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New Generation Strategy

IGCC Technology

New Generation Strategy

IGCC TechnologyPresented by:

Mary Zando, Manager

Chemical Systems,

New Generation Projects

Dan Duellman, Manager

Mechanical & Balance of Plant,

New Generation Projects

Monty Jasper, Manager

New Plant Development Projects

APP Site Visit

October 30 – November 4, 2006

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Revenues: $14.5 billion

Assets: $37 billion

US customers: 5 million

US employees: 22,000

Source: AEP 2003 Annual Report

The American Electric Power System

100 years in operation

36,000 MW generation capacity – more than 70% coal Largest generator of electricity in US Largest coal purchaser and consumer – over 70 million

short tons (64 million metric tons) per year

39,000 miles (62,000 km) transmission 7,900 miles (12,600 km) 230 – 765 kV

200,000 miles (320,000 km) distribution 5 million customers in

11 states

$11.9 billion annual revenue $36.2 billion assets

Source: AEP 2005 Annual Report

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The American Electric Power System

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Revenues: $14.5 billion

Assets: $37 billion

US customers: 5 million

US employees: 22,000

Source: AEP 2003 Annual Report

AEP Today: The Need for New Generation

AEP is committed to providing reliable, affordable, and sustainable electricity to our 5 million customers.

AEP has not added base load capacity since 1991 (Zimmer conversion)

AEP will need approximately 1200 MW of additional generating capacity in our Eastern region by 2010

AEP believes that Integrated Gasification Combined Cycle (IGCC) technology is the best choice for capacity additions in the East

Lansing

Indianapolis

FrankfortAshland

Charleston

Ft.Wayne

South Bend

Wheeling

Indiana

Ohio

Michigan

Kentucky

Tennessee

Columbus

Richmond

VirginiaWest

Virginia

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Site Selection & Evaluation Process

Where is the best site to build a new IGCC Power Plant in AEP East? Site Study Team Established

Representatives from AEP Third Party Consultant retained for study

Potential Sites Identified AEP existing plants sites AEP owned/controlled property Fatal Flaw Analysis to narrow list 15 sites identified for evaluation

Developed Ranking Criteria Established Design Basis

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Design Basis - Key Siting Parameters

600 MW IGCC Unit (with option to expand to 1200 MW) 2 x 2 x 2 x 1 Configuration

2 Operating Gasifiers / Gas Cleanup Systems 2 Combustion Turbines 2 Heat Recovery Steam Generators 1 Steam Turbine

600 MW 1200 MW

Fuel Consumption 2 million(1.8 million)

4 million(3.6 million)

short tons per year(metric tons per year)

Heat Rate HHV 8,500 (2,142) 8,500 (2,142) Btu/kWh (kcal/kWh)

Make-up water flow 5,500 (347) 11,000 (693) gallons per minute (liters per second)

Land Requirements:

power block 30 (12) 45 (18) acres (hectares)

gasification island 60 (24) 105 (43) acres (hectares)

rail loop 150 (60) 150 (60) acres (hectares)

coal yard 40 (16) 40 (16) acres (hectares) inside rail loop

solid waste disposal 150 (60) 300 (121) acres (hectares)

Total (rail delivery) 390 (158) 600 (243) acres (hectares)

Total (barge delivery) 280 (113) 490 (198) acres (hectares)

Operating staff 125 200 full time equivalent employees

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Site Selection Ranking Criteria

Site Topography Topography and Size Expandability Distance from Waste Disposal Flood Potential Constructability

Air & Water – Environmental Distance from Class I Areas Dispersion Conditions Existing Air Quality Air Quality Non-Attainment Area CO2 Sequestration - Third Party

Desktop Study Transmission

Distance from Transmission Transmission Stability Feasibility of 2 Unit Transmission

plan

Fuel Delivery Distance from Rail or Barge Alternate Transportation Distance from Natural Gas Pipeline Delivered Coal Cost Differential

Cooling Water Distance from Adequate Water Source Adequacy of Cooling Water Source

Land Use Designated Parks & Recreation Areas Existing Land Use Existing Residences Nearby Land Use

Habitat Wetlands Impact Potential Other Natural Habitats Impact Potential Documented Presence of Threatened

and Endangered Species

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Site Selection Ranking Criteria

Weighting Factors Scale of 1 - 10

Rating Factors Scale of 1 – 5

Example below

Criteria Description Weighting Factor

Evaluation Criteria Rating Factor

Plant Site Topography and Size 8 0.5 to 1.0 percent slope and less than 100,000 c.y. (76,000 cubic meters) fill

