MEMORANDUM 

TO: Steam Electric Rulemaking Record 

FROM: Deb Bartram, ERG 

TJ Finseth, ERG 

 Elizabeth Sabol, ERG 

 Daisy Wang, ERG 

DATE: January 28, 2013 

SUBJECT: Steam Electric Effluent Guidelines Non-Water Quality Impacts

1. INTRODUCTION/BACKGROUND

The elimination or reduction of one form of pollution has the potential to aggravate other 

environmental problems, an effect frequently referred to as cross-media impacts. Under sections 

304(b) and 306 of the Clean Water Act, EPA is required to consider non-water quality 

environmental impacts (NWQIs) in developing effluent limitations guidelines and standards 

(ELGs). Accordingly, ERG evaluated the effect of these regulations on energy usage, air 

pollution, solid waste generation and management, and water usage. 

ERG determined that the proposed ELGs have NWQIs associated with operations for treating 

and managing flue gas desulfurization (FGD) wastewater, combustion residual landfill leachate, 

and ash transport water. The proposed ELGs also limit flue gas mercury control wastewater and 

gasification wastewater; however, because all plants generating flue gas mercury control 

wastewater and gasification wastewater currently operate the technologies identified as the basis 

for BAT, ERG does not predict any net increase of energy or fuel usage, sludge generation, air 

emissions, or water usage for these wastestreams for the proposed ELGs. Additionally, because 

all plants generating and discharging nonchemical metal cleaning wastes are already meeting the 

proposed BAT limitations, based on the current BPT standard, ERG does not predict any net 

increase of energy or fuel usage, sludge generation, air emissions or water usage for nonchemical 

metal cleaning wastes for the proposed ELGs. ERG estimated NWQIs on a plant-specific basis 

for each of the technologies and activities that make up the regulatory options considered for the 

proposed Steam Electric ELGs. These technologies include: 

 Chemical precipitation wastewater treatment; 

 Biological wastewater treatment; 

 Vapor-compression evaporation; 

 Dry vacuum fly ash transport; 

 Mechanical drag system (MDS) or remote MDS bottom ash transport; 

 Transportation of solids (on or off site); 

 Disposal of solids (on or off site landfills); and 

 Combustion residual surface impoundment operation and maintenance. 
Memorandum 

January 28, 2013 

Page 2 

Table 1-1 presents the regulatory options that are being considered for this rulemaking, and the 

technologies recommended for each wastestream that would lead to NWQIs. Increased need for 

transportation and disposal of solids via trucks will occur as a result of each technology 

considered for the proposed ELGs because sludge from wastewater treatment and dry handled 

ash will need to be moved to landfills, instead of pumped and wet sluiced to impoundments. 

Table 1-1. Steam Electric Regulatory Options 

Wastestreamsa

Technologies Leading to Non-Water Quality Environmental Impacts 

1 2 3 4 5

FGD 

Wastewater 

Chemical 

Precipitation 

Chemical 

Precipitation + 

Biological 

Treatment 

Chemical 

Precipitation + 

Biological 

Treatment 

Chemical 

Precipitation + 

Biological 

Treatment 

Chemical 

Precipitation + 

Vaporcompression 

Evaporation 

Fly Ash Transport 

Water 

None None Dry vacuum fly 

ash transport 

Dry vacuum fly 

ash transport 

Dry vacuum fly 

ash transport 

Bottom Ash 

Transport Water 

None None None MDS/remote 

MDS bottom ash 

transport 

MDS/remote 

MDS bottom ash 

transport 

Leachate None None None Chemical 

Precipitation 

Chemical 

Precipitation a

 Nonchemical metal cleaning wastes, gasification wastewater, and flue gas mercury control wastewater are not 

listed in the table because there are no non-water quality environmental impacts associated with the proposed ELGs 

for these wastestreams. 

In the evaluation of technology options being considered for the Steam Electric industry, ERG 

estimated the following NWQIs: 

 Energy Usage. Due to the proposed ELGs, steam electric power plants will use 

additional energy to transport ash and other solids on or off site, to operate 

wastewater treatment systems (e.g., chemical precipitation, biological treatment), 

and to operate ash handling systems. Similarly, as applicable, ERG also estimated 

the decrease in energy requirements resulting from the reduction in wet sluicing 

operations and use of earth-moving equipment. Energy usage included in this 

analysis is expressed in either megawatt hours (MWh) for equipment added to the 

plant systems or in consumed fuel (gallons) for transportation equipment. 

 Air Pollution. Steam electric power plants generate air pollution when they use 

energy, and as such, the incremental increase in energy usage associated with the 

regulatory options will also result in increased air pollution. Air emissions are 

generated from the operation of wastewater treatment systems and ash handling 

systems, as well as from the operation of transport vehicles such as dump, 

vacuum, and water trucks. Similarly, ERG also estimated the decrease in air 

pollution associated with the reduction in wet sluicing operations and the use of 

earth-moving equipment. ERG also estimated the change in air emissions 

associated with the change in the profile of electricity generation based on the 

affect of the proposed rule. Criteria air pollutants are those pollutants for which a 

national ambient air quality standard (NAAQS) has been set and include SO2 and 
Memorandum 

January 28, 2013 

Page 3 

NOx. Greenhouse gases (GHGs) are gases such as CO2, CH4, and N2O1 that 

absorb radiation, thereby trapping heat in the atmosphere, and contributing to 

global warming. The NWQI analysis quantifies the incremental amount of air 

emissions for each of the ELG regulatory options. 

 Solid Waste Generation. Steam electric power plants generate solid waste 

associated with dry ash as a result of fly ash and bottom ash handling and sludge 

from wastewater treatment systems. The regulatory options would not alter the 

amount of fly ash or bottom ash generated. However, the regulatory options 

evaluated would likely increase the amount of solid waste generated from FGD 

wastewater and landfill leachate treatment, including sludge from chemical 

precipitation, biological treatment, and vapor-compression evaporation 

technologies. Solid waste included in this analysis is expressed as tons per year. 

