MEMORANDUM

TO: Steam Electric Rulemaking Record

FROM: Elizabeth Gentile, ERG

DATE: September 30, 2015

SUBJECT: Methodology for Estimating Impoundment Age, Capacity, and Reductions in 

Capacity Used to Estimate Benefits Associated with Avoided Impoundment 

Failures

Steam electric power plants manage combustion residuals such as flue gas desulfurization (FGD) 

solids, fly ash, and bottom ash using either wet or dry handling practices. For plants that use wet 

handling systems, the combustion residuals are typically sluiced to one or more surface 

impoundments (i.e., settling ponds), where the solids settle out of the water. In addition to solids, 

these impoundments typically contain water with high concentrations of pollutants originating 

from the combustion residuals, including dissolved metals.

Although the impoundments are subject to state regulations, events such as the failure of a 

combustion residual impoundment at the Tennessee Valley Authority’s Kingston Fossil Plant in 

2008, demonstrate the potential severity and cost of structural failures. In that case, over 5 

million cubic yards of combustion residual was accidentally released, resulting in cleanup costs 

and other costs and damages exceeding $1 billion. Although the probabilities of catastrophic 

releases such as the Kingston’s spill may be low, the high costs associated with these events 

mean that even very small risks entail significant costs to society. In addition, other smaller 

unintentional releases (e.g., spills) from surface impoundments may also result in substantial 

damages and incur large cleanup and other costs.

Some plant owners may reduce or terminate their reliance on impoundments to handle 

combustion residuals in response to the requirements of the effluent limitations guidelines and 

standards (ELGs). These changes would affect the future probability of impoundment failures 

and, as a result, accidental, and sometimes catastrophic, releases of combustion residual solids 

and wastewater. Potential benefits arising from the reduced risk of impoundment failures include 

avoided cleanup costs, environmental damage, and litigation costs.

EPA quantified and monetized these benefits based on predictions about how future 

impoundment structural failures and other accidental releases from impoundments would be 

reduced by the ELGs, and the commensurate avoided costs of spill cleanup, natural resource 

damages, and litigation expenses. The details of this analysis are described in the Benefits and 

Cost Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category report (EPA-821-R-15-005).

The analysis used to estimate the benefits associated with these avoided impoundment failures

takes into account the impoundment age, capacity (expressed as volume, in cubic feet), the type 
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September 30, 2015

Page 2

of impoundment (i.e., storage or disposal), and the estimated reductions in impoundment 

capacity. Therefore, ERG used data reported in responses to the Questionnaire for the Steam 

Electric Power Generating Effluent Guidelines (Steam Electric Survey) to obtain these 

characteristics from each of the 1,070 coal combustion residual (CCR) impoundments considered 

in the scope of the Steam Electric ELGs.

1 ERG also estimated how the future impoundment 

capacity for each impoundment would be reduced under each of the five regulatory options. For 

more information on the regulatory options considered as part of the rulemaking, see Section 8 of 

the Technical Development Document for the Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (EPA-821-R-15-007).

1.0 DETERMINING SURFACE IMPOUNDMENT AGE

ERG used data from Part A of the Steam Electric Survey to determine the age of CCR surface 

impoundments. Question A3-2, Table A-4, requested information on the initial year the 

impoundment was brought online for both active and inactive impoundments. ERG was able to 

obtain the year brought online for 1,059 of the 1,070 CCR impoundments from the Steam 

Electric Survey.

For the remaining 11 impoundments, ERG used the data from the 1,059 impoundments to 

calculate an average installation year associated with active impoundments and an average

installation year associated with inactive impoundments.

ERG calculated the impoundment age by subtracting the year the impoundment was brought 

online from 2009. ERG used 2009 as the basis for the age because the data collected in the 

Steam Electric Survey represents 2009.

2.0 DETERMINING SURFACE IMPOUNDMENT CAPACITY

ERG determined the capacity, or volume, for all 1,070 CCR surface impoundments using data 

from Part D of the Steam Electric Survey. Table D-5 requested information on the original 

volume (in cubic feet) of the surface impoundment. From Table D-5, ERG was able to determine 

the volume for 893 impoundments.

For the remaining 177 surface impoundments, ERG estimated the volume of the impoundments 

using the following hierarchy of estimation methods:

1) For three of these impoundments (two active and one inactive)2, ERG determined the

impoundment volume using the original surface area (in square feet), top elevation (in 

feet), and bottom elevation (in feet). ERG calculated the volume of the three

impoundments using the following equation:

Volume (ft3) = Surface Area (ft2) × [Top Elevation (ft) – Bottom Elevation (ft)]

 1 Using information reported for the Steam Electric Survey, EPA determined that in 2009 there were 1,070 surface 

impoundments containing coal combustion residuals that had not been retired and closed. If surface impoundments 

containing petroleum coke residuals are also included, the total number of surface impoundments containing either 

coal or petroleum coke combustion residuals is 1,071.

