# Cost and Performance Baseline for Fossil Energy Plants Volume 3 Executive Summary : Low Rank Coal and Natural Gas to Electricity

September 2011

D OE/NETL

- 2010/1399

## Disclaimer

This report 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 usefulnes s 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 othe rwise 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.

### COST AND PERFORMANCE BASELINE FOR FOSSIL ENERGY PL ANTS VOLUME 3 EXECUTIVE SUMMARY : LOW RANK COAL AND NATURAL GAS TO ELECT RICITY

DOE/NETL

- 2010/1399

September 2011

NETL Contact:
James B. Black
Office of Program Planning & Analysis, Performance Division

National Energy Technology Laboratory www.netl.doe.govThis page intentionally left blank

## NETL Viewpoint Background

The goal of Fossil Energy Research, Development, and Demonstration (RD&D) is to ensure the availability of ultra

- clean (“zero” emissions), abundant, low

- cost, domestic electricity and energy (including hydrogen) to fuel economic prosperity and strengthen energy security. A broad portfolio of technologies is being developed within the Clean Coal Program to accomplish this objective. Ever increasing technological enhancements are in various stages of the research “pipeline,” and multiple paths are being pursued to create a portfolio of promising technologies for development, demonstration, and ev entual deployment. The technological progress of recent years has created a remarkable new opportunity for coal . Advances in technology are making it possible to generate power from fossil fuels with great improvements in the effi ciency of energy

use whi le at the same time significantly reducing the impact on the environment, including the long

- term impact of fossil energy use on the Earth’s climate. The objective of the Clean Coal RD&D Program is to build on these advances and bring these building block s together into a new, revolutionary concept for future coal

- based power and energy production. 

### Objective To establish baseline performance and cost estimates for today’s fossil energy plants, it is necessary to look at the current state of technology. S uch a baseline can be used to benchmark the progress of the Fossil Energy RD&D portfolio. This study provides an accurate, independent assessment of the cost and performance for Integrated Gasification Combined Cycle (IGCC)
, Pulverized Coal (PC), Circulat ing Fluidized Bed Combustor (CFBC), and Natural Gas Combined Cycle (NGCC) plants with and without carbon dioxide (CO 2 ) capture and sequestration operating at sites in Montana and North Dakota. The Montana coal plants use Powder River Basin (PRB) coal and the minemouth North Dakota coal plants use North Dakota lignite (NDL) coals. 

### Approach The power plant configurations analyzed in this study were modeled using the ASPEN Plus® (Aspen) modeling program. Performance and process limits were based upon publi shed reports, information obtained from vendors and users of the technology, cost and performance data from design/build utility projects, and/or best engineering judgment. Capital and operating costs were estimated by WorleyParsons based on simulation re sults and through a combination of existing vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. O peration and maintenance (O&M) costs and the cost for transporting, storing, and monitoring (TS&M) carbon dioxid e (CO 2 ) in the cases with carbon capture were also estimated based on reference data and scaled estimates. The cost of electricity (COE) was determined for all plants assuming investor

- owned utility (IOU) financing. The initial results of this analysis w ere subjected to a significant peer review by industry experts, academia and government research and regulatory agencies. Based on the feedback from these experts, the report was updated both in terms of technical content and revised costs. Fossil Energy RD&D aims at improving the performance and cost of clean coal power systems including the development of new approaches to capture and sequester greenhouse gases (GHGs). Improved efficiencies and reduced costs are required to improve the competitiveness o f these systems in today’s market and regulatory environment as well as in a carbon constrainedscenario. The results of this analysis provide a starting point from which to measure the progress of RD&D achievements.Cost and Performance Baseline for Fossil Energy Plants

VI 

# Table of Contents

TABLE OF CONTENTS

................................ ................................ ................................ ........... VI LIST OF EXHIBITS

................................ ................................ ................................ .................. VII PREPARED BY

................................ ................................ ................................ ....................... VIII ACKNOWLEDGMENTS

................................ ................................ ................................ .......... IX EXECUTIVE SUMMARY

................................ ................................ ................................ ........... 1 P ERFORMANCE

................................ ................................ ................................ .............................. 7 E

NERGY E FFICIENCY

................................ ................................ ................................ .................. 7 W

ATER U SE

................................ ................................ ................................ .............................. 10 C OST R ESULTS

................................ ................................ ................................ ............................ 14 T

OTAL O VERNIGHT C OST

................................ ................................ ................................ .......... 14 C OST OF E LECTRICITY

................................ ................................ ................................ .............. 18 C OST OF CO 2 A VOIDED

................................ ................................ ................................ ............ 23 F UEL C OST S ENSITIVITY

................................ ................................ ................................ ........... 26 C

APACITY F ACTOR S ENSITIVITY

................................ ................................ ................................ 28 C OMBINED NGCC C APACITY F ACTOR AND N ATURAL G AS P RICE P ARITY

................................ .. 30 E NVIRONMENTAL P ERFORMANCE

................................ ................................ ............................... 32 CO 2 E MISSIONS

................................ ................................ ................................ ........................ 36 CO 2 E MISSION P RICE I MPACT

................................ ................................ ................................ .. 39 C OMBINED CO 2 E MISSION AND N ATURAL G AS P RICE P ARITY

................................ .................... 41 REFERENCES

................................ ................................ ................................ ............................. 42Cost and Performance Baseline for Fossil Energy Plants

VII 

# List of Exhibits

Ex hibit ES

- 1 Case Descriptions

................................ ................................ ................................ ..... 2 Exhibit ES

- 2 Results Summary for IGCC Cases

................................ ................................ ........... 4 Exhibit ES

- 3 Results Summary for Combustion Cases

................................ ................................ . 5 Exhibit ES

- 4 Results Summary for NGCC Cases

................................ ................................ ......... 6 Exhibit ES

- 5 Net Plant Efficiency for Montana Site (HHV Basis)

................................ ............... 8 Exhibit ES

- 6 Net Plant Efficiency for North Dakota Site (HHV Basis)

................................ ....... 9 Exhibit ES

- 7 Raw Water Withdrawal and Consumption for Montana Site

................................ 12 Exhibit ES

- 8 Raw Water Withdrawal and Consumption for North Dakota Site

......................... 13 Exhibit ES

- 9 Plant Capital Costs for Montana Site

................................ ................................ ..... 16 Exhibit ES

- 10 Plant Capital Costs for North Dakota Site

................................ ........................... 17 Exhibit ES

- 11 Economic Parameters Used to Calculate COE

................................ .................... 19 Exhibit ES

- 12 COE by Cost Component for Montana Site

................................ ......................... 21 Exhibit ES

- 13 COE by Cost Component for North Dakota Site

................................ ................. 22 Exhibit ES

- 14 First Year CO 2 Avoided Costs for Montana Site

................................ ................. 24 Exhibit ES

- 15 First Year CO 2 Avoided Costs for North Dakota Site

................................ ......... 25 Exhibit ES

- 16 Sensitivity to Fuel Costs for Montana Site

................................ .......................... 27 Exhibit ES

- 17 Sensitivity to Fuel Costs for North Dakota Site

................................ ................... 27 Exhibit ES

- 18 Sensitivity to Capacity Factor for Montana Site

................................ .................. 29 Exhibit ES

- 19 Sensitivity to Capacity Factor for North Dakota Site

................................ .......... 29 Exhibit ES

- 20 Non

- Capture Sensitivity to NGCC CF and NG Price

................................ .......... 30 Exhibit ES

- 21 CCS Sensitivity to CO 2 Capture NGCC CF and NG Price

................................ .. 31 Exhibit ES

- 22 CCS Sensitivity to Non

- Capture NGCC CF and NG Price

................................ . 31 Exhibit ES

- 23 Study Environmental Targets

................................ ................................ ............... 32 Exhibit ES

- 24 Mercury Emissions Rates

................................ ................................ ..................... 33 Exhibit ES

- 25 SO 2 , NOx, and Particulate Emission Rates for Montana Site

.............................. 34 Exhibit ES

- 26 SO 2 , NOx, and Particulate Emission Rates for North Dakota Site

...................... 35 Exhibit ES

- 27 CO 2 Emissions Normalized By Net Output for Montana Site

............................. 37 Exh ibit ES

- 28 CO 2 Emissions Normalized By Net Output for North Dakota Site

..................... 38 Exhibit ES

- 29 Sensitivity to Carbon Emissions Price for Montana Site

................................ ..... 39 Exhibit ES

- 30 Sensitivity to Carbon Emissions Price for North Dakota Site

............................. 40 Exhibit ES

- 31 Lowest Cost Technology Parity Sensitivity to CO 2 and NG Prices

..................... 41Cost and Performance Baseline for Fossil Energy Plants

VIII 

### PREPARED BY Research and Development Solutions, LLC (RDS) :

UPDATED BY Energy Sector Planning and Analysis (ESPA) :

Vincent H. Chou Booz Allen Hamilton
Norma J. Kuehn Booz Allen Hamilton

Lora L. Pinkerton WorleyParsons Group, Inc

. Marc J. T urner Booz Allen Hamilton Elsy Varghese WorleyParsons Group, Inc.
Mark C. Woods Booz Allen Hamilton

DOE Contract # DE

- FE0004001Cost and Performance Baseline for Fossil Energy Plants

IX 

# Acknowledgments

This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Dep artment of Energy’s (DOE) National Energy Technology Laboratory (NETL) under DOE NETL Contract Number DE

- AM26

- 04NT41817 ; Subtask 41817

- 401.01. 04

. The report was updated by Booz Allen Hamilton Inc. under DOE NETL Contract Number DE

FE0004001, Energy Sector Planning and Analysis. The authors wish to acknowledge the excellent guidance, contributions, an d cooperation of the NETL staff and other past contributors, particularly:
John Wimer , Director of O ffice of Program Planning and Analyses (OPPA) Larry Rath, D irector Performance Division

- OPPA
James Black
Jared Ciferno
Kristin Gerdes
Eric Grol Jeffrey Hoffmann
Michael Matuszewski Wally Shelton

