. These construction expenses would 
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include permits and applicable taxes which should cover any costs associated with jurisdictional 

regulatory approval. Moreover, with respect to permitting approval by the NPDES permitting 

authority, the plant would need an NPDES permit independently of this rule as the Clean Water 

Act already requires that the plant’s discharges needs a permit. The permit must apply the 

technology-based provisions of the Clean Water Act (BPT, BCT, BAT) as appropriate on a BPJ 

basis even without this rule and any additional limitations necessary to meet water quality 

standards. Additionally, EPA does not expect most plants to incur costs to retire or render 

equipment obsolete because most plants will not be removing existing equipment to comply with 

the new effluent guidelines. Where these costs are incurred it would be considered a 

contingency cost which is an element of indirect capital costs.

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: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposal is the result of a now all too familiar “sue-and-settle” consent decree process that 

has forced EPA to propose this rule prematurely. Although the Agency obtained extensions to 

the original Consent Decree deadlines, the rulemaking is extremely complex, and EPA does not 

appear to have fully completed its analyses before concluding that it must rush to issue the 

proposal. For instance, the Agency has failed to gather comprehensive data to fully characterize 

current industry wastewater discharges, has failed to adequately understand and distinguish 

significant differences between fly ash waste streams and bottom ash waste streams, and has not 

properly coordinated this rulemaking with the CCR rulemaking.

Perhaps one result of EPA’s rush to issue the rulemaking was its inability to narrow its proposal 

to a reasonable number of regulatory alternatives. Instead, EPA proposed eight separate possible 

combinations of regulatory outcomes for various waste streams, not counting an extensive array 

of other considerations such as Best Management Practices and voluntary measures. This 

number of alternatives does not give the public adequate notice of EPA’s actual regulatory 

intentions within a predictable range, and instead forces the public to comment on options that 

EPA may not seriously consider. The large number of options suggests that EPA’s thinking on 

the ultimate rule has not, without considering comments from the public, matured to the point 

where it is ready to present the public with a set of realistic alternatives. The proper course of 

action at this point is to treat its proposal as an Advance Notice of Proposed Rulemaking, which 

EPA should have issued in the first place instead of a Notice of Proposed Rulemaking, and 

repropose the rule, based on comments, with a more limited set of regulatory options, each 

accompanied by thorough analysis.

Comment Response: 
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EPA strongly disagrees with the commenter’s “sue and settle” allegation as this rulemaking 

resulted from the process specified in section 304(m) of the Act requiring EPA to review and 

revise effluent guidelines, as appropriate. EPA had not revised this effluent guideline since 

1982, thirty-three years ago, and major changes in the processes at these plants and their 

wastewaters resulted in discharges that were not being controlled at the appropriate level of 

control under the Act. For this reason, this point source category emerged from the 304(m) 

process as a priority for effluent guidelines revision. EPA disagrees with the commenter’s 

assertion that “EPA proposed the rule too prematurely.” EPA evaluated all available data as part 

of the proposed rulemaking. EPA has supplemented the set of characterization data with 

information obtained through public comment, as discussed in Section 3 of the TDD and 

elsewhere in this record.

See response to DCN EPA-HQ-OW-2009-0819-4495-A1, Excerpt Number 1 in Comment Code 

1.c for further discussion on EPA’s presentation of regulatory options at proposal and response 

to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 6 also in Comment Code 1.c 

regarding the need for a reproposal.

EPA disagrees with the commenter’s assertion that it has failed to distinguish significant 

differences between fly ash transport water and bottom ash transport water. As described in 

Section 10.2.2 of the TDD, EPA used separate data sets to characterize fly ash transport water 

and bottom ash transport water. EPA also estimated compliance costs separately for each 

wastestream based on the requirements of each handling system.

See response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 64 in Comment 

Code 27.e regarding BMPs. See preamble section VIII for EPA’s decisions regarding the 

voluntary incentives program.

Commenter Name: Kim Mireles

Commenter Affiliation: Luminant

Document Control Number: EPA-HQ-OW-2009-0819-4614-A1

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

When Mistakes and Biases in EPA's Technical Analyses are Corrected, 

Additional Controls are Unwarranted

In coming up with its preferred options, EPA has made errors in its supporting analyses, used 

unreasonable assumptions, selected and rejected data without explanation, and used unsound 

statistical methods. Also, based on analysis conducted by Utility Water Act Group (UWAG), 

EPA has underestimated the costs of retrofitting technologies like chemical precipitation and 

biological treatment for FGD, dry handling for bottom ash, and dry handling for fly ash. For 
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example, limited cost inputs were used assuming a green-field type of installation- thus these 

costs were not burdened by the real-world conditions often experienced in retro-fit situations. 

These costs include, but are not limited to engineering costs, overhead, and the very real costs of 

integrating new systems within an existing power plant. Dependent upon site conditions, this last 

cost category can be significant as physical space for new systems (and infrastructure to support 

its operation) may simply not exist. These errors, in combination, go toward underestimating the 

cost and overestimating the benefits of the proposals.

Luminant is greatly concerned by the data used for evaluating wastewater streams and 

establishing limits. Considering the importance and financial impact of the rule, and the 

administration's focus on transparency in the rulemaking process, Luminant encourages EPA to 

use sound science and good engineering estimation practices. The proposed regulation does not 

reflect these principles.

Comment Response: 

EPA disagrees that it has “underestimated the costs of retrofitting technologies like chemical 

precipitation and biological treatment for FGD, dry handling for bottom ash, and dry handling 

for fly ash” and that it has not used “sound science and good engineering estimation 

practices.” See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 210 for 

discussion of EPA’s cost and loads estimates.

EPA also disagrees with the commenter’s assertion that EPA’s cost estimates assume a “greenfield type of installation” and do not represent retrofit situations. EPA evaluated the potential 

costs associated with retrofitting operations. Additionally, EPA included indirect costs for each 

technology option evaluated. As described in Section 9 of the TDD, indirect capital cost accounts 

for all non-direct costs incurred as a result of installing the handling system (e.g., engineering 

costs, construction expenses, contractor’s fees, and contingency).

See Sections 6 through 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).

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 153

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Costs incurred by UWAG members show that constructing new landfills and expanding existing 

ones are expensive. Furthermore, the cost is site-specific and depends on factors such as the 
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capacity of the landfill. For example, Company A’s74 actual cost for developing a new landfill 

was $303,987,000 just for the first part. The second and third parts of the project will be 

constructed later and are estimated to cost $25,242,000 and $82,757,000, respectively. The 

project had to be constructed in three phases because the project’s footprint was large.

Company B’s budgeted costs for developing new landfills range from $25 to 

$40 million. Company C added additional cells to two landfills at a cost of $618,550 (17.8 acres 

for approximately 8 years’ capacity) and $548,618 (9.4 acres for approximately 4.5 years of 

capacity), respectively. Another UWAG member, Company D, estimates the cost per acre to 

expand a landfill at $600,000 to $1 million.

Moreover, the annual operating cost of disposing fly ash in an onsite landfill is $3.50 to $6.00 

per ton, compared to wet handling. EPA must consider costs such as these before it can estimate 

the cost or cost-effectiveness of its options for disposing of bottom ash, fly ash, FGMC 

wastewater, and FGD solids.

74 These companies are UWAG members. We refer to them as Company A, B, C, and D to 

protect possible confidential business information.

Comment Response: 

EPA agrees with the commenter’s assertion that disposal costs should be considered as part of 

the cost estimate. As discussed in Section 9 of the TDD, EPA’s compliance cost estimates 

account for costs associated with transporting and disposing of any solids generated as a result of

complying with the final rule. In addition, EPA updated populations and plant-specific cost 

module input data to account for any plant operation changes based on implementation of the 

RCRA requirements (i.e., the CCR final rule) and the Clean Power Plan.

EPA appreciates the information on landfill construction and expansion costs but without 

detailed information on landfill size, liner, leachate collection, or other specific cost element 

information, these estimates cannot be incorporated into EPA’s 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: 12

External Review Flag: Economics/Benefits

External Review Incorporated into Response: No

Comment Excerpt: 
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3. Shorter annualization and cost recovery periods need to be considered in the 

proposed rule.

The time period assumed for cost recovery is a primary consideration when the cost effectiveness 

of any new technology installation is evaluated. EPA assumes that costs are annualized over a 

20-year period, but has previously used a 15-year period to develop ELGs for other industry 

categories. UWAG believes, and AEP agrees, that an annualization period based on a 15-year

service life is a more appropriate assumption and is consistent with past EPA practice.

The application of the proposed wastewater treatment technologies will require the installation of 

major equipment, such as tanks, clarifiers, etc., which should last 20 years, but not without 

significant maintenance. Motors, gear boxes, linings/coatings, biological substrates, etc., will all 

need to be replaced or rebuilt over the 20-year time period. Higher energy components, such as 

pumps and agitators, will also need to be rebuilt or replaced. In other words, the assumption of a 

20-year service life for the proposed treatment technologies is not feasible. A shorter cost 

recovery period, such as 15 years, is more realistic. Market conditions, technological 

developments, and changing regulations simply do not allow a longer cost recovery period.

Comment Response: 

EPA disagrees that it should use a service life of 15 years. The commenter supports its assertion 

by stating that such equipment will last twenty years with significant maintenance. EPA agrees 

and its costing methodology reflects this. 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.

Commenter Name: R. W. Greene

Commenter Affiliation: Mercatus Center at George Mason University

Document Control Number: EPA-HQ-OW-2009-0819-3411-A1

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposed regulatory changes generally lower permitted wastewater discharges. For most 

existing sources of wastewater entering surface water, the same requirements are applied by each 

of the EPA's four preferred regulatory alternatives, which differ in terms of the requirements 

applicable to existingdischarges of pollutants found in two waste streams. The EPA estimates 

different levels of costs for the four alterna tives. One criticism of starting with just four 

alternatives is that the alternatives being considered are, in fact, quite narrow. The major 

provisions of the alternatives for both existing sources and new sources of pollutants are 

summarized below, along with proposals for the control of new wastewater sources, for which 
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there really are no alternative regulatory proposals. The EPA manages to count a total of eight 

alternatives for old and new sources by matching the proposals for new sources to the 

alternatives for existing sources. This is misleading because the proposals for new sources are 

just minor tweaks to the four alternatives for existing sources.

Comment Response: 

EPA disagrees with the commenter’s assertion that the regulatory options considered are too 

narrow. The preferred options ranged from no additional controls for certain wastestreams, such 

as bottom ash transport water and FGD wastewater at certain sized operations, to establishing 

zero discharge limitations. In addition, EPA received comments to the contrary, arguing that too 

many regulatory options were evaluated; see comment EPA-HQ-OW-2009-0819-4466-A1, 

Excerpt Number 10.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

When calculating “total weighted pounds-equivalent” (TWPEs) removals (i.e., pollutant 

reductions) based on dry handling for fly ash and dry handling or closedloop systems for bottom 

ash, it is entirely inappropriate to include pollutants attributable to source waters as “removals.” 

Pollutants present in source waters will remain in the source waters if the units convert to dry or 

closed-loop handling. Therefore, EPA must adjust its TWPEs for those wastestreams to subtract 

out the source water contribution before using the estimated TWPE reductions in its cost 

effectiveness analysis, its environmental assessment, or its benefit/cost analysis.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 39 in Comment Code 

4.b for a discussion of source water data.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 42

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Inaccurate Assumption that No Pollutants would be Removed and No Technologies would 

need to be installed for FGD Wastewater under Option 3b at Oak Creek Power Plant.

Proposed Preferred Regulatory Option 3b for FGD Wastewater calls for chemical precipitation 

plus biological treatment for scrubbed capacities greater than or equal to 2,000 MW. For all 

scrubbed capacities less than 2,000 MW, the treatment technology is Best Professional Judgment 

(“BPJ”). The chemical precipitation WWTS installed and operated at Elm Road Generating 

Station treats combined FGD wastewaters from Oak Creek Units 5-8 and Elm Road Units 1 and 

2. The combined scrubbed capacity of those units is 2545.6 MW. It appears EPA only 

considered the combined capacities of the Oak Creek units (1191.6 MW) in making its 

determination that no pollutants would be removed and no technologies would need to be 

installed under Regulatory Option 3b at Oak Creek Power Plant. If Option 3b is promulgated by 

EPA, then OCPP-ERGS would need to comply with the CP+BIO limits.

Comment Response:

As described in Section VIII of the preamble, EPA did not base the final BAT requirements on 

proposed regulatory option 3b. EPA included costs for all units with greater than 50 MW 

nameplate capacity to meet the BAT limitations based on chemical precipitation plus biological 

treatment for FGD wastewater. See the Incremental Costs and Pollutant Removals for the Final 

Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category (Costs & Loads Report) (DCN SE05831/SE05832) for further discussion on 

EPA’s cost estimates.

Commenter Name: Becky Hayat

Commenter Affiliation: Natural Resources Defense Council (NRDC)

Document Control Number: EPA-HQ-OW-2009-0819-4490-A1

Comment Excerpt Number: 11

External Review Flag: Economics/Benefits

External Review Incorporated into Response: No

Comment Excerpt: 

In addition to reductions in water use, dry ash handling methods may have additional benefits, 

such as decreasing O&M costs and bringing in additional revenue.

Besides reductions in water use, there are other benefits associated with the conversion from a 

wet ash handling system to a dry handling method. With respect to fly ash, dry handling has 

become the standard for new installations and retrofits over the last few decades. Based on 

industry responses to the Steam Electric survey, the reasons cited for installing dry handling 

systems include environmental remediation, economic opportunity, and the need to replace ash 

impoundments approaching full storage capacity.19 Specifically, the economic opportunity refers 
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to the potential for dry handling methods to lower O&M costs, as well as to the emergence of 

local markets, enabling the reuse and sale of fly ash and bottom ash to concrete suppliers.

19 TDD at 4-23.

Comment Response: 

EPA agrees with the commenter’s assertion that plants reported the ability to reuse and market 

dry fly and dry bottom ash in response to the Steam Electric Survey; however, EPA’s costing 

account for costs associated with plants transporting and disposing of fly ash and/or bottom ash 

in a landfill.

EPA did analyze the potential benefits associated with the enhanced marketability of dry ash for 

the final rule. The analyses are described in Chapter 10 of the BCA document and provide 

information about the potential magnitude of benefits to steam electric power plants and to 

society more generally from enhancing beneficial reuse of the CCR. Also see response to related 

comment DCN EPA-HQ-OW-2009-0819-4490-A1, Excerpt Numbers 29 in comment code 29.a.

EPA agrees with the commenter that there are broad environmental benefits from the final 

rule including reduction in water use. 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: 58

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s industry-wide cost estimate does not reflect anticipated unit retirements or conversions, 

id., that would occur after December 31, 2014,229 even though many of those retirements would 

happen before the first year in which EPA assumes that the technologies would be 

implemented—2017.230 This arbitrary cut-off date excludes the entire class of plants that are 

likely to shut down or switch to natural gas just before the MATS compliance deadline of April 

2015.231 A number of these plants slated for retirement, but included in EPA’s analysis, have 

wet FGD systems, as shown in Table 2.

Table 2 – Wet-Scrubbed Units that Have Announced Retirement But Were Included 

in EPA’s Cost Analysis

State Plant Name and Units Retirement Date

KY Big Sandy Unit 2 2015
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State Plant Name and Units Retirement Date

AL Colbert Units 1-5 2016 for Units 1-4, 2018 for Unit 5

NY Danskammer 2012

IN Harding Street Units 5, 6 2016

PA Hatfield’s Ferry Units 1-3 2013

OH Muskingum River Unit 5 2015

NV Reid Gardner Units 1-4 2014 for Units 1-3, 2017 for Unit 4

IN Tanners Creek Unit 4 2015

PA Mitchell Power Station Unit 3 2013

PA Shawville Units 3, 4 2015

GA Yates Units 1, 6, 7 2015

Source:

--EIA Form 860 (2012) (generating unit size);

--National Electric Energy Data System Annual Coal Unit Characteristics (2012) (sulfur dioxide 

control technology installed)

-- List of Announced Retirements Included in EPA’s Cost Calculations (retirement date)

Accounting for these additional retirements and conversions would lower the industry-wide cost 

of all options.232

229 EPA-HQ-OW-2009-0819-2149, at 2.

230 RIA at Table 3-1.

231 List of Announced Retirements Included in EPA’s Cost Calculations, submitted by 

Commenters as an exhibit to this letter.

232 A plant that converts to run on natural gas would no longer need to operate its wet FGD 

system.

Comment Response: 

As discussed in Section 4.2.5 of the TDD and DCN SE05069, EPA’s analysis of regulatory 

options considered for the final rule appropriately accounts for announced plant retirements and 

fuel conversions prior to the date by which plants must achieve BAT limitations (approximately 

8 years from promulgation of the final rule). As described in the Memorandum to the Steam 

Electric Rulemaking Record: Changes to Industry Profile for Steam Electric Generating Units for 
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the Steam Electric Effluent Guidelines Final Rule (DCN SE05069), EPA has updated the list of 

plants and generating units identified as retiring or converting fuels prior to this date. See also 

preamble Section V.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: 130

External Review Flag: Statistics

External Review Incorporated into Response: No

Comment Excerpt: 

b) On page 10-5 and elsewhere the TDD states “EPA treated all results that were less than the 

quantitation limit (i.e., J-values and nondetects below the method detection limit) as half the 

sample-specific quantitation limit for all analytes.” This method decreases the variability of the 

resulting estimates, leading to a standard deviation of the fitted distribution that is too small. It is 

unclear why this substitution was done here, and elsewhere the quantitation limit itself was 

substituted. The inconsistency is unnecessary – there are good published methods for censored 

data. See Helsel (2012) for a description of them.

Alternative Recommendation: instead use censored-data methods such as the Kaplan-Meier

estimator to estimate statistics for data with nondetects and J values. Kaplan-Meier is the 

standard method in drug trials and medical statistics for estimates from censored data, as so has 

precedent in other regulatory contexts.

Comment Response: 

EPA did not use J values in its final loadings estimates. See response to DCN-EPA-HQ-OW2009-0819-4655, Excerpt Number 42.

With respect to how EPA used no-detect values in developing the effluent limitations, see 

Appendix A, Essay Section 3.5 and the Statistical Support Document for Effluent Limitations 

(DCN SE05733). EPA does not agree that it should use the Kaplan-Meier approach suggested by 

the commenter. See the response to Appendix A, Essay Section 4.2.

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: 79

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Constructing New Landfills Would Be Costly and Time-Consuming.

Before moving past EPA’s proposed BAT options for each of the seven key wastestreams, it is 

necessary to address landfill creation, which is associated with many of the proposed 

options. Several of EPA’s eight options for fly ash, bottom ash, and FGMC disposal require ash 

(or the solids from evaporation for FGD wastewater in option 5) to be disposed ofin 

landfills. Constructing a landfill can take 8 years or more, and even expanding an existing 

landfill can take 14 to 30 months. Also, a power plant owner may go through the entire 

permitting process only to have the landfill permit application turned down. See Power 

Engineering, Kentucky agency denies permit for coal ash landfill at Trimble County Power Plant 

(Mar. 21, 2013), at http://www.power-eng.com/articles/2013/03/kentucky-agency-denies-permitfor-coal-ash-landfill-at-trimble-c.html. EPA must consider costs such as these before it can 

estimate the cost or cost-effectiveness of its options for disposing of bottom ash, fly ash, and 

FGMC.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4466-A1, Excerpt Number 11 in Comment 

Code 27.e regarding landfill capacity and timing for new landfills.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In benefit‐cost analyses, regulatory costs often involve well‐defined, monetized categories, as is 

the case with engineering cost estimates. Nonetheless, these costs are not free of errors, 

imprecision, or uncertainty. There is a research literature documenting the tendency for ex ante 

estimates of regulatory costs to overstate the true, ex post costs.

One widely cited study, by Winston Harrington and colleagues at Resources for the Future, 

identified 25 major rules for which they could find both ex ante agency cost estimates and ex 

post cost calculations, the latter usually provided by independent researchers. In twelve of the 25 

cases, the ex ante estimates were more than 25 percent higher than the actual costs, compared to 

only six cases in which the estimates were more than 25 percent lower.44 The study discusses a 

number of reasons for overestimates, including:
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 Technological innovation, spurred in part by regulation, may lead to reduced costs and/or 

improved efficiency in compliance technologies, as apparently happened with scrubbers 

for coal plants. In other words, once industry begins investing in compliance with a rule, 

a market develops in compliance technologies, and compliance costs often go down in 

ways that ex ante cost estimates do not project.

 Advance analyses also tend to estimate maximum rather than most likely compliance 

costs. This may occur inadvertently, if expensive technologies are available off the shelf 

and are better known; it may result from strategic considerations by affected industries, 

seeking to inflate cost estimates as an argument against regulation; or it may result from 

deliberate choices by agencies, seeking to minimize grounds for court challenges from 

industry.

 Error correction may be asymmetric—the affected industries will reliably call attention to 

gross underestimates of compliance costs, while there may be no corresponding pressure 

to reduce gross overestimates. The affected industry tends to have better access to 

information about compliance costs than the agency or members of the public, making 

the rulemaking record subject to this inherent bias.

In another study comparing prospective and actual costs of major regulations, legal scholar 

Thomas McGarity and economist Ruth Ruttenberg also find a preponderance of overestimates.45

Their description of potential grounds for upward bias in ex ante costs includes the points 

identified by Harrington et al., plus some additional possibilities:

 For lack of information, agencies may compare the costs of a proposed regulation to a 

zero regulation, zero compliance baseline, rather than appropriately measuring the 

incremental costs relative to prior regulations and the actual level of voluntary 

compliance.

 Companies may include the costs of upgrading other equipment in their reported costs of 

regulatory compliance.

44 Harrington, W., R.D. Morgentstern, and P. Nelson. "On the accuracy of regulatory cost 

estimates." Journal of Policy Analysis and Management 19, no. 2 (2000): 297‐322.

45 McGarity, T.O., and R. Ruttenberg. "Counting the cost of health, safety, and environmental 

regulation." Texas Law Review, 2001: 1997‐2058.

Comment Response: 

EPA acknowledges the commenter’s points that compliance costs may often be overestimated 

based on various assumptions that tend to be conservative. However, because it is not possible to 

predict future costs of technology implementation, EPA appropriately based its estimates of the 

best available data at the time the rule is promulgated. In addition, EPA received and evaluated 

public comments contrary to this argument identifying specific areas where costs were 

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

210. EPA conducted a thorough evaluation of public comments and adjusted its cost estimates, 

to increase or decrease costs, where appropriate.
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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: 42

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

8. EPA’s Sensitivity Analyses on its Use of Nondetect Data Demonstrated 

Extremely High-Biased Distortions in TWPEs when using Full Value for Nondetect Results for Many Pollutants with High Toxic Weighting Factors

EPA, to its credit, did perform a sensitivity analysis on its use of the full value of each fly ash 

transport water and bottom ash transport water non-detect result when calculating TWPEs. EPAHQ-OW-2009-0819-2241. These checks demonstrated that many of the loadings from the most 

toxic pollutants with the highest EPA-calculated TWPEs are based almost entirely on non-detect 

values. Parameters such as thallium, tin, sulfide, and beryllium are almost entirely based on nondetect data according to the EPA sensitivity analysis. EPA-HQ-OW-2009-0819-2241.1.

However, the EPA analysis was flawed because it did not properly perform the same sensitivity 

analysis on the 1982 Development Document data.12 EPA did not have or did not use individual 

analyses for the average plant data taken from Tables V-32 and V-33 in the 1982 Development 

Document and therefore did not have information as to what portion of the average values were 

detected or not. For the TVA data summarized in Table V-34, the 1982 Development Document 

states that the values were likely overestimated because non-detects were counted at face 

value. 1982 Development Document at 154. But EPA did have individual data points for the 

TVA average data from Table V-34 (see Tables A-1 to A-17), and these data showed that for 

many key high TWPE parameters, the TVA results, like the Form 2C results, were dominated by 

non-detected results, and at values that exceeded any detections in modern lab data by factors as 

high as 10,000.

The following table lists parameters that were greatly affected by non-detect results. In addition, 

the non-detect component of the 1982 Development Document data is mostly unknown. What is 

clear is that the average data reported from the 1982 Development Document, except for arsenic, 

are anywhere from eight to 200 times higher in concentration than the modern data, once 

corrected for high non-detect values from the Form 2Cs.

Pollutant EPA Calculated

BA TWPE

Approximate Percentage 

of EPA TWPE Based on 

Non-Detect (ND) Data

Comments

Sulfide Essentially 100%

Although there were three 

ostensibly “detected” results (out 

of 22 samples), basic chemistry 
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Pollutant EPA Calculated

BA TWPE

Approximate Percentage 

of EPA TWPE Based on 

Non-Detect (ND) Data

Comments

1,587,993 tells us that sulfides are not present 

in oxygenated water.

Tin 107,375 100%

All data points in the EPA 

database were ND. EPA used onehalf the value for the ND data and 

in its SER erroneously labeled the 

result as detected.

Thallium 125,945 Nearly 100%

One detected value; all ND values 

were higher than the detected 

results, some by 400 times.

Silver 84,839 Nearly 100%

Only 2 detections for BA ponds, 

ND values up to 100 times 

higher. TVA silver data (Table V34) used for combined ash had 

approximately 120 results, with 

only two detections right at the 

detection level (DL). That DL was 

0.01 mg/L, 100 times higher than 

modern detection limits.

Beryllium 4,254 98% ND values

in TVA data

TVA beryllium data (Table V-34) 

used for combined ash had

approximately 120 results, with 

only three detections right at the 

DL. The DL was 0.01, 10 times 

higher than modern detection 

results.

Nickel 14,500 Unknown, but up to 95%

TVA nickel data (Table V-34) 

used for combined ash had 

approximately 120 results. There 

were no detections, and the DL 

was 0.050 mg/L, 50 times higher 

than modern detection 

results. Most of the Ni TWPE 

decrease was due to dropping the 

Table V-33 nickel data, where the 

percentage of non-detect values 

and DL limits are unknown.

Antimony 1,154 97%

Only one detected result. Nondetect values up to 200 times 

higher than modern detection 

values.
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The 1982 data dominate all the data, not only by sheer number of analyses but also in 

concentration values. For all of the 1982 data except arsenic, the concentrations and resultant 

TWPE from the 1982 data alone are eight to 200 times higher than the resultant TWPE using the 

modern analyses, once these values have been adjusted for a few high non-detect values reported 

in Form 2C.

12 While EPA did not have quantitation or detection limits for the 1982 Development Document 

data, it included the “nondetected values equal to the value provided in the data source (e.g., <2 

ug/L became 2 ug/L).” EPA-HQ-2009-0819-2241, p. 2. EPA used these values in the sensitivity 

analysis.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 

15.d regarding the 1982 TDD regarding bottom ash transport water loadings and TWPE for the 

final rule. 

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, including Tables V-32, V-33, 

and Appendix A, and its use in the rulemaking.

For the reasons explained in the 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.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 23

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. EPA’s Statistical Method for Estimating Pollutant Loadings from Ash Impoundments Is 

Biased High

First, EPA has erred in calculating the number of TWPEs in effluents from ash ponds, including 

fly ash ponds, bottom ash ponds, and “combined” ponds that hold both fly ash and bottom 

ash. EPA’s statistical errors are documented in the report by AKRF, Inc., Technical Review of 

Statistical Methods and Data Baseline Ash Impoundment Pollutant Loadings and TWPEs, which 
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is Attachment 1 to these comments. Also, EPA has not adequately explained how it estimated 

pollutant loadings, as explained in the Gradient Report (Attachment 2).

1. Using Undetectable Results for Sulfides for Form 2C and Other Pollutants from Various 

Sources as if They Were MeasuredEffectiveness

As the AKRF report explains, over half EPA’s estimated baseline TWPE for ash impoundment 

effluent consists of sulfides. But almost all EPA’s measurements of sulfides were below the 

detection limit. EPA raised these “nondetect” results to the detection limit, which is the highest 

concentration possible given the inability to detect sulfides at all.

EPA’s estimates of sulfides for bottom ash and fly ash ponds were based on only five sample 

results from Form 2Cs, and all of them found no detectable sulfides. For combined ash ponds, 

EPA’s estimate of sulfides was based on 17 sample results from Form 2Cs, only three of which 

were above the detection limit. Over half EPA’s estimate of TWPE for ash impoundment 

effluent, then, has no basis in fact.

2. Multiplying Average Flow by Average Concentration Biased the Calculation of Average 

Loading

In addition to the inappropriate use of undetectable sulfides, EPA’s statistical method was biased 

in a way that overestimated the loading of pollutants from ash ponds.

EPA’s method for estimating the average loading in pounds per year per impoundment was to 

multiply the average concentration (the average over all impoundments) times the average 

transport water flow rate (the average over all impoundments). EPA then multiplied its estimate 

of the average loading per impoundment times the number of impoundments to estimate 

industry-level loadings.

To do the calculation correctly, EPA should have calculated the product of the concentration 

times the transport water flow rate for each impoundment and then averaged the results over all 

impoundments. The average of products (the right way to calculate average loadings) is not 

equal to the product of averages (EPA’s method). When pollutant concentrations are negatively 

correlated with transport water flow rates (that is, concentrations are lower when flows are 

higher), as they are here, EPA’s method produces estimates that are biased high.

Adjusting EPA’s estimates to account for this bias reduces the estimated total loadings (summed 

over the three impoundment types) by 63%, from 2,182,900,000 to 801,786,870. Adjusting each 

estimate of TWPE to account for the bias reduces the total TWPE by 59%, from 5,233,000 to 

2,169,828.

Combined, the two errors (assuming numbers for undetectable sulfides and calculating pollutant 

loadings as the product of averages) probably caused EPA’s baseline TWPE estimates to be too 

high by a factor of six. Computing the total TWPE without the invalid sulfide data reduces the 

baseline TWPE from 5,240,000 to 2,121,609. Adjusting the estimate to account for the likely 

bias in loading estimates further reduces the baseline TWPE to 859,686.
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Thus, the combined effect of EPA’s calculation errors was to produce an estimate of total TWPE 

that is six times too high. This overestimate of pollutant loadings in turn made EPA’s 

calculations of dollars per TWPE too low.

C. The TWPE Analysis Should Not Use “J” and “U” Values

In ELG rulemakings for other industries EPA has been cautious about relying on data that are 

undetectable or questionable. This type of data is represented by U (non-detected) and J 

(questionable detections for metals, inorganics, and GC analyses) qualifiers. Generally “U” or 

“J” data in the effluent do not much affect TWPE, since they are all low numbers. However, 

using “J” and “U” values is a matter of concern if TWPE calculations are based on pollutants 

with high TWFs that are nearly all “J” or “U.”

For example, for the proposed Transportation Equipment Cleaning (TEC) Industry rule, EPA 

took a few “J” qualified pesticide detections in the influent as sufficient to calculate 

TWPE. Because of the large TWF of these pesticides, they were over 95% of the TWPE for the 

rule. In the final TEC rule, this was corrected, and EPA did not calculate TWPE for a compound 

unless the concentration averaged at least five times the reporting limit for the compound and 

was detected in at least two influent samples in each subcategory. EPA also eliminated all Jqualified detections of pesticides that had been banned in the U.S.

More information about how to select pollutants to calculate TWPE is found in EPA’s “CostEffectiveness Analysis of Effluent Limitation Guidelines and Standards for the Centralized 

Waste Treatment Industry,” EPA 821-R-98-018 (Dec. 1998), Docket No. W-98-21 (hereinafter 

CWT Cost-Effective Analysis). These methods place many practical restrictions on detected 

pollutants in the influent, some of which could be applied to screen out “J” or “U” qualified or 

other questionable data. Also, if virtually all the results for a pollutant are undetected in the 

influent (possibly at an elevated reporting limit due to analytical interference), then no removal 

can be credited simply because the effluent has a lower reporting limit.

For the proposed steam electric guidelines, EPA did not use J or U data for wastewater. Instead 

EPA used one-half the Reporting Limit (RL) for data reported as

The CWT Cost-Effectiveness Analysis does not discuss how to handle qualified results. It does, 

however, contain statements indicating that a pollutant needs to be present in significant amounts 

in the baseline (influent) wastewater, that it must be capable of being treated to some degree of 

effectiveness, and that it should be relatively toxic and not ubiquitous in the environment.

The qualifications for pollutants of concern for TWPE calculations are given on pages 2-2 to 2-3 

of the CWT Cost-Effectiveness Analysis:

Generally, pollutants of concern were not included for the following reasons:

 the pollutant was not effectively treated by the option technology (the pollutant level 

increased across the technology)
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 the pollutant was not detected at treatable levels in the influent streams at the facilities 

forming the basis for the options limitations and standards

 the pollutant is pervasive in the environment as a mineral and is relatively nontoxic (for 

example, calcium)

 the pollutant is often used as a treatment chemical, and

 the pollutant’s TWF is zero.

These conditions suggest how “U” and “J” qualified data should be handled. In particular, the 

second condition (that is, the pollutant should be initially present at treatable levels) should rule 

out pollutants with only “U” and “J” measurements. “U” and “J” qualified results clearly do not 

indicate “treatable levels.”

On page 7-27 of EPA’s “Development Document for Proposed Effluent Limitations Guidelines 

and Standards for the Centralized Waste Treatment Industry, Volume 1,” EPA 821-R-98-020, 

Docket No. W-98-21 (CWT 1998 Development Document) for the proposed CWT rule, EPA did 

widen the definition of “effective treatment” to include pollutants for which some marginal 

apparent removal was observed. EPA stated on page 7-27, “[f]inally, EPA eliminated those 

pollutants for which the treatment technology forming the basis of the option is not a standard 

method of treatment. For example, chemical precipitation systems are not designed to remove 

BOD5. Table 7-11 lists these pollutants for each subcategory and option.” Table 7-11 included 

boron as a parameter that was not treated effectively by chemical precipitation, and EPA 

concluded that any apparent boron removal across this technology was “incidental.” CWT 1998 

Development Document.

Moreover, EPA eliminated boron from TWPE consideration in the CWT rulemaking because 

chemical precipitation technology is not the standard method of treatment. CWT 1998 

Development Document at 7-27 to 7-28.

In addition, the third and fourth conditions (contaminants that are pervasive as a mineral in the 

environment and pollutants that are often used as a treatment chemical) should apply to both 

magnesium and manganese. Crushed limestone used in scrubbers contains magnesium. While 

this is not used to treat wastewater directly, it is essential to removing SO2 from the gas stream.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655-A1, Excerpt Number 4 for more 

information on methodology for multiplying plant-specific ash transport discharge flows by 

average pollutant concentrations and information on sulfide.

For the reasons explained in the 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.

EPA describes in Section 10 of the TDD the methodology for handling results below the 

quantitation limit. For all wastestreams, EPA’s estimates of baseline pollutant loadings and 

pollutant removals for the final rule use “1⁄2 the sample-specific reporting/quantitation limit” (“1⁄2 
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QL) for all U- and J-flagged observations. In other words, EPA did not use U or J values as 

reported for the final rule in its loadings estimates. However, contrary to the commenter’s 

suggestion, EPA did not eliminate the data, rather it appropriately included the data as non-detect 

and assigned a value equal to 1⁄2 the QL. This approach recognizes that EPA does not have Jvalue and MDL information for much of the data and allows EPA to use a consistent 

methodology for all sources of data (e.g., EPA-sampled vs self-monitoring) and all 

wastestreams. EPA also considered several alternative approaches for estimating baseline 

loadings and pollutant removals, as described in the TDD. Also see the memorandum entitled 

Evaluation of Alternatives for Handling Qualified Analytical Data in the Steam Electric Pollutant 

Loadings (SE05879) for further discussion on how EPA handled data where the analyte 

concentration measured below the method detection limit (MDL) or the quantitation limit (QL) 

including a sensitivity analysis of three alternate methodologies and their effect on the pollutant 

loadings calculations.

EPA disagrees with the commenter’s assertion that the TWPE analysis should handle non-detects 

in the data set by excluding results qualified as “U” and “J” values. For discussion on how EPA 

handled non-detects in the data set see response to DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 72 in Comment Code 15.d.

The commenter cites examples of how EPA has handled data for past ELGs. Many if not all of 

the examples are provided to address their concern about J values but the cited examples are 

specific to other applications. EPA notes that the examples provided by the commenter are 

specific to the individual industry examined and the data for that industry and that EPA’s 

approach may vary from one industry to the next. The examples provided by the commenter 

demonstrate this. Generally, for all industries, EPA reviews criteria related to the frequency of 

detection and/or the level that is considered treatable for that type of wastewater. EPA did so in 

this rulemaking. However, as it did in the examples cited by the commenter, EPA used an 

approach appropriate for the steam electric industry. Also, see response to DCN EPA-HQ-OW2009-0819-4499-A1, Excerpt Number 72 in comment code 15.d.

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. EPA Overstates the Likelihood that Impoundments Will Close

We address below EPA’s methodology for determining the avoided costs (benefits) associated 

with utilities’ compliance with the ELGs. We have an initial concern, however, with the 

preliminary assumption of this portion of the BCA, namely the supposition that surface 
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impoundments will close if they are no longer able to accept the combustion residual 

wastestreams that they currently receive. This assumption underlies much of EPA’s analysis but 

as we address in Section II above, many impoundments will continue to operate even if they are 

prohibited from accepting one or more CCR wastewater streams. Nothing in the ELG proposal 

would require any existing impoundment to close and it is likely that many companies will 

continue to use impoundments to manage other permissible wastewater streams (assuming EPA 

selects the Subtitle D Prime option under the CCR rule, as recommended above), even if only for 

ancillary wastewater treatment or the management of low volume wastestreams.

Indeed, as discussed above, the ELG Proposal expressly contemplates impoundments remaining 

open to manage certain legacy CCR transport wasters and to serve as part of the ELG treatment 

option for other regulated wastewaters. The Agency’s analysis of this issue appears to be based 

on three reports issued by ERG, EPA’s consultants on this issue, namely: (i) “Methodology for 

Estimating Impoundment Age, Capacity, and Reductions in Capacity Used to Estimate Benefits 

Associated with Avoided Impoundment Failures,” (ii) “Steam Electric Effluent Guidelines—

Methodology for Identifying Surface Impoundment Closures Based on Regulatory Options,” and 

(iii) “Revised Pond Closure Analysis Including Partial Benefits.” While the first two reports 

provide a methodological framework for calculating likely pond closures, the third report 

provides details on the pond closures that ERG determined will occur. Unfortunately, this third 

document has been withdrawn from the rulemaking docket because it has been determined to 

contain confidential business information. Accordingly, USWAG’s comments will necessarily 

be limited to an analysis of ERG’s description of its methods as described in the first two reports.

According to the second report identified above which assessed full impoundment closures, it 

appears that ERG examined only the current and future management of three CCR wastewater 

streams for each of the reviewed impoundments. It then determined the impact of each of the 

proposed regulatory options on the continuing management of each of the three wastestreams—

e.g., option three would eliminate the management of FGD and fly ash transport waters in 

impoundments but would not affect bottom ash management. It determined how each regulatory 

option would impact existing impoundments based on the wastestreams currently managed in the 

impoundments. Based on the regulatory options, it assumed that these impoundments would 

either (i) not be affected by a particular regulatory option because the wastestreams managed in 

the impoundment were not affected by the particular regulatory option, (ii) be partially closed 

because at least one wastestream could no longer be managed in the impoundment under the 

regulatory option, or (iii) closed because all currently managed wastestreams could no longer be 

managed in the impoundment under the regulatory option.

What is notable about this analysis is that ERG only assesses three wastestreams and concludes 

that an impoundment will close based on the following rationale: “[t]he implementation of the 

regulatory option being evaluated will eliminate all the combustion residual wastes (e.g., FGD 

wastewater, fly ash, and/or bottom ash) currently stored in the surface impoundment; therefore, 

ERG assumes the plant will close the surface impoundment.” Id. at 3. This methodology makes 

a number of significant assumptions about current and expected future utility management 

practices and totally ignores the myriad other wastestreams evaluated as part of EPA’s proposal 

and included in the ELGs for this industry. As explained above, many utilities are likely to elect 

to keep impoundments open to manage these other wastestreams, as well as other legacy 
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transport waters already placed in the impoundment. However, ERG assumes these 

impoundments will close based solely on the future management possibilities of only three 

wastestreams and excludes the capacity of all these “closed” units from potentially having 

releases and structural failures. This assumption is at odds with the structure of the ELG 

proposal which in fact contemplates the continued operation of these impoundments for the 

above wastewaters and therefore necessarily vastly overstates the avoided costs (benefits) 

associated with this proposal.

In the first ERG report listed above, there are also some key assumptions provided in a very brief 

summary of its section on the reductions in impoundment capacity. For impoundments slated to 

be “partially closed,” ERG identifies a key supposition that “[w]hile the reduction in flow 

entering the pond will not necessarily decrease the size of the impoundment unless the plant 

closes portions of the impoundment after implementation of the ELGs, the impoundment will 

receive less combustion residual solid waste and therefore, will be less likely to have a breach of 

the impoundment.” Id. at 3. ERG, however, provides absolutely no analysis or background why 

this sweeping assumption might be accurate. It would seem just as likely that flow not 

containing CCRs could also lead to a breach. This rationale is, at least, a poor basis for assuming 

a reduction in the rate of future structural failures of impoundments.

While each of these assumptions overstates the avoided costs of the proposal, we cannot provide 

analysis of the actual methodologies used or the impact of these assumptions on the projected 

closures of impoundments because the report laying out these details has not been included in the 

docket. EPA should provide this critical report to the public (even in a redacted form) so that the 

impact of this assumption can be addressed as part of this rulemaking process. Failure to provide 

this critical information for review and comment deprives the public of evaluating a critical 

component of the rulemaking record and raises serious concerns regarding whether EPA has met 

its obligations under the Administrative Procedure Act to provide public notice and an 

opportunity to comment on this rulemaking.

Comment Response: 

The commenter raises several issues regarding the analysis of avoided impoundment failure 

benefits. Regarding assumptions on impoundment closure and failure rates, see response to DCN 

EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 129 in comment code 29.g. For 

convenience, EPA repeats some of the relevant points from that response below:

 First, the commenter expresses concerns “with the preliminary assumption of this portion 

of the BCA, namely the supposition that surface impoundments will close if they are no 

longer able to accept the combustion residual wastestreams that they currently 

receive.” EPA notes that this statement misstates EPA’s assumptions and analysis. In the 

impoundment analysis, EPA does not assume that all impoundments would close as a 

result of the ELGs, but instead assumes that plants would reduce the amount of coal 

combustion residues handled wet and therefore stored in impoundments. This will in turn 

reduce the amount of CCR that may be involved in the event of an impoundment release.

 Second regarding the statement that “the impoundment will receive less combustion 

residual solid waste and therefore, will be less likely to have a breach of the 
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impoundment,” EPA notes that this is not an accurate depiction of EPA’s benefit 

analysis; EPA does not assume that decreasing the size of impoundments will reduce the 

probability of an impoundment breach. Instead, as described in Chapter 6 of the BCA, 

EPA assumed a constant rate of failure across impoundments under the baseline and postcompliance scenarios. However, EPA did assume that reducing the amount of ash stored 

in a given impoundment will reduce the volume that accumulates in the impoundment 

over time, and that may be released in the event of a release. EPA accordingly estimated 

lower expected costs for the same number of future releases due to reduced CCR volumes 

involved. Additionally, for the final rule analysis, EPA further improved this estimate by 

calculating release rates separately for large impoundments and small impoundments for 

two types of failures, and calculating probabilities and capacity factors within those 

groups.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 48

External Review Flag: Statistics

External Review Incorporated into Response: No

Comment Excerpt: 

5. EPA’s Method of Calculating Bottom Ash Pollutant Loading Is Further 

Biased High by the Statistical Procedures Used

In Section 10 of the 2013 TDD EPA describes its method for calculating baseline ash 

impoundment pollutant loadings (see 2013 TDD at 10-22, -26 to -27).

As explained above and in the attached report by AKRF, Inc., EPA calculated baseline ash 

impoundment loadings in four steps:

1. estimate industry-level average pollutant concentration (pounds per million gallons);

2. estimate impoundment-specific ash transport water flow rates (million gallons per day)

3. estimate impoundment specific loadings based on the industry average pollutant concentr

ation and impoundmentspecifictransport water flow rates; and

4. estimate the industry-level loadings as the sum of impoundment-specific loading 

estimates.

AKRF’s Report, Attachment 1 at 4.

Thus, EPA calculated average loading per impoundment by multiplying the average pollutant 

concentration times the average transport water flow rate.
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For each impoundment, the loading is the product of the concentration times the transport water 

flow rate at that impoundment. The average of products (the proper way to calculate average 

loadings) is not equal to the product of averages (EPA’s incorrect methodology). This fact is at 

the heart of the statistical theory of correlations.14

If pollutant concentrations are negatively correlated with transport water flow rates (as UWAG 

believes they are, based on the analysis below), then EPA’s methodology will produce estimates 

that are biased high.

To determine how much bias, AKRF analyzed the data in EPA’s ICR database. The data files 

were merged by plant, steam electric unit, and impoundment. Data on plants and steam electric 

units that reported bottom ash production, sluicing flows, nameplate generation capacity, and 

50% or more of BTUs produced by coal were included in the assessment. Plants and steam 

electric units that had relevant data redacted as confidential business information were excluded 

from the assessment. In addition, impoundments that received both fly ash and bottom ash were 

excluded. A total of 104 impoundments in the data files satisfied these criteria.

The ICR database also contained data on bottom ash sluice flow rates. Accordingly, an estimate 

of the coefficient of variation for bottom ash transport water flow rates could be calculated 

directly from the ICR database. A systematic list of pollutant concentrations associated with 

bottom ash transport water, or impoundment discharges, was not included in the ICR 

responses. However, data on bottom ash transport water concentrations can be used as a 

surrogate under the assumption that the mass of pollutants produced in the bottom ash transport 

water is proportionate to the mass of bottom ash produced. In that case, the concentration of 

bottom ash in the sluice flow is proportionate to the concentration of pollutants.

For each plant and impoundment, AKRF calculated two variables: (1) tons of bottom ash sluiced 

to the impoundment per year, and (2) gallons of sluicing flow to the impoundment per year. The 

associated bottom ash concentration (in lbs/gal) then was calculated as the ratio of the annual 

pounds of bottom ash produced (and sluiced to the impoundment) to the annual gallons of 

sluicing flow. Those data are listed in Appendix 1 of the AKRF report.

The concentration of bottom ash in transport water was negatively correlated with transport 

water flow. The correlation coefficient is p=-0.128. The coefficients of variation for 

concentration and flow are fairly large. The coefficient of variation for concentration is 2.67, 

and the coefficient of variation for flow is 1.98. Inserting these estimates into equation (1) gives 

the following:

This result indicates that EPA’s estimates of bottom ash impoundment pollutant loadings are 

likely to be 3.16 times too high.
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In short, EPA’s estimates of industry-level ash impoundment pollutant loadings are likely to be 

severely biased high due to the methodology EPA chose for calculating loadings. As described 

above, EPA’s approach will generate estimates that are biased high if pollutant concentrations 

are negatively 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.

The ICR data clearly show that the variance of bottom ash transport water flows is large. Under 

the assumption that the weight of pollutants produced is proportionate to the weight of bottom 

ash produced, the data also show a negative correlation between pollutant concentrations and 

transport flows and a very large coefficient of variation for pollutant concentrations. These 

conditions combine to make EPA’s estimates of bottom ash impoundment pollutant loadings 

likely 3.16 times too high.

This assessment of bias assumes that EPA’s estimates of average pollutant concentrations are 

themselves unbiased. The AKRF report addresses only the biases due to the statistical method 

EPA used to estimate bottom ash impoundment pollutant loadings. Errors in EPA’s estimates of 

average pollutant concentrations compound the biases discussed here. Such flaws in EPA’s 

pollutant loading estimates are explored below and in the referenced Gradient Report.

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.

14 Lindgren, B. W. 1976. Statistical Theory. MacMillan Publishing Co., Inc. NY. 614 pp.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655-A1, Excerpt Number 4 for more 

information on methodology for multiplying plant-specific ash transport discharge flows by 

average pollutant concentrations.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 195

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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UWAG also calculated baseline loadings and TWPEs for the four wastestreams, and its numbers 

are quite different from EPA’s. The following table compares UWAG and EPA baseline pounds 

and TWPEs by wastewater type:

Wastewater Type

UWAG 

Baseline pounds

(lbs)

EPA Baseline 

pounds

(lbs)

UWAG 

Baseline 

TWPEs

EPA Baseline

TWPEs

FGD wastewater 2,020,656,667 3,235,266,375 1,187,396 3,026,294

Fly ash sluice 539,073,287 477,606,921 379,776 2,521,988

Bottom ash sluice 223,943,290 1,701,527,532 342,523 2,716,057

Leachate 120,199,859 89,806,446 60,922 56,506

Industry Total 2,903,873,103 5,504,207,274 1,970,617 8,320,845

As shown in the table, UWAG estimates a total of 1.97 million TWPEs, while EPA estimates 

8.32 million TWPEs.83 EPA’s estimate of TWPEs is four times higher than UWAG’s. EPA’s 

estimate of loadings is about 2.6 billion pounds higher than UWAG’s.

EPA’s plant-specific loadings are not available in the record for the rulemaking as EPA claims 

the information must be shielded to protect confidential business information. However, based 

on UWAG’s critique of EPA’s characterization data for bottom ash, fly ash, and FGD 

wastewater, EPA has grossly overstated the plant-specific loadings and TWPEs and the 

industrywide loadings and TWPEs. Since EPA’s loadings and TWPE calculations are a major 

source of underlying data for much of its analysis in the Environmental Assessment, it is critical 

that they be accurate. The loadings would affect major portions of EPA’s analysis, including:

 EPA’s comparison of steam electric TWPEs to those of other industries (Environmental 

Assessment at 3-14);

 EPA’s comparison of steam electric loadings to those of publicly-owned treatment works 

(Environmental Assessment at 3-15 to 3-19);

 EPA’s assessment of steam electric loadings to the Chesapeake Bay watershed 

(Environmental Assessment at 3-19 to 3-21); and

 EPA’s assessment of steam electric loadings to the Great Lakes watershed 

(Environmental Assessment at 3-22 to 3-24).

Because of EPA’s multiple errors in characterizing the wastestreams, EPA’s comparisons and 

assessments are not valid.

But of even more importance is the effect of the loadings on EPA’s water quality modeling and 

the related wildlife and human health modeling. As EPA notes:

 The water quality model uses plant-specific input data (i.e., plant-specific pollutant 

loadings and cooling water flow rate), surface-water-specific characteristic data (e.g., receiving 

water flow rate, lake volume), and default assumption values to quantify the environmental 

impacts of the evaluated waste streams to surface waters. It calculates pollutant concentrations in

the surface water and sediment. These concentrations are inputs for the wildlife model, which 

calculates the bioaccumulation of pollutants in fish tissue and determines impacts to 
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wildlife. The fish tissue concentration calculated in the wildlife model is an input to the human 

health model.

Environmental Assessment at 4-5 to 4-6 (footnotes omitted). Since EPA used plant-specific 

pollutant loadings, and since EPA’s loadings and TWPEs are gross overestimates, then all 

portions of the Environmental Assessment that depend on the water quality model, the wildlife 

model, or the human health model are inaccurate and likely grossly overstate both the baseline 

impacts of the industry as a whole and the individual modeled plants, and also the likely 

environmental and human health benefits stemming from the modeled regulatory options that 

EPA used as a basis for its evaluations.

The inaccurate loadings information would also impact EPA’s assessment of current surface 

water quality issues. For example, EPA claims 49% of the immediate receiving waters exceeded 

a water quality standard under baseline loadings. 78 Fed. Reg. at 34,506 col. 3. But EPA’s 

loadings are almost four times the industry estimated loadings, which suggests that EPA’s 

assessment of water quality exceedances is also overstated. The same would be true for all EPA 

assessments based on the models, including all predicted wildlife impacts and potential benefits, 

and all human health predicted impacts and benefits. EPA’s fundamentally flawed pollutant 

loading and TWPE estimates are further explored in detail in the following section and the 

referenced Gradient Report.

Until such time as EPA corrects its loadings and TWPEs through use of proper characterization 

data for each of the four wastestreams and through use of appropriate flow rates for all plants, 

none of EPA’s water quality modeling and resulting human health and wildlife modeling should 

be relied upon.

83 UWAG’s calculations, for comparison purposes, use the same pollutants that EPA used in 

Table 1 of the ERG memorandum “Steam Electric Pollutant-Level Loadings and Removals for 

Each Wastestream and Regulatory Option,” EPA-HQ-OW-2009-0819-2250, except for 

chromium (VI) in FGD wastewater, and cyanide, fluoride, and sulfide for ash transport waters.

Comment Response: 

EPA disagrees with the commenter that baseline pollutant loadings are overestimated by 2.6 

billion pounds. See Section 10 of the TDD for details on EPA’s estimate of baseline and postcompliance pollutant loadings by wastestream for the final rule. EPA made revisions to the costs 

and loads calculations in response to comments for fly ash transport water, bottom ash transport 

water, and FGD wastewater. Sections 11 and 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 (Costs & Loads Report) (DCN SE05831/SE05832), 

the TDD, and response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in 

Comment Code 15.d. The report also includes plant-specific pollutant loadings for baseline and 

each technology option, although EPA acknowledges that some of these data are redacted from 

the non-CBI version of this report.
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EPA also disagrees with the commenter's assertion that it “grossly overstated the plant-specific 

loadings" and that therefore the EA results "are inaccurate and likely grossly overstate both the 

baseline impacts of the industry as a whole and the individual modeled plants.” EPA disagrees 

that this then led to grossly overestimating environmental and human health benefits stemming 

from the modeled regulatory options that EPA used as a basis for its evaluations. Given the 

revisions EPA made in response to comments to the costs and loads calculations for the final 

rule, as described above, revisions were also made to the loads used in the EA analyses, which 

resulted in revisions to the EA outputs that were used in the benefits analyses.

EPA notes that is updated its estimates of cost-effectiveness for the regulatory options for the 

final rule. See the RIA. Also see responses to 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: 127

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Options

Southern decided to estimate its likely compliance costs for the rule and compare those costs to 

EPA’s. EPA outlined eight options in the Proposed Rule, and each option would have different 

operational and monetary consequences for Southern Company. Table 20 summarizes each of 

the eight regulatory options.
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For purposes of examining the compliance costs of the rule for its facilities, Southern focused on 

EPA’s four preferred options, 3a, 3b, 3, and 4a. EPA describes its methodology and assumptions 

for estimating compliance costs in the 2013 TDD and the IC&PR.

In the 2013 TDD, EPA presents the following estimates of the numbers of plants expected to 

incur compliance costs by wastestream and preferred regulatory option:

Regulatory 

Option57

FGD 

Wastewater 

Fly Ash 

Transport 

Water 

Bottom Ash 

Transport 

Water 

Combustion 

Residual 

Leachate 

Nonchemical 

Metal Cleaning 

Wastes 

3a 0 66 0 0 0

3b 17 66 0 0 0

3 116 66 0 0 0

4a 116 66 115 0 0

2013 TDD, p. 9-10, Table 9-2.

EPA did not provide plant-specific cost estimates for the technologies it evaluated for the five 

major wastestreams (FGD wastewater, fly ash transport water, bottom ash transport water, 

combustion residual leachate, and nonchemical metal cleaning waste). However, on June 23, 

2013 Southern requested its plant-specific cost information (along with other company-specific 

data) from EPA. EPA responded to Southern’s request on July 31, 2013. Therefore, this section 
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of Southern’s comments compares EPA’s estimated compliance costs for Southern facilities with 

Southern’s own estimates for the same technologies.

Basis of Southern’s Cost Estimates

Southern Company has developed plant-specific capital costs for each regulatory option in the 

proposed rule. Southern’s capital costs are screening level estimates with -30% to +70% level of 

accuracy, including miscellaneous unidentified costs. It is standard practice, based on the Project 

Management Institute, to include contingency costs based on the defined scope of work (or cost 

classification) to cover costs that the facility knows it will need but for which it lacks enough 

detailed planning or engineering to identify, quantify, or price. Southern has many years of 

experience in developing costs for pollution control equipment and has used this experience to 

develop costs for complying with the proposed rule. The costs are provided both in 2010 dollars, 

to better compare to the EPA’s 2010 cost estimates. In-service costs are costs that will occur 

during the proposed implementation period. The in-service dollars are approximately 22% higher 

than the 2010 dollars.

Southern’s capital costs are based on the total capital costs, which by definition include the total 

project expenditures required to install the system at each plant, from conceptual design to 

startup of the control equipment. The major cost elements can be broken down into the following 

categories: (1) installed equipment, (2) balance of plant (BOP), (3) engineering costs, (4) profits 

and overheads (contractor and subcontractor), and (5) contingency or miscellaneous unidentified 

costs. BOP costs include site work (e.g., demolition, relocation of buildings or other equipment, 

concrete, piping, miscellaneous metals and finishes, mechanical, HVAC, electrical, and 

instrumentation and control. Engineering costs include conceptual design, services during 

construction, startup of technologies, and operator training.

In an effort to compare to EPA’s costs, Southern Company costs represent total plant costs and 

as such do not represent any particular ownership share for those plants or units who may have 

multiple owners.

57 This table shows two essential flaws in EPA’s cost analysis. First, EPA assumes that none of 

the preferred options would result in compliance costs for nonchemical metal cleaning wastes for 

any plants. Second, EPA assumes no plant will incur compliance costs related to combustion 

residual leachate. Both of these assumptions are likely wrong, as we discuss below.

Comment Response: 

EPA reviewed the specific capital cost comparisons provided by the commenter for FGD 

wastewater, bottom ash transport water, and fly ash transport water. See the response to DCN 

EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 133 in Comment Code 6.f for EPA’s 

response on the commenter’s cost comparison and a discussion of why EPA was not able to 

complete a plant-specific/company-specific comparison of the final compliance capital cost 

estimates to the capital costs provided by the commenter.
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In addition, see EPA’s responses to the following specific cost comments made by the 

commenter:

 DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 128 (in Comment Code 10.b) 

for EPA’s response to Southern’s cost estimates for the treatment of FGD wastewater 

with chemical precipitation followed by biological treatment;

 DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 129 (in Comment Code 16.b) 

for EPA’s response to Southern’s cost estimates on bottom ash retrofits;

 DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 130 (in Comment Code 14.b) 

for EPA’s response to Southern’s cost estimates on fly ash transport water retrofits; and

 DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 131 (in Comment Code 16.b) 

for EPA’s response to Southern’s cost estimates on landfills.

After reviewing all public comments on the proposed rule, EPA updated its compliance cost 

estimates (including purchased equipment, O&M costs, other direct costs, and indirect costs). 

EPA includes all major cost elements named by the commenter in the final cost report, see 

Section 9 of the TDD and see a detailed description in the Incremental Costs and Pollutant 

Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category (Costs & Loads Report) (DCN SE05831/SE05832). 

These updates increased EPA’s plant-specific cost estimates compared to proposal. Please see 

the following comment responses for more details on changes to EPA’s cost estimates:

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

Code 14.b for more specific discussion regarding EPA’s revisions to the fly ash transport water 

cost estimates including updates to cost equations, BOP costs, engineering overhead, profits and 

overhead, contingency, and land.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 in Comment Code 

16.b for more specific discussion regarding EPA’s revisions to the bottom ash transport water 

cost estimates, including BOP costs, engineering overhead, profits and overhead, contingency, 

and land.

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Numbers 24 and 30 in 

Comment Codes 9.b and 10.b respectively for more specific discussion regarding EPA’s 

revisions to the FGD wastewater cost estimates.

Finally, EPA disagrees with the commenter that existing plants will incur costs to treat nonchemical metal cleaning wastes and combustion residual leachate. As described in EPA’s 

response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 154 (in Comment Code 22), 

EPA determined that it does not have sufficient information to set new requirements; therefore, 

continues to reserve BAT/PSES/NSPS/PSNS for non-chemical metal cleaning wastes, as the 

previously promulgated regulations did. Additionally, BAT for combustion residual leachate is 

equal to the previously promulgated BPT limitations on TSS for low volume waste sources. 

Therefore, EPA maintains that no plants will incur compliance costs associated with these 

wastestreams. 
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EPA notes that the commenter did not provide a breakdown of their costs and that there have 

been changes in the industry as described in Section V of the final preamble. Therefore, EPA 

can not directly compare the costs presented by this commenter to the costs of the final rule.

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: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

III. EPA Needs to Correct Overestimation of Pollution Removals

A. Ash Pollutant Removals are Overestimated

Based on the information contained in the industry comments to be submitted on this proposal 

made available to Advocacy, EPA has apparently made several major errors in estimating the 

amount of pollution removals to be achieved by this regulation, particularly with respect to the 

fly ash and bottom ash wastewater. According to EPA, the fly ash and bottom ash wastewater 

removals account for two-thirds (5.2 million) of the total 7.8 million toxic pound-equivalents 

achieved by regulating the three major waste streams (fly ash, bottom ash, and flue gas 

desulfurization). The TWPE metric is used to measure the benefits of pollutant removals to the 

public. By industry’s estimate, the 5.2 million TWPEs is more likely to be in the neighborhood 

of 400,000 TWPEs. This EPA overestimate of pollution removals means that the agency has 

vastly inflated the benefits of this regulation with respect to ash pollutant removals, which 

currently represent about two-thirds of all the benefits of this rule. Part of the determination of 

what constitutes “best available technology economically achievable” includes consideration of 

the costs and pollutant removals (benefits to the public). Proper estimation of the ash wastewater 

flows is critical in estimating the cost effectiveness of this rule and evaluating the merits of the 

regulatory options for ash wastewater controls. In the past, EPA has promulgated only those 

rules whose cost effectiveness (cost/toxic pound-equivalent of pollution removed) was in the 

$100 ($1981)/pound-equivalent (PE) and under range for direct dischargers of wastewater 

(facilities that discharge water directly into water bodies).20 This calculation was used in past 

ELGs to help evaluate the final regulation, so it needs to be carefully determined.

After correcting for errors in both the wastewater flows and the chemical concentrations, 

industry finds that instead of 5.2 million pound-equivalents (PE), the more accurate figure would 

be approximately one-fifteenth of that amount, or about 400,000 pound-equivalents.21 This 

discrepancy is attributable to various errors, primarily: (1) using non-detect data to project high 

concentrations of pollutants for pollutants that are not really present or are present at much lower 

concentrations, (2) using outdated data from the 1970s reflecting much higher pollutant loadings 

than current plants, and (3) the failure to subtract contributions from common low toxicity 
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chemicals (such as calcium and magnesium) found in the source water that are not attributable to 

the steam electric plants being regulated. Correction of these and other errors dramatically 

changes the estimated cost effectiveness of the rule with respect to ash wastewaters. This is 

particularly important since the cost of the control of ash wastewaters is 65% of the total cost of 

this rule regulating the three major waste streams.22

20 See discussion below about the basis for the $100/PE benchmark.

21 See industry comments.

22 The costs of Option 4 (control of fly ash, bottom ash and FGD) is $1.37 billion annually. The 

cost of the ash water controls portion of this Option is $887 million annually.

Comment Response: 

Following proposal, EPA revised it approach for identifying POCs for some wastestreams and 

expanded its ash and FGD characterization datasets based on public comments. See Section 6 

and 10 of the TDD.

Regarding 1982 data, EPA’s use of non-detects, and source water in EPA’s loadings 

calculations, see response DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in 

comment code 15.d. EPA revised its estimates of compliance costs and pollutant removals and 

determined that the final rule is cost effective. See responses to comment code 6.h.

EPA disagrees that part of its determination of what constitutes BAT or BADCT is based on 

benefits. See DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3, in comment code 

6.e.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 133

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Comparison of EPA’s Total Industry Costs to Southern’s Total Costs

Given EPA’s multiple erroneous assumptions about the Southern Company fleet of plants and 

their likely costs to retrofit technologies needed to comply with the final ELG Rule, it is no 

surprise that EPA’s total costs of compliance for Southern differ greatly from Southern’s own 

estimates. Southern’s total costs for compliance for each regulatory option are provided in the 
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table below. The costs are provided in 2010 dollars for comparison purposes and in-service 

dollars which are costs during the actual implementation time period. Even comparing EPA’s 

costs with the low end of Southern’s range illustrates the huge differences between the estimates, 

option by option.

Table 27: Comparison of Southern’s Costs to EPA’s Costs per Preferred Option, 2010$

Preferred 

Regulatory 

Option

Total EPA 

2010 Costs 

(M$)

2010 Dollars In-Service Dollars 

Total 

Southern 

Costs 

(M$)

Southern -

30% (M$)

Southern 

+70% 

(M$)

Total 

Southern 

Costs 

(M$)

Southern -

30% (M$)

Southern 

+70% 

(M$)

3a $89 $1,651 $1,156 $2,806 $2,035 $1,424 $3,459

3b $166 $1,858 $1,301 $3,159 $2,299 $1,609 $3,908

3 $342 $2,165 $1,515 $3,680 $2,689 $1,882 $4,572

4a $732 $2,816 $1,972 $4,788 $3,520 $2,464 $5,984

As discussed earlier, EPA did not include costs for NCMCW separation and treatment. 

Southern’s estimates include those costs because it is unclear, based on the regulation as 

proposed, if Southern will be able to comply without these expenditures.

For Option 3a, the lowest-cost option, EPA estimates Southern will need to expend $89 million 

(2010$), while Southern estimates a cost between $1.2 and 2.8 billion (2010$). Clearly, the 

Agency and Southern are far apart in their cost estimates. Southern believes its estimates are 

more accurate because, as noted above, EPA failed to account for several major categories of 

capital costs in almost every category of technology. Also, Southern’s estimates are more 

accurate because they are based on greater knowledge of the individual units being retrofitted 

and experience with construction in the local markets.

Figure 7 compares EPA’s total industry costs (2010$) to Southern’s total costs (2010$) for each 

regulatory option. Southern’s in-service costs were de-escalated to 2010 dollars in order to 

compare directly to EPA’s 2010 costs. (Actual in-service dollars are about 22% higher than the 

2010 dollars for proposed BAT technologies.) Southern’s total costs for Options 1, 2, 3a, 3b and 

3 are greater than EPA’s total cost to the industry for these options. In addition, Southern’s upper 

range for Option 4a very close to EPA’s total industry cost for Option 4a. Again, this illustrates 

that EPA’s estimated compliance costs for the industry are grossly underestimated.

EPA needs to reassess its costs for each technology by including all of the major costs elements 

that have been overlooked. At a minimum, EPA costs should include reasonable 

engineering and balance of plant costs, profits and overheads, and contingency costs because 

EPA’s costs are considered screening level cost estimates with little to no plant-specific 

engineering project definition.
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1 Southern’s estimates have been de-escalated to 2010 dollars to compare costs to EPA’s 2010 

estimates. Actual in-services dollars are about 22% higher than the 2010 dollars shown in this 

graph.

Comment Response: 

In general, EPA was not able to complete a plant-specific/company-specific comparison of the 

final compliance cost estimates to the costs provided by the commenter because Southern’s bases 

for their costs are unclear. Although Southern provides plant-specific plant wide capital cost 

estimates for four plants operated by Georgia Power, they do not provide any description of the 

components of their estimates, for example, specific equipment and cost elements that they 

include in their estimates and how they differ from EPA’s detailed estimates. For example, they 

do not state whether they are including costs for denitrification systems, heat exchangers, and/or 

buildings, and if so, for which plants these costs are included. Additionally, they do not state the 

design of the chemical precipitation and biological treatment system, including assumed 

residence time and redundancy of equipment, and whether the design is consistent with EPA’s 

estimates. It is not stated in the commenter’s letter what type of dry bottom ash handling or dry 

fly ash handling conversions were used in the commenter’s estimates. They state in Excerpt 
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Number 127 that they “estimated their costs based on the same technologies used by EPA.” They 

also state that “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.” However, EPA has no information from the commenter 

on these engineering estimates and the various scenarios used to estimate their costs. In addition, 

they do not indicate whether Southern used the same wastewater flow and ash tonnage basis as 

EPA, or whether and how they altered EPA’s design basis for that technology.

As the commenter states, EPA provided the commenter with plant-specific costs by technology 

and a description of the specific equipment and costs for each technology was provided in the 

Costs and Loads Report. Although some elements of these costs were redacted due to CBI, EPA 

did provide costs for many detailed elements of the estimates, including specific costs for 

equipment, installation, site prep, and operating labor. As part of these plant-specific costs, EPA 

provided information on plant-specific cost assumptions (e.g., what treatment system 

components were considered treatment in place, whether the plant was identified as one 

requiring a heat exchanger). All of the individual cost elements were described in the sanitized 

Costs and Loads at proposal. In contrast, Southern provided no such details of its cost estimates 

made for each plant to allow EPA to consider whether plant-specific changes to the costs are 

warranted, and it did not specify what costs it thinks should be changed and why; they only 

provided plant-level estimates with no supporting basis.

Additionally, the commenter points out that it included costs associated with non-chemical metal 

cleaning wastes and EPA’s final compliance costs do not. Since the rule does not include any 

new requirements for this wastestream, it is incorrect that the commenter included these costs. 

As described in EPA’s response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 154 

(in Comment Code 22), EPA determined that it does not have sufficient information to set new 

requirements; therefore, continues to reserve BAT/PSES/NSPS/PSNS for non-chemical metal 

cleaning wastes, as the previously promulgated regulations did.

It is also unclear if the commenter’s cost estimates include costs associated with combustion 

residual leachate. Because BAT for combustion residual leachate is equal to the previously 

promulgated BAT limitations on TSS for low volume waste sources, EPA maintains that no 

existing plants will incur compliance costs associated with these wastestreams.

It is unclear if the commenter included costs associated with constructing new landfills at 

plants. The commenter includes a section in its comments (F. Costs of Additional Landfills for 

Dry Ash Disposal) that discuss the costs for expanding or constructing new landfills; however, it 

is not clear if it included these costs in their plant-level cost estimates. EPA’s cost estimates 

include costs for expansion of existing landfills or offsite disposal, not for constructing new 

onsite landfills.

Finally, the commenter (in this and other comments) states that “EPA failed to account for 

several major categories of capital costs in almost every category of technology.” EPA reevaluated its entire cost estimates based on this and other comments. See the following comment 

responses for details on these evaluations:
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 See responses to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Numbers 127 

through 132 in Comment Codes 6.f, 10.b, 16.b, 14.b, 16.b, and 22 respectively for EPA’s 

response to the commenter’s assertions about FGD biological treatment costs, fly ash dry 

handling conversion costs, bottom ash dry handling conversion costs, combustion 

residual leachate costs, and nonchemical metal cleaning waste treatment costs.

 In addition, see the response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt 

Number 45 in Comment Code 14.b for more specific discussion regarding EPA’s 

revisions to the fly ash transport water cost estimates including updates to cost equations, 

BOP costs, engineering overhead, profits and overhead, contingency, and land.

 See response to DCN EPA-HQ-OW-2009-0819- 4655, Excerpt Number 53 in Comment 

Code 16.b for more specific discussion regarding EPA’s revisions to the bottom ash 

transport water cost estimates, including BOP costs, engineering overhead, profits and 

overhead, contingency, and land.

 See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Numbers 24 and 30 in 

Comment Codes 9.b and 10.b respectively for more specific discussion regarding EPA’s 

revisions to the FGD wastewater cost estimates.

Commenter Name: Roger E. Claff

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OW-2009-0819-4641-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Has Improperly Established Steam Electric Effluent Guidelines and Has Not Properly 

Determined Technology Costs

Under Section 304(b)(2)(B) of the Clean Water Act, USEPA is charged to include specific 

factors when determining the control measures and practices to be applicable to point sources 

within the category. The datasets and cost analysis of the additional control technology for 

existing power plants is likely inadequate to justify additional treatment for the sources removed 

from the existing definition of low volume waste sources. EPA is charged to properly assess 

existing sources and technology to establish credible technology-based standards for each 

category. The Utility Water Act Group (UWAG) in its comments raises numerous substantive 

concerns with the Proposed Rule. The UWAG comments highlight significant deficiencies, 

including the protocols for identifying pollutants of concern; reliance on old or very limited data; 

and assumptions that pollutants were present in concentrations equal to the very high detection or 

quantification limits associated with very old data. These and other deficiencies (including 

censoring data to remove high cost measurements) resulted in significantly underestimated costs 

for the limits included in the Proposal.
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For instance, EPA notes that in the absence of readily available data on flue gas mercury control 

wastewater, it assumes the pollutants of concern are the same as in fly ash transport water. The 

assumption that vapor control liquids are similar as transport water is without technical basis

and clearly indicates the Agency did not put forth the diligence necessary to meet the intentions 

of the Act.

Section 304 (b) (2) (B) indicates the cost of achieving the effluent reduction is to be factored into 

determining the best measure and practices available to base a categorical standard.

UWAG comments note in the instance of FGD wastewater that EPA calculated maximum design 

flow rates for plants that have no FGD treatment system. This faulty assumption leads EPA to 

underestimate the actual design flow rate and as a result underestimate the capital costs for the 

treatment options.

In the cost estimates for water recycling, in most instances EPA has assumed the only cost for 

recycling will be piping. This is an unsupported estimate of the true costs to reuse in-plant waste 

liquids. Providing water treatment systems to assure corrosion protection and prevent creation of 

biological hazards, and producing a recycled water stream suitable for reuse, are more costly 

than the capital of piping and significantly more costly to operate and maintain. EPA must revisit 

their cost estimates to more adequately represent the true cost of in plant recycling.

Comment Response: 

EPA disagrees with the commenter that the datasets and cost analysis is “likely inadequate” to 

justify the rule. As stated in preamble section VIII, EPA considered the technologies described in 

the preamble and Section 7 of the TDD, and selected BAT in light of the factors specified in 

CWA sections 304(b)(2)(B) and 301(b)(2)(A) (also see preamble Section IV.B.3).

Other specific comments raised in UWAG’s letter, and referenced by the commenter, are 

addressed elsewhere in this comment response document.

Regarding the “very old data” referred to by the commenter see response to DCN EPA-HQ-OW2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d.

Regarding identification determining pollutants of concern see responses to comment code 6a.

Regarding flue gas mercury control wastewater, EPA is setting zero discharge for FGMC 

wastewater in the final rule. Based on EPA’s evaluation of the responses to the Steam Electric 

Survey, EPA has determined that the dry handling or closed-loop systems are the industry 

standard for the treatment of FGMC wastewater; therefore, EPA there are no compliance costs 

for any plants to meet the zero discharge requirements. EPA disagrees that it “did not put forth 

the diligence necessary to meet the intentions of the Act.” See response to DCN EPA-HQ-OW2009-0819-4305-A3, Excerpt Number 88 in Comment Code 21.a.

EPA disagrees with the commenter’s assertion that capital costs for FGD treatment equipment 

were underestimated. As indicated in Section 4.1.1 of the Incremental Costs and Pollutant 

Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric 
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Power Generating Point Source Category (Costs & Loads Report) (DCN SE05831/SE05832),

EPA used the scrubber purge flow as reported in the Steam Electric Survey for existing FGD 

systems. EPA used the 24-hour average daily design flow rate as reported in response to the 

Steam Electric Survey for plants planning to install an FGD system. These flows were not 

dependent on whether a plant had an existing FGD wastewater treatment system in place. In 

both cases (existing and planned FGD systems), EPA used flow in conjunction with a capacity 

factor to estimate purchased equipment costs as described in Section 6 of the report.

EPA disagrees with the commenter’s assertion EPA has underestimated costs associated with 

FGD wastewater recycle. EPA included costs for a pump and piping to handle recycle within the 

FGD system. As described in Section 4.5.4 of the Incremental Costs and Pollutant Removals for 

the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category (Costs & Loads Report) (DCN SE05831/SE05832), EPA 

determined the amount of water recycled on a plant-by-plant basis such that 80% of the plantspecific maximum chloride limit reported in the Steam Electric Survey is not exceeded. EPA 

does not expect plants will experience significant increases in corrosion or other hazards related 

to equipment because this is within normal operating parameters as indicated in the Steam 

Electric Survey.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 43

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Further, the UWAG comments point out that the EPA measurements were often of 

measurements made below the detection level. UWAG points out that EPA also made regulatory 

determinations based upon raising “nondetect” results to the detection limit. This is not proper. 

For combined ash ponds, EPA’s estimate of sulfides was based on 17 sampling events, only 

three of which were above the detection limit. Over half of EPA’s estimates of TWPE for ash 

impoundment effluent, then, have no basis in fact. In addition to the inappropriate use of 

undetectable sulfides, EPA’s statistical method was biased so as to overestimate the loading of 

pollutants from ash ponds.

EPA’s method for estimating the average loading in pounds per year per impoundment was to 

multiply the average concentration (the average over all impoundments) times the average 

transport water flow rate (the average over all impoundments). EPA then multiplied its estimate 

of the average loading per impoundment times the number of impoundments to estimate 

industry-level loadings. To do the calculation correctly, EPA should have calculated the product 

of the concentration times the transport water flow rate for each impoundment and then averaged 

the results over all impoundments.
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Adjusting EPA’s estimates to account for this bias reduces the estimated total loadings (summed 

over the three impoundment types) by 63%, from 2,182,900,000 to 801,786,870. Adjusting each 

estimate of TWPE to account for the bias reduces the total TWPE by 59%, from 5,233,000 to 

2,169,828.

Combined, the two errors (assuming numbers for undetectable sulfides and calculating pollutant 

loadings as the product of averages) probably caused EPA’s baseline TWPE estimates to be too 

high by a factor of six. Computing the total TWPE without the invalid sulfide data reduces the 

baseline TWPE from 5,240,000 to 2,121,609. Adjusting the estimate to account for the likely 

bias in loading estimates further reduces the baseline TWPE to 859,686. Thus, the 

combined effect of EPA’s calculation errors was to produce an estimate of total TWPE that 

is six times too high. This overestimate of pollutant loadings in turn made EPA’s calculations of 

dollars per TWPE too low.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 4 for more information 

on methodology for multiplying plant-specific ash transport discharge flows by average pollutant 

concentrations and information on sulfide.

EPA revised its estimates of pollutant loadings (pounds and TWPEs) for the final rule so EPA 

does not agree with the values cited by the commenter. For EPA’s final estimates, see TDD 

Section 10. Regarding how EPA used nondetect data see response to DCN EPA-HQ-OW-2009-

0819-4499-A1, Excerpt Number 72 in comment code 15.d.

Also see responses to comment code 6.h.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655-A2

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

 US EPA (2013b, Section 10) presents a detailed methodology to calculate industry-wide 

pollutant loadings. The equations used to calculate the total pollutant loadings from steam 

electric power generating facilities via wastewater discharges are simple and technically 

sound. However, insufficient documentation of key input prohibits interested parties from 

reproducing the analysis to ensure calculations are error free. Specifically, the TDD does 

not present pollutant concentration and the effluent wastewater data obtained as a result 

of US EPA's sampling efforts. While, the TDD does refer to supporting documentation 

containing the sampling data, multiple values for the same pollutant are reported, and it is 
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therefore difficult, if not impossible, to determine which values were used. For example, 

at the Duke Energy Carolinas' facilities (i.e., Belews Creek and Allen), both dissolved 

and total metal concentrations were reported for influent and effluent discharges. 

Similarly, at the Progress Energy Carolinas Roxboro facility, multiple values for metal 

concentrations were reported and it was not mentioned if the results are for total metals or 

dissolved metals. US EPA should be more explicit about how the data were used to 

develop the summary values presented in the TDD.

 In some cases we were not able to replicate the calculations US EPA used to determine 

baseline pollutant loadings and the amount of pollutants removed upon using a specific 

treatment technology. For example, multiplying data presented in Table 10-3 of the TDD 

by the average flue gas desulfurization (FGD) wastewater discharge noted in Table 10-9 

of the TDD produces a resultant total pollutant loading of 2,924,198,666 lbs/year. 

However, the total loading value reported in Table 10-9 is 3,240,000,000 lbs/year. The 

difference between these values is too large to be rounding error. The TDD and 

supporting documents (cited in the TDD) do not provide details of the pollutant loading 

calculations for each individual wastewater stream. US EPA should review the pollutant 

loading calculations to check the accuracy of the reported pollutant loadings or provide 

more information on how the values were obtained, if they are in fact correct.

Comment Response: 

As at proposal, for the final rule EPA has included available sampling data in the record, and 

data that met the data acceptance criteria that EPA had in time for decision-making were 

included in the analytical database for the final rule (DCN SE05359. EPA’s methodology for 

handling multiple values for the same pollutant at the same plant is described in the Incremental 

Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (Costs & Loads Report) (DCN 

SE05831/SE05832). In general, for each plant, EPA first averaged sample and sample duplicate 

results, then averaged multiple samples from the same day, and then calculated a plant average 

pollutant concentration. This information was also described in the supporting technical 

documentation for the proposed rule. EPA’s baseline pollutant loadings and pollutant removal 

estimates use total metals, not dissolved metals. EPA does not agree that fact was unclear at 

proposal. Information about dissolved metals concentrations provides valuable insight to the 

operation of a treatment system; however, using dissolved metals to quantify the pollutant 

removals would underestimate the actual removals because it would not take into account the 

contributions from pollutants in particulate form. Regarding the form of metals reported in 

tables, the value represents total metals (also referred to as total recoverable metals) unless the 

entry specifically notes the value represents dissolved metals.

