1. Cost and Performance Baseline for Fossil Energy Plants – Volume 1 Bituminous Coal and Natural Gas to Electricity
Revision 2 – November 2010
Revision 1 – August 2007
Original – May 2007
U.S. Department of Energy
National Energy Technology Laboratory

2. Disclaimer
This presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

3. Objective
Determine cost and performance estimates of near-term commercial offerings for power plants both with and without current technology for CO2 capture
Consistent design requirements
Up-to-date performance and capital cost estimates
Technologies built now and deployed in the near term
Provides baseline costs and performance
Compare existing technologies
Guide R&D for advancing technologies within the FE Program

4. Study Matrix F Class Plant Type ST Cond. (psig/°F/°F) GT Gasifier/
Boiler
Acid Gas Removal/
CO2 Separation / Sulfur Recovery
CO2
Cap
IGCC
1800/1050/1050 (non-CO2 capture cases)
1800/1000/1000
(CO2 capture cases)
F Class
GEE
Selexol / - / Claus
Selexol / Selexol / Claus
90%
CoP
E-Gas
MDEA / - / Claus
Shell
Sulfinol-M / - / Claus PC
2400/1050/1050
Subcritical
Wet FGD / - / Gypsum
Wet FGD / Econamine / Gypsum
3500/1100/1100
Supercritical
NGCC
HRSG
- / Econamine / -
Total 14 Cases. 3 Different gasifiers, subcritical and supercritical PC steam plants, Natural gas and SNG
GEE – GE Energy
CoP – Conoco Phillips

5. Design Basis: Coal Type
Illinois #6 Coal Ultimate Analysis (weight %)
As Rec’d
Dry
Moisture
11.12
Carbon
63.75
71.72
Hydrogen
4.50
5.06
Nitrogen
1.25
1.41
Chlorine
0.29
0.33
Sulfur
2.51
2.82
Ash
9.70
10.91
Oxygen (by difference)
6.88
7.75
100.0
HHV (Btu/lb)
11,666
13,126
Recent data from the Henry Hub Spot Price index indicate a natural gas price in the $8.80/MMBtu range.
This will have a tremendous affect on our results, since it is ~50% higher than our cost.
We should perform a sensitivity analysis of fuel price (including coal) vs. LCOE

6. Environmental Targets
Pollutant
IGCC1
PC2
NGCC3
SO2
lb/MMBtu
0.085 lb/MMBtu
< 0.6 gr S /100 scf
NOx
15 ppmv 15% O2
lb/MMBtu
2.5 15% O2 PM
lb/MMBtu
0.013
lb/MMBtu
Negligible Hg
> 90% capture
lb/TBtu
1 Based on EPRI’s CoalFleet User Design Basis Specification for Coal-Based IGCC Power Plants
2 Based on BACT analysis, exceeding new NSPS requirements
3 Based on EPA pipeline natural gas specification and 40 CFR Part 60, Subpart KKKK

7. 5 Year Construction Period 3 Year Construction Period
Economic Assumptions
First Year of Capital Expenditure
Effective Levelization Period (Years) (PC & IGCC)
33 (NGCC)
5 Year Construction Period
3 Year Construction Period
High Risk
Low Risk
Capital Charge Factor
12.4%
11.6%
11.1%
10.5%
Dollars
Coal ($/MM Btu)
Natural Gas ($/MM Btu)
Capacity Factor
IGCC
PC/NGCC
No fancy economic tricks employed.
Showing that assumptions are ‘in-line’ with what makes sense and what studies have reported.
Further detailed assumptions are available and a detailed list can be provided for each case. (I will have a list case by case assumptions on hand or will take peoples information and send them the details).
Grassroots plant unless noted otherwise

