cost and performance baseline for fossil energy plants national energy technology laboratory may 15,...

Cost and Performance Baseline for Fossil Energy Plants

National Energy Technology Laboratory

May 15, 2007Revised August 2007

Final Results

Revised 7/27/072

DisclaimerThis presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

Revised 7/27/073

Objective Determine cost and performance estimates of

near-term commercial offerings for power plants both with and without current technology for CO2 capture Consistent design requirements Up-to-date performance and capital cost estimates Technologies built now and deployed by 2010-2012

Provides baseline costs and performance Compare existing technologies Guide R&D for advancing technologies within the FE

Program

Revised 7/27/074

Study Matrix

Plant

Type

ST Cond.

(psig/°F/°F)GT

Gasifier/

Boiler

Acid Gas Removal/

CO2 Separation / Sulfur Recovery

CO2

Cap

IGCC

1800/1050/1050 (non-CO2

capture cases)

1800/1000/1000

(CO2 capture cases)

F Class

GESelexol / - / Claus

Selexol / Selexol / Claus 90%

CoP

E-Gas

MDEA / - / Claus

Selexol / Selexol / Claus 88%1

ShellSulfinol-M / - / Claus

Selexol / Selexol / Claus 90%

PC

2400/1050/1050

SubcriticalWet FGD / - / Gypsum

Wet FGD / Econamine / Gypsum 90%

3500/1100/1100

Supercritical

Wet FGD / - / Gypsum

Wet FGD / Econamine / Gypsum 90%

NGCC 2400/1050/950 F Class HRSG- / Econamine / - 90%

GEE – GE EnergyCoP – Conoco Phillips

1 CO2 capture is limited to 88% by syngas CH4 content

Revised 7/27/075

Design Basis: Coal Type

Illinois #6 Coal Ultimate Analysis (weight %)

As Rec’d Dry

Moisture 11.12 0

Carbon 63.75 71.72

Hydrogen 4.50 5.06

Nitrogen 1.25 1.41

Chlorine 0.29 0.33

Sulfur 2.51 2.82

Ash 9.70 10.91

Oxygen (by difference) 6.88 7.75

100.0 100.0

HHV (Btu/lb) 11,666 13,126

Revised 7/27/076

Environmental Targets

PollutantIGCC1 PC2 NGCC3

SO20.0128

lb/MMBtu0.085

lb/MMBtu< 0.6 gr S /100

scf

NOx15 ppmv (dry)

@ 15% O2

0.07 lb/MMBtu

2.5 ppmv @ 15% O2

PM0.0071

lb/MMBtu0.017

lb/MMBtuNegligible

Hg > 90% capture1.14 lb/TBtu

Negligible

1 Based on EPRI’s CoalFleet User Design Basis Specification for Coal-Based IGCC Power Plants2 Based on BACT analysis, exceeding new NSPS requirements3 Based on EPA pipeline natural gas specification and 40 CFR Part 60, Subpart KKKK

Revised 7/27/077

Economic Assumptions

Startup 2010

Plant Life (Years) 20

Capital Charge Factor, %

High Risk

(All IGCC, PC/NGCC with CO2 capture) 17.5

Low Risk

(PC/NGCC without CO2 capture) 16.4

Dollars (Constant) 2007

Coal ($/MM Btu) 1.80

Natural Gas ($/MM Btu) 6.75

Capacity Factor

IGCC 80

PC/NGCC 85

Revised 7/27/078

Technical Approach

1. Extensive Process Simulation (ASPEN) All major chemical processes and equipment are simulated Detailed mass and energy balances Performance calculations (auxiliary power, gross/net power output)

1. Extensive Process Simulation (ASPEN) All major chemical processes and equipment are simulated Detailed mass and energy balances Performance calculations (auxiliary power, gross/net power output)

2. Cost Estimation Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.) Sources for cost estimation

Parsons Vendor sources where available

Follow DOE Analysis Guidelines

2. Cost Estimation Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.) Sources for cost estimation

Parsons Vendor sources where available

Follow DOE Analysis Guidelines

Revised 7/27/079

Study Assumptions

Capacity Factor assumed to equal Availability IGCC capacity factor = 80% w/ no spare gasifier PC and NGCC capacity factor = 85%

