MEMORANDUM

TO: Steam Electric Rulemaking Record

FROM: Elizabeth Gentile, ERG

Deb Bartram, ERG

DATE: September 30, 2015

SUBJECT: Steam Electric Effluent Guidelines Non-Water Quality Environmental 

Impacts for BAT/PSES

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 

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

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

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

ash transport water. The ELGs also establish limits for 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 ELGs. ERG estimated NWQIs on a 

plant-specific basis for each of the technologies and activities that make up the six regulatory 

options considered for the ELGs. These technologies include:

• Chemical precipitation wastewater treatment;

• Biological wastewater treatment;

• 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.

For a complete description of the technologies considered for the ELGs, see EPA’s Incremental 

Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category report [U.S. EPA, 2015b]. Table

1-1 presents the regulatory options considered for this rulemaking, and an abbreviated 

description of the BAT technology basis for each wastestream. An increased need for 
Memorandum

September 30, 2015

Page 2

transportation and disposal of solids via trucks is projected for each of the BAT technologies 

because sludge from wastewater treatment and ash converted to dry handling or closed-loop wet 

handling will need to be moved to landfills, instead of being pumped to impoundments.
Memorandum

September 30, 2015

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Table 1-1. Steam Electric Regulatory Options

Wastestreamsa

Technologies Leading to Non-Water Quality Environmental Impacts

A B C D E Fb,c

FGD

Wastewater

Chemical 

Precipitation

Chemical 

Precipitation + 

Biological Treatment

Chemical 

Precipitation + 

Biological Treatment

Chemical 

Precipitation + 

Biological Treatment

Chemical 

Precipitation + 

Biological Treatment

Evaporation

Fly Ash Transport Water Dry Handling Dry Handling Dry handling Dry handling Dry handling Dry handling

Bottom Ash Transport 

Water

Impoundment (Equal

to BPT)

Impoundment (Equal

to BPT)

Dry handling/Closed

loop (for units >400 

MW); 

Impoundment

(Equal to BPT)(for 

units ≤400 MW)

Dry handling/

Closed loop

Dry handling/

Closed loop

Dry handling/

Closed loop

Combustion Residual 

Leachate

Impoundment (Equal

to BPT)

Impoundment (Equal

to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Chemical 

Precipitation

Chemical 

Precipitation

a – Gasification wastewater and flue gas mercury control wastewater are not listed in the table because there are no NWQIs associated with the ELGs for these 

wastestreams.

b – For Regulatory Option F, NWQIs were estimated only for the plant population that takes both the Disposal of Coal Combustion Residuals from Electric Utilities

(CCR) regulation and the Clean Power Plan (CPP) into account.

c – As part of the BAT for existing sources, the final rule establishes a voluntary incentives program that provides the certainty of more time for plants to implement new 

BAT requirements, if they adopt additional process changes and controls that achieve limitations based on evaporation technology. The information is this memorandum

can also be used to evaluate the NWQIs of the voluntary program. EPA does not know how many plants will elect this approach. However, the information for Regulatory 

Option F provides an upper bound estimate if all plants were to elect to comply with the voluntary program. EPA also notes that Regulatory Option F includes more 

stringent requirements for combustion residual leachate than is required under the voluntary program or Regulatory Option D so to the extent that the more stringent 

leachate requirements in Regulatory Option F contribute to increased NWQIs, these would be overestimates for the voluntary program. 
Memorandum

September 30, 2015

Page 4

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

estimated the following NWQIs:

• Energy Usage. Due to the 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 earthmoving 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 Emissions. Steam electric power plants generate air pollution when they use 

energy, and as such, changes in energy usage associated with the regulatory 

options will also affect the air emissions from operations at power plants. Air 

emissions result from the generation of electricity needed to operate 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 emissions 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 projected to result from implementing the ELG. Criteria air pollutants 

are those pollutants for which a national ambient air quality standard (NAAQS) 

has been set and include SO2 and 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 change in air emissions for each of the ELG regulatory options.

• Solid Waste Generation. Steam electric power plants generate solid waste (e.g., 

fly ash, bottom ash) when burning fossil fuels such as coal or petroleum coke to 

generate electricity. Although the ELG regulatory options may alter where plants 

dispose of their fly ash or bottom ash (e.g., landfills or beneficial use, rather than 

impoundment disposal), the ELG would not increase the amount of ash or FGD 

solids (i.e., gypsum or calcium sulfite) they generate. EPA does project that the 

regulatory options evaluated would increase the amount of solid waste associated 

with FGD wastewater and combustion residual leachate from landfills by 

generating treatment residual solids from chemical precipitation, biological

treatment, and evaporation technologies.

