§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
1
EPA
also
considered
other
models
that
are
more
commonly
used
for
private
sector
analyses
but
decided
to
focus
its
model
selection
process
on
models
developed
for
public
policy
analyses.

NODA
Version
 
March
12,
2003
B3­
1
Chapter
B3:
Electricity
Market
Model
Analysis
INTRODUCTION
The
section
316(
b)
Phase
II
Existing
Facilities
Rule
applies
to
a
subset
of
facilities
within
the
electric
power
generation
industry.
The
rule
applies
to
steam
electric
generating
units
that
use
cooling
water
withdrawn
directly
from
waters
of
the
U.
S.
Generating
units
with
a
non­
steam
prime
mover
and
those
steam
units
that
use
cooling
water
from
a
source
other
than
a
water
of
the
U.
S.
are
not
subject
to
this
rule.
In
addition,
this
rule
only
applies
to
plants
with
a
design
intake
flow
of
at
least
50
million
gallons
per
day
(
MGD).
However,
due
to
interdependencies
within
the
electric
power
market,
impacts
on
in­
scope
facilities
may
result
in
indirect
impacts
throughout
the
industry.
Direct
impacts
on
plants
subject
to
the
rule
may
include
changes
in
capacity
utilization,
generation,
and
profitability.
Potential
indirect
impacts
on
the
electric
power
industry
may
include
changes
to
the
generation
and
revenue
of
facilities
and
firms
not
subject
to
the
rule,
changes
to
bulk
system
reliability,
and
regional
and
national
impacts
such
as
changes
in
the
price
and
demand
for
electricity.

EPA
used
ICF
Consulting's
Integrated
Planning
Model
(
IPM
®
)
,
an
integrated
energy
market
model,
to
conduct
the
economic
analyses
supporting
the
section
316(
b)
Phase
II
rule.
The
model
addresses
the
interdependencies
within
the
electric
power
market
and
accounts
for
both
direct
and
indirect
impacts
of
regulatory
actions.
EPA
used
the
model
to
analyze
two
potential
effects
of
the
preferred
option
and
other
regulatory
options:
(
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.

The
remainder
of
this
chapter
presents
an
overview
of
the
IPM
and
the
results
of
the
IPM
analysis
for
the
preferred
option.
Chapter
B8:
Alternative
Options
­
Electricity
Market
Model
Analysis
presents
the
IPM
analysis
for
the
alternative
waterbody/
capacity­
based
option.

B3­
1
SUMMARY
COMPARISON
OF
ENERGY
MARKET
MODELS
EPA
conducted
research
to
identify
models
suitable
for
analysis
of
environmental
policies
that
affect
the
electric
power
industry.
Through
a
review
of
forecasting
studies
and
interviews
with
industry
personnel,
EPA
identified
three
potential
models
and
considered
each
for
the
analyses
in
support
of
the
Phase
II
rule:
(
1)
the
Department
of
Energy's
National
Energy
Modeling
System
(
NEMS),
(
2)
the
Department
of
Energy's
Policy
Office
Electricity
Modeling
System
(
POEMS),
and
(
3)
ICF
Consulting's
Integrated
Planning
Model
(
IPM).
These
models
are
widely
used
in
the
analysis
of
various
issues
related
to
public
policies
affecting
the
electric
power
generation
industry
and
have
been
reviewed.
1
The
three
models
considered
by
EPA
were
developed
to
meet
the
specific
needs
of
different
users;
they
therefore
differ
in
terms
of
structure
and
functionality.
EPA
established
a
set
of
modeling
and
logistical
criteria
to
select
the
model
that
is
best
CHAPTER
CONTENTS
B3­
1
Summary
Comparison
of
Energy
Market
Models.
B3­
1
B3­
2
Integrated
Planning
Model
Overview
.
.
.
.
.
.
.
.
.
.
.
B3­
3
B3­
2.1
Modeling
Methodology
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
3
B3­
2.2
Specifications
for
the
Section
316(
b)
Analysis
.
B3­
6
B3­
2.3
Model
Inputs
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
7
B3­
2.4
Model
Outputs
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
8
B3­
3
Economic
Impact
Analysis
Methodology
.
.
.
.
.
.
.
.
B3­
9
B3­
3.1
Market­
level
Impact
Measures
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
9
B3­
3.2
Facility­
level
Impact
Measures
.
.
.
.
.
.
.
.
.
.
.
.
B3­
10
B3­
4
Analysis
Results
for
the
Preferred
Option
.
.
.
.
.
.
.
B3­
12
B3­
4.1
Market
Analysis
for
2010
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
12
B3­
4.2
Analysis
of
Phase
II
Facilities
for
2010
.
.
.
.
.
.
B3­
18
B3­
4.3
Market
Analysis
for
2008
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
24
B3­
5
Uncertainties
and
Limitations
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
29
References
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
31
Appendix
to
Chapter
B3
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
32
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
2
Please
see
Section
B3­
A.
1
of
the
appendix
to
this
chapter
for
a
comparison
of
the
three
electricity
market
models
considered
for
this
analysis.

B3­
2
NODA
Version
 
March
12,
2003
suited
for
the
analysis
of
section
316(
b)
regulatory
options.
Modeling
criteria
refer
to
the
models'
technical
capabilities
that
are
required
to
provide
the
outputs
necessary
for
the
analysis
of
the
section
316(
b)
regulation.
They
include
the
following:

<
Redefining
model
plants
 
The
energy
market
models
considered
by
EPA
aggregate
similar
generating
units
into
model
plants
to
reduce
the
amount
of
time
required
to
run
the
model.
However,
such
an
aggregation
is
usable
only
if
the
aggregated
units
are
similar
in
the
base
case
and
also
have
similar
compliance
requirements
under
the
analyzed
policy
cases.
The
Phase
II
compliance
requirements
of
in­
scope
facilities
are
based
on
the
location,
design,
construction,
and
capacity
of
their
cooling
water
intake
structures
(
CWIS).
In
contrast,
the
existing
aggregation
of
these
models
is
based
on
factors
including
unit
age,
unit
type,
fuel
type,
capacity,
and
operating
costs.
Therefore,
the
model
used
for
the
Phase
II
analysis
had
to
be
able
to
accommodate
a
different
aggregation
scheme
for
model
plants
or
even
to
run
all
in­
scope
facilities
as
separate
model
plants.

<
Predicting
the
economic
retirement
of
generating
capacity
 
Compliance
with
Phase
II
regulation
may
increase
the
capital
and
operating
costs
of
some
facilities
to
a
point
where
it
is
no
longer
economically
profitable
to
operate
the
facility,
or
one
or
more
of
its
generating
units.
The
economically
sound
decision
for
a
firm
owning
such
a
facility
or
unit
would
be
to
retire
the
facility
or
unit
rather
than
comply
with
the
regulation.
Therefore,
the
model
needed
to
have
the
ability
to
project
early
retirements
as
a
result
of
compliance
with
section
316(
b)
regulation
and
the
market's
response
to
such
closures,
including
increased
capacity
additions
or
increased
market
prices.
In
addition,
to
support
EPA's
economic
impact
analysis,
the
model
had
to
be
able
to
map
early
retirements
to
specific
facilities
or
units.

<
Representing
the
impact
of
structural
changes
to
the
industry
from
deregulation
 
Assumptions
regarding
deregulation
of
the
electric
utility
industry
could
impact
a
model's
ability
to
accurately
depict
the
profit
maximizing
decisions
of
firms.
Deregulation
of
the
wholesale
market
for
electricity
is
expected
to
reduce
wholesale
prices
as
competition
in
markets
increases.
These
changes
may
impact
decisions
regarding
the
retirement
of
existing
generating
units,
investment
in
new
generating
units,
and
technology
and
fuel
choices
for
new
generation
capacity.
Therefore,
it
was
necessary
for
the
market
model
to
reflect
the
most
recent
trends
in
the
deregulation
of
wholesale
energy
markets.

EPA
also
considered
a
number
of
logistical
criteria
to
determine
the
most
appropriate
model
for
the
analyses
of
the
Phase
II
rule.
While
a
given
model
may
be
desirable
from
an
analytical
perspective,
its
use
may
be
restricted
due
to
other
limitations
unrelated
to
the
model's
capabilities.
The
logistical
criteria
used
to
evaluate
each
model
refer
to
administrative
issues
and
include
the
following:

<
Availability
of
the
model
 
Due
to
the
tight
regulatory
schedule
of
the
Phase
II
rule,
the
model
selected
for
this
analysis
had
to
be
accessible
at
the
time
data
inputs
were
available,
and
had
to
be
able
to
turn
around
the
analyses
in
a
relatively
short
period
of
time.
Some
of
the
models
considered
for
this
analysis
are
used
to
conduct
analyses
in
support
of
annual
reports.
Such
requirements
may
limit
access
to
the
model
and
the
staff
required
to
execute
the
model,
and
therefore
prevent
the
use
of
the
model
for
this
analysis.

<
Sufficient
documentation
of
methods
and
assumptions
 
Sufficient
documentation
of
the
model
structure
and
assumptions
was
required
to
allow
for
the
necessary
review
of
results
and
procedure.
While
it
may
not
be
possible
to
disclose
specific
details
of
the
structure
and
function
of
a
model,
a
general
discussion
of
the
mechanics
of
the
model,
its
assumptions,
inputs,
and
results
was
required
to
make
a
model
useable
for
this
analysis.

<
Cost
 
EPA
considered
the
cost
of
using
each
model
together
with
each
model's
ability
to
satisfy
the
other
modeling
and
logistical
criteria
in
determining
the
most
appropriate
model
for
the
analysis
of
this
rule.
The
model
had
to
be
sufficiently
robust
with
respect
to
the
other
criteria
while
remaining
within
the
budget
constraints
for
this
analysis.

EPA
assessed
each
market
model
with
respect
to
the
aforementioned
modeling
and
logistical
criteria
and
determined
that
the
IPM
was
best
suited
for
the
Phase
II
analysis.
2
A
principal
strength
of
the
IPM
as
compared
to
other
models
is
the
ability
to
evaluate
impacts
to
specific
facilities
subject
to
this
rule.
Another
important
advantage
of
the
IPM
model
is
that
it
has
a
history
of
prior
use
by
EPA.
The
Agency
has
successfully
used
the
IPM
in
support
of
a
number
of
major
air
rules.
Finally,
the
IPM
model
has
been
reviewed
and
approved
by
the
Office
of
Management
and
Budget
(
OMB).
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
3
The
EPA
Base
Case
2000
is
the
latest
EPA
specification
of
the
U.
S.
power
market
using
the
IPM.
Past
applications
of
the
IPM
for
EPA
analyses
have
used
a
predecessor
EPA
base
case
specification.
Section
B3­
A.
2
of
the
appendix
to
this
chapter
contains
a
summary
of
the
major
differences
between
the
EPA
Base
Case
2000
and
the
previous
EPA
base
case
specification.

4
EPA
used
the
IPM
to
forecast
operational
changes,
including
changes
in
capacity,
generation,
revenues,
electricity
prices,
and
plant
closures,
resulting
from
the
rule.
In
other
policy
analyses,
the
IPM
is
generally
also
used
to
determine
the
compliance
response
for
each
model
facility.
This
process
involves
selecting
the
optimal
response
from
a
menu
of
compliance
options
that
will
result
in
the
least­
cost
system
dispatch
and
new
resource
investment
decision.
Compliance
options
specified
by
IPM
may
include
fuel
switching,
repowering,
pollution
control
retrofit,
co­
firing
multiple
fuels,
dispatch
adjustments,
and
economic
retirement.
EPA
did
not
use
this
capability
to
choose
the
compliance
responses
of
the
facilities
subject
to
section
316(
b)
regulation.
Rather
EPA
exogenously
estimated
a
compliance
response
using
the
costs
of
technologies
capable
of
meeting
the
percentage
reductions
required
under
the
regulation.
In
the
postcompliance
analysis,
these
compliance
costs
were
added
as
model
inputs
to
the
base
case
operating
and
capital
costs.

5
Since
the
EPA
Base
Case
2000
model
plants
were
initially
created
to
support
air
policy
analyses,
the
original
configuration
was
not
appropriate
for
the
section
316(
b)
analysis.
See
the
discussion
of
model
plant
aggregation
in
Section
B3­
2.2
below.

NODA
Version
 
March
12,
2003
B3­
3
B3­
2
INTEGRATED
PLANNING
MODEL
OVERVIEW
This
section
presents
a
general
overview
of
the
capabilities
of
the
IPM,
including
a
discussion
of
the
modeling
methodology,
the
specification
of
the
model
for
the
section
316(
b)
analysis,
and
model
inputs
and
outputs.

B3­
2.1
Modeling
Methodology
a.
General
framework
The
IPM
is
an
engineering­
economic
optimization
model
of
the
electric
power
industry,
which
generates
least­
cost
resource
dispatch
decisions
based
on
user­
specified
constraints
such
as
environmental,
demand,
and
other
operational
constraints.
The
model
can
be
used
to
analyze
a
wide
range
of
electric
power
market
issues
at
the
plant,
regional,
and
national
levels.
In
the
past,
applications
of
the
IPM
have
included
capacity
planning,
environmental
policy
analysis
and
compliance
planning,
wholesale
price
forecasting,
and
asset
valuation.
3
The
IPM
uses
a
long­
term
dynamic
linear
programming
framework
that
simulates
the
dispatch
of
generating
capacity
to
achieve
a
demand
­
supply
equilibrium
on
a
seasonal
basis
and
by
region.
The
model
seeks
the
optimal
solution
to
an
"
objective
function,"
which
is
a
linear
equation
equal
to
the
present
value
of
the
sum
of
all
capital
costs,
fixed
and
variable
operation
and
maintenance
(
O&
M)
costs,
and
fuel
costs.
The
objective
function
is
minimized
subject
to
a
series
of
userdefined
supply
and
demand,
or
system
operating,
constraints.
Supply­
side
constraints
include
capacity
constraints,
availability
of
generation
resources,
plant
minimum
operating
constraints,
transmission
constraints,
and
environmental
constraints.
Demand­
side
constraints
include
reserve
margin
constraints
and
minimum
system­
wide
load
requirements.
The
optimal
solution
to
the
objective
function
is
the
least­
cost
mix
of
resources
required
to
satisfy
system
wide
electricity
demand
on
a
seasonal
basis
by
region.
In
addition
to
existing
capacity,
the
model
also
considers
new
resource
investment
options,
including
capacity
expansion
or
repowering
at
existing
plants
as
well
as
investment
in
new
plants.
The
model
selects
new
investments
while
considering
interactions
with
fuel
markets,
capacity
markets,
power
plant
cost
and
performance
characteristics,
forecasts
of
electricity
demand,
reliability
criteria,
and
other
constraints.
The
resulting
system
dispatch
is
optimized
given
the
resource
mix,
unit
operating
characteristics,
and
fuel
and
other
costs,
to
achieve
the
most
efficient
use
of
existing
and
new
resources
available
to
meet
demand.
The
model
is
dynamic
in
that
it
is
capable
of
using
forecasts
of
future
conditions
to
make
decisions
for
the
present.
4
b.
Model
plants
The
model
is
supported
by
a
database
of
boilers
and
electric
generation
units
which
includes
all
existing
utility­
owned
generation
units
as
well
as
those
located
at
plants
owned
by
independent
power
producers
and
cogeneration
facilities
that
contribute
capacity
to
the
electric
transmission
grid.
Individual
generators
are
aggregated
into
model
plants
with
similar
O&
M
costs
and
specific
operating
characteristics
including
seasonal
capacities,
heat
rates,
maintenance
schedules,
outage
rates,
fuels,
and
transmission
and
distribution
loss
characteristics.

The
number
and
aggregation
scheme
of
model
plants
can
be
adjusted
to
meet
the
specific
needs
of
each
analysis.
The
EPA
Base
Case
2000
contains
1,390
model
plants.
5
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
B3­
4
NODA
Version
 
March
12,
2003
PNW
CALI
NWPE
AZNM
RMPA
MAPP
SPPN
SPPS
ERCT
FRCC
ENTG
TVA
SOU
MANO
ECAO
VACA
MACS
MACE
LILC
WUMS
DSNYU
UPNY
MACW
NENG
MECS
NYC
c.
IPM
regions
The
IPM
divides
the
U.
S.
electric
power
market
into
26
regions
in
the
contiguous
U.
S.
It
does
not
include
generators
located
in
Alaska
or
Hawaii.
The
26
regions
map
into
North
American
Reliability
Council
(
NERC)
regions
and
sub­
regions.
The
IPM
models
electric
demand,
generation,
transmission,
and
distribution
within
each
region
and
across
the
transmission
grid
that
connects
regions.
For
the
analyses
presented
in
this
chapter,
IPM
regions
were
aggregated
back
into
NERC
regions.
Figure
B3­
1
provides
a
map
of
the
regions
included
in
the
IPM.
Table
B3­
1
presents
the
crosswalk
between
NERC
regions
and
IPM
regions.

Figure
B3­
1:
Regional
Representation
of
U.
S.
Power
System
as
Modeled
in
IPM
Source:
U.
S.
EPA,
2002.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
6
The
IPM
developed
output
for
a
total
of
five
model
run
years
2008,
2010,
2013,
2020,
and
2026.
Model
run
years
2020
and
2026
were
specified
for
model
balance,
while
run
years
2008,
2010,
and
2013
were
selected
to
provide
output
across
the
compliance
period.
Output
for
2026
was
not
used
in
this
analysis.