GE gasifier operated in radiant/quench mode Shell gasifier with CO2 capture used water injection for

cooling (instead of syngas recycle) Nitrogen dilution was used to the maximum extent possible in

all IGCC cases and syngas humidification/steam injection were used only if necessary to achieve approximately 120 Btu/scf syngas LHV

In CO2 capture cases, CO2 was compressed to 2200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,055 feet and monitored for 80 years

CO2 transport, storage and monitoring (TS&M) costs were included in the levelized cost of electricity (COE)

Revised 7/27/0710

IGCC Power Plant

Current State-of-the-Art

Revised 7/27/0711

Current TechnologyIGCC Power Plant

Emission Controls:PM: Water scrubbing and/or candle filters to get 0.0071 lb/MMBtu NOx: N2 dilution to ~120 Btu/scf LHV to get 15 ppmv @15% O2

SOx: AGR design target of 0.0128 lb/MMBtu; Claus plant with tail gas recycle for ~99.8% overall S recovery

Hg: Activated carbon beds for ~95% removal

Advanced F-Class CC Turbine: 232 MWe

Steam Conditions:1800 psig/1050°F/1050°F (non-CO2 capture cases)

1800 psig/1000°F/1000°F (CO2 capture cases)


SOx: AGR design target of 0.0128 lb/MMBtu; Claus plant with tail gas recycle for ~99.8% overall S recovery



Steam Conditions:1800 psig/1050°F/1050°F (non-CO2 capture cases)

1800 psig/1000°F/1000°F (CO2 capture cases)

Revised 7/27/0712

GE Energy Radiant

Coal

Cryogenic Oxygen

Slag/Fines

Water

High Pressure

Steam

Radiant Syngas Cooler

Radiant Quench Gasifier

SyngasScrubber

Solids

Saturated Syngas 398OF

Quench Chamber

2,500OF

1,100OF

419OF

Coal

Cryogenic Oxygen

Slag/Fines

Water

High Pressure

Steam

Radiant Syngas Cooler

Radiant Quench Gasifier

SyngasScrubber

Solids

Saturated Syngas 398OF

Quench Chamber

2,500OF

1,100OF

419OF

Coal Slurry63 wt.%

95% O2

Slag/Fines

Syngas 410°F, 800 Psia

Composition (Mole%):H2 26%CO 27%CO2 12%H2O 34%Other 1%H2O/CO = 1.3

Design: Pressurized, single-stage, downward firing, entrained flow, slurry feed, oxygen blown, slagging, radiant and quench cooling

Note: All gasification performance data estimated by the project team to be representative of GE gasifier

To Acid Gas Removalor

To Shift

Revised 7/27/0713

ConocoPhillips E-Gas™

Coal Slurry63 wt. %

Stage 2

95 % O2Slag

Quench

Char

Slag/Water Slurry

Syngas Syngas1,700°F, 614 psia

Composition (Mole%):H2 26%CO 37%CO2 14%H2O 15%CH4 4%Other 4%H2O/CO = 0.4

(0.78)

(0.22)

Stage 12,500oF

614 Psia

To Fire-tube boiler

Design: Pressurized, two-stage, upward firing, entrained flow, slurry feed, oxygen blown, slagging, fire-tube boiling syngas cooling, syngas recycle

Note: All gasification performance data estimated by the project team to be representative of an E-Gas gasifier


To Shift

Revised 7/27/0714

Shell Gasification

Syngas350°F, 600 Psia

Composition (Mole%):H2 29%CO 57%CO2 2%H2O 4%Other 8%H2O/CO = 0.1

DryCoal

Design: Pressurized, single-stage, downward firing, entrained flow, dry feed, oxygen blown, convective cooler

Convective CoolerSoot Quench& Scrubber

95% O2

HP Steam

650oF

Steam

Source: “The Shell Gasification Process”, Uhde, ThyssenKrupp Technologies

Syngas Quench2

Notes: 1. All gasification performance data

estimated by the project team to be representative of Shell gasifier.

