Document ID: EPA-HQ-OAR-2003-0053-2071
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-03-10T05:00Z

3­
1
CHAPTER
3.
SO2
AND
CARBON
REDUCTION
OPTIONS
This
chapter
provides
the
results
of
analysis
of
hypothetical
pollution
control
options
for
SO2
and
carbon
emissions
from
the
electric
power
industry.
It
is
organized
into
three
sections:
(
1)
SO2
reduction
options,
(
2)
carbon
reduction
options,
and
(
3)
SO2
and
carbon
reduction
options.

The
options
presented
in
this
report
are
hypothetical
approaches
to
emission
controls
on
the
electric
power
industry
for
each
pollutant
and
do
not
represent
the
EPA
or
Administration
position
on
how
any
of
these
pollutants
should
be
reduced
in
the
future.
EPA
has
made
no
determinations
whether
or
how
much
additional
SO2
control
could
be
needed
to
address
fine
particulate
problems,
or
whether
and
to
what
extent
there
should
be
future
reductions
of
mercury
or
carbon
dioxide
emissions.
Specifically
with
regard
to
carbon
dioxide,
the
Administration
has
committed
not
to
implement
the
Kyoto
Protocol
without
the
advice
and
consent
of
the
Senate.

SO2
REDUCTION
OPTIONS
The
SO2
control
options
examined
in
this
report
are
at
levels
below
what
is
required
for
power
plants
under
the
CAAA
Title
IV
SO2
Allowance
Trading
program.
These
reduced
levels
were
examined
because
additional
SO2
reductions
from
electric
generators,
which
are
the
dominant
source
of
SO2
emissions,
are
likely
to
be
essential
to
any
future
program
designed
to
meet
the
fine
particle
ambient
air
quality
standard.

The
analysis
of
the
SO2
control
options
assumes
a
continuation
of
the
current
emissions
cap­
and­
trade
program
with
the
"
banking"
of
SO2
allowances
(
stockpiling
of
allowances
for
future
use,
or
trading).
For
these
alternatives,
the
SO2
emissions
cap
is
lowered
in
2007
to
a
level
that
analysis
indicates
will
provide
substantial
SO2
reductions
in
2010
from
the
Base
Case.
Under
these
options,
allowances
that
are
banked
under
the
Title
IV
program
before
2007
could
be
used
by
power
plants
to
make
a
gradual
transition
to
the
lower
SO2
levels
of
the
2007
emissions
caps.

For
this
analysis,
IPM
was
set
to
simulate
a
SO2
emissions
cap
for
the
power
generation
industry
for
2007
and
beyond.
It
was
assumed
that
the
cap
was
imposed
at
the
beginning
of
2005
and
that
companies
could
"
bank"
additional
allowances
in
2005
to
2007
for
use
later.
Exhibit
3­
1
lists
the
four
options
that
were
set
up
for
this
analysis
and
the
SO2
emissions
caps
that
would
go
into
effect
in
2007
and
thereafter.
The
title
of
each
alternative
control
option
reflects
the
percentage
reduction
each
option
provides
in
SO2
emissions
levels
compared
to
the
Base
Case
in
2010.
3­
2
Exhibit
3­
1
Options
for
SO2
Emissions
Reduction
Beyond
CAAA
Title
IV
for
the
Electric
Power
Industry
Control
Options
Based
on
their
Specified
SO2
Emissions
Reduction
Target*
2007
SO2
Emissions
Cap
(
1,000
tons)

40
Percent
Reduction
in
SO2
in
2010
4,261
45
Percent
Reduction
in
SO2
in
2010
3,788
50
Percent
Reduction
in
SO2
in
2010
3,314
55
Percent
Reduction
in
SO2
in
2010
2,841
*
Reduction
from
the
Base
Case
of
9,662
thousand
tons
of
SO2
in
2010.

Air
Emissions
Changes
For
each
of
the
pollution
control
options,
EPA
modeled
the
changes
in
SO2,
NOx,
carbon,
and
mercury
emissions
from
the
Base
Case.
Exhibits
3­
2
through
3­
6
show
the
national
results
of
the
analysis
for
each
of
the
control
options
compared
to
the
Base
Case
emissions.
The
last
two
exhibits
in
this
series
show
mercury
emissions
for
all
sources
and
for
coal­
fired
units
only.
Exhibits
3­
7
through
3­
18
show
the
regional
emissions
for
each
air
pollutant
over
time
for
these
control
options.
The
amount
of
regional
emissions
reduction
occurring
under
each
control
option
can
be
determined
by
comparing
these
results
to
the
Base
Case
regional
results
in
Chapter
2
(
see
Exhibits
2­
7
through
2­
9).

In
addition
to
lowering
SO2
emissions,
each
control
option
decreases
mercury
emissions
significantly
from
coal­
fired
units.
In
the
alternatives
examined,
mercury
reductions
in
2010
are
10
to
14
percent
lower
than
the
Base
Case.
This
results
from
the
addition
of
flue
gas
desulfurization
units
(
scrubbers)
at
coal­
fired
units,
which
are
assumed
on
average
to
remove
a
third
of
the
mercury
in
the
flue
gas,
and
from
the
movement
to
greater
natural
gas
generation
from
coal.
(
Natural
gas
has
only
trace
concentrations
of
mercury).
There
are
much
smaller
percentage
reductions
in
NOx
and
carbon
emissions
from
these
alternative
SO2
control
options.
The
results
suggest
that
the
installation
of
scrubbers
is
the
dominant
reason
for
the
mercury
reductions.
More
details
on
how
the
electric
generation
system
responds
to
each
of
the
control
options
are
provided
in
the
next
section.
3­
3
Exhibit
3­
2
Annual
SO2
Emissions
for
the
Electric
Power
Industry
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
1,000
tons)

Options
2005
2007
2010
Base
Case
11,049
10,864
9,658
40
Percent
Reduction
in
SO2
in
2010
7,103
7,021
5,661
45
Percent
Reduction
in
SO2
in
2010
6,714
6,430
5,300
50
Percent
Reduction
in
SO2
in
2010
6,303
5,868
4,939
55
Percent
Reduction
in
SO2
in
2010
5,938
5,672
4,523
Exhibit
3­
3
Annual
and
Summer
NOx
Emissions
for
the
Electric
Power
Industry
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
1,000
tons)

Options
2005
2007
2010
Annual
Emissions
Base
Case
4,221
4,255
4,147
40
Percent
Reduction
in
SO2
in
2010
4,212
4,252
4,085
45
Percent
Reduction
in
SO2
in
2010
4,210
4,247
4,049
50
Percent
Reduction
in
SO2
in
2010
4,203
4,246
4,019
55
Percent
Reduction
in
SO2
in
2010
4,192
4,237
4,006
Summer
Emissions
Base
Case
1,436
1,449
1,386
40
Percent
Reduction
in
SO2
in
2010
1,436
1,449
1,375
45
Percent
Reduction
in
SO2
in
2010
1,435
1,448
1,369
50
Percent
Reduction
in
SO2
in
2010
1,432
1,448
1,353
55
Percent
Reduction
in
SO2
in
2010
1,431
1,447
1,350
3­
4
Exhibit
3­
4
Annual
Carbon
Emissions
for
the
Electric
Power
Industry
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
Million
Metric
Tons)

Options
2005
2007
2010
Base
Case
605
615
621
40
Percent
Reduction
in
SO2
in
2010
604
614
615
45
Percent
Reduction
in
SO2
in
2010
603
613
612
50
Percent
Reduction
in
SO2
in
2010
603
613
610
55
Percent
Reduction
in
SO2
in
2010
602
612
608
Exhibit
3­
5
Annual
Mercury
Emissions
for
All
Sources
in
the
Electric
Power
Industry
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
Tons)

Options
2005
2007
2010
Base
Case
51.9
52.0
50.9
40
Percent
Reduction
in
SO2
in
2010
47.5
47.6
45.9
45
Percent
Reduction
in
SO2
in
2010
47.3
46.5
45.1
50
Percent
Reduction
in
SO2
in
2010
46.4
46.1
44.5
55
Percent
Reduction
in
SO2
in
2010
46.0
46.0
43.8
Exhibit
3­
6
Annual
Mercury
Emissions
for
the
Coal­
Fired
Units
of
the
Electric
Power
Industry
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
Tons)

