EPRI Studies of IGCC Impacts – Emissions, Economics and Status

1. EPRI Studies of IGCC Impacts – Emissions, Economics and Status APPA New Generation Workshop August 1, 2007 Portland, Oregon Stu Dalton (sdalton@epri.com)Director, Generation

2. Other Wind Nuclear Coal Combustion Turbine Combined Cycle Retirements 1999 2001 2003 2005 2007 2009 2011 2013 2015 U.S. Capacity Additions – All TypesEvaluation of Announcements, 1999 to 2015, as of Fourth Qtr. 2006 Capacity, MW 60,000 50,000 40,000 30,000 20,000 10,000 0 -10,000 US Still depends on coal for >50% of KWh “Other” includes biomass, solar, hydro, internal combustion, geothermal, pet coke or any other type with announcements available to investigator. Capacity additions for each year prior to summer peak load season.Source: Forthcoming “Power Plant Update” prepared for EPRI Program 67 by EVA.

3. New Technology Deployment Curve for Coal Research Development Demonstration Deployment Mature Technology Advanced USCPC Plants 1400°F 1150°F+ CO2 Capture USCPC Plants 1150°F+ 1100°F IGCC Plants Anticipated Cost of Full-Scale Application Oxyfuel <1100°F 1050°F SCPC Plants CO2 Storage Time and level of maturity Not All Technologies at the Same Level of Maturity.

4. PC Fleet Average SCPC (1050°F Steam) w/ SCR USPC (1100°F Steam) w/ SCR IGCC (CoP E-Gas) w/ SCR NGCC (GE 7FB) w/ SCR 37% 38% 38% 39% 38% 39% 33% 50% 0.3 1.1 0.3 1.1 13 <0.1 nil <0.3 <0.5 <0.3 <0.5 6 <0.2 <0.1 1 <0.2 <0.2 <0.1 nil ~36% 80% 80% 90% -- 1,950 1,900 1,900 1,850 1,850 1,800 2,250 800 1,200 1,100 1,000 750 600 Coal Technology Options – w/o CO2 Capture (approximate data) NSPS = New Source Performance Standards PC = Pulvervized Coal SCPC = Supercritical PC USPC = Ultra-Supercritical IGCC = Integrated Gasification NGCC = Natural Gas NSPS 2006 Efficiency(HHV Basis) -- PRB Bit. SO2lb/MW-hr 1.4 NOXlb/MW-hr 1.0 Regulated Particulatelb/MW-hr 0.2 Mercury% Reduction -- CO2lb/MW-hr -- Non-Regulated Water Usagegal/MW-hr -- Relative Emissions Profiles for PC and IGCC are Very Low.

5. Plant Construction Costs Escalating

6. Capital Cost Estimates in Press Announcements and Submissions to PUCs 2006-7 — All Costs Are Way Up!

7. EPRI PC and IGCC Net Power Output With and Without CO2 Capture (Illinois #6 Coal)

8. EPRI PC and IGCC Capital Cost EstimatesWith and Without CO2 Capture (Illinois #6 Coal)(All IGCC and CCS cases have +10% Contingency for FOAK)

9. EPRI PC and IGCC Cost of ElectricityWith and Without CO2 Capture (Illinois #6 Coal)(All IGCC and CCS cases have +10% TPC Contingency for FOAK)

10. Basis for EPRI CoalFleet Program 2006 PC & IGCC Estimates Report 1013355 - Nth and FOAK (First of a Kind) • Total Plant Costs (TPC) include total field costs, engineering, and contingency. Historically, usually estimated for Nth-of-a-kind plants. • FOAK costs have not typically been included in previously reported estimates. However, in view of the current SOA and rapidly escalating costs, an additional 10% contingency has been added to the IGCC and CO2 capture designs. • TCR is also reported because it is believed to be closer to what is reported to PUCs in project submissions • For PC plants, EPRI has used a TCR/TPC multiplier of 1.16, and estimates are shown as range -5% to +10% • For IGCC plants, EPRI has used a TCR/TPC multiplier of 1.19, and estimates are shown as range -5% to +20% • Most previous studies reported cost of capture at the battery limit. In this report, we have added $10/mt for transportation, monitoring, and storage. So reported costs include CCS. • We recognize that the use of these additional contingencies, multipliers, and ranges for IGCC and CO2 capture is debatable. It is anticipated that they should be reduced as the technologies mature.

11. Challenge = Cost… Recent EPRI Economic Evaluations of SOA Coal Technologies with CO2 Capture and Sequestration (CCS) • At the current state-of-the art (SOA) there is no “silver bullet” technology for CCS. Technology selection depends on the location, coal, and application. • IGCC/Shift is least cost for bituminous coals • IGCC/Shift and PC plants with amine scrubbing have similar COE for high-moisture subbituminous coals • PC with amine scrubbing is least cost for lignites • CFBC can handle high-ash coals and other low-value fuels • Oxy-fuel (O2/CO2 Combustion) and chemical looping are technologies at developmental stage

12. Coal Characteristics Drive Technology Selection Nth Plant Economics

13. Integrated Gasification Combined Cycle (IGCC) With CO2 Removal Coal Sulfur CO2 GasCleanUp CCPowerBlock Air ASU Gasifier Shift Power O2 H2 Slag CO2 Sulfur Product Steam CO2 Compressor IGCC with CO2 Capture(e.g., FutureGen, Carson Hydrogen Power Project) CO2Recovery(e.g., Selexol 2nd stage) SulfurRecovery ShiftReactor Needs Space, Energy and Integration.