2. CO2 capture incorporates full water quench instead of syngas quench.


To Shift

HP Steam

Slag

Gasifier2,700oF

615 psia

Revised 7/27/0715

IGCC Performance ResultsNo CO2 Capture

GE Energy E-Gas Shell

Gross Power (MW) 770 742 748

Auxiliary Power (MW)

Base Plant Load 23 25 21

Air Separation Unit 103 91 90

Gas Cleanup 4 3 1

Total Aux. Power (MW) 130 119 112

Net Power (MW) 640 623 636

Heat Rate (Btu/kWh) 8,922 8,681 8,304

Efficiency (HHV) 38.2 39.3 41.1

Revised 7/27/0716

IGCC Economic ResultsNo CO2 Capture

GE Energy E-Gas Shell

Plant Cost ($/kWe)1

Base Plant 1,323 1,272 1,522

Air Separation Unit 287 264 256

Gas Cleanup 203 197 199

Total Plant Cost ($/kWe) 1,813 1,733 1,977

Capital COE (¢/kWh) 4.53 4.33 4.94

Variable COE (¢/kWh) 3.27 3.20 3.11

Total COE2 (¢/kWh) 7.80 7.53 8.05

1Total Plant Capital Cost (Includes contingencies and engineering fees)

2January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/106Btu

Revised 7/27/0717

IGCC Power Plant

With CO2 Capture

Revised 7/27/0718

Current TechnologyIGCC Power Plant with CO2 Scrubbing


SOx: Selexol AGR removal of sulfur to < 28 ppmv H2S in syngas Claus plant with tail gas recycle for ~99.8% overall S recovery



Steam Conditions: 1800 psig/1000°F/1000°F


SOx: Selexol AGR removal of sulfur to < 28 ppmv H2S in syngas Claus plant with tail gas recycle for ~99.8% overall S recovery




Revised 7/27/0719

Shift 1 Shift 2 Shift 3

Water-Gas Shift Reactor System

H2O/CO Ratio1

GE 1.3

E-Gas 0.4

Shell 1.5

Design: Haldor Topsoe SSK Sulfur Tolerant Catalyst Up to 97.5% CO Conversion 2 stages for GE and Shell, 3 stages for E-Gas H2O/CO = 2.0 (Project Assumption) Overall P = ~30 psia

775oF 450oF 500oF 450oF Cooling

Relative HP* Steam Flow

Steam Turbine Output (MW)

GE 1.0 275

E-Gas 2.4 230

Shell 0.9 230

455oF

Steam Steam

H2O + CO CO2 + H2

*High Pressure Steam

1 Prior to shift steam addition

Revised 7/27/0720

IGCC Performance Results

GE Energy

CO2 Capture NO YES

Gross Power (MW) 770 745


Base Plant Load 23 23

Air Separation Unit 103 121

Gas Cleanup/CO2 Capture 4 18

CO2 Compression - 27

Total Aux. Power (MW) 130 189

Net Power (MW) 640 556

Heat Rate (Btu/kWh) 8,922 10,505

Efficiency (HHV) 38.2 32.5

Energy Penalty1 - 5.7

1CO2 Capture Energy Penalty = Percent points decrease in net power plant efficiency due to CO2 Capture