 Water Usage. Steam electric power plants use water in wet sluicing operations 

for fly ash and bottom ash, as well as operating FGD wet scrubbers. The 

regulatory options for fly ash and bottom ash eliminate or reduce water use 

associated with current wet sluicing operating systems. The amount of water used 

for FGD wastewater treatment is only reduced for plants that recycle water as part 

of their treatment system. 

This memorandum presents the methodology used for estimating the incremental increases in 

NWQI, perspective on the potential impacts the NWQIs have on an industry- and national-level, 

and a summary of the NWQI determined for each regulatory option. 

2. ENERGY USAGE METHODOLOGY

Energy usage associated with the implementation of the Steam Electric ELGs is based on energy 

used to operate wastewater treatment systems, dry ash transport systems, and transport and 

disposal operations. For those plants that ERG determined would incur costs to comply with the 

regulatory options, ERG considered whether or not there would be an associated incremental 

change in the amount of energy used. That energy use varies depending on the regulatory option 

evaluated and the current operations of the plant. Therefore, as applicable, ERG estimated the 

additional energy usage for equipment added to the plant systems or for fuel consumed for 

transportation and operating equipment. Similarly, as applicable, ERG also estimated the 

decrease in energy requirements resulting from the reduction in wet sluicing operations and use 

of earth-moving equipment. Energy usage associated with power usage was estimated based on 

the horsepower rating of the pumps and other equipment, and was calculated in terms of MWhs. 

To determine potential increases in electrical energy use, ERG estimated the amount of energy 

needed to operate wastewater treatment systems and ash handling systems. To determine 

potential decreases in electrical energy use, ERG estimated the amount of energy saved from 

reducing wet sluicing pump operations based on the horsepower rating of the pumps. Similarly, 

ERG estimated the amount of energy saved by reducing the number of backhoes needed to 

dredge solids from ash impoundments, resulting from the reduction of wet sluicing operations. 

 

1

 EPA did not specifically evaluate nitrous oxide emissions as part of the NWQI analysis. To avoid double counting 

air emission estimates, EPA only calculated nitrogen oxide emissions, which would include nitrous oxide emissions. 
Memorandum 

January 28, 2013 

Page 4 

ERG estimated these energy savings using the horsepower rating of the backhoe engine. ERG 

only estimated energy savings associated with earth-moving equipment for plants operating 

surface impoundments. See EPA’s Incremental Costs and Pollutant Removals for Proposed 

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

Category for more information on the specific calculations used to estimate energy [U.S. EPA, 

2013b]. 

For example, ERG calculated the net increase in energy requirements using the following general 

equation: 

Net Energy Increase (MWh) = Wastewater Treatment Energy Demand (MWh) + Fly Ash 

Handling Energy Demand (MWh) + Bottom Ash Handling Energy Demand (MWh) – 

Wet Sluicing Energy Demand (MWh) – Earth-moving Equipment Energy Demand 

(MWh) 

Table 2-1 presents the net increases in annual electrical energy usage associated with the 

regulatory options considered as part of this rulemaking. 

Energy usage also includes the fuel consumption associated with transporting the solid waste 

generated due to the technology options. The methodology associated with estimating the fuel 

consumption for transportation is described in EPA’s Incremental Costs and Pollutant Removals 

for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating 

Point Source Category report [U.S.EPA, 2013b]. That methodology estimates the need for 

increased transportation of solid waste and ash at steam electric power plants to onsite or offsite 

landfills using open dump trucks. The frequency and distance of transport depends on a plant’s 

operation and configuration. For example, the volume of waste generated per day determines the 

frequency with which trucks will be travelling to and from the storage sites. The availability of 

either an onsite or offsite non-hazardous landfill and its distance from the plant determines the 

length of travel time. Fuel usage is calculated as gallons of fuel used. In general, the fuel usage is 

calculated as shown: 

Fuel (gallons) plant = [((Loading Time (hr/trip) idling + Unloading Time (hr/trip) idling) x 

(Fuel Consumption (gal/hr) idling)) + (Transport Distance (mile/round trip) x 

Fuel consumption (gal/mile))] x (Number of Trips (trips/yr)). 

Where: 

Loading Time (hr/trip) = The estimated time to load an open dump truck with 

sludge and/or ash per trip. Consistent with the 

transportation cost methodology, ERG estimates the 

loading time to be 0.1667 hours (10 minutes) per trip 

[U.S.EPA, 2013b]. 

Unloading Time (hr/trip) = The estimated time to unload an open dump truck with 

sludge and/or ash per trip. Consistent with the 

transportation cost methodology, ERG estimates the 

unloading time to be 0.1667 hours (10 minutes) per trip 

[U.S.EPA, 2013b]. 
Memorandum 

January 28, 2013 

Page 5 

Fuel Consumption (gal/hr) idling = The estimated fuel consumption while the truck is 

idling. The MOBILE6.2 vehicle emission modeling 

software assumes that dump trucks average 2.5 miles 

per hour and 6.6 miles per gallon at idle. Therefore, 

ERG estimates the idle fuel consumption to be 0.38 

gal/hr. 

Transport Distance (mile/round trip) = The estimated round trip distance to/from the landfill. 

Distance varies based on plants with onsite versus 

offsite landfills. For onsite landfills, ERG estimates a 

round trip to be 2.6 miles. For offsite landfills, ERG 

estimates a round trip to be 40 miles. 

Fuel consumption (gal/mile) = The estimated fuel consumption while the truck is in 

drive. Consistent with the transportation cost 

methodology, ERG estimates the fuel consumption to 

be 20.24 gal/100 miles [U.S.EPA, 2013b]. 

Number of Trips (trips/yr) = The calculated number of trips for one year, based on 

the amount of ash and/or FGD solids generated by the 

plant, in the transportation cost methodology to truck 

all ash and FGD solids to the onsite or offsite landfill 

[U.S.EPA, 2013b]. 

ERG also estimated fuel consumption associated with the dust suppression water trucks based on 

the total distance (in miles) traveled and the total number of hours estimated for water truck 

operations. See Section 7.1.6.9 in EPA’s Incremental Costs and Pollutant Removals for 

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

Source Category report for more information on the specific calculations used to estimate water 

truck fuel usage [U.S.EPA, 2013b]. 