However, the approach used by the commenter would not replicate EPA’s baseline pollutant 

loadings because the approach described is not the approach used by EPA. The commenter used 

pollutant concentrations from TDD Table 10-3, which provides information on average effluent 

concentrations for FGD wastewater from surface impoundments. EPA’s methodology, however, 

is more precisely tailored to the site-specific conditions at each plant and uses three datasets of 

pollutant concentrations, shown in Tables 10-3 through 10-5, to represent effluent from surface 

impoundments, chemical precipitation systems, and biological treatment systems. Thus, the 
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difference between EPA’s and the commenter’s pollutant removal calculations is due to the 

commenter using a different (and less precise) methodology, not due to rounding error.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

1. The costs presented by EPA do not appear to include all the costs of doing business.

The costs presented by EPA do not appear to include all the costs of doing business. 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 an Allowance for Funds Used During Construction 

(AFUDC). AFUDC is an accounting mechanism that recognizes the cost of debt and equity used 

to finance the construction of new utility assets. AFUDC is allowed for virtually all regulated 

utilities under FERC rules and allows a utility to capitalize the interest cost of construction.

Fully-loaded costs represent the total amount that will be borne by utility customers as a result of 

this regulation. EPA does not account for company indirect and overhead costs in its estimates, 

but it is standard practice to include these additional real costs as they are a necessary cost of 

doing business for any activity.

According to the AEP Cost Allocation Manual:

“Indirect costs cannot be identified with a particular activity and must be charged to the 

appropriate activity or activities to which they relate using relevant cost allocators. Indirect costs 

include, but are not limited to, corporate or business unit overheads, general and administrative 

overheads, and certain taxes.”

EPA’s calculation of the full cost to affected facilities neglects to include these indirect costs and 

company overheads which are real costs that will be borne by a company’s customers, and 

ultimately cause further underestimation of the compliance costs associated with these 

guidelines.

The AEP direct cost estimates include contingencies to cover difficult construction situations 

with limited acreage for installing new 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 estimated 

fully-loaded costs for each wastewater that it evaluated.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 210.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

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. EPA’s estimates 

of sulfide concentrations for bottom ash ponds and fly ash ponds were based on only 5 sampling 

events, all of which found no sulfide above the reporting limit. For those 5 sampling events, EPA 

claimed the concentrations were at the reporting limits. For combined ash ponds, EPA’s 

estimate of sulfide concentration was based on 17 sampling events, of which only three were 

above the reporting limits. Accordingly, over half of EPA’s estimate of TWPE for ash 

impoundment effluent has no basis in fact.

EPA’s statistical formulation for estimating industry level loadings is fundamentally biased. In 

particular, when: 1) pollutant concentrations and ash transport water flows are negatively 

correlated, 2) the transport water flows are highly variable among impoundments, and 3) the 

concentration for a pollutant are highly variable among impoundment, the bias is positive and 

large. Data from responses to EPA’s Information Collection Request (“ICR”) Questionnaire for 

the Steam Electric Power Generating Effluent Guidelines (EPA 2010) demonstrate that all three 

of these conditions were satisfied in the ash transport data. Furthermore the data indicate that 

EPA’s estimates of industry level pollutant loadings from ash impoundments are too high by a 

factor of more than 2.

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: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 4. Also response to DCN 

EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment code 15.d.
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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: 52

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Capital Costs Are Underestimated and All Additional Costs Will Result in Higher 

Electricity Costs to the Consumer

APPA supports UWAG’s critique of EPA’s economic assessment methods. UWAG’s comments 

contain numerous examples of how EPA (and its contractors) failed to look at the capital 

expenditures expected by utilities in response to this rulemaking. For example, EPA’s 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), or demolition/relocation, or structural modifications. 

EPA notes that “[t]he estimated prices are approximate as each plant site will vary in 

layout.”21 In fact, when EPA requested the cost data, it 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 cover these expenses.22 APPA points out (in agreement with UWAG’s detailed 

critique) that EPA’s capital costs for conveyance and intermediate storage are underestimated 

because they do not consider all of the Balance of Plant (BOP) costs and costs associated with 

site-specific issues. EPA’s analysis does not look at conveyance and intermediary storage for 

smaller or scaled down plants.

21 EPA-HQ-OW-2009-0819-2007, p. 6.

22 EPA-HQ-OW-2009-0819-1959.20.

Comment Response: 

As described in Section 9 of the TDD, EPA has revised the costs estimates associated with 

indirect capital costs from proposal to ensure they include engineering, engineering overhead, 

contractor fees, construction expenses, and contingency costs. EPA acknowledges that some 

sites may require costs in addition to average industry costs but has accounted for them by 

including contingency costs. See the response to DCN EPA-HQ-OW-2009-0819-4448-A1, 

Excerpt Number 69. The requirements of the ELG would not result in plants needing to 

implement boiler modifications or upgrade existing piping to more erosive-resistant material, and 

plants should not need to make major structural modifications or demolish or relocate existing 

equipment (except, in specific instances such as replacing equipment under the boiler for MDS 

installation).
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s method for calculating Baseline Ash Impoundment Loadings (pounds per year) has four 

steps:

1. Estimate industry-level average pollutant concentration (pounds per million gallons)

2. Estimate impoundment-specific ash transport water flow rates (million gallons per day)

3. Estimate impoundment-specific loadings based on the industry-average pollutant 

concentration and impoundment-specific transport water flow rates

4. Estimate the industry-level loadings as the sum of impoundment-specific loading estimates.

EPA’s method is algebraically equivalent to estimating the industry-level loadings as the product 

of the number of impoundments times an estimate of the average loading per impoundment (see 

Appendix A). Furthermore, EPA’s formulation for estimating the average loading per 

impoundment is algebraically equivalent to multiplying the average pollutant concentration times 

the average transport water flow rate (see Appendix A).

For each ash impoundment type and pollutant, EPA calculated a toxicity weighted pound 

equivalent (“TWPE”) by multiplying the estimated annual loading times the pollutant-specific 

toxicity weighting factor (“TWF”). EPA calculated values for the TWFs for each pollutant from

chronic aquatic life values and the human health values from the literature (EPA, 2006).

EPA then summed the TWPEs over all pollutants of concern to calculate the overall TWPE for 

each ash impoundment type.

Comment Response: 

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 4.

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: 3
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For each waste stream, EPA excluded all pollutants that were measured below the quantitation 

limit in all samples representing the baseline effluent discharges for that specific waste stream. 

Therefore, if a pollutant was measured above the quantitation limit at least once (emphasis 

added) in the baseline effluent concentration dataset, that pollutant was included in the loadings 

analysis. As part of the analysis EPA utilized a process of assigning a value to results that were 

less than the quantitation limit (i.e., results between the method level of detection and level of 

quantitation, and nondetects below the method detection limit) as half the sample‐ specific 

quantitation limit for all analytes (Technical Development Document, EPA‐821‐R‐13‐002, page 

10‐5) in order to calculate pollutant loading from a waste stream.

Assigning a value to samples that have non‐detected values artificially inflates the TWPE (and 

reducing the corresponding cost effectiveness $ per TWPE) when a particular pollutant of 

concern may not be present at all. The practice of assigning a value to a data point that is non‐

detect when calculating a TWPE results in a significant bias in the potential amount of 

pollutants and should not be used.

Comment Response: 

As described in Section 6 of the TDD, for wastestreams where EPA is establishing numeric 

effluent limits, the pollutants of concern (POCs) are those pollutants that are present at treatable

concentrations in a significant percentage of untreated wastewater samples. EPA reviewed data 

for the untreated FGD wastewater, combustion residual leachate, and gasification wastewater to 

identify pollutants detected at greater than or equal to 10 times the quantitation limit in at least 

10 percent of all samples. For wastestreams where EPA is establishing zero discharge standards 

(i.e., fly ash transport water, bottom ash transport water, and FGMC wastewater), POCs are all 

pollutants that are confirmed to be present (i.e., detected) in at least 10 percent of all samples.

Also see response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 72 in comment 

code 15.d.

Also see responses to 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: 199

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

B. Pollutant Loading

1. Pollutant Loading

In addition to its more qualitative assessment of environmental damage based on the case 

studies, EPA uses a model to estimate the impacts of power plant effluents on current surface 

water quality, as well as changes under different types of controls. Pollutant loading estimates 

(both baseline loadings and reductions due to controls) are central to EPA’s risk estimates and 

ultimately to EPA’s benefits estimates.

Regarding the characterization of baseline conditions, Gradient’s review identified several 

shortcomings in the analysis that undermine the reliability of the results. Collectively, these 

limitations lead to uncertain (and likely overestimated) baseline loadings that cannot reliably 

serve as the benchmark from which to measure improvements from alternative control 

technologies. Specific shortcomings of EPA’s analysis of baseline pollutant loadings include:

 model inputs and assumptions are not always transparent, and so key results cannot be 

replicated;

 the estimation of baseline pollutant loadings using measured effluent concentrations are 

based on a limited data set that are not representative of industrywide discharges; and

 the effectiveness of some baseline control technologies is mischaracterized, leading to 

likely overestimates of discharges.

Comment Response: 

EPA notes that the details of the pollutant loading calculations, including model inputs, were 

included in the non-CBI Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Generating Point Source Category 

Report - DCN SE03581 (see DCN EPA-HQ-OW-2009-0819-2256).

For the final rule, based on data submitted in comments and in follow up to those comments, 

EPA expanded its ash characterization dataset used for baseline pollutant loadings. See Section 

6.6.4 of the TDD for a description of the characterization data used to identify POCs in bottom 

ash and Section 10.2.2 for a description of ash impoundment data. Regarding the 

representativeness of the baseline pollutant loadings, see response to DCN EPA-HQ-OW-2009-

0819-4487-A1, Excerpt Number 45 in Comment Code 4.b for a discussion of the sufficiency of 

EPA’s dataset for this rulemaking. Also see response to DCN EPA-HQ-OW-2009-0819-4499-

A1, Excerpt Number 72 in comment code 15.d.

EPA disagrees that “the effectiveness of some baseline control technologies is mischaracterized.” 

EPA notes that the commenter has not provided any data to demonstrate how the “effectiveness 

of some baseline control technologies” has been “mischaracterized.”
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Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

Document Control Number: EPA-HQ-OW-2009-0819-4655-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Pollutant Loading

In addition to the more qualitative assessment of environmental damage based on the case 

studies, US EPA uses a model to estimate the impacts of ELG effluent on current surface water 

quality, as well as changes under different types of controls. Pollutant loading estimates (both 

baseline and reductions from controls) are central to US EPA's risk estimates and ultimately to 

US EPA's benefits estimates. Our review identified several shortcomings in the baseline 

conditions analysis that undermine the reliability of the results. Collectively, these limitations 

lead to uncertain (and likely over estimated) baseline loadings that cannot reliably serve as the 

benchmark from which to measure improvements from alternative control technologies. Specific 

shortcomings of US EPA's analysis of baseline pollutant loadings include:

 Model inputs and assumptions are not always transparent, so key results cannot be 

replicated;

 The estimation of baseline pollutant loadings using measured effluent concentrations are 

based on a limited data set that may not be representative of industry-wide discharges; 

and

 The effectiveness of some baseline control technologies is mischaracterized, leading to 

likely overestimates of discharges.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 199.

Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Cost
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It appears that EPA has not fully examined the capital expenditures that will be required to 

comply with these regulations as proposed. For example, we see no cost documentation or 

mention of electrical, mechanical (except for tie-in of the pipeline that previously went to the ash 

pond), upgraded contro l systems, boiler modifications, upgraded piping (more erosive-resistant 

material), demolition/relocation or structural modifications that would be required. EPA notes 

that "[t]he estimated prices are approximate as each plant site will vary in layout. "1 In fact, 

when EPA requested the cost data, EPA asked that the cost data "assume average industry 

operating conditions and no special circumstances (e.g., headroom below the boiler)." It appears 

that 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.2It also appears that EPA's capital costs for conveyance and 

intermediate storage are underestimated because they do not consider all of the Balance of Plant 

(BOP) costs and costs associated with site-specific issues.

1 EPA-HQ-OW -2009-0819-2007, p. 6.

2 EPA-HQ-OW -2009-0819-1959.20.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 210.

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: 110

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

• EPA also underestimated costs for balance of plant, engineering overhead, and profits and 

overhead for both fly ash and bottom ash retrofits.

• For both fly ash and bottom ash retrofits, EPA failed to provide for contingency. A standard 

level of contingency would be 20% of the capital costs.

• EPA also did not include costs for any land acquisition to provide space for the retrofitted fly 

ash and bottom ash handling systems. This assumes that all sites have adequate space for the 

equipment already, which is not accurate.

• For FGD wastewater retrofits, EPA understated costs by using “typical” FGD purge flow rates 

instead of maximum design flow rates. When constructing a new treatment system, engineers 
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must use the maximum design flow rate rather than an average or typical flow rate. Therefore, it 

is inappropriate to base construction costs on an average or typical flow rate.

• Also, EPA did not include any contingency costs for FGD wastewater retrofits. A standard 

level of contingency would be 20% of the capital costs for a relatively uncomplicated retrofit, 

and could be higher for a more complex retrofit.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 210.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 212

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

XXV. The Regulatory Impact Analysis Also Depends on Faulty Input Values

The RIA (EPA-HQ-OW-2009-0819-2239) suffers from the same major problem as the 

BCA: the compliance cost inputs are erroneous. As we have listed above, the many flaws in 

EPA’s cost estimates for bottom ash, fly ash, and FGD retrofits renders the overall compliance 

cost analysis invalid. These flaws are not small matters; for instance, we suspect EPA’s use of 

the wrong formulas for conveyance and intermediate storage portions of dry fly ash retrofits 

lowers costs of those components by 46%.

UWAG urges EPA to re-evaluate its entire methodology for estimating compliance costs for the 

rule and to do the same for its assessment of pollutant loadings. It should then revise the BCA 

and the RIA to better reflect more accurate costs and environmental benefits, as well as more 

accurate industry-level impacts of this rulemaking. EPA’s re-evaluation, since it covers very 

significant portions of the supporting evidence for the rule, should be presented to the public for 

additional review and comment.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 210.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company
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Document Control Number: EPA-HQ-OW-2009-0819-4379-A1

Comment Excerpt Number: 151

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Assertion That Pollutant Discharges are Increasing is Not Supported in the Record

Additionally, EPA asserts that the volume and total mass of the pollutant discharges have 

increased each year (presumably since the enactment of the current regulations in 1982) as a 

result of new technologies for generating electric power and the implementation of air pollution 

controls. In particular, EPA contends that technology like coal gasification, and air pollution 

controls like flue gas desulfurization, selective catalytic reduction, and flue gas mercury controls, 

have altered existing wastestreams or created new wastewater streams that have purportedly led 

to an increase in discharges. 78 Fed. Reg. at 34435. Southern does not believe EPA’s 

characterization of the extent and increase in pollution from the industry is supported by the 

record. Even if there were some increases in pollution discharged from some individual plants, it 

does not appear that EPA fully considered the overall industry trend and expansion of waterquality based effluent limits on power plant discharges.

Comment Response: 

EPA disagrees that that record does not show that pollutant discharges increased as plants 

implemented controls such as FGD systems and gasification systems. It is indisputable that 

pollutant discharges from a plant increase when a process, such as an FGD system, is installed 

and creates a new wastewater discharge that contain pollutants that have been captured from the 

air emissions and transferred to the wastewater. Furthermore, since the ELGs were last revised in 

1982, plants have moved towards new technologies like coal gasification and the number of flue 

gas desulfurization systems greatly increased. These new technologies and air controls are 

contributing new pollutants to wastewater that were previously not present or were present in 

much lower numbers.

EPA also disagrees that water quality-based effluent limitations take the place of technologybased effluent limitations and standards. Technology based standards provide the minimum that 

is supposed to be implemented by all dischargers. BP Exploration & Oil Inc. v. EPA, 66 F.3d 

784, 789 (6th Cir. 1995) (In formulating these guidelines, the CWA directs EPA to institute 

progressively more stringent effluent guidelines in stages); Texas Oil & Gas Ass’n et al v. US 

EPA, 161 F.3d 923, 927 (5th Cir. 1998) (The CWA prescribes progressively more stringent 

technological standards that the EPA must use as a guidepost in setting discharge limits for 

regulated pollutants.)

See response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 61 in Comment 

Code 6.c. Furthermore, the record demonstrates that water quality-based effluent limits for 

power plants have not been implemented widely. In EPA’s evaluation of many permits for these 

facilities, EPA found the permits did not have metals limits even where the waterbodies the 
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facilities were discharging to are impaired for metals. Even when WQBELs have been 

implemented, such as for the FGD wastestream, the wastewater still contains substantial 

quantities of pollutants.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

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

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In addition to the problems noted in the preceding comments, EPA has mishandled effluent data 

for several parameters. Not only is the majority of the mercury data flawed due to the high 

detection levels of the analytical methods used, but EPA apparently rounded up the mercury 

results from 0.00063 mg/L to 0.001 mg/L for bottom ash effluent. There is no reason to do this, 

all other concentrations are reported to at least two or three significant figures. This misleadingly 

increases the estimated mercury TWPE by almost 60%. For other POCs, EPA treated numerous 

non-detects at full value, also leading to mistakenly higher TWPEs. Proper treatment when 

numerous non-detects occur is to set them at no more than one-half the detection limit, not at the 

detection limit. If all the results are non-detects, as was the case for cadmium in the bottom ash 

pond effluent at the Ratts plant, no TWPEs should be calculated. There would be no aquatic 

toxicity from effluents with all non-detect analysis.

Comment Response: 

EPA agrees with the commenter that there was a rounding error in the mercury data for ash 

transport water presented at proposal in Table 10-7 of the proposed rule TDD. For the final rule, 

EPA has since updated its ash characterization dataset and the revised value for bottom ash 

impoundment effluent is 0.709 ug/L, as shown in Table 10-7 of the final rule TDD (or 0.000709 

mg/L).

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: 99

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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In addition to its qualitative assessment of environmental damage, EPA uses a more quantitative 

model to understand the impacts of power plant effluents on current surface water quality, as 

well as changes that would be predicted under different types of controls. Pollutant loading 

estimates (both baseline loadings and reductions due to controls) are central to EPA’s estimates 

of risks and ultimately benefits, underlying both ecological and human health aspects of the 

proposed rule. Specific shortcomings of EPA’s analysis of baseline pollutant loadings include:

 Model inputs and assumptions are not always transparent, and so key results cannot be 

replicated;

 The estimation of baseline pollutant loadings using measured effluent concentrations are 

based on a limited data set that may not be representative of industry-wide discharges; 

and

 The effectiveness of baseline control technologies has been mischaracterized, leading to 

likely overestimates of discharges.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 199 in Comment Code 

6.f.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 193

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For some plants, EPA miscalculated fly ash transport water and bottom ash transport water flow 

rates. In some cases, the flow rates used by EPA are four or five times the actual flow rate. EPA 

appears to have used the total ash pond influent flow rate (reported in Part D of the 2010 ICR), 

rather than the bottom ash and fly ash sluice rates (reported in Part C of the 2010 ICR). Since 

other types of wastewaters such as storm water, coal pile runoff, and low volume wastes may 

also be directed to the ash ponds and be part of the ash pond influent, use of the total influent 

flow rate as the equivalent of the ash sluice flow rate grossly overstates the ash sluice rates for 

some ponds. 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 industrywide pollutant loading analysis 

invalid.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 134 in Comment 

Code 17 for more information on EPA’s calculation of ash transport water discharge flow rates. 

EPA disagrees that it used the total ash pond influent flow rate; rather, it used the ash pond 

influent flow rates specifically designated as “fly ash sluice,” “bottom ash sluice,” and/or 

“combined ash sluice. Additionally, EPA accounted for any recycle to accurately reflect the 

discharge.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The estimates of the impacts of discharges from steam electric plants are overstated because EPA 

has overestimated the pollutant loadings. These overestimates of pollutant loadings stem from 

using old data, making assumptions about undetected pollutants, counting sulfides that were 

almost certainly not present, counting intake pollutants not added by power plants, and using 

statistical methods that biased the results high.

Having overestimated the pollutant loadings, EPA also overestimated their environmental 

impacts by relying on old cases of damage from coal combustion material releases, measures of 

impact without evidence of actual environmental harm, and discredited models of human health 

effects.

Finally, EPA underestimated the costs of retrofitting technologies such as equipment for dry 

handling of fly ash and balance-of-plant, engineering overhead, and contingency costs.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 210.

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Steam Electric Pollutant Loading Contributions Are Flawed.

UWAG's analyses, which Georgia Power adopts, shows that EPA has vastly overstated the 

amount of pollutants being discharged from power plants. Based on additional sampling and 

analysis by UWAG's consultant, sulfides are generally not present in ash pond discharges, so the 

huge amount of TWPEs that EPA calculates into industry loadings should be removed. That 

adjustment alone would dramatically reduce the steam electric percentage range by EPA's own 

calculations. See EPA-HQ-OW-2009-0819-2232. EPA should also review the ash pond flow 

rates used in its analysis, as we suspect they were over-estimated. Since it appears that EPA has 

overstated the percentage of TWPEs attributable to the steam electric industry by at least a factor 

of two, Georgia Power requests that EPA make every effort to correct the record on this point 

and adjust its Proposed Rule accordingly.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 134 in Comment 

Code 17 for more information on EPA’s calculation of ash transport water discharge flow rates.

Regarding Sulfides, for the reasons explained in EPA’s response to DCN-EPA-HQ-OW-2009-

0819-4487-A1, Excerpt 14, EPA did not include loadings estimates for sulfide in the final rule 

for ash transport water, so related comments are outside the scope of 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: 67

External Review Flag: Statistics

External Review Incorporated into Response: No

Comment Excerpt: 

6.8 Treating all data that are less than the quantitation limit as one-half of the 

sample-specific quantitation limit for all analytes decreases the variability of the 

resulting estimates, leading to a standard deviation of the fitted distribution that 

is too low.

On page 10-5 and elsewhere in the TDD [EPA, 2013], EPA treated all results less than the 

quantitation limit (that is, J-values and non-detects below the method detection limit) as one-half 

of the sample-specific quantitation limit for all analytes.

Alternative recommendation: Use censored-data methods, such as Kaplan-Meier, to estimate 

statistics for data with non-detects and J values. Because it is the standard method used in drug 

trials and medical statistics for estimates from censored data, Kaplan-Meier has precedent in 

other regulatory contexts.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 130 in this comment 

code, response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt Number 66 in Comment 

Code 31.h.i, and Appendix A, Essay Section 4.2.2.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 37

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Dominion's Chesterfield Power Station in Chesterfield, Virginia uses treated effluent from a 

nearby publicly owned sewage treatment plant to supply water to its wet FGD scrubbers. This 

novel water reuse arrangement avoids additional water withdraws from the James River. The 

water sourced from the sewage treatment plant contains higher values of nitrates and nitrites than 

those seen at Allen and Bellow Creek. We are concerned that Chesterfield will be unable to 

apply the GE ABMet technology and remove nitrates and nitrates to the levels necessary to 

comply with the proposal. We estimate that Chesterfield will need to install a much larger 

ABMet system to accommodate the increased nitrates and nitrites in the influent. We do not 

believe the proposal accounts for these additional capital costs in its estimates.

Comment Response: 

While EPA agrees with the commenter’s assertion that water sourced from a publically owned 

sewage treatment plant may contain higher levels of nitrates and nitrites than those seen at Allen 

and Belews Creek, the two plants operating the BAT biological treatment technology whose data 

were used to calculate pollutant loadings, EPA disagrees with the commenter’s assertion that 

Chesterfield will need to install a much larger biological treatment system to accommodate the 

increased nitrates and nitrites. As discussed in Section 6.2.1 of the Incremental Costs and 

Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category (Costs & Loads Report) (DCN 

SE05831/SE05832), the biological treatment system is designed to treat FGD wastewater with 

nitrate/nitrite as N concentrations up to 100 ppm. For plants demonstrating nitrate/nitrite as N 

concentrations above 100 ppm, EPA included additional costs for a denitrification system 

upstream of the ABMet system. See response to DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 44 in Comment Code 10.b. Generally, POTW effluent has a total nitrogen 

concentration of 18 to 30 ppm. The normal total nitrogen concentration is well below the 100 

ppm concentration for nitrate/nitrite as N which would require additional denitrification 

treatment. EPA has reviewed the Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines responses provided by Chesterfield. Because no nitrate/nitrite as N 
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concentrations were reported in response to question B6-2 EPA has reasonably assumed that the 

wastewater used at Chesterfield is within the typical POTW total nitrogen concentrations and no 

additional costs associated with denitrification are included in EPA’s compliance cost 

estimate. EPA notes that the commenter did not provide any data along with its comments to 

show that the total nitrogen concentration in the FGD wastewater at Chesterfield is not within 

this range.

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Increased operating costs

The proposed regulations will impose on all covered sources significant increased capital and 

operating costs including: energy, chemicals, water, labor, permits, fees, health & safety, 

training, solids disposal, maintenance, operators licenses, liability insurance and connection fees.

Sources that are not covered by the regulation still anticipate an increase cost of purchased power 

because the additional regulatory burden on electric generating units will result in higher electric 

rates. In addition, these sources will incur direct costs because state agencies will very likely 

apply the regulations to power plants that are associated with manufacturing. This has happened 

before for other regulations that apply to steam electric generating units.

Comment Response: 

EPA agrees with the commenter that some of the plants covered by the final rule will have 

“increased capital and operating costs.” EPA also agrees with the commenter that “[s]ources that 

are not covered by the regulation still anticipate an increase cost of purchased power because the 

additional regulatory burden on electric generating units will result in higher electric rates.” See 

the RIA for additional information regarding the estimated increase in electricity rates.

Regarding increases in costs associated with power plants located at manufacturing facilities, 

EPA has revised the applicability to help clarify that these plants are not included within the 

scope of the ELG. Therefore, any additional cost that they may incur is outside the scope of this 

rulemaking. See response to DCN EPA-HQ-OW-2009-0819-4486-A2, Excerpt Number 2 in 

Comment Code 5.a.
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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: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Based on Southern’s estimates of its own costs to comply with the Rule, EPA has grossly 

underestimated both Southern’s costs and those for the industry at large. For example, based on a 

screening level analysis, Southern estimates it will expend between $2.0 and $4.8 billion to 

comply with Option 4a, while EPA estimates Southern will expend only $732 million for that 

option. In contrast, EPA estimates an industry total cost for compliance of $5.5 billion for Option 

4a. Clearly if Southern’s costs are even the minimum estimate of $2 billion (which is about 37% 

of EPA’s total of $5.5 billion) then EPA has greatly underestimated the costs to the industry as a 

whole.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 133.

Commenter Name: Jeffrey A. McNelly

Commenter Affiliation: Anthracite Region Independent Power Producers Association 

(ARIPPA)

Document Control Number: EPA-HQ-OW-2009-0819-4453-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In addition, EPA’s concept of using an effluent limits and loading limits appears to be a new 

approach. In the past, EPA had established effluent limits and did not couple that to loading 

limits. The concept of loading is tied to the amount of water to be treated. This is a problematic 

issue from the perspective that any water contributions that is highly variable will result in wide 

swings in pollutant loading. Determining the volume of water that will be treated will be 

problematic; especially if it is tied to precipitation events (of an unknown duration) making if 

difficult to insure proposer treatment; especially with relationship to CCR management.

Comment Response: 

EPA agrees with the commenter’s assertion that the “concept of loading is tied to the amount of 

water to be treated [which can be] a problematic issue from the perspective that any water 
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contributions that is highly variable will result in wide swings in pollutant loading.” EPA 

disagrees with the commenter that “EPA’s concept of using an effluent limits and loading limits 

appears to be a new approach.” The Steam Electric Power Generation ELGs have always been 

written in 40 CFR 423 as mass-based limitations, based on multiplying the flow by the numeric 

concentration limitations. However, the final rule allows for the use of concentration-based 

limitations, by including the following language: “At the permitting authority's discretion, the 

quantity of pollutant allowed to be discharged may be expressed as a concentration limitation 

instead of any mass based limitations.”

The final rule does not require internal monitoring to demonstrate compliance with certain 

numeric limitations and standards. See response to DCN EPA-HQ-OW-2009-0819-4305-A3, 

Excerpt Number 117 in 26d.

Commenter Name: Lisa C. Messinger

Commenter Affiliation: Vectren Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4317-A1

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Although this section of the proposed rule does not appear to affect our plants, we would like to 

take the opportunity to correct inaccuracies with how our data is used in supporting 

documentation for the rulemaking. In the Technical Development Document (EPA-821-R-13-

002) (pp 6-8 and 6-9), EPA correctly states that fly ash/bottom ash transport water flow rate is 

the rate of the sluicing system to the impoundment and does not necessarily represent the fly 

ash/bottom ash discharge flow rate FROM the plant, yet proceeds to use the total flow rates in 

all pollutant loading and TWPE calculations.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 134 in Comment 

Code 17 for more information on EPA’s calculation of ash transport water discharge flow rates.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 45

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

In addition, the cost modules for Fly Ash Transport and Bottom Ash Transport Water did not 

include the closure costs for the transport piping; dewater bins and other miscellaneous 

equipment or expedited closure costs for existing impoundments and costs for providing new 

treatment facilities for low volume wastes no longer directed to these closed impoundments. The 

model costs needs to consider the impact of the anti-circumvention requirements that would 

require the separation of low-volume waste water from "zero" discharge wastes or leachate (if 

landfill expansions are considered new sources.

Comment Response: 

EPA agrees with the commenter’s assertion that closure costs for ash transport water piping and 

impoundment closure costs are not included in the compliance cost estimates. EPA is not 

requiring plants to dismantle piping or close existing impoundments. In some cases EPA’s cost 

estimate assumes that some piping and other existing equipment will be reused to save costs, see 

Sections 7 and 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 (Costs & Loads Report) (DCN SE05831/SE05832) for more details. Any existing 

impoundment, including those that receive wastewaters other than ash transport water, is not 

required to close under the final rule; these impoundments can continue to operate.

Additionally, EPA does not expect that plants will incur any additional costs associated with 

anti-circumvention requirements that are included in the final rule. As described in preamble 

section VIII, anti-circumvention provision only apply to wastestreams with zero discharge 

limitations or standards. For fly ash and bottom ash, the installation of the technology bases will 

result in separation of the transport water from other low volume wastes. Therefore, EPA 

concludes that there are no additional costs required. Combustion residual leachate is not subject 

to any anti-circumvention provision.

Commenter Name: Jeffrey A. McNelly

Commenter Affiliation: Anthracite Region Independent Power Producers Association 

(ARIPPA)

Document Control Number: EPA-HQ-OW-2009-0819-4453-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

ARIPPA is further concerned that the proposed methodology to address discharge limits are tied 

to loadings that are based on flows and the limitations established in the rule. associated with 

storm water runoff from CCR storage or management sites. The rule does not look at situations 

The management of these flows could become very expensive in terms of property and 
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impoundment storage capacity as well as managing biological treatment systems for selenium 

and having the system function properly.

Comment Response: 

EPA focused this rulemaking on revisions to the effluent limitations guidelines and standards for 

specific wastestreams discharged from steam electric power plants. EPA identified the specific 

wastestreams included in this rulemaking based on the results from its detailed study that was 

completed in 2009. Storm water runoff from CCR storage or management sites was not 

identified for inclusion in this rulemaking. This comment is outside the scope of the rulemaking.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 43

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Method for Estimating Plant-Specific Costs

EPA's cost estimates include two cost components:

 Capital costs (onetime costs) and

 Annual operating and maintenance (O&M) costs.

As appropriate, EPA also accounted for expected reductions in the plant's costs associated with 

their current operations or treatment systems that would no longer be needed as a result of 

installing and operating the technology bases (e.g., avoided costs to manage surface 

impoundments).

Comment Response: 

EPA agrees that its cost estimates include both capital costs and O&M costs. EPA also agrees 

that it “accounted for expected reductions in the plant's costs associated with their current 

operations or treatment systems that would no longer be needed.”

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 31
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

It should be noted that this issue of bias, due to EPA’s method for estimating loadings, may 

extend beyond ash impoundment pollutant loadings to any of EPA’s estimates of pollutant 

loadings that were calculated as the product of averages. The proper method of calculating the 

average annual pollutant loading, as the technical report explains, is the average of the products. 

The effect of this bias is illustrated in examples provided in the report by AKRF, Inc.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655-A1, Excerpt Number 4.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Selenium should be regulated based upon realistic Toxic Weighted Pound Equivalent (TWPE). 

EPA made poor analytical judgments by showing pollutants that were actually at the non-detect 

level. EPA’s exaggerated calculation also increased the projected reductions TWPE by nine

times the actual number. APPA defers to the Utility Water Act Group’s (UWAG) more 

detailed critique but points out that this is type of error is not a good basis for regulating 

selenium.

Comment Response: 

EPA does not select regulated pollutants, pollutants of concern, based on TWPE. For details on 

EPA’s selection of regulated pollutants, see Section 11 of the TDD.

Other specific comments raised in UWAG’s letter, and referenced by the commenter, are 

addressed elsewhere in this comment response document.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

Document Control Number: EPA-HQ-OW-2009-0819-5140-A2
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Comment Excerpt Number: 101

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Selenium should be regulated based upon realistic Toxic Weighted Pound Equivalent (TWPE). 

EPA made poor analytical judgments by showing pollutants that were actually at the non-detect 

level. EPA’s exaggerated calculation also increased the projected reductions TWPE by nine

times the actual number. APPA defers to the Utility Water Act Group’s (UWAG) more 

detailed critique but points out that this is type of error is not a good basis for regulating 

selenium.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 95 in Comment Code 

10.c.

Other specific comments raised in UWAG’s letter, and referenced by the commenter, are 

addressed elsewhere in this comment response document.

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: 108

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

As demonstrated by UWAG’s analysis of EPA’s cost-effectiveness using model plants, as well 

as other cost analyses discussed above, EPA assumptions systematically resulted in an 

underestimation of costs associated with the proposed rule. Additionally, this underestimation of 

costs associated with the proposed rule was demonstrated to carryover on an industry-wide basis 

by UWAG’s consultant, NERA Economic Consulting (NERA).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Numbers 136 in Comment Code 

6.h and 210 in this comment code. 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: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 85

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The annual operating cost of disposing fly ash in an onsite landfill ranges between $3.50 and 

$6.00 per ton, compared to wet handling, where the annual cost is little more than pump 

maintenance. EPA must consider costs such as these before it can estimate the cost or costeffectiveness of its options for disposing of bottom ash, fly ash, FGMC wastewater, and FGD 

solids.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 153.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

APPA believes that the EPA cost analyses and technology assessments were not very realistic. 

See Tables 3-6. These costs far exceed EPA’s typical $404 per TWPE reduction cost.

Comment Response: 

See responses to comment code 6.h.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 102

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

APPA believes that the EPA cost analyses and technology assessments were not very realistic. 

See Tables 3-6. These costs far exceed EPA’s typical $404 per TWPE reduction cost.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2 Excerpt Number 12.

Commenter Name: Jeffrey A. McNelly

Commenter Affiliation: Anthracite Region Independent Power Producers Association 

(ARIPPA)

Document Control Number: EPA-HQ-OW-2009-0819-4453-A1

Comment Excerpt Number: 19

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The concept of using effluent limits to determine loading is problematic based on how one 

determines projected volume of water to be managed, including precipitation events.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4453-A1, Excerpt Number 14.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Additionally, several flaws were identified with EPA’s methodology for calculating toxicweighted pound-equivalent (TWPE) loadings and removals for each regulatory option.

Comment Response: 

Regarding baseline loadings for FGD wastewater see responses in comment codes 8.c and 8.d.
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Regarding loadings and removals for FGD chemical precipitation see responses in comment 

code 9.c.

Regarding loadings and removals for FGD biological treatment see responses in comment code 

10.c.

Regarding loadings and removals for fly ash wastewater see responses in comment codes 13.c, 

13.d, and 14.c.

Regarding loadings and removals for bottom ash wastewater see responses in comment codes 

15.c, 15.d, and 16.c.

Regarding loadings and removals for leachate see responses in comment codes 18.c, 18.d and 

19.c.

Regarding loadings and removals for flue gas mercury control wastewater see responses in 

comment code 21.d.

Regarding loadings and removals for nonchemical metal cleaning wastes see responses in 

comment code 22.c.

Regarding loadings and removals for gasification wastewater see responses in comment code 

23.c.

Regarding loadings and removals for FGD evaporation see responses in comment code 8.d.

For further discussion on EPA’s estimates of loadings and removals see TDD Section 10 and the 

Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (Costs & Loads 

Report) (DCN SE05831/SE05832).

Also see responses to Comment Code 6.h.

Responses to other specific comments made by the commenter are located in elsewhere in this 

comment response document.

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: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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EPA should consider further regulatory options, including exempting all bottom ash wastewater 

flows, and setting higher exclusion levels for fly ash and FGD wastewaters.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4686-A1, Excerpt Number 20 in Comment 

Code 5.c.

EPA determined that it would inappropriate to include a threshold in the final rule for fly ash 

wastewater, other than the 50 MW threshold for small generating units, based on its analysis for 

the final rule, see preamble section VIII.

Commenter Name: B. Hasten

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4832-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The technology for complete pollutant removal is available from the French/Japan.

Comment Response: 

EPA made every effort to study available wastewater treatment technology for the steam electric 

power industry. See preamble Section VIII and the TDD for details on the technology bases that 

EPA selected for the final rule.

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: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s methodology for calculating toxic weighted pound equivalent (TWPE) loadings and 

removals was flawed in several areas.

Comment Response: 
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Regarding baseline loadings for FGD wastewater see responses in comment codes 8.c and 8.d.

Regarding loadings and removals for FGD chemical precipitation see responses in comment 

code 9.c.

Regarding loadings and removals for FGD biological treatment see responses in comment code 

10.c.

Regarding loadings and removals for fly ash wastewater see responses in comment codes 13.c, 

13.d, and 14.c.

Regarding loadings and removals for bottom ash wastewater see responses in comment codes 

15.c, 15.d, and 16.c.

Regarding loadings and removals for leachate see responses in comment codes 18.c, 18.d and 

19.c.

Regarding loadings and removals for flue gas mercury control wastewater see responses in 

comment code 21.d.

Regarding loadings and removals for nonchemical metal cleaning wastes see responses in 

comment code 22.c.

Regarding loadings and removals for gasification wastewater see responses in comment code 

23.c.

Regarding loadings and removals for FGD evaporation see responses in comment code 8.d.

For further discussion on EPA’s estimates of loadings and removals see TDD Section 10 and the 

Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (Costs & Loads 

Report) (DCN SE05831/SE05832).

Also see responses to comment code 6.h.

Responses to other specific comments made by the commenter are located in elsewhere in this 

comment response document.

Commenter Name: Eric Schaeffer

Commenter Affiliation: Environmental Integrity Project et al.

Document Control Number: EPA-HQ-OW-2009-0819-4761-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

This case by case approach to setting BAT limits on toxic pollutants imposes significant costs on 

EPA, state agencies, nongovernmental organizations, and industry. The Agency has enough 

information to provide a reasonable estimate of these costs to permitting agencies given the time 

and effort it has spent on the Merrimack permit, the estimates that we have provided in 

comments submitted separately, and taking into account concerns states have expressed about 

the burden of having to set standards in each permit.10 These administrative costs would be 

eliminated through an ELG that set industry-wide standards based on appropriate consideration 

of the best available technologies.11

Even more significant, setting standards on a permit-by-permit basis will impose treatment costs 

in the absence of an ELG. Yet EPA has failed to include these costs under Options 3a and 3b, 

which require case-by-case BAT determinations for FGD wastewater discharges.12 These costs 

must be accounted for in this rulemaking. EPA Region 1 has already proposed that chemical and 

biological treatment reflects BAT for treatment of scrubber waste from the Merrimack plant, 

although that facility has gone further by installing a zero liquid discharge system.13 And if 

states conduct a proper BPJ analysis, they will arrive at BAT determinations that are close to 

what EPA has proposed for Options 4 and 5.14

EPA has the information it needs to estimate the costs, or at least a range of costs, that would be 

incurred based on BAT limits that are likely to be required through individual permits in the 

absence of an ELG. EPA must include these costs in compliance estimates for Options 3a and 

3b. Furthermore, because these case-by-case determinations are required now, in the absence of 

an ELG, the estimated costs of complying with the standards that EPA has proposed should be 

adjusted by subtracting investments in treatment processes that would otherwise be required 

through individual permit decisions.

The Clean Water Act mandates that EPA promulgate revised ELGs that reflect BAT.15 As we 

have clearly stated in our comments, it is also fairer, more protective, and likely less expensive in 

the long run to set industry-wide standards than to develop BAT limits on a permit by permit 

basis.16 Taking the latter course will add layers of administrative burden and cost to the process 

of upgrading wastewater treatment to the technology based standards required by law. The 

adoption of effluent guidelines based on the best available technologies will eliminate that 

burden, and EPA’s cost estimates should be adjusted to reflect that reality.

10 Id.

11 Id.

12 Id.

13 Id.
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14 Id.

15 Id. § II.

16 Id. § III.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6 (in Comment Code 

6.j.i) and other responses in Comment Code 6.j.i.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4704-A1

Comment Excerpt Number: 32

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Used an Improper Method to Backout Costs for the 400 MW and Smaller Units

The EPA estimated the cost of Option 4a, which includes the 400 MW threshold, by backing out 

the costs of these smaller units using a procedure based on the fraction of the total wet bottom 

ash contributed by the 400 MW and smaller units. EPA initially developed plant-level costs by 

summing unit-level costs. CAR, p. 8-4. Rather than using these original unit-level costs to back 

out the costs for 400-MW and smaller units, EPA developed a different method to convert the 

plant-level costs to unit level costs. In this new method, EPA calculated an "adjustment factor" 

as the ratio of wet bottom ash from units greater than 400 MW to total plant wet bottom 

ash. This "adjustment factor" was multiplied by plant-level costs and TWPE to estimate the 

costs and TWPE reductions for units subject to regulation under Option 4a.143

However, most of the costs are not proportional to the amount of wet bottom ash produced, but 

rather to the capacity of the unit. The installed capital cost, for example, is proportional to the 

design capacity of the unit (CAR, Sec. 8.1.4). Many of these smaller units (<400 MW) operate at 

very low capacity factors and thus produce a small fraction of the bottom ash (wastewater and 

TWPE) from a plant with other larger units that operate at higher capacity factors. Thus, this 

procedure distributes too much of the industry-wide cost of bottom ash transport water control to 

the >400 MW units. This overestimates the cost of Option 4a expressed in dollars per TWPE. 

The 400 MW and under costs could have more simply and accurately been broken out using the 

original unit-level data used to calculate the plant-level costs!
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143 “ERG Memorandum from TJ Finseth, Danielle Lewis, and Elizabeth Sabol,” Re: 

‘Methodologies for Estimating Costs and Pollutant Removals for Steam Electric ELG 

Regulatory Option 4a,’ April 15, 2013.

Comment Response: 

EPA has revised its estimates of compliance costs and pollutant loadings for the final rule. See 

Section 9 of the Technical Development Document for the Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (TDD) (DCN

SE05904) for details specific to the compliance cost estimates and Section 10 of the TDD for 

details specific to pollutant loadings and removals. In addition, EPA has not selected proposed 

regulatory option 4a so the commenters concerns about the 400 MW threshold are no longer 

relevant. For discussion on option selection for BAT for the final rule see preamble section VIII.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 156

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

As explained more fully in the accompanying report by Synapse Energy Economics, compliance 

cost estimates prepared before the installation of controls often overestimate costs.686 Studies 

have documented this effect in major federal rule makings.687 Researchers have identified 

explanations for the trend. Once a rule is finalized and the deadline approaches, a market is 

created, or strengthened, in the pollution controls required, which often leads to technological 

innovation and a drop in price.688 Additionally, cost analyses may rely on high-end estimates 

because of conservative, counterfactual assumptions by agencies and because of strategic 

behavior by the regulated industry.689 Finally, since the regulated industry has better access to 

information on compliance costs, industry is better positioned to point out underestimates than 

the public is able to point out overestimates of costs.690

In this case, it is not necessary to wait until the compliance deadline to compare EPA's cost 

estimates to the actual compliance costs. Instead, the attached report by Dr. Phyllis Fox, 

Appendix E, documents that EPA's assumptions have resulted in significantly overestimating the 

cost of compliance.691

Dr. Fox focused her comments on EPA's inflated cost estimates for bottom ash handling systems, 

but the errors she identified applied to the controls for other waste streams as well. EPA ignored 

economies of scale when calculating the cost of controls for all waste streams, 

which systematically inflates the cost of all proposed options. Similarly, EPA's inclusion of 

units that have already announced they will retire results in overestimating the total compliance 
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cost for all proposed options. As explained in the attached, 88 units have announced that they 

are shutting down completely or switching fuels, and will not incur compliance costs – yet these 

units are included in EPA's calculation of total compliance costs.693 Finally, the inappropriately 

high annualization factor was used to calculate the cost of all options, and therefore increased the 

cost of all options. Taken together, these assumptions and methodologies have dramatically 

inflated EPA's cost estimates for all options, confirming research showing that ex ante 

compliance costs are usually overestimated.

686 Synapse Report, Appendix A.

687 Id. at 16-18.

688 Id. at 16.

689 Id. at 16-17.

690 Id. at 17.

691 Fox Report, Appendix E.

693 List of Announced Retirements Included in EPA’s Cost Calculations, submitted by 

Commenters as an exhibit to this letter.

Comment Response: 

EPA agrees with the commenter’s assertion that costs associated with the treatment technology 

used as the basis for the final rule will decrease over time. EPA’s compliance cost estimates 

reflect the best available cost data for the treatment technology at the time the analysis was 

conducted. Because EPA cannot accurately predict how costs associated with a specific 

treatment technology will change in the future, EPA used the data currently available.

EPA disagrees with the commenter’s assertion that economies of scale were ignored. EPA’s 

approach of using cost curves accounts for economies of scale. As described throughout the 

Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (Costs & Loads 

Report) (DCN SE05831/SE05832), EPA used vendor cost estimates for the costs associated with 

equipment or treatment systems at several specific wastewater flow rates and generated a curve 

to relate costs to wastewater flow rate. Using these curves, EPA was able to scale costs to a 

plant-specific wastewater flow.

Additionally, EPA has updated the Industry Profile Memo (Memorandum to the Steam Electric 

Rulemaking Record: Changes to Industry Profile for Steam Electric Generating Units for the 

Steam Electric Effluent Guidelines Final Rule - DCN SE05069) to reflect recent changes in 

retirements and fuel conversions.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 30

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Total annualized compliance and social costs: EPA’s assertion that the cost to industry of 

requiring Option 5 is too high is presented without explanation or justification. Dollar‐ figure 

costs can only be understood in the context of the scale of an industry. Costs that would be far 

too high for a small industry to bear may be indiscernible to a larger industry such as steam‐

electric power generation. In addition, EPA’s cost analysis is inflated by the inclusion of some 

plants that have since retired. Cost‐to‐revenue analysis (discussed below) is a more appropriate 

way for EPA to present evidence of high costs.

In addition, EPA’s measure of compliance cost (and, therefore, the use of this measure in cost‐to‐revenue ratios and 

cost‐effectiveness tests) is based on a strong and—by EPA’s own admission—inaccurate assumption. EPA assumes 

that all of the compliance costs associated with the proposed steam electric ELGs will be borne by the owners of the 

power plants and not, as is undeniably the common practice in the industry, passed on in some part to consumers in 

higher utility rates.154

154 78 Fed. Reg. at 34,495.

Comment Response: 

EPA disagrees that the record does not provide the proper basis for rejecting the option that uses 

evaporation as the technology basis for FGD wastewater (Option 5 at proposal). See Section VIII 

of the preamble and EPA’s response to related comment DCN EPA-HQ-OW-2009-0819-4684-

A1, Excerpt Number 216 (in comment code 28.b) for a discussion of the rationale for rejecting 

the option.

EPA notes that it has updated the Industry Profile Memo (Memorandum to the Steam Electric 

Rulemaking Record: Changes to Industry Profile for Steam Electric Generating Units for the 

Steam Electric Effluent Guidelines Final Rule - DCN SE05069) to reflect recent changes in 

retirements and fuel conversions. The analysis of the final rule reflects these revisions to the 

universe of steam electric power plants.

Commenter Name: Becky Hayat

Commenter Affiliation: Natural Resources Defense Council (NRDC)
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Document Control Number: EPA-HQ-OW-2009-0819-4490-A1

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Using a dry handling system may be the most cost-effective choice in the long-run for steam 

electric generating facilities. The use of water in a wet handling system, as opposed to air as a 

cooling agent in a dry handling system, can incur additional costs. Factors such as water 

treatment, corrosion damages, and higher disposal and maintenance costs all should be 

considered as plants re-evaluate their wet ash handling practices.20

20 United Conveyor Corporation, Wet-to-Dry Conversion: Bottom Ash & Fly Ash Systems 

(2009).

Comment Response: 

The final rule establishes BAT requirements for fly ash and bottom ash based on dry ash 

handling (or closed-loop systems for bottom ash), as described in preamble section VIII.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 79

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s industry-wide cost estimate also does not account for how the closure of FGD wastewater 

settling ponds will make space available for on-site landfills, which would dramatically reduce 

the operating costs (transportation and fuel) compared to off-site disposal.

Comment Response: 

EPA agrees with the commenter’s assertion that the closure of FGD ponds would make space 

available for on-site landfills. However, the final rule does not require plants to close existing 

impoundments. Because plants may continue to operate these impoundments, EPA does not 

estimate costs associated with closing these impoundments, nor was any space associated with 

these impoundments assumed to be reallocated or reused as part of the analyses for the final 

ELG.
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6.g. Regulatory Options - Definitions

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: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Power plants that do not own offsite landfill receiving its waste; should not be held responsible 

for the receiving facility complying with the effluent limitations guidelines. The steam electric 

ELGs do not apply to offsite landfills for coal-related waste where the landfill is not owned or 

operated by a utility. Rather, if the offsite landfill is an ordinary landfill unit in the Landfills 

Point Source Category, then it is regulated by the ELGs in 40 C.F.R. Part 445.

Comment Response: 

EPA agrees that plants operating landfills that do not meet the applicability of 40 CFR 423.10 

are not subject to this rule.
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6.g.i. Combustion residual leachate (leachate)

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

IV. EPA SHOULD AMEND OR CLARIFY THE DEFINITION OF THE 

TERM “COMBUSTION RESIDUAL LEACHATE” SO THAT IT IS NOT OVERBROAD

It is important for EPA to confirm in the final ELG rule that the definition of the term 

“combustion residual leachate” does not capture wastewater streams that are not subject to 

regulation under this rulemaking; specifically, wastewaters that are not channeled and 

discharged via points sources to a water of the United States. The proposed definition of 

leachate is as follows:

The term combustion residual leachate means leachate from landfills or surface impoundments 

containing residuals from the combustion of fossil or fossil- derived fuel. Leachate includes 

liquid, including any suspended or dissolved constituents in the liquid, that has percolated 

through or drained from waste or other materials placed in a landfill, or that pass through the 

containment structure (e.g., bottom, dikes, berms) of a surface impoundment. Leachate also 

includes the terms seepage, leak, and leakage, which are generally used in reference to leachate 

from an impoundment.

78 Fed. Reg. at 34533 (proposed to be codified at 40 C.F.R. § 423.11(r)).

This definition is overbroad in at least three respects. First, it could be misconstrued as stating 

that stormwater flowing off of a landfill is leachate. Second, the proposed definition potentially 

is broad enough to apply to water that comes into contact with CCR that is beneficially 

used. Third, the proposed definition could be read to mean that EPA intends to regulate seepage 

and leakage from units that is not collected or channelized and discharged through a point 

source. It would be inappropriate to construe water as leachate subject to the proposed ELG 

requirements in any of these circumstances, and USWAG does not believe that EPA intended the 

definition to be as broad as it appears to be. Therefore, we request that the Agency revise the 

regulatory text accordingly.

A. Stormwater That Flows from a Landfill Is Not Regulated Combustion Residual 

Leachate

The proposed definition of combustion residual leachate includes liquid that is “drained from 

waste or other materials placed in a landfill.” 78 Fed. Reg. at 34533 (proposed to be codified at 

40 C.F.R. § 423.11(r)). This imprecise wording could be misinterpreted as converting 
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stormwater that flows off of a capped or active landfill unit into leachate. Rather, only water that 

has percolated through a landfill and collected by a leachate collection system should be 

regulated as combustion residual leachate.

As the Agency is aware, rainwater that runs off of a landfill unit is defined in several existing 

regulations as stormwater. For example, 40 C.F.R. § 122.26 defines stormwater, in part, to 

include “stormwater runoff, snow melt runoff, and surface runoff and drainage.” Id. at § 

122.26(b)(13) (emphasis added). This definition captures any stormwater runoff from a landfill 

site, including those that are capped and those that are still in operation. Further, contaminated 

stormwater that runs off of the active portion of a landfill and comes into contact with CCR is 

captured by the term “stormwater discharge associated with industrial activity,” which includes, 

among other things, activities involving “[l]andfills . . . that receive or have received any 

industrial waste” and “[s]team electric power generating facilities, including coal handing sites.” 

Id. at § 122.26(b)(14)(v) & (vii)). Similarly, the effluent limitations guidelines for the landfills 

point source category characterize rain water flowing off a capped portion of a landfill as noncontaminated stormwater and water flowing off the active portion of a landfill as contaminated 

stormwater. 40 C.F.R. § 445.2(b) & (g). This distinction is reflected in EPA’s Multi-Sector 

General Permit for Stormwater Discharges Associated With Industrial Activity 

(“MSGP”), which likewise expressly categorizes rainwater flowing off of a landfill as 

contaminated or non- contaminated stormwater (depending on whether it comes into contact with 

wastes). MSGP Sector L, Sections 8.L.4.1 & 8.L.4.5.

To avoid confusion and unnecessary regulation, EPA should unambiguously differentiate 

between leachate and stormwater in the text of the final ELG rule and/or its preamble. Any 

water flowing off a capped or active portion of a landfill site should be properly considered 

stormwater. As EPA has proposed in its preferred option (Options 3a, 3b, and 4a), leachate 

percolating through CCR should be subject to existing BPT limits for low volume 

waste, whereas water flowing off a capped or active landfill should remain subject to applicable 

standards for stormwater.

B. Water That Comes into Contact with a CCR that Is Beneficially Used Is Not

Combustion Residual Leachate

In addition to the above, it is important for EPA to clarify that the definition of combustion 

residual leachate does not inappropriately include water that has come into contact with CCR 

that has been beneficially used and which has not been disposed or otherwise managed in a 

CCR landfill or surface impoundment. The proposed definition of combustion residual leachate 

extends only to leachate from “landfills or surface impoundments containing residuals from the 

combustion of fossil or fossil-derived fuels.” 78 Fed. Reg. at 34533 (proposed to be codified at 

40 C.F.R. § 423.11(r)) (emphasis added). On its face, this definition embraces only leachate 

from CCR that was placed in the unit for containment – i.e., either disposal or storage. CCR that 

is beneficially used is not placed in a surface impoundment or landfill for containment, but rather 

it is used to serve a functional purpose as a replacement for virgin materials.

While the proposed definition of “combustion residual leachate” should not and does not 

encompass water that comes into contact with CCR that is beneficially used, confirmation of this 
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point in the final rule is important to avoid any unnecessary confusion that would run counter to 

EPA’s important policy goal of promoting the beneficial use of CCR. As the Agency 

acknowledged in the CCR Proposal, utilities and other commercial sectors are continually 

exploring means for using CCR for beneficial uses, as opposed to managing these materials in 

landfills or surface impoundments. 75 Fed. Reg. at 35153. And as EPA has expressed on 

numerous occasions, it does “not wish to place any unnecessary barriers on the beneficial use of 

[CCR],” id. (quoting the 2000 CCR Regulatory Determination). We are concerned, however, 

that the final ELG rule may cause confusion unless EPA clarifies that the term “combustion 

residual leachate” refers only to leachate from units that manage or dispose of CCR and does not 

encompass water that may come into contact with CCR that is beneficially used.

For example, landfills and impoundments often are constructed using structural fill and 

embankments that utilize CCR. During the operation of a landfill operators also may use CCR 

for daily cover, and at the end of a unit’s operational life CCR may be used as part of the final 

cover material. CCR also may be used as road base for service roads for these units and for other 

roads. In these circumstances, the CCR is not being placed in the landfill or impoundment for 

containment, but instead is being used as a construction material. When these units contain only 

non-CCR low volume wastes, the fact that there may be some incidental contact between water 

and beneficially used CCR should not be interpreted to mean that any leachate from the unit is 

“coal combustion leachate.” This is because the units are not being used to “contain” CCR and 

therefore any leachate from these units is not encompassed by the definition of “combustion 

residual leachate.”

In addition to the beneficial use of CCR in the construction and operation of impoundments and 

landfills, CCR is commonly used throughout the country for a wide array of other beneficial 

uses, including by state Departments of Transportation and other local and municipal entities for 

use in the construction of roadbed embankments and for structural fill in other state and 

municipal construction projects. Indeed, work is underway to revise and reinstate an ASTM 

standard setting forth particular standards for the design and construction of engineered 

structural fills using CCR (see ASTM E2277 Standard). Obviously, these types of CCR 

beneficial use activities are outside the scope of the proposal rule (which applies only to the 

steam electric power industry) and therefore any water than may pass through CCR when used in 

these types of structural fill beneficial use applications is not subsumed within the proposed 

definition of combustion residual leachate.

To avoid any confusion in the final ELG rule, it is important for EPA to confirm that the term 

“combustion residual leachate” does not encompass any water that may come into incidental 

contact with CCR when used in beneficial use applications.

C. The Proposed ELG Standards for Leachate Do Not Apply to Water that Is Not 

Collected or Channelized And Discharged Through a Point Source

USWAG also is concerned that the definition of combustion residual leachate may be construed 

as applying the ELG requirements for leachate to non-point source discharges, such as 

stormwater runoff and seepage or leakage from a CCR management unit. It is important 

for EPA to clarify that this is not the Agency’s intent. Wastewaters from a landfill or 
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impoundment are not “discharged” through a point source if they are not first channelized or 

otherwise collected. Rather, water leaving the site of a landfill or surface impoundment can be 

characterized as a regulated discharge for purposes of this rulemaking only if it first goes through 

some kind of “conveyance” (e.g., a pipe or ditch). See Nw. Envtl. Def. Ctr. v. Brown, 617 

F.3d 1176, 1181 (9th Cir. 2011); Oregon Natural Desert Ass’n v. Dombeck, 172 F.3d 1092, 1098 

(9th Cir. 1998); Hudson Riverkeeper Fund, Inc. v. Harbor at Hastings Assocs., 917 F. Supp. 251, 

257 (S.D.N.Y. 1996). Obviously, stormwater that flows off a landfill site and water that seeps 

from the bottom of a unit that has not been collected or channelized through any discrete 

conveyance and discharged through a point source cannot be regulated under this rulemaking.

As discussed above, however, the definition of combustion residual leachate is vague and 

potentially could be read as applying to stormwater flowing off of a landfill. This definition may 

suggest that EPA intends to include such stormwater (improperly defined as leachate) as being 

subject to the proposed ELG requirements. It should be evident that diffuse stormwater 

cannot be regulated as a point source discharge unless it is first collected and channelized by the 

utility. We ask that EPA make this point expressly to remove any potential confusion.

Similarly, the proposed definition of combustion residual leachate also “includes the terms 

seepage, leak, and leakage.” Like stormwater, seepage or leakage of any water from a CCR 

management unit cannot be subject to the proposed ELG standards unless it collected and 

discharged through a point source. Seepage and leakage from a landfill or surface impoundment 

that is not collected or channelized and discharged through a point source is not subject to this 

rulemaking; rather, such seepage or leakage may subject to state regulations and will be subject 

to the groundwater monitoring requirements under the standards for CCR management units 

included in the proposed CCR rule.

In fact, in a webinar on the ELG proposal, EPA correctly stated that the “proposed effluent 

guidelines apply to leachate that is collected and then subsequently discharged as a point source 

to surface waters. So to the extent that there may not be a system and perhaps there is leachate 

that makes it to groundwater . . . the effluent guidelines and the NPDES permit would not apply 

to that.” Transcript from EPA Aug. 20, 2013 Webinar on “Stream Electric Power Generating 

Effluent Guidelines – Proposed Rule,” at 12-13. This situation would be appropriately subject to 

the CCR rule rather than the ELG rule. Therefore, USWAG requests that the Agency 

unambiguously affirm in the final ELG rule, as EPA made clear during the Agency’s ELG 

webinar, that wastewaters from CCR units that are not channelized and discharged via a point 

source to a water of the United States—including stormwater, seepage, and leakage—are not 

subject to the proposed ELG standards.

Comment Response: 

The definition of point source (and indirect discharger/industrial user) and who needs an NPDES 

permit is a basic issue that is outside the scope of this rule. This rule specifies the technologybased limits and standards and pretreatment standards that apply when those underlying 

requirements are triggered. Determining who is a point source is generally a fact-specific 

determination made by the permitting authority. The definition of what is the wastestream 

combustion residual leachate is not tied to the definition of what is a point source.
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The final rule defines combustion residual leachate as follows: “The term combustion residual 

leachate means leachate from landfills or surface impoundments containing combustion 

residuals. Leachate is composed of liquid, including any suspended or dissolved constituents in 

the liquid, that has percolated through waste or other materials emplaced in a landfill, or that 

passes through the surface impoundment’s containment structure (e.g., bottom, dikes, berms). 

Combustion residual leachate includes seepage and/or leakage from a combustion residual 

landfill or impoundment unit. Combustion residual leachate includes wastewater from landfills 

and surface impoundments located on non-adjoining property when under the operational control 

of the permitted facility.”

EPA wishes to distinguish “combustion residual leachate” from stormwater for purposes of this 

rule. (EPA is not intending to change or address the definition of stormwater under the Act in 

this rule.) Conceptually, “combustion residual leachate” is more about percolating through a 

landfill or impoundment and stormwater is about surface flow from a landfill. (Surface flow 

from an impoundment would be neither combustion residual leachate nor stormwater under this 

rule). For purposes of distinguishing combustion residual leachate from stormwater under this 

rule, stormwater simply runs off from the top layers of the landfill. Although the stormwater may 

theoretically come into contact with some CCR material, it is does not percolate, nor is it seepage 

or leakage and thus it is not combustion residual leachate. See Figure 4-10 in the 

TDD. Although under this rule, stormwater is not leachate, it is stormwater discharge associated 

with industrial activity (40 CFR 122.26(b)(14).

The commenter also mentions the use of combustion residual as structural fill for impoundments 

and landfills and/or as a daily cover for the landfill. In this instance, where the stormwater 

percolates through a CCR landfill, or seeps or leaks from the landfill, the wastewater discharges 

are leachate. Although the use of the combustion residuals as structural fill or cover may be 

considered a “beneficial reuse” in the sense that it prevents that need to use virgin materials, the 

combustion residuals have higher levels of toxic pollutants compared to the virgin materials; 

therefore, the percolation, seepage, and leakage receive the same level of control as discharges 

coming from a leachate collection system. EPA generally agrees with the comments that the 

combustion residual leachate definition does not “include water that has come into contact with 

CCR that has been beneficially used and which has not been disposed or otherwise managed in a 

CCR landfill or surface impoundment.” For example, EPA agrees that water contacting 

combustion residuals used in road base or in roadbed embankments would not be considered 

combustion residual leachate. This application clearly is not a landfill or surface impoundment.

Regarding the non-point source discharges, the final rule does not define whether something is a 

point source; that is outside the scope of this final rulemaking. As is the case for any ELGs, the 

final rule requirements only apply to NPDES permitted discharges or discharges to POTWs.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 146
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. “Leachate” Cannot Include Runoff from Landfills or Seepage and Leaks that Are Not 

Point Source Discharges to a Water of the United States

The proposed definition of “combustion residual leachate” is too broad because, on its face, it 

could be inappropriately interpreted to include stormwater runoff from landfills. It also could be 

interpreted to capture seepage from landfills and surface impoundments that does not constitute a 

“point source” discharge to a water of the United States. EPA should make clear in the final 

rule, either by amending the definition or by explaining in the preamble, that such runoff and 

seepage are not “combustion residual leachate” subject to the ELGs.

1. Leachate Should Not Include Stormwater Runoff From Landfills

EPA proposes to define combustion residual leachate as follows:

Leachate includes liquid, including any suspended or dissolved constituents in the liquid that has 

percolated through or drained from waste or other materials emplaced in a landfill, or that pass 

through the containment structure (e.g., bottom, dikes, berms) of a surface 

impoundment. Leachate also includes the terms seepage, leak, and leakage, which are generally 

used in reference to leachate from an impoundment.

78 Fed. Reg. at 34,533 col. 3 (proposed 40 C.F.R. § 423.11(r)).

The phrase “drained from waste” in this definition could be read to include rainwater that runs 

off a landfill, even though such runoff is defined as stormwater under EPA’s regulations. EPA 

should be careful not to alter this important regulatory distinction in this rulemaking. In fact, 

EPA recognizes this important difference in section 4.3.5 of the TDD, where it distinguishes 

between leachate and stormwater by including a diagram, Figure 4-10:
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The same diagram was “Figure 3” in the Federalism/UMRA Supplemental Information –

Package #2 that EPA distributed. EPA-HQ-OW-2009-0819-0909, p. 10. Figure 4-10 shows 

leachate percolating through the landfill and collecting in a leachate collection 

system. Separately it shows rain falling on the landfill surface and runoff from the landfill 

running into a runoff drainage ditch. The clear and appropriate distinction here is that runoff 

from a landfill is not “leachate.”

Indeed, this point is consistent with EPA’s existing regulatory regimes for runoff from landfills 

of various types where the runoff is regulated as stormwater. For example, “stormwater” in 40 

C.F.R. § 122.26 is defined to mean “storm water runoff, snow melt runoff, and surface runoff 

and drainage.” Id. at § 122.26(b)(13) (emphasis added). This definition captures any 

stormwater runoff from a landfill, including those that are capped and those that are still in 

operation. Furthermore, contaminated stormwater that runs off a landfill (e.g., from an active 

portion of a landfill) is captured by the term “[s]torm water discharge associated with industrial 

activity,” including, among other things, activities involving “[l]andfills . . . that receive or have 

received any industrial waste” and “[s]team electric power generating facilities, including coal 

handing sites.” Id. § 122.26(b)(14)(v) & (vii)).

The fact that runoff is characterized as stormwater also is consistent with the effluent limitations 

guidelines for the “landfills” point source category (40 C.F.R. Part 445), which cover stormwater 

that is “contaminated”:
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Landfill wastewater means all wastewater associated with, or produced by, landfilling activities 

except for sanitary wastewater, non-contaminated storm water, contaminated ground water, and 

wastewater from recovery pumping wells. Landfill wastewater includes, but is not limited to, 

leachate, gas collection condensate, drained free liquids, laboratory derived wastewater, 

contaminated storm water and contact washwater from washing truck, equipment, and railcar 

exteriors and surface areas which have come in direct contact with solid waste at the landfill 

facility

40 C.F.R. § 445.2(f) (emphasis added).

That landfill runoff is regulated as stormwater is further reflected in EPA’s Multi-Sector General 

Permit for Stormwater Discharges Associated With Industrial Activity (“MSGP”). Specifically, 

with respect to runoff from a capped landfill, sector L of the MSGP provides, in relevant part, 

that such stormwater is viewed as “non-contaminated stormwater,” which includes “stormwater 

that does not come into direct contact with landfill wastes, the waste handling and treatment 

areas, or landfill wastewater. Non-contaminated stormwater includes stormwater that flows off 

the cap, cover, intermediate cover, daily cover, and/or final cover of the landfill.” Section 

8.L.4.5 of Sector L of the MSGP (emphasis added). Stormwater from the uncapped part of a 

landfill is designated as “contaminated stormwater,” which is defined, in relevant part, to include 

“stormwater that comes into direct contact with landfill wastes, the waste handling and treatment 

areas, or landfill wastewater. Some areas of a landfill that may produce contaminated 

stormwater include (but are not limited to) the open face of an active landfill with exposed waste 

(no cover added)....” Section 8.L.4.1 of Sector L of the MSGP.

The point is that runoff from a landfill is stormwater and differs from water that percolates 

through waste placed in a landfill or surface impoundment, which is “leachate.” Therefore, it is 

critical that EPA clarify in the final rule that “combustion residual leachate” does not include 

stormwater runoff from landfills.70

Moreover, stormwater runoff from a landfill is not a “discharge” (and hence does not need an

NPDES permit) if it is not channelized. Stormwater becomes a discharge only if it goes through 

some kind of “conveyance” (which is understood to mean a pipe or ditch). So if the stormwater 

is not channelized, it cannot be a “discharge” requiring an NPDES permit. See Hudson 

Riverkeeper Fund v. Harbor at Hastings Assocs., 917 F. Supp. 251, 257 (S.D.N.Y. 1996) 

(dismissing a CWA claim that rainfall touching an industrial building was a point source because 

it eventually flowed into a nearby river). As the Ninth Circuit said, “[s]tormwater that is not 

collected or channeled and then discharged, but rather runs off and dissipates in a natural and 

unimpeded manner, is not a discharge from a point source as defined by § 502(14).” Nw. Envtl. 

Def. Ctr. v. Brown, 640 F.3d 1063, 1070 (9th Cir. 2011) (emphasis added). Courts have declined 

to classify pollution coming from “runoff caused primarily by rainfall around activities that 

employ or create pollutants” as a “point source.” Or. Natural Desert Ass’n v. Dombeck, 172 

F.3d 1092, 1098 (9th Cir. 1998).

Similarly, courts define pollution as a “nonpoint source” when it is caused by diffuse sources 

such as runoff. “Broad though [the] definition [of point source] may be, we are of [the] opinion 

that it does not include unchannelled and uncollected surface waters.” Appalachian Power Co. 
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v. Train, 545 F.2d 1351, 1373 (4th Cir. 1976); see also Envtl. Def. Ctr., Inc. v. EPA, 344 F.3d 

832, 842 n.8 (9th Cir. 2003), cert. denied, 541 U.S. 1085 (2004) (“Diffuse runoff, such as 

rainwater that is not channeled through a point source, is considered nonpoint source pollution 

and is not subject to federal regulation.”).71

70 Despite the definitions already in EPA’s regulations, the 2013 TDD at 6-12 states that 

“[l]eachate, which includes contaminated stormwater, that has come into contact with 

combustion residual solids deposited in an impoundment or a landfill . . . .” To the extent this 

statement is inconsistent with EPA’s existing regulatory structure distinguishing between 

stormwater and leachate, it must be revised to be consistent with EPA’s existing regulatory 

structure.

71 See also Or. Natural Desert Ass’n v. U.S. Forest Serv., 550 F.3d 778, 785 (9th Cir. 2008) 

(explaining Congress chose not to regulate “generalized runoff”); Natural Res. Def. Council v. 

EPA, 915 F.2d 1314, 1316 (9th Cir. 1990) (explaining that runoff of pesticides from farmland is 

not a “point source”); Cordiano v. Metacon Gun Club, Inc., 575 F.3d 199, 220 (2d Cir. 2009) 

(“Nonpoint source pollution is, generally, runoff: salt from roads, agricultural chemicals from 

farmlands, oil from parking lots, and other substances washed by rain, in diffuse patterns, over 

the land and into navigable waters”) (quoting United States v. Plaza Health Lab., 3 F.3d, 643, 

652 (2d Cir. 1993)).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 147

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

2. Seepage that Is Not Channeled or Discharged to a Surface Water Cannot Be Regulated 

Leachate Under the ELG Rule

If stormwater has to be channeled before qualifying as a point source discharge, so must 

“seepage” and “leakage.” Another problem with the proposed definition of “leachate” is that the 

language in the proposed text (“seepage, leak or leakage, which are generally used in reference 

to leachate from an impoundment”) might imply that all such seepage and leakage would qualify 

as “combustion residual leachate.”
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As with stormwater, here again the language of the proposed regulatory text sweeps too 

broadly. Seepage or leakage can be regulated as combustion residual leachate subject to this 

rulemaking only if the water is a “point source.” And that means only if it is channeled and 

discharged to a “water of the United States.”

As with stormwater, discussed above, EPA is authorized to regulate “discharges” from a “point 

source.” A point source is a discernible, confined, and discrete conveyance (33 U.S.C. 

§ 1362(14)), which generally means a channel or conduit (though it also includes wells, 

containers, rolling stock, concentrated animal feeding operations, and vessels). See Sierra Club 

v. Abston Constr. Co., 620 F.2d 41, 45 (5th Cir. 1980) (a “point source” is the “conveyance” that 

constitutes “the means by which pollutants are ultimately deposited into a navigable body of 

water) (emphasis added); see also Plaza Health Lab., Inc., 3 F.3d at 646 (point sources are 

“physical structures and instrumentalities that systematically act as a means of conveying 

pollutants from an industrial source to navigable waterways,” such as a pipe); Hudson 

Riverkeeper Fund, 917 F. Supp. at 257 (dismissing a CWA claim that rainfall touching an 

industrial building was a point source because it eventually flowed into a nearby river). See

Comments of the Utility Water Act Group on Questionnaire for Steam Electric Power 

Generating Effluent Guidelines, Doc. No. EPA-HQ-OW-2009-0819-0052 (April 8, 2010) at 58.

In short, “seeps” and “leakage” from landfills and surface impoundments cannot be regulated as 

combustion residual leachate under this rulemaking unless the water is collected or channelized 

and then discharged via a point source to surface water that constitutes a water of the United 

States. While seepage that is not collected or channeled would be subject to the groundwater 

monitoring and corrective action requirements under EPA’s proposed CCR rulemaking, the ELG 

regulations apply only when the seepage is channeled and released through a point source to a 

surface water that constitutes a water of the United States. Therefore, it is important for EPA 

either (1) to clarify in the final rule “seepage” and “leakage” means only seepage and leakage 

that is collected and then discharged via a point source to a water of the United States or (2) to 

amend the regulatory text to ensure that these conditions attach to the terms “seepage, leak, and 

leakage” in the definition.72

72 Any contrary interpretation – i.e., that uncollected seepage or drainage constitutes combustion 

residual leachate – is not only inconsistent with the plain language of the statute. Also, it would 

result in the impractical obligation of compelling affected facilities to incur hundreds of millions 

of dollars to install systems to collect such water. This would effectively require removing the 

combustion residue from the unit and retrofitting the unit with a liner and collection pipe. The 

costs of such a requirement – which have not been calculated by EPA in this rulemaking – would 

be enormous. Based on member input, the average cost for installing leachate collection systems 

for 13 different ash ponds was about $3,600,000, an average of about $275,000 per 

installation. The actual cost at one plant for three ash ponds was $1.6 million, or over $500,000 

per pond. Other plants owned by the same company had systems installed that cost in the mid-

$100,000 range (meaning, again, about $500,000 per pond). But these were unusually low costs, 

because they did not include engineering and design costs or alarms, controls, and buildings for 

controls that would ordinarily be included. A cost of $500,000 might be achievable for a small, 
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one-acre treatment pond. But a larger, 100+ acre deep disposal pond would cost upwards of $10 

million. Large as these costs are, they could be much worse if EPA applied an 

“anticircumvention” provision that required the leachate to be monitored and treated before reuse 

or recycling.

Comment Response: 

The definition of a point source is outside the scope of the final rulemaking. The definition of 

what is the wastestream “combustion residual leachate” is not tied to the definition of what is a 

point source. See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 148

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

C. “Combustion Residual Leachate” Should Not Include Water That May Contact CCR 

That Is Beneficially Used

EPA should clarify that the term “combustion residual leachate” does not include water that has 

come into contact with CCR that has been beneficially used and has not been disposed of or 

otherwise managed in a CCR landfill or surface impoundment.

It is important to encourage the beneficial use of CCR. For example, landfills and 

impoundments are sometimes constructed using structural fill and embankments using 

CCR. Operators of a landfill may use CCR for daily cover and as part of the final cover material 

when the landfill is closed. CCR also can be used as road base for service roads to landfills and 

for other roads as well.

These uses of CCR are not to “contain” residuals and therefore do not fall within the proposed 

definition. But EPA should clarify that this is so. The final ELG rule should say clearly that the 

term “combustion residual leachate” does not include water that may come into incidental 

contact with CCR used in beneficial use applications.

D. Regulation of “Combustion Residual Leachate” Should Not Interfere with Beneficial 

Reuse Activities

Either in the definition of “combustion residual leachate” or in the preamble to the final rule, 

EPA should be careful to limit the interpretation of the term so as not to have the effluent 

standards apply to unintended activities. For example, the limits on “leachate” should not apply 
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to pond dewatering, which might include collecting and pumping out water from existing coal 

combustion residuals in old impoundments, before capping the site. Likewise the limits should 

not apply to intercepting a contaminated groundwater plume some distance from an 

impoundment so the groundwater can be treated and discharged.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

The final rule regulates the discharges from dewatering an impoundment as “legacy wastewater” 

subject to the BAT legacy wastewater requirements promulgated in the final rule. For example, if 

a plant dewaters an impoundment used to treat fly ash transport water, the existing fly ash 

transport water “legacy wastewater” BAT limitations would be applied to the discharge during 

dewatering.

In this rule, EPA is not specifying what would happen if groundwater were contaminated and the 

site was being cleaned up. The definitions of the rule apply to discharges requiring an NPDES 

permit and indirect dischargers (pretreatment standards).

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definition for this wastestream must be revised to clarify that: (1) stormwater runoff if not 

included, (2) leachate does not include any liquid unless it is collected or channelized and 

subsequently discharged via a point source, and (3) that this definition does not include leachate 

from offsite landfills that are not owned or operated by the permittee.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Regarding item (3) provided in the comment above, see response to DCN EPA-HQ-OW-2009-

0819-4305-A3, Excerpt Number 103. The definition of what is the wastestream combustion 

residual leachate is not tied to the definition of what is a point source.
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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: 30

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA also needs to revise the definition of combustion residual leachate to (1) exclude 

stormwater runoff, (2) clarify that “seeps” or “leaks” from surface impoundments which are not 

collected or channelized and are not subsequently discharged via a point source are not included, 

and (3) clarify that leachate from offsite landfills that are not operated or owned by the permittee 

are not included.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 14.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 103

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Proposed Definition of Combustion Residual Leachate is Inconsistent and Must Be

Modified to Exclude Storm Water Runoff, Seepage, and Leaks that Do Not Constitute a 

Point Source Discharge to a Water of the U.S.

Duke Energy recommends that EPA make several changes to the proposed definition for 

“combustion residual leachate” because the definition(s) EPA proposes is inconsistent, overly 

broad and does not represent EPA’s intent based on the information presented in the Proposed 

Rule and supporting technical documents.

First, EPA provides three different variations for the definition of combustion residual leachate. 

At least two different definitions are listed in the Proposed Rule and a third version is listed in 

the Technical Development Document (TDD). Appendix A: Definitions, Acronyms, and 

Abbreviations Used in This Notice69 in the Proposed Rule states that the definition for 

combustion residual leachate “Includes landfills and surface impoundments located on nonadjoining property when under the operational control of the permitted facility.” The TDD, 

Section 2.2, pages 2-5 and 2-6 asserts that “The term combustion residual leachate means 
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leachate from onsite landfills or surface impoundments....”70 In §423.11 (r) 71 of the Proposed 

Rule, the definition of combustion residual leachate does not make it clear whether it applies to 

leachate from both onsite and offsite landfills and impoundments.

Duke Energy asserts that the definition for combustion residual leachate should not apply to 

offsite landfills where the landfill is not owned or operated by the utility. These landfills would 

already be regulated by ELGs under the Landfill Point Source Category72.

Second, EPA is proposing an overly broad definition of combustion residual leachate which 

could be inappropriately interpreted to include storm water runoff from landfills and seepage 

from landfills and surface impoundments that do not constitute a point source discharge to a 

water of the United States.

EPA proposes to define combustion residual leachate as follows:

Leachate includes “liquid, including any suspended or dissolved constituents in the liquid that 

has percolated through or drained from waste or other materials emplaced in a landfill, or that 

pass through the containment structure (e.g., bottom, dikes, berms) of a surface impoundment. 

Leachate also includes the terms seepage, drains, leak, and leakage, which are generally used in 

reference to leachate from an impoundment.73

The phrase “drained from waste” in the above definition could be interpreted as capturing 

rainwater that runs off of a landfill, when such runoff is in fact defined as storm water under 

EPA’s existing regulations74. Runoff from a landfill differs from water that percolates through 

waste placed in a landfill or surface impoundment. Therefore, EPA must clarify in the final rule 

that the definition of “combustion residual leachate” does not include stormwater runoff from 

landfills, because this stormwater is already regulated under the CWA Industrial Storm Water 

permit program.

In addition, stormwater runoff from a landfill is not a “discharge” if it is not channelized. 

Stormwater becomes a discharge only if it goes through some kind of conveyance, such as a pipe 

or ditch, and only then would it require an NPDES permit.

It should also be noted, that again, there is an inconsistency between the proposed regulatory 

language and the Technical Development Document75 with regards to this definition. The TDD 

states that “leachate, which includes contaminated storm water, that has come into contact with 

combustion residual solids deposited in an impoundment or a landfill...” To the extent this 

statement is inconsistent with EPA’s existing regulatory structure distinguishing between 

stormwater and leachate, it must be revised to be consistent with EPA’s existing regulatory 

structure.

Another problem with the proposed definition of “leachate” is that the language in the proposed 

text referencing “seepage, leak or leakage, which are generally used in reference to leachate from 

an impoundment” implies that all such seepage and leakage would qualify as combustion 

residual leachate. This language is overly broad and does not represent EPA’s assumed intent 

based on the information presented in the Proposed Rule and supporting technical documents. 
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“Seeps” and “leakage” from landfills and surface impoundments cannot be regulated as 

combustion residual leachate under this rulemaking unless the water is collected or channelized, 

and then discharged via a point source to surface water that constitutes a water of the U.S. Any 

seepage that is not collected or channeled would be subject to the groundwater monitoring 

requirements under EPA’s proposed Coal Combustion Residual (CCR) rule. Therefore, EPA 

must clarify in the final rule that the definition of “combustion residual leachate” only includes 

leachate that is collected or channelized and subsequently discharged to surface water classified 

as a water of the United States.

