# Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2 , November 20 10

DOE/NETL
- 20 10 / 1397

# 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 liabili ty 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, pr ocess, 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.

# COST AND PERFORMANCE BASELINE FOR FOSSIL ENERGY PLANTS VOLUME 1: BITUMINOUS COAL AND NATURAL GAS TO ELECTRICITY

DOE/ 20 10 / 1397 Final Report (Original Issue Date, May 2007) Revision 1, August 2007 Revision 2, November 2010

NETL Contact:

James Black Combustion Systems Lead Office of Systems, Analysis and Planning

National Energy Technology Laboratory www.netl.doe.gov

## This 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 hyd rogen) 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 re search “pipeline,” and multiple paths are being pursued to create a portfolio of promising technologies for development, demonstration, and eventual 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 while 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 blocks 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. Such 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 Pulverized Coal ( PC ) Combustion, Integrated Gasification Combined Cycles (IGCC), and Natural Gas Combined Cycles (NGCC), all with and without carbon dioxide (CO 2 

## ) capture and sequestratio n assuming that the plants use technology available today. 

## 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 published reports, info rmation 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 results 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 dioxide ( CO 2 

## ) in the cas es 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 were 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.

## Results This independent analysis of fossil energy plant cost and performance is considered to be the most comprehensive set of publicly available data to date. While input was sought from technology vendors, the final assessment of performance and cost was determined independent ly, and may not represent the view s of the technology vendors. The extent of collaboration with technology vendors varied from case to case, with minimal or no input from some vendors. Selection of system components and plant configurations from potentia l options and the rapid escalation in labor and material costs made it a challenge to develop state

- of

- the

- art configurations and cost estimates

. The rigorous expert technical review and systematic use of existing vendor quotes and project design/build da ta to develop the cost estimates in this report are believed to provide the most up

- to

- date performance and costs available in the public literature. The main purpose of publishing Revision 2 is to update performance and economic results. N ew data from t echnology vendors was incorporated into the modeling approach , owner’s costs were added to the financial model , and supple mental chapters were added that extend beyond the original report scope. The f ollowing are h ighlights of the study:

**•** Coal

- based plants using today’s technology are capable of producing electricity at relatively high efficiencies of about 39 percent , h igher heating value ( [HHV] , without CO 2 

## capture) on bituminous coal while meet ing or exceed ing current environmental requirements for criteria pollutants.

**•** T otal overnight cost ( TOC ) for the non

- capture plants are as follows: NGCC, $ 718 /kW; PC, $2 , 01 0 /kW (average); IGCC, $ 2,50 5 /kW (average). With CO 2 

## capture, capital costs are: NGCC, $1, 497 /kW; P C, $ 3,5 90 /kW (average); IGCC, $ 3,5 68 /kW (average).

**•** At fuel costs of $1. 64 /MMBtu of coal and $ 6.55 /MMBtu of natural gas, the COE for the
non - capture plants is : 59 mills/kWh for NG C C, 59 mills/kWh for P C (average) , and 77 mills/kWh (average) for IGCC.

**•** When today’s technology for CO 2 

## capture and sequestration (CCS) is integrated into these new power plants, the resultant COE , including the cost of CO 2 

## TS&M , is: 86 mills/kWh for NGCC; 1 08 mills/kWh (average) for P C; and 1 12 mills/kWh (average) for IGC C. The cost of transporting CO 2 

## 50 miles for storage in a geologic formation with over 30 years of monitoring is estimated to add about 3 to 6 mills/kWh. This represents less than 5 .5 percent of the COE for each CO 2 

## capture case

. **•** A sensitivity study on natu ral gas price shows that at a coal price of $1.64/MMBtu , the average COE for IGCC with capture equal s that of NGCC with CO 2 

## capture at a gas price of $ 9. 8 0 /MMBtu. T he average COE for PC with capture equals that of NGCC with capture at a gas price of $ 9. 25 /MMBtu. In te rms of capacity factor (CF) , when non capture NGCC drops to 4 0 percent, such as in a pe aking application, the COE is comparable to non - capture IGCC operating at base load (80 percent CF ). 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 of these s ystems in today’s market and regulatory environment as well as in a carbon constrained scenario. 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

VII 

# Table of Contents

TABLE OF CONTENTS
................................ ................................ ................................ .......... VII LIST OF EXHIBITS
................................ ................................ ................................ ................... XI PREPARED BY
................................ ................................ ................................ ....................... XIX ACKNOWLEDGMENTS
................................ ................................ ................................ ......... XX LIST OF ACRONYMS AND ABBREVIATIONS
................................ ............................... XXI EXECUTIVE SUMMARY
................................ ................................ ................................ ........... 1 P ERFORMANCE



## ................................ ................................ ................................ .............................. 3 E

NERGY 

## E FFICIENCY



## ................................ ................................ ................................ .................. 3 W

ATER 

## U SE



## ................................ ................................ ................................ ................................ 7 C OST 

## R ESULTS



## ................................ ................................ ................................ .............................. 9 T

OTAL 

## O VERNIGHT 

## C OST



## ................................ ................................ ................................ ............ 9 C OST OF 

## E LECTRICITY



## ................................ ................................ ................................ .............. 11 CO 2 

## E MISSION 

## P RICE 

## I MPACT



## ................................ ................................ ................................ .. 16 C OST O F 

## CO 2 

## A VOIDED



## ................................ ................................ ................................ ............ 19 E NVIRONMENTAL 

## P ERFORMANCE



## ................................ ................................ ............................... 21 1. INTRODUCTION
................................ ................................ ................................ ................ 27 2. GENERAL EVALUATION BASIS
................................ ................................ ................... 31 2.1 S ITE 

## C HARACTERISTICS



## ................................ ................................ ................................ .. 31 2.2 C OAL 

## C HARACTERISTICS



## ................................ ................................ ................................ 32 2.3 N ATU RAL 

## G AS 

## C HARACTERISTICS



## ................................ ................................ .................. 34 2.4 E NVIRONMENTAL 

## T ARGETS



## ................................ ................................ ............................ 34 2.4.1 IGCC

................................ ................................ ................................ .......................... 37 2.4.2 PC

................................ ................................ ................................ .............................. 38 2.4.3 NGCC

................................ ................................ ................................ ......................... 39 2.4.4 C ARBON 

## D IOXIDE



## ................................ ................................ ................................ ........ 40 2.5 C APACITY 

## F ACTOR



## ................................ ................................ ................................ ......... 41 2.6 R AW 

## W ATER 

## W ITHDRAWAL AND CONSUM PTION



## ................................ ............................ 41 2.7 C OST 

## E STIMATING 

## M ETHODOLOGY



## ................................ ................................ ................ 42 2.7.1 C APITAL 

## C OSTS



## ................................ ................................ ................................ ............ 42 2.7.2 O PERATIONS AND 

## M AINTENANCE 

## C OSTS



## ................................ ................................ ....... 52 2.7.3 CO 2 

## T RANSPORT 

## , S TORAGE AND 

## M ONITORING



## ................................ .............................. 53 2.7.4 F INANCE 

## S TRUCTURE 

## , D ISCOUN TED 

## C ASH 

## F LOW 

## A NALYSIS 

## , AND 

## COE

.......................... 56 2.8 IGCC S TUDY 

## C OST 

## E STIMATES 

## C OMPARED TO 

## I NDUSTRY 

## E STIMATES



## .......................... 63 3. IGCC POWER PLANTS
................................ ................................ ................................ .... 67 3.1 IGCC C OMMON 

## P ROCESS 

## A REAS



## ................................ ................................ ................... 67 3.1.1 C OAL 

## R ECEIVING AND 

## S TORAGE



## ................................ ................................ ................... 67 3.1.2 A IR 

## S EPARATION 

## U NIT 

## (ASU) C HOICE AND 

## I NTEGRATION



## ................................ ............. 68 3.1.3 W ATER 

## G AS 

## S HIFT 

## R EACTORS



## ................................ ................................ ....................... 72 3.1.4 M ERCURY 

## R EMOVAL



## ................................ ................................ ................................ .... 72 3.1.5 A CID 

## G AS 

## R EMOVAL 

## (AGR) P ROCESS 

## S ELECTION



## ................................ ......................... 73 3.1.6 S ULFUR 

## R ECOVERY 

## /T AIL 

## G AS 

## C LEANUP 

## P ROCESS 

## S ELECTION



## ................................ ....... 81 3.1.7 S LAG 

## H ANDLING



## ................................ ................................ ................................ .......... 84 3.1.8 P OWER 

## I SLAND



## ................................ ................................ ................................ ............ 84 3.1.9 S TEAM 

## G ENERATION 

## I SLAND



## ................................ ................................ ......................... 88

### Cost and Performance Baseline for Fossil Energy Plants

VIII 

## 3.1.10 A CCESSORY 

## E LECTRIC 

## P LANT



## ................................ ................................ ................... 92 3.1.11 I NSTRUMENTATION AND 

## C ONTROL



## ................................ ................................ ............ 92 3.2 G ENERAL 

## E LECTRIC 

## E NERGY 

## IGCC C ASES



## ................................ ................................ .... 93 3.2.1 G ASIFIER 

## B ACKGROUND



## ................................ ................................ ............................... 94 3.2.2 P ROCESS 

## D ESCRIPTION



## ................................ ................................ ................................ 96 3.2.3 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 103 3. 2.4 S PARING 

## P HILOSOPHY



## ................................ ................................ ................................ 105 3.2.5 C ASE 

## 1 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 105 3.2.6 C ASE 

## 1

- M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .............. 116 3.2.7 C ASE 

## 1

- C OST 

## E STIMATING



## ................................ ................................ ........................ 124 3.2.8 C ASE 

## 2

- GEE IGCC WITH 

## CO 2 

## C APTURE



## ................................ ................................ .. 131 3.2.9 C ASE 

## 2 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 135 3.2.10 C ASE 

## 2

- M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .......... 146 3.2.11 C ASE 

## 2

- C OST 

## E STIMATING



## ................................ ................................ .................... 155 3.3 C ONOCO 

## P HILLIPS 

## E

- G AS TM 

## IGCC C ASES



## ................................ ................................ ..... 162 3.3.1 G ASIFIER 

## B ACKGROUND



## ................................ ................................ ............................. 162 3.3.2 P ROCESS 

## D ESCRIPTION



## ................................ ................................ .............................. 164 3.3.3 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 170 3.3.4 S PARING 

## P HILOSOPHY



## ................................ ................................ ................................ 170 3.3.5 C ASE 

## 3 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 172 3.3.6 C ASE 

## 3

- M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .............. 182 3.3.7 C ASE 

## 3

- C OSTS 

## E STIMATING 

## R ESULTS



## ................................ ................................ ........ 191 3.3.8 C ASE 

## 4

- E

- G AS 

## TM IGCC P OWER 

## P LANT WITH 

## CO 2 

## C APTURE



## ................................ ..... 198 3.3.9 C ASE 

## 4 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 202 3.3.10 C ASE 

## 4

- M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .......... 214 3.3.11 C ASE 

## 4

- C OST 

## E STIMATING 

## R ESULTS



## ................................ ................................ ...... 222 3.4 S HELL 

## G LOBAL 

## S OLUTIONS 

## IGCC C ASES



## ................................ ................................ ..... 229 3.4.1 G ASIFIER 

## B ACKGROUND



## ................................ ................................ ............................. 229 3.4.2 P ROCESS 

## D ESCRIPTION



## ................................ ................................ .............................. 231 3.4.3 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 237 3.4.4 S PARING 

## P HILOSOPHY



## ................................ ................................ ................................ 239 3.4.5 C ASE 

## 5 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 239 3.4.6 C ASE 

## 5

- M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .............. 250 3.4.7 C ASE 

## 5

- C OST 

## E STIMATING



## ................................ ................................ ........................ 258 3.4.8 C ASE 

## 6

- S HELL 

## IGCC P OWER 

## P LANT WITH 

## CO 2 

## C APTURE



## ................................ ......... 265 3.4.9 C ASE 

## 6 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 271 3.4.10 C ASE 

## 6

- M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .......... 282 3.4.11 C ASE 

## 6

- C OST 

## E STIMATING



## ................................ ................................ .................... 290 3.5 IGCC C ASE 

## S UMMARY



## ................................ ................................ ................................ . 297 4. PULVERIZED COAL RANK INE CYCLE PLANTS
................................ ................... 305 4.1 PC C OMMON 

## P ROCESS 

## A REAS



## ................................ ................................ ...................... 306 4.1.1 C OAL AND 

## S ORBENT 

## R ECEIVING AND 

## S TORAGE



## ................................ ........................... 306 4.1.2 S TEAM 

## G ENERATOR AND 

## A NCILLARIES



## ................................ ................................ ........ 306 4.1.3 NO X 

## C ONTROL 

## S YSTEM



## ................................ ................................ ............................... 309 4.1.4 P ARTICULATE 

## C ONTROL



## ................................ ................................ ............................. 310 4.1.5 M ERCURY 

## R EMOVAL



## ................................ ................................ ................................ .. 310

### Cost and Performance Baseline for Fossil Energy Plants

IX 

## 4.1.6 F LUE 

## G AS 

## D ESULFURIZATION



## ................................ ................................ ..................... 310 4.1.7 C ARBON 

## D IOXIDE 

## R ECOVERY 

## F ACILITY



## ................................ ................................ ....... 313 4.1.8 P OWER 

## G ENERATION



## ................................ ................................ ................................ .. 318 4.1.9 B ALANCE OF 

## P LANT



## ................................ ................................ ................................ ... 318 4.1.10 A CCESSORY 

## E LECTRIC 

## P LANT



## ................................ ................................ ................. 322 4.1.11 I NSTRUMENTATION AND 

## C ONTROL



## ................................ ................................ .......... 322 4.2 S UBCRITICAL 

## PC C ASES



## ................................ ................................ ............................... 322 4.2.1 P ROCESS 

## D ESCRIPTION



## ................................ ................................ .............................. 323 4.2.2 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 327 4.2.3 S PARING 

## P HILOSOPHY



## ................................ ................................ ................................ 329 4.2.4 C ASE 

## 9 P ERFORMANCE 

## R ESULTS



## ................................ ................................ ................ 329 4.2.5 C ASE 

## 9

– M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ ............. 338 4.2.6 C ASE 

## 9

– C OST 

## E STIMATING



## ................................ ................................ ....................... 346 4.2.7 C ASE 

## 10

– PC S UBCRITICAL 

## U NIT WITH 

## CO 2 

## C APTURE



## ................................ ............... 353 4.2.8 C ASE 

## 10 P ERFORMANCE 

## R ESULTS



## ................................ ................................ .............. 353 4.2.9 C ASE 

## 10

– M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ ........... 364 4.2.10 C ASE 

## 10

– C OST 

## E STIMATING



## ................................ ................................ ................. 373 4.3 S UPERCRITICAL 

## PC CASES



## ................................ ................................ ............................ 380 4.3. 1 P ROCESS 

## D ESCRIPTION



## ................................ ................................ .............................. 380 4.3.2 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 384 4. 3.3 S PARING 

## P HILOSOPHY



## ................................ ................................ ................................ 385 4.3.4 C ASE 

## 11 P ERFORMANCE 

## R ESULTS



## ................................ ................................ .............. 385 4.3.5 C ASE 

## 11

– M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ ........... 394 4.3.6 C ASE 

## 11

– C OSTS 

## E STIMATING 

## R ESULTS



## ................................ ................................ ...... 402 4.3.7 C ASE 

## 12

– S UPERCRITICAL 

## PC WITH 

## CO 2 

## C APTURE



## ................................ .................... 409 4.3.8 C ASE 

## 12 P ERFORMANCE 

## R ESULTS



## ................................ ................................ .............. 409 4.3.9 C ASE 

## 12

– M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ ........... 420 4.3.10 C ASE 

## 12

– C OST 

## E STIMATING 

## B ASIS



## ................................ ................................ ........ 429 4.4 PC C ASE 

## S UMMARY



## ................................ ................................ ................................ ...... 4 36 5. NATURAL GAS COMBINED CYCLE PLANTS
................................ ......................... 443 5.1 NGCC C OMMON 

## P ROCESS 

## A REAS



## ................................ ................................ ................ 443 5.1.1 N ATURAL 

## G AS 

## S UPPLY 

## S YSTEM



## ................................ ................................ ................... 443 5.1.2 C OMBUSTION 

## T URBINE



## ................................ ................................ ............................... 443 5.1.3 H EAT 

## R ECOVERY 

## S TEAM 

## G ENERATOR



## ................................ ................................ ......... 445 5.1.4 NO X 

## C ONTROL 

## S YSTEM



## ................................ ................................ .............................. 445 5.1.5 C ARBON 

## D IOXIDE 

## R ECOVERY 

## F ACILITY



## ................................ ................................ ....... 446 5.1.6 S TEAM 

## T URBINE



## ................................ ................................ ................................ ......... 448 5.1.7 W ATER AND 

## S TEAM 

## S YSTEMS



## ................................ ................................ ...................... 449 5.1.8 A CCESSORY 

## E LECTRIC 

## P LANT



## ................................ ................................ ..................... 451 5.1.9 I NSTRUMENTATION AND 

## C ONTROL



## ................................ ................................ .............. 451 5.2 NGCC C ASES



## ................................ ................................ ................................ ............... 452 5.2.1 P ROCESS 

## D ESCRIPTION



## ................................ ................................ .............................. 452 5.2.2 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 455 5. 2.3 S PARING 

## P HILOSOPHY



## ................................ ................................ ................................ 456 5.2.4 C ASE 

## 13 P ERFORMANCE 

## R ESULTS



## ................................ ................................ .............. 457 5.2.5 C ASE 

## 13

– M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ ........... 464

### Cost and Performance Baseline for Fossil Energy Plants

X 

## 5.2.6 C ASE 

## 13

– C OST 

## E STIMATING



## ................................ ................................ ..................... 469 5.2.7 C ASE 

## 14

– NGCC WITH 

## CO 2 

## C APTURE



## ................................ ................................ ....... 476 5.2.8 C ASE 

## 14 P ERFORMANCE 

## R ESULTS



## ................................ ................................ .............. 476 5.2.9 C ASE 

## 14 M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ .............. 486 5.2.10 C ASE 

## 14

– C OST 

## E STIMATING



## ................................ ................................ ................. 492 5.3 NGCC C ASE 

## S UMMARY



## ................................ ................................ ............................... 499 6. EFFECT OF HIGHER NAT URAL GAS PRICES AND DISPATCH

- BASED CAPACITY FACTORS
................................ ................................ ................................ ............ 505 6.1 I NCREASING 

## N ATURAL 

## G AS 

## P RICES



## ................................ ................................ .............. 505 6.2 P RICE 

## M ETHODOLOGY



## ................................ ................................ ................................ .. 505 6.3 C OST OF 

## E LECTRICITY



## ................................ ................................ ................................ .. 506 6. 4 D ISPATCH



## - B ASED 

## C APACITY 

## F ACTORS



## ................................ ................................ ........ 513 6.5 D ISPATCH 

## M ODELING 

## R ESULTS 

## W ITHIN 

## PJM

................................ ............................... 516 6.6 PJM I NDEPENDENT 

## S YSTEM 

## O PERATOR



## ................................ ................................ ....... 522 6.6.1 PJM R OLES AND 

## R ESPONSIBILITIES



## ................................ ................................ ............ 523 6.6.2 G ENERATION 

## M IX



## ................................ ................................ ................................ ....... 524 6.6.3 PJM M ARKETS



## ................................ ................................ ................................ ........... 524 6.6.4 PJM E NERGY 

## M ARKETS



## ................................ ................................ ............................. 525 6.6.5 D AY



## - A HEAD 

## M ARKET



## ................................ ................................ ................................ . 525 6.6.6 P RICES AND 

## D EMAND



## ................................ ................................ ................................ . 527 6.7 D ESCRIPTION OF THE 

## PJM R EGIONAL 

## M ODELING



## ................................ ........................ 529 6.8 WP LAN 

## ET M ODEL 

## I NPUTS



## ................................ ................................ ........................... 530 7. DRY AND PARALLEL COO LING
................................ ................................ ................ 533 7.1 S TUDY 

## R ESULTS



## ................................ ................................ ................................ ........... 535 7.2 S ENSITIVITY 

## C ASE



## ................................ ................................ ................................ ........ 542 7.3 C ONCLU SIONS



## ................................ ................................ ................................ ............... 543 8. GEE IGCC IN QUENCH

- ONLY CONFIGURATION W ITH CO 2 

## CAPTURE
........ 545 8.1 C ASE 

## 2A

– GEE IGCC IN 

## Q UENCH 

## O NLY 

## M ODE WITH 

## CO 2 

## C APTURE



## ......................... 546 8.1.1 K EY 

## S YSTEM 

## A SSUMPTIONS



## ................................ ................................ ......................... 550 8.1.2 C ASE 

## 2A P ERFORMANCE 

## R ESULTS



## ................................ ................................ .............. 552 8.1.3 C ASE 

## 2A

– M AJOR 

## E QUIPMENT 

## L IST



## ................................ ................................ ........... 561 8.1.4 C ASE 

## 2A

– C OST 

## E STIMATING



## ................................ ................................ ..................... 570 9. SENSITIVITY TO MEA S YSTEM PERFORMANCE AN D COST BITUMINOUS BASELINE CASE 12A
................................ ................................ ................................ .............. 577 9.1 B ASIS FOR 

## S ENSITIVITY 

## A NALYSIS



## ................................ ................................ ............... 577 9.2 P ERFORMANCE



## ................................ ................................ ................................ .............. 577 9.3 C OST 

## E STIMATING



## ................................ ................................ ................................ ........ 583 10. REVISION CONTROL
................................ ................................ ................................ . 591 11. REFERE NCES
................................ ................................ ................................ ............... 595

### Cost and Performance Baseline for Fossil Energy Plants

XI 

# List of Exhibits

Exhibit ES

- 1 Case Descriptions

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

- 2 Cost and Performance Summary and Environmental Profile for All Cases

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

- 3 Net Plant Efficiency (HHV Basis)

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

- 4 Raw Water Withdrawal and Consumption

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

- 5 Plant Capital Costs

................................ ................................ ................................ . 10 Exhibit ES

- 6 Economic Parameters Used to Calculate COE

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

- 7 COE by Cost Component

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

- 8 COE Sensitivity to Fuel Costs in Non

- Capture Cases

................................ ........... 14 Exhibit ES

- 9 COE Sensitivity to Fuel Costs in CO 2 

## Capture Cases

................................ ............ 15 Exhibit ES

- 10 COE Sensitivity t o Capacity Factor

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

- 11 Impact of Carbon Emissions Price on Study Technologies

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

- 12 Lowest Cost Power Generation Options Comparing NGCC and Coal

................ 18 Exhibit ES

- 13 First Year CO 2 

## Avoided Costs

................................ ................................ ............. 20 Exhibit ES

- 14 Study Environmental Targets

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

- 15 SO 2 

## , NOx, and Particulate Emission Rates

................................ .......................... 23 Exhibit ES

- 16 Mercury Emission Rates

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

- 17 CO 2 

## Emissions Normalized By Net Output

................................ ......................... 26 Exhibit 1

- 1 Case Descriptions

................................ ................................ ................................ ..... 29 Exhibit 2

- 1 Site Ambient Conditions

................................ ................................ ........................... 31 Exhibit 2

- 2 Site Characteristics

................................ ................................ ................................ ... 31 Exhibit 2

- 3 Design Coal

................................ ................................ ................................ ............... 33 Exhibit 2

- 4 Natural Gas Composition

................................ ................................ .......................... 34 Exhibit 2

- 5 Standards of Performance for Electric Utility Steam Generating Units

................... 35 Exhibit 2

- 6 NSPS Mercury Emission Limits

................................ ................................ ............... 36 Exhibit 2

- 7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

......... 36 Exhibit 2

- 8 Environmental Targets for IGCC Cases

................................ ................................ ... 37 Exhibit 2

- 9 Environmental Targets for PC Cases

................................ ................................ ........ 38 Exhibit 2

- 10 Environmental Targets for NGCC Cases

................................ ................................ 39 Exhibit 2

- 11 Capital Cost Levels and their Elements

................................ ................................ .. 43 Exhibit 2

- 12 Features of an AACE Class 4 Cost Estimate

................................ .......................... 44 Exhibit 2

- 13 AACE Guidelines for Process Contingency

................................ ........................... 48 Exhibit 2

- 14 TASC/TOC Factors

................................ ................................ ................................ . 49 Exhibit 2

- 15 Owner’s Costs Included in TOC

................................ ................................ ............. 50 Exhibit 2

- 16 CO 2 

## Pipeline Specification

................................ ................................ ..................... 53 Exhibit 2

- 17 Deep, Saline Aquifer Specification

................................ ................................ ........ 54 Exhibit 2

- 18 Global Economic Assumptions

................................ ................................ .............. 57 Exhibit 2

- 19 Financial Structure for Investor Owned Utility High and Low Risk Projects

........ 58 Exhibit 2

- 20 Illustration of COE Solutions using DCF Analysis

................................ ................ 60 Exhibit 2

- 21 PC with CCS in Current 2007 Dollars

................................ ................................ .... 61 Exhibit 2

- 22 Capital Charge Factors for COE Equation

................................ ............................. 62 Exhibit 2

- 23 COE and LCOE Summary

................................ ................................ ...................... 63 Exhibit 3

- 1 Air Extracted from the Combustion Turbine a nd Supplied to the ASU in Non

Carbon Capture Cases

................................ ................................ ................................ ........... 70 Exhibit 3

- 2 Typical ASU Process Schematic

................................ ................................ .............. 71

### Cost and Performance Baseline for Fossil Energy Plants

XII 

## Exhibit 3

- 3 Flow Diagram for a Conventional AGR Unit

................................ ........................... 75 Exhibit 3

- 4 Common Chemical Reagents Used in AGR Processes

................................ ............ 76 Exhibit 3

- 5 Physical Solvent AGR Process Simp lified Flow Diagram

................................ ....... 77 Exhibit 3

- 6 Common Physical Solvents Used in AGR Processes

................................ ............... 78 Exhibit 3

- 7 Common Mixed Solvents Used in AGR Processes

................................ .................. 79 Exhibit 3

- 8 Equilibrium Solubility Data on H 2 

## S and CO 2 

## in Various Solvents

.......................... 79 Exhibit 3

- 9 Typical Three

- S tage Claus Sulfur Plant

................................ ................................ ... 82 Exhibit 3

- 10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas

................................ ................................ ................................ ................................ ........ 85 Exhibit 3

- 11 Typical Fuel Specification for F

- Class Machines

................................ ................... 86 Exhibit 3

- 12 Allowable Gas Fuel Contaminant Level for F

- Class Machines

............................. 87 Exhibit 3

- 13 Case 1 Block Flow Diagram , GEE IGCC without CO 2 

## Capture

............................ 98 Exhibit 3

- 14 Case 1 Stream Table, GEE IGCC without CO 2 

## Capture

................................ ........ 99 Exhibit 3

- 15 GEE IGCC Plant Study Configuration Matrix

................................ ..................... 103 Exhibit 3

- 16 Balance of Plant Assumptions

................................ ................................ .............. 104 Exhibit 3

- 17 Case 1 Plant Performance Summary

................................ ................................ .... 106 Exhibit 3

- 18 Case 1 Emissions

................................ ................................ ................................ .. 107 Exhibit 3

- 19 Case 1 Carbon Balance

................................ ................................ ......................... 108 Exhibit 3

- 20 Case 1 Sulfur Balance

................................ ................................ ........................... 108 Exhibit 3

- 21 Case 1 Water Balance

................................ ................................ ........................... 109 Exhibit 3

- 22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic

................................ ................................ ................................ ............................ 111 Exhibit 3

- 23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic

................................ 112 Exhibit 3

- 24 Case 1 Combined

- Cycle Power Generation Heat and Mass Balance Schematic

. 113 Exhibit 3

- 25 Case 1 Overall Energy Balance (0°C [32°F] Reference)

................................ ...... 115 Exhibi t 3

- 26 Case 1 Total Plant Cost Summary

................................ ................................ ........ 125 Exhibit 3

- 27 Case 1 Total Plant Cost Details

................................ ................................ ............ 126 Exhibit 3

- 28 Case 1 Initial and Annual O&M Costs

................................ ................................ . 130 Exhibit 3

- 29 Case 2 Block Flow Diagram , GEE IGCC with CO 2 

## Capture

............................... 132 Exhibit 3

- 30 Case 2 Stream Table , GEE IGC C with CO 2 

## Capture

................................ ........... 133 Exhibit 3

- 31 Case 2 Plant Performance Summary

................................ ................................ .... 136 Exhibit 3

- 32 Case 2 Air Emissions

................................ ................................ ............................ 137 Exhibit 3

- 33 Case 2 Carbon Balance

................................ ................................ ......................... 138 Exhibit 3

- 34 Case 2 Sulfur Balance

................................ ................................ ........................... 138 Exhibit 3

- 35 Case 2 Water Balance

................................ ................................ ........................... 139 Exhibit 3

- 36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic

................................ ................................ ................................ ............................ 141 Exhibit 3

- 37 Case 2 Syngas Cleanup Heat and M ass Balance Schematic

................................ 142 Exhibit 3

- 38 Case 2 Combined

- Cycle Power Generation Heat and Mass Balance Schematic

. 143 Exhibit 3

- 39 Case 2 Overall Energy Balance (0°C [32°F] Reference)

................................ ...... 145 Exhibit 3

- 40 Case 2 Total Plant Cost Summary

................................ ................................ ........ 156 Exhibit 3

- 41 Case 2 Total Plant Cost Details

................................ ................................ ............ 157 Exhibit 3

- 42 Case 2 Initial and Annual Operating and Maintenance Costs

.............................. 161 Exhibit 3

- 43 Case 3 Block Flow Diagram , E

- GasTM IGCC without CO 2 

## Capture

.................... 165 Exhibit 3

- 44 Case 3 Stream Table , E

- GasTM IGCC without CO 2 

## Capture

................................ 166 Exhibit 3

- 45 CoP IGCC Plant Study Configuration Matrix

................................ ...................... 171

### Cost and Performance Baseline for Fossil Energy Plants

XIII 

## Exhibit 3

- 46 Case 3 Plant Performance Summary

................................ ................................ .... 173 Exhibit 3

- 47 Case 3 Air Emissions

................................ ................................ ............................ 174 Exhibi t 3

- 48 Case 3 Carbon Balance

................................ ................................ ......................... 175 Exhibit 3

- 49 Case 3 Sulfur Balance

................................ ................................ ........................... 175 Exhibit 3

- 50 Case 3 Water Balance

................................ ................................ ........................... 176 Exhibit 3

- 51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

................................ ................................ ................................ ............................ 177 Exhibit 3

- 52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic

................................ 178 Exhibit 3

- 53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 179 Exhibit 3

- 54 Case 3 Overall Energy Ba lance (0°C [32°F] Reference)

................................ ...... 181 Exhibit 3

- 55 Case 3 Total Plant Cost Summary

................................ ................................ ........ 192 Exhibit 3

- 56 Case 3 Total Plant Cost Details

................................ ................................ ............ 193 Exhibit 3

- 57 Case 3 Initial and Annual Operating and Maintenance Co sts

.............................. 197 Exhibit 3

- 58 Case 4 Block Flow Diagram , E

- GasTM IGCC with CO 2 

## Capture

......................... 199 Exhibit 3

- 59 Case 4 Stream Table , E

- GasTM IGCC with CO 2 

## Capture

................................ ..... 200 Exhibit 3

- 60 Case 4 Plant Performance Summary

................................ ................................ .... 204 Exhibit 3

- 61 Case 4 Air Emissions

................................ ................................ ............................ 205 Exhibit 3

- 62 Case 4 Carbon Balance

................................ ................................ ......................... 206 Exhibit 3

- 63 Case 4 Sulfur Balance

................................ ................................ ........................... 206 Exhibit 3

- 64 Case 4 Water Balance

................................ ................................ ........................... 207 Exhibit 3

- 65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

................................ ................................ ................................ ............................ 209 Exhibit 3

- 66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic

................................ 210 Exhibit 3

- 67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 211 Exhibit 3

- 68 Case 4 Overall Energy Balance (0°C [32°F] Reference)

................................ ...... 213 Exhibit 3

- 69 Case 4 Total Plant Cost Summary

................................ ................................ ........ 223 Exhibit 3

- 70 Case 4 Total Plant Cost Details

................................ ................................ ............ 224 Exhibit 3

- 71 Case 4 Initial and Annual Operating and Maintenance Costs

.............................. 228 Exhibit 3

- 72 Case 5 Block Flow Diagram , Shell IGCC without CO 2 

## Capture

......................... 232 Exhibit 3

- 73 Case 5 Stream Table , Shell IGCC without CO 2 

## Capture

................................ ...... 233 Exhibit 3

- 74 Shell IGCC Plant Study Configuration Matrix

................................ ..................... 238 Exhibit 3

- 75 Case 5 Plant Performan ce Summary

................................ ................................ .... 240 Exhibit 3

- 76 Case 5 Air Emissions

................................ ................................ ............................ 241 Exhibit 3

- 77 Case 5 Carbon Balance

................................ ................................ ......................... 242 Exhibit 3

- 78 Case 5 Sulfur Balance

................................ ................................ ........................... 242 Exhibit 3

- 79 Case 5 Water Balance

................................ ................................ ........................... 243 Exhibit 3

- 80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

................................ ................................ ................................ ............................ 245 Exhibit 3

- 81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic

................................ 246 Exhibit 3

- 82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 247 Exhibit 3

- 83 Case 5 Overall Energy Balance (0°C [32°F] Reference)

................................ ...... 249 Exhibi t 3

- 84 Case 5 Total Plant Cost Summary

................................ ................................ ........ 259 Exhibit 3

- 85 Case 5 Total Plant Cost Details

................................ ................................ ............ 260 Exhibit 3

- 86 Case 5 Initial and Annual Operating and Maintenance Costs

.............................. 264 Exhibit 3

- 87 Case 6 Block Flow Diagram , Shell IGCC with CO 2 

## Capture

.............................. 268 Exhibit 3

- 88 Case 6 Stream Table , Shell IGCC with CO 2 

## Capture

................................ ........... 269

### Cost and Performance Baseline for Fossil Energy Plants

XIV 

## Exhibit 3

- 89 Case 6 Plant Performance Summary

................................ ................................ .... 272 Exhibit 3

- 90 Case 6 Air Emissions

................................ ................................ ............................ 273 Exhibit 3

- 91 Case 6 Carbon Balance

................................ ................................ ......................... 274 Exhibit 3

- 92 Case 6 Sulfur Balanc e
................................ ................................ ........................... 274 Exhibit 3

- 93 Case 6 Water Balance

................................ ................................ ........................... 275 Exhibit 3

- 94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

................................ ................................ ................................ ............................ 277 Exhibit 3

- 95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic

................................ 27 8 Exhibit 3

- 96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic

. 279 Exhibi t 3

- 97 Case 6 Overall Energy Balance (0°C [32°F] Reference)

................................ ...... 281 Exhibit 3

- 98 Case 6 Total Plant Cost Summary

................................ ................................ ........ 291 Exhibit 3

- 99 Case 6 Total Plant Cost Details

................................ ................................ ............ 292 Exhibit 3

- 100 Case 6 Initial and Annual Operating and Maintenance Costs

............................ 296 Exhibit 3

- 101 Estimated Performance and Cost Results for IGCC Cases

................................ . 297 Exhibit 3

- 102 Plant Capital Cost for IGCC Cases

................................ ................................ ..... 298 Exhibit 3

- 103 COE for IGCC Cases

................................ ................................ .......................... 299 Exhibit 3

- 104 Capacity Factor Sensitivity of IGCC Cases

................................ ........................ 300 Exhibit 3

- 105 Coal Price Sensitivity of IGCC Cases

................................ ................................ 301 Exhibit 3

- 106 Cost of CO 2 

## Avoided in IGCC Cases

................................ ................................ . 301 Exhibit 3

- 107 Carbon Conversion Efficiency and Slag Carbo n Content

................................ .. 302 Exhibit 3

- 108 Raw Water Withdrawal and Consumption in IGCC Cases

................................ 304 Exhibit 4

- 1 Fluor Econamine FG Plus SM 

## Typical Flow Diagram

................................ ............. 314 Exhibit 4

- 2 CO 2 

## Compressor Interstage Pressures

................................ ................................ .... 317 Exhibit 4

- 3 Case 9 Block Flow Diagram, Subcritica l Unit without CO 2 

## Capture

..................... 324 Exhibit 4

- 4 Case 9 Stream Table, Subcritical Unit without CO 2 

## Capture

................................ . 325 Exhibit 4

- 5 Subcritical PC Plant Study Configuration Matrix

................................ .................. 327 Exhibit 4

- 6 Balance of Pl ant Assumptions

................................ ................................ ................ 328 Exhibit 4

- 7 Case 9 Plant Performance Summary

................................ ................................ ...... 330 Exhibit 4

- 8 Case 9 Air Emissions

................................ ................................ .............................. 331 Exhibit 4

- 9 Case 9 Carbon Balance

................................ ................................ ........................... 332 Exhibit 4

- 10 Case 9 Sulfur Balance

................................ ................................ ........................... 332 Exhibit 4

- 11 Case 9 Water Balance

................................ ................................ ........................... 333 Exhibit 4

- 12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO 2 

## Capture

...... 335 Exhibit 4

- 13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle

................................ .... 336 Exhibit 4

- 14 Case 9 Overall Energy Balance (0°C [32°F] Reference)

................................ ...... 337 Exhibit 4

- 15 Case 9 Tot al Plant Cost Summary

................................ ................................ ........ 347 Exhibit 4

- 16 Case 9 Total Plant Cost Details

................................ ................................ ............ 348 Exhibit 4

- 17 Case 9 Initial and Annual Operating and Maintenance Costs

.............................. 352 Exhibit 4

- 18 Case 10 Block Flow Diagram, Subcritical Unit with CO 2 

## Capture

...................... 354 Exhibit 4

- 19 Case 10 Stream Table, Subcritical Unit with CO 2 

## Capture

................................ ... 355 Exhibit 4

- 20 C ase 10 Plant Performance Summary

................................ ................................ ... 357 Exhibit 4

- 21 Case 10 Air Emissions

................................ ................................ .......................... 358 Exhibit 4

- 22 Case 10 Carbon Balance

................................ ................................ ....................... 359 Exhibit 4

- 23 Case 10 Sulfur Balance

................................ ................................ ......................... 359 Exhibit 4

- 24 Case 10 Water Balance

................................ ................................ ......................... 359 Exhibit 4

- 25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO 2 

## Capture

......... 361

### Cost and Performance Baseline for Fossil Energy Plants

XV 

## Exhibit 4

- 26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle

................................ .. 362 Exhibit 4

- 27 Case 10 Overall Energy Balance (0°C [32°F] Reference)

................................ .... 363 Exhibit 4

- 28 Case 10 Total Plant Cost Summary

................................ ................................ ...... 374 Exhibit 4

- 29 Case 10 Total Plant Cost Details

................................ ................................ .......... 375 Exhibit 4

- 30 Case 10 Initial and Annual Operating and Maintenance Costs

............................ 379 Exhibit 4

- 31 Case 11 Block Flow Diagram, Supercritical Unit without CO 2 

## Capture

.............. 381 Exhibit 4

- 32 Case 11 Stream Table, Supercritical Unit without CO 2 

## Capture

.......................... 382 Ex hibit 4

- 33 Supercritical PC Plant Study Configuration Matrix

................................ ............. 384 Exhibit 4

- 34 Case 11 Plant Performance Summary

................................ ................................ .. 386 Exhibit 4

- 35 Case 11 Air Emissions

................................ ................................ .......................... 387 Exhibit 4

- 36 Case 11 Carbon Balance

................................ ................................ ....................... 387 Exhibit 4

- 37 Case 11 Sulfur Balance

................................ ................................ ......................... 388 Exhibit 4

- 38 Case 11 Water Balance

................................ ................................ ......................... 388 Exhibit 4

- 39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO 2 

## Capture

. 391 Exhibit 4

- 40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle

............................... 392 Exhibit 4

- 41 Case 11 Overall Energy Balance (0°C [32°F] Reference )

................................ .... 393 Exhibit 4

- 42 Case 11 Total Plant Cost Summary

................................ ................................ ...... 403 Exhibit 4

- 43 Case 11 Total Plant Cost Details

................................ ................................ .......... 404 Exhibit 4

- 44 Case 11 Initial and Annual Operating and Maintenance Costs

............................ 408 Exhibit 4

- 45 Case 12 Block Flow Diagram, Supercritical Unit with CO 2 

## Capture

................... 410 Exhibit 4

- 46 Case 12 Stream Table, Supercritical Unit with CO 2 

## Capture

............................... 411 Exhibit 4

- 47 Case 12 Plant Performance Summary

................................ ................................ .. 413 Exhibit 4

- 48 Case 12 Air Emissions

................................ ................................ .......................... 414 Exhibit 4

- 49 Case 12 Carbon Balance

................................ ................................ ....................... 415 Exhibit 4

- 50 Case 12 Sulfur Balance

................................ ................................ ......................... 415 Exhibit 4

- 51 Case 12 Water Balance

................................ ................................ ......................... 415 Exhibit 4

- 52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO 2 

## Capture

...... 417 Exhibit 4

- 53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle

............................... 418 Exhibit 4

- 54 Case 12 Overall Energy Balance (0°C [32°F] Reference)

................................ .... 419 Exhibit 4

- 55 Case 1 2 Total Plant Cost Summary

................................ ................................ ...... 430 Exhibit 4

- 56 Case 12 Total Plant Cost Details

................................ ................................ .......... 431 Exhibit 4

- 57 Case 12 Initial and Annual Operating and Maintenance Costs

............................ 435 Exhibit 4

- 58 Estimated Performance and Cost Results for Pulverized Coal Cases

.................. 436 Exhibi t 4

- 59 Plant Capital Cost for PC Cases

................................ ................................ ........... 437 Exhibit 4

- 60 COE for PC Cases

................................ ................................ ................................ . 438 Exhibit 4

- 61 Sensitivity of COE to Capacity Factor for PC Cases

................................ ........... 439 Exhibit 4

- 62 Sensitivity of COE to Coal Price for PC Cases

................................ .................... 440 Exhibit 4

- 63 First Year Cost of CO 2 

## Avoided in PC Cases

................................ ....................... 440 Exhibit 4

- 64 Raw Water Withdrawal and Con sumption in PC Cases

................................ ....... 442 Exhibit 5

- 1 Combustion Turbine Typical Scope of Supply

................................ ....................... 444 Exhibit 5

- 2 CO 2 

## Compressor Interstage Pressures

................................ ................................ .... 449 Exhibit 5

- 3 Case 13 Block Flow Diagram, NGCC without CO 2 

## Capture

................................ . 453 Exhibit 5

- 4 Case 13 Stream Table, NGCC with out CO 2 

## Capture

................................ ............. 454 Exhibit 5

- 5 NGCC Plant Study Configuration Matrix

................................ .............................. 455 Exhibit 5

- 6 NGCC Balance of Plant Assumptions

................................ ................................ .... 456 Exhibit 5

- 7 Case 13 Plant Performance Summary

................................ ................................ .... 457

### Cost and Performance Baseline for Fossil Energy Plants

XVI 

## Exhibit 5

- 8 Case 13 Air Emissions

................................ ................................ ............................ 458 Exhibit 5

- 9 Case 13 Carbon Balance

................................ ................................ ......................... 458 Exhibit 5

- 10 Case 13 Water Balance

................................ ................................ ......................... 459 Exhibit 5

- 11 Case 13 Heat and Mass Balance, NGCC without CO 2 

## Capture

........................... 461 Exhibit 5

- 12 Case 13 Overall Energy Balance (0°C [32°F] Reference)

................................ .... 463 Exhibit 5

- 13 Case 13 Total Plant Cost Summary

................................ ................................ ...... 470 Exhibit 5

- 14 Case 13 Total Plant Cost Details

................................ ................................ .......... 471 Exhibit 5

- 15 Case 13 Initial and Annual Operating and Maintenance Cost Summary

............. 475 Exhibit 5

- 16 Case 14 Block Flow Diagram, NGCC with CO 2 

## Capture

................................ .... 477 Exhibit 5

- 17 Case 14 Stream Table, NGCC with CO 2 

## Capture

................................ ................ 478 Exhibit 5

- 18 Case 14 Plant Performance Summary

................................ ................................ .. 479 Exhibit 5

- 19 Case 14 Air Emissions

................................ ................................ .......................... 480 Exhibit 5

- 20 Case 14 Carbon Balance

................................ ................................ ....................... 480 Exhibi t 5

- 21 Case 14 Water Balance

................................ ................................ ......................... 481 Exhibit 5

- 22 Case 14 Heat and Mass Balance, NGCC with CO 2 

## Capture

................................ 483 Exhibit 5

- 23 Case 14 Overall Energy Balance (0°C [32°F] Reference)

................................ .... 485 Exhibit 5

- 24 Case 14 Total Plant Cost Summary

................................ ................................ ...... 493 Exhibit 5

- 25 Case 14 Total Plant Cost Det ails

................................ ................................ .......... 494 Exhibit 5

- 26 Case 14 Initial and Annual Operating and Maintenance Cost Summary

............. 498 Exhibit 5

- 27 Estimated Performance and Cost Results for NGCC Cases

................................ . 499 Exhibit 5

- 28 Plant Capital Cost for NGCC Cases

................................ ................................ ..... 500 Exhibit 5

- 29 COE of NGCC Cases

................................ ................................ ............................ 501 Exhibit 5

- 30 Sensitivity of COE to Capacity Factor in NGCC Cases

................................ ....... 502 Exhibit 5

- 31 Sensitivity of COE to Fuel Price in NGCC Cases

................................ ................ 502 Exhibit 5

- 32 Raw Water Withdrawal and Consumption in NGCC Cases

................................ . 504 Exhibit 6

- 1 COE By Cost Component

................................ ................................ ....................... 508 Exhibit 6

- 2 First Year CO 2 

## Avoided Costs

................................ ................................ ................ 509 Exhibit 6

- 3 COE Sensitivity to Fuel Costs in Non

- Capture Cases

................................ ............ 510 Exhibit 6

- 4 COE Sensitivity to Fuel Costs in CO 2 

## Capture Cases

................................ ............ 511 Exhibit 6

- 5 COE Sensitivity to Capacity Factor in Non

- Capture Cases

................................ ... 512 Exhibit 6

- 6 COE Sensitivity to Capacity Factor in Capture Cases

................................ ............ 513 Exhibit 6

- 7 Dispatch Ba sed Capacity Factors for Cases without CO 2 

## Capture

......................... 514 Exhibit 6

- 8 Estimated Stacking Order in PJM for Year 2010 Based on First Year Production Costs

................................ ................................ ................................ ................................ .... 517 Exhibit 6

- 9 Capacity Factors of Replacement Units Dispatched into PJM

............................... 518 Exhibit 6

- 10 Dispatch Based Capacity Factors Assuming No CO 2 

## Capture

............................. 518 Exhibit 6

- 11 Summary of Prospective Facility Parameters for Modeling

................................ . 519 Exhibit 6

- 12 Comparison of COE as a Function of Capacity Factor

................................ ........ 520 Exhibit 6

- 13 Impact of Dispatched Based Capacity Factors on the Cost of Ele ctricity

............ 521 Exhibit 6

- 14 The PJM Operating Territory

................................ ................................ ............... 523 Exhibit 6

- 15 PJM Installed Capacity by Fuel Type

................................ ................................ ... 524 Exhibit 6

- 16 PJM East Day

- Ahead LMP for 2006

................................ ................................ .... 526 Exhibit 6

- 17 PJM Load and Day

- Ahead LMP for 2006

................................ ............................ 527 Exhibit 6

- 18 PJM Day

- Ahead LMP vs. Demand for 2006

................................ ........................ 528 Exhibit 6

- 19 PJM Price/Load Distribution for 2006

................................ ................................ .. 528 Exhibit 6

- 20 Data Sources for Electricity Generation in the PJM Region in Year 2006

.......... 530

### Cost and Performance Baseline for Fossil Energy Plants

XVII 

## Exhibit 6

- 21 Assumptions for Projecting PJM Year 2006 into 2010

................................ ........ 531 Exhibit 6

- 22 Breakdown of Additional Generation in the PJM ISO by Fuel Type

................... 531 Exhibit 6

- 23 Summary of Prospective Facility Parameters

................................ ....................... 532 Exhibit 7

- 1 Cost Accoun ts Affected by Change in Cooling System

................................ ......... 534 Exhibit 7

- 2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Case s

................................ ................................ ................................ ................................ ............. 536 Exhibit 7

- 3 Absolute Decrease in Raw Water Withdrawal for Parallel and Dry Cooling Cases

................................ ................................ ................................ ................................ ............. 537 Exhibit 7

- 4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case

..................... 538 Exhibit 7

- 5 Total Overnight Cost for Baseline, Parallel and Dry Cooling Cases

...................... 540 Ex hibit 7

- 6 COE for Baseline, Parallel and Dry Cooling Systems

................................ ............ 541 Exhibit 7

- 7 Design Ambient Conditions for SC PC Sensitivity Case

................................ ........ 542 Exhibit 8

- 1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO 2 

## Capture

........ 547 Exhibit 8

- 2 Case 2A Stream Table, GEE Quench Only IGCC with CO 2 

## Capture

.................... 548 Exhibit 8

- 3 GEE IGCC Plant Study Configuration Matrix

................................ ....................... 551 Exhibit 8

- 4 Case 2A Plant Per formance Summary

................................ ................................ .... 553 Exhibit 8

- 5 Case 2A Air Emissions

................................ ................................ ........................... 554 Exhibit 8

- 6 Case 2A Carbon Balance

................................ ................................ ........................ 555 Exhibit 8

- 7 Case 2A Sulfur Balance

................................ ................................ .......................... 555 Exhibit 8

- 8 Case 2A Water Balance

................................ ................................ .......................... 556 Exhibit 8

- 9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance Sch ematic

................................ ................................ ................................ ............................ 557 Exhibit 8

- 10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic

.............................. 558 Exhibit 8

- 11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic

................................ ................................ ................................ ................................ ............. 559 Exhibit 8

- 12 Case 2A Overall Energy Balance

................................ ................................ ......... 561 Exhibit 8

- 13 Case 2A Total Plant Cost Summary

................................ ................................ ..... 571 Exhibit 8

- 14 Case 2A Total Plant Cost Details

................................ ................................ ......... 572 Exhibit 8

- 15 Case 2A Initial and Annual Operating and Maintenance Costs

........................... 576 Exhibit 9

- 1 Case 12A Block Flow Diagram, Supercritical Unit with CO 2 

## Capture (MEA Sensitivity)

................................ ................................ ................................ .......................... 579 Exhibit 9

- 2 Case 12A Stream Table, Supercritical Unit with CO 2 

## Capture

.............................. 580 Exhibit 9

- 3 Case 12A Plant Performance Summary

................................ ................................ .. 582 Exhibit 9

- 4 Case 12A Total Plant Cost Summary

................................ ................................ ..... 584 Exhibit 9

- 5 Case 12A Total Plant Cost Details

................................ ................................ ......... 585 Exhibit 9

- 6 Case 12A Initial and Annual Operating and Maintenance Costs

........................... 589 Exhibit 10

- 1 Record of Revisions

................................ ................................ .............................. 591

### Cost and Performance Baseline for Fossil Energy Plants

XVIII 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

XIX 

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

UPDATED BY Energy Sector Planning and Analysis (ESPA) :

John L. Haslbeck Booz Allen Hamilton Norma J. Kuehn Booz Allen Hamilton Eric G. Lewis Booz Allen Hamilton

Lora L. Pinkerton WorleyParsons Group, Inc
. James Simpson WorleyParsons Group, Inc. Marc J. Turner Booz Allen Hamilton Elsy Varghese WorleyParsons Group, Inc. Mark C. Woods Booz Allen Hamilton

DOE Contract # DE

- FE0004001

### Cost and Performance Baseline for Fossil Energy Plants

XX 

# Acknowledgments This report was initially prepared by Research and Development Solutions, LLC (RDS) for the United States Department 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 OSAP Systems Division Jam es Black Daniel Cicero Jared Ciferno Kristin Gerdes Eric Grol Jeffrey Hoffmann

Julianne Klara

Patrick Le Michael Matuszewski Sean Plasynski

Larry Rath Wally Shelton

Gary Stiegel William Summers

Thomas Tarka Maria Vargas Pamela Capicotto formerly of Parsons Corporation Michael Rutkowski formerly of Parsons Corporation Ronald Schoff formerly of Parsons Corporation Vladimir Vaysman WorleyParsons Group, Inc.

### Cost and Performance Baseline for Fossil Energy Plants

XXI 

## AACE Association for the Advancement of Cost Engineering L IST OF A CRONYMS AND A BBREVIATIONS

ADIP Aqueous di

- is oproponal AEO Annual Energy Outlook AGR Acid gas removal ANSI American National Standards Institute Aspen Aspen Plus ® 

## ASU Air separation unit BACT Best available control technology BEC Bare erected cost BFD Block flow diagram BFW Boiler feedwater Bt u British thermal unit Btu/h r British thermal unit per hour Btu/kWh British thermal unit per kilowatt

- hour Btu/lb British thermal unit per pound Btu/scf British thermal unit per standard cubic foot
m 3 

## /d Cubic meters per day CAMR Clean Air Mercury Rule CCF Capital Charge Factor CCS Carbon capture and sequestration CDR Carbon Dioxide Recovery CF Capacity factor CGE Cold gas efficiency CL Closed

- loop
cm Centimeter CMU Carnegie Mellon University CO C arbon monoxide CO 2 

## Carbon dioxide COE Cost of electricity CoP ConocoPhillips COS Carbonyl sulfide CRT Cathode ray tube CS Carbon steel CT Combustion turbine CTG Combustion Turbine

- Generator CWP Circulating water pump CWS Circulating water system DCS Distributed control system DI De

- ionized DIPA Diis o propanolamine DLN Dry low NOx DOE Department of Energy

### Cost and Performance Baseline for Fossil Energy Plants

XXII 

## EAF Equivalent availability factor E

- Gas TM 

## ConocoPhillips gasifier technology EIA Energy Information Administration EM Electromagnetic EMF Emission modification factors EPA Environmental Protection Agency EPC Engineer/ Procure/Construct EPRI Electric Power Research Institute EPCM Engineering/Procurement/Construction Management EU European Union ESP Electrostatic precipitator FD Forced draft FERC Federal Energy Regulatory Commission FG Flue gas FGD Flue gas desulfurization FOAK First

- of

- a - kind FRP Fiberglass

- reinforced plastic ft Foot, feet FW Feedwater ft, w.g. Feet of water gauge GADS Generating Availability Data System gal Gallon gal/MWh Gallon per megawatt hour GCV Gross calorific value GDP Gross domestic product GEE G eneral E lectric Energy GHG G reenhouse gas g pd Gallons per day gpm Gallons per minute gr/100 scf grains per one hundred standard cubic feet GSU Generator s tep

- u p t ransformers GT Gas turbine GWh Gigawatt

- hour h Hour H 2 

## Hydrogen H 2 

## S Hydrogen s ulfide H 2 

## SO 4 

## Sulfuric acid Hg Mercury HDPE High

- density polyethylene HHV Higher heating value hp Horsepower HP High

- pressure HRSG Heat recovery steam generator

### Cost and Performance Baseline for Fossil Energy Plants

XXIII 

## HSS Heat stable salts HVAC Heating, ventilating, and air conditioning ICR Information Collection Request ID Induced draft IEA International Energy Agency IGCC Integrated gasification combined cycle IGVs Inlet guide vanes In. H 2 

## O Inches water In. Hga Inches mercury (absolute pressure) In. W.C. Inches water column IOU Investor

- owned utility IP Intermed iate pressure IPM Integrated Planning Model IPP Independent power producer ISO International Standards Organization kg/GJ Kilogram per gigajoule kg/h r Kilogram per hour kJ Kilojoules kJ/h r Kilojoules per hour kJ/kg Kilojoules per kilogram km K ilometer KO Knockout kPa Kilopascal absolute kV Kilovolt kW Kilowatt kWe Kilowatt

- electric kWh Kilowatt

- hour LAER Lowest Achievable Emission Rate LF Levelization factor lb Pound lb/gal Pound per gallon lb/h r Pounds per hour lb/ft 2 

## Pounds per square foot lb/MMBtu Pounds per million British thermal units lb/MWh Pounds per megawatt

- hour lb/TBtu Pounds per trillion British thermal units LCOE Levelized cost of electricity LGTI Louisiana Gasification Technology, Inc. LHV Lower heating value LMP Locational Marginal Price LNB Low NOx burner LNG Liquified natural gas LP Low

- pressure

### Cost and Performance Baseline for Fossil Energy Plants

XXIV 

## lpm Liters per minute LSE L oad

- serving entities
m Meters m/min Meters per minute
m 3 

## /min Cubic meter per minute MAC Main Air Compressor MAF Moisture / Ash

- Free MCR Maximum continuous rat ing
m d Mil lidarcy MDEA Methyldiethanolamine MEA Monoethanolamine MHz Megahertz Mills/kWh Tenths of a cent per kilowat t hour MJ/Nm 3 

## Megajoule per normal cubic meter MMBtu Million British thermal units (also shown as 10 6 

## Btu) MMBtu/h r Million British thermal units (also shown as 10 6 

## Btu) per hour MMkJ Million kilojoules (also shown as 10 6 

## kJ) MMkJ/h r Million kilojoules (also shown as 10 6 

## kJ) per hour MNQC Multi Nozzle Quiet Combustor mol% Mole percent MPa Megapascals MVA Mega volt

- amps MW Megaw a tt MWe Megawatts electric MWh Megawatt

- hour N 2 

## Nitrogen N/A Not applicable NaOH Sodium hydroxide NEMA National Electrical Manufacturers Association NERC North American Electric Reliability Council NETL National Energy Technology Laboratory NGCC Natural gas combined cycle N H 3 

## Ammonia Nm 3 

## Normal cubic meter Nm 3 

## /h r Normal cubic meter per hour NMP N

- methyl

- 2

- pyrrolidone NOAK Nth

- of

- a - kind NOx Oxides of nitrogen NSPS New Source Performance Standards NSR New Source Review O&GJ Oil & Gas Journal O 2 

## Oxygen O&M Operation and maintenance

### Cost and Performance Baseline for Fossil Energy Plants

XXV 

## OC Fn 

## Category n fixed operating cost for the initial year of operation OD Outside diameter OEM Original equipment manufacturers OFA Overfire air OP/VWO Over pressure/valve s wide open PA Primary air PC Pulverized coal PECO Philadelphia Electric Company PJM P ennsylvania

- New J ersey - M aryland Interconnection PM Particulate matter PO Purchase order POTW Publicly Owned Treatment Works PP&L Pennsylvania Power & Light Co mpany ppm Parts per million ppmv Parts per million volume ppmvd Parts per million volume, dry PPS Polyphenylensulfide PRB Powder River Basin coal region PSD Prevention of Significant Deterioration PSE&G Public Service Electric & Gas Co mpany p si Pounds per square inch psia Pounds per square inch absolute psig Pounds p er square inch gage PTFE Teflon (Polytetrafluoroethylene) PSFM Power systems financial model RD&D Research, Development, and Demonstration RDS Research and Development Solutions, LLC RH Reheater RTO R egional transmission organization SC Supercritical
s cf Standard cubic feet scfh Standard cubic feet per hour scfm Standard cubic feet per minute Sch Schedule scmh Standard cubic meter per hour SCOT Shell Claus Off

- gas Treating SC PC Supercritical Pulverized Coal SCR Selective catalytic reduction SEP Samenwerke nde Electriciteits

- Productiebedrijven NV SG Specific gravity SFC Synthetic Fuels Corporation SGC Synthesis gas cooler SGS Sour gas shift

### Cost and Performance Baseline for Fossil Energy Plants

XXVI 

## Shell Shell Global Solutions SNCR Selective non

- catalytic reduction SNG Synthetic natural gas SO 2 

## Sulfur dioxide SOx Ox ides of sulfur SRU Sulfur recovery unit SS Stainless steel SS Amine SS Specialty Amine STG Steam turbine generator Syngas Synthe tic gas TASC Total as

- spent cost TOC Total overnight cost TPC Total plant cost TEWAC Totally Enclosed Water

- to

- Air

- Cooled TGTU Tail gas treating unit Tonne Metric t on (1000 kg) TPC Total plant cost TPD Tons per day TPH Tons per hour TPI Total plant investment TS&M Transport, storage , and monitoring U.S. United States vol% Volume percent WB Wet bulb WGS Water

- gas shift wg Water gauge WTI West Texas Intermediate wt% Weight percent yr Year $/kW Dollars per kilowatt $/MMBtu Dollars per million British thermal units $/MMkJ Dollars per million kilojoule $/MW Dollars per megawatt $/MWh Dollars per megawatt

- hour °C Degrees Celsius

° F De grees Fahrenheit 5

- 10s Fifty hour work weeks

### Cost and Performance Baseline for Fossil Energy Plants

1 

## The objective of this report i s to present an accurate, independent assessment of the cost and performance of fossil energy power systems, specifically integrated gasification combined cycle (IGCC), pulverized coal (PC), and natural gas combined cycle (NGCC) plants, using a consistent technical and economic approach that accurately reflects current market conditi ons. Th is is Volume 1 of a four volume report. The four volume series consists 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 The cost and performance of the various fossil fuel

- based technologies will most likely determine which combination of technologies will be utilized to meet the de mands 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 r egulation o f air, water, and solid waste discharges from fossil

fueled power plants

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

- scale de monstrations under the Department of Energy’s ( DOE ) Clean Coal Programs T welve power plant configurations were analyzed as listed in Exhibit ES

- 1 . The list includes s ix IGCC cases utilizing General Electric Energy (GEE), ConocoPhillips (CoP), and Shell Global Solutions ( Shell ) gasifiers each with and without carbon dioxide ( CO 2 

## ) capture; four PC cases, two subcritical and two supercritical (SC) , each with and without C O 2 

## capture; and two NGCC plants with and without CO 2 

## capture. Two additional cases were originally included in this study and involve production of synthetic natural gas (SNG) and the repowering of an existing NGCC facility using SNG. The two SNG cases were subsequently moved to Volume 2 of this report resulting in the discontinuity o f case numbers (1

- 6 and 9

- 14). W hile input was sought from various technology vendors, the final assessment of performance and cost was determined independently and has not been reviewed by individual vendors. Thus, portions of this report may not represent the views of the technology vendors. The extent of collaboration with technology vendors varied from case to case, with minimal or no collaboration obtained from some ve ndors. The methodology included performing steady

- state simulations of the various technologies using the ASPEN Plus ® 

## (Aspen) modeling program. The resulting mass and energy balance data from

### Cost and Performance Baseline for Fossil Energy Plants

2 

## the Aspen model were used to size major pieces of equipment. T hese equipment sizes formed the basis for cost estimating. Performance and process limits were based upon published reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best en gineering judgment . Capital and operating costs were estimated by WorleyParsons based on simulation results and through a combination of vendor quotes, scaled estimates 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) Annual Energy Outlook (AEO) 2008 . The first year of capital expenditure (2007) costs used are $1. 55 /MMkJ ($1. 64 /MMBtu) for coal (Illinois No. 6) and $ 6.21 /MMk J ($ 6.55 /MMBtu) for natural gas, both on a HHV basis and in 2007 United States ( U.S. ) dollars. Exhibit ES

- 1 Case Descriptions

Case Unit Cycle Steam Cycle, psig/ **°** F/ **°** F Combustion Turbine Gasifier/Boiler Technology Oxidant H 2 

### S Separation/

Removal Sulfur Removal/ Recovery CO 2 

### Separa
tion
1 IGCC 1800/1050/1050 2 x 

### Advanced F Class GEE Radiant Only 95 mol% O 2 Selexol Claus Plant

2 IGCC 1800/1000/1000 2 x 

### Advanced F Class GEE Radiant Only 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage
3 IGCC 1800/1050/1050 2 x 

### Advanced F Class CoP E

- GasTM 95 mol% O 2 Refrigerated MDEA Claus Plant

4 IGCC 1800/1000/1000 2 x 

### Advanced F Class CoP E

- GasTM 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage
5 IGCC 1800/1050/1050 2 x 

### Advanced F Class Shell 95 mol% O 2 Sulfinol

- M Claus Plant

6 IGCC 1800/1000/1000 2 x 

### Advanced F Class Shell 95 mol% O 2 Selexol Claus Plant Selexol 2 nd stage

-- -- -- -- -- -- -- -- --

-- -- -- -- -- -- -- -- --

9 PC 2400/1050/1050 Subcritical PC Air Wet Flue gas desulfuri

zation ( FGD ) / Gypsum 10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Amine Absorber 11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum
12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Amine Absorber
13 NGCC 2400/1050/10 50 2 x 

### Advanced F Class HRSG Air

14 NGCC 2400/1050/10 50 2 x 

### Advanced F Class HRSG Air Amine Absorber 

## All plant c onfigurations are evaluated based on installation at a greenfield site. Since these are state

- of

- the

- art plants, they will have higher efficiencies than the average power plant population. Consequently, these plants would be expected to be near the top o f the dispatch list and the study

### Cost and Performance Baseline for Fossil Energy Plants

3 

## capacity factor ( CF ) is 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 othe r factors can influence dispatch order and CF , sensitivity of the cost of electricity ( COE ) to CF is evaluated and presented later in this Executive Summary ( Exhibit ES

- 10 ) and in the body of the report. The nominal net plant output for this study is set at 550 megawatt ( MW ) . The actual net output varies between technologies because the combustion turbines (CT s) in the IGCC and NGCC cases are manufactured in discrete sizes, but the boilers and steam turbines in the PC cases are readily available in a wide range of capacities. The result is that all of the PC cases have a net output of 550 MW, but the IGCC case s have net outputs ranging from 49 7 (Case 6 ) to 6 29 MW (Case 5) . The range in IGCC net output is caused by the much higher auxiliary load imposed in the CO 2 

## capture cases, primarily due to CO 2 

## compression, and the need for extraction steam in the water

- ga s 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 const ant net output from the steam cycle given the fixed input ( CT ). Likewise, the two NGCC cases have a net output of 5 55 and 4 74 MW because of the CT constraint. Exhibit ES

- 2 shows the cost, performance , and environmental profile summary for all cases. The results are discussed below in the following order:

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

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

**•** Environmental profile
P ERFORMANCE

The net plant efficiency (H H V basis) for all twelve cases is shown in Energy Efficiency Exhibit ES

- 3

. The primary conclusions that can be drawn are:

**•** The NG CC with no CO 2 

## capture has the highest net efficiency of the technologies modeled in this study with an efficiency of 50.2 percent.

**•** The NGCC case with CO 2 

## capture results in the highest efficiency (4 2

. 8 percent) among all of the capture technologies.

