Cost and Performance Baseline for Fossil Energy Plants National Energy Technology Laboratory May 15, 2007 Revised August 2007 Final Results

Revised 7/27/07 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.

Revised 7/27/07 3 Objective  Determine cost and performance estimates of near-term commercial offerings for power plants both with and without current technology for CO 2 capture  Consistent design requirements  Up-to-date performance and capital cost estimates  Technologies built now and deployed by  Provides baseline costs and performance  Compare existing technologies  Guide R&D for advancing technologies within the FE Program

Revised 7/27/07 4 Study Matrix Plant Type ST Cond. (psig/°F/°F) GT Gasifier/ Boiler Acid Gas Removal/ CO 2 Separation / Sulfur Recovery CO 2 Cap IGCC 1800/1050/1050 (non-CO 2 capture cases) 1800/1000/1000 (CO 2 capture cases) F Class GE Selexol / - / Claus Selexol / Selexol / Claus90% CoP E-Gas MDEA / - / Claus Selexol / Selexol / Claus88% 1 Shell Sulfinol-M / - / Claus Selexol / Selexol / Claus90% PC 2400/1050/1050Subcritical Wet FGD / - / Gypsum Wet FGD / Econamine / Gypsum90% 3500/1100/1100Supercritical Wet FGD / - / Gypsum Wet FGD / Econamine / Gypsum90% NGCC2400/1050/950 F Class HRSG - / Econamine / -90% GEE – GE Energy CoP – Conoco Phillips 1 CO 2 capture is limited to 88% by syngas CH 4 content

Revised 7/27/07 5 Design Basis: Coal Type Illinois #6 Coal Ultimate Analysis (weight %) As Rec’dDry Moisture Carbon Hydrogen Nitrogen Chlorine Sulfur Ash Oxygen (by difference) HHV (Btu/lb)11,66613,126

Revised 7/27/07 6 Environmental Targets Pollutant IGCC 1 PC 2 NGCC 3 SO lb/MMBtu lb/MMBtu < 0.6 gr S /100 scf NOx 15 ppmv 15% O lb/MMBtu % O 2 PM lb/MMBtu lb/MMBtu Negligible Hg > 90% capture 1.14 lb/TBtu Negligible 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

Revised 7/27/07 7 Economic Assumptions Startup 2010 Plant Life (Years) 20 Capital Charge Factor, % High Risk (All IGCC, PC/NGCC with CO 2 capture) 17.5 Low Risk (PC/NGCC without CO 2 capture) 16.4 Dollars (Constant) 2007 Coal ($/MM Btu) 1.80 Natural Gas ($/MM Btu) 6.75 Capacity Factor IGCC 80 PC/NGCC 85

Revised 7/27/07 8 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) 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 Parsons Vendor sources where available  Follow DOE Analysis Guidelines 2. Cost Estimation  Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.)  Sources for cost estimation Parsons Vendor sources where available  Follow DOE Analysis Guidelines

Revised 7/27/07 9 Study Assumptions  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 CO 2 capture used water injection for cooling (instead of syngas recycle)  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 CO 2 capture cases, CO 2 was compressed to 2200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,055 feet and monitored for 80 years  CO 2 transport, storage and monitoring (TS&M) costs were included in the levelized cost of electricity (COE)

Revised 7/27/07 10 IGCC Power Plant Current State-of-the-Art

Revised 7/27/07 11 Current Technology IGCC Power Plant Emission Controls: PM: Water scrubbing and/or candle filters to get lb/MMBtu NOx: N 2 dilution to ~120 Btu/scf LHV to get 15 O 2 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 (non-CO 2 capture cases) 1800 psig/1000°F/1000°F (CO 2 capture cases) Emission Controls: PM: Water scrubbing and/or candle filters to get lb/MMBtu NOx: N 2 dilution to ~120 Btu/scf LHV to get 15 O 2 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 (non-CO 2 capture cases) 1800 psig/1000°F/1000°F (CO 2 capture cases)

Revised 7/27/07 12 GE Energy Radiant Coal Slurry 63 wt.% 95% O 2 Slag/Fines Syngas 410°F, 800 Psia Composition (Mole%): H 2 26% CO 27% CO 2 12% H 2 O 34% Other 1% H 2 O/CO = 1.3 Design: Pressurized, single-stage, downward firing, entrained flow, slurry feed, oxygen blown, slagging, radiant and quench cooling Note: All gasification performance data estimated by the project team to be representative of GE gasifier To Acid Gas Removal or To Shift

