IPM Model - Updates to Cost and Performance for APC Technologies
CO2 Reduction Retrofit Cost Development Methodology
Final
March 2023
Project 13527-002
Eastern Research Group, Inc.
Prepared by
Sargent &. LundyLLC
55 East Monroe Street Chicago, IL 60603 USA 312-269-2000
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LEGAL NOTICE
This analysis ("Deliverable") was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole use
of Eastern Research Group, Inc. ("Client") in accordance with the agreement between S&L and Client. This
Deliverable was prepared using the degree of skill and care ordinarily exercised by engineers practicing
under similar circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to the
particular scope limitations, budgetary and time constraints, and business objectives of the Client;
(2) information and data provided by others may not have been independently verified by S&L; and (3) the
information and data contained in this Deliverable are time sensitive and changes in the data, applicable
codes, standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any
use or reliance upon this Deliverable by third parties shall be at their sole risk.
Thisworkwas funded by the U.S. Environmental Protection Agency (EPA) through Eastern Research Group,
Inc. (ERG) as a contractor and reviewed by ERG and EPA personnel.
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Sargent Si Lundy11'
IPM Model - Updates to Cost and Performance for
APC Technologies
Project No. 13527-002
March 2023
CO2 Reduction Retrofit Cost Development Methodology
Purpose of Cost Algorithms for the IPM Model
The primary purpose of the cost algorithms is to provide generic order-of-magnitude costs for
various air quality control technologies that can be applied to the electric power generating
industry on a system-wide basis, not on an individual unit basis. Cost algorithms developed for
the IPM model are based primarily on a statistical evaluation of cost data available from various
industry publications as well as Sargent & Lundy's proprietary database and do not take into
consideration site-specific cost issues. By necessity, the cost algorithms were designed to
require minimal site-specific information and were based only on a limited number of inputs
such as unit size, gross heat rate, baseline emissions, removal efficiency, fuel type, and a
subjective retrofit factor.
The outputs from these equations represent the "average" costs associated with the "average"
project scope for the subset of data utilized in preparing the equations. The IPM cost equations
do not account for site-specific factors that can significantly affect costs, such as flue gas volume
and temperature, and do not address regional labor productivity, local workforce characteristics,
local unemployment and labor availability, project complexity, local climate, and working
conditions. In addition, the indirect capital costs included in the IPM cost equations do not
account for all project-related indirect costs a facility would incur to install a retrofit control,
such as project contingency.
Establishment of the Cost Basis
To establish a basis for retrofit of carbon dioxide (CO2) reduction technologies, cost data were
collected from the public domain and Sargent & Lundy's (S&L's) recent experience associated
with recent amine-based CO2 capture processes implemented as retrofits to power facilities. All
data sources were combined to provide a representative CO2 reduction cost basis. Due to the
limited availability of actual as-spent costs for CO2 capture projects, the cost estimation tool
could not be benchmarked against recently executed projects to confirm how accurately it
reflects current market conditions. While the coal-fired applications utilize a robust amount of
data sources, from feasibility and FEED studies, it is only recently that feasibility and FEED
studies have been completed for NGCC applications of this technology. As such, cost
multipliers are used to compare coal-fired capital cost pricing to NGCC applications.
A cost algorithm for pre-combustion CO2 reduction using oxy-combustion technology was not
developed. This technology is best reserved for new units, rather than for power plant retrofits.
In addition, there are too few examples of retrofits to provide a basis for the costs. Therefore, an
algorithm cannot be accurately developed and is not included in the CO2 reduction technology
algorithm. For retrofit applications, the oxy-combustion technology will need to be evaluated on
a case-by-case basis to justify its cost competitiveness against the almost commercially
demonstrated amine-based capture technology.
Page 1
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Sargent Si Lundy11'
IPM Model - Updates to Cost and Performance for
APC Technologies
Project No. 13527-002
March 2023
CO2 Reduction Retrofit Cost Development Methodology
The least-squares curve fit of the data was defined as a "typical" CO2 capture retrofit for removal
of >90% of the inlet CO2. The typical CO2 capture retrofit was based on the following:
Retrofit Difficulty = 1 (average retrofit difficulty);
Gross Heat Rate = 10,000 Btu/kWh;
Type of Coal = PRB;
Project Execution = Engineer, Procurement, and Construction (EPC) contracts; and
Typical CO2 capture rate = 90% removal efficiency.
For CO2 capture, the technology is expected to be applicable to any unit size and, depending how
much flue gas is treated, would scale up based on multiple parallel capture trains.