• Water Intake. Steam electric power plants use intake 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 substantially 

reduce the intake water use associated with current wet sluicing operating 

systems. The amount of intake water used for FGD wastewater treatment is only 

reduced for plants that recycle FGD wastewater as part of their treatment system.

 1 ERG did not specifically evaluate nitrous oxide emissions (N2O) as part of the NWQI analysis. To avoid double 

counting air emission estimates, ERG only calculated nitrogen oxide emissions (NOx), which would include N2O.
Memorandum

September 30, 2015

Page 5

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

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

and a summary of the NWQIs estimated for each regulatory option. ERG calculated NWQIs for 

two scenarios of power plant populations: (1) taking into account the implementation of the CCR 

rule (and other regulatory requirements except for CPP); and (2) taking into account 

implementation of both the CCR rule and the CPP.

2 The calculations and results for estimating 

NWQIs are included in the following databases:

• DCN SE05953: Calculation of NWQIs taking into account the implementation of the 

CCR rule for Regulatory Options A through E.

• DCN SE05954: Calculation of NWQIs taking into account the implantation of both 

the CCR rule and the CPP for Regulatory Options A through F.

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 units of MWhs.

The energy usage values used in the NWQI energy calculations are calculated in the steam 

electric cost models (DCNs SE05841, SE05842, SE05862, and SE05864). 

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

needed to operate wastewater treatment systems and ash handling systems. See EPA’s

Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source Category report for more 

information on the specific calculations used to estimate energy needed to operate wastewater 

treatment systems and dry or closed-loop ash handling systems [U.S. EPA, 2015b].

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. 

In general, the estimated amount of energy associated with reducing pump operations was 

calculated as follows: 

 2 At the time EPA performed the analyses for this rule, the details of the final CPP rule had not yet been determined 

and promulgated. EPA therefore used information from the proposed CPP rule as a reasonable and best available 

source of information for purposes of the ELG analyses. EPA subsequently assessed how the effects of the final CPP 

compared to the proposed CPP, as it relates to the ELG analyses, and determined that basing the analyses on the 

final CPP would not substantially change the results nor EPA’s determination that the NWQIs associated with the 

final ELG are acceptable.
Memorandum

September 30, 2015

Page 6

Pond Energy Consumption (kWh) = (0.0229 x [Flow Rate / (60 min/hr x 24 hpd)] + 0.9268) x hp 

KW Factor x Operating Hours x Operating Days

where:

Flow Rate = The FGD scrubber purge flow rate, fly ash transport 

water flow rate, or bottom ash transport water flow 

rate, in gpd.

3

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

kW/hp.

Operating Hours = Pump operating hours per day.

Operating Days = Pump operating days per year.

Similarly, ERG estimated the amount of energy saved by reducing the number of front-end 

loaders (i.e., earthmoving equipment) needed to dredge solids from ash impoundments based on 

the horsepower rating of the engine. ERG estimated energy savings based on horsepower rating 

of the engine based on the available data used for the impoundment savings methodology [U.S. 

EPA, 2015b]. ERG estimated energy savings associated with earthmoving equipment for plants 

operating surface impoundments for each CCR type (i.e., fly ash, bottom ash, and/or FGD). In 

general, the estimated amount of energy associated with reducing the number of front-end 

loaders for each wastestream was calculated as follows: 

Earthmoving Energy Consumption (kWh) = Earthmoving Engine Horsepower (hp) x hp KW 

Factor x Earthmoving Operating Hours x Earthmoving Operating Days

where:

Earthmoving Engine 

Horsepower

= The horsepower of the front-end loader, 190 hp.

hp KW Factor = Factor to convert horsepower to kilowatts, 0.7456 

kW/hp.

Earthmoving Operating 

Hours

= Estimated number of hours the earthmoving equipment 

is operated per day, 8 hours per day.

Earthmoving Operating 

Days

= Estimated number of days the earthmoving equipment 

is operated per year, 260 days per year.

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) –

 3 The pump horsepower for fly ash and bottom ash transport water was calculated at the generating unit level first 

and summed to plant level. 
Memorandum

September 30, 2015

Page 7

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 the ELG. Table 2-2 adjusts the results shown in Table 

2-1, taking into account implementation of the CPP.