NODA
Version
 
March
12,
2003
B3­
5
Table
B3­
1:
Crosswalk
between
NERC
Regions
and
IPM
Regions
NERC
Region
IPM
Regions
ASCC
 
Alaska
Not
Included
ECAR
 
East
Central
Area
Reliability
Coordination
Agreement
ECAO,
MECS
ERCOT
 
Electric
Reliability
Council
of
Texas
ERCT
FRCC
 
Florida
Reliability
Coordinating
Council
FRCC
HI
 
Hawaii
Not
Included
MACC
 
Mid
Atlantic
Area
Council
MACE,
MACS,
MACW
MAIN
 
Mid­
America
Interconnect
Network
MANO,
WUMS
MAPP
 
Mid­
Continent
Area
Power
Pool
MAPP
NPCC
 
Northeast
Power
Coordination
Council
DSNY,
LILC,
NENG,
NYC,
UPNY
SERC
 
Southeastern
Electricity
Reliability
Council
ENTG,
SOU,
TVA,
VACA
SPP
­
Southwest
Power
Pool
SPPN,
SPPS
WSCC
 
Western
Systems
Coordinating
Council
AZNM,
CALI,
NWPE,
PNW,
RMPA
Source:
U.
S.
EPA,
2002.

d.
Model
run
years
The
IPM
models
the
electric
power
market
over
the
26­
year
period
2005
to
2030.
Due
to
the
data­
intensive
processing
procedures,
the
model
is
run
for
a
limited
number
of
years
only.
Run
years
are
selected
based
on
analytical
requirements
and
the
necessity
to
maintain
a
balanced
choice
of
run
years
throughout
the
modeled
time
horizon.
EPA
selected
the
following
run
years
for
this
analysis:
2008,
2010,
and
2013.6
The
model
run
years
were
selected
before
the
proposal
analysis
for
the
following
reasons:

<
2008
was
selected
based
on
the
assumption
that
all
in­
scope
facilities
would
be
required
to
comply
with
the
requirements
of
the
preferred
option
during
the
first
five
years
after
promulgation
(
at
the
time,
promulgation
was
scheduled
for
August
28,
2003
so
that
the
compliance
window
would
have
been
2004
to
2008).
Therefore,
in
2008,
all
facilities
would
have
been
in
compliance,
and
2008
would
have
represented
the
post­
compliance
state
of
the
industry.
<
2013
was
selected
based
on
the
assumption
that
facilities
costed
with
a
cooling
tower
(
a
requirement
for
some
facilities
under
the
two
alternative
options
analyzed
with
the
IPM
at
proposal)
would
have
to
comply
by
the
end
of
the
permit
term
of
the
first
permit
issued
after
promulgation
(
at
the
time,
this
was
2004
to
2012).
As
installation
of
a
cooling
tower
may
require
the
temporary
shut­
down
of
the
facility,
2013
would
have
represented
the
first
full,
post­
compliance
year
for
options
requiring
cooling
towers.
<
2010
was
selected
as
an
additional
year
during
which
facilities
costed
with
a
cooling
tower
may
experience
temporary
connection
outages
during
cooling
tower
installation
and
connection.

With
the
change
in
promulgation
date
from
August
28,
2003
to
February
16,
2004,
EPA
changed
its
compliance
year
assumptions
by
one
year
(
because
start­
up
activities
are
required
for
compliance
with
the
Phase
II
rule,
it
will
no
longer
be
possible
to
comply
in
2004).
However,
changing
run
years
requires
significant
structural
changes
to
the
IPM.
EPA
therefore
decided
not
to
change
the
model
run
years
selected
at
proposal
for
this
NODA
analysis.

The
model
assumes
that
capital
investment
decisions
are
only
implemented
during
run
years.
Each
model
run
year
is
mapped
to
several
calendar
years
such
that
changes
in
variable
costs,
available
capacity,
and
demand
for
electricity
in
the
years
between
the
run
years
are
partially
captured
in
the
results
for
each
model
run
year.
Table
B3­
2
below
identifies
the
model
run
years
specified
for
the
analysis
of
Phase
II
regulatory
options,
and
the
calendar
years
mapped
to
each.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
B3­
6
NODA
Version
 
March
12,
2003
Table
B3­
2:
Model
Run
Year
Mapping
Run
Year
Mapped
Years
2008
2005­
2009
2010
2010­
2012
2013
2013­
2015
2020
2016­
2022
2026
2023­
2030
Source:
IPM
model
specification
for
the
Section
316(
b)
NODA
Base
Cases.

EPA
mainly
relied
on
data
for
2010
in
the
analyses
of
the
preferred
option
(
presented
in
this
chapter)
and
on
data
for
2013
in
the
analyses
of
the
waterbody/
capacity­
based
option
(
presented
in
the
updated
Chapter
B8:
Alternative
Regulatory
Options
­
Electricity
Market
Model
Analysis).
Section
B3­
4
below
and
Section
B8­
1
in
Chapter
B8
describe
EPA's
rationale
for
selecting
these
model
run
years.

B3­
2.2
Specifications
for
the
Section
316(
b)
Analysis
The
analysis
of
regulatory
options
considered
for
Phase
II
regulation
required
changes
in
the
original
specification
of
the
IPM
model.
Specifically,
the
base
case
configuration
of
the
model
plants
and
model
run
years
were
revised
according
to
the
requirements
of
this
analysis.
Both
modifications
to
the
existing
model
specifications
are
discussed
below.

<
Changes
in
the
Aggregation
of
Model
Plants:
As
noted
above,
the
IPM
aggregates
individual
boilers
and
generators
with
similar
cost
and
operational
characteristics
into
model
plants.
Since
the
IPM
model
plants
were
initially
created
to
support
air
policy
analyses,
the
original
configuration
was
not
appropriate
for
the
section
316(
b)
analysis.
At
proposal,
the
steam
electric
generators
at
facilities
subject
to
the
Phase
II
rule
were
disaggregated
from
the
existing
IPM
model
plants
and
"
run"
as
individual
facilities
along
with
the
other
existing
model
plants.
This
change
increased
the
total
number
of
model
plants
from
1,390
to
1,777.
For
the
NODA
analysis,
EPA
also
disaggregated
non­
steam
generators
at
Phase
II
facilities
and
generators
at
facilities
subject
to
the
upcoming
Phase
III
regulation.
This
change
increased
the
total
number
of
model
plants
from
1,777
to
2,096.

<
Use
of
Different
Model
Run
Years:
The
original
specification
of
the
EPA
Base
Case
2000
of
the
IPM
uses
five
model
run
years
chosen
based
on
the
requirements
of
various
air
policy
analyses.
Because
EPA
assumed
that
all
facilities
subject
to
Phase
II
regulation
would
come
into
compliance
within
the
first
permitting
cycle
after
promulgation
in
2004
(
i.
e.,
2005
to
2013),
the
run
years
specified
for
the
EPA
Base
Case
2000
are
not
of
primary
interest
to
this
analysis.
Therefore,
EPA
selected
different
run
years
for
the
section
316(
b)
analysis
in
order
to
obtain
model
output
throughout
the
compliance
period
(
see
discussion
of
run
year
selection
in
section
B3­
2.1.
d
above).
The
change
in
run
years
and
run
year
mappings
are
summarized
below.

Table
B3­
3:
Modification
of
Model
Run
Years
EPA
Base
Case
2000
Specification
Section
316(
b)
Base
Case
Specification
Run
Year
Run
Year
Mapping
Run
Year
Run
Year
Mapping
2005
2005­
2007
2008
2005­
2009
2010
2008­
2012
2010
2010­
2012
2015
2013­
2017
2013
2013­
2015
2020
2018­
2022
2020
2016­
2022
2026
2023­
2030
2026
2023­
2030
Source:
IPM
model
specifications
for
the
EPA
Base
Case
2000
and
the
Section
316(
b)
NODA
Base
Cases.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
7
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.

8
No
facilities
under
the
preferred
option
were
costed
with
flow
reduction
technologies.
However,
44
facilities
were
costed
with
flow
reduction
technology
under
the
waterbody/
capacity­
based
option.

9
The
capital
charge
rate
is
a
function
of
capital
structure
(
debt/
equity
shares
of
an
investment),
pre­
tax
debt
rate
(
or
interest
cost),
debt
life,
post­
tax
return
on
equity,
corporate
income
tax,
depreciation
schedule,
book
life
of
the
investment,
and
other
costs
including
property
tax
and
insurance.
The
discount
rate
is
a
function
of
capital
structure,
pre­
tax
debt
rate,
and
post­
tax
return
on
equity.

NODA
Version
 
March
12,
2003
B3­
7
EPA
compared
the
base
case
results
generated
from
the
two
different
specifications
of
the
IPM
model.
The
base
case
results
could
only
be
compared
for
those
run
years
that
are
common
to
both
base
cases,
2010
and
2020.
This
comparison
identified
little
or
no
difference
in
the
base
case
results:

<
Base
case
total
production
costs
(
capital,
O&
M,
and
fuel)
using
the
revised
section
316(
b)
specifications
do
not
change
in
2010
and
are
lower
by
0.1%
in
2020.
<
Early
retirements
of
base
case
oil
and
gas
steam
capacity
under
the
section
316(
b)
specifications
are
lower
by
850
MW.
Early
retirements
of
base
case
nuclear
capacity
decreased
by
480
MW.
There
is
no
difference
in
the
early
retirement
of
coal
capacity.
<
The
change
in
model
specifications
results
in
virtually
no
change
in
base
case
coal
and
a
1.5
percent
reduction
in
gas
fuel
use
in
2010.

B3­
2.3
Model
Inputs
Compliance
costs
and
compliance­
related
capacity
reductions
are
the
primary
model
inputs
in
the
analysis
of
section
316(
b)
regulations.
EPA
determined
compliance
costs
for
each
of
the
531
facilities
subject
to
Phase
II
regulation
and
modeled
by
the
IPM.
7
For
each
facility,
compliance
costs
consist
of
capital
costs
(
including
costs
for
new
screens
or
fish
barrier
nets,
intake
relocation,
recirculating
system
modifications,
and
intake
piping
modification),
fixed
O&
M
costs,
variable
O&
M
costs,
permitting
costs,
and
capacity
reductions
(
for
information
on
the
costing
methodology,
see
the
Section
316(
b)
Technical
Development
Document,
DCN
4­
0004).
8
Capital
cost
inputs
into
the
IPM
are
expressed
as
a
fixed
O&
M
cost,
in
dollars
per
KW
of
capacity.
The
capital
costs
of
compliance
reflect
the
up­
front
cost
of
construction,
equipment,
and
capital
associated
with
the
installation
of
required
compliance
technologies.
The
IPM
uses
two
single
up­
front
cost
values
as
model
inputs
(
one
each
for
technologies
with
a
useful
life
of
10
and
30
years,
respectively)
and
translates
these
values
into
a
series
of
annual
post­
tax
payments
using
a
discount
rate
of
5.34
percent
and
a
capital
charge
rate
of
12
percent
for
the
duration
of
the
book
life
of
the
investment
(
assumed
to
be
30
years
for
recirculating
systems
and
10
years
for
other
compliance
technologies)
or
the
years
remaining
in
the
modeling
horizon,
whichever
is
shorter.
9
Fixed
O&
M
cost
inputs
into
the
IPM
are
expressed
in
terms
of
dollars
per
KW
of
capacity
per
year.

Variable
O&
M
cost
inputs
are
expressed
in
dollars
per
MWh
of
generation.

Permitting
costs
consist
of
initial
permitting
costs,
annual
monitoring
costs,
repermitting
costs
(
occurring
every
five
years
after
issuance
of
the
initial
permit),
and,
for
some
facilities,
pilot
study
costs.
Permitting
cost
inputs
are
expressed
as
follows:
initial
permitting
and
pilot
study
activities
are
necessary
for
the
on­
going
operation
of
the
plant
and
are
therefore
added
to
the
capital
costs
for
technologies
with
a
30­
year
useful
life;
annual
monitoring
and
annualized
repermitting
costs
are
added
to
the
fixed
O&
M
costs.

Capacity
reductions
consist
of
an
energy
penalty
and
a
one­
time
generator
downtime.
Energy
penalty
estimates
reflect
the
long­
term
reduction
in
capacity
due
to
the
on­
going
operation
of
compliance
technologies
and
are
expressed
in
terms
of
a
percentage
change
in
capacity.
Energy
penalties
were
only
applied
to
facilities
estimated
to
install
flow
reduction
technologies.
The
energy
penalty
consists
of
two
components:
(
1)
a
reduction
in
unit
efficiency
due
to
increased
turbine
back­
pressure
and
(
2)
an
increase
in
auxiliary
power
requirements
to
operate
the
cooling
tower
(
e.
g.,
for
pumping
and
fanning).
EPA's
estimate
of
O&
M
compliance
costs
already
includes
the
auxiliary
power
requirement
component
of
the
energy
penalty
(
see
Chapter
B1
of
the
EBA,
as
published
at
proposal,
http://
www.
epa.
gov/
ost/
316b/
econbenefits/
b1.
pdf).
However,
to
fully
capture
the
effect
of
the
energy
penalty
in
the
market
model
analysis,
both
components
of
the
energy
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
10
For
example,
a
facility
with
a
downtime
in
2008
was
modeled
as
if
1/
5th
of
its
downtime
occurred
in
each
year
between
2005
and
2009.
A
potential
drawback
of
this
approach
of
averaging
downtimes
over
the
mapped
years
is
that
the
snapshot
of
the
effect
of
downtimes
during
the
model
run
year
is
the
average
effect;
this
approach
does
not
model
potential
worst
case
effects
of
above­
average
amounts
of
capacity
being
down
in
any
one
NERC
region
during
any
one
year.

11
This
information
is
provided
in
Schedule
IV
­
Generator
Information,
Question
3.
A
(
Design
flow
rate
for
the
condenser
at
100%
load).
Design
intake
flow
data
at
the
generator
level
is
not
available
for
nonutilities
nor
for
those
utility
owned
plants
with
a
steam
generating
capacity
less
than
100
MW.
Generator­
level
design
intake
flow
data
were
not
available
for
57
of
the
531
modeled
facilities.

12
Repowering
in
the
IPM
consists
of
converting
oil/
gas
or
coal
capacity
to
combined­
cycle
capacity.
The
modeling
assumption
is
that
each
one
MW
of
existing
capacity
is
replaced
by
two
MW
of
repowered
capacity.

13
Nuclear
plants
are
evaluated
for
economic
viability
at
the
end
of
their
license
term.
Nuclear
units
that,
at
age
30,
did
not
make
a
major
maintenance
investment,
are
provided
with
a
10­
year
life
extension,
if
they
are
economically
viable.
These
same
units
may
subsequently
undertake
a
20­
year
re­
licensing
option
at
age
40.
Nuclear
units
that
already
had
made
a
maintenance
investment
are
provided
with
a
20­
year
re­
licensing
option
at
age
40,
if
they
are
economically
viable.
All
nuclear
units
are
ultimately
retired
at
age
60.

B3­
8
NODA
Version
 
March
12,
2003
penalty
needed
to
be
applied
as
a
percentage
reduction
in
capacity.
To
avoid
double­
counting
of
the
auxiliary
power
requirements,
EPA
did
not
apply
the
variable
component
of
O&
M
compliance
costs
to
facilities
estimated
to
install
flow
reduction
technologies
(
the
main
component
of
variable
O&
M
costs
associated
with
recirculating
systems
are
auxiliary
power
requirements).
Generator
downtime
estimates
reflect
the
amount
of
time
generators
are
off­
line
while
compliance
technologies
are
constructed
and/
or
installed
and
are
expressed
in
weeks.
In
contrast
to
the
energy
penalty,
the
generator
downtime
is
a
one­
time
event
that
affects
flow
reduction
technologies
and
several
other
compliance
technologies.
Generator
downtime
is
estimated
to
occur
during
the
year
when
a
facility
complies
with
the
policy
option.
Since
the
years
that
are
mapped
into
a
run
year
are
assumed
to
have
the
same
characteristics
as
the
run
year
itself,
generator
downtimes
were
applied
as
an
average
over
the
years
that
are
mapped
into
each
model
run
year.
10
The
IPM
operates
at
the
boiler
level.
It
was
therefore
necessary
to
distribute
facility­
level
costs
across
affected
boilers.
EPA
used
the
following
methodology:

<
Steam
electric
generators
operating
at
each
of
the
531
modeled
section
316(
b)
facilities
were
identified
using
data
from
Forms
EIA­
860A
and
860B
(
1998
and
1999).
<
Generator­
specific
design
intake
flows
were
obtained
from
Form
EIA­
767
(
1998).
11
<
Facility­
level
compliance
costs
were
distributed
across
each
facility's
steam
generators.
For
facilities
with
available
intake
flow
data,
this
distribution
was
based
on
each
generator's
proportion
of
total
design
intake
volume;
for
facilities
without
available
intake
flow,
this
distribution
was
based
on
each
generator's
proportion
of
total
steam
electric
capacity.
<
Generator­
level
compliance
costs
were
aggregated
to
the
boiler
level
based
on
the
EPA's
Base
Case
2000
cross­
walk
between
boilers
and
generators.

B3­
2.4
Model
Outputs
The
IPM
generates
a
series
of
outputs
on
different
levels
of
aggregation
(
boiler,
model
plant,
region,
and
nation).
The
economic
analysis
for
the
Phase
II
rule
used
a
subset
of
the
available
IPM
output.
For
each
model
run
(
base
case
and
each
analyzed
policy
option)
and
for
each
model
run
year
(
2008,
2010,
2013,
and
2020)
the
following
model
outputs
were
generated:

<
Capacity
 
Capacity
is
a
measure
of
the
ability
to
generate
electricity.
This
output
measure
reflects
the
summer
net
dependable
capacity
of
all
generating
units
at
the
plant.
The
model
differentiates
between
existing
capacity,
new
capacity
additions,
and
existing
capacity
that
has
been
repowered.
12
<
Early
Retirements
 
The
IPM
models
two
types
of
plant
closures:
closures
of
nuclear
plants
as
a
result
of
license
expiration
and
economic
closures
as
a
result
of
negative
net
present
value
of
future
operation.
13
This
analysis
only
considers
economic
closures
in
assessing
the
impacts
of
the
preferred
option
and
other
regulatory
alternatives.
However,
cases
where
a
nuclear
facility
decides
to
renew
its
license
in
the
base
case
but
does
not
renew
its
license
in
the
post­
compliance
case
for
a
given
policy
option
are
also
considered
economic
closures
and
an
impact
of
that
policy
option.

<
Energy
Price
 
The
average
annual
price
received
for
the
sale
of
electricity.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
14
EPA
conducted
model
runs
based
on
different
electricity
demand
assumptions:
(
1)
a
case
using
EPA's
electricity
demand
assumptions
and
(
2)
a
case
using
Annual
Energy
Outlook
(
AEO)
electricity
demand
assumptions.
The
analyses
presented
in
this
chapter
are
based
on
EPA's
electricity
demand
assumptions.
The
analyses
of
the
waterbody/
capacity­
based
option
presented
in
Chapter
8:
Alternative
Options:
Electricity
Market
Model
Analysis
are
based
on
AEO
electricity
demand
assumptions.