Transportation, storage, and monitoring (TS&M) of the captured CO2 are not included in the
base cost estimates and instead costs can be included as a user input on a $/ton basis.
CO2 Capture Methodology
Technology Description
The amine-scrubbing process is the most widely studied and used demonstration process for
post-combustion CO2 capture. This process involves passing the flue gas through an absorber
column counter-currently with an amine solvent. At low temperatures, the CO2 is absorbed by
the amine solvent and removed from the flue gas. The treated flue gas passes through wash
levels prior to exiting the stack. The C02-rich solvent leaves the absorber and is heated and
regenerated in the stripper column. Once the CO2 is desorbed from the amine, a concentrated
CO2 stream is dehydrated to remove any moisture and compressed to pipeline quality for
transportation and/or sequestration. Steam is typically taken from the unit's existing steam cycle
and passed through a reboiler to provide the heat needed to strip the CO2 from the amine. While
certain applications justify the use of new natural gas auxiliary boilers for steam production, this
module is based solely on steam extraction, to avoid additional emissions associated with
additional fuel combustion.
To limit degradation of the expensive amine solvent, SO2 and SO3 emissions must be treated
prior to the absorber vessel to lower concentrations of these emissions to less than 2 to 10 ppm.
If a unit is not already equipped with flue gas desulfurization (FGD) technology, then it will need
to be added. Therefore, capital and operating and maintenance (O&M) costs for a wet FGD
(WFGD) which is capable of lowering the SO2 concentration down to 2-10 ppm should be
included as part of the overall CO2 capture cost. Note that the cost of retrofitting FGD is not
included as part of the CO2 cost algorithm.
Page 2
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Sargent Si Lundy11'
IPM Model - Updates to Cost and Performance for
APC Technologies
Project No. 13527-002
March 2023
CO2 Reduction Retrofit Cost Development Methodology
Inputs
Several input variables are required to predict future retrofit costs. The gross unit size in MW
and carbon content of the fuel are the major variables for the capital estimation. A retrofit factor
that equates to the difficulty in construction of the system must be defined. Note that the costs
could increase significantly for congested sites or sites with limited adjacent space. One
example for the use of a retrofit factor is if a facility needs to minimize additional water
consumption. For cases where a hybrid cooling system is required due to limited water
availability, a retrofit factor of 1.15 should be used to account for the increase in the capital cost
associated with that system.
The gross unit heat rate will factor into the amount of flue gas generated and, ultimately, the size
of the absorber, stripper, compressor, and balance of plant costs. Heat rate is an input from the
user, with a suggested starting point of 10,000 Btu/kWh for coal-fired boilers, and 6,660
Btu/kWh for natural gas combined cycle (NGCC) facilities.
The CO2 rate will have the greatest influence on the solvent makeup rate and steam required in
the regeneration process. The type of fuel (Bituminous, PRB, Lignite, or Natural Gas) will
influence the CO2 quantity in the flue gas because of the differing carbon compositions typical in
these types of fuels.
The evaluation includes a user-selected option for identifying if the unit is equipped with FGD.
If the unit fires coal and is not already equipped with FGD technology, costs for installing a
WFGD should also be incorporated. The user is required to use the WFGD IPM cost algorithm
to generate the capital and O&M costs for the technology.
Any changes from the base assumptions should be incorporated to derive more accurate costs.
Outputs
Total Project Costs (TPC)
First, the installed costs are calculated for each required base module. Note that costs to build a
pipeline are not included in this cost algorithm; it is assumed that another entity will be funding
the CO2 pipeline construction. The base module installed costs include the following:
All equipment,
Installation,
Buildings,
Foundations,
Electrical, and
Retrofit difficulty.
Page 3
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Sargent Si Lundy11'
IPM Model - Updates to Cost and Performance for Project No. 13527-002
APC Technologies March 2023
CO2 Reduction Retrofit Cost Development Methodology
These costs can potentially range widely because of the relatively new nature of the process, as
well as site-specific details. Capital costs estimated here are expected to encompass a +/- 50%
range.
The base modules are as follows:
Base capture island cost, including compression
Base balance of plant costs including piping, ductwork, cooling system,
steam integration, foundations, etc.
BMI + BMBOP
The total base module installed cost (BM) is then increased by the following:
Engineering and construction management costs at 15% of the BM cost;
Labor adjustment for 6 x 10-hour shift premium, per diem, etc., at 10% of the BM
cost; and
Contractor profit and fees at 10% of the BM cost.
