Document ID: EPA-HQ-OAR-2003-0053-2069
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-03-10T05:00Z

2­
1
CHAPTER
2.
METHODOLOGY
AND
THE
BASE
CASE
The
chapter
explains
how
pollution
control
options
for
emissions
of
sulfur
dioxide
(
SO2),
mercury,
and
carbon
dioxide
(
carbon)
from
the
electric
power
industry
were
analyzed.
The
chapter
also
provides
a
forecast
of
future
electric
generation,
air
emissions,
and
fossil
fuel
use
for
the
Base
Case
for
this
study.

The
study
uses
a
Base
Case
to
measure
the
changes
in
electric
generation
practices,
air
emissions
and
costs
that
would
result
from
control
options
for
SO2,
mercury,
and
carbon
emissions.
The
Base
Case
assumes
current
federal
and
State
requirements
for
air
pollution
control
including
the
future
implementation
of
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990
(
CAAA)
for
SO2
and
nitrogen
oxide
(
NOx)
emissions
and
the
NOx
SIP
call.
It
is
assumed
that
compliance
with
the
NOx
SIP
call
will
be
achieved
through
a
regional
cap­
and­
trade
program.

METHODOLOGY
This
section
explains
the
approach
and
describes
the
key
assumptions
that
are
used
to
analyze
different
pollution
control
options
for
the
electric
power
industry.
Most
of
the
assumptions
made
in
this
study
are
described
in
greater
detail
in
U.
S.
Environmental
Protection
Agency,
Analyzing
Electric
Power
Industry
under
the
CAAA,
March
1998.1
However,
the
Agency
updated
the
mercury
emissions
and
mercury
control
cost
functions
during
the
preparation
of
this
study
and
the
details
of
these
revised
assumptions
are
provided
in
technical
appendices
of
this
report.

Analytical
Overview
For
each
pollution
control
alternative,
this
analysis
examined
the
changes
from
the
Base
Case
in
estimated
air
emissions,
production
costs,
generation,
capacity,
and
fuel
use.

The
analyses
have
a
wide
scope
geographically
and
over
time,
examining
the
actions
of
close
to
8,000
utility
and
non­
utility
electric
generation
units
in
all
48
contiguous
States
for
a
period
starting
in
2005
and
running
through
2025.
The
results
are
reported
for
the
years
2005,
2007,
and
2010.
Examining
the
industry
over
many
years
makes
it
possible
to
take
many
important
dynamic
effects
into
account.
For
example,
the
effects
of
efficiency
gains
over
time
and
the
choice
between
capital­
intensive
control
measures
and
measures
that
increase
operating
costs
can
be
investigated
by
projecting
the
power
industry's
response
over
a
long
analytical
period.
In
addition,
the
effects
of
allowing
the
banking
of
emission
reductions
can
be
analyzed
only
in
a
dynamic
framework.

1
This
report
can
also
be
found
at
an
EPA
website
with
the
address:
http://
www.
epa.
gov/
capi.
2­
2
The
Integrated
Planning
Model
(
IPM)
was
used
in
this
analysis
to
predict
the
actions
of
power
plant
operators
over
time
in
response
to
alternative
levels
of
air
pollution
controls.
IPM
is
a
detailed
computer
model
of
the
electric
power
industry.
The
model
finds
the
most
efficient
(
that
is,
the
least­
cost)
way
to
satisfy
the
demand
for
electricity
under
a
series
of
limitations
or
constraints.
The
constraints
under
which
IPM
"
produces"
electricity
can
include
a
limit
on
tons
of
NOx,
SO2,
carbon,
and
mercury
emissions
during
the
summer
(
ozone
season),
or
annually.
By
setting
constraints
on
any
one,
or
combination
of
these
air
pollutants
over
time,
EPA
can
model
various
control
options
for
emissions
cap­
and­
trade
programs.
The
Base
Case
for
this
analysis
is
provided
by
running
IPM
with
an
ozone
(
summer)
season
limitation
of
544
thousand
tons
of
NOx
emissions
in
22
eastern
States
and
the
District
of
Columbia
covered
by
the
NOx
SIP
call.
2
This
case
also
has
a
national
SO2
emissions
cap
for
the
Title
IV
SO2
allowance­
trading
program.
3
To
look
at
other
control
options
that
apply
cap­
and­
trade
approaches,
EPA
simply
adds
other
air
emissions
constraints,
and/
or
changes
the
NOx
and
SO2
constraints.

IPM
can
also
be
used
to
examine
rate­
based
controls
(
e.
g.
an
emissions
limitation
of
.15
pounds
of
NOx
for
every
million
BTUs
of
fossil
energy
use).
This
allows
consideration
of
control
options
that
require
removal
of
a
specified
percentage
of
a
pollutant
from
a
generation
unit's
emissions
(
e.
g.
removal
of
80
percent
of
the
mercury
emissions
from
a
coal­
fired
boiler
flue
gases).
EPA
has
generally
used
these
types
of
"
command­
and­
control"
options
for
Section
112
controls
under
the
CAAA
in
setting
standards
for
hazardous
air
pollutants
based
on
the
maximum
achievable
control
technology
(
MACT).
If
EPA
decides
to
regulate
mercury
emissions
from
coal­
fired
electric
generation
units
under
the
CAAA,
the
Agency
could
set
MACT
requirements
for
these
units.
To
analyze
this
type
of
control,
plants
in
the
model
are
given
specific
emission
rates
that
match
the
control
requirements
and
added
pollution
control
costs
that
cover
the
capital,
operating,
and
maintenance
expenses.
In
a
single
model
run,
IPM
is
able
to
consider
cap­
andtrade
controls
on
some
pollutants
and
the
setting
of
emission
rates
under
MACT
requirements
for
others.

