IPM Model - Updates to Cost and Performance for APC Technologies
SCR Cost Development Methodology for Coal-fired Boilers
Final
April 2023
Project 13527-002
Eastern Research Group, Inc.
Prepared by
Sargent S. Lundy
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.
This work was funded by 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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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final April 2023
Sargent Si Lundy
Coal-Fired SCR Cost Development Methodology
Purpose of IPM Model
Cost algorithms in the IPM model are based primarily on a statistical evaluation of cost data
available from various industry publications, and do not take into consideration site-specific cost
issues. The primary purpose of the IPM cost modules 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. By necessity, the cost
algorithms were designed to require minimal site-specific information. The IPM cost equations
can provide order-of-magnitude capital costs for various air quality control systems based only on
a limited number of inputs such as unit size, gross heat rate, inlet NOx level, fuel sulfur level, %
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 impact costs, such as flue gas volume, temperature and do not
address regional labor productivity, local workforce characteristics, local unemployment and labor
availability, project complexity, local climate, and working conditions. Finally, 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 Cost Basis
The 2004 to 2006 industry cost estimates for SCR units from the "Analysis of MOG and Ladco's
FGD and SCR Capacity and Cost Assumptions in the Evaluation of Proposed EGU 1 and EGU 2
Emission Controls" prepared for Midwest Ozone Group (MOG) were used by Sargent & Lundy
LLC (S&L) to develop the SCR cost model. In addition, S&L included data from "Current Capital
Cost and Cost-effectiveness of Power Plant Emissions Control Technologies" prepared by J. E.
Cichanowicz for the Utility Air Regulatory Group (UARG) in 2010 and 2013. The published data
was significantly augmented by the S&L in-house database of recent SCR projects. The current
industry trend is to retrofit high-dust hot-side SCRs. The cold-side tail-end SCRs encompass a
small minority of units and as such were not considered in this evaluation.
The data was converted to 2021 dollars based on an escalation factor of 2.5% based on the
industry trends over the last ten years (2010 - 2020) excluding the current market conditions1.
Finally, the cost estimation tool was benchmarked against recent SCR projects to confirm the
applicability to the current market conditions.
The available data was analyzed in detail regarding project specifics such as coal type, NOx
reduction efficiency and air pre-heater requirements. The data was refined by fitting each data
set with a least squares curve to obtain an average $/kW project cost as a function of unit size.
The data set was then collectively used to generate an average least-squares curve fit. Based on
the recently acquired data, it appears the overall capital cost has increased by approximately
17% over the costs developed for 2016. Analysis for the data indicates that these units had a high
degree of retrofit difficulty, high elevation, or low-quality fuel.
The costs for retrofitting a plant smaller than 100 MW increase rapidly due to the economy of
size. The older units which comprise a large proportion of the plants in this range generally have
more compact sites with very short flue gas ducts running from the boiler house to the chimney.
Because of the limited space, the SCR reactor and new duct work can be expensive to design
and install. Additionally, the plants might not have enough margins in the fans to overcome the
pressure drop due to the duct work configuration and SCR reactor and therefore new fans may
be required.
^ To escalate prices from Jan 2021 to July 2022 costs, an escalation factor of 19.5% should be used, based on the Handy Whitman steam production plant
index.
Page 1
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final April 2023
Sargent Si Lundy
Coal-Fired SCR Cost Development Methodology
The least squares curve fit was based upon an average of the SCR retrofit projects in recent
years. Retrofit difficulties associated with an SCR may result in significant capital cost increases.
A typical SCR retrofit was based on:
• Retrofit Difficulty = 1 (Average retrofit difficulty);
• Gross Heat Rate = 9500 Btu/kWh;
• SO2 Rate = < 3.0 Ib/MMBtu;
• Type of Coal = Bituminous; and
• Project Execution = Multiple lump sum contracts.
Methodology
Inputs
To predict SCR retrofit costs several input variables are required. The unit size in MW is the
major variable for the capital cost estimation followed by the type of fuel (Bituminous, PRB, or
Lignite) which will influence the flue gas quantities as a result of the different typical heating
values. The fuel type also affects the air pre-heater costs if ammonium bisulfate or sulfuric acid
deposition poses a problem. The unit heat rate factors into the amount of flue gas generated and
ultimately the size of the SCR reactor and reagent preparation. A retrofit factor that equates to
difficulty in construction of the system must be defined. The NOx rate and removal efficiency will
impact the amount of catalyst required and size of the reagent handling equipment.
