1

The Case for Integrated Gasification Combined Cycle

Technology

Presentation to Michigan Public Service CommissionLansing, MI

August 22, 2006

Dale E. HeydlauffVice President-New Generation

deheydlauff@aep.com

2

AEP: An introduction

Coal NG Nuclear Hydro Wind

75% 15% 6% 2% 2%

AEP Facts at a Glance

Largest U.S. Electricity Generator and coal user

• 11 States (7-East & 4-West)• 36,000 MW Generation• 78 MM tons of coal per year• 39,000 Miles Transmission

210,000 Miles Distribution • 5 Million Customers• 20,000 Employees• US$ 14.5 Billion Revenue• US$ 36.7 Billion in Assets

3

Now is the Time to Upgrade our Nation’s Electricity Infrastructure

• 70% load growth in past 25 years– Little new baseload capacity added– Little new transmission added

• Nuclear generation capacity reaching output limit– 1990 66% capacity factor – 2004 91% capacity factor

• Coal generation capacity becoming fully utilized– 1990 59% capacity factor– 2004 74% capacity factor

• Demand expected to grow another 20% over next 10 years– Long lead time for baseload generation capacity

4

Electric Power’s Future

• Population growth and increased electrification requires about 250-300 GW of baseload generating capacity over next 25 years

• No silver bullet … Need a portfolio• Future demand probably met largely by coal:

– Gas supply issues and price volatility in North America

– LNG imports will exacerbate U.S. trade imbalance

– Nuclear could be revived, but probably decades away from a major resurgence

– Renewables (particularly wind) promising, but infrastructure/intermittency limits penetration

5

U.S. Forecasts Largest Coal Generation Capacity Installation in 40 Years

Source: U.S. Department of Energy NETL & Annual Energy Outlook 2005.

Cap

acity

Add

ed (G

Ws) Capacity Addition

Levels Not Seen in 40 Years

Industry Growth Trend Not Seen in

50 Years

20 YearMarket Trough

U.S. Coal Capacity Additions, 1940 U.S. Coal Capacity Additions, 1940 –– 20252025

0123456789

1011121314151617181920

1940 1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025

6Source: Energy Information Administration, March 2005.

8.1¢ 30%

6.1¢65%

5.8¢94%

5.6¢10%

5.7¢64%

5.0¢96%

7.0¢74%

6.1¢7%

6.5¢74%

7.2¢88%

8.6¢50%

11.3¢1%

5.8¢95%

6.6¢48%

7.8¢42%

6.5¢82%

6.3¢65%

6.6¢56%

6.1¢86%

6.9¢49%

7.6¢38%

6.9¢70%

5.8¢51%

7.1¢ 35%

7.0¢59%

5.6¢98%

6.8¢87%

9.4¢1%

12.0¢16%

7.0¢42%

6.1¢56%

6.7¢65%

6.2¢ 41%

4.6¢ 92%

6.5¢45%

8.1¢55%

5.1¢99%

7.0¢62%

6.1¢ 60%

5.0¢0%

10.8¢8%

15.6¢15%

NH 11.4¢ 17%VT 11.1¢ 0% MA 10.8¢ 22% RI 10.8¢ 0%CT 10.4¢ 13%NJ 10.2¢ 19%DE 7.3¢ 65%MD 7.2¢ 52%

¢ = average retail price per kilowatt hour for 2004

% = percent of total generation from coal for 2004 < 6.0¢

≥ 6.0¢ - < 7.0¢≥ 7.0¢ - < 8.5¢≥ 8.5¢ Hydro

Retail Cost Per kWh & Percent of Coal GenerationRetail Cost Per kWh & Percent of Coal Generation

Low-Cost Electricity from Coal:Coal Fuels 50%+ of U.S. Electricity

7

Emissions from CoalEmissions from Coal--Fueled Generating PlantsFueled Generating Plants

* EstimateSource: EPA’s Clean Air Markets database; EIA 2004 Annual Energy Outlook; GE Energy; SFA Pacific.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

