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

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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

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

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

Environmental Targets Pollutant IGCC1 PC2 NGCC3 SO2 0.0128 lb/MMBtu 0.085 lb/MMBtu < 0.6 gr S /100 scf NOx 15 ppmv (dry) @ 15% O2 0.07 lb/MMBtu 2.5 ppmv @ 15% O2 PM 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible Hg > 90% capture 1.14 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

5 Year Construction Period 3 Year Construction Period Economic Assumptions First Year of Capital Expenditure 2007 Effective Levelization Period (Years) 35 (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 2007 Coal ($/MM Btu) 1.64 Natural Gas ($/MM Btu) 6.55 Capacity Factor IGCC 80 PC/NGCC 85 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

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

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

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)

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

Current Technology IGCC Power Plant without CO2 Capture Emission Controls: PM: Water scrubbing and/or candle filters to get 0.0071 lb/MMBtu NOx: N2 dilution to ~120 Btu/scf LHV to get 15 ppmv @15% O2 SOx: AGR design target of 0.0128 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

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/ Quench/Scrubber @ outlet

IGCC Power Plant With CO2 Capture

Current Technology IGCC Power Plant with CO2 Capture Emission Controls: PM: Water scrubbing and/or candle filters to get 0.007 lb/MMBtu NOx: N2 dilution to ~120 Btu/scf LHV to get 15 ppmv @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?

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 700-870oF 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

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

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

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

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

Current Technology Pulverized Coal Power Plant* *Orange Blocks Indicate Unit Operations Added for CO2 Capture Case PM Control: Baghouse to achieve 0.013 lb/MMBtu (99.8% removal) SOx Control: FGD to achieve 0.085 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)

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 2.5 ppmvd @ 15% O2 Steam Conditions: 2400 psig/1050°F/1050°F

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

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

Environmental Performance Comparison IGCC, PC and NGCC

Criteria Pollutant Emissions for All Cases

CO2 Emissions for All Cases

Raw Water Withdrawal and Consumption Comparison IGCC, PC and NGCC

Raw Water Withdrawal and Consumption per MWnet (Absolute)

Economic Results for All Cases

CO2 Avoided Costs

Plant Cost Comparison

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

Highlights

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

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)

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

Summary Table for All Cases

Summary Table