Technical Support Document
Analysis in Support of the Clean Air Interstate Rule
Using the Integrated Planing Model
U.S. Environmental Protection Agency
Clean Air Markets Division
Washington, DC
May 28, 2004
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Table of Contents
A. Overview 3
B. Background 3
C. Proposed Control Strategy Analysis 4
1. Emissions 4
2. Projected Costs 5
3. Projected Control Technology Retrofits 6
4. Projected Generation Mix 6
5. Projected Coal Production for the Electric Power Sector 7
6. Projected Retail Electricity Prices 7
7. Projected Fuel Price Impacts 9
D. Limitations of Analysis 9
E. Significant Energy Impact 10
F. Appendix 10
1. Integrated Planning Model Run Used in the Analysis 10
2. Projected State by State Emissions Data (2015) for the Updated Modeling of
the Proposed Control Strategy 11
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A. Overview
This document summarizes additional analysis that EPA has performed related to the
January 30, 2004 proposal to reduce emissions of sulfur dioxides (SO2) and nitrogen oxides
(NOx) that contribute to downwind non-attainment (69 FR 4566). More specifically, EPA used
the Integrated Planning Model to assess the impacts of the proposed reductions in the geographic
area proposed in the January, 2004 notice using the NOx emissions cap and a close
approximation of the SO2 cap proposed for the CAIR (see Section D of this document).
The Integrated Planning Model (IPM), developed by ICF Consulting, is a dynamic linear
programming model that can be used to examine air pollution control policies for various
pollutants throughout the contiguous U.S. for the entire power system. Documentation for IPM
can be found at www.epa.gov/airmarkets/epa-ipm.
B. Background
On January 30, 2004, EPA proposed emission reduction requirements on 29 States and
the District of Columbia. Those emission reduction requirements were based on achieving
highly cost-effective emission reductions from large electricity generating units.
r\
Figure 1
States Covered by the
Proposed CAIR
Proper ed State; for both S CJ, and NO*
I Propos ed States for ozone s eas on N Ox only
States not covered under the C.AJR
While EPA believes that the modeling it performed for the January, 2004 proposal
provided a reasonable estimate of the impact of requiring highly cost-effective emission
reductions from electricity generating units, it did not exactly model the proposed control region.
For both SO2 and NOx, EPA had used modeling that differed slightly from the proposed January,
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2004 proposal control strategy, otherwise known as the Clean Air Interstate Rule (CAIR)1. For
SO2 in particular, EPA modeled the program assuming a cap on national emissions rather than in
the 29 States proposed. Although the modeling done at that time provided a very reasonable
approximation of the impacts of the original CAIR, EPA has completed additional analysis. This
additional analysis examines the effect of covering the geographic region proposed in the January
30, 2004 proposal using the NOx emissions cap and a close approximation of the SO2 cap
proposed for the CAIR (see Section D of this document).
C. Proposed Control Strategy Analysis
For SO2, EPA proposed that 28 States and the District of Columbia must reduce
emissions of SO2. Modeling done for the original CAIR proposal applied a cap on emissions of
SO2 on all 48 contiguous States and the District of Columbia. EPA believed that this was a
reasonable approximation of the proposed program, because 92% of the SO2 emissions in the 48
contiguous States occur in the 28 States that were covered by the proposal.
For NOx, EPA proposed an annual cap on 28 States and the District of Columbia and an
ozone season only cap on the State of Connecticut. In its modeling for the original proposal,
EPA modeled a NOx cap on a slightly different region2.
For the supplemental proposal, EPA has performed refined modeling of the emission
reduction requirements proposed on January 30, 2004. In this refined modeling, EPA modeled
the exact control regions for both SO2 and NOx, as proposed3.
1. Emissions
For the proposed control region as a whole, the results were very consistent with
modeling done for the NPR. Table 1 compares the emissions from the two modeling runs.
The January, 2004 proposal was formerly known as the Interstate Air Quality Rule (IAQR).
The NOx region modeled for the January, 2004 proposal included Minnesota, Iowa, Missouri, Arkansas,
and the Eastern half of Texas along 1-35, and all States to the east of these States.