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1.0 to 2.0 percent slope or 100,000 to 300,000 c.y. (76,000 to 228,000 cubic meters) fill

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2.0 to 3.0 percent slope or 300,000 to 600,000 c.y. (228,000 to 456,000 cubic meters) fill

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3.0 to 4.0 percent slope or 600,000 to 1,000,000 c.y. (456,000 to 760,000 cubic meters) fill

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4.0 to 5.0 percent slope or more than 1,000,000 c.y. (760,000 cubic meters) fill

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Expandability for Future Units 7 Three or more units can fit on site 5

Only two units can fit on site 3

Only one unit can fit on site 1

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Results

Top Sites by State Mountaineer – West Virginia Great Bend – Ohio Carrs - Kentucky

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Generating Technology Options: Integrated Gasification Combined Cycle (IGCC) Plants

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Business Models of Various Technology Suppliers Syngas over the fence

Technology owner provides capital investment and operating services

Cost of syngas may be tied to fuel cost, escalation, other factors

Also oxygen over the fence Licensing

Technology owner provides equipment design and performance guarantees for equipment

Owner assumes risk of integrated unit performance Turn key EPC with performance guarantees

Technology owner provides engineering and design of integrated unit and all components

Technology owner also assumes cost and schedule risk Guaranty of total unit performance: inputs vs. outputs

Gasification Technology Options

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Commercial Technology Choices Slurry fed – Conoco, GE

Slurry fed technologies suited to high rank fuels Dry fed – Shell

Better heat rate, longer injector life Technology suited for lower rank subituminous coals as well

as high rank fuels Heat Recovery/Integration

Quench – GE Chemical production applications

Radiant syngas cooler – GE, Conoco, Shell Heat recovery for power generation in steam turbine

Convective syngas cooler – GE Availability impact due to plugging – not selected for

reference plant

Gasification Technology Options

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Current Configuration – AEP East IGCC

Net output 621 MW, Heat Rate 8,890 Btu/kWh (2,240 kcal/kWh) Target turndown to 40% of full load, and load following operation

- Broad fuel specification (eastern bituminous coal, petcoke) GE (formerly Texaco) Gasifiers

- Two radiant + quench gasifiers – no spare- Operating pressure 625 psi (43 bar)

Turbine-Generators- Two GE 7FB combustion turbines - 232 MW each

Evaporative inlet cooling- Single steam turbine – 300 MW

Emissions Control Systems- Selexol acid gas removal system for sulfur (H2S) removal w/COS reactor

- Activated carbon bed for mercury removal- Syngas moisturization, nitrogen diluent for NOx control

Space provisions for future polygeneration and CO2 capture

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The gasifier operates at approximately 625 psi (43 bar) and 2550oF (1400oC)

Gasifier volume 1800 cubic ft (50.4 cubic meters)

The RSC generates high pressure steam by cooling the hot syngas from the gasifier from 2550oF to 1250oF (1400oC to 700oC).

The RSC vessel is lined with waterwall panels along the inside perimeter of the vessel as well as some in the radial direction. The steam is generated in the RSC and circulated to the external steam drum.

The RSC concept has been demonstrated at plants in Germany as well as Coolwater and Polk Power in the USA. The vessel is about 6 m in diameter and 30-40 m long.

The AEP RSC design is different than the Polk Power design because it has an internal water quench section at the vessel bottom which further cools the syngas at about 450oF (230oC).

Gasifier/Radiant Syngas Cooler (RSC)

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When the gasifier load changes the oxygen to slurry ratio remains constant because the oxygen to carbon ratio is part of the control system.

The gasifier is connected to the RSC through a flange connection. The vessel heads and flanges are protected by the refractory lined transfer line.

The molten slag from the gasifier solidifies as it cools inside the RSC, and is collected in a water quench section at the bottom of the RSC. The slag and fines are removed through a lockhopper (LH) system which is automatically cycled to collect the slag at high pressure. The LH is then isolated and depressurized, and slag is dumped. The LH is re-pressurized and returned to collection mode. There will be 2 to 3 LH cycles per hour, depending on the fuel ash content.

Gasifier/Radiant Syngas Cooler (RSC)

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The velocity from the gasifier to the RSC decelerates from 15-20 feet per second (5-6 meters per second) to less than 3 feet per second (1 meter per second).

The velocity profile of the syngas from the gasifier to the RSC is based upon jet flow calculations. The jet velocity when it hits the waterwall cannot be so high that it causes erosion and cannot be low enough to allow ash deposition.

