### 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. I NTRODUCTION /B ACKGROUND

The elimination or reduction of one form of pollution has the potential to aggravate other environmental problems, an effect frequently re ferred to as cross-media impacts. Under sections 304(b) and 306 of the Clean Water Act, EPA is required to consid er 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 an d management, and water usage.

ERG determined that the proposed ELGs have NW QIs 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 gasificati on wastewater currently ope rate the technologies identified as the basis for BAT, ERG does not predict a ny net increase of energy or fuel usage, sludge generation, air emissions, or water usage for these wastestream s 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 gene ration, air emissions or water usage for nonchemical metal cleaning wastes for the proposed ELGs. ER G 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 wastew ater 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, instea d of pumped and wet sl uiced to impoundments.

Table 1-1. Steam Electric Regulatory Options

Wastestreams a Technologies Leading to Non-Wate r 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, ga sification wastewater, and flue gas mercury control wastewater are not
listed in the table because there are no non-water quality environmental impact s associated with the proposed ELGs
for these wastestreams.

In the evaluation of technology options being co nsidered 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 ot her solids on or off site, to operate wastewater treatment systems (e.g., chemi cal precipitation, biological treatment), and to operate ash handling systems. Sim ilarly, as applicable, ERG also estimated the decrease in energy requirements result ing from the reduction in wet sluicing operations and use of earth-moving equipm ent. Energy usage included in this analysis is expressed in either megawa tt hours (MWh) for equipment added to the plant systems or in consumed fuel (g allons) for transportation equipment.

 Air Pollution . Steam electric power plants generate air pollution when they use energy, and as such, the incremental increa se in energy usage associated with the regulatory options will also result in increased air pollution. Air emissions are generated from the operation of wastewat er 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 estim ated 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 polluta nts are those pollutants for which a national ambient air quality standard (NAAQS) has been set and include SO 2 andMemorandum January 28, 2013 Page 3

NO
x . Greenhouse gases (GHGs) are gases such as CO 2 , CH 4 , and N 2 O 1 that absorb radiation, thereby trapping heat in the atmosphere, and contributing to global warming. The NWQI analysis quan tifies 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. Th e regulatory options would not alter the amount of fly ash or bottom ash genera ted. However, the re gulatory options evaluated would likely incr ease the amount of solid wa ste 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 oper ating 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 NW QIs have on an industry- and national-level, and a summary of the NWQI determ ined for each regulatory option.

2. E NERGY U SAGE M ETHODOLOGY

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 pl ants 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. Similarl y, as applicable, ERG also estimated the decrease in energy requirements resulting from th e reduction in wet sluicing operations and use of earth-moving equipment. Energy usage associat ed with power usage was estimated based on the horsepower rating of the pumps and other equi pment, 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 syst ems 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 ho rsepower 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 calcul ations 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 consumpti on associated with transporting the solid waste generated due to the technology options. The me thodology 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 me thodology 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 a nd distance of transpor t depends on a plant’s operation and configuration. For ex ample, the volume of waste ge nerated per day determines the frequency with which trucks will be travelling to and from the storage site s. The availability of
either an onsite or offsite non-h azardous landfill and its distance from the plant determines the length of travel time. Fuel usage is calculated as gallons of fuel us ed. 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 ga llon at idle. Therefore, ERG estimates the idle fuel consumption to be 0.38 gal/hr.

Transport Distance (mile/round trip) = The estim ated round trip distance to/from the landfill. Distance varies based on pl ants 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 calcula ted number of trips for one year, based on the amount of ash and/or FGD solids generated by the plant, in the transportatio n 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 Po llutant Removals for Proposed Effluent Limitations Guidelines and St andards 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 consump tion associated with th e regulatory options are
shown in Table 2-1.