Options
2005
2007
2010
Base
Case
47.9
48.0
46.9
40
Percent
Reduction
in
SO2
in
2010
43.4
43.6
41.9
45
Percent
Reduction
in
SO2
in
2010
43.3
42.5
41.2
50
Percent
Reduction
in
SO2
in
2010
42.4
42.1
40.5
55
Percent
Reduction
in
SO2
in
2010
42.0
42.0
39.8
3­
5
Exhibit
3­
7
Regional
Electric
Generation
and
Air
Emissions
for
2005
40%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
37
86
28
93
273
1.1
16
ECAO
221
525
167
797
1,527
7.6
117
ERCT
126
261
154
323
318
4.3
45
MACE
46
101
17
58
101
1.2
9
MACW
43
101
28
120
131
2.0
17
MACS
24
55
15
64
63
0.7
9
WUMS
24
57
19
66
195
1.0
12
MANO
83
193
51
224
492
4.1
37
MAPP
73
165
154
356
442
3.6
39
UPNY
57
131
22
63
116
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
62
184
1.5
12
FRCC
90
183
121
251
198
2.1
29
VACA
126
292
69
270
826
3.4
42
TVA
66
154
43
193
420
2.2
26
SOU
103
231
87
270
807
3.6
41
SPPN
40
91
53
156
174
1.4
20
SPPS
114
227
152
303
471
2.7
41
CNV
109
249
32
76
50
1.2
22
WSCP
71
168
19
45
22
0.3
7
WSCR
109
252
178
418
294
2.7
51
TOTAL
1,610
3,633
1,436
4,212
7,103
47.5
604
3­
6
Exhibit
3­
8
Regional
Electric
Generation
and
Air
Emissions
for
2007
40%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
88
27
92
269
1.1
16
ECAO
220
527
166
800
1,474
7.4
117
ERCT
129
269
158
333
318
4.3
47
MACE
45
96
18
60
104
1.3
10
MACW
43
103
29
124
139
2.0
17
MACS
25
58
15
65
63
0.8
9
WUMS
25
58
19
63
190
1.0
12
MANO
87
203
51
223
487
4.1
37
MAPP
75
167
155
356
438
3.6
39
UPNY
59
135
22
63
113
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
63
182
1.5
12
FRCC
95
192
122
249
198
2.1
30
VACA
132
306
70
277
834
3.5
44
TVA
66
155
43
193
417
2.2
26
SOU
103
234
87
276
785
3.6
42
SPPN
41
93
54
160
177
1.4
21
SPPS
119
234
157
306
471
2.7
42
CNV
113
261
33
80
50
1.2
24
WSCP
71
168
19
45
22
0.3
7
WSCR
110
255
179
420
292
2.7
52
TOTAL
1,645
3,712
1,449
4,252
7,021
47.6
614
3­
7
Exhibit
3­
9
Regional
Electric
Generation
and
Air
Emissions
for
2010
40%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
40
92
27
92
268
1.1
17
ECAO
226
537
181
830
1,245
7.5
121
ERCT
136
285
124
247
291
4.0
44
MACE
51
104
17
57
67
1.3
11
MACW
41
98
29
126
91
2.1
18
MACS
26
63
15
67
58
0.7
9
WUMS
26
59
19
64
188
1.0
13
MANO
87
203
51
227
366
3.5
37
MAPP
76
171
151
351
430
3.5
39
UPNY
54
120
18
50
108
0.8
9
LILC
6
14
1
3
0
0.3
1
NENG
49
118
16
43
59
1.5
12
FRCC
98
200
112
233
172
2.1
30
VACA
136
320
67
279
509
3.2
45
TVA
68
158
41
186
373
2.1
25
SOU
108
241
86
273
476
3.3
42
SPPN
44
100
55
161
167
1.4
22
SPPS
122
244
139
269
429
2.6
41
CNV
121
274
31
73
50
1.2
21
WSCP
76
181
17
39
22
0.3
8
WSCR
108
249
177
416
292
2.7
51
TOTAL
1,699
3,830
1,375
4,085
5,661
45.9
615
3­
8
Exhibit
3­
10
Regional
Electric
Generation
and
Air
Emissions
for
2005
45%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
86
28
93
270
1.1
16
ECAO
220
524
168
799
1,310
7.3
117
ERCT
126
261
155
323
318
4.3
45
MACE
46
101
17
58
95
1.3
9
MACW
43
101
28
120
128
2.0
17
MACS
24
56
15
65
55
0.8
9
WUMS
24
57
19
66
195
1.0
12
MANO
84
194
52
226
488
4.1
37
MAPP
74
165
154
356
438
3.6
39
UPNY
57
131
22
64
117
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
62
180
1.5
12
FRCC
90
183
119
248
181
2.1
29
VACA
125
290
69
267
773
3.4
41
TVA
65
154
41
191
416
2.1
26
SOU
102
231
87
271
740
3.5
41
SPPN
40
91
53
157
173
1.4
20
SPPS
115
228
153
304
471
2.7
41
CNV
109
249
32
76
50
1.2
22
WSCP
71
168
19
45
22
0.3
7
WSCR
109
252
178
418
293
2.7
51
TOTAL
1,609
3,633
1,435
4,210
6,714
47.3
603
3­
9
Exhibit
3­
11
Regional
Electric
Generation
and
Air
Emissions
for
2007
45%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
39
88
27
92
264
1.0
16
ECAO
220
526
167
799
1,270
7.3
117
ERCT
129
269
158
333
318
4.3
47
MACE
45
96
18
60
102
1.3
10
MACW
43
103
29
124
118
2.0
17
MACS
24
59
15
67
58
0.7
9
WUMS
25
57
19
63
187
1.0
12
MANO
87
203
51
225
371
3.5
36
MAPP
75
167
154
355
435
3.6
39
UPNY
59
135
22
63
113
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
63
148
1.4
12
FRCC
96
192
121
246
180
2.1
30
VACA
131
304
69
272
773
3.5
43
TVA
66
156
43
193
421
2.1
26
SOU
103
235
87
280
671
3.5
42
SPPN
41
94
54
161
171
1.3
21
SPPS
119
234
157
304
466
2.6
42
CNV
113
261
33
80
50
1.2
24
WSCP
71
168
19
45
22
0.3
7
WSCR
110
255
179
420
291
2.7
52
TOTAL
1,645
3,712
1,448
4,247
6,430
46.5
613
3­
10
Exhibit
3­
12
Regional
Electric
Generation
and
Air
Emissions
for
2010
45%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
40
92
27
92
267
1.1
17
ECAO
225
534
182
826
1,172
7.4
121
ERCT
136
285
124
239
274
3.8
43
MACE
50
104
16
57
66
1.3
11
MACW
41
98
29
126
91
2.1
18
MACS
26
63
15
67
58
0.9
9
WUMS
26
58
18
62
185
1.0
12
MANO
87
202
51
225
337
3.4
36
MAPP
76
172
149
347
423
3.5
39
UPNY
54
120
18
50
102
0.7
9
LILC
6
15
1
3
0
0.3
1
NENG
50
118
16
43
50
1.4
12
FRCC
98
200
111
222
146
2.0
30
VACA
136
319
69
279
416
3.2
45
TVA
67
156
40
182
360
2.0
25
SOU
107
242
86
277
403
3.2
43
SPPN
44
101
54
160
164
1.3
22
SPPS
123
246
137
265
423
2.5
41
CNV
121
274
31
73
50
1.2
21
WSCP
76
181
17
39
22
0.3
8
WSCR
108
249
177
416
291
2.7
51
TOTAL
1,699
3,830
1,369
4,049
5,300
45.1
612
3­
11
Exhibit
3­
13
Regional
Electric
Generation
and
Air
Emissions
for
2005
50%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
86
28
93
271
1.1
16
ECAO
220
523
169
798
1,273
7.3
117
ERCT
126
261
155
323
318
4.3
45
MACE
46
101
17
58
94
1.3
9
MACW
43
101
29
119
115
2.0
17
MACS
24
56
15
65
55
0.8
9
WUMS
24
57
19
66
195
1.0
12
MANO
83
194
52
228
375
3.5
37
MAPP
74
165
154
355
437
3.6
38
UPNY
57
131
22
64
117
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
62
116
1.5
12
FRCC
90
183
119
247
180
2.1
29
VACA
125
290
68
267
707
3.3
41
TVA
65
154
41
189
416
2.1
25
SOU
102
231
87
273
644
3.4
41
SPPN
40
91
53
157
168
1.3
20
SPPS
115
228
150
296
460
2.6
41
CNV
109
249
32
76
50
1.2
22
WSCP
71
168
19
45
22
0.3
7
WSCR
109
252
178
418
293
2.7
51
TOTAL
1,609
3,633
1,432
4,203
6,303
46.4
603
3­
12
Exhibit
3­
14
Regional
Electric
Generation
and
Air
Emissions
for
2007
50%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
39
88
27
92
262
1.0
16
ECAO
221
526
168
799
1,195
7.2
117
ERCT
129
269
158
333
318
4.3
47
MACE
45
96
18
60
99
1.3
10
MACW
44
103
29
124
89
2.1
17
MACS
24
58
15
66
56
0.7
9
WUMS
25
57
19
63
187
1.0
12
MANO
86
202
50
225
361
3.4
36
MAPP
75
166
154
355
434
3.5
39
UPNY
59
135
22
63
113
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
63
116
1.5
12
FRCC
96
193
121
249
182
2.1
30
VACA
132
305
70
273
556
3.3
43
TVA
66
155
42
191
395
2.1
26
SOU
102
233
87
278
506
3.3
42
SPPN
42
95
54
160
169
1.3
21
SPPS
119
234
157
304
466
2.6
42
CNV
113
261
33
80
50
1.2
24
WSCP
71
168
19
45
22
0.3
7
WSCR
110
255
179
420
291
2.7
52
TOTAL
1,645
3,712
1,448
4,246
5,868
46.1
613
3­
13
Exhibit
3­
15
Regional
Electric
Generation
and
Air
Emissions
for
2010
50%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
41
93
27
92
249
1.0
17
ECAO
225
533
181
824
1,092
7.3
121
ERCT
136
285
121
236
268
3.7
42
MACE
50
103
16
57
66
1.3
11
MACW
41
98
29
126
91
2.1
18
MACS
26
63
15
67
56
1.0
9
WUMS
26
58
18
63
185
1.0
12
MANO
87
202
51
225
320
3.3
36
MAPP
76
172
149
346
400
3.5
38
UPNY
54
120
18
50
102
0.7
9
LILC
6
15
1
3
0
0.3
1
NENG
49
118
16
43
49
1.3
12
FRCC
97
200
100
207
115
1.9
29
VACA
136
320
69
280
400
3.1
46
TVA
68
156
40
180
355
1.9
25
SOU
108
242
87
272
340
3.0
42
SPPN
44
101
54
160
164
1.3
21
SPPS
123
247
135
263
327
2.4
41
CNV
121
274
31
73
50
1.2
21
WSCP
76
181
17
39
22
0.3
8
WSCR
108
249
177
416
290
2.7
51
TOTAL
1,699
3,830
1,353
4,019
4,939
44.5
610
3­
14
Exhibit
3­
16
Regional
Electric
Generation
and
Air
Emissions
for
2005
55%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
86
28
93
269
1.1
16
ECAO
220
523
170
798
1,217
7.3
117
ERCT
126
261
154
323
318
4.3
45
MACE
46
100
17
57
92
1.3
9
MACW
43
102
29
121
85
2.0
17
MACS
23
56
14
64
54
0.7
9
WUMS
24
57
19
66
195
1.0
12
MANO
83
193
51
227
371
3.5
37
MAPP
74
165
154
354
435
3.6
38
UPNY
57
131
22
64
117
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
62
116
1.5
12
FRCC
90
183
119
243
170
2.0
29
VACA
126
289
69
265
533
3.2
41
TVA
66
155
41
188
402
2.1
25
SOU
102
231
87
273
572
3.3
41
SPPN
40
92
53
158
169
1.3
21
SPPS
115
228
149
295
460
2.6
41
CNV
109
249
32
76
50
1.2
22
WSCP
71
168
19
45
22
0.3
7
WSCR
109
252
178
418
293
2.7
51
TOTAL
1,609
3,633
1,431
4,192
5,938
46.0
602
3­
15
Exhibit
3­
17
Regional
Electric
Generation
and
Air
Emissions
for
2007
55%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
39
88
27
92
262
1.0
16
ECAO
220
525
169
799
1,161
7.2
117
ERCT
130
270
159
334
318
4.3
47
MACE
46
97
18
62
77
1.3
10
MACW
44
103
29
123
86
2.1
17
MACS
24
58
15
66
55
0.7
9
WUMS
25
57
19
63
187
1.0
12
MANO
86
202
50
225
357
3.4
36
MAPP
75
166
154
353
433
3.5
39
UPNY
59
135
22
63
112
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
63
121
1.5
12
FRCC
96
193
121
245
172
2.1
30
VACA
132
305
70
273
544
3.3
43
TVA
67
157
42
189
385
2.1
26
SOU
101
232
86
277
423
3.3
42
SPPN
42
95
53
160
169
1.3
21
SPPS
119
233
155
303
447
2.6
41
CNV
113
261
33
80
50
1.2
24
WSCP
71
168
19
45
22
0.3
7
WSCR
110
255
179
420
291
2.7
52
TOTAL
1,645
3,712
1,447
4,237
5,672
46.0
612
3­
16
Exhibit
3­
18
Regional
Electric
Generation
and
Air
Emissions
for
2010
55%
SO2
Reduction
in
2010
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
40
92
26
90
148
0.9
16
ECAO
225
534
181
827
1,015
7.3
121
ERCT
136
284
121
237
247
3.6
42
MACE
50
103
16
58
54
1.3
11
MACW
41
98
29
125
90
2.1
18
MACS
26
62
15
66
50
1.0
9
WUMS
26
58
18
62
184
1.0
12
MANO
87
202
51
223
315
3.3
36
MAPP
76
172
148
345
397
3.5
38
UPNY
54
120
18
50
97
0.7
9
LILC
6
15
1
3
0
0.3
1
NENG
50
118
16
43
36
1.3
12
FRCC
97
200
99
205
114
1.9
29
VACA
138
322
71
282
301
3.0
46
TVA
67
157
40
180
353
1.9
25
SOU
108
240
86
268
282
2.9
41
SPPN
44
101
54
159
162
1.4
21
SPPS
122
247
133
257
319
2.3
40
CNV
121
275
31
73
50
1.2
21
WSCP
76
181
17
39
22
0.3
8
WSCR
108
249
177
416
287
2.7
51
TOTAL
1,699
3,829
1,350
4,006
4,523
43.8
608
3­
17
Costs
and
Power
System
Changes
The
electric
generation
system
will
make
adjustments
to
meet
electricity
demand
and
comply
with
the
pollution
control
requirements
of
each
of
these
SO2
reduction
options.
Exhibit
3­
19
shows
the
annual
incremental
electricity
production
costs
for
power
companies
installing
controls
and
making
other
changes
to
reduce
SO2
emissions
to
the
specified
levels.

