Note
to:
Files
From:
Doug
Carter,
DOE/
FE­
26
Subject:
Analysis
of
NSR
rule
impacts
Date:
August
21,
2003
Introduction
Both
EPA
and
DOE/
EIA
have
modeled
potential
impacts
of
allowing
efficiency
upgrades
on
coal­
fired
power
plants,
and
results
of
these
simulations
were
included
in
the
draft
Regulatory
Impact
Analysis
(
RIA)
published
by
EPA.
The
major
differences
in
the
two
analyses
were
that
they
used
different
simulation
models
(
NEMS
vs
IPM),
and
they
evaluated
somewhat
different
assumptions
for
how
the
change
at
the
power
plant
might
manifest
in
operation
(
i.
e.,
assumptions
on
efficiency,
capacity,
and
availability
changes).
After
additional
consideration,
DOE
conducted
further
analysis,
using
assumptions
differing
from
both
of
the
earlier
analyses.

Discussion
A
change
in
the
definition
of
"
routine
maintenance,
repair,
and
replacement"
(
RMRR)
would
likely
remove
a
barrier
to
improvements
in
power
plant
efficiency
(
or
heat
rate),
which
is
generally
perceived
as
a
positive
outcome,
with
probable
emission
reduction
implications.
Such
changes
could
also
affect
availability,
if
companies
repair
or
replace
components
which
are
likely
sources
of
future
breakdowns,
and
capacity,
if
repairs
enable
a
unit
to
increase
its
electrical
output
with
or
without
an
increase
in
fuel
consumption.
Increases
in
availability
and
capacity
would
likely
lead
to
an
emissions
increase,
if
applied
uniformly
across
all
coal
units.
Hence,
from
an
emissions
perspective,
there
is
a
tension
between
pure
efficiency
improvements,
and
availability
or
capacity
improvements.

Availability
changes
are
perhaps
the
easiest
to
consider
with
historic
data.
A
substantial
body
of
data
accumulated
by
the
North
American
Electric
Reliability
Council
(
NERC)
shows
that,
over
the
past
two
decades,
reliability
at
coal­
fired
power
plants
has
improved,
but
at
a
declining
rate
in
recent
years.
The
data
in
Figure
1
suggest
that
future
improvements
in
availability
will
be
modest
compared
to
improvements
in
the
1980'
s,
for
example.
A
cumulative
future
improvement
of
1%
seems
like
a
most
likely
scenario,
but
an
improvement
of
2%
may
be
possible.
These
two
values
are
evaluated
in
this
analysis.

Possible
efficiency
improvements
were
discussed
in
the
draft
RIA.
They
apply
almost
equally
to
the
"
boiler
side"
of
the
power
plant
and
the
"
turbine
side".
Improvements
of
up
to
15%
seem
feasible
with
known
or
emerging
technologies.
Earlier
modeling
by
DOE
evaluated
rates
of
5%,
10%,
and
15%.
Because
improvements
of
15%
were
essentially
extensions
of
the
trends
established
by
the
lower
efficiency
improvement
assumptions,
this
analysis
focuses
on
improvements
of
5%
and
10%.
A
greater
efficiency
improvement
is
still
deemed
reasonable,
given
the
ongoing
voluntary
programs
to
minimize
carbon
dioxide
emissions
as
well
as
the
potential
for
fuel
savings
and
lower
overall
operational
costs,
but
the
emission
implications
of
such
efficiency
improvements
can
be
inferred
from
simulations
of
efficiency
improvements
of
5%
and
10%.

The
significant
change
in
this
set
of
simulations
by
DOE,
compared
to
DOE's
earlier
analysis,
is
the
inclusion
of
an
assumed
improvement
in
capacity,
where
efficiency
is
improved.
(
EPA's
simulations,
included
in
the
draft
RIA,
incorporated
capacity
increases,
but
DOE's
did
not.)
DOE
discussed
this
issue
with
knowledgeable
individuals
involved
in
power
generation1
and
reached
the
following
conclusions:

 
Most
older
power
plants
in
the
U.
S.
were
designed
with
excess
capacity
in
the
turbine
unit,
compared
to
the
boiler
systems.
Newer
plants
in
the
U.
S.
are
designed
in
a
more
balanced
manner.
Typical
steam
turbines
in
the
1960'
s,
for
example,
would
have
the
ability
to
generate
about
10%
more
electricity
than
the
boiler
could
support
with
steam
production,
if
the
turbine
were
in
optimum
condition.

 
Many
existing
boilers
operate
outside
their
original
design
specifications,
due
to
use
of
lower
sulfur
coal,
application
of
low­
NOx
burners,
or
other
changes
which
have
left
the
boilers
with
insufficient
auxiliary
equipment,
such
as
pulverizers,
to
maintain
original
design
steam
production.
Such
changes
at
power
plants
have
impacted
the
boiler­
side
of
the
power
plant
more
than
the
steam
turbine­
side.

