Document ID: EPA-HQ-OW-2002-0049-0199
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2003-03-19T05:00Z

Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
1
1
The
twelve
NERC
regions
presented
are:
ASCC
(
Alaska
Systems
Coordinating
Council),
ECAR
(
East
Central
Area
Reliability
Coordination
Agreement),
ERCOT
(
Electric
Reliability
Council
of
Texas),
FRCC
(
Florida
Reliability
Coordinating
Council),
HI
(
Hawaii),
MAAC
(
Mid
Atlantic
Area
Council),
MAIN
(
Mid­
America
Interconnected
Network,
Inc.),
MAPP
(
Mid­
Continent
Area
Power
Pool),
NPCC
(
Northeast
Power
Coordination
Council),
SERC
(
Southeastern
Electricity
Reliability
Council),
SPP
(
Southwest
Power
Pool),
and
WSCC
(
Western
Systems
Coordinating
Council).
Memorandum
Date
March
12,
2003
To
The
Record
From
Lynne
Tudor,
OW/
EPA,
and
Antje
Siems,
Dan
Rosenfeld,
and
Janet
Larson,
Abt
Associates
Inc.

Subject
Supporting
Documentation
of
Changes
to
Economic
Impacts
in
Support
of
the
Section
316(
b)
Phase
II
NODA
This
memorandum
provides
more
detailed
information
supporting
the
"
other
economic
analyses"

discussed
in
Section
VI
of
the
Section
316(
b)
Phase
II
Notice
of
Data
Availability
(
NODA).
These
analyses
include:
(
1)
an
analysis
of
total
national
costs;
(
2)
a
cost­
to­
revenue
analysis
at
the
facility
and
firm
levels;
(
3)
an
analysis
of
compliance
costs
per
household
at
the
North
American
Electric
Reliability
Council
(
NERC)
level;
and
(
4)
an
analysis
of
compliance
costs
relative
to
electricity
price
projections,

also
at
the
NERC
level.
1
These
four
measures
are
provided
in
addition
to
the
impact
measures
based
on
the
Integrated
Planning
Model
(
IPM
®
)
analyses
(
see
Section
V
of
the
Notice).
These
measures
are
used
to
assess
the
magnitude
of
compliance
costs;
they
are
not
used
to
predict
closures
or
other
types
of
economic
impacts
on
facilities
subject
to
Phase
II
regulation.

For
this
NODA,
EPA
analyzed
changes
to
the
preferred
option
and
the
"
Intake
Capacity
Commensurate
with
Closed­
Cycle,
Recirculating
Cooling
System
based
on
Waterbody
Type/
Capacity"
Option
(
hereafter
the
"
waterbody/
capacity­
based"
option).
This
memo
therefore
only
addresses
these
two
regulatory
options.
For
a
discussion
of
the
original
methodology
used
by
EPA
for
the
proposal
analysis,
please
refer
to
the
chapters
in
Part
B
of
the
Economic
and
Benefits
Analysis
(
EBA)
document
in
support
of
the
proposed
rule
at
http://
www.
epa.
gov/
waterscience/
316b/
econbenefits/
(
DCN
4­
0002).

It
should
be
noted
that
the
results
of
the
preferred
option
and
the
waterbody/
capacity­
based
option
cannot
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
2
2
For
example,
compliance
requirements
in
NERC
regions
without
estuarine/
tidal
river
or
ocean
facilities
(
i.
e.,
ECAR,
MAIN,
MAPP,
and
SPP)
are
identical
under
the
two
options.
For
this
NODA
analysis,
all
facilities
in
these
regions
would
have
had
identical
compliance
costs
under
the
two
options,
were
it
not
for
the
difference
in
base
case
assumptions.

3
EPA's
2000
Section
316(
b)
Industry
Survey
identified
540
facilities
that
are
subject
to
the
preferred
rule.
EPA
applied
sample
weights
to
the
540
facilities
to
account
for
non­
sampled
facilities
and
facilities
that
did
not
respond
to
the
survey.
The
540
analyzed
facilities
represent
551
facilities
in
the
industry.
be
directly
compared
to
each
other.
EPA
used
two
different
demand
growth
assumptions
for
the
IPM
base
cases
of
the
preferred
option
(
EPA
electricity
demand
assumption)
and
the
waterbody/
capacity­
based
option
(
AEO
electricity
demand
assumption,
upon
request
by
the
Department
of
Energy).
Since
EPA
is
using
IPM
base
case
data
in
its
estimate
of
the
cost
of
installation
downtime,
the
cost
of
the
energy
penalty,
and
revenues,
the
results
presented
in
this
section
could
vary
between
the
two
options,
even
for
facilities
or
NERC
regions
with
identical
compliance
requirements
under
the
two
options.
2
1.
National
Costs
The
costs
in
this
section
are
based
on
551
facilities
with
steam­
electric
generators
which
EPA
identified
as
being
subject
to
Section
316(
b)
Phase
II
regulation.
3
The
costs
include
all
facility­
incurred
costs
associated
with
compliance
with
the
two
analyzed
options:
one­
time
technology
costs,
one­
time
cost
of
installation
downtime,
annual
operating
and
maintenance
costs,
cost
of
the
energy
penalty
incurred
by
facilities
estimated
to
upgrade
to
a
recirculating
cooling
tower
system,
and
permitting
costs
(
including
initial
permit
costs,
annual
monitoring
costs,
and
repermitting
costs).
Not
included
in
this
analysis
are
costs
of
administering
the
rule
incurred
by
permitting
authorities
and
the
federal
government.

Table
1
below
summarizes
different
measures
of
national,
facility­
incurred
compliance
costs
developed
for
the
NODA
analyses
for
the
preferred
option
and
the
waterbody/
capacity­
based
option.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
3
Table
1:
Summary
of
National
Costs
($
2002;
million)

Preferred
Option
Waterbody/
Capacity­
Based
Option
All
Phase
II
Facilities
Number
of
Phase
II
facilities
551
551
Total
pre­
tax
facility
cost
$
416
$
1,280
Total
post­
tax
facility
cost
$
269
$
797
Phase
II
Facilities
Excluding
Baseline
Closures
Number
of
Phase
II
facilities
543
544
Total
pre­
tax
facility
cost
$
410
$
1,273
Total
post­
tax
facility
cost
$
265
$
793
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
4
EPA
estimates
that
the
total
annual
post­
tax
facility
compliance
cost
of
the
preferred
option
for
the
551
in­
scope
facilities
is
$
269
million
annually.
Table
2
below
presents
annualized
facility
compliance
costs
by
cost
category
and
NERC
region
for
the
preferred
option.
The
annualized
cost
by
NERC
region
ranges
from
approximately
$
0.4
million
for
facilities
located
in
ASCC
to
$
48.9
million
for
facilities
located
in
ECAR.