Exhibit
3­
19
shows
the
incremental
cost
(
from
the
Base
Case)
of
meeting
the
alternative
SO2
levels.
Although
the
analysis
assumed
that
the
SO2
emissions
levels
were
lowered
in
2007
to
achieve
a
specific
percentage
reduction
from
the
Base
Case
in
2010,
Exhibit
3­
19
shows
that
costs
begin
accruing
in
2005
as
many
companies
decide
to
make
reductions
early
at
a
lower
cost,
banking
those
early
reductions
for
later
use.
Such
early
banking
reduces
overall
costs
by
providing
sources
with
an
option
to
make
a
more
gradual
transition
into
compliance
with
a
lower
SO2
emissions
cap
than
a
program
without
banking
can
provide.

Exhibit
3­
19
Annual
Costs
for
the
Electric
Power
Industry
for
Four
SO2
Reduction
Options
(
Million
1990$)

Control
Options
2005
2007
2010
40
Percent
Reduction
in
SO2
in
2010
$
1,230
$
1,282
$
1,873
45
Percent
Reduction
in
SO2
in
2010
$
1,465
$
1,639
$
2,121
50
Percent
Reduction
in
SO2
in
2010
$
1,656
$
1,977
$
2,451
55
Percent
Reduction
in
SO2
in
2010
$
1,908
$
2,116
$
2,814
The
compliance
costs
result
from
the
installation
of
scrubbers,
the
addition
of
more
natural
gas
combined­
cycle
capacity,
and
changes
in
the
dispatching
of
generation
units
 
there
is
less
use
of
coal­
fired
generation
and
more
use
of
units
powered
by
natural
gas.
Exhibit
3­
20
shows
the
increases
in
scrubber
installation
relative
to
the
Base
Case.
Under
the
Base
Case,
at
the
beginning
of
2005,
about
90
GW
of
about
304
GW
of
coal­
fired
capacity
should
already
have
scrubbers.
Exhibit
3­
21
shows
the
increases
in
natural
gas
combined­
cycle
capacity
as
the
SO2
emissions
levels
are
lowered.
Exhibit
3­
22
provides
the
changes
in
electric
generation
that
occurs
under
each
of
the
control
cases
relative
to
the
Base
Case
for
generation
units
that
use
coal
and
natural
gas/
oil.
There
is
little
change
from
the
base
case
in
the
output
of
generation
units
using
other
fuels
(
e.
g.
nuclear,
hydroelectric)
in
the
SO2
reduction
alternatives.
The
next
section
shows
the
changes
in
coal
and
other
fossil
fuel
use.
3­
18
Exhibit
3­
20
Cumulative
Installation
of
New
Scrubber
Capacity
at
Coal­
Fired
Units
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
GW)
Options
2005
2007
2010
Base
Case
4
4
6
40%
SO2
Reduction
in
2010
43
45
70
45%
SO2
Reduction
in
2010
52
59
75
50%
SO2
Reduction
in
2010
61
68
82
55%
SO2
Reduction
in
2010
67
71
93
Exhibit
3­
21
Natural
Gas
Combined­
Cycle
Capacity
for
the
Base
Case
and
Four
SO2
Reduction
Options
(
GW)
Options
2005
2007
2010
Base
Case
45
50
112
40%
SO2
Reduction
in
2010
47
52
116
45%
SO2
Reduction
in
2010
47
52
117
50%
SO2
Reduction
in
2010
48
52
118
55%
SO2
Reduction
in
2010
49
53
119
Note:
These
estimates
include
both
new
combined­
cycle
and
repowered
units
to
combined­
cycle.
3­
19
Exhibit
3­
22
Electric
Generation
Capacity
and
Production
for
Units
Using
Fossil
Fuels
for
the
Base
Case
and
Four
SO2
Reduction
Options
Fuel
Type
Capacity
by
Fuel
Type
(
GW)
Generation
by
Fuel
Type
(
Billion
kWh)

2005
2007
2010
2005
2007
2010
Base
Case
Coal
305
305
304
2,084
2,091
2,114
Oil/
Natural
Gas
240
250
282
561
626
759
40%
SO2
Reduction
in
2010
Coal
304
304
302
2,066
2,073
2,067
Oil/
Natural
Gas
241
251
283
578
643
805
45%
SO2
Reduction
in
2010
Coal
304
303
302
2,061
2,067
2,051
Oil/
Natural
Gas
241
252
283
583
649
822
50%
SO2
Reduction
in
2010
Coal
304
303
301
2,057
2,063
2,038
Oil/
Natural
Gas
242
252
285
587
653
835
55%
SO2
Reduction
in
2010
Coal
304
303
301
2,053
2,058
2,029
Oil/
Natural
Gas
242
252
285
591
658
843
Note:
Coal­
fired
units
are
assumed
to
lose
about
2
percent
of
their
capacity
when
they
install
scrubbers.
See
Exhibit
3­
20
to
assess
the
impact
of
scrubber
installation
on
the
capacity
over
time.

Fossil
Fuel
Use
Exhibits
3­
23
through
3­
27
show
the
changes
in
coal
consumption
that
result
from
each
of
the
alternative
pollution
control
options
relative
to
the
Base
Case.
(
See
Exhibit
2­
11
for
a
geographic
breakout
of
the
coal
supply
regions.)
Exhibit
3­
28
shows
the
changes
in
natural
gas
and
oil
use
by
the
power
industry.

