IPM Model - Updates to Cost and Performance for APC Technologies
SNCR Cost Development Methodology for Coal-fired Boilers
Final
February 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 Project No. 13527-002
Performance for APC Final February 2023
Technologies
Sargent S Lundy
Coal-Fired SNCR 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 formulation of the SNCR cost estimating model is based upon a proprietary Sargent & Lundy
LLC (S&L) in-house database of recent (2016 to 2021) quotes for both lump sum and EPC
contracts. The S&L in-house database of project costs were 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. The data was analyzed in detail regarding project
specifics such as coal type, boiler type, and NOx reduction efficiency. The data includes projects
that involved cyclone boilers, T-fired and wall fired systems with multiple levels of injection. The
cyclone boiler costs include rich reagent injection (RRI).
The S&L data was fitted with a least squares curve to establish the trend in $/kW as a function of
gross MW. The SNCR cost model parameters were adjusted to account for market changes and
escalation, and then the model output was compared to the S&L data. The model output followed
a $/kW correlation very similar to the S&L in-house data, once the adjustments were made to the
model. Based on recently acquired data, it appears the overall capital cost has increased by
approximately 32% over the costs developed in 2016.
The higher project costs at the lower end of the MW range is due primarily to economies of scale.
Additionally, older power plants in the 50 MW range tend to have plant sites that are more
compact and therefore difficult to accommodate the reagent storage areas and piping, injection
mixing/dilution equipment and construction activities. The smaller power plants also tend to have
older control systems that may require upgrades to accommodate the new SNCR control system.
The S&L data includes SNCR projects with various types of boilers, coals, sulfur levels and
retrofit complexities. The typical SNCR retrofit was based on:
Retrofit Difficulty = 1 (Average retrofit difficulty);
Gross Heat Rate = 9800 Btu/kWh;
^ 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.
1
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IPM Model - Updates to Cost and Project No. 13527-002
Performance for APC Final February 2023
Technologies
Sargent S Lundy
Coal-Fired SNCR Cost Development Methodology
SO2 Rate = < 3 Ib/MMBtu;
Type of Coal = Bituminous; and
Project Execution = Multiple lump sum contracts.
Methodology
Inputs
To predict future retrofit costs several input variables are required. The unit size in MW and NOx
levels are the major variables for the capital cost estimation followed by the type of fuel. The fuel
type affects the air pre-heater costs if sulfuric acid or ammonium bisulfate deposition poses a
problem. In general, if the level of SO2 is above 3 Ib/MMBtu, it is assumed that air heater
modifications will be required. The unit heat rate factors into the amount of NOx generated and
ultimately the size of the SNCR reagent preparation system. 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 urea required and size of the reagent handling equipment. Finally, the boiler
type will influence the capital costs of the SNCR system and balance of plant considerations.
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 SNCR costs are directly impacted by the site elevation. This base cost
module 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 SNCR cost should be
increased by:
14.7 psia/12.2 psia = 1.2 multiplier to the base SNCR cost
The NOx removal efficiency achievable with SNCR is limited by unit size and inlet NOx
concentrations. The SNCR efficiency is significantly lower for large boilers compared to small
boilers primarily due to the large penetration required for urea droplets to cover the flue gas. For
pulverized coal (PC) applications, the highest efficiency that could be achieved is approximately
15% for units greater than 400 MW, 20% for units 200-400 MW, and 25% for units smaller than
200 MW. For fluidized-bed combustion (FBC) coal applications the highest efficiency that can be
achieved is 50%. For all coal-fired applications a target floor of 0.08 Ib/MMBtu is the lowest outlet
NOx emission rate that can be reliably achieved by SNCR technology throughout the operating
load range. Lower emission rates may periodically be achieved when the unit is operating at
lower loads.
Outputs
Total Project Costs (TPC)
First the installed costs are calculated for each required base module. The base module installed
costs include:
2
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IPM Model - Updates to Cost and Project No. 13527-002
Performance for APC Final February 2023
Technologies
Sargent S Lundy
Coal-Fired SNCR Cost Development Methodology
All equipment;
Installation;
Buildings;
Foundations;
Electrical;
Water treatment for the dilution water; and
Retrofit difficulty.
modules are:
Base SNCR system
Base air heater modifications, as required
Base balance of plant costs including: piping, site upgrades, water treatment for
the dilution water, etc...
BMS + 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.
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 0% of the CECC and
owner's costs as these projects are expected to be completed in less than a year
after the equipment is released for the fabrication.
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.
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 SNCR installation. The FOM is the sum of the FOMO, FOMM, and FOMA.
The base
BMS =
BMA =
BMB =
BM =
3
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IPM Model - Updates to Cost and Project No. 13527-002
Performance for APC Final February 2023
Technologies
Sargent S Lundy
Coal-Fired SNCR Cost Development Methodology
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, 0 additional operators are required a new SNCR system.
