§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
1
The
updated
Chapter
B3:
Electricity
Market
Model
Analysis
presents
a
detailed
description
of
the
IPM
and
a
discussion
of
the
methodology
EPA
used
to
estimate
economic
impacts
using
the
IPM
(
see
DCN
5­
3002).

2
Note
that
the
number
of
Phase
II
facilities
and
their
capacity
and
operating
statistics
not
sample­
weighted.

3
The
capacity
presented
is
"
pre­
run"
capacity,
which
is
defined
as
the
generating
units
currently
operating
and
those
planned
units
committed
to
be
built
by
2013,
as
identified
by
the
IPM.
Pre­
run
capacity,
rather
than
base
case
capacity,
is
used
for
this
measure
because
the
base
case
reflects
certain
operating
decision
(
e.
g.,
repowering
decisions
or
facility
closures)
that
may
not
be
taken
in
the
postcompliance
scenario.
Therefore,
the
pre­
run
capacity
provides
a
more
useful
measure
of
the
percentage
of
currently
existing
capacity
estimated
to
be
affected
by
the
installation
of
a
recirculating
wet
cooling
tower
under
the
waterbody/
capcity­
based
option.

NODA
Version
 
March
12,
2003
B8­
1
Chapter
B8:
Alternative
Options
­

Electricity
Market
Model
Analysis
INTRODUCTION
This
chapter
presents
EPA's
electricity
market
model
analysis
using
ICF
Consulting's
Integrated
Planning
Model
(
IPM
®
)
for
the
waterbody/
capacity­
based
option.

B8­
1
OVERVIEW
OF
IPM
ANALYSIS
OF
ALTERNATIVE
OPTIONS
EPA
used
the
IPM,
an
integrated
energy
market
model,
to
analyze
two
potential
effects
of
the
waterbody/
capacity­
based
option:
(
1)
potential
energy
effects
at
the
national
and
regional
levels,
as
required
by
Executive
Order
13211
("
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use");
and
(
2)
potential
economic
impacts
on
in­
scope
facilities.
1
The
waterbody/
capacity­
based
option
has
more
stringent
compliance
technology
requirements
than
the
preferred
option.
Specifically,
for
the
NODA
analysis,
EPA
estimates
that
this
option
would
require
44
facilities
to
meet
performance
standards
for
impingement
mortality
and
entrainment
reduction
based
on
reducing
cooling
water
intake
flow
to
a
level
commensurate
with
that
which
can
be
attained
by
a
closed­
cycle,
recirculating
system.
2
For
this
analysis,
EPA
conservatively
assumed
that
all
44
facilities
would
install
a
recirculating
wet
cooling
tower.
The
compliance
requirements
for
all
other
facilities,
with
the
exception
of
some
minor
permitting
requirements,
are
identical
to
those
of
the
preferred
option.

EPA
mainly
relied
on
data
for
2013
in
the
analyses
of
the
waterbody/
capacity­
based
option
presented
in
this
chapter.
2013
was
chosen
to
represent
the
effects
of
the
alternative
option
for
a
typical
year
in
which
all
facilities
are
in
compliance
(
compliance
years
for
the
waterbody/
capacity­
based
option
are
2005
to
2013;
however,
for
the
purposes
of
this
analysis,
all
facilities
are
modeled
to
comply
by
2012).
EPA
also
analyzed
potential
market­
level
impacts
of
the
alternative
waterbody/
capacity­
based
option
for
a
year
within
the
compliance
period
during
which
some
Phase
II
facilities
experience
installation
downtimes.
This
analysis
used
output
from
model
run
year
2008
and
is
presented
in
Section
B8­
4
below.

The
framework
for
the
analysis
of
the
waterbody/
capacity­
based
option
is
identical
to
that
used
for
the
analysis
of
the
preferred
option
in
Chapter
B3:
Electricity
Market
Model
Analysis.
However,
it
should
be
noted
that
the
results
of
the
electricity
market
model
analysis
for
the
waterbody/
capacity­
based
option
cannot
be
directly
compared
to
the
results
of
the
analysis
for
the
preferred
option
(
presented
in
Chapter
B3)
because
(
1)
the
two
analyses
use
different
base
cases
with
different
assumptions
about
future
growth
in
electricity
demand
and
(
2)
the
analyses
use
output
for
different
model
run
years
(
2010
for
the
preferred
option
and
2013
for
the
waterbody/
capacity­
based
option).

Table
B8­
1
below
presents
the
number
and
steam
electric
capacity
of
facilities
in
each
NERC
region
that
EPA
estimated
would
install
a
cooling
tower
under
the
waterbody/
capacity­
based
option.
3
The
table
also
presents
total
capacity
for
each
region
and
the
percentage
of
total
capacity
in
each
region
that
was
costed
with
a
cooling
tower.
The
final
two
columns
CHAPTER
CONTENTS
B8­
1
Overview
of
IPM
Analysis
of
Alternative
Options
.
B8­
1
B8­
2
Market
Level
Analysis
for
2013
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B8­
2
B8­
3
Analysis
of
Phase
II
Facilities
for
2013
.
.
.
.
.
.
.
.
.
.
B8­
9
B8­
3.1
In­
Scope
Phase
II
Facilities
as
a
Group
.
.
.
.
.
.
.
B8­
9
B8­
3.2
Individual
Phase
II
Facilities
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B8­
15
B8­
4
Market
Level
Analysis
for
2008
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B8­
15
B8­
5
Uncertainties
and
Limitations
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B8­
20
References
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B8­
21
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
B8­
2
NODA
Version
 
March
12,
2003
present
the
total
capacity
of
all
facilities
subject
to
Phase
II
regulation
and
the
percentage
of
all
Phase
II
capacity
that
was
costed
with
a
cooling
tower.

Table
B8­
1:
Distribution
of
Cooling
Towers
for
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Region)

NERC
Region
Facilities
Estimated
to
Install
a
Cooling
Tower
Total
National
Capacity
(
MW)
CT
Capacity
as
%
of
National
Capacity
Total
Phase
II
Capacity
(
MW)
CT
Capacity
as
%
of
Phase
II
Capacity
Number
of
Facilities
Steam
Electric
Capacity
(
MW)

ECAR
­
­
135,107
0%
82,310
0%

ERCOT
2
1,254
83,948
1.5%
43,287
2.9%

FRCC
5
8,578
57,919
14.8%
28,353
30.3%

MAAC
10
9,421
72,414
13.0%
35,744
26.4%

MAIN
­
­
72,074
0%
40,595
0%

MAPP
­
­
42,206
0%
16,235
0%

NPCC
10
6,695
81,386
8.2%
36,684
18.3%

SERC
7
7,237
220,625
3.3%
107,507
6.7%

SPP
­
­
55,711
0%
20,471
0%

WSCC
8
11,980
184,226
6.5%
25,383
47.2%

Total
42
45,164
1,005,617
4.5%
436,569
10.3%

Source:
IPM
analysis:
IPM
pre­
run
data,
EPA
analysis
2003.

Overall,
EPA
conservatively
estimates
that
44
facilities
would
install
a
cooling
tower
under
this
option
(
rather
than
comply
by
demonstrating
that
they
can
achieve
comparable
reductions
in
impingement
mortality
and
entrainment
using
other,
lower­
cost
technologies).
Two
of
these
facilities
are
located
in
Hawaii
and
are
therefore
not
included
in
the
IPM
analysis.
Table
B8­
1
shows
that
the
42
facilities
estimated
to
install
a
cooling
tower
and
modeled
by
the
IPM
are
located
in
six
NERC
regions.
In
aggregate,
they
operate
45,164
MW
of
steam
electric
capacity
(
4.5
percent
of
the
total
capacity
and
10.3
percent
of
Phase
II
capacity).
FRCC
and
MAAC
are
projected
to
have
the
highest
percentage
of
total
capacity
that
was
costed
with
a
cooling
tower
(
14.8
and
13.0
percent,
respectively).
In
WSCC,
only
6.5
percent
of
total
capacity
is
costed
with
a
cooling
tower.
However,
these
eight
facilities
represent
47.2
percent
of
all
capacity
subject
to
the
Phase
II
rule
in
WSCC.
There
are
no
facilities
in
ECAR,
MAIN,
MAPP,
and
SPP
costed
with
a
cooling
tower
under
this
option.

B8­
2
MARKET
ANALYSIS
FOR
2013
This
section
presents
the
results
of
the
IPM
analysis
for
all
facilities
modeled
by
the
IPM.
The
market­
level
analysis
includes
results
for
all
generators
located
in
each
NERC
region
including
facilities
that
are
in­
scope
and
facilities
that
are
out­
of­
scope
of
Phase
II
regulation.
Market­
level
impacts
associated
with
the
waterbody/
capacity­
based
option
are
assessed
using
the
following
six
impact
measures:
(
1)
capacity
changes,
including
changes
in
existing
capacity,
new
additions,
repowering
additions,
and
closures;
(
2)
electricity
price
changes,
including
changes
in
energy
prices
and
capacity
prices;
(
3)
generation
changes;
(
4)
revenue
changes;
(
5)
cost
changes,
including
changes
in
fuel
costs,
variable
O&
M
costs,
fixed
O&
M
costs,
and
capital
costs;
(
6)
changes
in
pre­
tax
income,
defined
as
revenues
minus
total
costs;
and
(
7)
changes
in
variable
production
costs
per
MWh.
For
each
measure,
Table
B8­
2
presents
the
results
for
the
base
case
and
the
waterbody/
capacity­
based
option,
the
absolute
difference
between
the
two
cases,
and
the
percentage
difference.
A
detailed
description
of
each
of
the
impact
measures
discussed
below
is
presented
in
Section
B3­
3.1
of
Chapter
B3:
Electricity
Market
Model
Analysis.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B8­
3
Table
B8­
2:
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
National
Totals
(
1)
Total
Domestic
Capacity
(
MW)
994,126
993,604
(
522)
­
0.1%