14. Coal Gasification Plants w/CO2 Capture (USA Today) • IGCC and CO2 removal offered commercially: • Have not operated in an integrated manner • Three U.S. non-power facilities and many plants in China recover CO2 • Coffeyville • Eastman • Great Plains • Great Plains recovered CO2 used for EOR: • 2.7 million tons CO2 per year • ~340 MWe if it were an IGCC The Great Plains Synfuels Plant http://www.dakotagas.com/Companyinfo/index.html Weyburn Pipeline http://www.ptrc.ca/access/DesktopDefault.aspx No Coal IGCC Currently Recovers CO2

15. Pulverized Coal With CO2 Capture “Today” ReduceNOx ReduceAsh ReduceSulfur CO2 to Use or Sequestration Fresh Water CO2 Removal e.g., MEA Coal PC Boiler Flue Gas to Stack SCR ESP FGD Air CO2 to Cleanup and Compression Fly Ash Gypsum/Waste Steam Turbine Cleaned Flue Gas to Atmosphere CO2Stripper • Pre-condition Flue Gas (Clean) less than 1 PPM SOx allowed? • Absorb CO2 • Strip CO2 • Requires significant energy Absorber Tower Flue Gas from Plant CO2 Stripper Reboiler Needs Space, Integration and Energy.

16. US Coal Units Operating Units w/ CO2 Capture (Today) • Three U.S. small plants in operation today: • Monoethanolamine (MEA) based • CO2 sold as a product or used: • Freezing chickens • Soda pop, baking soda • ~140 $/ton CO2 (claim by operators) • 300 metric tons recovered per day: • ~15 MWe power plant equivalent • Many pilots planned and in development: • 5 MW Chilled Ammonia Pilot • Many other processes under development AES Cumberland ~ 10 MW (Report 1012796) Assessment of Post-Combustion Carbon Capture Technology Only Demonstrated on a Small Scale to Date.

17. Challenge- Regulatory Uncertainty on CO2 Emissions • Kyoto Signatory Countries post 2012. New G-8 Proposals • New Motion in Australia, EU • US proposed Federal legislation Intense in Washington – MANY bills • US Regional Initiatives • Western Regional Climate Action (WA,OR,CA,AZ, and NM). Western Governors Association (WGA) • RGGI – East Coast Regional GHG Initiative (10 NE States) • Powering the Plains (ND,SD,IA,MN,WI, Manitoba) • California, Washington - others… • New long term base load power or renewal (>5years) commitments shall have CO2 emissions no greater than NGCC (established as <1100 lbs/MWh ~ 500 kg/MWh). • Liability of CO2 injection into geological formations? New questions with BP “Carson Hydrogen Power Project” project in California

18. Address Societal Concerns Confirmed Long Term Sequestration CO2 Capture • Plant Efficiency • Capture Technology • Capture Pilots • Capture Demonstrations • Test Multiple Geologies • Well Integrity • Monitoring • Liability • Health • Public Acceptance Preparing for Carbon Constraints Variation of Plants Variation Geology Multiple Challenges Requiring Concurrent Resolution.

19. CoalFleet for Tomorrow is an International Collaboration on Clean Coal including CO2 Capture • Participants from 5 continents , Asia, Australia, Europe, Africa, North America (2/3 of all coal fired in NA) • Best design guides developed by industry for industry • Power Producers, Suppliers, Rail, Coal, engineering firms, Governmental entities • Many of the leading “early deployment” firms working with us to assure successful designs that meet the performance and operational goals • New plants starting to look at designs for CO2 capture and integration

20. CoalFleet Participants Span 5 Continents>60% of U.S. Coal-Based Generation, Large European Generators,Major OEMs (50 & 60 Hz) and EPCs, CEC, U.S. DOE • Alliant Energy Corp. • Alstom Power • Ameren Services Company • American Electric Power • Arkansas Electric Coop. • Austin Energy • Babcock & Wilcox Company • Bechtel Corp. • BP Alternative Energy International • California Energy Commission • ConocoPhillips Technology • Consumers Energy • CPS Energy • CSX Transportation • Dairyland Power Coop. • Doosan Heavy Industries (Korea) • Duke Energy Corp. • Dynegy • EdF (France) • Edison International • Edison Mission Energy • Endesa (Spain) • ENEL (Italy) • Entergy • E.ON UK • E.ON US • ESKOM (South Africa) • Exelon Corp. • FPL • GE Energy (USA) • Golden Valley Electrical Assoc.