Table 2-1. Industry-Level Energy Requi rements 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 ne t increase in annual electric energy consumption associated with the preferred options, ERG comp ared 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 electricMemorandum January 28, 2013 Page 6

power plants throughout the United States. A ccording to EPA’s Emissions & Generation Resource Integrated Database (eGRID), the el ectric power industry ge nerated approximately 3,951 million MWh of electricity in 2009 [U.S. EPA, 2012a]. ERG estimates that energy increases associated with Regulatory Option 3 w ill be less than eight thousandths of a percent (0.008%) of the total electricity generated by a ll 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 fu el consumption (gallons) estimated for the preferred options, as shown in Table 2-1, to national fuel consumpti on 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 Regul atory Option 4 will be less than 18 thousandths of a percent (0.018%) of total fuel consum ption by all motor vehicles.

3. A IR P OLLUTION M ETHODOLOGY

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

1) Additional auxiliary electricity use by steam electric plants to operate wastewater treatment, ash handling, and other syst ems needed to comply with the new effluent limits and standards;

2) Additional transportation-related emissi ons 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 pl ants 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 ch ange 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 El ectric Power Generating Point Source Categor y report for additional discussion of th e 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 tech nology 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 incr eased auxiliary electric ity using year-explicit emission factors projected in the In tegrated Planning Model (IPM) for CO 2 , NO
x , and SO 2 2 . EPA obtained emission factors for years 2017 thr ough 2024 based on IPM outputs for Run Year 2020 and emission factors for years 2025 through 204 0 based on IPM output for Run Year 2030. ERG
used values associated with Run Year 2030 beca use these values represent the estimated annual emission factors after full impl ementation of the proposed rule.

Because IPM was only run for Options 3 and 4, th e IPM emission factors for Option 3 were used to estimate changes in auxiliary power air em issions for Regulatory Options 1, 2, and 3 and IPM emissions factors for Option 4 were used to estim ate 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 CO 2 , NO
x , and SO 2 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

CO 2 NO X SO 2 CO 2 NO X SO 2 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 wi th auxiliary energy requirements for SO 2 ; however, for other air emission analyses for transportation, ERG calculated values for SO X . ERG assumes that SO 2 represents the values
for SO X for auxiliary energy requirements.Memorandum January 28, 2013 Page 8

For plants with capacity utiliza tion rates (CUR) of 90.4 percent or less, emissions were estimated using plant-specific and year-explicit em ission factors obtained from IPM outputs. 3 These plants are assumed to be able to generate th e 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 additiona l electricity consumpti on 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 usi ng part of its existing generatio n to power equipment, requiring other plants within the same NE RC region to generate additional electricity to meet demand).

EPA calculated NO
x emissions as follows:

Where:

NOX t = Total NO
x emissions in year t

. E

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

per year. EF_NOX p,t

= NO
x emission factor at plant p in year t , in tons NO
x per MWh. If CUR p > 90.4 percent, EF_NOX p,t

is based on average EF_NOX t for the NERC region where plant p is located. For t = 2017 to 2024, the calculations use

IPM EF_NOX p,2020 . For t = 2025 to 2040, the calculations use IPM EF_NOX p,2030

. T

p,t

= Timing adjustment to reflect year when plants are assumed to install the compliance technology between 201 7 and 2021 and start incurring additional electricity consumption ( T p,t

=0 if t < Year when plant p installs technology; T p,t

=1 if t  Year when plant p installs technology).
W

i = Sample weight for plant p

.