**•** The NGCC with CO 2 

## capture results in a relative efficiency penalty of 14.7 percent ( 7. 4 absolute percent ) , compared to the non

- capture case. The NGCC penalty is less than for the PC cases because natural gas is less carbon intensive than coal, and there is l ess CO 2 

## to capture and to compress for equal net power outputs.

**•** The energy efficiency of the IGCC non

- capture cases is as follows: the dry

- fed Shell gasifier (4 2 .1 percent), the slurry

- fed, two

- stage CoP gasifier (39. 7 percent) and the slurry

- fed, single

- stage GEE gasifier (3 9

. 0 percent).

### Cost and Performance Baseline for Fossil Energy Plants

4 

## • When CO 2 

## capture is added to the IGCC cases, the energy efficiency of all three cases is more nearly equal than the non

- capture cases , ranging from 31. 0 percent for CoP to 32. 6 perce nt for GEE, with Shell intermediate at 3 1

. 2 percent.

**•** The relative efficiency penalty for adding CO 2 

## capture to the IGCC cases is 21.4 percent on average. The relative penalty for subcritical and SC PC is 28

. 9 and 27

. 6 percent , respectively. The relative penalty for NGCC is 1 4 .7 percent.

**•** SC PC without CO 2 

## capture has an efficiency of 39.3 percent. Subcritical PC has an efficiency of 36.8 percent, which is the lowest of all the non

- capture cases in the study.

**•** The addition of CO 2 

## capture to the PC cases via the Flu o r Econamine FG Plus SM 

## (Econamine ) p rocess 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 PC plant requires a chemical absorption process rather than physical absorption. For chemical absorption processes, the regeneration requirements are more energy intensive. The relative efficiency impact on NGCC is less because of the lower carbon intensity of natural gas relative to coal as mentioned above.

### Cost and Performance Baseline for Fossil Energy Plants

5 

## Exhibit ES

- 2 Cost and Performance Summary and Environmental Profile for All Cases

1 

### CF is 80% for IGCC case s and 85% for PC and NGCC cases 2 

### COE and Levelized COE are defined in Section 2.7

.

PERFORMANCE Case 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 0% 90% 0% 90% 0% 90% 0% 90% 0% 90% 0% 90% Gross Power Output (kWe) 747,800 734,000 738,200 703,700 737,000 673,400 582,600 672,700 580,400 662,800 564,700 511,000 Auxiliary Power Requirement (kWe) 125,750 190,750 113,140 190,090 108,020 176,540 32,580 122,740 30,410 112,830 9,620 37,430 Net Power Output (kWe) 622,050 543,250 625,060 513,610 628,980 496,860 550,020 549,960 549,990 549,970 555,080 473,570 Coal Flowrate (lb/hr) 466,901 487,011 459,958 484,212 436,646 465,264 437,378 614,994 409,528 565,820 N/A N/A Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 167,333 167,333 HHV Thermal Input (kWth) 1,596,320 1,665,074 1,572,582 1,655,503 1,492,878 1,590,722 1,495,379 2,102,643 1,400,162 1,934,519 1,105,812 1,105,812 Net Plant HHV Efficiency (%) 39.0% 32.6% 39.7% 31.0% 42.1% 31.2% 36.8% 26.2% 39.3% 28.4% 50.2% 42.8% Net Plant HHV Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924 9,277 13,046 8,687 12,002 6,798 7,968 Raw Water Withdrawal (gpm/MW net ) 7.6 10.7 7.0 11.1 6.6 11.3 10.7 20.4 9.7 18.3 4.3 8.4 Process Water Discharge (gpm/MW net ) 1.6 2.0 1.4 2.1 1.2 2.0 2.2 4.7 2.0 4.3 1.0 2.1 Raw Water Consumption (gpm/MW net ) 6.0 8.7 5.5 9.0 5.3 9.3 8.5 15.7 7.7 14.1 3.3 6.3 CO 2 Emissions (lb/MMBtu) 197 20 199 20 197 20 204 20 204 20 118 12 CO 2 Emissions (lb/MWh gross ) 1,434 152 1,448 158 1,361 161 1,783 217 1,675 203 790 87 CO 2 Emissions (lb/MWh net ) 1,723 206 1,710 217 1,595 218 1,888 266 1,768 244 804 94 SO 2 Emissions (lb/MMBtu) 0.0012 0.0022 0.0117 0.0022 0.0042 0.0021 0.0858 0.0017 0.0858 0.0016 Negligible Negligible SO 2 Emissions (lb/MWh gross ) 0.0090 0.0166 0.0852 0.0173 0.0290 0.0171 0.7515 0.0176 0.7063 0.0162 Negligible Negligible NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.070 0.070 0.070 0.070 0.009 0.008 NOx Emissions (lb/MWh gross ) 0.430 0.376 0.434 0.396 0.409 0.396 0.613 0.747 0.576 0.697 0.060 0.061 PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 0.0130 0.0130 0.0130 0.0130 Negligible Negligible PM Emissions (lb/MWh gross ) 0.052 0.055 0.052 0.057 0.049 0.057 0.114 0.139 0.107 0.129 Negligible Negligible Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 1.143 1.143 1.143 1.143 Negligible Negligible Hg Emissions (lb/MWh gross ) 4.16E-06 4.42E-06 4.15E-06 4.59E-06 3.95E-06 4.61E-06 1.00E-05 1.22E-05 9.41E-06 1.14E-05 Negligible Negligible COST Total Plant Cost (2007$/kW) 1,987 2,711 1,913 2,817 2,217 3,181 1,622 2,942 1,647 2,913 584 1,226 Total Overnight Cost (2007$/kW) 2,447 3,334 2,351 3,466 2,716 3,904 1,996 3,610 2,024 3,570 718 1,497 **Bare Erected Cost** 1,528 2,032 1,470 2,113 1,695 2,385 1,317 2,255 1,345 2,239 482 926 **Home Office Expenses** 144 191 138 199 156 221 124 213 127 211 40 78 **Project Contingency** 265 369 256 385 302 444 182 369 176 362 62 162 **Process Contingency** 50 119 50 120 63 131 0 105 0 100 0 60 **Owner's Costs** 460 623 438 649 500 723 374 667 377 657 133 271 Total Overnight Cost (2007$ x 1,000) 1,521,880 1,811,411 1,469,577 1,780,290 1,708,524 1,939,878 1,098,124 1,985,432 1,113,445 1,963,644 398,290 709,039 Total As Spent Capital (2007$/kW) 2,789 3,801 2,680 3,952 3,097 4,451 2,264 4,115 2,296 4,070 771 1,614 COE (mills/kWh, 2007$) 1,2 76.3 105.6 74.0 110.3 81.3 119.4 59.4 109.6 58.9 106.5 58.9 85.9 **CO2 TS&M Costs** 0.0 5.2 0.0 5.5 0.0 5.6 0.0 5.8 0.0 5.6 0.0 3.2 **Fuel Costs** 14.3 17.1 14.0 18.0 13.3 17.9 15.2 21.3 14.2 19.6 44.5 52.2 **Variable Costs** 7.3 9.3 7.2 9.8 7.8 9.9 5.1 9.2 5.0 8.7 1.3 2.6 **Fixed Costs** 11.3 14.8 11.1 15.5 12.1 16.7 7.8 13.1 8.0 13.0 3.0 5.7 **Capital Costs** 43.4 59.1 41.7 61.5 48.2 69.2 31.2 60.2 31.7 59.6 10.1 22.3 LCOE (mills/kWh, 2007$) 1,2 96.7 133.9 93.8 139.9 103.1 151.4 75.3 139.0 74.7 135.2 74.7 108.9 Integrated Gasification Combined Cycle Pulverized Coal Boiler NGCC GEE R+Q CoP E-Gas FSQ Shell PC Subcritical PC Supercritical Advanced F Class

### Cost and Performance Baseline for Fossil Energy Plants

6 

## Exhibit ES

- 3 Net Plant Efficiency (HHV Basis)

39.0%

32.6% 39.7%

31.0% 42.1%

31.2% 36.8%

26.2% 39.3%

28.4% 50.2%

42.8%

0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0%

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureEfficiency, % (HHV Basis)

### Cost and Performance Baseline for Fossil Energy Plants

7 

## Three water values are presented for each technology in Water Use Exhib it ES

- 4 : raw water withdrawal , process discharge , and raw water consumption . Each value is normalized by net output. Raw water withdrawal is the difference between demand and internal re cycle. Demand is the amount of water required to satisfy a particular process (slurry, quench, f lue gas desulfurization [ FGD ] makeup, etc.) and internal recycle is water available within the process (boiler feedwater [BFW] blowdown, condensate, etc.). Raw water withdrawal is the water removed from the ground or diverted from a surface

- water source 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 difference 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. All plants are equipped with evaporative cooling towers, and all process blowdown streams are assumed to be treated and recycled to the cooling tower. The primary conclusions that c an be drawn are:

**•** In all cases the primary water consumer is cooling tower makeup, which ranges from 73 to 99 percent of the total raw water consumption

.

**•** Among non

- capture cases, NGCC requires the least amount of raw water withdrawal , followed by IGCC and PC. If an average raw water consumption for the three IGCC cases and two PC cases is used, the relative normalized raw water consumption for the technologies is 2. 5 :1. 7 :1.0 (PC:IGCC:NGCC). The relative results are as expected given the much 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 the NGCC case have comparable steam turbine outputs, but IGCC requires additional water f or coal slurry (GEE and CoP), syngas quench (GEE), humidification (CoP and Shell), gasifier steam (Shell), and slag handling (all cases), which increases the IGCC water withdrawal over NGCC.

**•** Among capture cases, raw 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 requirements. If average water consumption val ues are used for IGCC and PC cases, the relative normalized raw water consumption for the technologies in CO 2 

## capture cases is 2. 4 :1. 4 :1.0 (PC: I GCC: N GCC). T he NGCC CO 2 

## capture case still has the lowest water consumption.

**•** CO 2 

## capture increases the average raw water consumption for all three technologies evaluated, but the increase is lowest for the IGCC cases . The average normalized raw water consumption for the three IGCC cases increases by about 58 percent 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 83 percent and NGCC by 9 1 percent. The large cooling water demand of the Econamine process driv es this substantial increase for PC and NGCC

.

### Cost and Performance Baseline for Fossil Energy Plants

8 

## Exhibit ES

- 4 Raw Water Withdrawal and Consumption

7.6 10.7

7.0 11.1

6.6 11.3 10.7 20.4

9.7 18.3

4.3 8.4

6.0 8.7

5.5 9.0

5.3 9.3 8.5 15.7

7.7 14.1

3.3 6.3

0.0 5.0 10.0 15.0 20.0 25.0

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureWater, gpm/MWnet 

### Raw Water Withdrawal Process Discharge Raw Water Consumption

### Cost and Performance Baseline for Fossil Energy Plants

9 

## C OST RESULTS

The Total Overnight Cost (TOC) for each plant was calculated by adding owner’s costs to the Total 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 catalyst loadings), materials, labor (direct and indirect), engineering and construction management, and contin gencies (process and project). Escalation and interes t on debt during the capital expenditure period were estimated and added to the TOC to provide the Total As

- Spent Cost (TASC). Total Overnight Cost

The cost estimates carry an accuracy of

- 15%/+30% , consistent with a “feasibility study ” level o f design engineering applied to t he various cases in this study

. The value of the study lies not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach a llows 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 resul t from a detailed design. The contingencies represent costs that are expected to occur. Each bare erected cost (BEC) account was evaluated against the level of estimate detail and field experience to determine project contingency. Process contingency wa s added to cost account items that were deemed to be first

- of

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

**•** Slurry Prep and Feed

– 5 percent on GE IGCC cases

- s ystems are operating at approximately 800 psi a as compared to 600 psi a for the other IGCC cases.

**•** 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 cases

– 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

- combustion 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 hydrogen 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 tec hnology in Exhibit ES

- 5 . The following conclusions can be drawn:

**•** Among the non

- capture cases, NGCC has the lowest TOC at $718 kW followed by PC with an average cost of $2,010/kW and IGCC with an average cost of $2,505/kW.

### Cost and Performance Baseline for Fossil Energy Plants

10 

## Exhibit ES

- 5 P lant Capital Cost s

Note: TOC expressed in 2007 dollars

. TASC expressed in m i xed

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

- year dollars for NGCC

. 2,447 3,334

2,351 3,466

2,716 3,904

1,996 3,610

2,024 3,570

718 1,497 2,789 3,801

2,680 3,952

3,097 4,451

2,264 4,115

2,296 4,070

771 1,614

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

GEE GEE w/ CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureTOC or TASC, $/kW TASC
Owner's Cost Process Contingency Project Contingency Home Office Expense
Bare Erected Cost

### Cost and Performance Baseline for Fossil Energy Plants

11 

## The average IGCC cost is 25 percent greater than the average PC cost. The process contingency for the IGCC cases ranges from $ 50

- 63 /kW while there is zero pro cess contingency for the PC and NGCC non

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

**•** The three IGCC non

- capture cases have a TOC ranging from $ 2,351 /kW (CoP) to $ 2,716 /kW (Shell) wit h GEE intermediate at $ 2,447 /kW.

**•** Among the capture cases, NGCC has the lowest TOC , despite the fact that the TOC of the NGCC capture case is more than double the cost of the non

- capture case at $1, 497 kW.

**•** Among the capture cases, the P C cases have the hig hest TOC at an average of $3,590/kW. The average TOC for IGCC CO 2 

## capture cases is $ 3,5 68 /kW, which is less than one percent lower than the average of the P C cases. The process contingency for the IGCC capture cases ranges from $1 19

- 131 /kW, for the PC ca ses from $ 100

- 105 /kW and $ 60 /kW for the NGCC case.

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 of Electricity

2 ] was used to determine a “base

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



## Exhibit ES

- 6 , provided the stip ulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). The first year capital charge factor (CCF) shown in , which was derived using the PSFM, can also be used to calculate COE using a simplified equation as detailed in Section 2.7.4

. 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 ri sk projects are those in which commercial scale operating experience is limited. The IGCC cases (with and without CO 2 

## capture) 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 leve lized cost of electricity (LCOE) was also calculated and is shown in Exhibit 2

- 23 , but the primary metric used in the balance of this study is COE. A more detailed di scussion of the two metrics is provided in Section 2.7 of the report.

1 

### This nominal escalation rate is equal to the average annual inflation 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 Ge neration Industry because the Electric Power Index only 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

12 

## Exhibit ES

- 6 Economic Parameters Used to Calculate COE High R isk (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 Engineer ing 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 be representative of January 2010 costs.
The COE results are shown in Exhibit ES

- 7 with the capital cost, fixed operating cost, variable operating cost , and fuel cost sho wn separately. 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, NGCC plants have the lowest COE (58.9 mills/kWh), followed by PC (average 59.2 mills/kWh) and IGCC (average 77.2 mills/kWh).

**•** In capture cases, NGCC plants have the lowest COE (85.9 mills/kWh), followed by PC (average 108.2 mills/kWh) and IGCC (average 111.8 mills/kWh).

**•** The COE for the three IGCC non

- captu re cases ranges from 74.0 mills/kWh (CoP) to 81.3 mills/kWh (Shell) with GEE intermediate at 76.3 mills/kWh. The study level of accuracy is insufficient to d e finitively quantify the differences in COE of the three IGCC technologies.

**•** Non

- capture SC PC has a COE of 58.9 mills/kWh and subcritical PC is 59.4 mills/kWh, an insignificant difference given the level of accuracy of the study estimate.

**•** IGCC is the most expensive technology with CO 2 

## capture, 3 percent higher than PC and 30 percent higher than NGCC.

**•** T he capital cost component of COE is between 56 and 59 percent in all IGCC and PC cases. It represents only 17 percent of COE in the NGCC non

- capture case and 26 percent in the CO 2 

## capture case.

**•** The fuel component of COE ranges from 15

- 19 percent for the IGCC cases and the PC CO 2 

## capture cases. For the PC non

- capture cases the fuel component varies from 24

- 26 percent. The fuel component is 76 percent of the total in the NGCC non

- capture case and 61 percent in the CO 2 

## capture case.

**•** CO 2 

## TS& M is estimated to add 3 to 6 mills/kWh to the COE, which is less than 5.5 percent of the total for all capture cases.

### Cost and Performance Baseline for Fossil Energy Plants

13 

## Exhibit ES

- 7 COE b y Cost Component

43.4 59.1
41.7 61.5 48.2 69.2

31.2 60.2

31.7 59.6

10.1 22.3 11.3 14.8

11.1 15.5

12.1 16.7

7.8 13.1

8.0 13.0

3.0 5.7 7.3 9.3

7.2 9.8

7.8 9.9

5.1 9.2

5.0 8.7

1.3 2.6 14.3 17.1

14.0 18.0

13.3 17.9

15.2 21.3

14.2 19.6

44.5 52.2 5.3 5.6 5.7

5.9 5.7

3.2 

### 76.28 105.66

74.02 110.39

81.31 119.46

59.40 109.69

58.91 106.63

58.90 85.93

0 20 40 60 80 100 120 140 160

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2

Capture Supercritical PC Supercritical PC w/ CO2

Capture NGCC NGCC w/ CO2 CaptureCOE, mills/kWh (2007$) 

### CO2 TS&M Costs Fuel Costs
Variable Costs
Fixed Costs Capital Costs

### Cost and Performance Baseline for Fossil Energy Plants

14 

## Exhibit ES

- 8 shows the COE sensitivity to fuel costs for the non

- capture cases. The solid line is the COE of NGCC as a function of natural gas cost. The points on the line represent the natural gas co st that would be required to make the COE of NGCC equal to PC or IGCC at a given coal cost. The coal prices shown ($1.23, $1.64, and $2.05/MMBtu) represent the baseline cost and a range of ±25 percent around the baseline. As an example, at a coal cost of $1.64/MMBtu, the COE of PC equals NGCC at a natural gas price of $6.59/MMBtu. Another observation from Exhibit ES

- 8 is that the COE of IGCC at a coal price of $1.23/ MMBtu is greater than PC at a coal price of $2.05/MMBtu, due to the higher capital cost of IGCC and its relative insensitivity to fuel price. For example, a decrease in coal cost of 40 percent (from $2.05 to $1.23/MMBtu) results in an IGCC COE decrease of only nine percent (80.7 to 73.7 mills/kWh). Fuel cost sensitivity is presented for the CO 2 

## capture cases in Exhibit ES

- 9 . Even at the lowest coal cost shown, the COE of NGCC is less than IGCC and PC at the baseline natural gas price of $ 6.55 /MMBtu. For the coal

- based technologies at the baseline coal cost of $1. 64 /MMBtu to be equal to NGCC, the cost of natural gas would have to be $ 9. 34 /MMBtu ( P C) or $ 9. 8 0 /MMBtu ( IGC C). Alternatively, for the COE of coal

- based technologies to be equal to NGCC at the high end coal cost of $2. 0 5/MMBtu, natural gas prices would have to be $ 9

. 98 /MMBtu for P C and $ 10. 35 /MMBtu for IGC C. Exhibit ES

- 8 COE Sens itivity to Fuel Costs in Non

- Capture Cases

40 50 60 70 80 90 100

3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu NGCC PC w/ coal at $1.23/MMBtu PC w/ coal at $1.64/MMBtu PC w/ coal at $2.05/MMBtu IGCC w/ coal at $1.23/MMBtu IGCC w/ coal at $1.64/MMBtu IGCC w/ coal at $2.05/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

15 

## Exhibit ES

- 9 COE Sensitivity to Fuel Costs in CO 2 

## Capture Cases

The sensitivity of COE to CF is shown for all technologies in Exhibit ES

- 10 . The subcritical and SC PC cases with no CO 2 

## capture are nearly identical so that the two curves appear as a single curve on the graph. The CF is plotted from 3 0 to 90 percent. The baseline CF is 80 percent for IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. The curves plotted in Exhibit ES

- 10 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 dominated by fuel charges, which decrease as the CF decreases. Conclusions that can be drawn from Exhibit ES

- 10 include:

**•** At a CF at or below 85 percent, NGCC has the lowest COE out of the non

- capture cases.

**•** The COE of NGCC with CO 2 

## capture is the lowest of the capture technologies i n the baseline study, and the advantage increases as CF decreases. The relatively low capital cost component of NGCC accounts for the increased cost differential with decreased CF.

**•** In non

- capture cases, NGCC at 40 percent CF has approximately the same COE as the average of the three IGCC cases at base load (80 percent CF) further illustrating the relatively small impact of CF on NGCC COE. 40 50 60 70 80 90 100 110 120 130 140

3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu NGCC PC w/ coal at $1.23/MMBtu PC w/ coal at $1.64/MMBtu PC w/ coal at $2.05/MMBtu IGCC w/ coal at $1.23/MMBtu IGCC w/ coal at $1.64/MMBtu IGCC w/ coal at $2.05/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

16 

## Exhibit ES

- 10 COE Sensitivity to Capacity Factor

In the event that future legislation assigns a cost to carbon 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 co al

- based technologies will be impacted more than natural gas

- based technologies. The most economically favored option for each technology is shown in C O 2 

## Emission Price Impact

Exhibit ES

- 11

. Hence the IGCC non

- capture case is based on the CoP gasifier, the IGCC capture case is based on the GEE technology, and the PC technology is based on supercritical steam conditions. The curves represent the study design conditions (capacity factor) and fu el prices used for each technology; namely 80 percent capacity factor for IGCC plants and 85 percent for PC and NGCC plants, and $1.64/MMBtu for coal and $6.55/MMBtu for natural gas. Natural gas fuel prices are more volatile than coal and tend to fluctuat e over a fairly large range. The two black lines shown in Exhibit ES

- 11 re present NGCC at a fuel price of $9.50/MMBtu and are shown for reference

. The dispatch

- base d capacity factor for NGCC plants, addressed in Section 6.4 of this report, is significantly less than 85 percent and would result in a higher COE as shown in Exhibit ES

- 10

. 0 50 100 150 200 250 300

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

Capacity Factor, % Shell w/CO2 capture Sub PC w/CO2 capture SC PC w/CO2 capture CoP w/CO2 capture GEE w/CO2 capture Shell no capture GEE no capture CoP no capture Sub PC no capture NGCC w/CO2 capture SC PC no capture NGCC no capture Coal = $1.64/MMBtu Natural Gas = $6.55/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

17 

## Exhibit ES

- 11 Impact of Carbon Emissions Price on Study Technologies

The intersection of the capture and non

- capture curves for a given technology gives the cost of CO 2 

## avoided for that technology , except for the IGCC cases which use different gasifier technologies for the capture and non

- capture cases . For example, the cost of CO 2 

## avoided is $69/tonne ($63/ton) for SC PC and $84/tonne ($76/ton) for NGCC. These values can be compared to those shown in Exhibit ES

- 13

. The following conclusions can be drawn from the carbon emission s p ric e 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 in tensity of natural gas relative to coal and the greater efficiency of the NGCC technology account for this effect.

**•** Capture for NGCC systems is only justified economically at CO 2 

## emissions prices greater than $83/tonne ($75/ton) at the baseline natural gas price of $6.55/MMBtu and $95/tonne ($86/ton) at the high er natural gas price of $9.50/MMBtu.

**•** The SC PC and IGCC non - capture curves are nearly parallel indicating that the CO 2 

## emission price impacts the two technologies nearly equally. The two lines gradually converge due to the slightly lower efficiency of SC PC relative to the CoP IGCC technology (3 9

. 3 versus 3 9.7 percent net efficiency)

. The SC PC and GEE IGCC cases with CO 2 

## capture start at nearly equivalent COE values and slowly diverge. The CO E of the SC PC case increases slightly faster than the GEE IGCC case 0 20 40 60 80 100 120 140 160

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



### First Year CO 2 

### Emission Price, $/tonne NGCC w/Cap ($9.50/MMBtu) NGCC ($9.50/MMBtu) IGCC (GEE) w/Capture IGCC (CoP) SCPC w/Capture SCPC NGCC w/Capture ($6.55/MMBtu) NGCC ($6.55/MMBtu)

### Cost and Performance Baseline for Fossil Energy Plants

18 

## because of the lower efficiency (28.4 versus 32.6 percent net efficiency) and slightly lower capture efficiency (90.2 versus 90.3 percent).

**•** Comparing only the coal

- based technologies, IGC C or PC with capture become the favored technology compared to SC P C with no capture at a n emission price of $6 7 /tonne ( $6 1 /ton )

.

**•** At a natural gas price of $ 9.50 /MMBtu, NGCC with capture has nearly the same COE as IGCC and SC PC with capture at a CO 2 

## emiss ion price of $3 0 /tonne ($ 27 /ton).

**•** At a natural gas price of $ 9.50 /MMBtu, SC PC without capture has a lower COE than NGCC without capture until the CO 2 

## emissions price exceeds $ 46 /tonne ($ 42 /ton). The relationship between technologies and CO 2 

## emission pricing can also be considered in a “phase diagram” type plot as shown in Exhibit ES

- 12

. The lines in the plot represent cost parity between different pairs of technologies.

Exhibit ES

- 12 Lowest Cost Power Generation Options Comparing NGCC and Coal

The plot demonstrates the following points:

**•** Non

- capture plants are the low cost option below a first year CO 2 

## price of $60/ton ne ($54/ton). 0 2 4 6 8 10 12 14 16 18 20

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

First Year CO 2 Emission Price, $/tonne COE parity between NGCC with CCS and IGCC with CCSCOE parity betweenSupercritical PC without CCSand IGCC with CCS 

## Supercritical PC

without CCS has lowest COE

NGCC with CCS has lowest COE IGCC with CCS has lowest COE

NGCC without CCS has lowest COE

### Cost and Performance Baseline for Fossil Energy Plants

19 

## • At natural gas prices below $6.50/MMBtu (and a capacity factor of 85 percent) NGCC is always preferred.

**•** At natural gas prices above $11/MMBtu coal plants are always preferred.

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)

The 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

- 13 for each of the six 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 

## captu re as the reference. The following conclusions can be drawn:

**•** The total first year cost of CO 2 

## avoided is $52.9/tonne ($48/ton) (average IGCC), $68.3/tonne ($62/ton) (average PC), and $83.8/tonne ($76/ton) (NGCC) using analogous non

- capture plants as the r eference and $75/tonne ($68/ton) (average IGCC), $71.6/tonne ($65/ton) (average PC), and $35.3/tonne ($32/ton) (NGCC) using SC PC without capture as the reference.

**•** C O 2 

## avoided costs for IGCC plants using analogous non

- capture plants as reference are substa ntially less than for PC and NGCC because the IGCC CO 2 

## removal is accomplished prior to combustion and at elevated pressure using physical absorption.

**•** CO 2 

## avoided costs for IGCC plants using analogous non

- capture as reference are less than NGCC plants beca use the baseline CO 2 

## emissions for NGCC plants are 44 percent less than for IGCC plants. Consequently, the normalized removal cost for NGCC plants is divided by a smaller amount of CO 2 

## .

**•** CO 2 

## avoided costs for the GEE IGCC plant are less than for the CoP and Shell IGCC plants. This is consistent with the efficiency changes observed when going from a
non - capture to capture configuration for the GEE IGCC plant. The GEE plant started with the lowest efficiency of the IGCC plants but realized the smallest re duction in efficiency between the non

- capture and capture configurations.

**•** CO 2 

## avoided cost s for NGCC using SC PC as the reference are 5 3 percent lower than IGCC and 5 0 percent lower than PC because of the relatively low COE of the NGCC capture plant compar ed to IGCC and PC.

### Cost and Performance Baseline for Fossil Energy Plants

20 

## Exhibit ES

- 13 First Year CO 2 

## Avoided Costs

43 54 61 68 69 84

66 73 86

75
69

36

0 10 20 30 40 50 60 70 80 90 100



### GEE CoP Shell Subcritical PC Supercritical PC NGCCFirst Year CO2Avoided Cost, $/tonne (2007$) 

### Avoided Cost (Analogous Technology w/o Capture Reference) Avoided Cost (SC PC w/o Capture Reference)

### Cost and Performance Baseline for Fossil Energy Plants

21 

## E NVIRONMENTAL PERFORM ANCE The environmental targets for each technology are summarized i n Exhibit ES

- 14 . E mission rates of sulfur dioxide ( SO 2 

## ), nitrogen oxide ( NOx ), and particulate matter ( PM ) are shown graphically i n Exhibit ES

- 15 , and emission rates of mercury (Hg) are shown separately in Exhibit ES

- 16 because of the orders of magnitude difference in emission rate values.

Exhibit ES

- 14 Study Environmental Targets Technology
Pollutant IGCC PC NGCC
SO 2 

## 0.0128 lb/MMBtu 0.085 lb/MMBtu Negligible

NOx 15 ppmv (dry) @ 15% O 2 

## 0.070 lb/MMBtu 2.5 ppmv (dry) @ 15% O 2 

## PM (Filterable) 0.0071 lb/MMBtu 0.013 lb/MMBtu Negligible Hg >90% capture 1.14 lb/TBtu N/A
Environmental targets were established for each of the technologies as follows:

**•** IGCC cases use the EPRI targe ts established in their CoalFleet for Tomorrow work as documented in the CoalFleet User Design Basis Specification for Coal

- Based Integrated Gasification Combined Cycle (IGCC) Power Plants , EPRI, Palo Alto, CA , 2009

.

**•** PC and NGCC cases are based on best avail able control technology (BACT) The primary conclusions that can be draw n are:

**•** The NGCC baseline plant generates the lowest emissions, followed by IGCC and then PC.

**•** In NGCC cases, study assumptions result in zero emissions of SO 2 

## , PM , and Hg. If the pipeline natural gas contained the maximum amount of sulfur allowed by Enviro nmental Protection Agency ( EPA ) definition (0.6 gr/100 scf), SO 2 

## emissions would be 0.000839 kg/GJ (0.00195 lb/MMBtu).

**•** Based on vendor data i t was assumed that dry low NOx (DLN) burners could achieve 25 ppmv (dry) at 15 percent O 2 

## and , coupled with a selec tive catalytic reduction (SCR) unit that achieve s 90 percent NOx reduction efficiency , would result in the environmental target of 2.5 ppmv ( dry) at 15 percent O 2 

## for both NGCC cases.

**•** Based on vendor data i t was a ssumed that Selexol, Sulfinol

- M , and refrigerated methyldiethanolamine ( MDEA ) could all meet the sulfur environmental target, hence emissions of approximately 0.0128 lb/MMBtu in each of the IGCC non

- capture cases. In the CO 2 

## capture cases, to achieve 9 5 percent CO 2 

## capture from the sy ng as, the sulfur

### Cost and Performance Baseline for Fossil Energy Plants

22 

## removal is greater than in the non

- capture cases resulting in emissions of approximately 0.00 09 kg/GJ (0.00 22 lb/MMBtu).

**•** It was a study assumption that each IGCC technology could meet the filterable particulate emission limit with the combin ation of technologies employed. In the case of Shell and CoP , this consists of cyclones, candle filters , and the syngas scrubber. In the case of GEE particulate control consists of a w ater quench and syngas scrubber.

**•** Based on vendor data i t was a ssumed t hat a combination of low NOx burners (LNBs) and nitrogen (N 2 

## ) dilution could limit IGCC NOx emissions to the environmental target of 15 ppmvd at 15 percent O 2 

## . The small variations in NOx emissions are due to small variations in CT gas volumes.

**•** Based on v endor data i t was a ssumed that 95 percent Hg removal could be achieved using carbon beds thus meeting the environmental target. The Hg emissions are reported in Exhibit ES

- 16 as lb per trillion Btu to make the values the same order of magnitude as the other reported values.

**•** It was a study assumption that the PC FGD unit w ould remove 98 percent of the inlet SO 2 

## , resulting in the environmental target of 0.037 kg/GJ (0.08 5 lb/MMBtu). In the CO 2 

## capture cases, the Econamine system employs a polishing scrubber to reduce emissions to 10 ppm v entering the CO 2 

## absorber. Nearly all of the remaining SO 2 

## is absorbed by the Econamine solvent resulting in negligible emissions of SO 2 

## in those cases.

**•** In PC cases , it was a study assumption that a fabric filter would remove 99.8 percent of the entering particulate and that there is an 80/20 split between fly as h and bottom ash. The result is the environmental target of 0.006 kg/GJ (0.013 lb/MMBtu) of filterable particulate.

**•** In PC cases, i t was a study assumption that NOx emissions exiting the boiler equipped with LNBs and overfire air (OFA) would be 0.22 kg/GJ (0.50 lb/MMBtu) and that an SCR unit would further reduce the NOx by 86 percent, resulting in the environmental target of 0.030 kg/GJ (0.070 lb/MMBtu).

**•** I n PC cases, i t was a study assumption that the environmental target of 90 percent of the incoming Hg wo uld be removed by the combination of SCR, fabric filter and wet FGD thus eliminating the need for activated carbon injection. The resulting Hg emissions for each of the PC cases are 4.92 x 10 - 7 

## kg/GJ (1.14 lb/TBtu). CO 2 

## emissions are not curre ntly 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 

## emissions are presented in Exhibit ES

- 17 for each case, normalized by net output. In the body of the report CO 2 

## emissions are presented on both a net and gross MWh basis. New Source Perf ormance 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:

### Cost and Performance Baseline for Fossil Energy Plants

23 

## Exhibit ES

- 15 SO 2 

## , NOx , and Particulate Emission Rates

0.00 0.02 0.04 0.06 0.08 0.10 0.12

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureEmissions, lb/MMBtu 

### SO2
NOx Particulate Matter

### Cost and Performance Baseline for Fossil Energy Plants

24 

## Exhibit ES

- 16 Mercury Emission Rates

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureHg Emissions, lb/TBtu

### Cost and Performance Baseline for Fossil Energy Plants

25 

## • In cases with no CO 2 

## capture , NGCC emits 5 6 percent less CO 2 

## than PC and 52 percent less CO 2 

## than IGCC per unit of net output. The lower NGCC CO 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 of heat input and coal contains 55 lb/MM Btu.

**•** T he CO 2 

## reduction goal in this study was a nominal 90 percent in all cases. The result is that the controlled CO 2 

## emissions follow the same trend as the uncontrolled, i.e., the NGCC case emits less CO 2 

## than the IGCC cases , which emit less than the PC cases.

**•** I n the IGCC cases the nominal 90 percent CO 2 

## reduc tion was accomplished by using two sour gas shift (SGS) reactors to convert carbon monoxide ( CO ) to CO 2 

## . A two

- stage Selexol process with a second stage CO 2 

## removal efficiency of 92 percent, a number that was supported by vendor quotes , was used in the GE E and Shell cases

. T he GEE CO 2 

## capture case resulted in 90.3 percent reduction of CO 2 

## in the syngas. The Shell capture case resulted in 90.1 percent reduction of CO 2 

## in the syngas. In the CoP case, in order for the capture target of 90 percent to be ach ieved , the Selexol efficiency was increased to 95 percent. This was done because of th e high syngas methane content (1 .5 vol% compared to 0.10 vol% in the GEE gasifier and 0.0 6 vol% in the Shell gasifier). The CoP capture case resulted in 90.4 percent reduction of CO 2 

## in the syngas.

**•** Among the three non

- capture IGCC cases th e Shell process has slightly lower emissions primarily because it is the most efficient. The emissions in the CO 2 

## capture cases are nearly identical for each case.

**•** The PC and NGCC ca ses both assume that all of the carbon in the fuel is converted to CO 2 

## in the FG and that 90 percent is subsequently removed in the Econamine process, which was also supported by a vendor quote.

### Cost and Performance Baseline for Fossil Energy Plants

26 

## Exhibit ES

- 17 C O 2 

## Emissions Normalized By Net Output

1,723

206 1,710

217 1,595

218 1,888

266 1,768

244 804

94


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

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 CaptureCO2Emissions, lb/net-MWh

### Cost and Performance Baseline for Fossil Energy Plants

27 

## 1. The objective of this report i s to present an accurate, independent assessment of the cost and performance of fossil energy power systems, specifically IGCC, PC, and NGCC plants, in a consistent technical and economic manner that accurately reflects current market conditions. This is Volume 1 of a four volume report. The four volume series consists of the follow ing: INTRODUCTION

**•** 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 The cost and performance of the various fossil fuel

- based technologies will largely determine which technologies will be utilized to meet the demands of the power market. Selection of new generation technologies will depend on many factors, including:

**•** Cap ital and operating costs

**•** Overall energy efficiency

**•** Fuel prices

**•** Cost of electricity ( COE )

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

**•** Current and potential r egulation o f air, water, and solid waste discharges from fossil

fueled power plants

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

- scale demonstrations under the DOE ’s Clean Coal Program s T welve different power plant design configurations were analyzed. The configurations are listed in Exhibit 1

- 1 . The list includes s ix IGCC cases utilizing the GEE, CoP, and Shell gasifiers each with and without CO 2 

## capture, and six cases representing conventional technologies: PC

subcritical, PC

- SC , and NGCC plants , with and without CO 2 

## capture. W hile input was sought from various technology vendors, the final assessment of performance and cost was determined independently, and may not represent the views of the technology vendors. Individual vendors have not reviewed this report and t he extent of collaboration with technology vendors varied from case to case, with minimal or no collaboration obtained from some vendors. Cases 7 and 8 were originally included in this study and involve production of SNG and the repowering of an existing NGCC facility using SNG. The two SNG cases were subsequently moved to Volume 2 of this report resulting in the discontinuity o f case numbers (1

- 6 and 9

- 14).
GENERATING UNIT CONF IGURATIONS A summary of plant configurations considered in this study is presented in Exhibit 1

- 1

. Components for each plant configuration are described in more detail in the corresponding report sections for each case.

### Cost and Performance Baseline for Fossil Energy Plants

28 

## The IGCC cases have different gross and net power outputs because of the gas turbine (GT) size constraint. The advanced F

- class turbine used to model the IGCC cases comes in a standard size of 232 MW when operated on syngas at International Standards Organization ( ISO ) condi tions

. Each case uses two CTs for a combined gross output of 464 MW. In the combined cycle a heat recovery steam generator (HRSG) extracts heat from the CT exhaust to power a steam turbine. However, the CO 2 

## capture cases consume more extraction steam th an the non

- capture cases, thus reducing the steam turbine output. In addition, the capture cases have a higher auxiliary load requirement than non

- capture cases, which serves to further reduce net plant output. While the two CT s provide 464 MW gross outp ut in all six cases, the overall combined cycle gross output ranges from 6 73 to 7 48 MW, which results in a range of net output from 49 7 (case 6 ) to 6 29 MW (case 5) . The coal feed rate required to achieve the gross power output is also different between the six cases, ranging from 198,220 to 220,899 kg/h r (4 37 ,000 to 487 ,000 lb/h r ). Similar to the IGCC cases, the NGCC cases do not have a common net power output. Th e NGCC system is again constrained by the available CT size, which is 181 MW at ISO conditions for both cases (based on the same advanced F class turbine used in the IGCC cases). Since the CO 2 

## capture case requires both a higher auxiliary power load and a significant amount of extraction steam, which significantly reduces the steam turbine output, the net output in the NGCC case is also reduced. All four PC cases have a net output of 550 MW. The boiler and steam turbine industry’s ability to match unit size to a custom specification has been commercially demonstrated enabling a common net output comparison of the PC cases in this study. The coal feed rate was increased in the CO 2 

## capture cases to increase the gross steam turbine output and account for t he higher auxiliary load, resulting in a constant net output. The balance of this report is organized as follows:

**•** Chapter 2 provides the basis for technical, environmental , and cost evaluations.

**•** Chapter 3 describes the IGCC technologies modeled and present s the results for the six IGCC cases.

**•** Chapter 4 describes the PC technologies modeled and presents the results for the four PC cases.

**•** Chapter 5 des c ribes the NGCC technologies modeled and presents the results for the two NGCC cases.

**•** Chapter 6 is a suppleme ntal chapter examining the impact of dry and parallel cooling systems

.

**•** Chapter 7 is a supplemental chapter examining the cost and performance of a GEE gasifier in a quench

- only configuration with CO 2 

## capture.

**•** Chapter 8 is a supp lemental chapter examining t he COE sensitivity to monoethanolamine ( MEA ) system performance and cost.

**•** Chapter 9 includes a record of report revisions.

**•** Chapter 10 contains the reference list.

### Cost and Performance Baseline for Fossil Energy Plants

29 

## Exhibit 1

- 1 Case Descriptions

Case Unit Cycle Steam Cycle, psig/ **°** F/ **°** F Combustion Turbine Gasifier/Boiler Technology Oxidant H 2 S Separation/ Removal Sulfur Removal/ Recovery PM Control NOx Control CO 2 Separa
tion CO 2 Capture CO 2 Sequestra
tion

1 IGCC 1800/1050/1050 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Single

- Stage Selexol Claus Plant Quench, scrubber and AGR adsorber N 2 dilution

2 IGCC 1800/1000/1000 2 x Advanced F Class GEE Radiant Only 95 mol% O 2 Two

- Stage Selexol Claus Plant Quench, scrubber and AGR adsorber N 2 dilution Selexol 2 nd stage 90% 1 Off

- Site

3 IGCC 1800/1050/1050 2 x Advanced F Class CoP E

- GasTM 95 mol% O 2 Refrigerated MDEA Claus Plant Cyclone, barrier filter and scrubber N 2 dilution

4 IGCC 1800/1000/1000 2 x Advanced F Class CoP E

- GasTM 95 mol% O 2 Selexol Claus Plant Cyclone, barrier filter and scrubber N 2 dilution Selexol 2 nd stage 90% 1 Off

- Site

5 IGCC 1800/1050/1050 2 x Advanced F Class Shell 95 mol% O 2 Sulfinol

- M Claus Plant Cyclone, barrier filter and scrubber N 2 dilution

6 IGCC 1800/1000/1000 2 x Advanced F Class Shell 95 mol% O 2 Selexol Claus Plant Cyclone, barrier filter and scrubber N 2 dilution Selexol 2 nd stage 90% 1 Off

- Site

9 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR
10 PC 2400/1050/1050 Subcritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR Amine Absorber 90% Off

- Site

11 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR
12 PC 3500/1100/1100 Supercritical PC Air Wet FGD/ Gypsum Baghouse LNB w/OFA and SCR Amine Absorber 90% Off

- Site

13 NGCC 2400/1050/1050 2 x Advanced F Class HRSG Air LNB and SCR
14 NGCC 2400/1050/1050 2 x Advanced F Class HRSG Air LNB and SCR Amine Absorber 90% Off

- Site

1 

### Defined as the percentage of carbon in the syngas that is captured; differences are explained in Chapter 3

.

### Cost and Performance Baseline for Fossil Energy Plants

30 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

31 

## 2. For each of the plant configurations in this study an Aspen model was developed and used to generate material and energy balances, which in turn were used to provide a design basis for items in the major equipment list. The equipment list and material balances were used as the basis for generating the capital and operating cost estimates. Perfo rmance and process limits were based upon published reports, information obtained from vendors and users of the technology, performance data from design/build utility projects, and/or best engineering judgment . Capital and operating costs were estimated b y WorleyParsons based on simulation results and through a combination of vendor quotes, scaled estimates from previous design/buil d projects, or a combina tion of the two. Ultimately a COE was calculated for each of the cases and is reported as the revenue requirement figure

- of

- merit. GENERAL EVALUATION B ASIS

The balance of this chapter documents the design basis common to all technologies, as well as environmental targets and cost assumptions used in the study. Technology specific design criteria are covered in subsequent chapter s. 2.1 SITE CHARACTERISTICS All plants in this study are assumed to be located at a generic plant site in Midwestern U.S. , with ambient conditions and site characteristics as presented in Exhibit 2

- 1 and Exhibit 2

- 2 . The ambient conditions are the same as ISO conditions. Exhibit 2

- 1 Site Ambient Conditions Elevation, ( ft ) 0 Barometric Pressure, MPa ( psia ) 0.10 (14.696) Design Ambient Temperature, Dry Bulb, °C ( **°** F ) 15 ( 59 ) Design Ambient Temperature, Wet Bulb, °C , ( **°** F ) 11 ( 51.5 ) Design Ambient Relative Humidity, % 60 Exhibit 2

- 2 Site Characteristics Location Greenfield, Midwestern USA Topography Level Size, acres 300 (PC/IGCC) , 100 (NGCC) Transportation Rail Ash /Slag Disposal Off Site Water Municipal (50%) / Groundwater (50%) Access Land locked , having access by rail and highway

CO 2 

## Storage Compressed to 15. 3 MPa (2,2 15 psi a ) , transported 80 kilometers (50 miles) and sequestered in a saline formation at a depth of 1,239 m (4,055 ft)

### Cost and Performance Baseline for Fossil Energy Plants

32 

## The land area for PC and IGCC cases assumes 30 acres are required for the plant proper and the balance provides a buffer of approximately 0.25 miles to the fence line. The extra land could also provide for a rail loop if required. In the NGCC cases it was assumed the plant proper occupies about 10 acres leaving a buffer of 0.15 miles to the plant fence line. In all cases it was assumed that the steam turbine is enclosed in a turbine building and in the PC cases the boiler is also enclosed. Th e gasifier in the IGCC cases and the CT s in the IGCC and NGCC cases are not enclosed. The following design parameters are considered site

- specific, and are not quantified for this study. Allowances for normal conditions and construction are included in th e cost estimates.

**•** Flood plain considerations

**•** Existing soil/site conditions

**•** Water discharges and reuse

**•** Rainfall/snowfall criteria

**•** Seismic design

**•** Buildings/enclosures

**•** Local code height requirements

**•** Noise regulations

– Impact on site and surrounding area
2.2 COAL CHARACTERISTICS The design coal is Illinois No. 6 with characteristics presented in Exhibit 2

- 3 . The coal properties are from NETL’s Coal Quality Guidelines [ 1 The Power Systems Financial Model (PSFM) was used to derive the capital charge factors ( CCF ) and levelization factors ( LF ) for this study [ ]

.
2

The coal cost used in this study i s $1.55/GJ ($1.64/MMBtu) (2007 cost of coal in June 2007 dollars). This cost was determined using the following information from the EIA 2008 AEO: ] . The PSFM requires that all cost inputs have a consistent cost year basis. Because the capital and operating cost estimates are in June 2007 dollars, the fuel costs must also be in June 2007 dollars.

**•** The 2007 minemouth cost of Illinois No. 6 in 2006 dollars, $32.66/tonne ($29.63/ton), was obtained from Supp lemental Table 112 of the EIA’s 2008 AEO for eastern interior high

- sulfur bituminous coal.

**•** The cost of Illinois No. 6 coal was escalated to 2007 dollars using the gross domestic product (GDP) chain

- type price index from AEO 2008, resulting in a price of $3 3.67/tonne ($30.55/ton) [ 3

**•** Transportation costs for Illinois No. 6 were estimated to be 25 percent of the minemouth cost based on the average transportation rate of the respective coals to the surrounding regions [ ]

.

4 ]

. The final delivered costs for Ill inois No. 6 coal used in the calculations is $42.09/tonne ($38.18/ton) or $1.55/GJ ($1.64/MMBtu). (Note: The Illinois No. 6 coal cost of $1.6366/MMBtu was used in calculations, but only two decimal places are shown in the report.)

### Cost and Performance Baseline for Fossil Energy Plants

33 

## Exhibit 2

- 3 Design Coal Rank Bituminous Seam Illinois No. 6 (Herrin) Source Old Ben M ine Proximate Analysis (weight %) (Note A) A s Received Dry Moisture 11.12 0.00 Ash 9.70 10.91 Volatile Matter 34.99 39.37 Fixed Carbon 44.19 49.72 Total 100 .00 100 .00 Sulfur 2.51 2.82 HHV, kJ/kg 27,113 30,506 HHV, Btu/lb 11,666 13,126 LHV, kJ/kg 26,151 29,544 LHV, Btu/lb 11,252 12,712 Ultimate Analysis (weight %) A s Received Dry Moisture 11.12 0.00 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 (Note B ) 6.88 7.75 Total 100 .00 100 .00 Notes: A. The proximate analysis assumes sulfur as volatile matter B

. By d ifference

### Cost and Performance Baseline for Fossil Energy Plants

34 

## 2.3 NATURAL GAS CHARACTE RISTICS Natural gas is utilized as the main fuel in Cases 13 and 14 (NGCC with and without CO 2 

## capture), and its composition is presented in Exhibit 2

- 4 [ 5 Exhibit 2

- 4 Natural Gas Composition ]

.
Component Volume Percentage Methane CH 4 

## 93.1 Ethane C 2 

## H 6 

## 3.2 Propane C 3 

## H 8 

## 0.7

n - Butane C 4 

## H 10 

## 0.4 Carbon Dioxide CO 2 

## 1.0 Nitrogen N 2 

## 1.6 Total 100 .0 LHV HHV kJ/kg 47, 454 5 2 , 581 M J/scm 3 4.71 38.46 Btu/lb 20, 410 22, 600 Btu/scf 9 32 1,0 3 2 Note: Fuel composition is normalized and heating values are calculated The first year cost of natural gas used in this study is $ 6.21 /MMkJ ($ 6.55 /MMBtu) (20 07 cost of natural gas in 2007 dollars). The cost was determined using the following information from the EIA’s 2008 AEO:

**•** The 20 07 East North Central region delivered cost of natural g as to electric utilities in 2006 dollars, $ 231.47 / 1000 m 3 

## ($ 6.5 5 / 1000 ft 3 

## ) , was obtained from the AEO 2008 reference case Table 108 and converted to an ener gy basis, $6.02/MMkJ ($6.35/MMBtu).

**•** The 20 07 cost was escalated to 2007 dollars using the GDP chain

- type price index from AEO 200 8 , resulting in a delivered 20 07 price in 2007 dollars of $ 6.21 /MMkJ ($ 6.55 /MMBtu) [ 3 ]

. (Note: The natural gas cost of $6.5478/MMBtu was used in calculations, but only two decimal places are shown in the report.)
2.4 ENVIRONMENTAL TARGET S The environmental targets for the study were conside red on a technology

- and fuel

- specific basis. In setting the environmental targets a number of factors were considered, including current emission regulations, regulation trends, results from recent permitting activities and the status of current BACT. Th e current federal regulation governing new fossil

- fuel fired electric utility steam generating units is the NSPS as amended in February 2006 and shown in Exhibit 2

- 5 , which represents the

### Cost and Performance Baseline for Fossil Energy Plants

35 

## minimum level of control that would be required for a new fossil energy plant [ 6

Exhibit 2

- 5 Standards of Performance for Electric Utility Steam Generating Units ]

. Stationary CT emission limits are further defined in 40 CFR Part 60, Subpart KKKK.
Built, Reconstructed, or Modified After February 28, 2005
New Units Reconstructed Units Modified Units

Emission

Limit % Reduction Emission Limit (lb/MMBtu) % Reduction Emission Limit (lb/MMBtu) % Reduction

PM 0.015 lb/MMBtu 99.9 0.015 99.9 0.015 99.8

SO 2 

### 1.4 lb/MWh 95 0.15 95 0.15 90

NOx 1.0 lb/MWh N/A 0.11 N/A 0.15 N/A



## The new NSPS standards apply to units with the capacity to generate greater than 73 MW of power by burning fossil fuels, as well as cogeneration units that sell more than 25 MW of power and more than one

- third of their potential output capacity to any util ity power distribution system. The rule also applies to combined cycle, including IGCC plants, and combined heat and power CT s that burn 75 percent or more synthetic

- coal gas. In cases where both an emission limit and a percent reduction are presented, t he unit has the option of meeting one or the other. All limits with the unit lb/MWh are based on gross power output. Other regulations that could affect emissions limits from a new plant include the New Source Review (NSR) permitting process and Preventio n of Significant Deterioration (PSD). The NSR process requires installation of emission control technology meeting either BACT determinations for new sources being located in areas meeting ambient air quality standards (attainment areas), or Lowest Achiev able Emission Rate (LAER) technology for sources being located in areas not meeting ambient air quality standards (non

- attainment areas). Environmental area designation varies by county and can be established only for a specific site location. Based on t he EPA Green Book Non

- attainment Area Map relatively few areas in the Midwestern U.S. are classified as “non

- attainment” so the plant site for this study was assum ed to be in an attainment area [ 7 In addition to federal regulations, state and local jurisdictions can impose even more stringent regulations on a new facility. However, since each new plant has unique environmental requirements, it was necessary to apply some judgment in setting the environmental targets for this study. ]

.

A s of October 200 9, no active legislation establishes acceptable mercury emission levels. The levels previously established by the Clean Air Mercury Rule (CAMR) have been vacated through the D.C Circuit Court

. Until new limits are established , t he previously established CAMR levels are used in this report

. The CAMR established NSPS limits for Hg emissions from new PC

- fired boilers based on coal type as well as for IGCC units independent of coal type. The NSPS limits, based on gross output, are shown in Exhibit 2

- 6 [ 8 ]

. The applicable limit in this study is 20 x 10 - 6 

## lb/MWh for both bituminous coal

- fired PC boilers and for IGCC units.

### Cost and Performance Baseline for Fossil Energy Plants

36 

## Exhibit 2

- 6 NSPS Mercury Emission Limits
Coal Type / Technology Hg Emission Limit
Bituminous 20 x 10 - 6 

## lb/MWh Subbituminous (wet units) 66 x 10 - 6 

## lb/MWh Subbituminous (dry units) 97 x 10 - 6 

## lb/MWh Lignite 175 x 10 - 6 

## lb/MWh Coal refuse 16 x 10 - 6 

## lb/MWh IGCC 20 x 10 - 6 

## lb/MWh The mercury content of 34 samples of Illinois No. 6 coal has an arithmetic mean value of 0.09 ppm (dry basis) with standard deviation of 0.06 based on coal samples shipped by Illinois mines [ 9 Exhibit 2

- 7 ]

. Hence, as illustrated in , there is a 50 percent probability that the mercury content in the Illinois No. 6 coal would not exceed 0.09 ppm (dry basis). The coal mercury content for this study was assumed to be 0.15 ppm (dry) for all IGCC and PC cases, which corresponds to the mean plus one standard deviation and encompasses about 84 percent of the samples. It was further assumed that all of the coal Hg enters the gas phase and none leaves with the bottom ash or slag. The current NSPS emission limits are provided below for each technology along with the environmental targets for this study and the control technologies employed to meet the targets. In some cases, application of the c ontrol technology results in emissions that are less than the target, but in no case are the emissions greater than the target.

Exhibit 2

- 7 Probability Distribution of Mercury Concentration in the Illinois No. 6 Coal

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

0.00 ppm Hg 0.05 ppm Hg 0.10 ppm Hg 0.15 ppm Hg 0.20 ppm Hg 0.25 ppm Hg 0.30 ppm Hg Mercury Concentraion in Coal, ppm dbProbability Illinois #6 Sample Will Be At or Below ValueP:\X_GEMSET\0_GEMSET Fuels Price Database\Rev.0 Fuels\[IllinoisNo6 Mercury.xls] Rev. 00 11/21/05 10:

Arithmetic Mean = 0.09 ppm db Standard Deviation = 0.06 ppm db

### Cost and Performance Baseline for Fossil Energy Plants

37 

## 2.4.1 The IGCC environmental targets were chosen to match the EPRI ’s design basis for their CoalFleet for Tomorrow Initiative and are shown in IGCC

Exhibit 2

- 8 [ 10

Exhibit 2

- 8 Environmental Targets for IGCC Cases ]

. EPRI notes that these are design targets and are not to be used for permitting values.

Pollutant Environmental Target NSPS Limit 1 

## Control Technology

NOx 15 ppmv (dry) @ 15% O 2 

## 1.0 lb/MWh (0.091 lb/MMBtu) Low NOx burners and syngas nitrogen dilution

SO 2 

## 0.0128 lb/MMBtu 1.4 lb/MWh (0.127 lb/MMBtu) Selexol, MDEA or Sulfinol (depending on gasifier technology)
Particulate Matter (Filterable) 0.0071 lb/MMBtu 0.015 lb/MMBtu Quench, water scrubber, and/or cyclones and candle filters (depending on gasifier technology) Mercury > 90% capture 20 x 10 - 6 

## lb/MWh (1.8 lb/TBtu) Carbon bed

1 

### The value in parentheses is calculated based on the highest IGCC heat rate in this study of 10,998 Btu/kWh, CoP

E

- Gas with CO 2 

### capture

. 

## Based on published vendor literature, it was assumed that LNB s and nitrogen dilution can achieve 15 ppmv d at 15 percen t O 2 

## , and that val ue was used for all IGCC cases [ 11 , 12 To achieve an environmental target of 0.0128 lb/MMBtu of SO 2 

## requires approximately 28 ppmv sulfur in the sweet syngas. The acid gas removal (AGR) process must have a sulfur capture efficiency of ab out 99.7 percent to reach the environmental target. Vendor data on each of the three AGR processes used in the non

- capture cases indicate that this level of sulfur removal is possible. In the CO 2 

## capture cases, the two

- stage Selexol process was designed for 95 percent CO 2 

## removal , which results in a sulfur capture of greater than 99.7 percent, hence the lower sulfur emissions in the CO 2 

## capture cases. ]

.

Most of the coal ash is removed from the gasifier as slag. The ash that remains entrained in the syngas is captured in the downstream equipment, including the syngas scrubber and a cyclone and either ceramic or metallic candle filters (CoP and Shell). The environmental target of 0.0071 lb/MMBtu filterable particulates can be achieved with each combination o f particulate control devices so that in each IGCC case it was assumed the environmental target was met exactly. The environmental target for mercury capture is greater than 90 percent. Based on experience at the Eastman Chemical plant, where syngas from a GEE gasifier is treated, the actual mercury removal efficiency used is 95 percent. Sulfur

- impregnated activated carbon is used by Eastman as the adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 psig). Mercury removal between 90 and 95 percent has been reported with a bed life of 18 to 24 months. Removal efficiencies may be even higher, but at 95 percent the measurement precision limit was

### Cost and Performance Baseline for Fossil Energy Plants

38 

## reached. Eastman has yet to experience any mercur y contamination in its product [ 13

2.4.2 ]

. Mercury removals of greater than 99 percent can be achieved by the use of dual beds, i.e., two beds in series. However, this study assumes that the use of sulfur

- impregnated carbon in a single carbon bed achieves 95 percent reduction of mercury emissions , which meets the environmental target and NSPS limits in all cases.

BACT was applied to each of the PC cases and the resulting emissions compared to NSPS limits and recent permit averages. Since the BACT results met or exceeded the NSPS requirements and the a verage of recent permits, they were used as the environmental targets as shown in PC

Exhibit 2

- 9 . The average of recent permits is comprised of 8 units at 5 locations. The 5 plants include Elm Road Generating Station, Longview Power, Prairie State, Thoroughbred , and Cross. It was assumed that LNBs and staged OFA would limit NOx emissions to 0.5 lb/MMBtu and that SCR technology would be 86 percent efficient, resulting in emissions of 0.07 lb/MMBtu for all cases. The wet limestone scrubber was assumed to be 98 percent efficient , which results in SO 2 

## emissions of 0.085 lb/MMBtu. Current technology allows FGD removal efficiencies in excess of 99 percent, but based on NSPS re quirements and recent permit averages, such high removal efficiency is not necessary. The fabric filter used for particulate control was assumed to be 99.8 percent efficient. The result is particulate emissions of 0.013 lb/MMBtu in all cases, which also e xceeds NSPS and recent permit average requirements. Exhibit 2

- 9 Environmental Targets for PC Cases

Pollutant Environmental Target NSPS Limit Average of Recent Permits Control Technology

NOx 0.07 lb/MMBtu 1.0 lb/MWh (0.111 lb/MMBtu) 0.08 lb/MMBtu Low NOx burners, overfire air and SCR

SO 2 

## 0.085 lb/MMBtu 1.4 lb/MWh (0.156 lb/MMBtu) 0.16 lb/MMBtu Wet limestone scrubber

Particulate Matter (Filterable) 0.013 lb/MMBtu 0.015 lb/MMBtu 0.017 lb/MMBtu Fabric filter

Mercury 1.14 lb/TBtu 20 x 10 - 6 

## lb/MWh (2.2 lb/TBtu) 2.49 lb/TBtu Co

- benefit capture

### Cost and Performance Baseline for Fossil Energy Plants

39 

## Mercury control for PC cases was assumed to occur through 90 percent co

- benefit capture in the fabric filter and the wet FGD scrubber. EPA used a statistical method to calculate the Hg co

benefit capture from units using a “best demonstrated technology” approach, which for bituminous coals was considered to be a combination of a fabric filter and an FGD system. The statistical analysis resulted in a co

- benefit capture e stimate of 86.7 percent with an efficiency range of 83.8 to 98.8 percent [ 14 ]

. EPA’s documentation for their Integrated Planning Model (IPM) provides mercury emission modification factors (EMF) based on 190 combinations of boiler types and control technolo gies. The EMF is simply one minus the removal efficiency. For PC boilers (as opposed to cyclones, stokers, fluidized beds , and ‘others’) with a fabric filter, SCR and wet FGD, the EMF is 0.1 , which corresponds to a re moval efficiency of 90 percent [ 15 ]

. The average reduction in total Hg emissions developed from EPA’s Information Collection Request (ICR) data on U.S. coal

- fired boilers using bituminous coal, fabric fil ters , and wet FGD is 98 percent [ 16

Since co

- benefit capture a lone exceeds the requirements of NSPS and recent permit averages, no activated carbon injection is included in this study. ]

. The referenced sources bound the co

- benefit Hg capt ure for bituminous coal units employing SCR, a fabric filter and a wet FGD system between 83.8 and 98 percent. Ninety percent was chosen as near the mid

- point of this range and it also matches the value used by EPA in their IPM.

2.4.3 BACT was applied to the NGCC cases and the resulting emissions compared to NSPS limits. The NGCC environmental targets were chosen based on reasonably obtainable limits given the control technologies employed and are presented in NGCC

Exh ibit 2

- 10

. Exhibit 2

- 10 Environmental Targets for NGCC Cases

Pollutant Environmental Target 40 CFR Part 60, Subpart KKKK Limits Control Technology

NOx 2.5 ppmv @ 15% O 2 

## 15 ppmv @ 15% O 2 

## Low NOx burners and SCR

SO 2 

## Negligible 0.9 lb/MWh (0.134 lb/MMBtu) 1 

## Low sulfur content fuel
Particulate Matter (Filterable) N/A N/A N/A
Mercury N/A N/A N/A

1 

## Assumes a heat rate of 6,719 Btu/kWh from the NGCC non

- capture case. Published vendor literature indicates that 25 ppmv NOx at 15 percent O 2 

## is achievable using natural gas an d DLN technology [ 17 , 18 ]

. The application of SCR with 90 percent efficiency further reduces NOx emissions to 2.5 ppmv, which was selected as the environmental target.

### Cost and Performance Baseline for Fossil Energy Plants

40 

## For the purpose of this study, natural gas was assumed to contain a negligible amount of sulfur compounds, and therefore generate negligible sulfur emissions. The EPA defines pipeline natural gas as containing >70 percent methane by volume or having a gross calorific value (GCV) of between 35.4 and 40.9 MJ/Nm 3 

## (950 and 1,100 Btu/scf) and having a total sulfur content of less than 13.7 mg/Nm 3 

## (0.6 gr/100 scf) [ 19

The pipeline natural gas was assumed to contain no particulate matter ( PM ) and no mercury resulting in no emissions of either. ]

. Assuming a sulfur content equal to the EPA limit for pipeline natural gas, resulting SO 2 

## emissions for the two NGCC cases in this study would be approximately 21 tonnes/yr (23.2 tons/yr) at 85 percent CF or 0.00084 kg/GJ (0.00195 lb/MMBtu). Thus , for th e purpose of this study, SO 2 

## emissions were considered negligible.

2.4.4 CO 2 

## is not currently regulated nationally . How ever, the possibility exists that federal carbon limits will be imposed in the future and this study examines cases that include a reduction in CO 2 

## emissions. Because the form of emission limits, should they be imposed, is not known, CO 2 

## emissions are rep orted on both a lb/(gross) MWh and lb/(net) MWh basis in each capture case emissions table. Carbon Dioxide

For the IGCC cases that have CO 2 

## capture, the basis is a nominal 90 percent removal based on carbon input from the coal and excluding carbon that exits the gasifier with the slag. In the GEE and Shell cases, this was accomplished by using two SGS reactors , to convert CO to CO 2 

## , and a tw o - stage Selexol process with a second stage CO 2 

## removal efficiency of 92 percent, a number that was supported by vendor quotes

. The GEE CO 2 

## capture case resulted in 90.3 percent reduction of CO 2 

## in the syngas. The Shell capture case resulted in 90.1 perc ent reduction of CO 2 

## in the syngas. In the CoP case, in order for the capture target of 90 percent to be achieved, a third SGS reactor was added and the Selexol efficie ncy was increased to 95 percent (the maximum removal efficiency supported by vendor quo tes). This was done because of the high syngas methane content (1.5 vol% compared to 0.10 vol% in the GEE gasifier and 0.06 vol% in the Shell gasifier). The CoP capture case resulted in 90.4 percent reduction of CO 2 

## in the syngas. For PC and NGCC cases t hat have CO 2 

## capture, it is assumed that all of the fuel carbon is converted to CO 2 

## in the FG . CO 2 

## is also generated from limestone in the FGD system, and 90 percent of the CO 2 

## exiting the FGD absorber is subsequently captured using the Econamine technology. The cost of CO 2 

## capture was calculated as an avoided cost as illustrated in the equation below

. Analogous non

- capture technologies and SC non - capture PC were chosen as sepa rate reference
cases. The COE in the CO 2 

## capture cases includes TS&M as well as capture and compression.



## MWh tons Emissions CO Emissions CO MWh COE COE Cost Avoided
removal with reference reference removal with 

## / } { / $ } {

2 2 

## − **−**
**=**

### Cost and Performance Baseline for Fossil Energy Plants

41 

## 2.5 CAPACITY FACTOR This study assumes that each new plant would be dispatched any time it is available and would be capable of g enerating maximum capacity when online. Therefore , CF and availability are equal. The availability for PC and NGCC cases was determined using the Generating Availability Data System (GADS) from the North American Elect ric Reliability Council (NERC) [ 20

NERC defines an equivalent avai lability factor (EAF), which is essentially a measure of the plant CF assuming there is always a demand for the output. The EAF accounts for planned and scheduled derated hours as well as seasonal derated hours. As such, the EAF matches this study’s defi nition of CF

. ]

. Since there are only two operating IGCC plants in North America, the same database was not useful for determining IGCC availability. Rather, input from EPRI and their work on the CoalFleet for Tomorrow Initiative was used.