IPM
Use
and
Assumptions
IPM
has
been
used
for
over
ten
years
by
electric
utilities,
trade
associations,
and
government
agencies
both
in
the
U.
S.
and
abroad
to
address
a
wide
range
of
issues
regarding
electric
power
markets.
It
has
been
used
for
capacity
planning,
environmental
policy
and
compliance
planning,
wholesale
price
forecasting,
and
asset
valuation.
4
EPA
has
used
this
model
extensively
for
environmental
policy
and
regulatory
analysis.
For
example,
EPA
has
used
IPM
to
analyze
the
emissions
reductions
and
costs
for
the
electric
power
industry
of:

 
NOx,
SO2,
and
mercury
emissions
control
strategies
as
part
of
the
Clean
Air
Power
Initiative
(
CAPI)
in
1996,

2
The
ozone
season
is
from
May
1st
to
September
30th
in
the
NOx
SIP
call.
This
is
also
referred
to
as
the
"
summer
season"
in
this
study.
3
EPA
also
looks
at
other
CAAA
controls
and
state
environmental
requirements
in
the
base
case,
which
will
be
explained
later
in
the
chapter.
4
ICF
Resources
developed
the
Integrated
Planning
Model
as
a
commercial
capacity­
planning
tool
and
for
policy
applications
over
wide
geographic
areas
or
for
the
entire
country.
EPA
had
ICF
set
up
IPM
for
environmental
policy
analysis
of
options
to
control
emissions
form
NOx.
SO2,
carbon,
and
mercury
with
the
assumptions
described
in
this
chapter.
Under
EPA's
direction,
ICF
prepared
the
Base
Case
and
control
options
presented
in
this
study.
2­
3
 
Implementation
of
the
Clean
Air
Act
Amendments
of
1990
as
required
under
Section
812
of
CAAA,

 
Implementation
of
National
Ambient
Air
Quality
Standards
(
NAAQS)
for
ozone
and
particulates
in
the
Regulatory
Impact
Analysis
supporting
these
rules,

 
Alternative
NOx
emissions
trading
and
rate­
based
programs
and
during
the
Ozone
Transport
Assessment
Group
(
OTAG)
process
in
1996
and
1997,

 
The
CAAA
Title
IV
NOx
Rule,

 
NOx
control
options
for
the
NOx
SIP
call
in
1997
and
1998
in
the
Regulatory
Impact
Analysis
to
support
this
rulemaking.

IPM
has
undergone
extensive
review
and
validation
over
this
ten­
year
period.
In
April
1996,
EPA
requested
participants
in
the
CAPI
process
to
comment
on
the
Agency's
approach
to
forecasting
electric
power
generation
and
selected
air
emissions.
EPA
received
many
helpful
comments
and
made
a
series
of
changes
in
its
methodology
and
assumptions
based
on
commenters=
recommendations.
IPM
and
EPA's
modeling
assumptions
were
reviewed
as
part
of
the
OTAG
process
and
in
the
preparation
of
the
NOx
SIP
call.
Again,
changes
were
made
to
the
methodology
and
assumptions
based
on
commenters=
recommendations.

The
version
of
IPM
currently
used
by
EPA
represents
the
U.
S.
electric
power
market
in
21
regions,
as
depicted
in
Exhibit
2­
1.
These
regions
correspond
in
most
cases
to
the
regions
and
sub­
regions
used
by
the
North
American
Electric
Reliability
Council
(
NERC).
IPM
models
the
electricity
demand,
generation,
transmission,
and
distribution
within
each
region
as
well
as
movement
of
power
on
the
transmission
grid
that
connects
the
different
electric
generation
regions.
EPA
uses
assumptions
in
IPM
that
are
meant
to
reflect
wholesale
competition
occurring
throughout
the
electric
power
industry.

The
model
includes
existing
utility
power
plants
as
well
as
independent
power
producers
and
cogeneration
facilities
that
sell
firm
capacity
into
the
wholesale
market.
Data
on
the
existing
boiler
and
generator
population,
which
consists
of
close
to
8,000
records,
are
maintained
in
EPA's
National
Electric
Energy
Data
System
(
NEEDS).
In
order
to
make
the
modeling
more
time
and
cost
efficient,
the
individual
boiler
and
generator
data
are
aggregated
into
A
model@
plants.
EPA's
application
of
the
model
has
focused
heavily
on
understanding
the
future
operations
of
coal­
fired
units,
which
will
have
the
greatest
air
emissions
among
the
fossil­
fired
2­
4
Exhibit
2­
1
Integrated
Planning
Model
Regions
in
the
Configuration
Used
by
EPA
CNV
SPPN
ERCT
NENG
LILC
UPNY
FRCC
WUMS
MECS
MACS
MACE
MACW
SOU
SPPS
WSCP
WSCR
MAPP
TVA
ECAO
MANO
VACA
2­
5
units.
The
operation
of
other
types
of
non­
fossil
fuel­
fired
generation
capacity,
including
nuclear
and
renewables,
are
also
simulated
but
at
a
higher
degree
of
aggregation.

Working
with
these
existing
model
plants
and
representations
of
alternative
new
power
plant
options,
IPM
determines
the
least­
cost
means
for
supplying
electricity
demand
while
limiting
air
emissions
to
remain
below
specified
policy
limits.
While
determining
the
least­
cost
solution,
IPM
also
determines
the
optimal
compliance
strategy
for
each
model
plant
as
part
of
system
wide
effort
to
minimize
electric
generation
costs.
For
this
study,
IPM
was
set
up
to
allow
selection
of
a
wide
range
of
compliance
options
by
the
model
plants
in
each
simulation,
including:

 
Fuel
Switching
 
For
example,
switching
from
high
sulfur
coal
to
low
sulfur
coal.

 
Repowering
 
For
example,
repowering
an
existing
coal
plant
to
a
natural
gas
combined­
cycle
plant.

 
Pollution
Control
Retrofit
 
For
example,
installing
selective
catalytic
reduction
(
SCR),
selective
non­
catalytic
reduction
(
SNCR),
or
gas
reburn
(
to
reduce
NOx
emissions),
or
flue
gas
desulfurization
(
to
control
SO2
emissions).

 
Economic
Retirement
 
For
example,
retiring
an
oil
or
gas
steam
plant.

 
Dispatch
Adjustments
 
For
example,
running
high­
NOx
cyclone
units
less
often,
and
low
NOx
combined­
cycle
plants
more
often.

IPM
provides
estimates
of
air
emissions
changes,
incremental
electric
power
generation
costs,
changes
in
fuel
use
and
electric
generation
practices,
and
other
potential
impacts
for
each
air
pollution
policy
analyzed.
In
using
IPM
to
analyze
air
emission
policies
over
the
past
three
years,
EPA
has
developed
a
set
of
data
and
assumptions
that
reflect
the
best
available
information
on
the
electricity
market
and
operating
factors.
These
data
and
assumptions
can
be
grouped
into
the
following
four
categories:

 
Macro
Energy
and
Economic
Assumptions
 
These
assumptions
are
related
primarily
to
electricity
demand
projections,
fuel
prices,
power
plant
availability,
heat
rates,
lifetimes,
and
capacity
factors.
Also
included
in
this
category
are
discount
rate
and
year
dollar
assumptions.

 
Electric
Technology
Cost
and
Performance
 
These
assumptions
are
related
to
electric
technology
cost
and
performance
for
existing
and
new
plants,
as
well
as
for
existing
plant
refurbishment
and
repowering.