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 cost

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

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

Source Category report [U.S.EPA, 2015b]. That methodology estimates the need for increased 

transportation of solid waste (including ash converted to dry or closed-loop wet handling) 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 the distance from 

the plant to the landfill determines the length of travel time. ERG used the following equation to 

calculate fuel usage, as gallons of fuel used, associated with the increased transportation:

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. ERG estimates the loading 

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

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

sludge and/or ash per trip. ERG estimates the unloading 

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

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 
Memorandum

September 30, 2015

Page 8

methodology, ERG estimates the fuel consumption to 

be 20.24 gal/100 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, 2015b].

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 EPA’s Incremental Costs and Pollutant Removals for the Final Effluent 

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

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

fuel usage [U.S.EPA, 2015b].

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

shown in Table 2-1. Table 2-2 adjusts the results shown in Table 2-1, taking into account 

implementation of the CPP.

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

Non-Water Quality 

Impact

Energy Use Associated with ELG

Option A Option B Option C Option D Option E

Electrical Energy Usage

(MWh) 59,400 140,000 248,000 339,000 373,000

Fuel

(Gallons Per Year 

(GPY)) 168,000 169,000 498,000 758,000 766,000

Table 2-2. Industry-Level Energy Requirements by Regulatory Option, Accounting for 

CPP

Non-Water Quality 

Impact

Energy Use Associated with ELG

Option A Option B Option C Option D Option E Option F

Electrical Energy 

Usage

(MWh) 51,700 102,000 187,000 237,000 264,000 1,480,000

Fuel

(GPY) 133,000 134,000 442,000 556,000 563,000 1,370,000

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

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

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

by all electric 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 

increases in electrical energy usage associated with Regulatory Option D or Regulatory Option D 
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September 30, 2015

Page 9

assuming all plants elect to comply with the voluntary incentives program (represented by 

Regulatory Option F), are less than 0.01 percent or 0.04 percent, respectively of the total 

electricity generated by all electric power plants in 2009.

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

regulatory options, as shown in Table 2-1 and Table 2-2, to national fuel consumption estimates 

for motor vehicles in the United States. According to the U.S. Energy Information 

Administration (EIA), on-highway vehicles, which include automobiles, trucks, and buses, 

consumed approximately 34 billion gallons of distillate fuel oil in 2009 [U.S. DOE, 2009]. ERG

estimates that the fuel consumption increase associated with Regulatory Option D or Regulatory 

Option D assuming all plants elect to comply with the voluntary incentives program (represented 

by Regulatory Option F), will be 0.002 percent or 0.004 percent, respectively of total fuel 

consumption by all motor vehicles in the United States.

3. AIR EMISSIONS 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 ELG.

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 Chapter 7 in EPA’s Benefit and Cost Analysis for the Final 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, 2015a].

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 

rulemaking.

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

4

. The 

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

emission analyses for transportation, ERG calculated values for SOX. The air emissions for SO2 are a reasonable 

estimate for SOX emissions from changes in auxiliary energy requirements.
Memorandum

September 30, 2015

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IPM output provides emission factors by plant and North American Electric Reliability 

Corporation (NERC) region, calculated as the ratio of projected emissions and projected 

electricity generation. Emission factors were obtained for years 2019 through 2022, 2023 

through 2027, and 2028 through 2042 based on IPM outputs for Run Year 2020, 2025, and 2030, 

respectively.

IPM was used to evaluate Regulatory Options B and D. The IPM emission factors for Regulatory 

Option B were used to estimate changes in auxiliary power air emissions for Regulatory Options 

A and B because the IPM emission factors for Regulatory Option B are the closest representation 

of Regulatory Option A. Similarly, the IPM emissions factors for Regulatory Option D were 

used to estimate changes in auxiliary power air emissions for Regulatory Options C, D, E, and F. 