The cost methodology is based on a unit located within 500 feet of sea level. The actual
elevation of the site should be considered separately and factored into the cost due to the effects
on the flue gas volume. The base SCR and balance of plant costs are directly impacted by the
site elevation. These two base cost modules should be increased based on the ratio of the
atmospheric pressure between sea level and the unit location. As an example, a unit located 1
mile above sea level would have an approximate atmospheric pressure of 12.2 psia. Therefore,
the base SCR and balance of plant costs should be increased by:
14.7 psia/12.2 psia = 1.2 multiplier to the base SCR and balance of plant costs
The NOx removal efficiency specifically affects the SCR catalyst, reagent and steam costs. The
lower level of NOx removal is recommended as 0.05 NOx/lb/MMBtu. In previous versions of the
IPM model, a higher achievable emission rate was set for bituminous compared to PRB and
lignite, the achievable lower levels were identified as 0.07 Ib/MMBtu and 0.05 Ib/MMBtu,
respectively. However, the recent data reviewed as part of this update showed that 0.05
Ib/MMBtu is achievable for all fuel types. This rate is consistent with recent SCR/catalyst
guarantee values for all fuel ranges including high sulfur/low oxidation catalyst applications such
as bituminous fuels.2
2
Ammonium bisulfate , SO3, and other byproducts could be produced by SCR operation, but can be managed through a variety of options, including
ensuring operating at a minimum temperature (or artificially managing the temperature with economizer modification or duct burners). The exact options
would be unit-specific and are not considered for this analysis.
Page 2
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final April 2023
Sargent Si Lundy
Coal-Fired SCR Cost Development Methodology
Outputs
Total Project Costs (TPC)
First the installed costs are calculated for each required base module. The base module installed
costs include:
• All equipment;
• Installation;
• Buildings;
• Foundations;
• Electrical; and
• Average retrofit difficulty.
The base modules are:
Base SCR cost
Base reagent preparation cost
Base air pre-heater cost
Base balance of plant costs including: ID or booster fans, ductwork
reinforcement, piping, etc...
BMR + BMF + BMA + BMB
The total base module installed cost (BM) is then increased by:
• Engineering and construction management costs at 10% 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.3
Additional costs and financing expenditures for the project are computed based on the CECC.
Financing and additional project costs include:
• Owner's home office costs (owner's engineering, management, and procurement) at
5% of the CECC; and
• Allowance for Funds Used During Construction (AFUDC) at 6% of the CECC and
owner's costs. The AFUDC is based on a two-year engineering and construction
cycle.
The total project cost is based on a multiple lump sum contract approach. Should a turnkey
engineering procurement construction (EPC) contract be executed, the total project cost could be
10 to 15% higher than what is currently estimated.
Escalation is not included in the estimate. The total project cost (TPC) is the sum of the CECC
and the additional costs and financing expenditures.
BMR =
BMF =
BMA =
BMB =
BM =
Generally, the direct cost of labor versus material/equipment is 50% material/equipment and 50% labor. Note that this is only direct cost and does not
include all the project/construction indirect costs. The 50% material/equipment typically breaks down into major categories as follows: Demolition/civil
work/concrete: ~5%, Steel: —20%, Electrical/Wires/Instrumentation: ~ 9%, Mechanical equipment: ~14%, Piping/Insulation: —2%
Page 3
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final April 2023
Sargent Si Lundy
Coal-Fired SCR Cost Development Methodology
Fixed O&M (FOM)
The fixed operating and maintenance (O&M) cost is a function of the additional operations staff
(FOMO), maintenance labor and materials (FOMM), and administrative labor (FOMA) associated
with the SCR installation. The FOM is the sum of the FOMO, FOMM, and FOMA.
The following factors and assumptions underlie calculations of the FOM:
• All of the FOM costs were tabulated on a per kilowatt-year (kWyr) basis.
• In general, half of an operator's time is required to monitor a retrofit SCR. The
FOMO is based on that 1/2 time requirement for the operations staff.
• The fixed maintenance materials and labor is a direct function of the process capital
cost at 0.5% of the BM for units less than 300 MW and 0.3% of the BM for units
greater than or equal to 300 MW.
• The administrative labor is a function of the FOMO and FOMM at 3% of (FOMO +
0.4FOMM).