NODA
Version
 
March
12,
2003
B3­
9
<
Capacity
Price
 
The
premium
over
energy
prices
received
by
facilities
operating
in
peak
hours
during
which
system
load
approaches
available
capacity.
The
capacity
price
is
the
premium
required
to
stimulate
new
market
entrants
to
construct
additional
capacity,
cover
costs,
and
earn
a
return
on
their
investment.
This
price
manifests
as
short
term
price
spikes
during
peak
hours
and,
in
long­
run
equilibrium,
need
be
only
so
large
as
is
required
to
justify
investment
in
new
capacity.

<
Generation
 
The
amount
of
electricity
produced
by
each
plant
that
is
available
for
dispatch
to
the
transmission
grid
("
net
generation").

<
Energy
Revenue
 
Revenues
from
the
sale
of
electricity
to
the
grid.

<
Capacity
Revenue
 
Revenues
received
by
facilities
operating
in
hours
where
the
price
of
energy
exceeds
the
variable
production
cost
of
generation
for
the
next
unit
to
be
dispatched
at
that
price
in
order
to
maintain
reliable
energy
supply
in
the
short
run.
At
these
peak
hours,
the
price
of
energy
includes
a
premium
which
reflects
the
cost
of
the
required
reserve
margin
and
serves
to
stimulate
investment
in
the
additional
capacity
required
to
maintain
a
long
run
equilibrium
in
the
supply
and
demand
for
capacity.

<
Fuel
Costs
 
The
cost
of
fuel
consumed
in
the
generation
of
electricity.

<
Variable
Operation
and
Maintenance
Costs
 
Non­
fuel
O&
M
costs
that
vary
with
the
level
of
generation,
e.
g.,
cost
of
consumables,
including
water,
lubricants,
and
electricity.

<
Fixed
Operation
and
Maintenance
Costs
 
O&
M
costs
that
do
not
vary
with
the
level
of
generation,
e.
g.,
labor
costs
and
capital
expenditures
for
maintenance.
In
post­
compliance
scenarios,
fixed
O&
M
costs
also
include
annualized
capital
costs
of
compliance
and
permitting
costs.

<
Capital
Costs
 
The
cost
of
construction,
equipment,
and
capital.
Capital
costs
are
associated
with
investment
in
new
equipment,
e.
g.,
the
replacement
of
a
boiler
or
condenser,
installation
of
technologies
to
meet
the
requirements
of
air
regulations,
or
the
repowering
of
a
plant.

B3­
3
ECONOMIC
IMPACT
ANALYSIS
METHODOLOGY
The
outputs
presented
in
the
previous
section
were
used
to
identify
changes
to
economic
and
operational
characteristics
such
as
capacity,
generation,
revenue,
cost
of
generation,
and
electricity
prices
associated
with
Phase
II
regulatory
options.
EPA
developed
impact
measures
at
two
analytic
levels:
(
1)
the
market
as
a
whole,
including
all
facilities
and
(
2)
the
subset
of
inscope
Phase
II
facilities.
Both
analyses
were
conducted
by
NERC
region.
In
both
cases,
the
impacts
of
each
option
are
defined
as
the
difference
between
the
model
output
for
the
base
case
scenario
(
i.
e.,
the
model
run
in
the
absence
of
section
316(
b)
Phase
II
regulations)
14
and
the
post­
compliance
scenario.
The
following
subsections
describe
the
impact
measures
used
for
the
two
levels
of
analysis.

B3­
3.1
Market­
level
Impact
Measures
The
market­
level
analysis
evaluates
regional
changes
as
a
result
of
Phase
II
regulatory
options.
Seven
main
measures
are
analyzed:

<
(
1)
Changes
in
available
capacity:
This
measure
analyzes
changes
in
the
capacity
available
to
generate
electricity.
A
long­
term
reduction
in
availability
may
be
the
result
of
the
energy
penalty
associated
with
the
installation
of
recirculating
systems,
and
of
partial
or
full
closures
of
plants
subject
to
the
rule.
In
the
short
term,
temporary
plant
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
15
Such
short­
term
capacity
reductions
would
not
be
expressed
as
changes
in
available
capacity
but
might
affect
electricity
generation,
production
costs,
and/
or
prices.

B3­
10
NODA
Version
 
March
12,
2003
shut­
downs
for
the
installation
of
Phase
II
compliance
technologies
may
lead
to
reductions
in
available
capacity.
15
When
analyzing
changes
in
available
capacity,
EPA
distinguished
between
existing
capacity,
new
capacity
additions,
and
repowering
additions.
Under
this
measure,
EPA
also
analyzed
capacity
closures.
Only
capacity
that
is
projected
to
remain
operational
in
the
base
case
but
is
closed
in
the
post­
compliance
case
is
considered
a
closure
as
the
result
of
the
rule.
An
option
may
result
in
partial
(
i.
e.,
unit)
or
full
plant
closures.
An
option
may
also
result
in
avoided
closures
if
a
facility's
compliance
costs
are
low
relative
to
other
affected
facilities.
An
avoided
closure
is
a
unit
or
plant
that
would
close
in
the
base
case
but
operates
in
the
post­
compliance
case.

<
(
2)
Changes
in
the
price
of
electricity:
This
measure
considers
changes
in
regional
prices
as
a
result
of
Phase
II
regulation.
In
the
long
term,
electricity
prices
may
change
as
a
result
of
increased
production
costs
of
the
Phase
II
facilities.
In
the
short­
term,
price
increases
may
be
higher
if
large
power
plants
have
to
temporarily
shut
down
to
construct
and/
or
install
Phase
II
compliance
technologies.
This
analysis
considers
changes
in
both
energy
prices
and
capacity
prices.

<
(
3)
Changes
in
generation:
This
measure
considers
the
amount
of
electricity
generated.
At
a
regional
level,
longterm
changes
in
generation
may
be
the
result
of
plant
closures,
energy
penalties,
or
a
change
in
the
amount
of
electricity
traded
between
regions.
In
the
short
term,
temporary
plant
shut­
downs
to
install
Phase
II
compliance
technologies
may
lead
to
reductions
in
generation.
At
the
national
level,
the
demand
for
electricity
does
not
change
between
the
base
case
and
the
analyzed
policy
options
(
generation
within
the
regions
is
allowed
to
vary).
However,
demand
for
electricity
does
vary
across
the
modeling
horizon
according
to
the
model's
underlying
electricity
demand
growth
assumptions.

<
(
4)
Changes
in
revenues:
This
measure
considers
the
revenues
realized
by
all
facilities
in
the
market
and
includes
both
energy
revenues
and
capacity
revenues
(
see
definition
in
section
B3­
2.4
above).
A
change
in
revenues
could
be
the
result
of
a
change
in
generation
and/
or
a
the
price
of
electricity.

<
(
5)
Changes
in
costs:
This
measure
considers
changes
in
the
overall
cost
of
generating
electricity,
including
fuel
costs,
variable
and
fixed
O&
M
costs,
and
capital
costs.
Fuel
costs
and
variable
O&
M
costs
are
production
costs
that
vary
with
the
level
of
generation.
Fuel
costs
generally
account
for
the
single
largest
share
of
production
costs.
Fixed
O&
M
costs
and
capital
costs
do
not
vary
with
generation.
They
are
fixed
in
the
short­
term
and
therefore
do
not
affect
the
dispatch
decision
of
a
unit
(
given
sufficient
demand,
a
unit
will
dispatch
as
long
as
the
price
of
electricity
is
at
least
equal
to
its
per
MWh
production
costs).
However,
in
the
long­
run,
these
costs
need
to
be
recovered
for
a
unit
to
remain
economically
viable.

<
(
6)
Changes
in
pre­
tax
income:
Pre­
tax
income
is
defined
as
total
revenues
minus
total
costs
and
is
an
indicator
of
profitability.
Pre­
tax
income
may
decrease
as
a
result
of
reductions
in
revenues
and/
or
increases
in
costs.

<
(
7)
Changes
in
variable
production
costs
per
MWh:
This
measure
considers
the
regional
change
in
average
variable
production
cost
per
MWh.
Variable
production
costs
include
fuel
costs
and
other
variable
O&
M
costs
but
exclude
fixed
O&
M
costs
and
capital
costs.
Production
cost
per
MWh
is
a
primary
determinant
of
how
often
a
power
plant's
units
are
dispatched.
This
measure
presents
similar
information
to
total
fuel
and
variable
O&
M
costs
under
measure
(
5)
above,
but
normalized
for
changes
in
generation.

B3­
3.2
Facility­
level
Impact
Measures
EPA
used
the
IPM
results
to
analyze
impacts
on
in­
scope
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
in­
scope
Phase
II
facilities.

a.
In­
scope
Phase
II
facilities
as
a
group
The
analysis
of
the
in­
scope
Phase
II
facilities
as
a
group
is
largely
similar
to
the
market­
level
analysis
described
in
Section
B3­
3.1
above,
except
that
the
base
case
and
policy
option
totals
only
include
the
economic
activities
of
the
531
in­
scope
Phase
II
facilities
represented
by
the
model.
In
addition,
a
few
measures
differ:
(
1)
new
capacity
additions
and
prices
are
not
relevant
at
the
facility
level,
(
2)
the
number
of
Phase
II
facilities
that
experience
closure
of
all
their
steam
electric
capacity
is
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
16
Such
short­
term
capacity
reductions
would
not
be
expressed
as
changes
in
available
capacity
but
might
affect
electricity
generation,
production
costs,
and/
or
prices.

NODA
Version
 
March
12,
2003
B3­
11
presented,
and
(
3)
repowering
changes
are
not
explicitly
analyzed
at
the
facility
level.
Following
are
the
measures
evaluated
for
the
group
of
Phase
II
facilities:

<
(
1)
Changes
in
available
capacity:
This
measure
considers
the
capacity
available
at
the
531
Phase
II
facilities.
A
long­
term
reduction
in
availability
may
be
the
result
of
the
energy
penalty
associated
with
the
installation
of
recirculating
systems,
partial
or
full
plant
closures,
a
change
in
the
decision
to
repower,
or
a
change
in
the
choice
of
air
pollution
control
technologies.
In
the
short
term,
temporary
plant
shut­
downs
for
the
installation
of
Phase
II
compliance
technologies
may
lead
to
reductions
in
available
capacity.
16
Under
this
measure,
EPA
also
analyzed
closures.
Only
capacity
that
is
projected
to
remain
operational
in
the
base
case
but
is
closed
in
the
post­
compliance
case
is
considered
a
closure
as
the
result
of
the
rule.
An
option
may
result
in
partial
(
i.
e.,
unit)
or
full
plant
closures.
An
option
may
also
result
in
avoided
closures
if
a
facility's
compliance
costs
are
low
relative
to
other
affected
facilities.
An
avoided
closure
is
a
unit
or
plant
that
would
close
in
the
base
case
but
operates
in
the
post­
compliance
case.
At
the
facility­
level,
both
the
number
of
full
closure
facilities
and
closure
capacity
are
analyzed.

<
(
2)
Changes
in
generation:
This
measure
considers
the
generation
at
the
531
Phase
II
facilities.
Long­
term
changes
in
generation
may
be
the
result
of
a
reduction
in
available
capacity
(
see
discussion
above)
or
the
less
frequent
dispatch
of
a
plant
due
to
higher
production
cost
as
a
result
of
the
policy
option.
In
the
short
term,
temporary
plant
shut­
downs
may
lead
to
reductions
in
generation
at
some
of
the
531
Phase
II
facilities.
For
some
Phase
II
facilities,
Phase
II
regulation
may
lead
to
an
increase
in
generation
if
their
compliance
costs
are
low
relative
to
other
affected
facilities.

<
(
3)
Changes
in
revenues:
This
measure
considers
the
revenues
realized
by
the
531
Phase
II
facilities
and
includes
both
energy
revenues
and
capacity
revenues
(
see
definition
in
section
B3­
2.4
above).
A
change
in
revenues
could
be
the
result
of
a
change
in
generation
and/
or
the
price
of
electricity.
For
some
modeled
316(
b)
facilities,
Phase
II
regulation
may
lead
to
an
increase
in
revenues
if
their
generation
increases
as
a
result
of
the
rule,
or
if
the
rule
leads
to
an
increase
in
electricity
prices.

<
(
4)
Changes
in
costs:
This
measure
considers
changes
in
the
overall
cost
of
generating
electricity
for
the
531
Phase
II
facilities,
including
fuel
costs,
variable
and
fixed
O&
M
costs,
and
capital
costs.
Fuel
costs
and
variable
O&
M
costs
are
production
costs
that
vary
with
the
level
of
generation.
Fuel
costs
generally
account
for
the
single
largest
share
of
production
costs.
Fixed
O&
M
costs
and
capital
costs
do
not
vary
with
generation.
They
are
fixed
in
the
short­
term
and
therefore
do
not
affect
the
dispatch
decision
of
a
unit
(
given
sufficient
demand,
a
unit
will
dispatch
as
long
as
the
price
of
electricity
is
at
least
equal
to
its
per
MWh
production
costs).
However,
in
the
long­
run,
these
costs
need
to
be
recovered
for
a
unit
to
remain
economically
viable.

<
(
5)
Changes
in
pre­
tax
income:
Pre­
tax
income
is
defined
as
total
revenues
minus
total
costs
and
is
an
indicator
of
profitability.
Pre­
tax
income
may
decrease
as
a
result
of
reductions
in
revenues
and/
or
increases
in
costs.

<
(
6)
Changes
in
variable
production
costs
per
MWh:
This
measure
considers
the
plant­
level
change
in
the
average
annual
variable
production
cost
per
MWh.
Variable
production
costs
include
fuel
costs
and
other
variable
O&
M
costs
but
exclude
fixed
O&
M
costs
and
capital
costs.

b.
Individual
Phase
II
facilities
To
assess
potential
distributional
impacts
among
individual
Phase
II
facilities,
EPA
analyzed
facility­
specific
changes
to
a
number
of
key
measures.
For
each
measure,
EPA
determined
the
number
of
Phase
II
facilities
that
experience
an
increase
or
a
reduction,
respectively,
within
three
ranges:
1
percent
or
less,
1
to
3
percent,
and
3
percent
or
more.
EPA
conducted
this
analysis
for
the
following
measures:

<
(
1)
Changes
in
capacity
utilization:
Capacity
utilization
is
defined
as
a
unit's
actual
generation
divided
by
its
potential
generation,
if
it
ran
100
percent
of
the
time
(
i.
e.,
generation
/
(
capacity
*
365
days
*
24
hours)).
This
measure
indicates
how
frequently
a
unit
is
dispatched
and
earns
energy
revenues
for
its
owner.

<
(
2)
Changes
in
generation:
See
explanation
in
subsection
a.
above.

<
(
3)
Changes
in
revenues:
See
explanation
in
subsection
a.
above.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
B3­
12
NODA
Version
 
March
12,
2003
<
(
4)
Changes
in
variable
production
costs
per
MWh:
See
explanation
in
subsection
a.
above.

<
(
5)
Changes
in
fuel
costs
per
MWh:
See
explanation
in
subsection
a.
above.

<
(
6)
Changes
in
pre­
tax
income:
See
explanation
in
subsection
a.
above.

B3­
4
ANALYSIS
RESULTS
FOR
THE
PREFERRED
OPTION
The
remainder
of
this
section
presents
the
results
of
the
economic
impact
analysis
of
the
preferred
option
for
the
ten
NERC
regions
modeled
by
the
IPM.
The
analysis
is
based
on
IPM
output
for
the
base
case
(
using
EPA
electricity
demand
assumptions)
and
the
preferred
option.
Results
are
presented
at
the
market
level
and
the
Phase
II
facility
level.

The
main
analysis
in
this
chapter
uses
output
from
model
run
year
2010.
Facilities
subject
to
the
preferred
option
are
expected
to
come
into
compliance
during
the
year
of
their
first
post­
promulgation
permit
(
2005
to
2009).
Therefore,
2010
is
the
first
year
during
which
all
facilities
are
in
compliance,
but
no
facilities
experience
technology
installation
downtimes.
2010
thus
represents
the
post­
compliance
condition
of
the
industry.
EPA
also
analyzed
potential
market­
level
impacts
of
the
preferred
option
for
a
year
within
the
compliance
period
during
which
some
Phase
II
facilities
experience
installation
downtimes.
This
secondary
analysis
represents
potential
short­
term
impacts
of
the
preferred
option
and
uses
output
from
model
run
year
2008.

B3­
4.1
Market
Analysis
for
2010
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.

Table
B3­
4
presents
the
market­
level
impact
measures
discussed
in
section
B3­
3.1
above:
(
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;
and
(
7)
changes
in
variable
production
costs
per
MWh.
For
each
measure,
the
table
presents
the
results
for
the
base
case
and
the
preferred
option,
the
absolute
difference
between
the
two
cases,
and
the
percentage
difference.