Erik Shuster Gary Stiegel
William Summers

Jenny Tennant John Haslebeck formerly of Booz Allen Hamilton
Eric G. Lewis f

ormerly of Booz Allen Hamilton
Pamela Capicotto formerly of Parsons Corporation
Michael Rutkowski formerly of Parsons CorporationCost and Performance Baseline for Fossil Energy Plants

1 The objective of this report is to present an accurate, independent assessment of the c ost and p erformance of L ow

- R ank C oal

- F ired P ower S ystems, specifically integrated gasification combined cycle (IGCC), pulverized coal (PC) and circulating fluidized bed (CFB) plants plus natural gas combined cycle ( NGCC ) plants at different elevations , using a consistent tech nical and economic approach that accurately reflects current or near term market conditions. This Executive Summary covers all the technology types that make up the Low Rank Coal Study, which is Volume 3 of a four volume series consist ing of the following : EXECUTIVE SUMMARY

**•** Volume 1: Bituminous Coal and Natural Gas to Electricity

**•** Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks)

**•** Volume 3: Low Rank Coal and Natural Gas to Electricity

**•** Volume 4: Bituminous Coal to Liquid Fuels with Carbon Capture
Vol ume 3 was published in 3 sub volumes and this Executive Summary encompass es all three sub volumes :

**•** Volume 3a : IGCC Cases [ 1

**•** Volume 3b : Comubustion Cases [ ]

2

**•** Volume 3 c : NGCC Cases [ ]
3

T he cost and performance of the various fossil fuel

- based technologie s will most likely determine which combination of technologies will be utilized to meet the demands of the power market. Selection of new generation technologies will depend on many factors, including: ]

**•** Capital and operating costs

**•** Overall energy efficiency

**•** Fuel prices

**•** Cost of electricity (COE)

**•** Availability
, reliability , and environmental performance

**•** Current and potential regulation of air, water, and solid waste discharges from fossil

fueled power plants

.

**•** Market penetration of c lean coal technologies that h ave matured and improved as a result of recent commercial

- scale demonstrations under the Department of Energy’s ( DOE ) Clean Coal Programs
Exhibit ES

- 1 shows the 28 cases in this study , one for each technology configuration, using either PRB or lignite coal at one of two site conditions, with and without CO 2 capture . This includes configurations for 12 oxygen

- blown IGCC plants based on the Shell Coal Gasification Process (SCGP), Transport Integrated Gasification (TRIGTM) gasifier , Siemens Fuel Gasifier (SFG), and Conoco Phillips (CoP) E

- GasTM gasifier s. Twelve combustion power plant configurations were analyzed including supercritical (SC) an d ultra

- supercritical (USC) pulverized coal (PC) plants and SC CFB plants. NGCC cases were also analyzed at each site.Cost and Performance Baseline for Fossil Energy Plants

2 The methodology included performing steady

- state simulations of the various technologies using the Aspen Plus ® (Aspen) modeling software . The resulting mass and energy balance data from the Aspen model were used to size major pieces of equipment. These equipment sizes formed the basis for cost estimating. Performance and process limits were based upon published reports, information obta ined from vendors and users of the technology, performance data from des ign/build utility projects, and best engineering judgment. Capital and operating costs were estimated based on simulation results and through a combination of vendor quotes, scaled

es timates from previous design/build projects, or a combination of the two. Baseline fuel costs for this analysis were determined using data from the Energy Information Administration’s (EIA) 2008 Annual Energy Outlook (AEO). The first year of capital expe nditure (2007) delivered costs used were $0.84/ gigajoule ( GJ ) ($0.89/ million British thermal unit [ MMBtu ] ) for Powder River Basin (PRB) coal and $0.79/GJ ($0.83/MMBtu) for North Dakota L ignite (NDL)
, both on a higher heating value (HHV) basis and in June 2 007 United States ( US ) dollars.
Exhibit ES

- 1 Case Descriptions

Case Gasifier / Boiler Fuel Steam Cycle, psig/ o F/ o F Sulfur Removal CO 2 Separation S1A Shell SCGP PRB 1800/1050/1050 Sulfinol

- M

- S1B Shell SCGP PRB 1800/1000/ 1000 Selexol Selexol 2 nd stage L1A Shell SCGP NDL 1800/1050/1050 Sulfinol

- M

- L1B Shell SCGP NDL 1800/1000/1000 Selexol Selexol 2 nd stage S2A TRIGTM PRB 1800/1050/1050 Sulfinol

- M

- S2B TRIGTM PRB 1800/1000/1000 Selexol Selexol 2 nd stage S3A Siemens SFG PRB 1800/1050/1050 Sulfinol

- M

- S3B Siemens SFG PRB 1800/1000/1000 Selexol Selexol 2 nd stage L3A Siemens SFG NDL 1800/1050/1050 Sulfinol

- M

- L3B Siemens SFG NDL 1800/1000/1000 Selexol Selexol 2 nd stage S4A CoP E

- GasTM PRB 1800/1050/1050 MDEA

- S4B CoP E

- GasTM PRB 1800/1000/1000 Selexol Selexol 2 nd stage S12A SC PC PRB 3500/1100/1 100 Spray Dry er FGD

- S12B SC PC PRB 3500/1100/1100 Spray Dry er FGD Amine Absorber L12A SC PC NDL 3500/1100/1100 Spray Dry er FGD

- L12B SC PC NDL 3500/1100/1100 Spray Dry er F GD Amine Absorber S13A USC PC PRB 4000/1200/1200 Spray Dry er FGD

- S13B USC PC PRB 4000/1200/1200 Spray Dry er FGD Amine Absorber L13A USC PC NDL 4000/1200/1200 Spray Dry er FGD

- L13B USCPC NDL 4000/1200/1200 Spray Dry er FGD Amine Absorber S22A SC CFB PRB 3500/1100/1100 Spray Dry er FGD

- S22B SC CFB PRB 3500/1100/1100 In

- bed Limestone Amine Absorber L22A SC CFB NDL 3500/1100/1100 In

- bed Limestone

- L22B SC CFB NDL 3500/1100/1100 In

- bed Limestone Amine Absorber S31A NGCC NG 2400/1050/1050

- - S31B N GCC NG 2400/1050/1050

- Amine Absorber L31A NGCC N G 2400/1050/1050

- - L31B NGCC N G 2400/1050/1050

- Amine AbsorberCost and Performance Baseline for Fossil Energy Plants

3 All plant configurations were evaluated based on installation at a greenfield site (Montana [MT]
, 3400 ft elevation, for cases using PRB coal and North Dakota [ND] , 1900 ft elevation, for cases using lignite). To compare the plants on an equivalent basis, it was assumed that these plants would be dispatched any time they are available. The study capacity factor ( CF ) was chosen to reflect the maximum availability demonstrated for the specific plant type, i.e.
, 80 percent for IGCC and 85 percent for PC and NGCC configurations. Since variations in fuel costs and other factors can influence dispatch order and CF , sensitivity of the cost of el ectricity ( COE ) to CF

was evaluated and is presented later in this Executive Summary in Exhibit ES

- 18 and Exhibit ES

- 19 . O nly the Shell and Siemens IGCC configurations are modeled at the North Dakota sit e with l ignite coal, so averages and comparisons between the two sites in later discussions can have a different basis. The nominal net plant output for this study is set at 550 megawatt s ( MW ) . The actual net output varies between technologies because the combustion turbines (CTs) in the IGCC and NGCC cases are manufactured in discrete sizes, but the boilers and steam turbines in the PC cases are available in a wide range of capacities. The result is that all of the PC cases have a net output of 550 MW, b ut the IGCC cases have net outputs ranging from 445 (Case S3B ) to 6 17 MW (Case L1A ) . The range in IGCC net output is caused by the higher auxiliary load incurred in the CO 2 capture cases, primari ly due to CO 2 compression, and the need for extraction steam in the water

gas shift (WGS) reactions, which reduces steam turbine output. Higher auxiliary load and extraction steam requirements can be accommodated in the PC cases (larger boiler and steam turbine) but not in the IGCC cases where it is impossible to maintain a constant net output from the steam cycle given the relatively fixed heat recovery from the CT . Likewise, the NGCC cases have a net output range of 435 (Case S31B) to 547 MW (Case L31A) because of the CT constraint and the CO 2 capture extraction steam and electrical auxiliaries

. Exhibit ES

- 2 shows the cost, performance
, and environmental profile results summary for all IGCC cases , Exhibit ES

- 3 displays the results for the combustion cases, and Exhibit ES

- 4 displays the results for the NGCC cases. The results are discussed below in the following order:

**•** Performance (efficiency and raw water consumption )

**•** Cost (plant capital costs and COE )

**•** Environmental profileCost and Performance Baseline for Fossil Energy Plants

4 Exhibit ES

- 2 Results Summary for IGCC Cases

1 CF is 80% for IGCC case s PERFORMANCE S1A L1A S1B L1B S2A S2B S3A L3A S3B L3B S4A S4B CO 2 Capture 0% 90% 0% 90% 0% 83% 0% 90% 0% 90% 0% 90% Gross Power Output (kW e ) 696,700 752,600 663,400 713,300 652,700 621,300 622,200 678,800 634,700 676,900 738,300 727,200 Auxiliary Power Requirement (kW e ) 124,020 135,900 191,790 213,240 107,280 160,450 117,480 135,680 189,410 210,390 133,460 212,130 Net Power Output (kW e ) 572,680 616,700 471,610 500,060 545,420 460,850 504,720 543,120 445,290 466,510 604,840 515,070 Coal Flowrate (lb/hr) 542,713 760,093 585,970 814,029 545,197 577,946 531,119 743,918 579,796 801,651 656,228 675,058 HHV Thermal Input (kW th ) 1,362,134 1,474,011 1,470,704 1,578,608 1,368,368 1,450,564 1,333,034 1,442,644 1,455,207 1,554,603 1,647,041 1,694,303 Net Plant HHV Efficiency (%) 42.0% 41.8% 32.1% 31.7% 39.9% 31.8% 37.9% 37.6% 30.6% 30.0% 36.7% 30.4% Net Plant HHV Heat Rate (Btu/kWh) 8,116 8,156 10,641 10,772 8,560 10,740 9,012 9,063 11,151 11,371 9,292 11,224 Raw Water Withdrawal (gpm/MW net ) 3.1 3.0 7.2 7.8 3.7 6.5 4.5 4.0 9.0 8.9 5.4 8.4 Process Water Discharge (gpm/MW net ) 0.8 0.8 1.4 1.6 0.8 1.0 1.1 1.1 1.6 1.7 1.1 1.5 Raw Water Consumption (gpm/MW net ) 2.3 2.2 5.9 6.2 2.9 5.5 3.4 2.9 7.4 7.2 4.3 6.9 CO 2 Emissions (lb/MMBtu) 214 219 22 22 211 36 214 219 22 22 213 22 CO 2 Emissions (lb/MWh gross ) 1,426 1,461 165 170 1,507 287 1,563 1,585 172 175 1,620 174 CO 2 Emissions (lb/MWh net ) 1,735 1,783 233 242 1,803 386 1,927 1,981 246 255 1,977 245 SO 2 Emissions (lb/MMBtu) 0.0023 0.0023 0.0009 0.0010 0.0019 0.0009 0.0039 0.0021 0.0009 0.0010 0.0016 0.0009 SO 2 Emissions (lb/MWh gross ) 0.015 0.015 0.007 0.007 0.013 0.007 0.029 0.016 0.007 0.008 0.012 0.007 NOx Emissions (lb/MMBtu) 0.062 0.063 0.050 0.049 0.059 0.049 0.061 0.061 0.051 0.050 0.052 0.044 NOx Emissions (lb/MWh gross ) 0.412 0.418 0.381 0.371 0.422 0.390 0.444 0.445 0.397 0.391 0.398 0.348 PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 PM Emissions (lb/MWh gross ) 0.047 0.047 0.054 0.054 0.051 0.057 0.052 0.051 0.056 0.056 0.054 0.056 Hg Emissions (lb/TBtu) 0.351 0.560 0.351 0.560 0.351 0.351 0.351 0.560 0.351 0.560 0.351 0.351 Hg Emissions (lb/MWh gross ) 2.34E-06 3.74E-06 2.66E-06 4.23E-06 2.51E-06 2.80E-06 2.57E-06 4.06E-06 2.75E-06 4.39E-06 2.67E-06 2.79E-06 COST Total Plant Cost (2007$/kW) 2,506 2,539 3,480 3,584 2,236 3,019 2,610 2,656 3,533 3,626 2,265 3,144 Total Overnight Cost (2007$/kW) 3,056 3,094 4,253 4,378 2,728 3,691 3,185 3,239 4,318 4,430 2,771 3,851
**Bare Erected Cost** 1,914 1,941 2,610 2,692 1,692 2,228 2,006 2,044 2,654 2,730 1,737 2,357 **Home Office Expenses** 177 179 242 250 157 207 186 189 247 254 162 221 **Project Contingency** 343 349 486 502 305 421 359 367 493 508 306 431 **Process Contingency** 72 69 142 141 83 164 60 56 139 135 60 135
**Owner's Costs** 550 556 773 794 492 672 575 583 785 804 505 706 Total Overnight Cost (2007$x1,000) 1,750,189 1,908,200 2,005,883 2,189,363 1,488,063 1,701,132 1,607,607 1,759,016 1,922,741 2,066,464 1,675,790 1,983,369 Total As Spent Capital (2007$/kW) 3,484 3,527 4,849 4,991 3,110 4,208 3,631 3,692 4,922 5,050 3,159 4,390 COE (mills/kWh, 2007$) 1 83.2 83.5 119.7 121.9 74.5 105.2 86.8 87.3 121.7 123.7 78.7 112.3
**CO 2**  **TS&M Costs** 0.0 0.0 6.0 5.7 0.0 5.9 0.0 0.0 6.3 6.2 0.0 5.8
**Fuel Costs** 7.2 6.7 9.5 8.9 7.6 9.5 8.0 7.5 9.9 9.4 8.3 10.0
**Variable Costs** 8.0 8.2 10.6 11.1 6.8 8.8 8.2 8.4 10.6 11.1 8.3 10.9
**Fixed Costs** 13.7 13.6 18.3 18.6 11.8 15.5 14.1 14.0 18.4 18.6 13.0 17.4 **Capital Costs** 54.2 54.9 75.4 77.6 48.4 65.4 56.5 57.4 76.6 78.5 49.1 68.3 LCOE (mills/kWh, 2007$) 1 105.4 105.8 151.8 154.5 94.5 133.3 110.0 110.7 154.3 156.9 99.8 142.4 Shell IGCC Cases TRIG IGCC Cases Siemens IGCC Cases CoP IGCC CasesCost and Performance Baseline for Fossil Energy Plants

5 Exhibit ES

- 3 Results Summary for Combustion Cases

1 CF is 85% for PC cases PERFORMANCE S12A L12A S12B L12B S13A L13A S13B L13B S22A L22A S22B L22B CO 2 Capture 0% 0% 90% 90% 0% 0% 90% 90% 0% 0% 90% 90% Gross Power Output (kW e ) 582,700 584,700 673,000 683,900 581,500 583,200 665,400 675,200 578,400 578,700 664,000 672,900 Auxiliary Power Requirement (kW e ) 32,660 34,640 122,940 133,850 31,430 33,170 115,320 125,170 28,330 28,670 113,990 122,820 Net Power Output (kW e ) 550,040 550,060 550,060 550,050 550,070 550,030 550,080 550,030 550,070 550,030 550,010 550,080 Coal Flowrate (lb/hr) 566,042 755,859 811,486 1,110,668 549,326 731,085 764,212 1,043,879 563,307 745,997 801,270 1,095,812 HHV Thermal Input (kW th ) 1,420,686 1,465,801 2,036,717 2,153,863 1,378,732 1,417,757 1,918,067 2,024,343 1,413,821 1,446,676 2,011,075 2,125,054 Net Plant HHV Efficiency (%) 38.7% 37.5% 27.0% 25.5% 39.9% 38.8% 28.7% 27.2% 38.9% 38.0% 27.3% 25.9% Net Plant HHV Heat Rate (Btu/kWh) 8,813 9,093 12,634 13,361 8,552 8,795 11,898 12,558 8,770 8,975 12,476 13,182 Raw Water Withdrawal, gpm 2,649 2,683 7,642 7,817 2,578 2,597 7,117 7,261 2,393 2,379 7,762 7,996 Raw Water Consumption, gpm 2,093 2,125 5,527 5,456 2,035 2,056 5,141 5,060 1,839 1,828 5,713 5,704 CO 2 Emissions (lb/MMBtu) 215 219 21 22 215 219 21 22 213 219 21 22 CO 2 Emissions (lb/MWh gross ) 1,786 1,877 222 236 1,737 1,820 211 225 1,775 1,865 220 236 CO 2 Emissions (lb/MWh net ) 1,892 1,996 271 293 1,836 1,930 255 276 1,866 1,963 265 288 SO 2 Emissions (lb/MMBtu) 0.119 0.132 0.002 0.002 0.119 0.132 0.002 0.002 0.102 0.113 0.002 0.002 SO 2 Emissions (lb/MWh gross ) 0.990 1.130 0.020 0.020 0.960 1.100 0.020 0.020 0.850 0.970 0.020 0.020 NO x Emissions (lb/MMBtu) 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 0.070 NO x Emissions (lb/MWh gross ) 0.582 0.599 0.723 0.752 0.566 0.581 0.689 0.716 0.584 0.597 0.723 0.754 PM Emissions (lb/MMBtu) 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 0.013 PM Emissions (lb/MWh gross ) 0.108 0.111 0.134 0.140 0.105 0.108 0.128 0.133 0.108 0.111 0.134 0.140 Hg Emissions (lb/TBtu) 0.597 1.121 0.597 1.121 0.597 1.121 0.597 1.121 0.302 0.482 0.302 0.482 Hg Emissions (lb/MWh gross ) 4.96E-06 9.59E-06 6.16E-06 1.20E-05 4.83E-06 9.29E-06 5.87E-06 1.15E-05 2.52E-06 4.11E-06 3.12E-06 5.19E-06 COST Total Plant Cost (2007$/kW) 1,033,301 1,122,438 1,797,852 1,958,416 1,084,716 1,185,901 1,827,095 1,973,559 1,062,836 1,123,412 1,812,415 1,943,572 Total Overnight Cost (2007$/kW) 2,293 2,489 3,987 4,341 2,405 2,628 4,049 4,372 2,357 2,490 4,018 4,307 **Bare Erected Cost** 1,530 1,663 2,517 2,750 1,577 1,725 2,530 2,738 1,480 1,563 2,424 2,600 **Home Office Expenses** 145 157 238 261 149 163 239 259 141 149 230 247 **Project Contingency** 204 220 406 438 213 231 408 437 210 221 407 435 **Process Contingency** 0 0 107 112 33 37 144 154 102 110 233 251 **Owner's Costs** 414 448 718 781 433 472 727 783 425 448 722 773 Total Overnight Cost (2007$x1,000) 1,261,175 1,369,100 2,192,877 2,387,887 1,322,909 1,445,367 2,227,086 2,404,506 1,296,474 1,369,642 2,209,764 2,368,935 Total As Spent Capital (2007$/kW) 2,600 2,823 4,545 4,949 2,742 2,996 4,615 4,984 2,687 2,839 4,580 4,909 COE (mills/kWh, 2007$) 1 57.8 62.2 107.5 116.4 62.2 67.3 107.7 115.4 61.5 64.6 108.0 115.2 **CO 2**  **TS&M Costs** 0.0 0.0 6.0 6.2 0.0 0.0 5.8 6.0 0.0 0.0 5.9 6.1 **Fuel Costs** 7.8 7.5 11.2 11.0 7.6 7.3 10.6 10.4 7.8 7.4 11.1 10.9 **Variable Costs** 5.1 6.1 9.3 11.0 5.1 6.1 9.0 10.3 5.3 6.1 9.5 11.0 **Fixed Costs** 9.0 9.7 14.5 15.7 9.3 10.1 14.7 15.8 9.1 9.5 14.5 15.4 **Capital Costs** 35.9 39.0 66.5 72.4 40.1 43.9 67.6 73.0 39.3 41.6 67.0 71.9 LCOE (mills/kWh, 2007$) 1 73.3 78.8 136.3 147.5 78.8 85.3 136.5 146.3 78.0 81.9 136.9 146.0 Supercritical CFB Supercritical Pulverized Coal Boiler Ultra-supercritical Pulverized Coal BoilerCost and Performance Baseline for Fossil Energy Plants