Table
2:
Private
(
Post­
Tax)
Annualized
Facility
Compliance
Costs
by
NERC
Region
for
the
Preferred
Option
(
in
millions,
$
2002)

NERC
Region
One­
Time
Costs
Recurring
Costs
Total
Capital
Technology
Connection
Outage
Initial
Permit
Application
Pilot
Study
O&
M
Monitoring,

Record
Keeping
&

Reporting
Energy
Penalty
Permit
Renewal
ASCC
$
0.1
$
0.0
$
0.1
$
0.0
$
0.0
$
0.1
$
0.0
$
0.1
$
0.4
ECAR
$
23.9
$
7.1
$
3.8
$
0.4
$
4.8
$
6.1
$
0.0
$
2.9
$
48.9
ERCOT
$
3.4
$
0.0
$
1.9
$
0.1
$
4.9
$
3.3
$
0.0
$
1.4
$
15.2
FRCC
$
10.5
$
0.7
$
1.3
$
0.2
$
1.9
$
2.1
$
0.0
$
1.0
$
17.7
HI
$
2.6
$
1.0
$
0.1
$
0.2
$
0.1
$
0.2
$
0.0
$
0.1
$
4.2
MAAC
$
11.2
$
3.2
$
1.6
$
0.3
$
2.1
$
2.5
$
0.0
$
1.3
$
22.2
MAIN
$
10.5
$
2.0
$
1.8
$
0.3
$
3.7
$
3.0
$
0.0
$
1.4
$
22.7
MAPP
$
2.7
$
1.1
$
2.0
$
0.1
$
1.4
$
2.8
$
0.0
$
1.5
$
11.7
NPCC
$
20.0
$
5.2
$
2.7
$
0.4
$
0.5
$
3.6
$
0.0
$
2.1
$
34.4
SERC
$
18.4
$
6.8
$
3.8
$
0.7
$
6.1
$
5.8
$
0.0
$
2.9
$
44.5
SPP
$
2.7
$
0.6
$
1.0
$
0.1
$
2.3
$
2.0
$
0.0
$
0.8
$
9.4
WSCC
$
26.9
$
3.4
$
1.5
$
0.3
$
2.7
$
2.1
$
0.0
$
1.2
$
38.1
Total
$
132.9
$
31.1
$
21.5
$
3.1
$
30.5
$
33.6
$
0.0
$
16.6
$
269.3
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
5
Table
3
presents
total
annual
facility
compliance
costs
by
cost
category
and
steam
plant
type
for
the
preferred
option.
Costs
are
presented
both
on
a
pre­
tax
and
post­
tax
basis.
Annual
post­
tax
compliance
costs
range
from
approximately
$
2.4
million
($
4.0
million
pre­
tax)
for
"
other
steam"
(
primarily
non­
fossil
waste)
steam
facilities
to
$
126.2
million
($
191.2
million
pre­
tax)
for
coal
steam
facilities.

Table
3:
Private
Annualized
Facility
Compliance
Costs
by
Steam
Plant
Type
for
the
Preferred
Option
(
in
millions,
$
2002)

Plant
Type
One­
Time
Costs
Recurring
Costs
Total
Capital
Technology
Connection
Outage
Initial
Permit
Application
Pilot
Study
O&
M
Monitoring,

Record
Keeping
&

Reporting
Energy
Penalty
Permit
Renewal
Pre­
Tax
Compliance
Costs
Coal
Steam
$
77.7
$
30.1
$
16.9
$
2.0
$
25.0
$
26.5
$
0.0
$
13.0
$
191.2
Combined
Cycle
$
2.2
$
0.6
$
0.9
$
0.1
$
0.4
$
1.6
$
0.0
$
0.7
$
6.4
Nuclear
$
79.0
$
11.7
$
2.9
$
1.6
$
5.0
$
5.4
$
0.0
$
2.2
$
107.7
O/
G
Steam
$
50.4
$
7.2
$
10.6
$
1.2
$
14.1
$
15.6
$
0.0
$
8.1
$
107.0
Other
Steam
$
1.5
$
0.1
$
0.7
$
0.0
$
0.4
$
0.9
$
0.0
$
0.5
$
4.0
Total
$
210.7
$
49.6
$
31.9
$
4.8
$
44.8
$
49.9
$
0.0
$
24.5
$
416.4
Post­
Tax
Compliance
Costs
Coal
Steam
$
50.3
$
19.3
$
11.5
$
1.3
$
16.8
$
18.1
$
0.0
$
8.9
$
126.2
Combined
Cycle
$
1.4
$
0.4
$
0.6
$
0.0
$
0.2
$
1.1
$
0.0
$
0.5
$
4.3
Nuclear
$
48.1
$
7.0
$
1.8
$
1.0
$
3.4
$
3.4
$
0.0
$
1.4
$
66.1
O/
G
Steam
$
32.2
$
4.3
$
7.1
$
0.8
$
9.9
$
10.5
$
0.0
$
5.4
$
70.3
Other
Steam
$
0.9
$
0.0
$
0.4
$
0.0
$
0.2
$
0.5
$
0.0
$
0.3
$
2.4
Total
$
132.9
$
31.1
$
21.5
$
3.1
$
30.5
$
33.6
$
0.0
$
16.6
$
269.3
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
6
Tables
4
and
5
below
present
the
same
information
as
Tables
2
and
3
for
the
waterbody/
capacity­
based
option.

Table
4:
Private
(
Post­
Tax)
Annualized
Facility
Compliance
Costs
by
NERC
Region
for
the
Waterbody/
Capacity­
Based
Option
(
in
millions,
$
2002)

NERC
Region
One­
Time
Costs
Recurring
Costs
Total
Capital
Technology
Connection
Outage
Initial
Permit
Application
Pilot
Study
O&
M
Monitoring,

Record
Keeping
&

Reporting
Energy
Penalty
Permit
Renewal
ASCC
$
0.1
$
0.0
$
0.1
$
0.0
$
0.0
$
0.1
$
0.0
$
0.1
$
0.4
ECAR
$
23.9
$
8.0
$
3.8
$
0.4
$
4.8
$
6.1
$
0.0
$
2.9
$
49.9
ERCOT
$
6.3
$
0.3
$
1.8
$
0.1
$
8.5
$
3.3
$
1.1
$
1.3
$
22.7
FRCC
$
36.6
$
13.0
$
1.1
$
0.2
$
35.4
$
2.1
$
10.7
$
0.8
$
99.7
HI
$
5.8
$
0.8
$
0.0
$
0.0
$
5.7
$
0.2
$
2.6
$
0.0
$
15.1
MAAC
$
59.5
$
13.2
$
1.2
$
0.1
$
48.2
$
2.5
$
16.6
$
0.9
$
142.3
MAIN
$
10.5
$
2.1
$
1.8
$
0.3
$
3.7
$
3.0
$
0.0
$
1.4
$
22.8
MAPP
$
2.7
$
1.2
$
2.0
$
0.1
$
1.4
$
2.8
$
0.0
$
1.5
$
11.7
NPCC
$
40.6
$
11.2
$
2.2
$
0.3
$
26.9
$
3.6
$
17.0
$
1.7
$
103.6
SERC
$
43.4
$
16.8
$
3.4
$
0.5
$
31.8
$
5.8
$
10.1
$
2.6
$
114.4
SPP
$
2.7
$
0.6
$
1.0
$
0.1
$
2.3
$
2.0
$
0.0
$
0.8
$
9.5
WSCC
$
98.5
$
25.9
$
1.0
$
0.1
$
53.2
$
2.1
$
22.8
$
0.8
$
204.4
Total
$
330.6
$
93.0
$
19.4
$
2.2
$
221.8
$
33.6
$
80.9
$
14.9
$
796.5
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
7
Table
5:
Private
(
Post­
Tax)
Annualized
Facility
Compliance
Costs
by
Steam
Plant
Type
for
the
Waterbody/
Capacity­
Based
Option
(
in
millions,
$
2002)