 
Air
Emissions
Rates
under
the
Base
Case
 
These
assumptions
cover
current
EPA
and
State
requirements
that
will
affect
emission
levels
from
various
facilities.
The
focus
has
been
on
SO2
and
NOx
controls
where
EPA
and
the
States
have
promulgated
regulations.
EPA
also
determines
carbon
and
mercury
emissions
through
the
fuels
used
for
electric
generation.
2­
6
 
Pollution
Control
Performance
and
Costs
 
These
assumptions
cover
the
performance
and
unit
costs
of
pollution
control
technologies
for
NOx,
SO2
and
mercury.
There
are
no
economically
available
direct
pollution
control
technologies
for
carbon
emissions
for
electric
generation
units.
Reductions
of
carbon
emissions
from
the
power
industry
result
from
reductions
in
electric
demand,
greater
generation
unit
efficiency,
fuel
switching,
and
changes
in
the
mix
of
generation
technologies.

Macro
Energy
and
Economic
Assumptions
In
developing
the
analysis
for
this
study,
EPA
makes
assumptions
about
major
macro
energy
and
economic
factors,
as
shown
in
Exhibit
2­
2.
See
Appendix
No.
2
of
EPA=
s
March
1998
report
Analyzing
Electric
Power
Generation
under
the
CAAA
for
details
on
most
of
the
macro
energy
and
economic
factors.

Exhibit
2­
2
Key
Baseline
Assumptions
for
Electricity
Generation
Factor
Assumption
Discount
Rate
(
percent
per
year)
6
Conversion
Factor
from
1997
to
1990
Dollars
0.83
Electricity
Demand
Growth
Rate
(
percent
per
year)
a
1997­
2000
=
1.6
2001­
2010
=
1.8
>
2010
=
1.3
Reductions
due
to
Climate
Change
Action
Plan
(
Billion
kWh)
2005
=
228
2007
=
293
2010
=
389
>
2019
=
608
Power
Plant
Lifetimes
Fossil
Steam
=
65
years
if

50
MW
=
45
years
if
<
50
MW
Nuclear
=
40
year
license
length
Turbines
=
30
years
U.
S.
Nuclear
Capacity
(
gigawatts)
2005
=
87
2007
=
86
2010
=
81
2020
=
50
Nuclear
Capacity
Factors
(
percent)
2005
=
80
2007
=
82
2010
=
81
2020
=
83
2­
7
Exhibit
2­
2
(
continued)
Key
Baseline
Assumptions
for
Electricity
Generation
Factor
Assumption
World
Oil
Prices
(
1997$
per
BBL)
2005
=
20.50
2007
=
20.80
2010
=
21.20
2020
=
22.40
Wellhead
Natural
Gas
Price
(
1997$
per
mmBtu)
b
2005
=
2.00
2007
=
2.00
2010
=
2.00
Coal
Steam
Power
Plant
Availability
(
percent)
2005/
10/
20
=
85
Existing
Power
Plant
Heat
Rates
No
change
over
time
Coal
Mining
Productivity
Increases
(
percent
change
per
year)
1995­
1999
=
3.1
2000­
2004
=
2.8
2005­
2009
=
2.4
2010­
2014
=
2.1
2015­
2025
=
2.1
Average
Delivered
Coal
Pricesb
(
percent
change
per
year
2001­
2010)
­
2.0
a
Does
not
include
any
adjustment
for
potential
improvements
related
to
the
Climate
Change
Action
Plan.
b
Based
on
recent
ICF
analyses
using
updated
coal
mining
productivity
and
supply
for
coal,
and
technology
and
supply
assumptions
for
gas.
Note
that
the
natural
gas
prices
are
not
an
assumption
in
the
model,
but
are
a
forecast
of
the
model.

Electric
Energy
Cost
and
Operating
Assumptions
In
order
to
simulate
the
electric
power
market
under
Base
Case
conditions
and
for
each
of
the
air
emission
control
options,
assumptions
are
made
on
the
cost
and
performance
of
new
power
plants
as
well
as
for
repowering
existing
power
plants.
These
characterizations
of
new
power
plant
costs
and
performance
are
used
in
IPM
to
determine
the
least
cost
means
for
meeting
projected
future
electricity
requirements
subject
to
alternative
pollution
control
restrictions.

Initially,
EPA
looked
at
all
the
existing
and
emerging
electric
generation
technologies
that
could
be
used
in
the
future
and
determined
which
are
likely
to
be
economic
to
build
from
2000
to
2025.
Those
technologies
that
looked
viable
were
then
included
in
IPM.
Power
plant
cost
and
performance
assumptions
that
are
included
in
IPM
for
new
conventional
and
unconventional
generation
units
include:

 
New
Conventional
Generation
Units
­
Conventional
Pulverized
Coal;
­
Advanced
Coal
(
Integrated
Gasification
Combined
Cycle
­
IGCC);
2­
8
­
Combined
Cycle;
­
Combustion
Turbine;
and
­
Nuclear
 
New
Renewable/
Nontraditional
Generation
Units
­
Biomass
IGCC;
­
Solar
Photovoltaics;
­
Solar
Thermal;
­
Geothermal;
and
­
Wind
Cost
and
performance
projections
were
developed
for
the
period
2005
through
2010
in
order
to
capture
changes
in
technology
over
time.
Regional
variations
in
the
capital
construction
and
labor
costs
in
making
assumptions
about
the
expenses
of
bringing
new
capacity
on
line
were
also
developed.
EPA
relied
heavily
on
work
that
the
Energy
Information
Administration
(
EIA)
did
in
support
of
recent
Annual
Energy
Outlooks
(
AEO97
and
AEO98).
EIA
had
its
approach
peer­
reviewed
during
its
development.
The
Agency
also
used
other
well­
recognized
reference
sources,
such
as
the
Electric
Power
Research
Institute's
Technical
Assessment
Guide.

In
addition
to
these
assumptions
on
new
power
plants,
EPA
also
developed
assumptions
on
the
cost
and
performance
of
repowering
existing
power
plants.
The
following
three
types
of
repowering
options
are
considered:

 
Repowering
Coal
Steam
to
Integrated
Gasification
Combined­
Cycle;

 
Repowering
Coal
Steam
to
Natural
Gas
Combined­
Cycle;
and
 
Repowering
Oil/
Gas
Steam
to
Natural
Gas
Combined­
cycle.

