MEMORANDUM
TO: Docket
FROM: EPA, Clean Air Markets Division
SUBJECT: Economic and Energy Impact Analysis for the Proposed Utility
MACT Rulemaking
DATE: January 28, 2004
This memorandum provides the results of the economic and energy impact analysis performed
for the proposed Utility MACT rulemaking. EPA used the Integrated Planning Model (IPM),
developed by ICF Consulting, to conduct its analysis. IPM is a dynamic linear programming
model that can be used to examine air pollution control policies for mercury and other pollutants
throughout the contiguous U.S. for the entire power system. Documentation for how the EPA
has configured IPM for pollution control analysis can be found at www.epa.gov/airmarkets/epa-
ipm.
This memorandum provides results for the MACT scenario following the emissions limits as
outlined in the proposed rule. The proposed rule would establish emission limits for Hg
depending on the rank of coal. Thus, the scenario that is analyzed here presumes the rate
requirements for existing coal-fired generating units shown in Table 1 below.
Table 1
Proposed Mercury MACT Emission Limits for Existing Coal-Fired
Electric Utility Steam Generating Units
Subcategories Based on Coal
Rank
Rates
(Ib/TBtu)
Bituminous
2.0
Subbituminous
5.8
Lignite
9.2
Coal refuse / Waste coal
0.4
IGCC units
19.0
Note: TBtu - trillion BTlJs of heat input
Source: Proposal of'Mercury KIACT, signed December 15, 2003, available on
the web at http://www.epa.gov/mercury/actions.htni
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Projected Emissions Reductions from 1999 Level
Mercury emissions from coal-fired power generators were estimated by EPA to be 48 tons in
19991. EPA has projected under its Base Case2 that mercury emissions from the power
generation sector will be further reduced in the coming years due to the NOx SIP call and Title
IV Acid Rain Program. EPA projects that additional SCR (about 90 GW by 2010) and scrubbers
(about 14 GW by 2010) will be installed to meet these program requirements and these
installations will also reduce mercury emissions. The co-benefits associated with NOx and S02
controls assumed in this modeling are presented in Table A-3 of the Appendix to this document
and in the IPM documentation. The levels of mercury reductions in both the Base Case and
under the proposed MACT are presented in Table 2 below.
Table 2
Mercury Emissions and Reduction for the Base Case and Proposed
MACT for 2010 and 2020
{tons)
Control Case
2010
2020
Base Case
44.80
44.69
Proposed MACT
30.16
31.34
Emission Reduction
14.64
13.35
Source: Integrated Planning Model results.
Projected Annual Costs
Total annual costs of the proposed MACT program are projected to be $1.6 billion in 2010 and
$1.1 billion in 2020. These costs represent about a 1.9% increase in 2010 and 1.1% increase in
2020 of total annual electricity production costs.
The lower cost of the MACT program in 2020 stems from total fuel costs being lower than those
in the Base Case. As in 2010, coal use reflects a shift away from bituminous and toward
subbituminous and lignite coal, relative to the Base Case. In addition, there is fuel switching
among bituminous coals. Projections for 2010 and 2020 differ in the sulfur content and cost of
the bituminous coals that are being displaced. In 2010, the shift was largely away from less-
expensive, high-sulfur bituminous coals. By 2020, the decrease in bituminous coal use was
largely in the more-expensive, lower-sulfur coals, which led to a decrease in the overall fuel
1 1999 EPA Mercury ICR data, cited in http://www.epa.gov/ttn/atw/combust/utiltox/stxstate2.pdf
2 Base Case includes Title IVAcid Rain Program, NOx SIP call and state rules finalized before March 1,
2003.
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costs. Also, while the proposed MACT rule is expected to result in a very slight increase in gas
prices in 2010, by 2020 this effect is largely attenuated.3
Notably, production costs are only one component of the final retail electricity prices seen by
consumers, and on average, make up from one-third to one-half of regional electricity prices.
Costs stemming from the transmission and distribution of electricity make up the remainder.
Thus a more meaningful measure of the impact of the rule is the price effect presented in the
section of this memo discussing retail prices.
Projected Control Technology Retrofits
In 2010, compliance with the MACT program is projected to be primarily through the
installation of activated carbon injection (ACI). Table 3 shows that about 63 GW of coal-fired
capacity is projected to install ACI. In addition, 1 GW of scrubbers and 2 GW of SCR are also
projected to be installed.