Table 3-1 presents the IPM emission factors for Regulatory Options B and D for CO2, NOx, and 

SO2 by NERC region, as well as the average for the United States.
Memorandum

September 30, 2015

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

IPM Run 

Year

NERC 

Region

Option B Option D

CO2 NOx SO2 CO2 NOx SO2

Metric Tonnes / MWh Tons / MWh Tons / MWh Metric Tonnes / MWh Tons / MWh Tons / MWh

2020

US 0.4276 0.0003 0.0003 0.4269 0.0003 0.0003 

FRCC 0.3271 0.0001 0.0000 0.3271 0.0001 0.0000 

MRO 0.5528 0.0006 0.0004 0.5525 0.0006 0.0004 

NPCC 0.2071 0.0001 0.0000 0.2071 0.0002 0.0000 

RFC 0.5296 0.0004 0.0005 0.5278 0.0004 0.0005 

SERC 0.4188 0.0002 0.0003 0.4178 0.0002 0.0003 

SPP 0.5667 0.0004 0.0003 0.5660 0.0004 0.0003 

TRE 0.4111 0.0002 0.0001 0.4106 0.0002 0.0001 

WECC 0.3345 0.0002 0.0001 0.3348 0.0002 0.0001 

2025

US 0.4189 0.0003 0.0003 0.4187 0.0003 0.0003 

FRCC 0.3296 0.0001 0.0000 0.3297 0.0001 0.0000 

MRO 0.5523 0.0006 0.0004 0.5522 0.0006 0.0004 

NPCC 0.1927 0.0001 0.0000 0.1926 0.0001 0.0000 

RFC 0.5138 0.0004 0.0005 0.5136 0.0004 0.0005 

SERC 0.4124 0.0002 0.0003 0.4116 0.0002 0.0003 

SPP 0.5572 0.0004 0.0003 0.5575 0.0004 0.0003 

TRE 0.3991 0.0002 0.0001 0.3982 0.0002 0.0001 

WECC 0.3303 0.0003 0.0001 0.3307 0.0002 0.0001 

2030

US 0.4310 0.0003 0.0003 0.4142 0.0003 0.0003 

FRCC 0.3228 0.0002 0.0001 0.3321 0.0001 0.0000 

MRO 0.5864 0.0006 0.0004 0.5617 0.0006 0.0004 

NPCC 0.2146 0.0002 0.0000 0.1986 0.0002 0.0000 

RFC 0.5129 0.0004 0.0005 0.4997 0.0004 0.0005 

SERC 0.4052 0.0002 0.0003 0.4072 0.0002 0.0003 
Memorandum

September 30, 2015

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

IPM Run 

Year

NERC 

Region

Option B Option D

CO2 NOx SO2 CO2 NOx SO2

Metric Tonnes / MWh Tons / MWh Tons / MWh Metric Tonnes / MWh Tons / MWh Tons / MWh

SPP 0.6138 0.0004 0.0003 0.5596 0.0004 0.0003 

TRE 0.4219 0.0002 0.0002 0.3949 0.0002 0.0001 

WECC 0.3498 0.0003 0.0001 0.3277 0.0002 0.0001 
Memorandum

January 28, 2013

Page 13

ERG assumed that plants with capacity utilization rates (CUR) of 90.4 percent or less would 

generate the additional auxiliary electricity on site and therefore estimated emissions using plantspecific and year-explicit emission factors obtained from IPM outputs.

5

ERG assumed that plants with CUR greater than 90.4 percent would draw additional electricity for 

auxiliary power from the grid within the NERC region instead of generating it on site. These plants 

will be using part of their existing generation to power equipment; however, other plants within the 

same NERC region would need to generate electricity to compensate for this reduction and meet 

electricity demands. Therefore, ERG used NERC-average emission factors for each year instead of 

plant-specific emissions factors when estimating incremental emissions for these plants.

In general, emissions were calculated using the following equation:

Emissionst = Ep × EFp,t × Tp,t × Op,t

where:

Emissiont = Total emissions for a specific pollutant in year t.

Ep = Incremental auxiliary power electricity consumption at 

plant p, in MWh per year.

EFp,t = Pollutant-specific emission factor at plant p in year t, in 

tons of pollutant per MWh. If CURp > 90.4 percent, 

EFp,t is based on average EFt for the NERC region 

where plant p is located (see Table 3-1). For t = 2019 to 

2022, the calculations use IPM EFp,2020. For t = 2023 to 

2027, the calculations use IPM EFp,2025. For t = 2028 to 

2042, the calculations use IPM EFp,2030.

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

assumed to install the compliance technology between 

2019 and 2023 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).

Op = A variable that takes on the value 1 if plant p is operating 

in year t, and 0 otherwise. For t = 2019 to 2022, the 

calculations use IPM Op,2020. For t = 2023 to 2027, the 

calculations use IPM Op,2025. For t = 2028 to 2042, the 

calculations use IPM Op,2030.