Table
B3­
4:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
National
Totals
(
1)
Total
Domestic
Capacity
(
MW)
887,915
887,933
18
0.0%

(
1a)
Existing
787,280
786,500
(
780)
(
0.1)%

(
1b)
New
Additions
79,683
79,770
87
0.1%

(
1c)
Repowering
Additions
20,951
21,662
711
3.4%
(
1d)
Closures
14,122
14,556
434
3.1%

(
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)
4,113,839
4,113,898
59
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
138,770
$
138,719
($
52)
0.0%

(
5)
Costs
(
Millions;
$
2002)
$
87,486
$
87,989
$
503
0.6%

(
5a)
Fuel
Cost
$
47,789
$
47,804
$
15
0.0%

(
5b)
Variable
O&
M
$
7,926
$
7,931
$
6
0.1%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
4:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B3­
13
(
5c)
Fixed
O&
M
$
23,417
$
23,848
$
430
1.8%

(
5d)
Capital
Cost
$
8,354
$
8,406
$
52
0.6%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
51,284
$
50,730
($
554)
(
1.1)%

(
7)
Variable
Production
Costs
($/
MWh)
$
13.54
$
13.55
$
0.00
0.0%

East
Central
Area
Reliability
Coordination
Agreement
(
ECAR)

(
1)
Total
Domestic
Capacity
(
MW)
118,529
118,529
0
0.0%

(
1a)
Existing
110,066
110,066
0
0.0%

(
1b)
New
Additions
8,394
8,394
0
0.0%

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

(
2a)
Energy
Prices
($
2002/
MWh)
$
22.63
$
22.64
$
0.01
0.0%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
56.08
$
56.12
$
0.04
0.1%

(
3)
Generation
(
GWh)
$
649,024
$
647,985
($
1,040)
(
0.2)%

(
4)
Revenues
(
Millions;
$
2002)
$
21,317
$
21,305
($
12)
(
0.1)%

(
5)
Costs
(
Millions;
$
2002)
$
12,492
$
12,580
$
88
0.7%

(
5a)
Fuel
Cost
$
6,367
$
6,362
($
5)
(
0.1)%

(
5b)
Variable
O&
M
$
1,585
$
1,585
$
0
0.0%

(
5c)
Fixed
O&
M
$
3,570
$
3,664
$
94
2.6%

(
5d)
Capital
Cost
$
970
$
969
($
1)
(
0.1)%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
8,825
$
8,725
($
100)
(
1.1)%

(
7)
Variable
Production
Costs
($/
MWh)
$
12.25
$
12.26
$
0.01
0.1%

Electric
Reliability
Council
of
Texas
(
ERCOT)

(
1)
Total
Domestic
Capacity
(
MW)
75,290
75,290
0
0.0%

(
1a)
Existing
71,901
71,728
(
172)
(
0.2)%

(
1b)
New
Additions
2,053
1,880
(
173)
(
8.4)%

(
1c)
Repowering
Additions
1,336
1,681
345
25.9%
(
1d)
Closures
0
0
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
29.38
$
31.18
$
1.80
6.1%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
14.09
$
4.26
($
9.83)
(
69.8)%

(
3)
Generation
(
GWh)
336,956
336,659
(
297)
(
0.1)%

(
4)
Revenues
(
Millions;
$
2002)
$
10,961
$
10,818
($
143)
(
1.3)%

(
5)
Costs
(
Millions;
$
2002)
$
8,000
$
8,034
$
34
0.4%

(
5a)
Fuel
Cost
$
5,241
$
5,234
($
7)
(
0.1)%

(
5b)
Variable
O&
M
$
699
$
700
$
1
0.2%

(
5c)
Fixed
O&
M
$
1,730
$
1,756
$
25
1.5%

(
5d)
Capital
Cost
$
330
$
344
$
14
4.2%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,961
$
2,784
($
176)
(
6.0)%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
4:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
B3­
14
NODA
Version
 
March
12,
2003
(
7)
Variable
Production
Costs
($/
MWh)
$
17.63
$
17.63
$
0.00
0.0%

Florida
Reliability
Coordinating
Council
(
FRCC)

(
1)
Total
Domestic
Capacity
(
MW)
50,324
50,324
0
0.0%

(
1a)
Existing
39,262
39,267
5
0.0%

(
1b)
New
Additions
11,062
11,057
(
5)
0.0%

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

(
2a)
Energy
Prices
($
2002/
MWh)
$
29.39
$
29.55
$
0.16
0.6%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
37.79
$
36.82
($
0.97)
(
2.6)%

(
3)
Generation
(
GWh)
189,076
188,878
(
199)
(
0.1)%

(
4)
Revenues
(
Millions;
$
2002)
$
7,459
$
7,435
($
24)
(
0.3)%

(
5)
Costs
(
Millions;
$
2002)
$
5,406
$
5,445
$
39
0.7%

(
5a)
Fuel
Cost
$
3,106
$
3,114
$
8
0.3%

(
5b)
Variable
O&
M
$
364
$
365
$
2
0.4%

(
5c)
Fixed
O&
M
$
1,184
$
1,219
$
35
3.0%

(
5d)
Capital
Cost
$
753
$
747
($
6)
(
0.8)%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,053
$
1,990
($
63)
(
3.1)%

(
7)
Variable
Production
Costs
($/
MWh)
$
18.35
$
18.42
$
0.07
0.4%

Mid­
Atlantic
Area
Council
(
MAAC)

(
1)
Total
Domestic
Capacity
(
MW)
63,784
63,784
0
0.0%

(
1a)
Existing
56,355
56,355
0
0.0%

(
1b)
New
Additions
5,771
5,771
0
0.0%

(
1c)
Repowering
Additions
1,658
1,658
0
0.0%
(
1d)
Closures
2,831
2,831
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
26.74
$
26.75
$
0.01
0.0%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
50.61
$
50.36
($
0.25)
(
0.5)%

(
3)
Generation
(
GWh)
276,051
276,530
480
0.2%

(
4)
Revenues
(
Millions;
$
2002)
$
10,605
$
10,605
$
0
0.0%

(
5)
Costs
(
Millions;
$
2002)
$
6,124
$
6,166
$
41
0.7%

(
5a)
Fuel
Cost
$
3,066
$
3,069
$
2
0.1%

(
5b)
Variable
O&
M
$
557
$
559
$
1
0.2%

(
5c)
Fixed
O&
M
$
1,929
$
1,966
$
36
1.9%

(
5d)
Capital
Cost
$
571
$
573
$
2
0.3%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
4,481
$
4,439
($
41)
(
0.9)%

(
7)
Variable
Production
Costs
($/
MWh)
$
13.13
$
13.12
($
0.01)
(
0.1)%

Mid­
America
Interconnected
Network
(
MAIN)

(
1)
Total
Domestic
Capacity
(
MW)
59,494
59,349
(
145)
(
0.2)%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
4:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B3­
15
(
1a)
Existing
51,551
51,121
(
430)
(
0.8)%

(
1b)
New
Additions
7,943
8,228
285
3.6%

(
1c)
Repowering
Additions
0
0
0
0.0%
(
1d)
Closures
5,191
5,625
434
8.4%

(
2a)
Energy
Prices
($
2002/
MWh)
$
22.66
$
22.60
($
0.06)
(
0.3)%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
54.31
$
54.72
$
0.42
0.8%

(
3)
Generation
(
GWh)
281,625
281,411
(
214)
(
0.1)%

(
4)
Revenues
(
Millions;
$
2002)
$
9,607
$
9,601
($
6)
(
0.1)%

(
5)
Costs
(
Millions;
$
2002)
$
5,795
$
5,817
$
22
0.4%

(
5a)
Fuel
Cost
$
2,930
$
2,956
$
26
0.9%

(
5b)
Variable
O&
M
$
586
$
584
($
2)
(
0.3)%

(
5c)
Fixed
O&
M
$
1,710
$
1,701
($
9)
(
0.5)%

(
5d)
Capital
Cost
$
569
$
576
$
7
1.2%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,812
$
3,783
($
28)
(
0.7)%

(
7)
Variable
Production
Costs
($/
MWh)
$
12.48
$
12.58
$
0.09
0.8%

Mid­
Continent
Area
Power
Pool
(
MAPP)

(
1)
Total
Domestic
Capacity
(
MW)
35,835
35,835
0
0.0%

(
1a)
Existing
32,672
32,672
0
0.0%

(
1b)
New
Additions
3,163
3,163
0
0.0%

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

(
2a)
Energy
Prices
($
2002/
MWh)
$
21.86
$
21.77
($
0.08)
(
0.4)%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
54.00
$
54.47
$
0.47
0.9%

(
3)
Generation
(
GWh)
181,713
181,598
(
115)
(
0.1)%

(
4)
Revenues
(
Millions;
$
2002)
$
5,878
$
5,878
($
1)
0.0%

(
5)
Costs
(
Millions;
$
2002)
$
3,430
$
3,445
$
15
0.4%

(
5a)
Fuel
Cost
$
1,722
$
1,719
($
3)
(
0.2)%

(
5b)
Variable
O&
M
$
381
$
381
$
0
0.0%

(
5c)
Fixed
O&
M
$
1,017
$
1,034
$
18
1.7%

(
5d)
Capital
Cost
$
311
$
311
$
0
0.0%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,448
$
2,433
($
16)
(
0.6)%

(
7)
Variable
Production
Costs
($/
MWh)
$
11.57
$
11.56
($
0.01)
(
0.1)%

Northeast
Power
Coordinating
Council
(
NPCC)

(
1)
Total
Domestic
Capacity
(
MW)
72,477
72,465
(
12)
0.0%

(
1a)
Existing
59,515
59,371
(
143)
(
0.2)%

(
1b)
New
Additions
2,082
1,926
(
155)
(
7.5)%

(
1c)
Repowering
Additions
10,881
11,168
287
2.6%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
4:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
B3­
16
NODA
Version
 
March
12,
2003
(
1d)
Closures
4,107
4,107
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
29.88
$
30.16
$
0.28
0.9%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
43.23
$
43.30
$
0.06
0.2%

(
3)
Generation
(
GWh)
278,649
278,809
160
0.1%

(
4)
Revenues
(
Millions;
$
2002)
$
11,220
$
11,305
$
85
0.8%

(
5)
Costs
(
Millions;
$
2002)
$
7,732
$
7,790
$
57
0.7%

(
5a)
Fuel
Cost
$
4,479
$
4,467
($
12)
(
0.3)%

(
5b)
Variable
O&
M
$
376
$
373
($
3)
(
0.7)%

(
5c)
Fixed
O&
M
$
1,781
$
1,846
$
65
3.6%

(
5d)
Capital
Cost
$
1,096
$
1,104
$
7
0.7%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,488
$
3,515
$
28
0.8%

(
7)
Variable
Production
Costs
($/
MWh)
$
17.42
$
17.36
($
0.06)
(
0.4)%

Southeastern
Electric
Reliability
Council
(
SERC)

(
1)
Total
Domestic
Capacity
(
MW)
194,485
194,528
42
0.0%

(
1a)
Existing
164,544
164,544
0
0.0%

(
1b)
New
Additions
29,941
29,983
42
0.1%

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

(
2a)
Energy
Prices
($
2002/
MWh)
$
24.64
$
24.64
$
0.00
0.0%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
48.23
$
48.31
$
0.09
0.2%

(
3)
Generation
(
GWh)
944,631
945,455
825
0.1%

(
4)
Revenues
(
Millions;
$
2002)
$
32,644
$
32,678
$
34
0.1%

(
5)
Costs
(
Millions;
$
2002)
$
19,753
$
19,854
$
101
0.5%

(
5a)
Fuel
Cost
$
10,314
$
10,314
($
1)
0.0%

(
5b)
Variable
O&
M
$
1,785
$
1,789
$
4
0.2%

(
5c)
Fixed
O&
M
$
5,264
$
5,344
$
80
1.5%

(
5d)
Capital
Cost
$
2,389
$
2,407
$
19
0.8%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
12,891
$
12,824
($
68)
(
0.5)%

(
7)
Variable
Production
Costs
($/
MWh)
$
12.81
$
12.80
($
0.01)
(
0.1)%

Southwest
Power
Pool
(
SPP)

(
1)
Total
Domestic
Capacity
(
MW)
49,948
50,092
144
0.3%

(
1a)
Existing
48,956
48,901
(
55)
(
0.1)%

(
1b)
New
Additions
992
1,081
89
8.9%

(
1c)
Repowering
Additions
0
111
111
0.0%
(
1d)
Closures
0
0
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
24.34
$
24.30
($
0.04)
(
0.2)%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
40.97
$
41.20
$
0.23
0.6%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
4:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B3­
17
(
3)
Generation
(
GWh)
221,527
221,961
435
0.2%

(
4)
Revenues
(
Millions;
$
2002)
$
7,434
$
7,453
$
18
0.2%

(
5)
Costs
(
Millions;
$
2002)
$
4,254
$
4,285
$
31
0.7%

(
5a)
Fuel
Cost
$
2,701
$
2,704
$
3
0.1%

(
5b)
Variable
O&
M
$
422
$
422
$
0
(
0.1)%

(
5c)
Fixed
O&
M
$
1,042
$
1,057
$
15
1.5%

(
5d)
Capital
Cost
$
88
$
101
$
13
14.8%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,181
$
3,168
($
13)
(
0.4)%

(
7)
Variable
Production
Costs
($/
MWh)
$
14.10
$
14.09
($
0.01)
(
0.1)%

Western
Systems
Coordinating
Council
(
WSCC)

(
1)
Total
Domestic
Capacity
(
MW)
167,748
167,737
(
11)
0.0%

(
1a)
Existing
152,459
152,475
16
0.0%

(
1b)
New
Additions
8,283
8,288
5
0.1%

(
1c)
Repowering
Additions
7,006
6,974
(
32)
(
0.5)%
(
1d)
Closures
705
705
0
0.0%

(
2a)
Energy
Prices
($
2002/
MWh)
$
27.19
$
27.18
($
0.01)
0.0%

(
2b)
Capacity
Prices
($
2002/
KW/
yr)
$
7.56
$
7.58
$
0.02
0.2%

(
3)
Generation
(
GWh)
754,587
754,611
24
0.0%

(
4)
Revenues
(
Millions;
$
2002)
$
21,645
$
21,643
($
3)
0.0%

(
5)
Costs
(
Millions;
$
2002)
$
14,499
$
14,574
$
75
0.5%

(
5a)
Fuel
Cost
$
7,863
$
7,865
$
2
0.0%

(
5b)
Variable
O&
M
$
1,171
$
1,173
$
2
0.2%

(
5c)
Fixed
O&
M
$
4,189
$
4,261
$
72
1.7%

(
5d)
Capital
Cost
$
1,277
$
1,275
($
2)
(
0.1)%

(
6)
Pre­
Tax
Income
(
Millions;
$
2002)
$
7,146
$
7,069
($
77)
(
1.1)%

(
7)
Variable
Production
Costs
($/
MWh)
$
11.97
$
11.98
$
0.01
0.0%

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
EPA
electricity
demand)
and
the
preferred
option.

Summary
of
Market
Results
at
the
National
Level.
The
results
presented
in
Table
B3­
4
show
that
capacity
closures
would
increase
by
434
MW,
which
represents
less
than
0.1
percent
of
total
baseline
capacity.
An
increase
in
new
capacity
additions
(
87
MW)
and
repowering
additions
(
711
MW)
would
make
up
for
this
loss.
Total
costs
of
electricity
generation
would
increase
by
0.6
percent,
largely
because
of
a
1.8
percent
increase
in
fixed
O&
M
costs
(
which
includes
charges
for
capital
costs
of
compliance).
Pre­
tax
income
would
decrease
by
1.1
percent.
The
preferred
option
would
not
lead
to
changes
in
total
domestic
capacity,
net
generation,
or
revenues.

Summary
of
Market
Results
at
the
Regional
Level.
At
the
regional
level,
the
preferred
option
would
result
in
the
following
changes:
<
ECAR,
MAAC,
MAPP,
SERC,
and
WSCC,
would
experience
increases
in
fixed
O&
M
costs,
driven
by
the
capital
costs
of
compliance
with
the
preferred
option,
but
overall
cost
increases
in
each
region
would
be
less
than
1.0
percent.
Pre­
tax
income
in
these
regions
would
decrease
by
between
0.5
and
1.1
percent.
All
other
measures
would
change
by
less
than
1.0
percent.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
B3­
18
NODA
Version
 
March
12,
2003
<
FRCC
would
experience
a
2.6
percent
reduction
in
capacity
prices.
Revenues
in
FRCC
would
decrease
by
0.3
percent
and
costs
would
increase
by
0.7
percent
(
largely
due
to
an
increase
in
fixed
O&
M
costs
of
3.0
percent),
leading
to
a
reduction
in
pre­
tax
income
of
3.1
percent.
All
other
measures
would
change
by
less
than
1.0
percent.
<
NPCC
and
SPP
would
experience
changes
in
capacity
additions
from
repowering
and
the
construction
of
new
capacity.
However,
these
changes
would
represent
less
than
0.5
percent
of
overall
capacity
in
the
two
regions.
Similar
to
ECAR,
MAAC,
MAPP,
SERC,
and
WSCC,
these
two
regions
would
experience
increases
in
fixed
O&
M
costs.
However,
the
overall
effect
in
NPCC
would
be
an
increase
in
pre­
tax
income,
as
revenues
rise
more
than
costs.
In
SPP,
the
decrease
in
pre­
tax
income
would
be
0.4
percent.
<
MAIN
is
the
only
region
that
would
experience
an
increase
in
post­
compliance
capacity
retirements.
Most
of
the
434
MW
increase
in
closures
(
0.7
percent
of
baseline
capacity)
is
due
to
a
nuclear
facility
that
reached
the
end
of
its
nuclear
operating
license.
In
the
base
case,
this
facility
would
have
extended
its
license
and
continued
operation
until
2020.
Under
the
preferred
option,
however,
this
facility
is
modeled
to
retire
by
2008.
An
increase
in
new
capacity
additions
of
285
MW
would
offset
much
of
this
retirement
loss.
MAIN
would
also
experience
an
0.8
percent
increase
in
variable
production
cost
per
MWh,
the
highest
increase
in
any
region.
This
increase
is
partially
due
to
the
incremental
loss
of
nuclear
capacity,
which
has
lower
production
costs
than
most
other
plant
types.
<
ERCOT
is
projected
to
experience
the
most
notable
changes
in
electricity
prices
and
new
capacity
among
the
ten
NERC
regions.
Repowering
additions
would
increase
by
345
MW
(
0.5
percent
of
baseline
capacity)
under
the
preferred
option.
Repowering
in
the
IPM
is
modeled
as
a
conversion
of
one
MW
of
existing
coal
or
oil
and
gas
steam
capacity
into
two
MW
of
combined­
cycle
capacity.
As
such,
repowering
in
ERCOT
under
the
preferred
option
consists
of
the
conversion
of
172
MW
of
existing
capacity
into
345
MW
of
new
repowered
capacity.
Since
total
capacity
in
ERCOT
remains
constant,
this
173
MW
net
increase
in
capacity
is
offset
by
a
173
MW
decrease
in
new
capacity
additions.
Postcompliance
energy
prices
are
expected
to
increase
by
6.1
percent.
This
increase
is
largely
driven
by
relatively
low
profit
margins
in
the
region.
ERCOT
also
experiences
the
largest
reduction
in
capacity
prices
with
almost
70
percent.
This
is
partially
due
to
the
increase
in
energy
prices,
which
allows
facilities
to
bid
their
undispatched
capacity
at
a
lower
price.
Revenues
and
pre­
tax
income
in
ERCOT
would
fall
by
1.3
percent
and
6.0
percent,
respectively,
the
highest
in
any
NERC
region.

B3­
4.2
Analysis
of
Phase
II
Facilities
for
2010
This
section
presents
the
results
of
the
IPM
analysis
for
the
Phase
II
facilities
that
are
modeled
by
the
IPM.
Ten
of
the
531
Phase
II
facilities
are
closures
in
the
base
case,
and
11
facilities
are
closures
under
the
preferred
option.
These
facilities
are
not
represented
in
the
results
described
in
this
section.