While IPM relied on the use of ACI to demonstrate compliance, ACI is not a technology that is
available for use in setting the MACT floor. The MACT floor rates (utilized in IPM) were
dependent only on demonstrated, commercially-available technologies that are currently in use
by coal-fired electric generation units (e.g., wet scrubbers and fabric filters).
Table 3
Projected Retrofits of ACI by Coal Rank for the Proposed MACT
in 2010
Coal Rank
Retrofit Type
Capacity (MW)
Bituminous
90% Removal ACI
55,197
60% Removal ACI
3,472
Subbituminous
90% Removal ACI
395
60% Removal ACI
3,925
Lignite
90% Removal ACI
60
60% Removal ACI
30
Total
63,079
Source: Integrated Planning Model results.
integrated Planning Model results.
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Projected Hg Emissions Reductions
When the emissions rates developed in today's rule are applied to current coal use (based on the
1999 EPA ICR), emissions are projected to be 34 tons. Based on modeling, total emissions from
affected coal-fired power plants are projected to be 30 tons in 2010 and 31 tons in 2020 (see
Table 4). However, EPA believes that the model over-estimates reductions in this analysis and
that emissions are likely to be much closer to the calculated level of 34 tons. This is further
discussed in the "Limitations of the Analysis" section of this memo.
Table 4
Projected Mercury Emissions by Coal Rank
(tons)
Coal Rank
Base Case
Proposed MACT
2010
2020
2010
2020
2010 Rate
(Ib/TBtu)
Bituminous
27.10
25.78
12.25
12.18
1.71
Subbituminous
14.33
15.43
14.43
15.60
4.86
Lignite
3.37
3.48
3.48
3.56
6.70
Total
44.80
44.69
30.16
31.34
Source: Integrated Planning Model results.
Emissions Reductions and Associated Costs
Most of the incremental costs projected under the proposed MACT rule are associated with
bituminous-fired coal units, as can be seen in Table 5. This is a direct consequence of the
emission limits established by the proposed MACT rule, which are relatively much tighter for
bituminous coal-fired units than they are for subbituminous or lignite-fired units.
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Table 5
2010 Proposed Mercury MACT Emissions Reductions and Incremental Annual Costs
by Coal Rank Relative to Base Case
Hg (tons reduced)
Annual Cost
(million $1999)
Bituminous
15.2
$1,551
Subbituminous
-0.4
$47
Lignite
-0.1
$2
Total
14.6
$1,600
Source: Integrated Planning Model results.
Due to increased generation and coal-switching, emissions from subbituminous-fired and lignite-
fired units are projected to increase slightly over the Base Case. Table 6 illustrates how, as a
result of the proposed MACT, coal use in 2010 is expected to shift away from bituminous coal
and towards increased use of subbituminous and lignite coal.
Table 6
Coal Use in 2010 by Coal Rank
(in TBtu)
Base Case
Proposed
MACT
Percent Change from
Base Case
Bituminous
14,818
14,481
-2.3%
Subbituminous
5,722
5,989
4.7%
Lignite
989
1,040
5.1%
Source: Integrated Planning Model results.
Table 7 shows that in 2010, NOx and S02 emissions are projected to be reduced in comparison
to Base Case emissions projections. These projected reductions are due to the reliance on some
S02 and NOx controls and coal-switching to achieve mercury reductions. When compared to the
Base Case, there is also a projected shift (about 6% of bituminous coal use measured in TBtus)
from higher-mercury, higher-sulfur bituminous coals towards lower-mercury, lower-sulfur
bituminous coals, which results in S02 emissions reductions. In addition, some units are
projected to use S02 controls (scrubbers) to comply with the MACT (about 1 GW). Projected
NOx emissions reductions from the Base Case are a result of seasonal NOx controls being
operated annually in the MACT case (about 90 GW of SCR operate annually) and the addition of
2 GW of SCR to achieve mercury control. The existence of NOx and S02 trading market (for
the NOx SIP call and Acid Rain program) would affect the choices for mercury compliance.
The value of the NOx and S02 allowance provides an economic incentive for control options that
reduce NOx and S02 emissions in addition to reductions in Hg emissions.
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Table 7
Approximate Emissions Reductions and Incremental Annual Costs by Control Option from Base Case in
2010 for Proposed MACT
Hg
(tons)
so2
(1,000 tons)
NOx
(1,000 tons)
Annual Cost
(million $1999)
ACI (60% removal)
1.0
--
--
$75
ACI (90% removal)
8.8
--
--
$990
New SCR
0.2
--
75
$25
Annual use of existing SCR
1.3
--
824
$135
New FGD
0.5
194
--
$40
Coal switching
2.8
397
--
$365
Total
14.6
591
899
$1,627
Note: Since there is an emissions cap on S02, these incremental reductions reflect a shift in emissions from 2010 to other year(s).