in ASU air comp. load w/o CT integration

Steam for Selexol

Includes H2S/CO2 Removal in Selexol

Solvent

Revised 7/27/0721

IGCC Performance ResultsGE Energy E-Gas Shell

CO2 Capture NO YES NO YES NO YES

Gross Power (MW) 770 745 742 694 748 693


Base Plant Load 23 23 25 26 21 19

Air Separation Unit 103 121 91 109 90 113

Gas Cleanup/CO2 Capture 4 18 3 15 1 16

CO2 Compression - 27 - 26 - 28

Total Aux. Power (MW) 130 189 119 176 112 176

Net Power (MW) 640 556 623 518 636 517

Heat Rate (Btu/kWh) 8,922 10,505 8,681 10,757 8,304 10,674

Efficiency (HHV) 38.2 32.5 39.3 31.7 41.1 32.0

Energy Penalty1 - 5.7 - 7.6 - 9.1


Revised 7/27/0722

IGCC Economic ResultsGE Energy E-Gas Shell


Plant Cost ($/kWe)1

Base Plant 1,323 1,566 1,272 1,592 1,522 1,817

Air Separation Unit 287 342 264 329 256 336



Total Plant Cost ($/kWe) 1,813 2,390 1,733 2,431 1,977 2,668

Capital COE (¢/kWh) 4.53 5.97 4.33 6.07 4.94 6.66

Variable COE (¢/kWh) 3.27 3.93 3.20 4.09 3.11 3.97

CO2 TS&M COE (¢/kWh) 0.00 0.39 0.00 0.41 0.00 0.41

Total COE2 (¢/kWh) 7.80 10.29 7.53 10.57 8.05 11.04

Increase in COE (%) - 32 - 40 - 37

$/tonne CO2 Avoided - 35 - 45 - 46

1Total Plant Capital Cost (Includes contingencies and engineering fees)

2January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/106Btu

Revised 7/27/0723

Comparison to PC and NGCC

Current State-of-the-Art

Revised 7/27/0724

Current TechnologyPulverized Coal Power Plant*

PM Control: Baghouse to achieve 0.013 lb/MMBtu (99.8% removal)

SOx Control: FGD to achieve 0.085 lb/MMBtu (98% removal)

NOx Control: LNB + OFA + SCR to maintain 0.07 lb/MMBtu

Mercury Control: Co-benefit capture ~90% removal

Steam Conditions (Sub): 2400 psig/1050°F/1050°F

Steam Conditions (SC): 3500 psig/1100°F/1100°F

PM Control: Baghouse to achieve 0.013 lb/MMBtu (99.8% removal)

SOx Control: FGD to achieve 0.085 lb/MMBtu (98% removal)

NOx Control: LNB + OFA + SCR to maintain 0.07 lb/MMBtu

Mercury Control: Co-benefit capture ~90% removal

Steam Conditions (Sub): 2400 psig/1050°F/1050°F

Steam Conditions (SC): 3500 psig/1100°F/1100°F

*Orange Blocks Indicate Unit Operations Added for CO2 Capture Case

Revised 7/27/0725

Current TechnologyNatural Gas Combined Cycle*

NOx Control: LNB + SCR to maintain 2.5 ppmvd @ 15% O2


NOx Control: LNB + SCR to maintain 2.5 ppmvd @ 15% O2


*Orange Blocks Indicate Unit Operations Added for CO2 Capture Case

HRSG

MEA

Combustion Turbine

CO2 Compressor

Stack

Direct ContactCooler

Blower

Natural Gas

Air Cooling WaterStack Gas

CO2

2200 psig

Reboiler Steam

Condensate Return

Revised 7/27/0726

PC and NGCC Performance Results

Subcritical Supercritical NGCC


Gross Power (MW) 583 680 580 663 570 520

Base Plant Load 29 48 26 43 10 13


CO2 Compression - 52 - 47 0 15

Total Aux. Power (MW) 33 130 30 117 10 38

Net Power (MW) 550 550 550 546 560 482

Heat Rate (Btu/kWh) 9,276 13,724 8,721 12,534 6,719 7,813

Efficiency (HHV) 36.8 24.9 39.1 27.2 50.8 43.7

Energy Penalty1 - 11.9 - 11.9 - 7.1


Revised 7/27/0727

PC and NGCC Economic ResultsSubcritical Supercritical NGCC


Plant Cost ($/kWe)1

Base Plant 1,302 1,689 1,345 1,729 554 676

Gas Cleanup (SOx/NOx) 246 323 229 302 - -

CO2 Capture - 792 - 752 - 441


Total Plant Cost ($/kWe) 1,549 2,895 1,575 2,870 554 1,172

Capital COE (¢/kWh) 3.41 6.81 3.47 6.75 1.22 2.75

Variable COE (¢/kWh) 2.99 4.64 2.86 4.34 5.62 6.70

CO2 TS&M COE (¢/kWh) 0.00 0.43 0.00 0.39 0.00 0.29

Total COE2 (¢/kWh) 6.40 11.88 6.33 11.48 6.84 9.74

Increase in COE (%) - 85 - 81 - 43

$/tonne CO2 Avoided - 75 - 75 - 911Total Plant Capital Cost (Includes contingencies and engineering fees)