The net increases in national annual fuel consumption associated with the regulatory options are 

shown in Table 2-1. 

Table 2-1. Industry-Level Energy Requirements by Regulatory Option 

Regulatory Option 

Electrical Energy Usage 

(MWh/year) 

Fuel Consumption

(GPY) 

1 84,333 172,205 

2 191,327 173,421 

3 303,332 3,041,191 

4 673,780 6,027,266 

5 2,835,389 7,548,543 

To provide some perspective on the potential net increase in annual electric energy consumption 

associated with the preferred options, ERG compared the estimated increase in energy usage 

(MWh), as shown in Table 2-1, to the net amount of electricity generated in a year by all electric 
Memorandum 

January 28, 2013 

Page 6 

power plants throughout the United States. According to EPA’s Emissions & Generation 

Resource Integrated Database (eGRID), the electric power industry generated approximately 

3,951 million MWh of electricity in 2009 [U.S. EPA, 2012a]. ERG estimates that energy 

increases associated with Regulatory Option 3 will be less than eight thousandths of a percent 

(0.008%) of the total electricity generated by all electric power plants and energy increases 

associated with Regulatory Option 4 will be 17 thousandths of a percent (0.017%) of the total 

electricity generated by all electric power plants. 

Similarly, ERG compared the additional net fuel consumption (gallons) estimated for the 

preferred options, as shown in Table 2-1, to national fuel consumption estimates for motor 

vehicles. According to the U.S. Energy Information Administration (EIA), in 2009, 

approximately 34 billion gallons of distillate fuel oil was consumed by on-highway vehicles, 

which include automobiles, trucks, and buses [U.S. DOE, 2009]. ERG estimates that the fuel 

consumption increase associated with Regulatory Option 3 will be less than nine thousandths of 

a percent (0.009%) of total fuel consumption by all motor vehicles and the fuel consumption 

increase associated with Regulatory Option 4 will be less than 18 thousandths of a percent 

(0.018%) of total fuel consumption by all motor vehicles. 

3. AIR POLLUTION METHODOLOGY

As described earlier, ERG estimated air emissions for the following three mechanisms: 

1) Additional auxiliary electricity use by steam electric plants to operate wastewater 

treatment, ash handling, and other systems needed to comply with the new 

effluent limits and standards; 

2) Additional transportation-related emissions due to the increased trucking of 

combustion residual waste to landfills; and 

3) The change in the profile of electricity generation due to relatively higher costs to 

generate electricity at plants incurring compliance costs for the proposed rule. 

The following sections provide greater detail on air emission changes associated with the first 

two mechanisms and present the estimated net change in air emissions accounting for all three 

mechanisms. See EPA’s Benefit and Cost Analysis for the Proposed Effluent Limitations 

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

report for additional discussion of the third mechanism [U.S. EPA, 2013a]. 

3.1 Air Emissions Associated with Energy

ERG estimated the energy usage associated with the operation of wastewater treatment systems 

and ash handling systems in kWh. Additionally, ERG also estimated the decrease in energy 

requirements associated with terminating wet sluicing operations and reduced use of earthmoving equipment associated with the new technology options. ERG used these estimates to 

calculate the net change in energy requirements for all regulatory options considered for this 

proposed rulemaking. 
Memorandum 

January 28, 2013 

Page 7 

ERG calculated air emissions resulting from increased auxiliary electricity using year-explicit 

emission factors projected in the Integrated Planning Model (IPM) for CO2, NOx, and SO2

2

. EPA 

obtained emission factors for years 2017 through 2024 based on IPM outputs for Run Year 2020 

and emission factors for years 2025 through 2040 based on IPM output for Run Year 2030. ERG 

used values associated with Run Year 2030 because these values represent the estimated annual 

emission factors after full implementation of the proposed rule. 

Because IPM was only run for Options 3 and 4, the IPM emission factors for Option 3 were used 

to estimate changes in auxiliary power air emissions for Regulatory Options 1, 2, and 3 and IPM 

emissions factors for Option 4 were used to estimate changes in auxiliary power air emissions for 

Regulatory Options 4 and 5. Table 3-1 presents the IPM emission factors for Regulatory Options 

3 and 4 for CO2, NOx, and SO2 by NERC region, as well as the average for the United States. 

Table 3-1. Summary of IPM Emissions Factors by NERC Region and Across 

Steam Electric Plants 

Run 

Year 

NERC 

Region / 

Plants 

Option 3 Option 4 

CO2 NOX SO2 CO2 NOX SO2

Metric 

Tonnes / 

MWh Tons / MWh Tons / MWh

Metric 

Tonnes / 

MWh Tons / MWh Tons / MWh

2020 

US 0.5324 0.0004 0.0005 0.5322 0.0004 0.0005 

ERCOT 0.5599 0.0003 0.0003 0.5610 0.0003 0.0003 

FRCC 0.5031 0.0003 0.0003 0.5051 0.0003 0.0003 

MRO 0.6892 0.0008 0.0008 0.6902 0.0008 0.0008 

NPCC 0.2694 0.0002 0.0002 0.2694 0.0002 0.0002 

RFC 0.5904 0.0005 0.0007 0.5904 0.0005 0.0007 

SERC 0.5674 0.0004 0.0006 0.5674 0.0004 0.0006 

SPP 0.7290 0.0006 0.0007 0.7290 0.0006 0.0007 

WECC 0.3772 0.0005 0.0002 0.3772 0.0005 0.0002 

2030 

US 0.5210 0.0004 0.0005 0.5204 0.0004 0.0005 

ERCOT 0.5411 0.0003 0.0002 0.5408 0.0003 0.0002 

FRCC 0.4782 0.0003 0.0002 0.4781 0.0003 0.0002 

MRO 0.6555 0.0007 0.0008 0.6555 0.0007 0.0008 

NPCC 0.2980 0.0002 0.0002 0.2979 0.0002 0.0002 

RFC 0.5764 0.0005 0.0006 0.5764 0.0005 0.0006 

SERC 0.5604 0.0004 0.0006 0.5604 0.0004 0.0006 

SPP 0.7130 0.0006 0.0007 0.7130 0.0006 0.0007 

WECC 0.3645 0.0004 0.0001 0.3645 0.0004 0.0001 

 

2

 EPA calculated air emissions associated with auxiliary energy requirements for SO2; however, for other air 

emission analyses for transportation, ERG calculated values for SOX. ERG assumes that SO2 represents the values 

for SOX for auxiliary energy requirements. 
Memorandum 

January 28, 2013 

Page 8 

For plants with capacity utilization rates (CUR) of 90.4 percent or less, emissions were estimated 

using plant-specific and year-explicit emission factors obtained from IPM outputs.3 These plants 

are assumed to be able to generate the additional auxiliary electricity on site. 