Plant
Type
One­
Time
Costs
Recurring
Costs
Total
Capital
Technology
Connection
Outage
Initial
Permit
Application
Pilot
Study
O&
M
Monitoring,

Record
Keeping
&

Reporting
Energy
Penalty
Permit
Renewal
Pre­
Tax
Compliance
Costs
Coal
Steam
$
145.5
$
37.1
$
15.7
$
1.7
$
110.2
$
26.5
$
39.5
$
12.1
$
388.3
Combined
Cycle
$
17.0
$
0.9
$
0.7
$
0.0
$
18.3
$
1.6
$
1.9
$
0.6
$
41.0
Nuclear
$
244.2
$
100.2
$
2.3
$
0.8
$
124.0
$
5.4
$
39.9
$
1.8
$
518.6
O/
G
Steam
$
125.4
$
13.6
$
9.3
$
0.8
$
103.9
$
15.6
$
50.2
$
7.0
$
325.8
Other
Steam
$
2.0
$
0.2
$
0.5
$
0.0
$
1.7
$
0.9
$
0.4
$
0.4
$
6.1
Total
$
534.0
$
152.0
$
28.5
$
3.3
$
358.2
$
49.9
$
131.9
$
21.9
$
1,279.8
Post­
Tax
Compliance
Costs
Coal
Steam
$
91.7
$
23.8
$
10.8
$
1.1
$
68.9
$
18.1
$
24.1
$
8.3
$
246.7
Combined
Cycle
$
10.5
$
0.5
$
0.5
$
0.0
$
11.3
$
1.1
$
1.2
$
0.4
$
25.6
Nuclear
$
147.3
$
60.3
$
1.5
$
0.5
$
75.2
$
3.4
$
24.0
$
1.2
$
313.5
O/
G
Steam
$
79.9
$
8.3
$
6.3
$
0.5
$
65.4
$
10.5
$
31.4
$
4.8
$
207.1
Other
Steam
$
1.2
$
0.1
$
0.3
$
0.0
$
1.0
$
0.5
$
0.2
$
0.2
$
3.6
Total
$
330.6
$
93.0
$
19.4
$
2.2
$
221.8
$
33.6
$
80.9
$
14.9
$
796.5
Supporting
Documentation
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Changes
to
Economic
Impacts
March
12,
2003
Page
8
Compliance
Schedule
The
following
three
tables
present
EPA's
updated
assumptions
with
respect
to
the
compliance
schedule
for
the
Phase
II
regulation
(
see
also
discussion
in
Section
III
of
the
Notice).
Table
6
presents
the
anticipated
compliance
years
for
technologies
other
than
recirculating
systems
and
for
facilities
upgrading
to
recirculating
systems,
respectively,
based
on
the
year
of
the
facility's
last
NPDES
permit.
Tables
7
and
8
present
the
number
of
Phase
II
facilities
by
their
anticipated
compliance
year
and
NERC
region
for
the
preferred
option
and
the
waterbody/
capacity­
based
option,
respectively.

Table
6:
Compliance
Schedule
for
Facilities
Costed
with
Cooling
Towers
Year
of
Last
NPDES
Permit
Compliance
Period
Year
of
First
Post­

Promulgation
Permit
Compliance
Year
for
Technologies
Other
than
Recirculating
Systems
Range
of
Compliance
Years
for
Recirculating
Systems
1995
or
2000
2005
2005
2006
­
2009
1996
or
2001
2006
2006
2007
­
2010
1997
or
2002
2007
2007
2008
­
2011
1998
or
2003
2008
2008
2009
­
2012
1999
or
2004
2009
2009
2010
­
2013
Supporting
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March
12,
2003
Page
9
Table
7:
Number
of
Phase
II
Facilities
by
Anticipated
Compliance
Year
and
NERC
Region
for
the
Preferred
Option
NERC
Region
Compliance
Year
Total
2005
2006
2007
2008
2009
ASCC
1
­
­
­
­
1
ECAR
16
26
29
17
14
102
ERCOT
12
6
4
14
16
52
FRCC
10
3
2
7
8
30
HI
­
­
­
­
3
3
MAAC
11
12
11
4
6
44
MAIN
16
11
7
7
10
51
MAPP
11
11
10
9
3
44
NPCC
13
18
12
9
10
61
SERC
21
20
29
11
15
96
SPP
11
3
5
9
4
32
WSCC
16
7
4
1
5
34
Total
138
116
114
88
95
551
Supporting
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March
12,
2003
Page
10
Table
8:
Number
of
Phase
II
Facilities
by
Anticipated
Compliance
Year
and
NERC
Region
for
the
Waterbody/
Capacity­
Based
Option
NERC
Region
Compliance
Year
Total
2005
2006
2007
2008
2009
2010
2011
2012
ASCC
1
­
­
­
­
­
­
­
1
ECAR
16
26
29
17
14
­
­
­
102
ERCOT
11
7
4
13
17
­
­
­
52
FRCC
9
3
2
7
8
­
­
1
30
HI
­
­
­
­
1
2
­
­
3
MAAC
7
15
9
7
4
2
­
­
44
MAIN
16
11
7
7
10
­
­
­
51
MAPP
11
11
10
9
3
­
­
­
44
NPCC
13
14
13
8
9
5
­
­
61
SERC
18
21
29
13
15
­
­
­
96
SPP
11
3
5
9
4
­
­
­
32
WSCC
11
9
7
2
5
­
­
­
34
Total
123
120
115
92
90
9
­
1
551
Supporting
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Economic
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March
12,
2003
Page
11
Installation
Downtime
EPA
also
changed
its
assumptions
about
facility
downtime
as
a
result
of
technology
installation
(
see
also
discussion
in
Section
III
of
the
Notice).
Table
9
presents
the
total
number
of
weeks
of
downtime
for
compliance
technology
installation
estimated
by
EPA
for
the
preferred
option
and
the
waterbody/
capacity­
based
option.

Table
9:
Number
of
Downtime
Weeks
for
Phase
II
Facility
by
NERC
Region
NERC
Region
Preferred
Option
Waterbody/
Capcity
Based
Option
ASCC
4
4
ECAR
102
106
ERCOT
­
8
FRCC
10
52
HI
6
8
MAAC
50
99
MAIN
23
23
MAPP
20
20
NPCC
59
111
SERC
67
111
SPP
8
8
WSCC
20
96
Total
369
645
2.
Cost­
to­
Revenue
Ratio
The
"
cost­
to­
revenue
ratio"
is
used
to
assess
the
magnitude
of
compliance
costs
relative
to
revenues.
This
test
is
commonly
used
to
evaluate
the
economic
practicability
of
regulatory
requirements.
The
cost­

torevenue
measure
is
a
useful
test
because
it
compares
the
cost
of
reducing
adverse
environmental
impact
from
the
operation
of
the
facility's
cooling
water
intake
structure
(
CWIS)
with
the
economic
value
(
i.
e.,

revenue)
of
the
facility's
economic
activities.
EPA
conducted
this
test
at
the
facility
and
firm
levels.