2 Surface area and elevation data for these three impoundments were not reported in the Steam Electric Survey.
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September 30, 2015

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2) For 111 of these impoundments (99 active and 12 inactive), ERG estimated the 

impoundment volume using an average volume per flow rate into an impoundment (in 

cubic feet per gallons per day (gpd)) corresponding to status (active or inactive). Using 

Steam Electric Survey data for all combustion residual impoundments that reported both 

baseline flow rates into the impoundment and impoundment volume, ERG calculated an

average volume per flow rate for each impoundment for which data were available and 

then averaged those ratios for all the impoundments to calculate a volume per flow factor, 

which was 600 ft3

/gpd.

3 See Section 3 for more information on how ERG calculated 

impoundment-specific flow rates entering the surface impoundments. ERG estimated the 

volume (in cubic feet) by multiplying the impoundment-specific flows rates (described in 

Section 4) by the calculated volume per flow factor.

3) For 63 of these impoundments (53 active and 10 inactive), ERG calculated the average 

volume for active and inactive impoundments based on the 896 impoundments for which 

impoundment volumes were reported in the Steam Electric survey (893 impoundments) 

or where ERG calculated the volume based on impoundment dimensions (3 

impoundments, identified in bullet 1). These 896 impoundments account for 832 active 

and 64 inactive impoundments. The average volume for active impoundments was 

49,400,000 ft3 and the average volume for inactive impoundments was 48,700,000 ft3

.

3.0 DETERMINING IMPOUNDMENT TYPE

In order to accurately estimate the benefits associated with certain types of impoundments, ERG 

developed an approach to classify the list of 1,070 impoundments as either storage or disposal. 

ERG used the same definitions for storage and disposal impoundments that were used in the 

CCR rule: 

• Storage impoundment – an impoundment that is periodically dredged and has its CCR 

disposed elsewhere such that it can continue operating indefinitely.

• Disposal impoundment – an impoundment that is not dredged and all CCRs are left in 

place in perpetuity.

ERG used the following steps to classify each of the 1,070 surface impoundments as storage or 

disposal:

1) Identified all impoundments that have a direct CCR influent (e.g., ash transport water 

flows directly from the generating unit to the impoundment) using the “pond mapping 

analysis4

” (based on Steam Electric Survey responses). These impoundments were 

classified as primary ponds (744 impoundments). All non-primary ponds (i.e., no direct 

CCR influent) were classified as storage ponds (326 impoundments). This assumption is 

similar to an assumption made by ORCR for the CCR rule, which assumed that each 

 3 ERG used Steam Electric Survey data from 625 combustion residual impoundments that reported both baseline 

flow rates into the impoundment and the impoundment volume.

4 The “pond mapping analysis” is an analysis that “maps” all impoundments in the survey to generating units to 

identify which generating units transfer which CCR wastestreams to all the impoundments and how the wastewater 

flows through the impoundments (e.g., which impoundments overflow to the next impoundment and which are in 

series versus in parallel) (DCN SE05875).
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September 30, 2015

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plant would operate only one disposal impoundment, and all other impoundments would 

be storage impoundments.

2) For all 744 primary impoundments identified in Step 1, ERG evaluated responses to 

Question D4-5 of the Steam Electric Survey to determine whether the plant reported 

dredging the impoundment within the last five years.

5

 All impoundments that were

reported as being dredged in this timeframe were classified as storage impoundments

(421 impoundments). 

3) For all 323 primary impoundments flagged after Step 2, ERG evaluated responses to 

Question D4-3 (Table D-5) to determine whether the plant reported an expected end of 

life for the impoundment and, if so, whether there are solids that are expected to remain 

in the impoundment at the end of its life. All impoundments with an expected end of life 

date of “infinite,” “indefinite,” or “life of plant” were classified as storage 

impoundments. Additionally, all impoundments with an end of life tonnage reported as 

zero were classified as storage impoundments (38 impoundments).

4) For the remaining 285 primary impoundments, ERG evaluated the EIA-923 data used by 

ORCR for the final CCR rule to determine whether: 1) the plant reported any CCR 

tonnages as disposed to any location; and 2) the plant reported any CCR tonnage as 

disposed in a surface impoundment. ERG used the following approach to classify the 

impoundments based on the EIA data:

a. If the plant reported any CCR tonnage as disposed in a surface impoundment, the 

impoundment was classified as disposal (143 impoundments).

b. If the plant did not report any CCR tonnage in the EIA data, the impoundment 

was classified as disposal (6 impoundments). 

c. If the plant reported any CCR tonnage as disposed to any location, but did NOT 

report any CCR tonnage as disposed in a surface impoundment, the impoundment 

will be classified as storage (136 impoundments).