2January 2007 Dollars, 85% Capacity Factor, 16.4% (no capture) 17.5% (capture) Capital Charge Factor, Coal cost $1.80/106Btu, Natural Gas cost $6.75/106Btu

Revised 7/27/0728

Environmental Performance Comparison

IGCC, PC and NGCC

Revised 7/27/0729

Criteria Pollutant Emissions for All Cases

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.10

0.11

0.12

GE GEw/CO2

CoP CoPw/CO2

Shell Shellw/CO2

PC-sub PC-subw/CO2

PC-SC PC-SCw/CO2

NGCC NGCCw/CO2

Em

iss

ion

s (

lb/M

MB

tu)

SO2

NOx

PM

Hg0.0

0.2

0.4

0.6

0.8

1.0

1.2

GE GEw/CO2

CoP CoPw/CO2

Shell Shellw/CO2

PC-sub PC-subw/CO2

PC-SC PC-SCw/CO2

NGCC NGCCw/CO2

Hg lb/TBtu

Revised 7/27/0730

CO2 Emissions for All Cases

197

19.6

199

23.6

200

18.7

203

20.3

203

20.3

119

11.9

0

50

100

150

200

250

GE GEw/CO2

CoP CoPw/CO2

Shell Shellw/CO2

PC-sub

PC-sub

w/CO2

PC-SC PC-SCw/CO2

NGCC NGCCw/CO2

lb/M

MB

tu

Revised 7/27/0731

Raw Water Usage Comparison

IGCC, PC and NGCC

Revised 7/27/0732

Raw Water Usage per MWnet (Absolute)

6.3

8.2

6.0

8.0

6.0

8.8

11.3

25.7

22.3

4.5

9.79.9

0

5

10

15

20

25

30

GE GEw/CO2

CoP CoPw/CO2

Shell Shellw/CO2

PC-sub PC-subw/CO2

PC-SC PC-SCw/CO2

NGCC NGCCw/CO2

Ra

w W

ate

r U

sa

ge

, gp

m/M

Wn

et

Revised 7/27/0733

Raw Water Usage per MWnet (Relative to NGCC w/ no CO2 Capture)

1.4

1.8

1.3 1.3

2.52.2

1.0

5.7

2.2

5.0

2.0

1.8

0

1

2

3

4

5

6

GE GEw/CO2

CoP CoPw/CO2

Shell Shellw/CO2

PC-sub PC-subw/CO2

PC-SC PC-SCw/CO2

NGCC NGCCw/CO2

Revised 7/27/0734

Economic Results for All Cases

Revised 7/27/0735

CO2 Mitigation Costs

43

81

40

32

91

85

37

75 75

45

35

46

0

10

20

30

40

50

60

70

80

90

100

NGCC PC-Subcritical

PC-Supercritical

Shell E-Gas GE-Energy

% Increase in COE

$/tonne CO2 Avoided

Revised 7/27/0736

Total Plant Cost Comparison

Total Plant Capital Cost includes contingencies and engineering fees

1841

2496

1549

2895

1575

2870

554

1172

0

500

1000

1500

2000

2500

3000

Avg IGCC Avg IGCCw/ CO2Capture

PC-Sub PC-Sub w/CO2

Capture

PC-Super PC-Superw/ CO2Capture

NGCC NGCC w/CO2

Capture

$/k

W (

$2

00

6)

Revised 7/27/0737

Cost of Electricity Comparison

January 2007 Dollars, Coal cost $1.80/106Btu. Gas cost $6.75/106Btu

7.79

10.63

6.40

11.88

6.33

11.48

6.84

9.74

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

Avg IGCC Avg IGCCw/ CO2Capture

PC-Sub PC-Sub w/CO2

Capture

PC-Super PC-Superw/ CO2Capture

NGCC NGCC w/CO2

Capture

cent

s/kW

h ($

200 7

)