A capital, engineering, and construction cost subtotal (CECC) is established as the sum of the
BM and the additional engineering and construction fees.
Additional costs and financing expenditures for the project are computed based on the CECC.
Financing and additional project costs include the following:
Owner's home office costs (owner's engineering, management, and procurement) are
included at 5% of the CECC.
Allowance for Funds Used During Construction (AFUDC) are included at 10% of the
CECC and owner's costs. The AFUDC is based on a three-year engineering and
construction cycle.
The total project cost is based on a turnkey engineering, procurement, and construction (EPC)
contract execution; as such, the total project cost is increased by 15% to account for risk and fees
associated with this structure.
Escalation is not included in the estimate because all costs are provided in 2021 dollars and are
not representative of recent COVID and inflation related pricing increases. The total project cost
(TPC) is the sum of the CECC and the additional costs and financing expenditures.
BMI =
BMBOP =
BM =
Page 4
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Sargent Si Lundy11'
IPM Model - Updates to Cost and Performance for
APC Technologies
Project No. 13527-002
March 2023
CO2 Reduction Retrofit Cost Development Methodology
Fixed O&M (FOM)
The fixed O&M cost is a function of the additional operations staff (FOMO), maintenance labor
and materials (FOMM), and administrative labor (FOMA) associated with the CO2 capture
installation. The FOM is the sum of the FOMO, FOMM and FOMA.
The following factors and assumptions underlie calculations of the FOM:
All the FOM costs were tabulated on a per-kilowatt-year (kW-yr) basis.
In general, 22 additional shift operators are required for operating the CO2 capture
facility. The FOMO was based on the number of additional operations staff required
as a function of generating capacity.
The fixed maintenance materials and labor factor is a direct function of the process
capital cost at 2.5% of the equivalent equipment and material portion, which is
expected to be 60% of the BM.
The administrative labor is a function of the FOMO and FOMM at 3% of the sum of
(FOMO + 0.4 FOMM).
Variable O&M (VOM)
Variable O&M is a function of the following:
Solvent makeup rates and unit costs,
Additional power required and unit power cost,
Loss of production due to steam consumption from the base plant, and
Makeup water required and unit water cost.
The following factors and assumptions underlie calculations of the VOM:
All the VOM costs were tabulated on a per-megawatt-hour (MWh) basis.
A VOM related calculations are estimated using different equations for NGCC and
coal-fired applications.
The solvent makeup cost is a function of total CO2 captured. The capital costs are
based on a 90% CO2 reduction design. An indicative value is included but can be
adjusted by the user.
The steam derate is estimated based on the steam extracted for use in the CO2
regeneration process. Steam rate is a function of total CO2 captured.
The additional power required includes increased fan power to account for the added
capture island pressure drop, system pumps, and compressor power. This
requirement is a function of total CO2 captured.
The makeup water rate is a function of total CO2 captured.
Page 5
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Sargent Si Lundy11'
IPM Model - Updates to Cost and Performance for Project No. 13527-002
APC Technologies March 2023
CO2 Reduction Retrofit Cost Development Methodology
The transportation, storage, and monitoring costs are not included. A cost can be
added by the user, based on an evaluated cos with respect to the amount of CO2
captured in ton.
Because of the widely varying consumption of power, steam, water, and solvent associated with
the various CO2 capture technologies, the variable O&M costs are developed as a fixed amount
based on averages of S&L in-house project data and design assumptions, calculated separately
for coal-fired or NGCC applications. Steam turbine derate is not calculated separately, as the
derate is expected to be similar based on total steam extraction, regardless of application.
Input options are provided so the user can adjust the variable O&M costs per unit. Average
default values are included in the base estimate. The variable O&M costs per unit options are as
follows:
Solvent cost in $/ton of CO2 captured; the cost could vary significantly by process
supplier;
Auxiliary power cost in $/kWh;
Makeup water costs in $/l,000 gallons;
Operating labor rate (including all benefits) in $/hr; and
Transportation, storage, and monitoring costs in $/ton.
The variables that contribute to the overall VOM are shown below:
Variable O&M costs for solvent
Variable O&M costs for transportation and storage of capture CO2
Variable O&M costs for additional auxiliary power and steam
consumption (lost revenue)
Variable O&M costs for makeup water
The total VOM is the sum of VOMS, VOMTS, VOMP, and VOMM. Table 1 is a complete
capital and O&M cost estimate worksheet.