EPA
used
the
IPM
results
from
model
run
year
2010
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
in­
scope
Phase
II
facilities.

a.
In­
scope
Phase
II
facilities
as
a
group
This
section
presents
the
analysis
of
the
potential
impacts
of
the
preferred
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
B3­
5
presents
the
impact
measures
for
the
group
of
Phase
II
facilities
discussed
in
section
B3­
3.2
above:
(
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;
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
preferred
option,
the
absolute
difference
between
the
two
cases,
and
the
percentage
difference.

Table
B3­
5:
Facility­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
National
Totals
(
1)
Total
Domestic
Capacity
(
MW)
430,840
429,668
(
1,172)
(
0.3)%

(
1a)
Closures
­
Number
of
Facilities
10
11
1
10.0%

(
1b)
Closures
­
Capacity
(
MW)
13,151
13,585
434
3.3%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
5:
Facility­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B3­
19
(
2)
Generation
(
GWh)
2,299,197
2,280,130
(
19,066)
(
0.8)%

(
3)
Revenues
(
Millions;
$
2002)
$
75,628
$
74,960
($
668)
(
0.9)%

(
4)
Costs
(
Millions;
$
2002)
$
47,820
$
47,705
($
115)
(
0.2)%

(
4a)
Fuel
Cost
$
25,242
$
24,869
($
373)
(
1.5)%

(
4b)
Variable
O&
M
$
5,092
$
5,072
($
20)
(
0.4)%

(
4c)
Fixed
O&
M
$
14,950
$
15,363
$
413
2.8%

(
4d)
Capital
Cost
$
2,537
$
2,402
($
135)
(
5.3)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
27,808
$
27,255
($
553)
(
2.0)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
13.19
$
13.13
($
0.06)
(
0.5)%

East
Central
Area
Reliability
Coordination
Agreement
(
ECAR)

(
1)
Total
Domestic
Capacity
(
MW)
82,313
82,313
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)
517,126
516,503
(
622)
(
0.1)%

(
3)
Revenues
(
Millions;
$
2002)
$
16,237
$
16,230
($
8)
0.0%

(
4)
Costs
(
Millions;
$
2002)
$
9,586
$
9,671
$
84
0.9%

(
4a)
Fuel
Cost
$
5,036
$
5,027
($
9)
(
0.2)%

(
4b)
Variable
O&
M
$
1,248
$
1,249
$
1
0.1%

(
4c)
Fixed
O&
M
$
2,961
$
3,054
$
94
3.2%

(
4d)
Capital
Cost
$
342
$
340
($
1)
(
0.4)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
6,651
$
6,559
($
92)
(
1.4)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.15
$
12.15
$
0.00
0.0%

Electric
Reliability
Council
of
Texas
(
ERCOT)

(
1)
Total
Domestic
Capacity
(
MW)
43,522
43,412
(
110)
(
0.3)%

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

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

(
2)
Generation
(
GWh)
158,462
155,729
(
2,733)
(
1.7)%

(
3)
Revenues
(
Millions;
$
2002)
$
5,365
$
5,153
($
211)
(
3.9)%

(
4)
Costs
(
Millions;
$
2002)
$
3,910
$
3,859
($
51)
(
1.3)%

(
4a)
Fuel
Cost
$
2,203
$
2,143
($
60)
(
2.7)%

(
4b)
Variable
O&
M
$
426
$
423
($
3)
(
0.8)%

(
4c)
Fixed
O&
M
$
1,181
$
1,206
$
24
2.1%

(
4d)
Capital
Cost
$
99
$
87
($
12)
(
12.2)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,455
$
1,294
($
160)
(
11.0)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
16.59
$
16.48
($
0.12)
(
0.7)%

Florida
Reliability
Coordinating
Council
(
FRCC)

(
1)
Total
Domestic
Capacity
(
MW)
27,537
27,542
5
0.0%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
5:
Facility­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
B3­
20
NODA
Version
 
March
12,
2003
(
1a)
Closures
­
Number
of
Facilities
0
0
0
0.0%

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

(
2)
Generation
(
GWh)
82,259
81,638
(
621)
(
0.8)%

(
3)
Revenues
(
Millions;
$
2002)
$
3,433
$
3,398
($
35)
(
1.0)%

(
4)
Costs
(
Millions;
$
2002)
$
2,021
$
2,044
$
23
1.2%

(
4a)
Fuel
Cost
$
1,154
$
1,148
($
6)
(
0.5)%

(
4b)
Variable
O&
M
$
188
$
187
$
0
(
0.2)%

(
4c)
Fixed
O&
M
$
673
$
708
$
35
5.2%

(
4d)
Capital
Cost
$
5
$
0
($
5)
(
100.0)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,412
$
1,354
($
58)
(
4.1)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
16.31
$
16.36
$
0.05
0.3%

Mid­
Atlantic
Area
Council
(
MAAC)

(
1)
Total
Domestic
Capacity
(
MW)
33,590
33,590
0
0.0%

(
1a)
Closures
­
Number
of
Facilities
2
2
0
0.0%

(
1b)
Closures
­
Capacity
(
MW)
2,831
2,831
0
0.0%

(
2)
Generation
(
GWh)
167,239
167,643
403
0.2%

(
3)
Revenues
(
Millions;
$
2002)
$
6,151
$
6,155
$
4
0.1%

(
4)
Costs
(
Millions;
$
2002)
$
3,469
$
3,509
$
41
1.2%

(
4a)
Fuel
Cost
$
1,662
$
1,666
$
4
0.2%

(
4b)
Variable
O&
M
$
341
$
342
$
1
0.3%

(
4c)
Fixed
O&
M
$
1,359
$
1,395
$
36
2.6%

(
4d)
Capital
Cost
$
106
$
106
$
0
0.0%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,683
$
2,646
($
37)
(
1.4)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.98
$
11.98
$
0.00
0.0%

Mid­
America
Interconnected
Network
(
MAIN)

(
1)
Total
Domestic
Capacity
(
MW)
35,373
34,943
(
431)
(
1.2)%

(
1a)
Closures
­
Number
of
Facilities
2
3
1
50.0%

(
1b)
Closures
­
Capacity
(
MW)
4,698
5,132
434
9.2%

(
2)
Generation
(
GWh)
217,225
214,778
(
2,447)
(
1.1)%

(
3)
Revenues
(
Millions;
$
2002)
$
6,748
$
6,671
($
77)
(
1.1)%

(
4)
Costs
(
Millions;
$
2002)
$
4,050
$
4,000
($
50)
(
1.2)%

(
4a)
Fuel
Cost
$
2,066
$
2,055
($
11)
(
0.5)%

(
4b)
Variable
O&
M
$
489
$
485
($
4)
(
0.9)%

(
4c)
Fixed
O&
M
$
1,390
$
1,376
($
14)
(
1.0)%

(
4d)
Capital
Cost
$
106
$
86
($
20)
(
19.0)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,697
$
2,670
($
27)
(
1.0)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.76
$
11.82
$
0.06
0.5%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
5:
Facility­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
NODA
Version
 
March
12,
2003
B3­
21
Mid­
Continent
Area
Power
Pool
(
MAPP)

(
1)
Total
Domestic
Capacity
(
MW)
15,727
15,727
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)
108,584
108,584
0
0.0%

(
3)
Revenues
(
Millions;
$
2002)
$
3,177
$
3,175
($
1)
0.0%

(
4)
Costs
(
Millions;
$
2002)
$
1,977
$
1,995
$
18
0.9%

(
4a)
Fuel
Cost
$
1,044
$
1,044
$
0
0.0%

(
4b)
Variable
O&
M
$
222
$
223
$
0
0.1%

(
4c)
Fixed
O&
M
$
597
$
614
$
18
2.9%

(
4d)
Capital
Cost
$
114
$
114
$
0
0.0%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,199
$
1,180
($
19)
(
1.6)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.67
$
11.67
$
0.00
0.0%

Northeast
Power
Coordinating
Council
(
NPCC)

(
1)
Total
Domestic
Capacity
(
MW)
37,651
37,484
(
167)
(
0.4)%

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

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

(
2)
Generation
(
GWh)
165,601
161,753
(
3,848)
(
2.3)%

(
3)
Revenues
(
Millions;
$
2002)
$
6,503
$
6,420
($
83)
(
1.3)%

(
4)
Costs
(
Millions;
$
2002)
$
5,114
$
5,042
($
72)
(
1.4)%

(
4a)
Fuel
Cost
$
2,756
$
2,652
($
104)
(
3.8)%

(
4b)
Variable
O&
M
$
276
$
269
($
7)
(
2.6)%

(
4c)
Fixed
O&
M
$
1,242
$
1,307
$
65
5.2%

(
4d)
Capital
Cost
$
840
$
815
($
25)
(
3.0)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,389
$
1,378
($
11)
(
0.8)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
18.31
$
18.05
($
0.26)
(
1.4)%

Southeastern
Electric
Reliability
Council
(
SERC)

(
1)
Total
Domestic
Capacity
(
MW)
107,450
107,450
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)
639,276
638,076
(
1,200)
(
0.2)%

(
3)
Revenues
(
Millions;
$
2002)
$
20,645
$
20,624
($
21)
(
0.1)%

(
4)
Costs
(
Millions;
$
2002)
$
12,038
$
12,081
$
43
0.4%

(
4a)
Fuel
Cost
$
6,137
$
6,105
($
31)
(
0.5)%

(
4b)
Variable
O&
M
$
1,365
$
1,366
$
1
0.1%

(
4c)
Fixed
O&
M
$
3,986
$
4,060
$
74
1.9%

(
4d)
Capital
Cost
$
550
$
549
($
1)
(
0.2)%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
5:
Facility­
Level
Impacts
of
the
Preferred
Option
(
NERC
Regions;
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
B3­
22
NODA
Version
 
March
12,
2003
(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
8,607
$
8,543
($
64)
(
0.7)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.73
$
11.71
($
0.03)
(
0.2)%

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)
109,901
109,194
(
707)
(
0.6)%

(
3)
Revenues
(
Millions;
$
2002)
$
3,419
$
3,401
($
17)
(
0.5)%

(
4)
Costs
(
Millions;
$
2002)
$
1,962
$
1,959
($
2)
(
0.1)%

(
4a)
Fuel
Cost
$
1,148
$
1,135
($
13)
(
1.2)%

(
4b)
Variable
O&
M
$
248
$
247
($
1)
(
0.6)%

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

(
4d)
Capital
Cost
$
8
$
7
($
1)
(
13.4)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
1,457
$
1,442
($
15)
(
1.0)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.71
$
12.65
($
0.05)
(
0.4)%

Western
Systems
Coordinating
Council
(
WSCC)

(
1)
Total
Domestic
Capacity
(
MW)
27,206
26,736
(
470)
(
1.7)%

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

(
1b)
Closures
­
Capacity
(
MW)
226
226
0
0.0%

(
2)
Generation
(
GWh)
133,524
126,232
(
7,293)
(
5.5)%

(
3)
Revenues
(
Millions;
$
2002)
$
3,952
$
3,733
($
219)
(
5.5)%

(
4)
Costs
(
Millions;
$
2002)
$
3,694
$
3,545
($
149)
(
4.0)%

(
4a)
Fuel
Cost
$
2,034
$
1,893
($
141)
(
6.9)%

(
4b)
Variable
O&
M
$
289
$
282
($
7)
(
2.4)%

(
4c)
Fixed
O&
M
$
1,004
$
1,072
$
68
6.8%

(
4d)
Capital
Cost
$
367
$
298
($
69)
(
18.8)%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
258
$
188
($
70)
(
27.0)%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
17.40
$
17.23
($
0.17)
(
1.0)%

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
EPA
electricity
demand)
and
the
preferred
option.

Comparison
of
Results
for
Phase
II
Facilities
and
the
Market.
The
IPM
results
for
the
in­
scope
Phase
II
facilities
as
a
group
(
presented
in
Table
B3­
5)
are
similar
to
the
results
at
the
market
level
(
presented
in
Table
B3­
4).
On
a
percentage
basis,
the
group
of
Phase
II
facilities
generally
experiences
higher
losses
in
generation,
revenues,
and
pre­
tax
income
compared
to
the
overall
market.
This
is
not
surprising
as
in­
scope
facilities
become
relatively
less
competitive
compared
to
facilities
not
in
scope
of
Phase
II
regulation
and
are
therefore
likely
to
lose
some
market
share
as
a
result
of
the
preferred
option.
Total
closure
capacity
among
the
Phase
II
facilities
is
the
same
as
at
the
market
level
but
represents
a
higher
percentage
of
total
base
case
capacity
(
0.1
percent
at
the
national
level).
Fixed
O&
M
costs
of
the
group
of
Phase
II
facilities
increase
relatively
more
than
at
the
market
level
because
fixed
O&
M
costs
include
the
capital
costs
of
compliance
with
Phase
II
regulatory
options.
In
many
regions,
however,
the
other
cost
accounts
decrease
for
the
Phase
II
facilities
because
of
the
reduction
in
generation.
On
a
per
MWh
basis,
variable
production
costs
also
decrease
in
many
regions
because
the
higher
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B3­
23
cost
units
generate
less
electricity
under
the
preferred
option
compared
to
the
base
case,
reducing
the
overall
average
cost
of
generation.

Summary
of
Phase
II
Facility
Results
at
the
National
Level.
Table
B3­
5
shows
that
the
preferred
option
would
lead
to
the
closure
of
one
additional
Phase
II
facility
(
which
accounts
for
approximately
0.1
percent
of
baseline
Phase
II
capacity)
thus
increasing
capacity
closures
by
434
MW.
Total
Phase
II
capacity
would
decrease
by
1,172
MW,
due
to
the
capacity
closure
and
several
facilities
that
were
projected
to
repower
in
the
base
case
but
do
not
under
the
preferred
option.
As
a
result,
generation,
revenues,
and
overall
costs
would
decrease
but
by
less
than
one
percent.
Pre­
tax
income
for
the
group
of
Phase
II
facilities
would
decrease
by
2.0
percent.

Summary
of
Phase
II
Facility
Results
at
the
Regional
Level.
Results
for
the
preferred
option
vary
somewhat
by
region.
For
many
regions,
impacts
follow
the
general
pattern
described
in
the
comparison
to
the
market
level
above:
generation,
revenues,
and
pre­
tax
income
decrease.
Overall
costs
decrease
in
many
regions
due
to
lower
levels
of
generation
but
increase
in
other
regions,
where
the
additional
compliance
costs
outweigh
the
reduction
in
generation.
The
preferred
option
would
result
in
the
following
changes:
<
ECAR,
MAAC,
MAPP,
SERC
and
SPP,
would
experience
reductions
in
pre­
tax
income
of
between
0.7
and
1.6
percent.
The
changes
in
most
other
measures
are
less
than
1.0
percent
in
these
regions.
<
MAIN
is
the
only
region
that
would
experience
an
incremental
closure
of
a
Phase
II
facility
under
the
preferred
option.
This
closure
is
responsible
for
the
reduction
in
Phase
II
capacity
in
the
region
and
would
contribute
to
a
decrease
in
Phase
II
post­
compliance
generation
and
revenues
(
see
also
discussion
in
Section
B3­
4.1
above).
Total
costs
would
also
decrease,
but
variable
production
cost
per
MWh
would
increase
because
the
projected
incremental
closure
affects
nuclear
capacity
which
has
lower
production
costs
than
most
other
plant
types.
<
WSCC
would
experience
the
largest
reduction
in
Phase
II
capacity,
losing
470
MW,
or
1.7
percent
of
base
case
capacity
under
the
preferred
option.
This
change
is
not
the
result
of
plant
closures
but
is
due
to
less
Phase
II
capacity
being
repowered
in
the
post­
compliance
scenario.
Phase
II
facilities
in
WSCC
also
experience
reductions
in
generation
and
revenues
of
5.5
percent
because
they
bear
a
relatively
high
compliance
cost
per
MW
of
capacity
under
the
preferred
option
(
the
highest
of
any
of
the
10
NERC
regions).
In
addition,
only
a
small
percentage
of
total
capacity
in
WSCC
(
27,200
MW
out
of
167,750
MW,
or
16
percent)
is
subject
to
Phase
II
regulation.
As
a
result,
facilities
not
subject
to
Phase
II
regulation
become
relatively
more
competitive
and
assume
some
of
the
generation
lost
by
Phase
II
facilities.
Overall,
costs
for
the
group
of
Phase
II
facilities
decrease.
Fixed
O&
M
costs,
which
include
Phase
II
compliance
costs,
increase
but
fuel
costs
and
variable
O&
M
costs
decrease
because
of
the
reduction
in
generation.
However,
the
reduction
in
revenues
outweighs
the
reduction
in
costs,
leading
to
an
overall
reduction
in
pre­
tax
income
of
27
percent
($
70
million),
the
highest
reduction
in
any
region.
This
relatively
high
percentage
reduction
is
partially
due
to
the
low
profit
margins
of
Phase
II
facilities
in
WSCC
in
the
base
case.
<
Phase
II
facilities
in
ERCOT
would
experience
reductions
in
generation
(­
1.7
percent),
revenues
(­
3.9
percent),
and
pretax
income
(­
11.0
percent).
Revenues
decrease
by
a
larger
percentage
than
generation
due
to
the
large
drop
in
capacity
prices
(
see
Table
B3­
4).
<
Phase
II
facilities
in
NPCC
would
experience
the
largest
reduction
in
generation
(­
2.3
percent)
of
any
region.
However,
revenues
only
decrease
by
1.3
percent
because
of
increases
in
both
energy
and
capacity
prices
(
see
Table
B3­
4).
NPCC
would
also
experience
the
second
largest
increase
in
fixed
O&
M
costs
(
5.2
percent)
as
a
result
of
bearing
relatively
high
compliance
cost
per
MW
of
capacity
under
the
preferred
option
(
the
second
highest
of
any
of
the
10
NERC
regions).
<
Phase
II
facilities
in
FRCC
would
experience
an
increase
in
total
costs
of
1.2
percent
under
the
preferred
option.
Combined
with
a
reduction
in
revenues
of
1.0
percent,
this
would
reduce
pre­
tax
income
for
Phase
II
facilities
in
FRCC
by
4.1
percent.

b.
Individual
Phase
II
facilities
In
addition
to
effects
of
the
preferred
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
facilityspecific
changes
in
(
1)
capacity
utilization
(
defined
as
generation
divided
by
capacity
multiplied
by
the
number
of
hours
per
year
 
8,760);
(
2)
generation;
(
3)
revenues;
(
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
B3­
6
presents
the
total
number
of
Phase
II
facilities
with
different
degrees
of
change
in
each
of
these
measures.
This
table
excludes
18
facilities
with
significant
status
changes
including
(
10
facilities
are
baseline
closures,
one
facility
is
a
policy
closure,
and
seven
facilities
that
changed
repowering
decisions
between
the
base
case
and
policy
case).
These
facilities
are
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
B3­
24
NODA
Version
 
March
12,
2003
either
not
operating
at
all
in
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
57
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
B3­
6:
Number
of
Individual
Phase
II
Facilities
with
Operational
Changes
(
2010)

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

(
1)
Change
in
Capacity
Utilization
9
15
24
9
6
9
441
­

(
2)
Change
in
Generation
7
1
44
10
3
17
431
­

(
3)
Change
in
Revenues
80
27
42
100
22
15
227
­

(
4)
Change
in
Variable
Production
Costs/
MWh
33
13
9
140
13
14
234
57
(
5)
Change
in
Fuel
Costs
16
11
9
24
11
10
375
57
(
6)
Change
in
Pre­
Tax
Income
105
113
199
22
13
37
24
­

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
(
EIA
electricity
demand)
and
the
preferred
option.

