Multi­
Emission
Control
Incremental
Cost
Assessment
October
2004
Michael
G.
Cashin,
P.
E.

Minnesota
Power
(
ALLETE)

Contact:
218­
722­
5642
ext.
3339
mcashin@
mnpower.
com
P
o
u
n
d
s
S
O
2
p
e
r
M
e
g
a
w
a
t
t
H
o
u
r
To
ns
S
O
2
per
y
ear
5
1
0
0
T
o
n
s
S
O
2
R
e
d
u
c
e
d
3
2
0
0
T
o
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s
S
O
2
R
e
d
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c
e
d
2
6
0
0
T
o
n
s
S
O
2
R
e
d
u
c
e
d
8
5
0
T
o
n
s
S
O
2
R
e
d
u
c
e
d
7
6
5
T
o
n
s
S
O
2
R
e
d
u
c
e
d
8
5
T
o
n
s
S
O
2
R
e
d
u
c
e
d
1
4
,
2
0
0
T
o
n
s
S
O
2
R
e
d
u
c
e
d
Diminishing
Returns
from
SO2
Emission
Control
Measures
2%
Sulfur
Bituminous
0.6%
Sulfur
Subbituminous
0.35%
Sulfur
Subbituminous
Low
Sulfur
Coal
+
Wet
Scrubbed
New
Units
Controls
Wide
Disparities
Exist
Between
Company
Average
Emission
Rates
Equitable
allocation
should
assure
low
emitters
are
not
allowance
short
or
technology
forced
Mix,
higher
sulfur
coal
or
no
scrubbers
ALLETE
(
Minnesota
Power)

(
80+
%
scrubbed,
low
sulfur
coal)

Reference:
Benchmarking
Air
Emissions
of
the
100
Largest
Electric
Generation
Owners
in
the
U.
S.
­­
2000
March
2002,
NRDC,
PSEG,
CERES
Diminishing
Returns
from
NOx
Emission
Control
Measures
Uncontrolled
NOx
Low
NOx
Burner
Operation
8.5
New
Units
Controls
Regional
Source
Emissions
under
Clear
Skies
CSA
2020
Modeled
Emission
Reductions
in
Minnesota:

°
14%
reduction
in
SO2
emissions
°
70%
reduction
in
NOx
emissions
°
3%
reduction
in
mercury
emissions
EPA
assesses
CSA
emission
reductions
in
Minnesota
based
on
control
retrofit
costs
vs.
projected
price
to
buy
allowances
from
other
states.

The
best
modeled
MN
economic
for
SO2
and
mercury
is
to
help
pay
for
controls
in
high
emissions
states
through
allowance
purchases.

(
Ref.
USEPA)
Incremental
Cost
Differences:
300
MW
Unit
Examples
SO
2
EPA
estimated
allowance,
marginal
cost:
$
625
to
$
1050
per
ton
2%
Sulfur
Bituminous
(
no
scrubber)
to
Flue
Gas
Desulfurization
$
630
per
ton
0.35%
Sulfur
Subbituminous
Wet
Scrubber
to
Dry
Sorbent
Injection
(
Scrubber)

$
4500
per
ton
NO
x
EPA
estimated
allowance,
marginal
cost,
Clear
Skies
Act
Zone
2:
$
870
per
ton
Zone
1:
$
1150
to
$
1425
per
ton
Low
NO
x
Burner
Technology
to
Neural
Network
Combustion
Optimization
$
400
per
ton
Low
NO
x
Burner
Technology
to
Selective
Catalytic
Reduction
$
2600
per
ton
Neural
Network
Optimization
to
Selective
Catalytic
Reduction
$
6600
per
ton
Hg
EPA
estimated
allowance,
marginal
cost:
$
35,000
per
pound
Dry
scrubber
for
SO
2
to
Sorbent
Injection
plus
Fabric
Filter
$
63,000
per
pound
Wet
scrubber
for
SO
2
to
Dry
Scrubber
for
SO
2,
Sorbent
Injection,
Fabric
Filter
Add
SO
2
scrubber
premium
to
mercury
cost
($
174,000
per
pound
Hg
removed)

M.
Cashin
October
2004
Wet
Scrubber
Capital
Costs
Wet
Scrubber
Capital
Costs
0
100
200
300
400
500
600
700
800
0
200
400
600
Unit
Size,
MW
Capital
Cost,

$/

kw
Wet
Scrubber
Capital
Costs
Wet
Scrubber
O&
M
Costs
(
1%
S
Coal)

0
2
4
6
8
10
0
20
40
60
80
100
Capacity
Factor
(%)

O&

M
Costs
($/

MWHR)
25
MW
60
MW
200
MW
500
MW
Wet
Scrubber
O&
M
Costs
Beck
EUEC
2004
Spray
Dryer
Absorber
Capital
Costs
Spray
Dryer
Absorber
Capital
Costs
0
100
200
300
400
500
600
700
0
200
400
600
Unit
Size,
MW
Capital
Cost,

$/

kw
SDA
Capital
Cost
Spray
Dryer
Absorber
O&
M
Costs
0
2
4
6
8
10
0
20
40
60
80
100
Capacity
Factor
(%)