6 Exhibit ES

- 4 Results Summary for NGCC Cases

1 CF is 85% NGCC cases PERFORMANCE Case S31A Case L31A Case S31B Case L31B CO 2 Capture 0% 0% 90% 90% Gross Power Output (kW e ) 522,100 557,000 470,000 501,600 Auxiliary Power Requirement (kW e ) 9,690 10,020 34,940 36,960 Net Power Output (kW e ) 512,410 546,980 435,060 464,640 Fuel Flowrate (lb/hr) 153,559 163,560 153,559 163,560 HHV Thermal Input (kW th ) 1,014,787 1,080,880 1,014,787 1,080,880 Net Plant HHV Efficiency (%) 50.5% 50.6% 42.9% 43.0% Net Plant HHV Heat Rate (Btu/kWh) 6,757 6,743 7,959 7,938 Raw Water Withdrawal, gpm 1,084 1,148 3,107 3,309 Raw Water Consumption, gpm 841 890 2,321 2,468 CO 2 Emissions (lb/MMBtu) 118 118 12 12 CO 2 Emissions (lb/MWh gross ) 784 783 87 87 CO 2 Emissions (lb/MWh net ) 799 797 94 94 SO 2 Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible SO 2 Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible NO x Emissions (lb/MMBtu) 0.009 0.009 0.009 0.009 NO x Emissions (lb/MWh gross ) 0.060 0.060 0.067 0.066 PM Emissions (lb/MMBtu) Negligible Negligible Negligible Negligible PM Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible Hg Emissions (lb/TBtu) Negligible Negligible Negligible Negligible Hg Emissions (lb/MWh gross ) Negligible Negligible Negligible Negligible COST Total Plant Cost (2007$/kW) 341,350 348,275 572,302 588,738 Total Overnight Cost (2007$/kW) 817 782 1,607 1,548 **Bare Erected Cost** 546 521 994 957 **Home Office Expenses** 46 44 84 81 **Project Contingency** 74 71 62 61 **Process Contingency** 0 0 174 168 **Owner's Costs** 151 145 291 281 Total Overnight Cost (2007$x1,000) 418,817 427,473 698,949 719,155 Total As Spent Capital (2007$/kW) 879 840 1,732 1,668 COE (mills/kWh, 2007$) 1 64.4 63.6 92.9 91.4 **CO 2**  **TS&M Costs** 0.0 0.0 3.4 3.3 **Fuel Costs** 48.2 48.1 56.7 56.6 **Variable Costs** 1.4 1.3 2.7 2.6 **Fixed Costs** 3.4 3.2 6.1 5.9 **Capital Costs** 11.5 11.0 24.0 23.1 LCOE (mills/kWh, 2007$) 1 81.7 80.6 117.8 115.8 NGCC with Advanced F ClassCost and Performance Baseline for Fossil Energy Plants

7 P ERFORMANCE

The net plant efficiency (H H V basis) for the Montana site cases is shown in Energy Efficiency
Exhibit ES

- 5 and for the North Dakota site, in Exhibit ES

- 6

. The primary conclusions that can be drawn are:

**•** The NGCC with no CO 2 capture has the highest net efficiency of the technologies modeled in this study with an efficiency of 50.6 percent at the North Dakota site, slightly higher than the 50.5 percent efficiency at the higher elevation Montana site.

**•** The NGCC cases with CO 2 capture results in the highest efficiency (43.0 percent for MT site, 42.9 percent for ND site) among all of the capture technologies.

**•** The trend for energy efficiency among the IGCC non

- capture cases at the MT site is as follows: the dry

- fed Shell gasifier (42.0 percent), the lower temperature dry fed TRIG gasifier (39.9 percent), the dry

- fed Siemens gasifier without high temperature syngas coolers (37.9 percent), and the slurry

- fed, two

- stage CoP gasifier (36.7 percent).

**•** When CO 2 capture is added to the IGCC cases, the efficiency of the different configurations begin to converge, as a larger p ortion of the auxiliaries is used for the common CO 2 capture and compression processes. The gasifier attributes that contribute to a high efficiency, such as dry feed or high temperature heat recovery with no quench, are negated by the need for shift stea m in capture cases. The Montana site cases range from 30.4 percent for CoP to 32.1 percent for Shell, with TRIG at 31.8 percent and Siemens at 30.6 percent overall net plant efficiency.

**•** The North Dakota site lignite IGCC cases have slightly lower efficien cy than the MT (PRB) site counterparts, mainly due to the lower rank coal. The non

- capture Shell case decreases from 42.0 to 41.8 percent efficiency, and the Siemens case decreases from 37.9 to 37.6 percent efficiency. The CO 2 capture Shell case decrease s from 32.1 to 31.7 percent efficiency, and the Siemens case decreases from 30.6 to 30.0 percent efficiency.

**•** SC PC without CO 2 capture has an efficiency of 38.7 and 37.5 percent for the Montana and North Dakota cases, respectively. CFB with similar steam conditions follow the same trends, but are slightly more efficient at 38.9 and 38.0 percent efficiency, respectively. As steam conditions become more aggressive, the USC PC cases have even higher efficiencies of 39.9 and 38.8 percent, respectively.

**•** The re lative efficiency penalty for adding CO 2 capture to the IGCC cases is 21.2 percent on average, the relative penalty for combustion cases is 30.3 percent, and the relative penalty for NGCC is 15.1 percent.

**•** The addition of CO 2 capture to the combustion cases has the highest relative efficiency penalties out of all the cases studied. This is primarily because the low partial pressure of CO 2 in the flue gas (FG) from a combustion plant requires a chemical absorption process rather than physical absorption. Fo r chemical absorption processes, the regeneration requirements are more energy intensive. The relative efficiency impact on a NGCC CO 2 capture configuration is less because of the lower carbon intensity of natural gas relative to coal, which more than off sets the reduced driving force for CO 2 separation due to the lower partial pressure of CO 2 in the flue gas.Cost and Performance Baseline for Fossil Energy Plants

8 Exhibit ES

- 5 Net Plant Efficiency for Montana Site (HHV Basis)

42.0%

32.1% 39.9%

31.8% 37.9%

30.6% 36.7%

30.4% 38.7%

27.0% 39.9%

28.7% 38.9%

27.3% 50.5%

42.9%

0% 10% 20% 30% 40% 50% 60%

Shell Shell w/CO2 Capture TRIG TRIG w/CO2 Capture Siemens Siemens w/CO2 Capture CoP CoP w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureEfficiency, % (HHV Basis)Cost and Performance Baseline for Fossil Energy Plants

9 Exhibit ES

- 6 Net P lant Efficiency for North Dakota Site (HHV Basis)

41.8%

31.7% 39.7%

30.8% 37.5%

25.5% 38.8%

27.2% 38.0%

25.9% 50.6%

43.0%

0% 10% 20% 30% 40% 50% 60%

Shell Shell w/CO2 Capture Siemens Siemens w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureEfficiency, % (HHV Basis)Cost and Performance Baseline for Fossil Energy Plants

10 Three water metrics are presented for each technology in Water Use
Exhibit ES

- 7 for the Montana site and Exhibit ES

- 8 for the North Dakota site : raw wat er withdrawal, process discharge, and raw water consumption. In each of these exhibits, the value s are normalized by the net plant output. Raw water withdrawal is the difference between demand and internal recycle. Demand is the amount of water required to satisfy a particular process (cooling tower makeup, f lue gas desulfurization [FGD] makeup, etc.) and internal recycle is water available within the process. Raw water withdrawal is the water removed from the ground or diverted from a surface

- water sou rce for use in the plant. Raw water consumption is the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source it was withdrawn from. Raw water consumption is the differe nce between withdrawal and process discharge, and it represents the overall impact of the process on the water source, which in this study is considered to be 50 percent from groundwater (wells) and 50 percent from a municipal

source. The largest consumer of raw water in all cases is cooling tower makeup. Since plants located in the Western U.S. need to consider limited water supplies, a parallel wet/dry condenser was chosen for all plant configurations. In a parallel cooling system half of the turbine e xhaust steam is condensed in an air

- cooled condenser and half in a water

- cooled condenser. Other cooling loads, including the Econamine process, are satisfied using cooling water. C ooling water is provided by a mechanical draft, evaporative cooling tower

. The primary conclusions that can be drawn are:

**•** In all cases the primary water consumer is cooling tower makeup, which ranges from 55 to 9 9 percent of the total raw water consumption

.

**•** Among non

- capture cases, NGCC requires the least amount of raw water w ithdrawal
, followed by IGCC and combustion cases (which include all PC and CFB cases, which have similar performance profiles)

. T he relative average normalized raw water consumption for the Montana site cases is 2.2 : 2.0 :1.0 (PC:IGCC:NGCC) and 2.2:1.6:1.0 for the North Dakota cases. The relative results are as expected given the higher steam turbine output in the PC cases
, which results in higher condenser duties, higher cooling
water flows
, and ultimately higher cooling water makeup

. The IGCC cases and t he NGCC case have comparable steam turbine outputs, but IGCC requires additional water for coal slurry (CoP), syngas quench ( Siemens ) , and slag handling (all cases ). No slurry fed gasifiers were included in the North Dakota results.