Table
B3­
6
indicates
that
the
majority
of
Phase
II
facilities
would
not
experience
changes
in
capacity
utilization,
generation,
or
fuel
costs
per
MWh
due
to
compliance
with
the
preferred
option.
Of
those
facilities
with
changes
in
post­
compliance
capacity
utilization
and
generation,
most
would
experience
decreases
in
these
measures.
The
majority
of
facilities
with
changes
in
post­
compliance
variable
production
costs
per
MWh
would
experience
increases.
However,
more
than
80
percent
of
those
increases
would
not
exceed
1.0
percent.
Changes
in
revenues
at
most
Phase
II
facilities
would
also
not
exceed
1.0
percent.
The
largest
effect
of
the
preferred
option
would
be
on
facilities'
pre­
tax
income:
over
80
percent
of
facilities
would
experience
a
reduction
in
pre­
tax
income,
with
almost
40
percent
experiencing
a
reduction
of
3.0
percent
or
greater.
These
reductions
are
due
to
a
combination
of
reduced
revenues
and
increased
compliance
costs.

B3­
4.3
Market
Analysis
for
2008
This
section
presents
market­
level
results
for
the
preferred
option
for
model
run
year
2008.
Unlike
the
market­
level
analysis
for
2010
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
B3­
7
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;
and
(
6)
changes
in
variable
production
costs
per
MWh.
For
each
measure,
the
table
presents
the
2008
results
for
the
base
case
and
the
preferred
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
2010
presented
in
Table
B3­
4
above.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B3­
25
Table
B3­
7:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
2008
and
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
%
Change
2010
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)
4,060,238
4,060,277
39
0.0%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
154,018
$
153,993
($
24)
0.0%
0.0%

(
4)
Costs
(
Millions;
$
2002)
$
86,389
$
86,901
$
513
0.6%
0.6%

(
4a)
Fuel
Cost
$
48,097
$
48,172
$
75
0.2%
0.0%

(
4b)
Variable
O&
M
$
7,828
$
7,828
($
1)
0.0%
0.1%

(
4c)
Fixed
O&
M
$
23,643
$
23,995
$
352
1.5%
1.8%

(
4d)
Capital
Cost
$
6,821
$
6,907
$
86
1.3%
0.6%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
67,629
$
67,092
($
537)
­
0.8%
­
1.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
13.77
$
13.79
$
0.02
0.1%
0.0%

East
Central
Area
Reliability
Coordination
Agreement
(
ECAR)

(
1a)
Energy
Price
($
2002/
MWh)
$
22.66
$
22.93
$
0.26
1.2%
0.0%

(
1b)
Capacity
Price
($
2002/
KW)
$
78.35
$
78.14
($
0.21)
­
0.3%
0.1%

(
2)
Total
Generation
(
GWh)
649,365
647,670
(
1,695)
­
0.3%
­
0.2%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
23,972
$
24,079
$
107
0.4%
­
0.1%

(
4)
Costs
(
Millions;
$
2002)
$
12,731
$
12,783
$
53
0.4%
0.7%

(
4a)
Fuel
Cost
$
6,619
$
6,587
($
31)
­
0.5%
­
0.1%

(
4b)
Variable
O&
M
$
1,579
$
1,578
($
1)
0.0%
0.0%

(
4c)
Fixed
O&
M
$
3,569
$
3,655
$
86
2.4%
2.6%

(
4d)
Capital
Cost
$
964
$
963
($
1)
­
0.1%
­
0.1%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
11,241
$
11,296
$
55
0.5%
­
1.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.62
$
12.61
($
0.02)
­
0.1%
0.1%

Electric
Reliability
Council
of
Texas
(
ERCOT)

(
1a)
Energy
Price
($
2002/
MWh)
$
29.98
$
30.08
$
0.10
0.3%
6.1
(
1b)
Capacity
Price
($
2002/
KW)
$
0.00
$
0.00
$
0.00
0.0%
­
69.8
(
2)
Total
Generation
(
GWh)
325,835
325,835
0
0.0%
­
0.1
(
3)
Total
Revenues
(
Millions;
$
2002)
$
9,768
$
9,802
$
33
0.3%
­
1.3%

(
4)
Costs
(
Millions;
$
2002)
$
7,728
$
7,765
$
37
0.5%
0.4%

(
4a)
Fuel
Cost
$
5,211
$
5,206
($
6)
­
0.1%
­
0.1%

(
4b)
Variable
O&
M
$
673
$
672
($
1)
­
0.2%
0.2%

(
4c)
Fixed
O&
M
$
1,696
$
1,713
$
17
1.0%
1.5%

(
4d)
Capital
Cost
$
148
$
174
$
26
17.8%
4.2%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
2,040
$
2,037
($
4)
­
0.2%
­
6.0%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
7:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
2008
and
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
%
Change
2010
B3­
26
NODA
Version
 
March
12,
2003
(
6)
Variable
Production
Costs
($
2002/
MWh)
$
18.06
$
18.04
($
0.02)
­
0.1%
0.0%

Florida
Reliability
Coordinating
Council
(
FRCC)

(
1a)
Energy
Price
($
2002/
MWh)
$
30.18
$
30.38
$
0.19
0.6%
0.6%

(
1b)
Capacity
Price
($
2002/
KW)
$
63.07
$
62.64
($
0.43)
­
0.7%
­
2.6%

(
2)
Total
Generation
(
GWh)
$
186,234
$
186,467
$
233
0.1%
­
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
8,719
$
8,741
$
22
0.3%
­
0.3%

(
4)
Costs
(
Millions;
$
2002)
$
5,349
$
5,389
$
39
0.7%
0.7%

(
4a)
Fuel
Cost
$
3,129
$
3,151
$
23
0.7%
0.3%

(
4b)
Variable
O&
M
$
354
$
355
$
1
0.4%
0.4%

(
4c)
Fixed
O&
M
$
1,172
$
1,193
$
21
1.8%
3.0%

(
4d)
Capital
Cost
$
694
$
688
($
6)
­
0.8%
­
0.8%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,370
$
3,352
($
17)
­
0.5%
­
3.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
18.70
$
18.81
$
0.11
0.6%
0.4%

Mid­
Atlantic
Area
Council
(
MAAC)

(
1a)
Energy
Price
($
2002/
MWh)
$
26.82
$
27.05
$
0.23
0.9%
0.0%

(
1b)
Capacity
Price
($
2002/
KW)
$
73.68
$
74.00
$
0.33
0.4%
­
0.5%

(
2)
Total
Generation
(
GWh)
274,753
274,729
(
24)
0.0%
0.2%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
12,024
$
12,109
$
84
0.7%
0.0%

(
4)
Costs
(
Millions;
$
2002)
$
5,985
$
6,020
$
35
0.6%
0.7%

(
4a)
Fuel
Cost
$
2,920
$
2,921
$
1
0.0%
0.1%

(
4b)
Variable
O&
M
$
553
$
554
$
1
0.2%
0.2%

(
4c)
Fixed
O&
M
$
2,125
$
2,156
$
30
1.4%
1.9%

(
4d)
Capital
Cost
$
386
$
389
$
3
0.8%
0.3%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
6,039
$
6,089
$
49
0.8%
­
0.9%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.64
$
12.65
$
0.01
0.1%
­
0.1%

Mid­
America
Interconnected
Network
(
MAIN)

(
1a)
Energy
Price
($
2002/
MWh)
$
22.68
$
22.93
$
0.25
1.1%
­
0.3%

(
1b)
Capacity
Price
($
2002/
KW)
$
78.80
$
78.10
($
0.69)
­
0.9%
0.8%

(
2)
Total
Generation
(
GWh)
285,282
284,198
(
1,085)
­
0.4%
­
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
11,208
$
11,180
($
28)
­
0.3%
­
0.1%

(
4)
Costs
(
Millions;
$
2002)
$
5,940
$
5,943
$
3
0.0%
0.4%

(
4a)
Fuel
Cost
$
2,940
$
2,967
$
27
0.9%
0.9%

(
4b)
Variable
O&
M
$
589
$
587
($
2)
­
0.3%
­
0.3%

(
4c)
Fixed
O&
M
$
1,949
$
1,925
($
24)
­
1.2%
­
0.5%

(
4d)
Capital
Cost
$
463
$
464
$
2
0.4%
1.2%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
7:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
2008
and
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
%
Change
2010
NODA
Version
 
March
12,
2003
B3­
27
(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
5,268
$
5,237
($
31)
­
0.6%
­
0.7%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.37
$
12.51
$
0.14
1.1%
0.8%

Mid­
Continent
Area
Power
Pool
(
MAPP)

(
1a)
Energy
Price
($
2002/
MWh)
$
22.41
$
22.66
$
0.26
1.1%
­
0.4%

(
1b)
Capacity
Price
($
2002/
KW)
$
78.32
$
78.01
($
0.31)
­
0.4%
0.9%

(
2)
Total
Generation
(
GWh)
179,067
178,978
(
89)
0.0%
­
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
6,756
$
6,790
$
33
0.5%
0.0%

(
4)
Costs
(
Millions;
$
2002)
$
3,353
$
3,369
$
17
0.5%
0.4%

(
4a)
Fuel
Cost
$
1,740
$
1,740
$
0
0.0%
­
0.2%

(
4b)
Variable
O&
M
$
366
$
366
$
0
0.0%
0.0%

(
4c)
Fixed
O&
M
$
998
$
1,015
$
17
1.7%
1.7%

(
4d)
Capital
Cost
$
249
$
249
$
0
0.0%
0.0%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
3,404
$
3,420
$
16
0.5%
­
0.6%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
11.76
$
11.76
$
0.01
0.0%
­
0.1%

Northeast
Power
Coordinating
Council
(
NPCC)

(
1a)
Energy
Price
($
2002/
MWh)
$
29.48
$
30.06
$
0.58
2.0%
0.9%

(
1b)
Capacity
Price
($
2002/
KW)
$
68.95
$
60.67
($
8.27)
­
12.0%
0.2%

(
2)
Total
Generation
(
GWh)
277,871
277,553
(
318)
­
0.1%
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
12,806
$
12,402
($
404)
­
3.2%
0.8%

(
4)
Costs
(
Millions;
$
2002)
$
7,668
$
7,716
$
49
0.6%
0.7%

(
4a)
Fuel
Cost
$
4,459
$
4,449
($
11)
­
0.2%
­
0.3%

(
4b)
Variable
O&
M
$
376
$
372
($
3)
­
0.9%
­
0.7%

(
4c)
Fixed
O&
M
$
1,779
$
1,833
$
54
3.0%
3.6%

(
4d)
Capital
Cost
$
1,053
$
1,062
$
9
0.8%
0.7%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
5,138
$
4,686
($
452)
­
8.8%
0.8%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
17.40
$
17.37
($
0.03)
­
0.2%
­
0.4%

Southeastern
Electric
Reliability
Council
(
SERC)

(
1a)
Energy
Price
($
2002/
MWh)
$
25.48
$
25.57
$
0.09
0.4%
0.0%

(
1b)
Capacity
Price
($
2002/
KW)
$
68.91
$
68.56
($
0.34)
­
0.5%
0.2%

(
2)
Total
Generation
(
GWh)
924,991
927,605
2,613
0.3%
0.1%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
36,464
$
36,589
$
125
0.3%
0.1%

(
4)
Costs
(
Millions;
$
2002)
$
19,134
$
19,301
$
167
0.9%
0.5%

(
4a)
Fuel
Cost
$
10,337
$
10,375
$
38
0.4%
0.0%

(
4b)
Variable
O&
M
$
1,760
$
1,761
$
2
0.1%
0.2%

(
4c)
Fixed
O&
M
$
5,182
$
5,252
$
70
1.3%
1.5%
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
Table
B3­
7:
Market­
Level
Impacts
of
the
Preferred
Option
(
NERC
2008
and
2010)

Economic
Measures
Base
Case
Preferred
Option
Difference
%
Change
%
Change
2010
B3­
28
NODA
Version
 
March
12,
2003
(
4d)
Capital
Cost
$
1,854
$
1,912
$
58
3.1%
0.8%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
17,330
$
17,288
($
42)
­
0.2%
­
0.5%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
13.08
$
13.08
$
0.01
0.0%
­
0.1%

Southwest
Power
Pool
(
SPP)

(
1a)
Energy
Price
($
2002/
MWh)
$
25.17
$
25.28
$
0.11
0.4%
­
0.2%

(
1b)
Capacity
Price
($
2002/
KW)
$
61.73
$
61.23
($
0.50)
­
0.8%
0.6%

(
2)
Total
Generation
(
GWh)
217,634
217,598
(
36)
0.0%
0.2%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
8,503
$
8,498
($
6)
­
0.1%
0.2%

(
4)
Costs
(
Millions;
$
2002)
$
4,214
$
4,225
$
11
0.3%
0.7%

(
4a)
Fuel
Cost
$
2,743
$
2,746
$
3
0.1%
0.1%

(
4b)
Variable
O&
M
$
419
$
420
$
1
0.1%
­
0.1%

(
4c)
Fixed
O&
M
$
1,031
$
1,042
$
11
1.1%
1.5%

(
4d)
Capital
Cost
$
21
$
18
($
4)
­
17.8%
14.8%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
4,289
$
4,273
($
16)
­
0.4%
­
0.4%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
14.53
$
14.55
$
0.02
0.1%
­
0.1%

Western
Systems
Coordinating
Council
(
WSCC)

(
1a)
Energy
Price
($
2002/
MWh)
$
28.58
$
28.59
$
0.02
0.1%
0.0%

(
1b)
Capacity
Price
($
2002/
KW)
$
18.17
$
18.06
($
0.11)
­
0.6%
0.2%

(
2)
Total
Generation
(
GWh)
739,205
739,644
439
0.1%
0.0%

(
3)
Total
Revenues
(
Millions;
$
2002)
$
23,797
$
23,805
$
8
0.0%
0.0%

(
4)
Costs
(
Millions;
$
2002)
$
14,287
$
14,390
$
103
0.7%
0.5%

(
4a)
Fuel
Cost
$
7,999
$
8,030
$
31
0.4%
0.0%

(
4b)
Variable
O&
M
$
1,160
$
1,162
$
2
0.2%
0.2%

(
4c)
Fixed
O&
M
$
4,140
$
4,210
$
70
1.7%
1.7%

(
4d)
Capital
Cost
$
989
$
988
($
1)
­
0.1%
­
0.1%

(
5)
Pre­
Tax
Income
(
Millions;
$
2002)
$
9,509
$
9,415
($
94)
­
1.0%
­
1.1%

(
6)
Variable
Production
Costs
($
2002/
MWh)
$
12.39
$
12.43
$
0.04
0.3%
0.0%

Source:
IPM
analysis:
Model
runs
for
Section
316(
b)
NODA
Base
Case
(
EPA
electricity
demand)
and
the
preferred
option.

Summary
of
Market
Results
at
the
National
Level.
The
results
presented
in
Table
B3­
7
show
that
under
the
preferred
option
downtimes
associated
with
the
installation
of
compliance
technologies
would
not
lead
to
significant
changes
in
economic
impacts
compared
to
the
results
for
2010
(
which
represents
the
post­
compliance
scenario
in
which
no
facilities
experience
downtimes).
There
would
be
an
0.2
percent
increase
in
fuel
costs
in
2008,
leading
to
an
increase
in
variable
production
cost
per
MWh
of
0.1
percent,
and
the
rise
in
capital
costs
would
be
somewhat
higher
in
2008
than
in
2010.

Summary
of
Market
Results
at
the
Regional
Level.
The
following
discussion
highlights
differences
in
the
analysis
results
between
2010
and
2008:
<
In
FRCC,
SERC,
and
WSCC,
most
impact
results
for
2008
and
2010
are
either
the
same
or
slightly
lower
in
2008.
FRCC
would
experience
a
smaller
decrease
in
capacity
prices
in
2008
which
would
result
in
higher
revenues
and
a
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B3­
29
smaller
loss
in
pre­
tax
income
compared
to
2010.
In
SERC,
energy
prices
and
generation
would
increase
more
in
2008
than
2010,
leading
to
an
increase
in
revenues
and
a
reduction
in
pre­
tax
income
loss.
In
WSCC,
fuel
costs
would
increase
by
0.4
percent,
resulting
in
an
0.3
percent
increase
in
variable
production
costs
per
MWh.
<
ECAR,
MACC,
and
MAPP
would
experience
increases
in
energy
prices
between
0.9
and
1.2
percent
in
2008.
These
increases
would
lead
to
higher
revenues
and
increases
in
pre­
tax
income
of
between
0.5
and
0.8
percent.
<
MAIN
and
NPCC
would
both
experience
increases
in
energy
prices
under
the
preferred
option
in
2008.
However,
capacity
prices
would
decrease,
leading
to
a
reduction
in
revenues
and
pre­
tax
income.
<
ERCOT
would
experience
substantially
lower
price
effects
in
2008
compared
to
2010.
The
increase
in
energy
prices
would
be
0.3
percent
compared
to
6.1
percent
in
2010.
Capacity
prices
in
2008
are
zero
in
both
the
base
case
and
under
the
preferred
option
as
a
result
of
excess
capacity
in
the
region
(
note
that
there
are
no
new
capacity
additions
in
ERCOT
in
2008).
ERCOT
would
also
experience
an
increase
in
revenues
and
a
smaller
reduction
in
pre­
tax
income
compared
to
2010.
<
In
SPP,
energy
prices
under
the
preferred
option
would
increase
by
0.4
percent
in
2008
while
capacity
prices
would
fall,
resulting
in
a
0.1
percent
reduction
in
revenues.
The
only
other
notable
difference
in
results
compared
to
2010
is
a
relatively
large
percentage
reduction
in
capital
costs
in
2008.
This
is
the
result
of
a
minor
delay
in
investment
in
new
capacity
additions
under
the
preferred
option:
approximately
120
MW
of
capacity
that
is
projected
to
be
built
in
2008
in
the
base
case
is
postponed
until
2010
under
the
preferred
option.
As
a
result,
2008
sees
a
reduction
in
capital
costs
while
2010
sees
an
increase.
Overall,
the
reduction
in
capital
costs
in
2008
comprises
less
than
0.1
percent
of
total
base
case
cost.