As
expected,
a
lower
SO2
emissions
cap
leads
to
lower
coal
demand
and
greater
use
of
natural
gas.
The
exhibits
also
show
that
the
lower
the
SO2
emissions
level,
the
lower
will
be
the
use
of
low­
sulfur
western
coal.
This
result
occurs
because
the
larger
reductions
in
SO2
emissions
can
most
cost­
effectively
be
reached
by
scrubbing
lower
sulfur
(
generally
Eastern)
coal.
3­
20
Exhibit
3­
23
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
the
Base
Case
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
138
138
109
Central
and
Southern
Appalachia
185
186
213
Midwest
125
120
109
West
503
511
540
Central
West
and
Gulf
64
64
63
Total
1,015
1,019
1,034
Exhibit
3­
24
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
40
%
SO2
Reduction
in
2010
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
123
127
138
Central
and
Southern
Appalachia
181
177
173
Midwest
141
144
148
West
506
506
492
Central
West
and
Gulf
62
63
57
Total
1,014
1,017
1,008
Exhibit
3­
25
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
45
%
SO2
Reduction
in
2010
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
139
142
138
Central
and
Southern
Appalachia
162
164
172
Midwest
145
152
147
West
503
491
488
Central
West
and
Gulf
62
63
52
Total
1,012
1,011
997
3­
21
Exhibit
3­
26
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
50
%
SO2
Reduction
in
2010
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
145
145
142
Central
and
Southern
Appalachia
158
164
172
Midwest
153
150
140
West
489
489
486
Central
West
and
Gulf
62
63
49
Total
1,008
1,009
989
Exhibit
3­
27
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
55
%
SO2
Reduction
in
2010
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
147
148
142
Central
and
Southern
Appalachia
155
161
176
Midwest
153
147
142
West
488
488
476
Central
West
and
Gulf
62
61
48
Total
1,005
1,006
984
3­
22
Exhibit
3­
28
Natural
Gas
and
Oil
Consumption
Under
the
Base
Case
and
Options
to
Lower
SO2
Emissions
by
the
Electric
Power
Industry
Fuel
Type
Units
2005
2007
2010
Base
Case
Natural
Gas
Trillion
cubic
feet
4.6
5.2
5.3
Oil
Million
Barrels
21.3
21.5
0.0
40%
SO2
Reduction
in
2010
Natural
Gas
Trillion
cubic
feet
4.7
5.3
5.6
Oil
Million
Barrels
21.2
21.0
0.0
45%
SO2
Reduction
in
2010
Natural
Gas
Trillion
cubic
feet
4.8
5.3
5.7
Oil
Million
Barrels
21.0
21.0
0.0
50%
SO2
Reduction
in
2010
Natural
Gas
Trillion
cubic
feet
4.8
5.4
5.8
Oil
Million
Barrels
21.0
21.0
0.0
55%
SO2
Reduction
in
2010
Natural
Gas
Trillion
cubic
feet
4.8
5.4
5.8
Oil
Million
Barrels
21.0
21.0
0.0
CARBON
REDUCTION
OPTIONS
In
the
current
debate
about
future
U.
S.
efforts
to
address
climate
change,
various
stakeholders
and
analysts
have
advanced
a
number
of
ways
to
lower
emissions
of
carbon
dioxide
and
other
greenhouse
gases.
For
this
study,
EPA
selected
two
of
these
many
options
to
analyze
the
effects
that
alternative
carbon
control
levels
could
have
on
the
electric
power
industry's
costs
and
emissions.
These
options
were
chosen
simply
to
represent
different
approaches
to
possible
limitations
on
carbon
emissions
for
electric
power
generators.
They
do
not
represent
the
full
possible
range
of
carbon
control
alternatives
for
the
electric
power
industry.
They
also
do
not
represent
an
EPA
or
Administration
position
on
what
the
electric
power
industry
should
do
to
address
climate
change.

The
two
hypothetical
options
are:

Carbon
Level
of
567
MMT
in
2008
 
In
this
hypothetical
case,
the
following
assumptions
are
made:
3­
23
1.
Beginning
in
2008,
electric
power
companies
are
required
to
have
emissions
allowances
to
cover
their
carbon
emissions.
The
industry
is
issued
a
certain
number
of
U.
S.
emissions
allowances
and
is
permitted
to
buy
more
allowances
in
an
international
trading
market.

2.
The
power
industry
is
allocated
463
MMT
of
carbon
emissions
allowances
per
year.
This
is
3
percent
below
the
1990
carbon
emissions
level
of
the
power
industry.
1
3.
The
power
industry
finds
it
most
economical
to
lower
its
annual
domestic
carbon
emissions
down
to
567
MMT
and
to
purchase
104
MMT
of
allowances
annually
on
the
international
market.
2
In
the
analysis
of
this
option,
the
567
MMT
carbon
emissions
level
is
modeled
as
a
domestic
carbon
cap
and
power
plants
are
allowed
to
trade
emissions
allowances
with
each
other.
3
This
alternative
is
consistent
with
the
economic
analysis
prepared
by
the
White
House
Council
of
Economic
Advisors
in
July
1998.4
Electricity
demand
in
this
option
is
the
same
as
in
the
Base
Case.
This
hypothetical
option
does
not
account
for
the
electricity
demand
reductions
that
could
result
from
possible
increased
electricity
prices
caused
by
the
cost
of
meeting
the
alternative
carbon
levels.
This
option
does
not
include
additional
energy
efficiency
measures
assumed
in
the
second
option
described
below.

High
Efficiency/
Carbon
Level
of
515
MMT
in
2008
 
In
this
hypothetical
case,
assumptions
1
and
2
are
the
same,
but
the
following
different
assumptions
are
made:

1.
Domestic
demand
side
programs
are
in
place
that
lower
electric
demand
by
about
1.5
percent
per
year
from
2000
through
2010
and
by
about
1
percent
per
year
1
For
the
U.
S.,
the
Kyoto
Protocol
requires
a
7
percent
reduction
in
greenhouse
gases
below
1990
levels
between
2008
and
2012.
Many
analysts
believe
that
the
U.
S.
would
really
be
required
to
lower
carbon
emissions
to
3
percent
below
1990
levels,
since
the
Kyoto
Protocol
allows
credit
for
growth
in
carbon
sinks
(
such
as
forest
growth),
which
is
expected
to
amount
to
4
percent
over
the
2008­
2012
period.
The
reduction
target
assumed
for
the
power
sector
in
this
analysis
is
based
on
the
assumption
that
each
industry
makes
proportional
reductions
in
emissions
to
3
percent
below
its
1990
levels.
The
electric
power
industry's
1990
carbon
emissions
level
was
477
MMT.
Other
assumptions
could
lead
to
higher
or
lower
targets
for
the
power
sector.
2
This
analysis
assumes
that
international
trading
of
carbon
allowances
is
not
restricted,
consistent
with
the
Council
of
Economic
Advisors'
study
of
July
1998
(
see
reference
4
below).
The
Energy
Information
Administration
(
EIA)
estimated
that
electric
power
generators
would
reduce
domestic
carbon
emissions
to
567
MMT
in
2010
and
make
international
carbon
allowance
purchases
for
the
rest
of
the
needed
allowances.
Domestic
emissions
of
567
MMT
would
be
19
percent
above
1990
levels
and
15
below
levels
EIA
has
forecasted
in
its
reference
case
for
2010.
See
EIA,
Impacts
of
the
Kyoto
Protocol
on
U.
S.
Energy
Markets
and
Economic
Activity,
October
1998.
3
The
Kyoto
Protocol
actually
sets
up
a
five­
year
budget
period
for
2008­
2012,
with
a
total
carbon
allowance
budget
equal
to
five
times
an
annual
level.
This
study
modeled
carbon
as
an
annual
limit,
however,
and
did
not
attempt
to
model
banking
(
stockpiling
of
allowances
for
later
use)
either
within
the
2008­
2012
period,
or
into
a
future
five­
year
period.
Banking
would
be
expected
to
make
a
program
less
expensive
over
its
lifetime
by
providing
inter­
temporal
flexibility:
Power
generators
would
have
flexibility
to
use
a
total
of
five
times
this
annual
limit
over
the
five­
year
period,
in
any
manner
that
they
wished,
and
to
carry
over
any
unused
allowances
from
the
first
period
to
later
ones.
The
extent
of
banking
between
periods
could
not
be
modeled
without
assumptions
regarding
carbon
limits
in
future
periods,
which
would
go
beyond
the
scope
of
this
study.
4
Council
of
Economic
Advisors,
the
White
House,
The
Kyoto
Protocol
and
the
President's
Policies
to
Address
Climate
Change:
Administration
Economic
Analysis,
July
1998.
3­
24
from
2010
through
2020.5
By
2010,
the
electricity
demand
would
be
15
percent
lower
than
the
power
industry
has
projected
it
will
be
and
forecasted
carbon
emissions
for
the
power
industry
would
be
590
MMT.

2.
The
power
industry
finds
it
least
expensive
to
lower
emissions
to
515
MMT
annually
and
purchase
52
MMT
of
allowances
annually.
The
515
MMT
carbon
emissions
level
is
modeled
as
a
domestic
carbon
emissions
cap
on
the
industry
and
power
plants
are
allowed
to
trade
emissions
allowances.
6
EPA
and
Lawrence
Berkeley
National
Laboratory
of
the
Department
of
Energy
have
examined
an
option
similar
to
this
in
a
recent
study.
7
Air
Emissions
EPA
examined
the
changes
in
air
emissions
from
2005
to
2010
for
these
options.
Because
no
early
reduction
banking
system
was
assumed
and
because
the
assumed
start
date
for
meeting
the
carbon
limits
was
2008,
all
large
changes
in
air
emissions
and
operation
of
the
electric
power
system
relative
to
the
Base
Case
occur
only
in
the
2010
results.
Therefore,
only
the
results
for
2010
are
reported
here.
Exhibits
3­
29
and
3­
30
provide
a
national
summary
of
air
emissions
for
the
two
carbon
reduction
alternatives
and
the
Base
Case.
Exhibits
3­
31
and
3­
32
show
the
regional
emissions
for
the
carbon
reduction
options
(
these
can
be
compared
to
the
regional
emissions
in
Chapter
2
for
the
Base
Case.)