8. Systems Analyses Categorization
Technical Approach
Systems Analyses Categorization
STUDY CATEGORY I II
III
Order of Magnitude Estimate (+/- >50% Accuracy)
Very little project-specific definition
Rough scaling of previous related but dissimilar analyses
“Back-of-the-envelope” analyses
Concept Screening (+/- 50% Accuracy)
Preliminary mass and energy balances
Modeling and simulation of major unit operations
Factored estimate based on previous similar analyses
Budget Estimate (+30% / -15% Accuracy)
Thorough mass and energy balances
Detailed process and economic modeling
Estimate based on vendor quotes, third-party EPC firms

9. Technical Approach 1. Extensive Process Simulation (ASPEN)
All major chemical processes and equipment are simulated
Detailed mass and energy balances
Performance calculations (auxiliary power, gross/net power output)
2. Cost Estimation
Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.)
Sources for cost estimation
WorleyParsons
Vendor sources where available
Follow DOE Analysis Guidelines

10. Study Assumptions IGCC capacity factor = 80% w/ no spare gasifier
Capacity Factor assumed to equal Availability
IGCC capacity factor = 80% w/ no spare gasifier
PC and NGCC capacity factor = 85%
GE gasifier operated in radiant/quench mode
Shell gasifier with CO2 capture used water injection for cooling (instead of syngas cooler)
Nitrogen dilution was used to the maximum extent possible in all IGCC cases and syngas humidification/steam injection were used only if necessary to achieve approximately 120 Btu/scf syngas LHV
In CO2 capture cases, CO2 was compressed to 2200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,000 feet and monitored for 80 years
CO2 transport, storage and monitoring (TS&M) costs were included in the levelized cost of electricity (COE)

11. Current State-of-the-Art
IGCC Power Plant
Current State-of-the-Art

12. Current Technology IGCC Power Plant without CO2 Capture
Emission Controls:
PM: Water scrubbing and/or candle filters to get lb/MMBtu
NOx: N2 dilution to ~120 Btu/scf LHV to get 15 O2
SOx: AGR design target of lb/MMBtu; Claus plant with tail gas recycle for ~99.8% overall S recovery
Hg: Activated carbon beds for ~95% removal
Advanced F-Class CC Turbine: 232 MWe
Steam Conditions: 1800 psig/1050°F/1050°F
Three Additional Processes
CO2 Pressure Loss
Thermal Efficiency Loss
*Syngas Cooling

13. Gasifiers GEE Texaco Gasifier ConocoPhillips Shell SCGP E-Gas
Slag
Fuel Gas
Dry Coal O2 HP
Steam
Gasifier Sweet Cold Gas Efficiency ~75% HHV
Radiant Syngas Cooler w/ outlet

14. IGCC Power Plant
With CO2 Capture

15. Current Technology IGCC Power Plant with CO2 Capture
Emission Controls:
PM: Water scrubbing and/or candle filters to get lb/MMBtu
NOx: N2 dilution to ~120 Btu/scf LHV to get 15 O2
SOx: Selexol AGR removal of sulfur to < 6 ppmv H2S in syngas
Claus plant with tail gas recycle for ~99.8% overall sulfur recovery
Hg: Activated carbon beds for ~95% removal
Advanced F-Class CC Turbine: 232 MWe
Steam Conditions: 1800 psig/1000°F/1000°F
Three Additional Processes
CO2 Pressure Loss
Thermal Efficiency Loss
*Syngas Cooling
Why is the reheat for the steam cycle for the CO2 Capture cases only 1000F instead of 1050F?

16. Water-Gas Shift Reactor System Steam as % of Main Steam Enthalpy1
Design:
Sulfur Tolerant Catalyst
Up to 98.5% CO Conversion
2 stages for GE and Shell, 3 stages for E-Gas
H2O/CO = 1.8 – 2.25 (to achieve 90% CO2 capture)
Steam
Steam oF
400oF
H2O/CO Ratio
1.8 – 2.25
800psia
550oF
Add approximate shift cost (total and % of total cost and capture cost).
Add steam producing arrows.
Steam as % of Main Steam Enthalpy1
22 – 40
H2O + CO CO2 + H2
1 Recovered from Heat Integration