Emissions of CO 2 and SO 2 are calculated sim ilarly but using the CO 2 and SO 2 emission factors, respectively. Table 3-2 presents the air emi ssions 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/Ye ar) Associated with Increased Auxiliary Electricity Per Regulatory Opti on Using IPM Emission Factors

Regulatory Option Air Emissions

NO X (tons/year) SO 2 (tons/year) CO 2 (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 emi ssions resulting from increased auxiliary electricity using EPA’s eGRID national estim ate of 0.0000136 tons of methane per MWh. Using the eGRID emission rates per MWh, ERG calculate d 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 Emissi on 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 Emission s (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 incr eased operation of transportation vehicles, ERG used the MOBILE6.2 model to generate air emi ssion factors (grams per mile) for hydrocarbons (HC), carbon monoxide (CO), NO
x , CO 2 , and particulate matter (PM). ERG assumed the general input parameters such as the year of the vehi cle, assumed to be 2010, to develop these factors (Baker, 2011). Because MOBILE6.2 does not estima te emission factors for methane, ERG used
the emission factors from the California Clim ate Action Registry, Gene ral 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 Californi a Climate Action Registry Transportation Emission Rates

NO

x Highway

(ton/mile) NO

x Local (ton/mile) SO

x (ton/mile) CO 2 (ton/mile) CH 4 (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 regula tory 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 Trip s (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 es timated 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 cal culated 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 truc ks associated with tr ansporting the additional solid waste, ERG also estimated the annual numbe r of miles that would be traveled by water trucks spraying water around landfills and ash unlo ading areas to control dust as described in
Section 2 of this memorandum. ER G used these estimates to calc ulate the net increase in air emissions for this rulemaking. See EPA’s Incremental Costs and Po llutant Removals for Proposed Effluent Limitations Guidelines and St andards 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 transporta tion of the solid waste for the proposed ELGs.Memorandum January 28, 2013 Page 11

Table 3-5. Industry-Level Air Emissions Associ ated with Transportation by Regulatory Option

Regulatory Option Air Emissions

NO

x (tons/year) SO

x (tons/year) CO 2 (metric tons/year) CH 4 (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 electr icity 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 genera tion due to compliance costs attributable to the proposed ELGs. Therefore, these ch anges, either increases or decr eases, in electricity generation
affect the air emissions from steam electric power plants. EPA only estimated the changes associated with the IPM predications for Regulat ory 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 Associat ed with Changes in Industry Profile For the Proposed Regulatory Option

Regulatory Option Air Emissions

NO

x (tons/year) SO 2 a (tons/year) CO 2 (metric tons/year)

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

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

a - EPA calculated air emission associat ed changes in industry profile for SO 2 ; however, for other air emission analyses for transportation, ERG calculated values for SO

x . ERG assumes that SO 2 represents the values for SO

x for auxiliary energy requirements.

3.4 Air Emission Comparisons to Other National Estimates

To provide some perspective on th e potential increase in annual ai r 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 elect ric 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

NO

x 0.00121 1 0.121

SO

x -0.00273 6 -0.045

CO 2 -1.282 2,403 -0.053

CH 4 0.000001 95 0.000001
Regulatory Option 4

NO

x 0.00154 1 0.154

SO

x -0.00329 6 -0.055

CO 2 -4.133 2,403 -0.172

CH 4 0.000001 95 0.000001

4. S OLID W ASTE G ENERATION M ETHODOLOGY

Solid waste associated with the implementati on of the Steam Electric ELGs is based on sludge generated from FGD wastewater treatment, in cluding sludge from ch emical precipitation, biological treatment, and vapor-compression evap oration. ERG estimated the amount of solid waste generated from each technology for each plan t. 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 genera ted. Therefore, these volumes will not be included in the estimation of NWQIs.

ERG determined dewatered sludge generation rate s for FGD chemical precipitation treatment by multiplying a flow-normalized dewatered sludge ge neration rate (expressed in tons per day of sludge per gallon per minute FGD flow) by the plan t flow rate. The flow-normalized dewatered sludge generation rate was determined based on responses in the questionnaire for FGD wastewater chemical precipita tion treatment. ERG selected the median flow-normalized dewatered sludge generation rate based on an asse ssment of the characteri stics of the dataset.
ERG then calculated the annual sludge generation as follows:

Annual Sludge Generation, tons/yr = Sludge Gene ration Rate × FGD Wast ewater Flow, gpm × 60 min/hr × 24 hr/day × 365 day/year

Where:

Sludge Generation Rate = The median fl ow normalized rate of sludge generation based on responses to the Questionnaire for the Steam
Electric Power Generati ng 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 conve rt 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 preci pitation sludge. Sludge generated by the vaporcompression evaporation system includes soften ing 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 sludg e production associated with the regulatory options is shown in Table 4-1.