The average EAF for coal

- fired plants in the 400

- 599 MW size range was 84.9 percent in 2004 and averaged 83.9 percent from 2000

- 2004. Given that many of the plants in this size range are older, the EAF was rounded up to 85 percent and that v alue was used as the PC plant CF

. The average EAF for NGCC plants in the 400

- 599 MW size range was 84.7 percent in 2004 and averaged 82.7 percent from 2000

- 2004. Using the same rationale as for PC plants, the EAF was rounded up to 85 percent and that valu e was also used as the NGCC plant CF

. EPRI examined the historical forced and scheduled outage times for IGCCs and concluded that the reliability factor (which looks at forced or unscheduled outage time only) for a single train IGCC (no spares) would be about 90 percent [ 21

There are four operating IGCC’s worldwide that use a solid feedstock and are primarily power producers (Polk, Wabash, Buggenum , and Puertollano). A 2006 report by Higman et al. examined the reliability of these IGCC power generation units and concluded that typical annual
on - stream times are around 80 percent [ ]

. To get the availability factor, one has to deduct the scheduled outage time. In reality t he scheduled outage time differs from gasifier technology

- to

- gasifier technology , but the differences are relatively small and would have minim al impact on the CF , so for this study it was assumed to be constant at a 30

- day planned outage per year (or two 15

- day outages) . The planned outage would amount to 8.2 percent of the year, so the availability factor would be ( 90 percent

- 8.2 percent), o r 81.2 percent

.

22

The addition of CO 2 

## capture to each technology was assumed not to impact the CF . This assumption was made to enable a comparison based on the impact of capital and variable operating costs only. Any reduction in assumed CF would further increase the COE for the CO 2 

## capture cases. ]

. The CF would be somewhat less than the on

- stream time since most plants operate at less than full load for some portion of the operating year. Given the results of the EPRI stud y and the Higman paper, a CF of 80 percent was chosen for IGCC with no spare gasifier required.

2.6 RAW WATER WITHDRAWAL AND CONSU MPTION A water balance was performed for each case on the major water consumers in the process. The tot al water demand for each subsystem was determined and internal recycle water available from various sources like BFW blowdown and condensate from syngas or FG (in CO 2 

## capture cases) was applied to offset the water demand. The difference between demand and recycle is raw

### Cost and Performance Baseline for Fossil Energy Plants

42 

## water withdrawal

. Raw water withdrawal is the water removed from the ground or diverted from a surface

- water source for use in the plant. Raw water consumption is also accounted for as 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 makeup was assumed to be provided 50 perce nt by a publicly owned treatment works (POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, slurry preparation makeup, ash handling makeup, syngas humidification, quench system makeup, and FGD system makeup. The difference between withdrawal and process water returned to the source is consumption. Consumption represents the net impact of the p rocess on the water source. BFW blowdown and a portion of the sour water stripper blowdown were assumed to be treated and recycled to the cooling tower. The cooling tower blowdown and the balance of the SWS blowdown streams were assumed to be treated and 90 percent returned to the water source with the balance sent to the ash ponds for evaporation. The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all cases utilized a mechanical draft, evaporative cooling tower, a nd all process blowdown streams were assumed to be treated and recycled to the cooling tower. The design ambient wet bulb temperature of 11°C (51.5°F) ( Exhibit 2

- 1 ) was used to achieve a cooling water temperature of 16°C (60°F) using an approach of 5°C (8.5°F). The cooling water range was assumed to be 11°C (20°F). The cooling tower makeup rate was determined using the following: [ 23

**•** Evaporative losses of 0.8 percent of the circulating water flow rate per 10°F of range ]

**•** Drift losses of 0.001 percent of the circulating water flow rate

**•** Blowdown losses were calculated as follows:

o Blowdown Losses = Evaporative Losses / (Cycles of Concentration

- 1) Where cycles of concentration is a measure of water quality, and a mid

- range value of 4 was chosen for this study. The water balances presented in subsequent sections include the water demand of the major water consumers within the process, the amount provided by internal recycle, the amount of raw water withdrawal by difference, the amount of process water returned to the source and the raw water consumption, again by difference.
2.7 COST ESTIMATING METH ODOLOGY The estimating methodology for capital costs, operations and main tenance costs, and CO 2 

## TS&M costs are described below. The finance structure, basis for the discounted cash flow analysis, and first

- year COE cost calculations are also described.
2.7.1 As illustrated in Capital Costs Ex hibit 2

- 11 , this study reports capital cost at four levels: Bare Erected Cost ( BEC ) , Total Plant Cost ( TPC ) , Total Overnight Cost ( TOC ) and Total As

- spent Capital ( TASC )

. BEC, TPC and TOC are “overnight” costs and are expressed in “base

- year” dollars. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. TASC is

### Cost and Performance Baseline for Fossil Energy Plants

43 

## expressed in mixed

- year, current

- year dollars over the entire capital expenditure period, which is assumed to last five years coal plants (2007 to 2011) and three years for natural gas plants (2007 to 2009)

.
Exhibit 2

- 11 Capital Cost Levels and their Elements

The BEC

The comprises the cost of process equipment, on

- site facilities and infrastructure that support the plant (e.g., shops, offices, labs, road), and the direct and indirect labor required for its construction and/or installation. The cost of EPC services and con tingencies is not included in BEC. BEC is an overnight cost expressed in base

- year (2007) dollars.
TPC

The comprises the BEC plus the cost of services provided by the engineering, procurement and construction (EPC) contractor and project and process conti ngencies. EPC services include: detailed design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes of work, as opposed to project permitting, which is not included here), and project/construction m anagement costs. TPC is an overnight cost expressed in base

- year (2007) dollars.
TOC

The comprises the TPC plus owner’s costs. TOC is an “overnight” cost, expressed in base

year (2007) dollars and as such does not include escalation during construction o r interest during construction. TOC is an overnight cost expressed in base

- year (2007) dollars. TASC 

## process equipment supporting facilities direct and indirect labor 

## BEC

TPC

TOC TASC EPC contractor services process contingency project contingency
preproduction costs inventory capital financing costs other owner’s costs
escalation during capital expenditure period interest on debt during capital expenditure period 

## Bare Erected Cost Total Plant Cost Total Overnight Cost Total As

- Spent Cost

BEC, TPC and TOC are all “overnight” costs expressed in base

- year dollars.
TASC is expressed in mixed

- year current dollars, spread over the capital expenditure period.



## is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction.

### Cost and Performance Baseline for Fossil Energy Plants

44 

## Accordingly, TASC is expressed in mixed, current

- year dollars over the capital expenditure period. Cost Estimate Basis and Classification The TPC and Operation and Maintenance (O&M) costs for each of the cases in the study were estimated by WorleyParsons us ing an in

- house database and conceptual estimating models. Costs were furthe r calibrated using a combination of adjusted vendor

- furnished and actual cost data from recent design projects. Recommended Practice 18R

- 97 of the Association for the Advancement of Cost Engineering International (AACE) describes a Cost Estimate Classifica tion System as applied in Engineering, Procurement and Construction for the process industries [ 24 Most techno

- economic studies completed by NETL feature cost estimates intended for the purpose of a “Feasibility Study” (AACE Class 4). ]

.
Exhibit 2

- 12 describes the characteristics of an AACE Class 4 Cost Estimate. Cost estimates in this stud y have an expected accuracy range of

- 15%/+30%. Exhibit 2

- 12 Features of an AACE Class 4 Cost Estimate Project Definition Typical Engineering Completed Expected Accuracy

1 to 15% plant capacity, block schematics, indicated layout, process flow diagrams for main proc ess systems, and preliminary engineered process and utility equipment lists - 15% to

- 30% on the low side, and +20% to +50% on the high side

System Code

- of

- Accounts The costs are grouped according to a process/system oriented code of accounts. This type of code

- of

- account structure has the advantage of grouping all reasonably allocable components of a system or process so they are included in the specific system account. (This would not be the case had a facility, area, or commodity account structure bee n chosen instead).
Non

- CO 2 

## Capture Plant Maturity T he case estimates provided include technologies at different commercial maturity levels. The estimates for the non

- CO 2 

## - capture PC and NGCC cases represent well

- developed commercial technology or “n th 

## pl ants.” The non

- capture IGCC cases are also based on commercial offerings, however, there have been very limited sales of these units so far. These non

- CO 2 

## - capture IGCC plant costs are less mature in the learning curve, and the costs listed reflect the “n ext commercial offering” level of cost rather than mature n th



## - of

- a - kind (NOAK) cost. Thus, each of these cases reflect s the expected cost for the next commercial sale of each of these respective technologies. CO 2 

## Removal Maturity The post

- combustion CO 2 

## removal technology for the PC and NGCC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications.

### Cost and Performance Baseline for Fossil Energy Plants

45 

## The pre

- combustion CO 2 

## removal technology for the IGCC capture cases has a stronger
com mercial experience base. Pre

- combustion CO 2 

## removal from syngas streams has been proven in chemical processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO 2 

## removal technology in commercial service, there are currently IGCC plants with CO 2 

## capture well along in the planning stages. Contracting Strategy The estimates are based on an EPCM approach utilizing multiple subcontracts. This approach provides the Owner with greater control of the project, while minimizing, if not eliminating most of the risk premiums typically included in an Engineer/Procure/Construct (EPC) contract price. In a traditional lump sum EPC contract, the Contractor assumes all risk fo r performance, schedule, and cost. However, as a result of current market conditions, EPC contractors appear more reluctant to assume that overall level of risk. Rather, the current trend appears to be a modified EPC approach where much of the risk remai ns with the Owner. Where Contractors are willing to accept the risk in EPC type lump

- sum arrangements, it is reflected in the project cost. In today’s market, Contractor premiums for accepting these risks, particularly performance risk, can be substantia l and increase the overall project costs dramatically. The EPCM approach used as the basis for the estimates here is anticipated to be the most cost effective approach for the Owner. While the Owner retains the risks, the risks become reduced with time, as there is better scope definition at the time of contract award(s). Estimate Scope The estimates represent a complete power plant facility on a generic site

. The plant boundary limit is defined as the total plant facility within the “fence line” inclu ding coal receiving and water supply system, but terminating at the high voltage side of the main power transformers. TS&M cost is not included in the reported capital cost or O&M costs, but is treated separately and added to the COE. Capital Cost Assumpt ions WorleyParsons developed the capital cost estimates for each plant using the company’s in

- house database and conceptual estimating models for each of the specific technologies. This database and the respective models are maintained by WorleyParsons a s part of a commercial power plant design base of experience for similar equipment in the company’s range of power and process projects. A reference bottoms

- up estimate for each major component provides the basis for the estimating models. Other key est imate considerations include the following:

**•** Labor costs are based on Midwest, Merit Shop. The estimating models are based on U.S. Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published annually. Based on the data provided in PAS, WorleyParsons used the weighted average payroll plus fringe rate for a standard craft distribution as developed for the estimating models. PAS presents information for eigh t separate regions. For this study, Region 5 (IL, IN, MI, MN, OH, and WI) was selected

.

### Cost and Performance Baseline for Fossil Energy Plants

46 

## • The estimates are based on a competitive bidding environment, with adequate skilled craft labor available locally.

**•** Labor is based on a 50

- hour work

- week (5

- 10s). No a dditional incentives such as per

diems or bonuses have been included to attract craft labor.

**•** While not included at this time, labor incentives may ultimately be required to attract and retain skilled labor depending on the amount of competing work in th e region, and the availability of skilled craft in the area at the time the pr ojects proceed to construction.

**•** The estimates are based on a greenfield site.

**•** The site is considered to be Seismic Zone 1, relatively level, and free from hazardous materials, archeological artifacts, or excessive rock. Soil conditions are considered adequate for spread footing foundations. The soil bearing capability is assumed adequate such that piling is not needed to support the foundation loads.

**•** Costs are limited to wit hin the “fence line,” terminating at the high voltage side of the main power transformers with the exception of costs included for TS&M , which are treated as an addition to COE

.

**•** Engineering and Construction Management a re estimated a t 8

- 10 percent of BEC. These costs consist of all home office engineering and procurement services as well as field construction management costs. Site staffing generally includes a construction manager, resident engineer, scheduler, and personnel for project controls, document control, materials management, site safety, and field inspection. Price Fluctuations During the course of this study, the prices of equipment and bulk materials fluctuated quite substantially. Some reference quotes pre

- dated the 2007 y ear cost basis while others were received post

- 2007. All vendor quotes used to develop these estimates were adjusted to June 2007 dollars accounting for the price fluctuations. Adjustments of costs pre

- dating 2007 benefitted from a vendor survey of actua l and projected pricing increases from 2004 through mid

- 2007 that WorleyParsons conducted for another project. The results of that survey were used to validate/recalibrate the corresponding escalation factors used in the conceptual estimating models. The more recent economic down turn has resulted in a reduction of commodity prices such that many price indices have 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. While these overall indices are nearly constant, it should be noted that the cost of individual equipment types may still devia te from the June 2007 reference point. Cross

- comparisons In all technology comparison studies, the relative differences in costs are often more significant than the absolute level of TPC. This requires cross

- account comparison between technologies to
rev iew the consistency of the direction of the costs. In performing such a comparison, it is important to reference the technical parameters for each specific item, as these are the basis for establishing the costs. Scope or assumption differences

### Cost and Performance Baseline for Fossil Energy Plants

47 

## can quic kly explain any apparent anomalies. There are a number of cases where differences in design philosophy occur. Some key examples are:

**•** The CT account in the GE E IGCC cases include s a syngas expander , which is not required for the Co P or Shell cases.

**•** The C T s for the IGCC capture cases include an additional cost for firing a high h ydrogen content fuel

.

**•** The Shell gasifier syngas cooling configuration is different between the CO 2 

## - capture and
non - CO 2 

## - capture cases, resulting in a significant differential in the rmal duty between the syngas coolers for the two cases. Exclusions The capital cost estimate includes all anticipated costs for equipment and materials, installation labor, professional services (Engineering and Construction Management), and contingency. The following items are excluded from the capital costs:

**•** All taxes, with the exception of payroll and property taxes (property taxes are included with the fixed O&M costs)

**•** Site specific considerations

– including, but not limited to, seismic zone, accessibility, local regulatory requirements, excessive rock, piles, laydown space, etc.

**•** Labor incentives in excess of 5

- 10s

**•** Additional premiums associated with an EPC contractin g approach Contingency Process and project contingencies are included in estimates to account for unknown costs that are omitted or unforeseen due to a lack of complete project definition and engineering. Contingencies are added because experience has sh own that such costs are likely, and expected, to be incurred even though they cannot be explicitly determined at the time the estimate is prepared. Capital cost contingencies do not cover uncertainties or risks associated with

**•** scope changes

**•** changes in la bor availability or productivity

**•** delays in equipment deliveries

**•** changes in regulatory requirements

**•** unexpected cost escalation

**•** performance of the plant after startup (e.g., availability, efficiency) Process Contingency Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the development status of a technology. Process contingencies are applied to each plant section based on its current technology status.

### Cost and Performance Baseline for Fossil Energy Plants

48 

## As shown in Exhibit 2

- 13 , AACE International Recommended Practice 16R

- 90 provides guidelines for estimating process contingency based on EPRI philosophy [ 25 Process contingencies have been applied to the estimates in this study as follows: ]

.

**•** Slurry Prep and Feed

– 5 percent on GE IGCC cases

- systems are operating at approximately 800 psi a as compared to 600 psi a for the other IGCC cases

**•** Gasifiers and Syngas Coo lers

– 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 cases

- unproven technology at commercial scale in IGCC service

**•** Mercury Removal

– 5 percent o n all IGCC cases

– minimal commercial scale experience in IGCC applications

**•** CO 2 

## Removal System

– 20 percent on all PC/NGCC capture cases

- post

- combustion process unproven at commercial scale for power plant applications

**•** CTG

– 5 percent on all IGCC non

- cap ture cases

– syngas firing and ASU integration ; 10 percent on all IGCC capture cases

– high hydrogen firing.

**•** Instrumentation and Controls

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

– integration issues

Exhibit 2

- 13 AACE Guidelines for Process Contingency
Technology Status Process Contingency (% of Associated Process Capital) New concept with limited data 40+ Concept with bench

- scale data 30

- 70 Small pilot plant data 20

- 35
Full

- sized modules have been operated 5

- 20 Process is used commercially 0

- 10 Process contingency is typically not applied to costs that are set equal to a research goal or programmatic target since these values presume to reflect the total cost. Project Contingency AACE 16R

- 90 states that project contingency for a “budget

- type” estimate (AACE Class 4 or 5) should be 15 to 30 percent of the sum of BEC, EPC fees and process contingency. This was used as a general guideline, but some project conting ency values outside of this range occur based on WorleyParsons’ in

- house experience.

### Cost and Performance Baseline for Fossil Energy Plants

49 

## Owner’s Costs Exhibit 2

- 15 explains the estimation method for owner’s costs. With some exceptions, the estimation method follows guidelines in Sections 12.4.7 to 12.4.12 of AACE International Recommended Practice No. 16R

- 90 [ 25 ] . The Electric Power Research Institute’s “Technical Assessment Guide (TAG®)

– Power Generation and Storage Technology Options” also has guidelines fo r estimating owner’s costs. The EPRI and AACE guidelines are very similar. In instances where they differ, this study has sometimes adopted the EPRI approach

. Interest during construction and escalation during construction are not included as owner’s cos ts but are factored into the COE and are included in TASC. These costs vary based on the capital expenditure period and the financing scenario. Ratios of TASC/TOC determined from the PSFM are used to account for escalation and interest during constructio n. Given TOC, TASC can be determined from the ratios given in Exhibit 2

- 14

.

Exhibit 2

- 14 TASC/TOC Factors
Finance Structure High Risk IOU Low Risk IOU Capital Expenditure Period Three Years Five Years Three Years Five Years
TASC/TOC 1.078 1.140 1.075 1.134

### Cost and Performance Baseline for Fossil Energy Plants

50 

## Exhibit 2

- 15 Owner’s Costs Included in TOC
Owner’s Cost Estimate Basis
Prepaid Royalties Any technology royalties are assumed to be included in the associated equipment cost, and thus are not included as an owner’s cost.

Preproduction

(Start

- Up) Costs **•** 6 months operating labor

**•** 1 month maintenance materials at full capacity

**•** 1 month non

- fuel consumables at full capacity

**•** 1 month waste disposal

**•** 25% of one month’s fuel cost at full capacity

**•** 2% of TPC Compared to AACE 16R

- 90, this includes additional costs for operating labor (6 months versus 1 month) to cover the cost of training the plant operators, including their participation in startup, and involving them occasionally during the design and construction. AACE 16R

- 90 and EPRI TAG® diffe r on the amount of fuel cost to include; this estimate follows EPRI. Working

Capital Although inventory capital (see below) is accounted for, no additional costs are included for working capital.

Inventory

Capital **•** 0.5% of TPC for spare parts

**•** 60 day suppl y (at full capacity) of fuel. Not applicable for natural gas.

**•** 60 day supply (at full capacity) of non

- fuel consumables (e.g., chemicals and catalysts) that are stored on site. Does not include catalysts and adsorbents that are batch replacements such as WGS, COS, and SCR catalysts and activated carbon. AACE 16R

- 90 does not include an inventory cost for fuel, but EPRI TAG® does.
Land **•** $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing Cost **•** 2.7% of TPC This financing cost (not included by AACE 16R

- 90) covers the cost of securing financing, including fees and closing costs but not including interest during construction (or AFUDC). The “rule of thumb” estimate (2.7% of TPC) is based on a 2008 private communication with a capital services firm.

### Cost and Performance Baseline for Fossil Energy Plants

51 

## Owner’s Cost Estimate Basis

Other Owner’s

Costs **•** 15% of TPC This additional lumped cost is not included by AACE 16R

- 90 or EPRI TAG®. The “rule of thumb” estimate (15% of TPC) is based on a 2009 private communication with WorleyParsons. Significant deviation from this value is possible as it is very site and owner specific. The lumped cost includes:

­ Preliminary feasibility studies, including a Front

- End Engineering Design (FEED) study

­ Economic development (costs for incentivizing local collaboration and support)

­ Construction and/or improvement of roads and/or railroad spurs outside of site boundary

­ Legal fees

­ Permitting costs

­ Owner’s engineering (staff paid by owner to give third

- party advice and to help the owner oversee/evaluate the work of the EPC contractor and other contr actors)

­ Owner’s contingency (Sometimes called “management reserve”, these are funds to cover costs relating to delayed startup, fluctuations in equipment costs, unplanned labor incentives in excess of a five

- day/ten

- hour

- per - day work week. Owner’s conting ency is NOT a part of project contingency.) This lumped cost does NOT include:

­ EPC Risk Premiums (Costs estimates are based on an Engineering Procurement Construction Management approach utilizing multiple subcontracts, in which the owner assumes project r isks for performance, schedule and cost)

­ Transmission interconnection: the cost of interconnecting with power transmission infrastructure beyond the plant busbar.

­ Taxes on capital costs: all capital costs are assumed to be exempt from state and local tax es.

­ Unusual site improvements: normal costs associated with improvements to the plant site are included in the bare erected cost, assuming that the site is level and requires no environmental remediation. Unusual costs associated with the following desig n parameters are excluded: flood plain considerations, existing soil/site conditions, water discharges and reuse, rainfall/snowfall criteria, seismic design, buildings/enclosures, fire protection, local code height requirements, noise regulations.

### Cost and Performance Baseline for Fossil Energy Plants

52 

## 2.7.2 The production costs or operating costs and related maintenance expenses (O& M) pertain to those charges associated with operating and maintaining the power plants over their expected life. These costs include: Operations and Maintenance Costs

**•** Operating labor

**•** Maintenance

– material and labor

**•** Administrative and support labor

**•** Consumables

**•** Fuel

**•** Waste di sposal

**•** Co

- p ro duct or b y - p roduct credit (that is, a negative cost for any by

- products sold) There are two components of O&M costs; fixed O&M, which is independent of power generation, and variable O&M, which is proportional to power generation. Operating Labor Operating labor cost was determined based on of the number of operators required for each specific case. The average base labor rate used to determine annual cost is $3 4.65 / hour . The associated labor burden is estimated at 30 percent of the base labor ra te. Taxes and insurance are included as fixed O&M costs totaling 2 percent of the TPC. Maintenance Material and Labor Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial capital cost. This represents a weighted ana lysis in which the individual cost relationships were considered for each major plant component or section. Administrative and Support Labor Labor administration and overhead charges are assessed at rate of 25 percent of the burdened O&M labor. Consumables The cost of consumables, including fuel, was determined on the basis of individual rates of consumption, the unit cost of each specific consumable commodity, and the plant annual operating hours. Quantities for major consumables such as fuel and sorbent were taken from technology

- specific heat and mass balance diagrams developed for each plant application. Other consumables were evaluated on the basis of the quantity required using reference data. The quantities for initial fills and daily consumables were calculated on a 100 percent operating capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the annual plant operating basis, or CF

. Initial fills of the consumables, fuels and chemicals, are different from the initial chemical loadings , which are included with the equipment pricing in the capital cost.

### Cost and Performance Baseline for Fossil Energy Plants

53 

## Waste Disposal Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In this study both slag from the IGCC cases and fly a sh and bottom ash from the PC cases are considered a wast e with a disposal cost of $17.89 /tonne ($ 16.23 /ton). The carbon used for mercury control in the IGCC cases is considered a hazardous waste with disposal cost of $ 926 /tonne ($8 4 0/ton). Co

- Products an d By

- Products By

- product quantities were also determined similarly to the consumables. However, due to the variable marketability of these by

- products, specifically gypsum and sulfur, no credit was taken for their potential salable value. It should be n oted that by

- product credits and/or disposal costs could potentially be an additional determining factor in the choice of technology for some companies and in selecting some sites. A high local value of the product can establish whether or not added capit al should be included in the plant costs to produce a particular co

- product. Ash and slag are both potential by

- products in certain markets, and in the absence of activated carbon injection in the PC cases, the fly ash would remain uncontaminated and have potential marketability. However, as stated above, the ash and slag are considered wastes in this study with a concomitant disposal cost.
2.7.3 For those cases that feature carbon sequestration, the capital and operating costs for CO 2 

## TS&M were independently estimated by NETL. Those costs were converted to a TS&M COE increment that was added to the plant COE. CO 2 

## Transport, Storage and Monitoring

CO 2 

## TS&M was modeled based on the following assumptions:

**•** CO 2 

## is supplied to the pipeline at the plant fence line a t a pressure of 15.3 MPa (2,215 psia). The CO 2 

## product gas composition varies in the cases presented, but is expected to meet the specification described in Exhibit 2

- 16 [ 26

Exhibit 2

- 16 CO 2 

## Pipeline Specification ]

. A glycol dryer located near the mid

- point of the compression train is used to meet the moisture specification.

Parameter Units Parameter Value Inlet Pressure MPa (psia) 15.3 (2,215) Outlet Pressure MPa (psia) 10.4 (1,515) Inlet Temperature °C (°F) 35 (95 ) N 2 

## Concentration ppmv < 300 O 2 

## Concentration ppmv < 40 Ar Concentration ppmv < 10 H 2 

## O Concentration ppmv < 150

### Cost and Performance Baseline for Fossil Energy Plants

54 

## • The CO 2 

## is transported 80 km (50 miles) via pipeline to a geologic sequestration field for injection into a saline formation.

**•** The CO 2 

## is transported and injected as a SC fluid in order to avoid two

- phase flow and achieve maximum efficiency [ 27 ]

. The pipeline is assumed to have an out let pressure (above the SC pressure) of 8

. 3 MPa (1, 200 psia) with no recompression along the way. Accordingly, CO 2 

## flow in the pipeline was modeled to determine the pipe diameter that results in a pressure drop of 6

. 9 MPa ( 1,0 00 psi) over an 80 km (50 mil e) pipeline length [ 28

**•** The saline formation is at a depth of 1,23 6 m (4,055 ft) and has a permeability of 22 millidarcy (md) (22 μm 2 

## ) and formation pressure of 8.4 MPa (1,220 psig) [ ]

. (Although not explored in this study, the use of boost compressors and a smaller pipeline diameter could possibly reduce capital costs for sufficiently long pipelines.) The diameter of the injection pipe will be of sufficient size that frictional losses during injection are minimal and no booster compression is required at the well

- head in order to achieve an appropriate down

- hole pressure , with hydrostatic head making up the difference between the injection and reservoir pressure.

29
29 ]

. This is considered an average storage site and requires roughly one injection well for each 9,360 tonnes (10,320 short tons) of CO 2 

## injected per day [ ]

. The assumed aquifer characteristics are tabulated in Exhibit 2

- 17

. The cost metrics utilized in this study provide a best estimate of TS&M costs for a “ favorable ” sequestration project, and may vary significantly based on variables such as terrain to be cro ssed by the pipeline, reservoir characteristics, and number of land owners from which sub

- surface rights must be acquired. Raw capital and operating costs are derived from detailed cost metrics found in the literature, escalated to June 2007

- year dollars using appropriate price indices. These costs were then verified against values quoted by industrial sources where possible. Where regulatory uncertainty exists or costs are undefined, such as liability costs and the acquisition of underground pore volume , analogous existing policies were used for representative cost scenarios. Exhibit 2

- 17 Deep, Saline Aquifer Specification
Parameter Units Base Case
Pressure MPa (psi) 8.4 (1,220)
Thickness m (ft) 161 (530) Depth m (ft) 1,236 (4,055) Permeability M d 22 Pipeline Distance km (miles) 80 (50) Injection Rate per Well tonne (ton) CO 2 

## /day 9,360 (10,320)

The following sections describe the sources and methodology used for each metric.

### Cost and Performance Baseline for Fossil Energy Plants

55 

## TS&M Captial Costs TS&M capital costs include both a 20 percent process contingency and 30 percent project contingency. In several areas, such as Pore Volume Acquisition, Monitoring, and Liability, cost outlays occur over a longer time period, up to 100 years. In these cas es a capital fund is established based on the net present value of the cost outlay, and this fund is then levelized similar to the other costs. Transport Costs CO 2 

## transport costs are broken down into three categories: pipeline costs, related capital expen ditures, and O&M costs. Pipeline costs are derived from data published in the Oil and Gas Journal’s (O&GJ) annual Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO 2 

## pipeline, as noted in various studies [ 27 , 29 , 30

30 ]

. The University of California performed a regression analysis to generate cost curves from the O&GJ data: (1) Pipeline Materials, (2) Direct Labor, (3) Indirect Costs, and (4) Right

- of

- w ay acquisition, with each represented as a function of pipeli ne length and diameter [ ]

. These cost curves were escalated to the June 2007 year dollars used in t his study. Related capital expenditures were based on the findings of a previous study funded by DOE/NETL, Carbon Dioxide Sequestration in Saline Formations

– Engi neering and Economic Assessment [ 29 ]

. This study utilized a similar basis for pipeline costs ( O&GJ Pipeline cost data up to the year 2000) but added a CO 2 

## surge tank and pipeline control system to the project. Transport O&M costs were assessed using me trics published in a second DOE/NETL sponsored report entitled Economic Evaluation of CO 2 

## Stora ge and Sink Enhancement Options [ 27 ]

. This study was chosen due to the reporting of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (a) do not report operating costs, or (b) report them in absolute terms for one pipeline, as opposed to as a length

- or di ameter

- based metric. Storage Costs Storage costs were divided into five categories: (1) Site Screening and Evaluation, (2) Injection Wells, (3) Injection Equipment, (4) O&M Costs, and (5) Pore Volume Acquisition. With the exception of Pore Volume Acquisi tion, all of the costs were obtained from Economic Evaluation of CO 2 

## Storage and Sink Enhancement Options [ 27 ]

. These costs include all of the costs associated wi th determining, developing, and maintaining a CO 2 

## storage location, including site evaluation, well drilling, and the capital equipment required for distributing and injecting CO 2 

## . Pore Volume Acquisition costs are the costs associated with acquiring righ ts to use the sub

surface volume where the CO 2 

## will be stored, i.e., the pore space in the geologic formation. These costs were based on recent research by Carnegie Mellon University , which examined existing sub

- surface rights acquisition as it pertains t o natural gas storage [ 31 ]

. The regulatory uncertainty in this area combined with unknowns regarding the number and type (private or government) of property owners, require a number of “best engineering judgment” decisions to be made

. In this study it was assumed that long

- term lease rights were acquired from the property owners in the projected CO 2 

## plume growth region for a nominal fee, and that an annual “rent” was paid when the plume reached each individual acre of their property for a period of up

### Cost and Performance Baseline for Fossil Energy Plants

56 

## to 1 00 years from the injection start date

. The present value of the life cycle pore volume costs are assessed at a 10 percent discount rate and a capital fund is set up to pay for these costs over the 100 y ear rent scenario. Liability Protection Liability Protection addresses the fact that if damages are caused by injection and long

- term storage of CO 2 

## , the injecting party may bear financial liability. Several types of liability protection schem e s have been suggested for CO 2 

## storage, including Bonding, Ins urance, and Federal Compensation Systems combined with either tort law (as with the Trans

- Alaska Pipeline Fund), or with damage caps and preemption, as is used for nuclear energy under the Price Anderson Act [ 32 ]

. However, a t present, a specific liability regime has yet to be dictated either at a Federal or (to our knowledge) State level. However, certain state governments have enacted legislation , which assigns liability to the injecting party, either in perpetuity (Wyoming) or until ten years after the c essation of injection operations, pending reservoir integrity certification, at which time liability is turned over to the state (North Dakota and Louisiana) [ 33 , 34 , 35

Liability costs assume that a bond must be purchased before i njection operations are permitted in order to establish the ability and good will of an injector to address damages where they are deemed liable. A figure of five million dollars was used for the bond based on the Louisiana fund level. This b ond level ma y be conservative ly high , in that the Louisiana fund covers both liability and monitoring, but that fund also pertains to a certified reservoir where injection operations have ceased, having a reduced risk compared to active operations. The b ond cost was
n ot escalated. ]

. In the case of Louisiana, a trust fund totaling five million dollars is established over the first ten years (120 months) of injection operations for each injector . This fund is then used by the state for CO 2 

## monitoring and, in the event of an at

- fault incident, damage payments.

Monitoring Costs Monitoring costs were evaluated based on the methodology set forth in the International Energy Agency ( IEA ) Greenhouse Gas ( GHG ) R&D Programme’s Overview of Monitoring Projects for Geologic Storage Projects report [ 36

2.7.4 ]

. In this scenario, operational monitoring of the CO 2 

## plume
occurs over 30 years (during plant operation) and closure monitoring occurs for the following fifty years (for a total of eighty years). Monitoring is via electromagnetic (EM) survey, gravity
sur vey, and periodic seismic survey ; EM and gravity surveys are ongoing while seismic survey occurs in years 1, 2, 5, 10, 15, 20, 25, and 30 during the operational period, then in years 40, 50, 60, 70, and 80 after injection ceases.

The global economic assumptions are listed in Finance Structure, Discoun ted Cash Flow Analysis, and COE Exhibit 2

- 18

. Finance structures were chosen based on the assumed type of developer/owner (investor

- owned utility (IOU) or independent power producer) and the assumed risk profile of the plant being assessed (low

- risk or high

- risk). For this study the owner/developer was assumed to be an IOU. All IGCC cases as well as PC and NGCC cases with CO 2 

## capture were considered high risk. The non

- capture PC and NGCC cases were considered low risk. Exhibit 2

- 19 describes the low

risk IOU and high

- risk IOU finance structures that were assumed for this study. These finance

### Cost and Performance Baseline for Fossil Energy Plants

57 

## structures were recommended in a 2008 NETL report based on interviews with project developers/owners, financial organizations and law firms [ 37 ]

.
Exhibit 2

- 18 Global Economic Assumptions Parameter Value TAXES Income Tax Rate 38% (Effective 34% Federal, 6% State) Capital Depreciation 20 years, 150% declining balance Investment Tax Credit 0% Tax Holiday 0 years CONTRACTING AND FINANCING TERMS Contracting Strategy Engineering Procurement Construction Management ( owner assumes project risks for performance, schedule and cost) Type of Debt Financing Non

- Recourse (collateral that secures debt is limited to the real assets of the project) Repayment Term of Debt 15 years Grace Period on Debt Repayment 0 years Debt Reserve Fund None ANALYSIS TIME PERIODS Capital Expenditure Period Natural Gas Plants: 3 Years Coal Plants: 5 Years Operational Period 30 years Economic Analysis Period (used for IRROE) 33 or 35 Years (capital expenditure period plus operational period) TREATMENT OF CAPITAL COSTS Capital Cost Escalation During Capital Expenditure Period (nominal annual rate) 3.6% 2 

### Distribution of Total Overnight Capital over the Capital Expenditure Period (before escalation) 3

- Year Period: 10%, 60%, 30% 5

- Year Period: 10%, 30%, 25%, 20%, 15% Working Capital zero for all parameters % of Total Overnight Capital that is Depreciated 100% (this assumption introduces a very small error even if a substantial amount of TOC is actually non

- depreciable) ESCALATION OF OPERATING REVENUES AND COSTS Escalation of CO E (revenue), O&M Costs, and Fuel Costs (nominal annual rate) 3.0% 3

2 

### A nominal average annual rate of 3.6 percent is assumed for escalation of capital costs during construction. This rate is equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 and 2008 according to the Chemical Engineering Plant Cost Index.
3 

### An average annual inflation rate of 3.0 percent is assumed. This rate is equivalent to the average annual escalation rate between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the so

called "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power Generation Industry may be more applicable, but that data does not provide a long

- term historical perspective since it only dates back to December 2003.)

### Cost and Performance Baseline for Fossil Energy Plants

58 

## Exhibit 2

- 19 Financial Structure for Investor Owned Utility High and Low Risk Projects Type of Security % of Total Current (Nominal) Dollar Cost Weighted Current (Nominal) Cost After Tax Weighted Cost of Capital Low Risk Debt 50 4.5% 2.25% Equity 50 12% 6% Total 8.25% 7.39% High Risk Debt 45 5.5% 2.475% Equity 55 12% 6.6% Total 9.075% 8.13% 

## DCF Analysis and Cost of Electricity The NETL Power Systems Financial Model (PSFM) is a nominal

- dollar 4 

## (current dollar) discounted cash flow (DCF) analysis tool. As explained below, the PSFM was used to calculate COE 5 

## Exhibit 2

- 20 in two ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, COE solutions are shown in for a generic pulverized coal (PC) power plant and a generic natural gas combined cycle (NGCC) power plant , each with carbon capture and sequestration installed

.

**•** The COE 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 consta nt in real terms over the operational period of the power plant . To calculate the COE, the PSFM was used to determine a “base

- year” (2007) COE that, when escalated at an assumed nominal annual general inflation rate of 3 percent 6



## Exhibit 2

- 20 , provided the stipulated internal rate of return on equity over the entire economic analysis period (capital expenditure period plus thirty years of operation). The COE solutions are shown as curved lines in the upper portion of for a PC power plant and a NGCC power plant. Since this analysis assumes that COE increases over the economic analysis period at the nominal annual general inflation rate, it remains const ant in real terms and the first

- year COE is equivalent to the base

- year COE when expressed in base

- year (2007) dollars.

4 

### Since the anal ysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect the interplay between depreciation and inflation.

5 

### For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant’s perspective it is actually the “price” received for the electricity generated to achieve the stated IRROE . However, since the price paid for generation is ultimately charged to the end user, from the customer’s perspective it is part of the cost of elect ricity.
6 

### This nominal escalation rate is equal to the average annual inflation 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 only 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

59 

## • The LEVELIZED COE 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 of 0 percent , i.e., that it remains constant in nominal terms over the operational period of the power plant. This study reports LCOE on a current

- dollar basis over thirty years. “Curre nt dollar” refers to the fact that levelization is done on a nominal, rather than a real, basis 7



## Exhibit 2

- 20 . “Thirty

- years” refers to the length of the operational period assumed for the economic analysis. To calculate the LCOE, the PSFM was used to calculate a bas e - year COE that, when escalated at a nominal annual rate of 0 percent , provided the stipulated return on equity over the entire economic analysis period. For the example PC and NGCC power plant cases, the LCOE solutions are shown as horizontal lines in th e upper portion of

. Exhibit 2

- 20 also illustrates the relationship between COE and the assumed developmental and operational timelines for the power plants. As shown in the lower portion of Exhibit 2

- 20 , the capital expenditure period is assumed to start in 2007 for all cases in this report. All capital costs included in this analysis, including project development and c onstruction costs, are assumed to be incurred during the capital expenditure period. Coal

- fueled plants are assumed to have a capital expenditure period of five years and natural gas

- fueled plants are assumed to have a capital expenditure period of three years. Since both types of plants begin expending capital in the base year (2007), this means that the analysis assumes that they begin operating in different years: 2012 for coal plants and 2010 for natural gas plants in this study

. Note that, according to the Chemical Engineering Plant Cost Index, June

- 2007 dollars are nearly equivalent to January

2010 dollars.

7 

### For this current

- dollar analysis, the LCOE is unifo rm in current dollars over the analysis period. In contrast, a constant

- dollar analysis would yield an LCOE that is uniform in constant dollars over the analysis period.

### Cost and Performance Baseline for Fossil Energy Plants

60 

## Exhibit 2

- 20 Illustration of COE Solutions using DCF Analysis

In addi tion to the capital expenditure period, the economic analysis considers thirty years of operation for both coal and natural gas plants. Since 2007 is the first year of the capital expenditure period, it is also the base year for the economic analysis. Acc ordingly, it is convenient to report the results of the economic analysis in base

- year (June 2007) dollars, except for TASC, which is expressed in mixed

- year, current dollars over the capital expenditure period. Consistent with our nominal

- dollar discoun ted cash flow methodology, the COEs shown on Exhibit 2

- 20 are expressed in current dollars. However, they can also be expressed in constant, base year dollars (June 2007) as shown in Exhibit 2

- 21 by adjusting them with the assumed nominal annual general inflation rate (3 percent ). Exhibit 2

- 21 illustrates the same information as in Exhibit 2

- 20 for a PC plant with CCS only on a constant 2007 dollar basis. With an assumed nominal COE escalation rate equal to the rate of inflation, the COE line now becomes horizontal and the LCOE decreases at a rate of 3 percent per year.

### Cost and Performance Baseline for Fossil Energy Plants

61 

## Exhibit 2

- 21 PC with CCS in Current 2007 Dollars

For scenarios that adhere to the global economic assumptions listed in Estimating COE with Capital Charge Factors Exhibit 2

- 18 and utilize one of the finance structures listed in Exhibit 2

- 19 , the following simplified equation can be used to estimate COE as a function of TOC 8



## Exhibit 2

- 22 , fixed O&M, variable O&M (including fuel), capacity factor and net output. The equation requires the application of one of the capital char ge factors (CCF) listed in . These CCFs are valid only for the global economic assumptions listed in Exhibit 2

- 18 , the stated finance structure, and the stated capital expenditure period.

8 

### Although TOC is used in the simplified COE equation, the CCF that multiplies it ac counts for escalation during construction and interest during construction (along with other factors related to the recovery of capital costs).

### Cost and Performance Baseline for Fossil Energy Plants

62 

## Exhibit 2

- 22 Capital Charge Factors for COE Equation
Finance Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Three Years Five Years Three Years Five Years
Capital Charge Factor (CCF) 0.111 0.124 0.105 0.116

All factors in the COE equation are expressed in base

- year dollars. The base year is the first year of capital expenditure, which for this study is assumed to be 2007. As shown in Exhibit 2

- 18 , all factors (COE, O&M and fuel) are assumed to escalate at a nominal annual general inflation rate of 3.0 percent . Accordingly, all first

- year costs (COE and O&M) are equivalent to base

- yea r costs when expressed in base

- year (2007) dollars.

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

year dollars ), assuming that the COE escalates th ereafter 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 from Exhibit 2

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

- year dollars 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, assumed to be constant over the operational period MWH = annual net megawatt

- hours of power generated at 100 percent capacity factor

### Cost and Performance Baseline for Fossil Energy Plants

63 

## The primary cost metric in this study is the COE, which is the base

- year cost presented in base

year dollars. Exhibit 2

- 23 presents this cost metric along with the COE escalated to the first year of operation (2010 for NGCC cases and 2012 for coal cases) using the average annual inflation rate of 3 percent. Similarly, the LCOE is presented in both base

- year dollars and first year of operation dollars. Using a similar methodology, the reader may generate either metric in the desired cost year basis. Exhibit 2

- 23 COE and LCOE Summary

Case COE LCOE
Base

- Year First Operational Year Base

- Year First Operational Year
2007$ (all cases) 2010$ ( NGCC cases) 2012$ (coal cases) 2007$ (all cases) 2010$ (NGCC cases) 2012$ (coal cases) 

## 1 76.28 N/A 88.43 96.70 N/A 112.10 2 105.66 N/A 122.49 133.94 N/A 155.27 3 74.02 N/A 85.81 93.83 N/A 108.77 4 110.39 N/A 127.97 139.93 N/A 162.22 5 81.31 N/A 94.26 103.07 N/A 119.48 6 119.46 N/A 138.49 151.43 N/A 175.55 9 59.40 N/A 68.86 75.29 N/A 87.29 10 109.69 N/A 127.16 139.05 N/A 161.20 11 58.91 N/A 68.29 74.67 N/A 86.56 12 106.63 N/A 123.61 135.16 N/A 156.69 13 58.90 64.36 N/A 7 4

. 65 8 1

. 58 N/A 14 85.93 93.89 N/A 10 8 .9 3 119. 03 N/A

2.8 IGCC STUDY COST ESTI MATES COMPARED TO IN DUSTRY ESTIMATES The estimated TO C for IGCC cases in this study ranges from $ 2,351 to $ 2,716 /kW for non

- CO 2 

## capture cases and $ 3,334 /kW to $ 3,904 /kW for capture cases. Plant size ranges from 62 2

- 6 29 MW (net) for non

- capture cases and 497

- 5 43 MW (net) for capture cases. Within the power industry there are several power producers interested in pursuing construction of an IGCC plant. While these projects are still in the relatively early stages of development, some cost estimates have been published. Published estimates t end to be limited in detail, leaving it to the reader to speculate as to what is contained within the estimate. In November 2007, the Indiana Utility Regulatory Commission approved Duke Energy’s proposal to build an IGCC plant in Edwardsport, Indiana. Th e estimated cost to build the 630 MW plant is $4,472/kW in June 2007 dollars. Duke expects the plant to begin operation in 2012. Other published estimates for similar proposed non

- CO 2 

## capture gasification plants range from $2,483/kW to $3,122/kW in June 2007 dollars. Corresponding plant sizes range form 770

- 600

### Cost and Performance Baseline for Fossil Energy Plants

64 

## MW , respectively. Published estimates from similar CO 2 

## capture facilities range from $4,581/kW to $5,408/kW, in June 2007 dollars, with sizes ranging from 400 to 580 MW [ 38 , 39 , 40 , 41 ]

. 9



## Project Scope Difference s in Cost Estimates

For this report, the scope of work is generally limited to work inside the project “fence line”. For outgoing power, the scope stops at the high side terminals of the Generator Step

- up Transformers (GSUs). Some typical examples of items outside the fenceline include:

**•** New access roads and railroad tracks

**•** Upgrades to existing roads to accommodate increased traffic

**•** Makeup water pipe outside the fenceline

**•** Landfill for on

- site waste (slag) disposal

**•** Natural gas line for backup fuel provisions

**•** Plant switchyard

**•** Electrical transmission lines & substation Estimates in this report are based on a generic mid

- western greenfield site having “normal” characteristics. Accordingly, the estimates do not address items such as:

**•** Piles or cai ssons
**•** Rock removal

**•** Excessive dewatering

**•** Expansive soil considerations

**•** Excessive seismic considerations

**•** Extreme temperature considerations

**•** Hazardous or contaminated soils

**•** Demolition or relocation of existing structures

**•** Leasing of offsite land for parking or laydown

**•** Busing of craft to site

**•** Costs of offsite storage This report is based on a reasonably “standard” plant. No unusual or extraordinary process equipment is included such as:

**•** Excessive water treatment equipment

**•** Air

- cooled condenser

**•** Automated coal reclaim

**•** Zero Liquid Discharge equipment

**•** SCR catalyst (IGCC cases only)

9 

### Costs were adjusted to June 2007 using the Chemical Engineering Plant Cost Index

### Cost and Performance Baseline for Fossil Energy Plants

65 

## For non

- capture cases, which are likely the most appropriate comparison against industry published estimates, this report is based on plant equipment sized for non

- capture only. None o f the equipment is sized to accommodate a future conversion to CO 2 

## capture. Labor This report is based on Merit Shop (non

- union) labor. If a project is to use Union labor, there is a strong likelihood that overall labor costs will be greater than those estimated in this report. This report is based on a 50 hour work week, with an ade quate local supply of skilled craft labor. No additional incentives such as per

- diems or bonuses have been included to attract and retain skilled craft labor. Contracting Methodology The estimates in this report are based on a competitively bid, multiple subcontract approach, often referred to as EPCM. Accordingly, the estimates do not include premiums associated with an EPC approach. It is believed that, given current market conditions, the premium charged by an EPC contractor could be as much as 30 per cent or more over an EPCM approach.

### Cost and Performance Baseline for Fossil Energy Plants

66 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

67 

## 3. Six IGCC power plant configurations were evaluated and the results are presented in this section. Each design is based on a market

- ready technology that is assume d to be commercially available to support startup. IGCC POWER PLANTS

The six cases are based on the GEE gasifier, the CoP E

- GasTM gasifier and the Shell gasifier, each with and without CO 2 

## capture. As discussed in Section 1 , the net output for the six cases varies because of the constraint imposed by the fixed GT output and the high auxiliary loads imparted by the CO 2 

## capture process. The CT is based on an advanced F

- class design. T he HRSG/steam turbine cycle varies based on the CT exhaust conditions. Steam conditions range from 12.4 MPa/5 59 °C/5 59 °C (1800 psig/ 1038 °F/10 38 °F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non

CO 2 

## capture cases and 12.4 MPa/53 4 °C/53 4 °C (1800 psig/ 993 °F/ 993 °F) to 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO 2 

## capture cases. The capture cases have a lower main and reheat steam temperature primarily because the turbine firing temperature is reduced to allow for a parts life equivalent to NGCC operation with a high

- hydrogen content fuel, which results in a lower turbine exhaust temperature. The evaluation scope included developing heat and mass balances and estimating plant performance. Equipment lists were developed for each design to support plant capital and operating cost estimates. The evaluation basis de tails, including site ambient conditions, fuel composition and environmental targets, were provided in Section 2 . Section 3.1 covers general information that is common to all IGCC cases, and case specific information is subsequently presented in Sections 3.2 , 3.3 and 3.4

. 3.1 IGCC COMMON PROCESS AREAS The IGCC cases have process areas , which are common to each plant configuration such as coal receiving and storage, oxygen supply, gas cleanup, power generation, etc. As detailed descriptions of these process areas for each case would be burdensome and repeti tious, they are presented in this section for general background information. Where there is case

- specific performance information, the performance features are presented in the relevant case sections.
3.1.1 The function of the Coal R eceiving and Storage system is to unload, convey, prepare, and store the coal delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to and including the slide gate valves at the outlet of the coal storage silos. Coal receiving and storage is identical for all six IGCC cases; however, coal preparation and feed are gasifier

- specific. Coal Receiving and Storage

Operation Description

– The coal is delivered to the site by 100

- car unit trains comprised of 91 tonne (100 ton) rail c ars. The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long

- term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iro n and then to the reclaim pile.

### Cost and Performance Baseline for Fossil Energy Plants

68 

## The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper under the pile. The feeders transfer the coal onto a belt conveyor that transfers the coal to the coal surge bin located in the crusher t ower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is routed to the tripper, which loads the coal into one of three silos. Two sampling systems are supplied: the as

- received sampling system and the as

- fired sampling system. Data from the analyses are used to support the reliable and efficient operation of the plant.
3.1.2 In order to economically and ef ficiently support IGCC projects, air separation equipment has been modified and improved in response to production requirements and the consistent need to increase single train output. “Elevated pressure” air separation designs have been implemented that result in distillation column operating pressures that are about twice as high as traditional plants. In this study, the main air compressor discharge pressure was set at 1.3 MPa (190 psia) compared to a traditional ASU plant operating pressu re of about 0 .7 MPa (105 psia) [ Air Separation Unit (ASU) Choice and Integration

42 ]

. For IGCC designs the elevated pressure ASU process minimizes power consumption and decreases the size of some of the equipment items. When the air supply to the ASU is integrated with the GT , the ASU operates at or near the supply pressure from the GT ’s air compressor.

The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been met is often compressed and sent to the GT . Since all product streams are being compressed , the ASU air feed pressure is optimized to reduce the total power consumption and to provide a good match with available compressor frame sizes. Residual Nitrogen Injection

Increasing the diluent flow to the GT by injecting residual nitrogen from the ASU can have a number of benefit s, depending on the design of the GT :

**•** Increased diluent increases mass flow through the turbine, thus increasing the power output of the GT while maintaining optimum firing temperatures for syngas operation. This is particularly beneficial for locations where the ambient temperature and/or elevation are high and the GT would normally operate at reduced output.

**•** By mixing with the syngas or by being injected directly into the combustor, the diluent nitrogen lowers the firing temperature (relative to natura l gas) and reduces the formation of thermal NOx. In this study, the ASU nitrogen product was used as the primary diluent with a design target of reducing the syngas lower heating value (LHV) to 4. 4

- 4. 7 MJ/Nm 3 

## ( 119

- 12 5 Btu/scf). If the amount of available nitrogen was not sufficient to meet this target, additional dilution was provided through syngas humidification, and if still more dilution was required, the third option was steam injection.

Integrati on between the ASU and the CT can be practiced by extracting some, or all, of the ASU’s air requirement from the GT . Medium British thermal unit ( Btu ) syngas streams result in a higher mass flow than natural gas to provide the same heat content to the GT

. Some GT designs may need to extract air to maintain stable compressor or turbine operation in response to increased fuel flow rates. Other GT s may balance air extraction against injection of all of the Air Integration

### Cost and Performance Baseline for Fossil Energy Plants

69 

## available nitrogen from the ASU. The amount of air extracted can also be varied as the ambient temperature changes at a given site to optimize year

- round performance. An important aspect of air

- integrated designs is the need to efficiently recover the heat of compression contained in the air extracted f rom the GT . Extraction air temperature is normally in the range 399

- 454°C (750

- 850°F), and must be cooled to the last stage main air compressor discharge temperature prior to admission to the ASU. High

- level recovery from the extracted air occurs by transferring heat to the nitrogen stream to be injected into the GT with a gas

- to

- gas heat exchanger.

The Buggenum, Netherlands unit built for Demkolec was the first elevated

- pressure, fully integrated ASU t o be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons per day [ TPD ] ) of 95 percent purity oxygen for a Shell coal

- based gasification unit that fuels a Siemens V94.2 GT . In normal operation at the Buggenum plant the ASU receives all of its air supply from and sends all residual nitrogen to the GT

. Elevated Pressure ASU Experience in Gasification

The Polk County, Florida ASU for the Tampa Electric IGCC is also an elevated

- pressure, 95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 TPD) of oxygen to a GEE coal

- based gasification unit, which fuels a General Electric 7FA GT . All of the nitrogen produced in the ASU is used in the GT . The original design did not allow for air extraction from the CT . After a CT air compressor failure in January, 2005, a modificati on was made to allow air extraction , which in turn eliminated a bottleneck in ASU capacity and increased overall power output [ 43 ]

.
For this study, air integration is used for the non

- carbon capture cases only. In the CO 2 

## capture cases, once the syngas is diluted to the target heating value, all of the available combustion air is required to maintain mass flow through the turbine and hence maintain power output. ASU Basis

The amount of air extracted from the GT in the non

- capture ca ses is determined through a process that includes the following constraints:

**•** The CT output must be maintained at 232 MW.

**•** The diluted syngas must meet heating value requirements specified by a CT vendor, which ranged from 4.4

- 4.7 MJ/Nm 3 

## (119

- 125 Btu/scf)

. Meeting the above constraints resulted in different levels of air extraction in the three non

- carbon capture cases as shown in Exhibit 3

- 1 . It was not a goal of this project to optimize the integration of the CT and the ASU, although several recent papers have shown that providing 25

- 30 percent of the ASU air from the turbine compressor provides the best balance between maximizing plant output and efficiency without c ompromising pla nt availability or reliability [ 44 , 45 ]

.

### Cost and Performance Baseline for Fossil Energy Plants

70 

## Exhibit 3

- 1 Air Extracted from the Combustion Turbine and Supplied to the ASU in Non

Carbon Capture Cases
Case No. 1 3 5
Gasifier GEE CoP Shell
Air Extracted from Gas Turbine, % 4.0 4.0 4.0 Air Provided to ASU, % of ASU Total 16.8 18.9 19.4 Air Separation Plant Process Description [ 46 The air separation plant is designed to produce 95 mole percent (mol%) O 2 

## for use in the gasifier. The plant is designed with two production trains, one for each gasifier. The air compressor is powered by an electric motor. Nitrogen is also recovered, compressed, and used as dilution in the GT combustor. A process schematic of a typical ASU is shown in ]

Exhibit 3

- 2

. The air feed to the ASU is supplied from two sources. A portion of the air is extracted from the compressor of the GT (non

- CO 2 

## capture cases only). The remaining air is supplied from a stand

alone compressor. Air to the stand

- alone compressor is first filtered in a suction filter upstream of the compressor. This air filter removes particulate, which may tend to cause compressor wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal compressor, with intercooling between each stage. Air from the stand

- alone compressor is combined with the extraction air, and the combined st ream is cooled and fed to an adsorbent

- based pre

- purifier system. The adsorbent removes water, CO 2 

## , and C 4 

## + saturated hydrocarbons in the air. After passing through the adsorption beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present. Downstream of the dust filter a small stream of air is withdrawn to supply the instrument air requirements of the ASU. Regeneration of the adsorbent in the pre

- purifiers is accomplished by passing a hot nitrogen stream through the of f

- stream bed(s) in a direction countercurrent to the normal airflow. The nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat exchanger. The regeneration nitrogen drives off the adsorbed contaminants. Following regen eration, the heated bed is cooled to near normal operating temperature by passing a cool nitrogen stream through the adsorbent beds. The bed is re

- pressurized with air and placed on stream so that the current on

- stream bed(s) can be regenerated. The air from the pre

- purifier is then split into three streams. About 70 percent of the air is fed directly to the cold box. About 25 percent of the air is compressed in an air booster compressor. This boosted air is then cooled in an aftercooler against coolin g water in the first stage and against chilled water in the second stage before it is fed to the cold box. The chiller utilizes low

pressure ( LP ) process steam at 0.3 MPa (50 psia) to drive the absorption refrigeration cycle . The remaining five percent o f the air is fed to a turbine

- driven, single

- stage, centrifugal booster compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it is fed to the cold box.

### Cost and Performance Baseline for Fossil Energy Plants

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## All three air feeds are cooled in the cold box to cryogenic t emperatures against returning product oxygen and nitrogen streams in plate

- and

- fin heat exchangers. The large air stream is fed directly to the first distillation column to begin the separation process. The second largest air stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the cryogenic separation process. Inside the cold box the air is separated into oxygen and nitrogen products. The oxygen product is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump. The pressurized liquid oxygen is then vaporized against the high

- pressure (HP) air feed before being warmed to ambien t temperature. The gaseous oxygen exits the cold box and is fed to the centrifugal compressor with intercooling between each stage of compression. The compressed oxygen is then fed to the gasification unit. Nitrogen is produced from the cold box at two p ressure levels. LP nitrogen is split into two streams. The majority of the LP nitrogen is compressed and fed to the GT as diluent nitrogen. A small portion of the nitrogen is used as the regeneration gas for the pre

- purifiers and recombined with the dil uent nitrogen

. A HP nitrogen stream is also produced from the cold box and is further compressed before it is also supplied to the GT

. Exhibit 3

- 2 Typical ASU Process Schematic

Air Air Filter Main Air Compressor CWS

CWR Steam Cond.
1st Stage DCA 2nd Stage DCA Prepurifiers Booster Air Compressor

Turbine Air Booster Regen Heater Steam

Cond. Regeneration Nitrogen
Regen. N2 Blower

Liq. Oxygen Pump Turbine Cryogenic Air Separation Unit

Single Train

GT Nitrogen HP Oxygen Oxygen Compressor

GT Nitrogen Compressor

Chiller Air from Gas Turbine

CWS

CWR

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## 3.1.3 Selection of Technology

- In the cases with CO 2 

## separation and capture, the gasifier product must be converted to hydrogen

- rich syngas. The first step is to convert most of the syngas CO to hydrogen (H 2 

## ) and CO 2 

## by reacting the CO with water over a bed of catalyst. The H 2 

## O:CO molar ratio in the shift reaction, shown below, is adjusted to approximately 2: 1 by the addition of steam to the syngas stream thus promoting a high conversion of CO. In the cases without CO 2 

## separation and capture, CO shift conver tors are not required. Water Gas Shift Reactors

Water Gas Shift: CO + H 2 

## O ↔ CO 2 

## + H 2 

## The CO shift converter can be located either upstream of the AGR step ( SGS ) or immediately downstream (sweet gas shift). If the CO converter is located downstream of the AGR , then the metallur gy of the unit is less stringent but additional equipment must be added to the process. Products from the gasifier are humidified with steam or water and contain a portion of the water vapor necessary to meet the water

- to

- gas criteria at the reactor inlet . If the CO converter is located downstream of the AGR , then the gasifier product would first have to be cooled and the free water separated and treated. Then additional steam would have to be generated and re

injected into the CO converter feed to meet the required water

- to

- gas ratio. If the CO converter is located upstream of the AGR step, no additional equipment is required. This is because the CO converter promotes carbonyl sulfide (COS) hydrolysis without a separate catalyst bed. Therefore, for th is study the CO converter was located upstream of the AGR unit and is referred to as SGS. Process Description

- The SGS consists of two paths of parallel fixed

- bed reactors arranged in series. Two reactors in series are used in each parallel path to achie ve sufficient conversion to meet the 90 percent CO 2 

## capture target. In the CoP case, a third shift reactor is added to each path to increase the CO conversion because of the relatively high amount of CH 4 

## present in the syngas
. W ith the third reactor adde d, CO 2 

## capture is 90.4 percent in the CoP case. Cooling is provided between the series of reactors to control the exothermic temperature rise. The parallel set of reactors is required due to the high gas mass flow rate. In all three CO 2 

## capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then used to adjust the syngas H 2 

## O:CO ratio to 2:1 on a molar basis. The heat exchanger after the second SGS reactor is used to raise intermediate pressure ( IP ) steam , which then passes through the reheater (RH) section of the HRSG in the GEE and CoP cases, and is used to preheat the syngas prior to the first SGS reactor in the Shell case. Approximately 9 7 percent conversion of the CO is achieved in the GEE and Shell cases, and about 98 percent conversion is achieved in the CoP case.
3.1.4 An IGCC power plant has the potential of removing mercury in a more simple and cost

- effective manner than conventional PC plants. This is because mercury can be rem oved from the syngas at elevated pressure and prior to combustion so that syngas volumes are much smaller than FG volumes in comparable PC cases. A conceptual design for a n activated , sulfur

- impregnated, carbon bed adsorption system was developed for merc ury control in the IGCC plants being studied. Data on the performance of carbon bed systems were obtained from the Eastman Chemical Company, which uses carbon beds at its syngas facility in Kingsport, Tennessee [ Mercury Removal

13 ]

.

### Cost and Performance Baseline for Fossil Energy Plants

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## The coal mercury content (0.15 ppm dry) and carbon bed removal efficiency (95 percent) were discussed previously in Section 2.4. IGCC

- specific design considerations are discussed below. Carbon Bed Lo cation

– The packed carbon bed vessels are located upstream of the sulfur recovery unit (SRU) and syngas enters at a temperature near 38°C (100°F). Consideration was given to locating the beds further upstream before the COS hydrolysis unit (in non

- CO 2 

## ca pture cases) at a temperature near 204°C (400°F). However, while the mercury removal efficiency of carbon has been found to be relatively insensitive to pressure variations, temperature adversely affects the removal efficiency [ 47 13 ]

. Eastman Chemical also operates their beds ahead of their SRU at a temperature of 30°C (86°F) [ ]

. Consideration was also given to locating the beds downstream of the SRU. However, it was felt that removing the mercury and other contaminants before the SRU would enhance the performance of the SRU and increase the life of the various solvents. Process Parameters

– An empty vessel basis gas residence time of approximately 20 seconds was used based on Eastman Chemical’s experience [ 13 ]

. Allowable gas velocities are limited by considerations of particle entrainment, bed agitation, and pressure drop. One

- foot

- per - second superficial velocity is in the middle of the range normally encountered [ 47 ] and was selected for this application. The bed density of 30 lb/ft 3 

## was based on the Calgon Carbon Corporation HGR

- P sulfur

impregnated pelletized activated carbon [ 48

Carbon Replacement Time

– Eastman Chemicals replaces its bed every 18 to 24 months [ ]

. These parameters determined the size of the vessels an d the amount of carbon required. Each gasifier train has one mercury removal bed and there are two gasifier trains in each IGCC case, resulting in two carbon beds per case. 13 ]

. However, bed replacement is not because of mercury loading, but for other reasons including:

**•** A buildup in pressure drop

**•** A buildup of water in the bed

**•** A buildup of other contaminants For this study a 24 month carbon replacement cycle was assumed. Under these assumptions, the mercury loading in the bed would build up to 0.6

- 1.1 weight percent (wt%). Mercury capacity of sulfur

- impregnated carbon can b e a s high as 20 wt% [ 49

3.1.5 ]

. The mercury laden carbon is considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.

Gasification of coal to generate power produces a syngas that must be treated prior to further utilization. A portion of the treatment consists of AGR and sulfur recovery. The environmental target for these IGCC cases is 0.0128 lb SO 2 

## /MMBtu, which requires that the total sulfur content of the syngas be reduced to less t han 30 ppmv. This includes all sulfur species, but in particular the total of COS and H 2 

## S, thereby resulting in stack gas emissions of less than 4 ppmv SO 2 

## . Acid Gas Removal (AGR) Process Selection

The use of COS hydrolysis pretreatment in the feed to the AGR process provides a me ans to reduce the COS concentration. This method was first commercially proven at the Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC projects. Several COS Hydrolysis

### Cost and Performance Baseline for Fossil Energy Plants

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## catalyst manufacturers including Haldor Topsoe and Porocel offer a catalyst that promotes the COS hydrolysis reaction. The non

- carbon capture COS hydrolysis reactor designs are based on information from Porocel. In cases with CO 2 

## capture, the SGS reactors reduce COS to H 2 

## S as discussed in Section 3.1.3

. The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction. The reaction is represented as follows. COS + H 2 

## O ↔ CO 2 

## + H 2 

## S Since t he reaction is exothermic, higher conversion is achieved at lower temperatures. However, at lower temperatures the reaction kinetics are slower. Based on the feed gas for this evaluation, Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS concentration is critical to the amount of H 2 

## S that must be removed with the AGR process, a retention time of 50

- 75 seconds was used to achieve 99.5 percent conversion of the COS. The Porocel activated alumina

- based catalyst, desig nated as Hydrocel 640 catalyst, promotes the COS hydrolysis reaction without promoting reaction of H 2 

## S and CO to form COS and H 2 

## . Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of
non - reacting components. Th erefore, the reaction is essentially isothermal. The product gas, now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal process and the AGR.

H 2 

## S removal generally consists of absorption by a regenerable sol vent. The most commonly used technique is based on countercurrent contact with the solvent. Acid

- gas - rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cool ed and recirculated to the top of the absorber, completing the cycle. Sulfur Removal

Exhibit 3

- 3 is a simplif ied diagram of the AGR process [ 50 There are well over 30 AGR processe s in common commercial use throughout the oil, chemical, and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and planned gasifiers shows that only six AGR processes are represented: Rectisol, Sulfinol, MDEA, Selexol, aqueous di

- isoprop onal (ADIP) amine , and FLEXSORB [ ]

.

52 ]

. These processes can be separated into three general types: chemical reagents, p hysical solvents, and hybrid solvents.