For plants with CUR greater than 90.4 percent, emissions were estimated using NERC-average 

emission factors for each year instead of plant-specific emissions factors. NERC-average factors 

were used based on the assumption that additional electricity consumption for auxiliary power 

will displace grid power within the region instead of coming from additional generation at the 

plant (i.e., the plant will be using part of its existing generation to power equipment, requiring 

other plants within the same NERC region to generate additional electricity to meet demand). 

EPA calculated NOx emissions as follows: 

Where: 

NOXt = Total NOx emissions in year t. 

Ep = Incremental auxiliary power electricity consumption at plant p, in MWh 

per year. 

EF_NOXp,t = NOx emission factor at plant p in year t, in tons NOx per MWh. If CURp > 

90.4 percent, EF_NOXp,t is based on average EF_NOXt for the NERC 

region where plant p is located. For t = 2017 to 2024, the calculations use 

IPM EF_NOXp,2020. For t = 2025 to 2040, the calculations use IPM 

EF_NOXp,2030. 

Tp,t = Timing adjustment to reflect year when plants are assumed to install the 

compliance technology between 2017 and 2021 and start incurring 

additional electricity consumption (Tp,t =0 if t < Year when plant p installs 

technology; Tp,t =1 if t  Year when plant p installs technology). 

Wi = Sample weight for plant p. 

Emissions of CO2 and SO2 are calculated similarly but using the CO2 and SO2 emission factors, 

respectively. Table 3-2 presents the air emissions associated with auxiliary energy usage 

calculated using IPM emission factors. 

 

3

 Emission factors are calculated as plant-level emissions divided by plant-level generation. 
Memorandum 

January 28, 2013 

Page 9 

Table 3-2. Estimated Air Emissions (Tons/Year) Associated with Increased Auxiliary 

Electricity Per Regulatory Option Using IPM Emission Factors 

Regulatory Option 

Air Emissions 

NOX

(tons/year) 

SO2

(tons/year) 

CO2

(metric tons/year) 

1 53.46 90.30 78,513.58 

2 118.45 190.35 180,117.93 

3 197.12 274.00 276,680.45 

4 527.26 708.98 619,790.12 

5 1,747.92 2,707.20 2,619,156.80 

Additionally, ERG calculated methane air emissions resulting from increased auxiliary 

electricity using EPA’s eGRID national estimate of 0.0000136 tons of methane per MWh. Using 

the eGRID emission rates per MWh, ERG calculated the air emissions associated with the 

additional energy estimated for the regulatory options considered as part of the proposed rule, as 

shown: 

Methane Emissions (tons) = Methane Emission Factor (ton/MWh) x Energy Usage (MWh)plant

Where: 

Methane Emission Factor (ton/MWh) = The eGRID air emission factor, 0.0000136, for 

methane. 

Energy Usage (MWh) = The incremental energy usage calculated for each plant 

for all technology options. 

Using this approach, ERG estimated the following methane air emissions associated with each 

regulatory option presented in Table 3-3. 

Table 3-3. Estimated Methane Air Emissions (Tons/Year) Associated with Increased 

Auxiliary Electricity Per Regulatory Option Using eGRID Emission Factors 

Regulatory Option 1 2 3 4 5 

Methane (tons/year) 1.15 2.61 4.14 9.19 38.66 

Source: eGRID2007 Version 1.0 

3.2 Air Emissions from Transportation

To estimate air emissions associated with increased operation of transportation vehicles, ERG 

used the MOBILE6.2 model to generate air emission factors (grams per mile) for hydrocarbons 

(HC), carbon monoxide (CO), NOx, CO2, and particulate matter (PM). ERG assumed the general 

input parameters such as the year of the vehicle, assumed to be 2010, to develop these factors 

(Baker, 2011). Because MOBILE6.2 does not estimate emission factors for methane, ERG used 

the emission factors from the California Climate Action Registry, General Reporting Protocol, 
Memorandum 

January 28, 2013 

Page 10 

Version 2.2. Table 3-4 provides a table of the transportation emission factors for each air 

pollutant considered in the NWQI analysis. 

Table 3-4. MOBILE6.2 and California Climate Action Registry 

Transportation Emission Rates 

NOx Highway 

(ton/mile) 

NOx Local 

(ton/mile) 

SOx 

(ton/mile) 

CO2

(ton/mile) 

CH4 

(ton/mile) 

6.76 x 10-7 6.52 x 10-7 1.58 x 10-8 0.0017 6.61 x 10-8

Source: MOBILE6.2 [U.S. EPA, 2004] and California Climate Action Registry, General Reporting Protocol, V2.2 

[California Climate Action Registry, 2007]. 

Note: The MOBILE6.2 highway and local emission rates are the same for all pollutant except nitrogen oxides. 

Using the transportation emission rates per mile, ERG calculated the air emissions associated 

with the additional energy estimated for the regulatory options considered as part of the proposed 

rule, as shown: 

Emission (tons) pollutant x, plant = (Air Emission Factor (ton/mile) pollutant x, vehicle) x 

(Transport Distance (mile/round trip)) x (Number of Trips (trips/yr)). 

Where: 

Air Emission Factor (ton/mile) pollutant x, vehicle = The transportation emission factor for each 

pollutant presented in Table 3-4. 

Transport Distance (mile/round trip) = The estimated round trip distance to/from the 

landfill. Distance varies based on plants with 

on-site versus off-site landfills. For on-site 

landfills, ERG estimated a round trip to be 2.6 

miles. For off-site landfills, ERG estimated a 

round trip to be 40 miles. 