To provide some perspective on the potentia l increase in annual solid waste generation associated with Regulatory Options 3 and 4, ERG co mpared 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 plan ts generated approximate ly 134 billion tons of solids in 2009. ERG estimates that solid waste ge neration increases associated with Regulatory Option 3 will be less than 0.001% of the total soli d waste generated by all electric power plants and the solid waste generation increases associat ed with Regulatory Option 4 will be less than 0.0011% of the total solid waste genera ted 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. W ATER U SAGE

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 precipita tion, biological treatment ) will not reduce the
amount of water used unle ss 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 wa ter for each of these processes. ERG used the responses from Question B5-1 of the Steam Electri c Survey (Part B – Flue Gas DesulfurizationMemorandum January 28, 2013 Page 14

(FGD) systems, Section 5 – FGD Wastewater Gene ration) for the five plants expected to implement FGD recycle to identify sources of F GD reagent preparation water, absorber make-up water, and mist eliminator wash water. For mo re 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 Informa tion, Section 3.1 – Bottom Ash Handling – Generating Unit Level Information) of the St eam 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 sour ce for FGD water or ash transport water as part of the intake wate r reduction analysis. ERG analyzed any plant identifying groundwater or well water as a source fo r 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 subsect ions specifically discuss the methodology
and results for intake water reductions a nd ground water reductions, respectively.

5.1 Intake Water Reduction Analysis Methodology and Results

Of the plants discharging ash tr ansport water, ERG identified 65 plants using intake water as a source for fly ash transport wate r and 180 plants using intake wa ter 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 treate d intake water based on the wate r sources reported by each plant in Questions B5-1, C2-2, and C3-3 of the St eam Electric Survey. ERG calculated the total
amount of raw and/or treated in take water identified in each response and divided by the total
amount of source water. This cal culation yielded a per centage of source wate r associated with intake water. For the FGD recycle plants, the so urce 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 ge nerating unit level. ERG calculated an average percentage of intake water based on all units discharging fly or botto m 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 a ssociated 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 th e FGD system by the average percentage of
source water associated with intake water. For each plant generating as h transport water, ERG multiplied the amount of ash transport water curre ntly 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 th e 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. Ta ble 5-1 presents the indu stry-level reduction in intake water flows by wastestream. There is no re duction in intake water associated with landfillMemorandum January 28, 2013 Page 15

leachate because intake water is not a source of this process. Landfill leachate is generally the result of precipitation perc olating 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 di scharge flow could underestimat e 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 pl ant would list both recycl ed 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 s econdary calculation to estimate the potential
reduction in intake water accounti ng for these recycle systems. Fo r this secondary calculation, ERG assumed that all plants identifying fly ash slui ce or bottom ash sluice in C2-2 or C3-3 used intake water to make-up 100% of the water discha rged as ash transport water. For these plants, ERG multiplied the amount of ash transport wate r discharged by 100% to determine the intake water reduction for these plants. This secondary ca lculation resulted in an increased intake water reduction of 2.3 percent. Table 5- 2 presents the industr y-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 overe stimate of the actual reduction in intake water because some plants us e sources of water other than intake water as make-up in their ash transport r ecycle systems. The two calculation methods used to generate the reductions in intake water presented in Tabl e 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 wate r source. For these two plants, ERG determined the amount of ground water reduc tion associated with the proposed ELGs using a methodology similar to that of th e 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 wa ter discharged annuall y. The resulting value represents the amount of ground water no longer required by the pl ant, or the reduction in ground water. Table 5-3 presents the industry-level reduction in gr ound water flows by wastestream.