Depending
on
the
policy
option
analyzed,
annualized
compliance
costs
include
all
capital
costs,
O&
M
costs,
administrative
costs,
energy
penalty
costs
(
where
applicable),
and
plant
outage
costs
of
compliance
with
Phase
II
regulation.
O&
M
costs
include
the
cost
of
auxiliary
power
requirements
as
a
result
of
the
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
12
4
This
annualization
methodology
is
different
from
the
one
conducted
for
the
national
cost
estimate
presented
in
Chapter
B1
of
the
EBA
and
used
in
Section
1
of
this
memo.
For
the
national
cost
estimate,
the
present
value
was
determined
as
of
the
first
year
the
Phase
II
rule
will
take
effect
(
2004).
In
contrast,
for
the
impact
analysis,
the
present
value
was
determined
as
of
the
first
year
of
compliance
of
each
facility
(
2005
to
2013).

5
EPA
used
2008
rather
than
2010
baseline
revenues
for
this
analysis
because
2008
is
the
first
model
run
year
specified
in
the
IPM
analyses.
EPA
used
the
first
model
run
year
because
it
more
closely
resembles
the
current
operating
conditions
of
in­
scope
facilities
than
later
run
years
(
over
time,
facilities
may
be
increasingly
affected
by
factors
other
than
a
Phase
II
regulation).
operation
of
recirculating
cooling
towers.
To
derive
the
constant
annual
value
of
the
capital
costs
and
the
value
of
the
cooling
tower
construction
and/
or
connection
plant
outage,
EPA
annualized
these
values
over
30
years,
using
a
seven
percent
discount
rate.
The
costs
of
condenser
upgrades
were
annualized
over
20
years.
Other
capital
costs,
which
include
fine­
mesh
traveling
screens
with
and
without
fish
handling
as
well
as
fish
handling
and
return
systems,
were
annualized
over
10
years.
EPA
then
added
the
annualized
capital
and
connection
outage
costs
to
annual
O&
M
costs,
administrative
costs,
and
the
cost
of
the
energy
penalty
to
derive
each
facility's
total
annual
cost
of
complying
with
the
Phase
II
rule.
4
For
a
detailed
analysis
of
the
compliance
cost
components
developed
for
this
analysis,
see
Chapter
B1
of
the
EBA
and
the
Section
316(
b)
Technical
Development
Document
(
DCN
4­
0004),
both
in
support
of
the
proposed
rule.

EPA
compared
the
annualized
compliance
costs
to
the
estimated
facility
and
firm
revenues
on
both
the
facility
and
firm
levels.
This
analysis
uses
thresholds
of
one
and
three
percent.

Facility­
Level
Analysis
EPA
examined
the
annualized
post­
tax
compliance
costs
of
the
preferred
option
and
the
waterbody/
capacity­
based
option
as
a
percentage
of
baseline
annual
revenues,
for
each
of
the
551
facilities
subject
to
Phase
II
of
the
Section
316(
b)
regulation.
This
measure
allows
for
a
comparison
of
compliance
costs
incurred
by
each
facility
with
its
revenues
in
the
absence
of
Phase
II
regulation.
The
revenue
estimates
are
facility­
specific
baseline
projections
from
the
IPM
base
case
for
2008
(
see
Section
V
of
this
Notice
for
a
discussion
of
EPA's
analyses
using
the
IPM).
5
If
IPM
revenues
were
not
available,

EPA
used
facility­
specific
electricity
generation
and
firm­
specific
wholesale
prices
as
reported
to
the
Energy
Information
Administration
(
EIA)
to
calculate
the
cost­
to­
revenue
ratio.

Tables
10
and
11
below
present
the
results
of
the
facility­
level
cost­
to­
revenue
measure,
by
facility
ownership
type
and
fuel
type,
for
the
preferred
option
and
the
waterbody/
capacity­
based
option,

respectively.
For
each
facility
type
and
fuel
type,
the
tables
present
(
1)
the
total
number
of
facilities;
(
2)
Supporting
Documentation
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Economic
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March
12,
2003
Page
13
the
number
of
facilities
with
a
cost­
to­
revenue
ratio
of
less
than
0.5
percent,
between
0.5
and
one
percent,

between
one
and
three
percent,
and
greater
than
three
percent;
and
(
3)
the
minimum
and
maximum
ratios.

Table
10
shows
that
the
vast
majority
of
facilities
subject
to
the
preferred
option,
404
out
of
551
(
73
percent),
would
incur
annualized
costs
of
less
than
one
percent
of
revenues.
Of
these,
292
facilities
would
incur
compliance
costs
of
less
than
0.5
percent
of
revenues.
Ninety­
seven
facilities
(
18
percent)

would
incur
costs
of
between
one
and
three
percent
of
revenues,
and
41
facilities
(
seven
percent)
would
incur
costs
of
greater
than
three
percent.
Eight
facilities
are
estimated
to
be
baseline
closures,
and
for
one
facility,
revenues
are
unknown.
Supporting
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Economic
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March
12,
2003
Page
14
Table
10:
Facility­
Level
Cost­
to­
Revenue
Measure
for
the
Preferred
Option
Facility
Type
Total
Number
of
Facilities
Number
of
Facilities
with
a
Ratio
of
Minimum
Ratio
Maximum
Ratio
<
0.5%
0.5­
1%
1­
3%
>
3%
Baseline
Closure
n/
a
By
Ownership
Type
Investor­
Owned
Utility
316
189
73
37
13
3
1
0.01%
102.6%

Nonutility
(
former
utility)
120
61
28
23
3
4
­
0.01%
8.3%

Nonutility
(
original)
15
3
­
7
5
­
­
0.03%
16.8%

Federal
Utility
14
13
­
1
­
­
­
0.07%
2.2%

State­
Owned
Utility
6
3
1
1
1
­
­
0.04%
4.1%

Political
Subdivision
8
4
­
1
2
1
­
0.06%
22.8%

Municipality
&
Municipal
Marketing
Authority
47
11
5
17
14
­
­
0.03%
62.9%

Rural
Electric
Cooperative
25
7
5
10
3
­
­
0.04%
10.4%

Totala
551
292
112
97
41
8
1
0.01%
102.6%

By
Fuel
Type
Coal
Steam
300
176
74
38
11
­
­
0.01%
20.3%

Combined­
Cycle
17
10
2
3
2
­
­
0.02%
5.7%

Nuclear
58
40
1
9
1
7
­
0.01%
3.1%

Oil/
Gas
Steam
167
66
34
42
24
1
­
0.03%
102.6%

Other
Steam
9
­
1
5
2
­
1
0.50%
4.0%

Totala
551
292
112
97
41
8
1
0.01%
102.6%

a
Individual
numbers
may
not
add
up
due
to
independent
rounding.

