### 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 Impact s for BAT/PSES

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 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, E RG evaluate d the effect of these regulations on energy usage
, air

emissions

, solid waste generation and management , and water usage

.

ERG determined that the ELG s ha ve NWQIs associated with operations for treating and managing flue gas desulfurization ( FGD ) wastewater, combustion residual landfill leachate, and ash transp ort water. The ELG s also establish limit s 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 identif ied 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 waste streams for the ELG s

. ERG estimated NWQIs on a plant

- specific basis for each of the technologies and ac tivities that make up the six regulatory option s considered for the ELGs . These technologies include:

• Chemical precipitation wastewater treatment;

• Biological wastewater treatment;

• E vaporation;

• 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

• C ombustion 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 forMemorandum September 30, 2015 Page 2

t ransportation and disposal of solid s 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 Page 3

Table 1

- 1 . Steam Electric Regulatory Options

Wastestreams a Technologies Leading to Non

- Water Quality Environmental Impacts

A B C D E F b ,c

F GD

W a s t e w at er Ch e mical Precipitation Ch e mical Precipitation +
B iological Treatment Ch e mical Precipitation + Biological Treatment Ch e mical Precipitation +
B iological Treatment Ch e mical Precipitation + Biological Treatment Evaporation

F ly A sh T r a n s p o rt W at er Dry Handling Dry Handling D r y h a n d li n g D r y h a n d li n g D r y h a n d li n g Dry handling

B ot t o m A s h T r a n s p o rt

W at er Impoundment (Eq u al

to B P T ) Impoundment (Eq u al

to B P T ) D r y h a n d li n g/C l o s ed

l oop (for units >400 MW); Impoundment (Eq u al to B P T )(for units ≤400 MW) D r y h a n d li n g/

C l o s ed l oop D r y h a n d li n g/

C l o s ed l oop Dry handling/ Closed loop

Combustion Residual

L e a ch at e Impoundment (Eq u al

to B P T ) Impoundment (Eq u al

to B P T ) Impoundment (Eq u al to B P T ) Impoundment (Eq u al to B P T ) Ch e mical 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 tak es 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 technol ogy . The information is this memo randum

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 th at Re gulatory 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 U sage

. Due to the ELG s , s team electric power plants will use additional

energy to transport ash and other solids on or off site, to operat e wastewater treatment systems (e.g., chemical precipita tion, biological treatment), and to
operat e ash handling systems. Similarly, as applicable, E RG also estimated the decrease in energy requirements resulting from the reduction in wet sluicing operations and use o f earth moving equipment

. Energy usage included in this analysis is expressed in either mega watt hours ( M W h) for equipment added to the plant systems or in consumed fuel (gallons ) for transportation equipment.

• Air Emissions

. Steam electric power plants generat e a ir 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

. A ir

emissions result from the generation of electricity needed to operate waste water treatment systems and ash handling systems, as well as from t he 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 es timated 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 SO 2 and 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 quantif ies

the incremental change in ai r 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 reg ulatory 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

sys tems. 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 ( N 2 O) as part of the NWQI analysis. To avoid double counting air emission estimates, ERG only calculated nitrogen oxide emissions (NOx), which would include N 2 O.Memorandum September 30, 2015 Page 5

This memorandum presents the methodology used for estimating the incremental changes in NWQI s
, per spective o n the potential impacts the NWQIs have on an industry and national level

, and a summary of the NWQI s estimated for each regulatory option

. ERG calculated NWQI s for

two scenarios of power plant populations : (1) taking into account the implementati on 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: Cal culation 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. E NERGY U SAGE M ETHODOLOGY

Energy usage associated with the implementation of the Steam Electric ELG s is based on energy used to operate wastewater treatment systems, dry ash transport systems, and transport and disposal operations. For those plants that ERG determ ined would incur costs to comply with t he 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 op erations of the plant . Therefore, as applicable, ERG estimated the additional energy usage for equipment added to the plant systems or for fuel consumed for

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

decrease i n energy requirements resulting from the reduction in wet sluic ing 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 u nits of MWh s. 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, 2015 b ].