Poun

ds P

er M

illio

n B

tu

Sulfur DioxideNitrogen Oxide

U.S.Average

2004*

Clean AirInterstate

Rule2010

New Midwest

Mine-mouth

Clean AirInterstate

Rule2015

0.10

0.340.39

0.16

0.26

0.120.182

0.07 0.06

0.94

New PRB Plant

Near-Zero

FutureGenGoals

0.030.06

New IGCCProjection

ExistingIGCC

(PermitLevel)

0.17

0.08

The Path Toward Near-Zero Emissionsfrom Coal-Fueled Generating Plants

8

Ultra-Supercritical Pulverized Coal

• For technical or financial reasons, IGCC technology may not be available for new coal generation

• To achieve maximum efficiency, AEP plans to build ultra-supercritical pulverized coal plants were IGCC is not feasible

• Ultra-supercritical PC plants have main boiler steam temperatures >1100oF and pressures >3600 PSI

• The technology costs 1-3% more than supercritical PC plantsTechnology PC PC PCSteam Cycle USC Supercritical SubcriticalThrottle Pressure, psig 3500 3500 2400Steam Temperature, F 1110/1125 1000/1000 1000/1000Fuel Lignite Lignite LigniteFuel HHV, Btu/lb 6360 6360 6360FGD Technology Wet FGD Wet FGD Wet FGDGross Turbine Heat Rate, Btu/kwh 7247 7526 7733Aux Power, % 0.09 0.09 0.09Boiler Efficiency, % 0.825 0.825 0.825Net Unit Heat Rate (Full Load), Btu/kwh 9653 10025 10300CO2 Emissions (Full Load), lb/MMBtu 218 218 218CO2 Emissions (Full Load), Tons/MWH 1.05 1.09 1.12

9

Sulfur

CO2Low Temp Gas Cooling

Shift Rx(option)

HgRemoval

ParticulateScrubber

GE"Quench"Gasifier

Slag/Frit

Coal

H2O

+

Air Separation Unit (ASU)

O2

Slurry

Acid Gas Removal

CO/H2

Fines/Char

Flexibility for CO2 Sequestration

(Concentrated Stream)

Sulfur RecoveryClaus/Scot

PRE-COMBUSTIONTreatment of Pollutants

•High pressure•Low Volume•Concentrated stream(easier to treat)

Air

Sulfur RecoveryClaus/Scot

Combustion Turbine

Compressed Air to ASU

HRSG

Steam Turbine

Electricity

Electricity

90+%Removal

98+%Removal

Courtesy Eastman Gasification Services

IGCC Overview

10

IGCC: Feedstock & by-product flexibility

Syngas

CoalBiomass

Refinery By-products• Petroleum Coke• Oil tars

Marketable By-products, e.g.:

SulfurSulfuric AcidSlag / Frits

Hydrogen Liquid Chemicals• Methanol• Diesel FuelsElectricity

Nitrogen From ASU

Lock Hopper

Coal Slurry Tank

Coal Slurry Mill

Slurry Pump

Water

Coal

Gasifier

Oxygen

Air from Combustion Turbine

Nitrogen to Combustion Turbine

Water

Steam to HP Steam Drum

HRSG

Slag

COS Hydrolyzer

Mercury Removal

Bed Acid Gas Removal/Sulfur Recovery Unit

Sulfur

Air Separation Unit (ASU)

Scrubbed Syngas

Clean Syngas

Combustion Turbine

From Power Block

Raw Syngas

Boiler Feed Pump

Compressed Air to ASU

Heat Recovery Steam GeneratorExhaust

Gas

Air

Steam Turbine

Syngas Scrubber

Steam from Radiant Syngas Cooler

Flare

CO2

Shift Reaction (Future)

Recycle to Process

Water to Radiant Syngas Cooler

Radiant Syngas Cooler (RSC)