The fixed maintenance materials and labor is a direct function of the process capital
cost at 1.2% of the BM.
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;
Dilution water required and unit water cost;
Additional power required and unit power cost; and
Boiler efficiency reduction due to the added water in the boiler and unit replacement
coal 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 usage is a function of the amount of NOx removed, NOx inlet rate, and
boiler type. A utilization factor (UF) of 15% is used for units with an inlet NOx of 0.3
Ib/MMBtu or lower and 25% for units with an inlet NOx greater than 0.3 Ib/MMBtu.
For CFB boilers a utilization factor of 25% is used.
The dilution water usage is based on creating a 5% dilute reagent stream for injection
into the boiler.
The additional power required includes compressed air or blower requirements for
the urea injection system and the reagent supply system.
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.
Impacts on the unit heat rate due to injection of liquid water into the boiler are
accounted for by additional coal costs to provide added boiler heat input and can be
included in the total variable costs.
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 for a 50% by weight solution in $/ton; No escalation was assumed from
2016 pricing;
Auxiliary power cost in $/kWh; No escalation has been observed for auxiliary power
cost;
Dilution water cost in $/1000 gallon;
Operating labor rate (including all benefits) in $/hr; and
Replacement coal cost in $/MMBtu.
The variables that contribute to the overall VOM are:
4
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IPM Model - Updates to Cost and Project No. 13527-002
Performance for APC Final February 2023
Technologies
Sargent S Lundy
Coal-Fired SNCR Cost Development Methodology
VOMR = Variable O&M costs for urea reagent
VOMM = Variable O&M costs for dilution water
VOMP = Variable O&M costs for additional auxiliary power
VOMB = Variable O&M costs for additional coal
The total VOM is the sum of VOMR, VOMM, VOMP, and VOMB. Table 1 shows a complete
capital and O&M cost estimate worksheet for an SNCR on a T-fired boiler. Table 2 shows a
complete capital and O&M cost estimate worksheet for an SNCR on a CFB boiler.
5
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IPM Model - Updates to Cost and Project No. 13527-002
Performance for APC Technologies Final February 2023
Sargent S l_uncily
Coal-Fired SNCR Cost Development Methodology
Table 1. Example Complete Cost Estimate for an SNCR System Installed on a T-fired boiler
Variable
Designation
Units
Value
Calculation
Boiler Type
BT
Tanqentiai *
< User Input
Unit Size
A
(MW)
300
< User Input
Retrofit Factor
B
1
< User Input (An ''average* retrofit has a factor = 1.0)
Heat Rate
C
(Btu'kWh)
9800
< User Input
NOx Rate
D
(lb/MMBtu'|
0.22
< User Input
SQ2 Ra te
E
(lb/MMBtu'|
2
< User Input
Type of Coal
F
Ģ 0.3 THEN UF = 0.25; ELSE UF = 0.15
Water Reqiired
N
(Ib/hr)
13358
MM 9
Heat Rate Penalty
Include in VOM? E
V
(%)
0.53
1175'N/TIOO
Aux Power
O
(%)
0.05
0.05 default val ue
Include in VOM? ~
Dilution Water Rate
P
(1000 gph)
1.60
N"0.12/1000
Urea Cost (50% wt solution)
Q
(Siton)
350
< User Input
Aux Power Cost
R
(S/kWh)
0.06
< User Input
Dilution Water Cost
S
(Si'kgal)
1
< User Input
Operating Labor Rate
T
(Stor)
60
< User Input (Labor cost including all benefits)
Replacement Coal Cost
U
(&WMBtu)
2
< User Input
Costs are all based on 2021 dollars
Capital Cost Calculation
Includes - Equipment installation, buldings, foundations, electrical, and retrofit difficulty
BTPB"G"253000"(A,H)A0.42;
(IF CFB then BT=0.75, ELSE BT=1)
IF E * 3 AND F=Biturninou5, THEN eQOOQWtA'G'H^Je. ELSE 0
BT* (L*Q. 12),448000,(A)*0.33;
(IF CFB then BT=0.75, ELSE BT=1)
BMS + BMA + BMB
BMS ($} =
BMA ($) =
BMB ($} =
BM(5) =
BM (5/KW) =
Total Project Cost
A1 = 10% of BM
A2 = 10% of BM
A3 = 10% of BM
CECC {$} = BM+A1+A2+A3
CECC ($,'kW) =
Example
$
$
$
$
2,753,000 SNCR (injectors, bJowers, DCS. reagent system) cost
5,417,000
8,170,000
27
817,000
817,000
817,000
10,621,000
35
Air heater modificationSQ3 control (Bituminous only & > 31b)'MMBtu)
Balance c# plant cost (piping, site upgrades, water treatment for the dilution
water, etc...)