### Cost and Performance Baseline for Fossil Energy Plants

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## Exhibit 3

- 3 Flow Diagram for a Conventional AGR Unit

Frequently used for AGR , chemical solvents are more suitable than physical or hybrid solvents for applications at lower operating pressures. The chemical nature of acid gas absorption makes solution loading and circulation less dependent on the acid gas partial pressure. Because the solution is aqueous, co

- absorption of hydrocarbons is minimal. In a conventional amine unit, the chemical solvent reacts exothermically with the acid gas constituents. They form a weak chemical bond that can be broken, releasing the acid gas and regenerating the solvent for reuse. Chemical Solvents

In recent years MDEA, a tertiary ami ne, has acquired a much larger share of the gas

- treating market. Compared with primary and secondary amines, MDEA has superior capabilities for selectively removing H 2 

## S in the presence of CO 2 

## , is resistant to degradation by organic sulfur compounds, has a low tendency for corrosion, has a relatively low circulation rate, and consumes less energy. Commercially available are several MDEA

- based solvents that are formulated for high H 2 

## S selectivity. Chemical reagents are used to remove the acid gases by a rev ersible chemical reaction of the acid gases with an aqueous solution of various alkanolamines or alkaline salts in water. Exhibit 3

- 4 lists commonly used chemical reagents along with principal licensors that use them in their processes. The process consists of an absorber and regenerator, which are connected by a circulation of the chemical reagent aqueous solution. The absorber contacts the lean sol ution with the main gas stream (at pressure) to remove the acid gases by absorption/ reaction with the chemical solution. The acid

- gas - rich solution is reduced to LP and heated in the stripper to reverse the reactions and strip the acid gas. The acid

- gas - lean solution leaves the bottom of the regenerator stripper and is cooled, pumped to the required pressure and recirculated back to the absorber. For some amines, a filter and a separate reclaiming section (not shown) are needed to remove undesirable rea ction byproducts. Treated

Gas

Cooler

Lean Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Feed Gas Treated Gas

Cooler

Lean Solvent L/R Exchanger

Rich Solvent Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Feed Gas

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## Exhibit 3

- 4 Common Chemical Reagents Used in AGR Processes Chemical Reagent Acronym Process Licensors Using the Reagent Monoethanolamine MEA Dow, Exxon, Lurgi, Union Carbide Diethanolamine DEA Elf, Lurgi Diglycolamine DGA Texaco, Fluor Triethanolamine TEA AMOCO Diisopropanolamine DIPA Shell Methyldiethanolamine MDEA BASF, Dow, Elf, Snamprogetti, Shell, Union Carbide, Coastal Chemical Hindered amine Exxon
Potassium carbonate “hot pot” Eickmeyer, Exxon, Lurgi, Union Carbide Typically, the absorber temperature is 27 to 49°C (80 to 120°F) for amine processes, and the regeneration temperature is the boiling point of the solutions, generally 104 to 127°C (220 to 260°F). The liquid circulation rates can vary widely, depending on the amount of acid gas being captured. However, the most suitable processes are those that will dissolve 2 to 10 standard cubic feet ( scf ) acid gas per gallon of solution circulated. Steam consu mption can vary widely also: 0.7 to 1.5 pounds per gallon (lb/gal) of liquid is typical, with 0.8 to 0.9 being a typical “good” value. CoP non

- capture , which utilizes the chemical solvent MDEA, uses 0.88 pounds of steam per gallon of liquid. The steam c onditions are 0.45 MPa (65 psia) and 151°C (304°F). The major advantage of these systems is the ability to remove acid gas to low levels at low to moderate H 2 

## S partial pressures.

Physical solvents involve absorption of acid gases into certain organic solvents that have a high solubility for acid gases. As the name implies, physical solvents involve only the physical solution of acid gas

– the acid gas loading in the solvent is pro portional to the acid gas partial pressure (Henry’s Law). Physical solvent absorbers are usually operated at lower temperatures than is the case for chemical solvents. The solution step occurs at HP and at or below ambient temperature while the regenerat ion step (dissolution) occurs by pressure letdown and indirect stripping with LP 0.45 MPa (65 psia) steam. It is generally accepted that physical solvents become increasingly economical, and eventually superior to amine capture, as the partial pressure of acid gas in the syngas increases. Physical Solvents

The physical solvents are regenerated by multistage flashing to LPs . Because the solubility of acid gases increases as the temperature decreases, absorption is generally carried out at lower temperatures, and refrigerati on is often required. Most physical solvents are capable of removing organic sulfur compounds. Exhibiting higher solubility of H 2 

## S than CO 2 

## , they can be designed for selective H 2 

## S or total AGR . In applications where CO 2 

## capture is desired the CO 2 

## is flashed off at various pressures, which reduces the compression work and parasitic power load associated with sequestration.

### Cost and Performance Baseline for Fossil Energy Plants

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## Physical solvents co

- absorb heavy hydrocarbons from the feed stream. Since heavy hydrocarbons cannot be recovered by flash reg eneration, they are stripped along with the acid gas during heated regeneration. These hydrocarbon losses result in a loss of valuable product and may lead to CO 2 

## contamination. Several physical solvents that use anhydrous organic solvents have been com mercialized. They include the Selexol process, which uses dimethyl ether of polyethylene glycol as a solvent; Rectisol, with methanol as the solvent; Purisol, which uses N

- methyl

- 2

- pyrrolidone (NMP) as a solvent; and the propylene

- carbonate process. Exhibit 3

- 5 is a simplified flow diagram for a physical reagent type AGR process [ 50 ]

. Common physical solvent processes, along with their licensors, are listed in Exhibit 3

- 6

. Exhibit 3

- 5 Ph ysical Solvent AGR Process Simplified Flow Diagram

Hybrid solvents combine the high treated

- gas purity offered by chemical solvents with the flash regeneration and lower energy requirements of physical solvents. Some examples of hybrid
s olvents are Sulfinol, Flexsorb PS, and Ucarsol LE. Hybrid Solvents

Sulfinol is a mixture of sulfolane (a physical solvent), diisopropanolamine (DIPA) or MDEA (chemical solvent), and water. DIPA is used when total AGR is specified, while MDEA provides for selective removal of H 2 

## S. Treated

Gas

Cooler

Lean Solvent L/R Exchanger Rich Solvent

Feed Gas Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Flash Gas Treated

Gas

Cooler

Lean Solvent L/R Exchanger Rich Solvent

Feed Gas Absorber

Lean Solvent Pump Reboiler Stripper Acid Gas Condenser

Flash Gas

### Cost and Performance Baseline for Fossil Energy Plants

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## Exhibit 3

- 6 Common Physical Solvents Used in AGR Processes

Solvent Solvent/Process Trade Name Process Licensors Dimethyl ether of poly

ethylene glycol Selexol UOP

Methanol Rectisol Linde AG and Lurgi Methanol and toluene Rectisol II Linde AG N

— methyl pyrrolidone Purisol Lurgi Polyethylene glycol and dialkyl ethers Sepasolv MPE BASF Propylene carbonate Fluor Solvent Fluor Tetrahydrothiophenedioxide Sulfolane Shell Tributyl phosphate Estasolvan Uhde and IFP Flexsorb PS is a mixture of a hindered amine and an organic solvent. Physically similar to Sulfinol, Flexsorb PS is very stable and resistant to chemical degradation. High treated

- gas purity, with less than 50 ppmv of CO 2 

## and 4 ppmv of H 2 

## S, can be achieved. Both Ucarsol LE

701, for selective removal, and LE

- 702, for total AGR , are formulated to remove mercaptans from feed gas. Mixed chemical and physical solvents comb ine the features of both systems. The mixed solvent allows the solution to absorb an appreciable amount of gas at HP . The amine portion is effective as a reagent to remove the acid gas to low levels when high purity is desired. Mixed solvent processes ge nerally operate at absorber temperatures similar to those of the amine

- type chemical solvents and do not require refrigeration. They also retain some advantages of the lower steam requirements typical of the physical solvents. Common mixed chemical and p hysical solvent processes, along with their licensors, are listed in Exhibit 3

- 7 . The key advantage of mixed solvent processes is their apparent ability to remove H 2 

## S and, in some cases, COS to meet very stringent purified gas specifications. Exhibit 3

- 8 shows reported equilibrium solubility data for H 2 

## S and CO 2 

## in various representative solvents [ 50 ]

. The solubility is expressed as scf of gas per gallon liquid per atmosphere gas partial pressure. The figure illustrates the relative solubilities of CO 2 

## and H 2 

## S in different solvents and the effects of temperature. More importantly, it shows an order of magnitude higher solubility of H 2 

## S over CO 2 

## at a given temperature, which gives rise to the selective absorption of H 2 

## S in physical solvents. It also illustrates that the acid gas solubility in physical solvents increases with lower solvent temperature s.

### Cost and Performance Baseline for Fossil Energy Plants

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## Exhibit 3

- 7 Common Mixed Solvents Used in AGR Processes Solvent/Chemical Reagent Solvent/Process Trade Name Process Licensors Methanol/MDEA or diethylamine Amisol Lurgi
Sulfolane/MDEA or DIPA Sulfinol Shell Methanol and toluene Selefining Snamprogetti (Unspecified) /MDEA FLEXSORB PS Exxon

Exhibit 3

- 8 Equilibrium Solubility Data on H 2 

## S and CO 2 

## in Various Solvents

### Cost and Performance Baseline for Fossil Energy Plants

80 

## The ability of a process to selectively absorb H 2 

## S may be further enhanced by the relative absorption rates of H 2 

## S and CO 2 

## . Thus, some processes, besides using equilibrium solubility differences, will use absorption rate differences between the two acid gases to achieve selectivity. This is particularly true of the amine processes where the CO 2 

## and H 2 

## S absorption rates are very different.

A two

- stage Selexol process is used for all IGCC CO 2 

## capture cases in this study. A brief process description follo ws. AGR used in CO 2 

## Capture Cases

Untreated syngas enters the first of two absorbers where H 2 

## S is preferentially removed using loaded solvent from the CO 2 

## absorber. The gas exiting the H 2 

## S absorber passes through the second absorber where CO 2 

## is removed using first flash regenerated, chilled solvent followed by thermally regenerated solvent added near the top of the column. The treated gas exits the absorber and is sent either directly to the CT or is partially humidified prior to entering the CT

. A portion of the gas can also be use d for coal drying, when required. The amount of hydrogen recovered from the syngas stream is dependent on the Selexol process design conditions. In this study, hydrogen recovery is 99.4 percent. The minimal hydrogen slip to the CO 2 

## sequestration stream m aximizes the overall plant efficiency. The Selexol plant cost estimates are based on a plant designed to recover thi s high percentage of hydrogen. The CO 2 

## loaded solvent exits the CO 2 

## absorber , and a portion is sent to the H 2 

## S absorber, a portion is sent to a reabsorber and the remainder is sent to a series of flash drums for regeneration. The CO 2 

## product stream is obtained from the three flash drums, and after flash regeneration the solvent is chilled and returned to the CO 2 

## absorber. The rich solvent ex iting the H 2 

## S absorber is combined with the rich solvent from the reabsorber and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent enters the H 2 

## S concentrator and partially flashes. The remaining liquid contact s nitrogen from the ASU and a portion of the CO 2 

## along with lesser amounts of H 2 

## S and COS are stripped from the rich solvent. The stripped gases from the H 2 

## S concentrator are sent to the reabsorber where the H 2 

## S and COS that were co

- stripped in the concen trator are transferred to a stream of loaded solvent from the CO 2 

## absorber. The clean gas from the reabsorber is combined with the clean gas from the H 2 

## S absorber and sent to the CT

. The solvent exiting the H 2 

## S concentrator is sent to the stripper where t he absorbed gases are liberated by hot gases flowing up the column from the steam heated reboiler. Water in the overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported as necessary to maintain the proper water cont ent of the lean solvent. The acid gas from the stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is first cooled by providing heat to the rich solvent, then further cooled by exchange with the product gas a nd finally chilled in the lean chiller before returning to the top of the CO 2 

## absorber.

There are numerous commercial AGR processes that could meet the sulfur environmental target of this study. The most frequently used AGR systems (Selexol, Sulfinol, MDEA, and Rectisol) have all been used with the Shell and GE E gasifiers in various applications. Both existing E

- Gas gasifiers use MDEA, but could in theory use any o f the existing AGR technologies [ AGR/Gasifier Pairings

50 ]

. The following selections were made for the AGR process in non

- CO 2 

## capture cases:

### Cost and Performance Baseline for Fossil Energy Plants

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## • GE E gasifier: Selexol was chosen based on the GE gasifier operating at the highest pressure (815 psia versus 6 15 psia for CoP and Shell) , which favors the physical solvent used in the Selexol process.

**•** CoP gasifier: Refrigerated MDEA was chosen because the two operating E

- Gas gasifiers use MDEA and because CoP lists MDEA as the selected AGR process on their websit e [ 51

**•** Shell gasifier: The Sulfinol process was chosen for this case because it is a Shell owned technology. While the Shell gasifier can and has been used with other AGR processes, it was concluded the most likely pairing would be with the Sulfinol process. ]

. Refrigerated MDEA was chosen over conventional MDEA because the sulfur emissions environmental target chosen is just outside of the range of conventional (higher temperature) MDEA.

The two

- stage Selexol process is used in all three cases that req uire CO 2 

## capture. According to the previously referenced SFA Pacific report, “For future IGCC with CO 2 

## removal for sequestration, a two

- stage Selexol process presently appears to be the preferred AGR process

– as indicated by ongoing engineering studies a t EPRI and various engineer ing firms with IGCC interests.” [ 52 ]
3.1.6 Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. The Claus process remains the mainstay for sulfur recovery. Conventional three

- stage Claus plants, with indirect reheat and feeds with a high H 2 

## S content, can approach 98 percent sulfur recovery efficiency. However, since environmental regulations have become more stringent, sulfur recovery plan ts are required to recover sulfur with over 99.8 percent efficiency. To meet these stricter regulations, the Claus process underwent various modifications and add

- ons. Sulfur Recovery/Tail Gas Cleanup Process Selection

The add

- on modification to the Claus plant selected for this study can be considered a separate option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU) process.
The Claus process converts H 2 

## S to elemental sulfur via the following reactions: The Claus Process

H 2 

## S + 3/2 O 2 

## ↔ H 2 

## O + SO 2 

## 2H 2 

## S + SO 2 

## ↔ 2H 2 

## O + 3S The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is: 3H 2 

## S + 3/2 O 2 

## ↔ 3H 2 

## O + 3S The sulfur in the vapor phase exists as S 2 

## , S 6 

## , and S 8 

## molecular species, with the S 2 

## predominant at higher temperatures, and S 8 

## pr edominant at lower temperatures. A simplified process flow diagram of a typical three

- stage Claus plant is shown in Exhibit 3

- 9 [ 52 ]

. One

- third of the H 2 

## S is burned in the furnace with oxygen from the air to give sufficient SO 2 

## to react with the remaining H 2 

## S. Since these reactions are highly exothermic, a waste heat boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is condensed in a condenser that follows the HP steam recovery section. LP steam is raised in the condenser. The tail gas from the first condenser then goes to seve ral catalytic conversion stages,

### Cost and Performance Baseline for Fossil Energy Plants

82 

## usually 2 to 3, where the remaining sulfur is recovered via the Claus reaction. Each catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid sulfur goes to the sulfur pit, while th e tail gas proceeds to the incinerator or for further processing in a TGTU.

The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent. Typical furnace temperatures are in the range from 1093 to 1427°C (2000 to 2600°F), and as the temperature decreases, conversion increases dramatically. Claus Plant Sulfur Recovery Efficiency

Exhibit 3

- 9 Typical Three

- Stage Claus Sulfur Plant

Claus plant sulfur recovery efficiency depends on many factors:

**•** H 2 

## S concentration of the feed gas

**•** Number of catalytic stages

**•** Gas reheat method In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases that contain about 20 to 50 percent H 2 

## S, a split

- flow design is often used. In this version of the Claus plant, part of the feed gas is bypassed around the furnace to the first catalytic stage, while the rest of the gas is oxidized in the furnace to mostly SO 2 

## . This results in a more stable temperature in the furnace.

Large diluent streams in the feed to the Claus plant, such as N 2 

## from combustion air, or a high CO 2 

## content in the feed gas, le ad to higher cost Claus processes and any add

- on or tail gas units. Oxygen

- Blown Claus

### Cost and Performance Baseline for Fossil Energy Plants

83 

## One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the furnace for dilute H 2 

## S streams is the oxygen

- blown Claus process. The oxygen

- blown Claus p rocess was originally developed to increase capacity at existing conventional Claus plants and to increase flame temperatures of low H 2 

## S content gases. The process has also been used to provide the capacity and operating flexibility for sulfur plants where the feed gas is variable in flow and composition such as often found in refineries. The application of the process has now been extended to grass roots installations, even for rich H 2 

## S feed streams, to provide operating flexibility at lower costs th an would be the case for conventional Claus units. At least four of the recently built gasification plants in Europe use oxygen enriched Claus units. Oxygen enrichment results in higher temperatures in the front

- end furnace, potentially reaching temperatu res as high as 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to 70 vol % O 2 

## in the oxidant feed stream. Although oxygen enrichment has many benefits, its primary benefit for lean H 2 

## S feeds is a stable furnace temperature. Sulfur recove ry is not significantly enhanced by oxygen enrichment. Because the IGCC process already requires an ASU, the oxygen

- blown Claus plant was chosen for all cases.

In many refinery and other conventional Claus applications, tail gas treating involves the removal of the remaining sulfur compounds from gases exiting the SRU . Tail gas from a typical Claus process, whether a conventional Claus or one of the extended versions of the process, usually contains small but varying quantities of COS, C S 2 

## , H 2 

## S, SO 2 

## , and elemental sulfur vapors. In addition, there may be H 2 

## , CO, and CO 2 

## in the tail gas. In order to remove the rest of the sulfur compounds from the tail gas, all of the sulfur

- bearing species must first be converted to H 2 

## S. Then, the resu lting H 2 

## S is absorbed into a solvent and the clean gas vented or recycled for further processing. The clean gas resulting from the hydrolysis step can undergo further cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The latter option is particularly suitable with physical absorption solvents. The approach of treating the tail gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus plant is the one used by the Shell Claus Off

- gas Treatin g (SCOT) process. With tail gas treatment, Claus plants can achieve overall removal efficiencies in excess of 99.9 percent. Tail Gas Treating

In the case of IGCC applications, the tail gas from the Claus plant can be catalytically hydrogenated and then recycled back into t he system with the choice of location being technology dependent, or it can be treated with a SCOT

- type process. In the each of the six IGCC cases the Claus plant tail gas is hydrogenated, water is separated, the tail gas is compressed and then returned t o the AGR process for further treatment.

A self

- supporting, refractory

- lined, carbon steel (CS) flare stack is typically provided to combust and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all six IGCC cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This flare stack eliminates the need for a separate Claus plant flare. Flare Stack

### Cost and Performance Baseline for Fossil Energy Plants

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## 3.1.7 The slag handling system conveys, stores, and disposes of slag removed from the gasific ation process. Spent material drains from the gasifier bed into a water bath in the bottom of the gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into pea

sized fragments. A slag/water slurry that is between 5 a nd 10 percent solids leaves the gasifier pressure boundary through either a proprietary pressure letdown device (CoP) or through the use of lockhoppers (GEE and Shell) to a series of dewatering bins. Slag Handling

The general aspects of slag handling are the same for al l three technologies. The slag is dewatered, the water is clarified and recycled and the dried slag is transferred to a storage area for disposal. The specifics of slag handling vary among the gasification technologies regarding how the water is separate d and the end uses of the water recycle streams. In this study the slag bins were sized for a nominal holdup capacity of 72 hours of full

- load operation. At periodic intervals, a convoy of slag

- hauling trucks will transit the unloading station underneath the hopper and remove a quantity of slag for disposal. Approximately ten truckloads per day are required to remove the total quantity of slag produced by the plant operating at nominal rated power. While the slag is suitable for use as a component of roa d paving mixtures, it was assumed in this study that the slag would be landfilled at a specified cost just as the ash from the PC boiler cases is assumed to be landfilled at the same per ton cost.
3.1.8 Power Island

The GT generator selected for this application is representative of the advanced F Class turbines. This machine is an axial flow, single spool, and constant speed unit, with variable inlet guide
vane (IGV) . The turbine includes advanced bucket cooling techniques, compressor aerod ynamic design and advanced alloys, enabling a higher firing temperature than the previous generation machines. The standard production version of this machine is fired with natural gas and is also commercially offered for use with IGCC derived syngas, alt hough only earlier versions of the turbine are currently operating on syngas. For the purposes of this study, it was assumed that the advanced F Class turbine will be commercial ly available for use on both conventional and high hydrogen content syngas rep resentative of the cases with CO 2 

## capture. High H 2 

## fuel combustion issues like flame stability, flashback , and NOx formation were assumed to be solved in the time frame needed to support deployment. However, because these are FOAK applications, process
c ontingencies were included in the cost estimates as described in Section 2.7. Performance typical of an advanced F class turbine on natural gas at ISO conditions is presented in Combustion Turbine

Exhibit 3

- 10

.

### Cost and Performance Baseline for Fossil Energy Plants

85 

## Exhibit 3

- 10 Advanced F Class Combustion Turbine Performance Characteristics Using Natural Gas Advanced F Class Firing Temperature Class, °C ( **°** F) 1371+ (2500+) Airflow, kg/s (lb/s) 431 (950) Pressure Ratio 18.5 NOx Emissions, ppmv 25 Simple Cycle Output, MW 185 Combined cycle performance Net Output, MW 280 Net Efficiency (LHV), % 57.5 Net Heat Rate (LHV), kJ/kWh (Btu/kWh) 6,256 (5,934)

In this service, with syngas from an IGCC plant, the machine requires some modifications to the burner and turbine nozzles in order to properly combust the low

- Btu gas and expand the combustion products in the turbine section of the machine. The modifications to the machine include some redesign of the original can

- annular combustors. A second modification involves increasing the nozzle areas of the turbine to accommodate the mass and volume flow of low

- Btu fuel gas combustion products, which are increased relative to those produced when firing natural gas. Other modifications include rearranging the various auxiliary skids that support the machine to accommodate the spatial requirements of the plant general arrangement. The generator is a standard hydrogen

- cooled machine with stat ic exciter.

The CT is typically supplied in several fully shop

- fabricated modules, complete with all mechanical, electrical , and control systems as required for CT operation. Site CT installation involves module inter

- connection, and linking CT modules to the plant systems. Combustion Turbine Package Scope of Supply

A GT when fired on LCV syngas has the potential to increase power output due to the increase in flow rate through the turbine. The higher turbine flow and moisture content of the combustion products can contribute to overheating of turbine components, affect rating criteria for the parts lives, and require a reduction in syngas firing temperatures (compared to the natural gas fi ring) to mai ntain design metal temperature [ CT Firing Temperature Control Issue for Low Calorific Value Fuel

53 ]

. Uncontrolled syngas firing temperature could result in more than 50 percent life cycle reduction of stage 1 buckets. Control systems for syngas applications include provisions to compensate for these effects by maintaining virtually constant generation output for the range of the specified ambient conditions. IGV s and firing temperature are used to maintain the turbine output at the maximum torque rating, producing a flat rating up to the IGV full open position. Beyond the IGV full open position, flat output may be extended to higher ambient air temperatures by steam/nitrogen injection.

### Cost and Performance Baseline for Fossil Energy Plants

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## In this study the firing temperature (defined as inlet rotor temperature) using natural gas in NGCC applications is 13 71 °C (25 0 0°F) while the firing temperature in the n on - capture IGCC cases is 13 3 3

- 1343 °C ( 2432

- 2449 °F) and in the CO 2 

## capture cases is 131 7

- 132 2 °C ( 2402

- 2412 °F). The further reduction in firing temperature in the CO 2 

## capture cases is done to maintain parts life as the H 2 

## O content of the combustion products increases from 6

- 9 vol% in the
non - capture cases to 1 2

- 1 4 vol% in the capture cases. The decrease in temperature also results in the lower temperature steam cycle in the CO 2 

## capture cases , ranging from 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) to 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO 2 

## capture cases versus 12.4 MPa/559°C/559°C (1800 psig/1038°F/1038°F) to 12.4 MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non

CO 2 

## capture cases

.
Typical fuel specifications and contaminant levels for successful CT operation are provided in reference [ Combustion Turbine Syngas Fuel Requireme nts

54 Exhibit 3

- 11 ] and presented for F Class machines in and Exhibit 3

- 12 . The vast majority of published CT performance information is specific to natural gas operation. Turbine performance using syngas requires vendor i nput as was obtained for this study. Exhibit 3

- 11 Typical Fuel Specification for F

- Class Machines
Max Min LHV, kJ/m 3 

## (Btu/scf) None 3.0 (100) Gas Fuel Pressure, MPa (psia) 3.1 (450)
Gas Fuel Temperature, °C ( **°** F) (1) Varies with gas pressure (2) Flammability Limit Ratio, Rich

- to

- Lean, Volume Basis (3) 2:2.1
Sulfur (4)

Notes:

1. The maximum fuel temperature is defined in reference [ 55 2. To ensure that the fuel gas supply to the GT is 100 percent free of liquids the minimum fuel gas temperature must meet the required superheat over the respective dew point. This requirement is independent of the hydrocarbon and moisture concentration. Superheat calculation shall be performed as de scribed in GEI

- 4140G [ ]

54 ]

. 3. Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly larger than those of nat ural gas may require start

- up fuel 4. The quantity of sulfur in syngas is not limited by specification. Experience has shown that fuel sulfur levels up to one percent by volume do not significantly affect oxidation/corrosion rates.

### Cost and Performance Baseline for Fossil Energy Plants

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## Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 16:1. This pressure ratio was vendor specified and less than the 18.5:1 ratio used in natural gas applications. The majority of compressor discharge air remains on

- board the machine and passes to the burner section to support combustion of the syngas. Compressed air is also used in burner, transition, and film cooling services. About 4

- 7 percent of the compressor air is extracted and integrated with the air supply of the ASU in non

- carbon capture cases. It may be technically possible to integrate the CT and ASU in CO 2 

## capture cases as well; however, in this study integration was considered only for non

- carbon capture cases. Normal Operation

Exhibit 3

- 12 Allowable Gas Fuel Contaminant Level for F

- Class Machines

Turbine Inlet Limit, ppbw Fuel Limit, ppmw
Turbine Inlet Flow/Fuel Flow

50 12 4
Lead 20 1.0 0.240 .080
Vanadium 10 0.5 0.120 0.040
Calcium 40 2.0 0.480 0.160 Magnesium 40 2.0 0.480 0.160
Sodium + Potassium Na/K = 28 (1) 20 1.0 0.240 0.080
Na/K = 3 10 0.5 0.120 0.40
Na/K ≤ 1 6 0.3 0.072 0.024 Particulates Total (2) 600 30 7.2 2.4
Above 10 microns 6 0.3 0.072 0.024
Notes: 1. Na/K=28 is nominal sea salt ratio 2. The fuel gas delivery system shall be designed to prevent generation or admittance of solid particulate to the GT gas fuel system Pressurized syngas is combusted in several (14) parallel diffusion combustors and syngas dilution is used to limit NOx formation. As described in Section 3.1.2 nitrogen from the ASU is used as the primary diluent followed by syngas humidification and finally by steam dilution, if necessary, to achieve an LHV of 4.4

- 4.7 MJ/Nm 3 

## (119

- 125 Btu/scf) . The advantages of using nitrogen as the primary diluent include:

### Cost and Performance Baseline for Fossil Energy Plants

88 

## • Nitrogen from the ASU is already partially compressed and using it for dilution eliminates wasting the compression energ y.

**•** Limiting the water content reduces the need to de

- rate firing temperature, particularly in the high

- hydrogen (CO 2 

## capture) cases. There are some disadvantages to using nitrogen as the primary diluent, and these include:

**•** There is a significant auxiliary power requirement to further compress the large nitrogen flow from the ASU pressures of 0.4 and 1.3 MPa (56 and 182 psia) to the CT pressure of 3.2 MPa (465 psia).

**•** L ow quality heat not otherwise useful for other applications can be used to preheat water fo r the syngas humidification process

.

**•** Nitrogen is not as efficient as water in limiting NOx emissions It is not clear that one dilution method provides a significant advantage over the other. However, in this study nitrogen was chosen as the primary diluen t based on suggestions by turbine industry experts during peer review of the report. Hot combustion products are expanded in the three

- stage turbine

- expander. Given the assumed ambient conditions, back

- end loss, and HRSG pressure drop, the CT exhaust temp erature is nominally 588 °C (1 090 °F) for non

- CO 2 

## capture cases and 56 2 °C ( 1044 °F) for capture cases. Gross turbine power, as measured prior to the generator terminals, is 232 MW. The CT generator is a standard hydrogen

- cooled machine with static exciter.
3.1.9 Steam Generation Island

The HRSG is a horizontal gas flow, drum

- type, multi

- pressure design that is matched to the characteristics of the GT exhaust gas when firing medium

- Btu gas. High

- temperature FG exiting the CT is conveyed through the HRSG to recover the large quantity of thermal energy that remains. Flue gas ( FG ) travels through the HRSG gas path and exits at 132°C (270°F) for all six IGCC cases. Heat Recovery Steam Generator

The HP drum produces steam at main steam pressure , while the IP drum produces process steam and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/ 3.1 MPa (1800/ 443 psia) for the HP/IP turbine sections, respectively. In addition to generating and superheating steam, the HRS G performs reheat duty for the cold/hot reheat steam for the steam turbine, provides condensate and feedwater (FW) heating, and also provides deaeration of the condensate. Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities due to temperature differences of the steam. The natural circulation HRSG provides the most cost

- effective and reliable design. The HRSG drums include moisture separators, internal baffles, and piping for FW /steam. All tubes, including economi zers, superheaters, and headers and drums, are equipped with drains. Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe work place.

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## Superheater, boiler, and economizer sections are supported by shop

- assembled structural steel. Inlet and outlet duct is provided to route the gases from the GT outlet to the HRSG inlet and the HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when appropriate. Suitable expansion joints are also included.

The steam turbine consists of an HP section, an IP section, and one double

- flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single

span, opposed

- flow casing, with the double

- flow LP section in a separate casing. The LP turbine has a last stage bucket length of 76 cm (30 in). Steam Turbine Generator and Auxiliaries

Main steam from the HRSG and gasifier i sland is combined in a header, and then passes through the stop valves and control valves and enters the turbine at either 12.4 MPa/559°C to 562°C (1800 psig/1038°F to 1043°F) for the non

- carbon capture cases, or 12.4 MPa/534°C (1800 psig/993°F to 994 °F ) f or the carbon capture cases. The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters th e IP section at 3.1 M Pa/ 558 °C to 561 °C ( 443 psig/ 1036 °F to 1041 °F) for the non

- carbon capture cases or 3.1 MPa/ 532 °C to 533 °C ( 443 psig/ 990 °F to 992 °F) for the carbon capture cases. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the LP section. The steam divides into two paths and flows through the LP sections, exhausting downward into the condenser. Turbine bearings are lubricated by a closed

- loop (CL) , water

- cooled, pressurized oil system. The oil is contained in a reservoir located below the turbine floor. During startup or unit trip an emergency oil pump mounted on the reservoir pumps the oil. When the turbine reaches 95 percent of synchronous speed, the main pump mounted on the turbine shaft p umps oil. The oil flows through water

- cooled heat exchangers prior to entering the bearings. The oil then flows through the bearings and returns by gravity to the lube oil reservoir. Turbine shafts are sealed against air in

- leakage or steam blowout using a modern positive pressure variable clearance shaft sealing design arrangement connected to a LP steam seal system. During startup, seal steam is provided from the main steam line. As the unit increases load, HP turbine gland leakage provides the seal s team. Pressure

- regulating valves control the gland header pressure and dump any excess steam to the condenser. A steam packing exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room. Any steam collected i s condensed in the packing exhauster and returned to the condensate system. The generator is a hydrogen

- cooled synchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirc ulation system using fans mounted on the generator rotor shaft. The heat absorbed by the gas is removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented from escaping at the rotor shafts by a CL oil seal system. Th e oil seal system consists of storage tank, pumps, filters, and pressure controls, all skid

- mounted. The STG is controlled by a triple

- redundant, microprocessor

- based electro

- hydraulic control system. The system provides digital control of the unit in acc ordance with programmed control

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## algorithms, color cathode ray tube ( CRT ) operator interfacing, and datalink interfaces to the balance

- of

- plant DCS, and incorporates on

- line repair capability.

The condensate system transfers condensate from the condenser hotwell to the deaerator, through the gland steam condenser, gasifier, and the low

- temperature economizer section in the HRSG. The system consists of one main condenser; two 50 percent capacity , motor

- driven, vertical condensate pumps; one gland steam condenser; and a low

- temperature tube bundle in the HRSG. Condensate is delivered to a common discharge header through separate pump discharge lines, each with a check valve and a gate valve. A c ommon minimum flow recirculation line discharging to the condenser is provided to maintain minimum flow requirements for the gland steam condenser and the condensate pumps. Condensate System

The function of the FW system is to pump the various FW streams f rom the deaerator storage tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps are provided for each of three pressure levels, HP, IP, and LP. Each pump is provided with inlet and outlet isolation valves, and outlet c heck valve. Minimum flow recirculation to prevent overheating and cavitation of the pumps during startup and low loads is provided by an automatic recirculation valve and associated piping that discharges back to the deaerator storage tank. Pneumatic flo w control valves control the recirculation flow. Feedwater System

The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or high bearing temperature. FW pump suction pressure and temperature are also monitored. In addition, the suction of each boiler feed pump is equipped with a startup strainer.

The function of the main steam system is to convey main steam generated in the synthesis gas cooler (SGC) and HRSG from the HRSG superheater outlet to the HP turbi ne stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG RH , and to the turbine reheat stop valves. Main and Reheat Steam Systems

Main steam at approximately 12.4 MPa/559°C to 562°C (1800 psig/1038°F to 1043°F) (non

CO 2 

## capture case s) or 12.4 MPa/534°C (1800 psig/993°F to 994 °F ) ( CO 2 

## capture cases) exits the HRSG superheater through a motor

- operated stop/check valve and a motor

- operated gate valve, and is routed to the HP turbine. Cold reheat steam at approximately 3.5 MPa/ 349 °C to 372°C ( 501 psia/ 661°F to 702 °F) exits the HP turbine, flows through a motor

- operated isolation gate valve, to the HRSG reheater. Hot reheat steam at approximately 3.1 MPa/558 to 561°C (443 psig/1036°F to 1041°F) for the non - carbon capture cases and 3.1 MP a/532°C to 533°C (443 psig/990°F to 992°F) for the CO 2 

## capture cases exits the HRSG RH through a motor

- operated gate valve and is routed to the IP turbines. Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for removal of condensate from the steam lines. Condensate collected in the drip pots and in low

point drains is discharged to the condenser through the drain system. Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are located ups tream of any branch connections on the main headers.

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## Safety valves are installed to comply with appropriate codes and to ensure the safety of personnel and equipment.

The circulating water system (CWS) is a closed

- cycle cooling wat er system that supplies cooling water to the condenser to condense the main turbine exhaust steam. The system also supplies cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary cooling system is a CL process that utilizes a higher quality water to remove heat from compressor intercoolers, oil coolers and other ancillary equipment and transfers that heat to the main circulating cooling water system in plate and frame heat exchangers. The heat transferred to the ci rculating water in the condenser and other applications is removed by a mechanical draft cooling tower. Circulating Water System

The system consists of two 50 percent capacity vertical CWP s, a mechanical draft evaporative cooling tower, and CS cement

- lined interconnecting piping. The pumps are single

- stage vertical pumps. The piping system is equipped with butterfly isolation valves and all required expansion joints. The cooling tower is a multi

- cell wood frame counterflow mechanical draft cooling tower. The condenser is a singl e - pass, horizontal type with divided water boxes. There are two separate circulating water circuits in each box. One

- half of the condenser can be removed from service for cleaning or for plugging tubes. This can be done during normal operation at reduce d load. The condenser is equipped with an air extraction system to evacuate the condenser steam space for removal of non

- condensable gases during steam turbine operation and to rapidly reduce the condenser pressure from atmospheric pressure before unit sta rtup and admission of steam to the condenser.

The raw water system supplies cooling tower makeup, cycle makeup, service water and potable water requirements. The water source is 50 percent from a POTW and 50 percent from groundwater. Booster pumps within the plant boundary provide the necessary pressure. Raw Water, Fire Protection, and Cycle Makeup Water Systems

The fire protection system provides water under pressure to the fire hydrants, hose stations, and fixed water suppression system within the build ings and structures. The system consists of pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, spray systems, and deluge spray systems. One motor

- operated booster pump is supplied on the intake structure of th e cooling tower with a diesel engine backup pump installed on the water inlet line. The cycle makeup water system provides high quality demineralized water for makeup to the HRSG cycle, for steam injection ahead of the WGS reactors in CO 2 

## capture cases, and for injection steam to the auxiliary boiler for control of NOx emissions, if required. The cycle makeup system consists of two 100 percent trains, each with a full

- capacity activated carbon filter, primary cation exchanger, primary anio n exchanger, mixed bed exchanger, recycle pump, and regeneration equipment. The equipment is skid

- mounted and includes a control panel and associated piping, valves, and instrumentation.

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## 3.1.10 The accessory electric plant consists of sw itchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, all required foundations, and standby equipment. Accessory Electric Plant

3.1.11 An integ rated plant

- wide distributed control system (DCS) is provided. The DCS is a redundant microprocessor

- based, functionally DCS . The control room houses an array of multiple video monitor (CRT) and keyboard units. The CRT/keyboard units are the primary int erface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to be operational and accessible 99.5 percent of the time it is required (9 9.5 percent availability). The plant equipment and the DCS are designed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are manually implemented, with operator selection of modular automation routine s available. The exception to this, and an important facet of the control system for gasification, is the critical controller system, which is a part of the license package from the gasifier supplier and is a dedicated and distinct hardware segment of the DCS. Instrumentation and Control

This critical controller system is used to control the gasification process. The partial oxidation of the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperature

and pressure

- dependent reaction. The critical con troller utilizes a redundant microprocessor executing calculations and dynamic controls at 100

- to 200

- millisecond intervals. The enhanced execution speeds as well as evolved predictive controls allow the critical controller to mitigate process upsets and maintain the reactor operation within a stable set of operating parameters.

### Cost and Performance Baseline for Fossil Energy Plants

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## 3.2 GENERAL ELECTRIC ENE RGY IGCC CASES This section contains an evaluation of plant designs for Cases 1 and 2, which are based on the GEE gasifier in the “radiant only” configuratio n. GEE off ers three design configurations: [ 56

**•** Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of water to quench the temperature to 2 89 °C (5 5 0°F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient. This configuration is examined in Section ]

8

.

**•** Radiant Only: In this configuration, the hot syngas exiting the ga sifier passes through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 677 °C (1 25 0°F), then through a water quench where the syngas is further cooled to about 2 32 °C (4 5 0°F) prior to entering the syngas scrubber. Relative to the que nch configuration, the radiant only design offers increased output, higher efficiency, improved reliability/availability, and results in the lowest COE . This configuration was chosen by GEE and Bechtel for the design of their reference plant.

**•** Radiant

- Conv ective: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1316°C (2400°F) to 760°C (1400°F), then passes over a pool of water where particulate is removed but the syngas is not q uenched, then through a convective syngas cooler where the syngas is further cooled to about 371°C (700°F) prior to entering additional heat exchangers or the scrubber. This configuration has the highest overall efficiency, but at the expense of highest c apital cost and the lowest availability. This is the configuration used at Tampa Electric’s Polk Power Station. Note that the radiant only configuration includes a water quench and, based on functionality, would be more appropriately named radiant

- quench. The term radiant only is used to distinguish it from the radiant

- convective configuration. Since radiant only is the terminology used by GEE, it will be used throughout this report. The balance of Section 3.2 is organized as follows:

**•** Gasifier Background provides information on the development and status of the GEE gasification technology.

**•** Process and System Description provides an overview of the technology opera tion as applied to Case 1. The systems that are common to all gasifiers were covered in Section 3.1 and only features that are unique to Case 1 are discussed furth er in this section.

**•** Key Assumptions is a summary of study and modeling assumptions relevant to Cases 1 and 2.

**•** Sparing Philosophy is provided for both Cases 1 and 2.

**•** Performance Results provides the main modeling results from Case 1, including the performance summary, environmental performance, carbon balance, sulfur balance, water balance, mass and energy balance diagrams , and mass and energy balance tables.

**•** Equipment List provides an itemized list of major equipment for Case 1 with account codes t hat correspond to the cost accounts in the Cost Estimates section.

### Cost and Performance Baseline for Fossil Energy Plants

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## • Cost Estimates provides a summary of capital and operating costs for Case 1.

**•** Process and System Description, Performance Results, Equipment List and Cost Estimates are repeated for Case 2.
3.2.1 Development and Current Status [ Gasifier Background 57

The oil price increases and supply disruptions of the 1970s renewed interest in the Texaco partial

- oxidation process for gasification of coal or other solid opportunity fuels. Three 14 tonne/day (15 TPD) pilot plants at the Montebello laboratories have been used to test numerous coals. Two larger pilot plants were also built. The first gasified 150 tonne/day (165 TPD) of coal and was built to t est syngas generation by Rührchemie and Rührkohle at Oberhausen, Germany, and included a SGC . The second gasified 172 tonne/day (190 TPD) of coal using a quench

- only gasifier cooler and was built to make hydrogen at an existing TVA ammonia plant at Muscle Shoals, Alabama. These two large

- scale pilot plants successfully operated for several years during the 1980s and tested a number of process variables and numerous coals. ]

– Initial development of the GEE gasification technology (formerly licensed by Texaco and then ChevronTexaco) was conducted in the 1940s at Texaco’s Montebello, California laboratories. From 1946 to 19 54 the Montebello pilot plant produced syngas (hydrogen and carbon monoxide) by partial oxidation of a variety of feedstocks, including natural gas, oil, asphalt, coal tar, and coal. From 1956 to 1958, coal was gasified in a 91 tonne/day (100 TPD) Texaco coal gasifier at the Olin Mathieson Chemical Plant in Morgantown, West Virginia, for the production of ammonia.

The first commercial Texaco coal gasification plant was built for Tennessee Eastman at Kingsport, Tennessee, and started up in 1983. To date, 24 gasifiers have been built in 12 plants for coal and petroleum coke. Several of the plants require a hydrogen

- rich gas and therefore directly water quench the raw gas to add the water for shifti ng the CO to H 2 

## , and have no SGC s. The Cool Water plant was the first commercial

- scale Texaco coal gasification project for the electric utility industry. This facility gasified 907 tonne/day (1,000 TPD) (dry basis) of bituminous coal and generated 120 MW of electricity by IGCC operation. In addition, the plant was the first commercial

- sized Texaco gasifier used with a SGC . The Cool Water plant operated from 1984 to 1989 and was a success in terms of operability, availability, and environmental performan ce. The Tampa Electric IGCC Clean Coal Technology Demonstration Project built on the Cool Water experience to demonstrate the use of the Texaco coal gasification process in an IGCC plant. The plant utilizes approximately 2,268 tonne/day (2,500 TPD) of co al in a single Texaco gasifier to generate a net of approximately 250 m egawatts electric ( MW e 

## ) . The syngas is cooled in a high

- temperature radiant heat exchanger, generating HP steam, and further cooled in convective heat exchangers (the radiant

- convective configuration). The particles in the cooled gas are removed in a water

- based scrubber. The cleaned gas then enters a hydrolysis reactor where COS is converted to H 2 

## S. After additional cooling, the syngas is sent to a conventional AGR unit, where H 2 

## S is absorbed by reaction with an amine solvent. H 2 

## S is removed from the amine by steam stripping and sent to a sulfuric acid (H 2 

## SO 4 

## ) plant. The cleaned gas is sent to a General Electric MS 7001FA CT

.

### Cost and Performance Baseline for Fossil Energy Plants

95 

## The Delaware Clean Energy Project is a coke gasification and CT repowering of an existing 130 MW coke

- fired boiler cogeneration power plant at the Motiva oil refinery in Delaware City, Delaware. The Texaco coal gasification process was modified to gasify 1,814 tonne/day (2,000 TPD) of this low

- quality petroleum coke. The plant is designed to use all the fluid petroleum coke generated at Motiva’s Delaware City Plant and produce a nominal 238,136 kg/h r (525,000 lb/h r ) of 8.6 MPa (125 0 psig) steam, and 120,656 kg/h r (266,000 lb/h r ) of 1.2 MPa (175 psig) steam for export to the refinery and the use/sale of 120 MW of electrical power. Environmentally, these new facilities help satisfy tighter NO x and SO 2 

## emission limitations at the Dela ware City Plant. Gasifier Capacity

– The largest GEE gasifier is the unit at Tampa Electric, which consists of the radiant

- convective configuration. The daily coal

- handling capacity of this unit is 2,268 tonnes (2,500 tons) of bituminous coal. The dry ga s production rate is 0.19 million Nm 3 

## /h r (6.7 million scfh) with an energy content of about 1,897 million kJ/h r (HHV) (1,800 million Btu/h r ). This size matches the F Class CT s that are used at Tampa. Distinguishing Characteristics

– A key advantage of the GEE coal gasification technology is the extensive operating experience at full commercial scale. Furthermore, Tampa Electric is an IGCC power generation facility, operated by conventional electric utility staff, and is environmentally one of the cleanest coal

- fired power plants in the world. The GEE gasifier also operates at the highest pressure of the three gasifiers in this study, 5.6 MPa (815 psia) compared to 4.2 MPa (615 psia) for CoP and Shell. Entrained

- flow gasifiers have fundamental environmenta l advantages over fluidized

- bed and moving

- bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The relatively high H 2 

## /CO ratio and CO 2 

## content of GEE gasification fuel gas helps achieve low NO x and CO emissions in even the higher

- temperature advanced CT s. The key disadvantages of the GEE coal gasification technology are the limited refractory life, the relatively high oxygen requirements and high waste heat recovery duty ( SGC design). As with the other entrained

- flow slagging gasifiers, the GEE process has this disadvantage due to its high operating temperature. The disadvantage is magnified in the single

- stage, slurry feed design. The quench design significantly reduces th e capital cost of syngas cooling, while innovative heat integration maintains good overall thermal efficiency although lower than the SGC design. Another disadvantage of the GEE process is the limited ability to economically handle low

- rank coals relative to moving

- bed and fluidized

- bed gasifiers or to entrained

- flow gasifiers with dry feed. For slurry fed entrained gasifiers using low

- rank coals, developers of two

- stage slurry fed gasifiers claim advantages over single

- stage slurry fed. Important Coal Ch aracteristics

– The slurry feeding system and the recycle of process condensate water as the principal slurrying liquid make low levels of ash and soluble salts desirable coal characteristics for use in the GEE coal gasification process. High ash levels i ncrease the ratio of water

- to

- carbon in the feed slurry, thereby increasing the oxygen requirements. The slurry feeding also favors the use of high

- rank coals, such as bituminous coal, since their low inherent moisture content increases the moisture

- free solids content of the slurry and thereby reduces oxygen requirements.

### Cost and Performance Baseline for Fossil Energy Plants

96 

## 3.2.2 In this section the overall GEE gasification process is described. The system description follows the block flow diagram (BFD) in Process Description

Exhibit 3

- 1 3 and str eam numbers reference the same e xhibit. The tables in Exhibit 3

- 14 provide stream composit ions, temperature, pressure, enthalpy , and flow rates for the numbered streams in the BFD.

Coal receiving and handling is common to all cases and was covered in Section Coal Grinding and Slurry Preparation 3.1.1 . The receiving and handling subsystem ends at the coal silo. Coal is then fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that deliver s the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. The coal slurry is discharged through a trommel screen into the r od mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62

- 68 percent using bituminous coal and CoP pr esented a paper showing the slurry concentration of Ill inois No. 6 coal as 63 percent [ 58 The coal grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required dep ends on local environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal slurry solids suspended. ]

.

The equipment in the coal grinding and slurry preparation system is fabricated of materials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are either rubber

- lined or hardened metal to minimize erosion. Piping is fabricated of high

- density polyethylene (HDPE).

This plant utilizes two gasification trains to process a total of 5, 083 tonnes/day (5, 603 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operates at maximum capacity. The largest operating GEE gasifier is the 2,268 tonne/day (2,500 TPD) unit at Polk Power St ation. However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this study, which operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas residence time. Gasification

The slurry feed pump takes suction from the slur ry run tank, and the discharge is sent to the feed injector of the GEE gasifier (stream 6). Oxygen from the ASU is vented during preparation for startup and is sent to the feed injector during normal operation. The air separation plant supplies 4 ,171 ton nes/day ( 4,597 TPD) of 95 mol% oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Carbon conversion in the gasifier is assumed to be 98 percent including a fines recycle stream.

### Cost and Performance Baseline for Fossil Energy Plants

97 

## The gasifier vessel is a refractory

- lined, HP combustion chamber. The coal slurry feedstock and oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal slurry and the oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316°C (2,400 **°** F) to produce syngas. The syngas co nsists primarily of hydrogen and carbon monoxide, with lesser amounts of water vapor and carbon dioxide, and small amounts of hydrogen sulfide, COS , methane, argon, and nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids f rom the reactor flow downward into a radiant heat exchanger where the syngas is cooled.

Syngas is cooled from 1,316°C (2,400°F) to 677 °C (1, 250 °F) in the radiant SGC (stream 9 ) and the molten slag solidifies in the proc ess. The solids collect in the water sump at the bottom of the gasifier and are removed periodically using a lock hopper system (stream 8 ). The waste heat from this cooling is used to generate HP steam. BFW in the tubes is saturated, and then steam and water are separated in a steam drum. Approximately 412 , 096 kg/h r ( 908,5 00 lb/h r ) of saturated steam at 13.8 MPa (2,000 psia) is produced. This steam then forms part of the general heat recovery system that provides steam to the steam turbine. Raw Gas Cooling/Particulate Removal

The syngas exiting the radiant cooler is directed downwards by a dip tube into a water sump. Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the syngas goes upwards through the water. The syngas exits the quench chamber s aturated at a temperature of 232 °C ( 450 °F). The slag handling system removes solids from the gasification process equipment. These solids consist of a small amount of unconverted carbon and essentially all of the ash contained in the feed coal. These sol ids are in the form of glass, which fully encapsulates any metals. Solids collected in the water sump below the radiant SGC are removed by gravity and forced circulation of water from the lock hopper circulating pump. The fine solids not removed from the bottom of the quench water sump remain entrained in the water circulating through the quench chamber. In order to limit the amount of solids recycled to the quench chamber, a continuous blowdown stream is removed from the bottom of the syngas quench. Th e blowdown is sent to the vacuum flash drum in the black water flash section. The circulating quench water is pumped by circulating pumps to the quench gasifier.

Syngas exiting the water quench passes to a syngas scrubb er where a water wash is used to remove remaining chlorides , NH 3 

## , SO 2 

## , and PM . The syngas exits the scrubber still saturated at 206 °C ( 403 °F) before it is preheated to 223°C (433°F) (stream 10 ) prior to entering the COS hydrolysis reactor

. Syngas Scrubber/Sour Water Stripper

The sour water stripper removes NH 3 

## , SO 2 

## , and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from SGC s. Sour water from the drum flows to the sour strippe r, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid and sent to the SRU . Remaining water is sent to wastewater treatment.

### Cost and Performance Baseline for Fossil Energy Plants

98 

## Exhibit 3

- 13 Case 1 Block Flow Diagram , GEE IGCC without CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

99 

## Exhibit 3

- 14 Case 1 Stream Table, GEE IGCC without CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0233 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0009 0.0009 0.0013 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3579 0.2825 0.2825 0.4151 CO 2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3416 0.2696 0.2696 0.3961 H 2 O 0.0099 0.2081 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0085 N 2 0.7732 0.5621 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0021 0.0020 0.0020 0.0000 O 2 0.2074 0.1985 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 21,872 1,067 102 19,380 5,298 0 4,829 0 22,212 28,142 28,142 19,153 V-L Flowrate (kg/hr) 631,164 28,941 3,290 543,810 170,485 0 87,000 0 446,032 552,597 552,597 390,595 Solids Flowrate (kg/hr) 0 0 0 0 0 211,783 0 23,236 0 0 0 0
Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.24 Enthalpy (kJ/kg) A 30.23 36.80 26.67 92.52 26.67

--- 558.58

--- 1,424.13 1,066.74 1,066.63 40.35 Density (kg/m 3 ) 1.2 1.6 11.0 24.4 11.0

--- 866.9

--- 13.9 26.7 26.3 41.9 V-L Molecular Weight 28.857 27.132 32.181 28.060 32.181

--- 18.015

--- 20.081 19.636 19.636 20.393
V-L Flowrate (lb mol /hr) 48,220 2,352 225 42,726 11,680 0 10,647 0 48,969 62,043 62,043 42,226 V-L Flowrate (lb/hr) 1,391,479 63,803 7,253 1,198,895 375,855 0 191,803 0 983,333 1,218,267 1,218,267 861,115 Solids Flowrate (lb/hr) 0 0 0 0 0 466,901 0 51,227 0 0 0 0
Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 760.0 Enthalpy (Btu/lb) A 13.0 15.8 11.5 39.8 11.5

--- 240.1

--- 612.3 458.6 458.6 17.3 Density (lb/ft 3 ) 0.076 0.098 0.687 1.521 0.687

--- 54.120

--- 0.870 1.665 1.643 2.617 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

100 

## Exhibit 3

- 14 Case 1 Stream Table, GEE IGCC without CO 2 

## Captu re (Continued)
13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0097 0.0000 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000 CH 4 0.0013 0.0000 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.3977 0.0002 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.1811 0.6124 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000 COS 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.3812 0.0000 0.0000 0.0415 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0012 0.0128 0.0000 0.0018 0.0006 0.0006 0.0006 0.0099 0.0099 0.0638 0.0638 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0086 0.1817 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 N 2 0.0191 0.1905 0.0000 0.2448 0.0309 0.0309 0.0309 0.7732 0.7732 0.7427 0.7427 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0023 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 19,992 951 0 839 19,445 19,445 19,445 110,253 4,410 136,882 136,882 35,596 V-L Flowrate (kg/hr) 422,592 36,883 0 31,997 397,047 397,047 397,047 3,181,557 127,262 3,995,152 3,995,152 641,276 Solids Flowrate (kg/hr) 0 0 5,307 0 0 0 0 0 0 0 0 0
Temperature (°C) 35 45 174 38 45 241 196 15 432 589 132 561 Pressure (MPa, abs) 5.21 5.2 0.409 5.512 5.171 5.136 3.172 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg) A 36.92 -1.2

--- -5.039 54.553 365.190 296.114 30.227 463.785 741.466 235.132 3,502.816 Density (kg/m 3 ) 43.4 95.0 5,288.2 97.7 40.0 24.1 16.4 1.2 7.9 0.4 0.9 35.1 V-L Molecular Weight 21.138 39

--- 38.145 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015
V-L Flowrate (lb mol /hr) 44,075 2,096 0 1,849 42,870 42,870 42,870 243,066 9,723 301,773 301,773 78,476 V-L Flowrate (lb/hr) 931,655 81,313 0 70,540 875,339 875,339 875,339 7,014,133 280,565 8,807,803 8,807,803 1,413,772 Solids Flowrate (lb/hr) 0 0 11,699 0 0 0 0 0 0 0 0 0
Temperature (°F) 94 112 345 100 112 465 386 59 810 1,093 270 1,043 Pressure (psia) 755.0 750.0 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 15.9 -0.5

--- -2.2 23.5 157.0 127.3 13.0 199.4 318.8 101.1 1,505.9 Density (lb/ft 3 ) 2.712 6 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.191

### Cost and Performance Baseline for Fossil Energy Plants

101 

## Syngas exiting the scrubber (stream 10 ) passes through a COS hydrolysis reactor where about 99.5 percent of the COS is converted to CO 2 

## and H 2 

## S (Section COS Hydrolysis , Mercury Removal and Acid Gas Removal

3.1.5 ). The gas exiting the COS reactor (stream 1 1 ) passes through a series of heat exchangers and knockou t (KO) drums to lower the syngas temperature to 3 5 °C ( 95 °F) and to separate entrained water. The cooled syngas (stream 1 2 ) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4 ). Cool, particulate

- free syngas (stream 1 3 ) enters the Selexol absorber unit at approximately 5. 2 MPa ( 755 psia) and 34 °C ( 94 °F). In this absorber, H 2 

## S is preferentially removed from the fuel gas stream along with smaller amounts of CO 2 

## , COS and other gases such as hydrogen. The rich solution leaving the bottom of the absorber is heated against the lean solvent returning from the regenerator before entering the H 2 

## S concentrator. A portion of the non

- sulfur bearing absorbed gases is driven from the solvent in the H 2 

## S concentrator using N 2 

## from the ASU as the stripping medium. The temperature of the H 2 

## S concentrator overhead stream is reduced prior to entering the reabsorber where a second stage of H 2 

## S absorption oc curs. The rich solvent from the reabsorber is combined with the rich solvent from the absorber and sent to the stripper where it is regenerated through the indirect application of thermal energy via condensation of LP steam in a reboiler. The stripper ac id gas stream (stream 14 ), consisting of 18 percent H 2 

## S and 61 percent CO 2 

## (with the balance mostly N 2 

## ), is then sent to the Claus unit.

Acid gas from the first

- stage stripper of the Selexol unit is routed to the Claus plant. The Claus plant partially oxidizes the H 2 

## S in the acid gas to elemental sulfur. About 5, 307 kg/h r ( 11,699 lb/h r ) of elemental sulfur (stream 1 5 ) are recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.6 percent. Claus Unit

Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. In the furnace, H 2 

## S is catalytically oxidized to SO 2 

## at a furnace tempe rature greater than 1,343°C (2,450°F), which must be maintained in order to thermally decompose all of the NH 3 

## present in the sour gas stream. Following the thermal stage and condensation of sulfur, two reheater and two sulfur converters are used to obtain a per - pass H 2 

## S conversion of approximately 99. 9 percent. The Claus Plant tail gas is hydrogenated and recycled back to the Selexol process (stream 16 ). In the furnace waste heat boiler, 12,432 kg/h r ( 27,408 lb/h r ) of 4.2 MPa ( 605 psia) steam are generat ed. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to produce some steam for the medium

- pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) and steam for the LP steam header and 2.9 MP a (415 psig) for IP steam

.
Clean syngas exiting the Selexol absorber is re

- heated (stream 1 8 ) using HP BFW and then expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). The syngas stream is diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 1 7 percent of the air requirements in the ASU (stream 21). The exhaust gas exits the CT at 589 °C (1, 093 °F) (stream 22) and enters the H RSG where additional heat is recovered until the FG exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the HRSG is used to Power Block

### Cost and Performance Baseline for Fossil Energy Plants

102 

## power an advanced, commercially available steam turbine using a 12.4 MPa/ 562 °C/ 562 °C (1800 psig/ 1043 °F/ 1043 °F) steam cycle.

The elevated pressure ASU was described in Section Air Separation Unit 3.1.2 . In Case 1 the ASU is designed to produce a nominal output of 4, 171 tonnes/day ( 4,597 TPD) of 95 mol% O 2 

## for use in the gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 13,051 tonnes/day ( 14,387 TPD) of nitrogen are also recovered, compressed, and used for dilution in the GT combustor (stream 4). About 4 percent of the GT air is used to supply approximately 1 7 percent of the ASU air requirements (stream 21).

Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 , and 3.1.11

.

### Cost and Performance Baseline for Fossil Energy Plants

103 

## 3.2.3 System assumptions for Cases 1 and 2, GEE IGCC with and without CO 2 

## capture, are presented in Key System Assumptions

Exhibit 3

- 15

. Exhibit 3

- 15 GEE IGCC Plant Study Configuration Matrix Case 1 2 Gasifier Pressure, MPa (psia) 5.6 (815) 5.6 (815) O 2 

## :Coal Ratio, kg O 2 

## /kg dry coal 0.9 1 0.9 1 Carbon Conversion, % 98 98 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

## (Btu/scf) 8, 6 63 ( 233 ) 8, 6 44 (2 32 )
Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/56 2 /56 2 (1800/10 43 /10 43 ) 12.4/53 4 /53 4 (1800/ 994 / 994 ) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

Combustion Turbine 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each) Gasifier Technology GEE Radiant Only GEE Radiant Only Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Slurry Solids Content , % 63 63 COS Hydrolysis Yes Occurs in SGS Sour Gas Shift No Yes H 2 

## S Separation Selexol Selexol 1 st 

## Stage Sulfur Removal, % 99. 7 99. 9
Sulfur Recovery Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur Claus Plant with Tail Gas Recycle to Selexol/

Elemental Sulfur
Particulate Control Water Quench, Scrubber, and AGR Absorber Water Quench, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control Multi Nozzle Quiet Combustor ( MNQC ) (LNB) and N 2 

## Dilution MNQC (LNB) and N 2 

## Dilution
CO 2 

## Separation N/A Selexol 2 nd 

## Stage Overall CO 2 

## Capture N/A 90. 3 % CO 2 

## Sequestration N/A Off

- site Saline Formation

### Cost and Performance Baseline for Fossil Energy Plants

104 

## The balance of plant assumptions are common to all cases and are presented in Balance of Plant

– Cases 1 and 2 Exhibit 3

- 16

. Exhibit 3

- 16 Balance of Plant Assumptions Recirculating Wet Cooling Tower Cooling system Fuel and Other storage Coal 30 days Slag 30 days Sulfur 30 days Sorbent 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt Motors between 250 hp and 5,000 hp 4,160 volt Motors above 5,000 hp 13,800 volt Steam and Gas Turbine Generators 24,000 volt Grid Interconnection Voltage 345 kV Water and Waste Water

Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater , and is assumed to be in sufficient quantities to meet plant makeup requirements

. Makeup for potable, process, and de

- ionized (DI) water is drawn from municipal sources

Process Wastewater Water associated with gasification activity and storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge.

Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant was sized for 5.68 cubic meters per day (1,500 gallons per day) Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.

### Cost and Performance Baseline for Fossil Energy Plants

105 

## 3.2.4 The sparing philosophy for Cases 1 and 2 is provided below. Single trains are utilized throughout with exceptions where equipment capacity requi res an additional train. There is no redundancy other than normal sparing of rotating equipment. Sparing Philosophy

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%)

**•** Two trains of slurry preparation and slurry pumps (2 x 50%)

**•** Two trains of gasi fication, including gasifier, SGC , quench and scrubber (2 x 50%).

**•** Two trains of syngas clean

- up process (2 x 50%).

**•** Two trains of Selexol AGR , single

- stage in Case 1 and two

- stage in Case 2, (2 x 50%) and one Claus

- based SRU (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%).
3.2.5 The plant produces a net output of 622 MWe at a net plant efficiency of 39.0 percent (HHV basis). GEE has reported a net plant effi ci ency of 38.5 percent for their reference plant , and they also presented a range of efficiencies of 38.5

- 40 percent depending on fuel type [ Case 1 Performance Results

59 , 60
Overall performance for the plant is summarized in ]

. Typically the higher efficiencies result from fuel blends that include petroleum coke. Exhibit 3

- 17 , which includes auxiliary power requirements. The ASU accounts for approximately 7 8 percent of the auxiliary load between the main air compressor, the nitrogen compressor , the oxygen compressor and ASU auxiliaries. The cooling water system, including the CWP s and the cooling tower fan, account for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 3 percent. All other individual au xiliary loads are less than 3 percent of the total.

### Cost and Performance Baseline for Fossil Energy Plants

106 

## Exhibit 3

- 17 Case 1 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,000 Sweet Gas Expander Power 7,500 Steam Turbine Power 276,300 TOTAL POWER, kWe 747,800 AUXILIARY LOAD SUMMARY, kWe Coal Handling 460 Coal Milling 2,180 Sour Water Recycle Slurry Pump 180 Slag Handling 1,120 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 53,820 Oxygen Compressor 10,260 Nitrogen Compressors 33,340 Boiler Feedwater Pumps 3,980 Condensate Pump 230 Quench Water Pump 520 Circulating Water Pump 4,200 Ground Water Pumps 430 Cooling Tower Fans 2,170 Scrubber Pumps 220 Acid Gas Removal 2,590 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 2,090 Miscellaneous Balance of Plant 2 

### 3,000 Transformer Losses 2,610 TOTAL AUXILIARIES, kWe 125,750 NET POWER, kWe 622,050 Net Plant Efficiency, % (HHV) 39.0 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,238 (8,756) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,540 (1,460) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 211,783 (466,901) Thermal Input 1 

### , kWt 1,596,320 Raw Water Withdrawal, m 3 

### /min (gpm) 17.9 (4,735) 

### Raw Water Consumption , m 3 

### /min (gpm) 14.2 (3,755)
1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

107 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 1 is presented in Environmental Performance

Exhibit 3

- 18

. Exhibit 3

- 18 Case 1 Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) @ 80% capacity factor kg/MWh (lb/MWh)
SO 2 

## 0.001 (0.001) 21 (24) 0.004 (.01) NOx 0.025 (0.059) 1,023 (1,128) 0.195 (.430) Particulates 0.003 (0.0071) 123 (136) 0.023 (.052) Hg 2.46E

- 7 (5.71E

- 7) 0.010 (0.011) 1.89E

- 6 (4.16E

- 6)

CO 2 

## 84.6 (196.8) 3,407,901 (3,756,568) 650 (1,434)
CO 2 1 

## 782 (1,723)
1 

### CO 2 

### emissions based on net power instead of gross power 

## The low level of SO 2 

## emissions is achieved by capture of the sulfur in the gas by the Selexol AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This results in a concentration in the FG of less than 4 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the Selexol process, thereby elim inating the need for a tail gas treatment unit. NO x emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO 2 

## @15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and ultimately destroyed in the Claus plant burner. This helps lower NO x levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of the mercury is captured from the syngas b y an activated carbon bed. CO 2 

## emissions represent the uncontrolled discharge from the process. The carbon balance for the plant is shown in Exhibit 3

- 19

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas and ASU vent gas.

### Cost and Performance Baseline for Fossil Energy Plants

108 

## Exhibit 3

- 19 Case 1 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/h r (lb/hr) Coal 135,000 (297,625) Slag 2,700 (5,952) Air (CO 2 

## ) 519 (1,143) Stack Gas 132,716 (292,588) ASU Vent 103 (227) CO 2 

## Product 0 (0) Total 135,519 (298,768) Total 135,519 (298,768)

Exhibit 3

- 20 shows the sulfur balances for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfu r recovered in the Claus plant and sulfur emitted in the stac k gas. Sulfur in the slag is consi dered to be negligible. Exhibit 3

- 20 Case 1 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/h r (lb/hr) Coal 5,308 (11,702) Elemental Sulfur 5,307 (11,699) Stack Gas 2 (3) CO 2 

## Product 0 (0) Total 5,308 (11,702) Total 5,308 (11,702)
Exhibit 3

- 21 shows the overall water balance for the plant. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re

- used as internal recycle. The difference between demand and recycle is raw water wi thdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be r epresented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water sour ce from which it was withdrawn. Water c onsumption represents the net impact of the plant process on the water source balance.