Source:
IPM
analysis:
Section
316(
b)
NODA
base
case
(
EPA
electricity
demand);
U.
S.
EPA
analysis,
2003.

Table
11
shows
that
out
of
the
551
facilities
subject
to
this
option,
382
(
69
percent)
would
incur
annualized
costs
of
less
than
one
percent
of
revenues.
Of
these,
281
(
51
percent)
would
incur
annualized
costs
of
less
than
0.5
percent
of
revenues.
One­
hundred
and
two
facilities
(
19
percent)
would
incur
costs
of
between
one
and
three
percent
of
revenues,
and
58
facilities
(
11
percent)
would
incur
costs
of
greater
than
three
percent.
EPA
estimates
that
seven
facilities
would
be
baseline
closures,
and
for
one
facility,
Supporting
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Economic
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March
12,
2003
Page
15
6
For
the
waterbody/
capacity­
based
option,
IPM
revenues
for
2008
were
not
available
for
seven
facilities
estimated
to
be
baseline
closures,
ten
facilities
not
modeled
by
the
IPM,
and
two
facilities
projected
to
have
zero
baseline
revenues.
EPA
used
facility­
specific
electricity
generation
and
firm­
specific
wholesale
prices
as
reported
to
the
Energy
Information
Administration
(
EIA)
to
calculate
the
cost­
to­
revenue
ratio
for
the
12
non­
baseline
closure
facilities
with
missing
information.
The
revenues
for
one
of
these
facilities
remained
unknown.
revenues
are
unknown.
6
Table
11:
Facility­
Level
Cost­
to­
Revenue
Measure
for
the
Waterbody/
Capacity­
Based
Option
Facility
Type
Total
Number
of
Facilities
Number
of
Facilities
with
a
Ratio
of
Minimum
Ratio
Maximum
Ratio
<
0.5%
0.5­
1%
1­
3%
>
3%
Baseline
Closure
n/
a
By
Ownership
Type
Investor­
Owned
Utility
316
190
63
38
22
2
1
0.01%
15.7%

Nonutility
(
former
utility)
120
50
24
26
16
4
­
0.01%
12.9%

Nonutility
(
original)
15
3
­
7
5
­
­
0.03%
16.8%

Federal
Utility
14
13
­
1
­
­
­
0.07%
2.1%

State­
Owned
Utility
6
3
­
2
1
­
­
0.03%
4.5%

Political
Subdivision
8
4
­
1
2
1
­
0.06%
22.8%

Municipality
&
Municipal
Marketing
Authority
47
10
9
18
10
­
­
0.03%
63.3%

Rural
Electric
Cooperative
25
8
5
9
3
­
­
0.03%
10.5%

Totala
551
281
101
102
58
7
1
0.01%
63.3%

By
Fuel
Type
Coal
Steam
300
171
68
42
18
­
­
0.01%
18.9%

Combined­
Cycle
17
9
­
6
2
­
­
0.02%
13.0%

Nuclear
58
36
­
7
8
7
­
0.01%
12.9%

Oil/
Gas
Steam
167
64
33
42
28
­
­
0.03%
63.3%

Other
Steam
9
1
­
5
2
­
1
0.40%
14.6%

Totala
551
281
101
102
58
7
1
0.01%
63.3%

a
Individual
numbers
may
not
add
up
due
to
independent
rounding.

Source:
IPM
analysis:
Section
316(
b)
NODA
base
case
(
AEO
electricity
demand);
U.
S.
EPA
analysis,
2003.

Firm­
Level
Analysis
EPA
also
conducted
a
firm­
level
analysis
to
evaluate
the
potential
impacts
on
firms
that
own
multiple
Supporting
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to
Economic
Impacts
March
12,
2003
Page
16
7
EPA
used
EIA
data
if
D&
B
data
were
not
available
for
privately­
owned
facilities,
and
D&
B
data
if
EIA
data
were
not
available
for
facilities
owned
by
other
entities.
If
neither
EPA
nor
EIA
data
were
available,
EPA
used
data
from
the
Section
316(
b)
Survey.
facilities
subject
to
Section
316(
b)
Phase
II
regulation.
Impacts
experienced
at
the
firm­
level
may
be
higher
for
firms
that
own
multiple
facilities
subject
to
the
rule.
The
firm­
level
analysis
is
based
on
the
aggregated
post­
tax
compliance
costs
for
each
facility
owned
by
the
128
parent
entities
to
the
firm's
total
sales
revenue.
EPA
identified
70
entities,
out
of
the
128
unique
domestic
parent
entities,
that
own
more
than
one
facility
subject
to
the
proposed
Phase
II
rule.

EPA
did
not
update
its
determination
of
the
domestic
parent
entities
of
Phase
II
facilities
for
this
NODA.

The
only
change
to
the
parent
entity
determination
since
proposal
was
due
to
the
change
in
the
universe
of
Phase
II
facilities:
Six
facilities
have
been
added
to
the
Phase
II
analysis
since
proposal;
these
six
facilities
are
owned
by
five
entities
which
all
own
other
Phase
II
facilities
and
were
therefore
already
part
of
the
Phase
II
proposal
universe.
Conversely,
five
facilities
have
been
dropped
since
proposal;
these
five
facilities
are
owned
by
five
entities.
Three
of
these
entities
do
not
own
other
Phase
II
facilities
and
are
no
longer
part
of
Phase
II
regulation.
As
a
result
of
these
changes,
the
number
of
domestic
parent
entities
decreased
from
131
at
proposal
to
128
for
this
NODA
analysis.
For
a
detailed
description
of
how
EPA
identified
domestic
parent
entities
at
proposal,
see
Chapter
B4
of
the
EBA
in
support
of
the
proposed
Phase
II
rule.

EPA
updated
and
modified
the
revenues
used
for
the
firm­
level
analysis
for
the
NODA.
At
proposal,

EPA
used
Dun
and
Bradstreet
(
D&
B)
sales
data
for
any
parent
entity
listed
in
the
database.
If
D&
B
data
were
not
available,
EPA
used
the
EIA
database
or
the
Section
316(
b)
Survey.
For
the
NODA
analysis,

EPA
used
the
D&
B
database
for
privately­
owned
entities
only.
For
other
entities,
EPA
used
the
EIA
database.
7
In
addition,
EPA
updated
the
average
Form
EIA­
861
data
used
for
this
analysis
from
1996
to
1998
(
used
at
proposal)
to
1997
to
1999
(
used
for
the
NODA).