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 kVV
B1 =5% of CECC
TPC' ($} - Includes Owner's Costs = CECC + B1
TPC' ($.'kW) - Includes Owner's Costs =
11,152,000
37
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
B2 = D% of (CECC + B1)
TPC ($) = CECC + B1
TPC ($/kW) =
$ - AFUDC (Zero for less than 1 year engineering and construction cycle}
$ 11r152,000 Total project cost
37 Total project cost per kW
6
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final February 2023
Sargent S. Luridly
Coal-Fired SNCR Cost Development Methodology
Variable
Designation
Units
Value
rji^jeotlsl ģ
Calculation
Boiler Type
BT
< User Input
Unit Size
A
(MW)
300
< User Input
Retrofit Factor
B
1
< User Input (An "average" retrofit has a factor = 1.0)
Heal Rate
C
(BtiVkWm
9800
< User Input
NOx Rate
D
(Itu'MMBtu)
0.22
< User Input
S02 Rate
E
(Ib/MMBtu)
2
< User Input
Type of Coal
F
lUmnnm ~
< User Input
Coal Factor
G
1
Bit=1.0, PRB=1.05, Li{]=1.07
Heat Rate Factor
H
0.98
a 10,000
Heat Input
1
(Btu/hrJ
2.94E+09
A'CMQOO
NOx Removal Efficiency
K
(%)
25
MQx Removed
L
(Ibtar)
162
D*l/10"e"K/100
Urea Rate (100%)
M
(Ib/hr)
703
UUF/46'30; IF Boiler Type = CFB OR D > 0.3 THEN UF = 0.25; ELSE UF = 0.15
Water Required
N
(Ih/hr)
13358
M'18
Heat Rate Penalty
Include in VOM? 13
V
(%}
0.53
1175W100
Aux Power
Include in VOM? ~
O
Ģ%)
0.05
0.05 default value
Di lution Water Rate
P
dOOOflph)
1.60
N'D.12'1000
Lfcea Cost (50% wt sol ution)
Q
f&tonl
350
< User Input
Aux Power Cost
R
(S/kWh)
0.06
< User Input
Di lution Water Cost
S
(Sftgal)
1
< User Input
Operating Labor Rate
T
($^hr)
60
< User Input (Labor cost indudi nq all benefits)
Replacement Coal Cost
U
($,'MMBtu)
2
< User Input
Fixed O&M Cost
FOMO (SfltW yr} = (No opera'.or time a55umed)"208Q"T,'(A"1000)
FOMM (WW yr) = BM"D.012/(B"A'1000)
FOMA jĢW yr} = 0.03'{FOMO+0.4*FOMM)
FOM (Si'kW yr} = FOMO + FOMM + FOMA
Variable O&M Cost
VOMR (S/MWh) = M'Q/A/1000
VOMM ($/MWh) = P-S/A
VOMP (S/MWh) = O*RM0
VOMB ($IMWh) = 0.001175'H'UIA
VOM (Ji'MWh) = VOMR + VOMM + VOMP + VOMB
Costs are all based on 2021 dollars
$
$ 0.33
$ 0.00
$ 0.33
$ 0.B2
$ 0.01
$ 0.03
$ 0.10
$ 0.96
Fixed O&M additional operating labor costs
Fixed O&M additional maintenance material and labor costs
Fixed O&M additional adrri nistrative labor costs
Total Fixed O&M costs
Variable O&M costs for Urea
Vari able O&M costs for dil ution water
Variable O&M costs for additional auxiliary power required.