 
Steam
turbines
tend
to
degrade
gradually
over
time.
In
terms
of
efficiency
and
capacity,
the
most
important
changes
appear
to
be
increased
steam
leakage
through
seals
(
thereby
avoiding
rotating
turbine
blades),
and
blade
erosion,
which
can
change
the
angle
of
impact
of
steam
on
blades
and
reduce
the
force
imparted
by
the
steam
on
the
blades.
In
terms
of
reliability,
turbine
blades
can
suffer
from
corrosion
and
metal
fatigue,
both
of
which
can
lead
to
blade
breakage,
which
can
lead
to
serious
injury
and
equipment
damage.

The
capacity
of
a
given
boiler
relative
to
its
associated
steam
turbine
is
a
site­
specific
relationship,
and
probably
varies
over
time.
However,
it
is
clear
that
if
a
boiler's
capacity
is
either
greater
than
or
equal
to
that
of
its
associated
steam
turbine,
any
capacity
increases
in
the
boiler
(
which
might
accompany
a
boiler
efficiency
improvement)
cannot
be
exploited
unless
the
turbine
increases
in
capacity
as
well.
This
phenomenon
suggests
that
overall
capacity
improvements
resulting
from
equipment
replacement
will
be
somewhat
smaller
than
overall
efficiency
improvements.
At
this
point,
there
is
insufficient
information
to
determine
the
exact
difference.
Earlier
simulations
by
DOE
assumed
no
improvement
in
capacity
from
efficiency
improvements,
and
earlier
EPA
scenarios
assumed
capacity
improvements
equaled
efficiency
improvements.
The
simulations
which
are
described
in
the
current
analysis
make
an
assumption
in
between
the
earlier
analyses:
that
capacity
improvements
will
equal
one­
half
the
assumed
efficiency
improvement.

1
Telecommunication
between
D.
Carter,
DOE,
and
R.
Moates,
TVA,
July
29,
2003.
Telecommunication
between
D.
Smith,
DOE,
and
J.
Murphy,
SAIC,
July
29,
2003.
Scenario
Matrix
Table
1
identifies
assumptions
used
in
the
current
computer
analysis.
Assessments
of
efficiency
improvements
of
15%
are
not
necessary
because
these
results
can
be
inferred
from
the
5%
and
10%
simulations,
and
earlier
runs.

Table
1.
Simulation
Run
Heat
Rate
&
Capacity
Increase
Availability
Increase
Base
0
0
S5.1
5%
&
2.5%
1%
S5.2
5%
&
2.5%
2%
S10.1
10%
&
5%
1%
S10.2
10%
&
5%
2%

Figure
1
Coal
Unit
Availability
(
NERC)

70
75
80
85
90
95
100
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Availability
Factor
0.5
%/
year
change
0.5
%/
year
change
0.3
%/
year
change
0.1
%/
year
change
R
esults
The
revised
assumptions
led
to
modest
changes
from
the
projected
emission
baselines.
Figures
2
and
3
show
the
projections
for
emissions
of
nitrogen
oxides
(
NOx)
and
sulfur
dioxide
(
SO2).
The
efficiency,
capacity,
and
availability
improvements
for
each
simulation
are
indicated
in
the
legends
on
the
figures.
For
example,
"
NOx
5­
2.5­
1"
is
a
scenario
for
NOx
emissions
in
which
efficiency
increases
5%,
capacity
increases
2.5%,
and
availability
increases
by
1%.
For
SO2,
it
was
surprising
that
emissions
changed
at
all,
given
the
national
limit,
or
"
cap",
on
power
plant
SO2.
The
small
projected
changes
are
due
to
possible
"
banking"
behavior,
in
which
source
owners
control
more
in
some
years
and
less
in
others
to
minimize
anticipated
control
costs.
Over
time,
all
of
these
scenarios
net
out
to
the
same
cumulative
SO2
emission
reductions.
For
the
scenarios
simulated,
NOx
emissions
are
generally
less
than
baseline
emissions,
although
the
reduction
is
quite
minor
for
the
simulations
assuming
only
5%
improvements
in
efficiency,
and
in
four
of
the
years
projected,
national
emissions
are
slightly
above
baseline
for
one
scenario.
Table
2
presents
NOx
results
for
selected
years.

Figure
4
shows
projected
emissions
of
mercury
under
all
of
the
scenarios
modeled.
Emissions
under
a
more
flexible
NSR
policy
are
consistently
lower
than
baseline
emissions,
with
the
exception
of
certain
years
in
the
case
for
5%
efficiency,
2.5%
capacity,
and
2%
availability
improvement.