Variable O&M (VOM)
Variable O&M is a function of:
• Reagent use and unit costs;
• Catalyst replacement and disposal costs;
• Additional power required and unit power cost; and
• Steam required and unit steam cost.
The following factors and assumptions underlie calculations of the VOM:
• All of the VOM costs were tabulated on a per megawatt-hour (MWh) basis.
• The reagent consumption rate is a function of unit size, NOx feed rate and removal
efficiency.
• The catalyst replacement and disposal costs are based on the NOx removal and total
volume of catalyst required.
• The additional power required includes increased fan power to account for the added
pressure drop and the power required for the reagent supply system. These
requirements are a function of gross unit size and actual gas flow rate.
• The additional power is reported as a percent of the total unit gross production. In
addition, a cost associated with the additional power requirements can be included in
the total variable costs.
• The steam usage is based upon reagent consumption rate.
Input options are provided for the user to 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:
• Urea cost in $/ton. No escalation was assumed from 2016 pricing;
• Catalyst costs that include removal and disposal of existing catalyst and installation
of new catalyst in $/cubic meter;
• Auxiliary power cost in $/kWh. No escalation has been observed for auxiliary power
cost since 2016;
• Steam cost in $/1000 lb; and
• Operating labor rate (including all benefits) in $/hr.
The variables that contribute to the overall VOM are:
Page 4
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IPM Model - Updates to Cost and Project No. 13527-002
Performance for APC Technologies Final April 2023
Sargent Si Lundy
Coal-Fired SCR Cost Development Methodology
VOMR = Variable O&M costs for urea reagent
VOMW = Variable O&M costs for catalyst replacement & disposal
VOMP = Variable O&M costs for additional auxiliary power
VOMM = Variable O&M costs for steam
The total VOM is the sum of VOMR, VOMW, VOMP, and VOMM. Table 1 is a complete capital
and O&M cost estimate worksheet.
Page 5
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final April 2023
Sargent Lundy
Coal-Fired SCR Cost Development Methodology
Table 1. Example Complete Cost Estimate for an SCR System
Variable
Designation
Units
Value
Calculation
Unit Size
A
(MW)
500
<— User Input
Retrofit Factor
B
1
<— User Input (An "average" retrofit has a factor = 1.0)
Heat Rate
C
(Btu/kWh)
9500
<— User Input
NOx Rate
D
(Ib/MMBtu)
0.3
<— User input
S02 Rate
E
(Ib/MMBtu)
3
<— User Input
Type of Coal
F
Bituminous ~
<— User Input
Coal Factor
G
1
Bit=1.0, PRB=1.05, Lig=1.07
Heat Rate Factor
H
0.95
C/10000
Heat Input
I
(Btu/hr)
4.75E+09
A*C*1000
NOx Removal Efficiency
K
(%)
75
<— User Input
NOx Removal Factor
L
0.9375
K/80
NOx Removed
M
(lb/hr)
1069
D'l/IO^'K/lOO
Urea Rate (100%)
N
(Ib/hr)
747
M*0.525*60/46*1.01/0.99
Steam Required
O
(lb/hr)
845
N*1.13
Aux Power
P
(%)
0.55
O.S^G'H)^^
Include in VOM?0
Urea Cost (50% wt solution)
R
($/ton)
350
<— User Input
Catalyst Cost
S
($/m3)
9000
<— User Input (Includes removal and disposal of existing catalyst and installation of new catalyst)
Aux Power Cost
T
($/kWh)
0.06
<— User Input
Steam Cost
U
($/klb)
4
<— User Input
Operating Labor Rate
V
($/hr)
60
<— User Input (Labor cost including all benefits)
Costs are all based on 2021 dollars
Capital Cost Calculation
Includes - Equipment, installation, buildings, foundations, electrical, and retrofit difficulty.
BMR ($) =
BMF ($) =
BMA ($) =
BMB ($) =
BM ($) =
BM ($/KW) =
370000*(B)*(L)/K).2*(A*G*H)A0.92
671000*(M)*0.25
IF E > 3 AND F=Bituminous, THEN SOOOO^BJ^A^Hy^O JS, ELSE 0
630000*(B)*(A*G*H)A0.42
BMR + BMF + BMA + BMB
Total Project Cost
A1 = 10% of BM
A2 = 10% of BM
A3 = 10% of BM
CECC ($) = BM+A1+A2+A3
CECC ($/kW) =
Example
105,963,000
3,837,000
7,345,000
8,386,000
125,531,000
251
12,553,000
12,553,000
12,553,000
163.190.000
326
SCR (ductwork modifications and strengthening, reactor, bypass) island cost
Base reagent preparation cost
Air heater modification (Bituminous only & > 3lb/MMBtu). For S03 control cost refer to PJFF+PM2.5 spreadsheet
ID or booster fans & auxiliary power modification costs
Total bare module cost including retrofit factor
Base cost per kW
Engineering and Construction Management costs
Labor adjustment for 6 x 10 hour shift premium, per diem, etc. ..