Number of Trips (trips/yr) = The calculated number of trips for one year, 

based on the amount of ash and/or FGD solids 

generated by the plant, in the transportation cost 

methodology to truck all ash and FGD solids to 

the onsite or offsite landfill [U.S.EPA, 2013b]. 

ERG estimated the annual number of miles that would be traveled by dump trucks or vacuum 

trucks moving ash or wastewater treatment solids to on- or off-site landfills related to the 

proposed regulatory options. In addition to the trucks associated with transporting the additional 

solid waste, ERG also estimated the annual number of miles that would be traveled by water 

trucks spraying water around landfills and ash unloading areas to control dust as described in 

Section 2 of this memorandum. ERG used these estimates to calculate the net increase in air 

emissions for this rulemaking. See EPA’s Incremental Costs and Pollutant Removals for 

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

Source Category report for more information [U.S.EPA, 2013b]. Table 3-5 presents the air 

emissions associated with additional transportation of the solid waste for the proposed ELGs. 
Memorandum 

January 28, 2013 

Page 11 

Table 3-5. Industry-Level Air Emissions Associated with Transportation by Regulatory 

Option 

Regulatory Option 

Air Emissions 

NOx 

(tons/year) 

SOx 

(tons/year) 

CO2 

(metric tons/year) 

CH4 

(tons/year) 

1 0.54 0.01 1,239.61 0.05 

2 0.54 0.01 1,248.34 0.05 

3 9.86 0.23 22,548.38 0.97 

4 19.29 0.45 44,167.15 1.89 

5 24.03 0.56 55,050.45 2.36 

3.3 Air Emissions from Change in Industry Profile

EPA estimated the change in the profile of electricity generation due to relatively higher costs to 

generate electricity at plants incurring compliance costs for the proposed rule using data from 

IPM. IPM predicts changes in electricity generation due to compliance costs attributable to the 

proposed ELGs. Therefore, these changes, either increases or decreases, in electricity generation 

affect the air emissions from steam electric power plants. EPA only estimated the changes 

associated with the IPM predications for Regulatory Options 3 and 4. The net changes in national 

annual air emissions, associated with the change in industry profile, estimated for Regulatory 

Options 3 and 4 are shown in Table 3-6. 

Table 3-6. Industry-Level Air Emissions Associated with Changes in Industry Profile For 

the Proposed Regulatory Option 

Regulatory Option 

Air Emissions 

NOx 

(tons/year) 

SO2

a

(tons/year) 

CO2 

(metric tons/year) 

3 1,000 -3,000 -1,462,000 

4 1,000 -4,000 -4,413,000 

a - EPA calculated air emission associated changes in industry profile for SO2; however, for other air emission 

analyses for transportation, ERG calculated values for SOx. ERG assumes that SO2 represents the values for SOx for 

auxiliary energy requirements. 

3.4 Air Emission Comparisons to Other National Estimates

To provide some perspective on the potential increase in annual air emissions associated with the 

preferred options, ERG compared the estimated increase in air emissions associated with 

Regulatory Options 3 and 4, the preferred options, to the net amount of air emissions generated 

in a year by all electric power plants throughout the United States. Table 3-7 presents the 2009 

emissions generated by the electric power industry, based on eGRID, and the percent of 

increased emissions associated with the proposed rule [U.S. EPA, 2012]. 
Memorandum 

January 28, 2013 

Page 12 

Table 3-7. Electric Power Industry Air Emissions for Regulatory Options 3 and 4 

Non-Water 

Quality Impact 

Value Associated with the 

Regulatory Option 

(Million Tons) 

2009 Emissions by Electric 

Power Industry 

(Million Tons) 

Increase In Emissions 

(%) 

Regulatory Option 3 

NOx 0.00121 1 0.121 

SOx -0.00273 6 -0.045 

CO2 -1.282 2,403 -0.053 

CH4 0.000001 95 0.000001 

Regulatory Option 4 

NOx 0.00154 1 0.154 

SOx -0.00329 6 -0.055 

CO2 -4.133 2,403 -0.172 

CH4 0.000001 95 0.000001 

4. SOLID WASTE GENERATION METHODOLOGY

Solid waste associated with the implementation of the Steam Electric ELGs is based on sludge 

generated from FGD wastewater treatment, including sludge from chemical precipitation, 

biological treatment, and vapor-compression evaporation. ERG estimated the amount of solid 

waste generated from each technology for each plant. Fly and bottom ash are also solid wastes 

generated at steam electric power plants; however, the regulatory options are not expected to 

alter the amount of ash generated. Therefore, these volumes will not be included in the 

estimation of NWQIs. 

ERG determined dewatered sludge generation rates for FGD chemical precipitation treatment by 

multiplying a flow-normalized dewatered sludge generation rate (expressed in tons per day of 

sludge per gallon per minute FGD flow) by the plant flow rate. The flow-normalized dewatered 

sludge generation rate was determined based on responses in the questionnaire for FGD 

wastewater chemical precipitation treatment. ERG selected the median flow-normalized 

dewatered sludge generation rate based on an assessment of the characteristics of the dataset. 

ERG then calculated the annual sludge generation as follows: 

Annual Sludge Generation, tons/yr = Sludge Generation Rate × FGD Wastewater Flow, gpm × 

60 min/hr × 24 hr/day × 365 day/year 

Where: 

Sludge Generation Rate = The median flow normalized rate of sludge generation 

based on responses to the Questionnaire for the Steam 

Electric Power Generating Effluent Guidelines (Steam 

Electric Survey). 

FGD Wastewater Flow = The FGD wastewater flow rate for the plant in units of 

gallons per minute. This value was calculated from the 

gallons per day value reported in the Steam Electric Survey 

and divided by 24 x 60 to convert to gallons per minute. 
Memorandum 

January 28, 2013 

Page 13 

Sludge generated by the biological treatment system is contained within the backwash 

wastewater which is recycled to the FGD wastewater chemical precipitation system and is 

ultimately removed with the chemical precipitation sludge. Sludge generated by the vaporcompression evaporation system includes softening sludge and crystallizer sludge. See EPA’s 

report entitled Incremental Costs and Pollutant Removals for Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Generating Point Source Category for more 

information [U.S.EPA, 2013b]. The net increase in national annual sludge production associated 

with the regulatory options is shown in Table 4-1. 