Duke Energy strongly recommends that these inconsistencies and clarifications be included in 

the final rule through a revised definition and the explanatory text in the preamble and provides a 

suggested revised definition for combustion residual leachate:

The term combustion residual leachate means leachate from landfills or surface 

impoundments containing residuals from the combustion of fossil or fossilderived fuel. Leachate includes liquid, including any suspended or dissolved 

constituents in the liquid that has percolated through the CCR or other materials 

placed in a landfill, subsequently captured in a leachate collection system or 

channelized and then discharged via a point source. This definition excludes 

stormwater runoff.

Clarify that the Term “Combustion Residual Leachate” Does Not Apply Where CCR is 

Beneficially Used

Duke Energy recommends EPA confirm in the final ELG Rule that the definition of “combustion 

residual leachate” does not include water that has come into contact with CCR in all applications 

where CCR has been beneficially used. The proposed definition of combustion residual leachate 

includes only leachate from “landfills or surface impoundments containing residuals from the 

combustion of fossil or fossil- derived fuels."76 This definition embraces only leachate from CCR 

that was placed in the unit for containment for either disposal or storage. CCR that is beneficially 

used is not placed in a surface impoundment or landfill for containment, but rather it is used to 

serve a functional purpose as a replacement for natural resources and virgin materials.

While the proposed definition of “combustion residual leachate” should not and does not 

encompass water that comes into contact with CCR that is beneficially used, confirmation of this 

point in the final ELG Rule is important to avoid any unnecessary confusion that would run 

counter to EPA’s goal of promoting the beneficial use of CCR. EPA acknowledged in the CCR 

Proposal, that “utilities and other commercial sectors are continually exploring means for using 

CCR for beneficial uses, as opposed to managing these materials in landfills or surface 

impoundments.”77 The beneficial applications include the beneficial use of CCR in the 

construction and operation of impoundments and landfills and the wide array of other beneficial 

uses, including State Departments of Transportation use in the construction of roadbed and 

embankments. These types of CCR beneficial use activities are outside the scope of the ELG 

Proposal. Therefore, any water that may come in contact with, and/or pass through, CCR that has 

been beneficially used should not be included in the proposed definition of combustion residual 

leachate.
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Duke Energy recommends that the final ELG Rule clarify that the term “combustion residual 

leachate” refers only to leachate from units that manage or dispose of CCR and does not 

encompass water that may come into contact with CCR that is beneficially used.

69 Id. at 34532

70 TDD at Section 2.2, pages 2-5 and 2-6 [EPA-921-R-13-002]

71 78 Fed. Reg. at 34533

72 40 CFR Part 445

73 78 Fed. Reg. at 34533 (proposed 40 C.F.R. § 423.11(r))

74 Additional information on EPA’s existing regulatory treatment of stormwater is included in 

UWAG’s comments (Sept. 20, 2013)

75 TCC Section 6.3, page 6-12

76 78 Fed. Reg. at 34533 as proposed to be codified at 40 C.F.R. § 423.11(r)

77 75 Fed. Reg. at 35153

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Also, regarding the commenter’s assertion that “the definition for combustion residual leachate 

should not apply to offsite landfills where the landfill is not owned or operated by the utility,” the 

rule applies to “owners and operators.” EPA may look to whether one entity exercises control 

over another to determine in a specific case that one entity is an owner or operator of another 

facility. See e.g., Waterkeeper Alliance Inc. v. EPA, 399 F.3d 486 (2nd Cir. 2005)(discharges 

“under the control of” a CAFO can be regulated), 

The provisions of this part are applicable to discharges resulting from the operation of a 

generating unit by an establishment primarily engaged in the generation of electricity for 

distribution and sale which results primarily from a process utilizing fossil-type fuel (coal, oil, or 

gas) or nuclear fuel in conjunction with a thermal cycle employing the steam water system as the 

thermodynamic medium.

Commenter Name: Leonard F. Hopkins

Commenter Affiliation: Southern Illinois Power Cooperative (SIPC)
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Document Control Number: EPA-HQ-OW-2009-0819-4309-A1

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

3) EPA should designate that stormwater or process water that comes in contact with “de 

minimis” levels of coal combustion residual is not treated as CCR leachate.

Comment Response: 

The final rule does not designate “de minimis” levels in the definition for combustion residual 

leachate. EPA notes the commenter did not provide data to support its assertion. Note that 

stormwater that comes into contact with combustion residuals, for example an open pile of coal 

ash, may create a contaminated stormwater. This wastewater is not covered in the combustion 

residual leachate definition. See preamble Appendix A.

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: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Definition of "Leachate" from Landfills Does Not Include Stormwater Runoff from 

Covered Landfills

Rainfall that runs off a landfill should not be classified as "combustion residual leachate."

According to EPA' s proposed definition, leachate includes "liquid, including any suspended or 

dissolved constituents in the liquid that has percolated through or drained from waste or other 

materials emplaced in a landfill, or that pass through the containment structure (e.g., bottom, 

dikes, berms) of a surface impoundment. Leachate also includes the terms seepage, drains, leak, 

and leakage, which are generally used in reference to leachate from an impoundment."

This definition should not be read to encompass stormwater runoff , which is entirely different. 

EPA recognized the distinction in section 4.3.5 of the TDD, which distinguishes between 

leachate and stormwater by including a diagram, Figure 4-10. This figure shows leachate 

percolating through the landfill and collecting in a leachate collection system. Separately it 

shows rain falling on the landfill surface and runoff from the landfill running into a runoff 

drainage ditch. The implication is that stormwater runoff is not "leachate."
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Some confusion may be caused, however, by the words "drained from waste" in the definition 

and from TDD Sections 4.3.5 and 6.3, where EPA says that leachate includes stormwater runoff 

from a landfill:

The two sources of landfill leachate are precipitation that percolates through the waste deposited 

in the landfill and the liquids produced from the combustion residual placed in the landfill. In 

addition to leachate, stormwater that contacts the landfill wastes and flows over the landfill may 

be contaminated. Leachate and contaminated stormwater contain heavy metals and other 

contaminants through the contact with the combustion residuals.

EPA should maintain the distinction between "leachate" and stormwater runoff ' to be consistent 

with its existing regulatory regimes for runoff from landfills. Runoff from a landfill is 

stormwater, different from water that percolates through waste placed in a landfill or surface 

impoundment , which is "leachate." EPA must clarify in the final rule that "combustion residual 

leachate" does not include stormwater from landfills .

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 115

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Proposed Definition of “Leachate” Must be Modified to Exclude Runoff From 

Landfills and Seepage and Leaks that Do Not Constitute a Point Source Discharge

The proposed definition of the term “combustion residual leachate” is overly broad because, on 

its face, it could be inappropriately interpreted to include stormwater runoff from landfills and 

also could be interpreted to capture seepage from landfills and surface impoundments that does 

not constitute a point source discharge to a water of the United States.

EPA should make clear in the final rule, either through amending the definition or including 

explanatory text in the preamble, that such runoff and seepage are not combustion residual 

leachate subject to the ELGs.

Leachate Does Not Include Stormwater Runoff From Landfills

EPA proposes to define combustion residual leachate as follows:
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Leachate includes liquid, including any suspended or dissolved constituents in the liquid that has 

percolated through or drained from waste or other materials emplaced in a landfill, or that pass 

through the containment structure (e.g., bottom, dikes, berms) of a surface impoundment. 

Leachate also includes the terms seepage, leak, and leakage, which are generally used in 

reference to leachate from an impoundment.

78 Fed. Reg. at 34,533, col. 3 (proposed 40 C.F.R. § 423.11(r)).

The phrase “drained from waste” in the above definition could be interpreted as capturing 

rainwater that runs off of a landfill, when such runoff is in fact defined as stormwater under 

EPA’s existing regulations. We assume that EPA is not attempting to alter this important 

regulatory distinction in this rulemaking. In fact, EPA recognizes this important difference in 

section 4.3.5 of the 2013 TDD where it distinguishes between leachate and stormwater by 

including a diagram, Figure 4-10:

(The same diagram was “Figure 3” in the Federalism/UMRA Supplemental Information –

Package #2 that EPA distributed. EPA-HQ-OW-2009-0819-0909, p. 10.) Figure 4-10 shows 

leachate percolating through the landfill and collecting in a leachate collection system. 

Separately it shows rain falling on the landfill surface and runoff from the landfill running into a 

runoff drainage ditch. The distinction here is that runoff from a landfill is not “leachate.”

This point is consistent with EPA’s existing regulatory regimes for runoff from landfills of 

various types where the runoff is regulated as stormwater. For example, the definitions of 

“stormwater” under 40 C.F.R. § 122.26 is defined to mean “storm water runoff, snow melt 
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runoff, and surface runoff and drainage.” Id. at § 122.26(b)(13) (emphasis added). This 

definition captures any stormwater runoff from a landfill, including those that are capped and 

those that are still in operation. Further, contaminated stormwater that runs off of a landfill (e.g., 

from an active portion of a landfill) is captured by the term “[s]torm water discharge associated 

with industrial activity” including, among other things, activities involving “[l]andfills . . . that 

receive or have received any industrial waste” and “[s]team electric power generating facilities, 

including coal handing sites.” Id. at § 122.26(b)(14)(v) & (vii)).

The point is that runoff from a landfill is stormwater, which differs from water that percolates 

through waste placed in a landfill or surface impoundment, which is leachate. EPA should clarify 

in the final rule that “combustion residual leachate” does not include stormwater runoff from 

landfills.41

In addition to the above, stormwater runoff from a landfill is not a “discharge” (and hence does 

not need a permit) if it is not channelized. Stormwater becomes a discharge only if it goes 

through some kind of “conveyance” (which is understood to mean a pipe or ditch). So if the 

stormwater is not channelized, it cannot be a discharge requiring an NPDES permit. See Hudson 

Riverkeeper Fund v. Harbor at Hastings Assocs., 917 F. Supp. 251, 257 (S.D.N.Y. 1996) 

(dismissing a CWA claim that rainfall touching an industrial building was a point source because 

it eventually flowed into a nearby river). As the Ninth Circuit noted, “[s]tormwater that is not 

collected or channeled and then discharged, but rather runs off and dissipates in a natural and 

unimpeded manner, is not a discharge from a point source as defined by § 502(14).” Nw. Envtl. 

Def. Ctr. v. Brown, 617 F.3d 1063, 1170 (9th Cir. 2011) (emphasis added). Courts repeatedly 

have declined to classify pollution coming from “runoff caused primarily by rainfall around 

activities that employ or create pollutants” as a “point source.” Or. Natural Desert Ass’n v. 

Dombeck, 172 F.3d 1092, 1098 (9th Cir. 1998).

Similarly, courts define pollution as a “non-point source” when it is caused by diffuse sources 

such as runoff. “Broad though [the] definition [of point source] may be, we are of [the] opinion 

that it does not include unchannelled and uncollected surface waters.” Appalachian Power Co. v. 

Train, 545 F.2d 1351, 1373 (4th Cir. 1976); see also Envtl. Def. Ctr., Inc. v. EPA, 344 F.3d 832, 

841 n.8 (9th Cir. 2003), cert. denied, 541 U.S. 1085 (2004) (“Diffuse runoff, such as rainwater 

that is not channeled through a point source, is considered nonpoint source pollution and is not 

subject to federal regulation.”).42

“Seepage” that Is Not Channeled or Discharged to a Surface Water Cannot Be Regulated 

Leachate Under the ELG Rule

Another problem with the proposed definition of “leachate” is that the language in the proposed 

text referencing “seepage, leak or leakage, which are generally used in reference to leachate from 

an impoundment” implies that all such seepage and leakage would qualify as “combustion 

residual leachate.” Here too, the plain language of the proposed regulatory text sweeps too 

broadly. Such seepage or leakage can be regulated as combustion residual leachate subject to this 

rulemaking only if the water is a “point source.” And that means only if it is channeled and 

discharged to a “water of the United States.”
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As with stormwater, discussed above, EPA is authorized to regulate “discharges” from a “point 

source.” A point source is a discernible, confined, and discrete conveyance (33 U.S.C.§ 

1362(14)), which generally means a channel or conduit (though it also includes wells, containers, 

rolling stock, concentrated animal feeding operations, and vessels). See Sierra Club v. Abston 

Constr. Co., 620 F.2d 41, 45 (5th Cir. 1980) (a “point source” is the “conveyance” that 

constitutes “the means by which pollutants are ultimately deposited into a navigable body of 

water) (emphasis added); see also Plaza Health Lab., Inc., 3 F.3d at 646 (point sources are 

“physical structures and instrumentalities that systematically act as a means of conveying 

pollutants from an industrial source to navigable waterways,” such as a pipe); Hudson

Riverkeeper Fund, 917 F. Supp. at 257 (dismissing a CWA claim that rainfall touching an 

industrial building was a point source because it eventually flowed into a nearby river). See 

Comments of the Utility Water Act Group on Questionnaire for Steam Electric 

Power Generating Effluent Guidelines, Doc. No. EPA-HQ-OW-2009-0819-0052 (April 8, 2010) 

at 58.

In short, “seeps” and “leakage” from landfills and surface impoundments cannot be regulated as 

combustion residual leachate under this rulemaking unless the water is collected or channelized 

and then discharged via a point source to surface water that constitutes a water of the United 

States. While seepage that is not collected or channeled would be subject to the groundwater 

monitoring and any applicable corrective action requirements under EPA’s proposed CCR 

rulemaking, the ELG regulations apply only when the seepage is channeled and released via a 

point source to a surface water that constitutes a water of the United States.

41 Despite the above, we note that text in the 2013 TDD Section 6.3 states that “[l]eachate, which 

includes contaminated storm water, that has come into contact with combustion residual solids 

deposited in an impoundment or a landfill . . . .” To the extent this statement is inconsistent with 

EPA’s existing regulatory structure distinguishing between stormwater and leachate, it must be 

revised to be consistent with EPA’s existing regulatory structure.

42 See also Or. Natural Desert Ass’n v. U.S. Forest Serv., 550 F.3d 778, 785 (9th Cir. 2008) 

(explaining Congress chose not to regulate “generalized runoff”); Natural Res. Def. Council v. 

EPA, 915 F.2d 1314, 1316 (9th Cir. 1990) (explaining that runoff of pesticides from farmland is 

not a “point source”); Cordiano v. Metacon Gun Club, 575 F.3d 199, 220 (2d Cir. 2009) 

(“‘Nonpoint source pollution is, generally, runoff: salt from roads, agricultural chemicals from 

farmlands, oil from parking lots, and other substances washed by rain, in diffuse patterns, over 

the land and into navigable waters.’”) (quoting United States v. Plaza Health Lab., 3 F.3d, 643, 

652 (2d Cir. 1993)).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.
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Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 43

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

b. Clarification on the definitions of leachate, contact storm water runoff and 

noncontact storm water runoff is needed.

EPA defines “leachate” as “the liquid that drains or leaches from a landfill or surface 

impoundment.” The agency notes two sources of leachate – precipitation that percolates through 

the wastes disposed in a landfill or impoundment and the storm water that enters the 

impoundment or contacts and flows over the landfill (78 FR at 34450). According to EPA, 

“leachate and contaminated storm water contain heavy metals and other contaminants through 

contact with the combustion residuals” (Id.). The agency also notes that leachate and storm water 

may be treated in separate impoundments or combined together.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Jacob G. Smeltz

Commenter Affiliation: Electric Power Generation Association (EPGA)

Document Control Number: EPA-HQ-OW-2009-0819-4450-A1

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should clarify in the final rule (1) the term “combustion residual leachate” does not 

encompass water that may come into contact with CCR that is beneficially used, and (2) that 

combustion residual leachate generated from additional landfill capacity developed for the sole 

purpose of managing CCR displaced from impoundments as a result of the final ELG 

requirements is not leachate from a “new source” and therefore is not subject to the new source 

pretreatment standards for combustion residual leachate.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.
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See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149 in Comment Code 

6.g.vii regarding new sources with respect to combustion residual leachate.

Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We also support UWAGs definition of “leachate” that excludes stormwater runoff from covered 

landfills and nonpoint source seepage.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Jeffrey A. McNelly

Commenter Affiliation: Anthracite Region Independent Power Producers Association 

(ARIPPA)

Document Control Number: EPA-HQ-OW-2009-0819-4453-A1

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The storm water runoff that comes in contact with CCR’s should not be considered leachate and 

as such does not require treatment. and/or allowed to be comingled.

If the effluent limitation guidelines of combustion residual leachate are applicable to storm water 

runoff that has come in contact with CCR’s, has EPA considered the need to build storm water 

holding impoundments of adequate size (to be defined) to serve as flow equalization 

impoundment in order to control the hydraulic loading on the treatment processes being used to 

treat the storm water runoff considered leachate?

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. The rule does not 

prohibit co-mingling but requires each wastestream to meet the applicable technology-based 
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effluent limitations and standards in this rule. Permitting authorities may use the “building 

block” approach or combined wastestream formula to do this. Stormwater is not regulated in this 

rule, but is regulated as “stormwater discharge associated with industrial activity” 40 CFR 

122.26(b)(14).

Commenter Name: Jeffrey A. McNelly

Commenter Affiliation: Anthracite Region Independent Power Producers Association 

(ARIPPA)

Document Control Number: EPA-HQ-OW-2009-0819-4453-A1

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

There needs to be clarification relative to the term “Coal Combustion Residual Leachate” such 

that it does not include storm water runoff.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Nysa Hogue

Commenter Affiliation: Indianapolis Power & Light Company (IPL)

Document Control Number: EPA-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Combustion Residual Leachate (CRL) BAT:

o The proposed rule is unclear if "contaminated stormwater" is subject to the proposed 

combustion residual leachate BPJ and BAT limits. Please clarify if the following are 

subject to the aforementioned limits: 

o stormwater runoff which contacts combustion residuals and then runs off a 

landfill;

o surface impoundment seepage which is contained and does not discharge to 

regulated waters;

o general plant stormwater discharged and treated by a surface impoundment (SI); 

and
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o closed surface impoundments (with and without leachate collection systems).

Based on the proposed definition of CRL included in Appendix A of the rule, stormwater does 

not appear to be regulated under the aforementioned limits.

IPL's consultant, CH2M HILL, contacted EPA regarding this question. On July 2, 2012, Mr. 

Ron Jordan verbally communicated to CH2M HILL that the CRL requirements do not apply to 

stormwater runoff, and that the runoff may be addressed as a low-volume wastewater. IPL 

appreciates this clarification, and asks that the ELG language be made consistent with this 

clarification that stormwater runoff is not to be regulated with CRL leachate and that EPA also 

clarify that stormwarter runoff even if exposed to outdoor CCR storage piles is not considered a 

LVW but should be regulated under facilities' NPDES stormwater permit limits.

Comment Response: 

Stormwater runoff is not included in the definition of combustion residual leachate; therefore, 

such discharges are not subject to the final limitations and standards for combustion residual 

leachate. Stormwater is not regulated in this rule, but is regulated as “stormwater discharge 

associated with industrial activity” 40 CFR 122.26(b)(14). General plant stormwater that is 

collected and treated in an impoundment and then discharged from the impoundment is not 

subject to the combustion residual leachate limitations and standards.

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Lastly, the final ELGs do not differentiate requirements based on the “type” of surface 

impoundment. In the event that a closed surface impoundment discharges wastewater meeting 

the definition of combustion residual leachate, it is subject to the final requirements.

Commenter Name: Nysa Hogue

Commenter Affiliation: Indianapolis Power & Light Company (IPL)

Document Control Number: EPA-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Based on the proposed CRL definition, it appears that stormwater runoff co-mingled with 

exposed CCR material (such as outdoor storage piles and incidental vehicular material tracking) 

is not subject to the proposed CRL limits. In addition, it would appear that these stormwater 

discharges would not be regulated under 40 CFR 423 but under the stormwater non-numeric 

effluent limitations established under our facilities NPDES permits. Please clarify.

Comment Response: 
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Stormwater runoff co-mingled with exposed CCR materials such as outdoor storage piles and 

incidental vehicular material tracking, is not subject to the combustion residual leachate 

limitations and standards. The stormwater is be regulated as “stormwater discharge associated 

with industrial activity” 40 CFR 122.26(b)(14).

Regarding stormwater discharges, see response to DCN EPA-HQ-OW-2009-0819-4652-A1, 

Excerpt Number 17.

Commenter Name: Nysa Hogue

Commenter Affiliation: Indianapolis Power & Light Company (IPL)

Document Control Number: EPA-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should clarify that the term "combustion residual leachate" does not include water that has 

come into contact with CCR that has been beneficially used and has not been disposed of or 

otherwise managed in a CCR landfill or surface impoundment. In the case of IPL, we are 

approved to use CCR for intermediate landfill cover and are also approved to use CCR for a base 

layer associated with future expansion of our existing on-site landfill. In addition, IPL uses CCR 

as road base for service roads to landfills and for other roads as well. These uses of CCR are not 

used to "contain" residuals and therefore do not fall within the proposed definition. Please 

clarify.

Comment Response: 

The final rule defines combustion residual leachate as follows: “The term combustion residual 

leachate means leachate from landfills or surface impoundments containing combustion 

residuals. Leachate is composed of liquid, including any suspended or dissolved constituents in 

the liquid, that has percolated through waste or other materials emplaced in a landfill, or that 

passes through the surface impoundment’s containment structure (e.g., bottom, dikes, berms). 

Combustion residual leachate includes seepage and/or leakage from a combustion residual 

landfill or impoundment unit. Combustion residual leachate includes wastewater from landfills 

and surface impoundments located on non-adjoining property when under the operational control 

of the permitted facility.”

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. There, EPA 

explains that EPA generally agrees with the comments that the combustion residual leachate 

definition does not “include water that has come into contact with CCR that has been 

beneficially used and which has not been disposed or otherwise managed in a CCR landfill or 

surface impoundment.” However, beneficial uses such as road base differ emplacement of CCR 
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in a landfill, even if they also are acting as intermediate landfill cover. See the definition of 

combustion residual leachate.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 24

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA cannot and should not regulate groundwater through its proposed regulation of Combustion 

Residual Leachate.

EPA is explicit that the definition of combustion residual leachate includes liquids “that pass 

through the containment structure”. If leachate has passed through the containment structure, 

which is assumed to have passed through the containment structure’s liner, then the leachate will 

infiltrate to groundwater. While this could be an eventual pathway to waters of the U.S. it is not a 

point source discharge to surface waters and not subject to NPDES regulation. This language in 

the combustion residual leachate definition introduces uncertainty about what EPA is intending 

to regulate and to what liquids the ELG applies to both now and in the future.

Comment Response: 

The definition of point source (and indirect discharger/industrial user) and who needs an NPDES 

permit is a basic issue that is outside the scope of this rule. This rule specifies the technologybased limits and standards and pretreatment standards that apply when those underlying 

requirements are triggered. Determining who is a point source is generally a fact-specific 

determination made by the permitting authority. The definition of what is the wastestream 

combustion residual leachate is not tied to the definition of what is a point source.

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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EPA cannot regulate “Combustion Residual Leachate” unless the leachate from landfills and 

impoundments is collected and directed to a point source discharge to waters of the U.S. The 

definitions and discussion in the final rule should make this clear.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 34

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definitions of Combustion Residual Leachate should be consistent in the ELG Rule and 

CCR Rule.

EPA is charged with ensuring that the steam electric ELG proposal is coordinated and consistent 

with other existing and proposed regulation. In order to properly coordinate this rulemaking with 

the coal combustion residual (CCR) rulemaking, EPA should change the definition of 

combustion residual leachate for this rulemaking to be “liquid that has percolated through 

materials placed in a landfill or has drained from a surface impoundment containing waste 

materials, that is collected and actively directed to discharge into waters of the U.S.” The rule 

should be clear that impacts to ground water, even leaks and seeps, are not intended to be 

regulated by the rule.

Comment Response: 

EPA’s CCR Rule does not include a definition for combustion residual leachate. See response to 

DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17 for a discussion regarding the use 

of the terms seeps and leaks in the final rule definition for combustion residual leachate. Also, 

see responses to Comment Code 27.e regarding the role of the ELGs and the role of the CCR 

rule.

Commenter Name: John C. Pozzo

Commenter Affiliation: Ameren Energy Resources Company

Document Control Number: EPA-HQ-OW-2009-0819-4459-A1

Comment Excerpt Number: 8
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The 2013 Technical Development Document and the Preamble to these rules contain discussions 

of leachate which differ, and may lead to confusion by State regulators. We ask that this 

definition be clarified by two additions. First, it should plainly state that storm water which falls 

upon or runs off a covered or capped ash impoundment or landfill, such that it does not contact 

or flow through ash, should not be classified or regulated as leachate. Second, it should clarify 

that leachate associated with ash impoundments or landfills are not subject to these regulations, 

unless it is discharged via a point source conveyance, to waters of the US.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. The definitions 

in the final TDD and preamble are consistent.

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: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

CCR Leachate: The proposed definition of this waste stream should be revised to clarify that 

storm water runoff is not included nor is any liquid that is not discharged via a point source.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

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: 32

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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EPA proposes to define combustion residual leachate as:

Leachate includes liquid, including any suspended or dissolved constituents in the liquid that has 

percolated through or drained from waste or other materials emplaced in a landfill, or that pass 

through the containment structure (e.g. bottom, dikes, berms) or a surface impoundment. 

Leachate also includes the terms seepage, drains, leaks and leakage, which are generally used in 

reference to leachate from an impoundment.6

This definition may be interpreted to include rainwater that runs off of a landfill, which is 

defined as storm water under existing EPA regulations. Further, if this storm water is not 

collected to form a point source discharge, it would not require an NPDES permit.

It is further recommended that the definition for “combustion residual leachate” be clarified so as 

to exclude storm water runoff and seepages that do not constitute a point source discharge 

consistent with the transcript of EPA statements during the August 20, 2013 Webcast.

6

78 Fed. Reg. at 34533

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

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: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

 "Leachate" should not include runoff from landfills or seepage and leaks that are not 

point source discharges to a water of the United States. The proposed definition of 

"combustion residual leachate" is too broad because, on its face, it could be 

inappropriately interpreted to include stormwater runoff from landfills. It also could be 

interpreted to capture seepage from landfills and surface impoundments that does not 

constitute a "point source" discharge to a water of the United States. USEPA should 

make clear in the final rule, either by amending the definition or by explaining in the 

preamble, that such runoff and seepage are not "combustion residual leachate" subject to 

the ELGs;
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 Leachate should not include stormwater runoff from landfills. USEPA includes the 

phrase "drained from waste" in the definition of combustion residual leachate which 

could be read to include rainwater that runs off a landfill, even though such runoff is 

defined as stormwater under the agency's regulations. USEPA should be careful not to 

alter this important regulatory distinction in this rulemaking. Moreover, stormwater 

runoff from a landfill is not a "discharge" (and hence does not need an NPDES permit) if 

it is not channelized. Stormwater becomes a discharge only if it goes through some kind 

of "conveyance" (which is understood to mean a pipe or ditch);

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

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: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

 Combustion residual leachate should not include water that may contact CCR that is 

beneficially used;

 Combustion residual leachate should not interfere with beneficial use activities. Either in 

the definition of "combustion residual leachate" or in the preamble to the final rule, 

USEPA should be careful to limit the interpretation of the term so as not to have the 

effluent standards apply to unintended activities. For example, the limits on "leachate" 

should not apply to pond dewatering, which might include collecting and pumping out 

water from existing coal combustion residuals in old impoundments, before capping the 

site;

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 148 regarding 

dewatering impoundments.

Commenter Name: James S. Alves

Commenter Affiliation: Florida Electric Power Coordinating Group
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Document Control Number: EPA-HQ-OW-2009-0819-4474-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Clarification re ELGs Applicability

The definition of “combustion residual leachate” as set forth in the proposed rule revisions (78 

Fed. Reg. 34533) is overbroad in that as drafted it encompasses liquids “that pass through the 

containment structure...of a surface impoundment” and specifically includes “seepage” and 

“leakage.” This language, standing alone, could potentially be construed as indicating that nonpoint source discharges of leachate through diffuse groundwater flow are regulated under the 

proposed rule revisions.

The FCG acknowledges that EPA’s preamble statement (78 Fed. Reg. 34450, 34454) tends to 

indicate that the phrase “combustion residual leachate” includes only those leachates that are 

captured in “collection systems” and thereafter released to surface waters via a point source 

discharge. Additionally, this understanding appears to be confirmed by EPA’s statements to the 

effect that the effluent limitation guidelines and standards apply only to direct and indirect (via 

POTWs) point source discharges to surface waters. (78 Fed. Reg. 34437).

Nonetheless, the proposed definition of combustion residual leachate as currently drafted is 

susceptible to being misinterpreted as applicable to non-point source seepage or leakage releases. 

Accordingly, the FCG requests that the “point source” clarifications which appear in the 

preamble statement be reflected in the final rule revision language.

Additionally, the FCG requests that EPA confirm that “combustion residual leachate” does not 

apply to stormwater from landfills or water that comes into contact with CCRs that have been 

beneficially used.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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“Combustion Residual Leachate” should exclude water that contacts beneficially used coal 

combustion residuals. We recommend that EPA confirm and clarify in the final ELG rule that 

the term “combustion residual leachate” does not include water that has come in contact with 

coal combustion residuals (“CCR”) that is or has been beneficially used. CCR that is 

beneficially used serves a functional purpose and often replaces other mined or virgin materials 

in the construction industry. In an effort to avoid the potential for additional stigma associated 

with the beneficial use of coal combustion products, EPA should specifically state that 

“combustion residual leachate” does not include water that may come into incidental contact 

with CCR when used in beneficial use applications.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 63

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

“Combustion Residual Leachate” Should Not Include Water that may Contact CCR that is 

Beneficially Used

We Energies recommends that EPA confirm and clarify in the final ELG rule that the term 

“combustion residual leachate” does not include water that has come in contact with CCR that is 

or has been beneficially used. The proposed ELG rule indicates that combustion residual 

leachate is “leachate from landfills or surface impoundments containing combustion residuals.” 

Id. at 34,532 col. 2. This includes “liquid, including any suspended or dissolved constituents in 

the liquid that has percolated through or drained from waste or other materials emplaced in a 

landfill.” Id.

Landfills that generate leachate subject to regulation in the ELG rule are defined as follows:

A disposal facility or part of a facility where solid waste, sludges, or other process residuals are 

placed in or on any natural or manmade formation in the earth for disposal and which is not a 

storage pile, a land treatment facility, a surface impoundment, an underground injection well, a 

salt dome or salt bed formation, an underground mine, a cave, or a corrective action 

management unit. Id. at 34,532 col. 3.

This definition of a CCR “landfill” differs than the definition of a “CCR landfill” in the proposed 

Coal Combustion Residuals Rule. See 75 Fed. Reg. 35,128, 35,130 col. 1 (June 21, 2010). The 
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proposed CCR Rule includes language that may define CCRs in sand and gravel pits, quarries, 

and “other large fill operations” as landfills. Id. at 35,133 col. 3. “Large fill operations” are not 

clearly defined in the proposed CCR Rule, and there is still some uncertainty as to what will be 

defined as a landfill versus a beneficial use in the future.

CCR that is beneficially used serves a functional purpose and often replaces other mined or 

virgin materials in the construction industry. Wisconsin regulates the beneficial use of industrial 

byproducts in NR 538, Wisconsin Administrative Code. NR 538 includes provisions for 

characterizing coal combustion products into five categories based on a combination of 

laboratory testing on total elemental analysis and ASTM water leach test criteria. This process 

has proven to work well in matching materials to appropriate use applications from an 

environmental perspective. NR 538.04 establishes location performance standards that prohibit 

impacts to wetlands, endangered or threatened species, surface water, groundwater, and other 

appropriate criteria. With respect to “large scale fill operations,” NR 538.18 establishes public 

participation requirements for projects involving 30,000 cubic yards of material (some 

exemptions apply). Similarly in NR 538.22, property owner notification is required for largesized beneficial use projects utilizing 10,000 cubic yards of industrial byproducts.

We Energies believes that EPA does not intend to regulate incidental contact water from CCRs 

used in beneficial use applications, including CCRs used in “large fill operations,” in the ELG 

rule. In an effort to avoid the potential for additional stigma associated with the beneficial use of 

coal combustion products, EPA should specifically state that “combustion residual leachate” 

does not include water that may come into incidental contact with CCR when used in beneficial 

use applications.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

For a discussion of the final CCR rule revised definition for CCR landfill, see docket number 

EPA–HQ–RCRA–2009–0640.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 85

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Combustion residual leachate should exclude water that contacts beneficially used coal 

combustion residuals to avoid the potential for additional stigma associated with the beneficial 

use of coal combustion residuals.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Vicki Card

Commenter Affiliation: Colorado Springs Utilities

Document Control Number: EPA-HQ-OW-2009-0819-4483-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

COMBUSTION RESIDUAL LEACHATE DEFINITION

The EPA’s Environmental Assessment for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category (Environmental 

Assessment / EPA-821-R- 13-003), states that “According to the documented case studies, lack 

of a liner [emphasis added] in surface impoundments and landfills is a significant factor in 

determining the extent of combustion wastewater impacts to ground water.”

The EPA's proposed definition of combustion residual leachate could unreasonably result in 

every concrete tank, impoundment, and landfill being subject to the ELG limits for discharges to 

groundwater - even those with appropriately designed liner and leachate collection systems, as 

no liner is completely impervious. Colorado Springs Utilities believes that the EPA must define 

an allowable seepage rate below which the ELG limits do not apply as the risk to underlying 

groundwater is negligible.

The following language is suggested:

(r) The term combustion residual leachate means leachate from landfills or surface 

impoundments containing residuals from the combustion of fossil or fossil-derived fuel. 

Leachate includes liquid, including any suspended or dissolved constituents in the liquid, that has 

percolated through or drained from waste or other materials placed in a landfill, or that pass 

through the containment structure (e.g., bottom, dikes, berms) of a surface impoundment at a

seepage rate exceeding 1 x 10-6cm/sec. Leachate also includes the terms seepage, leak, and 

leakage at rates in excess of 1 x 10-6cm/sec, which are generally used in reference to leachate 

from an impoundment. Seepage, leak, and leakage at design rates less than 1 x 10-6cm/sec would 

be considered "Allowable Seepage", and shall not be considered a point source or discharge to 

Waters of the United States, by virtue of the insignificant nature.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 
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4-304

Also see responses in Comment Code 27.e regarding the role of the ELGs and the role of the 

CCR rule. EPA disagrees with the commenter that an “allowable seepage rate” should be 

specified in the definition for combustion residual leachate because the rate at which the leachate 

moves through the liner does not preclude that fact that it is still leachate. 

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Stormwater hitting the top of a landfill and running off appears to be considered leachate. It is 

not appropriate to consider stormwater flow as leachate because that runoff is often different 

from leachate and has lower metals loading than leachate.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Lisa M. Jaeger

Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)

Document Control Number: EPA-HQ-OW-2009-0819-4486-A2

Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Nor has EPA laid the necessary foundation for the CCR management provisions as they relate to 

stormwater. There appears to be a disconnect between the Preamble and the Technical 

Development Document for the ELGs dealing with CCR leachate. Unlike other EPA ELGs, the 

proposed effluent limit on CCR leachate does not clarify whether the leachate is only from the 

underdrain system or includes both the underdrain discharge and runoff. In prior rules for which 

stormwater was a concern, EPA has established guidelines for the type of precipitation event for 

which the stormwater management system should be designed. In this proposed rule, EPA has 

not identified the precipitation event that should be addressed in stormwater management 

systems. The lack of specificity on this point makes designing controls very difficult.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

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: 23

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Combustion residual leachate should continue to be classified as low-volume waste.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 140 in Comment Code 

18.a.

Also, see preamble for why the final rule does not treat Combustion residual leachate as a lowvolume waste.

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: 61

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Should Make Clear That the Definition of “Leachate” Does Not Include Stormwater 

Runoff from Covered Landfills.

EPA should clarify that rainfall that runs off a covered landfill should not be classified as 

“combustion residual leachate.” Currently, EPA’s record does not make clear whether “leachate” 

includes stormwater runoff. For example, section 4.3.5 of the TDD includes a Figure 4-10 

showing leachate percolating through the landfill and collecting in a leachate collection system, 

and separately, showing rain falling on the landfill surface and runoff from the landfill running 

into a runoff drainage ditch. The implication is that runoff is not “leachate.” However, in TDD 

sections 4.3.5 and 6.3 EPA says that leachate includes stormwater runoff from a landfill, e.g.:
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“The two sources of landfill leachate are precipitation that percolates through the waste 

deposited in the landfill and the liquids produced from the combustion residual placed in the 

landfill. In addition to leachate, stormwater that contacts the landfill wastes and flows over the 

landfill may be contaminated. Leachate and contaminated stormwater contain heavy metals and 

other contaminants through the contact with the combustion residuals.”

TDD § 4.3.5.

EPA appears to be distinguishing between stormwater that runs off the top of a covered landfill 

(without contacting coal combustion residual) and “contaminated” stormwater that percolates 

down through the coal combustion residual in the landfill. It would help for EPA to clarify that 

“combustion residual leachate” does not include stormwater runoff from landfills that have been 

capped.

Moreover, stormwater is not a “discharge” (and hence does not need a permit) if it is not 

channelized. Stormwater becomes a discharge only if it goes through some kind of 

“conveyance” (which is understood to mean a pipe or ditch). So if the stormwater is not 

channelized, it cannot be a discharge requiring an NPDES permit. See Sierra Club v. Abston 

Constr. Co., 620 F.2d 41, 45-46 (5th Cir. 1980) (a “point source” is the “conveyance” which 

constitutes “the means by which the pollutants are ultimately deposited into a navigable body of 

water) (emphasis added); see also United States v. Plaza Health Labs, Inc., 3 F.3d 643, 646 (2nd 

Cir. 1993) (point sources are “physical structures and instrumentalities that systematically act as 

a means of conveying pollutants from an industrial source to navigable waterways, such as a 

pipe); Hudson Riverkeeper Fund v. Harbor at Hastings Associates, 917 F. Supp. 251, 257 

(S.D.N.Y. 1996) (dismissing a CWA claim that rainfall touching an industrial building was a 

point source because it eventually flowed into a nearby river).

As the district court in the latter case noted, “[s]tormwater that is not collected or channeled and 

then discharged, but rather runs off and dissipates in a natural and unimpeded manner, is not a 

discharge from a point source as defined by Section 502(14)” (Order at 9) (citing Northwest 

Env’l Defense Center v. Brown, 640 F.3d 1063, 1079 (9th Cir. 2011) (emphasis in 

original). Courts have repeatedly declined to classify pollution coming from “runoff caused 

primarily by rainfall around activities that employ or create pollutants” as a “point source.” Nat. 

Desert Ass’n v. Dombeck, 172 F.3d 1092, 1098 (9th Cir. 1998).

Similarly, courts define pollution as “non-point source” when it is caused by diffuse sources such 

as runoff. “Broad though [the] definition [of point source] may be, we are of [the] opinion that it 

does not include unchanneled and uncollected surface waters.” Appalachian Power Co. v. Train, 

545 F.2d 1351, 1373 (4th Cir. 1976). See Envt’l Defense Center v. EPA, 344 F.3d 832, 842 n.8 

(9th Cir. 2003) (“diffuse runoff, such as rainwater that is not channeled through a point source is 

considered nonpoint source pollution and is not subject to federal regulation.”).15

15 See also Or. Natural Desert Ass’n v. United States Forest Serv., 550 F.3d 778, 785 (9th Cir. 

2008) (explaining Congress chose not to regulate “generalized runoff”); Natural Resources Def. 
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Council v. EPA, 915 F.2d 1314, 1316 (9th Cir. 1990) (explaining runoff of pesticides from 

farmland not a “point source”); Cordiano v. Metacon Gun Club, 575 F.3d 199, 220 (2nd Cir. 

2009) (“‘Nonpoint source pollution is generally runoff: salt from roads, agricultural chemicals 

from farmlands, oil from parking lots, and other substances washed by rain, in diffuse patterns, 

over the land and into navigable waters.’”) (quoting Plaza Health Labs, 3 F.3d at 652).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

EPA agrees that discharges of stormwater from capped landfills is not combustion residual 

leachate as defined by the final rule. The definition of point source and what is stormwater from 

a point source is outside the scope of this rule. See 40 CFR 122.26(b)(14). The definition of what 

is the wastestream combustion residual leachate is not tied to the definition of what is a point 

source.

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: 62

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

“Seepage” that is Not Channeled or Discharged to a Surface Water Cannot Be Regulated 

“Leachate”

Another definitional problem with “leachate” is that some of the language in the proposal 

suggests that “seepage” and “drainage” qualify as “combustion residual leachate.” This can be so 

only if the water is collected in a “point source.” And that means only if it is channeled and 

discharged to a “water of the United States.”

As with stormwater, discussed above, EPA is authorized to regulate “discharges” only from a 

“point source.” A point source is a discernible, confined and discrete conveyance (33 USC § 

1362(14)), which generally means a channel or conduit (though it also includes wells, containers, 

rolling stock, concentrated animal feeding operations, and vessels). See Comments of the Utility 

Water Act Group on Questionnaire for Steam Electric Power Generating Effluent Guidelines, 

Doc. No. EPA-HQ-OW-2009-0819 (April 8, 2010) at 58.

“Seeps,” unless collected or channelized, are not “point sources,” especially seepage through the 

berm or dam at an ash pond that does not reach surface waters. So EPA’s proposed rule can 

apply only when the seepage is channeled and released to a surface water, including when 

leachate becomes subject to the stormwater permitting regulations.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. The definition of 

point source and what is stormwater from a point source is outside the scope of this rule. See 40 

CFR 122.26(b)(14). The definition of what is the wastestream combustion residual leachate is 

not tied to the definition of what is a point source.

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: 64

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

“Combustion Residual Leachate” Should Not Include Water that May Contact CCR that is 

Beneficially Used

Furthermore, EPA should clarify that the term “combustion residual leachate” does not include 

water that has come into contact with CCR that has been beneficially used and has not been 

disposed of or otherwise managed in a CCR landfill or surface impoundment.

It is important to encourage the beneficial use of CCR. For example landfills and impoundments 

are sometimes constructed using structural fill and embankments using CCR. Operators of a 

landfill may use CCR for daily cover and as part of the final cover material when the landfill is 

closed. CCR can also be used as road base for service roads to landfills and for other roads as 

well.

These uses of CCR are not used to “contain” residuals and therefore do not fall within the 

proposed definition. But EPA should clarify that this is so. The final ELG rule should say 

clearly that the term “combustion residual leachate” does not include water that may come into 

incidental contact with CCR used in beneficial use applications.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

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

Comment Excerpt Number: 27
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA must revise the proposed definition of “combustion residual leachate” to clarify that 

“seepage ... leak, and leakage” are covered by the definition only when such seepage, leak or 

leakage is collected or channeled and discharged via a point source to a surface water of the 

United States. A contrary interpretation would unlawfully exceed EPA’s statutory authority for 

ELGs, which is limited to “discharges” to a “point source,” and be unworkable and unjustified. 

For example, short of requiring an existing impoundment to retrofit with a seepage or leak 

collection system, it would not be possible to determine compliance of seepage or leaks. 

However, requiring an existing impoundment to retrofit with a seepage or leak collection system 

would be extremely costly (costs which apparently were not analyzed as part of any of EPA’s 

proposed regulatory options) and not cost effective.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt Number 62.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

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

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should also define “combustion residual leachate” to include only leachate generated from 

landfills or surface impoundments and collected through a leachate collection system designed as 

such. Regulating leachate from unlined surface impoundments and landfills is inappropriate and 

beyond the scope of the Clean Water Act (CWA). EPA's pending CCR rule is a more suitable 

vehicle for regulation of leachate from unlined surface impoundments or landfills.12 The 

groundwater monitoring system required under the proposed CCR rule would detect any impacts 

from unlined surface impoundments or landfills and require implementation of corrective action 

to address those impacts.13 Furthermore, the definition of leachate should not apply to 

stormwater runoff, or stormwater in contact with beneficially reused CCR.

12 See 75 Fed. Reg. at 35204-35207.

13 Id.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt Number 62.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 34

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should not include stormwater runoff from the tops of covered landfills within the 

definition of leachate. See TDD at 4-35.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 38

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA also needs to clarify the potential implications of the revised definition of combustion 

residuals leachate and potential issues with commingling leachate with other low volume wastes 

or potentially contaminated storm water runoff in an impoundment prior to treatment and 

compliance with BPT effluent limits and/or new source numeric standards.

Comment Response: 

The final rule does not contain a requirement that combustion residual leachate may not be 

commingled with other wastestreams nor does it contain a requirement to monitor for 

compliance prior to commingling with other wastestreams. See preamble.
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Commenter Name: Steve Jackson

Commenter Affiliation: Alliant Energy Corporate Services, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4516-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definition of "combustion residual leachate" is overly broad.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Steve Jackson

Commenter Affiliation: Alliant Energy Corporate Services, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4516-A2

Comment Excerpt Number: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definition of "combustion residual leachate" is overly broad.

The proposed definition of "combustion residual leachate" is "leachate from landfills or surface 

impoundments containing residuals from the combustion of fossil or fossil-derived fuels." This 

definition is overly broad in that it does not include reference to the act or method of collection 

of leachate nor the design of structures that enable the operator to collect leachate, i.e., liner and 

leachate collection system. Without such a structure leachate cannot be readily collected and 

managed, and, if it can't be collected it can't be treated. EPA acknowledges at page 4-35 of the 

TDD, while discussing landfill and impoundment leachate and runof, that "Unlined 

impoundments and landfills do not collect leachate migrating away from the 

impoundment/landfill ...". However, the proposed definition would subject any leachate from a 

fossil fuel combustion residual landfill or surface impoundment to the ELG rule. Alliant Energy 

recommends that EPA revise this definition to clarify that combustion residual leachate is 

"collected from landfills or surface impoundments containing residuals from the combustion of 

fossil or fossil-derived fuels."

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 
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Commenter Name: Chuck D. Barlow

Commenter Affiliation: Entergy Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4519-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

III. The definition of "leachate" needs to exclude storm water runoff from covered 

landfills, and the leachate requirements need to be clarified.

The definition of "leachate" needs to be clarified to exclude storm water runoff from covered 

landfills (Technical Development Document ["TDD"] Figure 4-10 of Section 4.3.5). The 

wording in different parts of the proposed rule leaves this unclear (TDD Section 4.3.5 and 

Section 6.3). At one point in the rule, the agency specifically says storm water runoff is not 

considered leachate. Then, the definition of "leachate" includes water that percolates through or 

runs off of a landfill due to rainfall (EPA-HQ-OW-2009-0819-0909, p. 10).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

See response to DCN EPA-HQ-OW-2009-0819-4454-A2, Excerpt Number 5 regarding 

closed/retired landfills/impoundments.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 28

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

TVA recommends that EPA clarify the current definition for leachate in §423.11(r) such that it 

pertains only to water that has come into contact with CCRs and that has subsequently passed 

through a dike or a berm (and not the surface water outfall). TVA suggests the following 

revision:

“Leachate includes liquid, including any suspended or dissolved constituents in the liquid, that 

has percolated through or drained from waste or other materials placed in a landfill, and
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[emphasis added] that pass through the containment structure (e.g., bottom, dikes, berms) of a 

surface impoundment. Leachate does not include stormwater runoff that discharges via a surface 

outfall.”

Without that clarification, surface runoff discharging through the surface water outfall (with 

likely different characteristics) could be inappropriately included in the definition of leachate. 

Finally, TVA requests that the definition of leachate be modified to exclude waters emanating 

from CCRs in beneficial use situations.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 24

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We support EPA's proposal to maintain existing TSS and oil and grease limitations for ash pond 

and landfill leachate. While we support the existing numerical limitations for oil and grease and 

TSS, we do not support the reclassification of leachate from a low volume waste to a separate, 

standalone wastestream. This change in classification is without a clear and well supported 

rationale. We also do not support what we believe to be an overly broad definition of 

leachate. Specifically, EPA's various definitions of leachate within the proposal appear to 

expand the definition of leachate to include stormwater runoff and seeps. We urge EPA to clarify 

that stormwater runoff and seeps are not covered by the definition of leachate. We also request 

that EPA clarify that a new cell at an existing landfill is not a "new source" to which the new 

source performance standards apply. Each of these issues is covered in detail in Section II.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

See preamble and response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 47 in 

Comment Code 18.a regarding the rationale for removing combustion residual leachate from the 

definition of low volume waste sources.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149 in Comment Code 

6.g.vii regarding new sources for combustion residual leachate.
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Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 48

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We also do not support what we believe to be an overly broad definition of leachate. Within the 

proposal, we find that EPA employs two distinct definitions of combustion residual leachate.

Preamble definition at 78 Fed. Reg. 34450, col. 2:

"leachate is the liquid that drains or leaches from a landfill or surface 

impoundment. Most landfills have a system to collect the leachate and some 

impoundments have leachate collection systems. The two sources of leachate are 

precipitation that percolates through the waste deposited in the 

landfill/impoundment and the liquids produced from the combustion residuals 

placed in the landfilll impoundment. In addition to leachate, stormwater that 

enters the impoundment or contacts and flows over the landfill would be 

contaminated with combustion residual pollutants. Leachate and contaminated 

stormwater contain heavy metals and other contaminants through the contact with 

the combustion residuals. "

Proposed rule definition at 78 Fed. Reg. at 34533, col. 3:

"(r) The term combustion residual leachate means leachate from landfills or 

surface impoundments containing residuals from the combustion of fossil or 

fossil-derived fuel. Leachate includes liquid, including any suspended or 

dissolved constituents in the liquid, that has percolated through or drained from 

waste or other materials placed in a landfill, or that pass through the containment 

structure (e.g., bottom, dikes, berms) of a surface impoundment.

Leachate also includes the terms seepage, leak, and leakage, which are generally 

used in reference to leachate from an impoundment."

In the first definition above, it appears that EPA believes leachate includes stormwater. In the 

second, and arguably the controlling definition from the proposed rule EPA makes no mention of 

stormwater in relation to leachate. We request that EPA clarify that the definition of leachate 

does not include stormwater runoff. This is because stormwater that runs off the top of covered 

landfill does not come into contact with combustion residuals. Any stormwater that infiltrates a 

covered landfill and comes into contact with the ash in the landfill or that seeps from an 

impoundment does not result in a point source discharge if the seepage is not collected or 
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channelized. EPA authority to regulate leachate extended to point source discharges and, 

therefore, is outside the purview of the EPA proposal.

In the event that stormwater comes into contact with an exposed area of CCR, we agree that it is 

possible for the stormwater to carry with it suspended solids and this water could be a potential 

source of TSS. However, it is unlikely that there will be enough retention time or volume of 

CCRs to create a metals contamination issue from this type of intermittent sheet flow across an 

exposed area. Therefore, we strongly urge the EPA to keep the two waste streams of stormwater 

and leachate separate in the final rule.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In sections IV and V of the comments, USWAG requests that EPA clarify in the final rule that 

(1) the term “combustion residual leachate” does not encompass (i) water that may come into 

contact with CCR that is beneficially used, (ii) stormwater runoff from landfills, and (iii) 

stormwater runoff and seapage and leaks from landfills and surface impoundments that are not 

collected and discharged through a point source,

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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It also is important for EPA to clarify in the final ELG rule that (1) the term “combustion 

residual leachate” (i) only encompasses wastewaters that percolate through CCR disposal units 

and where such wastewaters are collected and discharged via a point source to a water of the 

United States, and (ii) does not apply to water that may come into contact with CCR that is 

beneficially used;

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. The definition of 

point source and what is stormwater from a point source is outside the scope of this rule. See 40 

CFR 122.26(b)(14). The definition of what is the wastestream combustion residual leachate is 

not tied to the definition of what is a point source.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 141

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Also, the definition of leachate should not be expanded to include seeps from 

impoundments. The “working knowledge” definition of leachate has always been leachate from 

landfills.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

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: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

AMP requests clarification from EPA as to the applicability of the Proposed ELG Rule to 

stormwater that enters a capped and closed landfill, such as the one owned by AMP. We doubt 
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EPA intended such a broad interpretation. AMP further requests guidance as to what would be 

considered “legacy” wastewater from a closed landfill.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4454-A2, Excerpt Number 2 in Comment Code 

16.b regarding stormwater entering a capped and closed landfill.

Commenter Name: Raymond L. Evans

Commenter Affiliation: FirstEnergy Corp.

Document Control Number: EPA-HQ-OW-2009-0819-4677-A2

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Also, to avoid any confusion in the final ELG Rule it is important that EPA clarify that the term 

"combustion residual leachate" does not include any water that may come into incidental contact 

with CCR when used in beneficial use applications.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.

Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-A1

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Alcoa disagrees with the inclusion of seeps and weeps from ashpond systems into the definition 

of combustion residual leachate. The Proposed Rule states that they are not low-volume, but then 

applies a low-volume limit. Alcoa does not see the need for this segregation. Seeps, weeps etc, 

should be included in low-volume wastewater streams and managed accordingly.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 140 in Comment Code 

18.a and the preamble for the final rule.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 78

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Definition of “Leachate” from Landfills Should Not Include Stormwater Runoff from 

Covered Landfills

Rainfall that runs off a landfill should not be classified as “combustion residual leachate.” 

According to EPA’s proposed definition, leachate includes “liquid, including any suspended or 

dissolved constituents in the liquid that has percolated through or drained from waste or other 

materials emplaced in a landfill, or that pass through the containment structure (e.g., bottom, 

dikes, berms) of a surface impoundment. Leachate also includes the terms seepage, drains, leak, 

and leakage, which are generally used in reference to leachate from an impoundment.”

This definition should not be read to encompass stormwater runoff, which is entirely different. 

EPA recognized the distinction in section 4.3.5 of the TDD, which distinguishes between 

leachate and stormwater by including a diagram, Figure 4-10. The same diagram was “Figure 3” 

in the Federalism/UMRA Supplemental Information – Package #2 (EPA-HQ-OW-2009-0819-

0909, p. 10.) that EPA distributed at a meeting on October 11, 2011. This meeting was arranged 

by EPA’s Congressional and External Affairs Office who invited a number of city officials were 

invited to look at the ELG issues in advance of the rulemaking. Its purpose was to look at 

unfunded mandates resulting from the rulemaking. Six APPA member utilities attended as 

parties representing city governments and electric utilities affected by the rule.

See Attachment 1 to these comments to see comments/questions filed as a follow up to this 

meeting addressing Unfunded Mandates Reduction Act impacts. This figure shows leachate 

percolating through the landfill and collecting in a leachate collection system. Separately it 

shows rain falling on the landfill surface and runoff from the landfill running into a runoff 

drainage ditch. The implication is that stormwater runoff is not “leachate.”

Some confusion may be caused, however, by the words “drained from waste” in the definition 

and from TDD Sections 4.3.5 and 6.3, where EPA says that leachate includes stormwater runoff 

from a landfill:

The two sources of landfill leachate are precipitation that percolates through the waste 

deposited in the landfill and the liquids produced from the combustion residual placed in the 
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landfill. In addition to leachate, stormwater that contacts the landfill wastes and flows over the 

landfill may be contaminated. Leachate and contaminated stormwater contain heavy metals and 

other contaminants through the contact with the combustion residuals.

TDD §4.3.5; see also TDD §6.3.

EPA should maintain the distinction between “leachate” and “stormwater runoff” to be 

consistent with its existing regulatory regimes for runoff from landfills. Runoff from a landfill is 

stormwater, different from water that percolates through waste placed in a landfill or surface 

impoundment, which is “leachate.” EPA must clarify in the final rule that “combustion residual 

leachate” does not include stormwater from landfills.

Moreover, stormwater is not a “discharge” (and hence does not need a permit) if it is not 

channelized. Stormwater becomes a discharge only if it goes through some kind of “conveyance” 

(which is understood to mean a pipe or ditch). So if the stormwater is not channelized, it cannot 

be a discharge requiring a National Pollutant Discharge Elimination System (NPDES) permit. As 

the Ninth Circuit noted, “[s]tormwater that is not collected or channeled and then discharged, but 

rather runs off and dissipates in a natural and unimpeded manner, is not a discharge from a point 

source as defined by §502(14).” Nw. Envtl. Def. Ctr. v. Brown, 617 F.3d 1176, 1181 (9th Cir. 

2011) (emphasis added). Courts repeatedly have declined to classify pollution coming from 

“runoff caused primarily by rainfall around activities that employ or create pollutants” as a 

“point source.” Oregon Natural Desert Ass’n v. Dombeck, 172 F.3d 1092, 1098 (9th Cir. 1998).

Similarly, courts define pollution as a “non-point source” when it is caused by diffuse sources 

such as runoff. “Broad though [the] definition [of point source] may be, we are of [the] opinion 

that it does not include unchanneled and uncollected surface waters.” Appalachian Power Co. v. 

Train, 545 F.2d 1351, 1373 (4th Cir. 1976). See Envtl. Def. Ctr., Inc. v. EPA, 344 F.3d 832, 841 

n.8 (9th Cir. 2003) (“[d]iffuse runoff, such as rainwater that is not channeled through a point 

source, is considered nonpoint source pollution and is not subject to federal regulation.”).27

27 See also Oregon Natural Desert Ass’n v. U.S. Forest Serv., 550 F.3d 778, 785 (9th Cir. 2008) 

(explaining Congress chose not to regulate “generalized runoff”); Natural Res. Def. Council v. 

EPA, 915 F.2d 1314, 1316 (9th Cir. 1990) (explaining runoff of pesticides from farmland is not a 

“point source”); Cordiano v. Metacon Gun Club, 575 F.3d 199, 220 (2nd Cir. 2009) (“‘Nonpoint 

source pollution is generally runoff: salt from roads, agricultural chemicals from farmlands, oil 

from parking lots, and other substances washed by rain, in diffuse patterns, over the land and into 

navigable waters’”) (quoting Plaza Health Labs., 3 F.3d at 652).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 26.

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: 79

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

“Seepage” that Is Not Channeled or Discharged to a Surface Water Cannot Be Regulated 

as “Leachate”

Another definitional problem with “leachate” is that some of the language in the proposal 

suggests that “seepage” and “drainage” qualify as “combustion residual leachate.” This can be so 

only if the water is a “point source.” And that means only if it is channeled and discharged to a 

“water of the United States.”

As with stormwater, discussed above, with seepage or drainage, EPA is authorized to regulate 

“discharges” from a “point source.” A point source is a discernible, confined, and discrete 

conveyance (33 U.S.C. §1362(14)), which generally means a channel or conduit (though it also 

includes wells, containers, rolling stock, concentrated animal feeding operations, and vessels). 

See Sierra Club v. Abston Constr. Co., 620 F.2d 41, 45-46 (5th Cir. 1980) (a “point source” is 

the “conveyance” that constitutes “the means by which pollutants are ultimately deposited into a 

navigable body of water) (emphasis added); see also United States v. Plaza Health Labs, Inc., 3 

F.3d 643, 646 (2nd Cir. 1993) (point sources are “physical structures and instrumentalities that 

systematically act as a means of conveying pollutants from an industrial source to navigable 

waterways,” such as a pipe); Hudson Riverkeeper Fund, Inc. v. Harbor at Hastings Assocs., 917 

F. Supp. 251, 257 (S.D.N.Y. 1996) (dismissing a CWA claim that rainfall touching an industrial 

building was a point source because it eventually flowed into a nearby river); Comments of the 

Utility Water Act Group on Questionnaire for Steam Electric Power Generating Effluent 

Guidelines, Doc. No. EPA-HQ-OW-2009-0819 (April 8, 2010) at 58.

“Seeps” and “leakage” from landfills and impoundments cannot be regulated as “combustion 

residual leachate” unless the water is collected or channelized and then discharged through a 

point source to a surface water that is a “water of the United States.” So EPA’s proposed rule 

should make this clear.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 26.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 80
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Combustion Residual Leachate” Should Not Include Water That May Contact CCR That 

Is Beneficially Used

EPA should clarify that the term “combustion residual leachate” does not include water that has 

come into contact with CCR that has been beneficially used and has not been disposed of or 

otherwise managed in a CCR landfill or surface impoundment. It is important to encourage the

beneficial use of CCR. For example, landfills and impoundments are sometimes constructed 

using structural fill and embankments using CCR. Operators of a landfill may use CCR for daily 

cover and as part of the final cover material when the landfill is closed. CCR also can be used as 

road base for service roads to landfills and for other roads as well.

These uses of CCR are not to “contain” residuals and therefore do not fall within the proposed 

definition. But EPA should clarify that this is so. The final ELG rule should say clearly that the 

term “combustion residual leachate” does not include water that may come into incidental 

contact with CCR used in beneficial use applications.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17. 

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 81

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

“Combustion Residual Leachate” Should Not Interfere with Beneficial Activities

Either in the definition of “combustion residual leachate” or in the preamble to the final rule, 

EPA should be careful to limit the interpretation of the term so as not to have the effluent 

standards apply to unintended activities. For example, the limits on “leachate” should not apply 

to pond dewatering, which might include collecting and pumping out water from existing coal 

combustion residuals in old impoundments, before capping the site. Likewise the limits should 

not apply to intercepting a contaminated groundwater plume some distance from an 

impoundment so the groundwater can be treated and discharged.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 148.

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: 57

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s proposed regulation of combustion residual leachate raises various issues for 

clarification. EPA staff provided helpful clarifications during the August 20, 2013 ELG 

rulemaking webcast, and EPA should reflect those and other clarifications in the final rule. First, 

consistent with the webcast, EPA should clarify that the only leachate regulated under the steam 

electric ELG is leachate that is collected and discharged to a water of the U.S. EPA has no 

authority under the CWA to regulate pollutants that are not discharged from a point source. This 

clarification should make it clear that unanticipated seeps from landfills or surface 

impoundments, that are not collected and discharged and therefore are not covered by a NPDES 

permit, do not give rise to liability under the CWA.

Second, EPA should clarify that the steam-electric ELG leachate provisions do not apply to 

stormwater runoff, even in the vicinity of landfills and ponds. Stormwater runoff is governed by 

EPA’s stormwater regulations.

Third, EPA should clarify that the leachate provisions apply only to generating units whose 

primary revenue is the generation of electricity and do not apply to off-site, independently owned 

landfills. The construction and operation of off-site, independently owned landfills are governed 

by EPA, state, and local landfill regulations and the landfills’ own direct NPDES permits, as 

applicable.

Fourth, also consistent with the August 2013 public meeting, EPA should explicitly acknowledge 

that CWA new source performance standards (NSPS) are not triggered by a new cell or new 

landfill built to manage CCR wastestreams displaced as a result of a facility’s compliance with a 

new ELG requirement. As EPA staff noted on the webcast, modification of an existing 

generating unit and its affiliated disposal facilities is an “existing source,” not a new source.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4652-A1, Excerpt Number 17.
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See response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 14 regarding the 

application of the combustion residual leachate limitations and standards to off-site landfills.

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149 in Comment Code 

6.g.vii regarding new sources for combustion residual leachate.
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6.g.ii. Nonchemical metal cleaning wastes (NCMCW)

Commenter Name: Patrick O’Loughlin

Commenter Affiliation: Buckeye Power, Inc.

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

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

the definition of NCMCW is overly broad - it could encompass virtually all wash water used at a 

facility. Buckeye Power endorses the definition of NCMCW proposed by the Utility Water Act 

Group: "Any wastewater from the cleaning of ash from gas-side process equipment from the 

boiler to the stack without chemical cleaning compounds, including boiler fireside cleaning and 

air preheater cleaning."

Comment Response: 

The final rule does not establish BAT effluent limitations and standards for non-chemical metal 

cleaning wastes (NCMCW) for the reasons discussed in the preamble to the final rule. Therefore, 

the final rule reserves revising the definitions for these wastestreams, which includes not 

defining non-chemical metal cleaning wastes. By not revising the effluent limitations and 

standards and not revising the definitions, the final rule will not result in changes to industry

operations for the specified wastestreams. However, the permitting authority will continue to 

have discretion in determining which cleaning wastewaters are metal cleaning wastes based on 

the facility-specific operations, the wastewater generated and the wastewater’s characteristics.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 113

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Duke Energy recommends refining the definition of nonchemical metal cleaning wastes as 

follows: “The term nonchemical metal cleaning waste means any wastewater from the cleaning 

of ash from gas-side process equipment from the boiler to the stack without chemical cleaning 

compounds, including boiler fireside cleaning and air preheater cleaning.”

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

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: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA is taking comment on the standards for nonchemical metal cleaning waste in the proposed 

rule. The existing definitions of metal cleaning waste and chemical metal cleaning waste are 

overly broad. The existing definitions of metal cleaning waste and chemical metal cleaning waste 

are overly broad. EPA should revise the definition of metal cleaning waste and chemical wastes.

EPA should define "nonchemical metal cleaning wastes" as follows: "The term nonchemical 

metal cleaning waste mean any wastewater from cleaning of ash from gas side process 

equipment from the boiler to the stack without chemical cleaning compounds, including boiler 

fireside cleaning and air preheater cleaning but not soot blowing or similar in-service boiler 

fireside cleaning." All other metal cleaning waste streams should be treated as low volume waste 

water. Cleaning metal buildings, railings, siding, stairs, etc. has little potential for environmental 

harm. The definition for chemical metal cleaning should be defined to include only chemical 

boiler cleaning waste water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

The final rule does not establish or revise BAT for metal cleaning wastes.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 98

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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The proposed definition of NCMCW should be amended to clarify that the term only includes 

wastewater from the cleaning of gas (fire)-side metal process equipment, without chemicals, 

from the boiler to the stack excluding soot blowing and boiler lancing.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 105

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA is Expanding the Universe of Water Washing Processes Regulated as NCMCW or 

MCW with Insufficient Analysis

As previously stated, in the 1974 and 1982 ELG TDDs and supporting documents, very limited 

NCMCW analytical data were available, and the data were exclusively chemical boiler cleaning 

wastes and NCMCWs associated with water washing of ash found on boiler fireside and the airpreheater. Without any additional analysis or discussion of costs, EPA now seems to interpret

NCMCW as inclusive of any steam or water stream that contacts a metal surface that is 

associated with equipment at steam electric facilities. While EPA does not identify specific 

NCMCW sources in the proposed new definition, other than boiler tube, boiler fireside, and air 

preheater cleaning, EPA references an extensive list of NCMCW generation frequencies as 

reported in the 2010 ICR. 2013 TDD at 6-21, Table 6-14. Characterizing these wastewaters 

(from 20 different operations) as NCMCW and determining to regulate them as such is certainly 

not supported by the record.

While a broader interpretation is not as problematic for an existing facility authorized to 

discharge NCMCW as a low volume waste using a centralized treatment system (ash pond, etc.), 

expanding water washing to process equipment other than gas-side will be extremely expensive 

and of very limited environmental benefit, especially if comingling is prohibited and iron and 

copper limits imposed.

Without additional clarification or a thorough analysis by EPA, any definition of NCMCW 

should be restricted to the gas-side cleaning of metal process equipment without chemicals. For 

example, the proposed definition of NCMCW at 40 C.F.R. Part 423.11(u) could be modified as 

follows:
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"The term nonchemical metal cleaning waste means any wastewater resulting from the cleaning 

of metal fireside process equipment from the boiler to the stack, without chemical cleaning 

compounds, including, but not limited to boiler fireside cleaning, and air preheater cleaning. The 

term does not include wastewater from processes that use steam or water to remove ash or slag 

during unit operation, including, but not limited to, soot blowing and boiler lancing."

No analytical data or supporting documents have been placed in the record to support the 

proposed expanded definition (that, if taken to the extreme, could be interpreted to include such 

benign discharges as intake screen backwash).

The interpretation of “any metal process equipment” also has created confusion over the 

decades. We recommend that EPA make it clear that NCMCWs are specific to the boiler 

fireside, or the gas path within the boiler system (process equipment) from the burners to the 

stack. This path usually includes: the furnace, furnace hopper, superheater, reheater, economizer, 

air preheater, precipitator, induced draft fans and associated walls, hoppers, and ducting. Many 

of these surfaces will accumulate fuel ash and metal corrosion products that need to be cleaned 

both during operation and during a full or partial outage condition.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22. 

Commenter Name: Jacob G. Smeltz

Commenter Affiliation: Electric Power Generation Association (EPGA)

Document Control Number: EPA-HQ-OW-2009-0819-4450-A1

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

To further clarify the rules governing nonchemical metal cleaning wastes and retain the original 

meaning of “metal cleaning wastes” as provided in the rulemaking records for 1974 and 1982, 

the EPA should provide a definition specifically for “nonchemical metal cleaning wastes.” As 

recommended by UWAG in their comments on the Proposal, “the term nonchemical metal 

cleaning waste means any wastewater from the cleaning of ash from gas-side process equipment 

from the boiler to the stack without chemical cleaning compounds, including boiler fireside 

cleaning and air preheater cleaning.”

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

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: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EKPC also seeks clarification on the scope of non-chemical metal cleaning wastes. Because of 

the broad definition of non-chemical metal cleaning wastes as wastewater from "cleaning of any 

metal process equipment without chemical cleaning compounds," a question exists as to whether 

the definition would reach to general wash water from cooling towers, coal handling equipment, 

as well as from floors or other surfaces that only incidentally come into contact with metal 

process equipment. It is especially important to clarify in the final rule that incidental contact of 

wash water with metal process equipment, which is unintended from a process "cleaning" 

standpoint, is not within the scope of non-chemical metal cleaning wastes. Additionally, EKPC 

requests that EPA specifically exclude from the definition of metal cleaning wastes washing 

down the boiler, boiler houses, silos, silo houses, cooling towers, coal handling equipment, 

driveways, road ways, parking lots and general housekeeping. These general wash waters allow 

the utilities to maintain a level of site cleanliness that is beneficial to the employees' general 

health, welfare, morale and provides safe work conditions.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Nonchemical Metal Cleaning Waste should remain within the definition of a low volume waste 

and the associated ELGs for this waste stream eliminated from the final rule.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 28

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Regulation of Non-Chemical Cleaning Wastes is overly broad as it would also regulate 

waters that do not generate pollutants with BAT limits.

EPA’s definition, along with the discussion in the preamble, is overly broad and unsubstantiated 

for non-chemical metal cleaning waste. The definition proposed includes all “wastewater from 

the cleaning of any metal process equipment without chemical.” EPA goes on to identify some 

examples with the disclaimer that the examples are not exclusive, but are illustrative and are “not 

limited to” the examples cited. If applied as written, tasks such as washing off the outside of a 

metal housing around a pump to remove dust would be considered non-chemical metal cleaning 

waste even though the process does not have the potential to generate the identified pollutants. 

We assume this was not the intent of the proposed rules but, as written, could potentially result in 

the inadvertent inclusion to these types of unrelated tasks and would be an overreach of EPA’s 

regulatory authority. EPA should change the definition to identify that only those waste streams 

with the pollutants identified in the ELG (iron and copper) are required to meet the proposed 

BAT limits for non- chemical metal cleaning waste. During the permit application process, 

permittees should submit data to document whether or not waste streams are required to comply 

with the BAT requirements. The process should include evaluation of actual contaminants and if 

copper and iron are not present, or can be historically demonstrated to be less than the BAT 

limits, then the non-chemical metal cleaning waste process should be exempt from the BAT 

limits.

EPA should narrow the definition such that only waste streams that discharge the identified 

contaminants are regulated by the ELG.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: Basil G. Constantelos

Commenter Affiliation: Midwest Generation, LLC.
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Document Control Number: EPA-HQ-OW-2009-0819-4464-A1

Comment Excerpt Number: 26

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Midwest Gen Also Respectfully Requests Certain Clarifications.

Midwest Gen also asks that EPA clarify that its definition of NCMCW does not include water 

used in condenser cleaning. In the condenser cleaning process, Midwest Gen shuts down each 

unit once per year and uses water to push brushes through the condenser tubes. The small 

volume of water used in condenser cleaning exits the tubes via the outfall for non-contact 

cooling water. It would be onerous and impractical for Midwest Gen to construct new piping to 

capture a small volume of condenser cleaning water, especially given that it would only be used 

once per year. EPA must consider process changes under the statutory factors for BAT, and the 

burdensome process changes necessary should EPA consider condenser cleaning water to be 

NCMCW weigh heavily against its treatment as such. Historically, this water has not been 

considered to be NCMCW. Moreover, EPA has presented no data to support treating condenser 

cleaning water as NCMCW.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

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

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should define non-chemical metal cleaning wastes as wastewater generated from cleaning 

"fireside" metal process equipment, without chemicals. This would limited to equipment that is 

cleaned within the electric generating unit, and not all metal process equipment. The definition is 

so vague that even the water intake screens in a river or lake could be included. Intake screens 

are typically metal mesh and are cleaned with water sprays to remove debris; i.e. water washed 

without chemicals. It can certainly be argued that the screens are process equipment too. EPA 

should narrow the definition of nonchemical metal cleaning waste to exclude such equipment.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: Vicki Card

Commenter Affiliation: Colorado Springs Utilities

Document Control Number: EPA-HQ-OW-2009-0819-4483-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Utilities supports APPA’s proposed definition of “nonchemical metal cleaning wastes” as 

follows: “The term nonchemical metal cleaning waste means any wastewater from the cleaning 

of ash from gas-side process equipment from the boiler to the stack without chemical cleaning 

compounds, including boiler fireside cleaning and air preheater cleaning but not soot blowing or 

similar in-service boiler fireside cleaning.” The limited record would only support a limited 

definition, such as APPA’s proposal.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: Vicki Card

Commenter Affiliation: Colorado Springs Utilities

Document Control Number: EPA-HQ-OW-2009-0819-4483-A1

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Due to the sparse data in the record, Utilities supports APPA’s recommendation to narrow the 

definition of nonchemical metal cleaning.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.
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Commenter Name: Chuck D. Barlow

Commenter Affiliation: Entergy Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4519-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

II. The definition of "nonchemical metal cleaning wastes" is ambiguous and should be

more explicit and various requirements should be clarified.

EPA should define "nonchemical metal cleaning wastes " explicitly as "any wastewater from the 

cleaning of ash from gas-side process equipment from the boiler to the stack without chemical 

cleaning compounds, including boiler fireside cleaning and air preheater cleaning." to prevent a 

myriad of other activities that generate wastewater with no probability of metal contamination 

from being captured under the umbrella of an ambiguous definition in the rule.

A broader definition may not be an issue for an existing facility authorized to discharge 

nonchemical metal cleaning waste using an existing, centralized treatment system for low 

volume wastes. However, expanding the meaning of "metal cleaning wastes" to water washing of 

process equipment other than gas-side ash removal would be expensive and of limited 

environmental benefit, especially if comingling is prohibited and iron and copper limits are 

imposed. No analytical data or supporting documents have been added to the record to support 

the proposed expanded definition, which, if taken to extremes, could be interpreted to include 

such benign discharges as common plant wash down water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment code 22.

Commenter Name: Gregory D. Elmore

Commenter Affiliation: Southern Nuclear Operating Company (SNC)

Document Control Number: EPA-HQ-OW-2009-0819-4582-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposed definition ofNCMCW should be amended to clarify that the term only includes 

wastewater from the cleaning of gas (fire)-side metal process equipment, without chemicals, 

from the boiler to the stack excluding soot blowing and boiler lancing.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 31

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The new definition in §423.11(u) for nonchemical metal cleaning waste also needs refinement as 

it currently includes wastewaters from cleaning ‘any metal process equipment’. If taken to the 

extreme this may be interpreted such that any wash down of metal components-e.g., pumps, 

piping, ductwork, structural members, tanks - would result in the generation of nonchemical 

metal cleaning waste. The proposed changes introduce the need to provide for segregation and 

treatment of any metal cleaning waste and are not only inconsistent with current industry 

practice, but would also be excessive and unnecessary. We therefore support the definition 

provided by UWAG in their comments for this wastestream.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

we request that EPA clarify the definition of non-chemical metal cleaning wastes to avoid 

expanding the practiced definition. We believe the EPA' s i nterpretation of the definition of nonchemical metal cleaning wastes in the proposed rule would require facilities to incur further costs 

and operational challenges while failing to produce the desired environmental benefit. We are 

especially concerned about expanding the universe of non-chemical metal cleaning wastes given 

the absence of effluent data, cost information, and benefit information in the proposed rule.
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We urge EPA to develop a practical definition of non-metal cleaning waste that targets EPA's 

concerns with ash and soot removal from boilers and air pre-heaters and that avoids 

unintentionally burdensome consequences such as expanded treatment requirements at nuclear 

units. Additionally, we request that EPA classify water washes with nothing added but soap or 

detergent, as non-chemical metal cleaning wastes.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4470-A1, Excerpt Number 27 in Comment Code 6.g.iii.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 54

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The EPA proposal defines non-chemical metal cleaning waste as,

"any wastewater resulting from the cleaning of any metal process equipment 

without chemical cleaning compounds, including, but not limited to, boiler tube 

cleaning, boiler fireside cleaning, and air preheater cleaning.. "

78 Fed. Reg. 34533 Col 3 (Emphasis Added) .

Under this definition, all wash waters of metal equipment regardless of copper or iron content 

require treatment. This definition would even include wash waters that contain little to no 

copper or iron. Yet, under the proposed definition these wash waters would need to be captured, 

separated from low volume wastewaters, and treated despite the lack of significant amounts of 

copper and iron, if any at all.

Specifically, we are concerned that routine non-chemical wash downs at nuclear power stations 

are unlikely to contain any significant amounts of copper or iron from ash or soot. Yet, the cost 

of collection and treatment of water washes at nuclear stations would be expected to be 

disproportionate to the amount of copper and iron removed. We note here that the rulemaking 

does not contain any pollutant or cost data for non-chemical metal cleaning waters at nuclear 

stations. At this time, the majority of stations treat wash water as low volume wastes such that 

there is no convincing data available. Without proper data and cost information, we cannot 

support national copper and iron limits for non-chemical washes at either nuclear or non-nuclear 

stations.
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Likewise, a non-chemical wash down of an air-cooled condenser at coal fired facilities and 

turbine washes at combustion turbine stations would not be expected to contain copper or iron. 

The record for this proposed rule contains little to no data to support including either condenser 

cleaning water or turbine washes in the definition.

For the reasons set forth above, we request that EPA adopt a more narrow definition of nonchemical metal cleaning wastes. We suggest that EPA could define non-chemical metal cleaning 

waste as any wastewater from the cleaning of ash from flue gas-side process equipment without 

chemical cleaning compounds, including boiler fireside cleaning and air pre-heater 

cleaning. Specifically, we believe EPA should not expand the definition to water washing of 

process equipment other than gas-side ash removal. There should also be a de minimis 

exemption for small wash streams such as the occasional washing of induced draft fan blades. 

This is an appropriate definition that restricts limitations to EPA's primary area of concern, ash 

and soot. Given that ash and soot are not found in nuclear stations, nuclear facilities should not 

be included in the definition of non chemical metal cleaning wastes.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22. See also response to 

DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 27 in Comment Code 6.g.iii.

Commenter Name: Dennis Wene

Commenter Affiliation: Alcoa Inc.'s Warrick Operations

Document Control Number: EPA-HQ-OW-2009-0819-4765-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Alcoa-Warrick believes EPA should define non-chemical metal cleaning wastes as wastewater 

generated from cleaning, without chemicals, to process contaminated metals such as "fireside" 

metal process equipment and not just any metal process equipment. The definition is vague and 

overly broad such that even the water intake screens in a river or lake could be included. The 

screens are typically metal mesh and are cleaned with water sprays to remove debris; i.e., water 

washed without chemicals and it can certainly be argued that the screens are process equipment 

too. EPA should state which wastewater streams it intends to regulate or provide guidance to the 

States.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.
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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: 88

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

One change is needed to clarify the rules and adhere to the meaning of “metal cleaning wastes” 

that was used in the 1974 and 1982 rulemaking records. EPA should define “nonchemical metal 

cleaning wastes” as follows: “The term nonchemical metal cleaning waste means any wastewater 

from the cleaning of ash from gas-side process equipment from the boiler to the stack without 

chemical cleaning compounds, including boiler fireside cleaning and air preheater cleaning but 

not soot blowing or similar in-service boiler fireside cleaning."

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: Paul Ling

Commenter Affiliation: Kansas City Power & Light Company

Document Control Number: EPA-HQ-OW-2009-0819-5406-A2

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should also confirm that non-chemical metal cleaning wastes mean only washes of gas-side 

process equipment with nothing added but soap or detergent be recognized as nonchemical.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

Document Control Number: EPA-HQ-OW-2009-0819-4448-A1
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Comment Excerpt Number: 52

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA defines “metal cleaning waste” as “any wastewater resulting from cleaning [with or without 

chemical cleaning compounds] any metal process equipment, including, but not limited to, boiler 

tube cleaning, boiler fireside cleaning, and air preheater cleaning” (78 FR at 34464). This 

definition includes any wastewater generated from either the chemical or nonchemical cleaning 

of metal process equipment. EPA defines “chemical metal cleaning waste” as “any wastewater 

resulting from cleaning of any metal process equipment with chemical compounds, including, 

but not limited to, boiler tube cleaning” (78 FR at 34465). During the earlier development of 

BAT effluent guidelines for these wastewaters, the term “nonchemical metal cleaning waste” 

was not defined, but in the EPA proposal, it is defined as “any wastewater resulting from the 

cleaning of metal process equipment without chemical cleaning compounds” (Id.).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 54

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

c. Metal cleaning wastes should be defined as washes of “gas-side process equipment.”