Ambient Air

Future

Nitrogen From ASU

Lock Hopper

Coal Slurry Tank

Coal Slurry Mill

Slurry Pump

Water

Coal

Gasifier

Oxygen

Air from Combustion Turbine

Nitrogen to Combustion Turbine

Water

Steam to HP Steam Drum

HRSG

Slag

COS Hydrolyzer

Mercury Removal

Bed Acid Gas Removal/Sulfur Recovery Unit

Sulfur

Air Separation Unit (ASU)

Scrubbed Syngas

Clean Syngas

Combustion Turbine

From Power Block

Raw Syngas

Boiler Feed Pump

Compressed Air to ASU

Heat Recovery Steam GeneratorExhaust

Gas

Air

Steam Turbine

Syngas Scrubber

Steam from Radiant Syngas Cooler

Flare

CO2

Shift Reaction (Future)

Recycle to Process

Water to Radiant Syngas Cooler

Radiant Syngas Cooler (RSC)

Ambient Air

Future

11

+53%+38%+63%Cost of Electricity

-20 to 25%-18% to 22%-30% to 35%Efficiency

+85% to 90%+30% to 40%+65% to 75%Capital Cost

NGCCIGCCPulverized Coal

Impact of Adding CO2 Capture

CO2 Capture – Eastern Bituminous Coal

Carbon capture (“scrubbing”) is a difficult and expensive process:– CO2 is a very stable

molecule– CO2 concentration is very

low in flue gases– Amine processes (MEA) are

the only currently proven approach - high capital cost

– A large amount of steam is required to regenerate the amine (strip the CO2 from the “carbon getter”) – large efficiency penalty

0

500

1000

1500

2000

2500

PC w/o CO2 PC w/CO2 IGCC w/oCO2 IGCC w/CO2

Capital Cost$/kW Heat Rate x10 (BTU/kWh)

Source: AEP , EPRI, and US DOE

3000

1212

Investing in IGCC

IGCC technology is strategic to keeping coal in the money IGCC technology is strategic to keeping coal in the money

13

Integrated Gasification Combined Cycle’s Promise

• Lowest capital cost (when mature) coal-based technology

• Feedstock & product flexibility (with added cost)– Coal, petcoke, or biomass feedstocks– Electricity, steam, syngas, liquid fuels, or chemical products

• Most efficient coal-based technology (when mature)• Best emission characteristics among coal-based

technologies• Most carbon-friendly coal technology• The technology of choice to KEEP COAL IN THE

MIX– Strategically important to the energy security and economies

of many states and the U.S.

14

AEP’s IGCC Investment• 600 MW Plant built by 2010; Another 600 MW by 2013

– Front-End Engineering & Design and environmental permitting underway on both plants

– Transmission studies requested of PJM

• Sites being considered include: – Meigs County, OH– Mason County, WV (adjacent to Mountaineer Plant)

• Regulatory cost recovery– Filed cost recovery plan with PUCO in 2005; Phase I approved– Filed Certificate of Convenience and Necessity in WV in 2006

• R&D Activities– Mountaineer Sequestration Project– FutureGen participation

15

Public policy tools to support IGCC:(Ohio example)

1. Public Utilities Commission suggested IGCC plant be built

3. AEP Ohio filed plan (March 2005) for recovering costs for 600 MW plant in operation mid-2010– Phase 1 (2006): $23.7 million for site engineering and plant

design approved on April 10, 2006. – Phase 2 (2007-2010): $237.4 million to recover financing

costs. Case to be filed in November 2006.– Phase 3: Recover $1.033 billion estimated plant cost over

its 40-year operating life with a regulated return on the investment. Case to be filed at conclusion of construction.

2. Need pre-construction assurance investment is recoverable

16

Leadership

• Choosing IGCC is not just a technology decision; it’s a leadership decision– If not AEP, then who?– If not coal, then what?

• Being a leader has its perils and risks– Partnerships and cooperation are necessary for

success• Federal and State Governments have a

critical role– Provide incentives and remove roadblocks