B3­
5
UNCERTAINTIES
AND
LIMITATIONS
There
are
uncertainties
associated
with
EPA's
analysis
of
the
electric
power
market
and
the
economic
impacts
of
the
preferred
option:

<
Demand
for
electricity:
The
IPM
assumes
that
electricity
demand
at
the
national
level
would
not
change
between
the
base
case
and
the
analyzed
policy
options
(
generation
within
the
regions
is
allowed
to
vary).
Under
the
EPA
Base
Case
2000
specification,
electricity
demand
is
based
on
the
AEO
2001
forecast
adjusted
to
account
for
demand
reductions
resulting
from
implementation
of
the
Climate
Change
Action
Plan
(
CCAP).
The
IPM
model,
as
specified
for
this
analysis,
does
not
capture
changes
in
demand
that
may
result
from
electricity
price
increases
associated
with
the
preferred
option.
While
this
constraint
may
overestimate
total
demand
in
policy
options
that
have
high
compliance
cost
and
that
may
therefore
lead
to
significant
price
increases,
EPA
believes
that
it
does
not
affect
the
results
analyzed
in
support
of
the
preferred
option.
As
described
in
Section
B3­
4
above,
the
price
increases
associated
with
the
preferred
option
in
most
NERC
regions
are
relatively
small.
EPA
therefore
concludes
that
the
assumption
of
inelastic
demandresponses
to
changes
in
prices
is
reasonable.

<
International
imports:
The
IPM
also
assumes
that
imports
from
Canada
and
Mexico
would
not
change
between
the
base
case
and
the
analyzed
policy
options.
Holding
international
imports
fixed
would
provide
a
conservative
estimate
of
production
costs
and
electricity
prices,
because
imports
are
not
subject
to
the
rule
and
may
therefore
become
more
competitive
relative
to
domestic
capacity,
displacing
some
of
the
more
expensive
domestic
generating
units.
On
the
other
hand,
holding
imports
fixed
may
understate
effects
on
marginal
domestic
units,
which
may
be
displaced
by
increased
imports.
However,
EPA
concludes
that
fixed
imports
do
not
materially
affect
the
results
of
the
analyses.
Only
four
of
the
ten
NERC
regions
import
electricity
(
ECAR,
MAPP,
NPCC,
and
WSCC)
and
the
level
of
imports
compared
to
domestic
generation
in
each
of
these
regions
is
very
small
(
0.03
percent
in
ECAR,
2.4
percent
in
MAPP,
5.6
percent
in
NPCC,
and
1.5
in
WSCC).

<
Repowering:
For
the
section
316(
b)
analysis,
EPA
is
not
using
the
IPM
function
that
allows
the
model
to
pick
among
a
set
of
compliance
responses.
As
a
result,
there
is
no
iterative
process
that
would
adjust
the
compliance
response
(
and
as
a
result
the
cost
of
compliance)
if
a
facility
chooses
to
repower.
Repowering
in
the
IPM
typically
consists
of
the
conversion
of
existing
oil/
gas
or
coal
capacity
to
new
combined­
cycle
capacity.
The
modeling
assumption
is
that
each
one
MW
of
existing
capacity
is
replaced
by
two
MW
of
repowered
capacity.
This
change
in
plant
type
and
size
might
lead
to
a
change
in
intake
flow
and
potentially
to
different
compliance
requirements
and
costs.
Since
combined­
cycle
facilities
require
substantially
less
cooling
water
than
other
oil/
gas
or
coal
facilities,
the
effect
of
repowering
is
likely
to
be
a
reduction
in
cooling
water
requirements
(
even
considering
the
doubling
of
the
plant's
capacity).
As
a
result,
not
allowing
the
model
to
adjust
the
compliance
response
or
cost
is
likely
to
lead
to
a
conservative
estimate
of
compliance
costs
and
potential
economic
impacts
from
the
preferred
option
and
the
alternative
regulatory
options
analyzed
with
the
IPM.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
B3­
30
NODA
Version
 
March
12,
2003
<
Downtime
associated
with
installation
of
compliance
technologies:
EPA
estimates
that
the
installation
of
several
compliance
technologies
would
require
the
steam
electric
generators
of
facilities
that
are
projected
to
install
such
technologies
to
be
off­
line
for
between
two
weeks
and
seven
months,
depending
on
the
technology.
Generator
downtime
is
estimated
to
occur
during
the
year
when
a
facility
complies
with
the
policy
option.
Since
the
years
that
are
mapped
into
a
run
year
are
assumed
to
have
the
same
characteristics
as
the
run
year
itself,
generator
downtimes
were
applied
as
an
average
over
the
years
that
are
mapped
into
each
model
run
year.
For
example,
years
2005
to
2009
are
all
mapped
into
2008.
Therefore,
a
facility
with
a
downtime
in
2008
was
modeled
as
if
1/
5th
of
its
downtime
occurred
in
each
year
between
2005
and
2009.
A
potential
drawback
of
this
approach
of
averaging
downtimes
over
the
mapped
years
is
that
the
snapshot
of
the
effect
of
downtimes
during
the
model
run
year
is
the
average
effect;
this
approach
does
not
model
potential
worst
case
effects
of
above­
average
amounts
of
capacity
being
down
in
any
one
NERC
region
during
any
one
year.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
B3:
Electricity
Market
Model
Analysis
NODA
Version
 
March
12,
2003
B3­
31
REFERENCES
U.
S.
Environmental
Protection
Agency
(
U.
S.
EPA).
2000.
Section
316(
b)
Industry
Survey.
Detailed
Industry
Questionnaire:
Phase
II
Cooling
Water
Intake
Structures
and
Industry
Short
Technical
Questionnaire:
Phase
II
Cooling
Water
Intake
Structures,
January,
2000
(
OMB
Control
Number
2040­
0213).
Industry
Screener
Questionnaire:
Phase
I
Cooling
Water
Intake
Structures,
January,
1999
(
OMB
Control
Number
2040­
0203).

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.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
B3­
32
NODA
Version
 
March
12,
2003
Appendix
to
Chapter
B3
INTRODUCTION
This
appendix
presents
additional,
more
detailed
information
on
EPA's
research
to
identify
models
suitable
for
analysis
of
environmental
policies
that
affect
the
electric
power
industry.
In
addition,
this
appendix
presents
a
comparison
of
the
specifications
of
the
EPA
Base
Case
2000
and
its
predecessor
Base
Case
specifications.

B3­
A.
1
SUMMARY
COMPARISON
OF
ENERGY
MARKET
MODELS
EPA
performed
research
to
identify
electricity
market
models
that
could
potentially
be
used
in
the
analysis
of
impacts
associated
with
regulatory
options
considered
for
section
316(
b)
Phase
II
regulation.
This
research
included
reviewing
available
forecast
studies
and
interviewing
persons
knowledgeable
in
the
area
of
electricity
market
forecasting.
EPA
focused
on
identifying
models
that
are
widely
used
for
public
policy
analyses,
peer
reviewed,
of
national
scope,
and
have
the
capabilities
needed
to
perform
regulatory
impact
scenario
analyses
of
the
type
required
for
the
section
316(
b)
Phase
II
economic
analyses.
Based
on
this
research,
EPA
identified
three
models
that
were
potentially
suitable
for
the
analysis
of
the
section
316(
b)
Phase
II
regulations:

<
(
1)
The
Department
of
Energy's
National
Energy
Modeling
System
(
NEMS),
<
(
2)
The
Department
of
Energy's
The
Policy
Office
Electricity
Modeling
System
(
POEMS),
and
<
(
3)
ICF
Consulting's
Integrated
Planning
Model
(
IPM
®
)
.

Each
of
these
models
was
developed
to
meet
the
specific
needs
of
different
end
users
and
therefore
differ
in
terms
of
structure,
inputs,
outputs,
and
capability.
Table
B3­
A­
1
below
presents
a
detailed
comparison
of
the
three
models.
The
comparison
comprises:

<
General
features,
including
a
description
of
each
model,
their
general
applications,
and
their
environmental
applications.

<
Modeling
features,
including
each
model's
treatment
of
existing
environmental
regulations,
of
industry
restructuring,
and
of
economic
plant
retirements;
their
regional
capabilities;
their
plant/
unit
detail
and
data
sources;
their
general
data
inputs
and
outputs;
and
their
data
inputs
and
outputs
required
for
the
section
316(
b)
analysis.

<
Logistical
considerations,
including
each
model's
costs,
computational
requirements,
accessability
and
response
time;
their
documentation
and
issues
regarding
disclosure
of
inputs
or
results;
and
general
notes
and
references.
CHAPTER
CONTENTS
B3­
A.
1
Summary
Comparison
of
Energy
Market
Models
B3­
32
B3­
A.
2
Differences
Between
EPA
Base
Case
2000
and
Previous
Model
Specifications.
.
.
.
.
.
.
.
.
.
.
.
.
.
B3­
38
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
NODA
Version
 
March
12,
2003
B3­
33
Table
B3­
A­
1:
Comparison
of
Electricity
Market
Models
Model
DOE/
EIA:
NEMS
DOE/
OP:
POEMS
(
OnLocation,
Inc.)
EPA/
Office
of
Air
Policy
(
OAP):
IPM
(
ICF
Consulting
Inc.)

General
Features
Description
Modular
structured
model
of
national
energy
supply
and
demand,
includes
macroeconomic,
international,
supply
and
demand
modules,
as
well
as
an
electricity
market
module
(
EMM)
that
can
be
run
independently.
The
EMM
represents
generation,
transmission
and
prices
of
electricity.

Based
on
forecasts
of
fuel
prices,
variable
O&
M,
and
electricity
demand,
determines
plant
dispatch
to
achieve
the
least
cost
supply
of
electric
power.
POEMS
is
a
model
integration
system
that
allows
the
substitution
of
the
TRADELEC
model
for
the
EMM
in
NEMS.
TRADELEC
allows
for
a
greater
level
of
detail
about
the
electricity
sector
than
the
EMM.
Designed
to
examine
the
effect
of
market
structure
transformation
of
the
electricity
sector.
It
solves
for
the
trade
of
the
commodity
as
a
function
of
relative
prices,
transmission
constraints
and
cost
of
market
entry
by
maximizing
economic
gains
achieved
through
commodity
trading.
A
production
cost
model
based
on
linear
programming
approach,
solves
for
least
cost
dispatch.
Simulates
system
dispatch
and
operations,
estimates
marginal
generation
costs
on
an
hourly
basis.

Minimizes
present
worth
of
total
system
cost
subject
to
various
constraints.

General
Applications
Used
to
produce
annual
forecasts
of
energy
supply,
demand,
and
prices
through
2020
for
the
Annual
Energy
Outlook.
Can
also
be
used
to
analyze
effects
of
regulations.
EIA
performs
studies
for
Congress,
DOE,
other
agencies.
Used
by
DOE's
policy
office
to
study
the
impacts
of
electricity
market
transformation/
deregulation
through
2010.
Supports
the
administration's
1999
bill
on
industry
deregulation,
the
Comprehensive
Electricity
Competition
Act
(
CECA).
Primary
model
used
by
EPA
Air
Program
offices
to
evaluate
policy
and
regulatory
impacts
through
2030.
EPA
Office
of
Policy
also
used
this
model
for
GCC
and
retail
deregulation
analysis.
Used
by
over
50
private
sector
clients
to
develop
compliance
plans,
price
forecasts,
market
analysis,
and
asset
valuation.

Environmental
Applications
Includes
a
Carbon
Emission
submodule.
Can
also
calculate
emissions.
Produced
"
Analysis
of
Carbon
Mitigation
Cases"
for
EPA.
DOE
application
generally
not
designed
to
perform
environmental
regulatory
analysis.
Examines
a
renewable
portfolio
standard.
EPA/
ARD
concluded
that
air
emission
estimates
are
low
relative
to
IPM
and
other
models.
However,
DOE
contractor
has
performed
analyses
of
environmental
policies
for
private
clients.
Analyzes
environmental
regulations
by
simultaneously
selecting
optimal
compliance
strategies
for
all
generating
units.
Can
calculate
emissions,
and
simulate
trading
scenarios.
Used
for
ozone
(
NOx),
SO2,
and
mercury
emissions
control
scenarios;
implementation
of
NAAQS
for
ozone
and
PM;
alternative
NOx
emissions
trading
and
rate­
based
programs
for
OTAG,
CAAA
Title
IV
NOx
Rule;
NOx
control
options;
RIA
for
the
NOx
SIP
call;
and
GCC
scenarios.
Possible
to
accommodate
other
environmental
regulations.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
Table
B3­
A­
1:
Comparison
of
Electricity
Market
Models
Model
DOE/
EIA:
NEMS
DOE/
OP:
POEMS
(
OnLocation,
Inc.)
EPA/
Office
of
Air
Policy
(
OAP):
IPM
(
ICF
Consulting
Inc.)

B3­
34
NODA
Version
 
March
12,
2003
Modeling
Features
Treatment
of
Environmental
Regulations
Reference
case
represents
all
existing
regulations
and
legislation
in
effect
as
of
July
1,
1998,
including
impacts
of
the
Climate
Change
Action
Plan
and
the
NOx
SIP
call.
EMM
can
analyze
seasonal
environmental
controls
to
the
extent
that
they
match
up
with
the
seasonal
representations
in
the
model
(
non­
sequential
months
are
grouped
according
to
similar
load
characteristics).
Assumes
existing
regulations
and
legislation
remain
in
place
and
facilities
comply
with
existing
regulations
in
the
least
cost
way.
Most
recent
reference
case
analysis
includes
NOx
SIP
call.
Assesses
a
renewable
portfolio
in
the
competition
case.
Does
not
include
other
proposed
or
anticipated
environmental
regulatory
scenarios
in
DOE
analysis.
The
base
case
includes
current
federal
and
state
air
quality
requirements,
including
future
implementation
of
SO2
and
NOx
requirements
of
Title
IV
of
the
CAA,
the
NOx
SIP
call
as
implemented
through
a
cap
and
trade
program.
Base
case
also
includes
assumptions
regarding
demand
reductions
associated
with
the
Climate
Change
Action
Plan.

Treatment
of
Restructuring
All
regions
assumed
to
have
wholesale
competition.
Only
states
with
enacted
legislation
are
treated
as
competitive
for
retail
markets
in
base
case.
Has
a
competitive
pricing
scenario
that
assumes
full
retail
competition.
Designed
to
compare
competitive
wholesale
and
cost­
of­
service
retail
market
structures
to
fully
competitive
market
structure
at
the
wholesale
and
retail
levels.
Compares
prices
and
determines
"
stranded
assets"
at
the
firm
level.
Pricing
modeled
for
114
power
control
areas,
assumes
profit
maximizing
behavior.
EPA
uses
assumptions
in
IPM
that
reflect
wholesale
competition
occurring
throughout
the
electric
power
industry.
Work
for
private
clients
uses
different
assumptions.

Treatment
of
Economic
Plant
Retirements
Uses
assumptions
about
licencing
and
needs
for
new
major
capital
expenses
to
forecast
nuclear
retirements.
For
fossil
steam,
model
checks
yearly
to
compare
revenues
at
market
price
with
future
O&
M
and
fuel
costs
to
forecast
economic
retirements.

Results
appear
to
have
second
highest
forecast
of
fossil
steam
retirements
compared
to
other
models.
Uses
same
method
as
NEMS
for
forecasting
"
forced"
retirements
of
nuclear
assets
due
to
operating
constraints
such
as
licences.
Economic
retirements
based
on
lack
of
ability
to
cover
short
term
going
forward
costs
and
the
cost
of
capacity
replacement
in
the
long
term.

Results
appear
to
have
highest
forecast
of
fossil
steam
retirements
compared
to
other
models.
Uses
assumptions
about
licencing
in
forecasting
nuclear
retirements.
The
IPM
model
retires
capacity
when
unit
level
operating
costs
reach
a
level
that
total
electric
system
costs
are
minimized
by
shutting
down
the
existing
unit.

Regional
Capabilities
Model
runs
analysis
for
15
supply
regions.
Analyzes
114
power
control
areas
connected
by
680
transmission
links.
Analyzes
26
supply
regions
that
can
be
mapped
to
NERC
regions.

Plant/
Unit
Detail
Groups
all
plants
into
36
capacity
types
based
on
fuel
type,
burner
technology,
emission
control
technology,
etc.
within
a
region.
Units
or
plants
can
be
grouped
differently
according
to
§
316(
b)
characteristics.
Units
are
grouped
according
to
demand
and
supply
regions,
fuel
type,
prime
mover,
in­
service
period,
similar
heat
rates.
There
are
6,000
unit
groupings,
an
average
of
55
per
power
control
area.
Plants
can
be
re­
grouped
for
§
316(
b).
Groups
approximately
12,000
generating
units
into
model
plants.
Grouped
by
region,
state,
technology,
boiler
configuration,
location,
fuel,
heat
rate,
emission
rate,
pollution
control,
coal
demand
region.
Plants
can
be
re­
grouped
for
§
316(
b).
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
Table
B3­
A­
1:
Comparison
of
Electricity
Market
Models
Model
DOE/
EIA:
NEMS
DOE/
OP:
POEMS
(
OnLocation,
Inc.)
EPA/
Office
of
Air
Policy
(
OAP):
IPM
(
ICF
Consulting
Inc.)