In
2010,
the
option
limiting
carbon
emissions
to
567
MMT
in
2008
option
lowers
annual
carbon
emissions
by
54
million
metric
tons
(
i.
e.,
about
nine
percent)
below
the
Base
Case
forecast.
8
However,
it
lowers
annual
mercury
emissions
by
about
15
percent
from
coal­
fired
units.
This
is
caused
by
the
projected
fuel
use
for
electric
generation
shifting
away
from
coal
to
natural
gas.
Natural
gas
has
about
60
percent
of
the
carbon
emissions
per
BTU
of
fuel
use,
and
only
trace
concentrations
of
mercury.
Annual
SO2
emissions
are
nearly
unchanged
because
of
the
assumed
SO2
emissions
cap
in
place
under
Title
IV
of
the
Clean
Air
Act.
This
cap
leads
5
North
American
Electric
Reliability
Council,
Electricity
Supply
&
Demand,
1997,
electronic
files
released
in
fall
1997.
6
A
carbon
emissions
level
of
515
MMT
is
nine
percent
above
1990
levels
and
21
percent
below
where
Energy
Information
Administration
(
EIA)
has
forecasted
that
the
U.
S.
electric
power
industry
will
be
in
its
reference
case
in
2010
(
657
MMT),
in
a
recent
study
that
EIA
published
on
options
to
lower
carbon
emissions
in
the
energy
sector.
The
recent
EIA
study
is
entitled
Impacts
of
the
Kyoto
Protocol
on
U.
S.
Energy
Markets
and
Economic
Activity,
October
1998.
7
U.
S.
Environmental
Protection
Agency
and
Ernest
Orlando
Lawrence
Berkeley
National
Laboratory,
Technology
and
Greenhouse
Gas
Emissions:
An
Integrated
Scenario
Analysis
Using
the
LBNL­
NEMS
Model,
October
1998.
8
Earlier
IPM
analysis
of
setting
carbon
emissions
caps
in
trading
programs
for
the
electric
power
industry
shows
that
there
is
a
direct
relationship
between
the
level
of
the
carbon
emissions
cap
and
mercury
emissions
that
will
occur.
As
the
carbon
level
is
set
at
lower
levels,
IPM
analysis
of
the
resulting
mercury
emissions
from
the
electric
power
industry
shows
that
it
also
decreases
and
does
so
at
a
proportionately
greater
rate.
This
is
because
as
the
emissions
cap
is
decreased
(
i.
e.,
made
more
stringent)
there
is
less
use
of
coal­
fired
generation,
the
main
source
of
mercury
emissions,
and
it
is
displaced
with
natural
gas
generation
which
has
much
lower
carbon
emissions
and
virtually
no
mercury
emissions.
For
instance,
in
a
presentation
made
by
EPA
in
November
1998
at
the
Center
for
Clean
Air
Policy,
IPM
analysis
showed
that
having
a
carbon
level
at
477
MMT
in
2010
lowers
carbon
emissions
by
23
percent
and
mercury
emissions
by
33
percent.
3­
25
sources
that
lower
their
coal
use
to
sell
allowances
to
other
sources
that
will
use
higher
sulfur
coals.
Summer
and
annual
NOx
emissions
drop
by
13
percent
and
15
percent,
respectively.
These
reductions
are
caused
by
the
projected
switch
from
coal
to
natural
gas
generation,
which
has
lower
NOx
levels.
The
summer
emissions
reduction
is
lower,
because
the
power
companies
in
areas
that
are
covered
by
the
NOx
SIP
call
lower
NOx
emissions
through
greater
natural
gas
use
and
sell
their
excess
allowances
to
other
companies.

The
High
Efficiency
 
Carbon
Level
at
515
MMT
in
2008
option
lowers
annual
carbon
emissions
by
106
million
metric
tons
below
the
Base
Case
(
more
than
15
percent).
However,
it
lowers
annual
mercury
from
coal­
fired
units
by
about
23
percent.
Annual
SO2
emissions
do
not
change
significantly,
but
summer
and
annual
NOx
emissions
drop
by
20
percent
and
23
percent,
respectively.
These
results
occur
for
the
same
reasons
mentioned
in
the
first
carbon
option
above.

Exhibit
3­
29
Annual
Changes
in
Selected
Air
Emissions
in
2010
for
the
Electric
Power
Industry
for
the
Base
Case
and
Two
Carbon
Reduction
Options
SO2
Annual
NOx
Summer
NOx
Carbon
Control
Options
(
1,000
tons)
(
1,000
tons)
(
1,000
tons)
(
MMT)

Base
Case
9,658
4,147
1,386
621
Carbon
Level
at
567
MMT
in
2008
9,574
3,518
1,201
567
High
Efficiency
 
Carbon
Level
at
515
MMT
in
2008
9,389
3,203
1,109
515
Exhibit
3­
30
Annual
Changes
in
Mercury
Emissions
in
2010
for
All
Sources
and
Coal­
fired
Units
in
the
Electric
Power
Industry
for
the
Base
Case
and
Two
Carbon
Reduction
Options
(
Tons)
Control
Sources
All
Sources
Coal­
fired
Units
Base
Case
50.9
46.9
Carbon
Level
at
567
MMT
in
2008
43.7
39.7
High
Efficiency
­
Carbon
Level
at
515
MMT
in
2008
39.9
35.9
3­
26
Exhibit
3­
31
Regional
Electric
Generation
and
Air
Emissions
for
2010
Carbon
Level
of
567
MMT
in
2008
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
41
92
26
87
264
0.7
16
ECAO
226
533
187
832
3,021
8.4
119
ERCT
136
283
85
139
236
2.3
34
MACE
47
98
16
56
129
1.2
10
MACW
41
98
30
123
553
2.9
17
MACS
29
71
14
65
210
1.1
10
WUMS
26
61
19
63
186
0.9
13
MANO
83
185
49
182
797
3.6
31
MAPP
77
176
126
288
443
2.8
35
UPNY
56
122
19
50
183
1.1
9
LILC
7
16
2
3
0
0.3
1
NENG
48
117
15
42
126
1.5
11
FRCC
98
206
88
174
247
1.8
27
VACA
136
319
68
267
916
3.5
44
TVA
70
163
42
184
552
2.0
26
SOU
104
223
78
219
890
3.1
36
SPPN
43
94
42
97
119
0.8
16
SPPS
126
266
86
147
252
1.4
33
CNV
124
281
31
73
50
1.2
22
WSCP
79
186
17
39
124
0.4
8
WSCR
102
237
163
387
277
2.5
48
TOTAL
1,699
3,827
1,201
3,518
9,574
43.7
567
3­
27
Exhibit
3­
32
Regional
Electric
Generation
and
Air
Emissions
for
2010
High
Efficiency
 
Carbon
Level
of
515
MMT
in
2008
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
85
28
87
258
0.8
15
ECAO
216
508
187
798
3,134
8.0
113
ERCT
126
265
66
106
168
1.5
29
MACE
40
86
16
56
129
1.2
9
MACW
41
97
31
124
554
2.9
17
MACS
29
69
15
62
212
1.0
10
WUMS
24
56
18
59
173
0.8
12
MANO
76
173
44
168
774
3.2
28
MAPP
70
160
109
249
415
2.5
30
UPNY
53
115
20
51
181
1.1
9
LILC
7
15
1
3
0
0.3
1
NENG
45
109
15
42
126
1.5
11
FRCC
91
194
75
147
200
1.7
25
VACA
125
290
70
261
910
3.4
40
TVA
66
154
38
154
509
1.7
22
SOU
99
206
81
207
958
2.9
33
SPPN
39
86
26
49
57
0.4
11
SPPS
122
258
75
116
207
1.1
29
CNV
118
268
30
71
50
1.2
20
WSCP
71
168
16
38
124
0.4
7
WSCR
96
222
150
355
250
2.4
44
TOTAL
1,592
3,585
1,109
3,203
9,389
39.9
515
3­
28
Costs
and
Power
System
Changes
In
the
model,
electric
power
generators
make
adjustments
in
such
things
as
fuel
use,
generator
capacity
utilization
and
new
generation
construction
in
response
to
changes
in
assumed
energy
demand
and
emissions
limitations.
Exhibit
3­
33
shows
the
annual
incremental
costs
of
these
adjustments
for
the
carbon
reduction
options.

Note
that
in
both
cases
domestic
carbon
emissions
remain
above
power
generators'
1990
levels.
The
costs
and
emissions
reductions
shown
in
this
report
are
only
those
that
result
from
the
reductions
from
the
Base
Case
level
to
567
MMT
and
515
MMT.
The
cost
of
purchasing
international
emissions
allowances
is
not
shown
in
this
analysis.
9
The
costs
shown
in
Exhibit
3­
33
are
the
annualized
incremental
costs
of
reducing
domestic
carbon
emissions
from
levels
associated
with
the
baseline
electricity
demand.
In
the
case
of
the
567
MMT
Carbon
Level
option,
this
is
a
reduction
of
54
MMT.
This
option
assumes
that
electricity
demand
is
the
same
as
that
used
in
the
Base
Case.
For
the
High
Efficiency
option,
there
is
a
reduction
of
106
MMT
from
Base
Case
levels
in
2010.
About
30
MMT
of
this
reduction
come
from
the
reduction
in
electricity
demand
caused
by
the
assumed
energy
efficiency
measures
(
see
Appendix
E
for
references
describing
such
measures)
included
in
this
option.
The
investment
costs
and
the
resultant
savings
from
electricity
use
are
shown
in
Exhibit
3­
34.
The
costs
of
achieving
the
remaining
76
MMT
from
changes
in
electricity
production
are
shown
in
Exhibit
3­
33.

Exhibit
3­
33
Annual
Costs
for
the
Electric
Power
Industry
in
2010
for
Two
Options
to
Lower
Carbon
Emissions
Options
Million
1990$
Carbon
Level
of
567
MMT
in
2008
$
1,038
High
Efficiency
 
Carbon
Level
of
515
MMT
in
2008
$
2,000
Note:
Costs
include
the
additional
resources
that
are
expended
to
produce
electric
power,
if
the
industry
is
lowering
carbon
emissions
to
the
levels
specified
in
each
option.
It
does
not
include
purchasing
of
carbon
allowances
in
an
international
trading
program.
A
discussion
of
allowance
purchase
costs
occurs
in
reference
9
below.