Using this approach, ERG identified 921 storage impoundments and 149 disposal 

impoundments.

4.0 ESTIMATING REDUCTION IN IMPOUNDMENT CAPACITY

ERG estimated the reduction in impoundment capacity for all 1,070 CCR surface impoundments

for each of the regulatory options for two scenarios: incorporating the effects of CCR rule and 

incorporating the effects from both the CCR rule and the proposed Clean Power Plan (CPP).6

Each of the six regulatory options will result in a decrease in the wastewater entering the

impoundments either by reducing or eliminating the volume of wastewater sent to the 

impoundment. ERG estimated that the impoundment capacity would decrease by the percent 

reduction in flow into each impoundment. While the reduction in flow entering the impoundment 

 5 ERG used a five-year dredging period because the Steam Electric Survey specifically asked the plants to identify 

whether the impoundment had been dredged in the past five years. Therefore, ERG could not evaluate whether the 

impoundment has been dredged in a longer time period. 6 EPA typically includes only final rules in its base case for its IPM analyses. However, at the time EPA performed 

the IPM analyses for this rule, it did not have details of the final CPP rule. EPA therefore used information from the 

proposed CPP rule as a proxy for purposes of the ELG analyses.
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September 30, 2015

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will not necessarily decrease the size of the impoundment unless the plant closes portions of the 

impoundment after the 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. Furthermore, any breach or spill that does occur would likely be less severe since 

the impoundment would contain less combustion residual solids or wastewater. ERG used the 

methodology described in the following subsections to estimate the reduction in impoundment 

capacity.

4.1 Estimate Total Baseline Flow

ERG used information from the Steam Electric Survey to determine the types of combustion 

residual waste contained in each of the 1,070 CCR impoundments. ERG determined which 

impoundments received FGD wastewater, fly ash transport water, and bottom ash transport 

water. The Steam Electric Survey did not require plants to differentiate between CCR leachate 

from impoundments versus CCR leachate from landfills. For this reason, ERG was unable to 

evaluate which impoundments contained combustion residual landfill leachate and, therefore, 

leachate was not included in the analysis.

ERG then calculated a baseline flow associated with each impoundment. As described in the

Incremental Costs and Pollutant Removals for Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category report (DCN 

SE05831), ERG estimated the amount of FGD wastewater discharged by each plant, at the FGD 

system level, for use in baseline and post-compliance pollutant loadings calculations. Similarly, 

ERG estimated the amount of fly ash, bottom ash, and/or combined ash wastewater discharged 

by each plant, and the generating unit level, for use in baseline and post-compliance pollutant 

loadings calculations.7 ERG used these waste stream specific baseline flow rates and the pond 

mapping analysis to calculate the total baseline flow for each impoundment.

First, ERG calculated waste stream-specific baseline flows for impoundments at plants where the 

waste stream specific impoundments matched between the listing of 1,070 CCR impoundments 

and the pond mapping analysis.8 ERG used the pond mapping analysis to assign the FGD-level 

and generating unit-level flows to the designated impoundments. For example, if a plant sends 

bottom ash transport water from Generating Unit A to Impoundment A and bottom ash transport 

water from Generating Unit B to Impoundment B, ERG assigned the Generating Unit A bottom 

ash transport water flow to Impoundment A only. 

For the plants where the impoundments did not match between the listing of the 1,070 CCR 

impoundments and the pond mapping analysis, ERG assumed that the impoundments operate in 

series such that each impoundment would receive the total volume of any combustion residual 

waste generated. For example, if two impoundments at a plant are flagged as FGD 

impoundments, ERG assigned the total FGD wastewater flow to both impoundments.

 7 For combined ash flows that could not be separated into bottom ash and fly ash waste streams based on flow data 

reported in the Steam Electric Survey, ERG used a ratio of the amount of ash produced per generating unit to the 

total amount of ash produced to estimate the separate fly ash and bottom ash flows at the generating unit level.

8 Because the list of 1,070 CCR ponds and the pond mapping analysis were developed using different data elements 

of the Steam Electric Survey database, the lists do not match exactly.
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September 30, 2015

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ERG calculated the total baseline flow associated with each impoundment by summing the waste

stream-specific flows. For example, if an impoundment contains FGD wastewater and fly ash 

transport water, ERG calculated the baseline flow into the impoundment as the volume of FGD 

wastewater generated plus the volume of fly ash transport water generated.