Tables
12
and
13
below
summarize
the
cost­
to­
revenue
ratios
for
the
128
entities
owning
in­
scope
electric
generating
facilities
by
the
parent
entity
type
for
the
preferred
option
and
the
waterbody/
capacity
based
option,
respectively.
For
each
entity
type
the
tables
present
(
1)
the
total
number
of
facilities
owned;
(
2)

the
total
number
of
firms;
(
3)
the
number
of
firms
with
a
cost­
to­
revenue
ratio
of
less
than
0.5
percent,

between
0.5
and
one
percent,
between
one
and
three
percent,
greater
than
three
percent;
and
(
4)
the
minimum
and
maximum
ratio.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
17
For
the
preferred
option,
EPA
estimates
that
of
the
128
unique
entities,
only
two
entities
would
incur
compliance
costs
of
greater
than
three
percent
of
revenues;
11
entities
would
incur
compliance
costs
of
between
one
and
three
percent
of
revenues;
eight
entities
would
incur
compliance
costs
of
between
0.5
and
one
percent
of
revenues;
and
the
remaining
107
entities
would
incur
compliance
costs
of
less
than
0.5
percent
of
revenues.
The
highest
estimated
cost­
to­
revenue
ratio
for
this
NODA
analysis
is
7.4
percent
of
the
entities'
annual
sales
revenue.
The
compliance
cost
estimates
used
for
this
firm­
level
analysis
include
costs
for
all
Phase
II
facilities,
including
facilities
estimated
to
be
baseline
closures.

Table
12:
Firm­
Level
Cost­
to­
Revenue
Measure
by
Entity
Type
for
the
Preferred
Option
Entity
Type
Total
Number
of
Facilities
Total
Number
of
Firms
Number
of
Firms
with
a
Ratio
of
Minimum
Ratio
Maximum
Ratio
<
0.5%
0.5­
1%
1
­
3%
>
3%

Private
450
70
68
1
1
­
0.00%
1.07%

Federal
14
1
1
­
­
­
0.16%
0.16%

State
7
4
4
­
­
­
0.02%
0.32%

Political
Subdivision
8
4
3
­
1
­
0.11%
1.32%

Municipality
&

Municipal
Marketing
Authority
47
34
17
6
9
2
0.04%
7.36%

Rural
Electric
Cooperative
25
15
14
1
­
­
0.18%
0.69%

Totala
551
128
107
8
11
2
0.00%
7.36%

a
Individual
numbers
may
not
add
up
to
totals
due
to
independent
rounding.

Source:
IPM
analysis:
Section
316(
b)
NODA
base
case
(
EPA
electricity
demand);
U.
S.
EPA
analysis,
2003.

EPA
estimates
that
under
the
waterbody/
capacity­
based
option
only
two
of
the
128
unique
entitieswould
incur
compliance
costs
of
greater
than
three
percent
of
revenues
the;
15
entities
would
incur
compliance
costs
of
between
one
and
three
percent
of
revenues;
16
entities
would
incur
compliance
costs
of
between
0.5
and
one
percent
of
revenues;
and
the
remaining
95
entities
would
incur
compliance
costs
of
less
than
0.5
percent
of
revenues.
The
highest
estimated
cost­
to­
revenue
ratio
for
this
NODA
analysis
is
7.4
percent
of
the
entities'
annual
sales
revenue.
The
compliance
cost
estimates
used
for
this
firm­
level
analysis
include
costs
for
all
Phase
II
facilities,
including
facilities
estimated
to
be
baseline
closures.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
18
8
The
number
of
residential
consumers
reported
in
Form
EIA­
861
is
based
on
the
number
of
utility
meters.
This
is
a
proxy
for
the
number
of
households
but
can
differ
slightly
due
to
bulk
metering
in
some
multi­
family
housing.
Table
13:
Firm­
Level
Cost­
to­
Revenue
Measure
by
Entity
Type
for
the
Waterbody/
Capacity­
Based
Option
Entity
Type
Total
Number
of
Facilities
Total
Number
of
Firms
Number
of
Firms
with
a
Ratio
of
Minimum
Ratio
Maximum
Ratio
<
0.5%
0.5­
1%
1
­
3%
>
3%

Private
450
70
58
7
5
­
0.00%
2.20%

Federal
14
1
1
­
­
­
0.16%
0.16%

State
7
4
3
1
­
­
0.02%
0.63%

Political
Subdivision
8
4
3
­
1
­
0.11%
1.32%

Municipality
&

Municipal
Marketing
Authority
47
34
16
7
9
2
0.04%
7.36%

Rural
Electric
Cooperative
25
15
14
1
­
­
0.18%
0.71%

Totala
551
128
95
16
15
2
0.00%
7.36%

a
Individual
numbers
may
not
add
up
to
totals
due
to
independent
rounding.

Source:
IPM
analysis:
Section
316(
b)
NODA
base
case
(
AEO
electricity
demand);
U.
S.
EPA
analysis,
2003.

3.
Cost
per
Household
EPA
also
conducted
an
analysis
that
evaluates
the
potential
cost
per
household,
8
if
Phase
II
facilities
were
able
to
pass
compliance
costs
on
to
their
customers.
This
analysis
estimates
the
average
compliance
cost
per
household
for
each
NERC
region,
using
two
data
inputs:
(
1)
the
average
annual
compliance
cost
per
megawatt
hour
(
MWh)
of
sales
and
(
2)
the
average
annual
MWh
of
electricity
sales
per
household.
Both
data
elements
were
calculated
by
NERC
region
using
the
following
approach.

Average
annual
compliance
cost
per
MWh
of
sales:
EPA
compiled
data
on
total
electricity
sales
(
including
residential,
commercial,
industrial,
public
street
highway
and
lighting,
and
other
sales)
from
the
2000
Form
EIA­
861
database.
Utility­
level
sales
were
aggregated
by
NERC
region
to
derive
each
region's
total
electricity
sales
in
2000.
In
addition,
EPA
aggregated
the
national
pre­
tax
compliance
costs
by
the
NERC
region
in
which
the
551
Phase
II
facilities
are
located.
The
average
compliance
cost
per
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
19
MWh
of
electricity
sales
is
calculated
by
dividing
total
electricity
sales
by
total
pre­
tax
compliance
costs
for
each
region.

Average
annual
electricity
sales
per
household:
Form
EIA­
861
differentiates
electricity
sales
by
customer
type
and
also
presents
the
number
of
customers
that
account
for
the
sales.
The
average
annual
electricity
sales
per
household
is
therefore
calculated
by
dividing
the
MWh
of
residential
sales
by
the
number
of
households.
This
calculation
was
again
done
by
NERC
region.

For
both
the
preferred
option
and
the
waterbody/
capacity­
based
option,
EPA
calculated
the
annual
compliance
cost
per
household
by
multiplying
the
average
annual
compliance
cost
per
MWh
of
sales
by
the
average
annual
electricity
sales
per
household.
This
analysis
assumes
that
power
generators
pass
costs
on
to
consumers,
on
a
dollar­
to­
dollar
basis,
and
that
each
sector
(
i.
e.,
residential,
industrial,
commercial,

public
street
highway
and
lighting,
and
other)
bears
an
equal
burden
of
compliance
costs
per
MWh
of
electricity.