### Cost and Performance Baseline for Fossil Energy Plants

109 

## Exhibit 3

- 21 Case 1 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge,

m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)

Slag Handling 0.50 (133) 0.50 (133) 0.0 (0) 0.0 (0) 0.0 (0) Slurry Water 1.45 (384) 1.45 (384) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 2.7 (726) 0.90 (237) 1.9 (489) 0.0 (0) 1.9 (489)
Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (8)

- 0.03 (

- 8) Condenser Makeup Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 0.2 (54)

0.20 (54) 0.0 (0) 0.2 (54)

0.20 (54) 0.0 (0) 0.2 (54)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 16.4 (4,321) 0.49 (129) 0.20 (54) 0.29 (75) 15.9 (4,192)

- 0.20 (

- 54)

- 0.29 (

- 75) 3.7 (972) 12.2 (3,220)

Total 21.3 (5,618) 3.34 (883) 17.9 (4,735) 3.7 (979) 14.2 (3,755)



## Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams Exhibit 3

- 22 through Exhibit 3

- 24 :

**•** Coal gasification and ASU

**•** Syngas cleanup , sulfur recovery and tail gas recycle

**•** Combined cycle power generation , steam , and FW
An overall plant energy balance is provided in tabular form in Exhibit 3

- 25 . The power out is the combined CT , steam turbine and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 17 ) is calculated by multiplying the power out by a combined generator efficiency of 98.2 percent.

### Cost and Performance Baseline for Fossil Energy Plants

110 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

111 

## Ex hibit 3

- 22 Case 1 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 1
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 1 GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- 1

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe Net Plant Power : 622 MWe Net Plant Efficiency , HHV : 39

. 0 % Net Plant Heat Rate : 8 , 756 BTU / KWe N 2 to GT Combustor 1 , 391 , 479 W 59

. 0 T 14

. 7 P 13

. 0 H

375 , 855 W 90

. 0 T 125

. 0 P 11

. 5 H

375 , 855 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 7 , 253 W

90

. 0 T 125

. 0 P 11

. 5 H 63 , 803 W 68

. 2 T 16

. 4 P 15

. 8 H

1 , 073 , 296 W 90

. 0 T 56

. 4 P 14

. 2 H

150 , 595 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 466 , 901 W 59

. 0 T 14

. 7 P

191 , 803 W

295

. 0 T 840

. 0 P 240

. 1 H

51 , 227 W 2 , 400

. 0 T

815

. 0 P 1 , 198 , 895 W 389

. 0 T 384

. 0 P 88

. 2 H

658 , 704 W

159

. 7 T 840

. 0 P 2 , 933

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 Air From GT Compressor 280 , 565 W

220

. 0 T 224

. 9 P 50

. 9 H

280 , 565 W 809

. 8 T 234

. 9 P 199

. 4 H 1 , 198 , 895 W 199

. 0 T 384

. 0 P 39

. 8 H 21

HP BFW N 2 to AGR N 2 Boost Compressor 24 , 996 W

199

. 0 T 384

. 0 P 39

. 8 H 24 , 996 W 376

. 3 T 785

. 0 P 84

. 2 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 4

983 , 333 W

1 , 250

. 0 T

805

. 0 P 612

. 3 H 1 , 218 , 267 W 402

. 9 T 800

. 0 P 445

. 7 H

Syngas Quench 1 , 346 , 417 W 450

. 0 T 805

. 0 P 535

. 7 H

8 9 Sour Water

7

### Cost and Performance Baseline for Fossil Energy Plants

112 

## Exhibit 3

- 23 Case 1 Syngas Cleanup Heat and Mass Balance Schematic

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 218 , 267 W 402

. 9 T 800

. 0 P 457

. 9 H 931 , 655 W 94

. 2 T 755

. 0 P 15

. 9 H 81 , 313 W 112

. 2 T 750

. 0 P 875 , 339 W 385

. 6 T 460

. 0 P 127

. 3 H

11 , 699 W

79 , 721 W 450

. 0 T 58

. 9 P 249

. 7 H 2 , 855 W 234

. 5 T 65

. 0 P 405

. 2 H 7 , 253 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 1
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 1 GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- 1

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe Net Plant Power : 622 MWe Net Plant Efficiency , HHV : 39

. 0 % Net Plant Heat Rate : 8 , 756 BTU / KWe 15

12

16 CO 2 Tailgas

71 , 392 W

120

. 0 T 56

. 8 P 32

. 0 H 861 , 115 W 95

. 3 T 760

. 0 P 17

. 3 H

9 , 181 W 118

. 2 T 56

. 8 P 44

. 4 H 3
70 , 540 W

100

. 0 T 799

. 5 P Raw Syngas 17 875 , 339 W

112

. 2 T 750

. 0 P 23

. 5 H

Claus Oxygen Preheater 7 , 253 W 450

. 0 T 124

. 5 P 91

. 9 H COS Hydrolysis 1 , 218 , 267 W 432

. 7 T 785

. 0 P 458

. 6 H

COS Hydrolysis

Preheater 1 , 218 , 267 W 432

. 9 T 795

. 0 P 458

. 6 H

10 11 Clean Gas Acid Gas

13



### AGR

- Selexol 14 Fuel Gas Expander Fuel Gas To GT

19
875 , 339 W

465

. 0 T 745

. 0 P 157

. 0 H 18

N 2 to AGR

24 , 996 W

376

. 3 T 785

. 0 P 84

. 2 H

Hydrogenation and Tail Gas

Cooling

Tail Gas Recycle

Compressor

### Cost and Performance Baseline for Fossil Energy Plants

113 

## Exhibit 3

- 24 Case 1 Combined

- Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

1 , 198 , 895 W 385

. 0 T 389

. 0 P 87

. 2 H

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H 1 , 581 , 185 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 807 , 803 W 269

. 7 T 15

. 2 P 101

. 1 H

875 , 339 W

385

. 6 T 460

. 0 P 127

. 3 H 8 , 807 , 803 W 1 , 092

. 7 T

15

. 2 P 318

. 8 H From Gasifier Island Preheating

To Claus LP BFW 1 , 413 , 772 W

1 , 042

. 7 T 1 , 814

. 7 P 1 , 505

. 9 H 9 , 644 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 440 , 764 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

26 , 992 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 542 , 260 W 512

. 1 T 65

. 0 P 1 , 288

. 0 H

1 , 581 , 185 W 103

. 2 T 120

. 0 P 71

. 4 H 1 , 581 , 185 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 661

. 9 T 65

. 0 P 1 , 361

. 9 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 1
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 1 GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- 1

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 748 MWe Auxiliary Load : 126 MWe Net Plant Power : 622 MWe Net Plant Efficiency , HHV : 39

. 0 % Net Plant Heat Rate : 8 , 756 BTU / KWe 20 22

24

19 23

Flue Gas

HOT WELL CONDENSER Make

- up 27 , 011 W

59

. 0 T 14

. 7 P 27

. 1 H 8 , 822 W 701

. 7 T 501

. 4 P 1 , 358

. 0 H 9 , 515 W 661

. 9 T 65

. 0 P 1 , 361

. 9 H 35 , 544 W

897

. 8 T 280

. 0 P 1 , 472

. 7 H 780 W 1 , 042

. 7 T 1 , 814

. 7 P 1 , 505

. 9 H 1 , 312 W 540

. 7 T 65

. 0 P 1 , 302

. 1 H Air Extraction

280 , 565 W

809

. 8 T 234

. 9 P 199

. 4 H 21

### Cost and Performance Baseline for Fossil Energy Plants

114 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

115 

## Exhibit 3

- 25 Case 1 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,747 (5,447) 4.8 (4.6) 5,752 (5,451) ASU Air 19.1 (18.1) 19 (18) CT Air 96.2 (91.2) 96 (91) Water 67.4 (63.9) 67 (64) Auxiliary Power 453 (429) 453 (429) TOTAL 5,747 (5,447) 187.4 (177.7) 453 (429) 6,387 (6,054) Heat Out GJ/hr (MMBtu/hr) ASU Vent 1.1 (1.0) 1 (1) Slag 89 (84) 36.3 (34.4) 125 (118) Sulfur 49 (47) 0.6 (0.6) 50 (47) CO 2 

## Cooling Tower Blowdown 27.3 (25.9) 27 (26) HRSG Flue Gas 939 (890) 939 (890) Condenser 1,536 (1,456) 1,536 (1,456) Non

- Condenser Cooling Tower Loads* 422 (400) 422 (400)
Process Losses* * 594 (563) 594 (563) Power 2,692 (2,552) 2,692 (2,552) TOTAL 138 (131) 3,557 (3,372) 2,692 (2,552) 6,387 (6,054) * Includes ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas

cooler (low level heat rejection) and extraction air cooler. ** Calculated by difference to close the energy balance.

### Cost and Performance Baseline for Fossil Energy Plants

116 

## 3.2.6 Major equipment items for the GEE gasifier with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Sec tion Case 1

- Major Equipment List

3.2.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 354 tonne/hr (390 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 354 tonne/hr (390 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 354 tonne/hr (390 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 3 0

### Cost and Performance Baseline for Fossil Energy Plants

117 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 236 tonne/h (260 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 287,504 liters (75,950 gal) 2 0

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 163 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 376,122 liters (99,360 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,128,440 liters (298,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 2 2

### Cost and Performance Baseline for Fossil Energy Plants

118 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,082,628 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,624 lpm @ 91 m H2O (1,750 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 493,508 kg/hr (1,088,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,366 lpm @ 27 m H2O (2,210 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 6,246 lpm @ 1,859 m H2O (1,650 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 1,060 lpm @ 223 m H2O (280 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 247 GJ/hr (234 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 88,579 lpm @ 21 m H2O (23,400 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 4,618 lpm @ 18 m H2O (1,220 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 3,066 lpm @ 268 m H2O (810 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single suction 2,082 lpm @ 49 m H2O (550 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,003,134 liter (265,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 303 lpm (80 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

119 

## ACCOUNT 4 GASIFIER, ASU AND AC CESSORIES INCLUDING LOW TEMPERATURE HEAT REC OVERY Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, entrained bed 2,812 tonne/day, 5.6 MPa (3,100 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 245,393 kg/hr (541,000 lb/hr) 2 0

3 Syngas Scrubber Including Sour Water Stripper Vertical upflow 336,112 kg/hr (741,000 lb/hr) 2 0

4 Raw Gas Coolers Shell and tube with condensate drain 215,910 kg/hr (476,000 lb/hr) 8 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 215,456 kg/hr, 35°C, 5.3 MPa (475,000 lb/hr, 95°F, 765 psia) 2 0

6 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 336,112 kg/hr (741,000 lb/hr) syngas 2 0

7 ASU Main Air Compressor Centrifugal, multi-stage 4,757 m3/min @ 1.3 MPa (168,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,268 tonne/day (2,500 tpd) of 95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi-stage 1,161 m3/min (41,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 6.5 MPa (940 psia) 2 0

10 Primary Nitrogen Compressor Centrifugal, multi-stage 3,766 m3/min (133,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

11 Secondary Nitrogen Compressor Centrifugal, single-stage 538 m3/min (19,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

12 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single-stage 0 m3/min (0 scfm) Suction - 2.6 MPa (380 psia) Discharge - 3.2 MPa (470 psia) 2 0

13 AGR Nitrogen Boost Compressor Centrifugal, single-stage 85 m3/min (3,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 5.4 MPa (790 psia) 2 0

14 Extraction Air Heat Exchanger Gas-to-gas, vendor design 69,853 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

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## ACCOUNT 5A SYNGAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIAR IES

ACCOUNT 7 HRSG, DUCTING, AND S TACK

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 215,003 kg/hr (474,000 lb/hr) 35°C (95°F) 5.2 MPa (760 psia) 2 0

2 Sulfur Plant Claus type 140 tonne/day (154 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 303,907 kg/hr (670,000 lb/hr) 221°C (430°F) 5.4 MPa (790 psia) 2 0

4 Acid Gas Removal Plant Selexol 232,239 kg/hr (512,000 lb/hr) 35°C (94°F) 5.2 MPa (755 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 36,161 kg/hr (79,721 lb/hr) 232°C (450°F) 0.4 MPa (58.9 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 31,997 kg/hr (70,540 lb/hr) each 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 230 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

3 Syngas Expansion Turbine/Generator Turbo Expander 218,359 kg/h (481,400 lb/h) 5.1 MPa (745 psia) Inlet 3.2 MPa (460 psia) Outlet 2 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (27 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 352,702 kg/hr, 12.4 MPa / 561 °C ( 777 , 575 lb / hr , 1 , 800 psig / 1 , 043 °F ) Reheat steam - 345,710 kg/hr, 3

. 1 MPa / 561 °C ( 762 , 160 lb / hr , 452 psig / 1 , 043 °F ) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

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## ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 291 MW 12

. 4 MPa / 561 °C / 561 °C ( 1 , 800 psig / 1043 °F / 1043 °F ) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,688 GJ/hr (1,600 MMBtu/hr), Inlet water temperature 16 °C ( 60 °F ) , Water temperature rise 11 °C ( 20 °F ) 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 420,181 lpm @ 30 m (111,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11 °C ( 51

. 5 °F ) wet bulb / 16 °C ( 60 °F ) CWT / 27 °C ( 80 °F ) HWT / 2,353 GJ/hr (2,230 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

122 

## ACCOUNT 10 SLAG RECOVERY AND HA NDLING Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 242,266 liters (64,000 gal) 2 0
2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0
3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 147,631 liters (39,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 2
6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0
7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 208,198 liters (55,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O (60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 2 0

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

123 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 54 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 29 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

124 

## 3.2.7 The cost estimating methodology was described previously in Section 2.6. Case 1

- Cost Estimating Exhibit 3

- 26 shows the total plant capital cost summ ary organized by cost account and Exhibit 3

- 27 shows a more detailed breakdown of the capital costs , along with owner’s costs, TOC, and TASC

. Exhibit 3

- 28 shows the initial and annual O&M costs. The estimated TO C of the GEE gasifier with no CO 2 

## captur e is $2 , 447 /kW. Pr ocess contingency represents 2.0 percent of the TO C and p roject contingency represents 10.8 percent. The COE is 76

. 3 mills/kWh

.

### Cost and Performance Baseline for Fossil Energy Plants

125 

## Exhibit 3

- 26 Case 1 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2009-Oct-08 Project: Bituminous Baseline Study

Case: Case 1 - GEE Radiant 640MW IGCC w/o CO2 Plant Size: 622.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $13,912 $2,585 $10,788 $0 $0 $27,285 $2,477 $0 $5,952 $35,714 $57

2 COAL & SORBENT PREP & FEED $23,713 $4,326 $14,245 $0 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92

3 FEEDWATER & MISC. BOP SYSTEMS $9,622 $7,783 $9,458 $0 $0 $26,863 $2,531 $0 $6,737 $36,131 $58

4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 $0 $0 $171,987 $15,755 $23,878 $32,445 $244,065 $392 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $160,703 $0 w/equip. $0 $0 $160,703 $15,577 $0 $17,628 $193,908 $312 4.4-4.9 Other Gasification Equipment $7,664 $11,266 $12,070 $0 $0 $31,001 $3,020 $0 $7,624 $41,645 $67 SUBTOTAL 4 $279,483 $11,266 $72,942 $0 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771

5A GAS CLEANUP & PIPING $57,957 $3,800 $55,494 $0 $0 $117,251 $11,380 $93 $25,944 $154,668 $249

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $186 6.2-6.9 Combustion Turbine Other $5,928 $887 $1,801 $0 $0 $8,615 $816 $0 $1,721 $11,152 $18 SUBTOTAL 6 $91,679 $887 $8,070 $0 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 $0 $0 $40,384 $3,840 $0 $4,422 $48,646 $78 7.2-7.9 SCR System, Ductwork and Stack $3,329 $2,373 $3,108 $0 $0 $8,810 $817 $0 $1,566 $11,193 $18 SUBTOTAL 7 $38,685 $2,373 $8,136 $0 $0 $49,194 $4,657 $0 $5,989 $59,839 $96

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,111 $0 $4,994 $0 $0 $34,104 $3,272 $0 $3,738 $41,114 $66 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,373 $1,001 $7,239 $0 $0 $18,613 $1,694 $0 $4,041 $24,348 $39 SUBTOTAL 8 $39,483 $1,001 $12,233 $0 $0 $52,718 $4,967 $0 $7,778 $65,462 $105

9 COOLING WATER SYSTEM $9,649 $9,237 $7,877 $0 $0 $26,763 $2,486 $0 $5,971 $35,220 $57

10 ASH/SPENT SORBENT HANDLING SYS $14,359 $8,029 $14,555 $0 $0 $36,943 $3,559 $0 $4,363 $44,864 $72

11 ACCESSORY ELECTRIC PLANT $28,222 $10,643 $21,238 $0 $0 $60,103 $5,165 $0 $12,277 $77,546 $125

12 INSTRUMENTATION & CONTROL $10,249 $1,885 $6,603 $0 $0 $18,737 $1,698 $937 $3,561 $24,933 $40

13 IMPROVEMENTS TO SITE $3,349 $1,974 $8,263 $0 $0 $13,586 $1,341 $0 $4,478 $19,405 $31

14 BUILDINGS & STRUCTURES $0 $6,725 $7,701 $0 $0 $14,427 $1,314 $0 $2,573 $18,313 $29

TOTAL COST $620,363 $72,516 $257,603 $0 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

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## Exhibit 3

- 27 Case 1 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,653 $0 $1,785 $0 $0 $5,439 $487 $0 $1,185 $7,111 $11 1.2 Coal Stackout & Reclaim $4,721 $0 $1,144 $0 $0 $5,865 $514 $0 $1,276 $7,655 $12 1.3 Coal Conveyors & Yd Crush $4,389 $0 $1,132 $0 $0 $5,522 $485 $0 $1,201 $7,207 $12 1.4 Other Coal Handling $1,148 $0 $262 $0 $0 $1,410 $123 $0 $307 $1,840 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,585 $6,464 $0 $0 $9,049 $867 $0 $1,983 $11,900 $19 SUBTOTAL 1. $13,912 $2,585 $10,788 $0 $0 $27,285 $2,477 $0 $5,952 $35,714 $57 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,558 $373 $244 $0 $0 $2,175 $186 $0 $472 $2,833 $5 2.3 Slurry Prep & Feed $21,299 $0 $9,398 $0 $0 $30,697 $2,789 $1,535 $7,004 $42,025 $68 2.4 Misc.Coal Prep & Feed $857 $623 $1,869 $0 $0 $3,349 $308 $0 $731 $4,388 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,330 $2,734 $0 $0 $6,063 $562 $0 $1,325 $7,950 $13 SUBTOTAL 2. $23,713 $4,326 $14,245 $0 $0 $42,284 $3,844 $1,535 $9,533 $57,195 $92 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,896 $4,974 $2,626 $0 $0 $10,496 $972 $0 $2,294 $13,762 $22 3.2 Water Makeup & Pretreating $620 $65 $347 $0 $0 $1,031 $98 $0 $339 $1,469 $2 3.3 Other Feedwater Subsystems $1,585 $536 $482 $0 $0 $2,602 $234 $0 $567 $3,403 $5 3.4 Service Water Systems $355 $731 $2,536 $0 $0 $3,621 $353 $0 $1,192 $5,167 $8 3.5 Other Boiler Plant Systems $1,904 $738 $1,829 $0 $0 $4,471 $424 $0 $979 $5,874 $9 3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $3 3.7 Waste Treatment Equipment $867 $0 $529 $0 $0 $1,395 $136 $0 $459 $1,991 $3 3.8 Misc. Power Plant Equipment $1,080 $145 $554 $0 $0 $1,779 $172 $0 $585 $2,536 $4 SUBTOTAL 3. $9,622 $7,783 $9,458 $0 $0 $26,863 $2,531 $0 $6,737 $36,131 $58 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $111,116 $0 $60,871 $0 $0 $171,987 $15,755 $23,878 $32,445 $244,065 $392 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $160,703 $0 w/equip. $0 $0 $160,703 $15,577 $0 $17,628 $193,908 $312 4.4 Scrubber & Low Temperature Cooling $5,873 $4,781 $4,975 $0 $0 $15,629 $1,501 $0 $3,426 $20,556 $33 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $1,791 $0 $1,681 $0 $0 $3,472 $417 $0 $948 $4,837 $8 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $6,486 $5,414 $0 $0 $11,900 $1,103 $0 $3,251 $16,253 $26 SUBTOTAL 4. $279,483 $11,266 $72,942 $0 $0 $363,691 $34,352 $23,878 $57,697 $479,618 $771

### Cost and Performance Baseline for Fossil Energy Plants

127 

## Exhibit 3

- 27 Case 1 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Single Stage Selexol $41,961 $0 $35,605 $0 $0 $77,565 $7,501 $0 $17,013 $102,080 $164 5A.2 Elemental Sulfur Plant $10,055 $2,004 $12,972 $0 $0 $25,031 $2,431 $0 $5,493 $32,955 $53 5A.3 Mercury Removal $1,057 $0 $804 $0 $0 $1,862 $180 $93 $427 $2,561 $4 5A.4 COS Hydrolysis $3,575 $0 $4,668 $0 $0 $8,243 $801 $0 $1,809 $10,853 $17 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,310 $0 $248 $0 $0 $1,558 $190 $0 $350 $2,098 $3 5A.7 Fuel Gas Piping $0 $688 $482 $0 $0 $1,170 $108 $0 $256 $1,534 $2 5A.9 HGCU Foundations $0 $1,108 $714 $0 $0 $1,822 $167 $0 $597 $2,586 $4 SUBTOTAL 5A. $57,957 $3,800 $55,494 $0 $0 $117,251 $11,380 $93 $25,944 $154,668 $249 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $186 6.2 Syngas Expander $5,928 $0 $819 $0 $0 $6,747 $641 $0 $1,108 $8,496 $14 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $4 SUBTOTAL 6. $91,679 $887 $8,070 $0 $0 $100,636 $9,540 $4,601 $12,256 $127,033 $204 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,357 $0 $5,027 $0 $0 $40,384 $3,840 $0 $4,422 $48,646 $78 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,706 $1,217 $0 $0 $2,923 $256 $0 $636 $3,816 $6 7.4 Stack $3,329 $0 $1,250 $0 $0 $4,579 $439 $0 $502 $5,519 $9 7.9 HRSG,Duct & Stack Foundations $0 $667 $640 $0 $0 $1,307 $122 $0 $429 $1,858 $3 SUBTOTAL 7. $38,685 $2,373 $8,136 $0 $0 $49,194 $4,657 $0 $5,989 $59,839 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $29,111 $0 $4,994 $0 $0 $34,104 $3,272 $0 $3,738 $41,114 $66 8.2 Turbine Plant Auxiliaries $202 $0 $463 $0 $0 $665 $65 $0 $73 $803 $1 8.3 Condenser & Auxiliaries $5,053 $0 $1,484 $0 $0 $6,537 $625 $0 $716 $7,878 $13 8.4 Steam Piping $5,117 $0 $3,600 $0 $0 $8,717 $749 $0 $2,367 $11,833 $19 8.9 TG Foundations $0 $1,001 $1,693 $0 $0 $2,694 $255 $0 $885 $3,835 $6 SUBTOTAL 8. $39,483 $1,001 $12,233 $0 $0 $52,718 $4,967 $0 $7,778 $65,462 $105

### Cost and Performance Baseline for Fossil Energy Plants

128 

## Exhibit 3

- 27 Case 1 Total Plant Cost Details (Co ntinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,699 $0 $1,219 $0 $0 $7,918 $754 $0 $1,301 $9,973 $16 9.2 Circulating Water Pumps $1,737 $0 $122 $0 $0 $1,859 $157 $0 $302 $2,318 $4 9.3 Circ.Water System Auxiliaries $147 $0 $21 $0 $0 $168 $16 $0 $28 $211 $0 9.4 Circ.Water Piping $0 $6,124 $1,588 $0 $0 $7,712 $697 $0 $1,682 $10,090 $16 9.5 Make-up Water System $343 $0 $490 $0 $0 $833 $80 $0 $183 $1,096 $2 9.6 Component Cooling Water Sys $723 $865 $615 $0 $0 $2,203 $206 $0 $482 $2,891 $5 9.9 Circ.Water System Foundations $0 $2,248 $3,822 $0 $0 $6,071 $576 $0 $1,994 $8,640 $14 SUBTOTAL 9. $9,649 $9,237 $7,877 $0 $0 $26,763 $2,486 $0 $5,971 $35,220 $57 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $11,822 $6,519 $13,243 $0 $0 $31,584 $3,048 $0 $3,463 $38,095 $61 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $575 $0 $626 $0 $0 $1,201 $116 $0 $198 $1,515 $2 10.7 Ash Transport & Feed Equipment $771 $0 $186 $0 $0 $957 $89 $0 $157 $1,204 $2 10.8 Misc. Ash Handling Equipment $1,191 $1,460 $436 $0 $0 $3,087 $294 $0 $507 $3,888 $6 10.9 Ash/Spent Sorbent Foundation $0 $51 $64 $0 $0 $115 $11 $0 $38 $163 $0 SUBTOTAL 10. $14,359 $8,029 $14,555 $0 $0 $36,943 $3,559 $0 $4,363 $44,864 $72 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $958 $0 $947 $0 $0 $1,905 $182 $0 $209 $2,296 $4 11.2 Station Service Equipment $3,920 $0 $353 $0 $0 $4,273 $394 $0 $467 $5,134 $8 11.3 Switchgear & Motor Control $7,247 $0 $1,318 $0 $0 $8,565 $794 $0 $1,404 $10,763 $17 11.4 Conduit & Cable Tray $0 $3,366 $11,106 $0 $0 $14,472 $1,400 $0 $3,968 $19,840 $32 11.5 Wire & Cable $0 $6,432 $4,226 $0 $0 $10,658 $774 $0 $2,858 $14,291 $23 11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,017 $6 11.7 Standby Equipment $236 $0 $230 $0 $0 $466 $44 $0 $77 $587 $1 11.8 Main Power Transformers $15,862 $0 $146 $0 $0 $16,008 $1,211 $0 $2,583 $19,801 $32 11.9 Electrical Foundations $0 $158 $416 $0 $0 $574 $55 $0 $189 $818 $1 SUBTOTAL 11. $28,222 $10,643 $21,238 $0 $0 $60,103 $5,165 $0 $12,277 $77,546 $125 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,012 $0 $676 $0 $0 $1,687 $160 $84 $290 $2,221 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $233 $0 $149 $0 $0 $382 $36 $19 $87 $524 $1 12.7 Computer & Accessories $5,397 $0 $173 $0 $0 $5,570 $511 $278 $636 $6,995 $11 12.8 Instrument Wiring & Tubing $0 $1,885 $3,854 $0 $0 $5,739 $487 $287 $1,628 $8,141 $13 12.9 Other I & C Equipment $3,608 $0 $1,752 $0 $0 $5,359 $504 $268 $920 $7,051 $11 SUBTOTAL 12. $10,249 $1,885 $6,603 $0 $0 $18,737 $1,698 $937 $3,561 $24,933 $40

### Cost and Performance Baseline for Fossil Energy Plants

129 

## Exhibit 3

- 27 Case 1 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,246 $0 $0 $2,351 $233 $0 $775 $3,360 $5 13.2 Site Improvements $0 $1,869 $2,483 $0 $0 $4,352 $429 $0 $1,435 $6,216 $10 13.3 Site Facilities $3,349 $0 $3,534 $0 $0 $6,883 $679 $0 $2,268 $9,830 $16 SUBTOTAL 13. $3,349 $1,974 $8,263 $0 $0 $13,586 $1,341 $0 $4,478 $19,405 $31 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,446 $3,484 $0 $0 $5,930 $546 $0 $971 $7,447 $12 14.3 Administration Building $0 $845 $613 $0 $0 $1,459 $130 $0 $238 $1,827 $3 14.4 Circulation Water Pumphouse $0 $167 $88 $0 $0 $255 $22 $0 $42 $319 $1 14.5 Water Treatment Buildings $0 $518 $506 $0 $0 $1,024 $93 $0 $167 $1,284 $2 14.6 Machine Shop $0 $433 $296 $0 $0 $729 $65 $0 $119 $912 $1 14.7 Warehouse $0 $699 $451 $0 $0 $1,149 $102 $0 $188 $1,439 $2 14.8 Other Buildings & Structures $0 $418 $326 $0 $0 $744 $66 $0 $162 $973 $2 14.9 Waste Treating Building & Str. $0 $935 $1,787 $0 $0 $2,723 $254 $0 $595 $3,572 $6 SUBTOTAL 14. $0 $6,725 $7,701 $0 $0 $14,427 $1,314 $0 $2,573 $18,313 $29

TOTAL COST $620,363 $72,516 $257,603 $0 $0 $950,481 $89,310 $31,044 $165,109 $1,235,944 $1,987

Owner's Costs Preproduction Costs 6 Months All Labor $12,214 $20 1 Month Maintenance Materials $2,742 $4 1 Month Non-fuel Consumables $269 $0 1 Month Waste Disposal $304 $0 25% of 1 Months Fuel Cost at 100% CF $1,627 $3 2% of TPC $24,719 $40 Total $41,874 $67 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,328 $21 0.5% of TPC (spare parts) $6,180 $10 Total $19,507 $31
Initial Cost for Catalyst and Chemicals $4,892 $8 Land $900 $1 Other Owner's Costs $185,392 $298

Financing Costs $33,370 $54 Total Overnight Costs (TOC) $1,521,880 $2,447 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,734,944 $2,789

### Cost and Performance Baseline for Fossil Energy Plants

130 

## Exhibit 3

- 28 Case 1 Initial and Annual O&M Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 1 - GEE Radiant 640MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8,756 MWe-net: 622 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $9.515 Maintenance Labor Cost $13,622,877 $21.900 Administrative & Support Labor $4,885,447 $7.854 Property Taxes and Insurance $24,718,883 $39.738 TOTAL FIXED OPERATING COSTS $49,146,120 $79.007 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $26,322,759 $0.00604

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 3,409 1.08 $0 $1,076,793 $0.00025

Chemicals

MU & WT Chem. (lbs) 0 20,311 0.17 $0 $1,026,436 $0.00024 Carbon (Mercury Removal) (lb) 54,833 75 1.05 $57,584 $23,034 $0.00001 COS Catalyst (m3) 422 0.29 2,397.36 $1,011,578 $202,316 $0.00005 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Selexol Solution (gal) 285,358 45 13.40 $3,823,295 $175,961 $0.00004 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.94 131.27 $0 $74,422 $0.00002 Subtotal Chemicals $4,892,457 $1,502,168 $0.00034

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Spent Mercury Catalyst (lb.) 0 75 0.42 $0 $9,148 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 615 16.23 $0 $2,912,403 $0.00067 Subtotal-Waste Disposal $0 $2,921,551 $0.00067

By-products & Emissions

Sulfur (tons) 0 140 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $4,892,457 $31,823,271 $0.00730

Fuel (ton) 0 5,603 38.18 $0 $62,470,676 $0.01433

### Cost and Performance Baseline for Fossil Energy Plants

131 

## 3.2.8 Case 2 is configured to produce electric power with CO 2 

## capture. The plant configuration is the same as Case 1, namely two gasifier trains, two advanced F Class turbines, two HRSGs , and one steam turbine. The gross power output from the plant is constrained by the capacity of the two CT s, and since the CO 2 

## capture process increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 1. Case 2

- GEE IGCC with CO 2 

## Capture

The process description for Case 2 is similar to Case 1 with several notab le exceptions to accommodate CO 2 

## capture. A BFD and stream tables for Case 2 are shown in Exhibit 3

- 29 and Ex hibit 3

- 30 , respectively. Instead of repeating the entire process description, only differences from Case 1 are reported here.

The gasification process is the same as Case 1 with the exception that total coal feed to the two gasifiers is 5, 302 tonnes/day ( 5,844 TPD) (stream 6) and the ASU provides 4,342 tonnes/day ( 4,786 TPD) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5). Gasification

Raw gas cooling and particulate removal are the same as Case 1 with the exception that approximately 443,118 kg/h r ( 976,891 lb/h r ) of saturated steam at 13.8 MPa (2,000 psia) is generated in the radiant SGCs. Raw Gas Cooling /Particulate Removal

No differences from Case 1. Syngas Scrubber/Sour Water Stripper

The SGS process was described in Section SGS 3.1.3 . In Case 2 steam (stream 1 1 ) is added to the syngas exiting the scrubber to adjust the H 2 

## O:CO molar ratio to 2:1 prior to the first SGS reactor. The hot syngas exiting the first stage of SGS is used to generate the steam that is added in stream 1 1 . A second stage of SGS results in 9 7 percent overall conversion of the CO to CO 2 

## . The warm syngas from the second stage of SGS (stream 1 2 ) is cooled to 236 °C (45 6 °F) by preheating the unshifted syngas prior to the SGS . The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the s econd SGS cooler the syngas is further cooled to 35 °C ( 95 °F) prior to the mercury removal beds.

Mercury removal is the same as in Case 1. Mercury Removal and AGR

The AGR process in Case 2 is a two stage Selexol process where H 2 

## S is removed in the first sta ge and CO 2 

## in the second stage of absorption as previously described in Section 3.1.5 . The process results in three product streams, the clean syngas, a CO 2 

## - rich stream and an acid gas feed to the Claus plant. The acid gas (stream 1 8 ) contains 35 percent H 2 

## S and 52 percent CO 2 

## with the balance primarily N 2 

## . The CO 2 

## - rich stream is discussed further in the CO 2 

## compression section.

### Cost and Performance Baseline for Fossil Energy Plants

132 

## Exhibit 3

- 29 Case 2 Block Flow Diagram , GEE IGCC with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

133 

## Exhibit 3

- 30 Case 2 Stream Table , GEE IGCC with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0166 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2823 0.0000 0.0060 CO 2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1089 0.0000 0.3082 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2689 0.0000 0.4366 H 2 O 0.0099 0.1363 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 N 2 0.7732 0.7061 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 O 2 0.2074 0.1356 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 27,361 1,650 96 20,051 5,526 0 5,037 0 23,122 29,284 7,193 36,478 V-L Flowrate (kg/hr) 789,560 45,332 3,080 562,615 177,828 0 90,748 0 465,243 575,983 129,587 705,570 Solids Flowrate (kg/hr) 0 0 0 0 0 220,904 0 24,237 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 Enthalpy (kJ/kg) A 30.23 35.64 26.67 92.50 26.67

--- 537.77

--- 1,424.65 1,065.71 2,918.18 942.21 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0

--- 872.0

--- 14.0 27.2 25.6 24.8 V-L Molecular Weight 28.857 27.476 32.181 28.060 32.181

--- 18.015

--- 20.121 19.669 18.015 19.343
V-L Flowrate (lb mol /hr) 60,321 3,637 211 44,204 12,183 0 11,106 0 50,976 64,561 15,858 80,419 V-L Flowrate (lb/hr) 1,740,683 99,940 6,791 1,240,354 392,044 0 200,064 0 1,025,685 1,269,825 285,691 1,555,516 Solids Flowrate (lb/hr) 0 0 0 0 0 487,011 0 53,433 0 0 0 0
Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 Enthalpy (Btu/lb) A 13.0 15.3 11.5 39.8 11.5

--- 231.2

--- 612.5 458.2 1,254.6 405.1 Density (lb/ft 3 ) 0.076 0.091 0.687 1.521 0.687

--- 54.440

--- 0.871 1.699 1.597 1.550 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

134 

## Exhibit 3

- 30 Case 2 Stream Table , GEE IGCC with CO 2 

## Capture (C ontinued)
13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000 CH 4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0078 0.0077 0.0124 0.0124 0.0002 0.0022 0.0000 0.0064 0.0000 0.0000 0.0000 0.0000 CO 2 0.4019 0.4055 0.0502 0.0502 0.9948 0.5214 0.0000 0.6664 0.0003 0.0083 0.0083 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.5692 0.5649 0.9139 0.9139 0.0048 0.1028 0.0000 0.2561 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0012 0.0013 0.0001 0.0001 0.0000 0.0226 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000 N 2 0.0058 0.0064 0.0105 0.0105 0.0000 0.0008 0.0000 0.0542 0.7732 0.7541 0.7541 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 27,978 28,368 17,423 17,423 10,425 497 0 390 110,253 139,657 139,657 34,500 V-L Flowrate (kg/hr) 552,391 564,920 90,179 90,179 456,650 17,684 0 12,529 3,181,557 3,834,352 3,834,352 621,521 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,524 0 0 0 0 0
Temperature (°C) 35 35 35 196 51 48 178 38 15 562 132 534 Pressure (MPa, abs) 5.14 5.1 5.102 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 37.11 36.4 195.532 1,124.237 -162.306 74.865

--- 5.295 30.227 834.762 343.819 3,432.885 Density (kg/m 3 ) 40.7 40.9 10.1 4.2 641.8 2.2 5,280.5 77.9 1.2 0.4 0.9 36.7 V-L Molecular Weight 19.744 20 5.176 5.176 43.805 35.588

--- 32.153 28.857 27.455 27.455 18.015
V-L Flowrate (lb mol /hr) 61,681 62,540 38,412 38,412 22,983 1,095 0 859 243,066 307,891 307,891 76,059 V-L Flowrate (lb/hr) 1,217,813 1,245,436 198,810 198,810 1,006,740 38,986 0 27,622 7,014,133 8,453,299 8,453,299 1,370,220 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,178 0 0 0 0 0
Temperature (°F) 95 95 95 384 124 119 352 100 59 1,044 270 994 Pressure (psia) 745.0 740.0 740.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 16.0 15.7 84.1 483.3 -69.8 32.2

--- 2.3 13.0 358.9 147.8 1,475.9 Density (lb/ft 3 ) 2.544 3 0.630 0.260 40.068 0.137 329.649 4.864 0.076 0.026 0.053 2.293

### Cost and Performance Baseline for Fossil Energy Plants

135 

## CO 2 

## from the AGR process is fl ashed at three pressure levels to separate CO 2 

## and decrease H 2 

## losses to the CO 2 

## product pipeline . The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psi a), compressed, and recycled back to the CO 2 

## absorber. The M P CO 2 

## stream is flashed at 1.0 MPa ( 149.7 psia)

. The L P CO 2 

## stream is flashed at 0.1 MPa (16.7 psia) , compressed to 1.0 MPa (149.5 psia) , and combined with the MP CO 2 

## stream . The combined stream is compressed from 2.1 MPa ( 149.5 psia) to a SC condition at 15.3 MPa (2 , 215 psia) using a multiple

- stage, intercooled compres sor. During compression, the CO 2 

## stream is dehydrated to a dewpoint of

- 40oC (

- 40°F) with triethylene glycol. The raw CO 2 

## stream from the Selexol process contains over 9 9 percent CO 2 

## . The CO 2 

## (stream 1 7 ) is transported to the plant fence line and is seq uestration ready. CO 2 

## TS&M costs were estimated using the methodology described in Section 2.7. CO 2 

## Compression and Dehydration

The Claus plant is the same as Case 1 with the following exceptions: Claus Unit

**•** 5, 528 kg/h r (12, 178 lb/h r ) of sulfur (stream 1 9 ) are produced

**•** The waste heat boiler generates 13,555 kg/hr (29,884 lb/h r ) of 4.0 MPa (575 psia) steam of which 12,679 kg/h r ( 27 , 953 lb/h r ) is available to the medium pressure steam header.

Clean syngas from the AGR plant is heated to 241°C ( 465°F ) using HP BFW before passi ng through an expansion turbine. The clean syngas (stream 1 6 ) is dil uted with nitrogen (stream 4) and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 2 2 ) exits the CT at 562 °C ( 1044 °F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 2 3 ) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 1 2.4 MPa/ 534 °C/ 534 °C (1800 psig/ 994 °F/ 994 °F) steam cycle. Power Block

The same elevated pressure ASU is used in Case 2 and produces 4, 342 tonnes/day ( 4,786 TPD) of 95 mole % oxygen and 14,591 tonnes/day ( 16,084 TPD) of nitrogen. There is no integration between the ASU and the CT

. Air Separation Unit ( ASU )

3.2.9 The Case 2 modeling assumptions were presented previously in Section Case 2 Performance Results 3.2.3

. The plant produces a net output of 543 MW at a net plant efficiency of 32. 6 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3

- 31 , which includes auxiliary power requirements. The ASU accounts for nearly 60 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor , an d ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 26 percent of the auxiliary power load. The BFW pumps and cooling water system ( CWP s and cooling tower fan) comprise over 6 percent of the load, leaving 8 perc ent of the auxiliary load for all other systems.

### Cost and Performance Baseline for Fossil Energy Plants

136 

## Exhibit 3

- 31 Case 2 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,000 Sweet Gas Expander Power 6,500 Steam Turbine Power 263,500 TOTAL POWER, kWe 734,000 AUXILIARY LOAD SUMMARY, kWe Coal Handling 470 Coal Milling 2,270 Sour Water Recycle Slurry Pump 190 Slag Handling 1,160 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 67,330 Oxygen Compressor 10,640 Nitrogen Compressors 35,640 CO 2 

### Compressor 31,160 Boiler Feedwater Pumps 4,180 Condensate Pump 280 Quench Water Pump 540 Circulating Water Pump 4,620 Ground Water Pumps 530 Cooling Tower Fans 2,390 Scrubber Pumps 230 Acid Gas Removal 19,230 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,780 Miscellaneous Balance of Plant 2 

### 3,000 Transformer Losses 2,760 TOTAL AUXILIARIES, kWe 190,750 NET POWER, kWe 543,250 Net Plant Efficiency, % (HHV) 32.6 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,458) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,509 (1,430) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 220,904 (487,011) Thermal Input 1 

### , kWt 1,665,074 Raw Water Withdrawal, m 3 

### /min (gpm) 22.0 (5,815) Raw Water Consumption , m 3 

### /min (gpm) 17.9 (4,739)
1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

137 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 2 is presented in Environmental Performance

Exhibit 3

- 32

. Exhibit 3

- 32 Case 2 Air Emissions

kg/GJ (lb/10 6 

## Btu) Tonne/year (tons/year) @ 80% capacity factor kg/MWh (lb/MWh)
SO 2 

## 0.001 (0.002) 39 (43) 0.008 (.02) NOx 0.021 (0.049) 878 (967) 0.171 (.376) Particulates 0.003 (0.0071) 128 (141) 0.025 (.055) Hg 2.46E

- 7 (5.71E

- 7) 0.010 (0.011) 2.01E

- 6 (4.42E

- 6) CO 2 

## 8.5 (19.7) 355,438 (391,804) 69 (152) CO 2 1 

## 93 (206)
1 

### CO 2 

### emissions based on net power instead of gross power 

## The low level of SO 2 

## emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. As a result of achieving the 90 percent CO 2 

## removal target, the sulfur compound s are removed to an extent that exceeds the environmental target in Section 2.4 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a concentration in the FG of less than 1 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas treatment unit. NO x emissions are limited by nitrogen dilution to 15 ppmvd (as NO 2 

## @15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process. This helps lower NO x levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of the syn gas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety

- five percent of mercury is captured from the syngas by an activated carbon bed. Ninety

- tw o percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. The carbon balance for the plant is shown in Exhibit 3

- 33

. The ca rbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. The carbon capture efficiency is defined as the amount of carbon in the CO 2 

## product stream relative to the amount of carbon in the coal less carbon contained in the slag , represented by the following fraction:

### Cost and Performance Baseline for Fossil Energy Plants

138 

## (Carbon in CO 2 

## Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or 274,672 /( 310,444

- 6,209 ) *100 or 90. 3 percent Exhibit 3

- 33 Case 2 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/h r (lb/hr) Coal 140,815 (310,444) Slag 2,816 (6,209) Air (CO 2 

## ) 540 (1,191) Stack Gas 13,842 (30,516) ASU Vent 107 (237) CO 2 

## Product 124,589 (274,672)

Total 141,355 (311,634) Total 141,355 (311,634)

Exhibit 3

- 34 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfu r recovered in the Claus plant and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible. Exhibit 3

- 34 Case 2 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/h r (lb/hr) Coal 5,537 (12,207) Elemental Sulfur 5,524 (12,178) Stack Gas 3 (6) CO 2 

## Product 10 (23) Total 5,537 (12,207) Total 5,537 (12,207)

Exhibit 3

- 35 shows the overall water balance for the plant. The exhibit is presented in an identical manner for Case 1.

### Cost and Performance Baseline for Fossil Energy Plants

139 

## Exhibit 3

- 35 Case 2 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge,

m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)

Slag Handling 0.53 (139) 0.53 (139) 0.0 (0) 0.0 (0) 0.0 (0) Slurry Water 1.51 (400) 1.51 (400) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 2.9 (757) 0.72 (191) 2.1 (566) 0.0 (0) 2.1 (566)
Humidifier 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 2.4 (627) 2.2 (571) 0.21 (56) 0.0 (0) 2.4 (627) 2.2 (571) 0.21 (56) 0.0 (0) 2.4 (627)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 18.0 (4,750) 0.49 (129) 0.21 (56) 0.28 (73) 17.5 (4,622)

- 0.21 (

- 56)

- 0.28 (

- 73) 4.0 (1,068) 13.5 (3,553)

Total 25.3 (6,673) 3.25 (858) 22.0 (5,815) 4.1 (1,076) 17.9 (4,739)



## Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams Exhibit 3

- 36 through Exhibit 3

- 38 :

**•** Coal gasification and ASU

**•** Syngas cleanup , sulfur recovery , and tail gas recycle

**•** Combined cycle power generation , steam , and FW An overall plant energy balance is presented in tabular form in Exhibit 3

- 39 . The power out is the combined CT , steam turbine and expander power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 31 ) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.

### Cost and Performance Baseline for Fossil Energy Plants

140 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

141 

## Exhibit 3

- 36 Case 2 Coal Gasification and Air Separation Units Heat and Mass Balance Schematic

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 2
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 2 GEE G ASIFIER ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- 2

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe Net Plant Power : 543 MWe Net Plant Efficiency , HHV : 32

. 6 % Net Plant Heat Rate : 10 , 458 BTU / KWe N 2 to GT Combustor 1 , 740 , 683 W 59

. 0 T 14

. 7 P 13

. 0 H

392 , 044 W 90

. 0 T 125

. 0 P 11

. 5 H

392 , 044 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 791 W

90

. 0 T 125

. 0 P 11

. 5 H 99 , 940 W 64

. 8 T 16

. 4 P 15

. 3 H

1 , 083 , 577 W 90

. 0 T 56

. 4 P 14

. 2 H

156 , 777 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 487 , 011 W 59

. 0 T 14

. 7 P

200 , 064 W

287

. 0 T 840

. 0 P 231

. 2 H

53 , 433 W 2 , 400

. 0 T

815

. 0 P 676 , 491 W 385

. 0 T 384

. 0 P 87

. 2 H

687 , 075 W

156

. 4 T 840

. 0 P 2 , 950

. 2 H 100

. 0 T 189

. 5 P 18

. 0 H

6 676 , 491 W 199

. 0 T 384

. 0 P 39

. 8 H

HP BFW N 2 to GT Combustor N 2 Boost Compressor 563 , 864 W

199

. 0 T 384

. 0 P 39

. 8 H 563 , 864 W 385

. 0 T 469

. 0 P 87

. 0 H

Saturated Steam

To HRSG HP Superheater GE Energy Gasifier

Radiant Syngas Cooler Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 4

1 , 025 , 685 W

1 , 250

. 0 T

805

. 0 P 612

. 5 H 1 , 269 , 825 W 403

. 1 T 800

. 0 P 458

. 2 H

Syngas Quench 1 , 403 , 986 W 450

. 0 T 805

. 0 P 536

. 1 H

8 9 10 Sour Water

7

### Cost and Performance Baseline for Fossil Energy Plants

142 

## Exhibit 3

- 37 Case 2 Syngas Cleanup Heat and Mass Balance Schematic

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 269 , 825 W 403

. 1 T 800

. 0 P 458

. 2 H 1 , 245 , 436 W 94

. 6 T 740

. 0 P 15

. 7 H 38 , 986 W 119

. 0 T 23

. 7 P 198 , 810 W 384

. 3 T 460

. 0 P 483

. 3 H

12 , 178 W 36 , 094 W 450

. 0 T 12

. 3 P 457

. 8 H

2 , 495 W 239

. 1 T 65

. 0 P 441

. 9 H 6 , 791 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 2
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 2 GEE G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- 2

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe Net Plant Power : 543 MWe Net Plant Efficiency , HHV : 32

. 6 % Net Plant Heat Rate : 10 , 458 BTU / KWe 19

13 20 CO 2 Tailgas

30 , 072 W

120

. 0 T 10

. 6 P 112

. 1 H 1 , 217 , 813 W 94

. 9 T 745

. 0 P 16

. 0 H

8 , 472 W 114

. 3 T 10

. 6 P 40

. 0 H 3 27 , 622 W

100

. 0 T 799

. 5 P

Raw Syngas 15 198 , 810 W 94

. 6 T 740

. 0 P 84

. 1 H

Claus Oxygen Preheater 6 , 791 W 450

. 0 T 124

. 5 P 91

. 9 H 18 Fuel Gas Expander Fuel Gas To GT

16 198 , 810 W

465

. 0 T 735

. 0 P 597

. 2 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam

12 11

COS Hydrolysis

Preheater 1 , 269 , 825 W 413

. 1 T 795

. 0 P 450

. 3 H 285 , 691 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 555 , 516 W 436

. 4 T 795

. 0 P 598

. 0 H
776

. 2 T 795

. 0 P 582

. 1 H 400

. 0 T 795

. 0 P 408

. 0 H 1 , 555 , 516 W 463

. 4 T 785

. 0 P 405

. 1 H

1 , 555 , 516 W 455

. 6 T 780

. 0 P 401

. 5 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

17

10 14

1 , 006 , 740 W 123

. 8 T 2 , 214

. 7 P

Tail Gas Recycle

Compressor Hydrogenation and Tail Gas

Cooling

### Cost and Performance Baseline for Fossil Energy Plants

143 

## Exhibit 3

- 38 Case 2 Combined

- Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H 1 , 875 , 803 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 453 , 299 W 269

. 9 T 15

. 2 P 147

. 8 H

198 , 810 W

384

. 3 T 460

. 0 P 483

. 3 H 8 , 453 , 299 W 1 , 043

. 8 T

15

. 2 P 358

. 9 H From Gasifier Island Preheating

To Claus LP BFW 1 , 370 , 220 W 993

. 8 T 1 , 814

. 7 P 1 , 475

. 9 H 10 , 303 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 399 , 040 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

28 , 836 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 550 , 132 W 474

. 9 T 65

. 0 P 1 , 269

. 6 H

1 , 875 , 803 W 102

. 9 T 120

. 0 P 71

. 1 H 1 , 875 , 803 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 614

. 9 T 65

. 0 P 1 , 338

. 7 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 2
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 2 GEE G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- 2

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 734 MWe Auxiliary Load : 191 MWe Net Plant Power : 543 MWe Net Plant Efficiency , HHV : 32

. 6 % Net Plant Heat Rate : 10 , 458 BTU / KWe 21 22

24

16 23

Flue Gas

HOT WELL CONDENSER Make

- up 313 , 510 W 59

. 0 T 14

. 7 P 27

. 1 H 9 , 026 W 660

. 5 T 501

. 4 P 1 , 334

. 5 H 9 , 761 W 614

. 9 T 65

. 0 P 1 , 338

. 7 H 34 , 034 W

852

. 1 T 280

. 0 P 1 , 448

. 8 H 798 W 993

. 8 T 1 , 814

. 7 P 1 , 475

. 9 H 1 , 337 W 505

. 0 T 65

. 0 P 1 , 284

. 5 H

### Cost and Performance Baseline for Fossil Energy Plants

144 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

145 

## Exhibit 3

- 39 Case 2 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,994 (5,681) 5.0 (4.7) 5,999 (5,686) ASU Air 24 (23) 24 (23) GT Air 96 (91) 96 (91) Water 83 (78) 83 (78) Auxiliary Power 687 (651) 687 (651) TOTAL 5,994 (5,681) 208 (197) 687 (651) 6,889 (6,529) Heat Out GJ/hr (MMBtu/hr) ASU Vent 2 (2) 2 (2) Slag 92 (88) 38 (36) 130 (123) Sulfur 51 (49) 1 (1) 52 (49) CO 2 

## - 74 (

- 70)

- 74 (

- 70) Cooling Tower Blowdown 30 (28) 30 (28) HRSG Flue Gas 1,318 (1,250) 1,318 (1,250) Condenser 1,513 (1,434) 1,513 (1,434) Non

- Condenser Cooling Tower Loads* 632 (599) 632 (599)
Process Losses** 643 (610) 643 (610) Power 2,642 (2,505) 2,642 (2,505) TOTAL 144 (136) 4,103 (3,889) 2,642 (2,505) 6,889 (6,529)

* Includes ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, and

syngas cooler (low level heat rejection). ** Calculated by difference to close the energy balance

.

### Cost and Performance Baseline for Fossil Energy Plants

146 

## 3.2.10 Major equipment items for the GEE gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 2

- Major Equipment List

3.2.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 3 0

### Cost and Performance Baseline for Fossil Energy Plants

147 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 299,921 liters (79,230 gal) 2 0

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 392,323 liters (103,640 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,176,894 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,407 lpm (900 gpm) 2 2

### Cost and Performance Baseline for Fossil Energy Plants

148 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,093,984 liters (289,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,836 lpm @ 91 m H2O (2,070 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 546,579 kg/hr (1,205,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,025 lpm @ 27 m H2O (2,120 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 6,057 lpm @ 1,859 m H2O (1,600 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 1,703 lpm @ 223 m H2O (450 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 362 GJ/hr (343 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 129,840 lpm @ 21 m H2O (34,300 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 5,716 lpm @ 18 m H2O (1,510 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,839 lpm @ 268 m H2O (750 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single suction 3,369 lpm @ 49 m H2O (890 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,608,800 liter (425,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 1,476 lpm (390 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

149 

## ACCOUNT 4 GASIFIER, ASU AND AC CESSORIES INCLUDING LOW TEMPERATURE HEAT REC OVERY Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, entrained bed 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 0

2 Synthesis Gas Cooler Vertical downflow radiant heat exchanger with outlet quench chamber 255,826 kg/hr (564,000 lb/hr) 2 0

3 Syngas Scrubber Including Sour Water Stripper Vertical upflow 350,173 kg/hr (772,000 lb/hr) 2 0

4 Raw Gas Coolers Shell and tube with condensate drain 388,275 kg/hr (856,000 lb/hr) 8 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 304,360 kg/hr, 35°C, 5.2 MPa (671,000 lb/hr, 95°F, 750 psia) 2 0

6 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 350,173 kg/hr (772,000 lb/hr) syngas 2 0

7 ASU Main Air Compressor Centrifugal, multi-stage 5,947 m3/min @ 1.3 MPa (210,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi-stage 1,189 m3/min (42,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 6.5 MPa (940 psia) 2 0

10 Primary Nitrogen Compressor Centrifugal, multi-stage 3,794 m3/min (134,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

11 Secondary Nitrogen Compressor Centrifugal, single-stage 538 m3/min (19,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

12 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single-stage 1,982 m3/min (70,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 3.2 MPa (470 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

150 

## ACCOUNT 5A SOUR GAS SHIFT AND S YNGAS CLEANUP

ACCOUNT 5B CO 2 

## COMPRESSION

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 303,907 kg/hr (670,000 lb/hr) 35 °C ( 95 °F ) 5.1 MPa (745 psia) 2 0

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 388,275 kg/hr (856,000 lb/hr) 227 °C ( 440 °F ) 5.4 MPa (790 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 157 GJ/hr (149 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two-stage Selexol 310,711 kg/hr (685,000 lb/hr) 35 °C ( 95 °F ) 5.1 MPa (740 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 18,009 kg/hr (39,704 lb/hr) 232 °C ( 450 °F ) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 13,782 kg/hr (30,385 lb/hr) 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 CO2 Compressor Integrally geared, multi-stage centrifugal 1,133 m3/min @ 15.3 MPa (40,000 scfm @ 2,215 psia) 4 0

### Cost and Performance Baseline for Fossil Energy Plants

151 

## A CCOUNT 6 COMBUSTION TURBINE A ND AUXILIARIES

ACCOUNT 7 HRSG, DUCTING, AND S TACK

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

3 Syngas Expansion Turbine/Generator Turbo Expander 49,578 kg/h (109,300 lb/h) 5.1 MPa (735 psia) Inlet 3.2 MPa (460 psia) Outlet 2 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 341,837 kg/hr, 12.4 MPa / 534 °C ( 753 , 621 lb / hr , 1 , 800 psig / 994 °F ) Reheat steam - 336,628 kg/hr, 3

. 1 MPa / 534 °C ( 742 , 137 lb / hr , 452 psig / 994 °F ) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

152 

## ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 277 MW 12

. 4 MPa / 534 °C / 534 °C ( 1 , 800 psig / 994 °F / 994 °F ) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 310 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,667 GJ/hr (1,580 MMBtu/hr), Inlet water temperature 16 °C ( 60 °F ) , Water temperature rise 11 °C ( 20 °F ) 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 461,820 lpm @ 30 m (122,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11 °C ( 51

. 5 °F ) wet bulb / 16 °C ( 60 °F ) CWT / 27 °C ( 80 °F ) HWT / 2,585 GJ/hr (2,450 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

153 

## ACCOUNT 10 SLAG RECOVERY AND HA NDLING Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 2 0
2 Slag Crusher Roll 14 tonne/hr (15 tph) 2 0
3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 68,137 liters (18,000 gal) 2
6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 2 0
7 Slag Separation Screen Vibrating 14 tonne/hr (15 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 14 tonne/hr (15 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 215,768 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O (60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 998 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

154 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 310 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 80 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 48 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

155 

## 3.2.11 The cost estimating methodology was described previously in Section Case 2

- Cost Estimating 2.7

. E xhibit 3

- 40 shows the TPC summary organized by cost account and Exhibit 3

- 41 shows a more detailed breakdown of th e capital costs along with owner’s costs, TOC, and TASC

. Exhibit 3

- 42 shows the initial and annual O&M costs. The estimated TO C of the GEE gasifier with CO 2 

## capture is $ 3,334 /kW. Process contingency represents 3.6 percent of the TPC and project contingency represents 11.1 percent. The COE, including CO 2 

## TS&M costs of 5

. 3 mills/kWh is 1 05

. 7 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

156 

## Exhibit 3

- 40 Case 2 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 2 - GEE Radiant 550MW IGCC w/ CO2 Plant Size: 543.3 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $14,280 $2,654 $11,074 $0 $0 $28,008 $2,542 $0 $6,110 $36,660 $67

2 COAL & SORBENT PREP & FEED $24,391 $4,448 $14,651 $0 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108

3 FEEDWATER & MISC. BOP SYSTEMS $10,158 $7,914 $10,237 $0 $0 $28,309 $2,671 $0 $7,166 $38,146 $70

4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $0 $176,251 $16,146 $24,460 $33,252 $250,109 $460 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $429 4.4-4.9 Other Gasification Equipment $7,894 $12,285 $12,270 $0 $0 $32,449 $3,078 $0 $7,755 $43,282 $80 SUBTOTAL 4 $314,803 $12,285 $74,659 $0 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969

5A GAS CLEANUP & PIPING $96,775 $3,334 $82,247 $0 $0 $182,357 $17,666 $27,526 $45,625 $273,174 $503

5B CO2 COMPRESSION $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $239 6.2-6.9 Combustion Turbine Other $5,550 $887 $1,748 $0 $0 $8,185 $775 $0 $1,650 $10,610 $20 SUBTOTAL 6 $97,576 $887 $8,331 $0 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $0 $38,401 $3,651 $0 $4,205 $46,257 $85 7.2-7.9 SCR System, Ductwork and Stack $3,376 $2,407 $3,153 $0 $0 $8,936 $828 $0 $1,589 $11,353 $21 SUBTOTAL 7 $36,996 $2,407 $7,933 $0 $0 $47,336 $4,480 $0 $5,794 $57,610 $106

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $0 $32,931 $3,160 $0 $3,609 $39,699 $73 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,211 $967 $7,075 $0 $0 $18,253 $1,662 $0 $3,950 $23,865 $44 SUBTOTAL 8 $38,333 $967 $11,883 $0 $0 $51,183 $4,821 $0 $7,559 $63,564 $117

9 COOLING WATER SYSTEM $10,319 $9,775 $8,388 $0 $0 $28,483 $2,646 $0 $6,348 $37,477 $69

10 ASH/SPENT SORBENT HANDLING SYS $14,734 $8,239 $14,938 $0 $0 $37,910 $3,652 $0 $4,476 $46,038 $85

11 ACCESSORY ELECTRIC PLANT $32,062 $12,584 $24,591 $0 $0 $69,237 $5,953 $0 $14,261 $89,451 $165

12 INSTRUMENTATION & CONTROL $11,404 $2,098 $7,347 $0 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51

13 IMPROVEMENTS TO SITE $3,485 $2,054 $8,600 $0 $0 $14,140 $1,396 $0 $4,661 $20,196 $37

14 BUILDINGS & STRUCTURES $0 $6,882 $7,834 $0 $0 $14,716 $1,340 $0 $2,628 $18,684 $34

TOTAL COST $723,574 $76,529 $303,902 $0 $0 $1,104,005 $103,905 $64,468 $200,468 $1,472,845 $2,711 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

157 

## Exhibit 3

- 41 Case 2 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,750 $0 $1,833 $0 $0 $5,583 $500 $0 $1,217 $7,299 $13 1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $0 $6,021 $528 $0 $1,310 $7,858 $14 1.3 Coal Conveyors & Yd Crush $4,505 $0 $1,162 $0 $0 $5,668 $498 $0 $1,233 $7,398 $14 1.4 Other Coal Handling $1,179 $0 $269 $0 $0 $1,448 $127 $0 $315 $1,889 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,654 $6,635 $0 $0 $9,289 $890 $0 $2,036 $12,215 $22 SUBTOTAL 1. $14,280 $2,654 $11,074 $0 $0 $28,008 $2,542 $0 $6,110 $36,660 $67 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $0 $2,236 $191 $0 $485 $2,913 $5 2.3 Slurry Prep & Feed $21,908 $0 $9,667 $0 $0 $31,575 $2,869 $1,579 $7,205 $43,227 $80 2.4 Misc.Coal Prep & Feed $881 $641 $1,922 $0 $0 $3,443 $316 $0 $752 $4,512 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,424 $2,811 $0 $0 $6,234 $577 $0 $1,362 $8,174 $15 SUBTOTAL 2. $24,391 $4,448 $14,651 $0 $0 $43,489 $3,954 $1,579 $9,804 $58,826 $108 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,836 $4,870 $2,571 $0 $0 $10,276 $952 $0 $2,246 $13,474 $25 3.2 Water Makeup & Pretreating $717 $75 $401 $0 $0 $1,193 $114 $0 $392 $1,699 $3 3.3 Other Feedwater Subsystems $1,552 $524 $472 $0 $0 $2,548 $229 $0 $555 $3,332 $6 3.4 Service Water Systems $411 $845 $2,934 $0 $0 $4,190 $409 $0 $1,380 $5,979 $11 3.5 Other Boiler Plant Systems $2,203 $854 $2,116 $0 $0 $5,173 $491 $0 $1,133 $6,796 $13 3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $4 3.7 Waste Treatment Equipment $1,003 $0 $612 $0 $0 $1,615 $157 $0 $532 $2,303 $4 3.8 Misc. Power Plant Equipment $1,121 $150 $576 $0 $0 $1,847 $178 $0 $608 $2,634 $5 SUBTOTAL 3. $10,158 $7,914 $10,237 $0 $0 $28,309 $2,671 $0 $7,166 $38,146 $70 4 GASIFIER & ACCESSORIES 4.1 Syngas Cooler Gasifier System $113,863 $0 $62,389 $0 $0 $176,251 $16,146 $24,460 $33,252 $250,109 $460 4.2 Syngas Cooler (w/ Gasifier - $) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $429 4.4 Scrubber & Low Temperature Cooling $6,049 $4,924 $5,125 $0 $0 $16,097 $1,546 $0 $3,529 $21,172 $39 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Soot Recovery & SARU $1,845 $876 $1,731 $0 $0 $4,452 $429 $0 $976 $5,857 $11 4.8 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $6,486 $5,414 $0 $0 $11,900 $1,103 $0 $3,251 $16,253 $30 SUBTOTAL 4. $314,803 $12,285 $74,659 $0 $0 $401,747 $37,935 $24,460 $62,183 $526,325 $969

### Cost and Performance Baseline for Fossil Energy Plants

158 

## Exhibit 3

- 41 Case 2 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $74,127 $0 $62,899 $0 $0 $137,025 $13,252 $27,405 $35,536 $213,219 $392 5A.2 Elemental Sulfur Plant $10,329 $2,059 $13,326 $0 $0 $25,713 $2,498 $0 $5,642 $33,853 $62 5A.3 Mercury Removal $1,376 $0 $1,047 $0 $0 $2,423 $234 $121 $556 $3,334 $6 5A.4 Shift Reactors $9,594 $0 $3,862 $0 $0 $13,456 $1,290 $0 $2,949 $17,696 $33 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,349 $0 $256 $0 $0 $1,605 $196 $0 $360 $2,161 $4 5A.7 Fuel Gas Piping $0 $634 $444 $0 $0 $1,078 $100 $0 $236 $1,413 $3 5A.9 HGCU Foundations $0 $642 $414 $0 $0 $1,056 $97 $0 $346 $1,498 $3 SUBTOTAL 5A. $96,775 $3,334 $82,247 $0 $0 $182,357 $17,666 $27,526 $45,625 $273,174 $503 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71 SUBTOTAL 5B. $18,256 $0 $11,190 $0 $0 $29,446 $2,836 $0 $6,456 $38,739 $71 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $239 6.2 Syngas Expander $5,550 $0 $767 $0 $0 $6,316 $600 $0 $1,038 $7,954 $15 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $5 SUBTOTAL 6. $97,576 $887 $8,331 $0 $0 $106,794 $10,123 $9,861 $13,432 $140,210 $258 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,620 $0 $4,780 $0 $0 $38,401 $3,651 $0 $4,205 $46,257 $85 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,731 $1,235 $0 $0 $2,965 $260 $0 $645 $3,870 $7 7.4 Stack $3,376 $0 $1,268 $0 $0 $4,644 $445 $0 $509 $5,598 $10 7.9 HRSG, Duct & Stack Foundations $0 $676 $650 $0 $0 $1,326 $123 $0 $435 $1,884 $3 SUBTOTAL 7. $36,996 $2,407 $7,933 $0 $0 $47,336 $4,480 $0 $5,794 $57,610 $106 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,123 $0 $4,808 $0 $0 $32,931 $3,160 $0 $3,609 $39,699 $73 8.2 Turbine Plant Auxiliaries $195 $0 $447 $0 $0 $642 $63 $0 $70 $775 $1 8.3 Condenser & Auxiliaries $5,009 $0 $1,471 $0 $0 $6,480 $619 $0 $710 $7,809 $14 8.4 Steam Piping $5,006 $0 $3,522 $0 $0 $8,528 $733 $0 $2,315 $11,576 $21 8.9 TG Foundations $0 $967 $1,635 $0 $0 $2,603 $247 $0 $855 $3,704 $7 SUBTOTAL 8. $38,333 $967 $11,883 $0 $0 $51,183 $4,821 $0 $7,559 $63,564 $117