4.2 Estimate Change in Baseline Capacity Associated with the CCR Rule

To account for the change in impoundment capacity associated with the CCR rule, ERG 

estimated the reduction in flow associated with CCR conversions. ERG subtracted the fly ash 

flows from the total baseline flows for fly ash impoundments at plants flagged as fly ash CCR 

conversions. ERG subtracted the bottom ash flows from the total baseline flows for bottom ash 

impoundments at plants flagged as bottom ash CCR conversions.9

ERG calculated the flow reduction using the following equation:

Percent CCR Baseline Reduction = (Baseline Flow – CCR Baseline Flow)/Baseline Flow

After calculating the percent reduction in flow associated with the CCR rule, ERG multiplied 

this percent reduction by the baseline volume calculated in Section 2.0 to estimate the reduced 

capacity for each impoundment associated with the CCR rule. 

ERG calculated a reduced capacity using the following equation:

CCR Baseline Volume = Baseline Volume x (1 – Percent CCR Baseline Reduction)

4.3 Estimate the Change in Capacity Associated with the ELG 

ERG then calculated the reduction in flow into the impoundment for Regulatory Options A 

through E.

10 ERG calculated post-compliance flows for each impoundment based on the types of 

combustion residual contained in the impoundment and the effect of the regulatory option. For 

example, if an impoundment contains FGD wastewater and bottom ash transport water, for 

Option A, the post-compliance flow would include only the bottom ash transport water and for 

Option D, the post-compliance flow would be zero.11 Because this flow reflects the change 

incorporating the CCR rule, ERG also subtracted fly ash transport water flows from plants 

flagged as fly ash CCR conversions and bottom ash transport water flow from plants flagged as 

bottom ash CCR conversions. ERG then calculated the flow reduction by subtracting the postcompliance flow from the CCR baseline flow for each impoundment.

ERG calculated the percent reduction in flow using the following equation:

Percent Reduction = (CCR Baseline Flow – Post-Compliance Flow)/CCR Baseline Flow

 9 See Section 9 of the TDD for more information on how the CCR rule was incorporated into the ELG analyses.

10 During development of the final rule, EPA decided not to base the final rule on Option F for existing sources (see 

Section VIII.C.1 of the preamble). 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 options considered.

11 If the flow is associated with a generating unit that is oil-fired or has a generating capacity of 50 megawatts (MW) 

or less, ERG did not subtract the flow from the total baseline flow. The ELGs contain no new requirements for these 

generating units.
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September 30, 2015

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As stated previously, ERG assumed that the percent reduction in flow is equivalent to the percent 

reduction in impoundment capacity because the impoundment will no longer have to handle or 

treat this percentage of flow.

After calculating the percent reduction in flow, ERG multiplied this percent reduction by the 

CCR baseline volume calculated in Section 4.2 to estimate the reduced capacity for each 

impoundment under each regulatory option.

ERG calculated a reduced capacity for each regulatory option using the following equation:

Option Volume = CCR Baseline Volume x (1 – Percent Reduction)

4.4 Estimate the Change in Capacity Associated with CPP 

ERG estimated reductions in impoundment capacities in addition to those calculated in Section 

4.3 to incorporate generating units projected to retire as a result of the CPP.12 First, ERG 

identified full CPP plant retirements (i.e., all operating generating units at a plant are projected to 

retire as a result of the CPP). ERG estimated no reductions in baseline capacity associated with 

the ELG. This analysis is likely an overestimate of reduction in capacity because ERG estimated 

reductions at plants with partial CPP retirements (i.e., only a portion of the operating generating 

units at a plant are projected to retire as a result of the CPP).

Additionally, ERG identified plants that have at least one operating generating unit flagged as a 

CPP retirement. ERG estimated no reductions in baseline capacity associated with the ELG. This 

analysis is likely an underestimate of reductions in baseline capacity because ERG did not 

estimate reductions at plants with partial CPP retirements.

The results of these analyses were used to determine a range of the baseline capacity reductions 

associated with the CPP.

5.0 RESULTS

The age, baseline capacity, CCR baseline capacity, and reduced capacity for each of the 1,070 

CCR impoundments under the five regulatory options are presented in the document entitled 

“Estimated Impoundment Age, Capacity, and Reductions in Capacity” (DCN SE05825A1). This 

file also includes the impoundment classification (i.e., storage or disposal) for each of the 1,070 

CCR impoundments and the estimated reductions associated with the two CPP analyses.

ERG’s impoundment-level baseline flows, CCR baseline flows, and option flows can be found in

ERG’s database for estimating reduced impoundment capacities for avoided impoundment 

failures (DCN SE05941).

 12 See Section 9 of the TDD for more information on how the CPP was incorporated into the ELG analyses.