Contractor profit and fees
Capital, engineering and construction cost subtotal
Capital, engineering and construction cost subtotal per kW
B1 = 5% of CECC
TPC' (S) - Includes Owner's Costs = CECC + B1
TPC* ($/kW) - Includes Owner's Costs =
B2 = 6% of (CECC + B1)
C1 = 15% of CECC + B1
8 160 000 Owners costs including all "home office" costs (owners engineering,
management, and procurement activities)
171,350,000 Total project cost without AFUDC
343 Total project cost per kW without AFUDC
10,281,000 AFUDC (Based on a 2 year engineering and construction cycle)
EPC fees of 15%
TPC ($) = CECC + B1 + B2
TPC ($/kW) =
181.631,000
363
Total project cost
Total project cost per kW
Page 6
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Project No. 13527-002
Final April 2023
Sargent S. Lundy
Coal-Fired SCR Cost Development Methodology
Variable
Designation
Units
Value
Calculation
Unit Size
A
(MW)
500
<— User Input
Retrofit Factor
B
1
<— User Input (An "average" retrofit has a factor = 1.0)
Heat Rate
C
(Btu/kWh)
9500
<— User Input
NOx Rate
D
(Ib/MMBtu)
0.3
<— User Input
S02 Rate
E
(Ib/MMBtu)
3
<— User Input
Type of Coal
F
Bituminous ~"
<— User Input
Coal Factor
G
1
Bit=1.0, PRB=1.05, Liq=1.07
Heat Rate Factor
H
0.95
C/10000
Heat Input
I
(Btu/hr)
4.75E+09
A*C*1000
NOx Removal Efficiency
K
(%)
75
<— User Input
NOx Removal Factor
L
0.9375
K/80
NOx Removed
M
(lb/hr)
1069
D*I/10WV100
Urea Rate (100%)
N
(Ib/hr)
747
M*0.525*60/46*1.01/0.99
Steam Required
O
(lb/hr)
845
N*1.13
Aux Power
P
(%)
0.55
0.56*(G*H)A0.43
Include in VOM?^
Urea Cost (50% wt solution)
R
($/ton)
350
<— User Input
Catalyst Cost
S
($/m3)
9000
<— User Input (Includes removal and disposal of existing catalyst and installation of new catalyst)
Aux Power Cost
T
($/kWh)
0.06
<— User Input
Steam Cost
U
($/k!b)
4
<— User Input
Operating Labor Rate
V
($/hr)
60
<— User Input (Labor cost including all benefits)
Costs are ail based on 2021 dollars
Fixed O&M Cost
0.13 Fixed O&M additional operating labor costs
0.75 Fixed O&M additional maintenance material and labor costs
0.01 Fixed O&M additional administrative labor costs
0.89 Total Fixed O&M costs
0.52 Variable O&M costs for Urea
0.39 Variable O&M costs for catalyst: replacement & disposal
q 23 Variable O&M costs for additional auxiliary power required including
additional fan power
0.01 Variable O&M costs for steam
1.25
IPM Model - Updates to Cost and
Performance for APC Technologies
FOMO ($/kW yr) = (1/2 operator time assumed)*2080*V/(A*1000) $
FOMM ($/kW yr) = (IF A < 300 then 0.005'BM ELSE 0.003*BM)/(B*A*1000) $
FOMA ($/kW yr) = 0.03*(FOMO+0.4*FOMM) $
FOM ($/kW yr) = FOMO + FOMM + FOMA $
Variable O&M Cost
VOMR ($/MWh) = N*Fi/(A*1000) $
VOMW ($/MWh) = (0.4*(GA2.9)*(LA0.71 )*S)/(8760) $
VOMP($/MWh)=P*T*10 $
VOMM ($/MWh) = 0*U/A/1000 $
VOM (S/MWh) = VOMR + VOMW + VOMP + VOMM $
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