Variable O&M costs for heat rate increase due- to water irgected into the
boiler
7
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project
Final
No. 13527-002
February 2023
Stirgent S. I_uncily
Coal-Fired SNCR Cost Development Methodology
Table 2. Example Complete Cost Estimate for an SNCR System Installed on a CFB boiler
Variable
Designation
Units
Value
Calculation
Boiler Type
BT
CFB ģ
< User Input
Unit Size
A
(MW)
500
< User Input
Retrofit Factor
B
1
< User Input (An 'average* retrofit has a factor = 1.0)
Heat Rate
C
(Bfei'kWh)
9800
< User Input
NOx Rate
D
(Ih/MMBtu)
0.22
< User Input
S02 Rate
E
(Ib/MMBtu)
2
< User Input
Type of Coal
F
IttmnCHA ~
< User Input
Coal Factor
G
1
Bit=1.Q, PRB=1.05, Ug=1.07
Heat Rate Factor
H
0.98
C/10,000
Heat Input
1
(BtuFhr)
4.90E+09
A'C'1000
NOx Removal Efficiency
K
(%)
25
NOx Removed
L
(Ihfhr)
270
D'l/IO^'K/IDG
Urea Rate (100%)
M
(Ifa/hr)
703
L'UF/46'30; IF Boiler Type = CFB OR D > 0.3 THEN UF = 0.25; ELSE UF = 0.15
Water Required
N
(Ibfhr)
13368
M'1S
Heat Rate Penalty
V
(%>
0.32
1 175'N/T1Q0
Include in VOM? ~
Aux Power
O
<*)
0.05
0.05 default value
Include in VOM? Ld
Dilution Water Rate
P
(1000 gph)
1.00
N'D. 12/1000
Urea Cost l'50% wt solution)
Q
(Srton)
350
< User Input
Aux Power Cost
R
(SflcWh)
0.06
< User Input
Dilution Water Cost
S
(Si'kgal)
1
< User Input
Operating Labor Rate
T
($/Hr)
60
< User Input (Labor cost including all benefits)
Replacement Coal Cost
U
(ftMMBtu)
2
< User Input
Costs are all based on 2021 dollars
Capital Cost Calculation
Includes - Equipment, installation, txildings, foundations, electrical, and retrofit difficulty
BTB*G,2530GD"(A'H)A0.42;
(IF CFB then BT=0.75. ELSE BT=1)
IF E * 3 AND F=Bituminous, THEN e0OOOW(A'G*H)*O.78. ELSE 0
BTfL^O. 12)"44800Q'tA)A0.33;
(IF CFB then BT=0.75, ELSE BT=1)
BMS + BMA + BMB
BMS ($) =
BMA ($} =
BMB ($} =
BM ($)
BM (S/KW) =
Total Project Cost
At = 10% of BM
A2 = 1 D% of BM
A3 = 1 D% of BM
CECC {$) = BM+A1+A2+A3
CECC ($/kW) =
Example
$
$
$
$
2,550,000 SNCR (injectors, blowers, DCS. reagent system) cost
Air heater modification! S03 control (Bituminous only & > 3ih/MMBtu)
nnn Balance of plant cost (piping, site upgrades, water treatment for the dilution
Ot1 lo.UULT , , .
water, etc...)
Total bare module cost including retrofit factor
Base cost per kW
7,672,000
15
787,000
767,000
767,000
9,973,000
20
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
IPC' {$) - Includes Owner's Costs = CECC + B1
IPC (I'kW) - Includes Owner's Costs =
10.472,000
21
Owners costs including all "home office" costs (owners engineering,
management and procurement activities)
Total project cost without AFUDC
Total project cost per kW without AFUDC
B2 = 0% of (CECC + B1)
TPC ($) = CECC + B1
TPC ($<'kW| =
$ - AFUDC (Zero for less than 1 year engineering and construction cycle)
$ 10,472,000 Total project cost
21 Total project cost per kW
8
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IPM Model - Updates to Cost and
Performance for APC Technologies
Project No. 13527-002
Final February 2023
Sargent S. Luridly
Coal-Fired SNCR Cost Development Methodology
Variable
Designation
Units | Value | Calculation
Boiler Type-
BT
CF6 ģ
< User Input
Unit Size
A
(MW)
500
< User Input
Retrofit Factor
B
1
< User Input (An "averaoe1 relrofit has a factor = 1.0}
Heal Rate
C
(Btu'kWh)
9800
< User Input
NQx Raite
D
(Ib/MMBtu)
0.22
< User Input
S02 Rate
E
(Ib/MMBtu!
2
< User Input
Type of Coal
F
SOfwnui ~
< User Input
CoaJ Factor
G
1
Bit=1.G, FRB=1.05, Liq=1.07
Heal Rate Factor
H
B.SB
C/10,000
Heal Input
1
(Btu/hr)
4.00E+09
A'CMCOO
NOx Removal Efficiency
K
(%)
25
NQx Removed
L
(IfcVhr'i
270
~ŽI/10*6K/1D0
Urea Rale (100%)
M
ilb,'hr}
703
LAlF/46,30; IF Boiler Type = CFB OR D > D.3 THEN UF = 0.25; ELSE UF = 0.15
Water Requred
N
(!Uhr>
13358
M"ie
Heal Rate Penalty
Include in VOM? El
V
(*)
0.32
1175TW1DQ
Aux Power
Include in VOM? ~
O
0.05
C.05 default value
Dilution Water Rate
P
(1KB gph)
1.00
N'0.12/1000
Urea Cost (50% wt solution)
Q
(3,tonl
350
< User Input
Aux Power Cost
R
($/kWh)
0.06
< User Input
D'lution Water Cost
S
(SiloqaO
1
< User Input
Operating Labor Rate
T
60
< User Input (Labor cost including all benefits)
Replacement Coal Cost
U
($/MMBtu)
2
< User Input
Fixed O&M Cost
FOMO (VkW yr) = (No operator time assumed)'2080"T/(A" 1DOO)
FOMM yr) = SWJ'O.Ot2r(B,A,1DOO}
FOMA ($/kW yr) = O.IJ3*
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