To determine potential decreases in electrical energy use, ERG e stimated the amount of energy saved from reducing wet sluic ing pump operations based on the h orsepower rating of the pumps

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

calculated as follows:

2 A t 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 f or 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 Consumpt ion ( kWh ) = (0.0229 x [Flow Rate / (60 min/hr x 24 hpd)] + 0.9268) x hp KW Factor x Operating Hours x Operating Days

w here :

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 impoundment s based on the horsepower rating of the engine

. ERG estimated energy savings based o n horsepower rating of the engine based on the availab le 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

loader s for each wastestream was calculated as follows:

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

Factor x Earthmoving Operating Hours x Ea rthmoving Operating Days

w here :

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 ( M Wh) = Wastewater Treatment Energy Demand ( M Wh) + Fly Ash

Handling Energy Demand ( M Wh) + Bottom Ash Handling Energy Demand ( M Wh)

–

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 ( M Wh)

– Earth

- moving Equipment Energy Demand ( M Wh )

Table 2

- 1 presents t he net increase s in annual electrical e nergy usage associated with the regul atory 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

.

Ene rgy usage also include s the fuel consum ption associated with transport ing the sol i d waste generated due to the technolog y 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, 201 5 b ] . That methodology estimate s the need for increased transportation of solid waste (including ash co n verted to dry or closed

- loop wet handling) to

on site or offsite landfills using open dump trucks. T he frequency and distance of transport depend s on a plant ’s operation and configuration. For example, the volume of wast e gener ated per day determine s 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 f uel usage

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

Fuel (gallons) p lant = [ ((Loading Time (hr /trip ) idling + Unloading Time (hr /trip ) idling ) x ( Fuel C onsumption ( gal /hr) idling )) + ( Transport Distance (mile/round trip) x Fuel con sumption (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 estimat es 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 un loading 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

pe r 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 versu s 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 costMemorandum 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 t ransportation cost methodology to truck

all ash and FGD solids to the onsite or offsite landfill
[ U.S.EPA, 201 5 b ]

.

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 inform ation on the specific calculations used to estimate water truck

fuel usage [ U.S.EPA, 201 5 b ]

.

The net increase s in national annual fuel consumption associated with the regul atory 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 Regulat ory 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 Regulat ory 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 option s
, 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 approximat ely 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 DMemorandum September 30, 2015 Page 9

assuming all plants elect to comply with the voluntary incentives program (re presented 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

reg ulatory option s, as shown in Table 2

- 1 and Table 2

- 2

, to national fuel consumption estimates

for motor vehicles in the United States . Accord ing 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 i ncrease 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 consumptio n by all motor vehicles in the United States

.

3. A IR E MISSIONS M ETHODOLOGY

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; an d

3) The change in the profile of electricity generation due to relatively higher costs to generate electricity at plants incurring complian ce 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 Categor y report for additional d iscussion of the third mechanism [ U.S. EPA, 201 5a ].

3.1 Air Emissions Associated with Energy

E RG estimated the energy usage associated with the operation of wastewater treatment systems and ash handling systems in kWh

. Additionally, ERG also estimated the decr ease in energy requirements associated with terminating wet sluicing operations and reduced use of earth

moving equipment associated with the new technology options. ERG used these estimates to calculate the net change in energy requirements for all regula tory options considere d 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 CO 2 , NO

x , and SO 2 4

. The

4 ERG calculated air emissi ons associated with auxiliary energy requirements for SO 2 ; however, for other air emission analyses for transportation, ERG calculated values for SO X . The air emissions for SO 2 are a reasonable

estimate for SO X emissions from changes in auxiliary energy re quirements.Memorandum September 30, 2015 Page 10

IPM output provides e mission factors by plant and North American Electric Reliability Corporation ( NERC ) region , calculated as the ratio of projected emissions and projected electricity generation

. E mission factors were obtained for years 20 19 through 202 2, 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 emission s 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 CO 2 , NO

x , and

SO 2 by NERC region, as well as the average for the United States.Memorandum September 30, 2015 Page 11

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

Met ric Tonne s / MWh Ton s / M Wh Ton s / M Wh Metric Tonne s / M Wh Ton s / M Wh Ton s / M Wh

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

RF C 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

TR E 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

202 5 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

SE RC 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

WE CC 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

RF C 0.5129 0.0004 0.0005 0.4997 0.0004 0.0005

SERC 0.4052 0.0002 0.0003 0.4072 0.0002 0.0003Memorandum September 30, 2015 Page 12

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

Met ric Tonne s / MWh Ton s / M Wh Ton s / M Wh Metric Tonne s / M Wh Ton s / M Wh Ton s / M Wh

SP P 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

WE CC 0.3498 0.0003 0.0001 0.3277 0.0002 0.0001Memorandum 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 plant

specific 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 ex isting generation to power equipment; however, other plants within the same NERC region would need to generate electricity to compensate for this reduction and meet

e lectricity demands. Therefore, ERG used NERC

- average emission factors for each year instea d of plant

- specific emissions factors when estimating incremental emissions for these plants

.

