Update on Clean Coal Technologies and CO 2 Capture & Storage

1. Update on Clean Coal Technologies and CO2 Capture & Storage For Oregon Public Utility Commission Salem ,OR - June 27, 2007 Neville Holt – EPRI Technical Fellow Advanced Coal Generation Technology

2. Clean Coal Technologies (CCT) and CO2 Capture and Storage (CCS) - Presentation Outline • Overview – Options for Response to Global Climate concerns • Clean Coal Technology (CCT) Options • EPRI CoalFleet Program • PC Post Combustion Removal – Status, Chilled Ammonia • Oxyfuel – Status, SaskPower, • IGCC – Status, Capture Technology, • Economic Studies DOE, EPRI - New Plants with and without Capture • IGCC/PC EPRI Study adding Capture to new plants designed without Capture • Effect of Capital Cost increases and Carbon (CO2) cost on COE and Strategic selection of power generation technologies • Summary

3. Regulatory Uncertainty on CO2 Emissions • Kyoto Signatory Countries post 2012. EU – ETS Phase 2. UK . • US proposed Federal legislation - McCain/Lieberman, Bingaman, Sanders/Boxer, Feinstein/Carper, Kerry/Snowe • 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: Governor’s Executive Order GHG targets 2010 cut to 2000 (-11%), 2020 cut to 1990 (-30%), 2050 80% below 1990. • New long term base load power or renewal (>5years) commitments shall have CO2 emissions no greater than NGCC (established as <1100 lbs/MWh). • Oregon & Washington have enacted similar legislation • Liability of CO2 injection into geological formations ?

4. IGCC Energy Storage PHEV Power Company Carbon Management Options

5. Options for CO2 Response(The Stabilization Wedge & Slices) • Conservation (Yes - but Rest of the World?) • Renewables (Yes - but not enough) • Nuclear (Ultimately Yes – but implies wide Proliferation) • Adaptation (Probably Yes – we always do) • Switch from Coal to Natural Gas (Maybe but not enough NG) • CO2 Capture & Sequestration (CCS) (Maybe but site specific & costly - Liability for the Sequestered CO2?) Notes : US Coal Power Plants emit > 2 billion metric tons of CO2/yr (~36% of US and 8% of World CO2 emissions). 1 billion metric tons/yr = ~25 million bpd of supercritical CO2 Effort Required for CCS Slice-World-wide build or replace 8 GW of Coal Power plants with CCS every year and maintain them until 2054

6. CO2 Capture in Coal Power Systems

7. 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 New Technology Deployment Curve for Coal Not All Technologies at the Same Level of Maturity.

8. EPRI Programs 2007ff • P 66 CoalFleet for Tomorrow – Future Coal Options Focus on Deployment of New Plants, Designs for Capture Readiness and Capture - 66 A Economic and Technical Overview (IGCC,PC,CFBC) - 66 B Gasification - IGCC and Co-production (Hydrogen, SNG, F-T Diesel etc) - 66 C Combustion - USC PC, Advanced materials, CFBC, OxyFuel • P 103 CO2 Capture & Storage Focus on Sequestration and Existing Plants - Participation in US Regional Partnerships, IEA GHG - Capture focus Existing Plants - Chilled Ammonia (ABS) 5 MW Pilot Plant

9. EPRI’s CoalFleet forTomorrow Program • Build an industry-led program toaccelerate the deployment ofadvanced coal-based power plants;use “lessons learned” to minimize risk: address “Capture Readiness” • Employ “learning by doing” approach; generalize actual deployment projects (50 & 60 Hz) to create design guides • Augment ongoing RD&D to speed market introduction of improved designs and materials; lead industry collaborative projects • 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 • Higher reliability • Near-zero SOX, NOX, PM, and Hg emissions • Shorter project schedule Further information availableat www.epri.com/coalfleet