Gasifier/Radiant Syngas Cooler (RSC)

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95% oxygen purity for oxygen to gasifier – 98% other uses Economy, ability to maintain design composition when changing

loads ASU will consume ~110 MW depending on fuel and ambient conditions Air integration

Approximately 25-30% of flow to main air compressor supplied by extraction air from CT at design point (ISO)

Lessons learned from Polk Unit output curtailed due to lack of ASU capacity

ASU Turndown Compressor limited to approximately 85% Can adjust air extraction to extend range

No plans to produce other gases for sale Storage capacity

8 hours full load oxygen use Nitrogen for purge, transfer CT to natural gas in case of ASU trip

Air Separation Unit

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Fuel Flexibility The gasification process can utilize any fuel containing hydrocarbons

Coal Biomass Petroleum Byproducts

Petcoke The AEP East IGCC design fuels include Northern Appalachian and

Illinois Basin bituminous coals and the ability to blend petcoke with coal

Technology selection is dependant on fuel Eastern Coal – Low moisture content, high heating value

Many eastern coals have high ash fusion temperatures, requiring the use of fluxant

Some eastern coals have high chloride content Lignite & PRB coals – High moisture content, high ash content, not

currently suited for slurry fed gasifiers, due to ability to achieve desired slurry concentration.

Gasification Fuel Options

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Impact of coal specifications

Coal ash fusion temperature - This is a slagging gasifier design which requires a less than 2500oF (1370oC) reducing ash fusion temperature. Coals with this low fusion temperatures are found in the Northern Appalachian and Illinois Basin. Coal in the Central and Southern Appalachian basin have high fusion temperatures and would require the addition of fluxant to suppress the ash fusion temperature. A fluxing system is currently not part of the AEP IGCC design.

Sulfur content range - The design sulfur content of the fuel effects the sizing of the Acid Gas Removal (AGR) and Sulfur Recovery Unit (SRU) systems. Coals from the Northern Appalachian and Illinois Basin have high sulfur content coals. The AEP coal specification allows for coals with sulfur content up to 7.5 lb SO2/mmBtu (5.26% wt. sulfur dry basis).

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Impact of coal specifications (cont.)

Chloride content Coals from the Illinois Basin have high levels of chlorides. For

IGCC technology, the chlorides are removed in the syngas cleaning systems. High chlorides may require the selection of higher alloys in certain systems, and may increase water usage. The AEP design provides for coal chlorides up to 3500 ppm (0.35% wt.).

Coal ash percentage Nearly all of the ash is removed from the gasifier as slag. The ash

content of the fuel determines the size of the slag handling systems. The AEP specification allows for ash content in the fuel up to 12%. This allows the use of many run-of-mine coals, with no coal washing needed.

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Coal Prep System

Rod mills are used to mix and pulverize the coal. Dry coal and processes water is added to the rod mills. Coal slurry is then pumped into the gasifier at operating pressure.

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There are two syngas/natural gas fired combustion turbines. The combustion turbine selected is the GE 7FB designed for syngas. Each turbine can generate 232 MW, utilizes air inlet cooling, and uses a hydrogen cooled generator.

Nitrogen from the ASU and steam will be added to the syngas to increase mass flow and reduce the flame temperature. This feature enhances the output of the turbine, and allows for lower NOx operation.

The HRSG is a two pressure design, which converts the heat from the exhaust of each combustion turbine into superheated steam. The HRSGs also receive steam from the gasification process.

The steam turbine used is a GE D-111 with 40 inch (1 m) last stage blades. Steam in condensed by a water tube condenser. The steam turbine output is 310 MW, and uses a hydrogen cooled generator.

The cooling tower provides circulating water for both the steam turbine condenser, and cooling loads from the ASU. The cooling tower is a mechanical draft type.

Power Block

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NOx 15 ppm NOx in exhaust gas (15% O2 ref) on syngas

25 ppm NOx in exhaust gas (15% O2 ref) on natural gas SO2

>99.5% removal 40 ppm total sulfur in syngas (H2S + COS)

0.02 lb SO2/mmBtu

~4 ppm total sulfur in exhaust gas (10% O2 ref) Particulates (PM10 and PM2.5) Mercury

Activated carbon bed for mercury removal Expect 90% of mercury in syngas

Other Hazardous Air Pollutants Startup considerations Environmental performance without CO2 removal comparable to

supercritical PC equipped with state of the art emissions controls

Air Emissions

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Acid gas technology choice MDEA – amine technology – chemical solvent Selexol – allows for deeper sulfur removal – physical solvent Rectisol – methanol solvent