(
1a)
Existing
786,374
780,274
(
6,100)
­
0.8%

(
1b)
New
Additions
182,493
183,708
1,214
0.7%

(
1c)
Repowering
Additions
25,258
29,622
4,364
17.3%
(
1d)
Closures
12,740
15,902
3,162
24.8%

(
2a)
Energy
Prices
($
2002/
MWh)
n/
a
n/
a
n/
a
n/
a
(
2b)
Capacity
Prices
($
2002/
KW/
yr)
n/
a
n/
a
n/
a
n/
a
(
3)
Generation
(
GWh)
4,603,844
4,604,637
793
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
166,539
$
168,246
$
1,707
1.0%

(
5)
Costs
(
Millions;
$
2002)
$
105,834
$
107,858
$
2,025
1.9%

(
5a)
Fuel
Cost
$
56,106
$
57,031
$
925
1.6%

(
5b)
Variable
O&
M
$
8,575
$
8,553
($
22)
­
0.3%

(
5c)
Fixed
O&
M
$
24,750
$
25,544
$
793
3.2%

(
5d)
Capital
Cost
$
16,402
$
16,730
$
328
2.0%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
60,705
$
60,388
($
317)
­
0.5%

(
7)
Variable
Production
Costs
($/
MWh)
$
13.42
$
13.59
$
0.16
1.2%

East
Central
Area
Reliability
Coordination
Agreement
(
ECAR)

(
1)
Total
Domestic
Capacity
(
MW)
133,048
133,048
0
0.0%

(
1a)
Existing
110,011
110,011
0
0.0%

(
1b)
New
Additions
22,967
22,967
0
0.0%

(
1c)
Repowering
Additions
70
70
0
0.0%
(
1d)
Closures
0
0
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
24.82
$
25.01
$
0.19
0.8%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
54.17
$
56.97
$
2.79
5.2%

(
3)
Generation
(
GWh)
701,807
702,751
944
0.1%

(
4)
Revenues
(
Millions;
$
2002)
$
24,848
$
25,137
$
289
1.2%

(
5)
Costs
(
Millions;
$
2002)
$
14,458
$
14,616
$
157
1.1%

(
5a)
Fuel
Cost
$
7,110
$
7,164
$
54
0.8%

(
5b)
Variable
O&
M
$
1,694
$
1,700
$
6
0.4%

(
5c)
Fixed
O&
M
$
3,723
$
3,818
$
95
2.6%

(
5d)
Capital
Cost
$
1,931
$
1,933
$
2
0.1%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
10,390
$
10,521
$
131
1.3%

(
7)
Variable
Production
Costs
($/
MWh)
$
12.55
$
12.61
$
0.07
0.5%

Electric
Reliability
Council
of
Texas
(
ERCOT)

(
1)
Total
Domestic
Capacity
(
MW)
86,609
86,589
(
20)
0.0%

(
1a)
Existing
69,832
69,315
(
517)
­
0.7%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
2:
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
B8­
4
NODA
Version
 
March
12,
2003
(
1b)
New
Additions
11,353
10,856
(
497)
­
4.4%

(
1c)
Repowering
Additions
5,425
6,418
993
18.3%
(
1d)
Closures
0
0
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
26.98
$
27.44
$
0.46
1.7%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
35.79
$
35.33
($
0.46)
­
1.3%

(
3)
Generation
(
GWh)
388,547
388,582
35
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
13,582
$
13,718
$
137
1.0%

(
5)
Costs
(
Millions;
$
2002)
$
9,926
$
10,068
$
142
1.4%

(
5a)
Fuel
Cost
$
6,104
$
6,190
$
86
1.4%

(
5b)
Variable
O&
M
$
754
$
753
$
0
0.0%

(
5c)
Fixed
O&
M
$
1,858
$
1,893
$
35
1.9%

(
5d)
Capital
Cost
$
1,211
$
1,232
$
21
1.8%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,656
$
3,651
($
5)
­
0.1%

(
7)
Variable
Production
Costs
($/
MWh)
$
17.65
$
17.87
$
0.22
1.2%

Florida
Reliability
Coordinating
Council
(
FRCC)

(
1)
Total
Domestic
Capacity
(
MW)
57,078
57,011
(
67)
­
0.1%

(
1a)
Existing
39,238
39,124
(
114)
­
0.3%

(
1b)
New
Additions
17,840
17,887
47
0.3%

(
1c)
Repowering
Additions
0
0
0
0.0%
(
1d)
Closures
812
812
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
29.88
$
31.03
$
1.14
3.8%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
42.38
$
39.70
($
2.69)
­
6.3%

(
3)
Generation
(
GWh)
218,165
218,162
(
2)
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
8,938
$
9,032
$
94
1.0%

(
5)
Costs
(
Millions;
$
2002)
$
6,669
$
6,885
$
217
3.3%

(
5a)
Fuel
Cost
$
3,747
$
3,818
$
71
1.9%

(
5b)
Variable
O&
M
$
408
$
410
$
1
0.3%

(
5c)
Fixed
O&
M
$
1,273
$
1,417
$
145
11.4%

(
5d)
Capital
Cost
$
1,240
$
1,240
$
0
0.0%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,270
$
2,146
($
123)
­
5.4%

(
7)
Variable
Production
Costs
($/
MWh)
$
19.05
$
19.38
$
0.33
1.7%

Mid­
Atlantic
Area
Council
(
MAAC)

(
1)
Total
Domestic
Capacity
(
MW)
71,441
71,228
(
213)
­
0.3%

(
1a)
Existing
57,426
57,237
(
189)
­
0.3%

(
1b)
New
Additions
12,357
12,340
(
18)
­
0.1%

(
1c)
Repowering
Additions
1,658
1,652
(
6)
­
0.4%
(
1d)
Closures
1,725
1,725
0
0.0%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
2:
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B8­
5
(
2a)
Energy
Prices
($
2002/
MWh)
$
27.96
$
28.35
$
0.38
1.4%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
52.52
$
52.56
$
0.04
0.1%

(
3)
Generation
(
GWh)
312,432
312,568
136
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
12,485
$
12,600
$
115
0.9%

(
5)
Costs
(
Millions;
$
2002)
$
7,670
$
7,985
$
314
4.1%

(
5a)
Fuel
Cost
$
3,687
$
3,747
$
59
1.6%

(
5b)
Variable
O&
M
$
633
$
631
($
2)
­
0.3%

(
5c)
Fixed
O&
M
$
2,165
$
2,414
$
249
11.5%

(
5d)
Capital
Cost
$
1,185
$
1,192
$
7
0.6%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
4,815
$
4,616
($
199)
­
4.1%

(
7)
Variable
Production
Costs
($/
MWh)
$
13.83
$
14.01
$
0.18
1.3%

Mid­
America
Interconnected
Network
(
MAIN)

(
1)
Total
Domestic
Capacity
(
MW)
66,420
66,385
(
35)
­
0.1%

(
1a)
Existing
51,122
50,110
(
1,012)
­
2.0%

(
1b)
New
Additions
15,298
16,275
977
6.4%

(
1c)
Repowering
Additions
0
0
0
0.0%
(
1d)
Closures
5,620
6,632
1,012
18.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
24.01
$
24.39
$
0.39
1.6%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
56.57
$
56.65
$
0.08
0.1%

(
3)
Generation
(
GWh)
307,839
306,011
(
1,828)
­
0.6%

(
4)
Revenues
(
Millions;
$
2002)
$
11,142
$
11,220
$
78
0.7%

(
5)
Costs
(
Millions;
$
2002)
$
6,743
$
6,758
$
15
0.2%

(
5a)
Fuel
Cost
$
3,358
$
3,424
$
65
1.9%

(
5b)
Variable
O&
M
$
622
$
619
($
3)
­
0.5%

(
5c)
Fixed
O&
M
$
1,724
$
1,653
($
71)
­
4.1%

(
5d)
Capital
Cost
$
1,039
$
1,062
$
23
2.2%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
4,399
$
4,462
$
63
1.4%

(
7)
Variable
Production
Costs
($/
MWh)
$
12.93
$
13.21
$
0.28
2.2%

Mid­
Continent
Area
Power
Pool
(
MAPP)

(
1)
Total
Domestic
Capacity
(
MW)
39,694
39,694
0
0.0%

(
1a)
Existing
32,668
32,668
0
0.0%

(
1b)
New
Additions
7,026
7,026
0
0.0%

(
1c)
Repowering
Additions
0
0
0
0.0%
(
1d)
Closures
476
476
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
22.53
$
22.95
$
0.42
1.8%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
55.99
$
55.95
($
0.04)
­
0.1%

(
3)
Generation
(
GWh)
201,006
201,091
85
0.0%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
2:
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
B8­
6
NODA
Version
 
March
12,
2003
(
4)
Revenues
(
Millions;
$
2002)
$
6,727
$
6,810
$
84
1.2%

(
5)
Costs
(
Millions;
$
2002)
$
4,011
$
4,041
$
29
0.7%

(
5a)
Fuel
Cost
$
1,982
$
1,989
$
7
0.3%

(
5b)
Variable
O&
M
$
406
$
407
$
1
0.1%

(
5c)
Fixed
O&
M
$
1,058
$
1,076
$
18
1.7%

(
5d)
Capital
Cost
$
565
$
569
$
4
0.7%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,715
$
2,770
$
55
2.0%

(
7)
Variable
Production
Costs
($/
MWh)
$
11.88
$
11.91
$
0.03
0.3%

Northeast
Power
Coordinating
Council
(
NPCC)

(
1)
Total
Domestic
Capacity
(
MW)
77,557
77,574
18
0.0%

(
1a)
Existing
59,678
59,462
(
217)
­
0.4%

(
1b)
New
Additions
7,325
7,381
56
0.8%

(
1c)
Repowering
Additions
10,554
10,732
179
1.7%
(
1d)
Closures
4,107
4,107
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
30.53
$
30.87
$
0.34
1.1%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
49.98
$
50.02
$
0.04
0.1%