**•** Among capture cases, r aw water withdrawal requirement s increase ( relative to non

capture cases) more dramatically for the PC and NGCC cases than for IGCC cases because of the large cooling water demand of the Econamine process , which results in greater cooling water makeup requ irements. T he relative average normalized raw water consumption for the Montana site CO 2 capture cases is 1.9 :1. 2 :1.0 (PC: I GCC: N GCC) and 2.2:1.3:1.0 for the North Dakota cases.

**•** CO 2 capture increases the average raw water consumption for all technologies, but the increase is lowest for the IGCC cases . The average normalized raw water consumption for the IGCC cases increases by about 98 percent for the Montana cases and 161 percent for the North Dakota cases due primarily to the need for additional water in the syngas to accomplish the WGS reaction

. With the addition of CO 2 capture, PC normalized raw water consumption increases by 174 percent for the Montana cases and 170 percent forCost and Performance Baseline for Fossil Energy Plants

11 the North Dakota cases. The NGCC cases’ water consumption increases by ap proximately 225 percent for both site locations

. The large cooling water demand of the Econamine process drives this substantial increase for the PC and NGCC technologies

.Cost and Performance Baseline for Fossil Energy Plants

12 Exhibit ES

- 7 Raw Water Withdrawal and Consumption for Montana Site

3.1 7.2

3.7 6.5

4.5 9.0

5.4 8.4

4.8 13.9

4.7 12.9

4.4 14.1

2.1 7.1

2.3 5.9

2.9 5.5

3.4 7.4

4.3 6.9

3.8 10.0

3.7 9.3

3.3 10.4

1.6 5.3

0 2 4 6 8 10 12 14 16

Shell Shell w/CO2 Capture TRIG TRIG w/CO2 Capture Siemens Siemens w/CO2 Capture CoP CoP w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureWater, gpm/Mwnet Raw Water Withdrawal Process Water Discharge Raw Water ConsumptionCost and Performance Baseline for Fossil Energy Plants

13 Exhibit ES

- 8 Raw Water Withdrawal and Consumption for North Dakota Site

3.0 7.8

4.0 8.9

4.9 14.2

4.7 13.2

4.3 14.5

2.1 7.1

2.2 6.2

2.9 7.2

3.9 9.9

3.7 9.2

3.3 10.4

1.6 5.3

0 2 4 6 8 10 12 14 16

Shell Shell w/CO2 Capture Siemens Siemens w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureWater, gpm/Mwnet Raw Water Withdrawal Process Water Discharge Raw Water ConsumptionCost and Performance Baseline for Fossil Energy Plants

14 C OST RESULTS

The Total Overnight Cost (TOC) for each plant was calculated by adding owner’s costs to the Tot al Plant Cost (TPC). The TPC for each technology was determined through a combination of vendor quotes, scaled estimates from previous design/build projects, or a combination of the two. TPC includes all equipment (complete with initial chemical and cata lyst loadings), materials, labor (direct and indirect), engineering and construction management, and contin gencies (process and project). Escalation and interest on debt during the capital expenditure period were estimated and added to the TOC to provide the Total As

- Spent Capital (TASC). Total Overnight Cost

The cost estimates carry an accuracy of

- 15%/+30% , consistent with a “feasibility study ” level o f design engineering

. The value of the study lies not in the absolute accuracy of the individual case results but in the fac t that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated. Project contingencies were added to the Engineering/Procurement/Construction Management (EPCM) capital accounts to cover project uncertainty and the cost of any additional equipment that would result from a detailed design. The contingencies represent costs that are expected to occur. Each bare erected cost (BEC) account was eval uated against the level of estimate detail and field experience to determine project contingency. Process contingency was added to cost account items that were deemed to be first

- of

- a

- kind (FOAK) or posed significant risk due to lack of operating experienc e. The cost accounts that received a process contingency include:

**•** Gasifiers and Syngas Coolers

– 15 percent on all IGCC cases

– next

- generation commercial offering and integration with the power island.

**•** Two Stage Selexol

– 20 percent on all IGCC capture c ases

– lack of operating experience at commercial scale in IGCC service.

**•** Mercury Removal

– 5 percent on all IGCC cases

– minimal commercial scale experience in IGCC applications.

**•** CO 2 Removal System

– 20 percent on all PC/NGCC capture cases

- post

- combustio n process unproven at commercial scale for power plant applications

.

**•** Combustion Turbine

- Generator (CTG)

– 5 percent on all IGCC non

- capture cases

– syngas firing and air separation unit ( ASU ) integration ; 10 percent on all IGCC capture

cases

– high hydroge n firing.

**•** Instrumentation and Controls

– 5 percent on all IGCC accounts and 5 percent on the PC and NGCC capture cases

– integration issues

. The normalized components of TO C and overall TASC are shown for each technology in Exhibit ES

- 9 for the Montana site and Exhibit ES

- 10 for the North Dakota site

. TOC is expressed in June 2007 dollars. TASC is expressed in mixed

- year 2007 to 2011 year dollars for coal plants and 2007 to 2009 mixed

- year dollars for NGCC. The following conclusions can be drawn:Cost and Performance Baseline for Fossil Energy Plants

15 **•** Among the non

- capture cases at the Montana site , NGCC has the lowest TOC at $ 817/ kW followed by the combustion cases with an average cost of $2, 352 /kW and IGCC with an average cost of $2, 935 /k W. At the North Dakota site, NGCC has the lowest TOC at $782/kW (which is lower than at the Montana site due to increased output) followed by PC with an average cost of $2,536/kW and IGCC with an average cost of $3,166/kW , using the lower rank coal

.
**•** Among the capture cases at the Montana site, NGCC has the lowest TOC of $1,607kW followed by PC with an average cost of $4,018/kW and IGCC with an average cost of $4,028/kW. At the North Dakota site, NGCC again has the lowest TOC, $1,548/kW, followed by PC wit h an average cost of $4,340/kW and IGCC with an average cost of $4,404/kW.

**•** The average non

- capture IGCC cost is 25 percent greater than the average PC cost. The process contingency for the IGCC non

- capture cases ranges from $56

- 83/kW, while there is minim al process contingency for the SC PC and NGCC non

- capture cases. The differential between IGCC and PC is reduced to 22 percent when the IGCC process contingency is eliminated.

**•** The average CO 2 capture IGCC cost is roughly equivalent to or slightly greater than the average PC cost. The process contingencies are universally higher for the more complex, less commercially mature CO 2 capture processes and plant configurations: the IGCC capture cases process contingency ranges from $ 135

- 164 /kW, the PC cases from $ 107

- 154 /kW
, CFB cases $233

- 251/kW
, and $ 168

- 174 /kW for the NGCC case s

.Cost and Performance Baseline for Fossil Energy Plants

16 Exhibit ES

- 9 P lant Capital Cost s for Montana Site

3,056 4,253

2,728 3,691

3,185 4,318

2,771 3,851

2,293 3,987

2,405 4,049

2,357 4,018

817 1,607 3,484 4,849

3,110 4,208

3,631 4,922

3,159 4,390

2,600 4,545

2,742 4,615

2,687 4,580

879 1,732

0 1,000 2,000 3,000 4,000 5,000 6,000TOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASCTOCTASC

Shell Shell w/CO2 Capture TRIG TRIG w/CO2 Capture Siemens Siemens w/CO2 Capture CoP CoP w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureCapital Costs, $/kW TASC Owner's Cost
Process Contingency Project Contingency
Home Office Expense Bare Erected CostCost and Performance Baseline for Fossil Energy Plants

17 Exhibit ES

- 10 Plant Capital Costs for North Dakota Site

3,094 4,378

3,239 4,430

2,489 4,341

2,628 4,372

2,490 4,307

782 1,548 3,527 4,991

3,692 5,050

2,823 4,949

2,996 4,984

2,839 4,909

840 1,668

0 1,000 2,000 3,000 4,000 5,000 6,000

TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC

Shell Shell w/CO2 Capture Siemens Siemens w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureCapital Costs, $/kW TASC Owner's Cost Process Contingency Project Contingency Home Office Expense Bare Erected CostCost and Performance Baseline for Fossil Energy Plants

18 The cost metric used in this study is the COE , which is the revenue received by the generator per net megawatt

- hour during the power plant’s first year of operation, assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant . To calculate the COE, the Power Systems Financial Model ( PSFM ) [ Cost o f Electricity

4 ] was used to determine a “base

- year” (2007) COE that, when escalate d at an assumed nominal annual general inflation rate of 3 percent 1

Exhibit ES

- 11 , provided the stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). The first year capital cha rge factor (CCF) shown in , which was derived using the PSFM, can also be used to calculate COE using the simplified equation below

.

w here:
COE = revenue received by the generator ($/MWh, equivalent to mills/kWh) du ring the power plant’s first year of operation ( but expressed in base

year dollars ), assuming that the COE escalates thereafter at a nominal annual rate equal to the general inflation rate, i.e., that it remains constant in real terms over the operational period of the power plant.
CCF = capital charge factor taken fro m Exhibit ES

- 11 that matches the applicable finance structure and capital expenditure period
TOC = total overnight capital, expressed in base

- year dol lars
OC FIX = the sum of all fixed annual operating costs, expressed in base

- year dollars
OC VAR = the sum of all variable annual operating costs, including fuel at 100 percent capacity factor, expressed in base

- year dollars
CF = plant capacity factor, ass umed to be constant over the operational period

MWH = annual net megawatt

- hours of power generated at 100 percent capacity factor

1 This nominal escalation rate is equal to the average annual inf lation rate between 1947 and 2008 for the U.S. Department of Labor’s Producer Price Index for Finished Goods. This index was used instead of the Producer Price Index for the Electric Power Generation Industry because the Electric Power Index on ly dates back to December 2003 and the Producer Price Index is considered the “headline” index for all of the various Producer Price Indices.Cost and Performance Baseline for Fossil Energy Plants