Table 3-2 presents the air emissions associated with auxiliary energy usage calculated using IPM 

emission factors for IPM Run Year 2025. Table 3-3 adjusts the results shown in Table 3-2, taking 

into account implementation of the CPP. ERG used values associated with IPM Run Year 2025 

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

September 30, 2015

Page 14

because these values represent the estimated annual emissions factors after full implementation of 

the rule.

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)

A 34.3 44.2 48,100

B 70.9 93 103,000

C 139 158 190,000

D 193 212 239,000

E 212 236 263,000

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

Electricity Per Regulatory Option Using IPM Emission Factors, Accounting for CPP

Regulatory Option

Air Emissions

NOX

(tons/year)

SO2

(tons/year)

CO2

(metric tons/year)

A 30.7 42.7 44,800

B 59.6 86.7 89,600

C 116 148 166,000

D 165 196 209,000

E 185 220 233,000

F 832 1,140 1,260,000

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 final rule, as shown:

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

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 and adjusted for CPP, presented in Table 3-4.
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September 30, 2015

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Table 3-4. Estimated Methane Air Emissions (Tons/Year) Associated with Increased

Auxiliary Electricity Per Regulatory Option Using eGRID Emission Factors

Regulatory Option

Methane Air Emissions

(Tons/Year)

Methane Air Emissions, Accounting

for CPP

(Tons/Year)

A 0.813 0.703

B 1.91 1.39

C 3.38 2.54

D 4.62 3.23

E 5.08 3.6

F NC 20.1

Source: eGRID2007 Version 1.0

NC – Not calculated.

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 NOX, CO2, and SOX. 

ERG assumed the general input parameters such as the year of the vehicle, assumed to be 2010, and 

the annual mileage accumulation by vehicle class 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, Version 2.2. Table 3-5

provides a table of the transportation emission factors for each air pollutant considered in the NWQI 

analysis.

Table 3-5. 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 each option considered for the final 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 3-5.

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

landfill. Distance varies based on plants with on-
Memorandum

September 30, 2015

Page 16

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, 2015b].

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 regulatory 

options considered for the ELG. 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 the Final Effluent 

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

Category report for more information on the estimated distance traveled by water trucks [U.S.EPA, 

2015b]. Table 3-6 presents the air emissions associated with additional transportation of the solid 

waste for the final rule. Table 3-7 adjusts the results shown in Table 3-6, taking into account 

implementation of the CPP.

Table 3-6. 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)

A 0.540 0.012 1,240 0.053

B 0.545 0.013 1,250 0.054

C 1.55 0.036 3,570 0.153

D 2.39 0.056 5,490 0.235

E 2.41 0.057 5,540 0.238

Table 3-7. Industry-Level Air Emissions Associated with Transportation by Regulatory 

Option, Accounting for CPP

Regulatory Option

Air Emissions

NOx

(tons/year)

SOx

(tons/year)

CO2

(metric tons/year)

CH4

(tons/year)

A 0.425 0.010 977 0.042

B 0.428 0.010 986 0.042

C 1.38 0.032 3,180 0.136

D 1.75 0.041 4,010 0.172

E 1.76 0.042 4,060 0.174
Memorandum

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Table 3-7. Industry-Level Air Emissions Associated with Transportation by Regulatory 

Option, Accounting for CPP

Regulatory Option

Air Emissions

NOx

(tons/year)

SOx

(tons/year)

CO2

(metric tons/year)

CH4

(tons/year)

F 4.26 0.101 9,810 0.421

3.3 Air Emissions from Change in Electricity Generation Profile

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

generate electricity at plants incurring compliance costs for the ELGs using data from IPM. IPM 

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

changes, either increases or decreases, in electricity generation from different electric power 

generators affect air emissions, for example by shifting generation from coal-fired electricity 

generation units to natural gas-fueled or other electricity generating units. The net changes in 

national annual air emissions associated with the change in electricity generation profile for

Regulatory Options B and D are shown in Table 3-8. The effects of the CPP are incorporated into 

IPM; therefore, the data presented in Table 3-8 account for CPP.