For
more
details
on
the
assumptions
made
about
the
cost
and
performance
of
new
power
plants
and
repowering
of
existing
power
plants,
see
Appendix
No.
3
of
EPA=
s
March
1998
report
Analyzing
Electric
Power
Generation
under
the
CAAA.
2­
9
Air
Emissions
under
the
Base
Case
EPA
had
to
make
assumptions
for
the
Base
Case
emissions
of
NOx,
SO2,
carbon,
and
mercury
for
this
study.
For
each
pollutant,
EPA
used
a
somewhat
different
approach
that
is
summarized
below.
Details
on
assumptions
that
EPA
used
in
preparing
air
emissions
estimates
with
IPM
can
be
reviewed
in
Appendix
No.
4
of
EPA's
March
1998
report,
Analyzing
Electric
Power
Generation
under
the
CAAA
and
EPA's
Regulatory
Impact
Analysis
for
the
NOx
SIP
Call,
FIP,
and
Section
126
Petitions,
Volume
1:
Costs
and
Economic
Impacts,
September
1998.

NOx
Emissions
­
There
are
four
sets
of
regulations
affecting
NOx
emissions
that
are
taken
into
account
in
this
analysis.
First,
State
requirements
are
considered,
especially
in
California.
Second,
EPA
factors
in
regulations
under
Title
I
of
the
Clean
Air
Act,
including
RACT
requirements
for
existing
sources,
EPA's
New
Source
Performance
Standards,
and
controls
based
on
Best
Available
Control
Technology
(
BACT)
and
Lowest
Achievable
Emissions
Rates
(
LAER)
that
would
be
in
effect
for
new
sources.
Third,
the
analysis
also
accounts
for
the
NOx
reductions
from
utility
units
under
Phases
I
and
II
of
Title
IV's
Acid
Rain
Program,
which
set
rate
limitations
for
most
coal­
fired
generators
greater
than
25
MW
of
capacity.
Finally,
the
NOx
SIP
call
covering
eastern
States
is
considered.
EPA
estimated
the
NOx
rates
of
generation
units
that
use
fossil
fuels
and
renewable
fuels,
such
as
municipal
waste
combustors.
EPA
takes
all
of
these
requirements
into
account
in
its
determination
of
individual
emissions
rates
for
model
plants
in
its
analysis.

SO2
Emissions
­
EPA
focused
primarily
on
the
emissions
from
coal­
fired
units,
because
they
are
the
dominant
source
of
SO2
emissions
in
this
sector.
For
existing
coal­
fired
generation
units
that
have
installed
flue
gas
desulfurization
units
(
scrubbers),
EPA
considered
how
they
would
operate
in
the
future
to
maximize
SO2
reductions
at
the
lowest
fuel
costs.
For
all
other
existing
coal­
fired
generation
units,
EPA
considered
limitations
that
have
been
placed
on
them
under
existing
state
air
pollution
control
programs
and
allowed
these
units
to
select
the
cheapest
way
to
comply
with
the
requirements
of
the
Title
IV
Allowance
Trading
Program
given
variations
in
the
sulfur
content
of
coals
and
their
delivered
prices.
IPM
contains
sulfur
content
factors
for
the
different
coal
grades
produced
throughout
the
country
that
can
be
combined
with
energy
use
estimates
for
model
plants
to
estimate
SO2
emissions.
New
coal­
fired
units
are
assumed
to
have
scrubbers
and
to
select
coals
that
allow
them
to
minimize
their
total
operating
costs.

Carbon
Emissions
 
EPA
considered
the
use
of
different
types
of
fossil
fuels
by
model
plants
in
IPM
and
the
relationship
between
specific
fuel
grades
(
e.
g.
lignite
and
bituminous
coal)
and
carbon
emissions.
The
Agency
used
fuel­
grade
specific
carbon
dioxide
emission
factors
developed
by
the
Energy
Information
Administration
for
this
purpose.

Mercury
Emissions
 
For
this
study,
EPA
updated
the
assumptions
in
the
March
1998
report,
Analyzing
Electric
Power
Generation
under
the
CAAA
for
mercury
emissions.
The
most
critical
sets
of
assumptions
that
EPA
made
in
its
forecast
of
mercury
emissions
are
the
mercury
content
of
fossil
fuels,
the
mercury
reductions
that
are
attributable
to
different
types
of
boilers
at
electric
generation
units,
and
their
existing
pollution
control
equipment
and
their
configuration.
2­
10
These
assumptions
are
explained
in
Appendix
A
(
mercury
concentrations
in
coal)
and
Appendix
B
(
emissions
modification
factors
for
electric
generation
units).

Pollution
Control
Performance
and
Cost
Assumptions
For
this
study,
pollution
control
performance
and
cost
assumptions
were
developed
for
alternative
levels
of
NOx,
SO2,
carbon,
and
mercury
emissions
from
power
plants.
Until
this
study,
IPM
was
set
up
to
allow
model
plants
in
pollution
control
simulations
the
opportunity
to
retrofit
only
once
over
the
period
of
the
analysis.
To
allow
for
the
evaluation
in
this
study
of
the
potential
actions
the
power
industry
may
take
to
implement
alternative
pollution
control
requirements
that
fall
at
different
times
over
the
period
examined,
IPM
was
set
to
allow
model
plants
to
undertake
two
retrofits
during
a
model
run.

It
is
important
to
recognize
that
the
power
industry
can
do
more
than
just
add
retrofit
controls
to
lower
their
air
emissions.
It
can
also
switch
fuels
at
units,
replace
older
units
with
new
ones,
change
dispatch
practices,
or
purchase
power
from
nearby
regions.
For
this
study,
IPM
was
set
up
to
allow
the
full
range
of
available
options
for
compliance
with
alternative
pollution
control
levels.

NOx
Controls
 
Cost
analysis
suggests
that
certain
types
of
generation
units
are
more
likely
to
add
pollution
controls
to
lower
NOx
emissions.
Existing
combustion
turbines
and
combined­
cycle
operations
will
be
unlikely
to
add
NOx
controls
due
to
their
relatively
low
levels
of
emissions
and
limited
use.
It
is
assumed
in
this
study
that
new
combined­
cycle
units
are
built
with
selective
catalytic
reduction
(
SCR)
on
them,
which
States
generally
require
for
compliance
with
BACT.
New
combustion
turbines
are
assumed
to
have
low
emission
rates
due
to
boiler
designs
that
do
not
necessitate
further
controls.
Additional
controls
for
generation
units
that
use
renewable
resources
were
not
assumed
to
be
needed.