VOMS =
VOMTS =
VOMP =
VOMM =
Page 6
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Sargent & LundylLC
IPM Model - Updates to Cost and Performance for APC Project No. 13527-002
Technologies March 2023
CO2 Reduction Retrofit Cost Development Methodology
Table 1. Example 1 (Coal)
Fill in the yeiow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defnec as outlined in &e table.
Variable
Designation
Units
Value
Calculation
Unit Size |Gross!
A
(MVV !-
700
< User Input
Retrofl Factor
B
< User Input (An " average" retrofit Has a factor = 1.0'|
Gross Heat Rale
C
(Btui'kWh)
10000
< User Input (Default Coal-Fired = 10,000; NGCC = 6.660:
Type of Fuel
D
PRB ~
< User Input
C02 Captive Rate
E
{toruhr)
674
A"C* 1000*0.9'Coai Rate /106 i 2GOO iBasec on 90% reduction 1
S02 Control Technology
F
FGD ~
< User Input
Steam Consumption
G
llhftv)
1,530,200
Coal: 1.16 ' E ' 2000 ; NGCC: 1.33 ' E ' 2000
Aux Power
H
(MW}
@6
Coa-i: 0.1465 * E ; NGCC: 0.2D7 ' E
Makeup Water Rate
1
Igpm}
4S94
Coal: 7.26 ' E ; NGCC: 9.73 ' E
Steam Turbine Derate
J
(MW}
123
0.155 * G/2000
Net Power Reduction
K
(MW}
222
H + J
Solvent Cost
L
(Won C02
removed}
3.5
< User Input
Aux Power Cost
M
($/kWh)
0.03
< User Input
Make*ฎ Water Cost
N
l'5<'kgaf)
1
< User Input
Operating Labor Rate
O
ISn'hr)
60
< User Input (Labor cost including ai benefits)
Transportation. Storage.
& Monitoring fTS&M)
P
(S.ton)
10
< User Input
Costs are all based on 2021 dollars
Capital Cost Calculation Example
Includes - Equipment- mstaiation, buildings foundations, electrical, mew physical'chemical wastewater treatment and retrofit difficulty
BMI |Si = +B24 L34BI Coal: [8830DD'(E)]' B
BMBOP (S) =
BM ($) =
BM (Si'KW) =
Total Project Cost
A1 = 15% of BM
A2 = 10% of BM
A3 = 10% of BM
Coal: [235200'(E)]1 B
BMI + BMC + BMBOP
NGCC: [8&30Q0,(E)1' B ' 1.45
NGCC: [235200*(E)] * B * 1.45
753,773.000
1077
113,067,000
75.373.000
75.378,000
Base C02 capture island cost including:
Absorbers and stacks, strippers, biowers. reagent tanks, heat exchangers,
compressors, etc...
Base balance of plant costs including:
Cooling system, steam supply, pp^g, ductwork, foundations, etc...
Total base cost including retrofit factor
Base cost per kW
Enq merino and Construction Management costs
Labor adjustment for 6 x 10 hour shift premium, per diem. etc...
C ontractor profit and fees
CECC {$) - Excludes Owner's Costs = BM+A1+A2+A3
1.017,601 r000 Capital, engineering and construction cost subtotal
CECC {S/kW) - Excludes Owner's Costs =
B1 =5% of CECC
TPC ($} - Includes Owner's Costs = CECC + B1
TPC" ($/kW) - Includes Owner's Costs =
B2 = 10% of {CECC + B1)
C1 = 15% of CECC + B1
TPC ($} - Includes Owner's Costs and AFUDC = CECC + B1 + B2
TPC (S/kW) - Includes Owner's Costs and AFUDC =
50.880.000
1,068.481.000
1526
106 848 000
168.667.000
1,175,329.000
1679
Capital, engineenng and construction cost subtotal per kW
Owners costs including all "home office" costs {owners engineering,
management, and procurement activities}
Total project cost without AFUDC
Total project cost per kW without AFUDC
AFUDC (Based on a 3 year engineering and construction cydie)
EPC G&A and risk fees of 15%
Total project cost
Total project cost per kW
Page 7
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Sargent & LundylLC
IPM Model - Updates to Cost and Performance for APC Project No. 13527-002
Technologies March 2023
CO2 Reduction Retrofit Cost Development Methodology
Table 1. Example 1 (Coal) Continued
Fill n the yeiow cells with the known data inputs. The resulting costs are tabulated betow. Variable names are defned as outlined in the table.