Table 3-8. Industry-Level Air Emissions Associated with Changes in Industry Profile For 

Regulatory Options B and D

Regulatory Option

Air Emissions

NOx

(tons/year)

SO2

a

(tons/year)

CO2

(metric tons/year)

B -3,320 -528 -1,440,000

D -11,600 -2,240 -2,550,000

a - ERG calculated air emissions associated with auxiliary energy requirements for SO2; however, for other air emission 

analyses for transportation, ERG calculated values for SOX. The air emissions for SO2 are a reasonable estimate for 

SOX emissions from changes in 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 

ELGs, ERG compared the estimated increase in air emissions associated with Regulatory Options B

and D to the net amount of air emissions generated in a year by all electric power plants throughout 

the United States. As described above in Section 3.1, the IPM emission factors for Regulatory 

Option B were used to estimate changes in auxiliary power air emissions for Regulatory Options A 

and B because the IPM emission factors for Regulatory Option B are the closest representation of 

Regulatory Option A. Similarly, the IPM emissions factors for Regulatory Option D were used to 

estimate changes in auxiliary power air emissions for Regulatory Options C, D, E, and F. Table 3-9

presents the 2009 emissions generated by the electric power industry, based on eGRID, and the 

percent of increased emissions associated with the Regulatory Options B and D [U.S. EPA, 2012a].

Table 3-10 adjusts the results shown in Table 3-9 and includes Regulatory Option F, taking into 

account implementation of the CPP.
Memorandum

September 30, 2015

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Table 3-9. Electric Power Industry Air Emissions for Regulatory Options B and D

Non-Water

Quality Impact

Value Associated with 

Selected Regulatory Option

(Million Tons)

2009 Emissions by Electric 

Power Generating Industry

(Million Tons)

Increase In Emissions

(%)

Regulatory Option B

NOx -0.00325 1 -0.326

SOx -0.000435 6 -0.00724

CO2 -1.46 2,403 -0.0612

CH4 0.00000195 95 0.00000206

Regulatory Option D

NOx -0.0114 1 -1.16

SOx 0.00245 6 0.0408

CO2 -2.55 2,403 -0.106

CH4 0.00000485 95 0.0000051

Table 3-10. Electric Power Industry Air Emissions for Regulatory Options B and D, 

Accounting for CPP

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 B

NOx -0.00326 1 -0.327

SOx -0.000441 6 -0.00735

CO2 -1.48 2,403 -0.0618

CH4 0.00000143 95 0.00000151

Regulatory Option D

NOx -0.0114 1 -1.16

SOx 0.00243 6 0.0406

CO2 -2.58 2,403 -0.108

CH4 0.0000034 95 0.00000358

Regulatory Option Fa

NOx -0.0108 1 -1.09

SOx 0.00337 6 0.0562

CO2 -1.41 2,403 -0.0589

CH4 0.0000205 95 0.0000216

a - ERG estimates that the increases in air emissions for Regulatory Option D assuming all plants elect to comply with 

the voluntary incentives program (represented by Regulatory Option F), are comparable to Regulatory Option D. 

4. SOLID WASTE GENERATION METHODOLOGY

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

generation of residual treatment solids from chemical precipitation, biological treatment, and 

evaporation. ERG estimated the amount of solid waste generated from each technology for each 
Memorandum

September 30, 2015

Page 19

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, NWQIs 

associated with fly ash or bottom ash are related to transport and disposal in an onsite or offsite 

landfill.

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. 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 evaporation system includes softening sludge and crystallizer 

sludge. See EPA’s Incremental Costs and Pollutant Removals for the Final Effluent Limitations 

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

for more information on the equations used to estimate annual sludge generation for each 

technology [U.S.EPA, 2015b]. The net change in national annual sludge production associated with 

the regulatory options is shown in Table 4-1. Table 4-2 adjusts the results shown in Table 4-1, 

taking into account implementation of the CPP.

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

Non-Water Quality 

Impact

Solid Waste Generation with the ELG

Option A Option B Option C Option D Option E

Sludge (Tons/Year) 583,000 596,000 596,000 596,000 794,000

Table 4-2. Industry-Level Solid Waste Increases by Regulatory Option, Accounting for 

CPP

Non-Water Quality 

Impact

Solid Waste Generation with the ELG

Option A Option B Option C Option D Option E Option F

Sludge (Tons/Year) 514,000 525,000 525,000 525,000 698,000 7,360,000

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

with Regulatory Option D and Regulatory Option D assuming all plants elect to comply with the 

voluntary incentives program (represented by Regulatory Option F), ERG compared the estimated 

increase in solid waste generation to the amount of solids generated in a year by electric generating 

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 the regulatory options will be less than 0.001 percent of the total solid 

waste generated by all electric power plants.