Note: Numbers may not add due to rounding errors.
Source: Calculations and estimates based on Integrated Planning Model results
Total projected state-level emissions for mercury, NOx and S02 for both the Base Case and the
proposed MACT Policy case are included in Appendix Tables A-l and A-2 respectively, at the
end of this memo.
It should be noted that other regulatory actions that are likely to occur over this time period
would likely realize much of the S02 and NOx reductions projected in this analysis. The
proposed IAQR, for example, would realize substantially greater reductions in NOx and S02. In
addition, technology control choices for mercury would likely be significantly affected by the
requirements of the IAQR. This analysis has not taken into account the interactions that may
result between this rulemaking and the IAQR.
Projected Generation Mix
The total amount of coal-fired generation and natural gas-fired generation is projected to remain
relatively unchanged by the MACT program, as can be seen in Table 8 below.
Relative to the Base Case, about 500 MW of coal-fired capacity is projected to be uneconomic to
maintain and about 75 MW is projected to re-power to natural gas by 2010. The uneconomic
coal plants are likely also affected by the overbuild of new gas-fired combined cycle plants since
2000. The IPM model can determine that specific generating units are uneconomic to maintain,
based on their fuel, operating and fixed costs, and whether they are needed to meet both demand
and reliability reserve requirements. In practice, units projected to be uneconomic to maintain
may be "mothballed", actually retired, or kept in service to ensure transmission reliability in
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certain parts of the grid. Our modeling is unable to distinguish between these potential
outcomes.
Table 8
Electricity Generation in 2010
(1,000 Gwh)
Fuel
Base Case
Proposed MACT
Coal
2,163
2,162
Oil/Natural Gas
852
854
Other
1,180
1,180
Note: Base Case results shown here may differ slightly from other EPA Base Case results
due to a different aggregation of run-years.
Source: Integrated Planning Model results.
Projected Coal Production for Electric Power Sector
Table 9 shows the projected changes in regional coal use by the power sector in 2010 under the
proposed MACT, relative to the Base Case. There is a noticeable shift, in 2010, from
Appalachian coals (which are generally bituminous and thus burned by plants with more
stringent MACT limits) towards Western coals. Due to Western coals' lower heat content, more
tons of coal need to be burned to make up for the projected lost Appalachian coal consumption.
Table 9
Coal Use by Electric Power Sector
(million tons)
Coal Supply Region
2000 Historical
2010 Base Case
2010 Proposed
MACT
Appalachia
299
315
304
Interior
131
177
177
West
475
536
554
National
905
1,028
1,034
Note: Base Case results shown here may differ slightly from other EPA Base Case results due to a different aggregation
of run-years.
Source: Integrated Planning Model results. Historical data from EIA Coal Industry Annual 2000,
represents coal deliveries.
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Projected Retail Electricity Prices
In 2020, retail electricity prices are projected to still be below 2000 prices. When compared to
2010 projections of the Base Case, electricity prices are projected to increase very slightly - only
about one-half a percent in 2010 and about two-tenths of a percent in 2020. Retail electricity
prices by power region are provided for the both the Base Case and the proposed MACT case for
the years 2010 and 2020 in Table 10 below.
Table 10
Retail Prices (Mills Per Kwh -1999$)
Power
Region
Main States Included
2000
Base Case
Proposed
MACT
% Price
Change
2010
2020
2010
2020
2010
2020
ECAR
OH, MI, IN, KY, WV, PA
57.4
51.2
56.6
52.1
57.0
1.7%
0.8%
ERCOT
TX
65.1
54.3
66.3
54.3
66.3
0.1%
0.1%
MAAC
PA, NJ, MD, DC, DE
80.4
58.5
74.0
58.8
74.1
0.6%
0.2%
MAIN
IL, MR, WI
61.2
53.0
62.5
53.3
62.7
0.5%
0.2%
MAPP
MN, IA, SD, ND, NE
57.4
54.5
49.0
54.6
48.9
0.2%
-0.2%
NY
NY
104.3
80.4
90.6
80.8
91.0
0.5%
0.4%
NE
VT, NH, ME, MA, CT, RI
89.9
71.8
83.9
72.0
84.2
0.3%
0.4%
FRCC
FL
67.9
71.1
68.6
71.5
68.8
0.5%
0.3%
STV
VA, NC, SC, GA, AL, MS, TN, AR, LA
59.3
55.9
54.7
56.3
54.9
0.8%
0.4%
SPP
KS, OK, MO
59.3
51.7
56.3
51.9
55.6
0.4%
-1.3%
PNW
WA, OR, ID
45.9
50.2
48.5
50.2
48.5
0.2%
0.0%
RM
MT, WY, CO, UT, NM, AZ, NV, ID
64.1
63.1
65.6
63.4
65.7
0.4%
0.2%
CALI
CA
94.7
96.1
97.5
96.2
97.5
0.1%
0.0%
National
Contiguous Lower 48 States
66.0
59.6
63.9
60.0
64.1
0.6%
0.2%
Source: EPA Retail Electricity Pricing Model with inputs from IPM.