(
3)
Generation
(
GWh)
311,569
312,033
463
0.1%

(
4)
Revenues
(
Millions;
$
2002)
$
13,102
$
13,225
$
124
0.9%

(
5)
Costs
(
Millions;
$
2002)
$
9,129
$
9,382
$
253
2.8%

(
5a)
Fuel
Cost
$
5,331
$
5,411
$
80
1.5%

(
5b)
Variable
O&
M
$
414
$
411
($
3)
­
0.8%

(
5c)
Fixed
O&
M
$
1,849
$
2,007
$
158
8.5%

(
5d)
Capital
Cost
$
1,535
$
1,554
$
19
1.2%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,973
$
3,843
($
129)
­
3.3%

(
7)
Variable
Production
Costs
($/
MWh)
$
18.44
$
18.66
$
0.22
1.2%

Southeastern
Electric
Reliability
Council
(
SERC)

(
1)
Total
Domestic
Capacity
(
MW)
220,567
220,497
(
70)
0.0%

(
1a)
Existing
164,552
164,421
(
131)
­
0.1%

(
1b)
New
Additions
56,015
56,076
61
0.1%

(
1c)
Repowering
Additions
0
0
0
0.0%
(
1d)
Closures
0
0
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
25.63
$
26.00
$
0.37
1.4%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
49.31
$
49.22
($
0.09)
­
0.2%

(
3)
Generation
(
GWh)
1,069,471
1,071,276
1,806
0.2%

(
4)
Revenues
(
Millions;
$
2002)
$
38,278
$
38,693
$
415
1.1%

(
5)
Costs
(
Millions;
$
2002)
$
24,452
$
24,836
$
385
1.6%

(
5a)
Fuel
Cost
$
12,571
$
12,731
$
159
1.3%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
2:
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B8­
7
(
5b)
Variable
O&
M
$
1,940
$
1,949
$
9
0.5%

(
5c)
Fixed
O&
M
$
5,558
$
5,739
$
181
3.3%

(
5d)
Capital
Cost
$
4,382
$
4,418
$
36
0.8%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
13,827
$
13,857
$
30
0.2%

(
7)
Variable
Production
Costs
($/
MWh)
$
13.57
$
13.70
$
0.13
1.0%

Southwest
Power
Pool
(
SPP)

(
1)
Total
Domestic
Capacity
(
MW)
55,711
55,712
2
0.0%

(
1a)
Existing
48,956
48,956
0
0.0%

(
1b)
New
Additions
6,755
6,756
2
0.0%

(
1c)
Repowering
Additions
0
0
0
0.0%
(
1d)
Closures
0
0
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
24.53
$
24.91
$
0.38
1.5%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
49.30
$
49.23
($
0.07)
­
0.1%

(
3)
Generation
(
GWh)
244,192
244,263
71
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
8,732
$
8,821
$
89
1.0%

(
5)
Costs
(
Millions;
$
2002)
$
5,072
$
5,115
$
43
0.8%

(
5a)
Fuel
Cost
$
3,051
$
3,072
$
21
0.7%

(
5b)
Variable
O&
M
$
441
$
442
$
1
0.2%

(
5c)
Fixed
O&
M
$
1,104
$
1,119
$
15
1.4%

(
5d)
Capital
Cost
$
476
$
482
$
6
1.4%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,661
$
3,706
$
45
1.2%

(
7)
Variable
Production
Costs
($/
MWh)
$
14.30
$
14.38
$
0.08
0.6%

Western
Systems
Coordinating
Council
(
WSCC)

(
1)
Total
Domestic
Capacity
(
MW)
186,001
185,866
(
135)
­
0.1%

(
1a)
Existing
152,891
148,972
(
3,920)
­
2.6%

(
1b)
New
Additions
25,558
26,144
586
2.3%

(
1c)
Repowering
Additions
7,552
10,750
3,198
42.4%
(
1d)
Closures
0
2,150
2,150
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
26.27
$
26.65
$
0.38
1.4%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
37.38
$
37.34
($
0.04)
­
0.1%

(
3)
Generation
(
GWh)
848,817
847,901
(
915)
­
0.1%

(
4)
Revenues
(
Millions;
$
2002)
$
28,705
$
28,989
$
284
1.0%

(
5)
Costs
(
Millions;
$
2002)
$
17,704
$
18,173
$
469
2.6%

(
5a)
Fuel
Cost
$
9,164
$
9,487
$
323
3.5%

(
5b)
Variable
O&
M
$
1,263
$
1,232
($
31)
­
2.5%

(
5c)
Fixed
O&
M
$
4,439
$
4,407
($
32)
­
0.7%

(
5d)
Capital
Cost
$
2,838
$
3,047
$
209
7.4%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
2:
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
by
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
B8­
8
NODA
Version
 
March
12,
2003
(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
11,001
$
10,816
($
185)
­
1.7%

(
7)
Variable
Production
Costs
($/
MWh)
$
12.28
$
12.64
$
0.36
2.9%

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
AEO
electricity
demand)
and
the
waterbody/
capacity­
based
option.

Summary
of
Market
Results
at
the
National
Level.
The
results
presented
in
Table
B8­
2
show
that
capacity
closures
would
increase
by
3,162
MW,
which
represents
less
than
0.4
percent
of
total
baseline
capacity.
An
increase
in
new
capacity
additions
(
1,214
MW)
and
repowering
additions
(
4,364
MW)
would
compensate
for
this
loss.
Total
domestic
capacity
would
decrease
by
0.1
percent
due
to
other
capacity
losses,
primarily
the
energy
penalties
associated
with
the
installation
of
cooling
towers.
Revenues
are
expected
to
increase
by
$
1.7
billion
(
1.0
percent)
under
this
option.
However,
total
costs
would
increase
by
a
greater
amount,
$
2.0
billion,
leading
to
a
loss
in
total
pre­
tax
income
of
$
317
million
(
0.5
percent).
The
increase
in
cost
is
driven
by
higher
fuel
cost
(
by
1.6
percent)
and
fixed
O&
M
costs
(
by
3.2
percent)
which
include
the
annualized
capital
cost
of
compliance
with
the
waterbody/
capacity­
based
option.

Summary
of
Market
Results
at
the
Regional
Level.
At
the
regional
level,
potential
impacts
under
the
waterbody/
capacitybased
option
vary
by
NERC
region.
Two
principal
factors
appear
to
influence
the
results:
(
1)
the
requirement
for
facilities
in
some
regions
to
install
relatively
high­
cost
recirculating
cooling
towers
and
(
2)
incremental
capacity
closures.
Both
factors
are
discussed
below:

<
Regions
with
cooling
towers.
Six
of
the
10
analyzed
NERC
regions
(
ERCOT,
FRCC,
MAAC,
MPCC,
SERC,
and
WSCC)
have
facilities
costed
with
a
cooling
tower
under
the
waterbody/
capacity­
based
option.
The
remaining
four
regions
(
ECAR,
MAIN,
MAPP,
SPP)
do
not
have
any
facilities
with
a
cooling
tower
requirement
(
see
also
Table
B8­
1
above).
In
general,
the
largest
increases
in
costs
as
a
result
of
this
option
would
be
to
fixed
O&
M
and
fuel
costs
in
regions
where
facilities
have
to
install
cooling
towers
under
this
option.
These
findings
are
not
surprising.
Capital
costs
of
compliance
are
modeled
as
fixed
O&
M
costs,
and
cooling
towers
have
relatively
high
capital
costs
compared
to
other
compliance
technologies.
In
addition,
the
energy
penalty
associated
with
the
operation
of
cooling
towers
would
lead
to
an
increase
in
the
facility's
heat
rate:
more
fuel
would
be
required
to
generate
the
same
quantity
of
electricity.
The
increased
costs
of
generation
in
these
regions
would
lead
to
a
rise
in
energy
prices,
which
in
turn
would
increase
revenues.
However,
pre­
tax
income
would
decrease
as
the
increased
cost
of
production
would
more
than
offset
increased
revenues
associated
with
higher
energy
prices.
<
Incremental
capacity
closures.
The
early
retirement
of
capacity
and
the
simultaneous
addition
of
new
or
repowered
capacity
to
replace
the
retired
capacity
have
the
potential
to
change
regional
cost
accounts,
depending
on
the
relative
efficiencies
of
the
retired
and
the
new
capacities.
Under
the
waterbody/
capacity­
based
option,
two
regions
(
MAIN
and
WSCC)
experience
closures
of
nuclear
capacity.
Both
regions
are
projected
to
experience
decreases
in
total
fixed
O&
M
because
nuclear
facilities,
in
general,
have
substantially
higher
fixed
O&
M
costs
when
compared
to
other
plant
types.
As
a
result,
at
the
regional
level,
decreases
in
these
costs
due
to
the
retirement
of
nuclear
capacity
would
more
than
offset
the
increases
associated
with
compliance
costs.
These
retirements
would
also
contribute
to
an
increase
in
total
fuel
costs,
as
nuclear
facilities
have
lower
average
fuel
costs
than
facilities
fired
by
other
fuels.
These
regions
would
also
experience
increases
in
energy
prices
and
revenues,
as
facilities
pass
a
portion
of
the
increased
fuel
and
compliance
costs
on
to
consumers.