NODA
Version
 
March
12,
2003
B3­
35
Modeling
Features
(
cont.)

Plant/
Unit
Data
Sources
Form
EIA­
860A
(
all
utility
plants);
Form
EIA­
867
(
nonutility
plants
<
1MW);
Form
EIA­
767
(
steam
plants
<
10MW);
Form
EIA­
759
(
monthly
operating
data
for
utility
plants).
Model
includes
"
virtually
all"
currently
existing
generating
units,
including
utility,
exempt
wholesale
generators
(
EWGs),
and
cogenerators.
Over
12,000
generating
units
are
represented
in
this
model.
Includes
all
utility
units
included
in
Form
EIA­
860
database.
Plus
IPPs
and
cogenerating
units
that
sell
firm
power
to
the
wholesale
market.
Also
draws
from
other
EIA
Forms,
Annual
Energy
Outlook
(
AEO),
UDI,
and
other
public
and
private
databases.
In
addition,
ICF
has
developed
a
database
of
industrial
steam
boilers
with
over
250
MMBtu/
hr
capacity
in
22
eastern
states.

General
Data
Inputs
Demand,
financial
data,
tax
assumptions,
EIA
and
FERC
data
on
capital
costs,
O&
M
costs,
operating
parameters,
emission
rates,
existing
facilities,
new
technologies,
transmission
constraints,
and
other
inputs
from
other
modules.
Inputs
are
similar
to
NEMS
(
for
demand,
fuel
price
and
macroeconomic
data),
and
EIA
reports.
FERC
filings
for
other
inputs
such
as
capacity,
operating
costs,
performance,
transmission,
imports,
and
financial
parameters.
Some
inputs
are
similar
to
NEMS,
including
demand
forecast,
and
cost
and
performance
of
new
and
existing
units.
Emission
constraints,
repowering,
and
retrofit
options
are
EPA
specified.
Fuel
supply
curves
are
used
to
model
gas
and
coal
prices.

Data
Inputs
for
§
316(
b)
EA
Would
need
to
provide
information
on
additional
capital
costs,
O&
M
costs,
study
costs,
outage
period
for
technology
installation,
and
changes
in
heat
rate
and
plant
energy
use
associated
with
each
type
of
technology
as
it
applies
to
each
type
of
model
plant.
Would
need
to
provide
information
on
additional
capital
costs,
O&
M
costs,
outage
period
for
installation,
and
changes
in
heat
rate
and
plant
energy
use
associated
with
each
type
of
technology
as
it
applies
to
each
plant
grouping.
Would
need
to
provide
information
on
additional
capital
costs,
O&
M
costs,
outage
period
for
installation,
and
changes
in
heat
rate
and
plant
energy
use
associated
with
each
type
of
technology
as
it
applies
to
each
type
of
model
plant.

General
Data
Outputs
Retail
price
and
price
components,
fuel
demand,
capital
requirements,
emissions,
DSM
options,
capacity
additions,
and
retirements
by
region
and
fuel
type.
Dispatch,
electricity
trade,
capacity
expansion,
retirements,
emissions,
and
pricing
(
retail
and
wholesale)
by
region,
state,
and
fuel
type.
Regional
and
plant
emissions;
fuel,
capital,
and
O&
M
costs;
environmental
retrofits;
capacity
builds;
marginal
energy
costs;
fuel
supply,
demand,
and
prices
(
primarily
wholesale;
one
study
focused
on
retail
market).
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
Table
B3­
A­
1:
Comparison
of
Electricity
Market
Models
Model
DOE/
EIA:
NEMS
DOE/
OP:
POEMS
(
OnLocation,
Inc.)
EPA/
Office
of
Air
Policy
(
OAP):
IPM
(
ICF
Consulting
Inc.)

B3­
36
NODA
Version
 
March
12,
2003
Data
Outputs
for
§
316(
b)
EBA
Results
would
include
additional
economic
retirements,
changes
in
generation,
and
changes
in
revenues
for
each
region
and
fuel
type.
EMM
cannot
provide
results
on
a
state­
by­
state
basis.

By
design,
it
is
not
possible
to
map
model
plant
results
back
to
specific
plant/
owner
using
current
modeling
approach.
Results
would
include
additional
economic
retirements,
changes
in
generation,
and
changes
in
revenues
for
each
region
and
plant
grouping.

Could
map
costs
to
units
and
owners
with
some
modification
of
structure.
Results
would
include
additional
economic
retirements,
changes
in
generation,
and
changes
in
revenues
for
each
region
and
model
plant
type.

Currently
has
ability
to
map
back
to
specific
unit
and
plant/
owner.
While
this
process
is
automated,
it
requires
2­
3
days
of
manual
checking
for
every
year
modeled.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
Table
B3­
A­
1:
Comparison
of
Electricity
Market
Models
Model
DOE/
EIA:
NEMS
DOE/
OP:
POEMS
(
OnLocation,
Inc.)
EPA/
Office
of
Air
Policy
(
OAP):
IPM
(
ICF
Consulting
Inc.)

NODA
Version
 
March
12,
2003
B3­
37
Logistical
Considerations
Costs
(
cost
estimates
should
be
considered
very
preliminary)
No
out­
of­
pocket
costs
expected.
Initial
policy
case
using
existing
scenario:
$
15­
20k.
Setting
up
new
base
case
scenario,
performing
several
runs,
and
producing
briefing:
$
40­
60k.
(
Assumes
plant
re­
grouping
cost
is
included
in
second
estimate
only.)
Initial
policy
case:
$
20­
30k.
Incremental
cases
$
2­
10k.
Regrouping
model
plants
would
be
labor
intensive
and
add
costs
to
analysis.

Computational
Requirements
Setting
up
a
policy
case
may
take
two
months.
The
model
run
time
is
two
hours
without
iterating
with
rest
of
NEMS,
four
hours
for
total
NEMS
iteration.
EIA
runs
NEMS
on
RS6000
workstations.
Setting
up
and
running
policy
case
could
take
from
a
few
days
to
a
few
weeks,
depending
on
whether
policy
case
builds
on
an
existing
scenario
and
the
complexity
of
the
policy
scenarios.
Depends
on
number
of
model
plants
and
number
of
years
in
analysis.
Base
case
approximately
4­
6
hours.

Accessability
and
Response
Time
Access
and
response
time
dependent
on
agreement
between
EIA
and
EPA
and
EIA's
schedule.
Could
be
difficult
to
get
results
turned
around
in
time
to
meet
regulatory
schedule,
depending
on
EIA's
reporting
schedule.
Access
and
response
time
potentially
dependent
on
agreement
between
DOE
and
EPA
and
DOE's
schedule.
Model
run
by
a
contractor.
ARD
has
impression
that
model
has
long
set­
up
time,
model
not
set
up
to
perform
many
iterations
quickly.
ICF
is
an
EPA
contractor.
Assume
that
access
and
response
time
will
be
consistent
with
requirements
of
analysis.

Documentatio
n
and
Disclosure
of
Inputs/
Results
Documentation
and
results
already
available
to
public.
Presented
by
year
for
fuel
type
and
region.
Could
make
aggregated
results
publicly
available.
EIA
does
not
release
plant­
specific
results.
Documentation
and
results
of
reference
and
competition
cases
are
available
to
public
on
DOE's
web
page.
Documentation
of
the
EPA
Base
Case
already
available
to
public.
Assume
disclosure
would
be
similar
to
that
for
NOx
SIP
call,
etc.
EPA/
ARD
states
that
there
is
more
in
public
domain
regarding
IPM
than
most
models.
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
Table
B3­
A­
1:
Comparison
of
Electricity
Market
Models
Model
DOE/
EIA:
NEMS
DOE/
OP:
POEMS
(
OnLocation,
Inc.)
EPA/
Office
of
Air
Policy
(
OAP):
IPM
(
ICF
Consulting
Inc.)

B3­
38
NODA
Version
 
March
12,
2003
Notes
The
NEMS
code
and
data
are
available
to
anyone
for
their
own
use.
Anyone
wishing
to
use
NEMS
is
responsible
for
any
code
conversions
or
setup
on
their
own
systems.
For
example,
FORTRAN
compilers
differ
between
the
workstation
and
PC.
Several
national
laboratories
and
consulting
firms
have
used
NEMS
or
portions
of
it,
but
the
time
investment
is
considerable.
One
out­
of­
pocket
expense
is
the
purchase
of
an
Optimization
Modeling
Library
(
OML)
license.
OML
is
used
to
solve
the
embedded
linear
programs
in
NEMS.
In
order
to
modify
or
execute
one
of
the
NEMS
modules
that
includes
a
linear
program
(
EMM
is
one
of
them),
an
OML
license
is
required.
DOE's
contractor
stated
that
they
may
need
to
make
some
structural
changes
to
the
modeling
framework
to
accommodate
the
requirements
for
§
316(
b)
analysis
so
that
the
model
can
incorporate
the
effects
of
the
additional
costs
into
the
decision
process
(
either
to
continue
running
a
plant
or
to
retire
and
replace
the
plant).
OAP
sensitive
to
other
EPA
offices
using
another
model
or
using
IPM
with
different
assumptions.
Willing
to
coordinate
and
provide
background
and
technical
support.

The
EPA
Base
Case
has
received
some
challenges
over
impacts
of
Climate
Change
Action
Plan
on
end­
use
demand.
However,
has
cleared
OMB
review
under
other
regulatory
proposals.

References
<
Annual
Energy
Outlook
1999,
Report#:
DOE/
EIA­
0383(
99);
<
Assumptions
to
the
AEO99,
Report#:
DOE/
EIA­
0554(
99);
<
EMM/
NEMS
Model
Documentation
Report,
Report#:
DOE/
EIAM0689
99);
<
Personal
communications
with
EIA
staff:
Jeffrey
Jones
(
jeffrey.
jones@
eia.
doe.
gov)
and
Susan
Holte
(
sholte@
eia.
doe.
gov).
<
POEMS
Model
Documentation,
June
1998;
<
Supporting
Analysis
for
the
Comprehensive
Electricity
Competition
Act
(
CECA),
May,
1999,
Report#:
DOE/
PO­
0059;
<
The
CECA:
A
Comparison
of
Model
Results,
September,
1999,
Report#:
SR/
OAIF/
99­
04;
<
Personal
communications
with
DOE
staff:
John
Conti
(
john.
conti@
hq.
doe.
gov),
EPA
staff:
Sam
Napolitano
(
napolitano.
sam@
epa.
gov),
and
contractor:
Lessly
Goudarzi
(
goudarzi@
onlocationinc.
com)
.
<
Analyzing
Electric
Power
Generation
Under
the
CAA
(
Appendix
2),
March,
1998
(
EPA/
OAR/
ARD);
<
Analysis
of
Emission
Reduction
Options
for
the
Electric
Power
Industry
(
Chapter
2),
March,
1999
(
EPA/
OAR/
ARD);
<
IPM
Demonstration,
May,
1998
(
slides
by
ICF);
<
Personal
communications
with
EPA
staff:
Sam
Napolitano
(
napolitano.
sam@
epa.
gov),
and
contractors:
John
Blaney
(
blaneyj@
icfkaiser.
com).

Source:
U.
S.
EPA
analysis,
2002.

B3­
A.
2
DIFFERENCES
BETWEEN
THE
EPA
BASE
CASE
2000
AND
PREVIOUS
MODEL
SPECIFICATIONS
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
NODA
Version
 
March
12,
2003
B3­
39
Past
applications
by
EPA
of
the
IPM
model
have
employed
a
predecessor
base
case
specification.
The
previous
specification
of
the
IPM
model,
EPA
Base
Case
1998,
was
recently
updated
to
the
current
EPA
Base
Case
2000.
The
revised
specification
used
for
the
section
316(
b)
analysis
uses
more
complete
and
current
cost
and
performance
data
for
new
and
existing
facilities,
updated
demand
growth
forecasts,
and
revised
financial,
fuel
cost,
and
regulatory
assumptions.
The
primary
differences
between
the
IPM's
EPA
Base
Case
2000
and
its
predecessor
model
specification
are
identified
and
discussed
below.
For
more
a
more
detailed
discussion
of
the
specification
of
the
EPA
Base
Case
2000
see
Documentation
of
EPA
Modeling
Applications
(
V.
2.1)
Using
the
Integrated
Planning
Model
(
U.
S.
EPA,
2002).

<
The
National
Electric
Energy
Data
System
(
NEEDS),
the
database
containing
location,
operational,
and
emission
data
for
each
of
the
existing
and
planned­
committed
generating
units
modeled
in
each
IPM
base
case
specification,
was
updated
using
1998
EIA
data
taken
primarily
from
Form
EIA­
860A,
Form
EIA­
860B,
Form
EIA­
759,
and
Form
EIA­
767.
In
addition,
the
update
used
data
from
the
1998
NERC
Electric
Supply
and
Demand
database,
second
quarter
values
from
EPA's
2000
Continuous
Emission
Monitoring
System
database,
and
the
EPA
1999
Information
Collection
Request
database.

<
The
EPA
Base
Case
1998
demand
growth
assumptions
were
updated
for
the
EPA
Base
Case
2000
specification.
The
demand
growth
assumptions
for
the
original
specification
were
based
on
the
1997
NERC
Electricity
Supply
and
Demand
forecast
for
Net
Energy
for
Load
in
early
years,
and
on
the
Data
Research
Institute
(
DRI)
1995
forecast
for
later
years.
These
original
forecasts
were
adjusted
based
on
EPA's
estimate
of
the
demand
reductions
resulting
from
implementation
of
the
Climate
Change
Action
Plan
(
CCAP).
The
EPA
Base
Case
1998
electricity
demand
growth
rate
was
1.6
percent
per
year
for
1997­
2000,
1.8
percent
per
year
for
2001­
2010,
and
1.3
percent
per
year
for
beyond
2010.
EPA
Base
Case
2000
electricity
demand
growth
is
based
on
the
AEO
2001
forecast.
The
AEO
2001
forecast
was
also
adjusted
to
account
for
impacts
of
initiatives
created
under
the
CCAP
in
the
revised
base
case
specification.
The
EPA
Base
Case
2000
average
annual
growth
rate
in
Net
Energy
for
Load
is
1.2
percent
for
2000­
2020.

<
Fuel
Price
assumptions
were
also
updated
under
the
EPA
Base
Case
2000
specification.
Revised
fuel
price
forecasts/
supply
curves
for
nuclear
and
biomass
assumptions
were
taken
from
AEO2000
and
AEO2001,
respectively,
and
natural
gas
information
was
derived
from
ICF's
Gas
Systems
Analysis
Model
(
GSAM).

<
The
underlying
assumptions
affecting
the
retirement
of
fossil
fired
and
nuclear
capacity
under
the
original
specification
were
revised
for
EPA
Base
Case
2000.
Fossil
power
plants
are
given
no
fixed
retirement
date
in
EPA
Base
Case
2000
as
compared
to
EPA
Base
Case
1998
where
they
were
assumed
to
have
a
finite
lifetime.
In
the
EPA
Base
Case
2000
retirement
is
determined
endogenously
based
on
economics.
In
addition,
the
option
of
re­
licensing
nuclear
units
was
introduced
for
EPA
Base
Case
2000,
based
on
AEO2000
nuclear
capacity
factor
forecast
data.
Nuclear
units
that
had
not
made
a
major
maintenance
investment,
at
age
30,
are
provided
with
a
10­
year
life
extension.
These
same
units
may
subsequently
undertake
a
20­
year
re­
licensing
option
at
age
40.
Nuclear
units
that
already
had
made
a
maintenance
investment
are
provided
with
a
20­
year
re­
licensing
option
at
age
40.
All
nuclear
units
are
ultimately
retired
at
age
60.

<
The
cost
and
performance
characteristics
of
new
and
existing
units
as
well
as
environmental
control
technologies
such
as
SO2
scrubbers,
selective
catalytic
reduction,
and
activated
carbon
injection
were
updated
using
more
recent
data
for
the
EPA
Base
Case
2000
specification.
For
example,
the
O&
M
costs
for
existing
units
were
updated
to
include
the
cost
of
capital
additions.
Further,
the
cost
and
performance
assumptions
for
new
units
were
updated
using
information
presented
in
AEO2000.

<
The
financial
assumptions
for
environmental
control
options
and
new
units
were
revised
based
on
recent
market
activity.
The
capital
charge
rate
and
discount
rate
in
EPA
Base
Case
1998
were
10.4%
and
6%,
respectively.
For
the
EPA
Base
Case
2000
specification
the
capital
charge
rate
and
discount
rate
were
revised
to
12%
and
5.34%,
respectively,
for
retrofits;
12.9%
and
6.14%,
respectively,
for
new
combined
cycle
units;
and
13.4%
and
6.74%,
respectively,
for
new
combustion
turbine
units.

<
The
EPA
Base
Case
2000
uses
updated
transmission
assumptions.
EPA
Base
Case
2000
organizes
the
United
States
into
26
different
power
market
regions
for
analyzing
inter­
regional
electricity
transfers
across
the
interconnected
bulk
power
transmission
grid
as
compared
to
21
power
market
regions
in
EPA
Base
Case
1998.
Assumptions
regarding
transmission
capabilities
in
the
EPA
Base
Case
2000
were
updated
based
on
more
recent
NERC
documents.

<
The
EPA
Base
Case
2000
is
updated
to
account
for
additional
environmental
regulations.
Specifically,
EPA
Base
Case
2000
accounts
for
EPA's
NOx
SIP
Call
regulation,
a
trading
program
covering
all
fossil
units
in
19
northeastern
§
316(
b)
Phase
II
EBA,
Part
B:
Costs
and
Economic
Impacts
Appendix
to
Chapter
B3
B3­
40
NODA
Version
 
March
12,
2003
states
during
the
ozone
season
(
May­
September).
In
addition,
state
level
environmental
regulations
in
Texas,
Missouri,
and
Connecticut
are
also
modeled.

<
The
aggregation
scheme
for
model
plants
was
revised
under
EPA
Base
Case
2000.
The
group
of
coal
fired
model
plants
was
further
disaggregated
based
on
power
plant
firing
type,
fine
particulate
controls,
and
post
combustion
NOx
controls.