Table
14
shows
the
results
of
this
analysis
for
the
preferred
option.
The
cost
per
residential
household
would
average
$
1.30,
and
range
from
$
0.55
per
year
in
ASCC
to
$
5.69
per
year
in
HI.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
20
Table
14:
Annual
Compliance
Cost
per
Residential
Consumer
by
NERC
Region
in
2000
for
the
Preferred
Option
($
2002)

NERC
Region
Total
Electricity
Sales
(
MWh)
Total
National
Pre­
Tax
Compliance
Cost
Annualized
Pre­

Tax
Compliance
Cost
($
/
MWh
Sales)
Residential
Electricity
Sales
(
MWh)
Number
of
Households
Annual
Residential
Sales/

Household
(
MWh)
Annual
Compliance
Cost/

Household
ASCC
5,309,970
$
365,651
$
0.07
1,854,968
230,534
8.05
$
0.55
ECAR
522,187,334
$
76,948,607
$
0.15
158,037,771
15,626,013
10.11
$
1.49
ERCOT
285,347,453
$
21,670,672
$
0.08
103,478,697
7,021,590
14.74
$
1.12
FRCC
182,848,371
$
27,154,034
$
0.15
92,391,451
6,721,120
13.75
$
2.04
HI
9,271,676
$
6,922,457
$
0.75
2,627,203
344,882
7.62
$
5.69
MAAC
229,193,120
$
37,371,992
$
0.16
82,890,271
8,982,600
9.23
$
1.50
MAIN
247,759,377
$
36,585,689
$
0.15
72,946,752
8,188,189
8.91
$
1.32
MAPP
139,246,194
$
15,352,411
$
0.11
47,997,755
4,848,274
9.90
$
1.09
NPCC
256,382,568
$
56,165,133
$
0.22
85,806,190
12,650,908
6.78
$
1.49
SERC
764,593,949
$
63,832,839
$
0.08
282,503,216
20,192,159
13.99
$
1.17
SPP
171,473,599
$
12,324,949
$
0.07
59,902,473
4,909,350
12.20
$
0.88
WSCC
599,645,124
$
61,665,308
$
0.10
201,895,024
22,010,686
9.17
$
0.94
U.
S.
3,413,258,735
$
416,359,743
$
0.12
1,192,331,771
111,726,305
10.67
$
1.30
Source:
U.
S.
DOE,
2000;
EPA
analysis,
2003.

Table
15
shows
the
results
of
this
analysis
for
the
waterbody/
capacity­
based
option.
The
cost
per
household
would
average
$
4.00,
and
range
from
$
0.55
per
year
in
ASCC
to
$
20.41
per
year
in
HI.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
21
9
The
Annual
Energy
Outlook
does
not
include
two
NERC
regions,
ASCC
and
HI.
Table
15:
Annual
Compliance
Cost
per
Residential
Consumer
by
NERC
Region
in
2000
for
the
Waterbody/
Capacity­
Based
Option
($
2002)

NERC
Region
Total
Electricity
Sales
(
MWh)
Total
National
Pre­
Tax
Compliance
Cost
Annualized
Pre­
Tax
Compliance
Cost
($
/
MWh
Sales)
Residential
Electricity
Sales
(
MWh)
Number
of
Households
Annual
Residential
Sales/

Household
(
MWh)
Annual
Compliance
Cost/
Houshold
ASCC
5,309,970
$
365,795
$
0.07
1,854,968
230,534
8.05
$
0.55
ECAR
522,187,334
$
78,527,538
$
0.15
158,037,771
15,626,013
10.11
$
1.52
ERCOT
285,347,453
$
33,805,805
$
0.12
103,478,697
7,021,590
14.74
$
1.75
FRCC
182,848,371
$
160,722,241
$
0.88
92,391,451
6,721,120
13.75
$
12.08
HI
9,271,676
$
24,838,714
$
2.68
2,627,203
344,882
7.62
$
20.41
MAAC
229,193,120
$
236,666,387
$
1.03
82,890,271
8,982,600
9.23
$
9.53
MAIN
247,759,377
$
36,778,203
$
0.15
72,946,752
8,188,189
8.91
$
1.32
MAPP
139,246,194
$
15,449,356
$
0.11
47,997,755
4,848,274
9.90
$
1.10
NPCC
256,382,568
$
172,926,197
$
0.67
85,806,190
12,650,908
6.78
$
4.57
SERC
764,593,949
$
175,494,912
$
0.23
282,503,216
20,192,159
13.99
$
3.21
SPP
171,473,599
$
12,428,707
$
0.07
59,902,473
4,909,350
12.20
$
0.88
WSCC
599,645,124
$
331,813,043
$
0.55
201,895,024
22,010,686
9.17
$
5.08
U.
S.
3,413,258,735
$
1,279,816,898
$
0.37
1,192,331,771
111,726,305
10.67
$
4.00
Source:
U.
S.
DOE,
2000;
EPA
analysis,
2003.

4.
Electricity
Price
Analysis
EPA
also
considered
potential
effects
of
the
Phase
II
regulation
on
electricity
prices.
EPA
used
three
data
inputs
in
this
analysis:
(
1)
total
pre­
tax
compliance
cost
incurred
by
facilities
subject
to
the
Phase
II
regulation;
(
2)
total
electricity
sales,
based
on
the
Annual
Energy
Outlook
(
AEO)
2002;
and
(
3)
prices
by
consumer
type
(
residential,
commercial,
industrial,
and
transportation),
also
from
the
AEO
2002.
All
three
data
elements
were
calculated
by
NERC
region.
9
Table
16
presents
the
annualized
costs
of
complying
with
the
preferred
option,
total
electricity
sales
(
in
MWh),
and
the
cost
in
cents
per
kilowatt
hour
(
KWh)
of
total
electricity
sales
by
NERC
region.
The
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
22
costs
per
KWh
sales
range
from
0.007
cents
in
SPP
to
0.020
cents
in
NPCC.

Table
16:
Compliance
Cost
per
KWh
of
Sales
by
NERC
Region
for
the
Preferred
Option
NERC
Region
Annualized
Pre­
Tax
Compliance
Costs
(
National;
$
2002)
Total
Electricity
Sales
(
MWh;
2000)
Annualized
Pre­
Tax
Compliance
Cost
(
Cents
/

KWh
Sales)

ASCC
$
365,651
 
 
ECAR
$
76,948,607
517,730,286
0.015
¢
ERCOT
$
21,670,672
269,072,083
0.008
¢
FRCC
$
27,154,034
182,241,013
0.015
¢
HI
$
6,922,457
 
 
MAAC
$
37,371,992
246,302,490
0.015
¢
MAIN
$
36,585,689
231,949,219
0.016
¢
MAPP
$
15,352,411
153,681,397
0.010
¢
NPCC
$
56,165,133
279,294,891
0.020
¢
SERC
$
63,832,839
759,772,644
0.008
¢
SPP
$
12,324,949
171,100,266
0.007
¢
WSCC
$
61,665,308
627,001,373
0.010
¢
U.
S.
$
416,359,743
3,418,263,184
0.012
¢
Source:
U.
S.
DOE,
2001;
U.
S.
EPA
analysis,
2003.

To
determine
potential
effects
of
these
compliance
costs
on
electricity
prices,
EPA
compared
the
compliance
costs
per
KWh
of
sales
to
baseline
electricity
prices.
This
analysis
assumes
that
power
generators
fully
recover
compliance
costs
from
consumers
and
that
each
sector
(
i.
e.,
residential,

commercial,
industrial,
and
transportation)
bears
an
equal
burden
of
compliance
costs
per
MWh
of
purchased
electricity.