For
this
report,
its
assumed
that
States
will
require
new
coal­
fired
units
to
have
SCR
to
comply
with
BACT
requirements.
New
oil/
gas
steam
units
are
considered
to
be
uneconomic
for
the
foreseeable
future.
For
existing
coal­
fired
and
oil/
gas
steam
units,
the
costs
and
performance
of
various
types
of
NOx
controls
were
examined
and
where
available
data
suggested
that
these
controls
could
be
employed
cost­
effectively,
they
were
used
in
IPM.
This
led
to
consideration
of
the
following
options
in
the
model:

 
Coal­
Fired
Steam
Electric
Generating
Units
­
Combustion
Controls;
­
Selective
Catalytic
Reduction
(
SCR);
­
Selective
Non­
Catalytic
Reduction
(
SNCR);
and
­
Natural
Gas
Reburn.

 
Oil
and
Gas­
Fired
Steam
Generating
Units
­
Selective
Catalytic
Reduction;
and
­
Selective
Non­
Catalytic
Reduction.
2­
11
The
Agency
is
now
aware
that
vendors
are
beginning
to
offer
hybrid
control
options
(
combining
SCR
with
SNCR,
or
SNCR
with
natural
gas
reburn).
This
could
ultimately
lead
to
a
somewhat
different
set
of
actions
by
the
regulated
community
over
time.
It
is
likely
to
lower
the
compliance
costs
the
regulated
community
faces
over
time
for
the
NOx
SIP
call.

SO2
Controls
 
In
this
analysis,
all
coal­
fired
units
were
allowed
to
lower
sulfur
dioxide
emissions
either
through
the
installation
of
flue
gas
desulfurization
technology
(
scrubbers),
or
the
selection
of
coals
with
lower
sulfur
contents.
The
Agency
looked
at
the
recent
trend
in
scrubber
installation
costs
in
developing
its
cost
functions.

Carbon
Controls
­
There
are
no
economical
post­
combustion
controls
available
for
removing
carbon
dioxide
emissions
at
this
time.
Reductions
in
carbon
emissions
are
possible
through
changes
in
dispatch
to
reduce
the
use
of
higher
emitting
coal­
fired
unit
generation,
or
through
replacement
of
older,
less
efficient
units
(
e.
g.
oil/
gas
steam)
with
newer
more
efficient
ones,
such
as
combined­
cycle
natural
gas.
Lowering
the
carbon
emissions
rates
of
electric
generation
units
using
fossil
fuels
occurs
in
IPM
through
the
repowering
of
units.
Coal­
fired
units
can
repower
to
combined­
cycle
natural
gas
(
with
a
lower
carbon
emissions
rate),
or
to
integrated
gasification
combined­
cycle
(
improving
their
efficiency
in
the
use
of
coal
by
gasifying
it
and
running
it
through
a
combined­
cycle
system).
Gas­
fired
steam
electric
units
can
also
repower
to
combined­
cycle
natural
gas
to
improve
their
efficiency.
EPA
does
not
consider
heat
rate
improvements
by
units
over
time
as
a
compliance
strategy
in
the
options
that
it
analyzed.
The
Agency
does
assume
that
because
of
deregulation
of
the
power
industry
that
heat
rates
will
be
maintained
and
not
degrade
over
time
as
they
have
in
the
past
at
generation
units
that
use
fossil
fuels.

Mercury
Controls
­
EPA
considered
what
type
of
pollution
control
could
be
used
to
lower
mercury
emissions
from
coal­
fired
electric
generation
units
in
the
future.
Although
EPA,
the
Department
of
Energy
(
DOE),
and
the
Electric
Power
Research
Institute
(
EPRI)
have
sponsored
research
in
this
area
in
the
past,
much
more
needs
to
be
done
to
develop
practical
mercury
control
technologies.
Based
on
current
information,
EPA's
Office
of
Research
and
Development
(
ORD)
concluded
that
the
most
likely
control
technologies
to
be
used
in
the
future,
if
the
Agency
makes
a
determination
that
it
should
regulate
mercury
from
coal­
fired
units
are
those
based
on
activated
carbon
injection.
EPA
has
seen
successful
application
of
these
technologies
on
municipal
waste
combustors
and
believes
that
this
experience
is
transferable
to
coal­
fired
units.
A
major
research
program,
however,
is
underway
to
field­
test
these
technologies
and
to
develop
refined
estimates
of
the
costs
and
performance
of
activated
carbon
injection
technologies.
Some
researchers
are
also
devoting
efforts
to
considering
whether
there
are
more
cost­
effective
sorbent
materials
than
activated
carbon.

EPA's
ORD
examined
recent
work
prepared
for
EPA's
Mercury
Report
to
Congress,
and
work
by
EPRI,
DOE,
and
other
sources
and
developed
the
mercury
control
cost
functions
used
in
this
report
for
carbon
injection
technology.
These
mercury
control
costs
and
performance
estimates
are
provided
in
Appendix
C.
The
Agency's
research
office
developed
these
cost
and
performance
functions
to
allow
the
Agency
to
analyze
the
costs
of
a
mercury
control
program
options.
In
considering
the
results
of
this
report,
it
should
be
recognized
that
much
more
work
is
2­
12
required
in
field
testing
activated
carbon
injection
based
technologies
in
coal­
fired
units
and
that
other
technologies
may
emerge
that
are
effective
controlling
mercury
emissions.

The
Agency
recognizes
that
coal
cleaning
holds
some
promise
for
lowering
mercury
levels
in
the
future
from
coal­
fired
units.
Although
EPA
was
able
to
account
for
existing
practices
of
cleaning
coal
in
estimating
future
mercury
emissions
in
the
Base
Case,
it
was
not
able
to
analyze
its
application
in
any
of
the
alternative
pollution
control
programs
considered
in
this
report.

Combination
Controls
­
EPA
also
developed
cost
and
performance
estimates
for
combining
different
types
of
controls
such
as
SCR
or
SNCR
with
coal
plant
scrubbers.
With
these
options,
IPM
can
determine
if
in
some
instances,
it
is
optimal
to
place
a
scrubber
and
SCR
or
SNCR
on
a
unit
to
reduce
SO2
emissions
and
NOx
emissions
from
a
given
plant
simultaneously.
In
determining
the
least
cost
means
for
complying
with
a
pollution
control
option,
the
model
can
choose
from
among
these
pollution
control
technologies
and
change
the
dispatch
of
model
plants.
For
example,
the
model
in
some
cases
can
reduce
the
utilization
of
high
NOx
emitting
units
and
increase
the
utilization
of
low
NOx
emitting
units.

Allowance
Allocations
and
Trading
Most
of
the
pollution
control
options
examined
in
this
study
are
implemented
through
emissions
cap­
and­
trade
programs.
Such
trading
programs
work
by
allocating
allowances
which
permit
the
emission
of
limited
quantities
of
pollution
during
the
specified
periods
(
e.
g.
ozone
season,
or
annually),
permitting
sources
to
choose
how
they
will
comply
with
control
requirements
by
reducing
emissions,
or
purchasing
allowances
from
other
sources.
For
the
analysis
provided
in
this
study,
the
initial
distribution
of
the
allowances
is
not
important;
the
only
relevant
fact
regarding
the
allowances
is
their
total
amount,
which
determines
the
total
number
of
tons
of
air
emissions
reductions
required.