Projected Fuel Price Impacts
The projected changes in fuel prices (prior to transport for coal, and price at the Henry Hub for
natural gas) are provided in Table 11. As can be seen, the proposed MACT policy is expected to
result in very little, if any, changes in fuel prices.
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Table 11
Average Coal Mine Mouth and Henry Hub Natural Gas Prices
(1999$)
2000
Base Case
Proposed MACT
2010
2020
2010
2020
Coal Mine Mouth (US$/MMBtu)
0.80
0.60
0.55
0.60
0.53
Henrv Hub (US$/MMBtu)
4.15
2.97
2.87
2.99
2.87
Source: Integrated Planning Model results; 2000 natural gas and coal data from Platts COALdat and GASdat.
Sensitivity of Assumptions for Natural Gas Prices and Electricity Growth
Sensitivity analysis was performed using the Energy Information Agency's (EIA) assumptions
for natural gas prices and electricity growth in place of those used by EPA in the primary
analysis. These particular assumptions involve higher natural gas prices in 2010 and in 2020 and
project electricity growth of 1.86% a year, rather than EPA projected growth of 1.55%. In
analyzing the sensitivity analysis output the EPA found:
Annual costs of proposed MACT are expected to be $1.6 billion in 2010 and $1.2 billion
in 2020. Projected total annual costs are almost identical to those in the primary analysis
in 2010, and total annual costs are projected to increase less than 10% in 2020 relative to
those using EPA assumptions (See Table 12).
Table 12
Comparison of Sensitivity Analysis Results of Projected Annual Costs to EPA Primary Case
(billion $1999)
2010
2020
Proposed MACT
1.6
1.1
Proposed MACT with EIA assumptions for electricity demand
growth and natural gas prices
1.6
1.2
Source: Integrated Planning Model results
As can be noted in Table 13, coal-fired generation increases under EIA assumptions, with
new coal-fired capacity projected: 5 GW in 2010 and 107 GW in 2020. Almost no
existing coal units are found to be uneconomic.
Increased projected mercury emissions (relative to the MACT analysis under EPA
primary case assumptions) accompany the increases in new coal-fired capacity and
generation, as can be seen in Table 14.
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For the same reasons as noted earlier and discussed in the "Limitations" section below, analysis
of the proposed MACT using EIA assumptions may underestimate expected mercury emissions.
Table 13
Comparison of Sensitivity Analysis Results of Projected Electricity Generation to EPA Primary
Case in 2010
(1,000 Gwh)
Proposed MACT for Primary
Case
Proposed MACT with EIA
assumptions for growth and gas
2010
2020
2010
2020
Coal
2,162
2,339
2,254
3,698
Oil/Natural Gas
854
1,807
954
802
Other
1,180
1,175
1,181
1,179
Source: Integrated Planning Model results
Table 14
Comparison of Sensitivity Analysis Results of Projected Mercury Emissions
to EPA Primary Case
(tons)
Projected Hg Emissions (tons)
2010
2020
Proposed MACT Primary Case
30.10
31.31
Proposed MACT with EIA assumptions for electricity demand
growth and natural gas prices
31.91
34.61
Source: Integrated Planning Model results.
Limitations of Analysis
Although the model can be equipped to analyze rate-based limits on the power sector, EPA's
configuration of IPM is more suitable for analyzing cap-and-trade programs and historically has
been used by EPA to analyze such programs. Control technology choices in the model were
developed by EPA primarily to address cap-and-trade options. In the case of mercury control
technology, the model allows for reductions of ACI only at the 60% and 90% level (rather than
the range of 60 to 90%). This choppiness in the model may lead to as much as 2 tons of over
compliance by the bituminous units. In addition, the modeling assumes a range of mercury
contents for different grades of coal, but due to averaging, may not fully capture all mercury
contents of all possible coal choices.
