Coal s Strategic Position in the U.S. for the Next 10 Years. Gerald A. Hollinden, Ph.D. URS Corporation Pittsburgh Coal Conference September 24, 2002

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1 Coal s Strategic Position in the U.S. for the Next 10 Years Gerald A. Hollinden, Ph.D. URS Corporation Pittsburgh Coal Conference September 24, 2002

2 Topics Coal production and use over last 100 years Projections for coal use over next 10 years The myth of grandfathered power plants Emission reduction regulations Emission control technologies Advanced coal-based power plants Emissions from coal vs. other fuels The future of coal

3 Coal Production Over the Last 100 Years 85% for electricity M 1200 i 1100 l l i 600 o 500 n 400 Year t o n s 5% for electricity

4 Electricity Generation by Fuel Type Oil 3% Gas 12% Nuclear 16% Oil 1% Gas 21% Nuclear 17% Renewable 9% Renewable 9% Coal 55% Coal 52% Source: EIA Annual Energy Outlook 2002 A8

5 Changes in Electricity Generation by Fuel Type While overall % of electricity generation from coal decreases, the actual generation using coal increases 15% Why? - New coal generating capacity plus higher capacity factors on existing coal units CF increased from 59% to 69% in last 10 years CF projected to increase to >80% by 2010 Source: EIA Annual Energy Outlook 200, A8&A9

6 Changes in Electricity Generation by Fuel Type During the same timeframe: Natural Gas: +214% Renewables (mostly hydro): +22% Nuclear: -2% Oil: -70% Source: EIA Annual Energy Outlook 2002 A16

7 Some Recent Coal Unit Announcements >20,000 MW Alliant Energy: 500 MW in WI Black Hills Energy Capital: 500 MW in WY Composite Power Corp.: 3,000 MW in UT Corn Belt Energy: 91 MW in IL Dominion Energy: 475 MW coal/waste coal in WV EnviroPower: 500 MW in IL Duke Energy: 700 MW in VA EnviroPower: 2x500 MW waste coalburning in IN EnviroPower: 500 MW waste coal-burning in KY Global Energy: 400 MW Kentucky Pioneer IGCC project in KY Global Energy: 540 MW Lima Energy Center IGCC project in OH Globaltex: 249 MW in WA Great River Energy: 500 MW in ND LS Power: 1,000 MW in AR MidAmerican Energy: 900 MW in IA NRG Energy: 675 MW Big Cajun II, Unit 4 in LA PacifiCorp: 500 MW in Utah Peabody Thoroughbred: 2x750 MW in KY Peabody Prairie State: 2x750 MW in IL Reliant Energy: 520 MW Seward CFB in PA Southern Illinois Power Cooperative: 120 MW CFB in IL Santee Cooper: 500 MW in SC Sunflower Electric and IEP: 600 MW in KS Tri-State G&T: 3x400 MW in CO Tucson Electric: 2x380 MW in AZ Wisconsin Energy Corp.: 3x600 MW in WI

8 How Much New Coal Capacity Will Actually be Built? EPRI (Sept. 2001): 25,000 + MW Utility Business (Dec. 2001): 22,000 + MW Energy Ventures Analysis (2001): ~27,000 MW EIA (AEO 2002): 6,200 MW Coal-Gen Conference (Aug. 2002): 38,253 MW

9 Whose forecast is right???

10 Deciding Factors Many coal plants that were announced soon after gas prices increased in were delayed or cancelled when gas prices decreased in 2002 Some new capacity was announced by merchant plant developers which have pulled back development plans or are no longer in business

11 Effect on Coal Use Known Increases in capacity factor will account for more coal being used in existing units Unknown How much new capacity will be built? Will NSR issues continue to stifle capacity increases?

12 The Myth of Grandfathered Power Plants The myth: Congress and EPA imposed stringent NOx and SO 2 limits on new power plants with the 1970 Clean Air Act Utilities accepted these more stringent limits in exchange for legislative concession to exempt existing plants

13 The Myth of Grandfathered Power Plants The myth: Utilities extracted this concession by representing that old plants would soon be retired and replaced with new clean plants Older plants have continued to operate well past their 30-year life, without any emission limits or controls

14 The Myth of Grandfathered Power Plants The truth: The 1970 Clean Air Act established national ambient air quality standards mandating that existing power plants meet emission limitations issued in SIPs Congress stated that existing sources of pollution either should meet the standard of the law or be closed down

15 The Myth of Grandfathered Power Plants The truth: Per EPA, most of the SO 2 reductions from came from the imposition of individual powerplants limits at existing plants through the State Implementation Plans (SIPs) under the 1970 Clean Air Act. The 263 older units named in the 1990 Clean Air Act Amendments reduced their SO 2 emissions by >50% from

16 Known Environmental Challenges SO 2 : reduction requirements from Phase II of Clean Air Act Amendments of 1990 NOx: SIP call NOx reduction requirements Mercury: Some level of mercury reduction will be set by EPA for 2007 (50%?, 90%?)