IPM
finds
the
least­
cost
method
for
producing
electric
power
for
the
industry
as
a
whole.
The
model
places
pollution
controls
or
makes
dispatch
changes
to
electric
generating
units
that
lead
to
the
achievement
of
emission
reductions
at
the
lowest
cost.
As
a
result,
some
firms'
power
plants
are
projected
to
be
tightly
controlled,
at
significant
cost,
while
other
firms'
plants
have
no
controls
beyond
those
assumed
in
the
baseline.

Realistically,
this
pattern
would
not
be
seen
unless
a
system
existed
to
give
incentives
to
the
firms
with
the
most
cost­
effective
control
possibilities
to
bear
the
greatest
part
of
the
control
burden.
EPA's
analysis
envisions
that
these
incentives
are
provided
by
an
emissions
trading
system
that
provides
sources
with
the
opportunity
to
buy
and
sell
allowances.
Under
such
a
system,
firms
are
assumed
to
either
buy
or
sell
allowances
depending
on
their
own
costs
of
control
in
comparison
to
the
market
price
of
allowances.
As
the
price
reacts
to
changes
in
demands
and
supplies
of
allowances,
the
market
will
help
ensure
that
the
costs
of
incremental
reductions
of
pollutants
covered
in
trading
programs
are
the
same
for
all
participants.
2­
13
General
Limitations
of
the
Analysis
This
analysis
incorporates
a
fine­
grained
representation
of
the
behavior
of
a
large
number
of
industrial
entities.
It
covers
both
a
long
period
of
time
and
a
wide
geographical
area.
As
with
any
attempt
to
project
the
future
in
detail,
it
is
subject
to
limitations
and
uncertainties.
Several
factors
could
lead
to
cost
and
emissions
impacts
above
or
below
the
reported
impacts.
Those
factors
include
the
following:

 
Speed
of
Deregulation
 
This
report
assumes
that
electric
utility
deregulation
will
continue
to
move
ahead
at
a
steady
pace.
It
also
assumes
that
deregulation
will
affect
the
electricity
market
in
specific
ways
including
lower
cost
of
transmission,
higher
coal
plant
availability,
and
lower
reserve
margins.
Should
deregulation
occur
more
quickly
or
more
slowly
than
assumed,
or
affect
the
electricity
system
in
different
ways,
the
estimated
costs
and
emissions
impacts
for
these
regulatory
options
may
differ.

 
Emissions
Reduction
Costs
and
Performance
 
This
report
uses
forecasted
changes
in
electric
generation
technology,
improvements
in
SO2
controls,
and
movements
in
fuel
prices
over
time.
These
factors
are
major
determinants
of
the
compliance
costs
of
the
control
options
examined
in
this
report.
The
soundness
of
the
forecasts
heavily
influences
the
results
of
this
analysis.
The
compliance
costs
of
mercury
control
options
rely
heavily
on
the
Agency's
assumptions
about
mercury
emissions
and
the
cost
functions
for
controlling
mercury
with
activated
carbon
injection
technologies.
For
each
of
these
areas,
there
is
considerable
uncertainty
and
the
results
of
the
mercury
control
options
analysis
should
be
considered
preliminary.

 
Administrative
Costs
 
No
administrative
costs
are
included
in
this
analysis.
Electric
utilities,
State
and
local
air
quality
regulatory
agencies,
and
EPA
will
incur
administrative
costs
in
addition
to
the
direct
costs
of
complying
with
the
control
options
analyzed
in
this
study.
For
some
electric
generation
units,
these
costs
will
include
monitoring
emissions,
certifying
compliance,
modifying
permits,
and
trading
allowances.
For
States
and
local
governments
and
EPA,
there
will
be
program
development
and
implementation
costs.
Experience
under
the
Title
IV
SO2
Allowance
Trading
program
suggests
that
the
cap­
andtrade
programs
considered
in
this
study
will
not
have
large
administrative
costs.
The
administrative
costs
of
Title
I
MACT
requirements
for
other
industries
are
not
large.

 
Regulatory
Program
Implementation
­
The
alternative
pollution
control
levels
analyzed
in
this
report
are
assumed
to
be
implemented
smoothly
and
at
specific
points
in
time.

 
Data
Limitations
­
EPA
has
constructed
a
database
for
this
analysis
that
consists
of
information
on
virtually
every
boiler
and
generator
in
the
U.
S.
The
Agency
has
assembled
the
best
information
on
each
boiler
and
generator
that
is
publicly
available.
Inevitably,
when
working
with
information
on
such
a
large
number
of
facilities,
some
units
may
not
be
represented
correctly.
Especially
for
the
consideration
of
mercury
emissions,
EPA
had
to
make
many
default
assumptions
regarding
the
configuration
of
existing
pollution
controls,
which
heavily
influences
the
emissions.
Efforts
are
underway
2­
14
to
improve
the
data
available
on
mercury
emissions
from
utility
boilers.
Comments
are
welcome
from
readers
with
knowledge
concerning
specific
units.
Improvements
to
the
database
could
lead
to
changes
in
estimates
of
emissions
and
potential
cost
impacts
for
the
regulatory
options
analyzed.

BASE
CASE
As
mentioned
above,
EPA
considered
implementation
of
the
NOx
SIP
call
and
future
CAAA
Title
IV
requirements
in
setting
up
the
Base
Case
for
this
study.
The
NOx
SIP
call
covers
the
States
shown
in
Exhibit
2­
3.
For
all
other
States,
EPA
has
assumed
implementation
of
the
NSPS,
BACT/
LAER,
and
RACT
under
Title
I
of
the
CAAA,
Title
IV
controls
on
coal­
fired
units
and
known
future
State
NOx
controls.
In
regards
to
the
NOx
SIP
call,
the
Agency
has
assumed
that
the
States
will
participate
in
the
cap­
and­
trade
program
that
EPA
recommended
in
the
rule
and
analyzed
in
its
Regulatory
Impact
Analysis
to
support
the
rule.