5. WATER INTAKE METHODOLOGY

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

operating wet FGD scrubbers. For the regulatory options that eliminate the discharge of ash 

transport water, ERG estimated the reductions in water intake by calculating the amount of ash 

transport water, specifically that amount of water identified as intake water or groundwater, which
Memorandum

September 30, 2015

Page 20

will no longer be discharged as part of the final rule. ERG performed reduction analyses for all 

plants currently discharging fly or bottom ash transport water.

The technology basis for the selected BAT regulatory option with respect to FGD wastewater 

discharges (e.g., chemical precipitation, biological treatment) would not be expected to reduce the 

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

ERG estimated that three plants will choose to reuse some of the FGD wastewater within the FGD 

system based on the maximum operating chlorides concentration compared to the design maximum 

chlorides concentration (other plants may also be able to do so). To estimate the intake water 

reductions associated with the recycled FGD wastewater, ERG used data from the Steam Electric 

Survey to calculate an average percentage of FGD wastewater identified as intake water. EPA 

multiplied this percentage by the amount of water that could be recycled by the FGD system to 

calculate the estimated water reduction. ERG also used the adjusted FGD scrubber purge flows to 

estimate compliance cost and pollutant loadings associated with these plants. See EPA’s report 

entitled Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines 

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

information [U.S. EPA, 2015b].

The calculations and results for estimating water reductions are included in the following databases:

• DCN SE05696: Calculation of water reductions taking into account the implementation 

of the CCR rule for Regulatory Options A through E.

• DCN SE05697: Calculation of water reductions taking into account the implantation of 

both the CCR rule and the CPP for Regulatory Options A through F.

5.1 Intake Water Reduction Analysis Methodology and Results

Of the plants discharging ash transport water, ERG identified 16 plants using intake water as a

source for fly ash transport water and 86 plants using intake water as a source for bottom ash 

transport water. Additionally, the three plants estimated to implement FGD recycle also use intake 

water as a source for FGD preparation water.6 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 three plants estimated to implement FGD 

recycle, ERG multiplied the amount being recycled within the FGD system by the average 

 6 Accounting for CPP, ERG identified 12 plants using intake water as a source for fly ash transport water and 60 plants 

using intake water as a source for bottom ash transport water. Additionally, there is only one plant estimated to 

implement FGD recycle. ERG determined that this plant uses intake water as a source for FGD preparation water.
Memorandum

September 30, 2015

Page 21

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 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 

final rule. Table 5-1 presents the industry-level reduction in intake water flows by wastestream. 

Table 5-2 adjusts the results shown in Table 5-1, to take into account implementation of the CPP.

There is no reduction in intake water associated with landfill 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 Process Water Reduction by Regulatory Option

Non-Water Quality 

Impact

Water Reduction with the ELG

Option A Option B Option C Option D Option E

Water Reduction

(Million Gallons/Day) 44.9 44.9 137 209 209

Table 5-2. Industry-Level Process Water Reduction by Regulatory Option, Accounting for 

CPP

Non-Water Quality 

Impact

Water Reduction with the ELG

Option A Option B Option C Option D Option E Option F

Water Reduction

(Million Gallons/Day) 36.3 36.3 108 143 143 143

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 7.6 percent and 10.9 

percent accounting for CPP for Regulatory Option D. Table 5-3 presents the industry-level 

reduction in intake water flows reflecting this second calculation methodology to account for ash 

transport water recycle systems. Table 5-4 adjusts the results shown in Table 5-3, taking into 

account implementation of the CPP.
Memorandum

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Table 5-3. Alternate Industry-Level Process Water Reduction by Regulatory Option

Non-Water Quality 

Impact

Water Reduction with the ELG

Option A Option B Option C Option D Option E

Water Reduction

(Million Gallons/Day) 44.9 44.9 143 223 223

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

Accounting for CPP

Non-Water Quality 

Impact

Water Reduction with the ELG

Option A Option B Option C Option D Option E Option F

Water Reduction

(Million Gallons/Day) 36.3 36.3 114 155 155 155

The reduction in intake water flows presented in Table 5-3 and Table 5-4 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 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.

5.2 Groundwater Reduction Analysis Methodology and Results

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

implementing FGD recycle identified groundwater as a water source. For this one plant, ERG 

determined the amount of ground water reduction associated with the final rule using a 

methodology similar to that of the intake water reduction analysis.