Notable
results
of
EPA's
analysis
of
the
waterbody/
capacity­
based
option
for
the
10
NERC
regions
are:
<
ECAR,
MAPP,
and
SPP
do
not
have
facilities
estimated
to
install
cooling
towers.
These
three
regions
also
do
not
experience
incremental
closures
due
to
the
waterbody/
capacity­
based
option.
As
a
result,
changes
in
their
operating
conditions
are
generally
smaller
than
for
the
other
seven
regions.
In
all
three
regions,
prices
would
increase,
leading
to
increases
in
revenues
of
between
1.0
and
1.2
percent.
Fixed
costs
would
also
increase,
but
the
rise
in
overall
costs
would
be
smaller
than
the
increase
in
revenues,
leading
to
higher
pre­
tax
income
(
between
1.2
and
2.0
percent).
Changes
in
variable
production
costs
in
these
regions
are
less
than
1.0
percent
and
smaller
than
in
the
other
seven
regions.
<
MAIN
also
does
not
have
facilities
estimated
to
install
cooling
towers.
However,
MAIN
would
experience
an
increase
in
post­
compliance
capacity
retirements
due
to
two
nuclear
facilities
reaching
the
end
of
their
nuclear
operating
licenses.
In
the
base
case,
these
facilities
would
have
extended
their
licenses
and
continued
operation.
Under
the
waterbody/
capacity­
based
option,
however,
these
facilities
would
retire
part
or
all
of
their
capacity
by
2013.
The
resulting
1,012
MW
increase
in
capacity
closures
(
1.5
percent
of
baseline
capacity)
would
be
offset
in
part
by
a
977
MW
increase
in
new
capacity
additions.
Since
nuclear
facilities
have
substantially
higher
fixed
O&
M
costs
when
compared
to
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
4
Note
that
of
the
540
surveyed
facilities
subject
to
the
section
316(
b)
Phase
II
Rule,
nine
are
not
modeled
in
the
IPM.
Three
facilities
are
in
Hawaii,
one
is
in
Alaska.
Neither
state
is
represented
in
the
IPM.
One
facility
is
identified
as
an
"
Unspecified
Resource"
and
does
not
report
on
any
EIA
forms.
Four
facilities
are
on­
site
generators
that
do
not
provide
electricity
to
the
grid.
Note
that
the
facility­
level
numbers
presented
in
this
section
are
not
sample­
weighted.

NODA
Version
 
March
12,
2003
B8­
9
other
plant
types,
the
closure
of
nuclear
capacity
in
this
region
would
result
in
a
4.1
percent
decrease
in
post­
compliance
fixed
O&
M
costs.
This
closure
would
also
contribute
to
a
1.9
percent
increase
in
average
fuel
costs
and
a
2.2
percent
increase
in
variable
production
cost
per
MWh
(
the
second
highest
of
any
region),
as
nuclear
facilities
have
lower
fuel
costs
than
most
other
plant
types.
While
revenues
in
MAIN
would
only
increase
by
0.7
percent
in
response
to
the
1.6
percent
increase
in
energy
prices,
pre­
tax
income
would
increase
by
1.4
percent,
due
in
part
to
the
reduction
in
fixed
costs.
<
FRCC
and
MAAC
would
experience
the
largest
increases
in
fixed
O&
M
costs
(
11.4
and
11.5
percent,
respectively)
as
both
regions
would
incur
relatively
high
compliance
costs
associated
with
the
installation
of
cooling
towers.
Fuel
costs
in
these
regions
would
increase
due
to
the
energy
penalty
also
associated
with
the
operation
of
cooling
towers.
These
increased
costs
would
contribute
to
an
increase
in
energy
prices
of
3.8
percent
in
FRCC
(
the
highest
of
any
region)
and
1.4
percent
in
MAAC.
While
these
higher
energy
prices
would
lead
to
increases
in
revenues
of
approximately
one
percent,
both
regions
would
experience
a
decrease
in
pre­
tax
income
in
excess
of
four
percent
(
the
largest
of
all
regions)
as
the
increased
cost
of
production
would
more
than
offset
increased
revenues.
<
In
ERCOT,
NPCC
and
SERC,
changes
similar
to
those
in
FRCC
and
MAAC
would
occur,
but
the
magnitude
of
these
changes
would
generally
be
smaller
as
total
compliance
costs
in
NPCC
and
ERCOT
are
lower.
SERC
would
experience
an
0.2
increase
in
pre­
tax
income
as
a
result
of
a
larger
increase
in
revenues
($
415
million)
compared
to
costs
($
385
million).
<
WSCC,
besides
MAIN,
is
the
only
region
to
experience
incremental
closures
under
the
waterbody/
capacity­
based
option:
one
large
nuclear
facility
with
a
capacity
of
2,150
MW
is
expected
to
close.
An
increase
in
repowering
additions
of
3,198
MW
would
compensate
for
this
loss.
Similar
to
MAIN,
the
closure
of
nuclear
capacity
would
result
in
a
decrease
in
fixed
O&
M
costs
and
an
increase
in
fuel
costs.
However,
unlike
MAIN,
which
does
not
have
any
facilities
with
a
cooling
tower
requirement,
eight
facilities
in
WSCC
are
estimated
to
install
cooling
towers
under
this
option.
The
relatively
high
cost
of
these
cooling
towers
would
offset
the
reduction
in
total
fixed
O&
M
costs
while
the
energy
penalties
associated
with
their
operation
would
contribute
to
the
3.5
percent
increase
in
fuel
costs
and
a
2.9
percent
increases
in
variable
production
cost
per
MWh
(
the
highest
of
any
region).
Energy
prices
would
increase,
leading
to
a
1.0
percent
increase
in
revenues.
Despite
this
increase,
pre­
tax
income
would
decline
as
a
result
of
the
rise
in
fuel
costs
and
a
7.5
percent
increase
in
capital
costs
associated
with
repowering
additions
and
other
investments.

B8­
3
ANALYSIS
OF
PHASE
II
FACILITIES
FOR
2013
This
section
presents
the
results
of
the
IPM
analysis
for
the
in­
scope
Phase
II
facilities
that
are
modeled
by
the
IPM.
4
Nine
of
the
531
Phase
II
facilities
are
closures
in
the
base
case,
and
12
facilities
are
closures
under
the
waterbody/
capacity­
based
option.
These
facilities
are
not
represented
in
the
results
described
in
this
section.

EPA
used
the
IPM
results
to
analyze
impacts
on
Phase
II
facilities
at
two
levels:
(
1)
potential
changes
in
the
economic
and
operational
characteristics
of
the
in­
scope
Phase
II
facilities
as
a
group
and
(
2)
potential
changes
to
individual
facilities
within
the
group
of
Phase
II
facilities.

B8­
3.1
In­
Scope
Phase
II
Facilities
as
a
Group
This
section
presents
the
analysis
of
the
potential
impacts
of
the
alternative
waterbody/
capacity­
based
option
on
the
in­
scope
Phase
II
facilities
as
a
group.
This
analysis
is
similar
to
the
market
level
analysis
described
above
but
is
limited
to
facilities
subject
to
the
requirements
of
the
section
316(
b)
rule.
Table
B8­
3
presents
the
impact
measures
for
the
in­
scope
Phase
II
facilities
as
a
group:
(
1)
capacity
changes,
including
changes
in
the
number
and
capacity
of
closure
facilities;
(
2)
generation
changes;
(
3)
revenue
changes;
(
4)
cost
changes,
including
changes
in
fuel
costs,
variable
O&
M
costs,
fixed
O&
M
costs,
and
capital
costs;
(
5)
changes
in
pre­
tax
income,
defined
as
revenues
minus
total
costs;
and
(
6)
changes
in
variable
production
costs
per
MWh
of
generation,
where
variable
production
cost
is
defined
as
the
sum
of
fuel
cost
and
variable
O&
M
cost.
For
each
measure,
the
table
presents
the
results
for
the
base
case
and
the
waterbody/
capacity­
based
option,
the
absolute
difference
between
the
two
cases,
and
the
percentage
difference.
A
detailed
description
of
each
of
the
impact
measures
discussed
below
is
presented
in
Section
B3­
3.2
of
Chapter
B3:
Electricity
Market
Model
Analysis.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
B8­
10
NODA
Version
 
March
12,
2003
Table
B8­
3:
Facility­
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
National
Totals
(
1)
Total
Domestic
Capacity
(
MW)
432,776
428,165
(
4,611)
­
1.1%

(
1a)
Closures
­
Number
of
Facilities
9
12
3
33.3%

(
1b)
Closures
­
Capacity
(
MW)
12,741
15,903
3,162
24.8%

(
2)
Generation
(
GWh)
2,319,049
2,270,627
(
48,422)
­
2.1%

(
3)
Revenues
(
Millions;
$
2002)
$
80,517
$
79,758
($
759)
­
0.9%

(
4)
Costs
(
Millions;
$
2002)
$
47,819
$
47,759
($
60)
­
0.1%

(
4a)
Fuel
Cost
$
24,214
$
23,686
($
528)
­
2.2%

(
4b)
Variable
O&
M
$
5,171
$
5,088
($
83)
­
1.6%

(
4c)
Fixed
O&
M
$
15,103
$
15,851
$
748
5.0%

(
4d)
Capital
Cost
$
3,331
$
3,133
($
198)
­
5.9%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
32,698
$
31,999
($
699)
­
2.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.67
$
12.67
$
0.00
0.0%

East
Central
Area
Reliability
Coordination
Agreement
(
ECAR)

(
1)
Total
Domestic
Capacity
(
MW)
82,258
82,258
0
0.0%

(
1a)
Closures
­
Number
of
Facilities
0
0
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
1
1
0
0.0%

(
2)
Generation
(
GWh)
537,822
538,244
422
0.1%

(
3)
Revenues
(
Millions;
$
2002)
$
17,747
$
17,947
$
200
1.1%

(
4)
Costs
(
Millions;
$
2002)
$
9,822
$
9,944
$
123
1.3%

(
4a)
Fuel
Cost
$
5,052
$
5,071
$
19
0.4%

(
4b)
Variable
O&
M
$
1,320
$
1,326
$
6
0.4%

(
4c)
Fixed
O&
M
$
2,991
$
3,085
$
94
3.1%

(
4d)
Capital
Cost
$
458
$
463
$
4
0.9%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
7,926
$
8,003
$
77
1.0%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.85
$
11.88
$
0.04
0.3%