### Cost and Performance Baseline for Fossil Energy Plants

159 

## Exhibit 3

- 41 Case 2 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,155 $0 $1,302 $0 $0 $8,457 $805 $0 $1,389 $10,652 $20 9.2 Circulating Water Pumps $1,856 $0 $134 $0 $0 $1,990 $168 $0 $324 $2,481 $5 9.3 Circ.Water System Auxiliaries $155 $0 $22 $0 $0 $177 $17 $0 $29 $224 $0 9.4 Circ.Water Piping $0 $6,481 $1,680 $0 $0 $8,161 $738 $0 $1,780 $10,679 $20 9.5 Make-up Water System $388 $0 $555 $0 $0 $943 $90 $0 $207 $1,240 $2 9.6 Component Cooling Water Sys $765 $915 $651 $0 $0 $2,331 $218 $0 $510 $3,060 $6 9.9 Circ.Water System Foundations $0 $2,379 $4,044 $0 $0 $6,423 $609 $0 $2,110 $9,142 $17 SUBTOTAL 9. $10,319 $9,775 $8,388 $0 $0 $28,483 $2,646 $0 $6,348 $37,477 $69 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $0 $32,424 $3,129 $0 $3,555 $39,109 $72 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $589 $0 $641 $0 $0 $1,229 $119 $0 $202 $1,551 $3 10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $0 $980 $91 $0 $161 $1,232 $2 10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $0 $3,160 $301 $0 $519 $3,980 $7 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $39 $167 $0 SUBTOTAL 10. $14,734 $8,239 $14,938 $0 $0 $37,910 $3,652 $0 $4,476 $46,038 $85 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $947 $0 $937 $0 $0 $1,885 $180 $0 $206 $2,271 $4 11.2 Station Service Equipment $4,697 $0 $423 $0 $0 $5,121 $472 $0 $559 $6,152 $11 11.3 Switchgear & Motor Control $8,684 $0 $1,579 $0 $0 $10,264 $952 $0 $1,682 $12,898 $24 11.4 Conduit & Cable Tray $0 $4,034 $13,308 $0 $0 $17,342 $1,677 $0 $4,755 $23,775 $44 11.5 Wire & Cable $0 $7,708 $5,064 $0 $0 $12,772 $928 $0 $3,425 $17,125 $32 11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,016 $7 11.7 Standby Equipment $234 $0 $228 $0 $0 $462 $44 $0 $76 $581 $1 11.8 Main Power Transformers $17,500 $0 $144 $0 $0 $17,644 $1,334 $0 $2,847 $21,825 $40 11.9 Electrical Foundations $0 $156 $410 $0 $0 $567 $54 $0 $186 $807 $1 SUBTOTAL 11. $32,062 $12,584 $24,591 $0 $0 $69,237 $5,953 $0 $14,261 $89,451 $165 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,126 $0 $752 $0 $0 $1,877 $178 $94 $322 $2,471 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $259 $0 $166 $0 $0 $425 $40 $21 $97 $583 $1 12.7 Computer & Accessories $6,005 $0 $192 $0 $0 $6,197 $569 $310 $708 $7,784 $14 12.8 Instrument Wiring & Tubing $0 $2,098 $4,288 $0 $0 $6,386 $542 $319 $1,812 $9,059 $17 12.9 Other I & C Equipment $4,014 $0 $1,949 $0 $0 $5,963 $561 $298 $1,023 $7,846 $14 SUBTOTAL 12. $11,404 $2,098 $7,347 $0 $0 $20,849 $1,889 $1,042 $3,962 $27,743 $51

### Cost and Performance Baseline for Fossil Energy Plants

160 

## Exhibit 3

- 41 Case 2 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $109 $2,337 $0 $0 $2,447 $243 $0 $807 $3,496 $6 13.2 Site Improvements $0 $1,945 $2,585 $0 $0 $4,530 $447 $0 $1,493 $6,470 $12 13.3 Site Facilities $3,485 $0 $3,678 $0 $0 $7,163 $706 $0 $2,361 $10,230 $19 SUBTOTAL 13. $3,485 $2,054 $8,600 $0 $0 $14,140 $1,396 $0 $4,661 $20,196 $37 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,377 $3,387 $0 $0 $5,764 $530 $0 $944 $7,238 $13 14.3 Administration Building $0 $882 $640 $0 $0 $1,522 $136 $0 $249 $1,906 $4 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $253 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $600 $585 $0 $0 $1,185 $107 $0 $194 $1,486 $3 14.6 Machine Shop $0 $452 $309 $0 $0 $761 $68 $0 $124 $952 $2 14.7 Warehouse $0 $729 $471 $0 $0 $1,200 $106 $0 $196 $1,502 $3 14.8 Other Buildings & Structures $0 $437 $340 $0 $0 $777 $69 $0 $169 $1,015 $2 14.9 Waste Treating Building & Str. $0 $976 $1,865 $0 $0 $2,841 $265 $0 $621 $3,728 $7 SUBTOTAL 14. $0 $6,882 $7,834 $0 $0 $14,716 $1,340 $0 $2,628 $18,684 $34

TOTAL COST $723,574 $76,529 $303,902 $0 $0 $1,104,005 $103,905 $64,468 $200,468 $1,472,845 $2,711
Owner's Costs Preproduction Costs 6 Months All Labor $13,488 $25 1 Month Maintenance Materials $2,998 $6 1 Month Non-fuel Consumables $384 $1 1 Month Waste Disposal $318 $1 25% of 1 Months Fuel Cost at 100% CF $1,697 $3 2% of TPC $29,457 $54 Total $48,341 $89 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,068 $26 0.5% of TPC (spare parts) $7,364 $14 Total $21,432 $39
Initial Cost for Catalyst and Chemicals $7,199 $13 Land $900 $2 Other Owner's Costs $220,927 $407

Financing Costs $39,767 $73 Total Overnight Costs (TOC) $1,811,411 $3,334 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,065,009 $3,801

### Cost and Performance Baseline for Fossil Energy Plants

161 

## Exhibit 3

- 42 Case 2 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 2 - GEE Radiant 550MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,458 MWe-net: 543 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $11.622 Maintenance Labor Cost $15,266,708 $28.103 Administrative & Support Labor $5,395,054 $9.931 Property Taxes and Insurance $29,456,896 $54.223 TOTAL FIXED OPERATING COSTS $56,432,165 $103.879 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $28,779,845 $0.00756

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,187 1.08 $0 $1,322,398 $0.00035

Chemicals

MU & WT Chem. (lbs) 0 24,944 0.17 $0 $1,260,554 $0.00033 Carbon (Mercury Removal) (lb) 79,786 109 1.05 $83,789 $33,516 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,246 4.28 498.83 $3,115,855 $623,171 $0.00016 Selexol Solution (gal) 298,502 95 13.40 $3,999,401 $371,618 $0.00010 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip 2.01 131.27 $0 $77,209 $0.00002 Subtotal-Chemicals $7,199,046 $2,366,068 $0.00062

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal-Other $0 $0 $0.00000
Waste Disposal

Spent Mercury Catalyst (lb.) 0 109 0.42 $0 $13,311 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 641 16.23 $0 $3,037,841 $0.00080 Subtotal Waste Disposal $0 $3,051,152 $0.00080 By-products & Emissions 0 0 0.00 $0 $0.00000

Sulfur (ton) 0 146 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,199,046 $35,519,462 $0.00933

Fuel (ton) 0 5,844 38.18 $0 $65,161,317 $0.01712

### Cost and Performance Baseline for Fossil Energy Plants

162 

## 3.3 CONOCOPHILLIPS E

- GAS TM 

## IGCC CASES This section contains an evaluation of plant designs for Cases 3 and 4, which are based on the CoP E

- GasTM gasifier. Cases 3 and 4 are very similar in terms of process, equipment, scope and arrangement, except that Case 4 includes SGS reactors, CO 2 

## absorption/regeneration and compression/transport systems. There are no provisions for CO 2 

## removal in Case 3. The balance of this section is organized in an analogous manner to Section 3.2 :

**•** Gasifier Background

**•** Process System Description for Case 3

**•** Key Assumptions for Cases 3 and 4

**•** Sparing Philosophy for Cases 3 and 4

**•** Performance Results for Case 3

**•** Equipment List for Case 3

**•** Cost Estimates for Case 3

**•** Process and System Description, Performance Results, Equipment List , and Cost Estimate for Case 4
3.3.1 Dow Chemical (the former principal stockholder of Destec Energy, which was bought by Global Energy, Inc., the gasifier business that was later purchased by CoP is a major producer of chemicals. They began coal gasification development work in 1976 with be nch

- scale (2 kg/h r [4 lb/h r ]) reactor testing. Important fundamental data were obtained for conversion and yields with various coals and operating conditions. This work led to the construction of a pilot plant at Dow’s large chemical complex in Plaquemin e, Louisiana. The pilot plant was designed for a capacity of 11 tonnes/day (12 TPD) (dry lignite basis) and was principally operated with air as the oxidant. The plant also operated with oxygen at an increased capacity of 33 tonnes/day (36 TPD) (dry lign ite basis). This pilot plant operated from 1978 through 1983. Gasifier Background

Following successful operation of the pilot plant, Dow built a larger 499 tonnes/day (550 TPD) (dry lignite basis) gasifier at Plaquemine. In 1984, Dow Chemical and the U.S. Synthetic Fuels Co rporation (SFC) announced a price guarantee contract , which allowed the building of the first commercial

- scale Dow coal gasification unit. The Louisiana Gasification Technology, Inc. (LGTI) plant, sometimes called the Dow Syngas Project, was also located in the Dow Plaquemine chemical complex. The plant gasified about 1,451 tonnes/day (1,600 TPD) (dry basis) of subbituminous coal to generate 184 MW (gross) of combined

- cycle electricity. To ensure continuous power output to the petrochemical complex, a mi nimum of 20 percent of natural gas was co

- fired with the syngas. LGTI was operated from 1987 through 1995. In September 1991, DOE selected the Wabash River coal gasification repowering project, which used the Destec Energy process, for funding under the C lean Coal Technology Demonstration Program. The project was a joint venture of Destec and Public Service of Indiana (PSI Energy, Inc.). Its purpose was to repower a unit at PSI’s Wabash River station in West Terre Haute, Indiana to produce 265 MW of net power from local high

- sulfur bituminous coal. The design of

### Cost and Performance Baseline for Fossil Energy Plants

163 

## the project gasifier was based on the Destec LGTI gasifier. Experience gained in that project provided significant input to the design of the Wabash River coal gasification facility and eliminat ed much of the risk associated with scale

- up and process variables. Gasifier Capacity

– T he gasifier originally developed by Dow is now known as the CoP E

GasTM gasifier. The daily coal

- handling capacity of the E

- Gas gasifier operating at Plaquemine was i n the range of 1,270 tonnes (1,400 tons) (moisture/ash

- free [MAF] basis) for bituminous coal to 1,497 tonnes (1,650 tons) for lignite. The dry gas production rate was 141,600 Nm 3 

## /h r (5 million scf/h r ) with an energy content of about 1,370 MMkJ/h r (1,300 MMBtu/h r ) (HHV). The daily coal

- handling capacity of the gasifier at Wabash River is about 1,678 tonnes (1,850 tons) (MAF basis) for high

- sulfur bituminous coal. The dry gas production rate is about 189,724 Nm 3 

## /hr (6.7 million scf/h r ) with an ene rgy content of about 1,950 MMkJ/h r (1,850 MMBtu/h r ) (HHV). This size matches the CT , which is a GE 7FA. With increased power and fuel GT demand, the gasifier coal feed increases proportionately. CoP has indicated that the gasifier can readily handle the increased demand. Distinguishing Characteristics

- A key advantage of the CoP coal gasification technology is the current operating experience with subbituminous coal at full commercial scale at the Plaquemine plant and bituminous coal at the Wabash plant. The two

- stage operation improves the efficiency, reduces oxygen requirements, and enables more effective operation on slurry feeds relative to a single stage gasifier. The fire

- tube SGC used by E

- Gas has a lower capital cost than a water

- tube design, an added advantage for the CoP technology at this time. However, this experience may spur other developers to try fire

- tube designs. Entrained

- flow gasifiers have fundamental environmental advantages over fluidized

- bed and moving

- bed gasifiers. They produc e no hydrocarbon liquids, and the only solid waste is an inert slag. The key disadvantages of the CoP coal gasification technology are the relatively short refractory life and the high waste heat recovery (SGC) duty. As with the other entrained

- flow slagg ing gasifiers, these disadvantages result from high operating temperature. However, the two

- stage operation results in a quenched syngas that is higher in CH 4 

## content than other gasifiers. This becomes a disadvantage in CO 2 

## capture cases since the CH 4 

## pa sses through the SGS reactors without change, and is also not separated by the AGR thus limiting the amount of carbon that can be captured. Important Coal Characteristics

- The slurry feeding system and the recycle of process condensate water as the princi pal slurrying liquid make low levels of ash and soluble salts desirable coal characteristics for use in the E

- GasTM coal gasification process. High ash levels increase the ratio of water to carbon in the coal in the feed slurry, thereby increasing the oxyg en requirements. Soluble salts affect the processing cost and amount of water blowdown required to avoid problems associated with excessive buildup of salts in the slurry water recycle loop. Bituminous coals with lower inherent moisture improve the slurry concentration and reduce oxygen requirements. The two

- stage operation reduces the negative impact of low

- rank coal use in slurry feed, entrained

- flow gasification. Low to moderate ash fusion

- temperature coals are preferred for slagging gasifiers. Coals with high ash fusion temperatures may require flux addition for optimal gasification operation.

### Cost and Performance Baseline for Fossil Energy Plants

164 

## 3.3.2 In this section the overall CoP gasification process is described. The system description follows the BFD in Process Description

Exhibit 3

- 43 and str eam numbers reference the same e xhibit. The tables in Exhibit 3

- 44 provide process dat a for the numbered streams in the BFD.

Coal receiving and handling is common to all cases and was covered in Section Coal Grinding and Slurry Preparation 3.1.1

. The receiving and handling subsystem ends at the coal silo. Coal grinding and slurry preparation is similar to the GEE cases but repeated here for completeness. Coal from the coal silo is fed onto a conveyor by vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry water pumps. T he coal slurry is discharged through a trommel screen into the rod mill discharge tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62

- 68 percent using bituminous coal and CoP presented a paper showing the slurry concentration of Ill inois No. 6 coal as 63 percent [ 58 ]

. The coa l grinding system is equipped with a dust suppression system consisting of water sprays aided by a wetting agent. The degree of dust suppression required depends on local environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal slurry solids suspended. The equipment in the coal grinding and slurry preparation system is fabricated of materials appropriate for the abrasive environment present in the system. The tanks and agitators are rubber lined. The pumps are ei ther rubber

- lined or hardened metal to minimize erosion. Piping is fabricated of HDPE.

This plant utilizes two gasification trains to process a total of 5,0 07 tonnes/day (5, 519 TPD) of Illinois No. 6 coal. Each of the 2 x 50 percent gasifier s operate at maximum capacity. The E

GasTM two

- stage coal gasification technology features an oxygen

- blown, entrained

- flow, refractory

- lined gasifier with continuous slag removal. About 78 percent of the total slurry feed is fed to the first (or bottom) s tage of the gasifier. The air separation plant supplies 3,711 tonnes/day (4,090 TPD) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). All oxygen for gasification is fed to this stage of the gasifier at a pressure of 4.2 MP a (615 psia). This stage is best described as a horizontal cylinder with two horizontally opposed burners. The highly exothermic gasification/oxidation reactions take place rapidly at temperatures of 1,316 to 1,427°C (2,400 to 2,600 **°** F). The hot raw gas from the first stage enters the second (top) stage, which is a vertical cylinder perpendicular to the first stage. The remaining 22 percent of coal slurry is injected into this hot raw gas. The endothermic gasification/devolatilization reaction in this s tage reduces the final gas temperature to about 1, 038 °C (1, 900 **°** F). Total slurry to both stages is shown as stream 7 in Gasification

Exhibit 3

- 43

.

### Cost and Performance Baseline for Fossil Energy Plants

165 

## Exhibit 3

- 43 Case 3 Block Flow Diagram , E

- GasTM IGCC without CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

166 

## Exhibit 3

- 44 Case 3 Stream Table , E

- GasTM IGCC without CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0241 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0078 0.0078 0.0096 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0465 0.0465 0.0575 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3011 0.3011 0.3727 CO 2 0.0003 0.0083 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1556 0.1559 0.1929 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2724 0.2724 0.3372 H 2 O 0.0099 0.2163 0.0000 0.0003 0.0000 1.0000 0.0000 0.9968 0.0000 0.1889 0.1885 0.0015 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.0000 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0072 0.0075 0.0092 N 2 0.7732 0.5460 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0157 0.0157 0.0194 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0000 0.0045 0.0045 0.0000 O 2 0.2074 0.2054 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 18,976 916 111 17,427 4,694 3,766 0 4,758 0 21,817 21,817 17,626 V-L Flowrate (kg/hr) 547,576 24,820 3,567 489,004 151,056 67,848 0 85,707 0 459,732 459,732 384,240 Solids Flowrate (kg/hr) 0 0 0 0 0 0 208,634 0 21,295 0 0 0
Temperature (°C) 15 20 32 93 32 343 15 149 1,038 186 186 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 0.10 5.79 4.24 4.07 4.00 3.83 Enthalpy (kJ/kg) A 30.23 36.92 26.67 92.52 26.67 0.00

--- 567.36

--- 673.10 672.88 39.55 Density (kg/m 3 ) 1.2 1.6 11.0 24.4 11.0 20.1

--- 862.4

--- 22.7 22.3 33.0 V-L Molecular Weight 28.857 27.090 32.181 28.060 32.181 18.015

--- 18.012

--- 21.073 21.073 21.799
V-L Flowrate (lb mol /hr) 41,834 2,020 244 38,420 10,348 8,303 0 10,490 0 48,098 48,098 38,859 V-L Flowrate (lb/hr) 1,207,199 54,719 7,864 1,078,070 333,021 149,578 0 188,951 0 1,013,536 1,013,536 847,104 Solids Flowrate (lb/hr) 0 0 0 0 0 0 459,958 0 46,947 0 0 0
Temperature (°F) 59 69 90 199 90 650 59 300 1,900 367 367 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 14.7 840.0 615.0 590.0 580.0 555.0 Enthalpy (Btu/lb) A 13.0 15.9 11.5 39.8 11.5

--- 243.9

--- 289.4 289.3 17.0 Density (lb/ft 3 ) 0.076 0.098 0.687 1.521 0.687 1.257

--- 53.837

--- 1.416 1.391 2.061 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

167 

## Exhibit 3

- 44 Case 3 Stream Table ( Continued )
13 14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction

Ar 0.0095 0.0098 0.0085 0.0085 0.0000 0.0000 0.0041 0.0055 0.0092 0.0092 0.0087 0.0087 0.0000 CH 4 0.0555 0.0576 0.0500 0.0500 0.0002 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.3597 0.3734 0.3241 0.3241 0.0010 0.0000 0.0848 0.0061 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.2137 0.1931 0.1676 0.1676 0.7537 0.0000 0.4983 0.7790 0.0003 0.0003 0.0803 0.0803 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.3299 0.3425 0.2973 0.2973 0.0009 0.0000 0.0209 0.1311 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0015 0.0015 0.1333 0.1333 0.0000 0.0000 0.3350 0.0018 0.0099 0.0099 0.0860 0.0860 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0090 0.0000 0.0000 0.0000 0.2443 0.0000 0.0014 0.0043 0.0000 0.0000 0.0000 0.0000 0.0000 N 2 0.0213 0.0221 0.0192 0.0192 0.0000 0.0000 0.0537 0.0723 0.7732 0.7732 0.7250 0.7250 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1000 0.1000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 18,275 17,601 20,276 20,276 674 0 873 649 110,253 4,410 137,246 137,246 40,181 V-L Flowrate (kg/hr) 408,330 380,350 428,548 428,548 27,980 0 28,108 24,090 3,181,557 127,262 3,971,848 3,971,848 723,874 Solids Flowrate (kg/hr) 0 0 0 0 0 5,215 0 0 0 0 0 0 0
Temperature (°C) 34 45 143 193 45 175 232 38 15 432 588 132 561 Pressure (MPa, abs) 3.79 3.76 3.21 3.2 3.757 0.409 0.406 5.512 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg) A 36.82 55.08 489.40 569.9 -0.670

--- 731.470 -6.625 30.227 463.785 783.868 272.294 3,500.624 Density (kg/m 3 ) 33.7 31.0 19.7 17.3 73.5 5,285.4 3.1 96.3 1.2 7.9 0.4 0.9 35.2 V-L Molecular Weight 22.344 21.610 21.135 21 41.529

--- 32.209 37.141 28.857 28.857 28.940 28.940 18.015
V-L Flowrate (lb mol /hr) 40,289 38,804 44,702 44,702 1,485 0 1,924 1,430 243,066 9,723 302,576 302,576 88,584 V-L Flowrate (lb/hr) 900,213 838,528 944,788 944,788 61,685 0 61,967 53,110 7,014,133 280,565 8,756,427 8,756,427 1,595,870 Solids Flowrate (lb/hr) 0 0 0 0 0 11,497 0 0 0 0 0 0 0
Temperature (°F) 94 112 290 380 112 347 450 100 59 810 1,091 270 1,041 Pressure (psia) 550.0 545.0 465.0 460.0 545.0 59.3 58.9 799.5 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 15.8 23.7 210.4 245.0 -0.3

--- 314.5 -2.8 13.0 199.4 337.0 117.1 1,505.0 Density (lb/ft 3 ) 2.105 1.938 1.230 1 4.586 329.954 0.195 6.012 0.076 0.495 0.026 0.056 2.194

### Cost and Performance Baseline for Fossil Energy Plants

168 

## The syngas produced by the CoP gasifier is higher in methane content than either the GEE or Shell gasifier. The two stage design allows for improved cold gas efficiency (CGE) and lower oxygen consumption, but the quenched second stage allows some CH 4 

## to r emain. The syngas CH 4 

## concentration exiting the gasifier in Case 3 is 4.3 vol% (compared to 0.10 vol% in Case 1 [GEE] and 0.0 01 vol% in Case 5 [Shell]). The relatively high CH 4 

## concentration impacts CO 2 

## capture efficiency as discussed further in Section 3.3.8

.

The raw syngas , less than 1, 038 °C (1, 900 **°** F) , from the second stage of the gasifier is cooled to 316 °C ( 600 °F) in the waste heat recovery ( SGC ) unit, which consists of a fire

- tube boiler and convective superheating and economizing sectio ns. 554,830 kg/hr (1,223,171 lb/hr) of HP saturated steam is raised as a result of the raw gas cooling. Fire

- tube boilers cost markedly less than comparable duty water

- tube boilers. This is because of the large savings in high

- grade steel associated with containing the hot HP syngas in relatively small tubes. Raw Gas Cooling/Particulate Removal

The coal ash is converted to molten slag, which flows down through a tap hole. The molten slag is quenched in water and removed through a proprietary continuous

- pressure letdown/dewatering system (stream 9 ). Char is produced in the second gasifier stage and is captured and rec ycled to the hotter first stage to be gasified. The cool ed gas from the SGC is cleaned of remaining particulate via a cyclone collector followed by a ceramic candle filter. Recycled syngas is used as the pulse gas to clean the candle filters. The recovered fines are pneumatically returned to the first stage o f the gasifier. The combination of recycled char and recycled particulate results in high overall carbon conversion (99.2 percent used in this study). Following particulate removal, additional heat is removed from the syngas to raise saturated IP steam at 0.4 MPa (65 psia) . In this manner the syngas is cooled to 232 °C ( 450 °F) prior to the syngas scrubber.

Syngas exiting the second of the two low temperature heat exchangers passes to a syngas scrubber where a water was h is used to remove chlorides , SO 2 

## , NH 3 

## , and particulate. The syngas exits the scrubber saturated at 169 °C ( 337 °F). Syngas Scrubber/Sour Water Stripper

The sour water stripper removes NH 3 

## , SO 2 

## , and other impurities from the scrubber and other waste streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber and condensate from SGC s. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid and sent to the SRU . Remaining water is sent to wastewater treatment.

Syngas exiting the scrubber is reheated to 186°C (367°F) by using HP steam from the HRSG evaporator prior to enter ing a COS hydrolysis reactor (stream 10 ). About 99.5 percent of the COS is converted to CO 2 

## and H 2 

## O (Section COS Hydrolysis , Mercury Removal and Acid Gas Removal

3.1.5 ). The gas exiting the COS reactor (stream 11 ) passes through a series of heat exchangers and KO drums to lower the syngas temperature to 35 °C ( 95 °F) and to separate entrained water. The coo led syngas (stream 12 ) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4 ).

### Cost and Performance Baseline for Fossil Energy Plants

169 

## Cool, particula te

- free syngas (stream 13 ) enters the absorb er unit at approximately 3. 8 MPa ( 550 psia) and 34 °C ( 94 °F). In the absorber, H 2 

## S is preferentially removed from the fuel gas stream by contact with MDEA. The absorber column is operated at 44 °C ( 112 °F) by refrigerating the lean MDEA solvent. The lower temperature is required to achieve an outlet H 2 

## S concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 1 7 ), consisting of 2 4 percent H 2 

## S and 7 5 percent CO 2 

## , is sent to the Claus unit. The acid gas is combined with t he sour water stripper off gas and introduced into the Claus plant burner section.

Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the acid gas along with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. In the furnace, H 2 

## S is catalytically oxidized to SO 2 

## at a furnace temperature of 1,316°C (2,400°F), which must be maintained in order to thermally decompose all of the NH 3 

## present in the sour gas stream. Claus Unit

Following the thermal st age and condensation of sulfur, two reheaters and two sulfur converters are used to obtain a per

- pass H 2 

## S conversion of approximately 99.5 percent. The Claus Plant tail gas is hydrogenated and recycle d back to the gasifier (stream 20 ). In the furnace was te heat boiler, 13,866 kg/h r ( 30,568 lb/h r ) of 3 .0 MPa ( 430 psia) steam is generated. This steam is used to satisfy all Claus process preheating and reheating requirements as well as to provide some steam to the medium

- pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header and IP steam at 2.9 MPa (415 psig)

. A flow rate of 5, 215 kg/h r (11, 497 lb/h r ) of elemental sulfur (stream 18 ) is recovered from the fuel gas stream. This value represents an overall sulfur recovery efficiency of 99. 7 percent.

Clean syng as exiting the MDEA absorber (stream 14 ) is partially humidified (stream 15 ) because there is not sufficient nitrogen from the ASU to provide the level of dilution required to reach the target syngas heating value. The moisturized syngas stream is reheate d (stream 16 ), further diluted with nitrogen from the ASU (stream 4) and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 19 percent of the total ASU air requirement (stream 22 ). The exhaust gas exit s the CT at 5 88 °C (1, 091 °F) (stream 23 ) and enters the HRSG where additional heat is recovered until the FG exits the HRSG at 132°C (270°F) (stream 24 ) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, c ommercially available steam turbine using a 12.4 MPa/ 561 °C/ 561 °C (1800 psig/ 1041 °F/ 1041 °F) steam cycle. Power Block

The elevated pressure ASU was described in Section Air Separation Unit 3.1.2 . In Case 3 , the ASU is designed to produce a nominal output of 3, 711 tonnes/day (4, 091 TPD) of 95 mol % O 2 

## for use in the gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air compressor is powered by an electric motor. Approximately 11,736 tonnes/day ( 12,937 TPD) of nitrogen are also recovered, compressed , and used as dilution in the GT combustor (stream 4). About 4 percent of the GT air is used to supply approximately 19 percent of the ASU air requirements (stream 2 2 ).

### Cost and Performance Baseline for Fossil Energy Plants

170 

## Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 , and 3.1.11

. 3.3.3 System assumptions for Cases 3 and 4, CoP IGCC with and without CO 2 

## capture, are compiled in Key System Assumptions

Exhibit 3

- 45

.
The balance of plant assumptions are common to all cases and were presented previously in Balance of Plant

– Cases 3 and 4

Exhibit 3

- 16

. 3.3.4 The sparing philosophy for Cases 3 and 4 is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment. Sparing Philosophy

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%)

**•** Two trains of slurry preparation and slurry pumps (2 x 50%)

**•** Two trains of gasification, including gasifier, SGC , cyclone, and candle filter (2 x 50%).

**•** Two trains of syngas clean

- up process (2 x 50%).

**•** Two trains of refrigerated MDEA AGR in Case 3 and two

- stage Selexol in Case 4 (2 x 50%),

**•** One train of Claus

- based sulfur recovery (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%).

### Cost and Performance Baseline for Fossil Energy Plants

171 

## Exhibit 3

- 45 CoP IGCC Plant Study Configuration Matrix Case 3 4 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615) O 2 

## :Coal Ratio, kg O 2 

## /kg dry coal 0.8 1 0.8 8 Carbon Conversion, % 99.2 99.2 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

## (Btu/scf) 8,3 19 ( 223 ) 7,02 1 ( 189 ) Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/56 1 /56 1 (1800/10 41 /10 41 ) 12.4/53 4 /53 4 (1800/ 994 / 994 ) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

CT 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each) Gasifier Technology CoP E

- GasTM CoP E

- GasTM Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Slurry Solids Content , % 63 63 COS Hydrolysis Yes Occurs in SGS SGS No Yes H 2 

## S Separation Refrigerated MDEA Selexol 1 st 

## Stage Sulfur Removal, % 99. 7 99. 9
Sulfur Recovery Claus Plant with Tail Gas Recycle to Gasifier/

Elemental Sulfur Claus Plant with Tail Gas Recycle to Gasifier/

Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N 2 

## Dilution and Humidification MNQC (LNB), N 2 

## Dilution and Humidification
CO 2 

## Separation N/A Selexol 2 nd 

## Stage Overall CO 2 

## Capture N/A 90 .4% CO 2 

## Sequestration N/A Off

- site Saline Formation

### Cost and Performance Baseline for Fossil Energy Plants

172 

## 3.3.5 The plant produces a net output of 625 MWe at a net plant efficiency of 39. 7 percent (HHV basis). Case 3 Performance Results

Overall performance for the entire plant is summarized in Exhibit 3

- 46 , which includes auxiliary power requirements. The ASU accounts for approximately 76 percent of the total auxiliary load distributed between the main air compressor, the oxyge n compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWP s and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 3. 9 percent. All other individual auxiliary loads are less than 3 .5 percent of the total.

### Cost and Performance Baseline for Fossil Energy Plants

173 

## Exhibit 3

- 46 Case 3 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 274,200 TOTAL POWER, kWe 738,200 AUXILIARY LOAD SUMMARY, kWe Coal Handling 460 Coal Milling 2,150 Sour Water Recycle Slurry Pump 180 Slag Handling 1,100 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 46,700 Oxygen Compressor 7,920 Nitrogen Compressors 29,910 Boiler Feedwater Pumps 4,410 Condensate Pump 240 Syngas Recycle Compressor 810 Circulating Water Pump 3,880 Ground Water Pumps 400 Cooling Tower Fans 2,010 Scrubber Pumps 320 Acid Gas Removal 3,150 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,610 Miscellaneous Balance of Plant 2 

### 3,000 Transformer Losses 2,540 TOTAL AUXILIARIES, kWe 113,140 NET POWER, kWe 625,060 Net Plant Efficiency, % (HHV) 39.7 Net Plant Heat Rate , kJ/kWh (Btu/kWh) 9,057 (8,585) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,414 (1,340) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 208,634 (459,958) Thermal Input 1 

### , kWt 1,572,582 Raw Water Withdrawal , m 3 

### /min (gpm) 16.5 (4,367) Raw Water Consumption , m 3 

### /min (gpm) 13.1 (3,465)
1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

174 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 3 is presented in Environmental Performance

Exhibit 3

- 47

. Exhibit 3

- 47 Case 3 Air Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)
SO 2 

## 0.005 (0.012) 200 (220) 0.039 (.09) NOx 0.026 (0.060) 1,017 (1,122) 0.197 (.434) Particulates 0.003 (0.0071) 121 (133) 0.023 (.052) Hg 2.46E

- 7 (5.71E

- 7) 0.010 (0.011) 1.88E

- 6 (4.15E

- 6) CO 2 

## 85.7 (199.2) 3,398,362 (3,746,053) 657 (1,448)
CO 2 1 

## 776 (1,710)

1 

### CO 2 

### emissions based on net power instead of gross power 

## The low level of SO 2 

## in the plant emissions is achieved by capture of the sulfur in the gas by the refrigerated Coastal SS Specialty Amine ( SS Amine ) AGR process. The AGR process removes 99 .7 percent of the sulfur compounds in the fuel gas down to a level of less than 30 ppmv. This results in a concentration in the FG of less than 4 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the gasifier, thereby eliminating the need for a tail gas treatment unit. NO x emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a lesser extent) to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and destroye d in the Claus plant burner. This helps lower NO x levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of the mercury is captured from the syngas by an activated carbon bed. CO 2 

## emissions represent the uncontrolled discharge from the process. The carbon balan ce for the plant is shown in Exhibit 3

- 48

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neg lected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag and CO 2 

## in t he stack gas and ASU vent gas.

### Cost and Performance Baseline for Fossil Energy Plants

175 

## Exhibit 3

- 48 Case 3 Carbon Bala nce Carbon In, kg/hr (lb/hr) Carbon Out, kg/h r (lb/hr) Coal 132,993 (293,199) Slag 1,064 (2,346) Air (CO 2 

## ) 507 (1,118) Stack Gas 132,344 (291,769) ASU Vent 92 (202) CO 2 

## Product 0 (0) Total 133,500 (294,317) Total 133,500 (294,317)

Exhibit 3

- 49 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfu r recovered in the Claus plant and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible. Exhibit 3

- 49 Case 3 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/h r (lb/hr) Coal 5,229 (11,528) Elemental Sulfur 5,215 (11,497) Stack Gas 14 (31) CO 2 

## Product 0 (0) Total 5,229 (11,528) Total 5,229 (11,528)

Exhibit 3

- 50 shows the overall water balance for the plant. The water balance was explained in Case 1 [GEE] , but is also presented here for completeness. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re

- used as internal recycle. The difference between demand and recycle is raw water wi thdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be r epresented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water sour ce from which it was withdrawn. Water c onsumption represents the net impact of the plant process on the water source balance.

### Cost and Performance Baseline for Fossil Energy Plants

176 

## Exhibit 3

- 50 Case 3 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdra wal, m 3 

### /min (gpm) Process Water Discharge,

m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)

Slag Handling 0.46 (122) 0.46 (122) 0.0 (0) 0.0 (0) 0.0 (0) Slurry Water 1.43 (378) 0.99 (263) 0.4 (115) 0.0 (0) 0.4 (115) Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier 0.8 (222) 0.8 (222) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.01 (4)

- 0.01 (

- 4) Condenser Makeup Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 1.3 (354) 1.1 (299)

0.21 (55) 0.0 (0) 1.3 (354) 1.1 (299)

0.21 (55) 0.0 (0) 1.3 (354)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 15.1 (3,991) 0.35 (93) 0.21 (55) 0.15 (38) 14.8 (3,898)

- 0.21 (

- 55)

- 0.15 (

- 38) 3.4 (897) 11.4 (3,000)

Total 19.2 (5,067) 2.65 (700) 16.5 (4,367) 3.4 (901) 13.1 (3,465)



## Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams Exhibit 3

- 51 through Exhibit 3

- 53 :

**•** Coal gasification and ASU

**•** Syngas cleanup , sulfur recovery , and tail gas recycle

**•** Combined cycle power generation , steam , and FW An overall plant energy balance is provided in tabular form in Exhibit 3

- 54 . The power out is the comb ined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 46 ) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.

### Cost and Performance Baseline for Fossil Energy Plants

177 

## Exhibit 3

- 51 Case 3 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 3
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 3 C O P G ASIFIER ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- 3

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 738 MWe Auxiliary Load : 113 MWe Net Plant Power : 625 MWe Net Plant Efficiency , HHV : 39

. 7 % Net Plant Heat Rate : 8 , 585 BTU / KWe N 2 to GT Combustor 1 , 207 , 199 W 59

. 0 T 14

. 7 P 13

. 0 H

333 , 021 W 90

. 0 T 125

. 0 P 11

. 5 H

333 , 021 W 223

. 0 T 740

. 0 P 37

. 5 H To Claus Plant
7 , 864 W

90

. 0 T 125

. 0 P 11

. 5 H 54 , 719 W

68

. 5 T 16

. 4 P 15

. 9 H

957 , 085 W 90

. 0 T 56

. 4 P 14

. 2 H 133 , 998 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Candle Filter Slurry Mix

Tank

E

- Gas TM Gasifier Milled Coal

Water

Slag Cyclones Saturated Steam to HRSG

BFW from HRSG

Blowdown to Flash Tank

Fire Tube Boiler Steam Drum

459 , 958 W 59

. 0 T 14

. 7 P

188 , 951 W

300

. 0 T 840

. 0 P 243

. 9 H

46 , 947 W 1 , 900

. 0 T

615

. 0 P 1 , 241 , 593 W 600

. 0 T 605

. 0 P 422

. 3 H 1 , 078 , 070 W 389

. 0 T 384

. 0 P 88

. 2 H

Fuel Gas

9 648 , 909 W

161

. 6 T 840

. 0 P 3 , 007

. 7 H 1 , 241 , 593 W 600

. 0 T 605

. 0 P 422

. 3 H 1 , 241 , 593 W

1 , 833

. 8 T

615

. 0 P 968

. 9 H 144 , 019 W 158

. 8 T 800

. 0 P 36

. 9 H

N 2 Diluent Preheater 1 , 241 , 593 W 450

. 0 T 600

. 0 P 361

. 4 H 100

. 0 T 189

. 5 P 18

. 0 H

7

8 Steam

149 , 578 W

650

. 0 T 740

. 0 P 1 , 316

. 8 H Syngas Recycle Compressor 144 , 019 W 105

. 0 T 600

. 0 P 18

. 8 H 4

Air From GT Compressor 280 , 565 W

220

. 0 T 224

. 9 P 50

. 9 H

280 , 565 W 809

. 8 T 234

. 9 P 199

. 4 H

IP BFW Raw Syngas to Scrubber

1 , 061 , 562 W 450

. 0 T 600

. 0 P 361

. 4 H 1 , 078 , 070 W 199

. 0 T 384

. 0 P 39

. 8 H

22

6

### Cost and Performance Baseline for Fossil Energy Plants

178 

## Exhibit 3

- 52 Case 3 Syngas Cleanup Heat and Mass Balance Schematic

Mercury Removal

Knock Out Drum

Raw Syngas Syngas Preheater Fuel Gas to GT

Sour Drum

To Water Treatment Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper Syngas Scrubber

Condensate to Deaerator

Condensate 1 , 061 , 562 W 450

. 0 T 600

. 0 P 361

. 4 H 1 , 013 , 536 W 336

. 7 T 595

. 0 P 284

. 4 H 900 , 213 W 93

. 7 T 550

. 0 P 15

. 8 H 944 , 788 W 290

. 3 T 465

. 0 P 210

. 4 H

61 , 685 W

112

. 2 T 545

. 0 P 944 , 788 W 380

. 0 T 460

. 0 P 245

. 0 H

11 , 497 W 61 , 967 W 450

. 0 T 58

. 9 P 314

. 5 H

3 , 916 W 191

. 1 T 65

. 0 P 190

. 1 H 7 , 864 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 3
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 3 C O P G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- 3

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 738 MWe Auxiliary Load : 113 MWe Net Plant Power : 625 MWe Net Plant Efficiency , HHV : 39

. 7 % Net Plant Heat Rate : 8 , 585 BTU / KWe 14

18

12 16

20 CO 2 Tailgas

53 , 768 W

120

. 0 T 56

. 8 P 33

. 1 H 847 , 104 W 95

. 2 T 555

. 0 P 17

. 0 H

8 , 858 W 118

. 5 T 56

. 8 P 44

. 8 H 3
53 , 110 W

100

. 0 T 799

. 5 P Humidification 15

838 , 528 W

112

. 2 T 545

. 0 P 23

. 7 H

Claus Oxygen Preheater 7 , 864 W 450

. 0 T 124

. 5 P 91

. 9 H COS Hydrolysis 1 , 013 , 536 W 367

. 0 T 580

. 0 P 289

. 3 H

COS Hydrolysis

Preheater 1 , 013 , 536 W 366

. 7 T 590

. 0 P 289

. 4 H

10 11

19 Clean Gas Acid Gas

13



### AGR

- MDEA 17

Tail Gas Compressor Hydrogenation And Tail Gas

Cooling

### Cost and Performance Baseline for Fossil Energy Plants

179 

## Exhibit 3

- 53 Case 3 Combined Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Gasifier Steam

Ip Extraction Steam To 250 PSIA Header Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

1 , 078 , 070 W 199

. 0 T 384

. 0 P 39

. 8 H

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H 1 , 603 , 037 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 756 , 427 W 269

. 9 T 15

. 2 P 117

. 1 H

944 , 788 W

380

. 0 T 460

. 0 P 245

. 0 H 8 , 756 , 427 W 1 , 091

. 1 T

15

. 2 P 337

. 0 H

LP Process Header From Gasifier Island Preheating

To Claus LP BFW 1 , 595 , 870 W

1 , 041

. 1 T 1 , 814

. 7 P 1 , 505

. 0 H 9 , 989 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 623 , 826 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

27 , 956 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 414 , 204 W 539

. 6 T 65

. 0 P 1 , 301

. 6 H

1 , 603 , 037 W 103

. 2 T 120

. 0 P 71

. 4 H 1 , 603 , 037 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 660

. 4 T 65

. 0 P 1 , 361

. 1 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 3
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 3 C O P G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- 3

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 738 MWe Auxiliary Load : 113 MWe Net Plant Power : 625 MWe Net Plant Efficiency , HHV : 39

. 7 % Net Plant Heat Rate : 8 , 585 BTU / KWe 21 23

25

16 24

Flue Gas

HOT WELL CONDENSER Make

- up 176 , 912 W 59

. 0 T 14

. 7 P 27

. 1 H 8 , 828 W 700

. 3 T 501

. 4 P 1 , 357

. 3 H 9 , 522 W 660

. 4 T 65

. 0 P 1 , 361

. 1 H 25 , 722 W

896

. 4 T 280

. 0 P 1 , 472

. 0 H 781 W 1 , 041

. 1 T 1 , 814

. 7 P 1 , 505

. 0 H 1 , 313 W 539

. 6 T 65

. 0 P 1 , 301

. 6 H Air Extraction

280 , 565 W

809

. 8 T 234

. 9 P 199

. 4 H 22

### Cost and Performance Baseline for Fossil Energy Plants

180 

## This page intentionally left b lank

### Cost and Performance Baseline for Fossil Energy Plants

181 

## Exhibit 3

- 54 Case 3 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,661 (5,366) 4.7 (4.5) 5,666 (5,370) ASU Air 16.6 (15.7) 17 (16) GT Air 96.2 (91.2) 96 (91) Water 62.2 (58.9) 62 (59) Auxiliary Power 407 (386) 407 (386) TOTAL 5,661 (5,366) 179.6 (170.2) 407 (386) 6,248 (5,922) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0.9 (0.9) 1 (1) Slag 35 (33) 23.9 (22.7) 59 (56) Sulfur 48 (46) 0.6 (0.6) 49 (46) CO 2 

## Cooling Tower Blowdown 25.2 (23.9) 25 (24) HRSG Flue Gas 1,082 (1,025) 1,082 (1,025) Condenser 1,415 (1,342) 1,415 (1,342) Non

- Condenser Cooling Tower Loads* 411 (389) 411 (389) Process Losses** 549 (521) 549 (521) Power 2,658 (2,519) 2,658 (2,519) TOTAL 83 (79) 3,507 (3,324) 2,658 (2,519) 6,248 (5,922)

* Includes ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas

cooler (low level heat rejection) and extraction air cooler. ** Calculated by difference to close the energy balance.

### Cost and Performance Baseline for Fossil Energy Plants

182 

## 3.3.6 Major equipment items for the CoP gasifier with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 3

- Major Equipment List

3.3.7 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 726 tonne (800 ton) 3 0

### Cost and Performance Baseline for Fossil Energy Plants

183 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 73 tonne/h (80 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 227 tonne/h (250 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 283,227 liters (74,820 gal) 2 0

7 Slurry Water Pumps Centrifugal 795 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 163 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 370,519 liters (97,880 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,028 lpm (800 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,111,406 liters (293,600 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,057 lpm (1,600 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,028 lpm (800 gpm) 2 2

### Cost and Performance Baseline for Fossil Energy Plants

184 

## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEM S AND EQUIPMENT Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,082,628 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,700 lpm @ 91 m H2O (1,770 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 478,994 kg/hr (1,056,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,101 lpm @ 27 m H2O (2,140 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 7,041 lpm @ 1,859 m H2O (1,860 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 492 lpm @ 223 m H2O (130 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 240 GJ/hr (228 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 86,307 lpm @ 21 m H2O (22,800 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 4,240 lpm @ 18 m H2O (1,120 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,801 lpm @ 268 m H2O (740 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single suction 1,628 lpm @ 49 m H2O (430 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 787,366 liter (208,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 303 lpm (80 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

185 

## ACCOUNT 4 GASIFIER, ASU AND AC CESSORIES INCLUDING LOW TEMPERATURE HEAT REC OVERY AND FUEL GAS S ATURATION Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized two-stage, slurry-feed entrained bed 2,722 tonne/day, 4.2 MPa (3,000 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 309,804 kg/hr (683,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 309,804 kg/hr (683,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 264,898 kg/hr (584,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 212,735 kg/hr (469,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 212,281 kg/hr, 35°C, 3.9 MPa (468,000 lb/hr, 95°F, 560 psia) 2 0

8 Saturation Water Economizers Shell and tube 91 GJ/hr (86 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 235,868 kg/hr, 143°C, 3.3 MPa (520,000 lb/hr, 290°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 2,271 lpm @ 12 m H2O (600 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 209,106 kg/hr (461,000 lb/hr) 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 264,898 kg/hr (584,000 lb/hr) syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi-stage 4,134 m3/min @ 1.3 MPa (146,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,996 tonne/day (2,200 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage 1,019 m3/min (36,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 5.1 MPa (740 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi-stage 3,370 m3/min (119,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single-stage 481 m3/min (17,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

18 Transport Nitrogen Boost Compressor Centrifugal, single-stage 57 m3/min (2,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 5.4 MPa (790 psia) 2 0

19 Extraction Air Heat Exchanger Gas-to-gas, vendor design 69,853 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

186 

## ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE A ND AUXILIARIES

ACCOUNT 7 HRSG, STACK, AND DUCTING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 211,374 kg/hr (466,000 lb/hr) 35°C (95°F) 3.8 MPa (555 psia) 2 0

2 Sulfur Plant Claus type 138 tonne/day (152 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 252,651 kg/hr (557,000 lb/hr) 188°C (370°F) 4.1 MPa (590 psia) 2 0

4 Acid Gas Removal Plant MDEA 224,528 kg/hr (495,000 lb/hr) 34°C (94°F) 3.8 MPa (550 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 28,108 kg/hr (61,967 lb/hr) 232°C (450°F) 0.4 MPa (58.9 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 24,090 kg/hr (53,110 lb/hr) each 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 398,131 kg/hr, 12.4 MPa / 561 °C ( 877 , 728 lb / hr , 1 , 800 psig / 1 , 041 °F ) Reheat steam - 358,685 kg/hr, 3

. 1 MPa / 561 °C ( 790 , 766 lb / hr , 452 psig / 1 , 041 °F ) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

187 

## ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 289 MW 12

. 4 MPa / 561 °C / 561 °C ( 1 , 800 psig / 1041 °F / 1041 °F ) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,561 GJ/hr (1,480 MMBtu/hr), Inlet water temperature 16 °C ( 60 °F ) , Water temperature rise 11 °C ( 20 °F ) 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 389,897 lpm @ 30 m (103,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11 °C ( 51

. 5 °F ) wet bulb / 16 °C ( 60 °F ) CWT / 27 °C ( 80 °F ) HWT / 2,173 GJ/hr (2,060 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

188 

## ACCOUNT 10 SLAG RECOVERY AND HA NDLING Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 223,339 liters (59,000 gal) 2 0
2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0
3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 136,275 liters (36,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 2
6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0
7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 189,271 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O (60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 816 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

189 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 47 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 29 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

### Cost and Performance Baseline for Fossil Energy Plants

190 

## ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

191 

## 3.3.7 The cost estim ating methodology was described previously in Section 2.6. Case 3

- Costs Estimating Results Exhibit 3

- 55 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 56 shows a more de tailed breakdown of the capital costs along with owner’s costs, TOC and TASC

. Exhibit 3

- 57 shows the initial and annual O&M costs. The e stimated TO C of the CoP gasifi er with no CO 2 

## capture is $ 2,351 /kW. Pr ocess contingency represents 2.1 percent of the TO C and project contingency is 10.9 percent. The COE is 74

. 0 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

192 

## Exhibit 3

- 55 Case 3 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 3 - ConocoPhillips 625MW IGCC w/o CO2 Plant Size: 625.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $13,783 $2,561 $10,689 $0 $0 $27,033 $2,454 $0 $5,897 $35,384 $57

2 COAL & SORBENT PREP & FEED $23,433 $4,283 $14,157 $0 $0 $41,873 $3,759 $0 $9,126 $54,759 $88

3 FEEDWATER & MISC. BOP SYSTEMS $9,806 $8,188 $9,436 $0 $0 $27,429 $2,581 $0 $6,822 $36,832 $59

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $117,991 $0 $65,449 $0 $0 $183,440 $16,853 $25,442 $34,617 $260,352 $417 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $145,765 $0 w/equip. $0 $0 $145,765 $14,129 $0 $15,989 $175,883 $281 4.4-4.9 Other Gasification Equipment $17,104 $9,335 $11,583 $0 $0 $38,023 $3,633 $0 $9,003 $50,658 $81 SUBTOTAL 4 $280,861 $9,335 $77,032 $0 $0 $367,228 $34,614 $25,442 $59,609 $486,893 $779

5A GAS CLEANUP & PIPING $47,943 $3,806 $47,221 $0 $0 $98,970 $9,573 $85 $21,865 $130,493 $209

5B CO2 COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,751 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $185 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,751 $806 $7,162 $0 $0 $93,719 $8,883 $4,601 $11,092 $118,295 $189

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,467 $0 $5,043 $0 $0 $40,510 $3,852 $0 $4,436 $48,798 $78 7.2-7.9 SCR System, Ductwork and Stack $3,335 $2,378 $3,114 $0 $0 $8,827 $818 $0 $1,570 $11,215 $18 SUBTOTAL 7 $38,802 $2,378 $8,157 $0 $0 $49,337 $4,670 $0 $6,006 $60,013 $96

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,970 $0 $4,963 $0 $0 $33,934 $3,256 $0 $3,719 $40,909 $65 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,556 $996 $7,591 $0 $0 $19,143 $1,738 $0 $4,220 $25,101 $40 SUBTOTAL 8 $39,526 $996 $12,554 $0 $0 $53,076 $4,994 $0 $7,939 $66,009 $106

9 COOLING WATER SYSTEM $9,144 $8,826 $7,504 $0 $0 $25,474 $2,366 $0 $5,687 $33,527 $54

10 ASH/SPENT SORBENT HANDLING SYS $19,026 $1,439 $9,440 $0 $0 $29,905 $2,869 $0 $3,575 $36,349 $58

11 ACCESSORY ELECTRIC PLANT $27,425 $10,189 $20,427 $0 $0 $58,041 $4,986 $0 $11,827 $74,854 $120

12 INSTRUMENTATION & CONTROL $10,234 $1,883 $6,594 $0 $0 $18,710 $1,696 $936 $3,556 $24,897 $40

13 IMPROVEMENTS TO SITE $3,328 $1,962 $8,212 $0 $0 $13,503 $1,333 $0 $4,451 $19,287 $31

14 BUILDINGS & STRUCTURES $0 $6,670 $7,642 $0 $0 $14,313 $1,303 $0 $2,553 $18,169 $29

TOTAL COST $609,063 $63,322 $246,227 $0 $0 $918,612 $86,080 $31,064 $160,007 $1,195,762 $1,913 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

193 

## Exhibit 3

- 56 Case 3 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,619 $0 $1,769 $0 $0 $5,388 $483 $0 $1,174 $7,045 $11 1.2 Coal Stackout & Reclaim $4,677 $0 $1,134 $0 $0 $5,811 $509 $0 $1,264 $7,584 $12 1.3 Coal Conveyors & Yd Crush $4,349 $0 $1,122 $0 $0 $5,470 $480 $0 $1,190 $7,141 $11 1.4 Other Coal Handling $1,138 $0 $260 $0 $0 $1,397 $122 $0 $304 $1,823 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,561 $6,404 $0 $0 $8,966 $859 $0 $1,965 $11,790 $19 SUBTOTAL 1. $13,783 $2,561 $10,689 $0 $0 $27,033 $2,454 $0 $5,897 $35,384 $57 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,542 $369 $242 $0 $0 $2,153 $184 $0 $467 $2,805 $4 2.3 Slurry Prep & Feed $21,042 $0 $9,358 $0 $0 $30,400 $2,714 $0 $6,623 $39,737 $64 2.4 Misc.Coal Prep & Feed $848 $617 $1,851 $0 $0 $3,316 $305 $0 $724 $4,345 $7 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,297 $2,707 $0 $0 $6,004 $556 $0 $1,312 $7,871 $13 SUBTOTAL 2. $23,433 $4,283 $14,157 $0 $0 $41,873 $3,759 $0 $9,126 $54,759 $88 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $3,157 $5,422 $2,862 $0 $0 $11,440 $1,060 $0 $2,500 $15,000 $24 3.2 Water Makeup & Pretreating $585 $61 $327 $0 $0 $974 $93 $0 $320 $1,387 $2 3.3 Other Feedwater Subsystems $1,727 $584 $525 $0 $0 $2,836 $255 $0 $618 $3,709 $6 3.4 Service Water Systems $335 $690 $2,394 $0 $0 $3,419 $334 $0 $1,126 $4,879 $8 3.5 Other Boiler Plant Systems $1,798 $697 $1,727 $0 $0 $4,221 $400 $0 $924 $5,546 $9 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,456 $140 $0 $319 $1,915 $3 3.7 Waste Treatment Equipment $818 $0 $499 $0 $0 $1,318 $128 $0 $434 $1,880 $3 3.8 Misc. Power Plant Equipment $1,072 $143 $550 $0 $0 $1,765 $170 $0 $581 $2,517 $4 SUBTOTAL 3. $9,806 $8,188 $9,436 $0 $0 $27,429 $2,581 $0 $6,822 $36,832 $59 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $117,991 $0 $65,449 $0 $0 $183,440 $16,853 $25,442 $34,617 $260,352 $417 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $145,765 $0 w/equip. $0 $0 $145,765 $14,129 $0 $15,989 $175,883 $281 4.4 LT Heat Recovery & FG Saturation $17,104 $0 $6,502 $0 $0 $23,606 $2,304 $0 $5,182 $31,092 $50 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,503 $612 $0 $0 $2,114 $203 $0 $463 $2,780 $4 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $7,833 $4,469 $0 $0 $12,302 $1,126 $0 $3,357 $16,785 $27 SUBTOTAL 4. $280,861 $9,335 $77,032 $0 $0 $367,228 $34,614 $25,442 $59,609 $486,893 $779

### Cost and Performance Baseline for Fossil Energy Plants

194 

## Exhibit 3

- 56 Case 3 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $33,341 $0 $28,290 $0 $0 $61,631 $5,960 $0 $13,518 $81,110 $130 5A.2 Elemental Sulfur Plant $9,938 $1,981 $12,822 $0 $0 $24,741 $2,403 $0 $5,429 $32,573 $52 5A.3 Mercury Removal $970 $0 $738 $0 $0 $1,708 $165 $85 $392 $2,350 $4 5A.4 COS Hydrolysis $3,196 $0 $4,173 $0 $0 $7,369 $717 $0 $1,617 $9,703 $16 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $499 $280 $157 $0 $0 $936 $89 $0 $205 $1,230 $2 5A.7 Fuel Gas Piping $0 $768 $538 $0 $0 $1,306 $121 $0 $285 $1,712 $3 5A.9 HGCU Foundations $0 $778 $501 $0 $0 $1,279 $118 $0 $419 $1,816 $3 SUBTOTAL 5A. $47,943 $3,806 $47,221 $0 $0 $98,970 $9,573 $85 $21,865 $130,493 $209 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,751 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $185 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,751 $806 $7,162 $0 $0 $93,719 $8,883 $4,601 $11,092 $118,295 $189 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,467 $0 $5,043 $0 $0 $40,510 $3,852 $0 $4,436 $48,798 $78 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,710 $1,220 $0 $0 $2,929 $257 $0 $637 $3,823 $6 7.4 Stack $3,335 $0 $1,253 $0 $0 $4,588 $440 $0 $503 $5,530 $9 7.9 HRSG, Duct & Stack Foundations $0 $668 $642 $0 $0 $1,310 $122 $0 $430 $1,861 $3 SUBTOTAL 7. $38,802 $2,378 $8,157 $0 $0 $49,337 $4,670 $0 $6,006 $60,013 $96 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,970 $0 $4,963 $0 $0 $33,934 $3,256 $0 $3,719 $40,909 $65 8.2 Turbine Plant Auxiliaries $201 $0 $460 $0 $0 $661 $65 $0 $73 $798 $1 8.3 Condenser & Auxiliaries $4,785 $0 $1,529 $0 $0 $6,314 $604 $0 $692 $7,609 $12 8.4 Steam Piping $5,570 $0 $3,918 $0 $0 $9,489 $815 $0 $2,576 $12,880 $21 8.9 TG Foundations $0 $996 $1,683 $0 $0 $2,679 $254 $0 $880 $3,813 $6 SUBTOTAL 8. $39,526 $996 $12,554 $0 $0 $53,076 $4,994 $0 $7,939 $66,009 $106

### Cost and Performance Baseline for Fossil Energy Plants

195 

## Exhibit 3

- 56 Case 3 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,338 $0 $1,153 $0 $0 $7,491 $713 $0 $1,231 $9,434 $15 9.2 Circulating Water Pumps $1,648 $0 $113 $0 $0 $1,761 $149 $0 $287 $2,197 $4 9.3 Circ.Water System Auxiliaries $140 $0 $20 $0 $0 $160 $15 $0 $26 $202 $0 9.4 Circ.Water Piping $0 $5,855 $1,518 $0 $0 $7,373 $666 $0 $1,608 $9,647 $15 9.5 Make-up Water System $327 $0 $467 $0 $0 $794 $76 $0 $174 $1,044 $2 9.6 Component Cooling Water Sys $691 $827 $588 $0 $0 $2,106 $197 $0 $461 $2,764 $4 9.9 Circ.Water System Foundations $0 $2,144 $3,645 $0 $0 $5,789 $549 $0 $1,901 $8,239 $13 SUBTOTAL 9. $9,144 $8,826 $7,504 $0 $0 $25,474 $2,366 $0 $5,687 $33,527 $54 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $16,609 $0 $8,191 $0 $0 $24,799 $2,383 $0 $2,718 $29,900 $48 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $548 $0 $596 $0 $0 $1,144 $111 $0 $188 $1,443 $2 10.7 Ash Transport & Feed Equipment $735 $0 $177 $0 $0 $912 $85 $0 $150 $1,147 $2 10.8 Misc. Ash Handling Equipment $1,135 $1,391 $415 $0 $0 $2,941 $280 $0 $483 $3,704 $6 10.9 Ash/Spent Sorbent Foundation $0 $48 $61 $0 $0 $109 $10 $0 $36 $155 $0 SUBTOTAL 10. $19,026 $1,439 $9,440 $0 $0 $29,905 $2,869 $0 $3,575 $36,349 $58 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $951 $0 $940 $0 $0 $1,891 $181 $0 $207 $2,279 $4 11.2 Station Service Equipment $3,741 $0 $337 $0 $0 $4,078 $376 $0 $445 $4,900 $8 11.3 Switchgear & Motor Control $6,917 $0 $1,258 $0 $0 $8,174 $758 $0 $1,340 $10,272 $16 11.4 Conduit & Cable Tray $0 $3,213 $10,599 $0 $0 $13,812 $1,336 $0 $3,787 $18,935 $30 11.5 Wire & Cable $0 $6,139 $4,034 $0 $0 $10,172 $739 $0 $2,728 $13,639 $22 11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,153 $308 $0 $519 $3,980 $6 11.7 Standby Equipment $234 $0 $229 $0 $0 $463 $44 $0 $76 $583 $1 11.8 Main Power Transformers $15,583 $0 $145 $0 $0 $15,727 $1,190 $0 $2,538 $19,454 $31 11.9 Electrical Foundations $0 $157 $412 $0 $0 $569 $54 $0 $187 $810 $1 SUBTOTAL 11. $27,425 $10,189 $20,427 $0 $0 $58,041 $4,986 $0 $11,827 $74,854 $120 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,010 $0 $675 $0 $0 $1,685 $159 $84 $289 $2,218 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $232 $0 $149 $0 $0 $381 $36 $19 $87 $523 $1 12.7 Computer & Accessories $5,389 $0 $173 $0 $0 $5,562 $510 $278 $635 $6,985 $11 12.8 Instrument Wiring & Tubing $0 $1,883 $3,849 $0 $0 $5,731 $486 $287 $1,626 $8,130 $13 12.9 Other I & C Equipment $3,602 $0 $1,749 $0 $0 $5,352 $504 $268 $918 $7,041 $11 SUBTOTAL 12. $10,234 $1,883 $6,594 $0 $0 $18,710 $1,696 $936 $3,556 $24,897 $40

### Cost and Performance Baseline for Fossil Energy Plants

196 

## Exhibit 3

- 56 Case 3 Total Plant Cost Details (C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $104 $2,232 $0 $0 $2,336 $232 $0 $771 $3,339 $5 13.2 Site Improvements $0 $1,857 $2,468 $0 $0 $4,326 $427 $0 $1,426 $6,178 $10 13.3 Site Facilities $3,328 $0 $3,512 $0 $0 $6,841 $674 $0 $2,255 $9,770 $16 SUBTOTAL 13. $3,328 $1,962 $8,212 $0 $0 $13,503 $1,333 $0 $4,451 $19,287 $31 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,435 $3,468 $0 $0 $5,903 $543 $0 $967 $7,413 $12 14.3 Administration Building $0 $842 $611 $0 $0 $1,452 $129 $0 $237 $1,819 $3 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $489 $477 $0 $0 $967 $87 $0 $158 $1,212 $2 14.6 Machine Shop $0 $431 $295 $0 $0 $726 $64 $0 $119 $909 $1 14.7 Warehouse $0 $696 $449 $0 $0 $1,145 $101 $0 $187 $1,433 $2 14.8 Other Buildings & Structures $0 $417 $324 $0 $0 $741 $66 $0 $161 $969 $2 14.9 Waste Treating Building & Str. $0 $931 $1,780 $0 $0 $2,711 $253 $0 $593 $3,557 $6 SUBTOTAL 14. $0 $6,670 $7,642 $0 $0 $14,313 $1,303 $0 $2,553 $18,169 $29

TOTAL COST $609,063 $63,322 $246,227 $0 $0 $918,612 $86,080 $31,064 $160,007 $1,195,762 $1,913
Owner's Costs Preproduction Costs 6 Months All Labor $12,309 $20 1 Month Maintenance Materials $2,766 $4 1 Month Non-fuel Consumables $239 $0 1 Month Waste Disposal $279 $0 25% of 1 Months Fuel Cost at 100% CF $1,603 $3 2% of TPC $23,915 $38 Total $41,111 $66 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,092 $21 0.5% of TPC (spare parts) $5,979 $10 Total $19,071 $31
Initial Cost for Catalyst and Chemicals $1,084 $2 Land $900 $1 Other Owner's Costs $179,364 $287

Financing Costs $32,286 $52 Total Overnight Costs (TOC) $1,469,577 $2,351 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,675,318 $2,680

### Cost and Performance Baseline for Fossil Energy Plants

197 

## Exhibit 3

- 57 Case 3 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 3 - ConocoPhillips 625MW IGCC w/o CO2 Heat Rate-net(Btu/kWh): 8,585 MWe-net: 625 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $9.469 Maintenance Labor Cost $13,775,415 $22.039 Administrative & Support Labor $4,923,582 $7.877 Property Taxes and Insurance $23,935,631 $38.293 TOTAL FIXED OPERATING COSTS $48,553,541 $77.678 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $26,551,568 $0.00606

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 3,144.24 1.08 $0 $993,106 $0.00023

Chemicals

MU & WT Chem. (lbs) 0 18,732 0.17 $0 $946,662 $0.00022 Carbon (Mercury Removal) (lb) 68,511 94 1.05 $71,948 $28,779 $0.00001 COS Catalyst (m3) 327 0.22 2,397.36 $784,204 $156,841 $0.00004 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 MDEA Solution (gal) 26,146 37 8.70 $227,412 $93,463 $0.00002 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.91 131.27 $0 $73,243 $0.00002 Subtotal Chemicals $1,083,564 $1,298,988 $0.00030

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Spent Mercury Catalyst (lb.) 0 94 0.42 $0 $11,430 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 563 16.23 $0 $2,669,064 $0.00061 Subtotal-Waste Disposal $0 $2,680,493 $0.00061

By-products & Emissions

Sulfur (ton) 0 138 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $1,083,564 $31,524,155 $0.00720

Fuel (ton) 0 5,519 38.18 $0 $61,541,712 $0.01405

### Cost and Performance Baseline for Fossil Energy Plants

198 

## 3.3.8 This case is configured to produce electric power with CO 2 

## capture. The plant configuration is the same as Case 3, namely two gasifier trains, two advanced F class turbines, two HRSGs , and one steam turbine. The gross power output from the plant is constrained by the capacity of the two CT s, and since the CO 2 

## capture and compression process increases the auxiliary load on the plant, the net out put is significantly reduced relative to Case 3. Case 4

- E

- GasTM IGCC Power Plant with CO 2 

## Capture

Th e process description for Case 4 is similar to Case 3 with several notable exceptions to accommodate CO 2 

## capture. A BFD and stream tables for Case 4 are shown in Exhibit 3

- 58 and Exhibit 3

- 59 , respectively. Instead of repeating the entire process description, only differences from Case 3 are reported here.