The CAIR proposal includes Connecticut in the program for NOx only, and allows the State to control
either during the ozone season, or annually if the State wishes to participate in the CAIR NOx trading program. The
modeling done for this analysis incorporates Connecticut with an ozone season NOx cap only, and does not allow
trading with CAIR States. If Connecticut chose to participate in the annual program for NOx, the total and marginal
costs of the CAIR would likely be slightly less than presented in this analysis.
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Table 1
SO2 and NOx Emissions from the Electric Power Sector Under the
Base Case and with CAIR
Emissions in the
Affected Region
(million tons)
SO2
NOx*
2002
Emissions
9.4
3.7
Base Case
2010
9.0
3.1
2015
8.3
3.2
Original
CAIR
Modeling
2010
5.3
1.6
2015
4.6
1.3
Updated
CAIR
Modeling
2010
5.0
1.6
2015
4.5
1.3
*Note: Excludes Connecticut
While the results within the control region were consistent, the refined modeling run,
which does not cap SO2 in the States that were not affected in the January 30, 2004 proposed
rule, provides a better forecast of the potential impact on those States not covered by the
rulemaking, assuming that additional requirements are not placed upon units in those States.
Modeling indicates that two States, North and South Dakota, would increase emissions of SO2
with the CAIR above what they would have emitted in the absence of the rule, although the
increases are relatively small in magnitude. In 2015, North Dakota is projected to increase
emissions of SO2 by roughly 20,000 tons (12% increase) and South Dakota by 10,000 tons (24%
increase), above what they would have emitted in the absence of the CAIR. The increase in SO2
for these two States represents less than 0.6% of projected nationwide SO2 emissions in 2015
under the CAIR proposal. Electricity generating units in these two border states, in the absence
of any other limitation on their emissions of SO2 other than Title IV, are able to provide power at
lower cost than electricity generating units in the CAIR region and increase their utilization in
order to meet regional electric demand at the lowest cost. EPA's modeling did not assume future
requirements, such as BART, that have not yet been finalized. Since there are a number of
BART affected electricity generating units in both North Dakota and South Dakota, inclusion of
BART requirements for these units would significantly lower SO2 emissions in these two States.
2. Projected Costs
For the January, 2004 proposal, EPA projected the annualized incremental cost for the
region to be $2.9 billion in 2010 and $3.7 billion in 2015. Regional costs with more recent
modeling are projected to be $4.2 billion in 2015. The marginal costs of reductions are also
consistent with newer modeling, as shown in Table 2.
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Table 2
Marginal Costs of CAIR With Original and Updated Modeling
Marginal Cost ($/ton)
SO2
NOx*
Original CAIR
Modeling
2010
$700
$1,300
2015
$1,000
$1,500
Updated CAIR
Modeling
2010
$800
$1,300
2015
$1,000
$1,500
Source: Estimates derived from the Integrated Planning Model.
3. Projected Control Technology Retrofits
The original proposal was projected to require the installation of an additional 63 GW of
flue gas desulfurization (scrubbers) on existing capacity for SO2 control and an additional 46 GW
of selective catalytic reduction (SCR) on existing capacity for NOx control by 2015. Updated
modeling projects 67 GW of scrubbers and 53 GW of SCR by 2015 (see Table 3).
Table 3
Pollution Control Installations by Technology with the Base Case (No Further
Controls) and with the Proposed CAIR in 2015
(GW)
Technology
Scrubbers
SCR
Base Case Total
(Cumulative)
120
125
Incremental with Original
CAIR Modeling
63
46
Incremental with Updated
CAIR Modeling
67
53
Note: Base Case includes existing scrubbers and SCR as well as additional retrofits for the Title IV Acid Rain
Program, the NOx SIP call, NSR settlements, and various State rules.
Source: Integrated Planning Model.
4. Projected Generation Mix
Table 4 shows the generation mix under the original CAIR modeling along with revised
modeling. Coal-fired generation and natural gas-fired generation do not change significantly
under EPA's updated modeling.