Variable
Designation
Units
Value
Calculation
Unl Size iGross:
A
(MW)
700
< User Input
Retrofit Facto'
B
1
< User Inout (An ' average" retrofit has a factor = 1.0)
Gross Heat Rate
C
(BtU'TcWh)
10000
< User Input (Default Coal-Fred = 10,000; NGCC = 6.660}
Type of Fuel
D
PSB w
< User Input
C02 Captu-e Rate
E
(ton/hr)
674
A'C* 1000*0.9"Coal Rate /108/ 2Q0D (Based on 90% reduction)
S02 Control Technology
F
FGD ~
< User Input
Steam Con&uanpbon
G
(Mr)
1,590.900
Coal: 1.18 * E ' 2000 ; NGCC: 1.33 * E ' 2000
Au> -:
H
(MW)
99
Coal: 0.1465 *E ; NGCC: 0.207 ' E
f.'s-.e.; vVaterRate
1
(gpm>
4S94
Coal: 7.26'E ; NGCC: 9.73 ' E
Steam Turbine Derate
J
.ฆv.v:
123
0.155 ' G / 2000
Net Pcwer Reduction
K
(MW)
222
H+J
Solvent Cost
L
($/ton C02
removed I
3.5
< User Input
Aux Power Cost
M
(S/kWh)
0.03
< User Input
f.'ฆ. 0 -: ;V a:er Cost
N
(S/kgal)
1
< User Input
Operating Labor Rate
O
(S/hr)
SO
< User Inout (Labor cost including al benefits'!
Transportation. Storage,
& Mopicr'"g iTS&M;
P
(S/ton)
10
< User Input
Fixed O&M Cost
FOMO (S/kW yr) = 22*2080'0/{A' 1000)
FOMM {$/kW yr) = BM'0.6,D.025/{B,A'1000)
FOMA (S.1cW yr) = 0.03'(FOMO+O.4* FOMM)
FOM Lost Revenue
Varable O&M costs for makeup water
Total Variabte O&M costs
Annual Capacity Factor =
Annual MWhs =
Annual Heat Input MMBtu =
Annual Ton C02 Createa =
Annual Ton C02 Removed =
Annual Ton C02 Emission =
Annual Avg C02 Emission Rate, Ib/MWh =
0.85
5,212.200
52,122,000
5.577.054
5,019,340 at remova efficiency - 90%
557.705
214 based on orglnal gross HM toad [A]
Annual Capital Recovery Factor = 0.082
Annual Capital Cost (Including AFUDC). $ =
Annual FOM Cost S =
Annual VOM Cost $ =
Total Annual C02 Capture Cost S =
Capital Cost. S/MWh =
FOM Cost, S/MWh =
VOM Cost, S/MWh =
Tot3! C02 Capture Cost. S/MWh =
C02 Capture from DOE 2019 BBS 12B
96.377,000
14,270,000
119,535.000
230.132,000
T 8.49
2.74
22.93
Capital Cost, S/ton =
FOM Cost. S/ton =
VOM Cost. S/ton =
Total C02 Capture Cost, S/ton =
Page 8
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Sargent & LundylLC
IPM Model - Updates to Cost and Performance for APC Project No. 13527-002
Technologies March 2023
CO2 Reduction Retrofit Cost Development Methodology
Table 2. Example 1 (NGCC)
Fill e\ the yelowr cells with the known data inputs. The resulting costs are tabulated betow Variable names are defined as outlined in the table.