Electric
Reliability
Council
of
Texas
(
ERCOT)

(
1)
Total
Domestic
Capacity
(
MW)
44,400
44,419
19
0.0%

(
1a)
Closures
­
Number
of
Facilities
0
0
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
0
0
0
0.0%

(
2)
Generation
(
GWh)
158,578
157,576
(
1,001)
­
0.6%

(
3)
Revenues
(
Millions;
$
2002)
$
5,867
$
5,882
$
15
0.3%

(
4)
Costs
(
Millions;
$
2002)
$
3,894
$
3,919
$
25
0.6%

(
4a)
Fuel
Cost
$
2,034
$
2,014
($
20)
­
1.0%

(
4b)
Variable
O&
M
$
423
$
421
($
2)
­
0.5%

(
4c)
Fixed
O&
M
$
1,196
$
1,235
$
38
3.2%

(
4d)
Capital
Cost
$
240
$
249
$
9
3.7%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
3:
Facility­
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B8­
11
(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,973
$
1,963
($
10)
­
0.5%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
15.49
$
15.46
($
0.04)
­
0.3%

Florida
Reliability
Coordinating
Council
(
FRCC)

(
1)
Total
Domestic
Capacity
(
MW)
27,513
27,399
(
114)
­
0.4%

(
1a)
Closures
­
Number
of
Facilities
0
0
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
812
812
0
0.0%

(
2)
Generation
(
GWh)
80,229
77,384
(
2,845)
­
3.5%

(
3)
Revenues
(
Millions;
$
2002)
$
3,532
$
3,469
($
63)
­
1.8%

(
4)
Costs
(
Millions;
$
2002)
$
1,943
$
2,047
$
104
5.3%

(
4a)
Fuel
Cost
$
1,035
$
998
($
37)
­
3.6%

(
4b)
Variable
O&
M
$
196
$
194
($
2)
­
1.2%

(
4c)
Fixed
O&
M
$
682
$
826
$
144
21.1%

(
4d)
Capital
Cost
$
30
$
29
($
1)
­
2.1%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,589
$
1,422
($
167)
­
10.5%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
15.35
$
15.41
$
0.05
0.3%

Mid­
Atlantic
Area
Council
(
MAAC)

(
1)
Total
Domestic
Capacity
(
MW)
34,696
34,501
(
195)
­
0.6%

(
1a)
Closures
­
Number
of
Facilities
1
1
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
1,725
1,725
0
0.0%

(
2)
Generation
(
GWh)
176,909
175,119
(
1,790)
­
1.0%

(
3)
Revenues
(
Millions;
$
2002)
$
6,720
$
6,737
$
17
0.3%

(
4)
Costs
(
Millions;
$
2002)
$
3,794
$
4,038
$
244
6.4%

(
4a)
Fuel
Cost
$
1,688
$
1,686
($
1)
­
0.1%

(
4b)
Variable
O&
M
$
366
$
362
($
4)
­
1.1%

(
4c)
Fixed
O&
M
$
1,509
$
1,757
$
248
16.4%

(
4d)
Capital
Cost
$
232
$
233
$
1
0.5%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,926
$
2,700
($
226)
­
7.7%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.61
$
11.69
$
0.09
0.8%

Mid­
America
Interconnected
Network
(
MAIN)

(
1)
Total
Domestic
Capacity
(
MW)
34,944
33,932
(
1,012)
­
2.9%

(
1a)
Closures
­
Number
of
Facilities
3
5
2
66.7%

(
1b)
Closures
­
Capacity
(
MW)
5,620
6,632
1,012
18.0%

(
2)
Generation
(
GWh)
219,900
214,425
(
5,475)
­
2.5%

(
3)
Revenues
(
Millions;
$
2002)
$
7,133
$
7,030
($
103)
­
1.4%

(
4)
Costs
(
Millions;
$
2002)
$
3,965
$
3,813
($
151)
­
3.8%

(
4a)
Fuel
Cost
$
2,000
$
1,976
($
24)
­
1.2%

(
4b)
Variable
O&
M
$
498
$
489
($
9)
­
1.9%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
3:
Facility­
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
B8­
12
NODA
Version
 
March
12,
2003
(
4c)
Fixed
O&
M
$
1,334
$
1,255
($
79)
­
5.9%

(
4d)
Capital
Cost
$
133
$
94
($
39)
­
29.4%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,168
$
3,217
$
48
1.5%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.36
$
11.49
$
0.13
1.2%

Mid­
Continent
Area
Power
Pool
(
MAPP)

(
1)
Total
Domestic
Capacity
(
MW)
15,723
15,723
0
0.0%

(
1a)
Closures
­
Number
of
Facilities
1
1
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
476
476
0
0.0%

(
2)
Generation
(
GWh)
111,302
111,376
74
0.1%

(
3)
Revenues
(
Millions;
$
2002)
$
3,331
$
3,378
$
46
1.4%

(
4)
Costs
(
Millions;
$
2002)
$
1,964
$
1,983
$
19
1.0%

(
4a)
Fuel
Cost
$
1,016
$
1,017
$
1
0.1%

(
4b)
Variable
O&
M
$
229
$
230
$
0
0.2%

(
4c)
Fixed
O&
M
$
599
$
617
$
18
2.9%

(
4d)
Capital
Cost
$
120
$
120
$
0
0.0%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,367
$
1,395
$
27
2.0%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.19
$
11.19
$
0.00
0.0%

Northeast
Power
Coordinating
Council
(
NPCC)

(
1)
Total
Domestic
Capacity
(
MW)
37,219
37,139
(
81)
­
0.2%

(
1a)
Closures
­
Number
of
Facilities
4
4
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
4,107
4,107
0
0.0%

(
2)
Generation
(
GWh)
159,927
159,005
(
921)
­
0.6%

(
3)
Revenues
(
Millions;
$
2002)
$
6,635
$
6,653
$
18
0.3%

(
4)
Costs
(
Millions;
$
2002)
$
4,964
$
5,136
$
172
3.5%

(
4a)
Fuel
Cost
$
2,681
$
2,694
$
13
0.5%

(
4b)
Variable
O&
M
$
269
$
264
($
5)
­
1.8%

(
4c)
Fixed
O&
M
$
1,238
$
1,396
$
157
12.7%

(
4d)
Capital
Cost
$
774
$
782
$
7
0.9%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,671
$
1,518
($
154)
­
9.2%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
18.45
$
18.61
$
0.16
0.8%

Southeastern
Electric
Reliability
Council
(
SERC)

(
1)
Total
Domestic
Capacity
(
MW)
107,458
107,327
(
131)
­
0.1%

(
1a)
Closures
­
Number
of
Facilities
0
0
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
0
0
0
0.0%

(
2)
Generation
(
GWh)
639,694
640,168
473
0.1%

(
3)
Revenues
(
Millions;
$
2002)
$
21,421
$
21,644
$
222
1.0%

(
4)
Costs
(
Millions;
$
2002)
$
12,075
$
12,305
$
230
1.9%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
3:
Facility­
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
NERC
Regions;
2013)

Economic
Measures
Base
Case
WB/
C­
Based
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B8­
13
(
4a)
Fuel
Cost
$
5,878
$
5,925
$
47
0.8%

(
4b)
Variable
O&
M
$
1,370
$
1,377
$
7
0.5%

(
4c)
Fixed
O&
M
$
3,984
$
4,158
$
174
4.4%

(
4d)
Capital
Cost
$
842
$
845
$
3
0.3%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
9,347
$
9,339
($
8)
­
0.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.33
$
11.41
$
0.08
0.7%

Southwest
Power
Pool
(
SPP)

(
1)
Total
Domestic
Capacity
(
MW)
20,471
20,471
0
0.0%

(
1a)
Closures
­
Number
of
Facilities
0
0
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
0
0
0
0.0%

(
2)
Generation
(
GWh)
109,024
108,345
(
679)
­
0.6%

(
3)
Revenues
(
Millions;
$
2002)
$
3,595
$
3,616
$
20
0.6%

(
4)
Costs
(
Millions;
$
2002)
$
1,878
$
1,873
($
5)
­
0.3%

(
4a)
Fuel
Cost
$
1,076
$
1,059
($
16)
­
1.5%

(
4b)
Variable
O&
M
$
240
$
240
($
1)
­
0.2%

(
4c)
Fixed
O&
M
$
557
$
570
$
13
2.4%

(
4d)
Capital
Cost
$
5
$
4
($
1)
­
22.2%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,718
$
1,742
$
25
1.4%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.07
$
11.99
($
0.08)
­
0.7%

Western
Systems
Coordinating
Council
(
WSCC)

(
1)
Total
Domestic
Capacity
(
MW)
28,093
24,997
(
3,096)
­
11.0%

(
1a)
Closures
­
Number
of
Facilities
0
1
1
n/
a
(
1b)
Closures
­
Capacity
(
MW)
0
2,150
2,150
n/
a
(
2)
Generation
(
GWh)
125,663
88,984
(
36,680)
­
29.2%

(
3)
Revenues
(
Millions;
$
2002)
$
4,534
$
3,402
($
1,132)
­
25.0%

(
4)
Costs
(
Millions;
$
2002)
$
3,522
$
2,701
($
821)
­
23.3%

(
4a)
Fuel
Cost
$
1,753
$
1,246
($
508)
­
29.0%

(
4b)
Variable
O&
M
$
258
$
186
($
73)
­
28.1%

(
4c)
Fixed
O&
M
$
1,013
$
953
($
60)
­
5.9%

(
4d)
Capital
Cost
$
497
$
316
($
181)
­
36.4%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,012
$
701
($
311)
­
30.7%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
16.01
$
16.09
$
0.08
0.5%

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
AEO
electricity
demand)
and
the
waterbody/
capacity­
based
option.