9
The
costs
to
the
power
industry
of
buying
carbon
allowances
under
an
international
cap­
and­
trade
approach
are
difficult
to
estimate.
The
number
of
allowances
purchased
internationally
depends
on
the
number
of
domestic
allowances
that
the
industry
is
awarded
and
the
price
of
international
allowances.
If
it
is
assumed
that
the
power
industry
is
annually
awarded
463
MMT
of
carbon
allowances
and
that
the
international
cost
of
allowances
is
$
19.50
per
ton
in
1990
dollars
(
equivalent
to
$
23
per
ton
in
1996
dollars,
the
high
end
of
the
range
in
the
CEA
report
referenced
earlier),
the
costs
would
be
estimated
as
follows:
For
the
first
option
(
567
MMT
in
2008),
the
annual
allowance
costs
would
be
$
2
billion.
For
the
second
option
(
High
Efficiency
 
515
MMT
in
2008),
the
annual
allowance
costs
would
be
$
1
billion.
3­
29
Exhibit
3­
34
Annual
Costs
for
the
Electric
Power
Industry
and
Power
Users
And
Savings
Resulting
from
Lower
Electricity
Use
in
2010
in
the
High
Efficiency
 
Carbon
Level
of
515
MMT
in
2008
Option
Cost
Categories
Million
1990$
Increased
Production
Costs*
$
2,000
Investment
in
Energy
Reduction
4,986
Savings
from
Energy
Reduction
7,864
Net
Savings
$
878
*
Costs
include
the
additional
resources
that
are
expended
to
produce
electric
power,
if
the
industry
is
lowering
carbon
emissions
to
the
levels
specified
in
each
option.
It
does
not
include
purchasing
of
carbon
allowances
in
an
international
trading
program.
A
discussion
of
allowance
purchase
costs
occurs
in
reference
9
in
this
chapter.

Changes
in
scrubber
installation,
combined­
cycle
capacity,
and
the
mix
of
electric
generation
for
units
using
fossil
fuels
are
shown
in
Exhibits
3­
35
through
3­
37.
Notably,
neither
carbon
program
option
leads
to
increased
use
of
generation
units
that
use
renewable
fuels
for
power
in
2010.

Exhibit
3­
35
Installation
of
New
Scrubber
Capacity
at
Coal­
fired
Units
in
2010
for
the
Base
Case
and
Two
Carbon
Reduction
Options
Options
GW
Base
Case
6
Carbon
Level
of
567
MMT
in
2008
4
High
Efficiency
/
Carbon
Level
of
515
MMT
in
2008
3
Exhibit
3­
36
Installation
of
Natural
Gas
Combined­
Cycle
Capacity
in
2010
for
the
Base
Case
and
Two
Carbon
Reduction
Options
Options
GW
Base
Case
112
Carbon
Level
of
567
MMT
in
2008
148
High
Efficiency/
Carbon
Level
of
515
MMT
in
2008
137
Note:
These
estimates
include
both
new
combined­
cycle
and
repowered
units
to
combined­
cycle.
3­
30
Exhibit
3­
37
Electric
Generation
Capacity
and
Production
for
Units
Using
Fossil
Fuels
for
the
Base
Case
and
Two
Carbon
Reduction
Options
Fuel
Type
Capacity
by
Fuel
Type
(
GW)
Generation
by
Fuel
Type
(
Billion
kWh)

2010
2010
Base
Case
Coal
304
2,114
Oil/
Natural
Gas
282
759
Carbon
Level
of
567
MMT
in
2008
Coal
300
1,843
Oil/
Natural
Gas
287
1,027
High
Efficiency
 
Carbon
Level
of
515
MMT
in
2008
Coal
285
1,682
Oil/
Natural
Gas
254
947
Note:
Coal­
fired
units
are
assumed
to
lose
about
2
percent
of
their
capacity
when
they
install
scrubbers.
See
Exhibit
3­
35
to
assess
the
impact
of
scrubber
installation
on
the
capacity
over
time.

Fuel
Use
Exhibits
3­
38
through
3­
41
show
the
forecasted
fuel
demand
for
coal
and
natural
gas
in
2010
for
the
two
carbon
reduction
options.
Both
carbon
options
produce
substantial
changes
in
the
demand
for
coal
and
natural
gas,
because
fuel
switching
to
less
carbon­
intensive
fuels
is
a
major
way
of
reducing
carbon
emissions
from
electricity
production.
No
oil
use
is
projected
for
2010
under
either
option.
3­
31
Exhibit
3­
38
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
in
2010
Under
the
Base
Case
Coal
Supply
Areas
Million
tons
Northern
Appalachia
109
Central
and
Southern
Appalachia
213
Midwest
109
West
540
Central
West
and
Gulf
63
Total
1,034
Exhibit
3­
39
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
2010
Under
a
Carbon
Level
of
567
MMT
in
2008
Coal
Supply
Areas
Million
tons
Northern
Appalachia
129
Central
and
Southern
Appalachia
185
Midwest
117
West
400
Central
West
and
Gulf
31
Total
861
Exhibit
3­
40
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
2010
Under
High
Efficiency/
Carbon
Level
of
515
MMT
in
2008
Coal
Supply
Areas
Million
tons
Northern
Appalachia
134
Central
and
Southern
Appalachia
169
Midwest
114
West
335
Central
West
and
Gulf
18
Total
771
3­
32
Exhibit
3­
41
Natural
Gas
Consumption
by
the
Electric
Power
Industry
in
2010
for
the
Base
Case
and
Two
Carbon
Reduction
Options
Options
Trillion
Cubic
Feet
Base
Case
5.3
Carbon
Level
of
567
MMT
in
2008
6.7
High
Efficiency/
Carbon
Level
of
515
MMT
in
2008
6.2
SO2
AND
CARBON
REDUCTION
OPTIONS
This
study
also
considered
two
options
that
lowered
both
carbon
and
SO2
emissions.
In
both
options,
carbon
and
SO2
emissions
limitations
are
simulated
to
be
achieved
through
capand
trade
programs.
Early
reduction
banking
of
allowances
is
allowed
for
SO2
emissions,
but
not
for
carbon
emissions.
The
two
options
are:

 
SO2
Reduction
of
50
Percent/
Carbon
Level
of
567
MMT
­
the
CAAA
Title
IV
SO2
emissions
cap
is
lowered
in
2007
to
a
level
that
provides
a
50
percent
reduction
in
2010.
In
2008,
a
carbon
emissions
cap
is
set
in
IPM
at
the
level
of
567
MMT.
After
being
set,
the
new
SO2
and
carbon
emissions
caps
remain
constant
through
2025.
The
analysis
uses
a
conservative
assumption
that
there
will
not
be
a
reduction
in
electric
demand
resulting
from
the
higher
electricity
costs
that
occur
because
of
compliance
with
the
SO2
and
carbon
reduction
requirements.

 
SO2
Reduction
of
50
Percent/
High
Efficiency
with
Carbon
Level
of
515
MMT­
the
CAAA
Title
IV
SO2
emissions
cap
is
lowered
in
2007
to
a
level
that
provides
a
50
percent
reduction
in
2010.
In
2008,
a
carbon
emissions
cap
is
set
in
IPM
at
a
level
of
515
MMT.
After
being
set,
the
new
SO2
and
carbon
emissions
caps
remain
constant
through
2025.
In
conjunction
with
these
caps,
the
US
pursues
programs
that
lower
electric
demand
from
the
Base
Case
by
15
percent
in
2010.
These
energy
efficiency
programs
begin
in
2001
and
gradually
lower
demand
over
time.

Air
Emissions
Exhibits
3­
42
through
3­
46
show
the
national
air
emissions
changes
for
the
two
SO2/
Carbon
reduction
options.
Regional
emissions
are
presented
in
Exhibits
3­
47
through
3­
52.
(
These
regional
emissions
estimates
can
be
compared
to
the
Base
Case
in
Chapter
2
to
consider
the
significance
of
the
emissions
changes
throughout
the
country.)

For
SO2
emissions,
the
combination
of
a
carbon
reduction
program
with
a
program
to
lower
SO2
emissions
by
50
percent
in
2010
leads
to
a
shifting
in
the
emissions
pattern
from
2005
to
2010.
Recognizing
that
it
will
be
cheaper
to
lower
SO2
emissions
in
the
future
when
a
carbon
program
exists,
the
model
projects
that
in
2005
and
2007
power
companies
will
use
more
of
their
banked
SO2
allowances
and
hold
fewer
in
reserve
in
the
future.
3­
33
The
combination
of
a
carbon
reduction
program
with
a
program
to
lower
SO2
emissions
by
50
percent
in
2010
helps
lower
summer
NOx
emissions
in
2010.
In
fact,
if
the
existing
installed
NOx
control
equipment
continues
to
operate
as
the
model
assumes
that
it
will,
summer
NOx
emissions
in
the
NOx
SIP
call
region
drop
below
the
NOx
emissions
cap
by
a
small
amount
in
2010.

Of
all
the
options
examined
in
this
chapter,
the
combined
SO2/
Carbon
reduction
control
options
provide
the
greatest
reduction
in
mercury
emissions.
By
2010,
the
50%
SO2
Reduction/
Carbon
Level
of
567
MMT
option
has
mercury
emissions
from
coal­
fired
units
that
are
26
percent
lower
than
the
Base
Case.
The
50%
SO2
Reduction/
High
Efficiency
 
Carbon
Level
of
515
MMT
option
has
mercury
emissions
from
coal­
fired
units
that
are
34
percent
below
the
Base
Case.