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Table 4
National Generation Mix with the Base Case (No Further Controls) and
the Proposed CAIR for the Original and Updated Modeling
(Thousand GWhs)
Generating
Fuel Use
Coal
Oil/Natural Gas
Other
2010
Base
Case
2,165
851
1,180
Original
CAIR
Modeling
2,139
876
1,179
Updated
CAIR
Modeling
2,141
873
1,179
2015
Base
Case
2,20
1,12
1,17
Original
CAIR
Modeling
2,172
1,155
1,179
Updated
CAIR
Modeling
2,170
1,157
1,179
2020
Base
Case
2,237
1,439
1,176
Original
CAIR
Modeling
2,172
1,503
1,175
Updated
CAIR
Modeling
2,171
1,505
1,176
Source: Integrated Planning Model.
5. Projected Coal Production for the Electric Power Sector
Coal production for electricity generation is practically unchanged in updated CAIR
modeling (Table 5). The reductions in emissions from the power sector will be met through the
installation of pollution controls for SO2 and NOx removal. The pollution controls can achieve
up to a 95% SO2 removal rate, which allows industry to rely more heavily on local bituminous
coal in the Eastern and Central parts of the country which has a higher sulfur content and is less
expensive to transport than Western subbituminous coal.
Table 5
Coal Production for the Electric Power Sector in 2000, with the Base Case (No Further
Controls), and with the Proposed CAIR for the Original and Updated Modeling
(Million Tons)
Supply Area
Appalachia
Interior
West
National
2000
299
131
475
905
Base Case
2010
318
177
535
1,029
2015
306
174
571
1,051
2020
286
189
594
1,070
Original CAIR
Modeling
2010
312
198
505
1,015
2015
313
203
516
1,031
2020
307
229
488
1,024
Updated CAIR
Modeling
2010
314
202
500
1,016
2015
312
215
504
1,031
2020
307
233
483
1,024
Source: Integrated Planning Model.
6. Projected Retail Electricity Prices
Retail electricity prices for the CAIR region are projected to increase a small amount with
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the proposed CAIR (Table 6). A cap-and-trade approach, as proposed in the CAIR, allows
industry to meet the requirements of the CAIR in the most cost-effective manner, thereby
minimizing the costs passed on to consumers. Regional retail electricity prices are projected to
be 2-3% higher with the CAIR.
Table 6
Projected Regional Retail Electricity Prices with the Base Case (No Further Controls)
and with the Proposed CAIR
(Mills/kWh, $1999)
Year
2010
2015
2020
Base Case
56.8
59.7
61.5
Original CAIR
Modeling
58.0
61.7
62.8
Percent Change
2.2%
3.3%
2.1%
Updated CAIR
Modeling
58.2
61.7
62.8
Percent Change
2.6%
3.4%
2.2%
Source: Retail Electricity Price Model.
Retail electricity prices by NERC region are in Table 7, and show small increases in retail
prices for the NERC regions in the Eastern part of the country. New modeling is consistent with
the original modeling done for the CAIR. By 2020, nationwide retail electricity prices are
projected to be less than 2% higher with the proposed CAIR.
Table 7
Retail Electricity Prices by NERC Region with the Base Case (No Further
Controls) and with the Original CAIR
(Mills/kWh, $1999)
Power
Region
ECAR
ERCOT
MAAC
MAIN
MAPP
NY
NE
FRCC
STV
SPP
PNW
RM
CALI
National
Primary States Included
OH, MI, IN, KY, WV, PA
XX
PA, NJ, MD, DC, DE
IL, MO, WI
MN, IA, SD, ND, NE
NY
VT, NH, ME, MA, CT, RI
FL
VA, NC, SC, GA, AL, MS, TN, AR, LA
KS, OK, MO
WA, OR, ID
MX, WY, CO, UT, NM, AZ, NV, ID
CA
Contiguous Lower 48 States
2000
57.4
65.1
80.4
61.2
57.4
104.3
89.9
67.9
59.3
59.3
45.9
64.1
94.7
66.0
Base Case
2010
51.2
54.4
58.5
53.0
54.5
80.4
71.8
71.1
55.8
51.7
50.2
62.9
96.0
59.5
2015
55.0
64.5
67.5
57.2
50.9
87.9
77.8
70.2
54.7
53.0
49.1
64.4
97.0
62.2
2020
56.6
66.3
74.1
62.6
49.0
90.8
84.1
68.6
54.7
56.4
48.6
65.5
97.5
63.9
Original CAIR
2010
53.4
54.7
60.3
54.6
55.4
82.0
72.7
72.2
56.5
52.5
50.5
63.5
96.5
60.6
2015
58.6
65.1
70.2
60.7
51.9
89.9
79.7
71.2
55.7
53.7
49.3
64.6
97.2
63.8
2020
58.8
66.8
75.4
64.1
49.8
91.0
84.3
69.8
56.0
57.0
48.7
65.8
97.8
65.0
Updated CAIR
2010
53.6
55.1
60.4
54.8
54.9
82.1
74.2
72.3
56.7
52.7
50.5
63.6
96.5
60.8
2015
58.7
65.0
69.7
60.8
51.4
89.6
81.0
71.2
55.9
54.2
49.3
64.6
97.3
63.9
2020
58.8
66.8
75.1
64.3
49.7
90.4
84.5
69.8
56.2
57.4
48.6
66.0
97.8
65.1
Source: Retail Electricity Price Model. 2000 prices are from EIA 's AEO 2003.