As cited in the UWAG comments,32 the terms “metal cleaning waste,” “chemical metal cleaning 

wastes,” and “boiler chemical cleaning waste” are not clearly defined and are often used 

synonymously in NPDES permits. These discharges are typically permitted with iron and copper 

limits if they are associated with chemical cleaning compounds. EPA now seems to interpret 

“metal cleaning wastes” as all-inclusive, which is not supported by the record. As shown in the 

following table of the various sources of wash water from cleaning metal process equipment at 

AEP’s plants (Table 8), a literal interpretation of EPA’s proposed definition could be overly 

expansive. We do not believe that it is EPA’s intent to regulate the common washing of 

external surfaces of process equipment or associated structures. Therefore any definition must be 

limited to the washing of internal surfaces that are in direct contact with the steam generating 

process. Without additional clarification or analysis by EPA, any definition of nonchemical 

metal cleaning wastes should be restricted to the gas-side removal of ash without 
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chemicals. AEP agrees with UWAG that expanding the definition of “metal cleaning wastes” to 

water washing of process equipment other than gas-side ash removal would be expensive and of 

limited environmental benefit. No analytical data or supporting documents have been added to 

the record to support the proposed expanded (and possibly all-encompassing) definition, which if 

taken to extremes, could be interpreted to include such benign discharges as intake screen 

backwash.

As proposed by UWAG, a suitable definition of “nonchemical metal cleaning wastes’ would be 

“any wastewater from the cleaning of ash from gas-side process equipment from the boiler to the

stack without chemical cleaning compounds, including boiler fireside cleaning and air preheater 

cleaning.” Limiting nonchemical metal cleaning wastes to gas-side ash related cleanings is 

appropriate as the focus of the effluent guidelines is to regulate combustion related processes.

If iron and copper limits are applied, further clarification of nonchemical metal cleaning wastes 

is critical. The current definition refers to “metal process equipment;” however this is so vague 

it could be interpreted to apply to essentially any equipment fabricated from metal, such as tanks, 

coolers, pumps, piping, etc... The list of such equipment at AEP’s facilities is quite extensive 

and currently washes of this equipment are typically handled as low volume wastes and internal 

iron and copper limits are not applied. Should such limits be applied, as proposed in the revised 

effluent guidelines, the cost impact, while difficult to determine, is expected to be both extremely 

significant and onerous. To determine the extent of nonchemical metal cleaning washes at its 

facilities, based on AEP’s interpretation of current nonchemical metal cleaning washes,

32 UWAG ELG Comments, September 20, 2013, at 268.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment 

Code 6.g.ii. The final rule does not establish or revise BAT for metal cleaning wastes or boiler 

cleaning wastes.

Commenter Name: Ronald H. Hix

Commenter Affiliation: NextEra Energy, Inc. (NEE)

Document Control Number: EPA-HQ-OW-2009-0819-4461-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Limit the Definition of Nonchemical Metal Cleaning Wastes
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EPA' s interpretation of "metal cleaning waste" has evolved over the decades from a narrow 

focus in the 1974 ELG (see 39 Fed. Reg. at 36,199 col. 1) to one much more expansive in the 

proposed ELG rule. For years, permitters and permittees have understood nonchemical metal 

cleaning wastes to mean only the washes of gas-side process equipment. Ifthe definition of 

"metal cleaning wastes" is expanded to encompass water washing of process equipment other 

than gas-side ash removal, it would be expensive for compliance and of limited environmental 

benefit, especially if comingling is prohibited and iron and copper limits are imposed. The 

criteria would trigger extensive, fact-specific analysis as applied to many types of power plant 

wash waters (e.g. non chemical turbine blades and condenser wash waters).

A specific example of the expansion occurring in this proposed rule is the consideration of 

condenser washes without the use of a chemical agent as a non chemical metal cleaning waste.

It is NEE' s position that power plant condenser cleaning, using high-pressure sprays but without 

the use of chemicals, is not a metal cleaning waste. This position is based on the following 

premises:

The current version of 40 CFR 423.11 (d) Specialized Definitions states:

"(d) The term metal cleaning waste means any wastewater resulting from cleaning (with or 

without chemicals compounds) and metal process equipment including, but not limited to, boiler 

tube cleaning, boiler fireside cleaning, and air preheater cleaning."

Historically, metal cleaning wastes have been limited to processes where chemical agents 

(typically solvents or corrosive liquids) have been utilized for removal of scale and corrosion 

products that have built up on the metal to be cleaned. The most common type of metal cleaning 

is a boiler tube cleaning which uses an acid, solvent or other agent to remove scale and 

contaminants to restore the heat conducting capacity of boiler tubes. The chemical is circulated 

through the tubes (the "water side") to conduct the cleaning. These cleaning solutions are 

generally neutralized, evaporated, sent to dedicated holding ponds for treatment or disposed of 

offsite.

Boiler fireside washes, air preheater washes and stack washes are examples of processes whose 

effluents have historically been considered metal cleaning wastes (more specifically nonchemical metal cleaning wastes). These processes consist of water used to rinse surfaces that 

have been exposed to combustion gases and flue gas, and often accumulate ash and slag.

Nowhere in the past has the simple process of using high pressure washes to clean the waterside 

(inside) of condenser tubes been considered as any type (chemical or non-chemical) of metal 

cleaning waste.

On Page 145 of the "Development Document for Effluent Limitations Guidelines and New 

Source Perfo1mance Standards for the Steam Electric Power Generation Point Source Category" 

(October 1974) condenser cleaning is discussed. It states:
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"Condenser Cleaning -

The other major heat transfer component in a boiler system (NEE Note: boiler and Pressurized 

Water Reactor nuclear steam generators were the other components discussed) is the 

condenser. The spent steam from the turbine is liquefied in the condenser by the condenser 

cooling water system .... Operational cleaning on the steam side depends on boiler water quality 

and is not done frequently. The water side of the condenser is cleaned with inhibited 

hydrochloric acid."

Nowhere in this document does it discuss cleaning of condensers without utilizing chemicals.

Another excerpt for an EPA document, "EPA Office of Compliance Sector Notebook Project: 

Profile of the Fossil Fuel Electric Power Generation Industry (September 1997), on Page 46, 

states,

"Metal and boiler cleaning waste (waterside) -Metal cleaning wastes are produced during 

cleaning of the boiler tubes, superheater, and condenser located on the water-side or steam-side 

of the boiler. Scale and corrosion products build up in the boiler and must be removed with 

chemical cleaning using an acid or alkaline solution."

This document only contemplates chemical metal cleaning of condenser tubes with no mention 

of high-pressure cleaning.

In conclusion, it's is NEE's position that wastewater generated from condenser cleanings that 

utilize corrosives or solvents are metal cleaning wastes. Conversely, there is no indication that 

waterside condenser cleaning using high pressure water should be considered and regulated as a 

metal cleaning waste.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22. See also response to 

DCN EPA-HQ-OW-2009-0819-4470-A1, Excerpt Number 27 in Comment Code 6.g.iii.

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: 67

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should also confirm, as permitters and permittees have understood for years, that 

nonchemical metal cleaning wastes mean only washes of gas-side process equipment. See 
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UWAG 1981 Comments Section IV and Appendices IV(A)-IV(F) at 1-2; 39 Fed. Reg. at 36,199 

col. 2; and UWAG Comments. If the meaning of “metal cleaning wastes” were expanded to 

encompass water washing of process equipment other than gas-side ash removal, this would be 

expensive and of limited environmental benefit, especially if comingling is prohibited and iron 

and copper limits are imposed. The criteria could trigger extensive, fact- specific analysis as 

applied to the many types of power plant washwaters (e.g., turbine blade and condenser 

washwaters). The following approach is more reasonable.

Specifically, EPA should define “nonchemical metal cleaning wastes” as: “any wastewater from 

the cleaning of ash from gas-side process equipment from the boiler to the stack without 

chemical cleaning compounds, including boiler fireside cleaning and air preheater cleaning.”

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22. The final rule does not 

establish or revise BAT for metal cleaning wastes.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-A1

Comment Excerpt Number: 36

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. The Regulatory Definition of “Nonchemical Metal Cleaning Waste” Must be Clarified

To adhere to the definition of “metal cleaning waste” established in both the 1974 and 1982 

limited rulemaking records applicable to steam electric power generating facilities, the term 

“nonchemical metal cleaning waste” should be defined as “any wastewater from the cleaning of 

ash from gas-side process equipment from the boiler to the stack without chemical cleaning 

compounds, including boiler fireside cleaning and air preheater cleaning.” In 1974, the term 

“metal cleaning waste” was narrowly defined as “any cleaning compounds, rinse waters, or any 

other waterborne residues derived from cleaning any metal process equipment including, but not 

limited to, boiler tube cleaning, boiler fireside cleaning and air preheater cleaning.” 39 Fed. Reg. 

at 36,199. This definition explains why many, including Bruce Smith, William Jordan, permit 

writers, and the regulated community, interpreted “metal cleaning wastes” to include only 

effluent streams from cleaning processes involving chemical solutions (acid cleaning of boilers); 

whereas water washing of ash found on boiler firesides and air preheaters constituted a “low 

volume waste.”
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In the decades since this 1974 rulemaking, the terms “metal cleaning waste,” “chemical metal 

cleaning waste,” and “boiler chemical cleaning waste” have been used loosely by many as 

synonyms in NPDES permits. Yet in these same permits, discharges have typically been saddled 

with iron and copper limits only if they are associated with chemical cleaning compounds. 

Specifically referencing NCMCWs in these permits was deemed unnecessary by permit writers 

and the industry alike because the Jordan Memorandum’s guidance clearly provided that such 

water washing operations constitute “low volume waste.” In light of this clear, and well-known 

historical backdrop, EPA cannot attempt to utilize this loose language or the easily explainable 

absence of NCMCW references in NPDES as a basis for asserting that the permit has iron and 

copper limits generically applicable to all “metal cleaning wastes” as defined in the Code of 

Federal Regulations. As explained above, the omission of express references to NCMCWs is 

consistent with industry practice since the 1970s.

Only now in this Proposed Rule is EPA attempting to greatly expand the definition of “metal 

cleaning wastes” as all-encompassing without offering any substantiating discussion, analysis, or 

data beyond the very limited data included in the 1974 and 1982 rulemakings. That data was 

exclusively related to chemical boiler cleaning wastes and nonchemical metal cleaning wastes 

associated with water washing of ash on boiler firesides and air preheaters and was deemed 

insufficient at that time. Such a broad interpretation of the term is simply not supported by the 

record. Attempting to expand the meaning of “metal cleaning wastes” to include water washing 

of process equipment other than gas-side ash removal would be expensive and of limited 

environmental benefit, especially if commingling is prohibited and iron and copper limits are 

imposed. Without additional clarification and a thorough analysis by EPA, any new definition of 

nonchemical metal cleaning wastes should be restricted to the gas-side removal of ash without 

chemicals.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: Patrick Finigan

Commenter Affiliation: Omaha Public Power District (OPPD)

Document Control Number: EPA-HQ-OW-2009-0819-4529-A1

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

E. Nonchemical Metal Cleaning Waste
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EPA is taking comment on the standards for nonchemical metal cleaning waste in the proposed 

rule. The ELGs define metal cleaning waste as ''any wastewater resulting from cleaning [with or 

without chemical cleaning compounds] any metal process equipment, including, but not limited 

to, boiler tube cleaning, boiler fireside cleaning, and air preheater cleaning.'' The definition of 

chemical metal cleaning waste is "any wastewater resulting from cleaning of any metal process 

equipment with chemical compounds, including, but not limited to, boiler tube cleaning.'' The 

regulations do not have a definition of nonchemical metal cleaning waste.

The existing definitions of metal cleaning waste and chemical metal cleaning waste are overly 

broad, and sweep in low-toxicity wastewater such as gas turbine compressor wash water 

comprised of simple detergent and water. EPA should revise the definition of metal cleaning 

waste and chemical metal cleaning waste such that it includes a defined list of metal cleaning 

wastes. EPA may do this by limiting the definition to the cleaning of metal surfaces associated 

with heat transfer or fuel combustion, by adding the terms "contact and noncontact noncombustion," after "any metal" or by limiting the cleaning waste covered to "boiler metal 

cleaning waste." Wastes that are currently covered by the metal cleaning waste provision, such 

as gas turbine compressor wash water, should instead be added to the list of low-volume waste as 

specified in in 40 C.F.R. § 423.11. EPA may need to re-open a comment period to make these 

changes.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment 

Code 6.g.ii. The final rule does not establish or revise BAT for metal cleaning wastes or boiler 

cleaning wastes.

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: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA is taking comment on the standards for nonchemical metal cleaning waste in the proposed 

rule.24 The development of these standards have important implications for the existing ELG 

regulations for metal cleaning waste and chemical metal cleaning waste. The ELG regulations 

define “metal cleaning waste” to mean ‘‘any wastewater resulting from cleaning [with or without 

chemical cleaning compounds] any metal process equipment, including, but not limited to, boiler 

tube cleaning, boiler fireside cleaning, and air preheater cleaning.’’25 The definition of 

“chemical metal cleaning waste” is “any wastewater resulting from cleaning of any metal 

process equipment with chemical compounds, including, but not limited to, boiler tube 
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cleaning.’’26 The existing regulations do not have a definition of nonchemical metal cleaning 

waste.27

The existing definitions of metal cleaning waste and chemical metal cleaning waste are overly 

broad, and sweep in low‐toxicity wastewater such as gas turbine compressor wash water 

comprised of simple detergent and water. EPA should revise the definition of metal cleaning 

waste and chemical metal cleaning waste such that it includes a defined list of metal cleaning 

wastes. EPA may do this by limiting the definition to the cleaning of metal surfaces associated 

with heat transfer or fuel combustion, by adding the terms “contact and noncontact non‐

combustion,” after “any metal” such that the definition would state, ‘‘any wastewater resulting 

from cleaning [with or without chemical cleaning compounds] any metal [“contact and 

noncontact non‐combustion,”] process equipment, including, but not limited to, boiler tube 

cleaning, boiler fireside cleaning, and air preheater cleaning’’ or by limiting the cleaning waste 

covered to “boiler metal cleaning waste.” Wastes that have been improperly categorized, such as 

gas turbine compressor wash water, should instead be added to the list of low‐volume waste as 

specified in in 40 C.F.R. § 423.11. EPA may need to re‐open a comment period to make these 

changes.

24 78 Fed. Reg. 34,465 (June 7, 2013).

25 40 C.F.R. § 423.11(d).

26 40 C.F.R. § 423.11(c).

27 78 Fed. Reg. 34,465 (June 7, 2013).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment 

Code 6.g.ii. The final rule does not establish or revise BAT for metal cleaning wastes or boiler 

cleaning wastes.

Commenter Name: Raymond L. Evans

Commenter Affiliation: FirstEnergy Corp.

Document Control Number: EPA-HQ-OW-2009-0819-4677-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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To further clarify the rules governing nonchemical metal cleaning wastes and retain the original 

meaning of "metal cleaning wastes" as provided in the rulemaking records for 1974 and 1982, 

the EPA should provide a definition for "nonchemical metal cleaning wastes." As recommended 

by UWAG in their comments, "the term nonchemical metal cleaning waste means any 

wastewater from the cleaning of ash from gas-side process equipment from the boiler to the stack 

without chemical cleaning compounds, including boiler fireside cleaning and air preheater 

cleaning."

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 and to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 22.

Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 42

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. Certain Definitions should be expanded and refined:

1. §423.11(a)-Update total residual chlorine definition to remove reference to the method 

used for total residual chlorine.

2. Expand blowdown definition to include relatively small quantities of water from bottom 

ash dewatering systems that would be removed to address dissolved solids concentrations 

if the no discharge of bottom ash transport water is adopted.

3. §423.11(u)-non-chemical metal cleaning wastes-Add “except where previously classified 

as low volume wastes by the permitting authority:”

Comment Response: 

Neither the proposal nor the final rule revises the definition of “total residual chlorine” or 

“blowdown”. For more information regarding the definition of non-chemical metal cleaning 

wastes, see response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15.
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6.g.iii. Metal cleaning wastes (MCW); chemical metal cleaning wastes

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

LPPC members also want EPA to revise the definition of metal cleaning waste, which is overly 

broad.

Comment Response: 

As described in preamble, the final rule does not revise the effluent limitations and standards for 

metal cleaning wastes, chemical metal cleaning wastes, and non-chemical metal cleaning wastes. 

Therefore, the final rule reserves revising the definitions for these wastestreams, which includes 

not defining non-chemical metal cleaning wastes. By not revising the effluent limitations and 

standards and not revising the definitions, the final rule will not result in changes to industry 

operations for the specified wastestreams. However, the permitting authority will continue to 

have discretion in determining which cleaning wastewaters are metal cleaning wastes based on 

the facility-specific operations, the wastewater generated and the wastewater’s characteristics.

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: 27

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

DP&L has the following general comments and/or requests for clarification on this topic:

 Metal cleaning waste should be defined as washes of "gas-side process equipment"; 

expanding the meaning of "metal cleaning wastes" to water washing of process 

equipment other than gas-side ash removal would be expensive and of limited 

environmental benefit, especially if comingling is prohibited and iron and copper limits 

imposed;

 Washwater from turbine blades is not "metal cleaning waste"; turbine washwater has 

always been classified as "low volume waste" and there is no sound reason to change that 

classification now;
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 "Boiler lancing" should be treated as bottom ash transport;

 Detergent should not be considered a "chemical".

Comment Response: 

EPA is not revising the definition for metal cleaning wastes. See response to DCN EPA-HQOW-2009-0819-4573-A1, Excerpt Number 2 for more information about metal cleaning waste 

definition.

Regarding wash water from turbine blades, EPA notes that the commenter provides no 

documentation to support the assertion that “turbine washwater has always been classified as 

‘low volume waste.’" Additionally, EPA would interpret turbine washwater as being included 

within the previously promulgated definition of metal cleaning wastes. Regarding boiler lancing, 

see response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 154 in Comment Code 

22.

Regarding soaps and detergents, EPA disagrees with the commenter that detergents are not 

chemicals and notes that the use of soaps or detergents with water for metal cleaning would 

constitute chemical cleaning. However, as indicated in the final rule preamble, EPA is not 

revising the definition for metal cleaning wastes. For further details see response to DCN EPAHQ-OW-2009-0819-4573-A1, Excerpt Number 2.

Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 19

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

This is concerning in that the definition of metal cleaning waste is not definitive and open-ended. 

This is problematic as it allows permit writers to categorize ANY operation involving the 

cleaning of ANY metal surface and impose iron and copper limitations, regardless of what type 

cleaning is being performed, its purpose, or the concentrations and/or quantities of metals in the 

wash water. This is clearly inappropriate for the simple rinsing of dirt or dust from such items as 

handrails and steel support structures, or pumps and other devices22 prior to maintenance or 

repainting,or rinsing for nothing more than esthetic reasons. It is also inappropriate to consider 

soap or detergent as a "chemical" for the purposes of defining chemical cleaning waste, as the 

definition of "chemical" is applicable to many common substances including water, salt, and 

sugar. Thus water washes with a detergent as the only added chemical should be clearly defined 

as "nonchemical".
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An example of this type of inappropriate categorization is combined cycle combustion turbine 

compressor wash water, which occurred in a 2009 NPDES Permit for our Rainey Generating 

Station near Anderson, South Carolina (NPDES Permit No. SC0048135). A detailed letter dated 

July 20, 2009 was provided to EPA Region IV which contained data definitely demonstrating 

why metal limitations should not be applied to this waste stream . However, the permitting 

agency included the metal limitations per EPA's directive. This clearly proves the need for the 

definition to be limited to the particular waste streams that would be subject to metal limitations.

Therefore, the definition should list specific metal cleaning waste streams that are shown to 

warrant metal limitations, and include all others in the definition of a "low volume waste". In 

particular, combusti on turbine compressor wash water should be listed as a specific "low 

volume waste" in Part 423.11 (b). In the October 14, 1980 proposed rule, EPA made a 

comparable determination when it decided to regulate boiler blowdown discharges as "low 

volume wastes". The reasoning provided was the low levels of iron and copper in boiler 

blowdown and the relatively low flow rates, citing a value of 33,280 gpd at an average coal-fired 

plant and concentrations of 2 and 20 mg/I respectively.23

22 Although the term "process" is included in the definition, this too is undefined and subject to 

varying interpretations.

23 47 FR 52297.

Comment Response: 

See responses to DCN EPA-HQ-OW-2009-0819-4573-A1, Excerpt Number 2 and to DCN EPAHQ-OW-2009-0819-4470-A1, Excerpt Number 27.
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6.g.iv. Transport water

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: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definition of transport water as it relates to bottom ash handling should be more clearly 

defined, especially in relation to submerged scraper conveyor (SSC) systems where the water is 

not utilized for the purpose of transport but for cooling or quenching. A large quantity of the 

water used in the SSC is re-circulated or recycled from a small pond after co-mingling with other 

water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 69.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The specialized definition for transport water under 40 CFR Section 423.11(p) coupled with anticircumvention requirements add to the impracticality of meeting the proposed zero discharge 

requirements and is unworkable as written. The proposed new specialized definition is:

(p) The term transport water means any process wastewater that is used to convey fly ash, 

bottom ash, or economizer ash from the ash collection equipment, or boiler, and has direct 

contact with the ash.

In most furnaces, the hot bottom ash is quenched in a water-filled hopper. Quench water is 

typically continuously fed into the top of the hopper and overflows into station floor drains. In 

addition, leaks of bottom ash transport water from valves, fittings, piping, dewatering bin seals, 

etc. also occur on a routine basis at all plants with this type of equipment. These wastewaters are 

not always directed back to bottom ash impoundments and are often treated within low volume 

wastewater industrial wastewater treatment systems or impoundments.
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Therefore, if the final rule requires zero discharge of bottom ash transport water, significant costs 

would be incurred to separate quench water and leakage from low volume wastewater treatment 

systems. Bottom ash quench water, equipment maintenance, and leaks should be specifically 

excluded from the definition of bottom ash transport water.

Comment Response: 

EPA disagrees with the commenter that bottom ash quench water and equipment maintenance 

should be specifically excluded from the definition of bottom ash transport water. First, EPA 

notes that quench water does not meet the definition of transport water, unless it is specifically 

pulled into the ash sluicing system. Additionally, as noted in preamble, EPA has accounted for 

the costs to temporarily store the bottom ash transport water during equipment maintenance and 

feed it back to the system without discharge in its cost analysis.

However, EPA agrees with the comment that leaks from the ash handling systems should not be 

included in the definition of transport water because the wastewaters are not always directed 

back to the bottom ash treatment systems and are often handled as low volume wastes. 

Additionally, EPA’s cost analyses do not account for any type of containment systems that could 

potentially be needed to segregate these waters and keep them within the system. As such, EPA 

has revised the transport water definition. As described in preamble Appendix A, the term 

transport water means any wastewater that is used to convey fly ash, bottom ash, or economizer 

ash from the ash collection or storage equipment, or boiler, and has direct contact with the ash. 

Transport water does not include low volume, short duration discharges of wastewater from 

minor leaks (e.g., leaks from valve packing, pipe flanges, or piping) or minor maintenance events 

(e.g., replacement of valves or pipe sections). See 40 CFR 423.11(p). 

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 69

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. The Definition of “Transport Water” Should Be Clarified

EPA proposed to define “transport water” for bottom ash and fly ash as “any process wastewater 

that is used to convey fly ash or bottom ash from the ash collection equipment and has direct 

contact with the ash.” 78 Fed. Reg. 34,533 col 3, proposed § 423.22(p).

The important word here, “convey,” should be understood as conveying by means of the 

engineered system for carrying ash to treatment or disposal. It should not include washing of fly 
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ash that may incidentally blow or fall onto floors or other surfaces, which properly belongs with 

“low volume waste.”

This is probably what EPA meant by using the words “from the ash collection equipment.” And 

it is consistent with what EPA says about water that drains from a bottom ash dewatering bunker:

As the bottom ash continues dewatering in the nearby bunker, water that drains from the system 

may be discharged; however, EPA does not consider this water from the bunker to be bottom ash 

transport water because the mechanical conveyor, and not the water, is the transport mechanism 

that moves the ash away from the boiler. Instead, the wastewater draining from the bunker would 

be low volume wastes.

78 Fed. Reg. 34,449 col. 2. So there is no doubt, EPA should clarify that, as a general matter, 

“transport water” includes only the water used in the “transport mechanism” designed and 

intended for the handling of ash.

Comment Response: 

As described in preamble Appendix A, the final rule provides a definition for transport water. 

The term transport water means any wastewater that is used to convey fly ash, bottom ash, or 

economizer ash from the ash collection or storage equipment, or boiler, and has direct contact 

with the ash. Transport water does not include low volume, short duration discharges of 

wastewater from minor leaks (e.g., leaks from valve packing, pipe flanges, or piping) or minor 

maintenance events (e.g., replacement of valves or pipe sections).

The definition clearly states that transport water is wastewater that is used to convey the ash.

Water generated from the mechanical drag system (MDS) is not subject to the bottom ash 

transport water limitations and standards. In a mechanical drag system, the mechanical scraper is 

used to convey the ash; therefore, these systems do not use water as the medium of transport and 

do not constitute a transport water system. Therefore, water generated from the mechanical drag 

system is not subject to the final rule requirements for bottom ash transport water. As such, the 

water draining from the bottom ash is also not transport water. However, in a system that does 

generate bottom ash transport water (e.g., remote MDS), the water that drains from the bottom 

ash in the dewatering bunker is considered bottom ash transport water and is subject to the 

bottom ash transport water limitations and standards.

EPA disagrees with the commenter that EPA needs to clarify the definition of transport water 

because it is already clear in the definition and in the discussion included in the preamble.

Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (ALLETE)

Document Control Number: EPA-HQ-OW-2009-0819-4768-A2

Comment Excerpt Number: 14
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

10. Transport Water clarification. EPA, in the “specialized definitions” found on FR page 

34533, defines the term “transport water”. The term “transport water” should be clarified and 

limited to mean only those waters that are used to convey fly ash or bottom ash from the 

generating facility to the ash impoundment and then only the bulk ash that is sourced from bag 

houses, electrostatic precipitators or other primary fly ash removal devices or bottom ash 

collection devices or similar systems that are designed to collect the majority of the fly ash or 

bottom ash from the coal combustion process.

Comment Response: 

EPA disagrees with the commenter that the definition of transport water should be limited to the 

conveyance of “fly ash or bottom ash from the generating facility to the ash impoundment.” If 

EPA were to limit the definition to a specific destination, plants could alter their operations to 

transport the wastewater to any destination other than an impoundment (e.g., basin, tank, 

dewatering bin, surface water) and only need to comply with the low volume waste sources 

limitations and standards.

EPA agrees with the commenter that the transport water is associated with the conveyance of ash 

from the “fly ash removal devices or bottom ash collection devices or similar systems,” which is 

why EPA included in the definition the language: “from the ash collection or storage equipment, 

or boiler.” EPA notes, however, that the definition also includes economizer ash, not just fly ash 

and bottom ash.

Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (MP)

Document Control Number: EPA-HQ-OW-2009-0819-4484-A1

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Transport Water clarification. EPA, in the “specialized definitions” found on FR page 34533, 

defines the term “transport water”. The term “transport water” should be clarified and limited to 

mean only those waters that are used to convey fly ash or bottom ash from the generating facility 

to the ash impoundment and then only the bulk ash that is sourced from bag houses, electrostatic 

precipitators or other primary fly ash removal devices or bottom ash collection devices or similar 

systems that are designed to collect the majority of the fly ash or bottom ash from the coal 

combustion process.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4768-A2, Excerpt Number 14.

Commenter Name: Nysa Hogue

Commenter Affiliation: Indianapolis Power & Light Company (IPL)

Document Control Number: EPA-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should clarify the definition of "transport water" to specify that it means only those waters 

used to convey fly ash or bottom ash from the generating facility to the ash 

impoundment. Transport water should include only water used to convey bulk ash that is 

sourced from bag houses, electrostatic precipitators, or other primary fly ash removal devices or 

bottom ash collection devices or similar systems that are designed to collect fly ash or bottom 

ash from the coal combustion process. IPL also recommends that EPA amend 40 CFR 423.11 to 

replace the current definition of "bottom ash" with the definition EPA includes in Appendix A. 

The proposed amended definition will clarify that boiler slag is bottom ash. In addition, the 

definition clarifies that ash removed through boiler lancing (i.e., "ash dislodged from furnace 

walls") is bottom ash.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4768-A2, Excerpt Number 14.

See response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45 in Comment 

Code 6.g.ix.

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: 50

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Definitions of Bottom Ash and Transport Waters Should Be Clarified.
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EEI recommends that EPA amend the proposed definition of “bottom ash,” which does not make 

clear that boiler slag is included, by replacing it with the definition in Appendix A to the 

proposed rule.14 The Appendix A bottom ash definition explicitly includes boiler slag:

The ash, including boiler slag, that drops out of the furnace gas stream in the furnace and which 

settles in the furnace or are [sic] dislodged from furnace walls. Economizer ash is included when 

it is collected with bottom ash.

78 Fed. Reg. at 34,532 col. 2.

Consistent with the Appendix A bottom ash definition, similar references to boiler slag as bottom 

ash occur throughout the preamble and the 2013 TDD (78 Fed. Reg. at 34,450 col. 1; at 34,453 

col 2; at 34,458 col.1; at 34,481, fn. 55; 2013 TDD at 8-2).

In addition to clarifying that boiler slag is bottom ash, such a proposed amended definition would 

clarify that ash removed through boiler lancing (i.e., “ash dislodged from furnace walls”) is 

bottom ash.

EEI recommends EPA amend section 423.11 to replace the current definition of “bottom ash” 

with the definition EPA includes in Appendix A. The proposed amended definition will clarify 

that boiler slag is bottom ash. In addition, the definition clarifies that ash removed through boiler 

lancing (i.e., “ash dislodged from furnace walls”) is bottom ash.

EPA also should clarify the definition of “transport water” at 78 Fed. Reg. 34533 to specify that 

it means only those waters used to convey fly ash or bottom ash from the generating facility to 

the ash impoundment. Transport water should include only water used to convey bulk ash that is 

sourced from bag houses, electrostatic precipitators, or other primary fly ash removal devices or 

bottom ash collection devices or similar systems that are designed to collect fly ash or bottom 

ash from the coal combustion process.

14 It is unclear why EPA included Appendix A in the preamble. Apparently EPA wanted to help 

readers of the proposed rule by including “[d]efinitions, [a]cronyms, and [a]bbreviations used in 

this notice”(78 Fed. Reg. at 34,532 col. 1). But in some cases the Appendix A definitions differ 

from the definitions in the proposed rule. The two should be consistent.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4768-A2, Excerpt Number 14.

See response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45 in Comment 

Code 6.g.ix.
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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: 165

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

5. The New Definition of “Low Volume Waste” Appears to Be Acceptable, with the 

Understanding that Ash from Venturi Scrubbers Is Not “Fly Ash Transport Water”

The proposed definition of “low volume waste” in proposed § 423.11 is as follows:

(b) The term low volume waste sources means, taken collectively as if from one source, 

wastewater from all sources except those for which specific limitations are otherwise established 

in this part. Low volume waste sources include, but are not limited to, the following: wastewaters 

from ion exchange water treatment systems, water treatment evaporator blowdown, laboratory 

and sampling streams, boiler blowdown, floor drains, cooling tower basin cleaning wastes, 

recirculating house service water systems, and wet scrubber air pollution control systems whose 

primary purpose is particulate removal. Sanitary wastes, air conditioning wastes, and wastewater 

from carbon capture or sequestration systems are not included in this definition.

This new definition includes “wet scrubber air pollution control systems” for particulate 

removal. In the preamble, EPA says that EPA proposes to remove FGD wastewater from the 

definition:

EPA is proposing to remove FGD wastewater, FGMC wastewater, gasification wastewater, and 

leachate from the definition of low-volume wastes.

78 Fed. Reg. at 34,457 col. 3.

As we understand the proposed definitions, ash collected in Venturi scrubbers is not considered 

“fly ash transport water” subject to a no-discharge requirement.

“Low volume waste” sources include “wet scrubber air pollution control systems whose primary 

purpose is particulate removal.” “Fly ash” does not include ash “when it is collected in wet 

scrubber air pollution control systems whose primary purpose is particulate removal.” Finally, 

flue gas desulfurization wastewater includes process wastewater generated from a scrubber 

system, including “any solids separation or solids dewatering processes.”

Thus we understand the references to particulate removal to refer to Venturi scrubbers. As noted 

in this passage from the 2013 TDD, EPA has determined that ash collected in Venturi scrubbers 

is not considered fly ash subject to the no discharge prohibition for fly ash transport water:
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Steam electric units employ three main particulate collection methods to remove fly ash from the 

flue gas: electrostatic precipitators (ESPs), baghouses, and venturi-type wet scrubbers....

....

Additionally, between fifteen and twenty-five generating units use venturi-type wet scrubbers to 

remove fly ash from the flue gas [ERG, 2013]. Venturi scrubbers contain a tube with flared ends 

and a constricted middle section. The flue gas enters from one of the flared ends and approaches 

the constricted section. A liquid slurry stream is added to the scrubber just prior to or at the 

constricted section. As the flue gas enters the constricted section, its pressure and velocity 

increases, which causes the gas and liquid slurry to mix. The greater the pressure drop in the 

scrubber, the better the mixing, and the better the reaction rate, which increases the particulate 

removal efficiency. However, venturi scrubbers must be operated at high pressure drops to 

remove the same level of particulates as ESPs, making their operation costs higher than ESPs 

[Babcock & Wilcox, 2005; U.S. EPA, 2010]. Based on the proposed revisions to the specialized 

definitions, described in Section 2.2, EPA does not consider the ash collected by venture [sic] 

scrubbers as fly ash, and therefore, the water generated by these systems is not considered fly ash 

transport water.

2013 TDD at 4-19 to -21(emphasis added).

EPA would do well to clarify in the preamble to the final rule that ash collected by Venturi 

scrubbers is not considered “fly ash” and that water generated by Venturi scrubber systems is not 

“fly ash transport water.”

Comment Response: 

The term fly ash means the ash that is carried out of the furnace by a gas stream and collected by 

a capture device such as a mechanical precipitator, electrostatic precipitator, or fabric filter. 

Economizer ash is included in this definition when it is collected with fly ash. Ash is not 

included in this definition when it is collected in wet scrubber air pollution control systems 

whose primary purpose is particulate removal. See preamble Appendix A.

EPA agrees with the commenter’s evaluation and EPA confirms that ash collected by Venturi 

scrubbers is not considered “fly ash” and that the water generated by Venturi scrubber systems is 

not “fly ash transport water” for the purposes of this final rule because it does not fall under the 

definition of fly ash as described in this response and in the preamble.
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6.g.v. Dry bottom ash handling system

Commenter Name: Chas Spell

Commenter Affiliation: Arizona Public Service Company

Document Control Number: EPA-HQ-OW-2009-0819-4303-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

APS requests that EPA modify the definition of “dry bottom ash handling system.” The 

proposed rule defines a dry bottom ash handling system as, “[a] system that does not use water to 

convey bottom ash away from the boiler. It includes systems that collect and convey the ash 

without the use of water, as well as systems in which bottom ash is mechanically or 

pneumatically conveyed away from the boiler.” EPA should amend the definition to 

acknowledge that the addition of moisture, up to 30%, is required for disposal compaction and 

fugitive dust mitigation. Furthermore, the definition should include the use of water to capture 

bottom ash. As EPA discusses in the preamble of the proposed rule, many handling systems are 

available, which eliminate the discharge of bottom ash transport water yet utilize water to 

capture bottom ash. By changing the definition to reflect the realities of water use in dry bottom 

ash handling systems, EPA can provide much needed clarity to the regulated community.

Comment Response: 

EPA did not propose to define the term “dry bottom ash handling” in the regulation, nor is it 

doing so in the final rule. The ELGs establish requirements for the discharge of pollutants in fly 

ash or bottom ash transport water, thus it is the term “transport water” that EPA does define in 

the final rule. That definition states, in part, that ash transport water is “wastewater that is used to 

convey fly ash, bottom ash, or economizer ash from the ash collection or storage equipment, or 

boiler, and has direct contact with the ash.” This accomplishes as least part of what the 

commenter is requesting because it specifically states that the transport water is wastewater used 

to convey the ash; by stating that, there is no need for the definition to also list mechanical and 

pneumatic conveyances as not being transport water. See preamble Appendix A for more 

information. 

EPA included the term “dry bottom ash handling system” in the glossary for the preamble and 

support documents as a short-hand term to easily refer to several technologies that do not use 

water as the motive force to convey ash. In these instances, it is broadly referring to types of ash 

handling technologies as a means of presenting information. Adding the language suggested by 

the commenter would not enhance the presentation of information in those documents and EPA 

determined that it may well introduce confusion.
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Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Use of Wastewater to “Condition” Ash

EPA references the use of FGD water in U.S. power plants to “condition” dry fly ash to control 

dust and/or to assist with compaction in its Final Detailed Study Report (Page 4-39). Clearly 

wastewater is already being mixed with ash as a mechanism to reduce wastewater volume and 

this referenced application is referred to as a “dry ash management technology”.

A primary intent of the proposed rule is to reduce, and in some cases eliminate, discharge of 

wastewater to the surface waters of the United States. This intent makes it understandable that 

the EPA emphasizes the use of “dry ash” management systems.

DSS technology clearly straddles the proposed ELG and CCR rules and is thus pertinent to 

EPA’s discussion on the Intersection Between the Proposed ELG and Coal Combustion 

Residuals Rules (ELG preamble III, G). The wording of the proposed ELG rule uses the term 

“sluicing” with the same meaning as the specialized definition: “transport water” (423.11(p)). At 

first glance, this may seem correct. But the specialized definition of “transport water” also 

includes the term “wastewater”. With DSS, the water that is mixed with the ash (whether it is 

FGD water, impoundment leachate, process water or other water) is consumed by hydration, 

pozzolanic reactions, bound by capillary forces and/or encapsulation and some water evaporates. 

Thus, with DSS, “transport water” is not wastewater pursuant to how wastewater is defined in 

the proposed rule. Instead, the transport water is stabilized along with the ash in a solid end 

product exhibiting favorable environmental properties. Leachate collected from dense slurry ash 

impoundments and/or landfills can be returned to the plant and used to produce additional dense 

slurry if appropriate.

The proposed rule requires revision to further define and distinguish terms such as “sluicing”. 

While DSS resembles “sluicing” during the initial preparation of the slurry, it results in a solid 

product exhibiting high compressional strength with no wastewater treatment or discharge 

requirements.

Comment Response: 

EPA does not agree that the “ELG rule uses the term ‘sluicing’ with the same meaning as the 

specialized definition: ‘transport water.’” EPA uses the term “sluicing” to refer to the specific 

operation conducted at plants to transport fly ash, bottom ash, or economizer ash away from the 

ash collection system. EPA uses the term “transport water” to refer to the water generated from 
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activities such as sluicing or any other activities that use transport water to convey the ash, such 

as the dense slurry operation. See preamble Appendix A for more information.

EPA also disagrees with the commenter that “with DSS, ‘transport water’ is not wastewater 

pursuant to how wastewater is defined in the proposed rule” because EPA did not define 

“wastewater” in the proposed rule. EPA has determined that the dense slurry system does 

generate transport water; therefore, would be subject to the final rule requirements for fly ash or 

bottom ash transport water. 

See the response to DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 13.

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

GEA EGI recommends that the proposed rule be modified to refine the definition of “dry ash” 

management to mean any ash management system or technique that eliminates waste transport 

water destined for treatment and/or off-site discharge regardless of its initial appearance or 

how it is prepared (even if it uses more water than the concept of “dry ash” management as 

referenced in the proposed rule). The current use and definition of “dry ash” in the proposed rule 

and preamble is not clear and seems to imply that “dry ash” management techniques do not 

employ the use of water even though most do.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4303-A2, Excerpt Number 9.

In addition, EPA does not agree with the commenter’s suggested language, which might confuse 

people by implying that the definition of ash transport water is broader than intended in the final 

rule. The commenter’s suggestion implies that ash handling technologies that do not use water as 

the means for transporting ash are within the definition of ash transport water, which they are 

not. 

Commenter Name: Lili Kranitz

Commenter Affiliation: GEA EGI Contracting/Engineering Co. Ltd.

Document Control Number: EPA-HQ-OW-2009-0819-5093-A2

Comment Excerpt Number: 13
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

GEA EGI suggests that the proposed ELG rule be modified to recognize the dense slurry process 

as a viable option for wastewater and ash management. Specifically, the rule should be modified 

to recognize a distinction between the two fundamentally different types of slurry that are used to 

transport coal combustion products to an impoundment or landfill. The two types include:

1. Pumped ash slurries that use roughly 10-20 parts water to 1 part ash (commonly termed

“lean slurry”). Lean slurry is the traditional ash transport method referenced in the 

proposed rules. Lean slurry contains copious amounts of excess contact water that is 

currently prohibited in new impoundments and that is prohibited altogether under the 

proposed ELG rule. This type of slurry does not produce a solid product but instead 

produces a sludge that presents a risk of liquefaction in the event of a dike failure. In 

addition, the contents of lean slurry impoundments are not consolidated or cemented. So 

in the event that this material dries on the surface, it can be easily mobilized by wind to 

create a dust hazard. Lastly, lean slurry impoundments exhibit relatively high hydraulic 

conductivity and so tend to produce large quantities of leachate that can pose a threat to 

ground water.

2. Pumped ash slurries that use roughly 1 part water to 1 part ash (commonly termed “dense

slurry”). Dense slurry is initially a thick pumpable fluid that solidifies by virtue of 

hydration and pozzolanic reactions to create a solid product within 24-72 hours following 

discharge. The water mixed with the ash is consumed near stoichiometrically (depending 

upon ash chemistry) resulting in very small quantities of free liquids. Any small amount 

of free liquid that may be present is lost to evaporation or bound by capillary forces in the 

cured product. Thus, discharge or treatment of transport water is not required. Upon 

curing, the dense slurry product is not subject to liquefaction or release of fugitive 

emissions. Discharge of wastewater is not required and enhanced protection of ground 

water is realized by virtue of enhanced metals sequestration, high capillary forces and 

low hydraulic conductivity of the cured product.

GEA EGI is suggesting that the proposed rule be modified to specifically allow power plant 

operators to pump dense slurry into landfills and/or impoundments provided the operator can 

demonstrate that the slurry solidifies within a reasonable period of time to produce a product that 

is not susceptible to liquefaction, does not require treatment/discharge of transport water and 

otherwise satisfies the intent of the proposed rule. Demonstrating dense slurry product 

performance can be achieved by testing selected “recipes” consisting of various mixtures of 

CCRs and wastewater from candidate plants in advance of deployment.

Comment Response: 

The final rule does not require steam electric power plants to use any specific technologies to 

comply with the final rule requirements, nor does EPA find a need for the rule to differentiate 

between what the commenter refers to as lean slurry and dense slurry wet ash handling practices. 
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The final rule establishes a zero discharge limit for pollutants in fly ash transport water and 

bottom ash transport water. Steam electric power plants may use the dense slurry process to 

transport the ash to the disposal site; however, because the dense slurry process generates 

transport water, the steam electric power plant must still meet the no discharge of wastewater 

pollutant limitations and standards.

As already noted, the ELGs do not require the use of a specific technology, nor do they prohibit 

the use of specific technologies. EPA recognizes the differences in the dense slurry process and 

traditional wet-sluicing (i.e., lean slurry) processes. Because of the much smaller volume of 

water used for the dense slurry process, steam electric power plants should be better able to 

engineer and operate the process that process so that there will be no discharge. To accomplish 

this, plants should divert stormwater away from the dense slurry to the extent practicable. If 

stormwater or other wastestreams come into contact with the dense slurry prior to completing the 

solidification and evaporation or encapsulation of the transport water, the fly and bottom ash in 

the commingled wastestream would need to comply with the zero discharge standard for fly ash 

and bottom ash transport water. 

Also, see response to DCN EPA-HQ-OW-2009-0819-5093-A2, Excerpt Number 5.
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6.g.vi. Gasification wastewater

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 99

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Definition of Gasification Wastewater is Overly Broad and Should be Modified

There are two slightly different versions of the definition for “gasification wastewater” included 

in the Proposed Rule.65 Both definitions are similar, but one says “any process wastewater”, 

while the other says wastewater “from all sources ... except those for which specific limitations 

are otherwise established.” This definition should be reconciled, such that sources with other 

established limitations would be excluded.

Additionally, EPA includes the following wastestreams they believe should be included in this 

definition: “Gasification wastewater includes, but is not limited to, the 

following: slag handling wastewater; sour/grey water (which includes condensate generated 

for gas cooling, as well as other wastestreams); CO2/steam stripper wastewater; air separation 

unit blowdown; and sulfur recover unit blowdown.“66 However, this list is overly broad in 

including certain wastestreams, such as the air separation unit blowdown. Air separation unit 

blowdown is a clean condensate that does not warrant expensive treatment in a vapor 

compression evaporator. In addition, although the proposed definition lists a number of varied 

wastestreams from IGCC facilities, the sampling events that EPA conducted focused only on 

effluent consisting of the vapor-compression evaporator condensate from the grey water 

treatment systems. It is inconsistent to then establish the same effluent limits for all other 

ancillary wastestreams, which could be located at multiple additional outfalls, based only on the 

sampling data from the narrow subset of grey water effluent data associated with the vaporcompression evaporation technology installed.

EPA also requested comments on areas that could limit or hinder the reuse or recycling of water. 

Including the clean condensate streams in this broad definition of gasification wastewater could 

hinder the reuse and recycling of water at an IGCC facility. The water generated by the air 

separation unit process, which EPA currently lists in the proposed definition, is a relatively pure 

water condensate generated from the compression of atmospheric air. If this condensate were to 

be included in this definition and then subject to the vapor-compression evaporation treatment 

technology, it would become unavailable to be used in other plant processes, such as for cooling 

tower make-up or gasification make-up water, which would result in the unnecessary 

consumption of additional water to support these processes.

Therefore, Duke Energy recommends that if EPA includes effluent limits for gasification 

wastewater in the Final Rule, then the definition be modified to clarify that gasification 
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wastewater should only include wastewaters which are specific to the IGCC gasification process, 

which should include only wastewater that is associated with the grey water system. The 

reference to the air separation unit and its associated condensate should be expressly removed.

65 78 Fed. Reg. at 34532 and 34533

66 78 Fed. Reg. at 34533

Comment Response: 

In response to comments, EPA revised the definition for gasification wastewater in the final rule. 

See 40 CFR 423.11(q). The revised definition clarifies that gasification wastewater includes the 

wastewater generated from the “gasification block” associated with the gasifier or syngas 

cleaning, combustion, and cooling processes. As such, gasification wastewater includes, but is 

not limited to the following: sour/grey water; CO2/steam stripper wastewater; sulfur recovery 

unit blowdown, and wastewater resulting from slag handling or fly ash handling, particulate 

removal, halogen removal, or trace organic removal. As suggested by the commenter, EPA 

revised the definition to exclude wastewater from air separation unit blowdown. This wastewater 

was not treated in the evaporation systems evaluated by EPA for this rule, and EPA determined 

that setting limitations and standards that include the air separation unit blowdown would result 

in additional costs beyond what EPA estimated for the plants to retrofit their operations. 

Furthermore, the wastewater from this process does not result from the gasifier itself, nor from 

syngas cleaning, combustion, or cooling.

The revised definition also excludes noncontact cooling water and runoff from fuel and/or 

byproduct piles.

EPA notes that the final rule does not include any anticircumvention provisions related to 

commingling of wastestreams applicable to wastestreams with numerical limitations, like 

gasification wastewater. See preamble section VIII.G.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 168

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. The Two Different Definitions of “Gasification Wastewater” Are Not Clear
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In the proposed BAT rules, “gasification wastewater” from existing sources would be subject to 

BPT limits for TSS and oil and grease and BAT limits for arsenic, mercury, selenium, and total 

dissolved solids. In particular, the arsenic limits are 4 μg/L as a daily maximum and unspecified 

for a monthly average.

The definition of “gasification wastewater” in proposed § 423.11 (78 Fed. Reg. at 34,533 col. 3) 

is this:

...any process wastewater generated from a system used to create synthesis [sic] gas from fuels 

such as coal or petroleum coke. Gasification wastewater includes, but is not limited to, the 

following: slag handling wastewater, sour/grey water (which includes condensate generated for 

gas cooling, as well as other wastestreams), CO2/steam stripper wastewater, air separation unit 

blowdown, and sulfur recovery unit blowdown.

A slightly different definition appears on page 34,532 col. 3:

Gasification Wastewater – Wastewater from all sources at an integrated gasification combined 

cycle operation except those for which specific limitations are otherwise 

established. Gasification wastewater includes, but is not limited to the following: slag handling 

wastewater; fly ash and water stream; sour/grey water (which consists of condensate generated 

for gas cooling, as well as other wastestreams); CO2/steam stripper wastewater; air separation 

unit blowdown; and sulfur recover unit blowdown.

Thus one definition says “any process wastewater,” while the other says wastewater “from all 

sources ... except those for which specific limitations are otherwise established.”

All three existing integrated gasification combined cycle (IGCC) plants (Polk, Wabash River, 

and Edwardsport) are different, and there are significant design differences and variations in the 

processes used, resulting in different byproducts.

The IGCC units generate different commercial byproducts. Each of the three burns a different 

fuel (petroleum coke, petroleum coke-coal blend, and coal). More attention should be given to 

defining what the wastestreams are before turning to the question of what data are needed to 

characterize those wastestreams.

If EPA does promulgate different limitations for “gasification wastewater,” it should define the 

wastestream to include only wastewater specific to the IGCC gasification process, meaning 

wastewater associated with the grey water system. References to air separation units and 

condensate from them should not be included.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 99.
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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: 76

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Two Different Definitions of “Gasification Wastewater” are Not Clear

If EPA retains gasification wastewater as a wastestream, it should clarify the definition of 

“gasification wastewater” subject to the proposed limitations and should specify that permit 

writers should fully take into account background levels of arsenic and selenium in setting and 

ELGs for those metals. The proposed rule contains two different definitions. First, the definition 

of “gasification wastewater” in proposed §423.11 (78 Fed. Reg. at 34,533 col. 3) is:

any process wastewater generated from a system used to create synthesis [sic] gas from fuels 

such as coal or petroleum coke. Gasification wastewater includes, but is not limited to, the 

following: slag handling wastewater, sour/grey water (which includes condensate generated for 

gas cooling, as well as other wastestreams), CO2/steam stripper wastewater, air separation unit 

blowdown, and sulfur recovery unit blowdown.

However, there is a slightly different definition on page 34,532 col. 3:

Gasification Wastewater – Wastewater from all sources at an integrated gasification combined 

cycle operation except those for which specific limitations are otherwise 

established. Gasification wastewater includes, but is not limited to the following: slag handling 

wastewater; fly ash and water stream; sour/grey water (which consists of condensate generated 

for gas cooling, as well as other wastestreams); CO2/steam stripper wastewater; air separation 

unit blowdown; and sulfur recover unit blowdown.

In short, one definition says “any process wastewater,” while the other says wastewater “from all 

sources...except those for which specific limitations are otherwise established.”

There should be only one definition. The second definition, which includes all wastestreams 

except those that have specific limitations, should be the only one.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 99.

Commenter Name: Paul Carpmone

Commenter Affiliation: Tampa Electric Company (TEC)
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Document Control Number: EPA-HQ-OW-2009-0819-4520-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Gasification Wastewater Defined Inconsistently

There is inconsistency between the preamble and the proposed rule in the definition of 

gasification wastewater. The first definition provided in the preamble (78 Fed. Reg. at p. 34,532 

col 3) is the following.

"Gasification Wastewater- Wastewater from all sources at an integrated gasification combined 

cycle operation except those for which specific limitations are otherwise established 

. Gasification wastewater includes, but is not limited to the following: slag handling 

wastewater; fly ash and water stream ; sour/grey water (which consists of condensate generated 

for gas cooling, as well as other wastestreams); C02/stearn stripper wastewater; air separation 

unit blowdown ; and sulfur recover unit blowdown."

Within the proposed rule (78 Fed. Reg. at p. 34,533 col 3), EPA defines gasification wastewater 

to include

"any process wastewater generated from a system used to create synthesis [sic] gas from fuels 

such as coal or petroleum coke. Gasification wastewater includes, but it not limited to, the 

following: slag handling wastewater, sour/grey water (which includes condensate generated for 

gas cooling, as well as the other wastewater); CO2/steam stripper wastewater; air separation 

unit blowdown; and sulfur recover unit blowdown."

The definition in the proposed rule should be the same as the definition in the preamble to be 

consistent and to provide the distinction that gasification wastewater does not (and should not) 

include wastestreams "for which specific limitations are otherwise established".

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 99.
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6.g.vii. New source

Commenter Name: David Y. Chung

Commenter Affiliation: Homer City Generation, L.P

Document Control Number: EPA-HQ-OW-2009-0819-5552-A2

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Finally, to the extent a facility expands upon an existing landfill, such expansion should not 

trigger the definition of “new source” in 40 C.F.R. § 122.29. Existing solid wastes (e.g., fly ash, 

bottom ash, gypsum, etc.) from the steam electric industry are routinely added to landfills. When 

new wastes are generated, disposal will likely occur in landfills.4 Consequently, active captive 

and non-captive landfills (and inactive landfills that become active) are in a continuous state of 

expansion and can be expanded horizontally and vertically for many years. Such expansions 

might include construction on onsite lands not contiguous with an existing landfill or at off-site 

locations. When a facility merely expands an existing landfill, it is not: (i) constructing a facility 

at a site where no other source is located; (ii) totally replacing process of production equipment 

that causes the discharge of pollutants at an existing source; or (iii) a source whose processes are 

substantially independent of an existing source at the same site. See id. § 122.29 (b)(1) (setting 

forth criteria for new source determinations).5

4 For example, waste biosolids from a new biological treatment system or crystallized salts 

associated with a new spray drier would be considered new wastes requiring disposal.

5 As set forth in more detail above, Homer City urges EPA not to finalize any of its proposed 

“anti-circumvention” provisions. If EPA chooses to do so, it should not impose any internal 

monitoring requirement for the BAT limits for leachate (i.e., it should not finalize Options 4 or 

5), and it should retain the language allowing for co-treatment of FGD wastewater with leachate 

without requiring operators to demonstrate compliance with the BAT limits for FGD wastewater 

prior to such co-treatment.

Comment Response: 

See Response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 18
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

V. EPA SHOULD CONFIRM THAT ADDITIONAL LANDFILL CAPACITY 

DEDICATED TO CCR DISPLACED AS A RESULT OF AN ELG REQUIREMENT ARE 

EXISTING SOURCES

USWAG seeks confirmation that any landfills constructed to manage CCR displaced as a result 

of a facility’s compliance with a newly imposed ELG requirement is not a “new source” and that 

any combustion residual leachate from such landfills is not subject to the rule’s new source 

pretreatment standards for combustion residual leachate. Clarification of this position is 

important because, under EPA’s preferred options, certain existing wastewater streams could 

become subject to a zero discharge standard. If this option is selected in the final rule, the likely 

alternative management practice for many utilities will be to convert to dry handling of fly ash 

and to dispose of the displaced CCR via dry handling in a landfill. While some utilities operate 

dry and wet handling systems in tandem and have adequate existing landfill space to manage the 

displaced CCR, many utilities currently manage CCR in impoundments and are unlikely to have 

existing landfill capacity to handle this diverted wastestream. These facilities will be compelled 

in many instances to expand or construct additional onsite landfills at their facilities. If sufficient 

space is not available or conditions are not otherwise suitable for constructing a landfill onsite, 

additional offsite landfill capacity will need to be constructed for the displaced CCR. In either 

case, the additional offsite landfill capacity will be dedicated to the same CCR that has 

been diverted from the pre-existing impoundment. For the reasons discussed below, 

USWAG requests that EPA clarify that this additional landfill capacity is not subsumed by the 

ELG requirements for new sources and, in particular, that the combustion residual leachate from 

such additional capacity is not subject to the proposed pre-treatment standards for combustion 

residual leachate from new sources.

EPA defines a “new source,” in part, as a newly constructed “building, structure, facility or 

installation from which there is or may be a Discharge of pollutants.” 40 C.F.R. §§ 122.2, 

403.3(m). Importantly, though, EPA’s guidance is clear that the term “source” in the definition 

of new source refers to the “facility generating the discharge, not the system treating it.” Laura 

Boorznazian, EPA, to Regional Water Division Directors (Sept. 26, 2006) (emphasis added); see 

also Transcript from EPA Aug. 20, 2013 Webinar on “Stream Electric Power 

Generating Effluent Guidelines – Proposed Rule,” at 13 (clarifying that “a new source is a new 

generating unit at an existing facility or . . . a new green field type of facility altogether.”). Thus, 

“in EPA’s view, where an owner or operator makes changes only to its wastewater treatment 

systems, and no changes occur in the production or wastewater generating processes of the plant, 

the source should not be reclassified as a new source.” Id. The same logic applies to facilities 

that must alter their CCR management practices to comply with the forthcoming ELG standards, 

but which make no changes in the production process that produces the regulated waste in the 

first instance –i.e., the stream electric generation process.
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When finalized, the ELG rule likely will require existing sources to institute broad changes in 

how they manage certain CCR wastestreams. The waste management modifications likely to be 

required by this rule will reduce the volume of wastewater to be discharged from facilities and 

will change the character of the wastewater, for example, from predominantly fly ash transport 

water from an impoundment to a lower volume of combustion residual leachate from CCR 

managed in a landfill. However, it is important to recognize that the source of these 

wastestreams—i.e., the steam electric generation facilities themselves—are not required to 

undergo any changes as a result of this rule. These modifications solely affect the waste 

management process and therefore any changes to the waste treatment process – i.e., the 

additional landfill capacity used to manage the displaced CCR from the same production 

source –should not be construed as "new sources."

In addition to being consistent with EPA’s established guidance regarding the definition of a 

“new source,” there are sound policy reasons for confirming that additional landfill capacity 

constructed to manage CCR displaced due solely to compliance with the ELG rule are not new 

sources. As an initial matter, from a risk perspective, the combustion residual leachate from the 

additional landfill capacity is, for all practical purposes, identical in composition to combustion 

residual leachate from “existing source” landfills. Moreover, it is not equitable to compel 

facilities to expend vast sums to convert existing sources to dry handling and, as a result of their 

efforts to comply with the rule, transform their status from existing source to new source.

Therefore, for the above reasons, USWAG requests that EPA confirm in the final rule that 

additional landfill capacity constructed to manage CCR displaced in order for a facility to 

comply with a zero discharge standard (or other new standard) is not a “new source” and that the 

leachate from such facilities are not subject to the new source pretreatment standards.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 149

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

E. New Landfill Cells and Additional Landfill Capacity Constructed to Manage Wastes 

Displaced as a Result of the ELG Revisions Are Not “New Sources”

It is possible that the new ELG rule, depending on what limits it sets for bottom ash and fly ash 

transport water, may cause power plants to cease managing certain coal ash transport waters in 
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impoundments and begin disposing of coal ash in landfills instead. As a result, existing landfills 

may have to be enlarged, and additional landfill capacity may have to be created either on- or 

offsite to manage the coal ash wastestreams displaced as a result of the revised ELG 

requirements that prohibits using impoundments to manage such wastes.

Because power stations may need to create addition landfill capacity for displaced wastestreams 

under the revised ELG rules, it is important for EPA to clarify in the final rule that new cells at 

existing landfills and additional landfill capacity – whether constructed on- or offsite – necessary 

to manage coal ash wastestreams displaced as a result of a revised ELG requirement are not 

“new sources” subject to “new source” performance standards. Similarly, EPA should clarify 

that combustion residual leachate from such additional capacity is not subject to the proposed 

pretreatment standards for combustion residual leachate from new sources (PSNS), but rather 

remains subject to the proposed PSES standards for existing sources.

This position is consistent with longstanding EPA policy. EPA guidance says that the term 

“source” in the definition of new source refers to the “facility generating the discharge, not the 

system treating it.” Memo from L. Boornazian and M. Smith, EPA, to Regional Water Division 

Directors (Sept. 28, 2006) (emphasis added) at 4, available at

www.epa.gov/npdes/pubs/newsource_dates.pdf. Thus, “in EPA’s view, where an owner or 

operator makes changes only to its wastewater treatment systems, and no changes occur in the 

production or wastewater generating processes of the plant, the source should not be reclassified 

as a new source.” Id.; see also 49 Fed. Reg. 37,998, 38,044 (Sept. 26, 1984).

Indeed, EPA’s own definition of “new source” does not apply to new cells or additional landfill 

capacity constructed to manage wastestreams from the same generating facility, for the reasons 

given below.

1. New Cells at an Existing Landfill

If a steam electric generating station opens a new cell in an existing landfill, the new cell is not a 

“new source” to which new source performance standards apply. The criteria for new source 

determinations are at 40 C.F.R. § 122.29(b). Section 122.29(b)(1) defines when a “source” 

(defined in § 122.29(a)(2) as any building, structure, facility, or installation from which there is 

or may be a discharge of pollutants) is classified as a “new source.”

First, a source is a new source when it is “constructed at a site at which no other source is 

located.” 40 C.F.R. § 122.29(b)(1)(i). An entirely new generating facility (at a “greenfield” site) 

is a new source. “New sources” also include sources (1) that totally replace the process or 

production equipment that causes the discharge of pollutants at an existing source, 40 C.F.R. 

§ 122.29(b)(1)(ii), and (2) whose processes are “substantially independent” of an existing source 

at the same site, 40 C.F.R. § 122.29(b)(1)(iii).

Obviously a new cell at an existing landfill does not “totally replace” the source of leachate 

discharges and is not “substantially independent” of the existing facility. Hence, a new cell at an 

existing facility would not be a “new source.” UWAG believes this is clear from 40 C.F.R. 

§ 122.29(b), but we recommend that EPA make it explicit in the final rule.
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2. Additional Landfill Capacity to Manage Displaced Wastestreams Is Not a New Source

Likewise, if the facility builds additional landfill capacity – whether onsite or offsite – to manage 

wastestreams displaced as a result of revisions to the ELG rule, the additional landfill capacity is 

not a “new source.” Obviously it is not at a “greenfield” site, as it is not a new generating 

station. And even if it “totally replaces” an existing landfill, it does not replace the power 

generating facility, which is the “source.”73 Finally, the new landfill capacity does not have 

processes “substantially independent” of the existing power plant – indeed, in these 

circumstances, the new capacity has been created solely to manage wastestreams from the 

existing source – i.e., the power plant – that have been prohibited from being managed in a 

surface impoundment by the revised ELGs.

If a power plant does not own the offsite landfill receiving its waste, it should not be responsible 

for complying with effluent limitations guidelines. The steam electric ELGs do not to apply to 

offsite landfills for coal-related waste where the unit is not owned or operated by a 

utility. Rather, if the offsite landfill is an ordinary landfill unit in the Landfills Point Source 

Category, then it is regulated by the ELGs in 40 C.F.R. Part 445. But it is the owner of the 

landfill that is responsible for meeting the requirements, not the party who contracts with the 

landfill to manage the waste material.

73 This position was reiterated by EPA during the EPA Webcast on the proposed ELG rule 

where, during the question-and-answer session, EPA affirmed that “[w]hat actually has been put 

into practice is that, generally speaking, a new source is a new generating unit at an existing 

facility or, of course, it could be a new green field type of facility altogether.” Transcript from 

EPA Aug. 20, 2013 Webinar on “Stream Electric Power Generating Effluent Guidelines –

Proposed Rule” (Attachment 28 to these comments) at 12-13.

Comment Response: 

EPA generally agrees with the commenter’s interpretation of the “new source” definition and its 

application to new landfills or expansions to existing landfills to manage combustion residuals 

requiring disposal in response to the ELG. As such, EPA is confirming the following:

1. An expansion to an existing landfill (e.g., a new landfill cell) at an existing steam electric 

power plant to manage the combustion residuals generated by existing generating units is 

considered an existing source and the combustion residual leachate from such a landfill 

would be subject to the combustion residual leachate BAT limitations.

2. A new landfill built at an existing plant to manage the combustion residuals generated by 

existing generating units is considered an existing source and the combustion residual 

leachate from such a landfill would be subject to the combustion residual leachate BAT 

limitations.

3. Numbers 1 and 2 above apply to both on-site or off-site landfills that are owned or 

operated by the steam electric power plant or its owner/subsidiary.
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Off-site-municipal landfills are not subject to the combustion residual leachate limitations and 

standards in the final rule, but rather, are subject to the requirements in 40 CFR 445, Landfills 

Point Source Category.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 108

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Duke Energy also recommends that EPA confirm that any new landfill or the expansion of an 

existing landfill constructed to manage the additional capacity needed for CCR displaced as a 

result of a facility’s compliance the ELG Final Rule is not classified as a “new source” and that 

any combustion residual leachate from such a landfill is not subject to the rule’s “New Source 

Performance Limits” for this wastestream. Clarification of this position is important since under 

the ELG Proposal the prohibition of discharging CCR transport water will force utilities to begin 

alternative management practices by converting to dry collection and disposal of flyash, bottom 

ash or both into landfills. While some of Duke Energy’s coal-fired units operate both dry and wet 

handling systems in tandem and may have adequate existing landfill space to manage the 

displaced CCR, many of the smaller generating stations currently only manage CCR in 

impoundments. Duke Energy will need to construct new landfills or expand existing landfills, 

some of which will be onsite, while some will be at off-site locations. Duke Energy also has

dedicated landfills that accept CCR from multiple stations and may need more of these types of 

landfills strategically located to provide additional landfill capacity to handle the flyash or 

bottom ash that could be collected dry in the future.

In all cases, the additional onsite or off-site landfill capacity will be dedicated to the same CCR 

that had been managed in the pre-existing impoundments at existing generating stations. Duke 

Energy requests that EPA clarify that this additional landfill capacity, whether from a new 

landfill or new cells at existing landfills, is not considered a “new source” under the ELG 

requirements and that the combustion residual leachate from such additional capacity is not 

subject to the proposed limits for combustion residual leachate from new sources.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Lisa C. Messinger

Commenter Affiliation: Vectren Corporation
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Document Control Number: EPA-HQ-OW-2009-0819-4317-A1

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We also request a more descriptive definition of “new source”, such as that offered in the EPA 

webcast which explained that it pertains to new "generating" units. During the webcast it was 

further specified, that modifications to existing units or the construction of a new landfill or 

landfill cells for the disposal needs of an existing facility would not be subject to New Source 

Perfomance Standards as listed in the ELG.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 142

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

PSNS Applicability

The new source definition and applicability is a significant consideration for both NSPS and 

PSNS. If ash ponds are eliminated as a treatment option for fly ash and possibly bottom ash, 

additional CCR landfills will be required at most plants. These landfills in many cases will be 

unable to be collocated at the generating facility, thereby necessitating possible treatment and 

permitting offsite. The proposal is unclear as to whether the existing source definition will apply 

to the landfill operation and whether the landfill itself is a new source or whether the source 

is the generating facility.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Mark Thoma

Commenter Affiliation: Otter Trail Power Company
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Document Control Number: EPA-HQ-OW-2009-0819-4446-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should explicitly acknowledge that new source performance standards (NSPS) for 

combustion residual leachate are not triggered by a new cell or new landfill built to manage 

coal combustion residual wastes at an existing generating unit. Modification of an existing 

generating unit and its affiliated disposal facilities is an “existing source,” not a new source.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

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: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

New landfill cells and additional landfill capacity constructed to manage wastes as a result of the 

ELG revisions are not "New Sources". This position is consistent with longstanding agency 

policy. USEPA guidance says that the term "source" in the definition of new source refers to the 

''facility generating the discharge, not the system treating it." Thus, "in EPA's view, where an 

owner or operator makes changes only to its wastewater treatment systems, and no changes 

occur in the production or wastewater generating processes of the plant, the source should not be 

reclassified as a new source."

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 64
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We Energies Asks EPA to Clarify its Definition of Existing Sources and New Sources in 

Regards to which Limits Apply to Combustion Residual Leachate.

We Energies questions how EPA intends to regulate combustion residual leachate based on the 

following scenarios.

Scenario #1: A new permitted landfill is constructed and receives combustion residual products 

(e.g., fly ash, bottom ash, FGD gypsum) from an existing site. How is the leachate 

characterized? What limits must be met: BAT limits for existing dischargers (which as 

proposed are the BPT limits) or NSPS?

Scenario #2: A new cell is constructed at an existing company landfill. How is the leachate 

characterized? What limits must be met: BAT limits for existing dischargers (which as 

proposed are the BPT limits) or NSPS?

We Energies interprets 40 CFR 122.29 to support the conclusion that under both of the scenarios 

presented above, the combustion residual leachate would not be treated as a “new source” and 

BAT limits for existing dischargers (which as proposed are the BPT limits) would govern. We 

Energies asks EPA to clarify this interpretation.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

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: 65

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

New Landfills and Landfill Cells Needed to Handle CCR Displaced by the Steam Electric 

ELGs Should Be Categorized as Existing Sources.

It is possible that the new ELG rule, depending on what limits it sets for bottom ash and fly ash 

transport water, may cause power plants to close ash impoundments and begin disposing of coal 
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ash in landfills instead. Existing landfills may have to be enlarged, and new landfills may have to 

be created either on- or offsite.

EPA should make clear that such new cells and landfills are not “new sources” subject to “new 

source” performance standards. EPA guidance says that the “new source” is the “facility 

generating the discharge, not the system treating it”:

[I]t is important to recognize that the “source” of a discharge from an industrial operation is the 

facility generating the discharge, not the system treating it. Mahelona v. Hawaiian Electric 

Company, Inc., 418 F. Supp 1328 (Aug. 27, 1976), 49 Fed. Reg. 38044 (Sept. 26, 1984).

L. Boornazian & M. Smith, New Source Dates for Direct and Indirect Dischargers (Sept. 28, 

2006), www.epa.gov/npdes/pubs/newsource_dates.pdf.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Tom DeLawrence

Commenter Affiliation: Alabama Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4489-A1

Comment Excerpt Number: 29

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

D. New Landfills on an Existing Site Do Not Constitute a “New Source” Subject to New 

Source Performance Standards

Current EPA regulations demonstrate that if an existing steam electric generating station opens a 

new landfill on an existing facility site, the new structure would not constitute a “new source” to 

which the new source performance standards apply. New source determinations are made 

according to the criteria found at 40 C.F.R. § 122.29(b). As Section 122.29(b)(1) clarifies, a 

“new source” emerges when: (1) the source is “constructed at a site at which no other source is 

located,” or (2) the source totally replaces the process or production equipment that causes the 

discharge of pollutants at an existing source; and (3) has processes that are “substantially 

independent” of an existing source at the same site. 40 C.F.R. § 122.29(b)(1)(i)-(iii)27 Under 

these definitions, even an entirely new landfill within the existing footprint of the plant is not 

a “new source” since such a landfill would not be “constructed at a site at which no other source 

is located,” 40 C.F.R. § 122.29(b)(1)(i); nor would such a structure “totally replace” either the 

power generating facility or the existing landfill for the facility. 40 C.F.R. § 122.29(b)(1)(ii). 

Further, the new landfill would not have processes “substantially independent” of the existing 
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power plant. Because it would not be a new source, the ELG rules do not need to address this 

issue.

27 EPA guidance also makes clear that the term “source” in the regulatory definition of “new 

source”, set out in 40 C.F.R. § 122.2 (which is incorporated by reference into 40 C.F.R. § 

122.29(b)), refers to the “facility generating the discharge, not the system treating it.” Laura 

Boorznazian, EPA, to Regional Water Division Directors (Sept. 26, 2006).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Cathy S. Woollums

Commenter Affiliation: MidAmerican Energy Holdings Company

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

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definition of “new source” should not apply to coal combustion residual 

landfills constructed to manage CCR displaced as a result of newly imposed ELG requirements, 

or to landfill expansions at an existing facility.

MidAmerican requests EPA clarify that leachate generated from required additional CCR landfill 

capacity is not included in the ELG requirements for new sources, and, in particular, that the 

combustion residual leachate from such expansion is not subject to the proposed pretreatment 

standards for new sources. Landfills constructed to manage CCR displaced as a result of a 

facility's compliance with a newly imposed ELG requirement do not meet the regulatory 

definition of “new source”9. Similarly, landfill expansions at existing facilities also do not meet 

that definition.

Leachate from CCR landfills, whether new or existing, should not be subject to the proposed 

ELG rule's new source pretreatment standards for combustion residual leachate. EPA provided 

clarification regarding this point during a webcast held August 20, 2013, stating that “a new 

source is a new generating unit at an existing facility” and that “a modification to an existing 

generating unit has not been treated as a new source by the NPDES program.” Clarification of 

this position is important as an initial applicability determination, because, under EPA's preferred 

options, certain existing wastewater streams such as fly ash transport water and bottom ash 

transport water could become subject to a zero discharge standard. If any of these options is 

selected for the final rule, the likely alternative for many facilities will be to convert their units to 
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dry handling of fly ash and/or bottom ash. Facilities would then need to construct additional 

capacity in currently existing landfills to manage this displaced fly ash and bottom ash.

Based on discussion in the ELG proposal,10 “new source” refers to a new facility, and would not 

apply to an expansion of an existing landfill. EPA defines “new source,” in part, as a newly 

constructed “building, structure, facility, or installation from which there is or may be a 

discharge of pollutants.”11 Although waste management modifications are likely to be required 

under the ELG rule, the source of the waste stream – i.e., the steam electric generation facility –

will not be required to undergo changes as a result of the rule. The modifications would solely 

affect the waste management process. Since there are no changes being made to the source of the 

combustion residual leachate, the regulated wastewater cannot be considered a “new source.” 

The combustion residual leachate from any additional landfill capacity is, for all practical 

purposes, identical in composition to combustion residual leachate from “existing source” 

landfills, and if the leachate from an expansion is co-managed with leachate from “existing 

source” landfills, the waste stream should not be considered a “new source” and should not be 

subject to new source pretreatment standards. EPA should clarify the text of the ELG rule to 

clearly exclude leachate collected from new landfills constructed to manage CCR displaced by 

the ELGs and landfill expansions from any NSPS requirements.

9 40 CFR §§122.2, 406.6(m) and 78 Fed. Reg. at 34438.

10 Id.

11 40 CFR §§122.2, 406.6(m)

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 36

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

To the extent a facility expands upon an existing landfill, such expansion should not trigger the 

definition of “new source” in 40 C.F.R. §122.29.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 37

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Active captive and non-captive landfills (and inactive landfills that become active) are in a 

continuous state of expansion and can be expanded horizontally and vertically for many years. 

These landfill expansions could also include construction on onsite land not contiguous with the 

existing landfill or at off-site locations. Often plans for future stages of expansion are included 

in the original permitting of the landfill.

Existing solid wastes (e.g., fly ash, bottom ash, gypsum, etc.) from the steam electric industry are 

routinely added to landfills. When new wastes are generated, disposal will likely occur in 

existing landfills and landfill expansions. For example, the waste biosolids from a new biological 

treatment system or crystallized salts associated with a new spray drier would be considered new 

wastes requiring disposal.

When a facility merely expands an existing landfill, it is not: (i) constructing a facility at a site 

where no other source is located; (ii) totally replacing process of production equipment that 

causes the discharge of pollutants at an existing source; or (iii) a source whose processes are 

substantially independent of an existing source at the same site. See id. § 122.29 (b)(1) setting 

forth criteria for new source determinations.

Existing EPA regulations are not sufficiently clear to determine what sources are New Sources. 

It is important to recognize that the source of these waste streams (i.e., the steam electric 

generation facilities themselves) is not required to undergo any changes as a result of this 

proposed rule. These modifications solely affect the waste management process and therefore 

any changes to the waste treatment process that may include should not be construed as “new 

sources.” NRG requests that EPA provide clear guidance that the proposed numeric standards for 

discharges of leachate from New Sources will not apply to existing steam electric generating 

plants.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.
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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: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Because electric generation facilities may need to create addition landfill capacity for displaced 

wastestreams under the revised ELG rules, it is important for EPA to clarify in the final rule that 

new cells at existing landfills and additional landfill capacity whether constructed on or offsite 

necessary to manage coal ash wastestreams displaced as a result of a revised ELG requirement 

are not “new sources” subject to “new source” performance standards. Similarly, EPA should 

clarify that combustion residual leachate from such additional capacity is not subject to the 

proposed pretreatment standards for combustion residual leachate from new sources (PSNS), but 

rather remains subject to the proposed PSES standards for existing sources.

This position is consistent with longstanding EPA policy. EPA guidance says that the term

“source” in the definition of new source refers to the “facility generating the discharge, not the 

system treating it.” Laura Boornazian, EPA, to Regional Water Division Directors (Sept. 26,

2006) (emphasis added), available at www.epa.gov/npdes/pubs/newsource_dates.pdf. Thus, “in 

EPA’s view, where an owner or operator makes changes only 

to its wastewater treatment systems, and no changes occur in the production or wastewater 

generating processes of the plant, the source should not be reclassified as a new source.” Id.; see 

also 49 Fed. Reg. 37998, 38044 (Sept. 26, 1984).

Indeed, EPA’s own definition of “new source” does not apply to new cells or additional landfill 

capacity constructed to manage wastestreams from the same generating facility, for the reasons 

given below.

A new cell at an existing landfill does not “totally replace” the source of leachate discharges and 

is not “substantially independent” of the existing facility. Hence, under no circumstances would 

a new cell at an existing facility be a “new source.” This is clear from 40 C.F.R. § 122.29(b), 

though it would be beneficial for EPA to confirm it.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

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: 12
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Likewise, if the facility builds additional landfill capacity – whether onsite or offsite – to manage 

wastestreams displaced as a result of revisions to the ELG rule, the additional landfill capacity is 

not a “new source.” Obviously it is not at a “greenfield” site, as it is not a new generating station. 

And even if it “totally replaces” an existing landfill, it does not replace the power generating 

facility, which is the “source.” Finally, the new landfill capacity does not have processes 

“substantially independent” of the existing power plant indeed, in these circumstances, the new 

capacity has been created solely to manage wastestreams from the existing source that have been 

prohibited from being managed in a surface impoundment by the revised ELGs.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

that combustion residual leachate generated from additional landfill capacity developed for the 

sole purpose of managing CCR displaced from impoundments as a result of the final ELG 

requirements is not leachate from a “new source” and therefore is not subject to the new source 

pretreatment standards for combustion residual leachate.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: James R. Roewer

Commenter Affiliation: Utility Solid Waste Activities Group (USWAG)

Document Control Number: EPA-HQ-OW-2009-0819-4652-A1

Comment Excerpt Number: 27

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

additional landfill capacity constructed solely to manage CCR displaced as a result of a revised 

ELG requirement is an “existing source."

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 179

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

D. PSNS Applicability

The new source definition and applicability is a significant consideration for both NSPS and 

PSNS. If ash ponds are eliminated as a treatment option for fly ash and possibly bottom ash, 

additional CCR landfills will be required at most plants. These landfills in many cases will be 

unable to be collocated at the generating facility, thereby necessitating possible treatment and 

permitting offsite. The proposal should make clear, as stated in previous sections of these 

comments, that new offsite landfills receiving CCRs from existing facilities are not new sources 

as they are not substantially independent of the generating facility.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 82

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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New Landfill Cells and Additional Landfill Capacity Constructed to Manage Wastes 

Displaced As a Result of the ELG Revisions Are Not “New Sources”

UWAG’s comments go into great detail on these issues related to waters of the U. S. and new 

and existing landfill cells. APPA defers to UWAG and offers a few examples to augment 

UWAG’s comments.

1. New Cells at an Existing Landfill

If a steam electric generating station opens a new cell in an existing landfill, the new cell is not a 

“new source” to which new source performance standards apply. The criteria for new source 

determinations are at 40 C.F.R. §122.29(b). Section 122.29(b)(1) defines when a “source” 

(defined in §122.29(a)(2) as any building, structure, facility, or installation from which there is or 

may be a discharge of pollutants) is classified as a “new source.”

First, a source is a new source when it is “constructed at a site at which no other source is 

located.” 40 C.F.R. §122.29(b)(1)(i). An entirely new generating facility (at a “greenfield” site) 

is a new source. “New sources” also include sources (1) that totally replace the process or 

production equipment that causes the discharge of pollutants at an existing source, 40 C.F.R. 

§122.29(b)(1)(ii), and (2) whose processes are “substantially independent” of an existing source 

at the same site, 40 C.F.R. §122.29(b)(1)(iii).

Obviously a new cell at an existing landfill does not “totally replace” the source of leachate 

discharges and is not “substantially independent” of the existing facility. Hence, under no 

circumstances would a new cell at an existing facility be a “new source.” This is clear from 40 

C.F.R. §122.29(b), though it would be beneficial for EPA to confirm it in the final rule.

2. Additional Landfill Capacity to Manage Displaced Wastestreams

Likewise, if the facility builds additional landfill capacity – whether onsite or offsite – to manage 

wastestreams displaced as a result of revisions to the ELG rule, the additional landfill capacity is 

not a “new source.” Obviously it is not at a “greenfield” site, as it is not a new generating station. 

And even if it “totally replaces” an existing landfill, it does not replace the power generating 

facility, which is the “source.” 28 Finally, the new landfill capacity does not have processes 

“substantially independent” of the existing power plant – indeed, in these circumstances, the new 

capacity has been created solely to manage wastestreams from the existing source – i.e., the 

power plant – that have been prohibited from being managed in a surface impoundment by the 

revised ELGs.