Revised 7/27/0738

Highlights

Revised 7/27/0739

NETL Viewpoint Most up-to-date performance and costs available in

public literature to date

Establishes baseline performance and cost estimates for current state of technology

Improved efficiencies and reduced costs are required to improve competitiveness of advanced coal-based systems In today’s market and regulatory environment Also in a carbon constrained scenario

Fossil Energy RD&D aimed at improving performance and cost of clean coal power systems including development of new approaches to capture and sequester greenhouse gases

Revised 7/27/0740

Result Highlights: Efficiency & Capital Cost Coal-based plants using today’s technology are

efficient and clean IGCC & PC: 39%, HHV (without capture on bituminous coal) Meet or exceed current environmental requirements Today’s capture technology can remove 90% of CO2, but at

significant increase in COE

Total Plant Cost: IGCC ~20% higher than PC capex NGCC: $554/kW PC: $1561/kW (average) IGCC: $1841/kW (average)

Total Plant Cost with Capture: PC > IGCC capex NGCC: $1169/kW IGCC: $2496/kW (average) PC: $2788/kW (average)

Revised 7/27/0741

Results Highlights: COE

20 year levelized COE: PC lowest cost generator PC: 64 mills/kWh (average) NGCC: 68 mills/kWh IGCC: 78 mills/kWh (average)

With CCS: IGCC lowest coal-based option NGCC: 96 mills/kWh IGCC: 105 mills/kWh (average) PC: 116 mills/kWh (average)

Breakeven LCOE* when natural gas price is: No Capture IGCC: $7.99/MMBtu PC: $6.15/MMBtu With Capture IGCC: $7.73/MMBtu PC: $8.87/MMBtu

* At baseline coal cost of $1.80/MMBtu

Revised 7/27/0742

Summary Table for All Cases

Revised 7/27/0743

Summary TableCase 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 9 Case 10 Case 11 Case 12 Case 13 Case 14

CO2 Capture No Yes No Yes No Yes No Yes No Yes No Yes

Gross Power Output (kWe) 770,350 744,960 742,510 693,840 748,020 693,555 583,315 679,923 580,260 663,445 570,200 520,090Auxiliary Power Requirement (kWe) 130,100 189,285 119,140 175,600 112,170 176,420 32,870 130,310 30,110 117,450 9,840 38,200Net Power Output (kWe) 640,250 555,675 623,370 518,240 635,850 517,135 550,445 549,613 550,150 545,995 560,360 481,890Coal Flowrate (lb/hr) 489,634 500,379 463,889 477,855 452,620 473,176 437,699 646,589 411,282 586,627 N/A N/ANatural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 165,182 165,182HHV Thermal Input (kWth) 1,674,044 1,710,780 1,586,023 1,633,771 1,547,493 1,617,772 1,496,479 2,210,668 1,406,161 2,005,660 1,103,363 1,103,363Net Plant HHV Efficiency (%) 38.2% 32.5% 39.3% 31.7% 41.1% 32.0% 36.8% 24.9% 39.1% 27.2% 50.8% 43.7%Net Plant HHV Heat Rate (Btu/kW-hr) 8,922 10,505 8,681 10,757 8,304 10,674 9,276 13,724 8,721 12,534 6,719 7,813Raw Water Usage, gpm 4,003 4,579 3,757 4,135 3,792 4,563 6,212 14,098 5,441 12,159 2,511 4,681Total Plant Cost ($ x 1,000) 1,160,919 1,328,209 1,080,166 1,259,883 1,256,810 1,379,524 852,612 1,591,277 866,391 1,567,073 310,710 564,628Total Plant Cost ($/kW) 1,813 2,390 1,733 2,431 1,977 2,668 1,549 2,895 1,575 2,870 554 1,172LCOE (mills/kWh)1