ERG calculated the percentage of ground water and/or well water based on the water sources 

reported by each plant in Question C3-3 of the Steam Electric Survey. ERG then calculated an 

average percentage of ground water based on all units generating bottom ash transport water. 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 5-5 presents the industry-level reduction in 

groundwater flows by wastestream. ERG did not estimate any changes in the industry-level 

reduction in groundwater flows after taking into account implementation of the CPP.

This plant did not identify ash sluice or transport water as a water source in Question 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 5-5. Industry-Level Ground Water Reductions

Wastestream Ground Water Flow Reduction (GPD)

FGD 0

Fly Ash 0
Memorandum

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Table 5-5. Industry-Level Ground Water Reductions

Wastestream Ground Water Flow Reduction (GPD)

Bottom Ash 22,000

Leachate 0

Total 22,000

5.3 Intake Water Reductions Compared to Industry Wastestream Discharges

As described above, ERG estimates that the ELGs will result in reduced water intake at power 

plants. For comparison, ERG compared the expected levels of intake water reductions to the 

estimated amount of wastewater discharged, as estimated for the baseline loadings, for each 

wastestream that would lead to NWQIs, presented in Table 5-6.

Table 5-6. Estimated Wastewater Discharges at Steam Electric Power Plants

Type of Wastewater

Total Baseline Industry Discharge 

Flow (Million Gallons/Day)

Total Baseline Industry Discharge 

Flow, Accounting for CPP (Million 

Gallons/Day)

FGD Wastewater 41.7 32.4

Ash Transport Water 298-315 214-228

Landfill and Impoundment Leachate 9.09 7.90

5.4 Impact of Steam Electric ELGs on Water Stressed Areas

EPA’s Office of Policy (OP) National Center for Environmental Economics (NCEE) completed a 

study on the impacts of the Steam Electric ELGs on water withdrawals from both surface

waterbodies and aquifers in water stressed areas. Because a number of steam electric power plants 

are located in regions that experience regular or intermittent drought conditions, NCEE analyzed 

the exposure of steam electric power plants to drought-related conditions and quantified the reduced 

water intake in water-stressed areas. NCEE first analyzed plants that would reduce water intake 

under Regulatory Option D with at least one week of water-stressed conditions and found that an 

annual average of 50 to 53 billion gallons of water would no longer be withdrawn from droughtprone areas. Additionally, NCEE analyzed plants that would reduce water intake under Regulatory

Option D under water-stressed conditions for 5 to 10 weeks and found that an annual average of 27 

to 29 billion gallons of water would no longer be withdrawn from drought-prone areas.

NCEE also found that water availability can have several other indirect effects including higher 

electricity prices, increased pollutant emissions, and the impingement and entrainment of aquatic 

organisms. For more information, see NCEE’s analysis “Water Withdrawals in Water Stressed 

Areas: Impacts of the Steam Electric Effluent Limitations Guidelines” [NCEE, 2015].

REFERENCES

1. Baker, Rick. 2011. Email Correspondence between Rick Baker and Elizabeth Sabol, Eastern 

Research Group, Inc. “RE: Fuel/Emission Factors for Dump Trucks.” (September 14). DCN 

SE02960.
Memorandum

September 30, 2015

Page 24

2. California Climate Action Registry. 2007. General Reporting Protocol: Reporting EntityWide Greenhouse Gas Emission, Version 2.2. (March). DCN SE02035.

3. NCEE. 2015. National Center for Environmental Economics. Water Withdrawals in Water 

Stressed Areas: Impacts of the Steam Electric Effluent Limitations Guidelines. (Date). DCN 

SE05943.

4. U.S. DOE. 2009. U.S. Department of Energy. Annual Electric Generator Report (collected 

via Form EIA-860). Energy Information Administration (EIA). The data files are available 

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

5. U.S. EPA. 2004. MOBILE6.2 Vehicle Emission Modeling Software, available online at: 

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

6. U.S. EPA. 2008. eGRID2007 Version 1.1, available online at: 

http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html. DCN SE02036.

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

(eGRID 2012) Technical Support Document. Available online at: 

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

rtDocument.pdf. DCN SE02112.

8. 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.

9. U.S. EPA. 2015a. Benefits and Cost Analysis for the Steam Electric Effluent Limitations 

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

EPA-821-R-15-004. (Date). 

10. U.S. EPA. 2015b. Incremental Costs and Pollutant Removals for the Final Effluent 

Limitations Guidelines and Standards for the Steam Electric Power Generating Point 

Source Category Report. (Date). DCN SE005831.