Revised 7/27/07 13 ConocoPhillips E-Gas™ Coal Slurry 63 wt. % Stage 2 95 % O 2 Slag Quench Char Slag/Water Slurry Syngas 1,700°F, 614 psia Composition (Mole%): H 2 26% CO 37% CO 2 14% H 2 O 15% CH 4 4% Other 4% H 2 O/CO = 0.4 (0.78) (0.22) Stage 1 2,500 o F 614 Psia To Fire-tube boiler Design: Pressurized, two-stage, upward firing, entrained flow, slurry feed, oxygen blown, slagging, fire-tube boiling syngas cooling, syngas recycle Note: All gasification performance data estimated by the project team to be representative of an E-Gas gasifier To Acid Gas Removal or To Shift

Revised 7/27/07 14 Shell Gasification Syngas 350°F, 600 Psia Composition (Mole%): H 2 29% CO 57% CO 2 2% H 2 O 4% Other 8% H 2 O/CO = 0.1 Dry Coal Design: Pressurized, single-stage, downward firing, entrained flow, dry feed, oxygen blown, convective cooler Convective Cooler Soot Quench & Scrubber 95% O 2 HP Steam 650 o F Steam Source: “The Shell Gasification Process”, Uhde, ThyssenKrupp Technologies Syngas Quench 2 Notes: 1.All gasification performance data estimated by the project team to be representative of Shell gasifier. 2.CO 2 capture incorporates full water quench instead of syngas quench. To Acid Gas Removal or To Shift HP Steam Slag Gasifier 2,700 o F 615 psia

Revised 7/27/07 15 IGCC Performance Results No CO 2 Capture GE EnergyE-GasShell Gross Power (MW) Auxiliary Power (MW) Base Plant Load Air Separation Unit Gas Cleanup431 Total Aux. Power (MW) Net Power (MW) Heat Rate (Btu/kWh)8,9228,6818,304 Efficiency (HHV)

Revised 7/27/07 16 IGCC Economic Results No CO 2 Capture GE EnergyE-GasShell Plant Cost ($/kWe) 1 Base Plant1,3231,2721,522 Air Separation Unit Gas Cleanup Total Plant Cost ($/kWe)1,8131,7331,977 Capital COE (¢/kWh) Variable COE (¢/kWh) Total COE 2 (¢/kWh) Total Plant Capital Cost (Includes contingencies and engineering fees) 2 January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/10 6 Btu

Revised 7/27/07 17 IGCC Power Plant With CO 2 Capture

Revised 7/27/07 18 Current Technology IGCC Power Plant with CO 2 Scrubbing Emission Controls: PM: Water scrubbing and/or candle filters to get lb/MMBtu NOx: N 2 dilution to ~120 Btu/scf LHV to get 15 O 2 SOx: Selexol AGR removal of sulfur to < 28 ppmv H 2 S in syngas 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/1000°F/1000°F Emission Controls: PM: Water scrubbing and/or candle filters to get lb/MMBtu NOx: N 2 dilution to ~120 Btu/scf LHV to get 15 O 2 SOx: Selexol AGR removal of sulfur to < 28 ppmv H 2 S in syngas 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/1000°F/1000°F

Revised 7/27/07 19 Water-Gas Shift Reactor System H 2 O/CO Ratio 1 GE1.3 E-Gas0.4 Shell1.5 Design:  Haldor Topsoe SSK Sulfur Tolerant Catalyst  Up to 97.5% CO Conversion  2 stages for GE and Shell, 3 stages for E-Gas  H 2 O/CO = 2.0 (Project Assumption)  Overall  P = ~30 psia 775 o F 450 o F 500 o F 450 o F Cooling Relative HP* Steam Flow Steam Turbine Output (MW) GE E-Gas Shell o F Steam H 2 O + COCO 2 + H 2 *High Pressure Steam 1 Prior to shift steam addition

Revised 7/27/07 20 IGCC Performance Results GE Energy CO 2 CaptureNOYES Gross Power (MW) Auxiliary Power (MW) Base Plant Load23 Air Separation Unit Gas Cleanup/CO 2 Capture418 CO 2 Compression-27 Total Aux. Power (MW) Net Power (MW) Heat Rate (Btu/kWh)8,92210,505 Efficiency (HHV) Energy Penalty CO 2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO 2 Capture  in ASU air comp. load w/o CT integration Steam for Selexol Includes H 2 S/CO 2 Removal in Selexol Solvent

Revised 7/27/07 21 IGCC Performance Results GE EnergyE-GasShell CO 2 CaptureNOYESNOYESNOYES Gross Power (MW) Auxiliary Power (MW) Base Plant Load Air Separation Unit Gas Cleanup/CO 2 Capture CO 2 Compression Total Aux. Power (MW) Net Power (MW) Heat Rate (Btu/kWh)8,92210,5058,68110,7578,30410,674 Efficiency (HHV) Energy Penalty CO 2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO 2 Capture