It is important to recognize that if a power plant does not own the offsite landfill receiving its 

waste, it should not be responsible for complying with effluent limitations guidelines. The steam 

electric ELGs do not to apply to offsite landfills for coal-related waste where the unit is not 

owned or operated by a utility. Rather, if the offsite landfill is an ordinary landfill unit in the 

Landfills Point Source Category, then it is regulated by the ELGs in 40 C.F.R. Part 445.
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28 This position was reiterated by EPA during the EPA Webcast on the proposed ELG rule 

where, during the question-and-answer session, EPA affirmed that “[w]hat actually has been put 

into practice is that, generally speaking, a new source is a new generating unit at an existing 

facility or, of course, it could be a new green field type of facility altogether.” Transcript from 

EPA Aug. 20, 2013, Webinar on “Stream Electric Power Generating Effluent Guidelines –

Proposed Rule,” at 12-13.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

Commenter Name: Paul Ling

Commenter Affiliation: Kansas City Power & Light Company

Document Control Number: EPA-HQ-OW-2009-0819-5406-A2

Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should also explicitly acknowledge that CWA new source performance standards (NSPS) 

are not triggered by a new cell or new landfill built to manage Coal Combustion Residues (CCR) 

waste streams displaced as a result of a facility’s compliance with a new steam electric ELG 

requirement. Modification of an existing generating unit and its affiliated disposal facilities is an 

existing source, not a new source. EPA guidance also says that the “new source” is the “facility 

generating the discharge, not the system treating it.”

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.

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: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

New cells in an existing landfill should not be classified as new sources under the Clean Water 

Act. New sources are typically indicated when new stand-alone operations are constructed at a 
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facility, or at a greenfield site. Expansions at existing units are typically not classified as new 

sources. Similarly, a new cell at an existing landfill should not be classified as a new source.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 149.
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6.g.viii. Pretreatment 10-yr/24 hr storm

Commenter Name: J. Madras

Commenter Affiliation: Missouri Department of Natural Resources

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

Comment Excerpt Number: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

11. Storm Events

The pretreatment definitions for the 10-year/24-hour storm refer to a NOAA Technical Paper 40 

from 1961. This should be updated to include April 2013 release of the NOAA Atlas 14 Volume 

8: Precipitation-Frequency Atlas of the United States (http://hdsc.nws.noaa.gov/hdsc/pfds/.)

Comment Response: 

EPA notes that the April 2013 release of the NOAA Atlas 14 Volume 8 is an acceptable 

document to use in defining a 10-year/24-hour rainfall event because the current definition 

allows for using the NOAA Technical Paper 40 from 1961 “or equivalent regional rainfall 

probability information developed therefrom.” Therefore, EPA decided not to revise the 

definition of 10-year/24-hour rainfall event for the final rule.

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: 23

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definitions for the 10-year/24-hour storm refer to a 1961 study. These should be updated.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 21.
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6.g.ix. Bottom ash and boiler slag

Commenter Name: Mark Thoma

Commenter Affiliation: Otter Trail Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4446-A1

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Definitions and Regulation of Boiler Slag and Bottom Ash

Otter Tail recommends that EPA include a separate definition for boiler slag to recognize the 

difference between the slag that is produced by a cyclone boiler in comparison to the bottom ash 

produced by pulverized coal boilers. At a minimum, EPA must amend the proposed definition of 

bottom ash, which does not make clear whether boiler slag is included, by replacing it with the 

definition in Appendix A to the proposed rule. Note that the Appendix A bottom ash definition 

explicitly includes boiler slag.

If EPA does not include a separate definition for boiler slag and instead agrees to include it 

within the definition of bottom ash, Otter Tail stresses that EPA must not impose an option that 

requires dry handling of boiler slag. Inherent to their design, cyclone boilers develop a molten 

slag that flows through the bottom of the boiler into a tank, where the slag is quenched in a water 

bath. This process cannot be completed without water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4633-A1, Excerpt Number 46.

Commenter Name: Nysa Hogue

Commenter Affiliation: Indianapolis Power & Light Company (IPL)

Document Control Number: EPA-HQ-OW-2009-0819-4454-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Please clarify if incidental/de minimis bottom or fly ash wastewater not associated with wet 

bottom or fly ash handling systems, as defined in the proposed rule, is subject to the proposed 

BA or Fly Ash BAT limits or will these type of discharges be regulated under the existing LVW 

BPT limits (40 CFR 423.12).
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Comment Response: 

It is unclear what the commenter means by “incidental/de minimis bottom or fly ash wastewater 

not associated with wet bottom or fly ash handling systems.” The final rule limitations and 

standards are for bottom ash transport water and fly ash transport water. Therefore, any 

wastewater that contacts fly ash or bottom ash that meets the definition for “transport water” 

would be subject to the final fly ash or bottom ash transport water effluent limitations and 

standards. Conversely, any wastewater that contacts fly ash or bottom ash that is not within the 

definition for “transport water,” although not subject to the final fly ash or bottom ash transport 

water effluent limitations and standards is subject to previously promulgated low volume waste 

sources BPT standards.

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: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

One clarification that DP&L suggests is to include boiler slag in the definition of bottom ash. 

Bottom ash is essentially agglomerated ash particles, formed in coal-fired furnaces that are too 

large to be carried through the stack with the flue gases. DP&L recommends that USEPA amend 

the definition of "bottom ash" explicitly to include "boiler slag." Boiler slag is the molten bottom 

ash collected at the base of furnaces that is quenched with water. When the molten slag contacts 

the quenching water, it fractures, crystallizes, and forms pellets. This boiler slag material is made 

of hard, black, angular particles that have a smooth, glassy appearance and is even more inert 

than other bottom ash. By including boiler slag in the ELG revisions, USEPA will be consistent 

with the proposed Coal Combustion Residuals rulemaking which specifically includes boiler 

slag within the universe of potentially regulated material and current regulatory practice.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 20

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

We also note that the definition of bottom ash is inconsistent throughout the proposed 

rulemaking and we urge EPA to amend the definition to provide clarity. As further explained in 

Section II, the definition of bottom ash in the final rule should include boiler slag.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 45

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In the preamble of the EPA proposal, it appears that EPA properly categorizes boiler slag as 

bottom ash. Specifically, EPA makes the following statement:

"Combustion residuals comprise a variety of wastes from the combustion process 

, including fly ash, bottom ash (which in includes boiler slag) ..."

78 Fed. Reg. 34450 col. 1.

Later in the appendix to the preamble EPA provides a definition of bottom ash that again 

includes boiler slag when it states:

"Bottom ash-The ash, including boiler slag, that drops out of the furnace gas 

stream in the furnace and which settles in the furnace or are dislodged from 

furnace walls. Economizer ash is included when it is collected with bottom ash."

78 Fed. Reg. 34532 col. 2.

In the proposed rule, however, EPA does not amend the definition of bottom ash to explicitly 

include boiler slag. Without amendment the definition of bottom ash from the 1982 ELG Rule 

will control which defines bottom ash as:

"[T]he ash that drops out of the furnace gas stream in the furnace and in the 

economizer sections. Economizer ash is included when it is collected with bottom 

ash."
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40 C.F.R. 423.11

We request that EPA amend the definition of "bottom ash" to explicitly include boiler slag 

within the definition of bottom ash in the final rule. This clarification will ensure that ash 

removed by boiler lancing is properly treated as bottom ash. We believe this definition is 

consistent with current regulatory practices and EPA's recognition in the Rule's preamble and is 

warranted given the inert nature of boiler slag.

Comment Response: 

EPA agrees with the commenter that the definition of bottom ash was not consistent in the 

proposal. EPA also agrees with the commenter that boiler slag should be included in the 

definition of bottom ash. As a result, EPA is promulgating the definition of bottom ash as “the 

ash, including boiler slag, which settles in the furnace or is dislodged from furnace walls. 

Economizer ash is included when it is collected with bottom ash” (See preamble Appendix A).

Additionally, EPA agrees with the commenter that “ash removed by boiler lancing is... bottom 

ash”.

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: 46

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Boiler slag is distinct from bottom ash inasmuch as it exists in true, solid form only after 

exposure to water. Specifically, boiler slag is formed when the molten ash collected at the base 

of the slag tap in cyclone type furnaces is quenched with water, causing the molten material to 

fracture and crystallize. Boiler slag is made up of hard, black, angular particles that have a 

smooth, glassy appearance. It is even more inert than traditional bottom ash. It is typically 

packaged as-is and shipped across the country for use in other construction processes and 

components of products such as roofing granules, sandblasting grit and de-icing of roadways, 

among other valuable uses.

EPA apparently considers boiler slag synonymous with bottom ash, see 78 Fed. Reg. at 34,532 

(defining bottom ash as “[t]he ash, including boiler slag, that drops out of the furnace gas stream 

in the furnace and which settles in the furnace or are [sic] dislodged from furnace walls. . . .), 

meaning quench waste water associated with the slag material could potentially be regulated by 

one of the two effluent limitation options proposed for the regulation of bottom ash transport 

water. PSNH respectfully requests that EPA modify the definition of “bottom ash” to specifically 

exclude boiler slag. Doing so would clarify that waste waters associated with boiler slag 
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formation are not subject to zero discharge standards, should the agency elect to promulgate that 

regulatory option.19 A wet bottom boiler is essential for boiler slag formation. Indeed, PSNH 

estimates it would cost nearly $4 million to retrofit a dry handling system to address only boiler 

slag formation at its facilities. The fact that boiler slag is some of the most inert material 

generated at steam electric generating facilities further supports PSNH’s request that EPA 

exclude it from the regulatory definition of bottom ash. In fact, slag contains only trace amounts 

of toxic pollutants and does not readily leach elevated concentrations of pollutants in water. 

Therefore, subjecting it to the effluent limitations in the Proposed Rule would not result in any 

benefit to the environment.

For all of these reasons, PSNH respectfully requests that EPA revise the definition of “bottom 

ash” to specifically exclude boiler slag. Alternatively, PSNH requests that even if boiler slag is 

subsumed in the definition of bottom ash, the agency either: (1) specifically exempt boiler slag 

from regulation under any final rule; or, (2) should EPA eliminate all permissible waste water 

discharges and impose dry handling, enumerate that boiler slag cannot be subject to such 

additional regulation and waste waters associated with slag

19 Specifically, the Proposed Rule defines a “dry bottom ash handling system” as “[a] system 

that does not use water to convey bottom ash away from the boiler. It includes systems that 

collect and convey the ash without any use of water, as well as systems in which bottom ash is 

mechanically or pneumatically conveyed away from the boiler.” 78 Fed. Reg. at 34,532 

(emphasis added).

Comment Response: 

EPA disagrees with the commenter that EPA should “modify the definition of ‘bottom ash’ to 

specifically exclude boiler slag.” EPA notes that many other industry commenters stated that 

boiler slag should be included in the definition of bottom ash, including UWAG, the industry 

trade association (see DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 28). For example, 

one commenter states, “Bottom ash is essentially agglomerated ash particles, formed in coalfired furnaces that are too large to be carried through the stack with the flue gases. DP&L 

recommends that USEPA amend the definition of ‘bottom ash’ explicitly to include ‘boiler slag.’ 

Boiler slag is the molten bottom ash collected at the base of furnaces that is quenched with 

water.” Other comments have said, “[treating boiler slag as part of bottom ash] is also consistent 

with current regulatory practice.”

EPA notes that in response to EPA’s Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines, PSNH provided a water balance diagram for its Merrimack Station that 

identifies the sluicing of the boiler slag to the impoundment as “BAS,” which signifies “bottom 

ash sluice.” Additionally, EPA reviewed the April 2014 Revised Draft Permit for the Merrimack 

Station (NPDES Permit No. NH0001465) and fact sheet states that “[t]he Draft Permit’s 

technology-based draft permit limits for TSS and O&G pertain to the low volume and ash 

transport waste streams entering the slag settling pond.” Therefore, the permitting authority 

already treats the boiler slag transport water as bottom ash transport water.
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Finally, EPA used data from at least two steam electric power plants with impoundments 

receiving boiler slag, that is Kyger Creek and Kammer, in its bottom ash baseline loadings 

analyses. Therefore, the data used in the analysis are representative of both bottom ash and boiler 

slag. For all these reasons, EPA has determined that it is appropriate to clarify the definition of 

bottom ash by including boiler slag in the definition.

EPA also disagrees with the commenter that subjecting boiler slag “to the effluent limitations in 

the Proposed Rule would not result in any benefit to the environment.” As noted previously, 

EPA used data from at least two steam electric power plants in its bottom ash analysis and found 

that there are pollutants present in the wastewater. Because the final rule establishes a zero 

discharge standard for bottom ash transport water, the final rule requirements will eliminate 

discharges of these pollutants to surface waters. As this is a technology-based rule, see DCN 

EPA-HQ-OW-2009-0819-4464-A1, Excerpt 3 for the role of cost-benefit analysis in EPA’s 

decisions for the final rule.

For comment related to modification of the bottom ash definition, please see response to DCN 

EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45.

EPA agrees with the commenter that “[a] wet bottom boiler is essential for boiler slag 

formation,” because the slag must be quenched in a water bath. While EPA is promulgating a no 

pollutant discharge limitation and standard for bottom ash transport water, EPA is not requiring 

the use of a dry handling system. In determining BAT and BADCT, EPA identifies technologies 

that serve as the bases for its requirements, but dischargers may use any technology to meet the 

limits. NWF et al. v. EPA, 286 F.3d 554, 558 (D.C. Cir. 2002). Cyclone boilers that generate 

boiler slag could comply with the final rule by installing and operating a mechanical drag system 

(MDS) that does not generate transport water. Similarly, the steam electric power plant could 

install a remote MDS and operate the system closed loop to meet the final rule 

requirements. EPA notes that there is at least one cyclone boiler generating unit that currently 

operates a MDS (Kansas City Power & Light’s La Cygne Generating Station).

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 28

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. The Definition of Bottom Ash Should Include Boiler Slag

Bottom ash is agglomerated ash particles, formed in coal-fired furnaces, that are too large to be 

carried into the stack with the flue gases. Instead the particles collect on the furnace walls or fall 

through open grates to an ash hopper at the bottom of the furnace. Bottom ash is relatively inert 
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and generally contains only small amounts of toxic pollutants. In water it does not readily leach 

elevated concentrations of toxic pollutants. The exact composition of bottom ash varies 

somewhat according to the type of coal being burned and other factors.

In the 1982 regulations, EPA defines bottom ash as follows:

[T]he ash that drops out of the furnace gas stream in the furnace and in the economizer 

sections. Economizer ash is included when it is collected with bottom ash.

40 C.F.R. § 423.11.

UWAG recommends that EPA amend the definition of “bottom ash” explicitly to include “boiler 

slag.” Boiler slag is the molten bottom ash collected at the base of slag tap and cyclone type 

furnaces that is quenched with water. When the molten slag contacts the quenching water, it 

fractures, crystallizes, and forms pellets. This boiler slag material is made of hard, black, angular 

particles that have a smooth, glassy appearance.

Boiler slag is even more inert than other bottom ash, as shown by sluice water data from plants 

like Merrimack, where the water is almost free of toxics, and by the fact that for decades most 

boiler slag has been sold for use as blasting grit and on roofing shingles. Boiler slag is produced 

in cyclone boilers which by design use water tanks at the bottom to crystallize the molten ash, so 

there is no option of dry handling. Boiler slag is produced by few plants and in small volumes 

compared to other bottom ashes.

EPA indicates in the preamble to the present ELG proposal that it considers boiler slag to be 

bottom ash:

Combustion residuals comprise a variety of wastes from the combustion process, including fly 

ash, bottom ash (which includes boiler slag)....

78 Fed. Reg. at 34,450 col. 1. Similar references to boiler slag as bottom ash occur throughout 

the preamble and the 2013 TDD (78 Fed. Reg. at 34,453 col. 2, 34,458 col. 1, 34,481 n.55; 2013 

TDD at 8-2). In Appendix A to the proposed rule, EPA provides a definition of bottom ash that 

explicitly includes boiler slag:

The ash, including boiler slag, that drops out of the furnace gas stream in the furnace and which 

settles in the furnace or are [sic] dislodged from furnace walls. Economizer ash is included when 

it is collected with bottom ash.

78 Fed. Reg. at 34,532 col. 2.

UWAG recommends EPA amend § 423.11 to replace the current definition of “bottom ash” with 

the definition in Appendix A3. This definition will clarify that boiler slag is bottom ash. In 

addition, the definition clarifies that ash removed by boiler lancing (i.e., “ash dislodged from 

furnace walls”) is bottom ash. See the discussion of boiler lancing later in these comments.
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From the text of the preamble and other sources, UWAG’s recommendation appears to be 

consistent with EPA’s intent to treat boiler slag as bottom ash. Also, EPA uses boiler slag pond 

discharge data from the Kyger Creek Station in its bottom ash analytical database, which further 

demonstrates EPA’s intent to classify boiler slag as bottom ash. Finally, UWAG’s 

recommendation is consistent with current regulatory practice.

However, because of the relatively harmless nature of boiler slag, it should be subject only to 

TSS and oil and grease limits even if EPA ultimately decides to put more stringent limits on 

other bottom ash.

3 Appendix A is intended to help readers of the proposed rule by including “[d]efinitions, [a]cronyms, and [a]bbreviations used in this notice” (id.

at 34,532 col. 1), but in some cases the Appendix A definitions differ from the definitions in the proposed rule.

Comment Response: 

See responses to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45 and DCN EPAHQ-OW-2009-0819-4633-A1, Excerpt Number 46. For the reasons EPA selected the options it 

promulgated, see the final rule preamble. EPA notes that the portion of the statute upon which 

this rule is based is technology driven rather than based on effects on receiving waters. See DCN 

EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 in Comment Code 6.e.

Commenter Name: Raymond L. Evans

Commenter Affiliation: FirstEnergy Corp.

Document Control Number: EPA-HQ-OW-2009-0819-4677-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. EPA's definition of bottom ash should include boiler slag and ash removed from the 

boiler walls.

Boiler slag is the molten ash collected at the base of the furnace that is quenched 

with water. Boiler slag is even more inert than other bottom ash and as such should be included 

in the definition of bottom ash. Also, ash removed by boiler lancing, or dislodged from the 

boiler wall should be defined as bottom ash. Clatification in the definition for bottom ash will 

avoid confusion in the future.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45.
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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: 48

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Definition of Bottom Ash Should Include Boiler Slag

Bottom ash is agglomerated ash particles, formed in coal-fired furnaces that are too large to be 

carried into the stack with the flue gases. Instead the particles collect on the furnace walls or fall 

through open grates to an ash hopper at the bottom of the furnace. 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 exact composition of bottom ash varies 

somewhat according to the type of coal being burned and other factors.

In the 1982 regulations, EPA defines bottom ash as “the ash that drops out of the furnace gas 

stream in the furnace and in the economizer sections. Economizer ash is included when it is 

collected with bottom ash.” 15 APPA agrees with UWAG that EPA should amend the 

definition of “bottom ash” explicitly to include “boiler slag.” Boiler slag is the molten bottom 

ash collected at the base of slag tap and cyclone type furnaces that is quenched with water. When 

the molten slag contacts the quenching water, it fractures, crystallizes, and forms pellets. This 

boiler slag material is made of hard, black, angular particles that have a smooth, glassy 

appearance. Boiler slag is even more inert than other bottom ash.

EPA indicates in the preamble to the present ELG proposal that it considers boiler slag to be 

bottom ash. “Combustion residuals comprise a variety of wastes from the combustion process, 

including fly ash, bottom ash (which includes boiler slag).”16 Similar references to boiler slag as 

bottom ash occur throughout the preamble and the 2013 Technical Development Documentation 

(TDD).17 In Appendix A to the proposed rule, EPA provides a definition of bottom ash, 

different from the one in the current regulation that explicitly includes boiler slag:

The ash, including boiler slag, that drops out of the furnace gas stream in the furnace and which 

settles in the furnace or are [sic] dislodged from furnace walls. Economizer ash is included when 

it is collected with bottom ash. 18

APPA recommends EPA amend §423.11 to replace the current definition of “bottom ash” with 

the definition EPA includes in Appendix A.19 This definition will clarify that boiler slag is 

bottom ash. In addition, the definition clarifies that ash removed by boiler lancing (i.e., “ash 

dislodged from furnace walls”) is bottom ash. Based upon the EPA’s proposed rule preamble and 

other sources, this recommendation appears to be consistent with EPA’s intent to treat boiler slag 

as bottom ash. It is also consistent with current regulatory practice.
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15 40 C.F.R. § 423.11.

16 78 Fed. Reg. at 34,450 col. 1.

17 (78 Fed. Reg. at 34,453 col. 2; at 34,458 col. 1; at 34,481, fn. 55; 2013 TDD at 8-2).

18 78 Fed. Reg. at 34,532 col. 2.

19 Appendix A is intended to help readers of the proposed rule by including “[d]efinitions, 

[a]cronyms, and [a]bbreviations used in this notice”(id. at 34,532 col. 1), but in some cases the 

Appendix A definitions differ from the definitions in the proposed rule.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4631-A1, Excerpt Number 45.
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6.g.x. FGD wastewater

Commenter Name: Tom DeLawrence

Commenter Affiliation: PowerSouth Energy Cooperative

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

Comment Excerpt Number: 30

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Definition of FGD Wastewater.

In the Draft Rule, EPA has proposed FGD wastewater as follows:

The term flue gas desulfurization (FGD) wastewater means any process wastewater generated 

from a wet flue gas desulfurization scrubber system, including any solids separation or solids 

dewatering processes.

By including wastewater from solids separation and dewatering processes, EPA’s proposed 

definition of FGD wastewater will frustrate and discourage utilities from recycling and/or 

reusing water at their facilities subject to a final rule. Currently, the Lowman Plant and some 

other facilities reuse water from the gypsum plant extracted from solids during the dewatering 

process3 for processes beyond those associated with the FGD system. Gypsum wash water 

should not be included within the definition of FGD wastewater because to do so will make those 

reuses infeasible. 

3 Specifically, these gypsum plant waters are discharged to the Lowman Plant’s FGD Pond. The 

waters return as makeup water to scrubber recycle tanks, limestone slurry ball mills, gypsum 

plant seal water, and to the old gypsum belt, and are often also used to flush pumps.

Comment Response: 

EPA has revised the definition of FGD wastewater in the final rule. See 40 CFR 423.11(n).

The overflow from the solids separation process (e.g., hydrocyclones) and the filtrate from 

vacuum filters are the primary sources of FGD wastewater from recirculating forced oxidation 

systems. The commenter argues that classifying these sources as FGD wastewater would prevent 

plant’s from reusing the gypsum wash water (which is captured in the filtrate from the vacuum 

filters) in other operations. However, the commenter provides no reasonable technical reason as 

to why the wastewater from this process should not be classified as FGD wastewater. The 

wastewater from the solids separation process and the solids dewatering process is the very 

wastewater stream that EPA determined warrants additional limitations and standards. The solids 

separation process separates the gypsum and other FGD solids from the liquid fraction in the 
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scrubber blowdown. Depending on factors such as the chloride concentration in the scrubber, 

this wastewater from the separation process is either returned to the scrubber or purged from the 

system (i.e., FGD purge) and in most cases sent to a surface impoundment or tank-based 

treatment system. For that reason, it is included within the definition of FGD wastewater. 

Similarly, the solids from the solids separation process are the gypsum solids (or calcium sulfite 

for an inhibited oxidation scrubber) that were created in the scrubber. Even after the separation 

step these solids contain substantial amount of liquid (approximately 40-50% solids), with the 

liquid being the wastewater from the scrubber. Thus, the water removed from these solids in the 

solids dewatering process is also FGD wastewater and therefore EPA determined it should be 

included within the definition of FGD wastewater.

The commenter states that the definition of FGD wastewater would discourage reuse, but EPA 

does not agree. FGD wastewater generally contains elevated concentrations of chlorides and 

would corrode most piping and equipment within the plant, thus limiting the opportunities for 

reuse unless it has been treated by an evaporation process. However, the commenter does 

identify two processes that are ideally suited for reuse of the FGD wastewater and are in no way 

constrained by the FGD wastewater definition: makeup water to scrubber recycle tanks and 

limestone slurry ball mills. The commenter’s reasons for opposing the definition of FGD 

wastewater are not persuasive.

Regarding the anti-circumvention provision see preamble section VIII.G.

Regarding the specific reuses identified in the commenter’s footnote, EPA does not preclude the 

plant from reusing FGD wastewater within the FGD process prior to complying with the final 

rule limitations and standards. Therefore, the plant could continue to reuse the FGD wastewater 

(as defined in the final rule) as makeup for the scrubber recycle tanks, limestone slurry ball mills, 

gypsum plant seal water, and the old gypsum belt, as long as those waters are retained in the 

FGD system or collected with the rest of the FGD wastewater. However, if the waters are not 

contained in the system (e.g., if the reference to the “old gypsum belt” is referring to washing the 

gypsum belt and the water is then collected in the floor drains and treated as a low-volume waste 

source), then that reuse would result in a combined wastestream; see preamble section XVI.A.4 

regarding combined wastestreams.

In regards to the use to flush pumps, EPA cannot comment on that use because it is dependent on 

which pumps are flushed and how the wastewater is then handled and regulated.

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Definition of "FGD Wastewater"

USEPA intends to apply separate limits to FGD wastewater, which the agency proposes to define 

as follows:

The term flue gas desulfurization (FGD) wastewater means any process wastewater generated 

from a wet flue gas desulfurization scrubber system, including any solids separation or solids 

dewatering processes. 

Proposed 40 C.F.R. §423.11.

DP&L's FGD facilities utilize, as makeup water, FGD wastewater that has been subject to solids 

removal. Including wastewater from solids separation and dewatering processes (along with the 

"anti-circumvention" proposals about mixing) will eliminate water recycling at these facilities.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 30.

Commenter Name: Vicki Card

Commenter Affiliation: Colorado Springs Utilities

Document Control Number: EPA-HQ-OW-2009-0819-4483-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Our concerns with the proposed rule are mostly due to ambiguities in certain definitions and 

regulations that lend themselves to varying interpretation, creating uncertainty for the regulated 

community.

FGD WASTEWATER DEFINITION

The language used in the proposed rule to describe FGD wastewater in Section VI (A)(2) 

[Industry Description - General Description of Industry – FGD Systems Page 34449] indicates 

that EPA is primarily concerned with regulating water containing sorbent used to remove 

pollutants from the flue gas and water associated with the FGD solids:

“In wet FGD systems, the flue gas stream comes in contact with a liquid stream containing a 

sorbent, typically lime or limestone, which is used to effect the mass transfer of pollutants from 

the flue gas to the liquid stream. This process not only transfers the sulfur dioxide from the flue 

gas to the liquid stream, but other pollutants (e.g., metals) as well”
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“Additionally, both calcium sulfite and gypsum typically require dewatering prior to 

sale/disposal and this dewatering process also generates a wastewater stream that may be 

reused or discharged”

However, the language contained in § 423.11(n) Specialized Definitions of the proposed rule is 

very broad and could be construed to include all process water associated with FGD systems –

not just the water associated with pollutant removal:

§ 423.11 Specialized Definitions.

“(n) The term flue gas desulfurization (FGD) wastewater means any process wastewater 

generated from a wet flue gas desulfurization scrubber system, including any solids separation 

or solids dewatering processes (emphasis added).”

Some FGD systems use water for ancillary purposes other than pollutant/solids removal – such 

as seal water used in vacuum pumps or liquid ring blowers. This water, which does not contact 

unscrubbed flue gas or remove solids, is often re-used. Requiring FGD water such as seal water 

to demonstrate compliance with the ELG standards before being reused would significantly deter 

the re-use of this water. Re-use of water is desired by Colorado Springs Utilities as our power 

plants are located in a semi-arid state that is currently under drought-related water restrictions.

The definition of FGD wastewater should be amended to clarify that the EPA only intends to 

regulate process water in direct contact with unscrubbed flue gas and dewatering process 

wastestreams under the proposed rule, and not FGD system water used for ancillary purposes. 

The following language is suggested:

“(n) The term flue gas desulfurization (FGD) wastewater mean process wastewater generated 

from a wet flue gas desulfurization scrubber system that is in direct contact with removed 

pollutants and/or solids. (emphasis added).”

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 30.

Wastewater used for the operation of the FGD system that does not come into contact with the 

flue gas or FGD solids (e.g., ancillary process water such as seal water used in vacuum pumps) is 

not included within the definition of FGD wastewater.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Briefly, it appears that the proposed rule contains a broad definition of FGD wastewater which 

may discourage the reuse of FGD effluent in processes such as the production of gypsum board. 

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 30.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 28

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The EPA proposal defines FGD wastewater as:

"any process wastewater generated specifically from the wet flue gas 

desulfurization scrubber system, including any solids separation or solids 

dewatering process."

78 Fed. Reg. 34532, col. 2

We believe that the inclusion of the language ''solids separation or solids dewatering process" 

discourages water reuse and recycling at facilities that reuse scrubber water in the process of 

making gypsum board. In these gypsum production systems, solids dewatering of gypsum 

produces a process wastewater that is then reused in other plant processes. The proposed EPA 

definition would require treatment of the process water from gypsum dewatering. This added 

treatment cost is likely to upset the economic viability of gypsum production and end the 

recycling of gypsum process waters. We request EPA to develop a definition of FGD 

wastewater that preserves the beneficial reuse of gypsum wash water.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 30.

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: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In conjunction with its proposed limitations on FGD waste water, EPA proposes to define that 

term as follows:

The term flue gas desulfurization (FGD) wastewater means any process wastewater generated 

from a wet flue gas desulfurization scrubber system, including any solids separation or solids 

dewatering processes.

By including waste water from solid separation and dewatering processes, EPA’s proposed 

definition of FGD waste water will frustrate and discourage utilities from recycling and/or 

reusing water at their facilities. Currently, some facilities reuse gypsum wash water beyond the 

scrubber for processes other than those associated with the FGD system. Gypsum wash water 

should not be included within the definition of FGD waste water because to do so will make 

those reuses unavailable and result in increased water consumption.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 30.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 80

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. Definition of “FGD Wastewater”

In the 1982 regulations, EPA decided to regulate wastewater from FGD scrubbers as a low 

volume waste. Now EPA intends to apply separate limits to FGD wastewater, which EPA 

proposes to define as follows:

The term flue gas desulfurization (FGD) wastewater means any process wastewater generated 

from a wet flue gas desulfurization scrubber system, including any solids separation or solids 

dewatering processes.

Proposed 40 C.F.R. § 423.11.
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Including wastewater from solids separation and dewatering processes (along with the “anticircumvention” proposals about mixing) would discourage water recycling. Some plants reuse 

scrubber wash water (i.e., process wastewater generated during dewatering of scrubber solids) 

for processes beyond the scrubber. Scrubber wash water should not be included in the definition 

of FGD wastewater because it would make those reuses infeasible.

Comment Response: 

EPA acknowledges that “[i]n the 1982 regulations, EPA decided to regulate wastewater from 

FGD scrubbers as a low volume waste;” however, for that rulemaking, EPA evaluated FGD 

wastewater and determined that “data sufficient to characterize waste loadings resulting from 

flue gas cleaning processes are not available. No net discharge data, i.e., influent and effluent 

data, are currently available for those systems. Additional studies will be needed to provide this 

data and to confirm the current discharge practices in the industry.” Development Document for 

Final Effluent Limitations Guidelines, New Source Performance Standards, and Pretreatment 

Standards for the Steam Electric Point Source Category. U.S. EPA. 1982. p.248.

As such, EPA has collected additional data and is promulgating limitations and standards for 

FGD wastewater in the final rule.

See response to DCN EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 30.
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6.g.xi. FGD gypsum

Commenter Name: Jessica Wicha

Commenter Affiliation: Gypsum Association

Document Control Number: EPA-HQ-OW-2009-0819-4456-A1

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I.FGD GYPSUM IS A MANUFACTURED PRODUCT AND SHOULD BE EXEMPT 

FROM REGULATION UNDER RCRA

In the preamble to the Proposed ELG Rule, EPA describes FGD gypsum as a "marketable 

product" and "saleable product" in its overview of FGD systems, but in its discussion of surface 

impoundments, the same material is described as a type of waste. Compare 78 Fed. Reg. at 

34449 with 78 Fed. Reg. at 34450. The Gypsum Association would like to clarify this 

inconsistency and incorrect characterization of FGD gypsum. As discussed in detail in our 

November 2010 comments on the Proposed CCR Rule, which included an overview of FGD 

gypsum and the wallboard manufacturing process, FGD gypsum is a product manufactured by 

electric utilities in a multistage process to meet precise specifications contractually identified by 

gypsum wallboard companies. As such, FGD gypsum and the resulting wallboard are products 

and not a waste.

Comment Response: 

EPA disagrees with the commenter that “FGD gypsum is a product manufactured by electric 

utilities in a multistage process to meet precise specifications contractually identified by gypsum 

wallboard companies.” EPA understands that this may be the case at some steam electric power 

plants; however, there are many plants that generate gypsum that does not meet specific 

requirements and is not sold to wallboard manufacturers. This gypsum is usually disposed of in 

an impoundment or landfill and would be classified as a waste. In any case, the ELG final rule 

does not set any requirements for FGD gypsum, only discharges of pollutants in FGD 

wastewater. Thus, the issues raised by the commenter are outside the scope this rulemaking.

EPA notes that comments submitted on the proposed CCR rule were addressed in the context of 

that rulemaking.

Commenter Name: Lauren P. Alterman

Commenter Affiliation: CertainTeed Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4660-A2

Comment Excerpt Number: 5
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

V. WALLBOARD GYPSUM IS A MANUFACTURED PRODUCT AND 

THEREFORE DOES NOT FALL WITHIN THE DEFINITION OF CCRS

In the preamble to the Proposed ELG Rule, EPA describes Wallboard Gypsum as a "marketable 

product" and "saleable product" in its overview of FGD systems, but its discussion of surface 

impoundments, the same material is described as a type of waste. Compare 78 Fed. Reg. at 

34449 with 78 Fed. Reg. at 34450. As discussed in detail in our November 2010 comments on 

the Proposed CCR Rule, which included an overview of Wallboard Gypsum and the wallboard 

manufacturing process, CertainTeed commented that Wallboard Gypsum is a product 

manufactured by electric utilities in a multistage process to meet precise specifications 

contractually identified by gypsum wallboard companies. The process is done to create a product 

and the material is not destined for disposal at any time in the process. As such, Wallboard 

Gypsum is a product, not a waste that is destined for disposal, and therefore Wallboard Gypsum 

does not fall within the Agency’s proposed definition of CCRs.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4456-A1, Excerpt Number 5.

The ELG final rule does not include a definition for CCRs because the final regulations do not 

refer to coal combustion residuals or establish any requirements related specifically to “coal 

combustion residuals.” See the final CCR rule for the definition of “coal combustion residuals” 

specific to that rule.

Commenter Name: Lauren P. Alterman

Commenter Affiliation: CertainTeed Corporation

Document Control Number: EPA-HQ-OW-2009-0819-4660-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Since Wallboard Gypsum is a manufactured product, not a waste and it is never destined for 

disposal, it is clear that Wallboard Gypsum does not fall within the definition of CCRs. 

CertainTeed requests that the Agency make a formal determination that Wallboard Gypsum does 

not fall within its proposed definition of CCRs.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4456-A1, Excerpt Number 5.

See response to DCN EPA-HQ-OW-2009-0819-4460-A2, Excerpt Number 5.
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6.g.xii. Primary particulate collection system

Commenter Name: Chad Miller

Commenter Affiliation: Montana-Dakota Utilities Co.

Document Control Number: EPA-HQ-OW-2009-0819-4457-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Primary Particulate Collection System.

The term "primary particulate collection system" is used frequently throughout the proposed 

ELG rule. Montana-Dakota would like EPA to define this term . It is important for the industry 

to fully understand this term as it will affect a facility's applicability to the proposed rule, 

specifically to FGMC wastewater and Fly Ash transport water standards.

Comment Response: 

The primary particulate collection system refers to the first air pollution control device in the flue 

gas pathway where the bulk of the fly ash is collected, such as collection at an electrostatic 

precipitator (ESP) or baghouse. For example, the flue gas pathway may consist of the following 

steps: SCR, ESP, activated carbon injection, baghouse, FGD system, and stack. In this case, the 

ESP would be considered the primary particulate collection system and the baghouse would be 

considered the secondary particulate collection system. EPA used the term in the preamble for 

the rule and Appendix A of the preamble defines the term. The term is not used in the text of the 

regulations; therefore, EPA determined that a definition of the term in 40 CFR Part 423 is not 

warranted. 

Commenter Name: Chad Miller

Commenter Affiliation: Montana-Dakota Utilities Co.

Document Control Number: EPA-HQ-OW-2009-0819-4457-A1

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Clarification is necessary for industry to determine a unit's name plate capacity and also what 

constitutes a primary particulate removal system.

Comment Response: 
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Regarding primary particulate removal system, see response to DCN EPA-HQ-OW-2009-0819-

4457-A1, Excerpt Number 6.

Regarding name plate capacity, EPA uses the definition defined by the U.S. Energy Information 

Administration, which is as follows:

Generator nameplate capacity (installed): The maximum rated output of a generator, prime 

mover, or other electric power production equipment under specific conditions designated by the 

manufacturer. Installed generator nameplate capacity is commonly expressed in megawatts 

(MW) and is usually indicated on a nameplate physically attached to the generator.
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6.g.xiii. Flue gas mercury control water (FGMC)

Commenter Name: Chad Miller

Commenter Affiliation: Montana-Dakota Utilities Co.

Document Control Number: EPA-HQ-OW-2009-0819-4457-A1

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Flue Gas Mercury Control Wastewater.

In the proposed ELG regulation, EPA defines Flue Gas Mercury Control Water (FGMC) in 

§423.11(o) as any process wastewater generated from an air pollution control system installed 

or operated for the purpose of removing mercury from flue gas. This includes fly ash collection 

systems when the particulate control system follows the injection of sorbents or implementation 

of other controls to remove mercury from flue gas. Flue gas desulfurization systems are not 

included in this definition.

In the preamble to the proposed ELG Rule, EPA discusses two (2) main types of FGMC systems 

that remove mercury from flue gas. One is the addition of oxidizers to the coal prior to 

combustion, whereby the oxidized mercury is removed in the wet FGD system. The second is the 

injection of activated carbon into the flue gas which adsorbs the mercury and is captured in a 

downstream particulate removal system.

In the preamble and Technical Development Document EPA states that the first type of FGMC 

system, the use of oxidizers prior to combustion, does not produce a new wastewater stream as it 

is handled with FGD wastewater.

EPA also discusses in the Technical Development Document and preamble how FGMC 

wastewater can be created from the second type of FGMC system, the use of activated 

carbon. However, this discussion is less clear. EPA states "If the injection [of activated carbon] 

occurs upstream of the primary particulate removal system, then the mercury -containing carbon 

is collected and handled the same way as the fly ash. Therefore, if the fly ash is wet sluiced, then 

the FGMC wastes are also wet sluiced and likely sent to the same surface impoundment." 

However, EPA does not clarify what the wet sluiced wastewater is defined as. Is the resulting 

wastewater fly ash transport water, FGMC wastewater, or both?

Montana-Dakota would like EPA to clarify, what wastewater stream would be created if the 

injection of activated carbon is prior to the primary particulate system and is subsequently wetsluiced.

Comment Response: 
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EPA confirms that FGMC systems that spray oxidizers onto the coal prior to combustion are not 

covered by the FGMC wastewater limitations and standards in the final rule. EPA reviewed the 

FGMC proposed definition and for the final rule, as described in preamble Appendix A, includes 

the following definition:

“Any wastewater generated from an air pollution control system installed or operated for the 

purpose of removing mercury from flue gas. This includes fly ash collection systems when the 

particulate control system follows sorbent injection or other controls to remove mercury from 

flue gas. FGD wastewater generated at plants using oxidizing agents to remove mercury in the 

FGD system and not in a separate FGMC system is not included in this definition.”

FGMC systems that inject activated carbon into the flue gas, which adsorbs mercury and is 

captured in a downstream particulate removal system could generate FGMC wastewater and 

would be subject to the final rule limitations and standards for that wastewater. In the example 

provided by the commenter, where injection of activated carbon occurs upstream of the primary 

particulate removal system and the mercury-containing carbon is collected and handled with the 

fly ash, the resulting commingled waste is considered fly ash because that is the predominant 

waste present. EPA is promulgating the same limitations and standards for FGMC wastewater 

and fly ash transport water. Therefore, the same effluent limitations and standards will apply to 

the wastewater, regardless of whether it is classified as FGMC wastewater or fly ash transport 

water.

Commenter Name: Chad Miller

Commenter Affiliation: Montana-Dakota Utilities Co.

Document Control Number: EPA-HQ-OW-2009-0819-4457-A1

Comment Excerpt Number: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The preamble and technical development document to the proposed rule clarified that FGMC 

wastewater is not created by the use of oxidizers; however, EPA did not clearly describe if 

FGMC wastewater is created by the injection of activated carbon. Specifically, Montana-Da kota 

requests the EPA clarify what wastewater stream would be created if the injection of activated 

carbon is prior to the primary particulate system and is subsequently wet -sluiced.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4457-A1, Excerpt Number 7.
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Commenter Name: John W. Myers

Commenter Affiliation: Tennessee Valley Authority (TVA)

Document Control Number: EPA-HQ-OW-2009-0819-4607-A1

Comment Excerpt Number: 39

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The definition of FGMC needs to be clarified to exclude oxidizers applied directly to coal. The 

definition should specifically exclude oxidizers sprayed directly onto coal as they may or may 

not go to a wet scrubber that would then have a discharge.

Comment Response: 

Comment Response: 

EPA notes that the final rule does not include a definition for flue gas mercury control (FGMC). 

Instead, the final rule provides a definition for FGMC system and FGMC wastewater. It is 

unclear from the comment, which definition the commenter believes should be revised.

Also, EPA disagrees with the commenter that the FGMC system definition should be revised to 

exclude oxidizing agents because the use of oxidizing agents in combination with a FGD system 

is a mechanism for the removal of mercury from the flue gas. Therefore, oxidizing agents need to 

be included in the FGMC system definition.

In addition, EPA agrees with the commenter that FGD wastewater generated in combination with 

the use of oxidizing agents should not be included in the definition for FGMC wastewater. See 

response to DCN EPA-HQ-OW-2009-0819-4457-A1, Excerpt Number 7 for further information.
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6.g.xiv. Low volume waste

Commenter Name: Gary A. Dawson

Commenter Affiliation: Consumers Energy Company

Document Control Number: EPA-HQ-OW-2009-0819-4452-A2

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We support UWAG’s clarification of the nonchemical metal cleaning wastewater definition, and 

encourage EPA to restrict its definition to those wastewaters generated on the fire side of the 

boiler, including air preheater cleaning. UWAG’s comments further clarify those wash waters 

that are to be excluded from this definition to exclude those wash waters that this rule is not 

intended to regulate. We also agree with UWAG’s definition of a low volume waste and its 

position on the criteria under which a nonchemical metal cleaning waste is deemed a low volume 

waste.

Comment Response: 

Related to the definition of non-chemical metal cleaning waste, please see response to DCN 

EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment Code 6.g.ii.

EPA was unable to find a revised definition of “low volume waste” in UWAG’s comments 

(DCN EPA-HQ-OW-2009-0819-4655). Therefore, limiting EPA’s ability to address the 

comment related to the low volume waste definition.

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: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should revise the proposed definition of nonchemical metal cleaning wastes to which 

Section 423.13(f) would apply to specifically exclude wastes already defined as low volume 

waste sources that are regulated at Section 423.12(b)(3).

Comment Response: 
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Related to the definition of non-chemical metal cleaning waste, please see response to DCN 

EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment Code 6.g.ii.

Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (MP)

Document Control Number: EPA-HQ-OW-2009-0819-4484-A1

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

MP also requests that EPA identify those waste sources it proposes to regulate as non-chemical 

metal cleaning waste sources and in doing so, provide clarification for the term “low volume 

wastes”.

Comment Response: 

Related to the definition of non-chemical metal cleaning waste, please see response to DCN 

EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment Code 6.g.ii.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

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

Comment Excerpt Number: 24

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Should Clarify the Treatment of Different “Washing” Activities 

EPA should clarify what washing is “low volume” wastewater and what washing is 

“nonchemical metal cleaning wastewater” subject to the regulation. Floor drainage wash waters 

are normally considered “low volume” wastewaters (not addressed in this proposed rule), but 

many routine and frequent nonchemical equipment wash waters are discharged to floor drains 

and sumps.

Comment Response: 

Related to the definition of non-chemical metal cleaning waste, please see response to DCN 

EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment Code 6.g.ii.
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Commenter Name: Michael G. Cashin

Commenter Affiliation: Minnesota Power (ALLETE)

Document Control Number: EPA-HQ-OW-2009-0819-4768-A2

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

MP also requests that EPA identify those waste sources it proposes to regulate as non-chemical 

metal cleaning waste sources and in doing so, provide clarification for the term “low volume 

wastes”.

Comment Response: 

Related to the definition of non-chemical metal cleaning waste, please see response to DCN 

EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 15 in Comment Code 6.g.ii.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

FGD wastewater and landfill leachate should continue to fall within the definition of “low 

volume waste” and the associated proposed ELGs for these specific waste streams should be 

eliminated from the final rule.

Comment Response: 

EPA disagrees with the commenter that the proposed limitations and standards for FGD 

wastewater and combustion residual leachate “should be eliminated from the final rule.” As 

described in preamble, EPA’s detailed study of the steam electric power industry found that the 

rise of new processes for generating electric power (for example coal gasification) and the 

widespread implementation of air pollution controls (such as flue gas desulfurization (FGD) and 

flue gas mercury controls (FGMC)) have altered existing wastestreams and created new types of 

wastewater at many steam electric power plants. Thus, the processes employed and pollutants 

discharged by the industry look very different today than they did over 30 years ago. Such 
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wastestreams include FGD wastewater, FGMC wastewater, carbon capture wastewater, and 

gasification wastewaters.

Controlling these wastestreams, as well as other combustion-related wastestreams at steam 

electric power plants (for example, fly ash and bottom ash transport water, and combustion 

residual leachate) is technically available and economically achievable for the point source 

category as a whole. See preamble for more information. While not determinative for Agency 

decision making, EPA notes that these wastestreams contain pollutants in concentrations and 

mass loadings that are causing documented environmental impacts. Therefore, the final rule 

establishes separate definitions for FGD wastewater, FGMC wastewater, gasification 

wastewater, and combustion residual leachate, making clear that these four wastestreams are no 

longer considered low volume waste sources. As well, the final rule establishes effluent 

limitations and standards for these wastestreams. See preamble section VIII for EPA’s rationale 

for promulgating the final effluent limitations and standards.
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6.g.xv. Impoundment (CCR impoundment, surface impoundment)

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposed rule uses the term “surface impoundment” or simply “impoundment” which as 

defined includes settling ponds and basins. We note that the use of the term impoundment in this 

rulemaking may be confusing since regulation of impoundments that are used for managing and 

disposing large volumes of coal combustion residuals (e.g., ash ponds) is being considered in 

other EPA proposed rules.

Comment Response: 

The final rule does not establish a definition of “surface impoundments” because the final rule 

does not establish BMP requirements related to surface impoundments, and the final regulations 

do not otherwise use the term "surface impoundments." See preamble section VIII.J.

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: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

many states manage CCRs through waste management programs. Many states manage CCR 

impoundments differently depending on whether the impoundment will serve as the final 

repository for the CCRs. EPA should clearly define in the final rule what constitutes a “CCR 

Impoundment,” to avoid confusion for states in determining which facilities are regulated under 

which programs.

Comment Response: 

see DCN EPA-HQ-OW-2009-0819-4475-A1, Excerpt Number 2.

See also EPA’s final CCR rule regarding the definition of "CCR surface impoundment," related 

definitions, and applicable requirements of that rule.
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6.g.xvi. Zero discharge and no discharge

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: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The use of terms such as “no discharge” or “zero discharge” should be carefully clarified in the 

final rule to avoid any possible loopholes or encouragement for direct dischargers to switch to 

indirect discharge processes to lessen compliance requirements. There is a difference between 

“no discharge of pollutants” and “zero discharge” (implies no discharge of any kind). ACWA 

suggests the language in the final rule be more understandable, especially if there is a difference 

in language between direct discharge and pretreatment standards. For example, the final rule 

could state, “there shall be no measurable pollutants in any wastewater discharged from the 

transport of fly ash.” Such clarification of zero discharge of pollutants and/or no process 

discharge should also describe the appropriate level of detection.

Comment Response: 

The final rule establishes the same BAT limitations and PSES standards for the wastestreams for 

which EPA is establishing a “no discharge of pollutants” requirement. Therefore, there are no 

potential loopholes for a plant to begin discharging to a POTW to avoid the requirements.

Additionally, the final rules establishes an anti-circumvention provision that applies only to those 

wastestreams with zero discharge limitations or standards. See the preamble section VIII.G and 

the TDD for a description of the anti-circumvention provision.

EPA does not see, for purposes of this rule, a difference between describing a requirement as a 

"no discharge" or a "zero discharge" requirement. For the “no discharge of pollutants” 

requirement, there is no level of detection that is appropriate. EPA notes that a “no discharge of 

pollutants” requirement was established for NSPS for fly ash transport water in the 1982 final 

rule, which has been implemented in the industry for the last 30-plus years.

Commenter Name: Zak Covar

Commenter Affiliation: Texas Commission on Environmental Quality (TCEQ)

Document Control Number: EPA-HQ-OW-2009-0819-4985-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Define the terms "no discharge" and "zero discharge"

The TCEQ recommends that the EPA include a definition of both terms in the specialized 

definitions subpart §123.11.

The terms "no discharge" and "zero discharge" as used in the proposed rule are not clearly 

defined. If the intent is to not discharge any pollutants in measurable amounts, then that 

clarification should be made and include a level of detection. If the intent is to not discharge any 

regulated wastestream (e.g., no flow), then that should be clearly stated.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4535-A2, Excerpt Number 15.
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6.g.xvii. Blowdown

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposal also contains new language regarding cooling tower blowdown discharge which 

may present compliance issues. 

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 213 in Comment Code 

5.d and DCN EPA-HQ-OW-2009-0819-4658-A2, Excerpt Number 2, in Comment Code 5.d.
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6.g.xviii. Changing definitions

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA also introduces unnecessary vagueries into the applicability of the ELGs through unjustified 

modifications of long-standing definitions.

Comment Response: 

EPA disagrees with the commenter that EPA has introduced “unnecessary vagueries into the 

applicability of the ELGs through unjustified modifications of long-standing definitions.” EPA 

has defined new terms and clarified existing terms as appropriate in the final rule. For further 

information please see the final preamble. 

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In addition , we believe the proposed rulemaking may expand the historic ELG definitions of 

FGD wastewater, bottom ash, leachate, and non-chemical metal cleaning waste which may 

create some unintentional ELG implementation issues. 

Comment Response: 

EPA disagrees with the commenter that the “rulemaking may expand the historic ELG 

definitions” for certain terms because, for example, for FGD wastewater and combustion residual 

leachate, the previously established ELGs never defined these terms. The final rule promulgates

definitions for these terms, as it also establishes limitations and standards for these particular 

wastestreams. Since these terms were not defined previously defined by the regulations, EPA 

could not be "expanding" previous definition.
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In addition, the final rule does not promulgate a definition for non-chemical metal cleaning 

wastes, nor does EPA describe a definition in the preamble; therefore, there is no expansion of 

the definition in the final rule. In addition, for bottom ash, the final rule promulgates a revised 

definition, which is a clarification of the existing definition. Therefore, the definition 

modification serves as a clarification, rather than an expansion of the term.

For more information on the definition of FGD wastewater, please see responses to Comment 

Code 6.g.x. For information on the definitions related to bottom ash, combustion residual 

leachate and non-chemical metal cleaning wastes, see responses to Comment Code 6.g.ix, 

Comment Code 6.g.i, and Comment Code 6.g.ii, respectively.
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6.h. Cost Effectiveness

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 102

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We have three preliminary conclusions from the analysis we've done. One is that the ash 

pollution removals have been vastly overestimated by EPA, and that's a key consideration when 

you're developing how to do your Final Rule.

Comment Response: 

EPA disagrees that its ash transport water pollutant reduction estimates are vastly overestimated 

in the final rule. In response to comments, EPA revised its estimates for the final rule. See 

chapter 10 of the final TDD for the final estimates and see response to DCN EPA-HQ-OW2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d.

See responses to comment codes 13.d and 15.d for detailed responses to ash loading comments.

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 149, regarding the 

requirement in the Clean Water Act to “identify . . . the degree of effluent reduction attainable.”

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 106

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Now, the major problem in the rulemaking that we saw is EPA overestimating the toxic weight 

pollutant removals. This is a fancy way of estimating how much pollution is in there and how to 

weight them.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 102 regarding EPA’s 

calculation of pollutant loadings. 
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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: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

If EPA nonetheless decides to finalize the rule based on the existing record, any further 

regulation of fly ash transport water and bottom ash transport water is unjustified and 

unwarranted because dry handling is not cost effective for either wastewater. The same is true for 

combustion residual leachate.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that dry handling for control of fly ash transport water discharges and dry 

handling or closed-loop systems for control of bottom ash transport water discharges represent 

Best Available Technology Economically Achievable (except for discharges from “small” or oilfired generating units) and Best Available Demonstrate Control Technology. For controlling 

discharges of combustion residual leachate, EPA determined that surface impoundments 

represent BAT and chemical precipitation represents BADCT. These technologies are available 

and economically achievable (i.e., affordable) for the industry as a whole, and have acceptable 

non-water quality environmental impacts as required by the Clean Water Act (see preamble 

Section VIII).

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions 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: Chris M. Hobson

Commenter Affiliation: Southern Company

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

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

As we examined EPA’s cost-effectiveness analysis, we found many flaws, beginning with its 

chosen characterization data and running through its technology costing methodologies. EPA’s 

cost-effectiveness analysis is not valid for bottom ash transport water, fly ash transport water, 

and FGD wastewater. Its analysis overstates the pollutants attributable to the industry and 

underestimates costs.

Comment Response: 

In response to comments, EPA revised its estimates of loadings, costs, and cost-effectiveness for 

the final rule. EPA disagrees with the commenter that these analyses are flawed or that its 

analyses overstate the pollutants attributable to the industry and underestimates costs of the final 

rule. See the TDD for final estimates of costs and loads and the RIA for final estimates of costeffectiveness.

The commenter’s statements regarding “flaws” in EPA’s characterization data and costing 

methodologies are too generalized to permit specific response. For responses to specific 

comments regarding bottom ash transport water characterization and loadings, see responses to 

comment codes 15.c, 15.d, and 16.c. For responses to specific comments regarding bottom ash 

transport water costs, see responses to comment code 16.b.

For responses to comments regarding fly ash transport water characterization and loadings, see 

responses to comment codes 13.c, 13.d, and 14.c. For responses to comments regarding fly ash 

transport water costs, see responses to comment code 14.b.

For responses to comments regarding FGD wastewater characterization and loadings, see 

responses to comment codes 8.c, 8.d, and 10.c. For responses to comments regarding FGD 

wastewater costs, see responses to comment code 10.b.

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

Comment Excerpt Number: 149

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Description of the Electric Utility Industry Should Be More Objective

 Steam Electric Pollutant Loading Contributions Are Flawed

In the preamble to the proposed rule, EPA emphasizes the environmental harm supposedly done 

by electric power plants, particularly those burning coal. Thus EPA starts by reporting “there are 

numerous documented instances of environmental impact associated with these power plant 

discharges, such as harm to human health, harm to aquatic life, contamination of sediment, and 

detrimental impacts to wildlife.” 78 Fed. Reg. at 34,435 col. 2; see also, id. 34,439-40, 34,504. 

Similarly, EPA says discharges from steam electric power plants contribute 50 to 60% of the 

reported toxic-weighted pollutant loadings of the combined discharges of all industrial 

categories. 78 Fed. Reg. at 34,505 col. 2. EPA’s contractor, ERG, provides a short explanation of 

how it compared steam electric loadings to those of other industries in a memorandum on the 

record. EPA-HQ-OW-2009-0819-2232. See also page 3 of the transcript of EPA’s August 20, 

2013 webcast, http://water.epa.gov/scitech/wastetech/guide/steamelectric/upload/webcast_8202013.pdf (“more than half of all toxic pollutants . . . linked to 

cancer, neurological damage, and ecological damages”).

Not surprisingly, advocacy groups have picked up this theme and emphasized the amount of 

pollution allegedly created by the coal industry. See Waterkeeper Alliance et al., Closing the 

Floodgates: How the Coal Industry is Poisoning Our Water and How We Can Stop It 

(2013).65 Early comments by environmental groups have taken advantage of EPA’s description. 

See Comments of Environmental Council of Rhode Island, EPA-HQ-OW-2009-0819-4034 

(Sept. 11, 2013) at 1.

As explained earlier in these comments, UWAG’s analyses show that EPA has vastly overstated 

the amount of pollutants being discharged. As UWAG’s comments have shown based on 

additional sampling and analysis by URS (see Attachment 5 to the UWAG comments), sulfides 

are generally not present in ash pond discharges, so the huge amount of TWPEs that EPA 

figures into industry loadings should be removed. That adjustment alone would dramatically 

reduce the steam electric percentage range by EPA’s own reckoning. See EPA-HQ- OW-2009-

0819-2232.

Also, the loadings attributable to use of the old, unreliable 1970s data from the 1982 

Development Document should be removed and replaced with better quality data that actually 

reflects wastewater discharges at today’s plants. Based on the industry’s suggested corrections 

and use of better data, we have calculated a revised total baseline loading of 1.97 

million TWPEs. Based on this corrected value and EPA’s formulas,66 the percentage of the total 

TWPEs attributed to the steam electric category is 27%.
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We have not been able to assess all the data underlying EPA’s industry loadings calculations. We 

suspect that EPA has used erroneous flow rates for ash pond discharges in many cases, but the 

relatively short comment period (particularly as to the loadings data which became available 

only about a week before the comments were due) has not allowed us to develop full evidence of 

that discrepancy. Therefore, while use of industry present loadings numbers indicate that the 

steam electric industry produces no more than 27% of total TWPEs, it is very likely that the 

percentage is lower than that.

There are additional factors which also affect the loadings calculations and assessment of their 

impact. Those factors include the following.

 When a pollutant is not detected, EPA assumes it is present at the highest possible level, 

given the detection limit.

 EPA assumes that exceeding a water quality criterion means that fish in the waterbody 

are harmed.

 EPA mischaracterizes scientific literature as proving harm to the environment when there 

was no evidence of damage.

 EPA relies heavily on old data, including data from before Clean Water Act requirements 

took effect.

 EPA used a faulty means of calculating pollutant loadings, making its estimate of 

loadings from ash ponds six times too high.

In light of these shortcomings, EPA would do well, with the final rule, to describe the industry 

more objectively and avoid alarming descriptions of pollutant loadings. Since it appears EPA has 

overstated the percentage of TWPEs attributable to the steam electric industry by at least a 

factor of two, and likely understated the contributions of other industries not currently 

undergoing an ELG rulemaking, Southern requests that EPA make every effort to correct the 

record on this point.

65

 http://earthjustice.org/documents/report/pdf/closing-the-floodgates.

66 The formulas are presented in ERG’s memo of April 19, 2013 titled “Comparison of Steam 

Electric Industry Toxic Loadings to Other Industrial Dischargers.” EPA-HQ-OW-2009- 0819-

2232.

Comment Response: 

Environmental Impacts: As discussed in the preamble, steam electric pollutant discharges 

present a serious public-health concern and cause severe ecological damage, as demonstrated by 

numerous documented impacts, scientific modeling, and other studies. See preamble section 

XIII, as well as responses to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Numbers 71 and 

76 in Comment Code 25.b for a discussion of EPA’s evaluation of documented environmental 

impacts. In addition, see Sections 3 and 6 of the Environmental Assessment for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 
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Category (EA Report) (DCN SE04527) for EPA’s assessment of the environmental impacts from 

steam electric power plant wastewater; Section 7 of the final EA Report for EPA’s assessment of 

the environmental improvements under the final rule; and Section 3.2 of the final EA Report for 

EPAs’ revised comparison of steam electric power plant loadings to other industries and to 

POTWs.

EPA disagrees that it “assumes that exceeding a water quality criterion means that fish in the 

waterbody are harmed.” As described in the EA Report, EPA calculates immediate receiving 

water specific pollutant concentrations in the water column and sediment and evaluates the 

potential impacts that receiving water concentrations pose to aquatic life and human health. In 

addition, EPA calculates the pollutant concentrations in exposed fish populations. EPA does not 

equate a water quality exceedance with a specific harmful effect to fish. EPA uses the calculated 

exceedances to indicate that aquatic organisms inhabiting these waters are under a greater threat 

than those in waters that do not have water quality exceedances.

EPA also disagrees with the commenter that the Agency “mischaracterizes scientific literature as 

proving harm to the environment when there was no evidence of damage.” Because the 

commenter’s statements are so generalized, and do not indicate what “scientific literature” the 

commenter thinks the Agency “mischaracterized,” or how so, EPA cannot offer a specific 

response to this particular comment.

Sulfides: In response to comments, EPA no longer identifies sulfide as a POC or includes it in its 

loadings calculations.

Use of 1982 TDD Data: See response to DCN EPA-HQ-OW-2009-0819-4499-A1, Excerpt 

Number 72 in Comment Code 15.d.

Ash Pond Discharge Flow Rates: EPA disagrees that it used “erroneous flow rates for ash pond 

discharges in many cases.” See the response to DCN EPA-HQ-OW-2009-0819-4379-A1, 

Excerpt Number 134 for a discussion of how EPA determined ash discharge flow rates, 

including accounting for recycle streams, for the final rule. In addition, where EPA received 

plant-specific comments about flow rates, it evaluated the comments and made changes to the 

flow rates used as appropriate.

Pollutants that are Not Detected: See response to DCN EPA-HQ-OW-2009-0819-4499-A1, 

Excerpt Number 72 in Comment Code 15.d.

Pollutant Loadings: EPA disagrees with the commenter that it “used a faulty means of 

calculating pollutant loadings.” This comment is too generalized to allow for a specific 

response. Nonetheless, EPA notes that, based on public comments, EPA revised its pollutant 

loadings estimates for the final rule, including its estimate of the contribution steam electric 

power plants have on combined discharges of all industrial categories. See the final preamble. 

Also, EPA assumes that “particularly as to the loadings data which became available only about 

a week before the comments were due” is referring to a version of the costs and loads report that 

was produced in response to a Freedom and Information Act (FOIA) request. EPA notes that it 

is statutorily obligated to protect information that has been claimed as confidential business 
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information (CBI). See response to DCN EPA-HQ-OW-2009-0819-4688 Excerpt Number 224 in 

Comment Code 1.c for more discussion on CBI information related to ash and FGD pollutant 

loadings.

Section 304(b)(2)(A) of the Clean Water Act requires that the Administrator publish regulations 

providing guidelines for effluent limitations which “identify, in terms of the amounts of 

constituents and chemical, physical, and biological characteristics of pollutants, the degree of 

effluent reduction attainable through the application of the best control measures and practices 

achievable including treatment techniques, process and procedure innovations, operating 

methods, and other alternatives for classes and categories of point sources . . . .” At least one 

court has held that EPA satisfies the statutory requirement to identify of the degree of effluent 

reduction attainable simply by (1) identifying the types of pollutants whose discharge must be 

limited, and (2) establishing in the regulations the amounts of these pollutants which may be 

discharged by the industry. Am. Paper Inst. v. Train, 543 F.2d 328, 342 (D.C. Cir. 1976). The 

court rejected the contention that “EPA is also required to furnish data as to the pollution 

reduction which can be expected from the [model] technologies.” The court said that the 

language of the Act does not “dictate[]” that EPA “must also estimate how much reduction in 

pollution will be achieved as a result of the enunciated standard.” Id. For this final rule, EPA 

has identified the types of pollutants whose discharge must be limited (e.g., depending on the 

wastestream to which the final rule applies, the rule specifies that TSS, arsenic, mercury, 

selenium, nitrate/nitrite as N, TDS, or all pollutants must be limited), and it has established in the 

regulations the amount of these pollutants which may be discharged by the steam electric 

industry (e.g., numeric limitations in mg/L or ug/L or ng/L for certain pollutants or “zero 

discharge” limitations for other pollutants).

Moreover, because estimate of effluent reduction is not a decision factor for BAT, estimates of 

such reductions are not a basis for remanding BAT limits, even where the estimates are alleged 

to have “serious flaws” or be “grossly mischaracterized.” Texas Oil & Gas Ass’n v. EPA, 161 

F.3d 923, 936 (5th Cir. 1998) (“Whatever value such benefit estimates may have, they are not a 

required part of the BAT determination. . . . As such, even serious flaws in the effluent reduction 

estimates could not provide grounds for remanding the zero discharge limit.”).

Commenter Name: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Best Available Technology ("BAT") economically achievable should be adopted for only those 

technologies that cost less than $404 (in 1981 dollar) per toxic-weighted pounds-equivalent 

("TWPE") as a high-end limit and closer to the more typical $200 $/TWPE.
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Comment Response: 

EPA disagrees with the commenter that BAT should be based on cost-effectiveness or pollutant 

reductions (measured in TWPE). The final rule establishes limitations and standards applicable 

to the discharge of pollutants from the steam electric power generating industry based on the 

“best available technology economically achievable” and the “best available demonstrated 

control technology,” as those terms are used in sections 301, 304, and 306 of the Clean Water 

Act. EPA determined that the suite of technology described as Option D and Option F represent 

BAT and BADCT, respectively, for the final rule because the technologies are available and 

economically achievable (i.e., affordable) for the industry as a whole, and have acceptable nonwater quality environmental impacts (see preamble Section VIII).

EPA revised pollutant loadings/reductions, costs, and cost-effectiveness for the final rule, based 

on public comments. See preamble section X and TDD Section 10 regarding pollutant 

loadings/reductions associated with the final rule, see preamble sections V.D and IX (and TDD 

Section 9) regarding compliance costs associated with the final rule, and see preamble section 

XV (and the RIA) for information on the cost-effectiveness of the final rule.

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of 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: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

BAT Requirements Should Be Adopted For Only Those Technologies That Cost Less Than $404 

(in 1981 dollars) Per TWPE.
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EPA calculates "cost-effectiveness" of proposed BAT requirements in terms of TWPEs of 

pollutants removed. This approach allows EPA to evaluate the relative efficiency of alternative 

regulatory options in removing toxic pollutants from effluent discharges. EPA has established a 

high-end limit of $404 in 1981 dollars as the highest cost per TWPE for BAT:

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/lbeq (Electrical and Electronic Components), in 1981 dollars.

78 Fed. Reg. at 34,504 col. 1-2. However, EPA has typically used a cost of less than $200 per 

TWPE. 68 Fed. Reg. 25,686, 25,701 (May 13, 2003). In several past ELG rulemakings, EPA 

published a table of cost-effectiveness estimates by industry category. In four cost-effectiveness 

analyses from 1996-2000, the highest cost per equivalent pound was listed as $404 in 1981 

dollars. EPA subsequently determined that a technology was not BAT "economically 

achievable" when it exceeded the $404 per TWPE.

Consistent with EPA's previous analyses and typical practice, EPA should adopt in this 

rulemaking only those technologies that are closer to the more typical $200 per TWPE range, but 

certainly less than the $400 per TWPE criterion, which were assessed through appropriate, 

rigorous cost-effectiveness analyses. Based on industry cost-effectiveness analysis, which relies 

on the $404 per TWPE as the high end of cost effectiveness and less than $200 per TWPE as 

typical, only the use of impoundment (settlement) as a technology basis is justifiable as cost

effective for fly ash transport water, bottom ash transport water, leachate, and flue gas mercury 

control wastewater. Furthermore, no additional treatment can be justified on a cost-effectiveness 

basis for plants with flue gas desulfurization wastewater with a flow rate of 200 GPM or less.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4447-A1, Excerpt Number 2. 

See preamble Section VIII for a description of the technology basis for the final rule, as well as 

an explanation for EPA’s decisions.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. Cost Effectiveness Analyses
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As required, EPA assessed the compliance costs and pollutant reduction associated with each of 

the proposed regulatory options. The agency’s TDD provides an in-depth discussion of these 

analyses and offers insight on how they were accomplished. EPA estimated costs and pollutant 

loads on a per plant basis. To confirm these estimates, AEP conducted a similar 

analysis. However, it was found that, without exception, EPA under-estimated the costs and 

over-estimated the benefits of the proposed treatment options for each of the wastewaters that 

were analyzed by AEP (FGD wastewater, fly ash and bottom ash transport water, leachate, and 

nonchemical metal cleaning wastes). There are many reasons for this discrepancy, but AEP 

emphasizes the more important ones in the following comments. Please note that each of the 

following concepts were applied to AEP’s cost analysis of the proposed revisions.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 149, regarding the 

requirement in the Clean Water Act to “identify . . . the degree of effluent reduction attainable.”

In response to comments, EPA revised its estimates of pollutant loadings and reductions, 

compliance costs, and benefits for the final rule. EPA disagrees with the commenter that the 

final costs are underestimated and that the final benefits or pollutant reductions are 

overestimated. See the TDD for information on pollutant loads and the approach EPA used to 

estimate compliance costs. See the BCA for final costs and benefits.

This Excerpt Number is general in nature, as the commenter offered no specific examples of 

where or how EPA “under-estimated the costs” or “over-estimated the benefits” of the final 

rule. EPA’s responses to more specific comments on each of these topics can be found 

throughout this comment response document.

Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 13

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

4. AEP’s Cost Effectiveness Analysis

AEP used the same methods as EPA to determine $/TWPE removed for each assessed 

wastewater; however, to simplify the analysis, only direct capital costs were used. Capital costs 

were determined based on actual installations, engineering studies, or best professional 

judgment. In all cases, the costs were converted to 2010$ and then to 1981$ using Engineering

News Record’s Construction Cost Index (CCI) as follows:7
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Adjustment factor – CCI1981/CCI2010 = 3535/8802 = 0.042

Like the agency, AEP used a 7% interest value and assumed a 20-year service life when 

annualizing costs estimates, but notes that use of a 15-year service life would be more 

appropriate.

In most cases, AEP’s $/TWPE estimates were higher than those estimated by EPA, sometimes 

much higher, despite the fact that EPA also included O&M expenses in its estimates. As a result, 

the cost differences highlighted in these comments will actually be much larger should the 

proposed ELG revisions be adopted by the agency. To fully assess the impact of the additional 

O&M expenses, AEP encourages the agency to refer to the comments of UWAG8and EPRI.9

7 EPA Regulatory Impact Analysis, Appendix D: Cost Effectiveness, April 19, 2013.

8 UWAG ELG Comments, September 20, 2013.

9 Electric Power Research Institute (EPRI) Comments on Proposed Effluent Limitations 

Guidelines Rule [hereinafter EPRI ELG Comments], September 20, 2013.

Comment Response: 

EPA revised pollutant loadings/reductions, costs, and cost-effectiveness for the final rule, based 

on public comments. See preamble section X and TDD Section 10 regarding pollutant 

loadings/reductions associated with the final rule, see preamble sections V.D and IX (and TDD 

Section 9) regarding compliance costs associated with the final rule, and see preamble section 

XV (and the RIA) for information on the cost-effectiveness of the final rule.

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

In regard to the commenter’s statements about service life, see response to DCN EPA-HQ-OW2009-0819-4448-A1, Excerpt Number 12 in Comment Code 6.f.
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Commenter Name: John McManus

Commenter Affiliation: American Electric Power System (AEP)

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

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

1. EPA should independently present all treatment technologies for each individual 

wastewater stream and dispense with the “bundling” of the proposed treatment options.

EPA is proposing to revise or establish BAT10, BADCT (NSPS)11, PSES12, and 

PSNS13 standards that may apply to discharges of seven waste streams: FGD wastewater, fly ash 

transport water, bottom ash transport water, combustion residual leachate, nonchemical metal 

cleaning wastes and wastewater from FGMC systems and gasification systems. In this proposal, 

EPA is presenting eight main regulatory options (Option 1, Option 3a, Option 2, Option 3b, 

Option 3, Option 4a, Option 4, and Option 5). Four of these options (Options 3a, 3b, 3, and 

4a) are preferred by the agency and one (Option 4a) is the basis of the proposed rule; however, it 

is very difficult to assess the impact of multiple option proposals. As a result, AEP believes that 

it must assess and comment on all of the options, but must also make numerous assumptions 

regarding which option or combination of options may affect the company. It is recommended 

that in future proposals, EPA evaluate the various options and select a single option upon which 

to base its proposal. Doing so would allow for the submittal of comments that are more directed 

and specific to the proposed changes.

Within each option, EPA proposes various technology options for each of the seven waste 

streams. Each option varies from the other based on which technologies are proposed for each 

waste stream. Often, this difference varies by only one technology proposal across the seven 

waste streams. For example, Options 4 and 5 are identical except that EPA proposes ZLD (vapor 

compression evaporation) for FGD wastewaters under Option 5 in lieu of biological treatment 

under Option 4. The problem with this proposal format is that the agency has “bundled” the 

technologies, limiting their application to power plants. Many, if not most, power plants generate 

at least five of the seven waste streams that are the focus of this rulemaking. The application of 

any given technology to a specific waste stream should not be limited by the technology that is 

proposed for another waste stream at that same facility. By “bundling” the technology options, 

the agency has limited the flexibility of the technology applications. For example, depending on 

the wastewater generated by a given facility, it may be better to consider chemical precipitation 

followed by biological treatment for FGD wastewater and to propose impoundments for the 

remaining facility wastewaters. This particular combination of technologies has not been 

proposed by the agency due to its unconventional presentation of the technology options. AEP 

encourages EPA to independently present all treatment technologies for each wastewater stream 

and to dispense with the “bundling” of the proposed treatment options.
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EPA performed a cost-effectiveness analysis of the regulatory options for existing plants and 

presented the results in the Federal Register notice. However, while the agency conducted the 

same analysis for each individual wastewater, it only presented the results for those technologies 

proposed under Option 3a, one of the least stringent options (78 FR at 34474). To allow for a 

more comprehensive comparison of the cost-effectiveness of the proposed treatment 

technologies, EPA needs to present the $/TWPE for each option on a wastewater-specific basis. 

For example, when assessing the $/TWPE for FGD wastewater, the agency should present the 

cost effectiveness information for chemical precipitation only, for chemical precipitation plus 

biological treatment, for chemical precipitation plus zero liquid discharge, for biological 

treatment only, and for zero liquid discharge only. This would allow for a better comparison of 

the cost effectiveness of the proposed treatment options.

While the agency proposal focuses on seven waste streams, AEP has submitted comments that 

address five of the seven. AEP does not generate wastewater from FGMC or gasification 

systems; therefore, our comments are limited to FGD wastewater, fly ash transport water, bottom

ash transport water, combustion residual leachate and nonchemical metal cleaning wastes.

10 BAT - Best available technology economically achievable, as defined by Sections 

301(b)(2)(A) and 304(b)(2)(B) of the CWA.

11 BADCT (NSPS) - Best Available Demonstrated Control Technology (New Source 

Performance Standards)

12 PSES - Pretreatment Standards for Existing Sources.

13 PSNS - Pretreatment Standards for New Sources.

Comment Response: 

For the steam electric rule, given the number of wastestreams and technology options under 

consideration, EPA chose to propose various regulatory options that contained different 

combinations of regulation by wastestream and technology option. This approach facilitated 

EPA’s ability to determine that the final rule, overall, met the statutory requirements of 

technological availability, economic achievability, and acceptable non-water quality 

environmental impacts (see preamble Section VIII). EPA’s decision to bundle technology 

options for various wastestreams for the steam electric rule is consistent with EPA’s approach in 

developing regulatory options for other point source categories regulated under the Clean Water 

Act. Furthermore, EPA’s approach here is consistent with how the industry handles such 

wastewaters. For example, where plants have chemical precipitation, biological treatment, or 

evaporation in place, they typically treat a single wastestream with these technologies. EPA 

notes that the final rule does not require industry to use a specified technology or wastewater 

management practice. Rather, they must meet the final limitations and standards that apply to 

the discharge of pollutants from steam electric power generating units.
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The commenter correctly states that EPA presented the cost-effectiveness ratio of the BAT and 

PSES requirements for the rule. As explained in Section XV of the final preamble, 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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule.

EPA is not required, and with the exception of bottom ash transport water chose not, to present 

the $/TWPE for each option on a wastestream-specific basis. EPA did, however, provide 

$/TWPE for zero pollutant discharge requirements for bottom ash transport water in the final 

rule. See Section XV in the final preamble and the RIA. Further, EPA assessed many factors for 

the rule at the “regulatory option” level rather than at the “wastestream” level. For example, 

EPA presented information on the non-water quality environmental impacts and economic 

impacts to the industry as a whole at the regulatory option level, rather than at the wastestream 

level. EPA chose this approach for cost-effectiveness because, as previously explained, while 

cost-effectiveness is not required by the Clean Water Act, it can be useful in describing 

regulatory options and comparing them to requirements across other industries. 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. This role is the same whether one is 

referring to the cost-effectiveness of the rule, cost-effectiveness for a particular wastestream, 

incremental cost-effectiveness, or cost-effectiveness of BAT or PSES.

Commenter Name: Lisa Carty

Commenter Affiliation: Xcel Energy

Document Control Number: EPA-HQ-OW-2009-0819-4458-A1

Comment Excerpt Number: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The cost effectiveness analysis overstates the benefits to be gained by the revised guidelines. In 

the case of bottom ash transport water, EPA’s limited dataset mentioned above was used to 

determine industry-wide pollutant loading which was then used to assess cost-effectiveness of 

pollution control technologies. The result grossly underestimates the costs of pollutant removal. 

EPA estimated $107/TWPE for bottom ash handling system retrofits. UWAG conducted a 

similar analysis correcting the flaws in EPA’s analysis and calculated costs to be between $1,730 
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to $17,446/TWPE. This type of flawed cost effectiveness analysis is present throughout the 

proposal. Since BAT limits are established based in part on a cost-benefit type test, it is essential 

that the analysis and underlying data be correct for the analysis to justify the proposed effluent 

limitation guidelines.

Comment Response: 

EPA disagrees with the commenter that EPA has “overstate[d] the benefits” or “grossly 

underestimate[d] the costs of the final rule. The commenter offers no specific examples of where 

or how EPA overstated benefits or underestimated costs, and thus EPA cannot offer a direct 

response here.

Nonetheless, EPA notes that it revised pollutant loadings/reductions, costs, and costeffectiveness for the final rule, based on public comments. See preamble section X and TDD 

Section 10 regarding pollutant loadings/reductions associated with the final rule, see preamble 

sections V.D and IX (and TDD Section 9) regarding compliance costs associated with the final 

rule, and see preamble section XV (and the RIA) for information on the cost-effectiveness of the 

final rule

For the final rule, EPA used a larger set of data upon which it based bottom ash transport 

wastewater loadings. See the TDD and responses to comments in Comment Code 15.d.

EPA disagrees that BAT limits are based on “a cost-benefit type test.” 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. For the role of benefit-cost in EPA’s 

decisions for the final rule, see response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt 

Number 3 in Comment Code 6.e.

Also see response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 14 regarding 

wastestream specific cost-effectiveness.

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: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA has understated the rule’s economic impact and has failed to perform an analysis of the 

cumulative impact of this rule and other rules affecting the power sector. UWAG’s and 

ACCCE’s analyses demonstrate that the rule will cost roughly twice as much as EPA’s 

estimates, with a total compliance cost of up to $4.8 billion per year. EPA’s proposal could also 
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cause 10.9 GW of additional coal shutdowns. EPA must analyze the cumulative impact of this 

rule along with other rules affecting the power sector.

Comment Response: 

In response to public comments, EPA revised its estimates of costs for the final rule. See the 

final preamble, TDD, and RIA.

EPA’s final analyses account for the cumulative impact of this rule and other rules affecting the 

power sector. See response to DCN EPA-HQ-OW-2009-0819-4183-A2, Excerpt Number 22, 

and the RIA.

As required by the Clean Water Act, EPA determined that the final rule is economically 

achievable (i.e., affordable), with minimal projected impact on the steam electric power 

generating industry as a whole. See preamble sections VIII.C.9 and IX.C, Chapter 5 of the RIA, 

and responses to comments in comment codes 28.b and 28.c.

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: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s preferred options, all of which require dry fly ash handling, and one of which requires 

dry bottom ash handling for large units, are not cost effective.