Summary
of
Phase
II
Facility
Results
at
the
National
Level.
The
results
presented
in
Table
B8­
3
show
that
under
the
alternative
waterbody/
capacity­
based
option
capacity
closures
within
the
group
of
Phase
II
facilities
would
increase
by
3,162
MW,
which
represents
less
than
one
percent
of
baseline
Phase
II
capacity.
This
increase
in
capacity
closures
would
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
B8­
14
NODA
Version
 
March
12,
2003
contribute
to
a
4,611
MW
decrease
in
total
Phase
II
capacity
(
1.1
percent
of
baseline
capacity).
The
balance
of
this
reduction
in
total
Phase
II
capacity
is
largely
due
to
energy
penalties
associated
with
the
operation
of
cooling
towers.
Total
Phase
II
generation
would
decrease
by
2.1
percent
under
this
option
(
in
part
due
to
the
reduction
in
total
capacity),
leading
to
a
reduction
in
Phase
II
fuel
costs,
variable
O&
M
costs,
and
revenues.
Revenues
would
decrease
by
a
smaller
amount
than
generation
(­
0.9
percent),
because
of
price
increases
in
many
regions.
Fixed
O&
M
costs,
which
include
the
annualized
capital
cost
of
compliance
with
the
waterbody/
capacity­
based
option,
would
increase
by
5.0
percent.
Overall,
revenues
would
decrease
by
$
759
million
and
costs
would
decrease
by
$
60
million.
Pre­
tax
income
for
the
group
of
Phase
II
facilities
would
be
reduced
by
approximately
$
700
million
(
2.1
percent)
under
this
option
compared
to
a
reduction
of
$
317
million
(
0.5
percent)
at
the
market
level.

Summary
of
Phase
II
Facility
Results
at
the
Regional
Level.
At
the
regional
level,
potential
impacts
under
the
waterbody/
capacity­
based
option
vary
by
NERC
region.
Two
principal
factors
appear
to
influence
the
results:
(
1)
the
requirement
for
facilities
in
some
regions
to
install
relatively
high­
cost
recirculating
cooling
towers
and
(
2)
incremental
capacity
closures.
For
a
discussion
of
these
factors,
please
refer
to
section
B8­
2
above.
Notable
results
of
the
regional
analysis
of
impacts
on
the
group
of
Phase
II
facilities
under
the
waterbody/
capacity­
based
option
are:
<
No
Phase
II
facilities
in
ECAR,
MAPP,
and
SPP
are
estimated
to
install
cooling
towers.
These
three
regions
also
do
not
experience
incremental
closures
due
to
the
waterbody/
capacity­
based
option.
As
a
result,
changes
in
their
operating
conditions
are
generally
smaller
than
for
the
other
NERC
regions.
<
MAIN
also
does
not
have
facilities
estimated
to
install
cooling
towers.
However,
two
facilities
in
MAIN,
accounting
for
1,012
MW,
would
close
under
this
option.
Both
are
nuclear
facilities
which,
in
the
base
case,
would
have
extended
their
licenses
and
continued
operation.
Under
the
waterbody/
capacity­
based
option,
however,
these
facilities
would
retire
part
or
all
of
their
capacity
by
2013.
As
a
result
of
this
net
loss
in
capacity,
generation,
revenues,
and
all
cost
accounts
for
Phase
II
facilities
in
MAIN
would
experience
reductions.
However,
costs
decrease
more
than
revenues,
resulting
in
a
small
increase
in
pre­
tax
income.
Since
nuclear
facilities
have
substantially
lower
fuel
and
variable
O&
M
costs
when
compared
to
other
plant
types,
the
closure
of
nuclear
capacity
in
this
region
would
result
in
an
increase
in
variable
production
cost
of
1.2
percent.
<
FRCC
and
MAAC
would
experience
the
largest
increases
in
fixed
O&
M
costs
(
21.1
and
16.4
percent,
respectively)
as
more
than
26
percent
of
Phase
II
capacity
in
each
region
would
install
cooling
towers
under
this
option
leading
to
relatively
high
compliance
costs.
Phase
II
facilities
in
these
regions
would
experience
decreased
generation
and
revenues
when
compared
to
market
level
trends
as
the
group
of
Phase
II
facilities
becomes
less
competitive
due
to
the
costs
of
compliance.
At
the
market
level,
revenues
increase,
indicating
that
facilities
not
subject
to
Phase
II
regulation
benefit
under
this
option.
Similarly,
reductions
in
pre­
tax
income
for
the
group
of
Phase
II
facilities
in
the
two
regions
exceed
losses
at
the
market.
<
In
ERCOT,
NPCC,
and
SERC,
changes
similar
to
those
in
FRCC
and
MAAC
would
occur,
but
the
magnitude
of
these
changes
would
generally
be
smaller
because
the
percent
of
Phase
II
capacity
installing
cooling
towers
and
total
compliance
costs
in
these
regions
are
lower.
<
The
group
of
Phase
II
facilities
in
WSCC
would
experience
larger
impacts
than
any
other
region
under
the
waterbody/
capacity­
based
option.
This
is
largely
due
to
the
fact
that
47.2
percent
of
Phase
II
capacity
in
WSCC
is
projected
to
install
cooling
towers
under
this
option.
One
nuclear
facility
would
close,
contributing
to
an
11
percent
loss
of
total
Phase
II
capacity
in
the
region.
Generation
would
decrease
by
29.2
percent.
Similarly,
revenues
and
all
cost
accounts,
except
for
fixed
O&
M
cost,
would
decrease
by
over
20
percent.
Fixed
O&
M
costs
decrease
by
a
small
amount
because
of
the
relatively
high
compliance
costs
associated
with
the
installation
of
eight
cooling
towers
in
this
region.

B8­
3.2
Individual
Phase
II
Facilities
In
addition
to
effects
of
the
waterbody/
capacity­
based
option
on
the
in­
scope
Phase
II
facilities
as
a
group,
there
may
be
shifts
in
economic
performance
among
individual
facilities
subject
to
Phase
II
regulation.
To
assess
such
potential
shifts,
EPA
analyzed
the
same
facility­
specific
changes
as
for
the
preferred
option:
changes
in
(
1)
capacity
utilization
(
defined
as
generation
divided
by
capacity
times
8,760);
(
2)
generation;
(
3)
revenue;
(
4)
variable
production
costs
per
MWh
of
generation
(
defined
as
variable
O&
M
cost
plus
fuel
cost
divided
by
generation);
(
5)
fuel
cost
per
MWh
of
generation;
and
(
6)
pre­
tax
income.
For
each
measure,
EPA
determined
the
number
of
Phase
II
facilities
that
experience
no
changes,
or
an
increase
or
a
reduction
within
three
ranges:
1
percent
or
less,
1
to
3
percent,
and
3
percent
or
more.

Table
B8­
4
presents
the
total
number
of
Phase
II
facilities
with
different
degrees
of
change
in
each
of
these
measures.
This
table
excludes
30
in­
scope
facilities
with
significant
status
changes
(
nine
facilities
are
baseline
closures,
three
facilities
are
policy
closures,
and
18
facilities
changed
their
repowering
decision
between
the
base
case
and
the
policy
case).
These
facilities
are
either
not
operating
at
all
in
either
the
base
case
or
the
post­
compliance
case,
or
they
experience
fundamental
changes
in
the
type
of
units
they
operate;
therefore,
the
measures
presented
below
would
not
be
meaningful
for
these
facilities.
In
addition,
the
changes
in
production
cost
per
MWh
and
fuel
cost
per
MWh
could
not
be
developed
for
62
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B8­
15
facilities
with
zero
generation
in
either
the
base
case
or
post­
compliance
scenario.
For
these
facilities,
the
change
in
production
cost
per
MWh
and
fuel
cost
per
MWh
is
indicated
as
"
n/
a."

Table
B8­
4:
Number
of
Individual
Phase
II
Facilities
with
Operational
Changes
(
2013)

Economic
Measures
Reduction
Increase
No
Change
N/
A
</=
1%
1­
3%
>
3%
</=
1%
1­
3%
>
3%

(
1)
Change
in
Capacity
Utilization
4
11
21
6
14
15
430
­

(
2)
Change
in
Generation
7
24
37
5
7
23
398
­

(
3)
Change
in
Revenues
56
13
41
108
247
28
8
­

(
4)
Change
in
Variable
Production
Costs/
MWh
18
5
8
154
115
21
118
62
(
5)
Change
in
Fuel
Costs
11
3
8
90
114
19
194
62
(
6)
Change
in
Pre­
Tax
Income
51
62
164
45
141
36
2
­

a
For
all
measures
percentages
used
to
assign
facilities
to
impact
categories
have
been
rounded
to
the
nearest
10th
of
a
percent.
b
The
change
in
capacity
utilization
is
the
difference
between
the
capacity
utilization
percentages
in
the
base
case
and
postcompliance
case.
For
all
other
measures,
the
change
is
expressed
as
the
percentage
change
between
the
base
case
and
postcompliance
values.

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
AEO
electricity
demand)
and
the
waterbody/
capacity­
based
option.

Table
B8­
4
indicates
that
the
majority
of
Phase
II
facilities
would
not
experience
changes
in
capacity
utilization
or
generation
due
to
compliance
with
the
waterbody/
capacity­
based
option.
Of
facilities
with
post­
compliance
changes
in
capacity
utilization
and/
or
generation,
the
majority
would
experience
reductions
in
these
measures.
Table
B8­
4
also
indicates
that
the
majority
of
Phase
II
facilities
would
experience
increases
in
revenues,
variable
production
costs
per
MWh,
and
fuel
costs
per
MWh
of
between
zero
and
three
percent.
Similarly,
almost
all
Phase
II
facilities
would
experience
a
change
in
pre­
tax
income,
with
a
slight
majority
seeing
a
reduction
in
this
measure.