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7. Projected Fuel Price Impacts
The impacts of the CAIR on coal and natural gas prices before shipment with new
modeling are in Table 8, and do not vary greatly with the original CAIR modeling. The increase
in coal prices is a result of a shift towards higher priced mine mouth coal and not from increases
in actual coal supply region costs.
Table 8
Average Coal Mine Mouth and Henry Hub Natural Gas Prices
with the Base Case (No Further Controls) and with the Proposed CAIR
(1999$/mmBtu)
Fuel
Coal
Natural Gas
2000
0.80
4. IS
Base Case
2010
0.60
2.97
2015
0.57
2.96
2020
0.55
2.87
Original CAIR Modeling
2010
0.61
3.06
2015
0.58
3.00
2020
0.57
2.92
Updated CAIR Modeling
2010
0.62
3.06
2015
0.59
3.01
2020
0.57
2.92
Note: Prices for various coals are not increasing, but the mix is changing towards coals that have higher mine
mouth prices.
Source: Integrated Planning Model. 2000 coal and natural gas data is from Platts COALdat and GASdat.
D. Limitations of Analysis
EPA's modeling is based on its best judgement for various input assumptions that are
uncertain, particularly assumptions for future fuel prices and electricity demand growth. In
addition, modeling using IPM does not take into account the potential for advancements in the
capabilities of pollution control technologies for SO2 and NOx removal as well as reductions in
their costs over time. Cap-and-trade regulation that provides clear market-based incentives for
reductions serves to promote innovation and the development of new technologies.
The CAIR SNPR proposed two alternatives for how the SO2 reduction target would be
achieved. The proposal took comment on implementing the reduction requirements in the
second phase either by using a 2.86 to 1 ratio (which would match the 65% reduction target) of
acid rain allowances to emissions, or alternatively, by implementing the reductions using a 3 to 1
ratio (for administrative simplicity) and then letting States create and distribute additional
allowances equal to the surplus created by the 3 to 1 ratio to achieve the proposed 65% reduction.
In either case, the effective cap on SO2 emissions from the power sector would be the same. In
the analysis for the proposed control strategy described in this document, the model assumed a 3
to 1 retirement ratio of 2015 and beyond Title IV allowances to implement the reductions in the
proposed control region, but did not increase the cap by the 130,000 tons of over compliance that
would result from this ratio. Therefore, in this modeling, EPA analyzed slightly greater emission
reductions than required by the proposal. This assumption was made for modeling simplicity and
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should result in a slight overestimate of costs for the proposal and of the emissions reductions
achieved.
EPA did not incorporate any BART modeling in this analysis. BART stands for best
achievable retrofit technology, and the BART rule which EPA has proposed requires facility
specific controls on affected units to improve visibility. BART would achieve reductions in non-
CAIR States and would likely mitigate any leakage issues, particularly related to the emissions
increases in the Dakota's that was pointed out in this analysis.