Neither of these two plants identif ied ash sluice or transport water as a water source in Questions C2-2 or C3-3 of the Steam Electric Survey; ther efore, ERG did not need to conduct a secondary analysis to estimate ground water reductions for recycle systems.

Table 5-3. Industry-Leve l 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 prop osed 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 regu latory option evaluated for the proposed rule. For comparison, ERG compared the expected levels of water reductions to the current amount of wastewater discharged fo r each wastestream that would lead to NWQIs, presented in Table 5-5.Memorandum January 28, 2013 Page 17

Table 5-4. Industry-Level Water Re duction 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. F UTURE P ROFILE AND N EW S OURCE NWQI E STIMATES

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 co ntrols that will likely be installed at plants because of recently promulgated Clean Air Act Requi rements. These controls will only affect the
FGD wastewater stream. For more informati on 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 as sociated with eight different
NSPS scenarios considered to be new sources. ER G calculated the NWQI associated with NSPS scenarios 1 and 4, for three model size plan ts: 350 MW, 600 MW, and 1,300 MW. A description of the scenarios is provided below:

 Scenario 1: New, Greenfield plant w ith 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 ex isting 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 a nd methodology for estimating costs, see ERG’s
memorandum “New Source Performance Sta ndards (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 es timate air emissions associated with auxiliary energy requirements. Based on the data provid ed 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 requ irements. Because national air emission factors were only calculated for Regul atory Options 3 and 4, ERG us ed the Option 3 national air emission factors (US) for model run year 2030 to calculate air emissi ons associated with increased auxiliary electricity for Regulatory Op tions 1, 2 and 3. ERG used the Option 4 national air emission factors (US) for model run year 203 0 to calculate air emissions associated with increased auxiliary electricity for Regulatory Op tions 4 and 5. Additionally, because these plants are not part of the current profile , air emissions associated with th e 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 sy stems that are expected to be installed after 2014, not all the current and future wet FGD sy stems) are presented in Table 6-1. The new source NWQI results for the three model plant si zes are presented in Table 6-2, Table 6-3, and
Table 6-4.MemorandumJanuary 28, 2013Page 19Table 6-1. Calculated Sum of NWQI for Each Treatment Option for the Future WetFGD Systems Expected to be InstalledAfter 2014RegulatoryOptionElectrical EnergyUsage(MWh/year)Fuel(GPY)Sludge(tons/year)NOXEmissions(tons/year)SOXEmissions(tons/year)CO2Emissions(tons/year)CH4Emissions(tons/year)1 7,945 36,411 138,920 3.30 3.98 4,860 0.1202 20,814 36,607 139,670 8.44 10.41 12,252 0.2953 20,814 36,607 139,670 8.44 10.41 12,252 0.2954 20,814 36,607 139,670 8.44 10.41 12,238 0.2955 195,623 286,581 1,112,889 79.18 97.83 114,551 2.758Note: The NWQI presented in this table onlyreflect the NWQI associated with the wet FGD systems that are expected to be installed after 2014 (i.e., afterpromulgation of the final