10. CoalFleet Participants Span 5 Continents>60% of U.S. Coal-Based Generation, Large European Generators,Major OEMs (50 & 60 Hz) and EPCs, U.S. DOE • AES • Alliant • Alstom Power • Ameren • American Electric Power • Arkansas Electric Coop • Austin Energy • Babcock & Wilcox • Bechtel Corp. • BP • California Energy Commission • CPS Energy • ConocoPhillips Technology • CSX Corporation • Dairyland Power Coop • Doosan Heavy Industries • Duke Energy Corp • Dynegy • East Kentucky Power Coop • EdF • Edison International • ENEL • Entergy • E.ON • ESKOM • Exelon Corp. • FirstEnergy Service • GE Energy • Great River Energy

11. CoalFleet Participants Span 5 Continents (cont’d) • Golden Valley Electrical Association • Hitachi • Hoosier Energy • Jacksonville Electric Authority • Kansas City Power & Light • Lincoln Electric • MHI • Minnesota Power • Nebraska Public Power District • New York Power Authority • PacifiCorp • Portland General Electric • Pratt Whitney Rocketdyne • Progress Energy • Public Service Co.New Mexico • Richmond Power & Light • Rio Tinto • Salt River Project • Shell • Siemens • Southern Company • Stanwell Corporation • Tri-State G&T • TVA • TXU • U.S. DOE • We Energies • Wisconsin Public Service

12. CoalFleet Continues to Expand Collaborative Relationship with International Organizations • Coordination with VGB for Europe and European firm participation • Growing Australian and Asian Involvement • Eskom adds African Involvement • Potential for Support from Asia-Pacific Partnership

13. 2 Percentage Point Efficiency Gain = 5% CO2 Reduction Commercial Supercritical Plant Range Subcritical Plant Range Advanced Ultra-Supercritical Plant Range PC Plant Efficiency and CO2 Reduction

14. CO2 to Use or Sequestration Fresh Water CO2 Removal e.g., MEA Coal PC Boiler Flue Gas to Stack SCR ESP FGD Air Fly Ash Gypsum/Waste Steam Turbine Pulverized Coal with CO2 Capture (Today) • Amine commercially available (multiple suppliers) • 3 U.S. plants in operation: • MEA, <15 MWe, >90% ΔCO2 • Key requirements: • ~5–6 acres for 600 MW plant • Near-zero SO2 and NO2 • Large reboiler steam (MEA>KS-1>Ammonia) • Many new process options being explored Energy Penalty ~29% CO2 to Cleanup and Compression Cleaned Flue Gas to Atmosphere CO2 Stripper Absorber Tower Flue Gas from Plant CO2 Stripper Reboiler Needs Space, Integration and Energy

15. E P R I AES Cumberland ~ 10 MW (Report 1012796) Assessment of Post-Combustion Carbon Capture Technology CO2 PC 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 for food grade • 300 metric tons recovered per day: • ~15 MWe power plant equivalent • Many pilots planned and in development: • 5 MWth Chilled Ammonia Pilot • Many other processes under development Only Demonstrated on a Small Scale to Date

16. CO2 Capture Retrofits Require a Lot of Space(and very clean flue gas) CO2 capture plant for 500-MW unit occupies 6 acres, i.e. 510 ft x 510 ft

17. Potential Improvements for Post Combustion CO2 Capture • Alternative equipment arrangements and designs - membrane absorbers (Kvaerner, TNO), membrane regenerator (Kvaerner) • Alternative solvents – Hindered Amine (MHI KS-1), Piperazine addition (promoter) to K2CO3, Other amines (PTRC at U. Regina) • Ammonium Carbonate with CO2 and water forms Ammonium Bicarbonate (EPRI/Alstom). Can be regenerated at pressure. Potential energy savings in regeneration and compression • Adsorption technologies – Amine enriched solids, K, Na and Ca carbonates, Lithium oxide • Cryogenic cooling of flue gas • Recycle flue gas to increase CO2 concentration (perhaps viable for NGCC – need to consider effect of lower oxygen)