Cost vs. effectiveness Depends on gas composition, sulfur removal desired

Capital O&M Effect on output

COS Hydrolysis Effects on total emissions COS removal in AGR varies from <10% (MDEA) to 100% (Rectisol) COS reactor required to cost effectively meet 99% sulfur removal

in MDEA and Selexol systems

Sulfur Removal

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Diluent injection Nitrogen – from ASU – increase CT mass flow/output CO2 – maximize slip in AGR – increase CT mass flow/output Steam – impact on steam cycle output

SCR Cost Uncertainty of catalyst formulation for coal derived syngas Interaction with sulfur

Ammonia salts produce particulate emissions, may deposit in HRSG

Other Air Emissions Particulate – salts, H2SO4

Ammonia – 5 ppm slip (ref 15% O2)

NOx Control

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Flare Options

Flare used to destroy raw or combustible gases during startup, shutdown, and transient events

Flare emissions result in elevated ground level concentrations of SO2

Operational and hardware modifications to reduce duration of flare events

Visibility low during daylight hours

Elevated Flare (AEP plant) Flare height 200 ft (60 m)

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Flare Options

Ground Level Flare

Enclosed Flare

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Current plan to discharge wastewater to Ohio River The discharge permits and their associated limits are set by the

state where the plant is sited The Ohio River Valley Water Sanitation Commission (ORSANCO) is

an organization that tries to address inconsistencies between states and proposes pollution control standards (www.orsanco.org).

ORSANCO discharge targets are set to protect the users of the water and avoid water quality degradation

The target values for some elements are very low

Wastewater Effluents

Parameter River Max Dissolved

River Max Total

Grey Water Cool Water

IGCC

Discharge Target

Average/Max

Mercury, ppt 1.93 13.1 630 10/20

Beryllium, ppb <0.2 <0.2 230 0.1/0.2

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Uncertainty of grey water composition Samples not available for jar tests Potential interferences in treatment Uncertainty on levels achievable level of treatment Detection Limits Historic data

Toxicity Chlorides in the effluent Daphnia survivability

Temperature

Wastewater Treatment Challenges

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Wastewater Treatment Process

Ammonia stripping

Grey Water Pretreatment

Wastewater treatment

Metals Removal

Biological treatment Filter

Final Effluent Sump

RetentionPond

LimeSulfide

Phosphoric acidAeration

Sludge Thickening

Filter Belt Presses

Makeup watersludge

Sludge to landfill

Holding Tank

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Zero liquid discharge system currently under evaluation Reduced effluent to river Capital cost still to be determined Uncertainties in grey water composition would also affect this

design Potentially higher auxiliary power consumption for this system Possibility of recovering metals for sale

Wastewater Effluents

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Byproduct disposition (Primarily Slag and Sulfur) Slag is the primary waste product produced by the IGCC process

The carbon content of the slag is the key parameter that effects the ability to market the product.

Slag is sold as roofing materials, grit blasting materials, and concrete additive. The acceptable carbon content for each of these applications is critical to its marketability.

The AEP plant will be designed with landfill capacity for disposal of slag.

Sulfur is a byproduct of the AGR system/sulfur recovery system. Sulfur can be produced as sulfuric acid, molten sulfur, or

pelletized or prilled sulfur. Local market condition will dictate the form of sulfur produced.

The AEP plant will be designed to produce molten sulfur. Landfill capacity will include space for sulfur disposal.

Solid Effluents

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Coal Storage

Unit 1

Unit 2

AEP Work Scope

GE/Bechtel Work Scope

UNIT 2 COOLING

TOWER FUTURE

UNIT 1 COOLING

TOWER

SRU – Sulfur Recovery Unit

Visitors Center

Truck Unloading

Future

Barge Unloader #1

Future

Barge Unloader #2

Flare

Flare

SRU

GSPB

PB

Maintenance Building/ Warehouse

Admin Building/ Control Room

345 KV Switchyard

Landfill Storage Pile

-345 KV Switchyard-Slag Handling & Storage-Coal Unloading-Coal Storage-Water Intake

TGT – Tail Gas Treating Unit AGR – Acid Gas Removal ASU – Air Separation Unit PB – Power BlockGS - Gasifier

River Water Intake House

ASU

TGT

AGR

Fluxing System

Future

Future

Future

CO2

CO2 -Future CO2 CaptureEquipment

Future Polygen

Future Polygen

Smathers

Great Bend IGCC Plant Scope of Work

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Great Bend - Site with Landfill & Property Lines