Revised 7/27/07 22 IGCC Economic Results GE EnergyE-GasShell CO 2 CaptureNOYESNOYESNOYES Plant Cost ($/kWe) 1 Base Plant1,3231,5661,2721,5921,5221,817 Air Separation Unit Gas Cleanup/CO 2 Capture CO 2 Compression Total Plant Cost ($/kWe)1,8132,3901,7332,4311,9772,668 Capital COE (¢/kWh) Variable COE (¢/kWh) CO 2 TS&M COE (¢/kWh) Total COE 2 (¢/kWh) Increase in COE (%) $/tonne CO 2 Avoided Total Plant Capital Cost (Includes contingencies and engineering fees) 2 January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/10 6 Btu

Revised 7/27/07 23 Comparison to PC and NGCC Current State-of-the-Art

Revised 7/27/07 24 Current Technology Pulverized Coal Power Plant* 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 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 * Orange Blocks Indicate Unit Operations Added for CO 2 Capture Case

Revised 7/27/07 25 Current Technology Natural Gas Combined Cycle* NOx Control: LNB + SCR to maintain % O 2 Steam Conditions: 2400 psig/1050°F/950°F NOx Control: LNB + SCR to maintain % O 2 Steam Conditions: 2400 psig/1050°F/950°F * Orange Blocks Indicate Unit Operations Added for CO 2 Capture Case HRSG MEA Combustion Turbine CO 2 Compressor Stack Direct Contact Cooler Blower Natural Gas AirCooling Water Stack Gas CO psig Reboiler Steam Condensate Return

Revised 7/27/07 26 PC and NGCC Performance Results SubcriticalSupercriticalNGCC CO 2 CaptureNOYESNOYESNOYES Gross Power (MW) Base Plant Load Gas Cleanup/CO 2 Capture CO 2 Compression Total Aux. Power (MW) Net Power (MW) Heat Rate (Btu/kWh)9,27613,7248,72112,5346,7197,813 Efficiency (HHV) Energy Penalty CO 2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO 2 Capture

Revised 7/27/07 27 PC and NGCC Economic Results SubcriticalSupercriticalNGCC CO 2 CaptureNOYESNOYESNOYES Plant Cost ($/kWe) 1 Base Plant1,3021,6891,3451, Gas Cleanup (SOx/NOx) CO 2 Capture CO 2 Compression Total Plant Cost ($/kWe)1,5492,8951,5752, ,172 Capital COE (¢/kWh) Variable COE (¢/kWh) CO 2 TS&M COE (¢/kWh) Total COE 2 (¢/kWh) Increase in COE (%) $/tonne CO 2 Avoided Total Plant Capital Cost (Includes contingencies and engineering fees) 2 January 2007 Dollars, 85% Capacity Factor, 16.4% (no capture) 17.5% (capture) Capital Charge Factor, Coal cost $1.80/10 6 Btu, Natural Gas cost $6.75/10 6 Btu

Revised 7/27/07 28 Environmental Performance Comparison IGCC, PC and NGCC

Revised 7/27/07 29 Criteria Pollutant Emissions for All Cases

Revised 7/27/07 30 CO 2 Emissions for All Cases

Revised 7/27/07 31 Raw Water Usage Comparison IGCC, PC and NGCC

Revised 7/27/07 32 Raw Water Usage per MW net (Absolute)

Revised 7/27/07 33 Raw Water Usage per MW net (Relative to NGCC w/ no CO 2 Capture)

Revised 7/27/07 34 Economic Results for All Cases

Revised 7/27/07 35 CO 2 Mitigation Costs

Revised 7/27/07 36 Total Plant Cost Comparison Total Plant Capital Cost includes contingencies and engineering fees

Revised 7/27/07 37 Cost of Electricity Comparison January 2007 Dollars, Coal cost $1.80/10 6 Btu. Gas cost $6.75/10 6 Btu cents/kWh ($2007)

Revised 7/27/07 38 Highlights

Revised 7/27/07 39 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

Revised 7/27/07 40 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 CO 2, but at significant increase in COE  Total Plant Cost: IGCC ~20% higher than PC capex  NGCC: $554/kW  PC: $1561/kW (average)  IGCC: $1841/kW (average)  Total Plant Cost with Capture: PC > IGCC capex  NGCC: $1169/kW  IGCC: $2496/kW (average)  PC: $2788/kW (average)

Revised 7/27/07 41 Results Highlights: COE  20 year levelized COE: PC lowest cost generator  PC: 64 mills/kWh (average)  NGCC: 68 mills/kWh  IGCC: 78 mills/kWh (average)  With CCS: IGCC lowest coal-based option  NGCC: 96 mills/kWh  IGCC: 105 mills/kWh (average)  PC: 116 mills/kWh (average)  Breakeven LCOE* when natural gas price is:  No Capture IGCC: $7.99/MMBtu PC: $6.15/MMBtu  With Capture IGCC: $7.73/MMBtu PC: $8.87/MMBtu * At baseline coal cost of $1.80/MMBtu

Revised 7/27/07 42 Summary Table for All Cases

Revised 7/27/07 43 Summary Table