No differences from Case 3. Coal Preparation and Feed Systems

The gasification process is the same as Case 3 with the exception that total coal feed to the two gasifiers is 5, 271 tonnes/day (5, 811 TPD) (stream 8 ) and the ASU provides 4, 234 tonnes/day (4, 668 TPD) of 95 mol % oxygen to the gasifier and Claus plant (str eams 5 and 3). Gasification

Raw gas cooling and particulate removal are the same as Case 3 with the exception that approximately 418,710 kg/h r ( 923,082 lb/h r ) of saturated steam at 13.8 MPa (2,000 psia) is generated in the SGC. Raw Gas Cooling /Particulate Removal

No differences from Case 3. Synga s Scrubber/Sour Water Stripper

The SGS process was described in Section Sour Gas Shift (SGS) 3.1.3 . In Case 4 steam (stream 11 ) is adde d to the syngas exiting the scrubber to adjust the H 2 

## O:CO molar ratio to approximately 2 .25 :1 prior to the first WGS reactor. The hot syngas exiting the first stage of SGS is used to preheat a portion of the water used to humidify the clean syngas leaving the AGR. The final stage of SGS brings the overall conversion of the CO to CO 2 

## to 98.5 percent. The syngas exiting the final stage of SGS still contains 1.2 vol% CH 4 

## , which is subsequently oxidized to CO 2 

## in the CT and results in a carbon capture of 90

. 4 percent. The warm syngas exiting the second stage of the SGS at 204°C (400°F) (stream 12) is cooled to 201 °C ( 393 °F) by preheating the syngas entering the first SGS reactor . The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. T he syngas is further dehydrated and cooled to 35°C (95°F) in syngas coolers prior to the mercury removal beds.

Mercury removal is the same as in Case 3. Mercury Removal and Acid Gas Removal

### Cost and Performance Baseline for Fossil Energy Plants

199 

## Exhibit 3

- 58 Case 4 Block Flow Diagram , E

- GasTM IGCC with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

200 

## Exhibit 3

- 59 Case 4 Stream Table , E

- GasTM IGCC with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 13 V-L Mole Fraction

Ar 0.0092 0.0209 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0071 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0125 0.0164 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0028 0.0037 CO 2 0.0003 0.0071 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3103 0.4090 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.4128 0.5441 H 2 O 0.0099 0.1780 0.0000 0.0003 0.0000 1.0000 1.0000 0.0000 0.9963 0.0000 1.0000 0.2376 0.0015 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 0.0063 N 2 0.7732 0.6187 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0090 0.0119 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0037 0.0000 0.0000 0.0046 0.0000 O 2 0.2074 0.1754 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 26,685 1,231 145 19,704 5,338 1,287 4,969 0 5,009 0 9,357 37,866 26,948 V-L Flowrate (kg/hr) 770,042 33,603 4,654 552,893 171,782 23,193 89,523 0 90,226 0 168,566 748,369 547,649 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 219,635 0 22,418 0 0 0
Temperature ( °C ) 15 19 32 93 32 154 343 15 171 1,038 288 204 35 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.79 5.10 0.10 5.79 4.24 5.52 4.07 3.79 Enthalpy (kJ/kg) A 30.23 36.49 26.67 92.50 26.67 599.34 3,063.97

--- 673.50

--- 2,918.18 873.73 40.91 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0 857.7 20.1

--- 836.0

--- 25.6 20.6 30.9 V-L Molecular Weight 28.857 27.295 32.181 28.060 32.181 18.015 18.015

--- 18.012

--- 18.015 19.764 20.322
V-L Flowrate (lb mol /hr) 58,830 2,714 319 43,440 11,768 2,838 10,955 0 11,044 0 20,628 83,479 59,411 V-L Flowrate (lb/hr) 1,697,652 74,082 10,260 1,218,920 378,715 51,133 197,365 0 198,914 0 371,625 1,649,872 1,207,359 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 484,212 0 49,422 0 0 0
Temperature ( °F ) 59 67 90 199 90 310 650 59 340 1,900 550 400 95 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 840.0 740.0 14.7 840.0 615.0 800.0 590.0 550.0 Enthalpy (Btu/lb) A 13.0 15.7 11.5 39.8 11.5 257.7 1,317.3

--- 289.6

--- 1,254.6 375.6 17.6 Density (lb/ft 3 ) 0.076 0.095 0.687 1.521 0.687 53.543 1.257

--- 52.192

--- 1.597 1.285 1.928 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

201 

## Exhibit 3

- 59 Case 4 Stream Table , E

- GasTM IGCC with CO 2 

## Capture (Continued)
14 15 16 17 18 19 20 21 22 23 24 25 V-L Mole Fraction

Ar 0.0071 0.0119 0.0114 0.0114 0.0002 0.0011 0.0000 0.0068 0.0092 0.0090 0.0090 0.0000 CH 4 0.0159 0.0262 0.0251 0.0251 0.0008 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0038 0.0063 0.0060 0.0060 0.0001 0.0007 0.0000 0.0076 0.0000 0.0000 0.0000 0.0000 CO 2 0.4172 0.0352 0.0338 0.0338 0.9945 0.7021 0.0000 0.6907 0.0003 0.0082 0.0082 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.5341 0.8964 0.8588 0.8588 0.0044 0.0591 0.0000 0.2007 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0015 0.0001 0.0421 0.0421 0.0000 0.0162 0.0000 0.0017 0.0099 0.1246 0.1246 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0062 0.0000 0.0000 0.0000 0.0000 0.2153 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000 N 2 0.0142 0.0239 0.0229 0.0229 0.0001 0.0010 0.0000 0.0901 0.7732 0.7529 0.7529 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1052 0.1052 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 27,761 16,435 17,155 17,155 10,499 800 0 812 110,253 139,694 139,694 34,515 V-L Flowrate (kg/hr) 575,208 83,813 96,780 96,780 459,855 31,069 0 27,560 3,181,557 3,831,230 3,831,230 621,792 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,494 0 0 0 0 0
Temperature ( °C ) 34 34 108 193 51 48 176 38 15 562 132 534 Pressure (MPa, abs) 3.8 3.757 3.206 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 39.0 196.106 903.063 1,360.503 -162.349 62.132

--- 1.774 30.227 839.766 348.188 3,432.696 Density (kg/m 3 ) 31.3 7.4 5.6 4.6 641.8 2.4 5,283.7 83.6 1.2 0.4 0.9 36.7 V-L Molecular Weight 21 5.100 5.642 5.642 43.800 38.814

--- 33.925 28.857 27.426 27.426 18.015
V-L Flowrate (lb mol /hr) 61,202 36,233 37,820 37,820 23,146 1,765 0 1,791 243,066 307,972 307,972 76,092 V-L Flowrate (lb/hr) 1,268,117 184,776 213,363 213,363 1,013,807 68,496 0 60,759 7,014,133 8,446,417 8,446,417 1,370,817 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,112 0 0 0 0 0
Temperature ( °F ) 94 94 227 380 124 119 349 100 59 1,044 270 994 Pressure (psia) 545.0 545.0 465.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 16.8 84.3 388.2 584.9 -69.8 26.7

--- 0.8 13.0 361.0 149.7 1,475.8 Density (lb/ft 3 ) 2 0.461 0.352 0.285 40.067 0.149 329.851 5.220 0.076 0.026 0.053 2.293

### Cost and Performance Baseline for Fossil Energy Plants

202 

## The AGR process in Case 4 is a two stage Selexol process where H 2 

## S is removed in the first stage and CO 2 

## in the second stage of absorption as previously described in Section 3.1.5 . The process results in three product streams, the clean syngas, a CO 2 

## - rich stream , an d an acid gas feed to the Claus plant. The acid gas (stream 1 9 ) contains 21.5 percent H 2 

## S and 70 percent CO 2 

## with the balance primarily H 2 

## . The CO 2 

## - rich stream is discussed further in the CO 2 

## compression section.

CO 2 

## from the AGR process is flashed at three pressure levels to separate CO 2 

## and decrease H 2 

## losses to the CO 2 

## product pipeline. The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

## absorber. The MP CO 2 

## stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 

## stream is flashe d at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia) , and combined with the MP CO 2 

## stream. The combined stream is compressed from 1.0 MPa ( 149.5 psia) to a SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled compressor. During compression, the CO 2 

## stream is dehydrated to a dewpoint of

- 40oC (

- 40°F) with triethylene glycol. The raw CO 2 

## stream from the Selexol process contains over 99 percent CO 2 

## . The CO 2 

## (stream 1 8 ) is tra nsported to the plant fence line and is sequestration ready. CO 2 

## TS&M costs were estimated using the methodology described in Section CO 2 

## Compression and Dehydration

2.7

.
The Claus pla nt is the same as Case 3 with the following exceptions: Claus Unit

**•** 5, 494 kg/h r ( 12 , 1 12 lb/h r ) of sulfur (stream 20 ) are produced

**•** The waste heat boiler generates 12 , 679 kg/h r ( 27 , 953 lb/h r ) of 3 .0 MPa ( 430 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

Clean syngas from the AGR plant is partially humidified to 4 percent because the nitrogen available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated (stream 1 7 ) to 193 °C (38 0 °F) using HP BFW , diluted with nitrogen (stream 4), and then enters the CT burner. There is no integration between the CT and the ASU in this case. The exhaust gas (stream 23 ) exits the CT at 562 °C ( 1044 °F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 24 ) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/ 534 °C/ 534 °C (1800 psig/ 994 °F/ 994 °F) steam cycle. Power Block

The elevated pressure ASU is the same as in other cases and produces 4,234 tonnes/day ( 4,668 TPD) of 95 mol % oxygen and 14,230 tonnes/day ( 15,686 TPD) of nitrogen. There is no integration between the ASU and the CT

. Air Separation Unit ( ASU )

3.3.9 The Case 4 modeling assumptions were presented previously in Section Case 4 Performance Results 3.3.3

.

### Cost and Performance Baseline for Fossil Energy Plants

203 

## The plan t produces a net output of 514 MWe at a net plant efficiency of 31. 0 percent (HHV basis). Overall performance for the entire plant is summarized in Exhibit 3

- 60 , which includes auxiliary power requirements. The ASU accounts for nearly 58 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor , an d ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 27 percent of the auxiliary power load. The BFW pumps and cooling water system ( CWP s and cooling tower fan) comprise nearly 6 percent of the load, leaving 9 pe rcent of the auxiliary load for all other systems.

### Cost and Performance Baseline for Fossil Energy Plants

204 

## Exhibit 3

- 60 Case 4 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 239,700 TOTAL POWER, kWe 703,700 AUXILIARY LOAD SUMMARY, kWe Coal Handling 470 Coal Milling 2,260 Sour Water Recycle Slurry Pump 200 Slag Handling 1,160 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 65,670 Oxygen Compressor 9,010 Nitrogen Compressors 35,340 CO 2 

### Compressor 31,380 Boiler Feedwater Pumps 4,160 Condensate Pump 310 Syngas Recycle Compressor 520 Circulating Water Pump 4,670 Ground Water Pumps 520 Cooling Tower Fans 2,410 Scrubber Pumps 400 Acid Gas Removal 19,900 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 3,700 Miscellaneous Balance of Plant 2 

### 3,000 Transformer Losses 2,660 TOTAL AUXILIARIES, kWe 190,090 NET POWER, kWe 513,610 Net Plant Efficiency, % (HHV) 31. 0 Net Plant Heat Rate , kJ/kWh (Btu/kWh) 11,604 (10,998) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,403 (1,330) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 219,635 (484,212) Thermal Input 1 

### , kWt 1,655,503 Raw Water Withdrawal, m 3 

### /min (gpm) 21.6 (5,717) Raw Water Consumption , m 3 

### /min (gpm) 17.5 (4,631)
1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

205 

## The environmental targets for emissions of Hg, NO x , SO 2 

## , CO 2 

## , and PM were presented in Section Environmental Performance

2.4 . A summary of the plant air emissions for Case 4 is presented in Exhibit 3

- 61

. Exhibit 3

- 61 Case 4 Air Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (tons/year)

80% CF kg/MWh (lb/MWh)
SO 2 

## 0.001 (0.002) 39 (43) 0.008 (.02) NOx 0.021 (0.049) 885 (976) 0.180 (.396) Particulates 0.003 (0.0071) 127 (141) 0.026 (.057)
Hg 2.46E

- 7 (5.71E

- 7) 0.010 (0.011) 2.08E

- 6 (4.59E

- 6)
CO 2 

## 8.5 (19.7) 354,267 (390,512) 72 (158) CO 2 1 

## 98 (217)

1 

### CO 2 

### emissions based on net power instead of gross power 

## The low level of SO 2 

## emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. The CO 2 

## capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.4 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a concentration in the FG of less than 1 ppmv. The H 2 

## S

- rich re generation gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S, and then recycled back to the Selexol , thereby eliminating the need for a tail gas treat ment unit. NO x emissions are limited by the use of humidification and nitrogen dilution to 15 ppmvd (NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

temperature AGR process and ultimately destroyed in the Cl aus plant burner. This helps lower NO x levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorbe r. The particulate emissions represent filterable particulate only. Ninety five percent of mercury is captured from the syngas by an activated carbon bed. Ninety five percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. The overall carbon removal is 90 .4 percent. The carbon balance for the plant is shown in Exhibit 3

- 62

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected in the carbon balance below since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, CO 2 

## in the stack gas, ASU vent gas and the captured CO 2 

## product. The carbon capture efficiency is defined as the amount of carbon in the

### Cost and Performance Baseline for Fossil Energy Plants

206 

## CO 2 

## product st ream relative to the amount of carbon in the coal less carbon contained in the slag , represen ted by the following fraction: (Carbon in Product for Sequestration)/[(Carbon in the Coal)

- (Carbon in Slag)] or 276,728 /( 308,659

- 2,469 ) *100 or 90 .4 percent In rev ision 1 of this report, the repor ted CO 2 

## capture efficiency was 88.4 percent. The high methane content of the syngas, relative to the GEE and Shell cases, prevented reaching the nominal 90 percent CO 2 

## capture. In order to achieve 90 percent capture, the two

- stage Selexol CO 2 

## removal efficiency was increased from 92 to 95 percent. Exhibit 3

- 62 Case 4 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/h r (lb/hr) Coal 140,006 (308,659) Slag 1,120 (2,469) Air (CO 2 

## ) 537 (1,185) Stack Gas 13,796 (30,416) ASU Vent 105 (231) CO 2 

## Product 125,522 (276,728)

Total 140,543 (309,844) Total 140,543 (309,844)

Exhibit 3

- 63 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack gas , and sulfur in the CO 2 

## product . Sulfur in the slag is conside red to be negligible. Exhibit 3

- 63 Case 4 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/h r (lb/hr) Coal 5,505 (12,136) Elemental Sulfur 5,494 (12,112) Stack Gas 3 (6) CO 2 

## Product 8 (18) Total 5,505 (12,136) Total 5,505 (12,136)

Exhibit 3

- 64 shows the overall water balance for the plant. The exhibit is presented in an identical manner for Case s 1 through 3

.

### Cost and Performance Baseline for Fossil Energy Plants

207 

## Exhibit 3

- 64 Case 4 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal,
m 3 

### /min (gpm) Process Water Discharge,

m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)

Slag Handling 0.49 (128) 0.49 (128) 0.0 (0) 0.0 (0) 0.0 (0) Slurry Water 1.51 (398) 1.51 (398) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier 0.2 (61) 0.2 (61) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 4.5 (1,193) 1.5 (395) 2.8 (743) 0.21 (55) 0.0 (0) 4.5 (1,193) 1.5 (395) 2.8 (743) 0.21 (55) 0.0 (0) 4.5 (1,193)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 18.2 (4,798) 1.0 (274) 0.21 (55) 0.26 (68) 0.6 (152) 17.1 (4,524)

- 0.21 (

- 55)

- 0.26 (

- 68)

- 0.6 (

- 152) 4.1 (1,079) 13.0 (3,445)

Total 24.9 (6,578) 3.3 (861) 21.6 (5,717) 4.1 (1,086) 17.5 (4,631)



## Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams Exhibit 3

- 65 through Exhibit 3

- 67 :

**•** Coal gasification and ASU

**•** Syngas cleanup including sulfur recovery and tail gas recycle

**•** Combined cycle power generation , steam , and FW An overall plant energy balance is provided in tabular form in Exhibit 3

- 68 . The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 60 ) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.

### Cost and Performance Baseline for Fossil Energy Plants

208 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

209 

## Exhibit 3

- 65 Case 4 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 4
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 4 C O P G ASIFIER ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- 4

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 704 MWe Auxiliary Load : 190 MWe Net Plant Power : 514 MWe Net Plant Efficiency , HHV : 31

. 0 % Net Plant Heat Rate : 10 , 998 BTU / KWe N 2 to GT Combustor

1 , 697 , 652 W 59

. 0 T 14

. 7 P 13

. 0 H

378 , 715 W 90

. 0 T 125

. 0 P 11

. 5 H

378 , 715 W 223

. 0 T 740

. 0 P 37

. 5 H To Claus Plant
10 , 260 W

90

. 0 T 125

. 0 P 11

. 5 H 74 , 082 W

66

. 9 T 16

. 4 P 15

. 7 H

1 , 080 , 178 W 90

. 0 T 56

. 4 P 14

. 2 H 152 , 901 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

457 , 753 W 385

. 0 T 469

. 0 P 87

. 0 H

Candle Filter Slurry Mix

Tank

E

- Gas TM Gasifier Milled Coal

Water

Slag Raw Syngas to Scrubber

Cyclones Syngas Recycle Saturated Steam to HRSG

BFW from HRSG

Blowdown to Flash Tank

Fire Tube Boiler Steam Drum

484 , 212 W 59

. 0 T 14

. 7 P

198 , 914 W

340

. 0 T 840

. 0 P 289

. 6 H

49 , 422 W 1 , 355 , 003 W 600

. 0 T 605

. 0 P 485

. 6 H 761 , 167 W

385

. 0 T 384

. 0 P 87

. 2 H

Fuel Gas

10 683 , 126 W

178

. 6 T 840

. 0 P 3 , 040

. 6 H 1 , 355 , 003 W 600

. 0 T 605

. 0 P 485

. 6 H 1 , 355 , 003 W

1 , 801

. 8 T

615

. 0 P 1 , 029

. 4 H Boost Compressor N 2 to GT Combustor

79 , 928 W

160

. 9 T 800

. 0 P 42

. 6 H

N 2 Diluent Preheater 1 , 355 , 003 W 450

. 0 T 600

. 0 P 422

. 6 H 100

. 0 T 189

. 5 P 18

. 0 H

8

9 Steam Sour Water

7 6 197 , 365 W

650

. 0 T 740

. 0 P 1 , 316

. 8 H 51 , 133 W 310

. 0 T 840

. 0 P 257

. 7 H Syngas Recycle Compressor 79 , 928 W 105

. 0 T 585

. 0 P 21

. 6 H 4

### Cost and Performance Baseline for Fossil Energy Plants

210 

## Exhibit 3

- 66 Case 4 Syngas Cleanup Heat and Mass Balance Schematic

Mercury Removal

Knock Out Drum Multistage Intercooled CO 2

Compressor
Raw Syngas Syngas Preheater Fuel Gas to GT

Sour Drum

To Water Treatment Makeup Water Interstage Knockout Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur High Temperature

Shift # 1 Low Temperature

Shift # 2

Knock Out From ASU

CO 2 Product Shift Steam Fuel Gas Humidification

Syngas Coolers

Sour Stripper Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Syngas Scrubber

Condensate to Deaerator

Condensate 371 , 625 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H

362

. 9 T 590

. 0 P 340

. 0 H

1 , 355 , 003 W 450

. 0 T 600

. 0 P 422

. 6 H 1 , 278 , 247 W 352

. 9 T 595

. 0 P 343

. 8 H 1 , 268 , 117 W 93

. 8 T 545

. 0 P 16

. 8 H 213 , 363 W 227

. 0 T 465

. 0 P 388

. 2 H

68 , 496 W

119

. 0 T 23

. 7 P 26

. 7 H

1 , 013 , 807 W 123

. 7 T 2 , 214

. 7 P 1 , 547 , 580 W 392

. 6 T 585

. 0 P 372

. 4 H 213 , 363 W 380

. 0 T 460

. 0 P 584

. 9 H

12 , 112 W 72 , 809 W 280

. 0 T 17

. 3 P 312

. 6 H

6 , 165 W 195

. 4 T 65

. 0 P 206

. 5 H 10 , 260 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 4
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 4 C O P G ASIFIER G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- 4

- PG

- 2 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 704 MWe Auxiliary Load : 190 MWe Net Plant Power : 514 MWe Net Plant Efficiency , HHV : 31

. 0 % Net Plant Heat Rate : 10 , 998 BTU / KWe 1 , 649 , 872 W 398

. 4 T 590

. 0 P 546

. 0 H 400

. 0 T 590

. 0 P 397

. 7 H 15

20 19

18 14

13 12 17

21 CO 2 Tailgas

65 , 864 W

120

. 0 T 10

. 6 P 106

. 8 H 1 , 207 , 359 W 94

. 6 T 550

. 0 P 17

. 6 H

12 , 050 W 111

. 6 T 10

. 6 P 37

. 1 H 1 , 014 , 845 W 60

. 0 T 135

. 0 P 3 Syngas Recycle 11

60 , 759 W 100

. 0 T 799

. 5 P

0

. 8 H 1 , 649 , 872 W 400

. 0 T 590

. 0 P 375

. 6 H 698

. 4 T 590

. 0 P 532

. 7 H

102 , 292 W 392

. 6 T 585

. 0 P 372

. 4 H Humidification 16

184 , 776 W 93

. 8 T 545

. 0 P 84

. 3 H

Claus Oxygen Preheater 10 , 260 W

450

. 0 T 124

. 5 P 91

. 9 H

Tail Gas Compressor Hydrogenation And Tail Gas

Cooling

### Cost and Performance Baseline for Fossil Energy Plants

211 

## E xhibit 3

- 67 Case 4 Combined Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Gasifier and WGS Steam

Ip Extraction Steam To 250 PSIA Header Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

1 , 218 , 920 W

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H 2 , 068 , 816 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 446 , 417 W 270

. 0 T 15

. 2 P 149

. 7 H

213 , 363 W

380

. 0 T 460

. 0 P 584

. 9 H 8 , 446 , 417 W 1 , 043

. 7 T

15

. 2 P 361

. 0 H

LP Process Header From Gasifier Island Preheating

To Claus LP BFW 1 , 370 , 817 W 993

. 7 T 1 , 814

. 7 P 1 , 475

. 8 H 9 , 744 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

1 , 398 , 140 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

27 , 273 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 460 , 271 W 464

. 8 T 65

. 0 P 1 , 264

. 6 H

2 , 068 , 816 W 102

. 7 T 120

. 0 P 70

. 9 H 2 , 068 , 816 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 614

. 7 T 65

. 0 P 1 , 338

. 6 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 4
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 4 C O P G ASIFIER P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- 4

- PG

- 3 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 704 MWe Auxiliary Load : 190 MWe Net Plant Power : 514 MWe Net Plant Efficiency , HHV : 31

. 0 % Net Plant Heat Rate : 10 , 998 BTU / KWe 22 23

25

17 24

Flue Gas

HOT WELL CONDENSER Make

- up 596 , 383 W 59

. 0 T 14

. 7 P 27

. 1 H 9 , 026 W 660

. 4 T 501

. 4 P 1 , 334

. 5 H 9 , 762 W 614

. 7 T 65

. 0 P 1 , 338

. 6 H 25 , 041 W

851

. 8 T 280

. 0 P 1 , 448

. 7 H 798 W 993

. 7 T 1 , 814

. 7 P 1 , 475

. 8 H 1 , 337 W 504

. 8 T 65

. 0 P 1 , 284

. 4 H

### Cost and Performance Baseline for Fossil Energy Plants

212 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

213 

## Exhibit 3

- 68 Case 4 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,960 (5,649) 5.0 (4.7) 5,965 (5,654) ASU Air 23.3 (22.1) 23 (22) GT Air 96.2 (91.2) 96 (91) Water 81.4 (77.1) 81 (77) Auxiliary Power 684 (649) 684 (649) TOTAL 5,960 (5,649) 205.8 (195.1) 684 (649) 6,850 (6,492) Heat Out GJ/hr (MMBtu/hr) ASU Vent 1.2 (1.2) 1 (1) Slag 37 (35) 25.2 (23.9) 62 (59) Sulfur 51 (48) 0.6 (0.6) 52 (49) CO 2 

## - 74.7 (

- 70.8)

- 75 (

- 71) Cooling Tower Blowdown 30.3 (28.8) 30 (29) HRSG Flue Gas 1,334 (1,264) 1,334 (1,264) Condenser 1,408 (1,334) 1,408 (1,334) Non

- Condenser Cooling Tower Loads* 755 (716) 755 (716) Process Losses** 749 (710) 749 (710) Power 2,533 (2,401) 2,533 (2,401) TOTAL 88 (83) 4,229 (4,008) 2,533 (2,401) 6,850 (6,492)

* Includes ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas cooler (low level heat rejection) and extraction air cooler. ** Calculated by difference to close the energy balance

### Cost and Performance Baseline for Fossil Energy Plants

214 

## 3.3.10 Major equipment items for the CoP gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account number s used in the cost estimates in Section Case 4

- Major Equipment List

3.3.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 363 tonne (400 ton) 6 0

### Cost and Performance Baseline for Fossil Energy Plants

215 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 481 tonne (530 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 298,179 liters (78,770 gal) 2 0

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 390,052 liters (103,040 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,170,080 liters (309,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,407 lpm (900 gpm) 2 2

### Cost and Performance Baseline for Fossil Energy Plants

216 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,101,555 liters (291,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,669 lpm @ 91 m H2O (2,290 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 606,907 kg/hr (1,338,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 8,555 lpm @ 27 m H2O (2,260 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 6,057 lpm @ 1,859 m H2O (1,600 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 1,287 lpm @ 223 m H2O (340 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 430 GJ/hr (407 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 154,066 lpm @ 21 m H2O (40,700 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 5,602 lpm @ 18 m H2O (1,480 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,801 lpm @ 268 m H2O (740 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single suction 3,066 lpm @ 49 m H2O (810 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,472,525 liter (389,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 1,855 lpm (490 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

217 

## ACCOUNT 4 GASIFIER, ASU AND AC CESSORIES INCLUDING LOW TEMPERATURE HEAT REC OVERY AND FUEL GAS SATURATION Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized two-stage, slurry-feed entrained bed 2,903 tonne/day, 4.2 MPa (3,200 tpd, 614.96 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 337,926 kg/hr (745,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 337,926 kg/hr (745,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 337,926 kg/hr (745,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 386,007 kg/hr (851,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 303,000 kg/hr, 35°C, 3.8 MPa (668,000 lb/hr, 95°F, 555 psia) 2 0

8 Saturation Water Economizers Shell and tube 36 GJ/hr (34 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 53,070 kg/hr, 108°C, 3.8 MPa (117,000 lb/hr, 227°F, 545 psia) 2 0

10 Saturator Water Pump Centrifugal 757 lpm @ 12 m H2O (200 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 53,070 kg/hr (117,000 lb/hr) 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 337,926 kg/hr (745,000 lb/hr) syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi-stage 5,805 m3/min @ 1.3 MPa (205,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage 1,161 m3/min (41,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 5.1 MPa (740 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi-stage 3,794 m3/min (134,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single-stage 538 m3/min (19,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

18 Gasifier Purge Nitrogen Boost Compressor Centrifugal, single-stage 1,614 m3/min (57,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 3.2 MPa (470 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

218 

## ACCOUNT 5A SOUR GAS SHIFT AND S YNGAS CLEANUP

ACCOUNT 5B CO 2 

## COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE A ND AUXILIARIES Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 301,185 kg/hr (664,000 lb/hr) 35 °C ( 95 °F ) 3.8 MPa (550 psia) 2 0

2 Sulfur Plant Claus type 145 tonne/day (160 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 411,408 kg/hr (907,000 lb/hr) 204 °C ( 400 °F ) 4.1 MPa (590 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 94 GJ/hr (89 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two-stage Selexol 316,154 kg/hr (697,000 lb/hr) 34 °C ( 94 °F ) 3.8 MPa (545 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 36,328 kg/hr (80,090 lb/hr) 232 °C ( 450 °F ) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 30,316 kg/hr (66,835 lb/hr) 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 CO2 Compressor Integrally geared, multi-stage centrifugal 1,141 m3/min @ 15.3 MPa (40,300 scfm @ 2,215 psia) 4 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

### Cost and Performance Baseline for Fossil Energy Plants

219 

## ACCOUNT 7 HRSG, DUCTING, AND S TACK

ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 341,986 kg/hr, 12.4 MPa / 534 °C ( 753 , 949 lb / hr , 1 , 800 psig / 994 °F ) Reheat steam - 298,222 kg/hr, 3

. 1 MPa / 534 °C ( 657 , 466 lb / hr , 452 psig / 994 °F ) 2 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 252 MW 12

. 4 MPa / 534 °C / 534 °C ( 1800 psig / 994 °F / 994 °F ) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 280 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,551 GJ/hr (1,470 MMBtu/hr), Inlet water temperature 16 °C ( 60 °F ) , Water temperature rise 11 °C ( 20 °F ) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

220 

## ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 SLAG RECOVERY AND HA NDLING Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 469,391 lpm @ 30 m (124,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11 °C ( 51

. 5 °F ) wet bulb / 16 °C ( 60 °F ) CWT / 27 °C ( 80 °F ) HWT

/ 2606 GJ/hr (2470 MMBtu/hr) heat duty 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 234,696 liters (62,000 gal) 2 0
2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0
3 Slag Depressurizer Proprietary 13 tonne/hr (14 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 140,060 liters (37,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 64,352 liters (17,000 gal) 2
6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0
7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 200,627 liters (53,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 64,352 liters (17,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O (60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 907 tonne (1,000 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

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## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 280 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 79 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 51 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 8 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

222 

## 3.3.11 The cost estimating methodology was described previously in Section 2.6. Case 4

- Cost Estimating Results Exhibit 3

- 69 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 70 shows a more detailed breakdown of the capital costs as well as TOC, TASC, and breakdown of owner’s costs

. Exhibit 3

- 71 shows the initial and annual O&M costs. The es timated TO C of the CoP gasifier with CO 2 

## capture is $ 3,466 /kW. Pr ocess contingency represents 3.5 percent of the TO C and pro ject contingency represents 11.1 percen t. The COE, including CO 2 

## TS& M costs of 5

. 6 mills/kWh, is 1 10

. 4 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

223 

## Exhibit 3

- 69 Case 4 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 4 - ConocoPhillips 500MW IGCC w/ CO2 Plant Size: 513.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $14,229 $2,644 $11,035 $0 $0 $27,908 $2,533 $0 $6,088 $36,529 $71

2 COAL & SORBENT PREP & FEED $24,241 $4,431 $14,646 $0 $0 $43,318 $3,889 $0 $9,441 $56,648 $110

3 FEEDWATER & MISC. BOP SYSTEMS $10,074 $7,882 $10,144 $0 $0 $28,101 $2,651 $0 $7,106 $37,858 $74

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $114,050 $0 $63,266 $0 $0 $177,316 $16,295 $24,521 $33,478 $251,609 $490 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $186,025 $0 w/equip. $0 $0 $186,025 $18,031 $0 $20,406 $224,461 $437 4.4-4.9 Other Gasification Equipment $24,056 $10,168 $14,678 $0 $0 $48,902 $4,688 $0 $11,449 $65,038 $127 SUBTOTAL 4 $324,131 $10,168 $77,944 $0 $0 $412,242 $39,014 $24,521 $65,332 $541,109 $1,054

5A GAS CLEANUP & PIPING $89,500 $3,812 $77,878 $0 $0 $171,190 $16,546 $26,077 $42,894 $256,707 $500

5B CO2 COMPRESSION $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $252 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $257

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,414 $3,652 $0 $4,207 $46,272 $90 7.2-7.9 SCR System, Ductwork and Stack $3,377 $2,407 $3,153 $0 $0 $8,938 $829 $0 $1,589 $11,355 $22 SUBTOTAL 7 $37,008 $2,407 $7,935 $0 $0 $47,351 $4,481 $0 $5,796 $57,628 $112

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $26,321 $0 $4,278 $0 $0 $30,600 $2,935 $0 $3,353 $36,888 $72 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,952 $903 $6,987 $0 $0 $17,843 $1,623 $0 $3,868 $23,333 $45 SUBTOTAL 8 $36,274 $903 $11,266 $0 $0 $48,442 $4,558 $0 $7,221 $60,222 $117

9 COOLING WATER SYSTEM $10,387 $9,859 $8,527 $0 $0 $28,773 $2,673 $0 $6,406 $37,852 $74

10 ASH/SPENT SORBENT HANDLING SYS $19,651 $1,481 $9,750 $0 $0 $30,882 $2,963 $0 $3,691 $37,536 $73

11 ACCESSORY ELECTRIC PLANT $31,778 $12,519 $24,431 $0 $0 $68,728 $5,909 $0 $14,164 $88,801 $173

12 INSTRUMENTATION & CONTROL $11,157 $2,052 $7,188 $0 $0 $20,397 $1,849 $1,020 $3,877 $27,142 $53

13 IMPROVEMENTS TO SITE $3,416 $2,014 $8,429 $0 $0 $13,859 $1,368 $0 $4,568 $19,796 $39

14 BUILDINGS & STRUCTURES $0 $6,693 $7,589 $0 $0 $14,282 $1,300 $0 $2,555 $18,136 $35

TOTAL COST $722,212 $67,672 $295,478 $0 $0 $1,085,363 $102,090 $61,479 $197,964 $1,446,895 $2,817 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

224 

## Exhibit 3

- 70 Case 4 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,737 $0 $1,826 $0 $0 $5,563 $498 $0 $1,212 $7,273 $14 1.2 Coal Stackout & Reclaim $4,829 $0 $1,171 $0 $0 $5,999 $526 $0 $1,305 $7,830 $15 1.3 Coal Conveyors & Yd Crush $4,489 $0 $1,158 $0 $0 $5,648 $496 $0 $1,229 $7,372 $14 1.4 Other Coal Handling $1,175 $0 $268 $0 $0 $1,443 $126 $0 $314 $1,883 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,644 $6,612 $0 $0 $9,256 $887 $0 $2,029 $12,172 $24 SUBTOTAL 1. $14,229 $2,644 $11,035 $0 $0 $27,908 $2,533 $0 $6,088 $36,529 $71 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying (incl. w/2.3) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,596 $382 $250 $0 $0 $2,228 $190 $0 $484 $2,902 $6 2.3 Slurry Prep & Feed $21,768 $0 $9,681 $0 $0 $31,449 $2,808 $0 $6,851 $41,108 $80 2.4 Misc.Coal Prep & Feed $877 $639 $1,914 $0 $0 $3,430 $315 $0 $749 $4,495 $9 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,411 $2,800 $0 $0 $6,211 $575 $0 $1,357 $8,143 $16 SUBTOTAL 2. $24,241 $4,431 $14,646 $0 $0 $43,318 $3,889 $0 $9,441 $56,648 $110 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,834 $4,868 $2,570 $0 $0 $10,272 $952 $0 $2,245 $13,468 $26 3.2 Water Makeup & Pretreating $709 $74 $396 $0 $0 $1,179 $112 $0 $387 $1,679 $3 3.3 Other Feedwater Subsystems $1,551 $524 $472 $0 $0 $2,546 $229 $0 $555 $3,330 $6 3.4 Service Water Systems $406 $835 $2,899 $0 $0 $4,140 $404 $0 $1,363 $5,907 $12 3.5 Other Boiler Plant Systems $2,177 $843 $2,090 $0 $0 $5,111 $485 $0 $1,119 $6,714 $13 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,456 $140 $0 $319 $1,915 $4 3.7 Waste Treatment Equipment $991 $0 $604 $0 $0 $1,595 $155 $0 $525 $2,276 $4 3.8 Misc. Power Plant Equipment $1,094 $146 $562 $0 $0 $1,802 $174 $0 $593 $2,569 $5 SUBTOTAL 3. $10,074 $7,882 $10,144 $0 $0 $28,101 $2,651 $0 $7,106 $37,858 $74 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (E-GAS) $114,050 $0 $63,266 $0 $0 $177,316 $16,295 $24,521 $33,478 $251,609 $490 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $186,025 $0 w/equip. $0 $0 $186,025 $18,031 $0 $20,406 $224,461 $437 4.4 LT Heat Recovery & FG Saturation $24,056 $0 $9,145 $0 $0 $33,201 $3,240 $0 $7,288 $43,730 $85 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,643 $669 $0 $0 $2,312 $222 $0 $507 $3,041 $6 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,525 $4,864 $0 $0 $13,389 $1,226 $0 $3,654 $18,268 $36 SUBTOTAL 4. $324,131 $10,168 $77,944 $0 $0 $412,242 $39,014 $24,521 $65,332 $541,109 $1,054

### Cost and Performance Baseline for Fossil Energy Plants

225 

## Exhibit 3

- 70 Case 4 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $70,224 $0 $59,586 $0 $0 $129,810 $12,554 $25,962 $33,665 $201,991 $393 5A.2 Elemental Sulfur Plant $10,291 $2,051 $13,278 $0 $0 $25,620 $2,489 $0 $5,622 $33,730 $66 5A.3 Mercury Removal $1,302 $0 $991 $0 $0 $2,294 $222 $115 $526 $3,156 $6 5A.4 Shift Reactors $7,138 $0 $2,873 $0 $0 $10,011 $960 $0 $2,194 $13,164 $26 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $545 $306 $172 $0 $0 $1,023 $98 $0 $224 $1,345 $3 5A.7 Fuel Gas Piping $0 $723 $506 $0 $0 $1,229 $114 $0 $269 $1,612 $3 5A.9 HGCU Foundations $0 $732 $472 $0 $0 $1,204 $111 $0 $394 $1,709 $3 SUBTOTAL 5A. $89,500 $3,812 $77,878 $0 $0 $171,190 $16,546 $26,077 $42,894 $256,707 $500 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76 SUBTOTAL 5B. $18,339 $0 $11,242 $0 $0 $29,581 $2,849 $0 $6,486 $38,916 $76 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,027 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,600 $252 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,027 $806 $7,475 $0 $0 $100,308 $9,507 $9,861 $12,339 $132,015 $257 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,414 $3,652 $0 $4,207 $46,272 $90 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,731 $1,235 $0 $0 $2,966 $260 $0 $645 $3,871 $8 7.4 Stack $3,377 $0 $1,269 $0 $0 $4,645 $445 $0 $509 $5,599 $11 7.9 HRSG,Duct & Stack Foundations $0 $677 $650 $0 $0 $1,326 $123 $0 $435 $1,885 $4 SUBTOTAL 7. $37,008 $2,407 $7,935 $0 $0 $47,351 $4,481 $0 $5,796 $57,628 $112 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $26,321 $0 $4,278 $0 $0 $30,600 $2,935 $0 $3,353 $36,888 $72 8.2 Turbine Plant Auxiliaries $182 $0 $417 $0 $0 $599 $59 $0 $66 $724 $1 8.3 Condenser & Auxiliaries $4,762 $0 $1,521 $0 $0 $6,284 $601 $0 $688 $7,573 $15 8.4 Steam Piping $5,008 $0 $3,523 $0 $0 $8,531 $733 $0 $2,316 $11,580 $23 8.9 TG Foundations $0 $903 $1,526 $0 $0 $2,429 $230 $0 $798 $3,457 $7 SUBTOTAL 8. $36,274 $903 $11,266 $0 $0 $48,442 $4,558 $0 $7,221 $60,222 $117

### Cost and Performance Baseline for Fossil Energy Plants

226 

## Exhibit 3

- 70 Case 4 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,196 $0 $1,401 $0 $0 $8,597 $819 $0 $1,412 $10,828 $21 9.2 Circulating Water Pumps $1,877 $0 $136 $0 $0 $2,013 $170 $0 $327 $2,510 $5 9.3 Circ.Water System Auxiliaries $157 $0 $22 $0 $0 $179 $17 $0 $29 $226 $0 9.4 Circ.Water Piping $0 $6,545 $1,697 $0 $0 $8,241 $745 $0 $1,797 $10,783 $21 9.5 Make-up Water System $384 $0 $549 $0 $0 $933 $90 $0 $205 $1,227 $2 9.6 Component Cooling Water Sys $773 $924 $657 $0 $0 $2,354 $221 $0 $515 $3,090 $6 9.9 Circ.Water System Foundations $0 $2,391 $4,064 $0 $0 $6,455 $612 $0 $2,120 $9,187 $18 SUBTOTAL 9. $10,387 $9,859 $8,527 $0 $0 $28,773 $2,673 $0 $6,406 $37,852 $74 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $17,164 $0 $8,464 $0 $0 $25,628 $2,462 $0 $2,809 $30,900 $60 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $564 $0 $613 $0 $0 $1,177 $114 $0 $194 $1,485 $3 10.7 Ash Transport & Feed Equipment $756 $0 $182 $0 $0 $938 $88 $0 $154 $1,180 $2 10.8 Misc. Ash Handling Equipment $1,168 $1,431 $427 $0 $0 $3,026 $288 $0 $497 $3,811 $7 10.9 Ash/Spent Sorbent Foundation $0 $50 $63 $0 $0 $112 $11 $0 $37 $160 $0 SUBTOTAL 10. $19,651 $1,481 $9,750 $0 $0 $30,882 $2,963 $0 $3,691 $37,536 $73 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $924 $0 $914 $0 $0 $1,839 $176 $0 $201 $2,216 $4 11.2 Station Service Equipment $4,676 $0 $421 $0 $0 $5,097 $470 $0 $557 $6,124 $12 11.3 Switchgear & Motor Control $8,644 $0 $1,572 $0 $0 $10,216 $948 $0 $1,675 $12,838 $25 11.4 Conduit & Cable Tray $0 $4,015 $13,247 $0 $0 $17,262 $1,670 $0 $4,733 $23,665 $46 11.5 Wire & Cable $0 $7,672 $5,041 $0 $0 $12,713 $924 $0 $3,409 $17,046 $33 11.6 Protective Equipment $0 $680 $2,474 $0 $0 $3,153 $308 $0 $519 $3,980 $8 11.7 Standby Equipment $229 $0 $223 $0 $0 $452 $43 $0 $74 $570 $1 11.8 Main Power Transformers $17,305 $0 $140 $0 $0 $17,445 $1,319 $0 $2,815 $21,579 $42 11.9 Electrical Foundations $0 $152 $398 $0 $0 $550 $53 $0 $181 $784 $2 SUBTOTAL 11. $31,778 $12,519 $24,431 $0 $0 $68,728 $5,909 $0 $14,164 $88,801 $173 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,101 $0 $735 $0 $0 $1,837 $174 $92 $315 $2,418 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $253 $0 $162 $0 $0 $415 $39 $21 $95 $571 $1 12.7 Computer & Accessories $5,875 $0 $188 $0 $0 $6,063 $557 $303 $692 $7,615 $15 12.8 Instrument Wiring & Tubing $0 $2,052 $4,196 $0 $0 $6,248 $530 $312 $1,773 $8,863 $17 12.9 Other I & C Equipment $3,927 $0 $1,907 $0 $0 $5,834 $549 $292 $1,001 $7,676 $15 SUBTOTAL 12. $11,157 $2,052 $7,188 $0 $0 $20,397 $1,849 $1,020 $3,877 $27,142 $53

### Cost and Performance Baseline for Fossil Energy Plants

227 

## Exhibit 3

- 70 Case 4 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $107 $2,291 $0 $0 $2,398 $238 $0 $791 $3,427 $7 13.2 Site Improvements $0 $1,906 $2,533 $0 $0 $4,440 $438 $0 $1,463 $6,341 $12 13.3 Site Facilities $3,416 $0 $3,605 $0 $0 $7,021 $692 $0 $2,314 $10,027 $20 SUBTOTAL 13. $3,416 $2,014 $8,429 $0 $0 $13,859 $1,368 $0 $4,568 $19,796 $39 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,246 $3,200 $0 $0 $5,445 $501 $0 $892 $6,838 $13 14.3 Administration Building $0 $870 $631 $0 $0 $1,501 $134 $0 $245 $1,880 $4 14.4 Circulation Water Pumphouse $0 $163 $86 $0 $0 $250 $22 $0 $41 $312 $1 14.5 Water Treatment Buildings $0 $592 $578 $0 $0 $1,171 $106 $0 $191 $1,468 $3 14.6 Machine Shop $0 $445 $305 $0 $0 $750 $67 $0 $122 $939 $2 14.7 Warehouse $0 $719 $464 $0 $0 $1,183 $105 $0 $193 $1,481 $3 14.8 Other Buildings & Structures $0 $431 $335 $0 $0 $766 $68 $0 $167 $1,001 $2 14.9 Waste Treating Building & Str. $0 $963 $1,840 $0 $0 $2,802 $261 $0 $613 $3,676 $7 SUBTOTAL 14. $0 $6,693 $7,589 $0 $0 $14,282 $1,300 $0 $2,555 $18,136 $35

TOTAL COST $722,212 $67,672 $295,478 $0 $0 $1,085,363 $102,090 $61,479 $197,964 $1,446,895 $2,817
Owner's Costs Preproduction Costs 6 Months All Labor $13,491 $26 1 Month Maintenance Materials $2,999 $6 1 Month Non-fuel Consumables $385 $1 1 Month Waste Disposal $295 $1 25% of 1 Months Fuel Cost at 100% CF $1,687 $3 2% of TPC $28,938 $56 Total $47,793 $93 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,995 $27 0.5% of TPC (spare parts) $7,234 $14 Total $21,230 $41
Initial Cost for Catalyst and Chemicals $7,371 $14 Land $900 $2 Other Owner's Costs $217,034 $423

Financing Costs $39,066 $76 Total Overnight Costs (TOC) $1,780,290 $3,466 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,029,531 $3,952

### Cost and Performance Baseline for Fossil Energy Plants

228 

## Exhibit 3

- 71 Case 4 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 4 - ConocoPhillips 500MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,998 MWe-net: 514 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $12.292 Maintenance Labor Cost $15,271,560 $29.734 Administrative & Support Labor $5,396,267 $10.507 Property Taxes and Insurance $28,937,909 $56.342 TOTAL FIXED OPERATING COSTS $55,919,243 $108.875 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $28,787,121 $0.00800

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 0 4,116 1.08 $0 $1,300,111 $0.00036

Chemicals

MU & WT Chem. (lbs) 0 24,523 0.17 $0 $1,239,310 $0.00034 Carbon (Mercury Removal) (lb) 104,394 143 1.05 $109,631 $43,852 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,484 4.44 498.83 $3,234,413 $646,883 $0.00018 Selexol Solution (gal) 300,533 98 13.40 $4,026,613 $384,543 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 2.00 131.27 $0 $76,827 $0.00002 Subtotal Chemicals $7,370,657 $2,391,415 $0.00066

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Spent Mercury Catalyst (lb.) 0 143 0.42 $0 $17,416 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 593 16.23 $0 $2,809,802 $0.00078 Subtotal Waste Disposal $0 $2,827,218 $0.00079 By-products & Emissions

Sulfur (ton) 0 145 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,370,657 $35,305,866 $0.00981

Fuel (ton) 0 5,811 38.18 $0 $64,786,772 $0.01800

### Cost and Performance Baseline for Fossil Energy Plants

229 

## 3.4 SHELL GLOBAL SOLUTIO NS IGCC CASES This section contains an evaluation of plant designs for Cases 5 and 6, which are based on the Shell gasifier. Cases 5 and 6 are very similar in terms of process, equipment, scope and arrangement, except that Case 6 employs a syngas quench and includes SG S reactors, CO 2 

## absorption/regeneration , and compression/transport systems. There are no provisions for CO 2 

## removal in Case 5. The balance of this section is organized in an analogous manner to Sections 3.2 and 3.3 :

**•** Gasifier Background

**•** Process System Description for Case 5

**•** Key Assumptions for Cases 5 and 6

**•** Sparing Philosophy for Cases 5 and 6

**•** Performance Results for Case 5

**•** Equipment List for Case 5

**•** Cost Estimates For Case 5

**•** Process and System Description, Performance Results, Equipment List , and Cost Estimate for Case 6
3.4.1 Development and Current Status

– Development of the Shell gasification process for partial oxidation of oil and gas began in the early 1950s. More than 75 commercial Shell partial

oxidation plants have been built worldwide to convert a variety of hydrocarbon liquids and gases to carbo n monoxide and hydrogen. Gasifier Background

Shell Internationale Petroleum Maatschappij B.V. began work on coal gasification in 1972. The coal gasifier is significantly different than the oil and gas gasifiers developed earlier. A pressurized, entrained

- flow, slagging coal gasifier was built at Shell’s Amsterdam laboratories. This 5 tonnes/day (6 TPD) process development unit has operated for approximately 12,000 hours since 1976. A larger 150 tonnes/day (165 TPD) pilot plant was built at Shell’s Hamburg refinery in Hambu rg, Germany. This larger unit operated for approximately 6,000 hours from 1978 to 1983, and successfully gasified over 27,216 tonnes (30,000 tons) of coal. From 1974 until mid

- 1981, Heinrich Koppers GmbH (now Krupp Koppers) cooperated with Shell in the de velopment work for the coal gasification technology at the 150 tonnes/day (165 TPD) pilot plant in Hamburg. Krupp Koppers is the licensor of the commercially proven Koppers

- Totzek coal gasification technology, an entrained

- flow slagging gasification syste m operated at atmospheric pressure. In June 1981, the partnership between Shell and Krupp Koppers was terminated. Since that time, this gasification technology has been developed solely by Shell as the Shell Coal Gasification Process. Krupp Koppers conti nued its own development of a similar pressurized, dry feed, entrained

- flow gasification technology called PRENFLO. Krupp Koppers has built and successfully operated a small 45 tonnes/day (50 TPD) PRENFLO pilot plant at Fuerstenhausen,

### Cost and Performance Baseline for Fossil Energy Plants

230 

## Germany. In 2000 S hell and Krupp Uhde agreed to join forces again in gasification and jointly offer the Shell coal gasification process. Based on the experience it gained with the Hamburg unit, Shell built a demonstration unit at its oil refinery and chemical complex in Dee r Park, Texas, near Houston. This new unit, commonly called SCGP

- 1 (for Shell Coal Gasification Plant

- 1), was designed to gasify bituminous coal at the rate of 227 tonnes/day (250 TPD) and to gasify high

- moisture, high

- ash lignite at the rate of 363 tonne s/day (400 TPD). The relatively small difference in size between the Hamburg and Deer Park units reflects design changes and improvements. The Deer Park demonstration plant operated successfully after startup in July 1987. Before the end of the program i n 1991, after 15,000 hours of operation, 18 different feedstocks were gasified at the plant, including domestic coals ranging from lignite to high

- sulfur bituminous, three widely traded foreign coals, and petroleum coke. The Deer Park unit produced superh eated HP steam in the waste heat recovery boiler. The plant also had facilities for extensive environmental monitoring and for sidestream testing of several AGR processes, including Sulfinol

- D, Sulfinol

- M, highly loaded MDEA, and various wastewater treatm ent schemes. In spring 1989, Shell announced that its technology had been selected for the large commercial

scale Demkolec B.V. IGCC plant at Buggenum, near Roermond, in The Netherlands. This plant generates 250 MW of IGCC electricity with a single Shell gasifier consuming 1,814 tonnes/day (2,000 TPD) (dry basis) of coal. The plant was originally owned and operated by Samenwerkende Electriciteits

- Productiebedrijven NV (SEP), a consortium of Dutch utilities, and began operation in 1994. In 2000 the plant was purchased by Nuon. Shell was extensively involved in the design, startup, and initial operation of this plant. A key feature of this design is the use of extraction air from the CT air compressor to feed the oxygen plant. Gasifier Capacity

– As of 20 09, Shell reported ten gasifiers in operation producing 100,000

- 150,000 Nm 3 

## /h r and three of the same size in construction. Another three ranging from 150,000

- 250,000 Nm 3 

## /h r are also in construction [ 61

Distinguishing Characteristics

– The key advantage of the Shell coal gasification technology is its lack of feed coal limit ations. One of the major achievements of the Shell development program has been the successful gasification of a wide variety of coals ranging from anthracite to brown coal. The dry pulverized feed system developed by Shell uses all coal types with
essen tially no operating and design modifications (provided the drying pulverizers are appropriately sized). The dry fed Shell gasifier also has the advantage of lower oxygen requirement than comparable slurry fed entrained flow gasifiers. ]

. The large gasifier operating in The Netherlands has a bituminous coal

- handling capacity of 1,633 tonnes/day (1,800 TPD) and produces dry gas at a rate of 158,575 Nm 3 

## /h r (5.6 million scf/h r ) with an energy content of about 1,792 MMkJ/h r (1,700 MMBtu/h r ) (HHV). This gasifier was sized to match the fuel gas requirements for the Siemens/Kraftwerk Union V

- 94.2 CT and could easily be scaled up to match advanced F Class turbine requirements

.

Entrained

- flow slagg ing gasifiers have fundamental environmental advantages over fluidized

bed and moving

- bed gasifiers. They produce no hydrocarbon liquids, and the only solid waste is an inert slag. The dry feed entrained

- flow gasifiers also have minor environmental advan tages over the slurry feed entrained

- flow gasifiers. They produce a higher H 2 

## S/CO 2 

## ratio acid gas, which improves sulfur recovery and lessens some of the gray water processing and the fixed

salts blowdown problems associated with slurry feeding.

### Cost and Performance Baseline for Fossil Energy Plants

231 

## A disadva ntage of the Shell coal gasification technology is the high waste heat recovery ( SGC ) duty. As with the other slagging gasifiers, the Shell process has this disadvantage due to its high operating temperature. The ability to feed dry solids minimizes the oxygen requirement and makes the Shell gasifier somewhat more efficient than entrained flow gasifiers employing slurry feed systems. The penalty paid for this increase in efficiency is a coal feed system that is more costly and operationally more complex. Demonstration of the reliability and safety of the dry coal feeding system was essential for the successful development of the Shell technology. The high operating temperature required by all entrained

- flow slagging processes can result in relatively hi gh capital and maintenance costs. However, the Shell gasifier employs a cooled refractory, which requires fewer change outs than an uncooled refractory. Life of a water wall is determined by metallurgy and temperature and can provide a significant O&M co st benefit over refractory lined gasifiers. Important Coal Characteristics

– Characteristics desirable for coal considered for use in the Shell gasifier include moderate ash fusion temperature and relatively low ash content. The Shell gasifier is extremel y flexible; it can handle a wide variety of different coals, including lignite. High

- ash fusion

- temperature coals may require flux addition for optimal gasifier operation. The ash content, fusion temperature, and composition affect the required gasifier operating temperature level, oxygen requirements, heat removal, slag management, and maintenance. However, dry feeding reduces the negative effects of high ash content relative to slurry feed gasifiers.
3.4.2 In this section the overall Shel l gasification process for Case 5 is described. The system description follows the BFD in Process Description

Exhibit 3

- 72 and stream numbers reference the same Exhibit. The tables in Exhibit 3

- 73 provide process data for the numbered streams in the BFD.

Coal receiving and handling is common to all cases and was covered in Section Coal Preparation and Feed Systems 3.1.1 . The receiving and handling subsystem ends at the coal silo. The Shell proces s uses a dry feed system , which is sensitive to the coal moisture content. Coal moisture consists of two parts, surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the surface moisture must be removed. The Illinoi s No. 6 coal used in this study contains 11.12 percent total moisture on an as

- received basis (stream 9). It was assumed that the coal must be dried to 5 percent moisture to allow for smooth flow through the dry feed system (stream 10). The coal is simult aneously crushed and dried in the coal mill then delivered to a surge hopper with an approximate 2

- hour capacity. The drying medium is provided by combining the off

- gas from the Claus plant TGTU and a slipstream of clean syngas (stream 8) and passing them through an incinerator. The incinerator FG , with an oxygen content of 6 vol%, is then used to dry the coal in the mill. The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to a dense phase pneumatic conveyor, whic h uses nitrogen from the ASU to convey the coal to the gasifiers.

### Cost and Performance Baseline for Fossil Energy Plants

232 

## Exhibit 3

- 72 Case 5 Block Flow Diagram , Shell IGCC without CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

233 

## Exhibit 3

- 73 Case 5 Stream Table , Shell IGCC without CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0262 0.0318 0.0023 0.0318 0.0000 0.0023 0.0100 0.0000 0.0000 0.0000 0.0095 0.0095 0.0096 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0006 0.0006 0.0006 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5980 0.0000 0.0000 0.0000 0.5797 0.5797 0.5833 CO 2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0158 0.0000 0.0000 0.0000 0.0143 0.0143 0.0151 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0007 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3142 0.0000 0.8090 0.0000 0.3006 0.3006 0.3024 H 2 O 0.0099 0.2378 0.0000 0.0003 0.0000 1.0000 0.0004 0.0013 0.0000 0.0935 0.0000 0.0252 0.0252 0.0194 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0009 0.0009 0.0001 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0081 0.0089 N 2 0.7732 0.5018 0.0178 0.9919 0.0178 0.0000 0.9919 0.0601 0.0000 0.0163 0.0000 0.0567 0.0567 0.0570 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0036 0.0036 0.0036 O 2 0.2074 0.2251 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 18,364 812 88 16,375 4,591 1,061 882 252 0 0 0 25,096 17,567 17,460 V-L Flowrate (kg/hr) 529,935 21,917 2,828 459,480 147,752 19,111 24,747 5,088 0 0 0 509,993 356,995 354,790 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 198,059 185,222 19,837 0 0 0
Temperature (°C) 15 21 32 93 32 343 32 45 15 16 1,427 1,079 191 177 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.41 3.65 0.10 5.79 4.24 4.24 4.03 3.90 Enthalpy (kJ/kg) A 30.23 37.32 26.67 92.52 26.67 3,063.97 21.22 60.75

--- 0.00 0.00 0.00 325.96 297.28 Density (kg/m 3 ) 1.2 1.6 11.0 24.4 11.0 20.1 60.5 27.8

--- 16.5

--- 7.6 21.0 20.9 V-L Molecular Weight 28.857 26.992 32.181 28.060 32.181 18.015 28.060 20.195

--- --- --- 20.322 20.322 20.320
V-L Flowrate (lb mol /hr) 40,486 1,790 194 36,101 10,122 2,339 1,944 555 0 0 0 55,328 38,729 38,493 V-L Flowrate (lb/hr) 1,168,307 48,319 6,236 1,012,980 325,738 42,132 54,557 11,218 0 0 0 1,124,342 787,039 782,178 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 436,646 408,345 43,732 0 0 0
Temperature (°F) 59 70 90 199 90 650 90 112 59 60 2,600 1,974 375 351 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 785.0 530.0 14.7 840.0 615.0 615.0 585.0 565.0 Enthalpy (Btu/lb) A 13.0 16.0 11.5 39.8 11.5 1,317.3 9.1 26.1

--- 140.1 127.8 Density (lb/ft 3 ) 0.076 0.101 0.687 1.521 0.687 1.257 3.774 1.734

--- 1.029

--- 0.475 1.310 1.303 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

234 

## Exhibit 3

- 73 Case 5 Stream Table , Shell IGCC without CO 2 

## Capture (C ontinued)

15 16 17 18 19 20 21 22 23 24 25 26 27 V-L Mole Fraction

Ar 0.0098 0.0098 0.0100 0.0079 0.0079 0.0004 0.0000 0.0058 0.0092 0.0092 0.0086 0.0086 0.0000 CH 4 0.0006 0.0006 0.0006 0.0005 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.5962 0.5845 0.5980 0.4741 0.4741 0.0167 0.0000 0.1034 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0155 0.0257 0.0158 0.0125 0.0125 0.4460 0.0000 0.2613 0.0003 0.0003 0.0752 0.0752 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.3091 0.3072 0.3142 0.2491 0.2491 0.0096 0.0000 0.0429 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0014 0.0015 0.0013 0.2083 0.2083 0.0063 0.0000 0.4259 0.0099 0.0099 0.0906 0.0906 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0091 0.0089 0.0000 0.0000 0.0000 0.3872 0.0000 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000 N 2 0.0583 0.0618 0.0601 0.0476 0.0476 0.1338 0.0000 0.1585 0.7732 0.7732 0.7210 0.7210 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1046 0.1046 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 17,081 17,426 16,771 21,155 21,155 402 0 510 110,253 4,410 137,428 137,428 39,521 V-L Flowrate (kg/hr) 347,994 358,740 338,688 417,666 417,666 14,964 0 13,723 3,181,557 127,262 3,962,154 3,962,154 711,987 Solids Flowrate (kg/hr) 0 0 0 0 0 0 4,959 0 0 0 0 0 0
Temperature (°C) 35 34 45 161 193 45 178 232 15 432 587 132 559 Pressure (MPa, abs) 3.72 3.69 3.65 3.21 3.2 3.654 0.409 0.406 0.101 1.619 0.105 0.105 12.512 Enthalpy (kJ/kg) A 0.00 44.26 60.75 0.00 762.9 13.883

--- 1,007.135 30.227 463.785 791.043 280.131 3,496.259 Density (kg/m 3 ) 29.5 29.6 27.8 17.7 16.2 60.9 5,278.6 2.6 1.2 7.9 0.4 0.9 35.2 V-L Molecular Weight 20.373 20.587 20.195 19.743 20 37.190

--- 26.923 28.857 28.857 28.831 28.831 18.015
V-L Flowrate (lb mol /hr) 37,657 38,417 36,974 46,639 46,639 887 0 1,124 243,066 9,723 302,978 302,978 87,130 V-L Flowrate (lb/hr) 767,195 790,887 746,680 920,797 920,797 32,989 0 30,253 7,014,133 280,565 8,735,053 8,735,053 1,569,662 Solids Flowrate (lb/hr) 0 0 0 0 0 0 10,933 0 0 0 0 0 0
Temperature (°F) 94 94 112 321 380 112 353 450 59 810 1,088 270 1,038 Pressure (psia) 540.0 535.0 530.0 465.0 460.0 530.0 59.3 58.9 14.7 234.9 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 19.0 26.1 328.0 6.0

--- 433.0 13.0 199.4 340.1 120.4 1,503.1 Density (lb/ft 3 ) 1.844 1.850 1.734 1.103 1 3.805 329.535 0.163 0.076 0.495 0.026 0.056 2.200

### Cost and Performance Baseline for Fossil Energy Plants

235 

## There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2 MPa (615 psia) and processing a total of 4, 753 tonnes/day (5, 240 TPD) of as

- received coal. The air separation plant supplies 3,614 tonnes/day (3,984 TPD) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant (stream 3). Coal reacts with oxygen and steam at a temperature of 1427°C (2600°F) in the gasifier to produce principally hy drogen and carbon monoxide with little carbon dioxide formed. Gasifier

The gasifier includes a refractory

- lined water wall that is also protected by molten slag that solidifies on the cooled walls.

High

- temperature heat recov ery in each gasifier train is accomplished in three steps, including the gasifier jacket, which cools and solidifies slag touching the gasifier walls and maintain s the syngas temperature at 1 , 427°C (2 , 600°F). The product gas from the gasifier is cooled to approximately 1,093 **°** C ( 2,000 **°** F) by adding cooled recycled fuel gas to lower the temperature below the ash melting point. Gas (stream 12) then goes through a duct cooler and syngas cooler, which lower the gas temperature from approximately 1,093 **°** C ( 2,000 **°** F) to 316 **°** C (600 **°** F), and produce HP steam for use in the steam cycle. Raw Gas Cooling/Particulate Removal

After passing through the duct cooler and syngas cooler , the syngas passes through a cyclone and a raw gas candle filter where a majority of the fine particles are removed and returned to the gasifier with the coal fuel. The filter consists of an array of ceramic candle elements in a pressure vessel. Fines produced by the gasification system are recirculated to extinction. The ash that is not carried out with the gas forms slag and r uns down the interior walls, exiting the gasifier in liquid form. The slag is solidified in a quench tank for disposal (stream 11). Lockhoppers are used to reduce the pressure of the solids from 4 .2 to 0.1 MPa ( 615 to 15 psia). The syngas scrubber remov es additional PM further downstream. After passing through the cyclone and ceramic candle filter array, t he syngas is further cooled to 191 °C ( 375 °F) (stream 13) by raising IP steam

.

About 30 percent of the cooled syngas is recycled back to the gasifier exit as quench gas. A single

- stage compressor is utilized to boost the pressure of the cooled fuel gas stream from 4.0 MPa (575 psia) to 4. 0 MPa ( 585 psia) to provide quench gas to cool the gas stream from the gasifier. Quench Gas Compressor

The raw syngas exiting the final raw gas cooler at 191 **°** C (3 75 **°** F) (stream 13) then enters the scrubber for removal of chlorides , SO 2 

## , NH 3 

## and remaining particulate. The quench scrubber washes the syngas in a counter

- curren t flow in two packed beds. The syngas leaves the scrubber saturated at a temperature of 94 **°** C ( 201oF ). The quench scrubber removes essentially all traces of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the scrub ber are sent to the slag removal and handling system for processing. Sy ngas Scrubber/Sour Water Stripper

The sour water stripper removes NH 3 

## , SO 2 

## , and other impurities from the waste stream of the scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the g as

### Cost and Performance Baseline for Fossil Energy Plants

236 

## scrubber and condensate from SGC s. Sour water from the drum flows to the sour stripper, which consists of a packed column with a steam

- heated reboiler. Sour gas is stripped from the liquid and sent to the SRU . Remaining water is sent to wastewater tr eatment.