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The mercury content of coal used in the modeling was developed using the more than 40,000
data points collected in EPA's 1999 Mercury ICR. To make this data usable in EPA's modeling,
these data points were first grouped by IPM coal types and IPM coal supply regions. (IPM coal
types divide bituminous, subbituminous, and lignite coal into different grades based on sulfur
content.) Cluster analysis and statistical averaging were used to provide a range of mercury
contents for each IPM coal type by supply region and sulfur content. Consequently, for each
type of coal in each coal supply region, there are from 1 to 3 emissions factors that characterize
the mercury content for that type of coal. Please see IPM documentation, Chapter 4 for further
information on mercury content of coal: www.epa.gov/airmarkets/epa-ipm.
Therefore, when modeling a facility specific limit, the averaging of mercury contents for
different grades of coal may underestimate emissions because it may not fully capture all
mercury contents of all possible coal choices. This factor along with the mercury technology
choice options available (discussed earlier) could result in an underestimate of mercury
emissions from the model.
Other limitations of this modeling analysis are that it presents a single set of resulting outputs
from a single set of input assumptions that represent EPA' best technical judgements regarding
the values of these variables. Sensitivity analysis with EIA gas price and electricity growth
assumptions provides insight from an alternate set of input assumptions in these two key areas.
This analysis yielded similar results with regards to some outputs (such as costs of the proposed
MACT) program, and differing results with regards to other outputs (such as the projected
Mercury Emissions in 2010 and 2020). Additional sensitivities, both on these variables and on
other input parameters, would provide additional information about the robustness of the results.
Another area of uncertainty is the performance of mercury control removal systems, like the one
assumed in the modeling, activated carbon injection (ACI). ACI systems with added pulse-jet
fabric filters have shown great promise in demonstrated tests. However, there is uncertainty
about the availability and effectiveness of ACI across all coal types in the 2010 timeframe, since
these systems have not been fully deployed on coal-fired electric generating plants. In fact, a
key limitation of this modeling analysis is that it does not take into account the potential for
advancements in the capabilities of mercury control technology and reductions in their costs over
time, so that the results for 2020 are less certain.
As configured, the IPM model also does not take into account demand response, i.e. consumer
reaction to the levels of electricity prices. The increased retail electricity prices shown on Table
10 would prompt end-users, to curtail (to some extent) their use of electricity and encourage
them to use substitutes4. These responses would lessen the demand for electricity, lowering
electricity production costs and prices and reducing generation and emissions.
4The degree of substitution/curtailment depends on the price elasticity of electricity.
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Energy Impact
According to Executive Order 13211: Actions that Significantly Affect Energy Supply,
Distribution, or Use, this proposed rule is significant because it has a greater than a 1% impact
on the cost of electricity production and because it results in the retirement of greater than 500
MW of coal-fired generation, this regulation is significant. It should be noted that EPA has
proposed a trading program to achieve mercury reduction as an alternative to the MACT
standard, which is a command and control regulation. The relative flexibility offered by a
trading program may ease the impact on energy production.
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APPENDIX
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Table A-l
Base Case Projected State Level Emissions for Hg, NOx (summer and total) and S02 in 2010
State
Hg (tons)
Summer NOx
Total NOx
Total SO2
(thousand tons)
Alabama
1.59
39
131
458
Arizona
0.48
35
79
48
Arkansas
0.93
23
51
123
California
0.04
1
2
11
Colorado
0.22
35
80
70
Connecticut
0.10
1
3
6
Delaware
0.19
4
10
46
Florida
0.82
62
140
233
Georgia
1.88
25
148
609
Illinois
1.89
44
170
591
Indiana
2.13
60
236
656
Iowa
0.78
36
82
152
Kansas
0.97
45
101
64
Kentucky
1.31
36
192
369
Louisiana
0.73
21
46
113
Maine
0.01
0
1
3
Maryland
1.28
10
60
229
Massachusetts
0.20
3
8
16
Michigan
1.42
36
118
375
Minnesota
0.69
43
101
85
Mississippi
0.23
18
42
73
Missouri
1.70
44
132
281
Montana
0.32
16
37
18
Nebraska
0.57
25
57
97
Nevada
0.21
14
36
17
New Hampshire
0.05
1
3
7
New Jersey
0.57
4
27
40
New Mexico
0.59
34
76
48
New York
1.23
18
47
197
North Carolina
0.93
22
60
191
North Dakota
1.11
33
78
160
Ohio
3.58
61
261
1.183
Oklahoma
1.19
34
76
133
Oregon
0.09
4
9
15
Pennsylvania
4.78
45
206
868
South Carolina
0.56
15
64
199
South Dakota
0.11
5
10
35
Tennessee
0.94
22
103
306
Texas
3.45
66
148
489
Utah
0.15
31
69
31
Virginia
0.60
14
53
186
Washington
0.24
9
21
6
West Virginia
1.96
26
155
539
Wisconsin
1.30
46
104
200
Wyoming
0.66
39
89
46
Total
44.79
1,204
3,723
9,625
Note: Base Case results shown here may differ slightly from other EPA Base Case results due to a different
aggregation of run-years. Source: Integrated Planning Model results.