To provide some perspective on the potential increase in annual solid waste generation 

associated with Regulatory Options 3 and 4, ERG compared the estimated increase in solid waste 

generation to the amount of solids generated in a year by electric power plants throughout the 

United States. According to the EIA, power plants generated approximately 134 billion tons of 

solids in 2009. ERG estimates that solid waste generation increases associated with Regulatory 

Option 3 will be less than 0.001% of the total solid waste generated by all electric power plants 

and the solid waste generation increases associated with Regulatory Option 4 will be less than 

0.0011% of the total solid waste generated by all electric power plants. 

Table 4-1. Industry-Level Solid Waste Increases by Regulatory Option 

Regulatory Option 

Sludge 

(tons/year) 

1 1,209,859 

2 1,218,691 

3 1,218,691 

4 1,459,011 

5 13,281,443 

5. WATER USAGE

Steam electric power plants generally use water for handling solid waste, including ash, and for 

operating wet FGD scrubbers. The regulatory options for fly ash and bottom ash will eliminate or 

reduce water use associated with current wet sluicing operating systems. The technology basis 

for FGD wastewater (e.g., chemical precipitation, biological treatment) will not reduce the 

amount of water used unless plants recycle FGD wastewater as part of their treatment system. 

For the regulatory options that eliminate wet ash sluicing operations, ERG estimated the 

reductions in water usage by calculating the amount of ash sluice water, specifically that amount 

of water identified as intake water or groundwater, which will no longer be discharged as part of 

the proposed rule. ERG performed reduction analyses for all plants currently discharging fly or 

bottom ash transport water. 

For all plants discharging ash transport water, fly and/or bottom ash, or identified as 

implementing FGD recycle under the proposed rule, ERG used information from the Steam 

Electric Survey to identify the sources of water for each of these processes. ERG used the 

responses from Question B5-1 of the Steam Electric Survey (Part B – Flue Gas Desulfurization 
Memorandum 

January 28, 2013 

Page 14 

(FGD) systems, Section 5 – FGD Wastewater Generation) for the five plants expected to 

implement FGD recycle to identify sources of FGD reagent preparation water, absorber make-up 

water, and mist eliminator wash water. For more information on the five plants expected to 

implement FGD recycle, see Section 4.4.3 of EPA’s Incremental Costs and Pollutant Removals 

for Proposed Effluent Limitations Guidelines and Standards for the Steam Electric Generating 

Point Source Category report [U.S.EPA, 2013b]. For sources of ash transport water, ERG used 

the responses from Questions C2-2 and C3-3 (Part C – Ash Handling, Section 2.1 – Fly Ash 

Handling – Generating Unit Level Information, Section 3.1 – Bottom Ash Handling – 

Generating Unit Level Information) of the Steam Electric Survey for each generating unit 

identified as discharging fly ash and bottom ash transport water, respectively. ERG analyzed all 

plants identifying raw intake water or treated intake water as a source for FGD water or ash 

transport water as part of the intake water reduction analysis. ERG analyzed any plant 

identifying groundwater or well water as a source for FGD water or ash transport water as part of 

the ground water reduction analysis. 

The plant-level results of these analyses can be found in the Steam Electric Rulemaking Record, 

DCNs SE01293 and SE02980. The following subsections specifically discuss the methodology 

and results for intake water reductions and ground water reductions, respectively. 

5.1 Intake Water Reduction Analysis Methodology and Results

Of the plants discharging ash transport water, ERG identified 65 plants using intake water as a 

source for fly ash transport water and 180 plants using intake water as a source for bottom ash 

transport water. Additionally, four of the five plants implementing FGD recycle also use intake 

water as a source for FGD preparation water. For each of these plants, ERG calculated the 

percentage of raw and/or treated intake water based on the water sources reported by each plant 

in Questions B5-1, C2-2, and C3-3 of the Steam Electric Survey. ERG calculated the total 

amount of raw and/or treated intake water identified in each response and divided by the total 

amount of source water. This calculation yielded a percentage of source water associated with 

intake water. For the FGD recycle plants, the source water is reported on an FGD system basis. 

For plants with multiple FGD systems, an average percentage was calculated. Sources of fly and 

bottom ash transport water are reported on a generating unit level. ERG calculated an average 

percentage of intake water based on all units discharging fly or bottom ash transport water. 

ERG used the amount of water identified for each plant as no longer being discharged along with 

the percentage of source water associated with intake water to determine how much intake water 

reduction would be realized by each plant. For the four plants implementing FGD recycle, ERG 

multiplied the amount being recycled within the FGD system by the average percentage of 

source water associated with intake water. For each plant generating ash transport water, ERG 

multiplied the amount of ash transport water currently discharged by the average percentage of 

intake water. Based on these calculations, ERG generated a plant-level list of the amount of 

intake water no longer required as a result of the proposed ELGs for each wastestream generated 

by the plant. ERG combined the FGD, fly ash, and bottom ash values to calculate the total 

amount of intake water in gallons per day. This single value represents the amount of intake 

water that will no longer be required by the plant, or the reduction in intake water, as a result of 

revisions to the proposed steam electric ELGs. Table 5-1 presents the industry-level reduction in 

intake water flows by wastestream. There is no reduction in intake water associated with landfill 
Memorandum 

January 28, 2013 

Page 15 

leachate because intake water is not a source of this process. Landfill leachate is generally the 

result of precipitation percolating through the landfill. 