18. Chilled Ammonia Process Performance Prediction (Early Data Only) Source: Nexant

19. 5 MW Chilled Ammonia CO2 Capture Pilot • Jointly Funded by Alstom and EPRI • Site- WE Energies Pleasant Prairie Power Plant • $11 million for construction, operation for one year, data collection and evaluation • Alstom will design, construct and operate • EPRI will collect data and provide evaluation • 24 firms have agreed to fund EPRI testing with more being added • Operations beginning in the 3rd Quarter of 2007 • AEP plans 30 MWth at Mountaineer, WV site to be followed by further scale-up at OK site ~2011. • Projects planned in Europe with EoN and Statoil capturing CO2 from Natural gas combustion (NGCC, Reformers , boilers )

20. 5 MW Chilled Ammonia CO2 Pilot Capture Pilot Gas takeoff Scrubber Module CO2 pilot location

21. 5 MW Chilled Ammonia CO2 Capture Pilot Participants AEP Ameren CPS Energy Dairyland DTE Energy Dynegy E.ON U.S. Exelon First Energy Great River Energy Hoosier KCPL MidAmerican NPPD Oglethorpe Pacificorp PNM Sierra Pacific SRP Southern Co Tri-State TXU TVA We Energies

22. CO2 Capture by O2/CO2 Combustion • O2/CO2 Combustion • Small test facilities at Canmet, B&W, Alstom • Potential reuse of existing boiler equipment • Pulverizers, air heaters, etc. • Potential “retrofit kit” • CO2 recycled for temp. control • SO2 removed from purge stream • If higher purity CO2 required • Requires large oxygen plant • Large auxiliary power requirement • Large net output reduction • Make-up power source for Retrofit of existing plant?

23. Oxyfuel Combustion in a PC Boiler Other potential CO2recycle take-off points Source: Vattenfall (GHGT7 2004)

24. Current Oxyfuel Development Status • Engineering design studies for commercial scale plants -(Air Products, Air Liquide, Jupiter Oxygen, Alstom, B&W, etc) • Operation of several pilot scale boilers • CANMET (~ 1 MM/Btu/hr) • Babcock and Wilcox (~5 MMBtu/hr). Larger 30 MWth unit in construction • Alstom CFB (2.6-7.4 MMBtu/hr) • A key issue is the removal of other gases (SO2, O2, NOx, HCl, Hg). Is FGD required, at least for high sulfur coals, on either recycle or CO2 product streams? To date there has been no testing of downstream non-condensable gas recovery system • To date no boiler testing at supercritical steam conditions • Vattenfall 30 MWth Oxyfuel demo near Schwarze Pumpe, Germany • SaskPower FEED study for 300 MW net with B&W, Air Liquide • AEP planned study of PC Retrofit with B&W

25. R0 is base case (no capture), A1 is oxyfuel, B1 is amine scrubbing. Triangles indicate COE if CO2 was sold for $42/tonne. Subbituminous Lignite Bituminous Comparison of Oxyfuel and Amine ScrubbingPreliminary Results for CCPC/DTI Project 366 (Canadian Dollars) Oxyfuel is Competitive with Amine Scrubbing for PRB

26. Sulfur Coal Gas Clean Up CC Power Block POWER Air ASU Gasifier O2 Slag Sulfur CO2 Coal CC Power Block Gas Clean Up ASU Gasifier Shift Air POWER O2 H2 Slag IGCC with and without CO2 Removal IGCC no CO2 capture H2 & CO2 (e.g., FutureGen) CO2 Capture = $, Space, Shift, H2 Firing, CO2 Removal, Energy

27. Coal Based IGCC Plants in Operation

28. Nuon- Buggenum, Netherlands 250 MW IGCC

29. Wabash 260 MW IGCC Repowering

30. Tampa Electric - Polk 250 MW IGCC

31. IGCC Environmental Control • Sulfur is removed (99.5-99.99%) from syngas using commercial gas processing technology. • NOx emissions are controlled by firing temperature modulation in the gas turbine. Possible addition of SCR if needed. • Particulates are removed from the syngas by filters and water wash prior to combustion so emissions are negligible. • Current IGCC designs available with SCR to achieve ~3ppmv each of SOx, NOx. • Mercury >90% removed from the syngas by absorption on activated carbon bed. • Water use is lower than conventional coal (70-80%). • Byproduct slag is vitreous and inert and often salable. • CO2 under pressure takes less energy to remove than from PC flue gas at atmospheric pressure. (Gas volume is <1% of flue gas from same MW size PC).