O&

M
Costs
($/

kw)
25
MW
60
MW
200
MW
500
MW
Spray
Dryer
Absorber
O&
M
Costs
Beck
EUEC
2004
SCR
Capital
Costs
SCR
Capital
Costs
0
50
100
150
200
250
300
350
400
0
200
400
600
Unit
Size,
MW
Capital
Cost,

$/

kw
SCR
Capital
Cost
SCR
O&
M
Costs
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
Capacity
Factor
(%)

O&

M
Costs
($/

MWhr)
25
MW
60
MW
200
MW
500
MW
SCR
O&
M
Costs
Beck
EUEC
2004
Mercury
Control
°
Cobenefits
resulting
from
control
of
SO
2
and/
or
PM
°
Sorbent
Injection
(
activated
carbon)

°
Sorbent
injection
systems
cost
in
the
vicinity
of
$
1.5
 
3.0
million
°
A
bag
house
may
be
required
in
addition
to
the
sorbent
injection
system
Baghouse
Capital
Costs
0
50
100
150
200
250
300
350
400
0
200
400
600
Unit
Size,
MW
Capital
Cost,

$/

kw
Baghouse
Capital
Cost
Clear
Skies
Act,

USEPA
Estimated
Marginal
Control
Costs:
SO2,
NOx
and
Mercury
Reference,
Natural
Gas
and
Oil
Outlook:
Robust
Pricing
to
Continue.
September
2003
Jeff
Mobley,
CFA
and
Wayne
Andrews,
Raymond
James
and
Associates,
Inc.

Natural
Gas
Price
Premium
vs.
Coal
Leaves
a
Margin
Favoring
Coal
That
Can
Offset
Emission
Control
Retrofit
Costs
or
the
New
Coal
Capital
Cost
Premium
Coal
Cost
Eq.

Current
Gas
Gas
Premium
M.
Cashin
September
2004
2000
Capacity
Factor,
Percent
for
Resource
Type
Ref
Department
of
Energy,
Annual
Energy
Outlook
National
Average
Utilization
of
a
Generating
Unit
by
Fuel
Type
is
in
Proportion
to
Fuel
Cost
and
Quantity
The
natural
gas
price
premium
compared
to
coal
gets
reflected
in
coal's
favored
utilization.

Limited
hydro
water
reserves
constrain
use.
Capital
Cost
Premium,

$
per
kW
65%
Capacity
Factor,
Equivalent
$
per
mmBtu
65%
Capacity
Factor,
Equivalent
$
per
MWH
40%
Capacity
Factor,
Equivalent
$
per
mmBtu
40%
Capacity
Factor,
Equivalent
$
per
MWH
15%
Capacity
Factor,
Equivalent
$
per
mmBtu
15%
Capacity
Factor,
Equivalent
$
per
MWH
$
100
per
kW
$
0.42
$
3.11/
MWH
$
0.68
$
5.03/
MWH
$
1.81
$
13.39/
MWH
$
200
per
kW
$
0.84
$
6.22
$
1.36
$
10.06
$
3.62
$
26.78
$
300
per
kW
$
1.26
$
9.33
$
2.04
$
15.09
$
5.43
$
40.74
$
400
per
kW
$
1.68
$
12.44
$
2.72
$
20.12
$
7.24
$
53.56
$
500
per
kW
$
2.10
$
15.55
$
3.40
$
25.15
$
9.05
$
66.95
$
600
per
kW
$
2.52
$
18.66
$
4.08
$
30.18
$
10.86
$
80.34
$
700
per
kW
$
2.94
$
21.77
$
4.76
$
35.21
$
12.67
$
93.73
$
800
per
kW
$
3.36
$
24.88
$
5.44
$
40.24
$
14.48
$
107.12
$
900
per
kW
$
3.78
$
27.99
$
6.12
$
45.27
$
16.29
$
120.51
Comparison,
Capital
Cost
Premium
vs.
Fuel
Cost
Differential
Basis:
Comparison
presumes
cycle
efficiency
from
a
natural
gas,
combined
cycle
unit
(
7.4
MBtu/
MWH)
and
a
15
year
LARR
of
17.6%
(
no
personal
property
tax)

Example:
A
base
load
duty
cycle
unit
(
65%
CF)
can
incur
a
$
500
per
kW
capital
cost
premium
if
the
expenditure
avoids
a
$
2.10/
mmBtu
fuel
cost
premium
M.
Cashin
September
2004
0
20
40
60
80
100
%
Nuclear
and
Renewables
100
80
60
40
20
0
%
COAL
100
80
60
40
20
0
%

GAS
&

OIL
"
More
Coal"

"
More
Gas
&
Oil"
"
More
Renewables
&

Nuclear"

Generation
(
Fuel)
Mix
Changes
for
CO2
Contingency
Planning
Add
a
Cost
Premium
to
Existing
Supply
e.
g.
Balanced
1/
3
each
coal/
gas/
renewables
1
2
3
M.
Cashin
September
2004
1.
More
Coal
2.
More
Gas
&
Oil
3.
More
Renewables
and
Nuclear
1/
3rd
Gas
1/
3rd
Renewables
1/
3rd
Coal