In general, emissions were calculated using the following equation :

Emissions t = E p × EF p,t × T p,t × O p,t

w here :

Emission t = Total emissions for a specific pollutant in year t

.

E p = Incremental auxiliary power e lectricity consumption at plant p , in MWh per year.

EF p,t = Pollutant

- specific emission factor at plant p in year t , in tons of pollutant per MWh

. If CUR p > 90.4 percent,

EF p,t is based on average EF t for the NERC region where plant p is located (see Table 3

- 1 )

. For t = 2019 to 2022, the calculations use IPM EF p,2020

. For t = 2023 to 2027, the calculations use IPM EF p, 2025

. For t = 2028 to 2042, the calculations use IPM EF p, 2030

.

T p,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 ( T p,t =0 if t < y ear when plant p installs technology; T p,t =1 if t ≥ y ear when plant p installs

tech nology)

. O p = 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 O p,2020

. For t = 2023 to 2027, the

calculations use IPM O p, 2025

. For t = 2028 to 2042, the

calculations u se IPM O p, 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

NO X ( t ons/ y ear) SO 2 ( t ons/ y ear) CO 2 ( m etric t ons/ y ear)

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

NO X ( t ons/ y ear) SO 2 ( t ons/ y ear) CO 2 ( m etric t ons/ y ear)

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 em ission factor , 0.0000136, for methane. Energy Usage (MWh) = The incremental energy usage calculated for each pl ant 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

.Memorandum September 30, 2015 Page 15

Table 3

- 4 . Estimate d Methane Air Emissions (Tons/Year) Associated with In creased Auxiliary Electricity Per Regulatory Option Using eGRID Emission Factors

Regulatory Option Methane Air Emissions (Tons/Year) Methane Air Emissions, A ccounting

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 transport ation vehicles

, ERG used the MOBILE6.2 model to generate air emission factors (gram s per mile) for NO X , CO 2 , and SO X

. 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 Califor nia Climate Action Registry Transportation Emission Rates

NO

x Highway

( ton /mi le ) NO

x Local ( ton /mi le ) SO

x ( ton /mi le ) C O 2 ( ton /mi le ) CH 4 ( ton /mi le )

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 (Transpor t 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, 20 15 b ]

.

E RG estimated the annual number of miles that would be traveled by dump trucks or vacuum trucks moving ash or wastewater treatment sol ids 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, E RG also estimated the annual number of miles that would be traveled by water truc ks 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 n et 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 mo re information on the estimated distance traveled by water trucks [ U.S.EPA,

20 15 b ]

. 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

N O

x (tons/year) SO

x (tons/year) CO 2 (metric tons/year) C H 4 (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

N O

x (tons/year) SO

x (tons/year) CO 2 (metric tons/year) C H 4 (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 0.174Memorandum September 30, 2015 Page 17

Table 3

- 7 . Industry

- Level Air Emissions Associated with Transportation by Regulatory Option , Accounting for CPP

Regulatory Option Air Emissions

N O

x (tons/year) SO

x (tons/year) CO 2 (metric tons/year) C H 4 (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 complia nce cos ts attributable to the ELG s

. T hese 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 g as

- fueled or other electricity generating unit s . The net changes in

national annual air emissions associated with the change in electricity generation profile for Regulatory Option s 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 Option s B and D

Regulatory Option Air Emissions

NO

x (tons/year) SO 2 a (tons/year) CO 2 (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 SO 2 ; however, for other air emission analyses for transportation, ERG calculated values for SO X . The air emissions for SO 2 are a reasonable estimate for

SO X 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 Option s B

and D to the net amount of air emissions generated in a year by all electric power plants through out
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 fo r 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, 2012 a ]

. Table 3

- 10 adjusts the results shown in Table 3

- 9 and includes Regulatory Option F

, taking into account implement ation of the CPP

.Memorandum September 30, 2015 Page 18

Table 3

- 9 . Electric Power Industry Air Emissions for Regulatory Option s 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