Table 5-1. Industry-Level Intake Water Reductions 

Wastestream Intake Water Flow Reduction (MGD) 

FGD 7.7 

Fly Ash 136.6 

Bottom Ash 283.5 

Leachate 0 

Total 427.8 

Calculating reductions based on discharge flow could underestimate the amount of intake water 

no longer needed by each plant because some plants currently recycle part of their ash transport 

water within the system. In such a system, plants would be using intake water to make-up 100% 

of the amount discharged. In these cases the plant would list both recycled sluice and raw or 

treated intake water as sources in Questions C2-2 or C3-3 of the Steam Electric Survey, each 

with a percentage of less than 100, but the amount of water discharged is equal to the amount of 

intake water. As a result, ERG conducted a secondary calculation to estimate the potential 

reduction in intake water accounting for these recycle systems. For this secondary calculation, 

ERG assumed that all plants identifying fly ash sluice or bottom ash sluice in C2-2 or C3-3 used 

intake water to make-up 100% of the water discharged as ash transport water. For these plants, 

ERG multiplied the amount of ash transport water discharged by 100% to determine the intake 

water reduction for these plants. This secondary calculation resulted in an increased intake water 

reduction of 2.3 percent. Table 5-2 presents the industry-level reduction in intake water flows 

reflecting this second calculation methodology to account for ash transport water recycle 

systems. 

Table 5-2. Alternate Industry-Level Intake Water Reductions 

Wastestream Intake Water Flow Reduction (MGD) 

FGD 7.7 

Fly Ash 136.6 

Bottom Ash 293.4 

Leachate 0 

Total 437.7 

The reduction in intake water flows presented in Table 5-2 may be an overestimate of the actual 

reduction in intake water because some plants use sources of water other than intake water as 

make-up in their ash transport recycle systems. The two calculation methods used to generate the 

reductions in intake water presented in Table 5-1 and Table 5-2 represent the minimum and 

maximum amount of intake water that would no longer be required by steam electric power 

plants as a result of ELG revisions, respectively. 
Memorandum 

January 28, 2013 

Page 16 

5.2 Groundwater Reduction Analysis Methodology and Results

ERG identified two plants using groundwater as a source for ash transport water. None of the 

plants implementing FGD recycle identified groundwater as a water source. For these two plants, 

ERG determined the amount of ground water reduction associated with the proposed ELGs using 

a methodology similar to that of the intake water reduction analysis. 

For both plants, ERG calculated the percentage of ground water and/or well water based on the 

water sources reported by each plant in Questions C2-2 and C3-3 of the Steam Electric Survey. 

ERG then calculated an average percentage of ground water based on all units generating fly or 

bottom ash transport water. For each plant, ERG multiplied the average percentage of ground 

water by the total amount of ash transport water discharged annually. The resulting value 

represents the amount of ground water no longer required by the plant, or the reduction in ground 

water. Table 5-3 presents the industry-level reduction in ground water flows by wastestream. 

Neither of these two plants identified ash sluice or transport water as a water source in Questions 

C2-2 or C3-3 of the Steam Electric Survey; therefore, ERG did not need to conduct a secondary 

analysis to estimate ground water reductions for recycle systems. 

Table 5-3. Industry-Level Ground Water Reductions 

Wastestream Ground Water Flow Reduction (GPD) 

FGD 0 

Fly Ash 43,755 

Bottom Ash 86,400 

Leachate 0 

Total 130,155 

5.3 Water Reductions Compared to Industry Wastestream Discharges

As described above, ERG estimates that the proposed regulatory options will result in reduced 

water usage at power plants. Table 5-4 presents the expected reduction in water usage associated 

with intake water, presented in Table 5-1, and ground water for each regulatory option evaluated 

for the proposed rule. For comparison, ERG compared the expected levels of water reductions to 

the current amount of wastewater discharged for each wastestream that would lead to NWQIs, 

presented in Table 5-5. 
Memorandum 

January 28, 2013 

Page 17 

Table 5-4. Industry-Level Water Reduction by Regulatory Option 

Regulatory Option 

Water Reduction 

(million gallons/year) 

1 2,820 

2 2,820 

3 52,700 

4 153,000 

5 153,000 

Table 5-5. Wastewater Discharge at Steam Electric Power Plants 

Type of Wastewater 

Number of Plants 

Discharging Wastewater 

Total Wastewater Discharged 

(2009, million gallons) 

FGD Wastewater 117 23,700 

Fly Ash Transport Water 95 81,100 

Bottom Ash Transport Water 245 157,000 

Landfill Leachate 100 - 115 2,200 

6. FUTURE PROFILE AND NEW SOURCE NWQI ESTIMATES

ERG also evaluated the increases of energy and fuel usage, sludge generation, and air emissions 

for the future profile population (i.e., future FGD installations) and new sources (i.e., new 

generating units that will be subject to the proposed New Source Performance Standards 

(NSPS)). ERG estimated NWQI for the population of plants identified as future profile based on 

data from IPM associated with new pollutant controls that will likely be installed at plants 

because of recently promulgated Clean Air Act Requirements. These controls will only affect the 

FGD wastewater stream. For more information on the future profile analyses, see ERG’s 

memorandum “Flue Gas Desulfurization Future Profile Sensitivity Analysis” [DCN SE01989]. 

Additionally, at EPA’s direction, ERG estimated compliance costs associated with eight different 

NSPS scenarios considered to be new sources. ERG calculated the NWQI associated with NSPS 

scenarios 1 and 4, for three model size plants: 350 MW, 600 MW, and 1,300 MW. A description 

of the scenarios is provided below: 

 Scenario 1: New, Greenfield plant with no surface impoundments, an onsite 

landfill, wet FGD scrubber, dry bottom ash handling system, and combustion 

residual leachate that is commingled with FGD wastewater for treatment. 

 Scenario 4: Existing plant with and existing surface impoundment (determined to 

have no capacity for additional combustion residuals), an onsite landfill, wet FGD 

scrubber, and dry bottom ash handling system. 