19 The project financial structure varies depending on the type of project (high risk or low risk) and the length of the capital expenditure period (3 year or 5 year). All cases were assumed to be undertaken at investor owned utilities ( IOUs ) . High risk projects are those in which commercial scale operating experience is limited. The IGCC and SC CFB cases (with and without CO 2
c apture) and the PC and NGCC cases with CO 2 capture were considered to be high risk. The

non

- capture PC and NGCC cases were considered to be low risk. Coal based cases were assumed to have a 5 year capital expenditure period and natural gas cases a 3 year period. The

c urrent

- dollar , 30

- year levelized cost of electricity (LCOE) was also calculated and is in the results summary , but the primary metric used in the balance of this study is COE.
Exhibit ES

- 11 Economic Parameters Used to Calculate COE

High Risk (5 year capital

expenditure period) Low Risk (5 year capital

expenditure period) High Risk (3 year capital

expenditure period) Low Risk (3 year capital

expenditure period)

First Year Capital Charge Factor 0.1 243 0.11 65 0. 1 111 0 .1 048

Commodity prices fluctuate over time based on overall economic activity and general supply and demand curves. While the cost basis for this study is June 2007, many price indices had similar values in January 2010 compared to June 2007. For example, the Chemical Engineering Plant Cost Index was 532.7 in June 2007 and 532.9 in January 2010, and the Gross Domestic Product Chain

- type Price Index was 106.7 on July 1, 2007 and 110.0 on January 1, 2010. Hence the June 2007 dollar cost base used in this study is expected to also be representative of January 2010
costs.
The COE results are shown in Exhibit ES

- 12 for the Montana site cases and Exhibit ES

- 13 for the North Dakota site c ases with the capital cost, fixed operating cost, variable operating cost
, and fuel cost shown individually . In the capture cases
, the CO 2 transport, storage , and monitoring (TS&M) costs are also shown as a separate bar segment. The following conclusions can be drawn:

**•** In non

- capture cases, at the Montana site, the combustion cases have the lowest COE ( average 60.5 mills/kWh), followed by NGCC ( 64.4 mills/kWh) and IGCC (average 80.8 mills/kWh). At the North Dakota site, the SC PC plant has the lowest COE (61.5 mills/kWh, all combustion cases average 64.7 mills/kWh), followed by NGCC (63.6 mills/kWh) and IGCC (average 85.4 mills/kWh).

**•** In capture cases, at the Montana site, NGCC plants have the lowest COE ( 92 .9 mills/kWh), followed by the combustion cases (a verage 10 7

. 7 mills/kWh) and IGCC (average 11 4

. 7 mills/kWh) , although the TRIG case (105.2 mills/kWh) , with an 83% CO 2 capture efficiency, is less expensive than the PC technologies

. At the North Dakota site, NGCC plants have the lowest COE (91.4 mills/kWh ), followed by the combustion cases (average 115.6 mills/kWh) and IGCC (average 122.8 mills/kWh).Cost and Performance Baseline for Fossil Energy Plants

20 **•** The capital cost component of COE is between 61 and 66 percent in all IGCC and PC cases. It represents only 18 percent of COE in the NGCC non

- capture case s a nd 26 percent in the CO 2 capture case s mainly because NGCC cases use a cleaner and less carbon intensive but more expensive fuel.

**•** The fuel component of COE ranges from 7

- 14 percent for the PC and IGCC cases. The fuel component is 75 percent of the total i n the NGCC non

- capture case s and 61 percent in the CO 2 capture case s

.

**•** CO 2 TS&M is estimated to add 3 to 6 mills/kWh to the COE, which is less than 6 percent of th e total for all capture cases.Cost and Performance Baseline for Fossil Energy Plants

21 Exhibit ES

- 12 COE by Cost Comp onent for Montana Site

54 75

48 65 56 77

49 68

36 67

40 68

39 67

12 24 14 18

12 16

14 18

13 17

9 14

9 15

9 14

3 6 8 11

7 9

8 11

8 11

5 9

5 9

5 9

1 3 7 9

8 10

8 10

8 10

8 11

8 11

8 11

48 57 6

6 6

6 6 6 6

3 83 120

75 105

87 122

79 112

58 107

62 108

62 108

64 93

0 20 40 60 80 100 120 140 160

Shell Shell w/CO2 Capture TRIG TRIG w/CO2 Capture Siemens Siemens w/CO2 Capture CoP CoP w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureCOE, mills/kWh (2007$) CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs
Capital CostsCost and Performance Baseline for Fossil Energy Plants

22 Exhibit ES

- 13 COE b y Cost Component for North Dakota Site

55 78

57 79

39 72

44 73

42 72

11 23 14 19

14 19

10 16

10 16

10 15

3 6 8 11

8 11

6 11

6 10

6 11

1 3 7 9

7 9

8 11

7 10

7 11

48 57 6 6

6 6 6

3 83 122

87 124

62 116

67 115

65 115

64 91

0 20 40 60 80 100 120 140 160

Shell Shell w/CO2 Capture Siemens Siemens w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureCOE, mills/kWh (2007$) CO2 TS&M Costs

Fuel Costs

Variable Costs

Fixed Costs
Capital CostsCost and Performance Baseline for Fossil Energy Plants

23 The first year cost of CO 2 avoided was calculated as illustrated in Equation ES

- 1: Cost of CO 2 Avoided



### MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided

removal with reference reference removal with 

### / } { / $ } {

2 2 

### − **−**

**=** (ES

- 1)

T he COE with CO 2 removal includes the costs of capture and compression as well as TS&M costs. The resulting avoided costs are shown in Exhibit ES

- 14 for the Montana site cases and Exhibit ES

- 15 for the No rth Dakota site cases for each of the technologies modeled. The avoided costs for each capture case are calculated using the analogous non

- capture plant as the reference and again with SC PC without CO 2 capture as the reference. The following conclusions can be drawn:

**•** CO 2 avoided costs for IGCC plants, using analogous non

- capture plants as reference, are substantially less than for PC and NGCC because the IGCC CO 2 removal is accomplished prior to combustion and at elevated pressure using physical absorpti on. This metric can be considered an intrinsic property to the technology or configuration gauging the ease of configuring the technology to capture CO 2 .

**•** The CO 2 avoided costs for NGCC plants, using analogous non

- capture as reference, are high in part bec ause the NGCC non

- capture configuration already emits a very low amount of carbon. Consequently, the removal cost for NGCC plants is normalized by a smaller amount of CO 2 being captured.

**•** CO 2 avoided costs for NGCC plants without capture , using SC PC as re ference, are substantially lower than all the other technologies. The inherent ly low carbon intensity of the fuel makes even the non

- capture NGCC configuration emit almost 60% less CO 2 t han the reference SC PC plant, making it a cost effective option for reducing or offsetting smaller amounts of CO 2 emissions . This metric can be used to assess the impact of building NGCC plants instead of coal plants.Cost and Performance Baseline for Fossil Energy Plants

24 Exhibit ES

- 14 First Year CO 2 Avoided Costs for Montana Site

54

48 46 44 68

63 64 89

82

69 86

73

68 67 68

13 43

0 10 20 30 40 50 60 70 80 90 100

Shell TRIG Siemens CoP SC PC USC PC CFB NGCC w/o CO2 Capture NGCC w/CO2 CaptureFirst Year CO2Avoided Cost, $/tonne (2007$) Analogous Technology w/o Capture Reference SC PC w/o Capture ReferenceCost and Performance Baseline for Fossil Energy Plants

25 Exhibit E S

- 15 First Year CO 2 Avoided Costs for North Dakota Site

58

47 70

64 67 87

74 78

70 68 68

12 34

0 10 20 30 40 50 60 70 80 90 100

Shell Siemens SC PC USC PC CFB NGCC w/o CO2 Capture NGCC w/CO2 CaptureFirst Year CO2Avoided Cost, $/tonne (2007$) Analogous Technology w/o Capture Reference SC PC w/o Capture ReferenceCost and Performance Baseline for Fossil Energy Plants

26 The COE sensitivity to fuel cost for the Montana site cases is presented in Fuel Cost Sensitivity
Exhibit ES

- 16 and in Exhibit ES

- 17 for the North Dakota site c ases . The solid line is the COE of NGCC as a function of natural gas cost , the higher green line representing the CO 2 capture case and the lower blue line representing the non

- capture case

. F or comparison , t he lowest COE configuration was selected to represent each technology type: TRIG for PRB IGCC cases, Shell for Lignite IGCC cases, and SC PC for the PC cases. The points on the line represent the natural gas cost that would be required to make the COE of NGCC equal to the other technologies at a varied coal
cost s

. For each coal type, associated with each site location, a range of coal price scenarios are plotted representing the base coal cost ± 25 percent. This translates to data points at [$0.67, $0.89, and $1.11/MMBtu] for the Montana PRB coal costs and [$0.62, $0.83, and $1.03/MMBtu] for the North Dakota lignite coal costs . As an example, at a PRB coal cost of $0.67 /MMBtu (25% less than the base cost) , the non

- capture IGCC becomes com petitive with NGCC at a natural gas price of $ 7

. 69 /MMBtu resulting in a COE of 102

. 8 mills/kWh

. At higher elevations, PC cases become more attractive, in part because there is no combustion turbine and thus no derate due to lower ambient pres sures. For th e non

- capture sce nario, the SC PC cases are the most cost competitive, requiring a natural gas price of $5.92/MMBtu for NGCC to generate power below the Montana PRB SC PC electricity cost of 57.8 mills/kWh assuming the base coal cost. For the lower elevat ion North Dakota site, NGCC becomes competitive at $6.36/MMBtu, resulting in a COE of 62.2 mills/kWh.
For the CO 2 capture configurations using the base costs , NGCC is the lowest cost option due to the low capital cost component of the COE . For the CO 2 cap ture configurations at the Montana site, the compact, high efficiency TRIG IGCC case results in a lower cost of electricity than the SC PC case, and beats the NGCC electrical generation cost when natural gas is above $7.97, compared to the base case PRB co sts. The Montana PRB CO 2 capture SC PC case requires a natural gas price of $8.23/MMBtu to be competitive with the NGCC CO 2 capture case.Cost and Performance Baseline for Fossil Energy Plants