Exhibit
3­
42
Annual
SO2
Emissions
for
the
Electric
Power
Industry
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
1,000
tons)
Options
2005
2007
2010
Base
Case
11,049
10,864
9,658
50
%
Reduction
in
SO2
in
2010
6,303
5,868
4,939
50
%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
6,971
6,913
4,641
50
%
Reduction
in
SO2/
HE
 
Carbon
Level
of
515
MMT
7,260
7,099
4,549
3­
34
Exhibit
3­
43
Annual
and
Summer
NOx
Emissions
for
the
Electric
Power
Industry
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
1,000
tons)
Options
2005
2007
2010
Annual
Emissions
Base
Case
4,221
4,255
4,147
50
Percent
Reduction
in
SO2
in
2010
4,203
4,246
4,019
50
%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
4,185
4,205
3,522
50
%
Reduction
in
SO2/
HE
 
Carbon
Level
of
515
MMT
4,169
4,149
3,151
Summer
Emissions
NOx
SIP
Call
Base
Case
1,436
1,449
1,386
50
Percent
Reduction
in
SO2
in
2010
1,432
1,448
1,353
50
%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
1,428
1,435
1,208
50
%
Reduction
in
SO2/
HE
 
Carbon
Level
of
515
MMT
1,432
1,427
1,072
Exhibit
3­
44
Annual
Carbon
Emissions
for
the
Electric
Power
Industry
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
MMT)
Options
2005
2007
2010
Base
Case
605
615
621
50
Percent
Reduction
in
SO2
in
2010
603
613
610
50
%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
602
611
567
50
%
Reduction
in
SO2/
HE
 
Carbon
Level
of
515
MMT
593
592
515
3­
35
Exhibit
3­
45
Annual
Mercury
Emissions
for
All
Sources
in
the
Electric
Power
Industry
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
Tons)
Options
2005
2007
2010
Base
Case
51.9
52.0
50.9
50
Percent
Reduction
in
SO2
in
2010
46.4
46.1
44.5
50
%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
47.2
47.2
38.6
50
%
Reduction
in
SO2/
HE
 
Carbon
Level
of
515
MMT
47.1
46.7
34.8
Exhibit
3­
46
Annual
Mercury
Emissions
for
the
Coal­
Fired
Units
of
the
Electric
Power
Industry
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
Tons)
Options
2005
2007
2010
Base
Case
47.9
48.0
46.9
50
Percent
Reduction
in
SO2
in
2010
42.4
42.1
40.5
50
%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
43.2
43.2
34.7
50
%
Reduction
in
SO2/
HE
 
Carbon
Level
of
515
MMT
43.1
42.7
30.8
3­
36
Exhibit
3­
47
Regional
Electric
Generation
and
Air
Emissions
for
2005
50%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
37
85
29
93
275
1.1
16
ECAO
219
523
166
796
1,411
7.4
116
ERCT
126
261
154
322
318
4.3
45
MACE
46
101
17
58
99
1.2
9
MACW
43
101
28
120
130
2.0
17
MACS
24
55
15
64
63
0.8
9
WUMS
24
57
19
65
194
1.0
12
MANO
82
192
50
223
482
4.0
37
MAPP
77
173
150
343
449
3.5
39
UPNY
58
132
22
64
116
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
104
24
62
183
1.5
12
FRCC
89
183
120
249
201
2.1
29
VACA
126
292
69
270
803
3.4
42
TVA
67
155
43
191
411
2.2
26
SOU
104
229
88
265
824
3.6
41
SPPN
40
91
53
156
173
1.4
20
SPPS
112
226
149
302
474
2.7
41
CNV
109
249
32
76
50
1.2
22
WSCP
71
168
19
44
22
0.3
7
WSCR
109
251
178
418
293
2.7
51
TOTAL
1,610
3,633
1,428
4,185
6,971
47.2
602
3­
37
Exhibit
3­
48
Regional
Electric
Generation
and
Air
Emissions
for
2007
50%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
87
28
93
269
1.1
16
ECAO
220
525
167
798
1,367
7.3
117
ERCT
129
269
158
333
318
4.3
47
MACE
45
95
18
60
103
1.3
10
MACW
43
103
29
124
136
2.0
17
MACS
26
62
15
65
63
0.8
9
WUMS
24
58
18
64
189
1.0
12
MANO
85
200
49
216
469
3.9
36
MAPP
79
174
150
342
444
3.5
39
UPNY
59
134
22
63
113
0.8
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
24
63
183
1.5
12
FRCC
93
190
118
245
196
2.0
29
VACA
131
303
69
274
810
3.5
43
TVA
70
159
43
191
410
2.1
26
SOU
104
231
88
268
837
3.6
41
SPPN
42
96
54
156
173
1.4
21
SPPS
116
231
152
301
471
2.7
41
CNV
113
261
33
80
50
1.2
24
WSCP
71
168
19
45
22
0.3
7
WSCR
110
255
179
420
291
2.7
52
TOTAL
1,645
3,712
1,435
4,205
6,913
47.2
611
3­
38
Exhibit
3­
49
Regional
Electric
Generation
and
Air
Emissions
for
2010
50%
Reduction
in
SO2/
Carbon
Level
of
567
MMT
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
40
92
27
88
253
0.7
16
ECAO
223
526
190
819
1,186
7.3
118
ERCT
135
282
94
164
180
2.5
36
MACE
48
100
16
54
81
1.2
10
MACW
42
97
31
122
82
2.1
17
MACS
29
74
14
60
37
0.7
10
WUMS
26
60
20
61
179
0.9
12
MANO
82
185
48
190
308
3.0
31
MAPP
75
171
120
275
316
2.8
33
UPNY
53
119
17
49
92
0.7
9
LILC
7
16
2
3
0
0.3
1
NENG
50
119
16
42
45
1.3
12
FRCC
101
211
92
192
115
1.8
29
VACA
136
317
65
249
426
2.8
42
TVA
73
168
37
160
289
1.6
24
SOU
102
216
80
218
344
2.5
35
SPPN
46
104
48
124
117
1.0
19
SPPS
125
268
89
158
244
1.6
34
CNV
123
281
31
73
50
1.2
22
WSCP
78
184
17
39
22
0.3
8
WSCR
104
239
168
393
276
2.5
48
TOTAL
1,698
3,828
1,220
3,534
4,641
38.6
567
3­
39
Exhibit
3­
50
Regional
Electric
Generation
and
Air
Emissions
for
2005
50%
Reduction
in
SO2/
High
Efficiency
 
Carbon
Level
of
515
MMT
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
36
83
29
93
276
1.1
16
ECAO
215
514
164
782
1,390
7.1
114
ERCT
123
256
158
335
318
4.3
45
MACE
46
100
18
59
101
1.2
9
MACW
43
101
29
120
132
2.0
17
MACS
21
49
15
62
106
0.7
8
WUMS
23
56
19
65
192
1.0
12
MANO
82
190
50
217
513
4.0
36
MAPP
75
168
151
345
478
3.5
38
UPNY
58
131
22
63
117
0.8
11
LILC
3
4
2
4
0
0.3
1
NENG
43
102
24
62
190
1.5
12
FRCC
87
178
121
248
273
2.1
28
VACA
124
288
70
269
825
3.5
41
TVA
67
153
43
189
405
2.1
25
SOU
103
228
87
262
924
3.7
40
SPPN
39
89
55
157
179
1.4
20
SPPS
107
217
148
303
475
2.7
40
CNV
107
245
32
76
50
1.2
21
WSCP
67
160
17
42
22
0.3
6
WSCR
109
251
178
417
294
2.7
51
TOTAL
1,577
3,561
1,432
4,169
7,260
47.1
593
3­
40
Exhibit
3­
51
Regional
Electric
Generation
and
Air
Emissions
for
2007
50%
Reduction
in
SO2/
High
Efficiency
 
Carbon
Level
of
515
MMT
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
36
83
28
92
273
1.1
16
ECAO
214
511
165
776
1,317
7.0
113
ERCT
125
259
160
339
318
4.3
46
MACE
43
93
18
60
105
1.2
9
MACW
43
103
30
124
139
2.0
17
MACS
23
55
15
64
102
0.7
9
WUMS
24
57
18
62
185
1.0
12
MANO
83
194
48
207
449
3.8
34
MAPP
75
166
149
340
467
3.5
38
UPNY
57
132
21
62
113
0.8
10
LILC
3
4
2
4
0
0.3
0
NENG
42
100
24
61
186
1.5
12
FRCC
88
180
119
244
269
2.1
28
VACA
125
290
70
272
839
3.5
42
TVA
66
152
42
187
398
2.1
25
SOU
104
230
88
262
923
3.7
41
SPPN
41
92
54
156
175
1.4
20
SPPS
105
213
146
299
475
2.7
40
CNV
108
246
32
76
50
1.2
21
WSCP
69
163
18
44
22
0.3
7
WSCR
109
251
178
417
293
2.7
51
TOTAL
1,584
3,573
1,427
4,149
7,099
46.7
592
3­
41
Exhibit
3­
52
Regional
Electric
Generation
and
Air
Emissions
for
2010
50%
Reduction
in
SO2/
High
Efficiency
 
Carbon
Level
of
515
MMT
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
37
84
28
88
250
0.7
15
ECAO
211
501
192
792
1,142
6.7
112
ERCT
126
265
73
121
135
1.7
30
MACE
46
95
16
53
73
1.2
9
MACW
38
89
27
110
86
1.8
15
MACS
28
71
15
60
44
0.6
10
WUMS
24
56
20
59
170
0.8
11
MANO
77
171
47
176
316
2.8
28
MAPP
70
158
103
232
294
2.3
30
UPNY
52
114
17
42
67
0.5
7
LILC
7
15
1
3
0
0.3
1
NENG
46
111
15
39
68
1.3
10
FRCC
95
200
69
137
102
1.7
26
VACA
124
290
67
243
465
2.7
39
TVA
68
157
37
147
249
1.4
22
SOU
94
198
74
183
459
2.2
30
SPPN
41
93
43
104
94
0.8
17
SPPS
122
259
77
125
197
1.2
30
CNV
113
256
31
72
50
1.2
19
WSCP
71
167
16
38
22
0.3
6
WSCR
102
236
162
385
267
2.5
47
TOTAL
1,591
3,585
1,131
3,210
4,549
34.8
515
3­
42
Cost
and
System
Changes
The
electric
generation
system
will
make
adjustments
to
meet
changes
in
electricity
demand
and
the
pollution
control
requirements
of
each
of
these
options.
Exhibit
3­
53
shows
the
incremental
annual
production
costs
for
power
companies
installing
controls
and
making
other
changes
to
comply
with
the
alternatives.
Earlier,
Exhibits
3­
19
and
3­
33
showed
the
annualized
costs
of
meeting
the
SO2
and
Carbon
options
separately.
In
looking
at
those
exhibits
in
conjunction
with
Exhibit
3­
53,
it
becomes
clear
that
a
joint
control
program
will
have
a
much
lower
overall
cost
(
between
$
450
million
to
$
800
million
lower
in
2010
for
the
options
analyzed)
than
two
separate
programs
since
some
of
the
actions
the
power
industry
takes
to
comply
with
either
program
are
the
same.
This
will
be
discussed
further
below.