For more information on the NSPS scenarios and methodology for estimating costs, see ERG’s 

memorandum “New Source Performance Standards (NSPS) Costing Memorandum” [DCN 

SE02129]. 
Memorandum 

January 28, 2013 

Page 18 

ERG used the same methodology as described in Sections 1 through 5 of this memorandum to 

estimate NWQI for the FGD future profile and NSPS scenarios. However, ERG did not use the 

plant-specific emission factor approach to estimate air emissions associated with auxiliary 

energy requirements. Based on the data provided in Table 3-1, ERG used the national air 

emission factors (US) for model run year 2030 for all future profile and NSPS air emission 

estimates associated with auxiliary energy requirements. Because national air emission factors 

were only calculated for Regulatory Options 3 and 4, ERG used the Option 3 national air 

emission factors (US) for model run year 2030 to calculate air emissions associated with 

increased auxiliary electricity for Regulatory Options 1, 2 and 3. ERG used the Option 4 national 

air emission factors (US) for model run year 2030 to calculate air emissions associated with 

increased auxiliary electricity for Regulatory Options 4 and 5. Additionally, because these plants 

are not part of the current profile, air emissions associated with the change in industry profile are 

not applicable for the future profile and NSPS NWQI. The results of the NWQI for the future 

profile wet FGD systems (i.e., only the wet FGD systems that are expected to be installed after 

2014, not all the current and future wet FGD systems) are presented in Table 6-1. The new 

source NWQI results for the three model plant sizes are presented in Table 6-2, Table 6-3, and 

Table 6-4. 
Memorandum 

January 28, 2013 Page 19 

Table 6-1. Calculated Sum of NWQI for Each Treatment Option for the Future Wet FGD Systems Expe

After 2014 

Regulatory 

Option 

Electrical Energy 

Usage 

(MWh/year) 

Fuel

(GPY) 

Sludge 

(tons/year) 

NOX Emissions 

(tons/year) 

SOX Emissions 

(tons/year) 

CO2 Emissio

(tons/year

1 7,945 36,411 138,920 3.30 3.98 4,860 2 20,814 36,607 139,670 8.44 10.41 12,252 3 20,814 36,607 139,670 8.44 10.41 12,252 4 20,814 36,607 139,670 8.44 10.41 12,238 5 195,623 286,581 1,112,889 79.18 97.83 114,551 

Note: The NWQI presented in this table only reflect the NWQI associated with the wet FGD systems that are expected to be installed a

promulgation of the final rule). The values presented in the table do not reflect the total NWQI associated with the current profile plus tinstallations. 
Memorandum 

January 28, 2013 Page 20 

Table 6-2. Calculated Sum of NWQI for New Sources Evaluated for the Proposed Rulemaking for 350 

NSPS 

Scenario 

Regulatory 

Option 

Electrical 

Energy Usage 

(MWh/year) 

Fuel

(GPY) 

Sludge 

(tons/year) 

NOx Emissions 

(tons/year) 

SOx Emissions 

(tons/year) 

CO2 Em

(tons/y

1 

1 180 165 4,056 0.07 0.09 2 

2 1,085 166 4,078 0.43 0.54 624 3 1,085 166 4,078 0.43 0.54 624 4 1,533 2,352 4,604 0.62 0.77 899 5 5,816 1,563 32,393 2.33 2.91 3,347 

4

1 180 165 4,056 0.07 0.09 2 2 1,085 166 4,078 0.43 0.54 624 3 1,085 166 4,078 0.43 0.54 624 4 1,085 166 4,078 0.43 0.54 623 5 5,545 1,291 31,869 2.22 2.77 3,189 
Memorandum 

January 28, 2013 Page 21 

Table 6-3. Calculated Sum of NWQI for New Sources Evaluated for the Proposed Rulemaking for 600 M

NSPS Scenario 

Regulatory 

Option 

Electrical 

Energy Usage 

(MWh/year) 

Fuel

(GPY) 

Sludge 

(tons/year) 

NOX Emissions 

(tons/year) 

SOX Emissions 

(tons/year) 

CO2 Em

(tons/y

1 

1 363 269 6,628 0.15 0.18 2 

2 1,590 270 6,663 0.64 0.79 915 3 1,590 270 6,663 0.64 0.79 915 4 2,123 3,865 7,565 0.86 1.06 1,250 5 9,410 2,571 52,974 3.77 4.71 5,416 

4

1 363 269 6,628 0.15 0.18 2 2 1,590 270 6,663 0.64 0.79 915 3 1,590 270 6,663 0.64 0.79 915 4 1,590 270 6,663 0.64 0.79 914 5 9,119 2,110 52,076 3.65 4.56 5,245 
Memorandum 

January 28, 2013 Page 22 

Table 6-4. Calculated Sum of NWQI for New Sources Evaluated for the Proposed Rulemaking for 1,300 

NSPS 

Scenario 

Regulatory 

Option 

Electrical 

Energy Usage 

(MWh/year) 

Fuel

(GPY) 

Sludge 

(tons/year) 

NOX Emissions 

(tons/year) 

SOX Emissions 

(tons/year) 

CO2 Em

(tons/y

1 

1 979 582 14,346 0.39 0.49 

2 3,169 585 14,422 1.27 1.58 1,823 3,169 585 14,422 1.27 1.58 1,824 4,014 8,362 16,377 1.63 2.01 2,375 20,286 5,563 114,662 8.13 10.14 11,67

4

1 979 582 14,346 0.39 0.49 2 3,169 585 14,422 1.27 1.58 1,823 3,169 585 14,422 1.27 1.58 1,824 3,169 585 14,422 1.27 1.58 1,825 19,910 4,568 112,717 7.98 9.96 11,45
Memorandum 

January 28, 2013 

Page 23 

REFERENCES

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SE02960. 

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online at: http://www.eia.gov/electricity/data/eia860/index.html. DCN SE01805. 

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http://www.epa.gov/oms/m6.htm. 

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6. U.S. EPA. 2012a. The Emissions & Generation Resource Integrated Database for 2012 

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http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2012_year09_TechnicalSuppo

rtDocument.pdf. DCN SE02112. 

7. U.S. EPA. 2012b. eGRID2012 Version 1.0 2009 Data. Available online at: 

http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html. DCN SE02111. 

8. U.S. EPA. 2013a. Costs and Benefits Analysis for Proposed Steam Electric Effluent 

Limitations Guidelines Regulation. (19 April). DCN SE03172. 

9. U.S. EPA. 2013b. Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitation Guidelines and Standards for the Steam Electric Generating Point Source 

Category Report. (19 April). DCN SE01957.