As configured, the IPM model also does not take into account demand response (i.e.,
consumer reaction to electricity prices). The increased retail electricity prices shown on Tables 5
and 6 would prompt end-users to curtail (to some extent) their use of electricity and encourage
them to use substitutes4. The response would lessen the demand for electricity, lowering
electricity prices and reducing generation and emissions.
EPA's latest update of IPM was completed in March of 2003, and does not incorporate
any State rules or regulations adopted after that date.
E. Significant 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 it results in the retirement of greater than 500 MW of
coal-fired generation.
Several aspects of the proposed CAIR proposal are designed to minimize the impact on
energy production. First, EPA has proposed a centralized trading program rather than the use of
command and control regulations. Second, EPA has proposed compliance deadlines cognizant
of the impact that those deadlines have on electricity production. Both of these aspects of the
proposed CAIR proposal reduce the impact of the proposal on the electricity sector.
F. Appendix
1. Integrated Planning Model Run Used in the Analysis
The data presented in this technical support document is from the IPM run
EPA216 CAIR SNPR.
The degree of substitution/curtailment depends on the price elasticity of electricity.
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2. Projected State by State Emissions Data (2015) for the Updated Modeling of the
Proposed Control Strategy with Interstate Trading
2015
Base Case
SO2 Emissions
NOx Emissions
CAIR
SO2 Emissions
NOx Emissions
CAIR Affected States
Alabama
Arkansas
Connecticut
Delaware
District Of Columbia
Florida
Georgia
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
New Jersey
New York
North Carolina
Ohio
Pennsylvania
South Carolina
Tennessee
Texas
Virginia
West Virginia
Wisconsin
Total
415.99
122.67
6.28
48.27
0.00
230.29
600.28
534.18
522.91
160.03
65.32
357.06
112.53
229.58
16.26
384.38
86.67
73.47
307.14
38.23
197.41
141.27
1025.23
805.55
195.54
309.63
487.07
184.74
485.12
175.74
8318.84
128.56
52.78
5.23
10.84
0.08
170.52
153.28
178.49
241.98
86.63
101.89
198.71
50.14
61.93
11.87
126.09
104.66
44.90
140.79
30.35
65.53
62.36
255.93
212.90
66.24
102.71
200.31
57.32
148.24
97.42
3168.66
295.50
77.93
6.28
34.57
0.00
173.80
142.97
240.27
329.21
146.03
55.61
271.51
94.29
39.59
4.45
378.92
74.09
29.18
255.66
20.10
100.82
141.27
268.69
168.15
145.25
192.43
349.00
114.72
140.59
167.88
4458.79
59.49
8.56
5.57
9.09
0.08
54.07
48.82
94.97
73.94
35.32
25.09
52.88
15.36
24.58
13.16
94.47
42.58
13.98
68.18
13.95
54.41
51.20
93.21
79.91
30.81
31.60
118.78
32.98
35.67
55.32
1338.05
Non CAIR States
Arizona
California
Colorado
Idaho
Maine
Montana
Nebraska
Nevada
New Hampshire
New Mexico
North Dakota
Oklahoma
Oregon
47.78
10.71
70.37
0.00
2.61
17.72
96.33
17.31
7.29
48.22
171.22
133.01
15.19
86.04
17.81
81.02
1.16
1.89
38.55
56.59
40.74
3.81
76.12
80.18
86.63
13.49
47.78
10.71
70.37
0.00
2.61
17.92
96.57
17.94
7.29
48.22
192.38
133.01
15.19
85.68
17.79
81.01
1.16
1.89
38.55
56.85
42.19
3.85
76.15
85.30
86.69
13.49
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Rhode Island
South Dakota
Utah
Vermont
Washington
Wyoming
Total
(Nationwide Total
0.00
41.46
31.38
0.00
5.36
45.99
761.95
9080.79
1.99
12.30
69.23
0.00
25.47
88.97
781.97
3950.63
0.00
51.21
31.38
0.00
5.36
45.99
793.94
5252.73
1.65
15.19
69.23
0.00
25.34
88.97
790.98
2129.03
Note: Connecticut was modeled with a summertime NOx Constraint only, and was not included in the CAIRfor SO2-
Source: Integrated Planning Model
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