Comment Response: 

EPA disagrees the final rule is not cost-effective. Although not required by the CWA, and not a 

determining factor for establishing BAT/PSES or BADCT/PSNS, cost-effectiveness analysis can 

be a useful tool for describing regulatory options that address toxic pollutants. As presented in 

preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the 

selected regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This 

cost-effectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements 

in other industries. The final PSES requirements for the selected regulatory option have a cost 

effectiveness of $1,228/lb-eq ($1981). This ratio is higher than the cost-effectiveness of PSES 

requirements in other industries. As explained in the preamble, the CE may be lower than 

estimated. Moreover, it is critical to establish PSES at the same level as BAT in this rule to avoid

creating an unintended incentive for plants to start sending their wastewater to POTWs in an 

attempt to avoid the requirements of the final rule. For the role of cost-effectiveness in EPA’s 
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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 Bailey

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

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

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA estimates the annual cost of the rule to industry will be between $168 million and $2.3 

billion. NERA Economic Consulting used UWAG’s cost information to determine the total cost 

of EPA’s proposal for the industry, as well as the impact on coal retirements. The NERA study 

(attached as Appendix 2) shows EPA’s proposal could have a compliance cost roughly twice 

EPA’s estimates (up to $4.8 billion annually), and could result in the retirement of an additional 

10.9 GW of coal-fired capacity.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4466-A1, Excerpt Number 3.

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: 12

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

B. Best Available Technology Historically Was Established by EPA at Under $100/PE

Industry estimates that the cost effectiveness of the rule as proposed is thousands of dollars/lbequivalent (PE) for regulation of bottom ash, not the under $40 to $60/PE estimated by EPA.23

For fly ash plants, the cost effectiveness is somewhat better.24 The February 2012 UWAG 

comments on the draft Merrimack Station permit offer a good summary of the history of cost 

effectiveness in ELGs. For example, in the 2003 promulgation of the Metals Products and 

Machinery (MP&M) ELG, EPA found that $1000/PE was too high; less than $200/PE was 

typical for BAT; $420/PE was “quite expensive;” and $455/PE was “very expensive.” The cost 

effectiveness for this rule, including removal of fly ash and bottom ash wastewater, cannot be 
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justified, since the figure, as in MP&M, is in the neighborhood of thousands of dollars/PE. In the 

past, EPA has declined to regulate such de minimis amounts of pollution. This means that the 

agency should seek more cost effective solutions, such as using chemical precipitation 

technology, instead of the current proposal of eliminating all ash wastewater discharges. In sum, 

EPA should seek a regulation with a cost/PE that is $100/PE or lower. In that manner, it would 

be complying with both the RFA and the Clean Water Act and minimizing small firm costs.

23 The industry estimate varied by size of plant, varying from several thousand dollars/PE to over 

ten thousand dollars/PE.

24 See industry comments for more detail on fly ash and bottom ash discharges, and correction of 

TWPE estimates.

Comment Response: 

EPA disagrees that the final rule is not cost-effective, or that EPA should seek a regulation with a 

cost/PE that is $100/PE or lower. Although not required by the CWA, and not a determining 

factor for establishing BAT/PSES or BADCT/PSNS, cost-effectiveness analysis can be a useful 

tool for describing regulatory options that address toxic pollutants. As presented in preamble 

section XV.B and in Appendix F of the RIA, the final BAT requirements for the selected 

regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This costeffectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements in 

other industries. 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.

Also see response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 14 regarding 

wastestream specific cost-effectiveness.

EPA notes this rule will not a significant economic impact on a substantial number of small 

entities. See preamble section XVII.C and RIA Chapter 8. EPA notes that, like the Clean Water 

Act, the Regulatory Flexibility Act does not require that EPA select for the final rule “a 

regulation with a cost/PE that is $100/PE or lower.”

EPA disagrees that the final rule regulates only de minimis pollutant discharges. See preamble 

section X and TDD chapter 10 for EPA’s estimates of pollutant loadings and reductions under 

the final rule. The steam electric industry is the single largest source of toxic pollutant 

discharges to the nation’s waters of all industrial categories regulatory under the Clean Water 

Act. See Section III of the final preamble.

The commenter states that chemical precipitation technology is more cost effective than a zero 

discharge standard for controlling discharges of ash transport water. EPA is not aware of any 

steam electric power plant that is using chemical precipitation to treat fly ash transport water or 

bottom ash transport water prior to discharge. Furthermore, EPA estimated the costs of treating 

fly ash transport water or bottom ash transport water using chemical precipitation and found that 
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they would be comparable to or higher than the costs associated with dry-handling, with fewer 

resulting pollutant reductions. See Evaluation of Chemical Precipitation Costs for Ash Transport 

Water (DCN SE05654). For this reason, EPA neither proposed nor finalized limitations or 

standards for fly ash transport water or bottom ash transport water based on chemical 

precipitation. 

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: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Proposed Rule is Not Cost-Effective.

As a result of using unrepresentative data and conducting flawed analyses, EPA has proposed a 

rule that is not cost-effective. EPA itself estimates that the cost of its proposal is between $185 

million and $954 million per year and the benefit is between $139 million and $483 million per 

year, and in our view these numbers significantly underestimate the costs and overestimate the 

benefits of the rule. Further, in all other ELGs, EPA has established a benchmark that the cost of 

removing one pound of toxic-weighted pounds-equivalent should not exceed $404 in 1981 

dollars. Yet as demonstrated below, the cost of many portions of the proposed rule would far 

exceed that benchmark. Our analysis of the proposed rule also belies EPA’s claim that its 

proposal will have little impact on the cost of compliance, plant closures, or electricity rates.

It would be ill-advised from an environmental and policy perspective for EPA to require the 

utility industry to invest billions of dollars for little environmental benefit, especially in this case 

when the electric utility fleet is already undergoing a transformation and other investments must 

be made to meet other environmental and energy regulatory obligations and goals

Comment Response: 

EPA disagrees that the final rule is based on unrepresentative data and flawed analyses. The 

commenter’s statements are too generalized to offer a specific response. Nonetheless, see 

responses to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 22 and DCN EPA-HQOW-2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d.

In response to public comments, EPA revised its estimates of pollutant loadings and reductions, 

compliance costs, and benefits for the final rule. EPA disagrees with the commenter that the 

final costs are underestimated and that the final benefits are overestimated. See TDD Sections 9 

and 10 for information on pollutant loads and the approach EPA used to estimate compliance 

costs. See the BCA for final costs and benefits. Based on the analysis done of pollutant 
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discharge reductions and benefits, EPA disagrees that the final rule will have “little 

environmental benefit.” Also, EPA notes that the final rule does not cost “billions of dollars.”

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

As required by the Clean Water Act, EPA determined that the final rule is economically 

achievable (i.e., affordable) for the steam electric power generating industry as whole, as it is 

projected to have minimal impact in terms of changes in steam electric generating unit capacity 

(i.e., unit or plant closures). EPA also determined that the final rule will have minimal impact on 

electricity rates. See preamble sections VIII.C.12 and IX, as well as RIA Sections 5 and 7.

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: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should rely on more current and reliable data for target wastestreams, and should revise its 

analyses to reflect such data, in order to avoid biases in assumptions that make its best available 

technology (BAT) determinations inappropriately conservative. Analyses by UWAG and the 

Electric Power Research Institute (EPRI) of more current data demonstrate that almost all of 

EPA’s preferred options and certain non-preferred options for FGD wastewater, bottom ash 

transport water, and fly ash transport water, and EPA’s non-preferred options that differ from its 

preferred options for combustion residual leachate, are not cost effective.

Rather, the current record supports limits consistent with current Best Practicable Control 

Technology Currently Available (BPT) (i.e., existing effluent limits for TSS and oil and grease) 

for bottom ash transport water and fly ash transport water.

Comment Response: 
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The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

Regarding the statement that EPA should rely on more current data, see response to DCN EPAHQ-OW-2009-0819-4499-A1, Excerpt Number 72 in Comment Code 15.d.

EPA determined that dry handling for control of fly ash transport water discharges and dry 

handling or closed-loop systems for control of bottom ash transport water discharges represent 

Best Available Technology Economically Achievable (except for such discharges from “small” 

or oil-fired generating units) and Best Available Demonstrate Control Technology. For 

controlling discharges of combustion residual leachate, EPA determined that surface 

impoundments represent BAT and chemical precipitation represents BADCT. These 

technologies are available and economically achievable (i.e., affordable) for the industry as a 

whole, and have acceptable non-water quality environmental impacts as required by the Clean 

Water Act (see preamble Section VIII).

In response to comments, EPA revised its estimates of pollutant loadings and reductions and 

compliance costs for the final rule. See the TDD and the RIA.

EPA disagrees that the rule is not cost-effective. Although not required by the CWA, and not a 

determining factor for establishing BAT/PSES or BADCT/PSNS, cost-effectiveness analysis can 

be a useful tool for describing regulatory options that address toxic pollutants. As presented in 

preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the 

selected regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This 

cost-effectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements 

in other industries. The final PSES requirements for the selected regulatory option have a cost 

effectiveness of $1,228/lb-eq ($1981). This ratio is higher than the cost-effectiveness of PSES 

requirements in other industries. As explained in the preamble, the CE may be lower than 

estimated. Moreover, it is critical to establish PSES at the same level as BAT in this rule to avoid 

creating an unintended incentive for plants to start sending their wastewater to POTWs in an 

attempt to avoid the requirements of 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: Quinlan J. Shea III

Commenter Affiliation: Edison Electric Institute (EEI)

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

Comment Excerpt Number: 112

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Also, as further detailed in UWAG’s comments and the associated NERA report, NERA 

analyzed the cost-effectiveness on an industry-wide basis (whereas UWAG assessed costeffectiveness on a model plant basis) for treatment technologies proposed in various options for 

bottom ash transport water, fly ash transport water, and FGD wastewater. NERA calculated 

incremental cost-effectiveness, that is, the additional costs per TWPE to go from one level of 

stringency to the next higher level. NERA compared these estimates to EPA’s estimates of costeffectiveness and to the levels of cost-effectiveness that EPA has found acceptable in 

rulemakings for other industries.

For all the proposed steam electric technologies, NERA calculated that the cost per TWPE would 

be far higher than the mean ($47/TWPE) and median ($15/TWPE) from past rulemakings. In 

every case but one, the cost per TWPE for the steam electric proposed technologies would be 

higher than the highest amount ($404 for Electrical and Electronic Components) that EPA has 

ever found acceptable. The one option with a cost-effectiveness less than that highest-ever 

amount is chemical precipitation for FGD wastewater, which is still a very high $311 per TWPE 

in 1981 dollars. Thus, as UWAG’s other analyses show, dry handling of fly ash and bottom ash 

cannot be justified on a cost-effectiveness basis. Furthermore, biological treatment and zero 

liquid discharge cannot be justified as a cost- effective BAT for FGD wastewater.

Comment Response: 

EPA notes that the commenter refers to incremental cost-effectiveness but then compares that to 

the cost-effective ratios for other ELGs. EPA disagrees that it has sent a cost-effective ratio 

benchmark above which the costs of removing one toxic-weighted pound-equivalent of 

pollutants would not be “acceptable.” Rather, consistent with other ELGs, for the steam electric 

rule, EPA presents the range of cost effectiveness of ELGs for other industries. 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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

Also see response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 14 regarding 

wastestream specific cost-effectiveness.

For a description of the technologies that EPA selected as the basis for the final rule, and why, 

see preamble Section VIII.
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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: 118

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Almost all of EPA’s preferred and certain non-preferred options for FGD wastewater, bottom ash 

transport water, and fly ash transport water, and all of EPA’s non-preferred options that differ 

from its preferred options for combustion residual leachate, are not cost effective. EPA should 

not adopt new ELG requirements for bottom ash transport water, should not require dry handling 

for fly ash transport water, and should not require biological treatment of FGD wastewater.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4487-A1, Excerpt Number 22.

For a description of the technologies that EPA selected as the basis for the final rule, and why, 

see preamble Section VIII.

Commenter Name: Dean Ellis

Commenter Affiliation: Dynegy Inc.

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

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA is required to consider the cost of compliance (see Clean Water Act § 304(b)(2)(B)) and has 

a longstanding practice of considering cost-effectiveness in establishing effluent limitations 

guidelines. As UWAG demonstrates, some of EPA’s proposals cannot be justified as costeffective in terms of toxic-weighted pound-equivalents (TWPEs) of pollutants removed. Most 

importantly, Dynegy does not believe that EPA has justified any it of its proposed regulatory 

options that would prohibit the discharge of bottom ash transport waters or prohibit the discharge 

of fly ash transport waters.

Comment Response: 
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EPA considered the cost of compliance in developing the final rule. See preamble Section IX, as 

well as the TDD and RIA.

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that the Option D technologies represent Best Available Technology 

Economically Achievable because these technologies are available and economically achievable 

(i.e., affordable) for the industry as a whole, and have acceptable non-water quality 

environmental impacts as required by the Clean Water Act (see preamble Section VIII).

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions 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: 36

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

As explained in UWAG’s comments on the Proposed ELG Rule, the rulemaking record shows 

that EPA has overstated the impact of electric power plants by a series of questionable 

assumptions and practices that overstate the amount of pollutants and their impact on the 

environment.

Comment Response: 
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In response to public comments, EPA revised its estimates of pollutant loadings and reductions 

for the final rule, as well as its environmental assessment analyses. EPA disagrees with the 

commenter that the final rule overstates the amount of pollutants discharged by steam electric 

power plants and their impact on the environment. See chapter 10 of the TDD and the EA for 

the final rule.

This comment is very general in nature. See other comment codes for responses to specific 

comments related to loadings and the EA.

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 149, regarding the 

requirement in the Clean Water Act to “identify . . . the degree of effluent reduction attainable.”

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: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NIPSCO prefaces these comments by noting that our review of the proposed ELG has largely 

focused on the four USEPA preferred options (3, 3a, 3b, and 4a) identified in the preamble to the 

proposed rule and designated in the Technical Development Document (TDD) as being, in 

USEPA’s opinion, economically achievable. However, NIPSCO emphasizes that we concur 

with USEPA’s assessment that Option 5 (one of the non-preferred rule options) “zero liquid 

discharge” requirement for Flue Gas Desulfurization (FGD) Wastewater is not economically 

achievable. NIPSCO offers no comments to the remaining non-preferred options (1, 2, and 4), 

because they do not reflect any new or modified treatment technologies beyond those 

represented by the preferred options.

Comment Response: 

EPA’s proposed Option 5 (substantially similar to Option F for the final rule) is not based on a 

“zero liquid discharge” requirement for FGD wastewater, but rather is based on evaporation 

technology, with numeric limitations for arsenic, selenium, mercury, and total dissolved solids. 

Regardless, for the final rule, EPA did not select evaporation as the BAT basis for control of 

FGD wastewater discharges from all existing steam electric power generating units,, for the 

reasons explained in preamble section VIII.C.1.

Although EPA did not select evaporation as the BAT basis for control of FGD wastewater 

discharges from all existing steam electric power generating units, as part of BAT for existing 

sources, the final rule also establishes a voluntary incentives program for plants that adopt 

process changes and controls that achieve limitations based on evaporation for FGD wastewater 
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discharges. See Section VIII.C.13 of the final preamble. Also, the new source standards (NSPS 

and PSNS) in the final rule are based on the Option F technologies (which includes zero 

discharge standards for control of discharges of fly ash transport water, bottom ash transport 

water, and FGMC wastewater, as well as standards based on evaporation for control of FGD 

wastewater discharges).

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

NRECA urges EPA to:

Reconsider the cost effectiveness of this rule, and to revise the final rule to promulgate standards 

based on $/TWPE comparable to those promulgated for other sectors.

Comment Response: 

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

NRECA urges EPA to reconsider the cost effectiveness of this rule, and to revise the final 

rule to promulgate standards based on $/TWPE comparable to those promulgated for 

other sectors. NRECA is concerned that EPA’s proposal is not cost-effective and that the 

incremental costs will weigh disproportionally on smaller entities.

NRECA has worked closely with our utility sector partners in the Utility Water Act Group 

(UWAG) and Utility Solid Waste Activities Group (USWAG) and endorses the extensive 

comments submitted by these organizations. Both organizations identified significant and 

compounding errors in EPA’s regulatory impact analysis that led the Agency to 

drastically inflate the benefits of the proposal and underestimate the costs.

UWAG developed a detailed critique of the errors in EPA’s cost effectiveness analysis which 

demonstrates that the cost-effectiveness of the proposal as measured in dollars per toxicweighted pound-equivalents2 ($/TWPE), are orders of magnitude higher than previous 

effluent guidelines (see Figure 1. Histogram of Cost-Effectiveness Values for Previous EPA 

BAT Regulations)

Figure 1: Histogram of Cost-Effectiveness Values for Previous EPA BAT Regulations 3

Note: Analysis excludes regulations with “BAT = BPT”.

Source: NERA analysis of EPA Regulatory Impact Analysis (EPA 2013b), Table D-5 (pp. D-7 to 

D-8)

2 EPA establishes toxic weighting factors (TWF) for each pollutant and the TWPE is the pounds 

of a pollutant in a wastewater multiplied by the TWF.
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3 UWAG comments, attachment c, Cost-Effectiveness Analysis of EPA’s Proposed Effluent 

Limitations Guidelines and Standards for Steam electric Power Plants, NERA Economic 

Consulting, September 2013.

Comment Response: 

See response to DCN-EPA-HQ-OW-2009-0819-4477-A1 , Excerpt Number 12.

EPA notes that the final rule establishes differentiated requirements for generating units that are 

less than or equal 50 MW. See Section VIII.C.12 of the final preamble. These differentiated 

requirements are expected to alleviate any impacts to small entities. See preamble Section 

XVII.C and RIA Section 8.

Commenter Name: Floyd Gilzow

Commenter Affiliation: Missouri Joint Municipal Electric Utility Commission (MJMEUC)

Document Control Number: EPA-HQ-OW-2009-0819-4576-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Finally, it is not clear that EPA has followed conventional Clean Water Act cost‐benefit analysis 

in its Best Available Technology (BAT) determinations in many of the eight options offered. We 

urge the EPA to review their analysis of pollutants and about the capital costs and impacts from 

some of these proposed technologies. If BAT is reviewed in light of the exaggerated pollutants 

discharged that the EPA would select Option 1.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA disagrees that proposed Option 1 represents BAT. EPA determined that the Option D 

technologies represent Best Available Technology Economically Achievable because these 

technologies are available and economically achievable (i.e., affordable) for the industry as a 

whole, and have acceptable non-water quality environmental impacts as required by the Clean 

Water Act (see preamble Section VIII).

EPA disagrees with the commenter’s statement that the Clean Water Act contains a “convention” 

of cost‐benefit analysis for BAT. For the role of cost-benefit analysis in establishing BAT, see 

response to DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 in comment code 6a.
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EPA notes that it revised pollutant loadings/reductions, costs, and cost-effectiveness for the final 

rule, based on public comments. See preamble section X and TDD Section 10 regarding 

pollutant loadings/reductions associated with the final rule, see preamble sections V.D and IX 

(and TDD Section 9) regarding compliance costs associated with the final rule, and see preamble 

section XV (and the RIA) for information on the cost-effectiveness of the final rule.

Commenter Name: Floyd Gilzow

Commenter Affiliation: Missouri Joint Municipal Electric Utility Commission (MJMEUC)

Document Control Number: EPA-HQ-OW-2009-0819-4576-A1

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

3. One primary comment, based on the present rulemaking record, is that EPA has not been able 

to justify, on a cost‐effectiveness basis, any wastewater treatment technology beyond what is 

already required by the 1982 steam electric guidelines. It appears, from calculations performed 

by the Utility Water Act Group, the Electric Power Research Institute, and others that the cost of, 

for example, dry handling of bottom ash would be considerably more costly than technologies 

EPA has required of other industries in past rulemakings.

We believe that this oversight is substantial enough that the rulemaking should be withdrawn, 

reviewed, and resubmitted with new costs or the rule should be restructured

Comment Response: 

EPA disagrees with the commenter that this rule “should be withdrawn, reviewed, and 

resubmitted with new costs or the rule should be restructured.”

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that the Option D technologies represent Best Available Technology 

Economically Achievable because these technologies are available and economically achievable 

(i.e., affordable) for the industry as a whole, and have acceptable non-water quality 

environmental impacts as required by the Clean Water At (see preamble Section VIII).

EPA revised pollutant loadings/reductions, costs, and cost-effectiveness for the final rule, based 

on public comments. See preamble section X and TDD Section 10 regarding pollutant 

loadings/reductions associated with the final rule, see preamble sections V.D and IX (and TDD 
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Section 9) regarding compliance costs associated with the final rule, and see preamble section 

XV (and the RIA) for information on the cost-effectiveness of the final rule.

EPA determined the final rule is cost-effective. Although not required by the CWA, and not a 

determining factor for establishing BAT/PSES or BADCT/PSNS, cost-effectiveness analysis can 

be a useful tool for describing regulatory options that address toxic pollutants. As presented in 

preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the 

selected regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This 

cost-effectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements 

in other industries. The final PSES requirements for the selected regulatory option have a cost 

effectiveness of $1,228/lb-eq ($1981). This ratio is higher than the cost-effectiveness of PSES 

requirements in other industries. As explained in the preamble, the CE may be lower than 

estimated. Moreover, it is critical to establish PSES at the same level as BAT in this rule to avoid 

creating an unintended incentive for plants to start sending their wastewater to POTWs in an 

attempt to avoid the requirements of 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: H. Morriss Barney IV

Commenter Affiliation: Texas Municipal Power Agency (TMPA)

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

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Our primary comment, based on the present rulemaking record, is that EPA has not been able to 

justify, on a cost-effectiveness basis, any wastewater treatment technology beyond what is 

already required by the 1982 steam electric guidelines. It appears, from calculations performed 

by the Utility Water Act Group, the Electric Power Research Institute, and others that the cost of, 

for example, dry handling of bottom ash would be considerably more than technologies EPA has 

required of other industries in past rulemakings. The burden of the higher cost will be even 

greater on community-owned electric utilities like ours.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4576-A1, Excerpt Number 9.

Regarding the burden on community-owned electric utilities, EPA conducted analyses to look at 

the impacts of the regulatory requirements on various types of entities, including small entities 

and government entities who own or operate community-owned electric utilities. These analyses, 

which are described in Chapter 9 of the RIA document show that the final rule would not 

significantly or uniquely affect small governments. EPA also looked at the impacts on 
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households based on other comments which suggested that community-owned utilities and 

cooperatives may be more likely to pass through costs to their consumers. For example, see 

response to comments EPA-HQ-OW-2009-0819-4565-A1, Excerpt Number 19 (in comment 

code 29.e) and EPA-HQ-OW-2009-0819-4460-A1, Excerpt Number 1 (in comment code 28.f).

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 22

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In the end, several of EPA’s proposed options are reasonable for an industry that is already 

regulated extensively. The “cost-effectiveness” analyses, especially as corrected by UWAG’s 

own work, show that for most wastestreams little additional regulation can be justified as costeffective. EPA’s description of the steam electric industry as contributing 50 to 60% of toxicweighted pollutant loadings has little relevance to the basic facts of technology cost and 

effectiveness. And, in any event, that description should be revised because EPA has 

overestimated pollutant loadings and overstated the environmental impacts of those loadings.

IV. EPA’s Cost-Effectiveness Analyses Do Not Support Zero Discharge for Bottom Ash or 

Fly Ash Transport Water or Chemical Precipitation for FGD Wastewater at Plants with 

under 200 gpm Design Flow

As is standard practice, EPA has calculated the “cost-effectiveness” of the proposed BAT 

requirements in terms of dollars per toxic-weighted pound-equivalents (TWPEs) of pollutants 

removed:

EPA often uses cost-effectiveness analysis in the development/revision of effluent limitations 

guidelines and standards to evaluate the relative efficiency of alternative regulatory options in 

removing toxic pollutants from the effluent discharges to the nation’s waters. Although not 

required by the Clean Water Act, cost-effectiveness analysis is a useful tool for evaluating 

regulatory options that address toxic pollutants.

78 Fed. Reg. at 34,503 col. 2.

Whether or not EPA is “required” to consider cost-effectiveness, it is clearly required to take 

account of “cost.” See Clean Water Act § 304(b)(2)(B). And EPA has a longstanding practice 

of considering cost-effectiveness. As we show below, some of EPA’s proposals cannot be 

justified as cost-effective.

Comment Response: 
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The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that the Option D technologies represent Best Available Technology 

Economically Achievable because these technologies are available and economically achievable 

(i.e., affordable) for the industry as a whole, and have acceptable non-water quality 

environmental impacts as required by the statute (see preamble Section VIII). As required by 

Section 304(b)(2)(B) of the Clean Water Act, EPA also took into account the “cost of achieving 

such effluent reduction . . . .” See preamble section IX and TDD Section 10.

In response to comments, EPA revised its pollutant loadings and reduction estimates for the final 

rule, including its estimate of the contribution steam electric power plants have on combined 

discharges from all industrial categories. In addition, based on public comments, EPA revised its 

compliance cost estimates, as well as its resulting cost-effectiveness for the final rule. See 

preamble section X and TDD Section 10 regarding pollutant loadings/reductions associated with 

the final rule, see preamble sections V.D and IX (and TDD Section 9) regarding compliance 

costs associated with the final rule, and see preamble section XV (and the RIA) for information 

on the cost-effectiveness of the final rule.

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. The final PSES requirements

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of the final rule. For 

the role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPAHQ-OW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.

In response to comments, EPA revised its environmental assessment analyses. EPA disagrees 

with the commenter that the final rule overstates the amount of pollutants discharged by steam 

electric power plants and their impact on the environment. See the TDD and EA 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: 24
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

D. EPA’s Estimates of Dollars per TWPE Are Too Low

Because of various inappropriate methods, assumptions, and choices of data, EPA’s calculations 

of $/TWPE for the steam electric industry are underestimated. For individual wastestreams, 

EPA finds costs of only $27 to $107:

The cost-effectiveness for zero discharge of fly ash transport and FGMC wastewater, as in 

Option 3a, is $27 per TWPE removed. The cost effectiveness of chemical precipitation alone is 

$70 per TWPE removed, while the cost effectiveness of chemical precipitation plus anaerobic 

biological treatment, which is included in all options except Option 3a, is $60 per TWPE 

removed. The cost effectiveness of zero discharge of bottom ash transport water for all units 

more than 50 MW is $107 per TWPE. In comparison, when this requirement is applied only to 

units more than 400 MW, as in Option 4a, the cost effectiveness value is $99 per TWPE 

removed.

EPA, “Technical Development Document for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category,” EPA-821-R-13-002 

(April 2013), EPA-HQ-OW-2009-0819-2257 (2013 TDD) at 8-34; see also 78 Fed Reg. at 

34,474 col. 1 and 34,504 (Table XII-1).

Correctly calculated, the costs per TWPE are much higher,

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 22 and response to DCN 

EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 27

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

A. By Longstanding Precedent, No BAT Requirement Should Cost More than $404 (in 

1981 Dollars) per TWPE
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EPA cites the highest cost per TWPE as $404 in 1981 dollars:

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/lbeq (Electrical and Electronic Components), in 1981 dollars.

78 Fed. Reg. at 34,504 col. 1-2. Typically the cost has been less than $200. 68 Fed. Reg. 

25,686, 25,701 col. 3 (May 13, 2003).

In several past ELG rulemakings, EPA published a table of cost-effectiveness estimates by 

industry category. In four cost-effectiveness analyses, dated 1996-2000, the highest cost per 

equivalent pound (that is, pound of pollutant adjusted for toxicity) was listed as $404 in 1981 

dollars2.

In the rulemaking for Metal Products and Machinery (MP&M), EPA determined that a 

technology was not BAT when it had a cost of $1000/PE because this was “substantially greater” 

than what EPA had typically imposed for BAT technology in other industries, generally less than 

$200/PE. 68 Fed. Reg. at 25,701 col. 3; see also id. at 25,702 col. 2. In the same rulemaking, 

EPA said that $455/PE was “very expensive per pound removed.” EPA’s “Development 

Document for the Final Effluent Limitations Guidelines and Standards for the Metal Products 

and Machinery Industry,” EPA-821-B-03-001 (Feb. 2003) (MP&M Development Document) at 

9-21 to -22. A cost of $420/PE was “quite expensive.” Id. at 9-13.

Thus far, then, UWAG agrees with EPA: cost-effectiveness analysis is (at least) a “useful tool,” 

and in other rulemakings EPA has typically imposed costs of less than $200/TWPE and no more 

than $404 (in 1981 dollars). Indeed, as the attached NERA report observes, the mean is 

$47/TWPE, and the median is $15/TWPE. UWAG has several recommendations, however, as to 

how the cost-effectiveness analysis should be conducted, as explained below.

2 See “Cost Effectiveness Analysis of Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas 

Extraction Point Source Category,” 821-R-96-021 (October 1996), Table 5-1 at 5-2 to 5-3, 

http://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=200035QV.txt; “Economic Analysis and Cost-Effectiveness Analysis of Proposed Effluent 

Limitations Guidelines and Standards for Industrial Waste Combustors” [for proposed rule], EPA-821-B-97-010 (January 1998) at C-E 4-2 and 

4-3, http://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=20002HH8.txt; EPA Office of Water, “Cost-Effectiveness Analysis of Proposed Effluent 

Limitations Guidelines and Standards for the Metal Products and Machinery Industry” (EPA-821-B-00-007 December 2000), page 10 (page 13 of 

the electronic version), [for proposed rule], 

http://water.epa.gov/scitech/wastetech/guide/mpm/upload/2001_01_10_guide_mpm_proposal_mpm_ce.pdf; EPA, “Cost-Effectiveness Analysis 

of Effluent Limitation Guidelines and Standards for the Centralized Waster Treatment Industry” (undated but listed in support of final rule of 

December 2000) at 4-3, http://water.epa.gov/scitech/wastetech/guide/treatment/upload/2006_12_28_guide_cwt_final_effective.pdf; see also

“Cost-Effectiveness Analysis of Effluent Limitations and Standards for the Nonferrous Metals Forming and Metal Powders Industry,” 

PB93158970 (August 1985) at 3-15 Table 3.7.

Comment Response: 
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EPA explained the bases for the options it selected in the preamble to the final rule. In particular, 

sections 301(b) and 304(b) of the Clean Water Act specify that Best Available Technology 

Economically Achievable (“BAT”) represents effluent limitations that are technologically 

available and economically achievable after a consideration of the following factors: 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 impacts (including energy requirements), 

and such other factors the Administrator deems appropriate.

Several commenters stated that EPA’s final rule should be “cost-effective” or that EPA should 

choose only “cost-effective” options. EPA interprets these statements about cost-effectiveness as 

using the term in the casual sense, similar to the notion of “bang for your buck.” These 

commenters, however, do not identify what they view as constituting “cost-effective.” Thus, 

considering “cost-effectiveness” in this general respect is not especially useful. Nonetheless, 

EPA notes that, in some cases, for the final rule, EPA did reject certain technology options for 

controlling specific wastestreams because there was another technology option that better 

controlled that wastestream and at a lower cost. See discussion of chemical precipitation for 

control of ash transport water in the TDD. 

Other commenters stated that EPA should have selected different options for the final rule based 

on EPA’s or their own “cost-effectiveness” analysis of those options. EPA interprets these 

statements about cost-effectiveness to refer to the kind of cost-effectiveness analysis that EPA 

traditionally performs for ELGs. In its effluent guidelines rulemakings, EPA uses the term “cost 

effectiveness” as a measure of the cost5per pound of pollutant discharge reduction (for BAT, 

these pollutant discharge reductions are normalized to account for the different toxicity among 

pollutants6). Indeed, this commenter uses the term cost-effectiveness to mean a measure of cost 

per pound of toxic-weighted pound of pollutant discharge reduction. This commenter further

states that “No BAT Requirement Should Cost More than $404 (in 1981 Dollars) per 

TWPE.” While EPA often calculates and presents cost-effectiveness values when conducting 

ELG rulemakings (see section XV of the preamble), it generally does not use cost-effectiveness 

as a decision criterion in establishing BAT, and it did not use the results of its “costeffectiveness” analysis as the basis for its decisions on the steam electric ELGs. EPA’s decision 

is consistent with the statute in a number of ways.

 

5

 Here, the costs are the estimated annualized incremental pre-tax costs to comply with alternative regulatory options, stated in 

1981 constant dollars. The annual costs include the annualized capital outlays for equipment and recurring expenses for operating 

and maintaining compliance equipment and meeting monitoring requirements.

6

 EPA adjusts the estimated reductions in discharges, or pollutant discharge reductions, associated with a regulatory option by

multiplying the estimated reduction quantity for each pollutant by a normalizing toxic weight (toxic-weighting factor, or “TWF”). 

The use of TWFs allows the reductions of different pollutants to be expressed on a constant toxicity basis. In the case of indirect 

dischargers, the reduction also accounts for the effectiveness of treatment at Publicly Operated Treatment Works (“POTWs”). 

See the Regulatory Impact Assessment for more details about how EPA accounts for differences in toxicity of pollutants of 

concern through the use of TWFs.
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The 1972 amendments to the modern Clean Water Act adopted a technology-forcing approach to 

pollutant reductions, meaning it is intended to reflect what technology can achieve.7 Congress 

adopted this approach in response to the failure of the prior approach under the Federal Water 

Pollution Control Act, in which regulation was predicated on having to demonstrate the 

environmental effects of control on receiving waters:

“The earliest version of the federal Water Pollution Control Act was passed in 1948 and 

amended five times before 1972. Throughout that 24 year period, Congress attempted to use 

receiving water quality as a basis for setting pollution control standards. At the end of that 

period, Congress realized not only that its water pollution control efforts until then had failed, 

but also that reliance on receiving water capacity as a crucial test for permissible pollution levels 

had contributed greatly to that failure.

Based on this experience, Congress adopted a new approach in 1972. Under the Act, ‘a 

discharger’s performance is . . . measured against strict technology-based effluent limitations 

specified levels of treatment to which it must conform, rather than against limitations derived 

from water quality standards to which it and other polluters must collectively conform.’

This new approach reflected developing views on practicality and rights. Congress concluded 

that water pollution seriously harmed the environment, and that although the cost of control 

would be heavy, the nation would benefit from controlling the pollution. Yet the scientific 

uncertainties made it difficult to assess the benefits to particular bodies of receiving water. Even 

if the federal government eventually could succeed at the task at which [it] had failed for 24 

years and thus could determine benefits and devise water quality standards, Congress concluded 

that the requisite further delay was too long for the nation to wait.”8

Thus, under the technology-based approach, section 301(b) of the Act authorizes the 

Administrator to set effluent limitations for categories of point sources in two increasingly 

stringent steps. 9 The first step, which applies to all pollutants, requires point sources to meet 

 

7 Technology-based provisions differ from other major types of environmental statutory provisions that are health or water 

quality-based or based on cost-benefit. For example, health-based provisions are based solely on what is necessary to protect 

against a particular risk. Cf. Whitman v. Am. Trucking Ass’n, 531 U.S. 457, 465 (2001) (“Section 109(b)(1) [of the Clean Air Act] 

instructs the EPA to set primary ambient air quality standards ‘the attainment and maintenance of which . . . are requisite to 

protect the public health’ with ‘an adequate margin of safety.’ . . . The EPA, ‘based on’ the information about health effects 

contained in the technical ‘criteria’ documents compiled under section 108(a)(2), is to identify the maximum airborne 

concentration of a pollutant that the public health can tolerate, decrease the concentration to provide an ‘adequate’ margin of 

safety, and set the standard at that level. Nowhere are the costs of achieving such a standard made part of that calculation.”) 

(citations omitted). Cost-benefit provisions direct the Agency to weigh the costs and benefits of regulation. For example, the 

Federal Insecticide, Fungicide, and Rodenticide Act requires all pesticide products sold or distributed in the United States to be 

registered with EPA, and EPA is directed to approve the registration if the pesticide will perform its intended function without 

“unreasonable adverse effects.” 7 U.S.C. § 136a(a). “Unreasonable adverse effects” includes “any unreasonable risk to man or 

the environment, taking into account the economic, social, and environmental costs and benefits of the use of any pesticide.” Id. § 

136(bb). The Toxics Substances Control Act is another cost-benefit statute, authorizing regulation of a chemical substance or 

mixture where it will present an unreasonable risk of injury or health or the environment. See 15 U.S.C. § 2605; Corrosion Proof 

Fittings v. EPA, 947 F.2d 1201, 1217 (5th Cir. 1991).

8 Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1042 (D.C. Cir. 1978) (citations and footnote omitted).

9 EPA v. Nat’l Crushed Stone Ass’n, 449 U.S. 64, 68 (1980); BP Exploration & Oil, Inc. v. EPA, 66 F.3d 784, 789-90 (6th Cir. 

1996).
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limitations based on application of the “best practicable control technology currently available,” 

or “BPT,” by 1977. Section 304(b)(1)(B) of the Act states:

“Factors relating to the assessment of [BPT] . . . shall include consideration of the total cost of 

application of technology in relation to the effluent reduction benefits to be achieved from 

such application, and shall also take into account the age of equipment and facilities involved, 

the process employed, the engineering aspects of the application of various types of control 

techniques, process changes, non-water quality environmental impact (including energy 

requirements), and such other factors as the Administrator deems appropriate” (emphasis added).

In general, BPT is to reflect the average of the best existing performances by industrial plants.10

Recognizing the technology-forcing aspect of the Clean Water Act and the difficulties of the 

prior water-quality based approach to controlling water pollution, the Supreme Court has 

interpreted the BPT cost-benefit factor as a “limited” cost-benefit balancing test, meaning that 

EPA is to limit the application of technology only where the costs are wholly disproportionate to 

the effluent reductions achieved.11

The second step of technology-based effluent limitations requires point sources to meet 

limitations based on application of the “best conventional technology,” or “BCT,” for 

conventional pollutants,12 and the “best available technology economically achievable,” or 

“BAT,” for toxic and non-conventional pollutants. In describing BAT, which was originally to 

be achieved by 1983, but which Congress later extended to 1989, section 301(b)(2)(A) of the Act 

states:

“In order to carry out the objectives of this Act there shall be achieved – . . . Effluent limitations 

which (i) shall require application of the best available technology economically achievable for 

such category or class, which shall result in reasonable further progress toward the national goal 

of eliminating the discharge of all pollutants . . . , which such effluent limitations shall require 

 

10 BP Exploration & Oil, Inc., 66 F.3d at 789; Kennecott Copper Corp. v. EPA, 612 F.2d 1232, 1238 (10th Cir. 1979); 

Weyerhaeuser Co., 590 F.2d at 1060; Am. Petroleum Inst. v. EPA, 540 F.2d 1023, 1034 (10th Cir. 1976); Am. Frozen Food Inst. 

v. Train, 539 F.2d 107, 117 (D.C. Cir. 1976); Am. Meat Inst. v. EPA, 526 F.2d 442, 462 (7th Cir. 1975); Tanners’ Council of Am., 

Inc. v. Train, 540 F.2d 1188, 1191 (4th Cir. 1976).

11 Nat’l Crushed Stone Ass’n, 449 U.S. at 71 n.10 (“Senator Muskie, the principal Senate sponsor of the Act, described the 

‘limited cost-benefit analysis’ employed in setting BPT standards as being intended to ‘limit the application of technology only 

where the additional degree of effluent reduction is wholly out of proportion to the costs of achieving such marginal level of 

reduction. . . .”) (citation omitted); E.I. du Pont de Nemours & Co. v. Train, 430 U.S. 112, 129-30 (1977) (quoting same 

statement by Senator Muskie as in Nat’l Crushed Stone Ass’n, as well as statement that the language in section 304(b) of the Act 

is intended “‘to avoid imposing on the Administrator any requirement to . . . ascertain water quality impact of effluent 

controls.’”) (citation omitted).

12 In describing BCT, CWA section 304(b)(4)(B) specifies the same factors as for BPT, except with respect to the way that costs 

and benefits are to be considered:

“Factors relating to the assessment of [BCT] shall include consideration of the reasonableness of the relationship between the

costs of attaining a reduction in effluents and the effluent reduction benefits derived, and the comparison of the cost and level 

of reduction of such pollutants from the discharge from publicly owned treatment works to the cost and level of reduction of 

such pollutants from a class or category of industrial sources, and shall take into account . . . such other factors the 

Administrator deems appropriate” (emphasis added).

EPA established a two-part cost test for BCT. 51 Fed. Reg. 24,974 (July 9, 1986). The final steam electric ELGs do not establish 

BCT limitations.
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elimination of discharges of all pollutants if the Administrator finds . . . that such elimination is 

technologically and economically achievable.”

The Supreme Court has said that the focus of BAT on “elimination” of discharges (section 

301(b)(2)(A) mentions “eliminating” or “elimination” three separate times over the course of one 

sentence) indicates Congressional intent to “mandate the greatest feasible reduction in water 

pollution,” which can be contrasted, for example, with the “less ambitious” goal in section 

316(b) of “minimizing adverse impact.”13 Section 304(b)(2)(B) of the Act specifies factors for 

BAT that are the same as those for BPT, except with regard to costs versus effluent reduction 

benefits:

“Factors relating to the assessment of [BAT] shall take into account 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, nonwater quality environmental impact (including energy requirements), and such other factors the 

Administrator deems appropriate” (emphasis added).

BAT is to reflect the performance of “the single best performing plant,” and it can rely on pilot 

projects, foreign plants, or technology transfer.14 Senator Muskie, the principal Senate sponsor of 

the Act, explained the distinction between BPT and BAT this way:

“The distinction between ‘best practicable’ and ‘best available’ is intended to reflect the need to 

press toward increasingly higher levels of control in six-year stages. Through the research and 

development of new processes, modifications, replacement of obsolete plans and processes, and 

other improvements in technology, it is anticipated that it should be possible, taking into account 

the cost of controls, to achieve by 1983 levels of control which approach and achieve the 

elimination of the discharge of pollutants.

As to the cost of ‘best available’ technology, the Conferees agreed upon the language of the 

Senate bill in section 304(b)(2). While cost should be a factor in the Administrator’s judgment, 

no balancing test will be required. The Administrator will be bound by a test of reasonableness. 

In this case, the reasonableness of what is ‘economically achievable’ should reflect an evaluation 

 

13 Entergy Corp. v. Riverkeeper, 556 U.S. 208, 219 (2009).

14 Chem. 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 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.”) (internal quotations and citations omitted); 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.”) (citation omitted); Am. Frozen Food Inst., 539 F.2d at 140 (upholding EPA’s use of data from two 

foreign plants); Weyerhaeuser Co., 590 F.2d at 1054 n.70 (upholding EPA’s use of data from pilot plants); Reynolds Metals Co. 

v. EPA, 760 F.2d 549, 562 (4th Cir. 1985) (upholding EPA’s use of data from technology employed in another industry); Cal. & 

Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 287 (2d Cir. 1977) (same).
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of what needs to be done to move toward the elimination of the discharge of pollutants and what 

is achievable through application of available technology – without regard to cost.”15

EPA’s decision not to use the results of its cost-effectiveness analysis to establish BAT for the 

final steam electric ELGs is consistent with the statutory text, structure, and history of the Clean 

Water Act, and it achieves the goals of the Act. As is clear from the text of the statute, the Act 

does not direct BAT to reflect a consideration of a weighing of costs in relation to pounds of 

pollutant discharge reductions, but rather simply requires BAT to reflect what is technologically 

and economically achievable after a consideration of, among other things, “the cost of achieving 

such effluent reduction.” Thus, for BAT, instead of comparing costs to pounds of pollutant 

discharge reductions, EPA typically estimates the costs of compliance and determines whether 

they are affordable to the industry as a whole, or whether the costs can be “reasonably borne” by 

the industry.16 EPA has generally looked at the affordability of the costs on the industry as a 

whole (or for a subcategory of the industry, as appropriate) by analyzing the effect of the 

regulation on plant closures and, to a more limited degree, firm failures.17 In a few past instances, 

EPA has also considered total industry costs, rather than impacts on plant closures or firms, in 

establishing BAT.18 Once EPA has identified technologically available and economically 

achievable options, some courts have stated that the Agency is allowed to consider whether 

increasingly more stringent requirements would impose significant costs while achieving only de 

minimis incremental pollutant reductions.19 EPA also considers non-water quality environmental

impacts and has on previous occasion based a decision not to select a technology option due to 

such impacts.20

Moreover, the Act’s structure and history clearly contemplate a two-step, phased-in approach to 

technology-based effluent limitations, where the first step represents what is “practicable,” and 

the second step is directed toward the complete elimination of discharges if such elimination is 

“technologically and economically achievable.” Thus, EPA views cost-effectiveness as more 

 

15 Congressional Research Service, a Legislative History of the Water Pollution Control Act Amendments of 1972, at 170 

(Comm. Print 1973).

16 Chem. Mfrs. Ass’n, 870 F.2d at 262; BP Exploration & Oil, 66 F.3d at 799-800. See also Nat’l Wildlife Fed’n v. EPA, 286 

F.3d 554, 570 (D.C. Cir. 2002); CPC Int’l Inc. v. Train, 540 F.2d 1329, 1341-42 (8th Cir. 1976), cert. denied, 430 U.S. 966 

(1977).

17 See Nat’l Wildlife Fed’n, 286 F.3d at 562-65; Nat’l Ass’n of Metal Finishers v. EPA, 719 F.2d 660, 666 (3d Cir. 1983); Am. 

Iron & Steel Inst., 526 F.2d at 1054; Ass’n of Pac. Fisheries, 615 F.2d at 808.

18 See 48 Fed. Reg. 32462, 32468 (July 15, 1983) (Final Rule establishing ELGs for the Electroplating and Metal Finishing Point 

Source Categories); 74 Fed. Reg. 62996, 63026 (Dec. 1, 2009) (Final Rule establishing ELGs for the Construction and 

Development Point Source Category); BP Exploration & Oil, Inc., 66 F.3d at 796-97.

19 Ass’n of Pac. Fisheries, 615 F.2d at 818 (“So long as the required technology reduces the discharge of pollutants, our inquiry 

will be limited to whether the Agency considered the cost of the technology, along with the other statutory factors, and whether 

its conclusion is reasonable. Of course, at some point extremely costly more refined treatment will have a de minimis effect on 

the receiving waters.”); Am. Petroleum Inst. v. EPA, 787 F.2d 965, 972 (5th Cir. 1986) (“EPA would disserve its mandate were it 

to tilt at windmills by imposing BAT limitations which removed de minimis amounts of pollutant agents from our nation’s 

waters, while imposing possibly disabling costs upon the regulated industry.”); Am. Petroleum Inst. v. EPA, 858 F.2d 261, 265-66 

(5th Cir. 1988), amended by 864 F.2d 1156, 1156-57 (5th Cir. 1989) (“BAT limitations properly may require industry, regardless 

of a discharge’s effect on water quality, to employ defined levels of technology to meet effluent limitations; a direct cost/benefit 

correlation is not required, so even minimal environmental impact can be regulated, so long as the prescribed alternative is 

‘technologically and economically achievable.’ We are mindful, however, that this approach has its limits, as explained by Judge 

(now Justice) Kennedy in Ass’n of Pac. Fisheries.”) (citations omitted).

20 See Effluent Limitations Guidelines, Pretreatment Standards, and New Source Performance Standards for the Commercial 

Hazardous Waste Combustor Subcategory of the Waste Combustors Point Source Category; Final Rule, 65 Fed. Reg. 4360, 4368 

(Jan. 27, 2000); BP Exploration & Oil, Inc., 66 F.3d at 796-97.
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closely relevant to establishing the first step of technology-based limitations, BPT. Indeed, 

unlike section 304(b)(2)(B), section 304(b)(1)(B) of the Act expressly directs that BPT reflect a 

consideration of “the total cost of application of technology in relation to the effluent reduction 

benefits to be achieved from such application.” Interpreting that provision, EPA has traditionally 

considered cost per pound of pollutant discharge reduction when establishing BPT. Due to the 

difference in the language used in section 304(b)(1)(B) compared to the language used in section 

304(b)(2)(B), EPA does not view as determinative cost per pound (or toxic-weighted) pound of 

pollutant discharge reduction for establishing controls reflecting BAT.21 This is consistent with 

numerous judicial interpretations.22 EPA’s view is that the Act’s stated goal in section 101 of 

eliminating the discharge of all pollutants,23 as well as its specific goal in section 301 that BAT 

result in the elimination of discharges where technologically and economically achievable,24 are 

achieved if EPA does not base BAT on a weighing of costs against pounds of pollutant discharge 

reductions, but rather focuses most importantly on the Act’s requirement that BAT limitations 

reflect what is technologically available and economically achievable for the industry as a whole 

(while taking into account the express factors in section 304(b)).

EPA’s approach for the final steam electric ELGs is consistent with the approach described 

above. EPA determined that the final rule is based on available and demonstrated treatment 

technologies. EPA analyzed the effect of the final rule on steam electric generating unit and plant 

closures and determined that the rule is affordable to the industry as a whole (see preamble 

Section VIII.C.9). EPA also considered the total industry costs and concluded it would not be 

appropriate to establish BAT limitations based on certain regulatory options due in part to total 

industry cost (see Section VIII of preamble). The final steam electric ELGs do not impose 

 

21 See Keene Corp. v. United States, 508 U.S. 200, 208 (1993) (“Where Congress includes particular language in one section of a 

statute but omits it in another . . . , it is generally presumed that Congress acts intentionally and purposely in the disparate 

inclusion or exclusion.”) (citation and internal quotations omitted); See also Dep’t of Homeland Security v. MacLean, 135 S. Ct. 

913, 919 (2015) (“Congress generally acts intentionally when it uses particular language in one section of a statute but omits it in 

another.”) (citation omitted). The same can be said in contrasting section 304(b)(2)(B)’s silence regarding costs versus benefits 

with the BCT provision, section 304(b)(4)(B), which directs EPA to consider “the reasonableness of the relationship between the 

costs . . . and the effluent reduction benefits derived.”

22 See Nat’l Crushed Stone Ass’n, 449 U.S. at 70-71 (“[I]n assessing BAT[,] total cost is no longer to be considered in 

comparison to effluent reduction benefits.”); Ass’n of Pac. Fisheries v. EPA, 615 F.2d 794, 818 (9th Cir. 1980) (“The 

conspicuous absence of the comparative language contained in section 304(b)(1)(B) leads us to the conclusion that Congress did 

not intend the Agency or this court to engage in marginal cost-benefit comparison.”); Am. Iron & Steel v. EPA, 526 F.2d 1027, 

1051-52, 1053 n.54 (3d Cir. 1975) (“there should be no cost-benefit analysis” for BAT); CPC Int’l, Inc. v. Train, 540 F.3d 1329, 

1341-42 (8th Cir. 1976), cert. denied, 430 U.S. 966 (1977) (BAT is “governed by standard of reasonableness without the 

necessity of a thorough cost-benefit analysis.”) (citations omitted); Reynolds Metals Co. v. EPA, 760 F.2d 549, 565 (4th Cir. 

1985) (“For BPT there must be a ‘limited balancing’ of costs against benefits, but as regards BAT, NSPS, PSES and PSNS no 

balancing is required . . . .”) (citations omitted); Rybachek v. EPA, 904 F.2d 1276, 1290-91 (10th Cir. 1990) (“In determining the 

economic achievability of a technology, the EPA must consider the ‘cost’ of meeting BAT limitations, but need not compare 

such cost with the benefits of effluent reduction.”) (citations omitted); Texas Oil & Gas Ass’n v. EPA, 161 F.3d 923, 936 (5th 

Cir. 1998) (“In applying the BAT standard, the EPA is not obligated to evaluate the reasonableness of the relationship between 

costs and benefits. . . . Indeed, the EPA may prescribe ELGs whose costs are significantly disproportionate to their benefits, just 

as long as the BAT determination remains economically feasible for the industry as a whole.”) (citations omitted); Am. Paper 

Inst. v. Train, 543 F.2d 328, 338, 354 (D.C. Cir. 1976) (“Section 304(b)(2)(B) mandates no such [cost-benefit] balancing for the 

1983 [BAT] limitations, nor does Section 306 require it for the new source performance standards.”); Nat’l Ass’n of Metal 

Finishers v. EPA, 719 F.2d 624, 659 (3d Cir. 1983) (“BPT is designed to eliminate inefficient discharges, i.e., where the benefits 

of pollutant reduction exceed the costs. . . . BAT assumes that inefficient discharges have been eliminated . . . [and] requir[es] the 

remaining dischargers to eliminate ‘efficient’ discharges, [including] where the costs outweigh the benefits of pollutant 

reduction.”).

23 33 U.S.C. § 1251(a)(1).

24 Id. 1311.
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exorbitant costs in exchange for only de minimis pollutant reductions – indeed the annual social 

cost of the final rule is $479.5 million and the estimated reductions attributable to the rule are 1.4 

billion toxic-weighted pounds per year (see preamble Section X), which is a significant figure 

given the Act’s goal of pollutant discharge elimination.25 Finally, EPA concluded that the final 

rule contains acceptable non-water quality impacts (see preamble Section VIII.C.10).

In addition to the fact that EPA’s decision not to use as determinative the results of its costeffectiveness analysis in establishing BAT is consistent with and implements the Act, EPA notes 

several limitations with its cost-effectiveness analysis that make the Agency cautious of its value 

as a decision tool. First, the toxic-weighting factors (“TWFs”) used to calculate toxic-weighted 

pollutant discharge reductions are derived from chronic aquatic life criteria and human health 

criteria (or toxic effect levels) established solely for the consumption of fish, where available. In 

cases where only one of these two criteria is available, TWFs account for only one particular 

type of harm. In this sense, they could be incomplete.

Second, this analysis does not account for all pollutants. Not all pollutants have TWFs, either 

because data are not available to set a TWF or toxicity is not the pollutants’ primary 

environmental impact (e.g., ecological impacts of Se). It ignores some of the greatest remaining 

pollutants impairing the nation’s waters, such as nutrients and conventional pollutants. Nutrient 

pollution is caused by excess nitrogen and phosphorus in the water, which causes algae to grow 

faster than ecosystems can handle. Significant increases in algae harm water quality, food 

resources and habitats, and decrease the oxygen that fish and other aquatic life need to survive. 

Algal blooms can severely reduce or eliminate oxygen in the water, leading to illnesses and death 

in fish. Some algal blooms are harmful to humans because of the toxins and bacteria they 

produce. Nutrient pollution in groundwater – including drinking water – can be harmful even in 

low levels.26

In addition, the TWF measurement is not a measure of impacts on the environment or human 

health because it does not account for the fate and effect of a pollutant. Risk is a function of 

toxicity and exposure. Only detailed exposure assessment data, based on an analysis of the fate 

and transport of pollutant discharge, exposure pathways, and uptake, would provide the 

information necessary to evaluate the extent to which regulatory options reduce environmental 

impacts and enhance human and ecological health. Site-specific conditions in the receiving 

waterbody, such as hydrodynamics and exposed fauna and biota, can result in different 

environmental effects beyond those that may be suggested by comparing pollutant mass only, 

even when adjusted for toxicity. Additionally, the TWF measurement does not address potential 

routes of potential environmental damage and human exposure other than via surface waters. 

 

25 EPA notes that it did make certain decisions on the final steam electric ELGs that have the effect of avoiding the imposition of 

significant incremental costs in exchange for de minimis incremental loadings reductions. For example, EPA ultimately chose 

not to establish more stringent BAT limitations than exist under previously established BPT regulations governing the discharge 

of pollutants in combustion residual leachate from existing sources. This would have increased the cost of the rule by 

approximately $56 million annually, while yielding only an estimated 3 percent reduction in total pollutant loadings from the 

industry.

26 EPA may calculate separate nutrient cost-effectiveness values for options that achieve nutrient reductions. EPA may similarly 

calculate separate cost-reasonableness ratios for the reduction of conventional pollutants (BOD, TSS, fecal coliform, pH, and oil 

and grease).
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Thus, the cost-effectiveness analysis only represents half of what the Agency would need to truly 

assess “bang for the buck.” 

Lastly, cost per pound or toxic-weighted pound of pollutant discharge reductions is not a 

measure of economic achievability and can be in tension with economic achievability. An option 

may be economically achievable because it is affordable to the industry as a whole, yet have a 

higher cost per pound or toxic-weighted pound of pollutant discharge reduction value than 

another. Conversely, the aggregate costs of a regulatory option and its associated burden on 

industry and the economy can cause a regulatory option to not be economic achievable, 

regardless of its cost per pound or toxic-weighted pound of pollutant discharge reduction. For 

these reasons, cost effectiveness is not determinative for establishing BAT.27

See also response to comment DCN EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3, in 

Comment Code 6.e.

Commenter Name: Elizabeth E. Aldridge, Hunton & Williams

Commenter Affiliation: UWAG

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

Comment Excerpt Number: 136

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

X. UWAG’s Industrywide Cost Estimates Show High Costs per TWPE for Bottom Ash, 

Fly Ash, and FGD Wastewater

In addition to UWAG’s analysis of costs using model plants, UWAG asked NERA Economic 

Consulting to develop calculations of cost-effectiveness for all three wastestreams using detailed 

UWAG cost and effluent information. NERA’s analysis is Attachment 14 to these comments.

NERA analyzed the treatment technologies proposed in various options for bottom ash transport 

water, fly ash transport water, and FGD wastewater. NERA calculated incremental costeffectiveness, that is, the additional costs per TWPE to go from one level of stringency to the 

next higher level. NERA compared these estimates to EPA’s estimates of cost-effectiveness and 

to the levels of cost-effectiveness that EPA has estimated in rulemakings for other industries.

For all the proposed steam electric technologies, NERA calculated that the cost per TWPE 

would be far higher than the mean ($47/TWPE) and median ($15/TWPE) from past rulemakings.

 

27 Thus, to the extent that commenters on the proposed ELGs raised issues challenging EPA’s data or methodology for estimating 

the “cost-effectiveness” of the rule, even assuming that EPA were to recalculate the cost-effectiveness values and get different 

results, these different results would not affect EPA’s decisions on the final rule since.
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NERA Cost-Effectiveness Estimates by Effluent Control Technology (1981$/TWPE)

Bottom Ash $1,959

Fly Ash $599

Chemical Precipitation $311

Incremental Biological $1,346

Incremental ZLD $1,369

In every case but one, the cost for TWPE for the steam electric proposals would be higher than 

the highest amount ($404 for Electrical and Electronic Components) EPA has specified.

The one option with a cost-effectiveness less than that highest-ever amount is chemical 

precipitation for FGD wastewater, which is still a very high $311 per TWPE in 1981 dollars.

Thus, as UWAG’s other analyses show, dry handling of fly ash, let alone bottom ash, cannot be 

justified on a cost-effectiveness basis.69 Biological treatment, let alone zero liquid discharge, 

cannot be justified for FGD wastewater.

69 NERA used flow rates from Part C of the ICR for the bottom ash and fly ash transport water 

analysis, and did not attempt to correct these flow rates to account for recycling of ash transport 

water. It is a fairly common practice to recycle a portion of the ash transport water to other plant 

functions, such as for use as makeup water to the scrubber. Therefore, both the UWAG pollutant 

loadings and costs per TWPE for these wastestreams are conservative estimates.

Comment Response: 

EPA disagrees with the commenter. See response to DCN EPA-HQ-OW-2009-0819-4447-A1, 

Excerpt Number 13 and DCN EPA-HQ-OW-2009-0819-4466-A1, Excerpt Number 8.

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.

Also see response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 14 regarding 

wastestream specific cost-effectiveness.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 26

External Review Flag: Economics/Benefits

External Review Incorporated into Response: No
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Comment Excerpt: 

 Cost‐effectiveness: EPA presents “cost‐effectiveness” for direct and indirect dischargers 

(although the vast majority of discharges are direct); this measure is the ratio of 

compliance costs to toxic‐weighted pollutants. Options 4 and 5 receive $70 and $111 per 

lb‐eq cost‐effectiveness estimates, respectively. EPA’s comparison to cost‐ effectiveness 

in other ELG categories showed a range of dollar to lb‐eq measures from less than $1 for 

inorganic chemicals to $404 electrical and electronic components.158 Like cost‐to‐revenue 

ratios, cost‐effectiveness depends on EPA measure of compliance costs, and suffers from 

the same biases. EPA uses compliance costs to industry—and not total costs to society—

to measure cost‐effectiveness; cost pass‐through assumptions are, therefore, critical in 

estimating values for these regulatory options. An assumption of greater pass‐through of 

costs to ratepayers would have the effect of lowering cost‐ effectiveness ratios. Again, 

EPA’s own assessment that the zero pass‐through assumption is not useful in 

determining profitability, effects to cash flow, or risk of financial distress would tend to 

preclude the use of cost‐effectiveness in assessing economic achievability for BAT.

158 Regulatory Impact Analysis, p.D‐8.

Comment Response: 

EPA agrees with the commenter that cost-effectiveness values are based on compliance costs and 

not on the total costs to society to address toxic pollutant discharges. This definition is a matter 

of convention. Specifically, as described in Appendix F of the RIA for the final rule, the costeffectiveness calculation is based on the annualized pre-tax costs to comply with regulatory 

options. They include the annualized capital outlays for equipment and recurring expenses for 

operating and maintaining compliance equipment, meeting monitoring requirements, etc. In the 

case of the final ELGs, the pre-tax compliance costs represent the major component of social 

costs (incremental government costs associated with the rule implementation are minimal). EPA 

states the cost effectiveness in 1981 constant dollars to allow comparison of promulgated ELGs. 

Whereas EPA agrees that cost pass-through assumptions will affect the presentation of the 

impacts of a rule on the plant owner in the cost-to-revenue analysis – since that is the perspective 

from which the analysis is being conducted, EPA disagrees that cost pass-through is relevant 

when looking at cost-effectiveness. EPA maintains that it is appropriate to use total compliance 

costs in the calculation of cost-effectiveness since the analysis is performed from the perspective 

of total expenditures incurred on behalf of society to remove the pollutants from discharges, 

irrespective of who (the plant owner or the consumer) incurs these costs. That said, EPA further 

recognizes the limitations of cost-effectiveness as a metric and tool for decision making. For the 

role of cost-effectiveness in EPA’s decisions for the final rule, see response to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 27 in Comment Code 6.h.
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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: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

APPA does not oppose the revisions of ELG that are periodically reviewed. The ELG revisions 

are based upon new data on Toxic Weighted Pounds Equivalent (TWPE) and the effectiveness of 

technology. The steam electric sector’s ELG were last revised in the 1980s and are now being 

reviewed as required under the Clean Water Act (CWA). APPA recognizes that it is time to 

consider revising the guidelines based on new information on the possible byproducts from 

Fluidized Gas Desulfurization (FGD) air pollution technologies (wet scrubbers) and because of 

concerns about selenium and other metals in wastewater. However, APPA does not believe that 

EPA has followed conventional CWA cost-benefit analysis in its Best Available Technology 

(BAT) determinations in many of the eight options offered. APPA urges EPA to review its 

analysis of pollutants and the capital costs and impacts from some of the proposed 

technologies. APPA believes if BAT is reviewed in light of the exaggerated pollutants 

discharged that EPA would select Option 1.

Comment Response: 

See response to DCN-EPA-HQ-OW-2009-0819-4576-A1, Excerpt Number 3.

EPA disagrees with the commenter that the ELG revisions are based on TWPE. EPA determined 

that the Option D technologies represent Best Available Technology Economically Achievable 

because these technologies are available and economically achievable (i.e., affordable) for the 

industry as a whole, and have acceptable non-water quality environmental impacts (see preamble 

Section VIII) as required by the statute.

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: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 33

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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The CWA is clear regarding the need to take cost into account. EPA’s decision regarding the 

best regulatory option in a final rule must be based upon cost-effectiveness.

Comment Response: 

EPA disagrees that the final rule must be based on cost-effectiveness. EPA determined that the 

Option D technologies represent Best Available Technology Economically Achievable because 

these technologies are available and economically achievable (i.e., affordable) for the industry as 

a whole, and have acceptable non-water quality environmental impacts (see preamble Section 

VIII) as required by the Clean Water Act.

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: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 42

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

By Longstanding Precedent, No BAT Requirement Should Cost More than $404 (in 1981 

Dollars) per TWPE

As is standard practice, EPA has calculated the “cost-effectiveness” of the proposed BAT 

requirements in terms of toxic-weighted pound-equivalents (TWPEs) of pollutants removed:

EPA often uses cost-effectiveness analysis in the development/revision of effluent limitations 

guidelines and standards to evaluate the relative efficiency of alternative regulatory options in 

removing toxic pollutants from the effluent discharges to the nation’s waters. Although not 

required by the Clean Water Act, cost-effectiveness analysis is a useful tool for evaluating 

regulatory options that address toxic pollutants.7

Whether or not EPA is “required” to consider cost-effectiveness, it is clearly required to take cost 

into account. See Clean Water Act §304(b)(2)(B). EPA has a longstanding practice of 

considering cost- effectiveness. As we show below, some of EPA’s proposals cannot be justified 

as cost-effective.

EPA says the highest cost per TWPE it has accepted in the past is $404 in 1981 dollars:8
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A review of approximately 25 of the most recently promulgated or revised BAT limitations shows 

BAT cost-effectiveness ranging from less than $1/pounds-equivalent (Inorganic Chemicals) to 

$404/pounds-equivalent (Electrical and Electronic Components), in 1981 dollars.

EPA is correct that it customarily uses cost-effectiveness analysis to judge technologies in ELG 

rulemakings. EPA is also correct that $404 per TWPE is close to the highest EPA has ever 

approved.

In several past ELG rulemakings, EPA published a table of cost-effectiveness estimates by 

industry category. In four cost-effectiveness analyses, dated 1996-2000, the highest cost per 

equivalent pound (that is, pound of pollutant adjusted for toxicity) was listed as $404 in 1981 

dollars.9

In the rulemaking for Metal Products and Machinery (MP&M), EPA determined that a 

technology was not BAT when it had a cost of $1,000/PE because this was “substantially 

greater” than what EPA had typically imposed for BAT technology in other industries, generally 

less than $200/PE.10

APPA (and UWAG) agree with EPA—cost-effectiveness analysis is (at least) a “useful tool,” 

and $404 (in 1981 dollars) is at the high end of what should be considered “acceptable.” APPA 

endorses UWAG’s recommendations on cost-effectiveness and how the cost effectiveness 

analysis should be conducted. The UWAG comments cover EPA’s statistical methods for 

estimating pollutant loadings from ash impoundments and point out many errors in the EPA’s 

AKRF report.

7

78 Fed. Reg. at 34,503 col. 2.

8

78 Fed. Reg. at 34,504 col. 1-2. Typically the cost has been less than $200. 68 Fed. Reg. 

25,686, 25,701 col. 3 (May 13, 2003).

9

See Cost Effectiveness Analysis of Final Effluent Limitations Guidelines and Standards for the 

Coastal Subcategory of the Oil and Gas Extraction Point Source Category, 821-R-96-021 

(October 1996), Table 5-1 at 5-2 to 5-3, 

http://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=200035QV.txt; Economic Analysis and CostEffectiveness Analysis of Proposed Effluent Limitations Guidelines and Standards for Industrial 

Waste Combustors [for proposed rule], EPA-821-B-97-010 (January 1998) at C-E 4-2 and 4-3, 

http://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=20002HH8.txt; EPA Office of Water, CostEffectiveness Analysis of Proposed Effluent Limitations Guidelines and Standards for the Metal 

Products and Machinery Industry (EPA-821- B-00-007 December 2000), page 10 (page 13 of 

the electronic version), [for proposed rule], 

http://water.epa.gov/scitech/wastetech/guide/mpm/upload/2001_01_10_guide_mpm_proposal_m

pm_ce.pdf; EPA, Cost-Effectiveness Analysis of Effluent Limitation Guidelines and Standards 

for the Centralized Waster Treatment Industry (undated but listed in support of final rule of 

December 2000) at 4-3, 

http://water.epa.gov/scitech/wastetech/guide/treatment/upload/2006_12_28_guide_cwt_final_eff

ective.pdf; see also Cost-Effectiveness Analysis of Effluent Limitations and Standards for the 
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Nonferrous Metals Forming and Metal Powders Industry, PB93158970 (August 1985) at 3-15 

Table 3.7.

10 68 Fed. Reg. 25,686, 25,701 col. 3, see also id. 25,702 col. 2 (May 13, 2003). In the same 

rulemaking, EPA said that $455/PE was “very expensive per pound removed.” MP&M 

Development Document at 9-21. A cost of $420/PE was “quite expensive.” Id. at 9-13.

Comment Response: 

See response to DCN-EPA-HQ-OW-2009-0819-4655, Excerpt Number 27.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 44

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Estimates of Dollars per TWPE Are Too Low

Because of various inappropriate methods, assumptions, and choices of data, EPA’s calculations 

of $/TWPE for the steam electric industry are underestimated. For individual wastestreams, EPA 

finds costs of only $27 to $107.

The cost-effectiveness for zero discharge of fly ash transport and FGMC wastewater, as in 

Option 3a, is $27 per TWPE removed. The cost effectiveness of chemical precipitation alone is 

$70 per TWPE removed, while the cost-effectiveness of chemical precipitation plus anaerobic 

biological treatment, which is included in all options except Option 3a, is $60 per TWPE 

removed. The cost effectiveness of zero discharge of bottom ash transport water for all units 

more than 50 MW is $107 per TWPE. In comparison, when this requirement is applied only to 

units more than 400 MW, as in Option 4a, the cost effectiveness value is $99 per TWPE 

removed.11

Correctly calculated, the costs per TWPE are much higher.

11 EPA, Technical Development Document for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category, EPA-821-R-13-002 

(April 2013), EPA-HQ-OW-2009- 0819-2257 (2013 TDD) at 8-34; see also 78 Fed Reg. at 

34,474 col. 1; 78 Fed. Reg. at 34,504.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 27

Commenter Name: Paul Ling

Commenter Affiliation: Kansas City Power & Light Company

Document Control Number: EPA-HQ-OW-2009-0819-5406-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Regulations such as the proposed steam electric ELG rule need to be crafted carefully so utilities 

are not forced to make changes such that costs exceed benefits and there is insufficient lead time 

to avoid or minimize adverse consequences to electricity customers, supply, and reliability. To 

avoid such adverse consequences, any final steam electric ELG rule should meet three 

objectives: (1) it should be based on accurate, representative data and sound analyses; (2) it 

should include only cost-effective requirements; and (3) it should provide for flexible 

implementation and reasonable compliance deadlines.

Comment Response: 

EPA has based the final rule on accurate and representative data and sound analyses. See the 

TDD and RIA regarding data used for the cost and loading analyses and EPA’s evaluation of 

cost-effectiveness.

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of 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.

The final rule allows for flexible implementation and has reasonable applicability deadlines. See 

Sections VIII.C.7 and XVI.A.1 of the preamble.
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For the role of benefit-cost in establishing BAT under the Clean Water Act, see response to DCN 

EPA-HQ-OW-2009-0819-4464-A1, Excerpt Number 3 in comment code 6.a.

EPA determined the rule will have minimal impacts on electricity prices, supply, and 

reliability. See RIA Sections 5, 7, and 10.

Commenter Name: Paul Ling

Commenter Affiliation: Kansas City Power & Light Company

Document Control Number: EPA-HQ-OW-2009-0819-5406-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA has adopted very conservative assumptions and extrapolated from very limited data to 

propose a rule that will have limited environmental benefits and significant costs. The proposed 

rule is not based on accurate, representative data and sound analyses. This affects EPA’s estimate 

of baseline pollutant loadings, technology choices, cost estimates, and quantification of benefits. 

For example, with respect to baseline pollutant loadings, over half of the pollutants (measured as 

toxic-weighted pollutant equivalents (TWPE) that EPA credits to its proposal are, at best, 

theoretical, and likely nonexistent. As a result of the use of these unrepresentative data and 

flawed analyses, EPA has proposed a rule that is not cost-effective.

Comment Response: 

EPA disagrees that the final rule “is not based on accurate, representative data and sound 

analyses” and that the final rule “is not cost-effective.” EPA maintains that it used the best 

available data to estimate baseline pollutant loads, select BAT, calculate compliance costs, and 

quantify benefits, as documented in the docket supporting the final rule. Following proposal, 

EPA expanded its datasets, reevaluated costs and loads, reevaluated environmental impacts and 

benefits, and determined that, collectively, the final BAT effluent limitations and standards meet 

the statutory requirements of the Clean Water Act. See the final preamble, the TDD, and the RIA

EPA revised pollutant loadings/reductions, costs, and cost-effectiveness for the final rule, based 

on public comments. See preamble section X and TDD Section 10 regarding pollutant 

loadings/reductions associated with the final rule, see preamble sections V.D and IX (and TDD 

Section 9) regarding compliance costs associated with the final rule, and see preamble section 

XV (and the RIA) for information on the cost-effectiveness of the final rule.

EPA disagrees the final rule is not cost-effective. 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 
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selected regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This 

cost-effectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements 

in other industries. The final PSES requirements for the selected regulatory option have a cost 

effectiveness of $1,228/lb-eq ($1981). This ratio is higher than the cost-effectiveness of PSES 

requirements in other industries. As explained in the preamble, the CE may be lower than 

estimated. Moreover, it is critical to establish PSES at the same level as BAT in this rule to avoid 

creating an unintended incentive for plants to start sending their wastewater to POTWs in an 

attempt to avoid the requirements of 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.

EPA disagrees the final rule will have limited environmental benefits. See the final EA and 

BCA.

Commenter Name: F. Gilzow

Commenter Affiliation: Missouri Joint Municipal Electric Utility Commission

Document Control Number: EPA-HQ-OW-2009-0819-5517-A2

Comment Excerpt Number: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

One primary comment, based on the present rulemaking record, is that EPA has not been able to 

justify, on a cost‐effectiveness basis, any wastewater treatment technology beyond what is 

already required by the 1982 steam electric guidelines. It appears, from calculations performed 

by the Utility Water Act Group, the Electric Power Research Institute, and others that the cost of, 

for example, dry handling of bottom ash would be considerably more costly than technologies 

EPA has required of other industries in past rulemakings.

We believe that this oversight is substantial enough that the rulemaking should be withdrawn, 

reviewed, and resubmitted with new costs or the rule should be restructured.

Comment Response: 

EPA disagrees the final rule is not cost-effective. Although not required by the CWA, and not a 

determining factor for establishing BAT/PSES or BADCT/PSNS, cost-effectiveness analysis can 

be a useful tool for describing regulatory options that address toxic pollutants. As presented in 

preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the 

selected regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This 

cost-effectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements 

in other industries. The final PSES requirements for the selected regulatory option have a cost 

effectiveness of $1,228/lb-eq ($1981). This ratio is higher than the cost-effectiveness of PSES 
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requirements in other industries. As explained in the preamble, the CE may be lower than 

estimated. Moreover, it is critical to establish PSES at the same level as BAT in this rule to avoid 

creating an unintended incentive for plants to start sending their wastewater to POTWs in an 

attempt to avoid the requirements of 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.

Also see response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 14 regarding 

wastestream specific cost-effectiveness.

The commenter states that the requirements in the final rule specific to bottom ash transport 

water are “considerably more costly than technologies EPA has required of other industries in 

past rulemakings.” In determining BAT, EPA does not compare the cost of a rule to 

another. The final rule establishes limitations and standards applicable to the discharge of 

pollutants from the steam electric power generating industry based on the “best available 

technology economically achievable” and the “best available demonstrated control technology,” 

as those terms are used in sections 301, 304, and 306 of the Clean Water Act. EPA determined 

that the Option D technologies represent Best Available Technology Economically Achievable 

because these technologies are available and economically achievable (i.e., affordable) for the 

industry as a whole, and have acceptable non-water quality environmental impacts as required by 

the statute (see preamble Section VIII).

Commenter Name: William Matthews

Commenter Affiliation: Cleco Corporation

Document Control Number: EPA-HQ-OW-2009-0819-5550-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Comment – I – Dry handling/closed loop (zero discharge ) is not adequately supported as a 

compliance option for bottom ash transport water

The Clean Water Act indicates at Section 304(b)(2)(B) that one of the factors to be taken into 

account in the assessment of best available technology is the cost of achieving such effluent 

reduction. EPA has complied with this by routinely considering the cost- effectiveness of 

compliance with ELG regulations for at least the past forty years. EPA’s current costeffectiveness bench-mark arrived at through all this cost-consideration activity over time for 

toxic pollutants is $404 per toxicity-weighted pound-equivalent (TWPE). The cost effectiveness 

of the BAT zero-discharge option for bottom ash transport water as arrived at by UWAG 

significantly exceeds the current $404/TWPE bench-mark.
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EPA’s cost effectiveness determinations, in dollars per TWPE, for a number of the waste streams 

of interest in the proposed rule are found in a document from the docket, Cost Effectiveness 

Calculation for Direct Dischargers at the Wastestream/Technology Level (EPA-HQ-OW-2009-

0819-2255). EPA’s cost effectiveness determination for the conversion of wet bottom ash 

handling systems to a zero discharge system is significantly understated at around $100/TWPE, 

for 400 mw, when compared to UWAG’s cost effectiveness determination of $1,954/TWPE. 

This appears to be due to a number of reasons:

- The number of good-quality samples taken by EPA for analyses was lacking. That is, an 

inadequate number of recent bottom ash water samples was taken to determine the pollutant 

concentrations. That one recent sample was taken at the Homer City plant. Older analytical data 

was included which came from sample events as far back as the 1980’s. In addition, some of the 

analytical data that was relied upon was taken from sample events at impoundments with 

contents made up of combined fly ash and bottom ash wastewater.

- The plant intake water contribution of the various chemical species of interest to the waste 

stream was not taken into account. When considering concentration values in the part per billion 

range, the intake water contribution can be significant.

- EPA’s calculations of pollutant loading in the bottom ash water was conducted using a flawed 

calculation method, based on the product of averages which biased the loading results high.

- Equipment cost estimates were too low. The costs of installing equipment for conversion from 

wet to dry ash handling were too low for a number of reasons which included failure to include 

all balance-of-plant costs in the total capital requirement.

The cost effectiveness determinations made by UWAG were much larger and were accomplished 

by:

- Using data from recent analyses of bottom ash water samples from numerous plants.

- Including costs ignored by EPA in the capital costs determinations for the treatment equipment.

- Applying an unbiased method for calculating loading in the waste water.

As EPA has documented in the past, its acceptable BAT cost-effectiveness range is $1/TWPE -

$404/TWPE. (78 Fed. Reg. at 34,504, col. 1-2). Because UWAG’s cost effectiveness value for 

the zero discharge bottom ash option was found to be well above this range maximum, it can be 

concluded that the zero discharge option for bottom ash water is not cost effective and therefore 

should be rejected as required treatment for compliance with the proposed rule.

Comment Response: 

See preamble Section VIII for a description of the technologies selected as BAT for the final 

rule, as well as EPA’s explanation for choosing the options that it did.
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EPA disagrees the final rule is not cost-effective. Although not required by the CWA, and not a 

determining factor for establishing BAT/PSES or BADCT/PSNS, cost-effectiveness analysis can 

be a useful tool for describing regulatory options that address toxic pollutants. As presented in 

preamble section XV.B and in Appendix F of the RIA, the final BAT requirements for the 

selected regulatory option (Option D) have a cost-effectiveness ratio of $134/lb-eq ($1981). This 

cost-effectiveness ratio is well within the range of cost-effectiveness ratios for BAT requirements 

in other industries.

Also see response to DCN EPA-HQ-OW-2009-0819-4448-A1, Excerpt Number 14 regarding 

wastestream specific cost-effectiveness.

EPA disagrees with the commenter that it has “routinely” complied with Clean Water Act 

Section 304(b)(2)(B)’s requirement to take into account “cost” when establishing Best Available 

Technology Economically Achievable by considering the “cost-effectiveness.” EPA also 

disagrees that it has a “benchmark” value for cost-effectiveness in establishing BAT. EPA did 

take into account cost in the final rule, in determining that the final rule is affordable for the 

industry as a whole. 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 responses to comment codes 6.f and 15.d, specifically DCN EPA-HQ-OW-2009-0819-4499-

A1, Excerpt Number 72 in Comment Code 15.d regarding the issues raised by this commenter 

related to ash loadings. EPA revised its cost estimates in response to comments. See the final 

TDD. For responses to comments regarding bottom ash costs, see responses to comment code 

16.b.

See responses to DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt Number 75 in Comment 

Code 4.b and DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 71 in Comment Code 13.d 

regarding bottom ash and combined fly ash and bottom ash wastewater characterization data and 

its use.

See the response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 53 in Comment Code 

16.b for updates made to the bottom ash cost methodology.

Commenter Name: David Y. Chung

Commenter Affiliation: Homer City Generation, L.P

Document Control Number: EPA-HQ-OW-2009-0819-5552-A2

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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EPA’s industry-wide cost effectiveness analysis is also flawed, as its calculations of cost per 

toxic-weighted pound-equivalent (TWPE) for FGD wastewater are orders of magnitude below 

those calculated by the Utility Water Act Group (“UWAG”).

Comment Response: 

EPA disagrees that its cost-effectiveness analysis for the final rule is flawed. EPA revised 

pollutant loadings/reductions, costs, and cost-effectiveness for the final rule, based on public 

comments. See preamble section X and TDD Section 10 regarding pollutant loadings/reductions 

associated with the final rule, see preamble sections V.D and IX (and TDD Section 9) regarding 

compliance costs associated with the final rule, and see preamble section XV (and the RIA) for 

information on the cost-effectiveness of the final rule.

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. The final PSES requirements 

for the selected regulatory option have a cost effectiveness of $1,228/lb-eq ($1981). This ratio is 

higher than the cost-effectiveness of PSES requirements in other industries. As explained in the 

preamble, the CE may be lower than estimated. Moreover, it is critical to establish PSES at the 

same level as BAT in this rule to avoid creating an unintended incentive for plants to start 

sending their wastewater to POTWs in an attempt to avoid the requirements of 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.
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6.i.i. Support/oppose Zero Discharge

Commenter Name: Lena Moffitt

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-3037

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Along with the Sierra Club and many other groups here today, I encourage the EPA to set zero 

discharge standards, and include rigorous treatment of toxic heavy metals in any remaining 

waste.

Comment Response: 

The final rule establishes zero discharge limitations and standards, as well as numeric limitations 

and standards for toxic pollutants, based on available and demonstrated treatment technologies, 

as described in preamble section VIII. For existing sources that discharge directly to surface 

water (except discharges from generating units that are 50 MW or less or that are oil-fired, see 

preamble section VIII.C.12), the final rule establishes a zero discharge limitation for all 

pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater. As well, 

it establishes numeric effluent limitations on mercury, arsenic, selenium, and nitrate/nitrite as N 

in FGD wastewater (except for those dischargers who choose – as part of the voluntary 

incentives program in this rule – to be subject to the BAT limitations on mercury, arsenic, 

selenium, and total dissolved solids (TDS) in FGD wastewater); numeric effluent limitations on 

mercury, arsenic, selenium and TDS in gasification wastewater, and a numeric effluent limitation 

on total suspended solids (TSS) in combustion residual leachate from landfills and surface 

impoundments (equal to the previously established Best Practicable Technology (BPT) limitation 

on TSS in low volume waste sources).