32. IGCC Commercial Teams 2004-5 • GE Energy (Gasification and Power block) and Bechtel • ConocoPhillips (E-Gas Gasification) and Fluor • Shell (Gasification and Gas cleanup), Krupp-Uhde and Black & Veatch Additional Candidates: MHI Siemens KBR-Southern Co

33. The Great Plains Synfuels Plant http://www.dakotagas.com/Companyinfo/index.html Weyburn Pipeline http://www.ptrc.ca/access/DesktopDefault.aspx Coal Gasification Plants w/CO2 Capture (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 No Coal IGCC Currently Recovers CO2

34. HP Steam Sulfur CO2to use or sequestration GasificationC + H2O = CO + H2 Sour Shift CO+ H2O = CO2 + H2 AGRU- H2S & CO2 Coal Prep Gas Cooling O2 H2? N2 Air Separation Unit Gas Turbine Air BFW BFW HRSG Air Steam IGCC with CO2 Capture(e.g., FutureGen, BP Carson) Steam Turbine Needs Space, Energy and Integration IGCC with CO2 Removal

35. IGCC Pre-Investment Options for later addition of CO2 Capture • Standard Provisions • Space for additional equipment, BOP, and site access at later date • Net power capacity, efficiency and cost penalty upon conversion to capture • Moderate Provisions • Additional ASU, Gasification and gas clean-up is needed to fully load the GT’s when Shift is added. • If this oversizing is included in the initial IGCC investment the capacity can be used in the pre-capture phase for supplemental firing or co-production. • This version of “capture ready” would then permit full GT output with Hydrogen (at ISO) when capture is added. Mitigates the cost and efficiency penalty. • However when shift is added considerable AGR modifications will be required • Extensive Provisions • Design with conversion-shift reactors, oversized components, AGR absorber sized for shifted syngas but no CO2 absorber and compressor • No need for major shutdown to complete the conversion to CO2 capture

36. Water-Gas Shift: Typical Process Configuration Pressure in bar Temp in ºC Shift Reactors Source: Haldor Topsoe

37. Gas Compositions and Flows before and after Shift- Adding Shift increases Syngas flow to AGR(Mol % Clean Dry Basis – Typical Bituminous Coal)

38. Clean H2-rich syngas CO2 CO2 Removal H2S Removal Solvent Absorption for IGCC Generic Process Flow Diagram with CO2 Capture Added Have to add second absorber and stripper column to capture CO2

39. 15 Gasification Projects Aimed at C&S – Day 1 • BP Carson • Xcel • Pacificorp Wyoming • FutureGen Demo • Hunton 10-15% • Indiana Gasification • TransCanada Polygen • Wallula RR, Washington • RWE • Stanwell ZeroGen Demo • Centrica / Progressive Energy • EoN UK • Powerfuel Hatfield UK • GreenGen Demo China • BP/Rio Tinto Australia IGCC with CO2 Capture from Day 1 • Current EPRI IGCC Knowledge Base Gasification Projects • 66 North America Projects • 38 International Projects

40. Summary - CO2 Capture Technology Status and Issues • IGCC and CO2 removal are offered commercially but have not operated in a mature integrated manner • Big issues IGCC Cost (particularly with low rank coals), Integration, and CO2 Storage • Advanced PC and CO2 post combustion are each offered commercially but CO2 removal has only operated at small scale and not integrated • Big issuesCO2 Capture Cost & Scale-up, Integration and CO2 Storage • Oxy-Fuel technology is in the early stages of development has only operated at small pilot plant facilities • Big issuesOxygen production cost and power consumption, Integration, CO2 purification and Storage Gasification and Combustion Needed With CO2 Options