Electric
Generation
The
Base
Case
forecast
presented
in
this
study
covers
years
2005
to
2010.
Exhibit
2­
4
shows
the
electric
generation
capacity
that
EPA
forecasts
will
operate
during
this
time
period.
The
forecast
shows
a
small
decline
in
coal­
fired
generation
capacity
over
time.
Gas­
fired
generation
capacity
increases
to
meet
future
electric
demand
growth.
Nuclear
generation
capacity
declines,
as
some
units
become
noneconomic
to
operate.
Other
capacity,
which
is
primarily
hydroelectric
and
other
electric
generation
units
using
renewable
resources,
does
not
change
much
in
the
time
period
analyzed.
2­
15
Exhibit
2­
3
States
Included
in
EPA's
NOx
SIP
Call
WI
IL
IN
MI
PA
NJ
DE
CT
DC
NY
MO
OH
WV
KY
VA
MD
NC
SC
TN
GA
AL
MA
RI
NH
Ozone
Transport
Region
States
in
the
NOx
SIP
Call
Other
States
in
the
NOx
SIP
Call
2­
16
Exhibit
2­
4
Future
Electric
Generation
Capacity
Under
the
Base
Case
(
GW)

Fuel
Type
2005
2007
2010
Coal
305
305
304
Oil/
Natural
Gas
240
250
282
Nuclear
87
86
81
Other*
138
138
138
Total
770
779
805
*
Includes
hydroelectric,
municipal
waste
combustors,
and
other
renewables,
pump
storage,
and
import
capability
from
Mexico
and
Canada.

Exhibit
2­
5
shows
the
electric
generation
forecast
that
EPA
is
using
for
this
period.
Coalfired
generation
will
provide
most
of
the
country's
power
from
2005
and
2010.
The
greatest
growth
in
electric
generation
occurs
for
units
that
use
oil
or
natural
gas.
The
exhibit
shows
a
decline
in
the
amount
and
share
of
power
produced
by
nuclear
units
by
2010.

Exhibit
2­
5
Future
Electric
Generation
under
the
Base
Case
(
Billion
kWh)

Fuel
Type
2005
2007
2010
Coal
2,084
2,091
2,114
Oil/
Natural
Gas
561
626
759
Nuclear
609
613
580
Other*
380
383
377
Total
3,634
3,713
3,831
*
Includes
hydroelectric,
municipal
waste
combustors,
and
other
renewables,
pump
storage,
and
import
capability
from
Mexico
and
Canada.

Greater
details
on
EPA's
generation
capacity
and
electric
generation
forecast
can
be
found
in
Appendix
D.
The
appendix
shows
the
amount
of
coal­
fired
and
oil­
gas
steam
capacity
that
is
retrofitted
with
post
combustion
controls
due
to
the
NOx
SIP
call
and
the
changes
over
time
in
the
repowering
of
oil/
gas
steam
units
to
combined­
cycle
natural
gas
units.
2­
17
Air
Emissions
Exhibit
2­
6
provides
a
national
forecast
of
the
Base
Case
for
NOx,
SO2,
mercury,
and
carbon
emissions.
5
The
chart
shows
NOx
and
SO2
emissions
dropping
over
time
as
a
result
of
CAAA
programs
that
go
into
effect
after
2000
and
the
greater
use
of
natural
gas
that
is
expected
by
2010.
Unregulated
mercury
emissions
drop
a
small
amount
over
time
due
to
some
shifting
towards
western
coals
that
are
assumed
to
have
generally
lower
mercury
concentrations
(
see
Exhibit
2­
11
below).
Unregulated
carbon
emissions
rise
as
a
greater
amount
of
electric
generation
over
time
is
produced
by
fossil
fuels
and
nuclear
use
declines.

The
Exhibits
2­
7,
2­
8,
and
2­
9
show
the
regional
breakout
of
these
air
emissions
and
electric
generation
(
Exhibit
2­
1
shows
the
location
of
each
NERC
region
in
the
exhibits).
The
air
emissions
are
regionally
highest
in
the
areas
that
rely
most
heavily
on
coal­
fired
generation.

Exhibit
2­
6
Future
Air
Emissions
under
the
Base
Case
For
the
Electric
Power
Industry
for
Selected
Air
Pollutants
Pollutant
Units
2005
2007
2010
Summer
Nitrogen
Oxides
(
NOx)
Thousand
short
tons
1,436
1,449
1,386
Annual
Nitrogen
Oxides
(
NOx)
Thousand
short
tons
4,221
4,255
4,147
Annual
Sulfur
Dioxides
(
SO2)
Thousand
short
tons
11,049
10,864
9,658
Annual
Mercury
Short
tons
51.9
52.0
50.9
Annual
Carbon
Million
Metric
tons
605
615
621
Exhibit
2­
10
considers
in
greater
depth
the
sources
of
mercury
emissions.
6
The
vast
majority
of
mercury
emissions
come
from
coal­
fired
generation.
The
next
largest
category
of
mercury
emissions
is
generation
units
that
use
renewable
energy
sources.
Sources
of
mercury
emissions
in
this
category
include
municipal
waste
combustors
(
MWCs),
geothermal
units,
and
units
that
use
coal
biproducts.
As
mentioned
earlier,
this
forecast
already
considers
the
effects
of
required
controls
on
MWCs.