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Table A-2
Proposed MACT Projected State Level Emissions for Hg, NOx (summer and total) and S02 in 2010
State
Hg (tons)
Summer NOx
Total NOx
Total SO2
(thousand tons)
Alabama
0.94
45
103
434
Arizona
0.33
35
79
48
Arkansas
0.86
23
51
123
California
0.05
1
2
11
Colorado
0.19
35
80
70
Connecticut
0.04
1
3
6
Delaware
0.06
4
8
38
Florida
0.62
52
117
237
Georgia
1.39
26
61
609
Illinois
1.52
47
129
513
Indiana
1.61
58
138
545
Iowa
0.77
35
83
154
Kansas
0.93
45
99
68
Kentucky
0.68
34
81
346
Louisiana
0.66
21
46
113
Maine
0.00
0
1
3
Maryland
0.32
10
24
233
Massachusetts
0.09
3
7
15
Michigan
1.33
39
94
377
Minnesota
0.69
43
99
88
Mississippi
0.18
18
42
73
Missouri
1.53
44
108
283
Montana
0.32
16
37
18
Nebraska
0.53
25
56
96
Nevada
0.12
14
35
16
New Hampshire
0.04
1
3
7
New Jersey
0.11
4
10
38
New Mexico
0.59
34
76
48
New York
0.25
17
39
188
North Carolina
0.72
21
60
191
North Dakota
1.12
35
80
172
Ohio
1.42
55
147
912
Oklahoma
1.09
34
76
133
Oregon
0.09
4
9
15
Pennsylvania
1.16
42
108
744
South Carolina
0.31
15
35
199
South Dakota
0.13
5
12
41
Tennessee
0.49
22
51
306
Texas
3.45
66
148
557
Utah
0.14
31
69
31
Virginia
0.32
14
33
183
Washington
0.24
9
21
6
West Virginia
0.92
27
71
502
Wisconsin
1.18
46
104
200
Wyoming
0.66
39
89
46
Total
30.17
1.195
2.824
9.034
Note: Since there is an emissions cap on S0:, these incremental reductions reflect a shift in emissions from 2010 to
other vear(s). Source: Integrated Planning Model results.
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Table A-3
EPA Mercury Removal Assumptions for Pollution Control Equipment
(% removal from the Hg content of coal)
Name for Control(s)
Bit % removal
Subbit % removal
Lignite % removal
PC/CS-ESP
36%
3%
0%
PC/CS-ESP/FGD
66%
16%
44%
PC/CS-ESP/FGD-Dry
36%
35%
0%
PC/CS-ESP/SCR/FGD
90%
66%
44%
PC/FF
00
\o
73%
0%
PC/FF/FGD
97%
73%
0%
PC/FF/FGD-Dry
95%
25%
0%
PC/FF/SCR/FGD
90%
85%
44%
PC/FGD
42%
30%
0%
PC/FGD-Dry
40%
15%
0%
PC/HS-ESP
10%
6%
0%
PC/HS-ESP/FGD
42%
20%
0%
PC/HS-ESP/FGD-Dry
40%
15%
0%
PC/HS-ESP/SCR/FGD
90%
25%
0%
Note: PC: Pulverized Coal,
CS-ESP: Cold side electrostatic precipitator,
HS-ESP: Hot side electrostatic precipitator,
FGD: Flue Gas Desulfurization - Wet,
FGD-Dry: Flue Gas Desulfurization - Dry,
SCR: Selective Catalytic Reduction,
FF: Fabric Filter
Source: Documentation of EPA Modeling Applications using the IPM model
(www.epa.gov/airmarkets/epa-ipm)
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