Commenter Name: T. Edwards

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-3676-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I am writing to urge EPA to finalize strong Effluent Limitation Guidelines for Steam Electric 

Power Generating plants requiring zero discharge.
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Electric utilities claim controlling their pollution is too costly. But failing to control pollution 

isn’t free; the public pays for this pollution. Technology to control power plant water pollution is 

currently available and widely used by other industries. All power plants, no matter their size, 

should be held to the same standard that protects the waters we all depend on for drinking, 

fishing, agriculture and recreation.

Please pass strong standards to limit all power plant water pollution to improve the health of 

rivers and streams, making the water we drink and the fish we eat safer.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3037, Excerpt Number 3.

Commenter Name: Kara Montaivo

Commenter Affiliation: Salt River Project Agricultural Improvement and Power District (SRP)

Document Control Number: EPA-HQ-OW-2009-0819-4179-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

However, SRP would like to make EPA aware that SRP successfully operates a power plant that 

employs a "zero liquid discharge " system for management of power plant wastewaters and coal 

combustion residuals. SRP's Navajo Generating Station (NGS) was designed at its inception to 

be a "zero discharge " facility, meaning that no water that is brought onto plant site would leave 

other than in the form of evaporation. To accomplish this,NGS employs a wide array of 

wastewater management technologies, including evaporation ponds, three brine concentrators 

and a crystallizer.

In addition, NGS conducts dry disposal of unused coal combustion residuals (fly ash, bottom 

ash, and flue gas desulfurization-gypsum byproduct). The use of dry disposal in conjunction with 

the dry climate and geology of the region reduces the mobility and leachability of any of the 

combustion residual constituents . Furthermore, SRP has instituted measures to prevent 

stormwater runoff (control dust, and monitor groundwater that further contain combustion 

residual constituents.

SRP recognizes that there are unique conditions at NGS that are not present at most other steam 

electric generating facilities. Much of SRP's success in using zero discharge technologies can be 

attributed to a favorable arid climate and suitable land area for installation and operation of the 

equipment supporting wastewater and combustion residual management. Although these 

technologies have been successfully deployed at NGS,SRP does not endorse a regulatory path 

where EPA would mandate widespread of use of zero liquid discharge technology at all of the 

country's steam-electric generating stations.
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Comment Response: 

EPA congratulates SRP in its efforts designing and implementing a “zero discharge” facility.

See response to DCN EPA-HQ-OW-2009-0819-3037, Excerpt Number 3.

Also, EPA agrees that the zero discharge process described by the commenter with respect to 

FGD waste is not available to the steam electric power generating industry as a whole and as 

such did not select it as BAT. See preamble Section VIII. As described in other comment 

responses, the evaporation technology basis for control of FGD wastewater is not equivalent to a 

zero liquid discharge process.

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

1. It is encouraging that EPA Is considering the combined implications of its ELG proposed rule 

with its CCR proposal in the risk assessment for the CCR rule. Since the primary risk 

associated with CCR material Is risk of a catastrophic release from a dam failure. BNCC and 

SJCC support the adoption of "dry handling " requirements under the ELG rule for certain CCR 

materials Including flv ash and flue gas mercurv control waste.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3037, Excerpt Number 3.

Comments related to the risk assessment for the CCR rule are outside the scope of this 

rulemaking (see Docket EPA-HQ-RCRA-2009-0640-11970).

Commenter Name: Pamela Ritger

Commenter Affiliation: Clean Wisconsin

Document Control Number: EPA-HQ-OW-2009-0819-4632-A1

Comment Excerpt Number: 17

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Clean Wisconsin urges the EPA to adopt Option 4a, the preferred alternative that will most 

reduce the amount of toxic pollution released by the steam electric power industry into our 

environment, and consequently, into our bodies through the ingestion of water and fish. 

However, as the EPA is well aware, these toxic pollutants do not enter our environment solely 

through direct discharge into surface waters or through indirect discharge through POTWs. They 

also leach into the soil and groundwater from coal combustion surface impoundments and 

landfills, as many coal combustion residual waste sites in Wisconsin and nationwide are unlined. 

The toxic pollutants to seep into the land and, often times, contaminate ground and surface 

waters years or decades after their disposal. For this reason, Clean Wisconsin urges the EPA to 

make dewatering of coal combustion residual processing mandatory for all coal-fired power 

plants, requiring dry handling of such wastes. Much coal water pollution results from using 

water to clean out bottom ash and fly ash from coal power plant systems. Rather than using, and 

wasting, clean water to remove ash from coal power plant systems, such removal can be done 

mechanically, eliminating the main source of water pollution from the process and saving 

increasingly scarce water resources. Sixty-six percent of coal and petroleum coke power plants 

already utilize these dry ash-handling methods for fly ash, and 22 percent use dry management 

systems for their bottom ash.49 The EPA should require the remaining power plants to follow 

suit.

49 Environmental Integrity Project et al., Closing the Floodgates: How the Coal Industry Is 

Poisoning Our Water and How We Can Stop It, p. 10-11 (July 2013). Available at 

http://www.environmentalintegrity.org/news_reports/documents/2013_07_23_ClosingTheFlood

gates-Final.pdf

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants to 

waters of the United States from the steam electric power generating industry, pursuant to the 

Clean Water Act. The final rule does not specifically address groundwater contamination or 

management of surface impoundments. See response to comments in comment code 27.e for 

more information.

Also, see response to DCN EPA-HQ-OW-2009-0819-3037, Excerpt Number 3 regarding zero 

discharge of pollutants in ash transport water to surface waters. See also preamble Section VIII 

regarding dry handling as the basis for certain final limitations and standards, including a 

description of the availability of dry handling or closed-loop technologies in the industry.

EPA did not select proposed option 4a (or the particular suite of technologies that form the basis 

for that option) for the final rule, for the reasons explained in preamble section VIII and 

responses to comments in comment code 6.i.vii.
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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: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Zero-Discharge (ZD) limits should not apply to incidental or emergency operation.

The proposal calls for ZD restrictions for wastewater streams associated with handling flyash, 

mercury emissions control systems, and, for larger units, bottom ash as well. As delineated in the 

preamble, power stations may choose a number of technologies to comply with a no-discharge 

limit. However, the rule should recognize that these are technologies, and are therefore subject to 

the mechanical vagaries and upsets inherent to technological devices. Presumably, the costeffectiveness imputed by the Agency is based on installing single systems appropriate to the 

plant, rather than multiple redundant technology systems. It is therefore reasonable to expect that 

a limit couched as zero-discharge will likely be exceeded during short-term emergency 

upsets. Accordingly, the expressed ZD limits should make provision for inevitable upsets 

by including the phrase, “except during short-term malfunctions.”

Comment Response: 

EPA disagrees that the rule “should make provision for inevitable upsets by including the phrase, 

‘except during short-term malfunctions.’” If an exceedance is caused by an upset condition, the 

plant would have an affirmative defense to an enforcement action if the requirements of 40 CFR 

§ 122.41(n) are met. Exceedances caused by a design or operational deficiency, however, are an 

indication that the plant’s performance does not represent the appropriate level of control. For 

these final limitations and standards, EPA determined that such exceedances can be controlled by 

diligent process and wastewater treatment system operational practices, such as appropriate 

inspection and repair of equipment and operator training and performance evaluations.

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

14.a for a discussion of the cost basis for dry ash handling systems, including costs for an 

appropriate level of redundancy to ensure the ash handling operations can proceed while still 

meeting the zero discharge of fly ash transport water and bottom ash transport water 

requirements.

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: Jay Hudson

Commenter Affiliation: Santee Cooper
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Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Temporary or Emergency Wet Sluicing

A number of the options in the proposed standards require zero discharge of ash transport water 

which will require installation of new ash handling systems. As noted by EPA, some facilities 

have converted from wet ash sluicing to dry ash handling, but have retained the wet system as a 

"backup" system. Operating problems can occur more easily with a retrofitted system than with 

an originally designed system, which can result in un-scheduled outages and additional costs. 

Therefore, we request that EPA provide an exemption that would allow the use of wet systems 

for limited periods of time at facilit ies that have or will retrofit to a no discharge handling 

system.

Comment Response: 

EPA disagrees that “operating problems can occur more easily with a retrofitted system than 

with an originally designed system,” and the commenter provides no data to support its assertion. 

See response to DCN EPA-HQ-OW-2009-0819-4382-A1, Excerpt Number 4 for further 

information.

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: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

CPS Energy believes zero liquid discharge (ZLD) options overall are too costly based on the 

various cost benefit analysis studied (EPA, EPRI, etc.) and we believe that more reasonable 

options are viable. In addition, water conservation is important especially in many parts of the 

country where return flows are vital due to water shortages. ZLD should not be required as BAT 

or as new source performance standards (NSPS) as long as return flows do not degrade the 

receiving water body or pose undue health threats. In drier regions of the country, it is important 

that water resources be conserved instead of being evaporated off. In our case, wastewater 

discharge is re-circulated in the cooling system so over 99% of the wastewater is reused. 

Consequently, it is inherently more important in dry parts of the US that the ZLD option not be 
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implemented so long as reasonable water quality discharge standards can be met by some other 

means.

Comment Response: 

EPA supports water conservation and, by establishing zero discharge limitations and standards as 

discussed in preamble section VIII, promotes this practice. The zero discharge limitations and 

standards will either lead steam electric power plants to implement processes that do not use 

water (for example, dry ash handling) or processes that incorporate recycle of the water that is 

used (for example, closed-loop bottom ash handling). Because of this, the plants will reduce the 

amount of fresh make-up that they need to withdraw from surface water or groundwater sources.

EPA has quantified the extent to which water use will be reduced as a result of the final rule (see 

the TDD and EPA’s memorandum evaluating non-water quality environmental impacts). 

Encouraging the use of dry ash handling and closed-loop processes that do not rely on surface 

impoundments will also conserve water by eliminating losses due to evaporation or infiltration. 

The commenter wrongly suggests that the receiving water would somehow suffer because the 

amount of return flow will be lessened; however, since these dry and closed-loop systems 

eliminate or substantially reduce the amount of water used, there will be a reduction in water 

withdrawn from the receiving water and the receiving water will actually experience an increase, 

rather than a decrease, in its water flows.

The commenter states that “it is inherently more important in dry parts of the US that the ZLD 

option not be implemented so long as reasonable water quality discharge standards can be met by 

some other means.” If the commenter is referring to the BAT/NSPS technology based on 

evaporation, they are mistaken in suggesting that the FGD evaporation process results in the 

water vapor being lost to atmosphere. The evaporation technology that is the basis for the NSPS 

(and voluntary incentives program BAT limitations) FGD effluent limitations, as well as the 

gasification wastewater effluent limitations, results in the water vapor being condensed. Plants 

are then able to reuse that condensate as makeup water for plant processes, or discharge it should 

they choose to do so. See preamble Section VIII for a discussion of the final NSPS applicable to 

FGD wastewater and the final BAT limitations in the voluntary incentives program, which are 

based on the use of evaporation technology.

With respect to the commenter’s assertion that zero pollutant discharge requirements for any 

wastestream is too costly, EPA disagrees. As explained in Section VIII of the preamble and the 

RIA, EPA determined the final rule is affordable for the industry as a whole.

As the statute requires, EPA establishes BAT limitations based on the statutory factors of 

technological availability and economic achievability, after considering the factors specified in 

the Clean Water Act, including non-water quality environmental impacts.

Regarding the role of cost benefit in EPA’s decisions on the final steam electric ELGs, see 

response to DCN EPA-HQ-2009-0819-4464-A1, Excerpt Number 3 (in comment code 6.e).
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Regarding the role of the receiving water quality in establishing limitations based on Best 

Available Technology Economically Achievable, see response to DCN EPA-HQ-OW-2009-

0819-4467-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: 152

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Based on the many flaws identified during our review, we do not believe the current data and 

methodology utilized by EPA in determining pollutant loadings, cost-effectiveness, or available 

technologies are based on sound policy or science. For example, FGD wastewater technology 

limits based on biological treatment or ZLD are not consistently achievable and would cause 

numerous non-compliance issues and forced plant outages while providing minimal added 

benefit over chemical precipitation treatment. Similarly, analysis by Southern, UWAG and 

industry suggest that almost all of EPA’s preferred options for FGD wastewater, bottom ash 

transport water and fly ash transport water, and all EPA’s preferred options for combustion 

residual leachate, are not cost effective.

Comment Response: 

EPA disagrees that the data and methodology used to establish the final rule are not based on 

sound policy or science. The commenter does not offer any specific comments or information 

regarding methodologies or data it believes are “flawed” and why. The data and analyses used in 

developing the final rule requirements are available and described in the final rule record. See 

responses to specific comments about the data or methodologies used through this comment 

response document.

Regarding the availability of chemical precipitation and biological treatment for control of 

pollutants in FGD wastewater discharges, see preamble section VIII and responses to comments 

in comment codes 9 and 10, respectively. The final rule does not establish limitations or 

standards based on “ZLD” technology. However, see preamble section VIII and responses to 

comments in comment code 11 regarding the availability of evaporation for control of pollutants 

in FGD wastewater discharges.

See Section 13 of the TDD regarding achievability of the final rule limitations and standards 

applicable to FGD wastewater discharges.

EPA disagrees with the commenter that the final rule will cause forced plant outages and notes 

that the commenter provided no data to support its assertion. See preamble sections VIII and IX 
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and the RIA for more information about projected impacts on the steam electric industry. Also, 

see discussion in the preamble on upset and bypass provisions.

See preamble section VIII for a discussion of the technology bases for the limitations and 

standards in the final rule applicable to FGD wastewater, fly ash transport water, bottom ash 

transport water, and combustion residual leachate. EPA notes that it is establishing NSPS (and 

BAT limitations in the voluntary incentives program) for FGD wastewater discharges based on 

the use of evaporation. See response to DCN EPA-HQ-OW-2009-0819-4655, Excerpt Number 

108 in Comment Code 11.a.

EPA disagrees with the commenter’s statement that “almost all of EPA’s preferred options ... 

are not cost-effective.” As described in preamble section XV, collectively, the final BAT 

requirements have a cost-effectiveness ratio well within the range of cost-effectiveness ratios for 

BAT requirements in other industries. In addition, EPA does not use cost-effectiveness as the 

sole basis for regulatory decisions. EPA often uses cost-effectiveness analysis in the 

development and revision of ELGs to evaluate the relative efficiency of alternative regulatory 

options in removing toxic pollutants from effluent discharges to the nation's waters. However, 

cost-effectiveness analysis is not required by the CWA and not a determining factor for 

establishing BAT and PSES, although it can be a useful tool for describing regulatory options 

that address toxic pollutants. 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: David M. Fraley

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

Document Control Number: EPA-HQ-OW-2009-0819-4382-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

City Utilities can support some, but not all aspects of the proposed rule. We do take issue with 

EPA’s economic analysis on the efficacy of zero-discharge limits for ash handling stream, 

especially if there is no allowances for inevitable mechanical upsets.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4382-A1, Excerpt Number 4 regarding upset 

conditions.

See response to DCN EPA-HQ-OW-2009-0819-4283-A1, Excerpt Number 14 regarding the 

claim that zero discharge technologies are too costly and not cost effective.
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Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion Resources, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4631-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Specifically, we have concerns regarding the practicality of retrofitting advanced FGD treatment 

technologies and closed loop bottom ash systems at existing facilities.

Comment Response: 

The technologies used as the basis for the final BAT requirements for ash transport water (dry 

handling or closed-loop systems), as applied to existing sources that are not oil-fired generating 

units or those generating units greater than 50 MW, have been in operation at power plants for 

more than 20 years and are amply demonstrated by the record supporting the final rule. Recent 

advancements related to bottom ash handling technologies have focused on providing more 

flexible retrofit solutions and improving the thermal efficiency of the boiler operation. These 

advancements result in additional savings related to electricity use, operation and maintenance, 

water costs, and thermal energy recovery. See preamble section VIII for additional discussion 

regarding the requirements of the final rule and availability of control technologies upon which 

the final rule is based. Additionally, since the time of the Steam Electric Industry Survey, 

companies have continued to upgrade, or announce their plans to upgrade, their fly ash and 

bottom ash handling systems at generating units (see TDD Section 4.5). 

Both chemical precipitation and biological treatment are well-demonstrated technologies that are 

available to steam electric power plants for use in treating FGD wastewater. EPA disagrees that 

application of these technologies to this sector is impractical. See responses to DCN EPA-HQOW-2009-0819-4655, Excerpt Number 107 in Comment Code 10.a, and Excerpt Numbers 108 

and 119, both located 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: 15

External Review Flag: Legal

External Review Incorporated into Response: No

Comment Excerpt: 
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Some of EPA’s options would require “no discharge” or “zero liquid discharge” for certain 

wastestreams, including fly ash, bottom ash, and even FGD wastewater. In no case has an 

adequate record been compiled to support such options. “No discharge” requirements must be 

carefully considered and fully supported by data. Although the Clean Water Act contains 

references to eliminating the discharge of pollutants, including a “goal” and a “policy” to that 

effect, Congress never directed that pollutants be eliminated without considering cost, as EPA 

recognizes in the preamble to the proposal. BP Exploration & Oil v. EPA, 66 F.3d 784, 796–97 

(6th Cir. 1996) (upholding EPA’s decision not to require zero discharge of produced waters based 

on reinjection for the Offshore subcategory of the Oil and Gas Extraction Point Source Category 

based in part on total industry cost), cited at 78 Fed. Reg. 34,473 col. 2. As with any other 

technology-based requirement, EPA must weigh factors, including cost and energy needs, and 

impose a requirement only if it reasonably takes these factors into account. Because of the high 

cost of no-discharge options and the relatively small incremental amounts of pollutants they 

remove, EPA cannot require them on the record as it now stands.

Comment Response: 

EPA did not consider at proposal, nor is EPA establishing for the final rule, a “no discharge” or 

“zero liquid discharge” requirement for FGD wastewater. The technology basis discussed at 

length in the preamble for the proposed and final rules for controlling discharges of FGD 

wastewater is evaporation.

Second, EPA disagrees that the requirements in the final rule lack adequate record support. As 

explained in the preamble to the final rule, the technologies selected as BAT for the regulated 

wastestreams are technologically available, economically achievable (i.e., affordable for the 

industry as a whole), and have acceptable non-water quality environmental impacts, as required 

by the Clean Water Act. In determining that the final rule is affordable for the steam electric 

industry as a whole, EPA fully considered “cost” in its decisions on the final rule. See preamble 

sections VIII and IX, the TDD, and the RIA.

EPA disagrees that the final rule will remove only “small incremental amounts of pollutants.” 

See preamble section X and the TDD for an estimate of pollutant loadings reductions attributable 

to 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.
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6.i.ii. Support Option 1

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

APPA endorses Option 1 (shaded in blue in Table 1) as the best regulatory option in 

consideration of FDG wastewater, fly ash, bottom ash and nonchemical metal cleaning wastes. 

However APPA believes Option 1 can be improved and offers several suggestions for doing so.

APPA’s Preferred Option

Based on the potential effects this rulemaking could have on member public power or 

community- owned utilities, APPA concludes that the most preferred and best-fitting option 

for public power utilities is Option 1. We believe that it is the best option to effectively clean 

waste-stream pollutants, while maintaining a fair cost burden for utilities of different sizes. Most 

impacted APPA members prefer having the certainty provided by Option 1 even though it is 

projected to have a slightly higher cost to implement than the other options proposed by EPA in 

this rulemaking. Certainty is important for municipalities that are faced with costly business 

decisions. Option 1 provides more certainty on effluent controls than other options and 

therefore lowers the long-run cost for public power utilities.

Comment Response: 

The final rule is not based on proposed Option 1 (or the specific suite of technologies that forms 

the basis for that option). See preamble Section VIII for EPA’s rationale for selecting 

Regulatory Option D for existing sources and Option F for new sources, and the associated 

technology bases for those options by wastestream, as well as EPA’s rationale for rejecting other 

proposed options. In particular, of possible interest to the commenter based on the commenter’s 

statements about the importance of “certainty,” EPA did not select certain regulatory options that 

would have required BAT for discharges of FGD wastewater to be established on a “best 

professional judgment,” or “BPJ” basis.

In general, the final rule provides great certainty to the industry because it establishes nationally 

applicable, technology-based effluent limitations and standards for six wastestreams that are 

discharged from steam electric power plants. While it is true that proposed Option 1 would have 

established limitations and standards for the discharge of non-chemical metal cleaning waste, 

which the final rule does not, EPA decided not to establish final limitations and standards for the 

discharge of non-chemical metal cleaning waste for the reasons described in preamble Section 

VIII.I.
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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: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Although there are important areas in which the proposed ELGs and standards can be improved, 

NPPD supports the generaL structure of the proposed rule. After closely analyzing the 

proposed effluent guidelines, NPP D has concluded that the most preferred and best-fitting 

option is EPA' s Option 1.

With our suggested changes as noted below, the proposed standards can provide the basis for a 

regulatory program that protects the enviromnent while recogni zing the economic, engineering, 

and environmental constraints that apply to individual electric generating facilities.

The proposed rule would apply to wastewater discharges from steam generating electric facilities 

through incorporation into National Pollution Discharge Elimination Systems (NPDES) permits 

issued by EPA or authorized states. The proposal considered a number of regulatory options for 

each of seven wastewater streams that may occur at steam electric generating units (EGUs): flue 

gas desulfurization (FGD) wastewater, fly ash transport water, bottom ash transport water, 

combustion residual leachate, flue gas mercury control (FGMC) wastewater, gasification 

wastewater, and nonchemical metal cleaning wastes. It is likely that EGUs will be subject to 

several different standards based on which waste streams they possess , leading to significant 

increases in costs.

EPA has proposed four preferred options and one "lead option," which is used for the regulatory 

text. Presenting a range of options is helpful for examining the regulatory alternatives for the 

waste stream s in question. However, some of the regulatory options proposed by EPA are more 

appropriate and reasonable for EGUs with different configurations. In addition, while some 

waste streams may require additional control, others remain well-controlled with current 

practices and should not be subject to additional regulation. EPA should focus the ELG revisions 

solely on waste streams that are new or significantly changed and waste streams that are not well 

controlled by the current ELG standards.

Comment Response: 

The final rule is not based on proposed Option 1 (or the specific suite of technologies that forms 

the basis for that option). See preamble Section VIII for EPA’s rationale for selecting Regulatory 

Option D for existing sources and Option F for new sources, and the associated technology bases 

for those options by wastestream, as well as EPA’s rationale for rejecting other proposed 

options.
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With respect to the commenter’s statement that “some of the regulatory options proposed by 

EPA are more appropriate and reasonable for EGUs with different configurations,” the 

commenter offers no explanation of what it means by “some . . . options” or “different 

configurations.” EPA determined that the final rule is based on technologies that are available 

and demonstrated, and that are affordable to the industry as a whole (see preamble Section VIII).

EPA cannot respond to the commenter’s statement that “while some waste streams may require 

additional control, others remain well-controlled with current practices” because it is too 

generalized and the commenter does not explain which wastestreams or practices it is referring 

to. Nonetheless, the final rule does focus – as the commenter states – on wastestreams at steam 

electric power plants that are new or have changed, as well as those that were not well-controlled 

by the previously established steam electric ELGs. As explained in preamble Section III, the 

previously established ELGs for the steam electric power generating industry, last updated in 

1982, do not adequately address the array of pollutants (toxic metals and others) discharged by 

this industry, nor have they kept pace with process changes and wastewater treatment technology 

developments that have occurred over the last three decades. The rise of new processes for 

generating electric power (e.g., coal gasification) and the widespread implementation of airpollution controls (e.g., flue gas desulfurization (FGD) and flue gas mercury controls (FGMC)) 

have altered existing wastestreams and created new sources of wastewater at many steam electric 

power plants, particularly coal-fired plants. As well, significant improvements in wastewater 

treatment and ash handling operations have occurred in the last 30 years. See Section VIII of the 

preamble for details about the wastestreams regulated as part of the final rule.

Commenter Name: Jay Hudson

Commenter Affiliation: Santee Cooper

Document Control Number: EPA-HQ-OW-2009-0819-4476-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Santee Cooper endorses Option 1as the best option consideri ng FGD Wastewater,Fly Ash, 

Bottom Ash, and Nonchemical Cleaning Waste . However, this Option cannot be wholly adopted 

as some variations are needed on particular waste streams. Of particular importance is 

consideration of the size of the various facilities, their age, the complexities involved in some 

particular cases, and the availability of land. While certainty is desired, 

the permitting authorities should be allowed some flexibility in adapting new standards to 

existing facilities.

Due to cost and other considerations, we do not believe that Options 4 and 5 could be cost 

effective for existing facilities. Therefore,we do not believe they should be given any additional 

consideration.
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Comment Response: 

The final rule is not based on proposed Option 1 (or the specific suite of technologies that forms 

the basis for that option). See preamble Section VIII for EPA’s rationale for selecting Regulatory 

Option D for existing sources and Option F for new sources, and the associated technology bases 

for those options by wastestream, as well as EPA’s rationale for rejecting other proposed 

options. 

During the rulemaking process, EPA considered the size, age of plant or generating unit, 

geographic location, fuel type, and processes employed at steam electric power plants in 

developing the final rule requirements (see Section 5 of the TDD). EPA ultimately determined 

that it would be appropriate to establish certain differentiated requirements for select generating 

units – those that are existing oil-fired generating units or those that are existing small generating 

units (i.e., with a nameplate capacity of 50MW or less) (see Section VIII.C.12 of the preamble 

for more details on these differentiated requirements). EPA concluded that no other 

differentiated requirements would be appropriate for the final rule.

EPA notes that while it based the final rule’s requirements on specific technologies identified as 

representing Best Available Technology Economically Achievable and Best Available 

Demonstrated Control Technology, steam electric power plants are not required to use such 

technologies and they have considerable flexibility in developing the approaches for compliance 

with the limitations and standards that are best suited for their particular operations. 

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: H. Morriss Barney IV

Commenter Affiliation: Texas Municipal Power Agency (TMPA)

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

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

TMPA appreciates EPA’s willingness to consider multiple options in this rulemaking. TMPA's 

preferred option is Option 1. We believe that it is the best option to effectively clean wastestream pollutants, while maintaining a fair cost burden for utilities of different sizes. TMPA 

prefers having the certainty provided by Option 1 even though it is estimated to have a slightly 

higher cost than other options proposed by EPA in their proposed rule. Certainty is important for 

municipalities that are faced with costly business decisions. Option 1 provides more certainty on 

effluent controls than other options and therefore lowers long-run cost for public power utilities.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 20.

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: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

2. In the final rule EPA should adopt an approach under Option 1 to enhance regulatory 

certainty and cost-effectiveness.

EPA has considered 8 options in the proposed rule. Of these eight options, OMU endorses 

Option 1 as the best regulatory option considering FGD wastewater, fly ash, bottom ash, and 

nonchemical metal cleaning wastes. Nonetheless, OMU ESS has recommendations for slight 

variations of this option.

Option 1 will effectively clean waste-stream pollutants while maintaining a fair cost burden for 

utilities, small or large. Although Option 1 is not the cheapest option offered by the EPA in the 

proposed rule, it has the most certainty which is a very important facet while budgeting and 

planning for future compliance at municipally owned power plants like OMU ESS.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 20.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

APPA prefers Option 1 of EPA’s list of eight options, with very important caveats as described 

below and in our comment details, and does not oppose revisions to the existing ELG that were 

last revised in 1982.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 20.

Commenter Name: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 95

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

APPA prefers Option 1 of EPA’s list of eight options, with very important caveats as described 

below and in our comment details, and does not oppose revisions to the existing ELG that were 

last revised in 1982.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5140-A2, Excerpt Number 20.

Commenter Name: F. Gilzow

Commenter Affiliation: Missouri Joint Municipal Electric Utility Commission

Document Control Number: EPA-HQ-OW-2009-0819-5517-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Finally, it is not clear that EPA has followed conventional Clean Water Act cost‐benefit analysis 

in its Best Available Technology (BAT) determinations in many of the eight options offered. We 

urge the EPA to review their analysis of pollutants and about the capital costs and impacts from 

some of these proposed technologies. If BAT is reviewed in light of the exaggerated pollutants 

discharged that the EPA would select Option 1.

Comment Response: 

It is not clear what the commenter means when it says that EPA has not followed “conventional 

Clean Water Act cost-benefit analysis.” Section 301(b) of the Clean Water Act requires that 

BAT reflect what is “technologically and economically achievable” for the elimination of 

discharges of pollutants, after a consideration of certain factors specified in section 304(b) of the 

Act. EPA determined that the final rule is based on technologies that are available and the final 

rule is affordable to the industry as a whole, after considering the factors specified in the Act, 
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including cost (see preamble Section VIII). The Act does not require EPA to conduct a costbenefit analysis for BAT, and EPA has traditionally not used cost-benefit analysis as a factor in 

establishing BAT. EPA’s decision is reasonable and consistent with the text, structure and 

history of the statute. See Nat’l Crushed Stone Ass’n v. EPA, 449 U.S. 64, 70-71 (1980); Ass’n of 

Pac. Fisheries v. EPA, 615 F.2d 794, 818 (9th Cir. 1980); Am. Iron & Steel v. EPA, 526 F.2d 

1027, 1051-52 (3d Cir. 1975). See also Weyerhaeuser v. Costle, 590 F.2d 1011, 1042 (D.C. Cir. 

1978). EPA did, however, assess and present the results of costs and benefits pursuant to 

Executive Order. See preamble sections IX.B and XIV and BCA.

The final rule is not based on proposed Option 1 (or the specific suite of technologies that forms 

the basis for that option). See preamble Section VIII for EPA’s rationale for selecting Regulatory 

Option D for existing sources and Option F for new sources, and the associated technology bases 

for those options by wastestream, as well as EPA’s rationale for rejecting other proposed options.

Commenter Name: F. Gilzow

Commenter Affiliation: Missouri Joint Municipal Electric Utility Commission

Document Control Number: EPA-HQ-OW-2009-0819-5517-A2

Comment Excerpt Number: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

While we appreciate EPA’s willingness to consider a number of alternatives including 8 options 

with four being ‘preferred’, we do not believe that the agency is complying with either the letter 

or the spirit of the federal administrative procedures act when it does not issue a single draft rule. 

It is difficult at best, and practically meaningless to offer comments on what amounts to a 

restaurant style menu of public policy options (take one from column one and two from column 

three). Given this approach however, we continue to believe that Option 1 may provide the most 

reasoned approach given the limited resources.

Comment Response: 

With respect to the commenter’s statement about Option 1, see response to DCN EPA-HQ-OW2009-0819-5140-A2, Excerpt Number 20.

EPA disagrees with the commenter that it did not follow the Administrative Procedure Act 

because it “[did] not issue a single draft rule.” Nothing in the APA requires EPA to identify a 

single regulatory option, and in fact EPA very often includes several alternatives under 

consideration in its Notices of Proposed Rulemaking. The APA requires a Notice of Proposed 

Rulemaking to include “either the terms or substance of the proposed rule or a description of the 

subjects and issues involved.” 5 U.S.C. § 553(b)(3). EPA’s Notice of Proposed Rulemaking for 

the steam electric ELGs included both a description of subjects and issues involved, as well as 

proposed regulatory text. EPA described in great detail in the preamble to the proposal the 
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wastestreams it was considering regulating, and the technologies it was considering basing such 

regulations on, along with possible limitations and standards. EPA’s draft regulatory text was 

based on one of its preferred options. Moreover, the Notice fairly apprised interested persons of 

all the main issues in the rulemaking such that they could meaningfully participate in the publiccomment process. For example, EPA described a voluntary incentives program and an anticircumvention provision in the preamble, which after considering public comments, EPA 

decided to finalize with particular changes for the final rule.
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6.i.iii. Support Option 5

Commenter Name: L. Goldberg

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-3698-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In April 2013, the EPA’s “Power Plant Pollution Standard” addresses only 468 million pounds of 

pollution a year!

We demand a stronger and more aggressive action of 53 Billion pounds of pollution per year!!

I support the proposed option that would require power plants to “dry handle” waste from fly and 

bottom ash ponds – and to use evaporation treatment for FGD scrubber sludge waste.

Please! Our government must step up and take a strong step/action to limit power plant water 

pollution now!!

Comment Response: 

The commenter supports Proposed Option 5 (which is the same as Option F described in the final 

rule preamble with respect to the wastestreams listed by the commenter). For the reasons 

explained in Sections VIII.C and E of the final preamble, EPA selected Option D as the basis for 

BAT limitations and PSES in the final rule. For the vast majority of steam electric power plants, 

the final rule establishes zero discharge limitations and standards based on dry handling 

applicable to discharges of fly ash transport water and flue gas mercury control wastewater, and 

it establishes zero discharge limitations and standards based on dry handling or closed-loop 

technologies applicable to discharges of bottom ash transport water. With respect to discharges 

of FGD wastewater, for the vast majority of steam electric power plants, the final rule establishes 

BAT limitations based on chemical precipitation plus biological treatment. See preamble section 

VIII.C.1 for an explanation of the basis for the final BAT limitations for FGD wastewater 

discharges, including why EPA did not select evaporation as the BAT basis for control of FGD 

wastewater discharges from all existing steam electric power generating units.

Although EPA did not select evaporation as the BAT basis for control of FGD wastewater 

discharges from all existing steam electric power generating units, as part of BAT for existing 

sources, the final rule also establishes a voluntary incentives program for plants that adopt 

process changes and controls that achieve limitations based on evaporation for FGD wastewater 

discharges. See Section VIII.C.13 of the final preamble. Also, the new source standards (NSPS 

and PSNS) in the final rule are based on the Option F technologies (which includes zero 

discharge standards for control of discharges of fly ash transport water, bottom ash transport 
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water, and FGMC wastewater, as well as standards based on evaporation for control of FGD 

wastewater discharges).

Finally, EPA revised its estimates of pollutant loadings reductions in response to comments. See 

the preamble section X and the TDD for EPA’s estimates reductions of pollutant discharges 

associated with the final rule.

Commenter Name: W. Byrd

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-3720-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I am writing to urge the EPA to issue strong standards that will keep billions of pounds of 

arsenic, lead, mercury and selenium from toxic power plant wastewater out of our rivers, lakes 

and streams.

I support the strongest proposed option that would require power plants to "dry handle" waste 

from both fly and bottom ash ponds and to use evaporation treatment for scrubber sludge waste. 

This option would reduce pollution by over 5 billion pounds per year, while the least stringent 

option, which 80% of plants are already in compliance, would merely reduce pollutants by less 

than half a billion pounds.

Since the ELG has not been updated since 1982, the most stringent options for effluent limitation

are needed to bring the best available technology to coal-fired power plants and the cleanest 

water to our taps.

Existing technology can achieve these goals while creating new jobs. I encourage the EPA to 

create these necessary standards for our health water, our communities and our environment.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Whitney Byrd

Commenter Affiliation: Wise Energy for Virginia Coalition

Document Control Number: EPA-HQ-OW-2009-0819-3920-A38

Comment Excerpt Number: 1
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Wise Energy for Virginia Coalition is in support of the following limitations (all of which 

are retained in Best Available Technology standard “BAT” Option 5):

 Dry handling of fly ash at all steam electric plants

 Chemical precipitation and biological treatment of scrubber (FGD) waste

 Dry handling of bottom ash at all steam electric plants

 Chemical precipitation of landfill leachate (Option 4)

 Evaporation treatment for scrubber waste (FGD), reducing discharges close to zero 

(Option 5)

 Stringent compliance deadlines

The most stringent option for ELG (BAT option 5) would reduce pollution by over 5 billion 

pounds per year, while the least stringent option (BAT option 3), which 80% of plants are 

already in compliance, would merely reduce pollutants by less than half a billion.

Comment Response: 

The commenter states that it supports proposed Option 5 (the same as Option F in the final rule 

for the wastestreams listed by the commenter) yet provided conflicting information as to its 

understanding of the proposed BAT limitations applicable to FGD wastewater in proposed 

Option 5. The proposed BAT basis for control of FGD wastewater discharges in Option F 

(which is equivalent to proposed Option 5 for the wastestreams listed by the commenter) is 

evaporation. See Section VIII of the final preamble. 

For the reasons explained in Sections VIII.C and E of the final preamble, EPA selected Option D 

as the basis for BAT limitations and PSES in the final rule. Option D represents the same suite 

of BAT technologies for all wastestreams as Option F (including dry handling for control of fly 

ash transport water and FGMC wastewater discharges, as well as dry handling or closed-loop 

technologies for control of bottom ash transport water discharges) with the exception of the 

model technologies for controlling FGD wastewater and combustion residual leachate. EPA 

selected surface impoundments as the BAT basis for control of combustion residual leachate 

discharges rather than chemical precipitation for the reasons described in Section VIIIC.6 of the 

final preamble. Similarly, except for “small” and oil-fired generating units, EPA selected 

chemical precipitation plus biological treatment as the BAT basis for control of FGD wastewater 

discharges rather than evaporation for the reasons described in Section VIII.C.1 of the final 

preamble. EPA notes that as part of BAT for existing sources, the final rule establishes a 

voluntary incentives program for facilities that adopt process changes and controls that achieve 

limitations based on evaporation for FGD wastewater discharges. See preamble section 

VIII.C.13. Moreover, the new source standards (NSPS and PSNS) in the final rule are based on 

the Option F technologies.
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Finally, also see Sections VIII and XVI.A.1 of the preamble for a discussion of the timing of the 

applicability of the limitations and standards in the final rule.

Commenter Name: Jamie Rhodes

Commenter Affiliation: Environment Council of Rhode Island

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

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Our organizations urge EPA to select Option 5 for the final rule. Option 5 would eliminate 

almost all toxic discharges from power plants, reducing pollution by more than 5 billion 

pounds a year. Strong rules are urgently needed because Steam Electric Power Plants are 

responsible for at least 50 to 60 percent of the toxic pollutants discharged into waters of the U.S. 

- more than the other nine top polluting industries combined.1. Despite the scope of this pollution 

problem, the existing standards have not been updated since 1982 and fail to set discharge limits 

on a long list of dangerous pollutants toxic to humans and aquatic life, including arsenic, 

mercury, lead and selenium. According to EPA, this failure has led to over 160 water bodies not 

meeting state water quality standards, 185 waters with fish consumption advisories and the 

degradation of 399 water bodies across the country that are drinking water supplies.2

1EPA, Environmental Assessment for the Proposed Effluent Limitation Guidelines and Standards 

for the Steam Electric Power Generating Point Source Category 3-14 (April 2013)

2

http://water.epa.gov/scitech/wastetech/guide/steam-electric/proposed.cfm

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Based on public comments, EPA revised its estimates of water bodies not meeting state water 

quality standards, fish consumption advisories and the degradation of water bodies across the 

country that are drinking water supplies. See the Environmental Assessment for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category (EA Report) (DCN SE04527).

Commenter Name: Jamie Rhodes

Commenter Affiliation: Environment Council of Rhode Island
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Document Control Number: EPA-HQ-OW-2009-0819-4034-A2

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Our organizations urge the Agency to move forward with Option 5, which would require 

power plants to control all of their pollution, not just some of it. EPA has proposed eight 

regulatory options, four of which are “preferred.” Yet none of the Agency’s “preferred” 

regulatory options are adequate to address this widespread pollution problem. The most stringent 

“preferred” option proposed by EPA (option 4a) would eliminate only 2.62 billion pounds of 

pollution – roughly less than half of all the annual pollution loading from power plants5. In 

contrast, Option 5, though not preferred by the Agency, would eliminate 96% of all pollution 

from power plants, cutting an estimated 5.3 billion pounds a year.6 For decades, the power plant 

industry has been given a free pass to dump their toxic wastewater into our rivers, lakes, streams 

and bays, but EPA’s analysis of Option 5 demonstrates that we can virtually eliminate this 

predominant source of toxic pollution to our waters using technologies that are readily available 

and affordable to the industry.

5

78 Fed. Reg. at 34,485- 34,486 (Table IX-4)

6

Id.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Jamie Rhodes

Commenter Affiliation: Environment Council of Rhode Island

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

Comment Excerpt Number: 14

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Our organizations urge EPA to move swiftly to finalize Option 5, which would eliminate billions 

of tons of pollution a year, resulting in thousands of river miles that are safer to swim and fish in, 

and thousands of miles of cleaner drinking water sources.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Commenter Name: Miyoko Sakashita

Commenter Affiliation: Center for Biological Diversity

Document Control Number: EPA-HQ-OW-2009-0819-4178-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We support the proposed rule because it contains much-needed revisions to the 1982 effluent 

limitations that will stem the toxic pollutants in wastewater streams from power plants. Power 

plant water pollution impairs our nation’s waters and threatens public health and wildlife. The 

long-awaited effluent limitations are a significant step forward in regulating toxic wastewater 

streams of mercury, arsenic, lead, and selenium from power plants. We urge EPA to select 

Option 5, which is the most comprehensive regulation and would significantly eliminate toxic 

discharges from power plants. We support Option 5 because it requires “zero discharge” of fly 

ash and bottom ash wastewater for all power plants, and it requires chemical precipitation and 

evaporation to treat Flue Gas Desulfurization (“FGD”) wastewater. EPA should finalize the 

most protective rule — Option 5 — and implement it promptly when finalized because delay 

will undermine the effectiveness of the regulation in protecting water quality and safety.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Commenter Name: Eugenia Marks, Senior Director of Policy, Audubon

Commenter Affiliation: Audubon Society of Rhode Island

Document Control Number: EPA-HQ-OW-2009-0819-4245-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We urge EPA to select Option 5 for the final rule. Option 5 would eliminate almost all toxic 

discharges from power plants, reducing pollution by more than 5 billion pounds a year. Strong 

rules are urgently needed because Steam Electric Power Plants are responsible for at least 50 to 

60 percent of the toxic pollutants discharged into waters of the U.S. - more than the other nine 

top polluting industries combined.[1] The existing standards have not been updated since 1982 

and fail to set discharge limits on a long list of dangerous pollutants toxic to humans and aquatic 
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life, including arsenic, mercury, lead and selenium. According to EPA, this failure has led to 

over 160 water bodies not meeting state water quality standards, 185 waters with fish 

consumption advisories and the degradation of 399 water bodies across the country that are 

drinking water supplies.

We ask that EPA provide stringent standards to achieve safe water for people and aquatic life by 

adopting Option 5 as the final rule.

[1] EPA, Environmental Assessment for the Proposed Effluent Limitation Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category 3-14 (April 2013)

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Based on public comments, EPA revised its estimates of water bodies not meeting state water 

quality standards, fish consumption advisories and the degradation of water bodies across the 

country that are drinking water supplies. See the Environmental Assessment for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category (EA Report) (DCN SE04527).

Commenter Name: D. Kuck

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4413-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Environmental Protection Agency (EPA) must finalize the strongest of the proposed 

standards for power plant water pollution in order to protect our waterways and ensure human 

safety.

I am a Health Professional - a veterinarian. My task is to protect the Public Health through 

ensuring safe food and drink. My job description is very similar to that of the EPA. It is clear to 

me that unsafe water that is filled with chemicals is a direct threat to PEOPLE, PETS, 

LIVESTOCK as well as all the other creatures and plants dependent upon water.

The Clean Water Act mandates that EPA require dischargers to use the best available technology 

to reduce or eliminate their water pollution. For decades, the coal industry has been allowed to 

dump millions of pounds of toxic waste into our rivers and streams without limit, and EPA now 
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has the opportunity to create new standards that will protect people and the environment from 

this dangerous pollution.

The best option proposed by EPA is for power plants to install zero liquid discharge technology 

and convert to safer coal ash handling systems that will eliminate discharges of the most 

contaminated wastewaters entirely. The proposed regulation includes less stringent standards that 

would fall short of what the Clean Water Act requires and would not go far enough to clean up 

this toxic pollution. Only by enacting the toughest standards proposed will EPA fulfill its duty to 

protect people and the environment.

Comment Response: 

EPA notes that it did not propose “zero liquid discharge technology” as the technology basis for 

the control of any discharges, including discharges of FGD wastewater. EPA assumes the 

commenter is referring to evaporation as the technology basis for control of FGD wastewater 

discharges, which was included in proposed Option 5, because it refers to the “strongest of the 

proposed standards for power plant water pollution.”

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Also, EPA notes the final rule establishes limitations and standards applicable to the discharge of 

pollutants from the steam electric power generating industry. The rule does not require the use 

of any particular technology or practice to meet the final limitations and standards, and plants are 

free to meet the limitations and standards using any technology or practice they choose.

Commenter Name: Nadia L. Luhr

Commenter Affiliation: North Carolina Conservation Network (NCCN)

Document Control Number: EPA-HQ-OW-2009-0819-4480-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

According to data reported by the EPA, steam electric power plants contribute more than half of 

the toxic pollutants discharged to water bodies by all industrial categories currently regulated 

under the Clean Water Act. Effluent limitation guidelines for steam electric power plants were 

last updated in 1982, and significant industry changes and technology improvements over the last 

three decades necessitate the adoption of stronger, more modern regulations.

We appreciate that the EPA is updating the effluent limitation guidelines, and as discussed in 

more detail below, the NC Conservation Network strongly urges the EPA to select Option 5 for 

the final rule. Option 5 would eliminate almost all toxic discharges, reducing pollution by more 

than 5 billion pounds each year and greatly benefiting public health and natural resources.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Based on public comments, EPA revised its estimates of water bodies not meeting state water 

quality standards, fish consumption advisories and the degradation of water bodies across the 

country that are drinking water supplies. See the Environmental Assessment for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category (EA Report) (DCN SE04527).

Commenter Name: Nadia L. Luhr

Commenter Affiliation: North Carolina Conservation Network (NCCN)

Document Control Number: EPA-HQ-OW-2009-0819-4480-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We Strongly Urge the EPA to Select Option 5 for the Final Rule

The EPA has proposed eight regulatory options of varying stringency. Option 5 would establish 

the strongest ELGs for steam electric power plants, and the EPA has estimated that Option 5 

would eliminate 96 percent of all pollutant discharges from power plants—approximately 5.3 

billion pounds each year.5In comparison, the EPA’s preferred option, Option 4a, would 

eliminate only 2.62 billion pounds of pollution each year.6 As stated in the proposed rule, 

“Option 5 would remove the most pollutants from steam electric power plant discharges.”7

Under the CWA, the Best Available Technology (“BAT”) standards that EPA is proposing to set 

for fly ash transport water, bottom ash transport water, and scrubber waste (“FGD waste”) must 

represent the best available technology that is economically achievable.8 A technology is 

“available” if it is in use in the industry, even if it is not widely used.9 Option 5 would require 

dry handling of fly ash, which has been a requirement for new power plants since 1982; it would 

require dry handling or closed-loop unit systems for bottom ash, which are already widely 

implemented by approximately 42 percent of existing facilities; and it would require chemical 

precipitation and vapor evaporation for the treatment of FGD wastewater— technology that has 

been used in at least one facility and is being considered for others.

In addition to being available, these technologies are economically achievable. A technology is 

economically achievable if the costs can be reasonably borne by the industry as a whole.10 If 

Option 5 were adopted, the vast majority of plants would incur costs of less than 1 percent of 

annual revenue. 798 facilities, approximately 75 percent of facilities under these rules, would see 

a cost-to-revenue ratio of zero percent.
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--

The ELGs proposed under Option 5 represent the best available technology that is economically 

achievable, and reflects technology that has already been adopted widely by a large number of 

facilities across the country. Promulgation of these rules would reduce pollution by more than 5 

billion pounds each year and greatly benefit the public health and natural resources. We strongly 

urge the EPA to move forward with the adoption of Option 5 in furtherance of its responsibility 

to protect the nation’s waterways and public health.

5

Id. at 34,485-34,486 (Table IX-4).

6

Id.

7

Id. at 34,473.

8

33 U.S.C. 1311(b)(2)(A).

9 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”).

10 Waterkeeper Alliance v. U.S. EPA, 399 F.3d 486, 516 (2d Cir. 2005).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. EPA determined, 

in accordance with the Clean Water Act, that the technologies that form the bases for the final 

rule are available and that the final rule is economically achievable for the industry as a whole, 

with acceptable non-water quality environmental impacts, as explained in preamble Section 

VIII. 

For the final rule, EPA updated its estimates of the number plants that already have or will have 

in the near future technologies in place that would enable them to meet zero discharge limitations 

and standards applicable to bottom ash transport water discharges. See the preamble.

Regarding EPA’s decision not to establish BAT limitations based on proposed Option 5 (Option 

F), see preamble Section VIII and response to DCN-EPA-HQ-OW-2009-0819-4684-A1, Excerpt 

Number 216 in comment code 28b.

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: 20

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The electricity sector’s drain on water resources and the associated risks are undeniable. Thus, 

EPA must implement regulations that work to alleviate the mounting water stresses across the 

nation caused by electric power plants’ dependency on water. We urge EPA to select Option 5, 

or at minimum Option 4, as its final rule, because in addition to eliminating almost all of the 

toxic pollutants discharged from power plants36, it would also yield the greatest reductions in 

water use. EPA is obligated to implement the most environmentally protective regulatory 

measure that is economically achievable for industry. Options 4 and 5 are the only regulatory 

alternatives that would allow EPA to fulfill its mandate under the CWA.

36 ELGs at 34,485–34,486 (Table IX-4).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. EPA also notes 

that the suite of technologies represented by proposed Option 4, cited by the commenter, is 

substantially similar to the suite of technologies represented by Option D in the final rule. See 

preamble section VIII for a description of the options.

Also see the preamble for estimates of reduced water withdrawals associated with the final rule.

Commenter Name: S. Hart

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4493

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Having grown up in a large city with public water that smelled of chemicals and we chose not to 

drink, I truly recognize what a blessing the land and resources of this area are. This is why I am 

writing to not only urge, but beg the EPA to issue strong rules to protect our water from being 

poisoned by toxic pollution from coal fired power plants. I strongly support any option that will 

require Duke energy to to stop storing coal ash, and what ever other waste is produced in leaky, 

under-regulated Impoundments. To use the best available biological and chemical treatments 

available on ALL of their wastewater, and to use evaporation treatment for sludge waste from air 

pollution scrubbers.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Also, EPA notes the final rule establishes limitations and standards on wastewater discharges 

from the steam electric power generating industry under the Clean Water Act and not 

requirements for management of coal ash surface impoundments. Thus, comments related to 

“storing coal ash” are outside the scope of this final rule.

Commenter Name: P. Ciaffone

Commenter Affiliation: Appalachian Voices

Document Control Number: EPA-HQ-OW-2009-0819-4494

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I encourage you to require the best technology, including zero-waste, to minimize the amount of 

waste product that leads to huge wet impoundments that are causing harm to our environment 

and health.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Commenter Name: B. Hart

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4496

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I support any option that will require Duke Energy and other utilities to stop storing waste in 

leaky impoundments, to use the best biological and chemical treatments available on all of their 

wastewater and to use evaporation treatment for sludge waste from air pollution scrubbers.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 
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Also, EPA notes the final rule establishes limitations and standards on wastewater discharges 

from the steam electric power generating industry under the Clean Water Act and not 

requirements for management of coal ash surface impoundments. Thus, comments related to 

“storing waste” are outside the scope of this final rule. 

Commenter Name: C. Lish

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4498-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I strongly urge the Environmental Protection Agency (EPA) to finalize zero-discharge water 

pollution standards to limit the amount of toxic metals that can be dumped into our waters from 

power plants.

“Our duty to the whole, including to the unborn generations, bids us to restrain an unprincipled 

present-day minority from wasting the heritage of these unborn generations. The movement for 

the conservation of wildlife and the larger movement for the conservation of all our natural 

resources are essentially democratic in spirit, purpose and method.”

-- Theodore Roosevelt

Power plants should be required to use the best available technology to reduce the most amount 

of pollution. Every year, these plants dump billions of pounds of arsenic, lead, mercury and 

selenium into surface waters. It’s time to end this reckless practice. Existing technology can 

easily solve this problem and should be employed.

“As we peer into society's future, we—you and I, and our government—must avoid the impulse 

to live only for today, plundering for our own ease and convenience the precious resources of 

tomorrow. We cannot mortgage the material assets of our grandchildren without risking the loss 

also of their political and spiritual heritage. We want democracy to survive for all generations to 

come, not to become the insolvent phantom of tomorrow.”

-- Dwight D. Eisenhower

I support the proposed option that would require power plants to “dry handle” waste from both 

fly and bottom ash ponds and to use evaporation treatment for Flue gas desulfurization scrubber 

sludge waste. By requiring coal plants to move hazardous coal ash with dry systems, rather than 

with water, the EPA can eliminate millions of gallons of dangerous ash wastewater every year. 

Smokestack scrubber sludge can also be treated using zero-discharge systems, and certainly 
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requires at least biological and chemical treatment to remove toxic heavy metals like selenium, 

arsenic, mercury, and lead.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Becky Smith

Commenter Affiliation: Clean Water Action et al.

Document Control Number: EPA-HQ-OW-2009-0819-4548-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Our organizations urge EPA to select Option 5 for the final rule. Option 5 would eliminate 

almost all toxic discharges from power plants, reducing pollution by more than 5 billion pounds 

a year. Strong rules are urgently needed because Steam Electric Power Plants are responsible for 

at least 50 to 60 percent of the toxic pollutants discharged into waters of the U.S. - more than the 

other nine top polluting industries combined.1 Despite the scope of this pollution problem, the 

existing standards have not been updated since 1982 and fail to set discharge limits on a long list 

of dangerous pollutants toxic to humans and aquatic life, including arsenic, mercury, lead and 

selenium. According to EPA, this failure has led to over 160 water bodies not meeting state 

water quality standards, 185 waters with fish consumption advisories and the degradation of 399 

water bodies across the country that are drinking water supplies.2

1 EPA, Environmental Assessment for the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category 3-14 (April 2013)

2

http://water.epa.gov/scitech/wastetech/guide/steam-electric/proposed.cfm

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Based on public comments, EPA revised its estimates of water bodies not meeting state water 

quality standards, fish consumption advisories and the degradation of water bodies across the 

country that are drinking water supplies. See the Environmental Assessment for the Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category (EA Report) (DCN SE04527).
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Commenter Name: Becky Smith

Commenter Affiliation: Clean Water Action et al.

Document Control Number: EPA-HQ-OW-2009-0819-4548-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA has an obligation under the Clean Water Act to end this reckless practice. Our organizations 

urge the Agency to move forward with Option 5, which would require power plants to control all 

of their pollution, not just some of it. EPA has proposed eight regulatory options, four of which 

are “preferred.” Yet none of the Agency’s “preferred” regulatory options are adequate to address 

this widespread pollution problem. The most stringent “preferred” option proposed by EPA 

(option 4a) would eliminate only 2.62 billion pounds of pollution – roughly less than half of all 

the annual pollution loading from power plants5. In contrast, Option 5, though not preferred by 

the Agency, would eliminate 96% of all pollution from power plants, cutting an estimated 5.3 

billion pounds a year.6 For decades, the power plant industry has been given a free pass to dump 

their toxic wastewater into our rivers, lakes, streams and bays, but EPA’s analysis of Option 5 

demonstrates that we can virtually eliminate this predominant source of toxic pollution to our 

waters using technologies that are readily available and affordable to the industry.

5

78 Fed. Reg. at 34,485- 34,486 (Table IX-4)

6

Id.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Becky Smith

Commenter Affiliation: Clean Water Action et al.

Document Control Number: EPA-HQ-OW-2009-0819-4548-A1

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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When considering costs, the Clean Water Act allows EPA to evaluate whether costs can be 

reasonably borne by the industry as a whole.13 EPA acknowledges in its proposal that Option 5 

would by far remove the largest amount of pollutants from power plant discharges, resulting in 

the greatest benefit to public health and the environment.14 And EPA has estimated that most 

utilities would only incur costs of less than 1% of annual revenue.15 Yet the Agency claims it 

did not select Option 5 as a “preferred” option because of concern that it is too expensive when 

compared with the other options. Clearly this industry can bear the comparatively small cost to 

comply with requirements mandated by the Clean Water Act to clean up their toxic 

discharges. Society has been unfairly forced to bear the cost of these discharges for decades.

13 See Waterkeeper Alliance v. U.S. EPA, 399 F.3d 486, 516 (2d Cir. 2005) and Rybachek v. 

U.S. EPA, 904 F. 2d 1276, 1290-91 (9th Cir. 1990)

14 Id. at 34,473

15 Id. at 34,494 (Table XI-4); 34,493

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. As explained in 

preamble Section VIII, EPA determined that the final rule is affordable for the industry as a 

whole.

With respect to EPA’s rationale for rejecting Option F as the basis for the final BAT limitations 

applicable to all existing steam electric power generating units, see preamble Section VIII.C.1 

and response to DCN-EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 216, in comment 

code 28b.

Commenter Name: M. E. Schultz

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4622-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I live in Texas, a state with a big number of coal-fired power plants. for decades these plants, 

with other chemical factories, have made Texas the worst air polluter in the country. It is an 

established fact that the Texas Commission for Environmental Quality (TCEQ) has and will 

continue to protect polluting industries and does all it can to resist EPA standards enforcement. It 

is a tragedy that workers who of necessity live near these coal fired plants, must continue to 
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submit to the chronic illness and early death of their family members, because of deadly 

ingestion of toxins in their water and air. WE TEXANS DEPEND ON THE EPA to make and 

enforce the strongest possible standards on these coal-fired power plants.

The best option proposed by EPA is for power plants to install zero liquid discharge technology 

and convert to safer coal ash handling systems that will eliminate discharges of the most 

contaminated wastewaters entirely. The proposed regulation includes less stringent standards that 

would fall short of what the Clean Water Act requires and would not go far enough to clean up 

this toxic pollution. Only by enacting the toughest standards proposed will EPA fulfill its duty to 

protect people and the environment.

Comment Response: 

EPA notes that it did not propose “zero liquid discharge technology” as the technology basis for 

the control of any discharges, including discharges of FGD wastewater. EPA assumes the 

commenter is referring to evaporation as the technology basis for control of FGD wastewater 

discharges, which was included in proposed Option 5.

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

EPA notes the final rule establishes limitations and standards applicable to the discharge of 

pollutants from the steam electric power generating industry. The final rule does not require the 

use of any particular technology or practice to meet the final limitations and standards, and plants 

are free to meet the limitations and standards using any technology or practice they choose.

Commenter Name: Pamela Ritger

Commenter Affiliation: Clean Wisconsin

Document Control Number: EPA-HQ-OW-2009-0819-4632-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Clean Wisconsin has reviewed EPA’s proposal and is disappointed that Option 5, the option that 

would eliminate almost all toxic discharges and reduce pollution by more than 5 billion pounds 

per year, is no longer a preferred alternative being considered for adoption.5In the absence of 

Option 5, Clean Wisconsin insists that the EPA adopt the most stringent option still under 

consideration, Option 4a.

5 Environmental Integrity Project et al., Closing the Floodgates: How the Coal Industry Is 

Poisoning Our Water and How We Can Stop It, p. 2 (July 2013). Available
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at http://www.environmentalintegrity.org/news_reports/documents/2013_07_23_ClosingTheFlo

odgates-Final.pdf

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Jeff Stant, Patricia Schuba and Rae Schnapp

Commenter Affiliation: Citizens Coal Council and the Wabash Riverkeeper

Document Control Number: EPA-HQ-OW-2009-0819-4657-A7

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We have collected information via government documents and databases that support a 

reasonable level of concern for the health and well-being of citizens in the path of migrating 

toxins that warrant the most prudent option, Option 5, under the Steam Electric Power 

Generating Effluents Guidelines Rule.

These examples show how communities, businesses and farmers are endangered by the lax 

regulations that allow utilities to continue to store toxins in ponds, sitting unlined in floodplains, 

discharging to bodies of water while technologies exist that could eliminate all discharges and 

recycle all wastes and ensure that all toxins are kept out of floodplains and surface waters.

Thank you for considering our comments in proposing the strongest rule possible to control the 

handling of coal ash waste water. We propose that the EPA issue a zero discharge ELG Rule.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Juliet Cohen

Commenter Affiliation: Chattahoochee Riverkeeper

Document Control Number: EPA-HQ-OW-2009-0819-4671-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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There are three power generation plants on the Chattahoochee River: (1) Plant McDonough 

(Cobb County) (recently converted from coal combustion to natural gas, but there still remain 

ash ponds on site); (2) Plant Wansley (Heard and Carroll Counties); and (3) Plant Yates (Coweta 

County).

Steam electric power plants contribute 50-60 percent of all toxic pollutants discharged to surface 

waters by all industrial categories regulated in the United States under the Clean Water Act. 

CRK strongly urges the EPA to adopt Option 5 as the final rule because, as stated in the public 

notice, Option 5 would remove the most pollutants from steam electric power plant discharges. 

Also, the technologies identified in Option 5 are potentially available and may be appropriate 

depending on the specific situations as the basis for water quality-based effluent limits in NPDES 

permits.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

EPA agrees with the commenter that “the technologies identified in Option 5 are potentially 

available and may be appropriate depending on the specific situations as the basis for water 

quality-based effluent limits in NPDES permits.” See preamble section XVI.E.

Commenter Name: Juliet Cohen

Commenter Affiliation: Chattahoochee Riverkeeper

Document Control Number: EPA-HQ-OW-2009-0819-4671-A2

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We strongly urge the EPA to adopt Option 5 as the final rule, the most environmentally 

protective regulation for steam electric generation plants.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Deanna White

Commenter Affiliation: Clean Water Action - Minnesota et al.

Document Control Number: EPA-HQ-OW-2009-0819-4681-A2

Comment Excerpt Number: 2
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA has proposed eight regulatory options, four of which are "preferred." We are concerned that 

none of the Agency’s "preferred" regulatory options are adequate to address this widespread 

pollution problem. The most stringent "preferred" option proposed by EPA (option 4a) would 

eliminate only 2.62 billion pounds of pollution – roughly less than half of all the annual pollution 

loading from power plants. In contrast, Option 5, though not preferred by the Agency, would 

eliminate 96% of all pollution from power plants, cutting an estimated 5.3 billion pounds a year. 

For decades, the power plant industry has essentially been given an unlimited permit to dump 

their toxic wastewater into our rivers, lakes, streams and bays. EPA has an opportunity to end 

this reckless practice and our organizations urge the Agency to move forward with Option 

5, which would require power plants to control all of their pollution, not just some of it. 

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 15

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA Must Select Option 5 for New Source Performance Standards. The Clean Water Act 

requires EPA to set and revise New Source Performance Standards (NSPS) for new sources that 

“reflect[] the greatest degree of effluent reduction achievable” through Best Available 

Demonstrated Control Technology, a standard that is even more stringent than BAT. EPA 

improperly rejected Option 5 for new sources without applying the correct legal standard, which 

is whether the costs of Option 5 can be reasonably borne by the industry.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.
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Document Control Number: EPA-HQ-OW-2009-0819-4684-A1

Comment Excerpt Number: 149

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

VIII. BADCT FOR NEW SOURCES IS OPTION 5.

The Clean Water Act requires EPA to set and revise New Source Performance Standards (NSPS) 

for new sources that “reflect[] the greatest degree of effluent reduction achievable through 

application of the best available demonstrated control technology, processes, operating methods, 

or other alternatives, including, where practicable, a standard permitting no discharge of 

pollutants” or BADCT.622 BADCT is the most stringent standard for control of discharges. As 

EPA notes, “Congress envisioned that new sources could meet tighter controls than existing 

sources because of the opportunity to incorporate the most efficient processes and treatment 

systems 

into the facility design.”623 In this case, EPA expressly noted that all of the treatment technologie

s identified in Option 5 are technologically available, and the record supports this 

determination.624 EPA improperly rejected Option 5 for NSPS solely because of higher costs 

associated with evaporation systems for FGD wastewater.625

EPA is required to “take into consideration the cost of achieving such effluent reduction, and any 

non-water quality environmental impact and energy requirements.”626 As 

courts have recognized, the language related to consideration of costs in section 306 is “virtually 

identical” to the language in in section 304(b)(2)(B) for existing sources.627 Similar to the 

relevant cost inquiry for BAT determinations,

[t]here is no language in s[section] 306 requiring a cost-benefit analysis. Rather, the EPA is 

required only to take costs under “consideration.” We conclude, therefore, that a cost-benefit 

analysis is not required in determining the reasonableness of the cost of achieving the new source 

standards. What is required for new source standards is a thorough study of initial and annual

costs and an affirmative conclusion that these costs can be reasonably borne by the industry.628

Thus, the relevant inquiry for EPA when setting NSPS is whether the “costs can be reasonably 

borne by the industry” as a whole,629 and costs are “to be given even less weight under 

section 306 than for existing sources.”630

622 33 U.S.C. § 1316(a)(1).

623 TDD at 8-37.

624 TDD at 8-40.
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625 Id.

626 33 U.S.C. § 1316(b)(1)(B).

627 See, e.g., Am. Iron & Steel Inst. v. EPA, 526 F.2d 1027, 1059 (3d Cir. 1975).

628 CPC Int’l, Inc. v. Train, 540 F.2d 1329, 1341-42 (8th Cir. 1976) (internal citations 

omitted). See also Am. Iron & Steel Inst., 526 F.2d at 1059.

629 CPC Int’l, Inc., 540 F.2d at 1341-42 (internal citations omitted).

630 Am. Iron & Steel Inst., 526 F.2d at 1059.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

EPA notes that its decision to establish NSPS and PSNS based on the Option F technologies was 

not based on its analysis of the benefits associated with that option. Rather, EPA’s decisions on 

the final rule were based on the factors specified by Sections 301, 304, and 306 of the Clean 

Water Act. See EPA v. Nat’l Crushed Stone Ass’n, 449 U.S. 64, 70-71 (1980); Ass’n of Pac. 

Fisheries v. EPA, 615 F.2d 794, 818 (9th Cir. 1980); Am. Iron & Steel v. EPA, 526 F.2d 1027, 

1051-52, 1053 n.54 (3d Cir. 1975); Nat’l Ass’n of Metal Finishers v. EPA, 719 F.2d 624, 659 (3d 

Cir. 1983). While EPA conducted an assessment of benefits pursuant to Executive Order, the 

benefits analysis was not determinative in the options selected by EPA for the final rule.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 4

External Review Flag: Economics/Benefits

External Review Incorporated into Response: No

Comment Excerpt: 

Option 5 is BAT for the steam‐electric industry

The sole additional control technology found in Option 5 but not in Option 4—vapor‐

compression evaporation—makes Option 5 the most effective of all the proposed steam‐electric 

regulatory options at controlling the discharge of pollutants. Option 5 is technologically 

achievable; zero‐liquid discharge technologies are used to control similar pollutants in many 

other industries, in several steam‐electric plants in the United States, and in several more abroad.
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Option 5 is also economically achievable. EPA has not demonstrated that Option 5 would be a 

burden to the steam electric industry. The measures of economic achievability presented by EPA 

are deeply flawed; EPA itself states that the metric for which it presents an adverse result for 

Option 5—the cost‐ to‐revenue ratio—“does not generally indicate whether profitability is 

jeopardized, cash flow is affected, or risk of financial distress is increased.” Option 5’s cost‐

effectiveness is within the bounds of those of approved ELGs (and is biased upward by the same 

faulty assumption used in the cost‐to‐revenue ratio), EPA presents no evidence of its plant 

closures, its household costs are negligible, and it results in an average annual increase of 2,112 

jobs.

Option 5 is BAT for the steam‐electric ELGs.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

With respect to EPA’s rationale for rejecting Option F as the basis for the final BAT limitations 

applicable to all existing steam electric power generating units, see preamble Section VIII.C.1 

and response to DCN-EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 216 in Comment 

Code 28.b.

EPA notes that it revised its costs and pollutant loadings estimates for the final rule, in response 

to public comments, and it thus it also revised its resulting “cost-effectiveness” (cost per toxic 

weighted pound of pollutant reductions) estimates. See preamble Section XV. 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: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 23

External Review Flag: Economics/Benefits

External Review Incorporated into Response: No

Comment Excerpt: 

The selection of Option 5 would require an additional improvement to controls: a vapor‐

compression evaporation system for FGD wastewater:

This type of system uses a falling‐film evaporator (or brine concentrator) to produce a 

concentrated wastewater stream and a distillate stream. With pretreatment, such as chemical 

precipitation and softening, brine concentrators can reduce wastewater volumes by 80 to 90 

percent. Plants can further process the concentrated wastewater stream in a crystallizer or spray 

dryer, which evaporates the remaining water to generate a solid waste product and potentially a 
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condensate stream. The distillate and condensate streams may be reused within the plant or 

discharged to surface waters. EPA identified two U.S. plants and four Italian plants that treat 

FGD wastewater using vapor‐compression evaporation. A third U.S. plant is currently installing 

a vapor‐ compression evaporation treatment system; it is scheduled to be operational by the end 

of 2013.128

As shown in Table 10, this single change limits the release of arsenic, mercury and selenium into 

public waterways. EPA explains that:

Physical/chemical treatment systems can achieve low effluent concentrations for a number of 

pollutants, and reduce concentrations even further when combined with biological treatments 

systems...However, these technologies have not been effective at removing substantial amounts 

of boron and pollutants that contribute to high concentrations of [Total Dissolved Solids]. 

[Vapor‐compression evaporation] can address these recalcitrant pollutants...129

The requirement of vapor‐compression evaporation for biological treatment of FGD wastewater 

represents the only difference between Options 4 and 5. Option 5’s additional pollutant 

removals, therefore, are the result of vapor‐compression evaporation and result in greater 

stringency than any of the other regulatory options. Option 5 removes far more pollutants than 

Option 4—8,201 million versus 7,831 million lb‐eq per year, respectively (see Table 10 above). 

Option 5’s total monetized benefits (excluding air‐related benefits), however, are slightly lower 

than those of Option 4—$434.1 million annualized versus $435.0 million in annualized terms 

(see Table 8). EPA offers an explanation for this result, stating:

[U]nder Option 4, EPA assumes that plants with both leachate and FGD waste streams 

implement chemical precipitation and biological treatment for the combined streams. Under 

Option 5, EPA assumes that plants treat the two streams separately: FGD wastewater by 

evaporation and leachate using chemical precipitation (which removes less pollutant load than 

biological treatment).130

This methodological quirk does not, however, explain away the mismatch between toxic‐

weighted pollutants and monetized benefits; rather, it illustrates a deep flaw in EPA 

methodology. While the additional pollutants removed in Option 5 have a higher toxic weight, 

they are not readily quantified or monetized. EPA’s erroneously values the removal of those 

toxic pollutants at zero dollars.

Listed as the major capital cost components of vapor‐compression evaporation systems are water 

softeners, brine concentrators, and forced‐circulation crystallizers.131 The brine 

concentrator (sometimes called a falling‐film evaporator) and forced‐circulation crystallizer are 

used in sequence: The brine concentrator separates FGD wastewater—which has already 

completed a chemical precipitation process—in brine and distillate; a forced‐circulation 

crystallizer (or other similar process, e.g., a spray dryer) then separates the brine concentrator 

distillate then passes into solid waste and a liquid condensate.132

The distillate and condensate may either be reused within the plant—in which case, the vapor‐

compression evaporation system results in “zero liquid discharge” from the FGD scrubber—or 
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may be released into surface waters or public water treatment works. Option 5 would regulate the 

latter; curiously, the former treatment of FGD wastewaters, zero liquid discharge, is not included 

among the regulatory options presented by EPA.

Effluent limitations for Option 5 are set based on a weighted average of brine concentrator 

distillate and crystallizer condensate measurements sampled from a single Italian plant that 

appears to follow a zero liquid discharge protocol:

For the treatment of FGD wastewater using chemical precipitation followed by a vapor‐

compression evaporation system, hereafter referred to as a “vapor‐compression evaporation” 

system (which is the technology serving as the basis for Regulatory Option 5), EPA evaluated 

three systems as part of the EPA sampling program. One plant operates a system that is similar to 

the technology basis for the FGD wastewater limitations in the proposed rule: a one‐stage 

chemical precipitation system followed by softening and a vapor‐compression evaporation 

system. EPA used the data from this plant to develop the limitations based on the vapor‐

compression evaporation technology for the treatment of the FGD wastewater. That plant is 

Enel’s Federico II Power Plant, located in Brindisi, Italy (hereafter referred to as Brindisi). EPA 

used data from a second plant for characterization purposes and not for limitations development 

because it only collected effluent data for one day from the plant. The third system does not 

represent the technology serving as the basis for the vapor‐compression evaporation option, and 

was not used for the limitations development. This plant operates a solids removal process prior 

to the vapor‐compression evaporation system but includes neither a full chemical precipitation 

system nor a softening step. Furthermore, this plant also operates a one‐stage evaporation system 

and instead of employing a second stage of evaporation to crystallize and remove salts and other 

pollutants from the concentration brine, mixes the brine with fly ash and sends it to the landfill 

for disposal.133

128 Id. at 34,452.

129 78 Fed. Reg. at 34,460.

130 78 Fed. Reg. at 34,518, Table XIV‐8

131 Id. at 34,482.

132 Technical Development Document, pp.3‐13 and 3‐14

133 Technical Development Document, p.13‐5; see also 78 Fed. Reg. at 34,490, Table X‐1; 

Technical Development Document Section 3.4.1; and DCN SE02002 sampling data for 

limits.xlsx.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.
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See Section VIII of the final preamble for updated information on U.S. plants known to EPA that 

are using evaporation.

EPA notes that it revised its costs and pollutant loadings estimates for the final rule, in response 

to public comments. See the TDD and RIA.

The commenter questions EPA’s benefits analysis for a regulatory option that includes BAT 

limitations based on evaporation for control of FGD wastewater discharges. EPA notes that it 

also revised its benefits analysis for the final rule in response to public comments. See the 

RIA. In addition, EPA notes that, during development of the final rule, EPA decided not to base 

the final rule on Option F for the reasons stated in preamble section VIII. As a result, EPA chose 

not to conduct particular analyses for Option F to the same extent that it did for some of the other 

regulatory options considered.

While the Agency considers cost-effectiveness and benefit-cost analysis as informative in the 

ELG rulemaking process, and it is something that is done for the final rule pursuant to Executive 

Order, EPA based the final rule on factors that the Clean Water Act (sections 301, 304, and 306) 

expressly directs EPA to consider when establishing Best Available Technology Economically 

Achievable (see preamble section VIII), not on its benefits analysis. For the role of cost-benefit 

in establishing BAT under the Clean Water Act, see response to DCN EPA-HQ-OW-2009-0819-

4464-A1, Excerpt Number 3, in comment code 6.h. As a result, EPA did not perform costeffectiveness or benefit-cost analyses for Option F for the final rule. With respect to the 

commenter’s statements about monetized benefits for Option 5, see response to DCN EPA-HQOW-2009-0819-4724-A2, Excerpt Number 1.

For a description of how EPA developed limitations and standards for FGD wastewater based on 

evaporation in the final rule, see Section 13 of the TDD.

The commenter suggests that EPA failed to consider “zero liquid discharge” requirements for 

FGD wastewater, based on evaporation technology, for the final rule. EPA is aware that some 

plants achieve zero pollutant discharge from the FGD scrubber to surface waters or POTWs and 

EPA considered establishing zero pollutant discharge requirements based on evaporation for 

FGD wastewater. EPA is mindful of the CWA’s pollutant discharge elimination goal. At the 

same time, EPA recognizes the extensive changes in this industry, and it wants to provide 

flexibility to plants in managing their wastewater and operations, as well as preserve the ability 

of plants to retain existing approaches where it is consistent with the CWA’s goals. While EPA 

would not choose to promote these considerations where it resulted in no further progress toward

the pollutant discharge elimination goal of the Act, treatment by evaporation is widely known as 

one of the most effective technologies to remove an extensive array of pollutants from 

wastewaters resulting from various industrial operations, including FGD wastewater. EPA is also 

mindful of the significant incremental costs that plants incur to employ this technology in 

comparison to other FGD wastewater treatment technologies. See final preamble Section VIII. 

Therefore, EPA decided not to establish zero pollutant discharge limitations and standards based 

on evaporation for FGD wastewater.
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Commenter Name: CWA Mass Mail Campaign

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-4772-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Strongly support option 5.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2. 

Commenter Name: T. Williams

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5159-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I support option V. We should all clean our streams, rivers, bays of any harmful pollution. Take 

a stand like Boston did in Cleaning their harbor.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: J. Rivers

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5219-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

You need to finalize a strong standard to keep power plant pollution out of our water sources. 

Choose option 5.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: K. Brooks

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5385-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Please take a strong stance to protect our water by getting the strongest standards possible for 

power plant water pollution. Choose option 5!

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.

Commenter Name: M. Dave

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5422-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Choose Option 5.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2.
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6.i.iv. Support/oppose Options 4/5

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA should choose either Option 4 or Option 5. The Clean Water Act requires that EPA base 

these critical protections on the best available technology economically achievable to reduce or 

eliminate pollution. EPA's Options 4 and 5 identify a number of technologies that live up to the 

standard, including treatment systems such as dry ash handling and vapor compression 

evaporation that have the potential to completely eliminate toxic pollution from certain 

wastewater streams.

EPA has found that these stringent treatment options are available and cost effective, and there is 

no legal basis for EPA to require anything less than a strong rule that fully lives up to the Clean 

Water Act's requirements that pollution be eliminated wherever it is feasible to do so. EPA 

should choose Option 5.

Comment Response: 

Although EPA did not select the proposed Option 4 or 5 for the final rule, it sets zero discharge 

standards and rigorous treatment of toxic heavy metals, as described in preamble sections III and 

VIII. 

EPA notes that for the final rule it selected Regulatory Option D represents BAT because it is 

available, affordable to the industry as a whole, and has acceptable non-water quality 

environmental benefits. It is similar to proposed Option 4 except for combustion residual 

leachate and non-chemical metal cleaning wastes. See preamble section VIII for EPA’s rationale 

for the final requirements for combustion residual leachate and non-chemical metal cleaning 

wastes.

Regarding proposed Option 5, the difference between proposed Option 4 and 5, is that Option 5 

would have established chemical precipitation and evaporation as BAT for FGD wastewater. See 

preamble section VIII for EPA’s rationale for not selecting evaporation as BAT. Also, see 

responses to DCN EPA-HQ-OW-2009-0819-3698-A1, Excerpt Number 2, as well as other 

responses in Comment Code 6.i.iii.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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

Comment Excerpt Number: 37

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

This goes on and on, but I would conclude by saying that Options 4 or 5 of the proposed effluent 

guidelines are necessary to prevent the continuing poisoning of our waters. Anything less is 

unacceptable.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 58

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The NPDES permits that limit iron but not arsenic and selenium with these lakes, regulation has 

done nothing to inhibit the impact of these toxic, steeping, shorefront mounds, but with these 

effluent limit guidelines and specifically Steam Electric Regulatory Options 4 and 5 of the 

pretreatment standards, as long overdue as they are, the EPA can start to catch back up to its 

original mid 1980s NPDES goal of eliminating pollutant discharges. We need Option 4 or 5 at 

this point, given the decades of accumulation from unrestricted discharges.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

Commenter Name: Mary Anne Hitt

Commenter Affiliation: Sierra Club

Document Control Number: EPA-HQ-OW-2009-0819-3920-A27

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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Comment Excerpt: 

The Sierra Club calls on the EPA to adopt a standard that adequately protects public health and 

our waterways. That means a standard that requires dry handling of coal ash, moving away from 

settling ponds that do essentially nothing to treat the waste, and using best water treatment 

technologies for scrubber sludge and leachate. These are labeled options 4 and 5 in the proposed 

rule.

As you know, we have technologies available today- in use at some coal plants, as a matter of 

fact - that can treat this pollution at a modest cost. EPA has every reason to adopt a strong 

standard. But I understand you are under great pressure to adopt a weak and inadequate standard.

This is no surprise. As President Obama noted in his climate speech last month, this is the 

boilerplate reaction of polluters any time improved health and safety protections are proposed. 

As the President also noted, these gloom-and-doom scenarios never come to pass, industry 

adapts and evolves, and we all enjoy cleaner water and air. I implore you to stand firm and adopt 

a robust standard that will really protect our water, and our kids - after all, it might be a 

couple more decades before we get another chance.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

Commenter Name: Appalachian Voices

Commenter Affiliation: Appalachian Voices

Document Control Number: EPA-HQ-OW-2009-0819-4501-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For these and other reasons detailed below, we implore EPA to adopt either Option 4 or Option 

5 in drafting a final Effluents Limitations Guideline.

EPA Should Require Dry Handling of Fly Ash and Bottom Ash and Set Zero Discharge 

Limits for FGD and other CCR Waste Streams

The developments in North Carolina that support EPA adopting Option 4 or Option 5 include:

1. Recent studies by researchers at Duke University that demonstrate downstream water 

quality degradation from contaminants discharged into the French Broad River, Mountain 

Island Lake and other water bodies;
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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2. Recent discoveries of unpermitted seeps and multiple exceedances of groundwater 

standards at nearly every coal ash pond in the state;

3. Actions taken by the NC General Assembly that have devastated state regulators' ability 

and authority to implement, monitor and enforce water quality standards.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

Commenter Name: Beth L. McGee

Commenter Affiliation: Chesapeake Bay Foundation

Document Control Number: EPA-HQ-OW-2009-0819-4513-A2

Comment Excerpt Number: 4

External Review Flag: Envr Assess

External Review Incorporated into Response: No

Comment Excerpt: 

There are substantial ecological benefits of Option 4 and 5 compared to the other options.