17. IGCC Performance Results
GE Energy
CO2 Capture NO
YES
Gross Power (MW)
748
734
Auxiliary Power (MW)
Base Plant Load 25 26
Air Separation Unit 98
115
Gas Cleanup/CO2 Capture 3 19
CO2 Compression - 31
Total Aux. Power (MW)
126
191
Net Power (MW)
622
543
Heat Rate (Btu/kWh)
8,756
10,458
Efficiency (HHV)
39.0
32.6
Energy Penalty1
6.4
Steam for Selexol
h in ASU air comp. load w/o CT integration
Includes H2S/CO2 Removal in Selexol Solvent
1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture

18. IGCC Performance Results
GE Energy
E-Gas
Shell
CO2 Capture NO
YES
Gross Power (MW)
748
734
738
704
737
673
Auxiliary Power (MW)
Base Plant Load 25 26 24 28 22
Air Separation Unit 98
115 86
111 85
103
Gas Cleanup/CO2 Capture 3 19 20 1
CO2 Compression - 31 30
Total Aux. Power (MW)
126
191
113
190
108
177
Net Power (MW)
622
543
625
514
629
497
Heat Rate (Btu/kWh)
8,756
10,458
8,585
10,998
8,099
10,924
Efficiency (HHV)
39.0
32.6
39.7
31.0
42.1
31.2
Energy Penalty1
6.4
8.7
10.9
1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture

19. Total Plant Cost, $/kWe (2007$)1
IGCC Economic Results
GE Energy
E-Gas
Shell
CO2 Capture NO
YES
Total Plant Cost, $/kWe (2007$)1
Base Plant
1,426
1,708
1,423
1,804
1,719
2,164
Air Separation Unit
312
429
281
437
285
421
Gas Cleanup/CO2 Capture
249
503
209
500
213
521
CO2 Compression - 71 76 75
Total
1,987
2,711
1,913
2,817
2,217
3,181
COE , $/MWh (2007$)
Capital
43.4
59.1
41.7
61.5
48.2
69.2
Fixed
11.3
14.8
11.1
15.5
12.1
16.7
Variable
7.3
9.3
7.2
9.8
7.8
9.9
Fuel
14.3
17.1
14.0
18.0
13.3
17.9
CO2 TS&M
0.0
5.3
5.6
5.7
Total2
76.3
105.7
74.0
110.4
81.3
119.5
CO2 Avoided, $/tonne (2007$)
Same technology 43 54 61
Compared to SCPC 66 73 86
1Total Plant Capital Cost (Includes contingencies and engineering fees but not owner’s costs)
280% Capacity Factor

20. Comparison to PC and NGCC Current State-of-the-Art

21. Current Technology Pulverized Coal Power Plant*
*Orange Blocks Indicate Unit Operations Added for CO2 Capture Case
PM Control: Baghouse to achieve lb/MMBtu (99.8% removal)
SOx Control: FGD to achieve lb/MMBtu (98% removal)
NOx Control: LNB + OFA + SCR to maintain 0.07 lb/MMBtu
Mercury Control: Co-benefit capture ~90% removal
Steam Conditions (Sub): 2400 psig/1050°F/1050°F
Steam Conditions (SC): 3500 psig/1100°F/1100°F
Challenge: Large volume of dilute flue gas (12.8 Mol % CO2) containing low levels of SO2, NOx and Particulates.
Sox control to 10 ppm for CO2 Capture Cases (Uses a polishing unit)

22. Current Technology Natural Gas Combined Cycle*
*Orange Blocks Indicate Unit Operations Added for CO2 Capture Case
Natural Gas
Direct Contact
Cooler
HRSG
Air
Cooling Water
Combustion Turbine
Stack Gas
Blower
Reboiler Steam
MEA
Stack
Condensate Return
CO2
2200 psig
Challenge: Large volume of dilute flue gas (12.8 Mol % CO2) containing low levels of SO2, NOx and Particulates.
Sox control to 10 ppm for CO2 Capture Cases (Uses a polishing unit)
CO2
Compressor
NOx Control: LNB + SCR to maintain % O2
Steam Conditions: 2400 psig/1050°F/1050°F