27 Exhibit ES

- 16 Sensitivity to Fuel Costs for Montana Site

Exhibit ES

- 17 Sensitivity to Fuel Costs for North Dakota Site 0 20 40 60 80 100 120 140 160

0 2 4 6 8 10 12 14COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu NGCC NGCC w/Cap

IGCC PRB
PC PRB

Baseline NG Price, $7.13/MMBtu PRB Coal Costs [$0.67, $0.89, $1.11/MMBtu]

0 20 40 60 80 100 120 140 160

0 2 4 6 8 10 12 14COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu NGCC NGCC w/Cap IGCC Lig PC Lig

Baseline NG Price, $7.13/MMBtu Lignite Coal Costs [$0.62, $0.83, $1.03/MMBtu]Cost and Performance Baseline for Fossil Energy Plants

28 The sensitivity of COE to CF is shown for the Montana site cases in Capacity Factor Sensitivity
Exhibit ES

- 18 and the North Dakota site cases in Exhibit ES

- 19

. The CF is plotted from 3 0 to 90 percent. Select cases were chosen to represent the general characteristics of each technology type and configuration and to facilitate comparison between cases. The baseline CF is 80 percent for IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. The curves for the IGCC cases assume that the CF could be extended to 90 percent with no spare gasifier. Similarly, the PC and NGCC curves assume that the CF could reach 90 percent with no additional capital equipment. Technologies with high capital cost (PC and IGCC with CO 2 capture) show a greater increase in COE with decreased CF. Conversely, NGCC with no CO 2 capture is relatively flat because the COE is dominat ed by fuel costs , which decrease as the CF decreases. Conclusions that can be drawn from this sensitivity include:

**•** For the Montana site, a t a CF below 70 percent, NGCC has the lowest COE out of the

non

- capture cases. Above this threshold, the TRIG IGCC c onfiguration has the lowest COE.

**•** For the North Dakota site, a t a CF below 85 percent, NGCC has the lowest COE out of the non

- capture cases. Above this threshold, the SC PC configuration has the lowest COE.

**•** NGCC with CO 2 capture is the most attractive CO 2 capture option and can be even less expensive than some of the non

- capture configurations, depending on the CF. At a CF below 40 percent, the NGCC CO 2 capture cases become just as costly as the IGCC non

capture running at the base load (80 percent CF) fur ther illustrating the relatively small impact of CF on NGCC COE.Cost and Performance Baseline for Fossil Energy Plants

29 Exhibit ES

- 18 Sensitivity to Capacity Factor for Montana Site

Exhibit ES

- 19 Sensitivity to Capacity Factor for North Dakota S ite 0 50 100 150 200 250 300 350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%COE, mills/kWh (2007$)

Capacity Factor Shell IGCC w/Capture SC PC w/Capture TRIG IGCC w/Capture NGCC w/Capture

Shell IGCC

TRIG IGCC

NGCC

SC PC

0 50 100 150 200 250 300 350

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%COE, mills/kWh (2007$)

Capacity Factor Shell IGCC w/Capture SC PC w/Capture NGCC w/Capture
Shell IGCC
NGCC
SC PCCost and Performance Baseline for Fossil Energy Plants

30 A plot combining the CF and fuel cost sensitivities for NGCC plants shows unique characteristics for this low capital cost, high fuel cost generating option , compared to the other options

. D ue to the high fuel cost, an NGCC plant may not be dispatched whenever the plant is available, which would lower the real world capacity factor. A parametric graph of the breakeven point for selected coal technologies show the required capacity factor and natural gas price, when the indicated coal technology (running at the baseline capacity factor) will have a lower COE than the analogous NGCC case at the same site location. A comparison of the non

capture cases is shown in Combined NGCC Capacity Factor and Natural Gas Price Parity

Exhib it ES

- 20 . The CO 2 capture cases are compared, using a $ 67 /tonne CO 2 emission price, to CO 2 Capture NGCC in Exhibit ES

- 21 and to non

- capture NGCC in Exhibit ES

- 22

. This CO 2 emission price shifts the COE breakeven lines up and to the left and corresponds to the breakeven point where the coal technologies have the lowest COE when adding CO 2 capture rather than paying for uncontrolled emissions. An analysis on the effects of CO 2 emissions prices are discu ssed in the CO 2 Emissions section.

Exhibit ES

- 20 Non

- Capture Sensitivity to NGCC CF and NG Price

0 2 4 6 8 10 12 14

30% 40% 50% 60% 70% 80% 90%Natural Gas Price, $/MMBtu

NGCC Capacity Factor Shell Lignite

Shell PRB

TRIG PRB Supercritical PC Lignite Supercritical PC PRB Coal Has Lowest COE

NGCC Has Lowest COECost and Performance Baseline for Fossil Energy Plants

31 Exhibit ES

- 21 CCS Sensitivity to CO 2 Capture NGCC CF and NG Price with $67/tonne CO 2 Emis sion Price

Exhibit ES

- 22 CCS Sensitivity to Non

- Capture NGCC CF and NG Price with $ 67 /tonne CO 2 Emission Price 0 2 4 6 8 10 12 14

30% 40% 50% 60% 70% 80% 90%Natural Gas Price, $/MMBtu

NGCC Capacity Factor Shell CCS Lignite

Shell CCS PRB
USC PC CCS Lignite

TRIG CCS PRB

USC PC CCS PRB Coal CCS Has Lowest COE

NGCC Has Lowest COE

0 2 4 6 8 10 12 14

30% 40% 50% 60% 70% 80% 90%Natural Gas Price, $/MMBtu

NGCC Capacity Factor Shell CCS Lignite

Shell CCS PRB
USC PC CCS Lignite

TRIG CCS PRB

USC PC CCS PRB Coal CCS Has Lowest COE

NGCC Has Lowest COECost and Performance Baseline for Fossil Energy Plants

32 E NVIRONMENTAL PERFORM ANCE The environmental targets are based on presumed best available control technology (BACT) for each technology and are summarized in Exhibit ES

- 23

. This study was conducted prior to the issuance of the EPA proposed rules “ National Emission Standards for Hazardous Air Pollutants f rom Coal and Oil

- Fired Electric U tility Steam Generating Units and Standards of Performance for Fossil

- Fuel

- Fired Electric Utility, Industrial

- Commercial

- Institutional, and Small Industrial

Commercial

- Institutional Steam Generating Unit s,” and consequently the emissions limits included in this proposed rule are not considered in this study. E mission s rates of mercury (Hg) are shown in Exhibit ES

- 24 , for both sites, and e mission rates of sulfur dioxide ( SO 2 ), nitrogen oxide (NOx), and particulate matter (PM) are s hown graphically in Exhibit ES

- 25 and Exhibit ES

- 26

. Exhibit ES

- 23 Study Environmental Targets

Technology

Pollutant IGCC PC CFB NGCC

SO 2 0.0128 lb/MMBtu 0.132 lb/MMBtu Negligible

NOx 15 ppmv (dry) @ 15% O 2 0.07 lb/MMBtu 2.5 ppmv (dry) @ 15% O 2
PM (Filterable) 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible

Hg (PRB) >90% capture 0.60 lb/TBtu 3.0 lb/TBtu N/A

Hg (Lignite) >90% capture 1.12 lb/TB tu 4.8 lb/TBtu N/A
The primary conclusions that can be drawn are:

**•** L ow NOx burners (LNB) with overfire air and selective catalytic reduction in the PC cases and low bed temperature and selective non

- catalytic reduction in the CFB cases achieve the 0.07 lb/ MMBtu NOx emission limit. A NOx emissions limit of 15 ppmv was achieved in the IGCC cases using LNB s and syngas dilution to the combustion turbine

. NGCC emissions were limited using dry LNB and an SCR to achieve 2.5 ppmv. For these concentration based e missions limits, t he resulting emissions on a lb/MMBtu basis for the coal

- based systems vary slightly because of the variable coal feed rates and flue gas volumes generated among cases.

**•** A dry FGD with baghouse in PC cases and cyclones and a baghouse in the CFB cases were able to achieve the 0.013 lb/MMBtu PM emission limit. A combination of cyclones, candle filters, and scrubbers were assumed to achieve the IGCC particulate limit of 0.0071 lb/MMBtu

.
**•** Sulfur emissions are uniformly low and vary with coal typ e and technology type. The AGR in the IGCC cases removes upwards of 99 percent of the sulfur as H 2 S, which is then recovered in the Claus plant as elemental sulfur. In

- bed limestone injection in the CFB cases is assumed to have an SO 2 removal efficiency of 94 percent while the spray dryer absorbers used in the PC cases is assumed to have a removal efficiency of 93Cost and Performance Baseline for Fossil Energy Plants

33 percent. While PRB and lignite coals have the similar sulfur content on an as

- received basis, more lignite coal is required to generate the sa me amount of electricity because of its lower heating value. As a consequence, more SO 2 is emitted at a constant capture efficiency in the lignite coal cases.

**•** In combustion

- based CO 2 capture cases the sulfur concentration is reduced even further to mainta in the performance of the amine

- based solvents through the use of a dry polishing scrubber ahead of the absorber.

**•** Lignite coal inherently has higher concentrations of mercury (and lower heating value) than the PRB coal, so the l ignite cases result in highe r mercury emissions. Using activated carbon beds, the IGCC cases are able to achieve the environmental targets. For combustion cases, m ercury emissions are higher for lignite coal cases compared to the analogous PRB coal case s because there is no co

- bene fit capture with lignite coals while PRB coal cases achieve some co

- benefit capture

. Mercury emissions are lower for the CFB cases because of higher co

- benefit capture in addition to the use of carbon injection.