Variable
Designation
Units
Value
Calculation
Unit Size [Gross;
A
(MW}
700
< User Ifisut
Retroft Factor
B
1
< User Incut (An ' average" retrofit has a 'actor = 1 Di
Gross Heat Rate
C
(Btu/kWh)
6660
< User Input (Default Coal-Fred = 10,000; NGCC = 6.660;
Type of Fuel
D
NGCC ~
< User Input
C02 Capture Rate
E
(tonihr)
245
A'C' 1 QOO'Q.0'Coa Rate10e / 2000 1 Base; on 90% reduction)
302 Control Technology
F
None ป
< User Input
Steam Consumption
G
(Ih/tv)
652,900
Coal: 1.18 1 E ' 2000 ; NGCC 1.33 " E ' 2OD0
Aux Power
H
(MW)
51
Coal: 0.1465 ' E ; NGCC: 0.207 * E
Makeup Water Rate
1
(gpm)
2388
Cca : 7.26 * E ; NGCC: 9.73 ' E
Steam Turbine Derate
J
(MW)
51
0.155 ' G / 2000
Net Power Reduction
K
(MW|
102
H + J
Solvent Cost
L
($fton C02
removed}
3.5
< User Input
Aux Power Cost
M
(SAWh)
0.03
< User Input
Makeup Water Cost
N
I'S.'kgai)
1
< User Input
Operating Labor Rate
O
iS-'hr)
60
< User Input (Labor cost including ai beneftsi
Transportation Storage,
& Maniftomg iTS&M}
P
(Vton}
10
< User Input
Costs are all based on 2021 dollars
Capital Cost Calculation Example
Includes - Equipment nstalation, buildings, fowidations, electrical, miner physicab'cfremical wastewater treatment and retrofit difficulty
BMI (J) = +B24:L34BI Coal: [883000*(E)]' B ; NGCC: I88300G'(E)]1 B ' 1.45 $ 314.267,0
BMBOP ($} =
BM(5) =
BM (S/KW) =
Total Project Cost
At = 15% ofBM
A2= 10% ofBM
A3 = 10% ofBM
Coal: [235200*(E)]' B
BMI + BMC + BMBOP
NGCC: [235200' (E)]1 B ' 1.45
83.710,000
307.077,000
560
50.607,000
30.708,000
30.703,000
Base C02 capture island cost including:
Absorbers and stacks, strippers, btewers, reagent tanks, heat exchangers,
compressors, etc...
Base baฃar
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Sargent & LundylLC
IPM Model - Updates to Cost and Performance for APC Project No. 13527-002
Technologies March 2023
CO2 Reduction Retrofit Cost Development Methodology
Table 2. Example 2 (NGCC) Continued
Fill in the yeJow cells with the knovim data inputs. The resulting costs are tabulated betew Variable names are defned as outlined in the table.
Variable
Designation
Units
Value
Calculation
Uret Size [Gross!
A
(MW)
700
< User lr*put
Retrofit Factor
6
1
< User Input (An 'average' retrofit has a factor = 1.0)
Gross Heat Rate
C
iBtu/kWh)
8660
< User Input ฆ, Default Coal-Fred = 10,000; NGCC = 6.660;
Type of Fuel
D
NGCC ~
< User Input
C02 Captive Rate
E
(ton/hr)
245
A'C'IOOO'O.Q'Coai Rate /1'OP/ 2000 iBasec on 90% reduction!
S02 Control Technology
F
None ~
< User Input
Steam Consumption
G
(Ibrtw)
652,900
Coal: 1.18 * E * 2000 ; NGCC: 1.33 * E ' 2OD0
Aux Power
H
(MW)
51
Coa;: 0.5465 1 E ; NGCC: 0.207 * E
Makeup Water Rate
I
(flPm)
2388
Coal: 7.26 ' E : NGCC: 9.73 ' E
Steam Turbine Derate
J
(MW)
51
0.155 ' G / 2000
Net Power Reduction
K
(MW)
102
H + J
Solvent Cost
L
(S/ton C02
removed)
3.5
< User Input
Aux Power Cost
M
(S.'kWhl
0.03
< User Input
Makeup Water Cost
N
iS/kgal)
1
< User Input
Operating Labor Rate
O
(5/hr'i
60
< User Input (Labor cost including aS benefts'i
Transportation. Storage,
& Moortomg iTS&M)
P
($/ton)
10
< User Input
Fixed O&M Cost
FOMO (SAW yr) = 22*2QHJ*'MWh) =1' 60 / 100Q ' N / A
VOM (S/MWh) = VOMS + VOMTS + VOMP + VOMM
Costs are all based on 2021 dollars
S 3.92
s a.53
$ 0.22
$ 12.67
S 1.23
S 3.51
$ 4.37
S 0.21
$ 9.31
Fixed O&M additional operating labor costs
Fixed O&M additional maintenance material and labor costs
Fixed O&M additional administrative labor costs
Total Fixed O&M costs
Variable O&M costs for solvent
Varable O&M costs for transportation, storage, and monitoring
Variable O&M costs for additional auxiliary power and steam required
> Lost Revenue
Varable O&M costs for makeup water
Total Variable O&M costs
Annual Capacity Factor =
Annual MWhs =
Annual Heat Input MMBtu =
Annual Ton C02 Created =
Annual Ton C02 Removed =
Annual Ton C02 Emission =
Annual Avg C02 Emission Rate, Ib/MWh =
0.85
5.212.20D
34,713.252
2.030,725
1,827,653 at removal efficiency - 9D%
203.073
78 based on original gross unit lead [A]
Annual Capital Recovery Factor = 0.082
Annual Capital Cost (IncJudng AFUDC). S =
Annual FOM Cost S =
Annual VOM Cost 1 =
Total Annual C02 Capture Cost, $ =
Capita! Cost. S/MWh =
FOM Cost. S/MWh =
VOM Cost. S/MWh =
Tcta? C02 Capture Cost, S/MWh =
C02 Culture from DOE 2019 BBS 12B
50,885.030
8.863.000
48,527,000
108,281,000
0.76
1.70
Capital Cost. Siton =
FOM Cost, S/ton =
VOM Cost. S/ton =
Total C02 Capture Cost, S/ton =
Page 10
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C02 Reduction Retrofit Cost Development Methodology
March 2023
Sargent & Lundy
Appendix A - Amine Capture Cost Comparison
HISTORICAL PERSPECTIVE
Post-combustion CO2 capture technology has been developed and advanced on power plant applications over
the last few decades. With two large-scale applications installed in North America on coal-fired power plants,
post-combustion amine-based capture has been proven to be a technically feasible technology to implement.