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Mountaineer IGCC Plant

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Great Bend IGCC Plant

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Startup Fuel

Natural gas to warm gasifier, electric demand for ASU Emissions

Time to place sulfur systems in service Time to start up

Over 70 hours for cold startup Turndown

Target to 40% net Availability

Target 85% Maintenance requirements

Refractory replacements Hot gas path turbine inspections

Production costs On par with conventional PC

Operational Considerations

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Evaluate capital cost for design features vs. benefits Screening Valuations

Capacity $1.5 million/MW Heat rate $5.0 million/100 Btu/kWh

($5.0 million/25.2 kcal/kWh) Availability $3.5 million/percentage point of availability

1st quarter 2005 – based on operating characteristics of similar sized plant in Ohio River Valley

Critical assumptions – fuel cost, capacity factor, production cost

Economic Considerations

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• Value of emissions credits is not included. • Assumes 80% capacity factor for PC and IGCC, 25% for NGCC. • EPC is overnight engineer, procure, construct 4Q2004. • Total project cost includes owner’s costs and AFUDC. • Transmission upgrades not included. • Results of AEP analysis based on EPRI studies.

Generating Technology Options:Cost of Electricity without CO2 Capture

PC

Supercritical

IGCC NGCC

Capacity, MW net 600 600 500

Fuel cost, $/mmBtu 1.50 1.50 6.00

Full Load Heat Rate, Btu/kWh 8,691 8,500 7,040

EPC Cost, $/kW 1,192 1,450 455

Total Project Cost, $/kW 1,442 1,737 550

Operations and Maintenance, $/MWh 8.49 9.63 6.66

Cost of Electricity, $/MWh 53.11 60.33 88.25

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CO2 Capture

Carbon capture (CO2) in IGCC system (syngas fuel) is proven and inexpensive:

Convert CO in syngas to CO2 using water-gas shift reactionCO + H2O CO2 + H2

Remove CO2 before the fuel is burned in the CT Lower volume of gases for processing Higher concentration of CO2

Either chemical (amine) or physical solvents IGCC stands out due to lower cost of CO2 removal

Commercial application depends on H2 burning CT technology

CO2 capture in flue gas (PC & NGCC application) more difficult: Flue gas volumes larger – lower pressure, combustion air Low CO2 partial pressure – physical solvents are impractical Amines (MEA or MDEA) applicable – but overall system becomes

expensive More work is needed on CO2 capture technology & cost from flue

gas in PC & NGCC applications

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CO2 Capture

Recent work indicates significant impact on cost of electricity to implement CO2 capture and sequestration:

Price adder will depend on the extent of CO2 capture

Cost of electricity for IGCC plants with CO2 capture expected to be lower than PC with CO2 capture

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• Value of emissions credits is not included. • Assumes 80% capacity factor for PC and IGCC. • Results of AEP analysis based on EPRI studies.

Generating Technology Options:Cost of Electricity with CO2 Capture

PC

Supercritical

IGCC

Capacity, MW net 425 501

Fuel cost, $/mmBtu 1.50 1.50

Full Load Heat Rate, Btu/kWh 12,100 10,700

Cost of Electricity, $/MWh 94 85

CO2 Removal Cost, $/ton 22 16

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No pre-investment for carbon capture Space in plot plan to be left for retrofit systems Clean shift will result in greater impact to steam cycle

Carbon Capture from Syngas

Gasifier Low-temperature syngas cooler (LTGC)

Low-pressure compressor (LP comp)

High-pressure compressor (HP comp)

Acid-gas removal (AGR)

Sulfur removal unit (SRU)

COAL

Tail-gas unit (TGU)

H2-rich syngasto Power Block(CT/HRSG)

Syngas Saturation

ShiftReactor(s)

MPsteam

CO2Absorber

CO2to capture

For internal utilization

N2 blending equipment

Syngas compressor

N2dilution

NEW RETROFIT UNITS

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Maintaining full load on gasifier at all times

Synergies with other stakeholders

Syngas contains H2, CO, CO2

Important building blocks in chemical manufacturing Potential to replace natural gas, petroleum in chemical

processes Polygeneration – production of power and chemicals at an IGCC

plant

Gases from air plant Argon Nitrogen Oxygen

Polygeneration Options

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Screening Study considered production of hydrogen, methanol, urea Methanol selected for further consideration

Ease of storage/transport Possible in-plant use

Start up fuel AGR solvent

Study assumptions Need to cycle daily Produce fuel grade product Conventional process

Capacity factor

Polygeneration Options