In
general,
for
the
scenarios
including
10%
improvements
in
heat
rates,
non­
capped
pollutant
emissions
were
reduced
by
about
2­
5%,
relative
to
the
base
case
(
current
NSR
policy).
For
scenarios
including
5%
improvements
in
heat
rates,
non­
capped
emissions
were
reduced
by
0.5
 
2%.
For
the
lesser
set
of
efficiency
improvement
simulations,
there
were
certain
combinations
of
assumptions
which
led
to
small
emission
increases
in
specific
years.

Table
2.
NOx
emission
changes
for
each
scenario.
Scenario
Assumed
%
change
in
NOx
Emissions,
million
tons
per
year
Heat
Rate
Capacity
Availability
2005
2010
2015
2020
2025
Baseline
0
0
0
3.60
3.93
3.98
4.05
4.11
S
5.2.1
­
5
2.5
1
3.59
3.88
3.93
4.01
4.08
S
5.2.2
­
5
2.5
2
3.60
3.90
3.98
4.05
4.12
S
10.5.1
­
10
5
1
3.55
3.75
3.83
3.91
3.97
S
10.5.2
­
10
5
2
3.56
3.78
3.87
3.95
4.02
Overall
cost
savings
can
be
estimated
by
making
a
conservative
estimate
that
the
cost
of
improvements
total
$
100
per
kilowatt
of
capacity
(
this
is
substantially
greater
than
preliminary
estimates
developed
by
DOE).
Cumulative
projected
savings,
assuming
this
level
of
investment
in
replaced
components,
are
presented
in
Figure
7.
These
totals
range
from
about
$
10
billion
to
$
100
billion
through
the
year
2025,
considering
only
the
change
in
electricity
prices.
Secondary
benefits,
not
quantified,
would
likely
evolve
from
reduced
consumption
of
natural
gas.
In
the
scenarios
simulated,
natural
gas
use
for
power
production
typically
declined
by
5
­
14%.
Such
a
reduction
would
reduce
the
price
of
natural
gas
in
all
sectors,
leading
to
additional
consumer
savings.
Figure
2
Power
Plant
Changes
&
Emissions
­
2
4
6
8
10
12
2002
2003
2004
2
005
2006
2007
200
8
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Emissions,
Million
tpy
NOx
Baseline
SO2
Baseline
NOx
5­
2.5­
1
SO2
5­
2.5­
1
NOx
5­
2.5­
2
SO2
5­
2.5­
2
Figure
3
Power
Plant
Changes
&
Emissions
­
2
4
6
8
10
12
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
20
21
2022
2023
2024
2025
Emissions,
Million
tpy
NOx
Baseline
SO2
Baseline
NOx
10­
5­
1
SO2
10­
5­
1
NOx
10­
5­
2
SO2
10­
5­
2
Figure
4
Power
Plant
Changes
and
Mercury
47
48
49
50
51
52
53
54
55
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Emissions,
tpy
Baseline
Mercury
Mercury
10­
5­
1
Mercury
10­
5­
2
Mercury
5­
2.5­
1
Mercury
5­
2.5­
2
Figure
5
Potential
Cost
Savings
From
NSR
Assuming
$
100/
kw
of
Replacements
(
20)
­
20
40
60
80
100
120
2004
Cumulative
Savings,
Billion
$
Scen
5
/
2.5
/
1
Scen
5
/
2.5
/
2
Scen
10
/
5
/
1
Scen
10
/
5
/
2
Related
Considerations
The
projections
in
this
analysis
do
not
include
consideration
of:
 
Heat
rate
(
efficiency)
improvements
exceeding
10%
 
Improvements
occurring
to
a
subset
of
coal
units,
such
as
units
above
a
certain
size
or
less
than
a
certain
age
 
Potential
improvements
to
similar
technologies
not
burning
coal
In
general,
all
of
these
considerations
would
tend
to
change
the
extent
of
predicted
changes,
but
not
the
direction.
Additionally,
although
heat
rate
improvements
as
low
as
5%,
and
availability
improvements
as
high
as
2%
are
deemed
possible
scenarios,
this
combination
of
assumptions
is
considered
less
likely
than
other
combinations
examined.

Conclusions
Future
emissions
from
power
plants,
aggregated
at
a
national
level,
are
projected
to
decrease
under
the
range
of
scenarios
examined
in
this
analysis,
which
are
predicated
on
an
NSR
policy
that
encourages
equipment
replacement
leading
to
higher
efficiency.
With
minimal
(
5%)
improvements
in
efficiency,
emissions
decrease
0­
1%.
With
efficiency
improvements
of
10%,
emissions
decrease
2­
5%.
In
addition
to
reductions
in
emissions,
substantial
savings
in
the
cost
of
electricity
are
possible
through
these
improvements,
totaling
between
$
10
billion
and
$
100
billion
(
in
2001
dollars)
by
the
year
2025.