5
EPA
is
reporting
carbon
emissions
rather
than
carbon
dioxide
emissions.
To
make
the
conversion
to
CO2
emissions,
the
carbon
results
needed
to
be
multiplied
by
3.67.
6
EPA
considered
whether
implementation
of
the
NOx
SIP
call
lead
to
changes
in
mercury
emissions
from
the
electric
power
industry
from
its
initial
base
case
prior
to
promulgation
of
this
rule.
The
Agency
found
that
the
NOx
SIP
call
did
not
produce
changes
in
mercury
emissions
in
any
significant
way.
The
rule
is
likely
to
produce
a
relatively
modest
shift
towards
greater
natural
gas
generation.
The
Agency
also
has
not
found
technical
data
or
reports
that
the
Agency
believes
show
that
NOx
controls
in
themselves
remove
mercury
from
boiler
flue
gases.
2­
18
Exhibit
2­
7
Regional
Electric
Generation
and
Air
Emissions
for
2005
For
the
Base
Case
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
37
85
27
92
276
1.1
16
ECAO
222
531
165
809
3,029
8.4
118
ERCT
126
261
154
323
565
4.7
45
MACE
46
100
17
57
138
1.4
9
MACW
43
102
28
122
553
2.9
17
MACS
22
53
14
63
211
1.0
8
WUMS
24
57
19
65
195
1.0
12
MANO
85
195
52
225
910
4.4
37
MAPP
74
165
154
354
613
3.8
38
UPNY
58
132
22
63
196
1.2
11
LILC
3
6
2
3
0
0.3
1
NENG
44
104
22
61
191
1.5
12
FRCC
89
180
121
243
319
2.1
28
VACA
127
293
70
271
947
3.6
42
TVA
65
151
45
194
596
2.2
26
SOU
104
235
88
277
1,174
3.9
42
SPPN
39
88
55
155
178
1.4
20
SPPS
113
226
151
305
484
2.7
41
CNV
109
249
32
76
50
1.2
22
WSCP
71
168
19
45
124
0.4
7
WSCR
109
252
178
418
301
2.7
51
TOTAL
1,610
3,634
1,436
4,221
11,049
51.9
605
2­
19
Exhibit
2­
8
Regional
Electric
Generation
and
Air
Emissions
for
2007
For
the
Base
Case
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
38
87
26
91
272
1.1
16
ECAO
223
533
166
811
2,966
8.4
118
ERCT
129
269
158
333
565
4.7
47
MACE
46
97
19
60
144
1.4
10
MACW
43
104
29
125
569
2.9
18
MACS
23
56
14
65
213
1.1
9
WUMS
25
58
18
64
191
1.0
12
MANO
88
205
51
222
861
4.4
37
MAPP
75
166
155
352
594
3.7
39
UPNY
59
135
22
62
188
1.1
11
LILC
3
6
2
3
0
0.3
1
NENG
44
105
22
62
191
1.5
12
FRCC
95
189
122
242
315
2.0
29
VACA
132
306
71
277
968
3.7
44
TVA
66
153
45
197
567
2.3
26
SOU
103
237
87
279
1,125
4.0
42
SPPN
40
90
56
156
179
1.4
20
SPPS
119
232
156
307
484
2.7
42
CNV
113
261
33
80
50
1.2
24
WSCP
71
168
19
45
124
0.4
7
WSCR
110
255
179
420
297
2.7
52
TOTAL
1,645
3,713
1,449
4,255
10,864
52.0
615
2­
20
Exhibit
2­
9
Regional
Electric
Generation
and
Air
Emissions
for
2010
For
the
Base
Case
Billion
kWh
NOx
(
1,000
tons)
SO2
(
1,000
tons)
Mercury
(
tons)
Carbon
(
MMT)

NERC
Region
Summer
Annual
Summer
Annual
Annual
Annual
Annual
MECS
40
92
27
92
277
1.1
17
ECAO
228
544
177
842
2,510
8.4
123
ERCT
136
283
125
260
330
4.3
45
MACE
50
101
17
55
124
1.2
10
MACW
41
98
29
125
461
2.5
18
MACS
25
63
14
66
211
1.1
9
WUMS
26
59
19
65
192
1.0
13
MANO
88
206
52
226
706
4.5
38
MAPP
77
172
152
350
590
3.7
39
UPNY
53
120
17
49
188
1.1
9
LILC
6
14
1
3
0
0.3
1
NENG
49
118
16
44
133
1.5
12
FRCC
98
198
118
239
317
2.0
30
VACA
137
321
71
285
962
3.7
46
TVA
68
158
44
197
451
2.2
27
SOU
109
244
86
282
1,081
4.0
43
SPPN
43
95
56
160
185
1.4
21
SPPS
121
239
142
281
475
2.7
41
CNV
121
274
31
73
50
1.2
21
WSCP
76
181
17
39
124
0.4
8
WSCR
108
249
177
416
293
2.7
51
TOTAL
1,699
3,831
1,386
4,147
9,658
50.9
621
2­
21
Exhibit
2­
10
Future
Mercury
Air
Emissions
under
the
Base
Case
For
the
Electric
Power
Industry
by
Electric
Generation
Source
(
Tons)
Fuel
Type
2005
2007
2010
Coal
47.9
48.0
46.9
Oil/
Gas
Steam
0.03
0.03
0.00
Renewables
4.0
4.0
4.0
Total
51.9
52.0
50.9
Fossil
Fuel
Choices
Examining
the
fossil
fuel
requirements
of
the
electric
power
industry
over
time
provides
some
interesting
insights
into
how
the
industry
will
operate.
Exhibit
2­
12
shows
IPM's
forecast
of
future
coal
consumption
to
meet
forecasted
electric
demand
from
2005
to
2010
(
see
Exhibit
2­
11
for
geographic
coverage
of
each
coal
supply
region).
Although
total
consumption
grows,
the
rate
of
growth
varies
among
major
supply
regions.
The
greatest
rate
of
growth
is
for
western
coal
that
has
a
low
sulfur
content
and
is
increasingly
cheaper
to
mine
and
ship
over
time.
There
is
a
forecasted
decline
in
consumption
from
Northern
Appalachia
and
the
Midwest.

Exhibit
2­
13
shows
the
changes
in
natural
gas
and
oil
use
over
time.
IPM
shows
a
significant
increase
in
natural
gas
consumption
for
electric
power
generation.
This
occurs
because
a
large
amount
of
future
electric
demand
growth
will
be
met
by
combined­
cycle
generation
units
that
use
natural
gas.
This
technology
is
more
energy
efficient
than
coal­
fired
generation
and
oil/
gas
steam
generation.
Combined­
cycle
natural
gas
units
provide
no
emissions
of
SO2,
trace
amounts
of
mercury,
limited
amounts
of
NOx,
and
about
two­
thirds
of
the
carbon
emissions
of
coal
for
every
Btu
consumed.
The
model
forecasts
that
electric
generation
units
will
no
longer
use
oil
after
2005.
2­
22
Exhibit
2­
11
Coal
Region
Map
West
ND
ME
MW
MP
WP
WG
CG
UC
US
CU
CD
NR
CR
NS
AZ
IA
MO
KS
OK
AN
AS
TX
LA
AS
AL
TN
IL
IN
KW
KE
OH
PC
PW
WN
WS
VA
WA
CS
Western
Northern
Great
Plains
Eastern
Northern
Great
Plains
Northwest
Rockies
Central
West
Gulf
Mid­
West
Northern
Appalachia
Southern
Appalachia
Central
Appalachia
Southwest
MD
2­
23
Exhibit
2­
12
Future
Coal
Consumption
under
the
Base
Case
For
the
Electric
Power
Industry
(
Million
tons)
Coal
Supply
Areas
2005
2007
2010
Northern
Appalachia
138
138
109
Central
and
Southern
Appalachia
185
186
213
Midwest
125
120
109
West
503
511
540
Central
West
and
Gulf
64
64
63
Total
1,015
1,019
1,034
Exhibit
2­
13
Future
Natural
Gas
and
Oil
Consumption
under
the
Base
Case
For
the
Electric
Power
Industry
Fuel
Units
2005
2007
2010
Natural
Gas
Trillion
cubic
feet
4.6
5.2
5.3
Oil
Million
Barrels
21.3
21.5
0