21. CoalFleet Participants Span 5 Continents (cont’d) • Great River Energy • Hoosier Energy • Integrys Energy Group (WPS) • Jacksonville Electric Authority • Kansas City Power & Light • Kellogg Brown & Root (KBR) • Lincoln Electric System • Midwest Generation • Minnesota Power • Mitsubishi Heavy Industries (MHI) • Nebraska Public Power District • New York Power Authority • Oglethorpe Power • PacifiCorp • PNM Resources • Portland General Electric • Pratt & Whitney Rocketdyne • Richmond Power & Light • Rio Tinto • Salt River Project • Siemens • Southern California Edison • Southern Company • Stanwell Corporation • TransCanada Pipelines Limited • Tri-State G&T • TVA • TXU • U.S. DOE (NETL) • We Energies • Wolverine Power • Xcel Energy

22. What’s Next – What’s Needed for Coal • Acceleration of the Industry efforts worldwide in addition to governmental efforts – new pilots, demonstrations, initiatives • Cost reductions and efficiency improvements for the underlying technology • Three “strata” of certainty/understanding • Political/siting, economic, technical

23. Backup sides

24. IGCC with CO2 Removal Steam Sulfur CO2to use or sequestration GasificationC + H2O = CO + H2 Shift CO+ H2O = CO2 + H2 Sulfur and CO2 Removal Coal Prep Gas Cooling O2 Hydrogen N2 Air Separation Unit Gas Turbine Air BFW BFW HRSG Air Steam Steam Turbine

25. IGCC CO2 Retrofit Considerations • The ideal IGCC that you would build if you knew it would later be retrofitted with CO2 capture would be quite different from the ideal IGCC you would build if you knew it would never capture CO2 • Direct water quenching over syngas coolers • Coal-water slurry over dry feeding • Higher gasifier operating pressure • Physical solvents for acid gas removal • Capability to handle additional pressure drop in syngas production train

26. PC CO2 Capture Retrofit Considerations • If you are designing a plant today with the idea that some time during its life it will be retrofitted with capture, there are some things you should do differently: • Add space • Place the plant near a suitable geologic storage site • Make the plant as efficient as practical – higher efficiency means less CO2 you will have to capture and compress • Design emissions controls to either achieve ultra-low SOx and NOx emissions today, or design the equipment to be upgraded to ultra-low emissions • Design steam turbine to accommodate very large extraction of low pressure steam for solvent regeneration “If just adding space for the CO2 equipment makes a coal power plant capture ready, then my driveway is Ferrari-ready” – David Hawkins, NRDC

27. USC Worldwide Experience Curve US Eddystone 1960 1135F 1112F

28. 2005 2010 2015 2020 2025 2030 IGCC RD&D Augmentation Plan—Expected Benefits Case:Slurry-fed gasifier, Pittsburgh #8 coal, 90% availability, 90% CO2 capture, 2Q 2005 dollars Total Plant Cost ($/kW) Plant Net Efficiency (HHV Basis) 2200 2000 1800 1600 1400 1200 40 38 36 34 32 30 • Mid-Term: • ITM oxygen • G-class to H-class CTs • Supercritical HRSG • Dry ultra-low-NOX combustors • Long-Term: • Membrane separation • Warm gas cleanup • CO2-coal slurry • Near-Term: • Add SCR • Eliminate spare gasifier • F-class to G-class CTs • Improved Hg detection • Longest-Term: • Fuel cell hybrids

29. 2005 2010 2015 2020 2025 USC PC RD&D Augmentation Plan—Expected Benefits Case:Pittsburgh #8 coal, 90% availability, 90% CO2 capture, as reported data from various studies (not standardized) Total Plant Cost ($/kW) Plant Net Efficiency (HHV Basis) 2400 2200 2000 1800 1600 1400 40 38 36 34 32 30 • Near Mid-Term: • Upgrade steam conditions to 4200/1110/1150 • Mid-Term: • Upgrade steam conditions to 5000/1300/1300, and then to 5000/1400/1400/1400 • Near-Term: • Upgrade solvent from MEA to MHI KS-1 (or equivalent) • Upgrade steam conditions from 3500/1050/1050 to 3615/1100/1100 • Long-Term: • Upgrade solvent to advanced sorbents

30. EPRI’s CoalFleet forTomorrow Program • Build an industry-led program toaccelerate the deployment ofadvanced coal-based power plants;members now span five continents • Employ “learning by doing” approach; generalize actual deployment projects (50 & 60 Hz) to create design guides • Augment ongoing RD&D to speed marketintroduction of improved designs and materials • Deliver benefits of standardization to IGCC (integration gasification combined cycle), USC PC (ultra-supercritical pulverized-coal), and SC CFBC (supercritical circulating fluidized-bed combustion) • Lower costs, especially with CO2 capture • High reliability • Near-zero SOX, NOX, and PM emissions • Shorter project schedule • Easier financing and insuring Further information availableat www.epri.com/coalfleet