B8­
4
MARKET
ANALYSIS
FOR
2008
This
section
presents
market­
level
results
for
the
waterbody/
capacity­
based
option
for
model
run
year
2008.
Unlike
the
market­
level
analysis
for
2013
described
above,
model
run
year
2008
includes
facilities
that
experience
a
one­
time
downtime
due
to
the
installation
of
Phase
II
compliance
technologies.
This
analysis
therefore
presents
potential
short­
term
effects
that
may
occur
during
the
five­
year
period
(
2005
to
2009)
represented
by
model
run
year
2008.
However,
it
should
be
noted
that
not
all
facilities
are
in
compliance
by
2008.
Therefore,
potential
effects
of
installation
downtimes
may
be
mitigated
by
the
fact
that
some
facilities
will
not
incur
compliance
costs
until
after
2008.

Table
B8­
5
below
presents
the
following
market­
level
impacts
for
2008:
(
1)
electricity
price
changes,
including
changes
in
energy
prices
and
capacity
prices;
(
2)
generation
changes;
(
3)
revenue
changes;
(
4)
cost
changes,
including
changes
in
fuel
costs,
variable
O&
M
costs,
fixed
O&
M
costs,
and
capital
costs;
(
5)
changes
in
pre­
tax
income,
defined
as
revenues
minus
total
costs;
and
(
6)
changes
in
variable
production
costs
per
MWh.
For
each
measure,
the
table
presents
the
results
for
the
base
case
and
the
waterbody/
capacity­
based
option,
the
absolute
difference
between
the
two
cases,
and
the
percentage
difference.
The
table
also
repeats
the
percentage
difference
based
on
the
market­
level
analysis
for
2013
presented
in
Table
B8­
2
above.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
B8­
16
NODA
Version
 
March
12,
2003
Table
B8­
5:
Comparison
of
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
2008
and
2013)

Economic
Measures
Base
Case
(
2008)
WB/
C­
Based
Option
(
2008)
Difference
(
2008)
%
Change
(
2008)
%
Change
(
2013)

National
Totals
(
1a)
Energy
Price
($
2002/
MWh)
n/
a
n/
a
n/
a
n/
a
n/
a
(
1b)
Capacity
Price
($
2002/
KW)
n/
a
n/
a
n/
a
n/
a
n/
a
(
2)
Total
Generation
(
GWh)
4,243,558
4,243,985
427
0.0%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
172,255
$
173,591
$
1,336
0.8%
1.0%

(
4)
Costs
(
Millions;
$
2002)
$
93,847
$
95,111
$
1,264
1.3%
1.9%

(
4a)
Fuel
Cost
$
51,909
$
52,330
$
421
0.8%
1.6%

(
4b)
Variable
O&
M
$
8,091
$
8,048
($
44)
­
0.5%
­
0.3%

(
4c)
Fixed
O&
M
$
24,216
$
24,767
$
552
2.3%
3.2%

(
4d)
Capital
Cost
$
9,631
$
9,965
$
335
3.5%
2.0%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
78,409
$
78,480
$
72
0.1%
­
0.5%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
14.14
$
14.23
$
0.09
0.6%
1.2%

East
Central
Area
Reliability
Coordination
Agreement
(
ECAR)

(
1a)
Energy
Price
($
2002/
MWh)
$
25.03
$
25.36
$
0.33
1.3%
0.8%

(
1b)
Capacity
Price
($
2002/
KW)
$
80.14
$
79.91
($
0.23)
­
0.3%
5.2%

(
2)
Total
Generation
(
GWh)
665,167
663,991
(
1,176)
­
0.2%
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
26,582
$
26,691
$
110
0.4%
1.2%

(
4)
Costs
(
Millions;
$
2002)
$
13,472
$
13,515
$
43
0.3%
1.1%

(
4a)
Fuel
Cost
$
6,921
$
6,923
$
1
0.0%
0.8%

(
4b)
Variable
O&
M
$
1,613
$
1,611
($
1)
­
0.1%
0.4%

(
4c)
Fixed
O&
M
$
3,610
$
3,691
$
82
2.3%
2.6%

(
4d)
Capital
Cost
$
1,329
$
1,290
($
39)
­
2.9%
0.1%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
13,109
$
13,176
$
67
0.5%
1.3%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.83
$
12.85
$
0.02
0.2%
0.5%

Electric
Reliability
Council
of
Texas
(
ERCOT)

(
1a)
Energy
Price
($
2002/
MWh)
$
29.59
$
31.08
$
1.49
5.0%
1.7%

(
1b)
Capacity
Price
($
2002/
KW)
$
48.19
$
40.35
($
7.83)
­
16.3%
­
1.3%

(
2)
Total
Generation
(
GWh)
341,915
342,502
587
0.2%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
13,770
$
13,702
($
68)
­
0.5%
1.0%

(
4)
Costs
(
Millions;
$
2002)
$
8,400
$
8,450
$
49
0.6%
1.4%

(
4a)
Fuel
Cost
$
5,540
$
5,542
$
2
0.0%
1.4%

(
4b)
Variable
O&
M
$
677
$
675
($
2)
­
0.3%
0.0%

(
4c)
Fixed
O&
M
$
1,723
$
1,743
$
20
1.2%
1.9%

(
4d)
Capital
Cost
$
461
$
490
$
29
6.3%
1.8%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
5:
Comparison
of
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
2008
and
2013)

Economic
Measures
Base
Case
(
2008)
WB/
C­
Based
Option
(
2008)
Difference
(
2008)
%
Change
(
2008)
%
Change
(
2013)

NODA
Version
 
March
12,
2003
B8­
17
(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
5,370
$
5,252
($
118)
­
2.2%
­
0.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
18.18
$
18.15
($
0.03)
­
0.2%
1.2%

Florida
Reliability
Coordinating
Council
(
FRCC)

(
1a)
Energy
Price
($
2002/
MWh)
$
30.75
$
31.08
$
0.33
1.1%
3.8%

(
1b)
Capacity
Price
($
2002/
KW)
$
64.79
$
63.37
($
1.42)
­
2.2%
­
6.3%

(
2)
Total
Generation
(
GWh)
197,481
196,939
(
542)
­
0.3%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
9,399
$
9,370
($
29)
­
0.3%
1.0%

(
4)
Costs
(
Millions;
$
2002)
$
5,868
$
6,014
$
147
2.5%
3.3%

(
4a)
Fuel
Cost
$
3,411
$
3,451
$
40
1.2%
1.9%

(
4b)
Variable
O&
M
$
379
$
378
($
1)
­
0.3%
0.3%

(
4c)
Fixed
O&
M
$
1,210
$
1,312
$
102
8.5%
11.4%

(
4d)
Capital
Cost
$
868
$
874
$
6
0.7%
0.0%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,531
$
3,356
($
176)
­
5.0%
­
5.4%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
19.19
$
19.44
$
0.25
1.3%
1.7%

Mid­
Atlantic
Area
Council
(
MAAC)

(
1a)
Energy
Price
($
2002/
MWh)
$
28.18
$
28.17
$
0.00
0.0%
1.4%

(
1b)
Capacity
Price
($
2002/
KW)
$
74.94
$
75.14
$
0.20
0.3%
0.1%

(
2)
Total
Generation
(
GWh)
289,502
288,953
(
549)
­
0.2%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
13,142
$
13,132
($
10)
­
0.1%
0.9%

(
4)
Costs
(
Millions;
$
2002)
$
6,665
$
6,827
$
162
2.4%
4.1%

(
4a)
Fuel
Cost
$
3,166
$
3,180
$
14
0.4%
1.6%

(
4b)
Variable
O&
M
$
594
$
591
($
3)
­
0.6%
­
0.3%

(
4c)
Fixed
O&
M
$
2,306
$
2,448
$
142
6.2%
11.5%

(
4d)
Capital
Cost
$
599
$
608
$
9
1.5%
0.6%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
6,478
$
6,306
($
172)
­
2.7%
­
4.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.99
$
13.05
$
0.06
0.5%
1.3%

Mid­
America
Interconnected
Network
(
MAIN)

(
1a)
Energy
Price
($
2002/
MWh)
$
24.20
$
24.57
$
0.37
1.5%
1.6%

(
1b)
Capacity
Price
($
2002/
KW)
$
78.33
$
77.81
($
0.52)
­
0.7%
0.1%

(
2)
Total
Generation
(
GWh)
294,504
294,233
(
271)
­
0.1%
­
0.6%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
11,982
$
12,032
$
50
0.4%
0.7%

(
4)
Costs
(
Millions;
$
2002)
$
6,288
$
6,304
$
15
0.2%
0.2%

(
4a)
Fuel
Cost
$
3,130
$
3,162
$
31
1.0%
1.9%

(
4b)
Variable
O&
M
$
604
$
604
$
0
0.0%
­
0.5%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
5:
Comparison
of
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
2008
and
2013)

Economic
Measures
Base
Case
(
2008)
WB/
C­
Based
Option
(
2008)
Difference
(
2008)
%
Change
(
2008)
%
Change
(
2013)

B8­
18
NODA
Version
 
March
12,
2003
(
4c)
Fixed
O&
M
$
1,966
$
1,942
($
24)
­
1.2%
­
4.1%

(
4d)
Capital
Cost
$
588
$
596
$
8
1.4%
2.2%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
5,694
$
5,729
$
35
0.6%
1.4%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.68
$
12.80
$
0.12
0.9%
2.2%

Mid­
Continent
Area
Power
Pool
(
MAPP)

(
1a)
Energy
Price
($
2002/
MWh)
$
23.73
$
23.77
$
0.04
0.2%
1.8%

(
1b)
Capacity
Price
($
2002/
KW)
$
77.83
$
77.17
($
0.66)
­
0.9%
­
0.1%

(
2)
Total
Generation
(
GWh)
186,975
187,698
723
0.4%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
7,295
$
7,300
$
5
0.1%
1.2%