78.0 102.9 75.3 105.7 80.5 110.4 64.0 118.8 63.3 114.8 68.4 97.4CO2 Emissions (lb/hr) 1,123,781 114,476 1,078,144 131,328 1,054,221 103,041 1,038,110 152,975 975,370 138,681 446,339 44,634

CO2 Emissions (tons/year) @ CF1 3,937,728 401,124 3,777,815 460,175 3,693,990 361,056 3,864,884 569,524 3,631,301 516,310 1,661,720 166,172

CO2 Emissions (tonnes/year) @ CF1 3,572,267 363,896 3,427,196 417,466 3,351,151 327,546 3,506,185 516,667 3,294,280 468,392 1,507,496 150,750CO2 Emissions (lb/MMBtu) 197 19.6 199 23.6 200 18.7 203 20.3 203 20.3 119 11.9

CO2 Emissions (lb/MWh)2 1,459 154 1,452 189 1,409 149 1,780 225 1,681 209 783 85.8CO2 Emissions (lb/MWh)3

1,755 206 1,730 253 1,658 199 1,886 278 1,773 254 797 93

SO2 Emissions (lb/hr) 73 56 68 48 66 58 433 Negligible 407 Negligible Negligible Negligible

SO2 Emissions (tons/year) @ CF1 254 196 237 167 230 204 1,613 Negligible 1,514 Negligible Negligible Negligible

SO2 Emissions (tonnes/year) @ CF1 231 178 215 151 209 185 1,463 Negligible 1,373 Negligible Negligible NegligibleSO2 Emissions (lb/MMBtu) 0.0127 0.0096 0.0125 0.0085 0.0124 0.0105 0.0848 Negligible 0.0847 Negligible Negligible NegligibleSO2 Emissions (lb/MWh)2

0.0942 0.0751 0.0909 0.0686 0.0878 0.0837 0.7426 Negligible 0.7007 Negligible Negligible NegligibleNOx Emissions (lb/hr) 313 273 321 277 309 269 357 528 336 479 34 34NOx Emissions (tons/year) @ CF1 1,096 955 1,126 972 1,082 944 1,331 1,966 1,250 1,784 127 127NOx Emissions (tonnes/year) @ CF1 994 867 1,021 882 982 856 1,207 1,783 1,134 1,618 115 115NOx Emissions (lb/MMBtu) 0.055 0.047 0.059 0.050 0.058 0.049 0.070 0.070 0.070 0.070 0.009 0.009NOx Emissions (lb/MWh)2

0.406 0.366 0.433 0.400 0.413 0.388 0.613 0.777 0.579 0.722 0.060 0.066PM Emissions (lb/hr) 41 41 38 40 37 39 66 98 62 89 Negligible NegligiblePM Emissions (tons/year) @ CF1 142 145 135 139 131 137 247 365 232 331 Negligible NegligiblePM Emissions (tonnes/year) @ CF1 129 132 122 126 119 125 224 331 211 300 Negligible NegligiblePM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0130 0.0130 0.0130 0.0130 Negligible NegligiblePM Emissions (lb/MWh)2

0.053 0.056 0.052 0.057 0.050 0.057 0.114 0.144 0.107 0.134 Negligible NegligibleHg Emissions (lb/hr) 0.0033 0.0033 0.0031 0.0032 0.0030 0.0032 0.0058 0.0086 0.0055 0.0078 Negligible NegligibleHg Emissions (tons/year) @ CF1 0.011 0.012 0.011 0.011 0.011 0.011 0.022 0.032 0.020 0.029 Negligible NegligibleHg Emissions (tonnes/year) @ CF1 0.010 0.011 0.010 0.010 0.010 0.010 0.020 0.029 0.019 0.026 Negligible NegligibleHg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 1.14 1.14 1.14 1.14 Negligible NegligibleHg Emissions (lb/MWh)2

4.24E-06 4.48E-06 4.16E-06 4.59E-06 4.03E-06 4.55E-06 1.00E-05 1.27E-05 9.45E-06 1.18E-05 Negligible Negligible1 Capacity factor is 80% for IGCC cases and 85% for PC and NGCC cases2 Value is based on gross output3 Value is based on net output

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