If
either
of
the
options
(
SO2
or
carbon
reduction)
were
considered
to
be
the
baseline
upon
which
to
judge
the
program
costs
of
the
other
options,
the
incremental
production
costs
of
the
other
additional
program
would
be
much
lower
that
those
earlier
exhibits
indicate.
For
instance,
if
the
50
Percent
SO2
reduction
option
is
assumed
be
the
baseline
for
judging
the
costs
of
a
future
carbon
program,
then
the
annual
incremental
production
cost
of
the
Carbon
Level
of
567
MMT
in
2008
option
in
2010
is
$
590
million,
rather
than
$
1,038
million
(
Exhibit
3­
33).

Exhibit
3­
53
does
not
show
for
the
50%
SO2
Reduction/
High
Efficiency
 
Carbon
Level
at
515
MMT
option
the
costs
of
the
electric
demand
reduction
program
and
its
savings.
This
information
is
provided
in
Exhibit
3­
54,
which
shows
the
increased
electric
generation
production
costs,
demand
reduction
program
costs
and
savings,
and
the
net
costs
that
occur
for
this
option.

Exhibit
3­
53
Annual
Costs
for
the
Electric
Power
Industry
Combined
SO2
/
Carbon
Reduction
Options
(
million
1990$)
Options
2005
2007
2010
50
%
SO2
Reduction/
Carbon
Level
567
MMT
$
1,320
$
1,337
$
3,041
50
%
SO2
Reduction/
High
Efficiency
 
Carbon
Level
515
MMT
$
1,117
$
1,173
$
3,629
Note:
Costs
include
the
additional
resources
that
are
expended
to
produce
electric
power,
if
the
industry
is
lowering
carbon
emissions
to
the
levels
specified
in
each
option.
It
does
not
include
purchasing
of
carbon
allowances
in
an
international
trading
program.
A
discussion
of
allowance
purchase
costs
occurs
in
reference
9
in
this
chapter.
3­
43
Exhibit
3­
54
Annual
Incremental
Production
Costs
for
the
Electric
Power
Industry
and
Power
Users
and
Savings
Resulting
from
Lower
Electricity
Use
in
2010
for
the
50%
SO2
Reduction/
High
Efficiency
 
Carbon
Level
515
MMT
Option
Cost
Categories
Million
1990$

Increased
Production
Costs
$
3,629
Investment
in
Energy
Reduction
4,986
Savings
from
Energy
Reduction
7,864
Net
Costs
$
751
Note:
These
costs
do
not
include
the
purchase
of
carbon
allowances
in
an
international
trading
program
The
electricity
production
system
compliance
costs
result
from
companies
installing
scrubbers,
greater
installation
of
natural
gas
combined­
cycle
units,
and
changes
in
the
dispatch
of
generation
units
 
there
is
less
use
of
coal­
fired
generation
and
more
use
of
units
powered
by
natural
gas.
Exhibit
3­
55
shows
the
differences
in
scrubber
installation
relative
to
the
Base
Case
and
the
50%
SO2
Reduction
in
2010
option.
Exhibit
3­
56
shows
the
changes
in
the
installation
of
natural
gas
combined­
cycle
capacity.
Exhibit
3­
57
provides
the
changes
in
electric
generation
that
occurs
under
each
of
the
control
cases
relative
to
the
Base
Case
and
the
50%
SO2
Reduction
in
2010
option
for
generation
units
that
use
coal
and
natural
gas/
oil.
Notably,
there
is
little
change
occurring
in
the
use
of
generation
units
using
any
other
fuels
in
these
combustion
options.

When
the
three
exhibits
below
are
examined
it
becomes
clear
that
to
achieve
the
50
Percent
SO2
Reduction
in
2010
under
a
single
control
alternative,
the
type
of
changes
that
the
power
industry
will
make
are
much
different
than
it
will
make
if
it
faces
a
combination
of
programs
to
lower
SO2
and
carbon
at
the
same
time.
In
the
combined
SO2/
carbon
reduction
options,
the
analysis
projects
that
the
electric
power
industry
will
rely
more
heavily
on
combined­
cycle
natural
gas
generation
than
scrubbers
for
lowering
SO2
emissions.
The
difference
in
this
investment
strategy
is
substantial,
because
each
GW
of
installed
scrubber
capacity
costs
about
$
150
million
to
install
(
in
1990$).

Exhibit
3­
55
Installation
of
New
Scrubber
Capacity
at
Coal­
Fired
Units
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
GW)
Options
2005
2007
2010
Base
Case
4
4
6
50%
SO2
Reduction
in
2010
61
68
82
50%
SO2
Reduction
/
Carbon
Level
of
567
MMT
in
2008
44
46
63
50%
So2
Reduction
/
HE
 
Carbon
Level
of
515
MMT
in
2008
38
39
45
3­
44
Exhibit
3­
56
Installation
of
Natural
Gas
Combined­
Cycle
Capacity
for
the
Base
Case,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
(
GW)
Baselines
2005
2007
2010
Base
Case
45
50
112
50%
SO2
Reduction
in
2010
48
52
116
50%
SO2
Reduction
/
Carbon
Level
of
567
MMT
in
2008
50
58
148
50%
SO2
Reduction
/
HE
 
Carbon
Level
of
515
MMT
in
2008
41
44
139
Exhibit
3­
57
Electric
Generation
Capacity
and
Production
for
Units
Using
Fossil
Fuels
for
the
Base
Call,
50%
SO2
Reduction,
and
Combined
SO2
/
Carbon
Reduction
Options
Fuel
Type
Capacity
by
Plant
Type
(
GW)
Generation
by
Plant
Type
(
Billion
kWh)
2005
2007
2010
2005
2007
2010
Base
Case
Coal
305
305
304
2,084
2,091
2,114
Oil/
Natural
Gas
240
250
282
561
626
759
50%
SO2
Reduction
Coal
304
303
301
2,057
2,060
2,038
Oil/
Natural
Gas
242
252
285
587
653
835
50%
SO2
Reduction
/
Carbon
Level
of
567
MMT
Coal
304
304
294
2,058
2,060
1,817
Oil/
Natural
Gas
241
251
291
586
656
1,054
50%
SO2
Reduction/
HE­
Carbon
Level
of
515
MMT
Coal
302
302
280
2,046
2,036
1,657
Oil/
Natural
Gas
228
228
260
526
540
972
Note:
Coal­
fired
units
are
assumed
to
lose
about
2
percent
of
their
capacity
when
they
install
scrubbers.
See
Exhibit
3­
55
to
assess
the
impact
of
scrubber
installation
on
the
capacity
over
time.
3­
45
Fossil
Fuel
Use
Exhibits
3­
58
through
3­
61
show
the
changes
in
coal
consumption
that
result
for
each
of
the
pollution
control
options
relative
to
the
Base
Case
and
the
50%
SO2
Reduction
in
2010
option.
Exhibit
3­
62
shows
the
changes
in
natural
gas
and
oil
use
by
the
electric
power
industry.

Although
total
coal
demand
drops
in
each
SO2/
carbon
reduction
option
from
the
Base
Case
levels,
in
Northern
Appalachia
and
the
Midwest,
there
is
actually
an
increase
in
demand.
This
occurs
for
largely
the
same
reason
that
it
did
in
the
SO2
reduction
options
in
the
preceding
section.
After
the
cost­
effective
SO2
reductions
from
the
use
of
western
coal
occurs,
the
next
most
economical
increment
is
to
install
scrubbers
that
use
higher
sulfur
coal
which
is
relatively
inexpensive
on
a
delivered
basis.

Exhibit
3­
58
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
Under
the
Base
Case
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
138
138
109
Central
and
Southern
Appalachia
185
186
213
Midwest
125
120
109
West
503
511
540
Central
West
and
Gulf
64
64
63
Total
1,015
1,019
1,034
Exhibit
3­
59
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
50
%
SO2
Reduction
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
145
145
142
Central
and
Southern
Appalachia
158
163
172
Midwest
153
150
140
West
489
489
486
Central
West
and
Gulf
62
63
49
Total
1,008
1,009
989
3­
46
Exhibit
3­
60
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
the
50
Percent
Reduction/
Carbon
Level
of
567
MMT
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
129
132
131
Central
and
Southern
Appalachia
174
173
146
Midwest
140
139
135
West
504
502
406
Central
West
and
Gulf
63
63
33
Total
1,010
1,009
852
Exhibit
3­
61
Coal
Consumption
by
the
Electric
Power
Industry
by
the
Major
Supply
Regions
for
the
50
Percent
Reduction/
High
Efficiency­
Carbon
Level
of
515
MMT
(
million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
124
124
122
Central
and
Southern
Appalachia
181
181
144
Midwest
131
130
116
West
504
499
373
Central
West
and
Gulf
63
63
21
Total
1,004
998
775
3­
47
Exhibit
3­
62
Natural
Gas
and
Oil
Consumption
under
the
Base
Case
and
Options
to
Lower
SO2
and
Carbon
Emissions
by
the
Electric
Power
Industry
Fuel
Type
Units
2005
2007
2010
Base
Case
Natural
Gas
Trillion
cubic
feet
4.6
5.2
5.3
Oil
Million
Barrels
21.3
21.5
0.0
50%
SO2
Reduction
Natural
Gas
Trillion
cubic
feet
4.8
5.4
5.8
Oil
Million
Barrels
21.0
21.0
0.0
50%
SO2
Reduction
/
Carbon
Level
of
567
MMT
in
2008
Natural
Gas
Trillion
cubic
feet
4.8
5.3
7.0
Oil
Million
Barrels
21.0
21.0
0.0
50%
SO2
Reduction
/
HE
­
Carbon
Level
of
515
MMT
in
2008
Natural
Gas
Trillion
cubic
feet
4.4
4.5
6.4
Oil
Million
Barrels
21.6
19.9
0.0