We commend EPA for moving this regulation forward and urge you to adopt Option 4 or 5 as 

your preferred alternative.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Notwithstanding the weak options that EPA now puts forward as “preferred” options, EPA’s 

underlying record for this rulemaking provides detailed analysis confirming that coal plants can 

shift away from leaking and unsafe impoundments to better and safer pollution controls, such as 

those incorporated into Options 4 and 5.13 By transitioning to dry ash management systems and 

employing superior wastewater treatment technologies such as chemical precipitation, in 
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EPA’s Response to Public Comments

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combination with biological treatment or vapor compression, it is possible to reduce pollution 

from coal plants by billions of tons each year, even achieving zero liquid discharge.14

13 See, e.g., Technical Development Document for the Proposed Effluent Limitations Guidelines 

and Standards for the Steam Electric Power Generating Point Source Category at 7-1-7-48 (Apr. 

2013), Docket No. EPA-HQ-LW-2008-0819-2257, [hereinafter TDD].

14 78 Fed. Reg. at 34,485-34,486.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8. Also, see 

responses to Comment Code 6.i.iii.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 16

External Review Flag: Economics/Benefits

External Review Incorporated into Response: No

Comment Excerpt: 

The Costs of Options 4 and 5 Can Be Reasonably Borne by the Industry. When the correct 

legal standard is applied, EPA’s own analysis establishes that the cost of both Options 4 and 5 

can be reasonably borne by the industry, for both new and existing plants. EPA found, for all 

options in the rule, that “the entity-level compliance costs are low in comparison to the entitylevel revenues; very few entities are likely to face economic impacts at any level.”15 EPA’s 

decisions not to choose Options 4 and 5 appear to be influenced by cost-benefit analysis. The 

Clean Water Act and court decisions make clear that BAT limitations cannot be based on costbenefit analysis. Congress precluded EPA from relying on cost-benefit analysis to develop BAT 

limitations because of concerns that the data on benefits will not be as extensive or robust as the 

data on costs, and therefore cost-benefit comparisons will inevitably skewed toward prioritizing 

costs. This rulemaking bears out Congress’s concerns, since EPA’s cost-benefit analysis 

systematically overestimates costs and underestimates benefits.

15 RIA at 4-9.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8. EPA’s decision 

not to base the final rule on a regulatory Option identical to proposed Option 4 was not because 

EPA determined proposed Option 4 to be not affordable to the steam electric industry. As 

explained in the referenced response, EPA selected Regulatory Option D as BAT for the final 

rule. It is similar to proposed Option 4 except for combustion residual leachate and nonchemical metal cleaning wastes. See Section VIII of the preamble for EPA’s rationale for the 

final requirements for combustion residual leachate and non-chemical metal cleaning wastes.

Regarding proposed Option 5, the difference between proposed Option 4 and 5, is that Option 5 

would have established chemical precipitation and evaporation as BAT for FGD wastewater. See 

Section VIII of the final preamble for EPA’s rationale for not selecting evaporation as BAT. See 

preamble Section VIII for EPA’s rationale for not selecting chemical precipitation plus 

evaporation as the basis of BAT for FGD wastewater. Also, see response to DCN EPA-HQ-OW2009-0819-4684-A1, Excerpt Number 216 in Comment Code 26,b.

For the role of benefit-cost in EPA’s decisions for the final rule, see response to DCN EPA-HQOW-2009-0819-4464-A1, Excerpt Number 3 in Comment Code 6.e.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

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

Comment Excerpt Number: 46

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Notwithstanding the weak options that EPA now puts forward as “preferred” options, EPA’s 

underlying record for this rulemaking provides detailed analysis confirming that coal plants can 

make a shift away from leaking and unsafe impoundments to better and safer pollution controls, 

such as those incorporated into Options 4 and 5.128 By transitioning to dry ash management 

systems and employing superior wastewater treatment technologies such as chemical 

precipitation, in combination with biological treatment or vapor compression, it is possible to 

reduce pollution from coal plants by billions of tons each year, even achieving zero liquid 

discharge.129

128 See, e.g., TDD at 7-1-7-48.

129 78 Fed. Reg. at 34,485-34,486.

Comment Response: 
Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category:

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See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

EPA notes that the commenter supported regulatory options that include dry ash management 

systems and chemical precipitation in combination with biological treatment or vapor 

compression (evaporation). As explained in the referenced response, EPA selected regulatory 

Option D as the basis for the final BAT limitations. This option includes dry ash handling (or 

closed loop) for ash transport water and chemical precipitation in combination with biological 

treatment for FGD wastewater as advocated for by the commenter.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Economic screening analysis

The Clean Water Act establishes a simple, clear standard for the choice of pollution control 

technologies to be enforced by EPA: For each industry, the most stringent, but still 

technologically achievable, control measures are identified. These are the measures to be 

enforced, unless there is evidence that a particular technology will place a prohibitive burden on 

the industry as a whole. In the proposed steam‐ electric ELGs, this standard has been ignored. 

Control technologies were identified, sorted into eight regulatory options, and ordered in terms 

of their relative impact on controlling the discharge of pollutants. Regrettably, the two most 

stringent of these options were then eliminated from further consideration—that is, not 

designated as “preferred”—without EPA presenting evidence demonstrating that they were either 

technologically or economically unachievable.

Congress’ mandate to EPA in the Clean Water Act requires that pollution control technologies 

be eliminated from consideration for BAT only on grounds of:

1. Stringency: There are other more effective technologies for controlling the discharge of 

pollutants from a particular effluent stream.

2. Technological achievability: The proposed technology is not achievable (i.e. cannot be 

purchased or installed).

3. Economic achievability: The cost of proposed technology is, in EPA’s determination, an 

unreasonable burden to the industrial category as a whole (here, all steam electric 

generators other than oil‐fired generating units and generating units with capacities 50 

MW or smaller).
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4-531

EPA’s original proposal recommended Options 3 and 4 as preferred, and only performed its full 

economic analysis using the IPM model on those two options. The EPA proposal found Options 

1 and 2 to be too lax—“neither option would represent the best available technology level for 

steam electric power plant discharges”—and rejected Option 5 even though “without question, 

Option 5 would remove the most pollutants from steam electric power plant discharges.” EPA’s 

elimination of Option 5 from consideration for this rulemaking was made on economic grounds: 

“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.”

Option 4 should be among EPA’s preferred options

Control technologies for Option 4—dry handling of bottom ash transport water for units with 

capacities 400 MW or smaller, and chemical precipitation of combustion residual leachate—are 

more effective at controlling the discharge of pollutants than are the Options selected by EPA as 

preferred. These control technologies are also—as documented by EPA in this rulemaking—

technologically achievable.

Furthermore, EPA itself describes Option 4 for as “economically achievable” and fails to make a 

case that it would be a burden to industry. EPA’s rationale for eliminating Option 4 from 

consideration is based entirely on a subcategorization of the steam‐electric industry that has not 

been appropriately justified in this docket.

Comment Response: 

See responses DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 16 and DCN EPAHQ-OW-2009-0819-4684-A1, Excerpt Number 46.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 18

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The Clean Water Act establishes a simple, clear standard for the choice of pollution control 

technologies to be enforced by EPA: For each industry, the most stringent, but still 

technologically achievable, control measures are identified. These are the measures to be 

enforced, unless there is evidence that a particular technology will place a prohibitive burden on 

the industry as a whole. In the proposed steam‐ electric ELGs, this standard has been ignored. 

Control technologies were identified, sorted into eight regulatory options, and ordered in terms 

of their relative impact on controlling the discharge of pollutants. Regrettably, the two most 
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EPA’s Response to Public Comments

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stringent of these options were then eliminated from further consideration—that is, not 

designated as “preferred”—without EPA presenting evidence demonstrating that they were either 

technologically or economically unachievable.

EPA’s eight regulatory options for its effluent limitations guidelines and standards for steam 

electric power generators are shown above in Table 2.104 Options 1, 2, 3, 4, and 5 were 

introduced in EPA’s original proposal;105 Options 3a, 3b, and 4a were introduced by the Office 

of Management and Budget (OMB) in its review of the proposal.106 Options described in bold 

text below are those designated by OMB as preferred, and, therefore, presented in more detail in 

the Federal Register (see also Table 2 above).

Option 1 differs from current EPA regulations by requiring chemical precipitation for FGD 

wastewater, but it would allow status quo practices (such as use of unlined impoundments) to 

continue for fly ash and bottom ash transport water. As with all eight proposed versions of the 

regulation, Option 1 also requires vapor‐compression evaporation for gasification wastewater 

and chemical precipitation for nonchemical metal cleaning wastewater.

Option 2 is identical to Option 1, with a single exception: Option 2 requires biological treatment, 

in addition to chemical precipitation, for FGD wastewater.

Option 3 adds zero‐discharge dry handling for fly ash transport water and flue gas 

mercury control wastewater to Option 2’s chemical precipitation and biological treatment 

for FGD wastewater.

Option 3a (introduced by OMB) is a weakened version of Option 3: controls for FGD 

wastewater would be determined on a case by case basis by permitting authorities using 

“best professional judgment.”

Option 3b (introduced by OMB) is an alternative weakening of Option 3: for FGD 

wastewater, the requirement of chemical precipitation is consistent with Option 3, but 

biological treatment is required only for plants with capacity equal to or greater than 2,000 

MW; biological treatment at smaller plants would be determined on a case by case basis by 

permitting authorities using “best professional judgment.”

Option 4 improves on Option 3’s chemical precipitation and biological treatment for FGD 

wastewater, and zero‐discharge dry handling for fly ash transport water and flue gas mercury 

control wastewater with two additions: zero‐discharge dry handling for bottom ash transport 

water and chemical precipitation of coal combustion residual leachate.

Option 4a (introduced by OMB) is a weakened version of Option 4: surface impoundments 

are permitted for bottom ash transport water at plants with capacity equal to or less than 

400 MW, and the removal of suspended solids is permitted for combustion residual 

leachate.

Option 5 strengthens Option 4’s control requirements by replacing biological treatment of FGD 

wastewater with vapor‐compression evaporation systems.
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104 Benefit‐Cost Analysis, p.3‐9

105 U.S. Environmental Protection Agency, Proposed Rule: Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category, as submitted to the 

Office of Budget and Management in accordance with Executive Order 12866

106 Office of Budget and Management, Revisions to: Proposed Rule: Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating Point Source Category

Comment Response: 

See responses to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 16 and DCN EPAHQ-OW-2009-0819-4684-A1, Excerpt Number 46.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 21

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s “preferred alternatives” for steam electric ELGs

Well‐supported subcategorization of an industry is permitted. Aside from this subcategorization 

process, however, Congress’ mandate to EPA in the Clean Water Act requires that pollution 

control technologies be eliminated from consideration for BAT only on grounds of:

4. Stringency: There are other more effective technologies for controlling the discharge of 

pollutants from a particular effluent stream.

5. Technological achievability: The proposed technology is not achievable (i.e. cannot be 

purchased or installed).

6. Economic achievability: The cost of proposed technology is, in EPA’s determination, an 

unreasonable burden to the industrial category as a whole (here, all steam electric generators 

other than oil‐fired generating units and generating units with capacities 50 MW or smaller).

EPA’s original proposal recommended Options 3 and 4 as preferred,122 and only performed its 

full economic analysis using the IPM model on those two options. The EPA proposal found 

Options 1 and 2 to be too lax—“neither option would represent the best available technology 

level for steam electric power plant discharges”123—and rejected Option 5 even though “without 

question, Option 5 would remove the most pollutants from steam electric power plant 
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discharges.”124 EPA’s elimination of Option 5 from consideration for this rulemaking was made 

on economic grounds: “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.”125

OMB’s review required EPA to instead recommend Options 3, 3a, 3b, and 4a, and introduced the

following language to EPA’s proposed guidelines to explain the rejection of Option 4 (discussed 

above).

EPA does not include Options 1 and 2 among its “preferred alternatives” on the basis that there 

are other more effective technologies than those that would be required under these regulatory 

options.126

The grounds for EPA’s decision to exclude Options 4 and 5 from its preferred alternatives are 

not well established. EPA’s failure to include Options 4 and 5 results in the elimination of the 

following control technologies from BAT consideration:

 Dry handling of bottom ash transport water for units with capacities 400 MW or smaller

 Chemical precipitation of combustion residual leachate

 Vapor‐compression evaporation of FGD wastewater (Option 5 only)

All three of these technologies are more effective than those included in among EPA’s preferred 

alternatives and are technologically achievable (see Table 9).

The following sub‐sections demonstrate that the control technologies removed from 

consideration when Options 4 and 5 were not designated as “preferred”—dry handling of 

bottom ash transport water for units with capacities 400 MW or smaller, chemical precipitation 

of combustion residual leachate, and vapor‐compression evaporation for FGD wastewater—meet 

the criteria set out in the Clean Water Act for BAT. That is, these control technologies are: 1) 

more stringent than the technologies required in EPA’s preferred options; 2) technologically 

achievable in the United States today; and 3) economically achievable for the steam electric 

industry as a whole.

Table 9. Eliminated control technologies

Eliminated

Technology Comparative Stringency Use in the Steam Electric Industry
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Dry handling of

bottom ash

transport water

for units with 

capacities 400 

MW or smaller

"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... Although 

surface impoundments can be effective at 

removing particulate forms of metals and 

other pollutants, they are not designed for 

nor are they effective at removing other 

pollutants of concern such as dissolved 

metals and nutrients. The concentrations 

of pollutants that remain in the 

wastestream at the ash impoundment 

effluent, in combination with the large 

volumes of bottom ash transport water 

discharged to surface waters, results in a 

large mass loading of pollutants of 

concern being discharged from surface 

impoundments. Effluent limitations and 

standards based on the technologies used 

as the basis for Options 4a (for units more 

than 400 MW), 4, and 5 would 

completely eliminate the discharge of 

pollutants in bottom ash transport 

water."(pp.34,461‐ 34,462)

283 steam electric units in the 

United States employ dry handing 

systems for bottom ash transport 

water. (p.34,454)

Chemical

precipitation of

combustion

residual leachate

"Under Options 1, 3a, 2, 3b, 3, and 4a, 

effluent limitations and standards for 

leachate from surface impoundments and 

landfills containing combustion residuals 

would be set equal to the current BPT 

effluent limitations, based on the 

technology of gravity settling in surface 

impoundments to removesuspended 

solids...[S]ince surface impoundments 

are not designed for, nor are they 

effective at, removing other pollutants of 

concern such as dissolved metals, EPA 

used chemical 

precipitation/coprecipitation as the 

technology basis for Options 4 and 5. 

Physical/chemical treatment systems are 

capable of achieving low effluent 

concentrations of various metals and are 

"The pollutants of concern in 

leachate are the same pollutants 

that are present in, and in many 

cases are also pollutants of 

concern for, FGD wastewater, fly 

ash transport wastewater, bottom 

ash transport water, and other 

combustion residuals...Given the

similarities present among the 

different types of wastewaters 

associated with combustion 

residuals, combustion residual 

leachate will be similarly 

amenable to chemical 

precipitation treatment. The 

treatability of pollutants such as 

arsenic and mercury using 

chemical precipitation technology 
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effective at removing many of the 

pollutants of concern present in leachate 

discharges to surface waters."(pp.34462‐

34,463)

is also demonstrated by technical 

information compiled for ELGs 

promulgated for other industry 

sectors."(p.34,454)

Vapor‐

compression

evaporation of

flue gas 

desulfurization 

wastewater 

(Option 5 only)

"Although EPA did not select Option 5 as 

the preferred BAT option, without 

question, Option 5 would remove the 

most pollutants from steam electric power 

plant discharges."(p.34,473)

"Two U.S. plants and four Italian 

plants are operating this 

technology to treat FGD 

wastewater from their coal‐fired 

generating units."(p.34,460)

Source: 78 Fed. Reg.

122 U.S. Environmental Protection Agency, Proposed Rule: Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category, as submitted to the 

Office of Budget and Management in accordance with Executive Order 12866.

123 78 Fed. Reg. at 34,472.

124 78 Fed. Reg. at 34,473.

125 78 Fed. Reg. at 34,473.

126 78 Fed. Reg. at 34,472‐34,473.

Comment Response: 

See responses to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 16 and DCN EPAHQ-OW-2009-0819-4684-A1, Excerpt Number 46.
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Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 28

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The goal of the Clean Water Act is to eliminate all pollution in U.S. surface waters. The most 

stringent of the regulatory options proposed by EPA do much more to eliminate more water 

pollution from power plants, do more to protect the environment, and save more human lives 

than would their less stringent “preferred” counterparts. Options 4 and 5—the most pollutant‐

reducing regulatory options presented by EPA—have been eliminated from consideration as 

steam‐electric ELGs inappropriately. Elimination from BAT consideration under the Clean 

Water Act requires one of the following:

1. Insufficient stringency: There are other more effective technologies for controlling the 

discharge of pollutants from a particular effluent stream.

2. Lack of technological achievability: The proposed technology is not achievable (i.e. 

cannot be purchased or installed).

3. Lack of economic achievability: The cost of proposed technology is, in EPA’s 

determination, an unreasonable burden to the industrial category as a whole (here, all 

steam electric generators other than oil‐fired generating units and generating units with 

capacities 50 MW or smaller).

Benefit‐cost analysis is not a permissible criterion for determining BAT under the Clean Water 

Act. Regulatory benefit‐cost analyses notoriously overestimate costs and underestimate benefits, 

and the benefit‐cost analysis for the proposed steam electric ELGs is no exception.

Option 4 is less stringent only than Option 5, and is both technologically and economically 

achievable. Option 5 passes all three tests.

Comment Response: 

See responses to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 16 and DCN EPAHQ-OW-2009-0819-4684-A1, Excerpt Number 46.

Commenter Name: Thomas Cmar

Commenter Affiliation: Earthjustice, et al.

Document Control Number: EPA-HQ-OW-2009-0819-4686-A1

Comment Excerpt Number: 29

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

Option 4 should be among EPA’s preferred options

Control technologies for Option 4—dry handling of bottom ash transport water for units with 

capacities 400 MW or smaller, and chemical precipitation of combustion residual leachate—are 

more effective at controlling the discharge of pollutants than are the Options selected by EPA as 

“preferred.” These control technologies are also—as documented by EPA in this rulemaking—

technologically achievable. Furthermore, EPA itself describes Option 4 for as “economically 

achievable” and fails to make a case that it would be a burden to industry. EPA’s rationale for 

eliminating Option 4 from consideration is based entirely on a subcategorization of the steam‐

electric industry that has not been appropriately justified in this docket.

Option 5 is BAT for the steam‐electric industry

The sole additional control technology found in Option 5 but not in Option 4—vapor‐

compression evaporation—makes Option 5 the most effective of all the proposed steam‐electric 

regulatory options at controlling the discharge of pollutants. Option 5 is technologically 

achievable; zero‐liquid discharge technologies are used to control similar pollutants in many 

other industries, in several steam‐electric plants in the United States, and in several more abroad.

Option 5 is also economically achievable. EPA has not demonstrated that Option 5 would be a 

burden to the steam electric industry. The measures of economic achievability presented by EPA 

are deeply flawed; EPA itself states that the metric for which it presents an adverse result for 

Option 5—the cost‐ to‐revenue ratio—“does not generally indicate whether profitability is 

jeopardized, cash flow is affected, or risk of financial distress is increased.”163 Option 5’s cost‐

effectiveness is within the bounds of those of approved ELGs (and is biased upward by the same 

faulty assumption used in the cost‐to‐revenue ratio), EPA presents no evidence of its plant 

closures, its household costs are negligible, and it results in an average annual increase of 2,112 

jobs.

In addition, as the vapor‐compression evaporation industry has developed, new designs and 

operation methods have become available. For example, Veolia’s press materials claim that the 

CoLDTM technology has the lowest capital and operating costs of all zero liquid discharge 

processes; CoLD has been successfully implemented at facilities in multiple industries.164 More 

generally, zero liquid discharge capital costs have dropped precipitously over the past decade. 

According to Bill Heins, general manager of thermal products and zero liquid discharge for GE 

Water and Process Technologies, total capital costs for installation dropped as much as 65 

percent over the past seven years.165

Option 5 is BAT for the steam‐electric ELGs.

163 Regulatory Impact Analysis, p.4‐2.
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164 Veolia Water. (2013). The CoLD Process: ZLD Wastewater Treatment for Coal‐fired 

Generation. Case Study, Veolia Water Solutions & 

Technologies.http://www.veoliawaterstna.com/vwst‐

northamerica/ressources/documents/1/30047,CoLD‐ Coal‐TDS‐1‐22.pdf.

165 Global Water Intelligence. (2009, December). From zero to hero – the rise of ZLD. Global 

Water Intelligence, 10(12). http://www.globalwaterintel.com/archive/10/12/market‐

insight/from‐zero‐to‐hero‐the‐rise‐of‐zld.html.

Comment Response: 

See responses to DCN EPA-HQ-OW-2009-0819-4684-A1, Excerpt Number 16 and DCN EPAHQ-OW-2009-0819-4684-A1, Excerpt Number 46.

As described in Section 7.1.4 of the TDD, a vendor of the evaporation system for treating FGD 

wastewater has developed a system that does not require a chemical precipitation or limesoftening step. Therefore, the FGD wastewater can be sent directly into the evaporation and 

crystallization process that is operated at a low temperature for optimizing the FGD wastewater 

chemistry. At a lower temperature, dissolved solids will crystallize (e.g., hydrates and double 

salts) at lower concentrations. Therefore, this system does not produce any additional sludge 

from chemical additions, allows the evaporated water to be reused, and produces stable solids for 

disposal [Veolia Water Solution, 2013; ERG, 2015e]. EPA is aware of one coal-fired power 

plant that operates a full-scale CoLDTM process system; however, it is not used to treat FGD 

wastewater. In addition, EPA lacks sufficient data on which to base industry-level compliance 

costs using this technology configuration and the commenter did not supply data that can be used 

to support such an analysis.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Overall Duke Energy Supports: EPA’s rejection of Options 4 & 5.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.
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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: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Because of the small contribution of toxics and high treatment costs for bottom ash transport 

water, WPSC supports Options 1 through 3 (including 3a and 3b), which would set effluent 

limits for bottom ash transport water attainable by treatment in a settling pond and equal to the 

current Best Practical Technology (BPT) limits for bottom ash transport water. WPSC does not 

support Options 4 and 5, which would require dry bottom ash handling systems, remote 

mechanical drag systems, or impoundment based systems that eliminate the discharge of bottom 

ash transport water at all facilities. Options 4 and 5 are not justified as they would require 

significant modifications at over 200 generating facilities, including the WPSC J.P. Pulliam and 

Weston Generating facilities.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.

Also see responses to Comment Codes 6.i.ii, 6.i.v, and 6.i.vi.

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: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The proposed ELG rule will encourage power plants to move toward the "dry handling" of CCR 

material and minimize these risks. As such, BNCC and SJCC support "dry handling" 

requirements for certain CCR wastes including fly ash and flue gas mercury control 

wastewater. See Comment # 2 below.

1. The EPA-preferred Options 3a. 3b.and 3, which specify water technology and treatment

standards for existing direct dischargers are both environmentally protective and cost 

effective. As a result, BNCC and SJCC would support adoption of any one of these three 

approaches.
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EPA-preferred Options 3a, 3b, and 3 specify water technology and treatment standards for 

existing power plants with wastewater discharge permits. These options require the "dry 

handling" of fly ash and flue gas mercury control waste, chemical precipitation combined with 

biological treatment for flue gas desulfurization wastewater , and chemical precipitation for 

nonchemical metal cleaning wastes. The standards included in these options are all 

environmentally protective, yet remain cost effective. As a result, we support adoption of any 

one these three approaches .

In contrast, EPA-preferred Option 4a along with the other Options 4 and 5 would place an 

unrealistic and unnecessary financial burden on utilities.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4770-A2, Excerpt Number 1.

Commenter Name: Michalene Reilly

Commenter Affiliation: Hoosier Energy Rural Electric Cooperative

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

Comment Excerpt Number: 23

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In conclusion, Hoosier strongly believes Regulatory Options 3b, 3, 4a, 4, and 5 are not 

economically achievable or feasible to implement at Hoosier's electric generating facilities. 

Hoosier would support Regulatory Option 1 , or, Option 2, provided it is modified to remove the 

biological treatment requirement.

Comment Response: 

The final rule establishes limitations and standards applicable to the discharge of pollutants from 

the steam electric power generating industry based on the “best available technology 

economically achievable” and the “best available demonstrated control technology,” as those 

terms are used in sections 301, 304, and 306 of the Clean Water Act.

EPA determined that the technologies represented by Regulatory Option D represent Best 

Available Technology Economically Achievable (except for discharges from “small” or oil-fired 

generating units) because they are available and economically achievable (i.e., affordable) for the 

industry as a whole, and have acceptable non-water quality environmental impacts as required by 

the Clean Water Act (see preamble Section VIII). Also see responses to Comment Code 6.i.ii.
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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: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

We Energies strongly supports EPA’s determination that Options 4 and 5 are not the preferred 

regulatory options for existing dischargers.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-3920-A1, Excerpt Number 8.
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6.i.v. Support/oppose Option 3a/3b

Commenter Name: Chas Spell

Commenter Affiliation: Arizona Public Service Company

Document Control Number: EPA-HQ-OW-2009-0819-4303-A2

Comment Excerpt Number: 6

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

For FGD wastewaters, APS supports Options 3a and 3b. The “Best Professional Judgment” 

(BPJ) approach proposed for FGD wastewaters should specify that it does not mean the permit 

writer has no standards for decision. To the contrary, the standards for making “BPJ” decisions 

have long been prescribed by 40 C.F.R. § 125.3(d). The permit writer “must consider” the listed 

statutory factors, including cost. See Clean Water Act 304(b) (2), (4) (B), 306(b) (1) (B). EPA 

should acknowledge in the final rule "BPJ" limits for FGD wastewater should not include 

chemical precipitation, biological treatment, and zero discharge as they are not cost-effective. 

Because none of these three treatment options are cost-effective, they cannot be required if "BPJ" 

is used.

Comment Response: 

The final rule is not based on proposed regulatory options 3a or 3b (or the specific suites of 

technologies that form the bases for these options), in part, due to the fact that they would require 

effluent limitations and standards for discharges of flue gas desulfurization (FGD) wastewater to 

be determined on a Best Professional Judgment (“BPJ”) basis. See preamble Section VIII and 

response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6 in Comment Code 

6.j.i. The final rule is based on Regulatory Option D for existing sources and Regulatory Option 

F for new sources. See preamble Section VIII for EPA’s rationale for selecting these options, 

and the technology bases they represent, for the final rule, as well as its rationale for rejecting

other options.

EPA disagrees with the commenter that “limits for FGD wastewater should not include chemical 

precipitation, biological treatment, and zero discharge as they are not cost-effective.” For the 

reasons explained in the preamble, except for existing small and oil-fired generating units (see 

preamble Section VIII.C.12), EPA determined that chemical precipitation plus biological 

treatment represents Best Available Technology Economically Achievable for the control of 

discharges of FGD wastewater because it is available and affordable for the industry as a whole, 

and it has acceptable non-water quality environmental impacts (see preamble Section VIII). For 

the role of cost-effectiveness in EPA’s decisions 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: P. J. Becker

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

Document Control Number: EPA-HQ-OW-2009-0819-4349-A2

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Pretreatment Standards for Existing Sources (PSES).

CWLP agrees with the proposed rule options 3a and 3b for the PSES. Options 3a and 3b (under 

Option 3b for units located at plants with a total wet-scrubbed capacity of less than 2,000 MW), 

the regulations would not specify PSES for FGD wastewater, and publicly owned treatment 

works (POTW) would need to develop local limits. CWLP has worked with our local POTW to 

allow for some of our WFGD treated effluent to be discharged to the POTW. CWLP has 

obtained a wastewater discharge permit with our POTW and we work very closely with them to 

in order to maintain our permit specific limits.

Comment Response: 

The final rule is not based on proposed regulatory options 3a or 3b (or the specific suites of 

technologies that form the bases for those options), which the commenter supports. EPA did not 

select for the final rule any regulatory option that would have required limitations and standards 

for discharges of FGD wastewater to be based on the permitting authority’s “best professional 

judgement” for the reasons explained in preamble Section VIII.C.1. For existing sources, except 

for small and oil-fired generating units (see preamble Section VIII.C.12), the final rule 

establishes limitations and standards for discharges of FGD wastewater that are based on 

chemical precipitation plus biological treatment (see preamble Section VIII.C.1). The selected 

technology basis for the final limitations and standards for this wastestream, which achieves 

significant pollutant reductions, is available and affordable to the industry as a whole, with 

acceptable non-water quality environmental impacts. See also Section IV of the preamble for an 

explanation of how PSES are analogous to BAT limitations. 

Commenter Name: Bruce W. Ramme

Commenter Affiliation: We Energies

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

Comment Excerpt Number: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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In general, We Energies partially supports EPA’s proposal of Options 3a, 3b, 3, or 4a (see 78 

Fed. Reg. at 34,468 – 34,470) as the preferred alternatives for BAT for existing dischargers. The 

Company believes most of the proposed preferred alternatives are adequate as written but 

believes some parts should be reconsidered (e.g., FGD wastewater BAT selection). 

Comment Response: 

The final rule is not based on the proposed options supported by the commenter (options 3a, 3b, 

3 or 4a), or on the specific suites of technologies that form the bases for those options. For an 

explanation of why EPA selected Option D for existing sources for the final rule, as well as why 

it rejected other options, see Section VIII of the preamble. EPA cannot respond to the 

commenter’s statement that “most of the preferred alternatives are adequate as written but . . . 

some parts should be reconsidered” because it is too generalized and without explanation or 

basis. Nevertheless, EPA’s decision to establish BAT limitations for the discharge of FGD 

wastewater based on chemical precipitation plus biological treatment (except for existing small 

and oil-fired generating units, see preamble Section VIII.C.12)) is explained in Section VIII.C.1.

Commenter Name: Stephen M. Frank

Commenter Affiliation: NRG Energy, Inc.

Document Control Number: EPA-HQ-OW-2009-0819-4510-A2

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Discharges Directly to Surface Water from Existing Facilities - Preferred Option 3a

Based on the extensive data collected by EPA, NRG supports the alternatives for Best Available 

Technology Economically Achievable (BAT) referred to as Option 3a for discharges directly to 

surface water from existing facilities. Specifically, we support establishing BAT of:

1. Numeric effluent limits for copper and iron in discharges of nonchemical metal cleaning 

wastes (where these limits are already enforced). We support EPA’s proposed exemption 

from new copper and iron BAT limitations for any existing discharges of nonchemical 

metal cleaning wastes that are currently authorized without iron and copper limits as is 

the case for many facilities in Maryland, Pennsylvania and Ohio.

2. Effluent limits for bottom ash transport water and combustion residual leachate from 

landfills and surface impoundments that are equal to the current Best Practicable Control 

Technology Currently Available (BPT) effluent limits for these discharges.

Comment Response: 
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The final rule is not based on proposed regulatory option 3a (or the specific suite of technologies 

that forms the basis for that option), which the commenter supports. See Section VIII of the final 

rule preamble for an explanation of why, for the final rule, EPA selected Regulatory Option D 

for existing sources and why it rejected other regulatory options. In particular, the final rule does 

not include a requirement that FGD wastewater limitations and standards be established on a 

Best Professional Judgment (BPJ) basis, unlike proposed Option 3a (see preamble Section 

VIII.C.1). See also response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6 in 

Comment Code 6.j.i.

For the reasons explained in Section VIII of the preamble, the final rule also does not establish 

BAT limits for discharges of nonchemical metal cleaning wastes, nor does it establish BAT 

limits for the discharge of bottom ash transport water that are equal to the previously established 

BPT limits (except in the case of discharges from existing small and oil-fired generating units, 

see preamble Section VIII.C.12). The final rule does, however, establish a BAT limit on TSS in 

discharges of combustion residual leachate that is equal to the previously established BPT limit 

on TSS in low volume waste sources.

Commenter Name: Brian Brazil

Commenter Affiliation: TransAlta Centralia Generation, LLC (TCG)

Document Control Number: EPA-HQ-OW-2009-0819-4665-A2

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Overall, TransAlta supports EPA’s choice of the option listed as 3b in Table VIII of the 

proposal. This option allows much stronger control of wastewater emissions than previous ELGs 

while allowing permitting agencies some discretion on what technology is economically feasible 

for their regulated sources.

Comment Response: 

The final rule is not based on proposed regulatory option 3b (or the specific suite of technologies 

that forms the basis for that regulatory option), which the commenter supports. See Section VIII 

of the final rule preamble for an explanation of why, for the final rule, EPA selected Regulatory 

Option D for existing sources and Option F for new sources and why it rejected other regulatory 

options. In particular, Section VIII.C.1 explains why the final rule does not require limitations 

and standards for discharges of FGD wastewater to be established on a “best professional 

judgment” basis. As explained in Section VIII.C.9 of the preamble, EPA determined that the 

final limitations and standards are economically achievable for the industry as a whole.
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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: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

AMP commends EPA for identifying a variety of options in the Proposed ELG Rule, including 

four options ‘‘preferred” by the agency. Of these, AMP would prefer either Option 3a or Option 

3b, which achieve the goal of environmental protection while requiring less expensive and less 

extensive retrofits or modifications for compliance.

Comment Response: 

The final rule is not based on proposed regulatory options 3a or 3b (or the specific suites of 

technologies that form the bases for those options), which the commenter supports. See Section 

VIII of the final rule preamble for an explanation of why, for the final rule, EPA selected 

Regulatory Option D for existing sources and Option F for new sources and why it rejected other 

regulatory options. In particular, Section VIII.C.1 explains why the final rule does not require 

limitations and standard for discharges of FGD wastewater to be established on a “best 

professional judgment” basis.

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

While Option 1 is the most cost-effective approach and preferred Option for LDEQ, Option 3a is 

a mix of practical treatment technologies for applicable waste streams at generating units in the 

state and is the LDEQ preferred Option out of the 4 EPA preferred options. Engineering and cost 

analyses indicate that, with the exception of biological treatment, the treatment costs under this 

option are cost effective and significantly less than those proposed under Option 4a, an option 

with some of the highest estimated costs. LDEQ supports selecting Option 3a (excepting 

biological treatment) out of the EPA preferred options as this represents the best balance between 

environmental benefit and implementation costs.

Comment Response: 
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The final rule is not based on the options supported or referenced by the commenter (option 1 or 

option 3a), or the specific suites of technologies that form the bases for those options. See 

Section VIII of the final rule preamble for an explanation of why, for the final rule, EPA selected 

Regulatory Option D for existing sources and Option F for new sources and why it rejected other 

regulatory options. In particular, Section VIII.C.1 explains why the final rule does not require 

limitations and standards for discharges of FGD wastewater to be established on a “best 

professional judgment” basis. In addition, EPA determined that the final rule is affordable for the 

industry as a whole (see Section VIII.C.9 of preamble). 

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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6.i.vi. Support Option 3

Commenter Name: Nancy A. Evans

Commenter Affiliation: PPL Services Corporation

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

Comment Excerpt Number: 16

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

PPL believes that the best balance of environmental protection, cost-effectiveness, and 

regulatory finality is achieved by Regulatory Option 3, with the appropriate modification to 

remove requirements for biological treatment unless the specific limits for the parameters of 

concern or modified to properly reflect what the technology can achieve. Accordingly, we 

request EPA to adopt that approach in the final ELGs.

Comment Response: 

EPA did not base the final ELGs on proposed Option 3 (or the specific suite of technologies that 

form the basis for that option). The final rule is based on Option D for existing sources and 

Option F for new sources, for the reasons explained in section VIII of the preamble.

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. The limitations and 

standards in the final ELGs properly reflect what the BAT/BADCT technologies can achieve. 

See Section 13 of the TDD and the preamble.
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6.i.vii. Support/oppose Options 3/4a

Commenter Name: Public Hearing Transcript

Commenter Affiliation: Public Hearing Transcript

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

Comment Excerpt Number: 147

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

And for these reasons, I support EPA's choice of Option 3 or 4 for the steam electric ELG.

Comment Response: 

The commenter noted that limiting the amount of toxic discharges will save lives, prevent 

illnesses, and protect freshwater ecosystems. This commenter also noted that the benefit and cost 

analyses for the proposed rule estimate that the rule will produce hundreds of millions of dollars 

of public health benefits as well as secondary health benefits. The commenter quoted estimated 

CO2 reduction impacts associated with Options 3 and 4 and expressed support for those options.

EPA did not base the final ELGs on proposed Option 3 or 4a (or the specific suite of 

technologies that form the bases for those options). The final rule is based on Option D for 

existing sources and Option F for new sources. For a description of these options, and the 

reasons EPA selected them, as well as why it rejected other options, see preamble section VIII. 

Although EPA did not select the proposed Options 3 or 4, the final rule sets zero discharge 

limitations and standards and other discharge requirements that EPA estimates will collectively 

remove 1.4 billion pounds of pollutants annually, as described in preamble section III.

Commenter Name: J. Madras

Commenter Affiliation: Missouri Department of Natural Resources

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

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

1. Technology Basis Options

The Department believes Options 3 or 4a are the best options for implementation in National 

Pollutant Discharge Elimination System (NPDES) permits, because they apply definitive 

technology based standards to all coal combustion facilities. These options, especially 4a, do the 

most to advance the fundamental goal of the NPDES program by eliminating discharges from 
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impoundments. These options are also preferable to the Department because they do not rely on 

best professional judgment (BPJ) decisions. The Department supports promulgation ofthe 

effluent limit guidelines requirements found in Option 3 or 4a because they will significantly 

improve the tools available to the States for effective permit development.

Comment Response: 

EPA did not base the final ELGs on proposed Options 3 or 4a (or the specific suite of 

technologies that form the bases for those options). The final rule is based on Option D for 

existing sources and Option F for new sources. For a description of these options, and the 

reasons EPA selected them, as well as why it rejected other options, see Section VIII of the 

preamble. Although EPA did not select the proposed Options 3 or 4, the final rule sets zero 

discharge limitations and standards and other discharge requirements that EPA estimates will 

collectively remove 1.4 billion pounds of pollutants annually, as described in preamble section 

III.

EPA agrees with the commenter that, where EPA has the information to establish nationally 

applicable, technology-based effluent limitations and standards, such limitations and standards 

are generally preferable to those developed on a “best professional judgment” (BPJ) basis. This 

is due, in part, to the fact that national limits provide predictability and clarity to the regulated 

entities, as well as affected communities, and they reduce the burdens associated with developing 

limits on a site-specific basis. For the reasons explained in Section VIII of the preamble, the final 

rule continues to reserve BAT/PSES/NSPS/PSNS for discharges of nonchemical metal cleaning 

wastes.

Commenter Name: Pamela Ritger

Commenter Affiliation: Clean Wisconsin

Document Control Number: EPA-HQ-OW-2009-0819-4632-A1

Comment Excerpt Number: 19

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The EPA is vested with the authority and duty to protect the citizens of the United States from 

environmental harm. In the case of coal combustion wastewater, the EPA has failed to perform 

its duties to protect the health of our people, wildlife and ecosystems for far too long. The oftencited excuse for not passing adequate regulation necessary to protect public health is cost. In this 

case, the cost to end the dumping of toxic pollutants from coal power plants would cost less than 

one percent of annual revenue for most coal plants and about two pennies a day for Americans if 

electric utilities passed on part of their cleanup costs to consumers, or less than $7 per year.50 It 

is a miniscule price to pay compared to the health care costs of treating cancer or the lifelong 

costs of caring for a child born with developmental or cognitive disorders. Therefore, not only 

should the EPA adopt Option 4a to comply with its duty to protect the American people, wildlife 
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and environment, but adopting the most stringent option also makes economic sense. As in most 

scenarios, the price of preventing illness pales in comparison to treating illness. The EPA should 

apply this same logic to its duty to regulate polluters, and protect human health to the best of its 

ability by adopting Option 4a.

50 Environmental Integrity Project et al., Closing the Floodgates: How the Coal Industry Is 

Poisoning Our Water and How We Can Stop It, p. 2 (July 2013). Available 

at http://www.environmentalintegrity.org/news_reports/documents/2013_07_23_ClosingTheFlo

odgates-Final.pdf

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-5049-A1, Excerpt Number 1 in Comment Code 

6.i.viii.

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: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EKPC's baseload generating capacity is from three coal-fired generating stations - Spurlock 

Station, Dale Station, and Cooper Station. The three stations have a combined output capacity of 

approximately 1,900 MW. When evaluating our approach to providing comments on the rule, 

EKPC focused on the impacts of the rule at Spurlock Station since Spurlock Station has two 

pulverized coal boilers (325 MWs and 555 MWs capacity, respectively) with two wet flue gas 

desulfurization ("FGD") systems. The ELG shall impact EKPC's coal-fired fleet, a perfect 

example of a smaller electric utility.

EKPC will be severely financially impacted by the cost of compliance associated with EPA's 

proposed ELGs for coal-fired steam electric utilities under any of EPA's four preferred 

alternatives. However, the most stringent preferred alternatives, Options 3 and 4a, are 

economically unachievable and are not otherwise justified as Best Available Control Technology 

Economically Achievable ("BAT"). Specifically, as set forth below, under Option 4a and at 

Spurlock Station alone, EKPC would incur capital costs in excess of $145 million to install 

treatment technologies to meet the proposed standards. Option 3 would require capital 

investments of approximately $90 million. As discussed herein, adoption of the most stringent 

proposed BAT alternatives is not justified, and EKPC supports adoption of preferred regulatory 
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Option 3a or 3b as the basis for the final ELGs. EKPC appreciates the opportunity to provide the 

following comments section-by-section for the EPA to consider during final rulemaking.

.....

In sum, EKPC contends that the record does not support selection of preferred Options 3 or 4a as 

BAT with respect to FGD wastewater, especially for smaller coal-fired utilities and generating 

stations, such as those operated by EKPC. The economic achievability evaluation underestimated 

the capital and operating costs of the necessary treatment systems; significant technical 

achievability issues remain; and the environmental benefit analysis of reductions in selenium that 

were performed by EPA were based upon an improper benchmark, as the 1987 recommended 

water quality criterion for aquatic life is outdated and known to be overly conservative.

.....

This fits within the confines of Best Professional Judgment (BPJ) and the rules intent. EKPC 

supports EPA in clearly defining the water quality standards, BPJ, BPT, BAT, and other 

technology based limits. A clearly defined target provides opportunity for innovation, 

engineering design and creativity.

EKPC appreciates the opportunity to provide these comments on such an important rulemaking 

for the electric-generating industry. As set forth above, EKPC respectfully requests that EPA 

reject preferred Options 3 and 4a as BAT as they would subject coal-fired utilities to 

unreasonable costs and would mandate compliance with emission limitations that may not be 

technologically achievable for limited additional environmental benefit.

Comment Response: 

EPA did not base the final rule on proposed regulatory options 3a or 3b. Rather, the final rule is 

based on Option D for existing sources and Option F for new sources. For a description of these 

options, and the reasons EPA selected them, as well as why it rejected other options, see 

preamble section VIII. EPA determined the final rule is technologically available, economically 

achievable (i.e., affordable) for the industry as a whole, and has acceptable non-water quality 

environmental impacts. See preamble section VIII.

EPA disagrees that the rule is not affordable, including for “smaller” plants, as the commenter 

suggested. As discussed in preamble section IX and the RIA, 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) and concluded the rule would have a 

minimal effect on steam electric generating capacity. These IPM results support EPA’s 

conclusion that the final rule is economically achievable. For additional information on 

economic achievability, see Sections VIII and IX of the final preamble and the RIA. EPA did 

consider the size of the generating unit, and ultimately determined that it would be appropriate to 

establish differentiated BAT limitations and PSES for generating units that are less than or equal 

to 50 MW, for the reasons explained in preamble section VIII. Again, taking these differentiated 
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requirements into account, EPA’s analyses show that the final limitations and standards are 

achievable for the industry as a whole, with little projected impact in terms of change in steam 

electric generating capacity, as well as a host of other metrics. See the RIA.

EPA disagrees that the effluent limitations developed for the final rule are not technologically 

available. EPA documented the technological availability of each technology used as the basis 

for the final ELGs and presented the basis for the limitations promulgated in Sections 7 and 13, 

respectively, of the TDD.

EPA disagrees with the commenter’s estimate of costs. Because the commenter does not provide 

any details related to its cost estimates, EPA was not able to specifically review the cost basis for 

the estimated value presented for the commenter’s plant. However, EPA reviewed all comments 

received and, where specific information was included, updated costs associated with the 

installation and operation of the model technologies, based on the treatment already in place at 

each plant.

Regarding the benchmark used for selenium, see the response for DCN EPA-HQ-OW-2009-

0819-4455-A1, Excerpt Number 21 in Comment Code 25.f.ii.
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6.i.viii. Support Options 4/4a

Commenter Name: J. and A. MacDonald

Commenter Affiliation: Private Citizen

Document Control Number: EPA-HQ-OW-2009-0819-5049-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

I urge the EPA to finalize the rules for the above mentioned docket, and I respectfully submit 

that the EPA should select option 4a for existing sources and option 4 for new sources.

While these are likely to have the highest estimated costs, and are likely to result in the most 

active push back by the power industry, I believe these could have overall lower costs than the 

other options. This is because it is exceedingly difficult to estimate the costs of negative 

externalities such as impairment of overall health of our population, and effects on fish stocks 

that may result from the

introduction of toxic metals into our water. As an example, it is very difficult to say how much a 

given level of metal pollution increases overall health costs, and so that usually doesn't get taken 

into account when assessing costs and benefits.

In addition, it has taken 30 years to update the rules governing the emission of toxins from 

power plants . it takes an inordinate amount of time and effort to make these changes and 

whatever rule is finalized will not be updated for perhaps another 30 years. Because of this, we 

should be as restrictive as possible now while we have the chance .

Comment Response: 

Although EPA did not select proposed Option 4a for existing sources or proposed Option 4 for 

new sources, the regulatory options EPA selected as BAT/NSPS for the final rule reflect the 

same technologies (or ones that achieve greater pollutant reductions) than the options supported 

by the commenter, with the exception of one wastestream.

For BAT, there are two main differences between proposed Option 4a and Option D, which is 

the option selected as the basis for BAT limitations in the final rule. In the final rule, EPA 

established zero pollutant discharge requirements for bottom ash transport water for units greater 

than 50 MW, whereas the proposed rule Option 4a would have only established such 

requirements for units greater than 400 MW. Also, for the reasons explained in the preamble, 

EPA reserved BAT limitations for non-chemical metal cleaning wastes. See the final preamble 

for a detailed discussion of the final requirements and the selection of Option D as the basis for 

BAT limitations in the final rule.

For new sources, the final rule establishes NSPS based on evaporation for FGD wastewater, but 

reserves NSPS for non-chemical metal cleaning wastes for the reasons specified in the preamble. 
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NSPS for the other wastestreams in the final rule are the same as those in proposed Option 4, the 

option advocated for by the commenter. See the preamble section VIII for a detailed discussion 

of the final requirements and the selection of Option F as the basis for NSPS in the final rule.

EPA revised its cost estimates of the final rule based on public comments. See the final TDD, 

RIA, and BCA. While EPA has available data to estimate the costs of technologies, EPA does 

not have available data to estimate cost off-sets such as monetized reductions associated with 

improvements to human health (“impairment of overall health of our population”) or positive 

effects on fish stocks as suggested by the commenter. EPA agrees that, due to a lack of 

information, it is often difficult to produce monetized estimates of benefits associated with 

reductions in discharges of pollutants.
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6.j.i. Oppose BPJ

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Flue Gas Desulfetization (FGD) Wastewater

1. Two of the regulatory options for the steam electric generation in Table 8-1 (3a and 3b) 

require Best Available Technology Economically Achievable (BAT) determination using Best 

Professional Judgment (BPJ) for FGD wastewater. All the steam electric generating stations in 

Indiana fall under 2,000 MW wet scrubbed capacity. If one of these two options is selected as 

final, Indiana will need to detetmine site specific BAT using BPJ for FGD wastewater for the 

majority of the steam electric generation facilities in Indiana. Requiring states to use BPJ to 

conduct a BAT detetmination that sets Technology Based Effluent Limits (TBELs) creates a 

significant burden for the state. In Indiana alone, for example, almost 25 permits will be renewed 

during the next permit cycle. Indiana lacks the personnel and technical resources needed to 

assess the performance wastewater treatment technologies and develop cost estimates of various 

options. While the case-bycase site specific BPJ option(s) allow flexibility, Indiana prefers that 

EPA set the technology-based effluent limitations (TBELs) based on a BAT standard. 

Additionally, the BPJ option would likely create inconsistencies and would require extensive 

time and resources to not only perfmm the analysis, but also defend the decisions in the event 

that permits are challenged by either the facility or third party groups.

Additionally, once-through scrubbers for the FGD waste stream technology were not evaluated 

in the draft rule; this may have been based on the assumption that this type of technology will be 

eliminated. We would not have corresponding reference information to use drafting permits if 

the BPJ option is finalized.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6 in Comment Code 

6.j.i regarding BPJ and the response to DCN EPA-HQ-OW-2009-0819-4607-A1, Excerpt 

Number 4 in Comment Code 5.b regarding EPA’s analysis of once-through scrubbers.

Commenter Name: J. Madras

Commenter Affiliation: Missouri Department of Natural Resources

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

Comment Excerpt Number: 6
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External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Options 3a and 3b require BPJ for removal of Flue Gas Desulfurization (FGD) 

wastewater. Option 3a requires BPJ for all facilities and 3b for facilities less than 2,000 MW. 

For Missouri, only Ameren-Labadie and Associated Electric-Thomas Hill are facilities that are 

greater than 2,000 MW, leaving the majority of Missouri's power plant permits subject to a BPJ 

decision.

Best professional judgment requires permit writers to make a decision based on financial and 

economic information available. This leaves the permits open to challenges from the facility and 

possible third parties, which leads to uncertainty and inconsistencies. A clearly defined 

technology basis makes the decision based on multiple, nationwide stakeholders and groups, 

which provides more information and holds the states and permittees to the same standard, thus 

removing individual and regional differences in permits.

2. Best Professional Judgment

Some of the proposed options leave permit requirements subject to the permitting authority's 

BPJ, introducing risk that alternatives would be missed, the best decision would not be made, the 

decision would be open to comment, and possible appeal by the facility or third party 

organizations. EPA has already invested significant resources in evaluating facilities, 

technologies and economic impacts. BPJ avoids having the guideline set the technology based 

standard that is achievable across the country, creating uncertainty and inconsistency in the 

regulatory environment. Missouri is currently at an impasse on power plant permits, due in large 

part to this regulatory uncertainty. Competing interests have frequently prevented 

implementation of any new requirements for these facilities, even those improvements 

successfully negotiated with the industry.

Options 3a and 3b require BPJ for removal ofFGD wastewater. 3a requires BPJ for all facilities 

and 3b for facilities less than 2,000 MW. For Missouri, only Ameren-Labadie, and Associated 

Electric-Thomas Hill are facilities that are greater than 2,000 MW, leaving the majority of 

Missouri permits to require a BPJ decision. BPJ requires a high level of specialized training and

places a significant strain on already limited staff time and limited resources available for 

training. BPJ requires significant investigation into, and decisions based on, economic and 

financial factors. At this time, Missouri's most highly trained permit writers have limited 

background in economics. Missouri, like many other states, currently has little access to funding 

for advanced specialized training in engineering and economics.

BPJ requires permit writers to make a decision based on the information available, leaving the 

permits open to challenges from the facilities and possible third parties. A clearly defined 

technology basis makes the decision based on multiple, nationwide stakeholders and groups, 

which provides more information and holds the states to the same standard, thus removing 

individual and regional differences in permits.
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Comment Response: 

As explained in Section VIII of the preamble, EPA did not base the final rule on proposed 

regulatory options 3a or 3b nor did EPA establish a requirement that would direct permitting 

authorities to establish limitations for FGD wastewater using site-specific BPJ for steam electric 

power plants. See Section VIII.C.1 for a discussion of why EPA rejected this approach. The 

rule will eliminate burden on permitting authorities to the extent it establishes specified 

limitations and standards. 

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: 3

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

ACWA supports EPA’s establishment of Best Available Technology Economically Achievable 

(BAT) standards for the Flue Gas Desulfurization (FGD) rather than a Best Professional 

Judgment (BPJ) standard. The adoption of a BAT standard is consistent with the direction 

provided to EPA in the CWA, and EPA has collected sufficient information to warrant the

establishment of a BAT standard for FGD. State water program staff rely significantly on EPA to 

research and collect the necessary data to determine technology-based limits for various 

industrial groups. Most states lack the personnel and technical resources needed to undertake a 

BPJ analysis on a site-specific basis, including assessing performance of wastewater treatment 

technologies and developing cost estimates of various options, both of which EPA has done. 

Additionally, for technology not evaluated in the proposed rule, or for which cost and 

performance analysis data is withheld as Confidential Business Information (CBI),3states would 

not have corresponding reference information to use for drafting permits with a BPJ standard.4 A 

BPJ standard could lead to inconsistencies across states in a key industrial sector. While a BPJ 

standard does offer continuity with existing processes and offers flexibility, again, most states 

prefer a BAT standard.

3 EPA’s April 2013 report, Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Power Generating Point Source 

Category Report (DCN SE01957), is referenced multiple times in the Technical Development 

Document but the report has been withheld from the docket due to CBI.

4 For example, states that have facilities with once-through scrubber technology for FGD 

wastewater would be required to replicate large portions of the ELG development process in 

order to perform the BPJ analysis required to choose Best Available Technology (BAT) for this 
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scrubber technology. This would include wastewater treatment performance and cost analysis 

that will be difficult for current state level staffing and technical resources. For states with 

facilities that predominately utilize this technology, the result could be particularly burdensome.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities to the extent it establishes specified limitations and 

standards.

Commenter Name: Donald R. Carlson

Commenter Affiliation: Kansas Department of Health and Environment (KDHE)

Document Control Number: EPA-HQ-OW-2009-0819-3922-A1

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

In both Options 3a and 3b (for total plant-level wet scrubbed capacity less than 2,000 MW), EPA 

is proposing that states make a Best Professional Judgment (BPJ) determination as to what 

constitutes BAT for FGD Wastewater. As indicated in the preamble of the proposed rule, EPA 

began reviewing the Steam Electric Power Generating Effluent Guideline Standards following 

publication of the detailed study of the industry in 2009 concentrating on the FGD 

wastestream. EPA also conducted an in-depth detailed survey of the steam electric industry in 

2010 collecting and summarizing industry data, technology vendor data, information and data 

from other sources such as EPRI (Electric Power Research Institute) as well as economic data 

from the industry. States have neither the luxury nor the resources to collect and evaluate the 

data EPA has collected to address a handful of NPDES permits they administer. EPA should 

establish BAT in the effluent guideline standards. In the case of the proposed rule, if EPA 

requires states to use BPJ to establish BAT criteria for the designated wastestream, it would be 

likely that if an industry decides to contest the state's determination as to what constitutes BAT 

for the FGD wastewater, the state will end up not only having to defend it's technical, 

enviromnental, and economical determination, but will have to justify that decision in light of 

EPA having not made a similar determination when finalizing the proposed rule. Where EPA 

has identified a BAT technology in the proposed rule, they should make a BAT determination for 

the entire industry rather than establishing multiple options, (eight in this case) for 

consideration. Due to the ever dwindling staffing and resources available to states, EPA should 

be making the call regarding BAT for the FGD wastewater.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities to the extent it establishes specified limitations and 

standards.

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: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

DEQ supports EPA's establishment of Best Available Technology Economically Achievable 

(BAT) standards for the Flue Gas Desulfurization (FGD) rather than a Best Professional 

Judgment (BPJ) standard. The adoption of a BAT standard is consistent with the direction 

provided to EPA in the CWA, and EPA has collected sufficient inf01mation to warrant the 

establishment of a BAT standard for FGD. States rely on EPA to research and collect the 

necessary data to determine technology-based limits since most states lack the personnel and 

technical resources needed to undertake a BPJ analysis on a case-by-case basis. Additionally , 

for technology not evaluated in the proposed rule, or for which cost and performance analysis 

data is withheld as Confidential Business Information (CBI), states would not have 

corresponding reference information to use for drafting permits with a 

BPJ standard. A BPJ standard could lead to inconsistencies across states in a key industrial 

sector. While a BPJ standard does offer continuity with existing process and offers flexibility, it 

is difficult for states to make the required analysis.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities to the extent it establishes specified limitations and 

standards.

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: 10

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 
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Option 3a that allows permit writers to use best practical judgment (BPJ) is not our preferred 

option. State staff is limited and will be taxed with making this decision and EPA has extensive 

knowledge of the process.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities to the extent it establishes specified limitations and 

standards.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 7

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Duke Energy does not support best professional judgment (BPJ) as this option will place undue 

burden on the NPDES permitting authorities and the industry, will result in an unevaluated 

increase in cost to the state agencies and further delay the installation of a model technology.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities to the extent it establishes specified limitations and 

standards.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 37

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Duke Energy does not support best professional judgment (BPJ) as an appropriate regulatory 

option for establishing BAT limits for FGD wastewater. This option will place undue burden on 

the NPDES permitting authorities and the industry and will result in an unevaluated increase in 

cost to the state agencies and further delay in the installation of a model technology.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4283-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities to the extent it establishes specified limitations and 

standards.

Commenter Name: Cari Boyce

Commenter Affiliation: Duke Energy

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

Comment Excerpt Number: 46

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Duke Energy does not support EPA option 3a using Best Professional Judgment (BPJ) to 

determine BAT limits for FGD wastewater. This option creates considerable uncertainty and will 

require a significant amount of resources to perform these evaluations nationwide, not only from 

the industry, but also from the state NPDES permitting authority. In addition, not only will the 

state need the resources to conduct the BPJ determination, it is also expected the state and others 

will have to spend considerable additional resources defending every BPJ decision. This will just 

further delay the installation of technology improvements for treating FGD wastewater and 

would further delay any potential environmental benefit. Even though the state NPDES 

permitting authority has the authority to determine BAT limits based on BPJ, historically, the 

states have relied on EPA to establish BAT limits due to this lack of resources. It is, therefore, 

not justified for EPA to regulate this decision to the state level in a national rulemaking, 

especially when costs to be incurred by the state were not evaluated or considered by EPA.

Furthermore, the uncertainty associated with a BPJ determination creates considerable 

challenges with long-term capital planning for a utility, since the determination of the specific 

technology required for compliance would not be known until the NPDES permit renewal. For a 

utility, such as Duke Energy, with a large number of potentially affected units, the ability to plan 

appropriately for the numerous technology installations is critical. Without the certainty, the 

capital costs to comply with the limits could increase dramatically and thus, directly adversely 

affect every customer.

Comment Response: 

For the final rule, EPA did not select proposed regulatory options 3a or 3b for final regulation 

because it has sufficient information to establish BAT requirements for FGD wastewater. See 

preamble section VIII.C and response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt 

Number 6. The rule will eliminate burden on permitting authorities to the extent it establishes 

specified limitations and standards.
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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: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

6.In the final rule EPA should adopt a modified Option 3 approach to enhance regulatory 

certainty and cost-effectiveness.

In the present regulatory environment of increased scrutiny of coal-fired generation, power 

plants – even when conducting operations in good faith and in strict compliance with applicable 

environmental rules – often find themselves subject to permit challenges, citizen suits, and other 

legal challenges. In some instances, the “second-guessing” inherent in such challenges has 

resulted in delays in implementing new regulatory requirements, unnecessary costs incurred by 

permittees forced to change compliance strategies, and controversies which serve the interested 

of neither EPA nor the facilities. Both merchant and regulated utility power generators have 

found this regulatory uncertainty to be a major impediment to efficient compliance planning.

EPA has proposed eight regulatory options for consideration in this rulemaking. To achieve 

compliance with the final ELGs (regardless of which option is ultimately adopted), it will be 

necessary for power plants to make substantial investments of both time and money. PPL views 

it as critical for EPA to adopt a regulatory approach in the final ELGs which promotes the most 

efficient implementation of new requirements and minimizes the risk of prolonged legal 

challenges of regulatory determinations made in good faith. At a minimum, such legal challenges 

create continuing uncertainty for the regulated community. However, these challenges also pose 

the risk of unnecessary costs that can substantially increase the price of electricity to the 

consumer.

We urge EPA to avoid regulatory approaches in the final rule which focus on subjective 

mechanisms (e.g., standards based on case-by-case application of best professional judgment) 

that only enhance the risk of second-guessing through subsequent legal challenges (e.g., Option 

3a). A modified Option 3 that takes into account our concerns about the ELG numerical 

limitations and the capabilities of the technologies that EPA has evaluated is preferable.

Comment Response: 

EPA did not establish a requirement that would direct permitting authorities to establish 

limitations for FGD wastewater using site-specific BPJ. See response to DCN EPA-HQ-OW2009-0819-4383-A1, Excerpt Number 6 and DCN EPA-HQ-OW-2009-0819-4305-A3, Excerpt 

Number 46. The rule will eliminate burden on permitting authorities and delay related to legal 

challenges to the extent it establishes specified limitations and standards.
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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: 93

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA also suggests a possible “BPJ” approach to determining proper FGD wastewater treatment. 

Southern does not favor a BPJ approach, as it fails to provide the industry with much certainty. 

However, if EPA applies a BPJ approach, it must specify that it does not mean the permit writer 

has no standards for decision. To the contrary, the standards for making “BPJ” decisions have 

long been prescribed by 40 C.F.R. § 125.3(d). The permit writer “must consider” the listed 

statutory factors, including cost. See Clean Water Act §§ 304(b)(2)(B), (4)(B), 306(b)(1)(B).

If EPA does include an option for “BPJ” limits for FGD wastewater, it should acknowledge that 

the data developed in this very rulemaking establish that chemical biological treatment and zero 

discharge are not cost-effective, and chemical precipitation may be cost effective only for plants 

with a maximum design flow rate greater than 200 gpm. On the other hand, if selenium in the 

plant’s final discharge does not meet the water quality standards for the receiving stream, the 

permitting authority can establish appropriate and protective water quality based effluent limits 

as part of the facility’s NPDES permit.

Comment Response: 

EPA did not promulgate Best Professional Judgment (BPJ) limits for FGD wastewater for steam 

electric power plants in the final rule. See preamble section VIII.C and responses to DCN EPAHQ-OW-2009-0819-4383-A1, Excerpt Number 6 and DCN EPA-HQ-OW-2009-0819-4305-A3, 

Excerpt Number 46. Comments related to guidance EPA should offer on BPJ limitations for 

FGD wastewater are not relevant to the final rule.

EPA did establish limits for FGD for the reasons discussed in the preamble, the TDD and the 

record for the 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: Ron Shipman

Commenter Affiliation: Georgia Power Company

Document Control Number: EPA-HQ-OW-2009-0819-4447-A1

Comment Excerpt Number: 27

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

BPJ Would Not Provide Industry With Much Certainty.

EPA suggests a possible "BPJ" approach to determining proper FGD wastewater 

treatment. Georgia Power urges EPA to reconsider a BPJ approach because it fails to provide 

the industry with much certainty. However, if EPA applies a BPJ approach, it must specify that 

it does not mean the permit writer has no standards for decision. To the contrary, the standards 

for making "BPJ" decisions have long been prescribed by 40 C.P.R. § l25.3(d). The permit 

writer "must consider" the listed statutory factors, including cost. See Clean Water Act§§ 

304(b)(2)(B), (4)(B), 306(b)(l)(B). If EPA does include an option for "BPJ" limits for FGD 

wastewater, it should acknowledge that the data developed in this very rulemaking establish that 

the following systems are not cost effective for reasons set forth above: (1)biological treatment 

plus chemical precipitation; (2) zero liquid discharge (ZLD) treatment; and (3) vapor 

compression-evaporation. Therefore, none of these three treatments can be required if "BPJ" is 

used.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 93. For the role of 

cost-effectiveness analysis in EPA’s decisions for the final rule, see response to DCN EPA-HQOW-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: 132

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA also suggests a possible “BPJ” approach to determining proper FGD wastewater 

treatment. UWAG does not favor a BPJ approach, as it fails to provide the industry with much 

certainty. However, if EPA applies a BPJ approach, it must specify that it does not mean the 

permit writer has no standards for decision. To the contrary, the standards for making “BPJ” 

decisions have long been prescribed by 40 C.F.R. § 125.3(d). The permit writer “must consider” 

the listed statutory factors, including cost. See Clean Water Act §§ 304(b)(2)(B), (4)(B), 

306(b)(1)(B).

If EPA does include an option for “BPJ” limits for FGD wastewater, it should acknowledge that 

the data developed in this very rulemaking establish that chemical biological treatment and ZLD 

are not cost-effective, and chemical precipitation may be cost effective only for plants with a 

maximum design flow rate greater than 200 gpm.
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Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 93. 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: 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: 11

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

9. Best Professional Judgment (BPJ):

OMU ESS is doesn’t believe BPJ is a sound option because it does not provide a certainty in 

planning for future compliance. If BPJ is directed to the permit writer, then the EPA should 

acknowledge that the data developed in the proposed rule for chemical precipitation, biological 

treatment, and zero liquid discharge are all not cost-effective approaches. These three should be 

eliminated if BPJ is used.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 93. 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: Theresa Pugh

Commenter Affiliation: American Public Power Association (APPA)

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

Comment Excerpt Number: 73

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Best Professional Judgment (BPJ)

EPA also suggests a possible “BPJ” approach to determining proper FGD wastewater treatment. 

Neither APPA nor UWAG favor an open-ended BPJ approach, as it fails to provide the industry 
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with much certainty. However, if EPA applies a BPJ approach, it must specify that it does not 

mean permit writers have no standards for decision. To the contrary, the standards for making 

“BPJ” decisions have long been prescribed by the CWA.24 Permit writers “must consider” the 

listed statutory factors, including cost.25

If EPA does include an option for “BPJ” limits for FGD wastewater, it should acknowledge that 

the data developed in this very rulemaking establish that chemical precipitation, biological 

treatment, and zero discharge are all not cost-effective, for the reasons set out in these comments. 

None of these three treatments should be required if “BPJ” is used.

24 See 40 C.F.R. § 125.3(d).

25 See Clean Water Act §§ 304(b)(2)(B), (4)(B), 306(b)(1)(B).

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4379-A1, Excerpt Number 93. 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: Raven Power Holdings, LLC

Commenter Affiliation: Raven Power Holdings, LLC

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

Comment Excerpt Number: 5

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Raven Power does not support the Best Professional Judgment (BPJ) (options 3A, 3B). These 

options will place an undue burden and cost on both industry and NPDES permitting authorities.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6.

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: 5

External Review Flag: No External Review

External Review Incorporated into Response: No
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Comment Excerpt: 

The Use of Best Professional Judgment

Pursuant to Option 3a, USEPA is contemplating a possible "BPJ" approach to determining 

proper FGD wastewater treatment. While in general DP&L supports flexibility in the application 

of regulations for treating wastewater, in this instance DP&L does not believe a BPJ approach is 

appropriate for FGD wastewater given the lack of mature, commercially available and 

demonstrable technologies for treating this wastewater stream.

Comment Response: 

EPA disagrees that there is a lack of mature, commercially available, and demonstrable 

technologies for treating FGD wastewater. As explained in Section VIII of the preamble, 

consistent with the statute, EPA’s selected regulatory option is based on technologies that are 

available, demonstrated, economically achievable, and have acceptable non-water quality 

environmental impacts. EPA’s 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 or more advanced technology that can meet the effluent 

limitations. 

EPA did not establish a requirement that would direct permitting authorities to establish 

limitations for FGD wastewater using site-specific BPJ. See preamble section VIII.C and 

response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6.

Commenter Name: Peter A. Tennant

Commenter Affiliation: Ohio River Valley Water Sanitation Commission (ORSANCO)

Document Control Number: EPA-HQ-OW-2009-0819-4512-A2

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Options 3a and 3b use Best Professional Judgment (BPJ) for choosing the FGD treatment 

technology. ORSANCO and its member States believe that this will place an undue burden on 

the States to individually develop the expertise to evaluate all the potential technologies as well 

as the economics of each option. It may also potentially open the permits up to legal 

challenge. Therefore we urge EPA to reject options 3a and 3b.

Comment Response: 
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See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will 

eliminate burden on permitting authorities and delay related to legal challenges to the extent it 

establishes specified limitations and standards.

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: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

TMPA prefers having the certainty of Best Available Technology (BAT) to the open ended 

Best Professional Judgment (BPJ) approach, since BPJ fails to provide the industry with 

certainty. BAT may have a higher cost than other options, but the certainty is important for 

municipalities that are faced with costly business decisions. BAT provides more certainty on 

effluent controls than other options and therefore lowers long-run cost for public power utilities.

Comment Response: 

EPA decided not to establish a requirement that would direct permitting authorities to establish 

limitations for FGD wastewater using site-specific BPJ. The rule will eliminate burden on 

permitting authorities and delay related to legal challenges to the extent it establishes specified 

limitations and standards.

See preamble section VIII.C and response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt 

Number 6.

Commenter Name: Jeff Udd

Commenter Affiliation: Minnesota Pollution Control Agency (MPCA)

Document Control Number: EPA-HQ-OW-2009-0819-4606-A1

Comment Excerpt Number: 2

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The MPCA requests that the proposed regulations contained in regulatory options 3a and 3b as 

identified in 78 Fed. Reg. 34,432 not be included in the final regulations due to the inclusion of 

Best Professional Judgment (BPJ) requirements for regulation of discharges from Flue Gas 

Desulfurization (FGD) waste streams. BPJ determinations defer the identification of attainable 
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treatment limits to individual permit authors on a case-by-case basis rather than establishing a 

uniform federal standard. Therefore these proposed regulations would fail to complete the task 

with which the EPA is charged under the Federal Water Pollution Control Act, and would 

instead be likely to create inconsistencies in the way FGD wastes are regulated at the national 

level.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. EPA’s 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 or 

more advanced technology that can meet the effluent limitations. The rule will limit the burden 

on permitting authorities and provide certainty to industry and a level playing field to the extent 

that it specifies limits in the final rule.

Commenter Name: Jeff Udd

Commenter Affiliation: Minnesota Pollution Control Agency (MPCA)

Document Control Number: EPA-HQ-OW-2009-0819-4775-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

The MPCA supports the revision of these regulations by the Environmental Protection Agency 

(EPA) to maintain up-to-date federal standards to which dischargers in this category of point 

sources will be subject. To that end, the MPCA requests that the proposed regulations contained 

in regulatory options 3a and 3b as identified in 78 Fed. Reg. 34,432 not be included in the final 

regulations due to the inclusion of Best Professional Judgment (BPJ) requirements for regulation 

of discharges from Flue Gas Desulfurization (FGD) waste streams. BPJ determinations defer the 

identification of attainable treatment limits to individual permit authors on a case‐by‐case basis 

rather than establishing a uniform federal standard. Therefore these proposed regulations would 

fail to complete the task with which the EPA is charged under the Federal Water Pollution 

Control Act, and would instead be likely to create inconsistencies in the way FGD wastes are 

regulated at the national level.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. EPA’s 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 or 

more advanced technology that can meet the effluent limitations. The rule will limit the burden 

on permitting authorities and provide certainty to industry and a level playing field to the extent 

that it specifies limits in the final rule.
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Commenter Name: Kelly Jean Heffner

Commenter Affiliation: Pennsylvania Department of Environmental Protection

Document Control Number: EPA-HQ-OW-2009-0819-4811-A1

Comment Excerpt Number: 1

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

With regard to the EPA identified four preferred options, Options: 3a, 3b, 3, and 4a, PaDEP 

favors option 3. PaDEP does not believe it to be appropriate, (options 3a and 3b), to install an 

Effluent Limitations Guideline (ELG) that directs the permit writer to use Best Professional 

Judgment (BPJ). The purpose of an ELG is to establish uniform minimum treatment standards 

for the wastestream, with the BPJ process only applicable when the ELG has not been developed 

or does not address the process or pollutants of concern.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6. The rule will limit 

the burden on permitting authorities and provide certainty to industry and a level playing field to 

the extent that it specifies limits in the final rule.

Commenter Name: Zak Covar

Commenter Affiliation: Texas Commission on Environmental Quality (TCEQ)

Document Control Number: EPA-HQ-OW-2009-0819-4985-A2

Comment Excerpt Number: 8

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

Establishing Limits Based on Best Professional Judgment

TCEQ is opposed to the revised rulemaking specificall y requiring establishment of effiuent 

limitations based on BPJ in lieu of BAT numerical standards

EPA has established various preferred options for various waste streams in the revised effluent 

guidelines in the rulemaking preamble. Several options identify not establishing Best Available 

Technology (BAT) standards and in the alternative, specifically require permitting authorities to 

establish limits based on Best Professional Judgment (BPJ). TCEQ is opposed to the revised 

rulemaking specifically requiring establishment of effluent limitations based on BPJ, and if EPA 

does not choose to specifically establish BAT numerical standards, the revised effluent 
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guidelines should remain silent in establishing effluent limitations for these specific waste 

streams.

Comment Response: 

See response to DCN EPA-HQ-OW-2009-0819-4383-A1, Excerpt Number 6.
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6.j.ii. Support BPJ

Commenter Name: Patrick Finigan

Commenter Affiliation: Omaha Public Power District (OPPD)

Document Control Number: EPA-HQ-OW-2009-0819-4529-A1

Comment Excerpt Number: 4

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

3.Unique Facility Wastewater Treatment Configurations

On average, individual facilities have unique configurations, which include combined 

wastewater treatment system, that precludes upstream monitoring and may affect compliance 

achievement. Because of the significant expense of requiring these facilities to completely 

reconfigure their existing operations, the final rule should provide facilities with existing 

combined wastewater treatment with an alternative option for setting its effluent discharge limits.

Under this approach, a qualifying facility would have the option to undertake a Best Professional 

Judgment (BPJ) process with their state regulator to set the plant-specific effluent limitations 

based on a number of factors, including the ELGs otherwise applicable to the facility and the 

unique operational and technical limits that preclude the facility to comply with these ELGs 

through the existing combined wastewater treatment system. It is our understanding that the 

number of facilities with this concern is quite small, and a BPJ option will provide an adequate 

process for addressing both monitoring and compliance concerns on a case-by-case basis.

In addition, sources with unique design considerations that affect compliance should be given an 

alternative BPJ process that would assist in finding the most reasonable compliance option.

Comment Response: 

This commenter raises a couple of issues: upstream monitoring and BPJ permitting. The final 

rule does not establish a proposed anti-circumvention provision that would have required internal 

monitoring to demonstrate compliance with certain numeric limitations and standards. See 

Section VIII of the preamble for additional information. Also, Section XVI of the preamble 

provides additional information on approaches for existing facilities with combined wastewater 

to address combined wastestreams.

With respect to BPJ permitting, in general, the final rule establishes limitations and standards for 

a variety of wastestreams as such BPJ is not available for those wastestreams. BPJ is only 

applicable in the absence of effluent guidelines. See CWA sections 301(b) and 402(A)(1). See 

Chapter 5 of the NPDES Permit Writer’s Manual. Also, see Section VIII of the preamble for 

EPA’s rationale for its selection of Regulatory Option D as the basis for the final rule and its 

rejection of other regulatory options. These decisions reflect EPA’s view of what represents Best 
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available technology economically achievable (existing sources) or best available demonstrated 

control technology (new sources) for the industry as a whole.

EPA notes the availability of variances as allowed for by the CWA in the preamble to the final 

rule. These include Fundamentally Different factors variances (301(n)), economic variances 

301(c)(nonconventional pollutants), and water quality variances (301(g) Section 301(g) of the 

CWA authorizes a variance from BAT effluent guidelines for certain nonconventional pollutants 

(ammonia, chlorine, color, iron, and total phenols): 

FDF Variances 

In the Water Quality Act of 1987, Congress added section 301(n). This provision explicitly 

authorizes modifications of the otherwise applicable BAT effluent limitations, if a discharger is 

fundamentally different with respect to the factors specified in CWA section 304 or 403 (other 

than costs) from those considered by EPA in establishing the effluent limitations and standards. 

CWA section 301(n) also defined the conditions under which EPA can establish alternative 

requirements. Under Section 301(n), an application for approval of a FDF variance must be 

based solely on (1) information submitted during rulemaking raising the factors that are 

fundamentally different or (2) information the applicant did not have an opportunity to submit. 

The alternate limitation must be no less stringent than justified by the difference and must not 

result in markedly more adverse non-water quality environmental impacts than the national 

limitation.

EPA regulations at 40 CFR part 125, subpart D, authorizing the Regional Administrators to 

establish alternative limitations, further detail the substantive criteria used to evaluate FDF 

variance requests for direct dischargers. Thus, 40 CFR § 125.31(d) identifies six factors (e.g., 

volume of process wastewater, age and size of a discharger's facility) that can be considered in 

determining if a discharger is fundamentally different. The Agency must determine whether, 

based on one or more of these factors, the discharger in question is fundamentally different from 

the dischargers and factors considered by EPA in developing the nationally applicable effluent 

guidelines. The regulation also lists four other factors (e.g., inability to install equipment within 

the time allowed or a discharger's ability to pay) that cannot provide a basis for an FDF variance. 

In addition, under 40 CFR § 125.31(b) (3), a request for limitations less stringent than the 

national limitation can be approved only if compliance with the national limitations will result in 

either (a) a removal cost wholly out of proportion to the removal cost considered during 

development of the national limitations, or (b) a non-water quality environmental impact 

(including energy requirements) fundamentally more adverse than the impact considered during 

development of the national limits. The legislative history of CWA section 301(n) underscores 

the necessity for the FDF variance applicant to establish eligibility for the variance. EPA's 

regulations at 40 CFR § 125.32(b)(1) and 40 CFR § 403.13 impose this burden upon the 

applicant. The applicant must show that the factors relating to the discharge controlled by the 

applicant's permit that are claimed to be fundamentally different are, in fact, fundamentally 

different from those factors considered by EPA in establishing the applicable guidelines and 

standards. In practice, very few FDF variances have been granted for past ELGs. An FDF 

variance is not available to a new source subject to NSPS or PSNS. DuPont v. Train, 430 U.S. 

112 (1977)
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Economic Variances

Section 301(c) of the CWA authorizes a variance from the otherwise applicable BAT effluent 

guidelines for nonconventional pollutants due to economic factors. See also CWA section 301(l). 

The request for a variance from effluent limitations developed from BAT guidelines must 

normally be filed by the discharger during the public notice period for the draft permit. Other 

filing periods can apply, as specified in 40 CFR § 122.21(m)(2). Specific guidance for this type 

of variance is provided in “Draft Guidance for Application and Review of Section 301(c) 

Variance Requests,” dated August 21, 1984, available on EPA's Web site at 

http://www.epa.gov/npdes/pubs/OWM0469.pdf.

Water Quality Variances

Section 301(g) of the CWA authorizes a variance from BAT effluent guidelines for certain 

nonconventional pollutants (ammonia, chlorine, color, iron, and total phenols) due to localized 

environmental factors. As this final rule does not establish limitations or standards for any of 

these pollutants, this variance is not applicable to this particular rule.

With respect to BPJ permitting, in general, the final rule establishes limitations and standards for 

a variety of wastestreams as such BPJ is not available for those wastestreams. BPJ is only 

applicable in the absence of effluent guidelines. See CWA sections 301(b) and 402(A)(1). See 

Chapter 5 of the NPDES Permit Writer’s Manual. Also see Section VIII of the preamble for 

EPA’s rationale for its selection of Regulatory Option D as the basis for the final rule and its 

rejection of other regulatory options.

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: 9

External Review Flag: No External Review

External Review Incorporated into Response: No

Comment Excerpt: 

EPA’s Technical Development Document (TDD) recognizes that there is a wide assortment of 

FGD designs, coal types using FGD, and existing FGD wastewater control systems.10 To 

address this situation, LPPC suggests that state regulators should be given the flexibility to assess 

the circumstances present at an individual facility. Thus, source‐specific Best Professional 

Judgment (BPJ) standards may be appropriate in certain instances.11 When needed, a BPJ 

process could be obtained by sources through an application or waiver process stating why the 

facility requires a separate process. A BPJ process would allow for considerations of factors 

including remaining life of the unit, size of the unit, discharge flow rate, and any physical 

constraints that would preclude chemical precipitation, and thus would be an important option 

for small or uniquely situated units. However, LPPC emphasizes that the BPJ process should 
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only be an alternative that the facility owner or operator elects in those situations where the 

application of chemical precipitation is not technically or economically feasible.

10 Tables 4‐11 and 4‐12 on page 4‐30 of the Technical Development Document for the 

Proposed Effluent Limitation Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category, EPA‐821‐R‐13‐002, April 2013 (TDD) note the number of different coal 

types and pollution control designs in the industry. The text on page 6‐2 of the TDD states that 

“[t]he pollutant concentrations in FGD wastewater vary from plant to plant depending on the 

coal type, the sorbent used, the materials of construction in the FGD system, the FGD system 

operation, the level of recycle within the absorber, and the air pollution control systems operated 

upstream of the FGD system.”

11 Several LPPC members with larger capacity plants (>2000MW) note that MW capacity is 

not an appropriate threshold for BPJ or other ELG limitations, also noting that FGD slurry 

blowdown flow rates from larger plants such as theirs is a small fraction of the approximately 1.2 

million gallons per day (MGD) average cited on page 6‐2 and in Table 6‐1 of the Technical 

Development Document for the Proposed Effluent Limitation Guidelines and Standards for the 

Steam Electric Power Generating Point Source Category, EPA‐821‐R‐13‐002, April 2013.

Comment Response: 

EPA disagrees that the BPJ process should be an alternative “that the facility owner or operator 

elects.” As described in Section VIII of the preamble, EPA determined Regulatory Option D is 

available and economically achievable for the industry. Also see response to DCN EPA-HQOW-2009-0819-4529-A1, Excerpt Number 4.