NO

x - 0.00325 1

- 0.326

SO

x - 0.000435 6

- 0.00724

CO 2 - 1. 46 2

, 403

- 0. 0612

CH 4 0.00000195 95 0.00000206

Regulatory Option D

NO

x - 0.0114 1

- 1.16

SO

x 0.00245 6 0.0408

CO 2 - 2. 55 2

, 403

- 0. 106

CH 4 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

NO

x - 0.00326 1

- 0.327

SO

x - 0.000441 6

- 0.00735

CO 2 - 1. 48 2

, 403

- 0. 0618

CH 4 0.00000143 95 0.00000151

Regulatory Option D

NO

x - 0.0114 1

- 1.16

SO

x 0.00243 6 0.0406

CO 2 - 2. 58 2,403

- 0. 108

CH 4 0.0000034 95 0.00000358

Regulatory Option F a

NO

x - 0.0108 1

- 1.09

SO

x 0.00337 6 0.0562

CO 2 - 1.41 2,403

- 0.0589

CH 4 0.0000205 95 0.0000216

a

- ERG estimates that the increases in air emissions for Regulatory O ption D assuming all plants elect to comply with the voluntary incentives program (represented by Regulatory Option F), are comparable to Regulatory Option D.

4. S OLID W ASTE G ENERATION M ETHODOLOGY

Solid waste associated with the implementation of the Steam Electric ELG s is based on the generation of residual treatment solids from chemical precipitation, biological treatment, and evaporation

. ERG estimated the amount of solid waste gener ated from each technology for eachMemorandum September 30, 2015 Page 19

plant

. F ly 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 ton s 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 ultimat ely 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, 201 5 b ]

. 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 Regulat ory 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 Regulat ory 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 g enerating 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 option s will be less than 0.001 percent of the total solid waste generated by all electric power plants.

5. W ATER I NTAKE M ETHODOLOGY

Steam electric power plants generally use water for handling solid waste, including ash, and for operating wet FGD scrubbers. For the regulatory optio ns 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 , whichMemorandum September 30, 2015 Page 20

will no longe r 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 pa rt 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 th is 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. S ee 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 f or more information [U.S. EPA, 2015b]

.

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

• DCN SE0 5696 : Calculation of water reductions taking into account the implementation of the CCR rule for Regulatory Options A through E.

• DCN SE0 5697 : Calculation of water reductions t aking 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 plant s estimated to implement FGD recycle also use intake water as a source for FGD preparation water. 6 For each of the se 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 wi th 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 t he 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 amo unt 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 c ombined 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

. T able 5

- 2 adjusts the results shown in Table 5

- 1

, to take into account implementation of the CPP

. Th ere 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 Ste am 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 th ese 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 multipl ied 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 September 30, 2015 Page 22

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 a n overestimate of the actual reduction in intake water because some plants use sources of water other than intake

water as make

- up in the ir 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 require d 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 ground water flows by wastestream

. ERG did not estimate any changes in the industry

- level reduction in groundwater flows after taking into account impl ementation 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 sy stems.

Table 5

- 5 . Industry

- Level Ground Water Reductions

Wastestream Ground Water Flow Reduction ( GPD )

FGD 0

Fly Ash 0Memorandum September 30, 2015 Page 23

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 7.9 0

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 el ectric 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 drought

prone ar eas. 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 droug ht

- 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].

R EFERENCES

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

SE 02960.Memorandum September 30, 2015 Page 24

2. California Climate Action Registry. 2007. General Reporting Protocol: Reporting Entity

Wide Greenhouse Gas Emission, Version 2.2. (March). DCN SE02035

.

3. NCEE. 2015. National Center for E nvironmental 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/electric ity/data/eia860/index.html. DCN SE01805.

5. U.S. EPA. 2004. MOBILE6.2 Vehicle Emission Modeling Software, available online at: http://www.epa.gov/o ms/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

. A vailable online at: http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2012_year09_TechnicalSuppo rtDocument.pdf . DCN SE02112.

8. U.S. EPA. 2012b . eGRI D2012 Version 1.0 2009 Data. A vailable online at: http://www.epa.gov/cleanenergy/energy

- resources/egrid/index.html . DCN SE0211 1

.

9. U.S. EPA. 201 5 a. 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. 201 5 b

. 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 SE0 05831

.