In the last five years, since the Petra Nova project, the U.S. Department of Energy (DOE) has actively engaged
various amine-solvent technology suppliers to conduct front-end, engineering and design (FEED) studies to
advance the technology and further refine and reduce the overall cost of capture.
The Global CCS Institute has tracked publicly available information on previously studied, executed, and
proposed CO2 capture projects. Recent pricing is approximately $40/tonne ($36/ton) on average for coal plants
(excluding transportation, storage, and monitoring), compared to Petra Nova and Boundary Dam whose actual
costs were reported to be $65 and $105/tonne ($59 and $95/ton), respectively, see Figure 1,1
Figure 1 Levelized Cost of CO2 Capture for Large Scale Post-Combustion Facilities at Coal-Fired
Power Plants
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^ PREVIOUSLY STUDIED FACILITIES # CURRENTLY OPERATING
FIRST GENERATION CAPTURE TECHNOLOGY LEARNING RATE
RECENTLY PROPOSED AND NEW FACILITIES
NEXT GENERATION CAPTURE TECHNOLOGY LEARNING RATE
Sections below discuss high-level cost comparisons for the application of amine-based CO2 capture system
considering retrofit vs. new application on both coal and NGCC facilities.
1 Global Status of CCS 2019: Targeting Climate Change. Figure 8.
https://ccsknowledge.com/pub/Publications/Global Status%20of CCS 2019%20 GCCSI.pdf
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C02 Reduction Retrofit Cost Development Methodology
March 2023
Sargent & Lundy
Appendix A - Amine Capture Cost Comparison
RETROFIT COST COMPARISON
In 2016, S&L developed a model to predict the cost to retrofit and operate a CO2 capture system at existing
coal-fired power plants. Since that time, cost of capture has come down incrementally, based on recent project
feasibility and FEED studies. S&L compared recent project estimates from 2020-2021 to the "IPM Model -
Updates to Cost and Performance for APC Technologies, CO2 Reduction Cost Development Methodology"
dated Final, February, 2017 (referred to as "2017 CO2 IPM Cost Equations"), as shown in Figure 2. The 2017
C02 IPM Cost Equations were developed and applied to coal-fired applications only. Based on the
advancements within the industry in terms of optimization of energy demand, solvent makeup costs, financing
costs, and lessons learned from pilot facilities, all recent project costs for coal-fired retrofits are noticeably
lower than the original curve, by approximately 20%2.
Figure 2 Recent Project Cost Estimate Comparison to 2017 CO2 IPM Cost Equations
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Unit Size (MWequivalent)
(All Costs in $2021)
2017 CO2 IPM Cost Equations
ซ Project Cost Estimates
*
Depending on the approach for implementing CO2 capture, the cost of capture for coal-fired units is generally
in the range of $30-50/tonne ($27-45/ton).3 The reduction in costs is due primarily to technology innovations
2 For this evaluation all costs are representative of 2021 dollars and excludes current market conditions; all other default parameters in
the IPM model were held constant. This comparison excludes any cost of transportation, storage, and monitoring (TS&M). In 2022,
inflation has resulted in an increase of C02 capture system costs of 15-20% on average; however, this continues to fluctuate.
3 For this evaluation all costs are representative of 2021 dollars and excludes current market conditions. The cost of capture excludes
costs related to transportation, storage, and monitoring (TS&M).
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C02 Reduction Retrofit Cost Development Methodology
March 2023
Sargent & Lundy
Appendix A - Amine Capture Cost Comparison
and lessons learned from implemented projects.