(
4)
Costs
(
Millions;
$
2002)
$
3,642
$
3,683
$
42
1.1%
0.7%

(
4a)
Fuel
Cost
$
1,877
$
1,890
$
13
0.7%
0.3%

(
4b)
Variable
O&
M
$
376
$
377
$
1
0.3%
0.1%

(
4c)
Fixed
O&
M
$
1,017
$
1,035
$
18
1.8%
1.7%

(
4d)
Capital
Cost
$
372
$
381
$
9
2.3%
0.7%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,653
$
3,616
($
36)
­
1.0%
2.0%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.05
$
12.08
$
0.03
0.3%
0.3%

Northeast
Power
Coordinating
Council
(
NPCC)

(
1a)
Energy
Price
($
2002/
MWh)
$
31.19
$
31.20
$
0.01
0.0%
1.1%

(
1b)
Capacity
Price
($
2002/
KW)
$
70.60
$
70.38
($
0.22)
­
0.3%
0.1%

(
2)
Total
Generation
(
GWh)
291,319
291,301
(
17)
0.0%
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
13,908
$
13,896
($
13)
­
0.1%
0.9%

(
4)
Costs
(
Millions;
$
2002)
$
8,240
$
8,317
$
77
0.9%
2.8%

(
4a)
Fuel
Cost
$
4,875
$
4,887
$
12
0.2%
1.5%

(
4b)
Variable
O&
M
$
393
$
391
($
2)
­
0.5%
­
0.8%

(
4c)
Fixed
O&
M
$
1,799
$
1,857
$
58
3.2%
8.5%

(
4d)
Capital
Cost
$
1,173
$
1,182
$
9
0.8%
1.2%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
5,669
$
5,579
($
90)
­
1.6%
­
3.3%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
18.08
$
18.12
$
0.04
0.2%
1.2%

Southeastern
Electric
Reliability
Council
(
SERC)

(
1a)
Energy
Price
($
2002/
MWh)
$
26.49
$
26.56
$
0.07
0.3%
1.4%

(
1b)
Capacity
Price
($
2002/
KW)
$
69.71
$
69.43
($
0.27)
­
0.4%
­
0.2%

(
2)
Total
Generation
(
GWh)
978,448
980,504
2,055
0.2%
0.2%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
39,685
$
39,811
$
126
0.3%
1.1%

(
4)
Costs
(
Millions;
$
2002)
$
21,171
$
21,493
$
322
1.5%
1.6%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
Table
B8­
5:
Comparison
of
Market
Level
Impacts
of
the
Waterbody/
Capacity­
Based
Option
(
2008
and
2013)

Economic
Measures
Base
Case
(
2008)
WB/
C­
Based
Option
(
2008)
Difference
(
2008)
%
Change
(
2008)
%
Change
(
2013)

NODA
Version
 
March
12,
2003
B8­
19
(
4a)
Fuel
Cost
$
11,457
$
11,521
$
64
0.6%
1.3%

(
4b)
Variable
O&
M
$
1,834
$
1,831
($
3)
­
0.2%
0.5%

(
4c)
Fixed
O&
M
$
5,302
$
5,475
$
173
3.3%
3.3%

(
4d)
Capital
Cost
$
2,578
$
2,665
$
88
3.4%
0.8%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
18,514
$
18,318
($
196)
­
1.1%
0.2%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
13.58
$
13.62
$
0.03
0.2%
1.0%

Southwest
Power
Pool
(
SPP)

(
1a)
Energy
Price
($
2002/
MWh)
$
25.94
$
25.84
($
0.10)
­
0.4%
1.5%

(
1b)
Capacity
Price
($
2002/
KW)
$
67.00
$
68.19
$
1.19
1.8%
­
0.1%

(
2)
Total
Generation
(
GWh)
225,563
225,164
(
400)
­
0.2%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
9,236
$
9,264
$
27
0.3%
1.0%

(
4)
Costs
(
Millions;
$
2002)
$
4,531
$
4,535
$
4
0.1%
0.8%

(
4a)
Fuel
Cost
$
2,909
$
2,905
($
3)
­
0.1%
0.7%

(
4b)
Variable
O&
M
$
426
$
426
$
0
0.1%
0.2%

(
4c)
Fixed
O&
M
$
1,051
$
1,063
$
11
1.1%
1.4%

(
4d)
Capital
Cost
$
146
$
141
($
4)
­
2.9%
1.4%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
4,705
$
4,728
$
23
0.5%
1.2%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
14.78
$
14.80
$
0.01
0.1%
0.6%

Western
Systems
Coordinating
Council
(
WSCC)

(
1a)
Energy
Price
($
2002/
MWh)
$
29.23
$
29.10
($
0.12)
­
0.4%
1.4%

(
1b)
Capacity
Price
($
2002/
KW)
$
30.03
$
37.90
$
7.87
26.2%
­
0.1%

(
2)
Total
Generation
(
GWh)
772,683
772,700
17
0.0%
­
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
27,255
$
28,393
$
1,137
4.2%
1.0%

(
4)
Costs
(
Millions;
$
2002)
$
15,569
$
15,973
$
403
2.6%
2.6%

(
4a)
Fuel
Cost
$
8,623
$
8,870
$
247
2.9%
3.5%

(
4b)
Variable
O&
M
$
1,196
$
1,164
($
32)
­
2.7%
­
2.5%

(
4c)
Fixed
O&
M
$
4,232
$
4,201
($
31)
­
0.7%
­
0.7%

(
4d)
Capital
Cost
$
1,518
$
1,738
$
220
14.5%
7.4%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
11,686
$
12,420
$
734
6.3%
­
1.7%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.71
$
12.99
$
0.28
2.2%
2.9%

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
AEO
electricity
demand)
and
the
waterbody/
capacity­
based
option.

Summary
of
Market
Results
at
the
National
Level.
The
results
presented
in
Table
B8­
5
show
that
under
the
waterbody/
capacity­
based
option
economic
impacts
due
to
downtimes
associated
with
the
installation
of
compliance
technologies
would
not
be
substantially
different
from
impacts
observed
in
2013
(
which
represents
the
post­
compliance
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
B8­
20
NODA
Version
 
March
12,
2003
scenario
in
which
no
facilities
experience
downtimes).
Total
cost
increases
would
be
lower
in
2008
than
2013,
reflecting
the
fact
that
some
facilities
would
not
yet
be
in
compliance
with
this
option.
Similarly,
increases
in
fuel
costs
in
2008
would
be
half
of
those
in
2013,
leading
to
lower
increases
in
variable
production
costs
per
MWh.

Summary
of
Market
Results
at
the
Regional
Level.
The
results
for
2008
in
most
regions
are
similar
to
results
for
2013.
Results
for
2008
reflect
installation
downtimes
for
some
facilities,
while
2013
results
do
not.
On
the
other
hand,
some
of
the
facilities
do
not
come
into
compliance
until
after
2008.
Therefore,
their
compliance
costs
would
not
be
reflected
in
the
2008
results
but
are
reflected
in
the
2013
results.
Overall,
the
impact
of
installation
downtimes
(
reflected
in
the
2008
results)
appears
to
be
similar
to
the
impact
of
compliance
costs
incurred
after
2008
(
reflected
in
the
2013
results).
The
following
discussion
highlights
differences
in
the
analysis
results
between
2013
and
2008:
<
Two
regions,
ECAR
and
ERCOT,
would
experience
higher
increases
in
energy
prices
in
2008
than
in
2013.
All
other
regions
would
experience
lower
impacts
on
energy
prices
in
2008
compared
to
2013.
<
Three
regions
(
MAAC,
SPP,
and
WSCC)
would
experience
increases
in
capacity
prices
in
2008,
compared
to
four
regions
(
ECAR,
MAAC,
MAIN,
and
NPCC)
in
2013.
The
increase
in
WSCC
would
be
26.2
percent;
the
increases
in
the
other
two
regions
would
be
less
than
2.0
percent.
<
Five
regions
(
ECAR,
FRCC,
MAAC,
MAIN,
and
SPP)
would
experience
reductions
in
generation
in
2008.
However,
these
reductions
are
all
less
than
0.3
percent
and
within
0.5
percent
of
the
changes
observed
in
2013.
<
Revenues
in
2008
would
decrease
in
four
regions
(
ERCOT,
FRCC,
MAAC,
and
NPCC)
but
these
reductions
are
0.5
percent
or
less
in
all
cases.
In
2013,
none
of
the
10
NERC
regions
would
experience
revenue
reductions.
<
Total
costs
in
2008
are
higher
in
MAPP
compared
to
2013.
In
all
other
regions,
2008
cost
increases
are
equal
to
those
observed
in
2013
or
less.
<
Six
regions
(
ERCOT,
FRCC,
MACC,
MAPP,
NPCC,
and
SERC)
would
experience
reductions
in
pre­
tax
income
in
2008.
The
largest
reduction,
5.0
percent,
would
be
in
FRCC,
compared
to
a
5.4
percent
reduction
in
2013.
The
reductions
in
all
other
regions
in
2008
would
be
less
than
3.0
percent.
<
Increases
in
variable
production
costs
would
be
lower
or
the
same
in
2008
compared
to
2013
in
all
10
NERC
regions.

B8­
5
UNCERTAINTIES
AND
LIMITATIONS
The
uncertainties
described
in
section
B3­
5
of
Chapter
B3:
Electricity
Market
Model
Analysis
also
apply
to
the
analyses
presented
in
this
chapter.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B8­
21
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U.
S.
Department
of
Energy
(
U.
S.
DOE).
1999a.
Form
EIA­
860A
(
1999).
Annual
Electric
Generator
Report
 
Utility.

U.
S.
Department
of
Energy
(
U.
S.
DOE).
1999b.
Form
EIA­
860B
(
1999).
Annual
Electric
Generator
Report
 
Nonutility.

U.
S.
Environmental
Protection
Agency
(
U.
S.
EPA).
2002.
Documentation
of
EPA
Modeling
Applications
(
V.
2.1)
Using
the
Integrated
Planning
Model.
EPA
430/
R­
02­
004.
March
2002.