17 Unknown Environmental Challenges Fine Particulates (PM 2.5 ): additional reductions in SO 2 and NOx 8-hour ozone standard: more NOx reductions? Mercury: proposed multi-pollutant legislation may be more stringent than EPA rules CO 2 : Kyoto Protocol, multi-pollutant legislation

18 Unknown Environmental Challenges Regional haze: additional SO 2 and NOx controls, primarily in western states Clear Skies Act of 2002 additional 50% SO 2 reduction by 2010 additional 58% NOx reduction by % mercury reduction by 2010

19 Comparison of Emission Reduction Programs Emission Year Current (Title IV and NOx SIP Call) Clear Skies Act of 2002 SO 2 (Million Tons) Current NOx (Million Tons) Current Mercury (Tons) Current

20 Emission Control Technologies SO 2 : Mature FGD technology now provides >98% removal, with high reliability and saleable by-products NOx: A wide range of combustion and post-combustion techniques Low-NOx burners to 0.4 lb/mmbtu or less 90% removal by SCR 90% removal by LoTOx (BOC) 55% reduction by SACR (Mitsui-Babcock) 20-40% reduction by SNCR

21 Emission Control Technologies Particulates (fly ash): 99.9% removal by ESPs or baghouses to <0.01 lb/mmbtu Mercury: retrofit technologies not yet mature nor tested at full load for sufficient periods Powdered activated carbon injection is most mature retrofit technology LoTOx oxidizes mercury so that it can be absorbed in FGD systems

22 Emission Control Technologies CO 2 : No practical removal system available CO 2 reduction requirements likely to target coal and not gas Expensive alternatives would significantly affect use of coal and cost of electricity Reduce coal use or switch to gas Capture and sequester CO 2

23 Advanced Coal Technologies Pulverized Coal (PC) Circulating Fluid Bed (CFB) Integrated Gasification Combined Cycle (IGCC)

24 Pulverized Coal Subcritical - conventional drum-type boiler operates at 1,000ºF and 2400 psi; existing fleet efficiency ~32% HHV; new units 35-37% HHV Supercritical - once-through boiler operates at 1,115 + ºF and >3,500 psi; efficiency 40-44% HHV Increased interest in supercritical PC due to fuel savings and lower emissions/mwh

25 Circulating Fluid Bed (CFB) Fuel is mixed with limestone and burned at low temperature in fluid bed boiler which makes steam Steam drives a turbine connected to a generator Emission controls: limestone to absorb SO 2, cyclone for particulates, Selective Non-Catalytic Reduction (SNCR) for NOx Efficiency = 34% HHV

26 Integrated Gasification Combined Cycle (IGCC) Integrated Gasification Combined Cycle (IGCC) Integrates coal with efficient combined cycle technology Coal is converted to synthetic gas which is burned in combined cycle plant 99%of sulfur is recovered as saleable sulfur or sulfuric acid Enables CO 2 capture Efficiency=41+%HHV

27 Capital Costs of Coal Technologies Pulverized Coal EPC cost (Coal-Gen 2002) $1,000-1,400/kW for recent projects Supercritical costs ~3-5% more than subcritical Fluid Bed: $1,100-$1,535/kW for recent projects IGCC: $925-1,350/kW for recent and proposed projects

28 Busbar Costs $/MWh PC (minemouth) at 0.65/mmBtu: $32.31 Combined cycle at $3.25/mmBtu: $34.36 PC at $0.90/mmBtu: $34.71 PC at $1.20/mmBtu: $37.52 Combined cycle at $3.75/mmBtu: $37.66 Combined cycle at $4.25/mmBtu: $40.95 Peabody Coal figures presented at Coal-Gen 2002, 90%

29 The Future of Coal: Efficiency Improvements Efficiency: continuous development of higher efficiency technologies Advanced supercritical Technologies that take advantage of improvements in combustion turbines, i.e. IGCC

30 The Future of Coal: Costs Capital costs not decreasing significantly, due to small number of new units and insufficient economies of scale Higher gas prices will give low-cost coal an edge

31 The Future of Coal: Environmental Performance SO 2, NOx, and PM - high removal, commercially available technologies at costs that allow coal to compete Mercury - commercially available technologies under development, but costs are high and are not applicable to all coals CO 2 - will be a significant challenge to coal if emission limits are imposed; IGCC s inherent ability for CO 2 capture could give it an environmental edge

32 In Conclusion Use of coal for generating electricity has come a long way in the past 100 years Over next 10 years, U.S. will continue to depend on coal for low-cost electricity to promote economic development Coal will be critical for national energy security Coal technologies are more efficient and cleaner, approaching performance of gas technologies CO 2 will be a big challenge for coal