Amine CO2 capture technology suppliers have made advancements in their solvent and process design that
allows for better capture of CO2 at low partial pressures. With these considerations, S&L has seen a large
reduction in overall cost of capture for NGCC facilities recently, however, there are still limitations to the
technology and overall economics. As seen in Figure 3, costs estimated for application of CO2 capture at a
NGCC facility are significantly higher on an evaluated cost ($/tonne or $/ton) than on a coal-fired facility,
approximately 50%, due to economies of scale and CO2 concentration.
Figure 3 CO2 Capture Retrofit Costs on Coal-Fired v. NGCC Units
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80
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(All Costs in $2021)
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NEW FACILITY COST COMPARISON
The cost of CO2 capture implementation constructed in parallel with new units is expected to be on the lower
end of the cost ranges provided in the previous sections, as the arrangement, design, and integration with the
base facility will be optimized. If new NGCC units are built with CO2 capture, the capacity factor can be
expected to be relatively high, similar to a base loaded facility (e.g. >85%); this also improves the overall
capture economics. However, as in retrofit applications, the costs estimated for application of CO2 capture at
a new NGCC facility are significantly higher on an evaluated cost ($/tonne or $/ton) than on a coal-fired facility.
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C02 Reduction Retrofit Cost Development Methodology
March 2023
Sargent & Lundy
Appendix A - Amine Capture Cost Comparison
Table 1: Comparative Cost of Capture
Coal w/ Carbon Capture-90%
Units
New Unit
ATB2021
New Unit EIA -
S&L
S&L Retrofit
Experience
Gross Unit Size
MW
Not specified
831
700
Net Nominal Capacity
MW
650
650
455
Net Nominal Heat Rate
Btu/kWh
10,830
12,507
14,776
CO2 Emission Rate
Ib/MMBtu
20.23
20.60
21.10
Capital Cost12
$/kW-net
$4,698
$5,876
$3,202
Fixed O&M Cost1
$/kW-year
$122.00
$59.54
$41.27
Variable O&M Cost16
$/MWh
$14.00
$10.98
$21.94
Fuel O&M Cost5
$/MWh-net
$24.12
$27.85
$0.00
Cost of Capture3 4
$/tonne
$39.08
$39.31
$48.81
$/ton
$35.45
$35.65
$44.27
NGCC w/ Carbon Capture-90%
Units
New Unit
ATB2021
New Unit EIA -
S&L
S&L Retrofit
Experience
Frame Type
Not specified
H-Class, 1x1x1
F-Class, 3x1
Net Nominal Capacity
MW
646
377
632
Net Nominal Heat Rate
Btu/kWh
7,160
7,124
9047
CO2 Emission Rate
Ib/MMBtu
11.86
11.70
11.5
Capital Cost12
$/kW-net
$2,435
$2,481
$1,267
Fixed O&M Cost1
$/kW-net-year
$65.00
$27.60
$21.64
Variable O&M Cost16
$/MWh-net
$6.00
$5.84
$8.29
Fuel O&M Cost5
$/MWh-net
$31.65
$31.49
$0.00
Cost of Capture3 4
$/tonne
$82.28
$68.24
$58.50
$/ton
$74.63
$61.89
$53.06
Notes:
1 All cost values in 2019 dollars, 2019 Case shown for ATB2021.
2AII capital cost values are presented as overnight costs.
3Assumed capacity factor of 85%.
4Assumed evaluation period of 20 years and 5.0% interest rate.
5 All cases have fuel O&M costs added using NETL assumptions ($51.96/ton coal, 11,666 Btu/lb coal;
$4.42/MMBtu gas, 22,483 Btu/lb gas); for retrofit case, no additional fuel usage is expected.
6AII steam turbine and aux power derate for the retrofit cases are accounted for within the variable O&M.
Note that there are many different assumptions considered in the EIA and the example retrofit evaluations
making this difficult to compare on a line by line basis. Unit derate costs due to steam turbine derates or
additional aux power demand due to carbon capture are typically covered in the variable O&M (VOM) costs;
in this case, the retrofit VOM is noticeably higher than the new unit VOM. Instead of including derates for the
new unit in VOM, it is covered separately in the EIA evaluation as part of fuel-based O&M costs. When
reviewing retrofit cases, often times property tax, insurance, and administrative impacts are excluded from the
fixed O&M (FOM) costs since the facility is expected to absorb that cost. While the retrofit cases suggest that
the FOM is lower, in reality, FOM costs for all four cases would be expected to be similar.
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