23. PC and NGCC Performance Results
Subcritical
Supercritical
NGCC
CO2 Capture NO
YES
Gross Power (MW)
583
673
580
663
565
511
Base Plant Load 28 45 25 41 10 12
Gas Cleanup/CO2 Capture 5 29 27
CO2 Compression - 49 15
Total Aux. Power (MW) 33
123 30
113 37
Net Power (MW)
550
555
474
Heat Rate (Btu/kWh)
9,277
13,046
8,687
12,002
6,798
7,968
Efficiency (HHV)
36.8
26.2
39.3
28.4
50.2
42.8
Energy Penalty1
10.6
10.9
7.4
1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture

24. PC and NGCC Economic Results
Subcritical
Supercritical
NGCC
CO2 Capture NO
YES
Total Plant Cost, $/kWe (2007$)1
Base Plant
1,376
1,730
1,413
1,763
584
718
Gas Cleanup (SOx/NOx)
246
316
234
297 -
805
766
456
CO2 Compression 91 87 52
Total
1,622
2,942
1,647
2,913
1,226
Capital
31.2
60.2
31.7
59.6
10.1
22.3
Fixed
7.8
13.1
8.0
13.0
3.0
5.7
Variable
5.1
9.2
5.0
8.7
1.3
2.6
Fuel
15.2
21.3
14.2
19.6
44.5
52.2
CO2 TS&M
0.0
5.9
3.2
Total 2
59.4
109.7
58.9
106.6
85.9
CO2 Avoided, $/tonne (2007$)
Same technology 68 69 84
Compared to SCPC 75 36
1Total Plant Capital Cost (Includes contingencies and engineering fees but not owner’s costs)
285% Capacity Factor

25. Environmental Performance Comparison
IGCC, PC and NGCC

26. Criteria Pollutant Emissions for All Cases

27. CO2 Emissions for All Cases

28. Raw Water Withdrawal and Consumption Comparison
IGCC, PC and NGCC

29. Raw Water Withdrawal and Consumption per MWnet (Absolute)

30. Economic Results for All Cases

31. CO2 Avoided Costs

32. Plant Cost Comparison

33. Cost of Electricity Comparison
Coal cost $1.64/106Btu, Gas cost $6.55/106Btu

34. Highlights

35. NETL Viewpoint
Most up-to-date performance and costs available in public literature to date
Establishes baseline performance and cost estimates for current state of technology
Improved efficiencies and reduced costs are required to improve competitiveness of advanced coal-based systems
In today’s market and regulatory environment
Also in a carbon constrained scenario
Fossil Energy RD&D aimed at improving performance and cost of clean coal power systems including development of new approaches to capture and sequester greenhouse gases

36. Result Highlights: Efficiency & Capital Cost
Coal-based plants using today’s technology are efficient and clean
IGCC & PC: 39%, HHV (without capture on bituminous coal)
Meet or exceed current environmental requirements
Today’s capture technology can remove 90% of CO2, but at significant increase in COE
Total Overnight Cost: IGCC ~25% higher than PC
NGCC: $718/kW
PC: $2010/kW (average)
IGCC: $2505/kW (average)
Total Overnight Cost with Capture: PC > IGCC
NGCC: $1497/kW
IGCC: $3568/kW (average)
PC: $3590/kW (average)

37. Results Highlights COE ($2007)
COE: NGCC & PC lowest cost generators
NGCC: 59 $/MWh
PC: 59 $/MWh (average)
IGCC: 77 $/MWh (average)
With CCS: PC lowest coal-based option
NGCC: 86 $/MWh
PC: 108 $/MWh (average)
IGCC: 112 $/MWh (average)
Breakeven FY COE* when natural gas price is:
No Capture IGCC: $9.24/MMBtu PC: $6.59/MMBtu
With Capture IGCC: $9.80/MMBtu PC: $9.34/MMBtu
* At baseline coal cost of $1.64/MMBtu

38. Summary Table for All Cases

39. Summary Table