Table
17
below
shows
the
annualized
pre­
tax
compliance
cost
in
cents
per
KWh
of
electricity
sales
for
the
preferred
option
and
the
AEO
electricity
prices
for
2000
by
consumer
type.
In
addition,
the
table
presents
the
price
increase
by
consumer
type
that
would
result
from
the
rule.
Under
the
preferred
option,
the
largest
potential
increase
in
electricity
prices
would
be
0.36
percent
for
an
industrial
facility
in
NPCC.

The
average
increase
in
electricity
prices
would
be
between
0.14
percent
for
residential
customers
(
0.012/
8.84)
and
0.25
percent
for
industrial
customers
(
0.012/
4.90).
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
23
Table
17:
Estimated
Price
Increase
as
a
Percent
of
2000
Pricesa
by
Consumer
Type
and
NERC
Region
for
the
Preferred
Option
($
2002)

Region
Annualized
Pre­
Tax
Compliance
Cost
(
Cents
/

KWh
Sales)
Residential
Commercial
Industrial
Transportation
All
Sectors
Average
Price
%

Change
Price
%

Change
Price
%

Change
Price
%

Change
Price
%

Change
ECAR
0.015
8.07
0.18%
7.45
0.20%
4.64
0.32%
7.10
0.21%
6.46
0.23%

ERCOT
0.008
8.37
0.10%
7.43
0.11%
4.36
0.18%
6.56
0.12%
6.82
0.12%

FRCC
0.015
8.33
0.18%
7.20
0.21%
5.33
0.28%
6.52
0.23%
7.62
0.20%

MAAC
0.015
10.46
0.14%
9.22
0.16%
7.12
0.21%
9.16
0.17%
9.14
0.17%

MAIN
0.016
9.12
0.17%
7.62
0.21%
5.05
0.31%
7.58
0.21%
7.15
0.22%

MAPP
0.010
8.30
0.12%
6.85
0.15%
4.64
0.22%
6.78
0.15%
6.45
0.15%

NPCC
0.020
11.46
0.18%
8.42
0.24%
5.54
0.36%
8.36
0.24%
8.95
0.22%

SERC
0.008
7.36
0.11%
6.54
0.13%
4.21
0.20%
5.65
0.15%
6.10
0.14%

SPP
0.007
7.16
0.10%
6.10
0.12%
4.05
0.18%
5.16
0.14%
5.88
0.12%

WSCC
0.010
9.20
0.11%
8.05
0.12%
5.09
0.19%
6.86
0.14%
7.61
0.13%

U.
S.
0.012
8.84
0.14%
8.03
0.15%
4.90
0.25%
7.91
0.15%
7.33
0.17%

a
Prices
are
in
cents
per
KWh.

Source:
EPA
analysis,
2003.

Table
18
presents
the
annualized
cost
of
complying
with
the
waterbody/
capacity­
based
option,
total
electricity
sales
(
MWh),
and
the
cost
in
cents
per
kilowatt
hour
(
KWh)
of
total
electricity
sales
by
NERC
region.
The
costs
per
KWh
sales
range
from
0.007
cents
in
SPP
to
0.096
cents
in
MAAC.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
24
Table
18:
Compliance
Cost
per
KWh
of
Sales
by
NERC
Region
for
the
Waterbody/
Capacity­
Based
Option
NERC
Region
Annualized
Pre­
Tax
Compliance
Costs
(
National;
$
2002)
Total
Electricity
Sales
(
MWh;
2000)
Annualized
Pre­
Tax
Compliance
Cost
(
Cents
/

KWh
Sales)

ASCC
$
365,795
 
 
ECAR
$
78,527,538
517,730,286
0.015
¢
ERCOT
$
33,805,805
269,072,083
0.013
¢
FRCC
$
160,722,241
182,241,013
0.088
¢
HI
$
24,838,714
 
 
MAAC
$
236,666,387
246,302,490
0.096
¢
MAIN
$
36,778,203
231,949,219
0.016
¢
MAPP
$
15,449,356
153,681,397
0.010
¢
NPCC
$
172,926,197
279,294,891
0.062
¢
SERC
$
175,494,912
759,772,644
0.023
¢
SPP
$
12,428,707
171,100,266
0.007
¢
WSCC
$
331,813,043
627,001,373
0.053
¢
U.
S.
$
1,279,816,898
3,418,263,184
0.037
¢
Source:
U.
S.
DOE,
2001;
U.
S.
EPA
analysis,
2003.

Table
19
below
shows
the
annualized
pre­
tax
compliance
cost
in
cents
per
KWh
of
electricity
sales
for
the
waterbody/
capacity­
based
option
and
the
AEO
electricity
prices
for
2000
by
consumer
type.
In
addition,

the
table
presents
the
price
increase
by
consumer
type
that
would
result
from
the
rule.
Under
this
option,

the
largest
potential
increase
in
electricity
prices
would
be
1.66
percent
for
an
industrial
facility
in
FRCC.

The
average
increase
in
electricity
prices
would
only
be
between
0.42
percent
for
residential
customers
and
0.76
percent
for
industrial
customers.
Supporting
Documentation
of
Changes
to
Economic
Impacts
March
12,
2003
Page
25
Table
19:
Estimated
Price
Increase
as
a
Percent
of
2000
Pricesa
by
Consumer
Type
and
NERC
Region
for
the
Waterbody/
Capacity­
Based
Option
($
2002)

Region
Annualized
Pre­
Tax
Compliance
Cost
(
Cents
/

KWh
Sales)
Residential
Commercial
Industrial
Transportation
All
Sectors
Average
Price
%

Change
Price
%

Change
Price
%

Change
Price
%

Change
Price
%

Change
ECAR
0.015
8.07
0.19%
7.45
0.20%
4.64
0.33%
7.10
0.21%
6.46
0.23%

ERCOT
0.013
8.37
0.15%
7.43
0.17%
4.36
0.29%
6.56
0.19%
6.82
0.18%

FRCC
0.088
8.33
1.06%
7.20
1.23%
5.33
1.66%
6.52
1.35%
7.62
1.16%

MAAC
0.096
10.46
0.92%
9.22
1.04%
7.12
1.35%
9.16
1.05%
9.14
1.05%

MAIN
0.016
9.12
0.17%
7.62
0.21%
5.05
0.31%
7.58
0.21%
7.15
0.22%

MAPP
0.010
8.30
0.12%
6.85
0.15%
4.64
0.22%
6.78
0.15%
6.45
0.16%

NPCC
0.062
11.46
0.54%
8.42
0.73%
5.54
1.12%
8.36
0.74%
8.95
0.69%

SERC
0.023
7.36
0.31%
6.54
0.35%
4.21
0.55%
5.65
0.41%
6.10
0.38%

SPP
0.007
7.16
0.10%
6.10
0.12%
4.05
0.18%
5.16
0.14%
5.88
0.12%

WSCC
0.053
9.20
0.58%
8.05
0.66%
5.09
1.04%
6.86
0.77%
7.61
0.70%

U.
S.
0.037
8.84
0.42%
8.03
0.47%
4.90
0.76%
7.91
0.47%
7.33
0.51%

a
Prices
are
in
cents
per
KWh.

Source:
EPA
analysis,
2003.