rule). The values presented in the table do not reflect the total NWQIassociated with the current profile plus the additional futureinstallations.MemorandumJanuary 28, 2013Page 20Table 6-2. Calculated Sum of NWQI for New Sources Evaluated for the Proposed Rulemaking for 350 MW Model PlantNSPSScenarioRegulatoryOptionElectricalEnergy Usage(MWh/year)Fuel(GPY)Sludge(tons/year)NOxEmissions(tons/year)SOxEmissions(tons/year)CO2Emissions(tons/year)CH4Emissions(tons/year)11 180 165 4,056 0.07 0.09 2 0.0022 1,085 166 4,078 0.43 0.54 624 0.0153 1,085 166 4,078 0.43 0.54 624 0.0154 1,533 2,352 4,604 0.62 0.77 899 0.025 5,816 1,563 32,393 2.33 2.91 3,347 0.08041 180 165 4,056 0.07 0.09 2 0.0022 1,085 166 4,078 0.43 0.54 624 0.0153 1,085 166 4,078 0.43 0.54 624 0.0154 1,085 166 4,078 0.43 0.54 623 0.0155 5,545 1,291 31,869 2.22 2.77 3,189 0.076MemorandumJanuary 28, 2013Page 21Table 6-3. Calculated Sum of NWQI for New Sources Evaluated for the Proposed Rulemaking for 600 MW Model PlantNSPS ScenarioRegulatoryOptionElectricalEnergy Usage(MWh/year)Fuel(GPY)Sludge(tons/year)NOXEmissions(tons/year)SOXEmissions(tons/year)CO2Emissions(tons/year)CH4Emissions(tons/year)11 363 269 6,628 0.15 0.18 2 0.0052 1,590 270 6,663 0.64 0.79 915 0.0223 1,590 270 6,663 0.64 0.79 915 0.0224 2,123 3,865 7,565 0.86 1.06 1,250 0.0305 9,410 2,571 52,974 3.77 4.71 5,416 0.12941 363 269 6,628 0.15 0.18 2 0.0052 1,590 270 6,663 0.64 0.79 915 0.0223 1,590 270 6,663 0.64 0.79 915 0.0224 1,590 270 6,663 0.64 0.79 914 0.0225 9,119 2,110 52,076 3.65 4.56 5,245 0.125MemorandumJanuary 28, 2013Page 22Table 6-4. Calculated Sum of NWQI for New Sources Evaluated for the Proposed Rulemaking for 1,300 MW Model PlantNSPSScenarioRegulatoryOptionElectricalEnergy Usage(MWh/year)Fuel(GPY)Sludge(tons/year)NOXEmissions(tons/year)SOXEmissions(tons/year)CO2Emissions(tons/year)CH4Emissions(tons/year)11 979 582 14,346 0.39 0.49 5 0.0132 3,169 585 14,422 1.27 1.58 1,824 0.0433 3,169 585 14,422 1.27 1.58 1,824 0.0434 4,014 8,362 16,377 1.63 2.01 2,372 0.0575 20,286 5,563 114,662 8.13 10.14 11,676 0.27841 979 582 14,346 0.39 0.49 5 0.0132 3,169 585 14,422 1.27 1.58 1,824 0.0433 3,169 585 14,422 1.27 1.58 1,824 0.0434 3,169 585 14,422 1.27 1.58 1,822 0.0435 19,910 4,568 112,717 7.98 9.96 11,452 0.273Memorandum January 28, 2013 Page 23

R EFERENCES

1. Baker, Rick. 2011. Email Correspondence betwee n Rick Baker and Elizabeth Sabol, Eastern Research Group, Inc. “RE: Fuel/Emission Factor s for Dump Trucks.” (September 14). DCN
SE02960.

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

3. U.S. DOE. 2009. U.S. Department of Energy. Annual Electric Genera tor Report (collected via Form EIA-860). Energy Information Administ ration (EIA). The data files are available online at: http://www.eia.gov/electricity /data/eia860/index.h tml. DCN SE01805.

4. U.S. EPA. 2004. MOBILE6.2 Vehicle Emission Modeling Software, available online at: http://www.epa.gov/oms/m6.htm.

5. U.S. EPA. 2008. eGRID2007 Version 1.1, available online at: http://www.epa.gov/cleanenergy/energy-re sources/egrid/index.html. DCN SE02036.

6. U.S. EPA. 2012a. The Emissions & Generation Resour ce Integrated Database for 2012 (eGRID 2012) Technical Support Document . Available online at: http://www.epa.gov/cleanenergy/document s/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-re sources/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 th e Steam Electric Generating Point Source Category Report . (19 April). DCN SE01957.