41. Plant Construction Costs Escalating

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

43. Recent Duke PUC Submissions April/May 2007 • Cliffside, NC 800 MW SCPC 1.8 B $ + 0.6B$ Financing. Or 2250$/kW + 750$/kW financing = Total 3000$/kW Scaling to 630 MW the cost would be 2417$/kW. If labor/productivity in NC is 0.9 (with MidWest 1.0) this would become ~2520$/kW in the Mid West. • Edwardsport, IN 630 MW IGCC (GE RQ) 1.985B$ including escalation at 4%/year through October 2011. Factor (1.04)4 = 1.17 . Total 3151 $/kW with escalation to 2011 or 2693 $/kW in 2007. • Consistent with Duke’s statement in Edwardsport, IN filing that IGCC is ~10-15% more than SCPC. • It is not completely clear what the costs represent (e.g. what is included or excluded). TPC? TPC + OC? However it is assumed that they are fairly consistent.

44. Capital Cost Estimates When comparing capital cost estimates, it is important to know what is included and, more importantly, what is not included! • Unfortunately, we do not know what is included in each of the capital cost estimates submitted to the PUCs. However, we believe most are similar to the EPRI Total Capital Requirement (TCR). • EPRI Total Capital Requirement is 16–19% higher than Total Plant Cost • Typical EPRI Owner’s Costs add about 5–7% to TPC • AFUDC adds another 11–12% to TPC • The adder for “other” Owner’s Costs varies widely • Depends on owner and site-specific requirements • Can easily add another 10–15% to TPC

45. DOE NETL Draft Report “Cost & Performance Comparison of Fossil Energy Power Plants” • IGCC, PC and NGCC designs evaluated a) without capture and b) with Capture. Illinois#6 coal $1.34/MBtu NG 7.46$/MBtu HHV. • GE Radiant Quench, COP E-Gas Full Slurry Quench, Shell Gas Recycle Quench . All based on 2 x GE 7 FB GTs. Designs with capture have additional coal gasification etc to fully load the GTs when firing Hydrogen. Lower net output with capture. NETL presented results for IGCC as an average of the three technologies • PC sub critical (2400/1050/1050) and Supercritical (3500/1100/1100). Designs with post combustion amine scrubbing capture are much larger so that net output is same as designs without capture • NGCC without capture and with post combustion amine scrubbing

47. But IGCC technologies were not all created equal !! - Particularly for CCS • Moisture is needed in the syngas for shift – and the least expensive way of accomplishing this is direct water quench – not by use of expensive syngas coolers • The DOE study used IGCC configurations with syngas coolers and the previous slide used an average of the three technologies. • Higher pressure (e.g., 800–1000 psig) decreases the cost of CO2 removal and compression through use of a physical absorption system (e.g., Selexol) • DOE ranking with CCS - GE , COP, Shell • GE offers a direct quench (not in DOE study) • Shell is rumored to offer water quench design soon • COP is likely to offer a modified operation for capture to inject more water

48. Syngas Composition Affects Shift Steam Requirements (Need >3:1 H2O/CO Ratio) and Overall Performance

49. EPRI CoalFleet Studies New Coal Plants 2006+ • Design Options in the face of Regulatory Uncertainty: – Design without CO2 Capture - Add Capture to Design without Capture - Design with Capture initially • Illinois # 6, Wyoming Sub- bituminous coal (PRB) • Supercritical PC with Amine Scrubbing (Fluor Econamine +). Steam temperatures 565 C (Ill#6) and 593 C (PRB). Single reheat. • IGCC - GE Radiant Quench (RQ) and Total Quench (Q) (Ill#6) - Shell Gas Recycle Quench (Ill #6 & PRB) - ConocoPhillips (COP) E Gas (Ill #6 & PRB)

50. Basis for EPRI CoalFleet Program 2006 PC & IGCC Estimates - 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. • Uncertain what the estimates presented to PUCs represent. Total Capital Requirement (TCR), which includes Owners costs and AFUDC 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.