Exhibit ES

- 24 Mercury Emissions Rates

0.351 0.597

0.302 0.560 1.121

0.482

0.000 0.200 0.400 0.600 0.800 1.000 1.200

IGCC PRB PC PRB CFB PRB NGCC MT IGCC Lig PC Lig CFB Lig NGCC NDEmissions, lb/TBtuCost and Performance Baseline for Fossil Energy Plants

34 Exhibit ES

- 25 SO 2 , NOx , and Particulate Emission Rates for Montana Site

0.002 0.001 0.002 0.001 0.004 0.001 0.002 0.001 0.119

0.002 0.119

0.002 0.102

0.002

0.062

0.050 0.059

0.049 0.061

0.051 0.052

0.044 0.070 0.070 0.070 0.070 0.070 0.070

0.009 0.009

0.007 0.007 0.007 0.007 0.007 0.007 0.007 0.007 0.013 0.013 0.013 0.013 0.013 0.013

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

Shell Shell w/CO2 Capture TRIG TRIG w/CO2 Capture Siemens Siemens w/CO2 Capture CoP CoP w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureEmissions, lb/MMBtu SO2
NOx ParticulateCost and Performance Baseline for Fossil Energy Plants

35 Exhibit ES

- 26 SO 2 , NOx , and Particulate Emission Rates for North Dakota Site

0.002 0.001 0.002 0.001 0.132

0.002 0.132

0.002 0.113

0.002 0.063

0.049 0.061

0.050 0.070 0.070 0.070 0.070 0.070 0.070

0.009 0.009 0.007 0.007 0.007 0.007 0.013 0.013 0.013 0.013 0.013 0.013

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14

Shell Shell w/CO2 Capture Siemens Siemens w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureEmissions, lb/MMBtu SO2
NOx
ParticulateCost and Performance Baseline for Fossil Energy Plants

36 CO 2 emissions are not currently regulated. However, since there is increasing momentum for establishing carbon limits, it was a n objective of this study to examine the relative amounts of CO 2 capture achievable among the six technologies. CO 2 emi ssions are presented in CO 2 Em issions

Exhibit ES

- 27 and Exhibit ES

- 28 for the two sites , normalized by net output. In each results summary table emissions are reported on both a net and gross MWh basis . New Source Performance Standards (NSPS) contain emission limits for SO 2 and NOx on a lb/(gross) MWh basis. However, since CO 2 emissions are not currently regulated, the potential future emission limit basis is not known and CO 2 emissions are presented in both ways. The following conclusions can be drawn :

**•** In cases with no CO 2 capture , NGCC emits 56 percent less CO 2 than the lowest PC case and 5 4 percent less CO 2 than the lowest IGCC case per unit of net output comparing each respective site . The NGCC C O 2 emissions reflect the lower carbon intensity of natural gas relative to coal and the higher cycle efficiency of NGCC relative to IGCC and PC

. Based on the fuel compositions used in this study, natural gas contains 41 lb carbon/MM Btu and the PRB and ND lignite coals contain 5 9 lb/MM Btu of heat input

.

**•** T he CO 2 reduction goal in this study was a nominal 90 percent, which is achieved for all cases except the TRIG IGCC , which remove 83% of the CO 2 , in part due to the high cold gas efficiency and high methane concentration. The result is that the controlled CO 2 emissions follow the same trend as the uncontrolled cases , i.e., the NGCC case emits less CO 2 than the IGCC cases
, which emit less than the PC cases.

**•** Among the non

- capture coal cases th e highest efficie ncy cases have the lowe st emissions, after accounting for the carbon intensity of the fuels

. T he range of emissions rates for the CO 2 capture cases is tightened after 90% of the carbon is captured and sequestered.Cost and Performance Baseline for Fossil Energy Plants

37 Exhibit ES

- 27 CO 2 Emissions Normalized By Net Output for Montana Site

1,735

233 1,803

386 1,927

246 1,977

245 1,892

271 1,836

255 1,866

265 799

94

0 500 1,000 1,500 2,000 2,500

Shell Shell w/CO2 Capture TRIG TRIG w/CO2 Capture Siemens Siemens w/CO2 Capture CoP CoP w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureCO2Emissions, lb/net-MWhCost and Performance Baseline for Fossil Energy Plants

38 Exhibit ES

- 28 CO 2 Emissions Normalized By Net Output for North Dakota Site

1,783

242 1,981

255 1,996

242 1,930

276 1,963

288 797

94

0 500 1,000 1,500 2,000 2,500

Shell Shell w/CO2 Capture Siemens Siemens w/CO2 Capture SC PC SC PC w/CO2 Capture USC PC USC PC w/CO2 Capture CFB CFB w/CO2 Capture NGCC NGCC w/CO2 CaptureCO2Emissions, lb/net-MWhCost and Performance Baseline for Fossil Energy Plants

39 In the event that future legislation assigns a cost to c arbon emissions, all of the technologies examined in this study will become more expensive. The technologies without carbon capture will be impacted to a larger extent than those with carbon capture, and coal

- based technologies will be impacted more than natural gas

- based technologies. The most economical option for each technology is used for the COE sensitivity to carbon emissions price shown for the Montana site cases in CO 2 Emission Price Impact

Exhibit ES

- 29 and for the North Dakota s ite cases in Exhibit ES

- 30

. Thus, the PC technology is represented by the SC PC cases and the IGCC technology is represented by the TRIG cases for the Montana site and the Shell cases for the North Dakota site. The curves represe nt the base study design conditions
, capacity factor
, and fuel prices used for each technology; namely 80 percent capacity factor for IGCC plants and 85 percent for PC and NGCC plants, and $0.89/MMBtu for the PRB coal and $0.83/MMBtu for the lignite coal a nd $ 7

. 13 /MMBtu for natural gas. Natural gas fuel prices are more volatile than coal and tend to fluctuate over a fairly large range. The dispatch

- based capacity factor for NGCC plants is significantly less than 85 percent and would result in a higher COE as was shown in the capacity factor sensitivity.

Exhibit ES

- 29 Sensitivity to Carbon Emissions Price for Montana Site

0 20 40 60 80 100 120 140 160 180

0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)

First Year CO 2 Emission Price, $/tonne Shell IGCC w/Capture
SC PC w/Capture
TRIG IGCC w/Capture
NGCC w/Capture

Shell IGCC

TRIG IGCC

NGCC

SC PCCost and Performance Baseline for Fossil Energy Plants

40 Exhibit ES

- 30 Sensitivity to Carbon Emissions Price for North Dakota Site

The intersection of the capture and non

- capture curves for a given technology gives the cost of CO 2 avoided for that technology. For example, the cost of CO 2 avoided is $6 8 /tonne for SC PC and $8 9 /tonne for NGCC at the Montana site, and $ 70/tonne a nd $87 /tonne for the North Dakota site . These values can be compared to those shown in Exhibit ES

- 14

. The following conclusions can be drawn from the carbon emissions price graph:

**•** At the baseline study conditions any cost applied to carbon emissions favors NGCC technology. While PC and NGCC with no capture start at essentially equivalent COEs, they diverge rapidly as the CO 2 emission cost increases. The lower carbon intensity of natural gas relative to coal and t he greater efficiency of the NGCC technology account for this effect.

**•** The SC PC and IGCC curves are nearly parallel indicating that the CO 2 emission price impacts the two technologies nearly equally. As the CO 2 emission price increases from zero, t he two technologies gradually converge due to the slightly lower efficiency of SC PC relative to the IGCC.

**•** For the coal

- based technologies, adding CO 2 capture become s the favored configuration compared to SC PC with no capture at an emission price above approxima tely $ 7 0/tonne

. 0 20 40 60 80 100 120 140 160 180

0 10 20 30 40 50 60 70 80 90 100COE, mills/kWh (2007$)

First Year CO 2 Emission Price, $/tonne Shell w/Capture SC PC w/Capture NGCC w/Capture
Shell

NGCC

SC PCCost and Performance Baseline for Fossil Energy Plants

41 The relationship between technologies and CO 2 emission pricing can also be considered in a “phase diagram” type plot as shown in Combined CO 2 Emission and Natural Gas Price Parity

Exhibit ES

- 31 . Th e lines in the plot represent cost parity between different pairs of technologies, combining the CO 2 emissions price and natural gas price sensitivities to determine the lowest cost generating option at all combinations of these economic parameters. The d arker lines represent the Montana site cases and the lighter lines represent the North Dakota site cases.
Exhibit ES

- 31 Lowest Cost Technology Parity Sensitivity to CO 2 and NG Prices

The lowest cost technology selection f or the given CO 2 emission and natural gas price follows the same trend for both the Montana and North Dakota site: NGCC dominates at low natural gas prices. The PC cases are the next attractive technology once natural gas prices exceed the colored horizon tal lines. The black vertical lines demarcate the economic conditions where including CO 2 capture to the base plant configuration results in the lowest overall COE. The slopes of the lines are a function of the relative CO 2 intensities of the technologie s as well as the natural gas cases sensitivity to fuel price.

When the parity charts are overlaid , it becomes apparent that the NGCC cases occupy a larger area as the lowest cost generating option at the North Dakota site , due in part to the reduced combus tion turbine derate at lower elevation. The vertical black break even lines for the Montana site occur at slightly higher CO 2 emissions prices com pared to the North Dakota site. 0 2 4 6 8 10 12 14

0 10 20 30 40 50 60 70 80 90 100 110Natural Gas Price, $/MMBtu

CO 2 Emissions Price, $/tonne SC PC has lowest COE

NGCC has lowest COE USC PC w / Capture has lowest COE

NGCC w / Capture has lowest COE North Dakota

MontanaCost and Performance Baseline for Fossil Energy Plants

42 1 “Cost and Performance Baseline for Fossil Energy Plants, Volume 3a: Low Rank Coal to Electricity: IGCC Cases”, DOE/NETL

- 2010/1399, May 2011 REFERENCES

2 “Cost and Performance Baseline for Fossil Energy Plants, Volume 3b: Low Rank Coal to Electricity: Combustion Cases”, DOE/NETL

- 2011/1463 , March 2011
3 “Cost and Performance Baseline for Fossil Energy Plants, Volume 3c: Natural Gas Combined Cycle at Elevation”, DOE/NETL

- 2010/1396, March 2011
4 NETL Power Systems Financial M odel Version 5.0, December 2008 User Guide available at: http://www.netl.doe.gov/business/solicitations/ssc2008/references/PSFM%20User%20G uide.pdf