H 2 

## S and COS are at significant concentrations, requiring removal for the power plant to achieve the low design level of SO 2 

## emissions. H 2 

## S is removed in an AGR process; however, because COS is not readily r emovable, it is first catalytically converted to H 2 

## S in a COS hydrolysis unit. COS Hydrolysis, Mercury Removal and AGR

Following the water scrubber, the gas is reheated to 177 **°** C ( 350 **°** F) and fed to the COS hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed t o H 2 

## S, which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the AGR process (stream 1 4 ), it must be cooled to about 35 **°** C ( 95 **°** F). During this cooling through a series of heat exchangers, part of the water vapor condenses. This water, which contains some NH 3 

## , is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a carbon bed to remove 95 percent of the Hg (Section 3.1.4 ). The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a mixture of amines and a physical solvent. The solvent consists of an aqueous amine and sulfolane. Sulfinol

- D uses diisoprop anolamine (DIPA), while Sulfinol

- M uses MDEA. The mixed solvents allow for better solvent loadings at high acid gas partial pressures and higher solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol

- M was selected for this application. The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column in which the H 2 

## S, COS, CO 2 

## , and small amounts of H 2 

## and CO are removed from the gas by the Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit. The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is flashed in the rich solvent f lash vessel. The flashed gas is then scrubbed in the LP contactor with lean solvent to remove H 2 

## S and COS. The overhead from the LP contactor is flashed in the LP KO drum. This gas can be used as a utility fuel gas, consisting primarily of H 2 

## and CO, at 0.8 MPa (118 psia) and 38 **°** C (101 **°** F). The solvent from the bottom of the LP contactor is returned to the rich solvent flash vessel. Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before entering the stripper. The stripper strips the H 2 

## S, COS, and CO 2 

## from the solvent at LP with heat supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor. The Sulfinol process removes essentially all of the CO 2 

## alo ng with the H 2 

## S and COS. The acid gas fed to the SRU contains 39 vol% H 2 

## S and 45 vol% CO 2 

## . The CO 2 

## passes through the SRU, the TGTU and ultimately is vented through the coal dryer. Since the amount of CO 2 

## in the syngas is small initially, this does not have a significant effect on the mass flow reaching the GT

. However, the costs of the sulfur recovery/tail gas cleanup are higher than for a sulfur removal process producing an acid gas stream with a higher sulfur concentration.

### Cost and Performance Baseline for Fossil Energy Plants

237 

## The SRU is a Claus bypass type SRU utilizing oxygen (stream 3) instead of air. The Claus plant produces molten sulfur (stream 21) by reacting approximately one third of the H 2 

## S in the feed to SO 2 

## , then reacting the H 2 

## S and SO 2 

## to sulfur and water. The use of Claus technology results in an overall sulfur recovery exceeding 99 percent. Claus Unit

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery plant. The sulfur plant produces approximately 119 tonnes/day (13 1 TPD) o f elemental sulfur. Feed for this case consists of acid gas from both the acid gas cleanup unit (stream 20) and a vent stream from the sour water stripper in the gasifier section. A slipst ream of clean syngas (stream 8) is passed through an incinerator a nd combusted with air. The hot, nearly inert incinerator off gas is used to dry coal before being vented to the atmosphere. In the furnace waste heat boiler, 11,991 kg/h r ( 26,435 lb/h r ) of 3. 0 MPa ( 430 psia) steam are generated. This steam is used to sat isfy all Claus process preheating and reheating requirements as well as to provide some steam to the medium

- pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) steam for the LP steam header.

Clean syngas exiting the Sulfino l absorber (stream 17) is humidified because there is not sufficient nitrogen from the ASU to provide the level of dilution required. The moisturized syngas (stream 18) is reheated (stream 19), further diluted with nitrogen from the ASU (stream 4) and ste am, and enters the advanced F Class CT burner. The CT compressor provides combustion air to the burner and also 19 percent of the air requirements in the ASU (stream 24). The exhaust gas exits the CT at 587 °C (1, 088 °F) (stream 25) and enters the HRSG whe re additional heat is recovered until the FG exits the HRSG at 132°C (270°F) (stream 26) and is discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, commercially available steam turbine using a 12.4 MPa/ 559 °C/ 559 ° C (1800 psig/ 1038 °F/10 38 °F) steam cycle. Power Block

The ASU is designed to produce a nominal output of 3, 614 tonnes/day ( 3,984 TPD) of 95 mol% O 2 

## for use in the gasifier (stream 5) and SRU (stream 3). The plant is designed with two producti on trains. The air compressor is powered by an electric motor. Approximately 11, 028 tonnes/day ( 12,156 TPD) of nitrogen are also recovered, compressed, and used as dilution in the GT combustor. About 4 percent of the GT air is used to supply approximate ly 19 percent of the ASU air requirements. Air Separation Unit (ASU)

Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 and 3.1.11

. 3.4.3 System assumptions for Cases 5 and 6, Shell IGCC with and without CO 2 

## capture, are compiled in Key System Assumptions

Exhibit 3

- 74

.

### Cost and Performance Baseline for Fossil Energy Plants

238 

## The balance of plant assumptions are common to all cases and were presented previously in Balance of Plant

– C ases 5 and 6

Exhibit 3

- 16

. Exhibit 3

- 74 Shell IGCC Plant Study Configuration Matrix Case 5 6 Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615) O 2 

## :Coal Ratio, kg O 2 

## /kg dry coal 0. 84 0. 84 Carbon Conversion, % 99.5 99.5 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

## (Btu/scf) 10, 841 ( 29 1 ) 10, 849 (2 9 1 ) Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/ 559 /5 59 (1800/10 38 /10 38 ) 12.4/53 4 /53 4 (1800/ 993 / 993) Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

CT 2x Advanced F Class (232 MW output each) 2x Advanced F Class (232 MW output each) Gasifier Technology Shell Shell Oxidant 95 vol% Oxygen 95 vol% Oxygen Coal Illinois No. 6 Illinois No. 6 Coal Feed Moisture Content, % 5 5 COS Hydrolysis Yes Occurs in SGS SGS No Yes H 2 

## S Separation Sulfinol

- M Selexol 1 st 

## Stage Sulfur Removal, % 99. 7 99. 9
Sulfur Recovery Claus Plant with Tail Gas Treatment / Elemental Sulfur Claus Plant with Tail Gas Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, and AGR Absorber Cyclone, Candle Filter, Scrubber, and AGR Absorber Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N 2 

## Dilution, Humidification and steam dilution MNQC (LNB), N 2 

## Dilution and Humidification
CO 2 

## Separation N/A Selexol 2 nd 

## Stage Overall CO 2 

## Capture N/A 90. 1 % CO 2 

## Sequestration N/A Off

- site Saline Formation

### Cost and Performance Baseline for Fossil Energy Plants

239 

## 3.4.4 The sparing philosophy for Cases 5 and 6 is provided below. Single trains are utilized throughout with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment. Sparing Philosophy

The plant design consists of the following major subsystems:

**•** Two ASU s (2 x 50%)

**•** Two trains of coal drying and dry feed systems (2 x 50%)

**•** Two trains of gasification, including gasifier, SGC , cyclone, and barrier filter (2 x 50%).

**•** Tw o trains of syngas clean

- up process (2 x 50%).

**•** Two trains of Sulfinol

- M acid gas removal in Case 5 and two

- stage Selexol in Case 6 (2 x 50%),

**•** One train of Claus

- based sulfur recovery (1 x 100%).

**•** Two CT /HRSG tandems (2 x 50%).

**•** One steam turbine (1 x 100%)

. 3.4.5 The plant produces a net output of 6 2 9 MWe at a net plant efficiency of 4 2. 1 percent (HHV basis). Shell has reported expected efficiencies using bituminous coal of around 44

- 45 percent (HHV basis), although this value excluded the n et power impact of coal drying [ Case 5 Performance Results

62

Overall performa nce for the entire plant is summarized in ]

. Accounting for coal drying would reduce the efficiency by only about 0.5

- 1 percentage points so the efficiency results for the Shell case are still lower in this study than reported by the vendor. Exhibit 3

- 75 , which includes auxiliary power requirements. The ASU accounts for approximately 79 percent of the total auxil iary load distributed between the main air compressor, the oxygen compressor, the nitrogen compressor, and ASU auxiliaries. The cooling water system, including the CWP s and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the BFW pumps account for an additional 4 percent. All other individual auxiliary loads are 3 percent or less of the total.

### Cost and Performance Baseline for Fossil Energy Plants

240 

## Exhibit 3

- 75 Case 5 Plant Performance Summary POWER SUMMARY (Gross Power at Gen erator Terminals, kWe) Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 27 3 , 0 00 TOTAL POWER, kWe 73 7 , 0 00 AUXILIARY LOAD SUMMARY, kWe Coal Handling 440 Coal Milling 2,040 Slag Handling 520 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 45,190 Oxygen Compressor 8,890 Nitrogen Compressors 29,850 Boiler Feedwater Pumps 4,500 Condensate Pump 230 Syngas Recycle Compressor 680 Circulating Water Pump 3,400 Ground Water Pumps 370 Cooling Tower Fans 1,760 Scrubber Pumps 770 Acid Gas Removal 620 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 890 Miscellaneous Balance of Plant 2 

### 3,000 Transformer Losses 2,520 TOTAL AUXILIARIES, kWe 1 08 , 02 0 NET POWER, kWe 62 8 , 98 0 Net Plant Efficiency, % (HHV) 4 2

. 1 Net Plant Heat Rate , kJ/kWh (Btu/kWh) 8,545 (8,099) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,393 (1,320) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 198,059 (436,646) Thermal Input 1 

### , kWt 1,492,878 Raw Water Withdrawal, m 3 

### /min (gpm) 15.7 (4,142) Raw Water Consumption , m 3 

### /min (gpm) 12.7 (3,356)

1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

241 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 5 is presented in Environmental Performance

Exhibit 3

- 76

. Exhibit 3

- 76 Case 5 Air Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 80% capacity factor kg/MWh (lb/MWh)
SO 2 

## 0.002 (0.004) 68 (75) 0.013 (.03) NOx 0.025 (0.059) 957 (1,055) 0.185 (.409) Particulates 0.003 (0.0071) 115 (127) 0.022 (.049) Hg 2.46E

- 7 (5.71E

- 7) 0.009 (0.010) 1.79E

- 6 (3.95E

- 6) CO 2 

## 84.7 (196.9) 3,188,643 (3,514,877) 617 (1,361) CO 2 1 

## 723 (1,595)

1 

### CO 2 

### emissions based on net power instead of gross power 

## The low level of SO 2 

## emissions is achieved by capture of the sulfur in the gas by the Sulfinol

- M AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel gas down to a level of less than 6 ppmv. This results in a concentration in the HRSG FG of less than 2 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the AGR to capture most of the remaining sulfur. The SO 2 

## emissions in Exhibit 3

- 76 include both the stack emissions and the coal dryer emissions. NO x emissions are limited by the use of nitrogen dilution, humidification and steam diluti on to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and destroyed in the Claus plant burner. This helps lower NO x levels as well. Particulate discharge to the atmosphe re is limited to extremely low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of t he mercury is captured from the syngas by an activated carbon bed. CO 2 

## emissions represent the uncontrolled discharge from the process. The carbon balance for the plant is shown in Exhibit 3

- 77

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as u nburned carbon in the slag, as dissolved CO 2 

## in the wastewater blowdown stream, and as CO 2 

## in the stack gas, ASU vent gas and coal dryer vent gas. Carbon in the wastewater blowdown stream is calculated by difference to close the material balance.

### Cost and Performance Baseline for Fossil Energy Plants

242 

## Exhibit 3

- 77 Case 5 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 126,252 (278,339) Slag 631 (1,392) Air (CO 2 

## ) 508 (1,120) Stack Gas 124,177 (273,764) ASU Vent 89 (197) CO 2 

## Product 0 (0) Dryer Stack Gas 1,863 (4,106)
Total 126,760 (279,459) Total 126,760 (279,459)

Exhibit 3

- 78 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the coal drying gas, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible

.

Exhibit 3

- 78 Case 5 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 4,964 (10,944) Elemental Sulfur 4,959 (10,933) Stack Gas 5 (11) CO 2 

## Product 0 (0)

Total 4,964 (10,944) Total 4,964 (10,944)

Exhibit 3

- 79 shows the overall water balance for the plant. Explanation on the water balance has been given for Case 1 [GEE] and Case 3 [CoP] but is also presented here for completeness. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and is re

- used as internal recycle. The difference between demand and recycle is raw water wi thdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be r epresented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water c onsumption represents the net impact of the plant process on the water source balance.

### Cost and Performance Baseline for Fossil Energy Plants

243 

## Exhibit 3

- 79 Case 5 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdra wal, m 3 

### /min (gpm) Process Water Discharge,

m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)

Slag Handling 0.43 (114) 0.2 (45) 0.3 (69) 0.0 (0) 0.3 (69) Quench/Wash 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0)
Humidifier 1.4 (365) 0.0 (0) 1.4 (365) 0.0 (0) 1.4 (365)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) Condenser Makeup Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 1.1 (282) 0.3 (84) 0.5 (135) 0.2 (62) 0.0 (0) 1.1 (282) 0.3 (84) 0.5 (135) 0.2 (62) 0.0 (0) 1.1 (282)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 13.2 (3,494) 0.25 (67) 0.23 (62) 0.02 (4) 0.0 (0) 13.0 (3,427)

- 0.23 (

- 62)

- 0.02 (

- 4) 3.0 (786) 10.0 (2,641)

Total 16.1 (4,254) 0.4 (112) 15.7 (4,142) 3.0 (786) 12.7 (3,356)



## Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams Exhibit 3

- 80 through Exhibit 3

- 82 :

**•** Coal gasification and ASU

**•** Syngas cleanup , sulfur recovery, and tail gas recycle

**•** Combined cycle power generation , steam , and FW An overall plant energy balance is provided in tabular form in Exhibit 3

- 54 . The power out is the comb ined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 75 ) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent.

### Cost and Performance Baseline for Fossil Energy Plants

244 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

245 

## Exhibit 3

- 80 Case 5 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

N OTES :

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 5
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 5 S HELL G ASIFIER ASU , G ASIFICATION , AND G AS C OOLING

DWG

. NO

. BB

- HMB

- CS

- 5

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Intercooled Air Compressor

Elevated Pressure

ASU Intercooled Nitrogen Compressor

Intercooled Oxygen Compressor

Milled Coal Sour Gas

Sour Water ASU VENT

Water Steam

Slag Removal Slag G ROSS P LANT P OWER : 737 MW E A UXILIARY L OAD : 108 MW E N ET P LANT P OWER : 629 MW E N ET P LANT E FFICIENCY , HHV : 42

. 1 % N ET P LANT H EAT R ATE : 8 , 099 BTU / KW E Dry Coal Coal Feeding Steam Air from GT Compressor

Candle Filter Cyclone Blowdown to Flash Tank BFW from HRSG Saturated Steam to HRSG N 2 to GT Combustor

Boost Compressor

Recycle Compressor

Raw Syngas to Scrubber Steam Drum 220

. 0 T 224

. 9 P 50

. 9 H

393

. 5 T 625

. 0 P 146

. 7 H To Claus Plant

9 10 1

3 4

7

6

11 13 2 1 , 168 , 307 W 59

. 0 T 14

. 7 P 48 , 319 W 69

. 5 T 16

. 4 P

937 , 042 W 90

. 0 T 56

. 4 P 14

. 2 H 130 , 495 W 50

. 0 T 182

. 0 P

2

. 9 H

6 , 236 W

90

. 0 T 125

. 0 P 11

. 5 H 325 , 738 W 90

. 0 T 125

. 0 P 11

. 5 H

325 , 738 W

241

. 2 T 940

. 0 P 40

. 8 H 54 , 557 W

376

. 3 T 785

. 0 P

436 , 646 W 59

. 0 T 14

. 7 P 408 , 345 W 60

. 0 T 840

. 0 P 1 , 526

. 1 H

43 , 732 W 2 , 600

. 0 T

615

. 0 P 1 , 124 , 342 W

1 , 974

. 4 T

615

. 0 P 750

. 2 H

787 , 039 W 375

. 0 T 585

. 0 P 140

. 1 H 280 , 565 W

809

. 8 T 234

. 9 P 199

. 4 H

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB / HR H E NTHALPY , B TU / L B MW E P OWER , M EGAWATTS E LECTRICAL 1 , 012 , 980 W 389

. 0 T 384

. 0 P 88

. 2 H

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA 5

42 , 132 W 650

. 0 T 740

. 0 P 1 , 317

. 3 H

Coal Drying Incinerator

Syngas Slip Stream Incinerator Air Flue Gas / Combustion Products

Incinerator Exhaust

11 , 218 W

112

. 2 T 530

. 0 P 26

. 1 H 53 , 179 W

59

. 0 T 14

. 7 P 92 , 698 W

290

. 0 T 14

. 4 P 12

8

Raw Gas Cooler 199

. 0 T 384

. 0 P 39

. 8 H

1 , 124 , 342 W 600

. 0 T 595

. 0 P 221

. 1 H 337 , 303 W 375

. 0 T 585

. 0 P 140

. 1 H

Syngas Cooler Duct Cooler

Steam Generation Shell Gasifier

### Cost and Performance Baseline for Fossil Energy Plants

246 

## Exhibit 3

- 81 Case 5 Syngas Cleanup Heat and Mass Balance Schematic

N OTES :

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 5
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 5 S HELL G ASIFIER G AS C LEANUP S YSTEM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Mercury Removal

Knock Out Drum Raw Syngas

Sour Drum

To Water Treatment Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur COS Hydrolysis

Sour Water

Reboiler Acid Gas

Tailgas Carbon Dioxide

Sour Gas

Sulfur Hydrogen

DWG

. NO

. BB

- HMB

- CS

- 5

- PG

- 2 P AGES 2 OF 3 Sour Stripper Clean Gas Acid Gas

Syngas Scrubber

G ROSS P LANT P OWER : 737 MW E A UXILIARY L OAD : 108 MW E N ET P LANT P OWER : 629 MW E N ET P LANT E FFICIENCY , HHV : 42

. 1 % N ET P LANT H EAT R ATE : 8 , 099 BTU / KW E Water

13 

### AGR

- Sulfinol

15 16 20

21

22

787 , 039 W

375

. 0 T 585

. 0 P 140

. 1 H 23 , 692 W 100

. 0 T 799

. 5 P

4

. 8 H 782 , 178 W

200

. 9 T 580

. 0 P 74

. 7 H 351

. 2 T 565

. 0 P 127

. 8 H

790 , 887 W 93

. 9 T 535

. 0 P 19

. 0 H

Syngas Coolers HP BFW 746 , 680 W 112

. 2 T 530

. 0 P 26

. 1 H

10 , 933 W 353

. 2 T 59

. 3 P

From ASU 11 , 669 W

90

. 0 T 125

. 0 P 11

. 5 H

1 , 962 W 141

. 5 T 65

. 0 P 75

. 9 H 30 , 253 W 450

. 0 T 58

. 9 P 32 , 989 W

112

. 2 T 530

. 0 P

Knock Out Tailgas to AGR HP BFW 350

. 0 T 575

. 0 P 128

. 0 H

767 , 195 W 94

. 4 T 540

. 0 P 19

. 5 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB / HR H E NTHALPY , B TU / L B MW E P OWER , M EGAWATTS E LECTRICAL

6 , 561 W 118

. 9 T 56

. 8 P 45

. 2 H Treated Syngas

14 Slip Stream to Coal Dryer 17 Humidification 18 Humidified Fuel Gas 19

8

Tailgas Recycle Compressor Hydrogenation And Tail Gas

Cooling

24 , 042 W

120

. 0 T 56

. 8 P

### Cost and Performance Baseline for Fossil Energy Plants

247 

## Exhibit 3

- 82 Case 5 Combined Cycle Power Generation Heat and Mass Balance Schematic

N OTES :

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 5
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS B ASELINE S TUDY C ASE 5 S HELL G ASIFIER P OWER B LOCK S YSTEM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB / HR H E NTHALPY , B TU / L B MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen

Synthesis Gas HRSG

HP Turbine IP Turbine Nitrogen Dilution

Intake

Ambient Air Steam Seal Regulator IP Extraction Steam to 250 PSIA Header Blowdown

Flash

To WWT

Make

- up

Gland Steam Condenser Condensate to Gasification Island HP BFW to Raw Gas Coolers

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Humidified Fuel Gas

Air to ASU Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump Water Steam

DWG

. NO

. BB

- HMB

- CS

- 5

- PG

- 3 P AGES 3 OF 3 Advanced F

- Class

Gas Turbine

G ROSS P LANT P OWER : 737 MW E A UXILIARY L OAD : 108 MW E N ET P LANT P OWER : 629 MW E N ET P LANT E FFICIENCY , HHV : 42

. 1 % N ET P LANT H EAT R ATE : 8 , 099 BTU / KW E Flue Gas / Combustion Products

To Gasifier MP Flash Bottoms LP Flash Tops

LP Process Header From Gasifier Island Preheating

To Claus LP BFW

IP Pump

23 24 4

19 25 26

27

7 , 014 , 133 W 59

. 0 T 14

. 7 P 280 , 565 W 809

. 8 T 234

. 9 P

920 , 797 W

380

. 0 T 460

. 0 P 328

. 0 H 1 , 012 , 980 W 385

. 0 T 389

. 0 P 8 , 735 , 053 W 1 , 088

. 0 T

15

. 2 P 340

. 1 H

1 , 569 , 662 W 1 , 038

. 0 T 1 , 814

. 7 P 1 , 503

. 1 H

103

. 2 T 120

. 0 P 71

. 5 H 34 , 923 W

585

. 0 T 2 , 000

. 7 P

592

. 9 H 12 , 478 W 298

. 0 T 65

. 0 P 1 , 178

. 6 H

1 , 395 , 354 W 537

. 3 T 65

. 0 P 1 , 300

. 5 H 8 , 735 , 053 W 269

. 6 T 15

. 2 P 120

. 4 H

1 , 548 , 142 W 235

. 0 T 105

. 0 P 203

. 3 H

140 , 851 W 59

. 0 T 14

. 7 P 27

. 1 H 1 , 604 , 593 W 278

. 8 T 2 , 250

. 7 P

251

. 9 H

1 , 548 , 142 W 101

. 1 T

1

. 0 P 69

. 1 H 1 , 400 W 657

. 5 T 65

. 0 P 1 , 359

. 7 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H 26 , 045 W

893

. 6 T 280

. 0 P 1 , 470

. 5 H

HOT WELL CONDENSER Steam Dilution 67 , 709 W 475

. 0 T 460

. 0 P 80 , 190 W 298

. 0 T 65

. 0 P 1 , 178

. 6 H

40 , 813 W 537

. 3 T 65

. 0 P 1 , 300

. 5 H

### Cost and Performance Baseline for Fossil Energy Plants

248 

## T his page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

249 

## Exhibit 3

- 83 Case 5 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,374 (5,094) 4.5 (4.3) 5,379 (5,098) ASU Air 16.0 (15.2) 16 (15) GT Air 96.2 (91.2) 96 (91) Water 59.0 (55.9) 59 (56) Auxiliary Power 389 (369) 389 (369) TOTAL 5,374 (5,094) 175.6 (166.5) 389 (369) 5,939 (5,629) Heat Out GJ/hr (MMBtu/hr) ASU Vent 0.8 (0.8) 1 (1) Slag 21 (20) 33.5 (31.7) 54 (51) Sulfur 46 (44) 0.6 (0.5) 47 (44) CO 2 

## Cooling Tower Blowdown 22.1 (20.9) 22 (21) HRSG Flue Gas 1,110 (1,052) 1,110 (1,052) Condenser 1,397 (1,324) 1,397 (1,324) Non

- Condenser Cooling Tower Loads* 215 (204) 215 (204) Process Losses** 439 (417) 439 (417) Power 2,653 (2,515) 2,653 (2,515) TOTAL 67 (63) 3,219 (3,051) 2,653 (2,515) 5,939 (5,629)

* Includes ASU compressor intercoolers, CO 2 

## compressor intercoolers, sour water stripper

condenser, syngas cooler (low level heat rejec tion) and extraction air cooler. ** Calculated by difference to close the energy balance

.

### Cost and Performance Baseline for Fossil Energy Plants

250 

## 3.4.6 Major equipment items for the Shell gasifier with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 5

- Major Equipment List

3.4.7

. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 163 tonne/hr (180 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 327 tonne/hr (360 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 163 tonne (180 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 327 tonne/hr (360 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 327 tonne/hr (360 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 726 tonne (800 ton) 3 0

### Cost and Performance Baseline for Fossil Energy Plants

251 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 73 tonne/hr (80 tph) 3 0
2 Conveyor No. 6 Belt w/tripper 218 tonne/hr (240 tph) 1 0
3 Roller Mill Feed Hopper Dual Outlet 435 tonne (480 ton) 1 0
4 Weigh Feeder Belt 109 tonne/hr (120 tph) 2 0
5 Coal Dryer and Pulverizer Rotary 109 tonne/hr (120 tph) 2 0
6 Coal Dryer Feed Hopper Vertical Hopper 218 tonne (240 ton) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

252 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SY STEMS AND EQUIPMENT Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,165,907 liters (308,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,473 lpm @ 91 m H2O (1,710 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 436,356 kg/hr (962,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 7,419 lpm @ 27 m H2O (1,960 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 6,927 lpm @ 1,859 m H2O (1,830 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 2,461 lpm @ 223 m H2O (650 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 133 GJ/hr (126 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 47,696 lpm @ 21 m H2O (12,600 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 4,391 lpm @ 18 m H2O (1,160 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,915 lpm @ 268 m H2O (770 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single suction 1,779 lpm @ 49 m H2O (470 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 851,718 liter (225,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 341 lpm (90 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

253 

## ACCOUNT 4 GASIFIER, ASU AND AC CESSORIES INCLUDING LOW TEMPERATURE HEAT REC OVERY AND FUEL GAS S ATURATION Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry-feed, entrained bed 2,631 tonne/day, 4.2 MPa (2,900 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 280,320 kg/hr (618,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 280,320 kg/hr (618,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 196,405 kg/hr (433,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 192,777 kg/hr (425,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 191,870 kg/hr, 35°C, 3.8 MPa (423,000 lb/hr, 94°F, 545 psia) 2 0

8 Saturation Water Economizers Shell and tube 131 GJ/hr (124 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 229,518 kg/hr, 161°C, 3.3 MPa (506,000 lb/hr, 321°F, 480 psia) 2 0

10 Saturator Water Pump Centrifugal 3,407 lpm @ 12 m H2O (900 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 186,426 kg/hr (411,000 lb/hr) 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 196,405 kg/hr (433,000 lb/hr) syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi-stage 3,993 m3/min @ 1.3 MPa (141,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 1,996 tonne/day (2,200 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage 991 m3/min (35,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 6.5 MPa (940 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi-stage 3,285 m3/min (116,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single-stage 453 m3/min (16,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

18 Transport Nitrogen Boost Compressor Centrifugal, single-stage 198 m3/min (7,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 5.4 MPa (790 psia) 2 0

19 Extraction Air Heat Exchanger Gas-to-gas, vendor design 69,853 kg/hr, 432°C, 1.6 MPa (154,000 lb/hr, 810°F, 235 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

2 54 

## ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE A ND AUXILIARIES

ACCOUNT 7 HRSG, DUCTING AND ST ACK

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 191,416 kg/hr (422,000 lb/hr) 35°C (94°F) 3.7 MPa (540 psia) 2 0

2 Sulfur Plant Claus type 131 tonne/day (144 tpd) 1 0

3 COS Hydrolysis Reactor Fixed bed, catalytic 195,045 kg/hr (430,000 lb/hr) 177°C (350°F) 4.0 MPa (580 psia) 2 0

4 Acid Gas Removal Plant Sulfinol 197,313 kg/hr (435,000 lb/hr) 34°C (94°F) 3.7 MPa (535 psia) 2 0

5 Hydrogenation Reactor Fixed bed, catalytic 13,723 kg/hr (30,253 lb/hr) 232°C (450°F) 0.4 MPa (58.9 psia) 1 0

6 Tail Gas Recycle Compressor Centrifugal 10,747 kg/hr (23,692 lb/hr) each 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.4 m (28 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 393,555 kg/hr, 12.4 MPa / 559 °C ( 867 , 640 lb / hr , 1 , 800 psig / 1 , 038 °F ) Reheat steam - 362,720 kg/hr, 3

. 1 MPa / 559 °C ( 799 , 662 lb / hr , 452 psig / 1 , 038 °F ) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

255 

## ACCOUNT 8 STEAM TURBINE GENERATOR AN D AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 289 MW 12

. 4 MPa / 559 °C / 559 °C ( 1 , 800 psig / 1038 °F / 1038 °F ) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,540 GJ/hr (1,460 MMBtu/hr), Inlet water temperature 16 °C ( 60 °F ) , Water temperature rise 11 °C ( 20 °F ) 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 340,687 lpm @ 30 m (90,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11 °C ( 51

. 5 °F ) wet bulb / 16 °C ( 60 °F ) CWT / 27 °C ( 80 °F ) HWT / 1,899 GJ/hr (1,800 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

256 

## ACCOUNT 10 SLAG RECOVERY AND HA NDLING Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 208,198 liters (55,000 gal) 2 0
2 Slag Crusher Roll 11 tonne/hr (12 tph) 2 0
3 Slag Depressurizer Lock Hopper 11 tonne/hr (12 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 124,919 liters (33,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 56,781 liters (15,000 gal) 2
6 Slag Conveyor Drag chain 11 tonne/hr (12 tph) 2 0
7 Slag Separation Screen Vibrating 11 tonne/hr (12 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 11 tonne/hr (12 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 177,914 liters (47,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 56,781 liters (15,000 gal) 2 0

12 Grey Water Pumps Centrifugal 189 lpm @ 433 m H2O (50 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 816 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 91 tonne/hr (100 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

257 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 320 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 47 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 27 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

258 

## 3.4.7 Case 5

- Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Costs Results Exhibit 3

- 84 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 85 shows a more detailed breakdown of the capital costs along with owner’s costs, TOC and TASC

. Exhibit 3

- 86 shows the initial and annual O&M costs. The estimated TO C of the Shell gasifier with no CO 2 

## capture is $ 2,716 /kW. Pr ocess contingency represents 2.3 percent of the TO C and project contingency represents 11.1 perc ent. The COE is 81

. 3 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

259 

## Exhibit 3

- 84 Case 5 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 5 - Shell 600MW IGCC w/o CO2 Plant Size: 629.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $13,346 $2,480 $10,349 $0 $0 $26,175 $2,376 $0 $5,710 $34,261 $54

2 COAL & SORBENT PREP & FEED $105,424 $8,399 $17,537 $0 $0 $131,359 $11,391 $0 $28,550 $171,300 $272

3 FEEDWATER & MISC. BOP SYSTEMS $9,632 $8,082 $9,224 $0 $0 $26,938 $2,534 $0 $6,691 $36,163 $57

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $171,446 $0 $73,699 $0 $0 $245,145 $21,883 $34,079 $46,149 $347,255 $552 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $148,365 $0 w/equip. $0 $0 $148,365 $14,381 $0 $16,275 $179,021 $285 4.4-4.9 Other Gasification Equipment $15,541 $9,100 $10,950 $0 $0 $35,592 $3,394 $0 $8,498 $47,483 $75 SUBTOTAL 4 $335,353 $9,100 $84,649 $0 $0 $429,102 $39,657 $34,079 $70,922 $573,760 $912

5A GAS CLEANUP & PIPING $50,101 $3,724 $47,806 $0 $0 $101,630 $9,827 $86 $22,447 $133,990 $213

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $184 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6 $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $188

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,374 $0 $5,030 $0 $0 $40,404 $3,842 $0 $4,425 $48,670 $77 7.2-7.9 Ductwork and Stack $3,337 $2,379 $3,116 $0 $0 $8,833 $819 $0 $1,571 $11,222 $18 SUBTOTAL 7 $38,712 $2,379 $8,146 $0 $0 $49,237 $4,661 $0 $5,995 $59,893 $95

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,830 $0 $4,946 $0 $0 $33,776 $3,241 $0 $3,702 $40,718 $65 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $10,446 $993 $7,524 $0 $0 $18,963 $1,722 $0 $4,181 $24,865 $40 SUBTOTAL 8 $39,276 $993 $12,470 $0 $0 $52,739 $4,963 $0 $7,883 $65,584 $104

9 COOLING WATER SYSTEM $8,350 $8,140 $6,922 $0 $0 $23,411 $2,174 $0 $5,234 $30,819 $49

10 ASH/SPENT SORBENT HANDLING SYS $17,858 $1,384 $8,862 $0 $0 $28,104 $2,696 $0 $3,366 $34,166 $54

11 ACCESSORY ELECTRIC PLANT $26,986 $10,003 $20,101 $0 $0 $57,090 $4,905 $0 $11,625 $73,620 $117

12 INSTRUMENTATION & CONTROL $10,318 $1,898 $6,648 $0 $0 $18,864 $1,710 $943 $3,585 $25,102 $40

13 IMPROVEMENTS TO SITE $3,326 $1,960 $8,206 $0 $0 $13,492 $1,332 $0 $4,447 $19,272 $31

14 BUILDINGS & STRUCTURES $0 $6,644 $7,614 $0 $0 $14,258 $1,298 $0 $2,544 $18,100 $29

TOTAL COST $744,432 $65,991 $255,695 $0 $0 $1,066,118 $98,407 $39,709 $190,092 $1,394,325 $2,217 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

260 

## Exhibit 3

- 85 Case 5 Total Plant Cost Details

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 5 - Shell 600MW IGCC w/o CO2 Plant Size: 629.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,505 $0 $1,713 $0 $0 $5,217 $467 $0 $1,137 $6,822 $11 1.2 Coal Stackout & Reclaim $4,529 $0 $1,098 $0 $0 $5,627 $493 $0 $1,224 $7,344 $12 1.3 Coal Conveyors & Yd Crush $4,211 $0 $1,086 $0 $0 $5,297 $465 $0 $1,152 $6,914 $11 1.4 Other Coal Handling $1,102 $0 $251 $0 $0 $1,353 $118 $0 $294 $1,766 $3 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,480 $6,201 $0 $0 $8,681 $832 $0 $1,903 $11,416 $18 SUBTOTAL 1. $13,346 $2,480 $10,349 $0 $0 $26,175 $2,376 $0 $5,710 $34,261 $54 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $40,051 $2,406 $5,836 $0 $0 $48,294 $4,167 $0 $10,492 $62,953 $100 2.2 Prepared Coal Storage & Feed $1,897 $454 $297 $0 $0 $2,648 $226 $0 $575 $3,450 $5 2.3 Dry Coal Injection System $62,432 $725 $5,798 $0 $0 $68,955 $5,939 $0 $14,979 $89,872 $143 2.4 Misc.Coal Prep & Feed $1,043 $759 $2,276 $0 $0 $4,078 $375 $0 $891 $5,344 $8 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $4,055 $3,329 $0 $0 $7,384 $684 $0 $1,614 $9,681 $15 SUBTOTAL 2. $105,424 $8,399 $17,537 $0 $0 $131,359 $11,391 $0 $28,550 $171,300 $272 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $3,130 $5,375 $2,837 $0 $0 $11,343 $1,051 $0 $2,479 $14,872 $24 3.2 Water Makeup & Pretreating $564 $59 $315 $0 $0 $938 $89 $0 $308 $1,335 $2 3.3 Other Feedwater Subsystems $1,713 $579 $521 $0 $0 $2,812 $253 $0 $613 $3,678 $6 3.4 Service Water Systems $323 $664 $2,306 $0 $0 $3,293 $321 $0 $1,084 $4,699 $7 3.5 Other Boiler Plant Systems $1,732 $671 $1,663 $0 $0 $4,065 $386 $0 $890 $5,341 $8 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,454 $140 $0 $319 $1,913 $3 3.7 Waste Treatment Equipment $788 $0 $481 $0 $0 $1,269 $124 $0 $418 $1,810 $3 3.8 Misc. Power Plant Equipment $1,071 $143 $550 $0 $0 $1,764 $170 $0 $580 $2,514 $4 SUBTOTAL 3. $9,632 $8,082 $9,224 $0 $0 $26,938 $2,534 $0 $6,691 $36,163 $57 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $171,446 $0 $73,699 $0 $0 $245,145 $21,883 $34,079 $46,149 $347,255 $552 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $148,365 $0 w/equip. $0 $0 $148,365 $14,381 $0 $16,275 $179,021 $285 4.4 LT Heat Recovery & FG Saturation $15,541 $0 $5,908 $0 $0 $21,449 $2,093 $0 $4,709 $28,251 $45 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $921 $375 $0 $0 $1,296 $124 $0 $284 $1,704 $3 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,179 $4,667 $0 $0 $12,847 $1,176 $0 $3,506 $17,528 $28 SUBTOTAL 4. $335,353 $9,100 $84,649 $0 $0 $429,102 $39,657 $34,079 $70,922 $573,760 $912 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

261 

## Exhibit 3

- 85 Case 5 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Sulfinol System $35,020 $0 $29,715 $0 $0 $64,735 $6,261 $0 $14,199 $85,194 $135 5A.2 Elemental Sulfur Plant $9,609 $1,915 $12,397 $0 $0 $23,921 $2,324 $0 $5,249 $31,494 $50 5A.3 Mercury Removal $976 $0 $743 $0 $0 $1,720 $166 $86 $394 $2,366 $4 5A.4 COS Hydrolysis $2,882 $0 $3,764 $0 $0 $6,646 $646 $0 $1,459 $8,751 $14 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,613 $271 $153 $0 $0 $2,037 $193 $0 $446 $2,677 $4 5A.7 Fuel Gas Piping $0 $764 $535 $0 $0 $1,298 $120 $0 $284 $1,703 $3 5A.9 HGCU Foundations $0 $773 $499 $0 $0 $1,272 $117 $0 $417 $1,805 $3 SUBTOTAL 5A. $50,101 $3,724 $47,806 $0 $0 $101,630 $9,827 $86 $22,447 $133,990 $213 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $85,752 $0 $6,269 $0 $0 $92,021 $8,724 $4,601 $10,535 $115,881 $184 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $4 SUBTOTAL 6. $85,752 $806 $7,162 $0 $0 $93,720 $8,883 $4,601 $11,092 $118,296 $188 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $35,374 $0 $5,030 $0 $0 $40,404 $3,842 $0 $4,425 $48,670 $77 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,711 $1,220 $0 $0 $2,931 $257 $0 $638 $3,826 $6 7.4 Stack $3,337 $0 $1,254 $0 $0 $4,591 $440 $0 $503 $5,534 $9 7.9 HRSG,Duct & Stack Foundations $0 $669 $642 $0 $0 $1,311 $122 $0 $430 $1,863 $3 SUBTOTAL 7. $38,712 $2,379 $8,146 $0 $0 $49,237 $4,661 $0 $5,995 $59,893 $95 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $28,830 $0 $4,946 $0 $0 $33,776 $3,241 $0 $3,702 $40,718 $65 8.2 Turbine Plant Auxiliaries $200 $0 $459 $0 $0 $659 $64 $0 $72 $796 $1 8.3 Condenser & Auxiliaries $4,740 $0 $1,514 $0 $0 $6,254 $598 $0 $685 $7,537 $12 8.4 Steam Piping $5,506 $0 $3,873 $0 $0 $9,379 $806 $0 $2,546 $12,731 $20 8.9 TG Foundations $0 $993 $1,678 $0 $0 $2,671 $253 $0 $877 $3,801 $6 SUBTOTAL 8. $39,276 $993 $12,470 $0 $0 $52,739 $4,963 $0 $7,883 $65,584 $104 9 COOLING WATER SYSTEM 9.1 Cooling Towers $5,766 $0 $1,049 $0 $0 $6,815 $649 $0 $1,120 $8,584 $14 9.2 Circulating Water Pumps $1,500 $0 $99 $0 $0 $1,599 $135 $0 $260 $1,993 $3 9.3 Circ.Water System Auxiliaries $129 $0 $18 $0 $0 $148 $14 $0 $24 $186 $0 9.4 Circ.Water Piping $0 $5,400 $1,400 $0 $0 $6,800 $615 $0 $1,483 $8,897 $14 9.5 Make-up Water System $317 $0 $453 $0 $0 $769 $74 $0 $169 $1,012 $2 9.6 Component Cooling Water Sys $637 $762 $542 $0 $0 $1,942 $182 $0 $425 $2,549 $4 9.9 Circ.Water System Foundations $0 $1,977 $3,361 $0 $0 $5,339 $506 $0 $1,753 $7,598 $12 SUBTOTAL 9. $8,350 $8,140 $6,922 $0 $0 $23,411 $2,174 $0 $5,234 $30,819 $49

### Cost and Performance Baseline for Fossil Energy Plants

262 

## Exhibit 3

- 85 Case 5 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $15,534 $0 $7,661 $0 $0 $23,194 $2,229 $0 $2,542 $27,965 $44 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $527 $0 $573 $0 $0 $1,100 $107 $0 $181 $1,387 $2 10.7 Ash Transport & Feed Equipment $706 $0 $170 $0 $0 $877 $82 $0 $144 $1,102 $2 10.8 Misc. Ash Handling Equipment $1,091 $1,337 $399 $0 $0 $2,827 $269 $0 $464 $3,561 $6 10.9 Ash/Spent Sorbent Foundation $0 $47 $59 $0 $0 $105 $10 $0 $34 $149 $0 SUBTOTAL 10. $17,858 $1,384 $8,862 $0 $0 $28,104 $2,696 $0 $3,366 $34,166 $54 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $950 $0 $939 $0 $0 $1,889 $180 $0 $207 $2,276 $4 11.2 Station Service Equipment $3,667 $0 $330 $0 $0 $3,998 $369 $0 $437 $4,803 $8 11.3 Switchgear & Motor Control $6,780 $0 $1,233 $0 $0 $8,013 $743 $0 $1,313 $10,069 $16 11.4 Conduit & Cable Tray $0 $3,149 $10,390 $0 $0 $13,539 $1,309 $0 $3,712 $18,561 $30 11.5 Wire & Cable $0 $6,017 $3,954 $0 $0 $9,971 $724 $0 $2,674 $13,369 $21 11.6 Protective Equipment $0 $679 $2,471 $0 $0 $3,150 $308 $0 $519 $3,976 $6 11.7 Standby Equipment $234 $0 $228 $0 $0 $462 $44 $0 $76 $583 $1 11.8 Main Power Transformers $15,356 $0 $144 $0 $0 $15,500 $1,173 $0 $2,501 $19,174 $30 11.9 Electrical Foundations $0 $157 $411 $0 $0 $568 $54 $0 $187 $810 $1 SUBTOTAL 11. $26,986 $10,003 $20,101 $0 $0 $57,090 $4,905 $0 $11,625 $73,620 $117 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,019 $0 $680 $0 $0 $1,699 $161 $85 $292 $2,236 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $234 $0 $150 $0 $0 $384 $36 $19 $88 $528 $1 12.7 Computer & Accessories $5,433 $0 $174 $0 $0 $5,607 $515 $280 $640 $7,043 $11 12.8 Instrument Wiring & Tubing $0 $1,898 $3,880 $0 $0 $5,778 $490 $289 $1,639 $8,197 $13 12.9 Other I & C Equipment $3,632 $0 $1,764 $0 $0 $5,396 $508 $270 $926 $7,099 $11 SUBTOTAL 12. $10,318 $1,898 $6,648 $0 $0 $18,864 $1,710 $943 $3,585 $25,102 $40

### Cost and Performance Baseline for Fossil Energy Plants

263 

## Exhibit 3

- 85 Case 5 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $104 $2,230 $0 $0 $2,335 $232 $0 $770 $3,336 $5 13.2 Site Improvements $0 $1,856 $2,466 $0 $0 $4,322 $426 $0 $1,425 $6,173 $10 13.3 Site Facilities $3,326 $0 $3,509 $0 $0 $6,835 $674 $0 $2,253 $9,762 $16 SUBTOTAL 13. $3,326 $1,960 $8,206 $0 $0 $13,492 $1,332 $0 $4,447 $19,272 $31 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,428 $3,459 $0 $0 $5,887 $542 $0 $964 $7,394 $12 14.3 Administration Building $0 $841 $610 $0 $0 $1,452 $129 $0 $237 $1,818 $3 14.4 Circulation Water Pumphouse $0 $166 $88 $0 $0 $254 $22 $0 $41 $317 $1 14.5 Water Treatment Buildings $0 $471 $460 $0 $0 $931 $84 $0 $152 $1,168 $2 14.6 Machine Shop $0 $431 $295 $0 $0 $725 $64 $0 $118 $908 $1 14.7 Warehouse $0 $695 $449 $0 $0 $1,144 $101 $0 $187 $1,432 $2 14.8 Other Buildings & Structures $0 $416 $324 $0 $0 $741 $66 $0 $161 $968 $2 14.9 Waste Treating Building & Str. $0 $931 $1,779 $0 $0 $2,710 $253 $0 $592 $3,555 $6 SUBTOTAL 14. $0 $6,644 $7,614 $0 $0 $14,258 $1,298 $0 $2,544 $18,100 $29

TOTAL COST $744,432 $65,991 $255,695 $0 $0 $1,066,118 $98,407 $39,709 $190,092 $1,394,325 $2,217
Owner's Costs Preproduction Costs 6 Months All Labor $12,811 $20 1 Month Maintenance Materials $2,891 $5 1 Month Non-fuel Consumables $407 $1 1 Month Waste Disposal $260 $0 25% of 1 Months Fuel Cost at 100% CF $1,521 $2 2% of TPC $27,887 $44 Total $45,778 $73 Inventory Capital 60 day supply of fuel and consumables at 100% CF $12,790 $20 0.5% of TPC (spare parts) $6,972 $11 Total $19,762 $31
Initial Cost for Catalyst and Chemicals $963 $2 Land $900 $1 Other Owner's Costs $209,149 $333

Financing Costs $37,647 $60 Total Overnight Costs (TOC) $1,708,524 $2,716 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,947,717 $3,097

### Cost and Performance Baseline for Fossil Energy Plants

264 

## Exhibit 3

- 86 Case 5 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 5 - Shell 600MW IGCC w/o CO2 Heat Rate-net (Btu/kWh): 8,099 MWe-net: 629 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 15.0 15.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,918,913 $9.410 Maintenance Labor Cost $14,578,930 $23.179 Administrative & Support Labor $5,124,461 $8.147 Property Taxes and Insurance $27,886,508 $44.336 TOTAL FIXED OPERATING COSTS $53,508,812 $85.072 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $27,756,840 $0.00630

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 2,982 1.08 $0 $941,938 $0.00021

Chemicals

MU & WT Chem. (lbs) 0 17,767 0.17 $0 $897,887 $0.00020 Carbon (Mercury Removal) (lb) 69,345 95 1.05 $72,824 $29,130 $0.00001 COS Catalyst (m3) 262 0.18 2,397.36 $627,613 $125,523 $0.00003 Water Gas Shift Catalyst (ft3) 0 0 498.83 $0 $0 $0.00000 Sulfinol Solution (gal) 26,146 629 10.05 $262,733 $1,846,503 $0.00042 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.82 131.27 $0 $69,945 $0.00002 Subtotal Chemicals $963,170 $2,968,988 $0.00067

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Spent Mercury Catalyst (lb.) 0 95 0.42 $0 $11,569 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 525 16.23 $0 $2,486,313 $0.00056 Subtotal-Waste Disposal $0 $2,497,882 $0.00057

By-products & Emissions

Sulfur (ton) 0 131 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $963,170 $34,165,649 $0.00775

Fuel (ton) 0 5,240 38.18 $0 $58,422,569 $0.01325

### Cost and Performance Baseline for Fossil Energy Plants

265 

## 3.4.8 This case is configured to produce electric power with CO 2 

## capture. The plant co nfiguration is the same as Case 5, namely two Shell gasifier trains, two advanced F class turbines, two HRSGs and one steam turbine. The gross power output is constrained by the capacity of the two CT s, and since the CO 2 

## capture and compression process in creases the auxiliary load on the plant, the net output is significantly reduced relative to Case 5 ( 49 7 MW versus 629 MW). Case 6

- Shell IGCC Power Plant with CO 2 

## Capture

The process description for Case 6 is similar to Case 5 with several notable exceptions to accommodate CO 2 

## capture. A BFD and strea m tables for Case 6 are shown in Exhibit 3

- 87 and Exhibit 3

- 88 , respectively. Instead of repeating the entire process description, only differences from Case 5 are reported here.

No differences from Case 5. Coal Preparation and Feed Systems

The gasification process is the same as Case 5 with the following exceptions: Gasification

**•** Total coal feed (as

- received) to the two gasifiers is 5, 065 tonnes/day (5, 583 TPD) (stream 9)

**•** The ASU provides 3,852 tonnes/day (4, 246 TPD) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3)

After the raw syngas is cooled to approximately 1,093°C (2,000°F) by the syngas quench recycle, syngas is further cooled to 899°C (1,650°F) by raising HP steam at 13.8 MPa (2,000 psia). A water quench follows to cool the raw syngas from 899°C (1,650°F) to 399°C (750°F) while providing a portion of the water required for WGS . The syngas is then cooled to 316°C (600°F) by raising steam , which is used in the SGS unit. After particulate filtra tion, the syngas is cooled to 232°C (450°F) by raising IP steam at 0.4 MPa (65 psia) before proceeding to the scrubber. Raw Gas Cooling /Particulate Removal

Syngas exits the scrubber at 191 °C ( 376 °F). Syngas Scrubber/Sour Water Stripper

The SGS process was described in Se ction Sour Gas Shift (SGS) 3.1.3 . In Case 6 the syngas after the scrubber is reheated to 197 °C ( 386 °F) and then steam (stream 14) is added to adjust the H 2 

## O:CO molar ratio to approximately 1.8 :1 prior to the first SGS reactor. The hot syngas exiting the first stage of SGS is used to preheat water used to humidify clean syngas prior to entering the CT . One more stage of SGS (for a total of two) results in 9 7

. 8 percent overall conversion of the CO to CO 2 

## . The warm syngas from the second stage of SGS is cooled to 248 °C ( 478 °F) by preheating the syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

### Cost and Performance Baseline for Fossil Energy Plants

266 

## Mercury removal is the same as in Case 5

. Mercury Removal and AGR

The AGR process in Case 6 is a two stag e Selexol process where H 2 

## S is removed in the first stage and CO 2 

## in the second stage of absorption. The process results in three product streams, the clean syngas (stream 18) , a CO 2 

## - rich stream and an acid gas feed to the Claus plant (stream 22) . The a cid gas contains 34 percent H 2 

## S and 51 percent CO 2 

## with the balance primarily H 2 

## . The CO 2 

## - rich stream is discussed further in the CO 2 

## compression section.

CO 2 

## from the AGR process is flashed at three pressure levels to se parate CO 2 

## and decrease H 2 

## losses to the CO 2 

## product pipeline. The HP CO 2 

## stream is flashed at 2.0 MPa (289.7 psia), compressed, and recycled back to the CO 2 

## absorber. The MP CO 2 

## stream is flashed at 1.0 MPa (149.7 psia). The LP CO 2 

## stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa (149.5 psia), and combined with the MP CO 2 

## stream. The combined stream is compressed from 1.0 MPa (149.5 psia) to a SC condition at 15.3 MPa (2215 psia) using a multiple

- stage, intercooled c ompressor. During compression, the CO 2 

## stream is dehydrated to a dewpoint of

- 40oC (

- 40°F) with triethylene glycol. The raw CO 2 

## stream from the Selexol process contains over 99 percent CO 2 

## . The CO 2 

## (stream 21) is transported to the plant fence line and is sequestration ready. CO 2 

## TS&M costs were estimated using the methodology described in Section 2.7. CO 2 

## Compression and Dehydration

The Claus plant is the same as Case 5 with the following exceptions: Claus Unit

**•** 5,277 kg/h r (11,634 lb/h r ) of sulfur (stream 23) are produced

**•** The waste h eat boiler generates 13,697 kg/h r (30,197 lb/h r ) of 3.0 MPa (430 psia) steam, which provides all of the Claus plant process needs and provides some additional steam to the medium pressure steam header.

Clean syngas from the AGR plant is combine d with a small amount of clean gas from the CO 2 

## compression process (stream 18) and partially humidified because the nitrogen available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 193°C (380°F) using HP BFW , diluted with nitrogen (stream 4), and then enters the CT burner. The exhaust gas (stream 27) exits the CT at 562°C (1,043°F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 28) and is discharge d through the plant stack. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a 12.4 MPa/534°C/534°C (1800 psig/993°F/993°F) steam cycle. There is no integration between the CT and the ASU in this case. Power Block

The same elevated pressure ASU is used as in Case 5 and produces 3,852 tonnes/day (4,246 TPD) of 95 mol% oxygen and 12, 290 tonnes/day ( 13,547 TPD) of nitrogen. There is no integration between the ASU and the CT

. Air Separation Unit ( ASU )

### Cost and Performance Baseline for Fossil Energy Plants

267 

## Balance of plant items were covered in Sections Balance of Plant 3.1.9 , 3.1.10 and 3.1.11

.

### Cost and Performance Baseline for Fossil Energy Plants

268 

## Exhibit 3

- 87 Case 6 Block Flow Diagram , Shell IGCC with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

269 

## Exhibit 3

- 88 Case 6 Stream Table , Shell IGCC with CO 2 

## Capt ure
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 V-L Mole Fraction

Ar 0.0092 0.0230 0.0318 0.0023 0.0318 0.0000 0.0023 0.0096 0.0000 0.0000 0.0000 0.0085 0.0061 0.0000 0.0047 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0005 0.0004 0.0000 0.0003 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0130 0.0000 0.0000 0.0000 0.5187 0.3712 0.0000 0.2873 CO 2 0.0003 0.0079 0.0000 0.0000 0.0000 0.0000 0.0000 0.0455 0.0000 0.0000 0.0000 0.0126 0.0090 0.0000 0.0070 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0004 0.0000 0.0003 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8727 0.0000 0.8090 0.0000 0.2691 0.1926 0.0000 0.1491 H 2 O 0.0099 0.1984 0.0000 0.0003 0.0000 1.0000 0.0004 0.0001 0.0000 0.0935 0.0000 0.1278 0.3758 1.0000 0.5172 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0008 0.0006 0.0000 0.0001 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0052 0.0000 0.0040 N 2 0.7732 0.5759 0.0178 0.9919 0.0178 0.0000 0.9919 0.0585 0.0000 0.0163 0.0000 0.0507 0.0363 0.0000 0.0281 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0024 0.0000 0.0019 O 2 0.2074 0.1948 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 24,277 1,004 102 17,310 4,886 1,130 940 308 0 5,809 0 26,493 29,249 11,003 37,783 V-L Flowrate (kg/hr) 700,548 27,328 3,289 485,713 157,225 20,363 26,368 1,900 0 37,081 0 531,672 569,894 198,213 723,426 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 211,040 160,281 21,137 0 0 0 0
Temperature (°C) 15 20 32 93 32 343 32 35 15 16 1,427 1,082 232 288 217 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.62 3.59 0.10 5.79 4.24 4.24 4.03 5.52 3.96 Enthalpy (kJ/kg) A 30.23 36.90 26.67 92.51 26.67 3,063.97 20.78 163.14

--- 3,549.69

--- 2,043.24 1,217.35 2,918.18 1,541.02 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0 20.1 62.8 8.5

--- 16.5

--- 7.5 19.1 25.6 19.5 V-L Molecular Weight 28.857 27.206 32.181 28.060 32.181 18.015 28.060 6.159

--- 6.383

--- 20.069 19.484 18.015 19.147
V-L Flowrate (lb mol /hr) 53,521 2,215 225 38,162 10,771 2,492 2,072 680 0 12,807 0 58,407 64,482 24,256 83,298 V-L Flowrate (lb/hr) 1,544,445 60,249 7,250 1,070,813 346,622 44,894 58,132 4,188 0 81,749 0 1,172,137 1,256,401 436,986 1,594,881 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 465,264 353,359 46,599 0 0 0 0
Temperature (°F) 59 68 90 199 90 650 90 94 59 60 2,600 1,980 450 550 422 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 815.0 520.0 14.7 840.0 615.0 615.0 585.0 800.0 575.0 Enthalpy (Btu/lb) A 13.0 15.9 11.5 39.8 11.5 1,317.3 8.9 70.1

--- 1,526.1

--- 878.4 523.4 1,254.6 662.5 Density (lb/ft 3 ) 0.076 0.097 0.687 1.521 0.687 1.257 3.918 0.531

--- 1.029

--- 0.468 1.190 1.597 1.218 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

270 

## Exhibit 3

- 88 Case 6 Stream Table (Continued)
16 17 18 19 20 21 22 23 24 25 26 27 28 29 V-L Mole Fraction

Ar 0.0062 0.0062 0.0096 0.0086 0.0086 0.0002 0.0017 0.0000 0.0065 0.0102 0.0092 0.0088 0.0088 0.0000 CH 4 0.0004 0.0004 0.0006 0.0005 0.0005 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0084 0.0084 0.0130 0.0116 0.0116 0.0002 0.0025 0.0000 0.1143 0.0060 0.0000 0.0000 0.0000 0.0000 CO 2 0.3776 0.3810 0.0455 0.0407 0.0407 0.9944 0.5141 0.0000 0.2866 0.6257 0.0003 0.0080 0.0080 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.5633 0.5593 0.8727 0.7819 0.7819 0.0050 0.1068 0.0000 0.0659 0.2694 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0016 0.0016 0.0001 0.1041 0.1041 0.0000 0.0300 0.0000 0.4715 0.0017 0.0099 0.1374 0.1374 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0057 0.0057 0.0000 0.0000 0.0000 0.0000 0.3398 0.0000 0.0014 0.0057 0.0000 0.0000 0.0000 0.0000 N 2 0.0368 0.0374 0.0585 0.0524 0.0524 0.0002 0.0047 0.0000 0.0516 0.0813 0.7732 0.7397 0.7397 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1060 0.1060 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 28,837 29,237 18,312 20,438 20,438 10,099 488 0 630 400 110,253 139,892 139,892 28,855 V-L Flowrate (kg/hr) 562,223 574,690 112,786 151,092 151,092 442,270 17,202 0 16,585 12,466 3,181,557 3,818,362 3,818,362 519,836 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 5,277 0 0 0 0 0 0
Temperature (°C) 35 35 35 137 193 51 48 178 232 38 15 562 132 534 Pressure (MPa, abs) 3.62 3.6 3.585 3.206 3.172 15.270 0.163 0.119 0.085 5.51 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 45.33 44.5 163.144 1,181.236 1,416.715 -161.704 85.006

--- 1,114.498 8.30 30.227 866.140 371.288 3,431.999 Density (kg/m 3 ) 28.1 28.1 8.5 6.9 6.0 639.8 2.2 5,279.4 0.5 74.4 1.2 0.4 0.8 36.8 V-L Molecular Weight 19.496 20 6.159 7.393 7.393 43.792 35.245

--- 26.336 31.160 28.857 27.295 27.295 18.015
V-L Flowrate (lb mol /hr) 63,576 64,458 40,371 45,059 45,059 22,265 1,076 0 1,388 882 243,066 308,408 308,408 63,615 V-L Flowrate (lb/hr) 1,239,491 1,266,974 248,650 333,100 333,100 975,038 37,925 0 36,563 27,484 7,014,133 8,418,047 8,418,047 1,146,042 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 11,634 0 0 0 0 0 0
Temperature (°F) 95 94 94 278 380 124 119 352 450 100 59 1,043 270 993 Pressure (psia) 525.0 520.0 520.0 465.0 460.0 2,214.7 23.7 17.3 12.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 19.5 19.1 70.1 507.8 609.1 -69.5 36.5

--- 479.1 3.6 13.0 372.4 159.6 1,475.5 Density (lb/ft 3 ) 1.753 2 0.531 0.431 0.374 39.942 0.135 329.584 0.033 4.646 0.076 0.026 0.053 2.295

### Cost and Performance Baseline for Fossil Energy Plants

271 

## 3.4.9 The Case 6 modeling assumptions were presented previously in Section Case 6 Performance Results 3.4.3

. The plant produces a net output of 497 MWe at a net plant efficiency of 31. 2 percent (HHV basis). Overall performance for the plant is summarized in Exhibit 3

- 89 , which includes auxiliary power requirements. The ASU accounts for approximately 58 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor and ASU auxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 28 percent of the auxiliary power load. The BFW and CWS ( CWP s and cooling tower fan) comprise approximately 4 percent of the load, leaving 10 percent of the auxiliary load for all oth er systems.

### Cost and Performance Baseline for Fossil Energy Plants

272 

## Exhibit 3

- 89 Case 6 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 464,000 Sweet Gas Expander Power 0 Steam Turbine Power 209,400 TOTAL POWER, kWe 67 3 , 4 00 AUXILIARY LOAD SUMMARY, kWe Coal Handling 460 Coal Milling 2,170 Slag Handling 550 Air Separation Unit Auxiliaries 1,000 Air Separation Unit Main Air Compressor 59,740 Oxygen Compressor 9,460 Nitrogen Compressors 32,910 CO 2 

### Compressor 30,210 Boiler Feedwater Pumps 3,500 Condensate Pump 280 Quench Water Pump 610 Syngas Recycle Compressor 790 Circulating Water Pump 4,370 Ground Water Pumps 510 Cooling Tower Fans 2,260 Scrubber Pumps 360 Acid Gas Removal 18,650 Gas Turbine Auxiliaries 1,000 Steam Turbine Auxiliaries 100 Claus Plant/TGTU Auxiliaries 250 Claus Plant TG Recycle Compressor 1,830 Miscellaneous Balance of Plant 2 

### 3,000 Transformer Losses 2,530 TOTAL AUXILIARIES, kWe 17 6 ,5 4 0 NET POWER, kWe 496,860 Net Plant Efficiency, % (HHV) 3 1

. 2 Net Plant Heat Rate , kJ/kWh (Btu/kWh) 11,526 (10,924) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,340 (1,270) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 211,040 (465,264) Thermal Input 1 

### , kWt 1,590,722 Raw Water Withdrawal, m 3 

### /min (gpm) 21. 3 (5,6 3 3) Raw Water Consumption , m 3 

### /min (gpm) 17.5 (4,6 16 )
1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

273 

## The environmental targets for emissions of Hg, NO x , SO 2 

## , CO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 6 is presented in Environmental Performance

Exhibit 3

- 90

. Exhibit 3

- 90 Case 6 Air Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 80% CF kg/MWh (lb/MWh)
SO 2 

## 0.001 (0.002) 37 (40) 0.008 (.02) NOx 0.021 (0.049) 847 (934) 0.180 (.396) Particulates 0.003 (0.0071) 123 (135) 0.026 (.057) Hg 2.46E

- 7 (5.71E

- 7) 0.010 (0.011) 2.09E

- 6 (4.61E

- 6) CO 2 

## 8.6 (20.0) 344,507 (379,754) 73 (161) CO 2 1 

## 99 (218)
1 

## CO 2 

## emissions based on net power instead of gross power
The low level of SO 2 

## emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. The CO 2 

## capture target results in the sulfur compounds being removed to a greater extent than required in the environmental targets of Section 2.4

. The clean syngas exit ing the AGR process has a sulfur concentration of approximately 4 ppmv. This results in a concentration in the HRSG FG of less than 1 ppmv. The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the AGR where most of the remaining sulfur is removed. NO x emissions are limited by the use of nitrogen dilution and humidification to 15 ppmvd (as NO 2 

## @ 15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process and subsequently destroyed in the Claus plant burner. This helps lower NO x levels as well. Particulate discharge to the atmosphere is limited to extremel y low values by the use of a cyclone and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particulate only. Ninety five percent of mercury is captured from t he syngas by an activated carbon bed. Ninety five percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. Because not all CO is converted to CO 2 

## in the shift reactors, the overall CO 2 

## removal is 90. 1 percent. The carbon balance for the plant is shown in Exhibit 3

- 91

. The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not used in the carbon capture equation below, but it is not neglected in the balance since the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned carbon in the slag, CO 2 

## in the stack gas, coal dryer vent gas, A SU vent gas and the captured CO 2 

## product. The carbon capture efficiency is defined as the amount of carbon in the CO 2 

## product stream relative to the amount of carbon in the coal less carbon contained in the slag , represented by the following fraction:

### Cost and Performance Baseline for Fossil Energy Plants

274 

## (Carbon in Product for Sequestration)/[(Carbon in the Coal)

- (Carbon in Slag)] or 265,992 /( 296,581

- 1,483 ) * 100 or 90. 1 percent Exhibit 3

- 91 Case 6 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/h r ( lb/hr) Coal 134,527 (296,581) Slag 673 (1,483) Air (CO 2 

## ) 532 (1,173) Stack Gas 13,416 (29,578) ASU Vent 95 (210) CO 2 

## Product 120,652 (265,992) Coal Dryer Stack Gas 223 (491)

Total 135,059 (297,754) Total 135,059 (297,754)

Exhibit 3

- 92 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the stack gas and sulfur from the tail gas unit that is vented through the coal dryer. Sulfur in the slag is considered negligible. Exhibit 3

- 92 Case 6 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 5,290 (11,661) Elemental Sulfur 5,277 (11,634)
Stack Gas 3 (6) CO 2 

## Product 10 (22)

Total 5,290 (11,661) Total 5,290 (11,661)

Exhibit 3

- 93 shows the overall water balance for the plant. The exhibit is presented in an identical manner as for previous cases

.

### Cost and Performance Baseline for Fossil Energy Plants

275 

## Exhibit 3

- 93 Case 6 Water Balance

Water Use Water Demand,

m 3 

### /min (gpm) Internal Recycle, m 3 

### /min (gpm) Raw Water Withdrawal, m 3 

### /min (gpm) Process Water Discharge,

m 3 

### /min (gpm) Raw Water Consumption,
m 3 

### /min (gpm)

Slag Handling 0.46 (121) 0.46 (121) 0.0 (0) 0.0 (0) 0.0 (0) Quench/Wash 3.2 (836) 2.2 (587) 0.9 (250) 0.0 (0) 0.9 (250)
Humidifier 0.7 (177) 0.7 (177) 0.0 (0) 0.0 (0) 0.0 (0)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.03 (7)

- 0.03 (

- 7) Condenser Makeup Gasifier Steam Shift Steam GT Steam Dilution BFW Makeup 3.8 (1,012) 0.3 (90) 3.3 (874) 0.18 (48) 0.0 (0) 3.8 (1,012) 0.3 (90) 3.3 (874) 0.18 (48) 0.0 (0) 3.8 (1,012)

Cooling Tower BFW Blowdown SWS Blowdown SWS Excess Water Humidifier Tower Blowdown 17.0 (4,490) 0.45 (119) 0.18 (48) 0.27 (71) 16.5 (4,371)

- 0.18 (

- 48)

- 0.27 (

- 71) 3.8 (1,010) 12.7 (3,361)

Total 25.1 (6,637) 3.8 (1,004) 21.3 (5,633) 3.8 (1,017) 17.5 (4,616)



## Heat and mass balance diagrams are shown for the following subsystems in Heat and Mass Balance Diagrams Exhibit 3

- 94 through Exhibit 3

- 96 :

**•** Coal gasification and ASU

**•** Syngas cleanup i ncluding s ulfur recovery and tail gas recycle

**•** Combined cycle power generation , s team , and FW An overall plant energy balance is provided in tabular form in Exhibit 3

- 97 . The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 3

- 89 ) is calculated by multiplying the power out by a combined generator efficiency of 98.4 percent.

### Cost and Performance Baseline for Fossil Energy Plants

276 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

277 

## Exhibit 3

- 94 Case 6 Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

N OTES :

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 6
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 6 S HELL G ASIFIER ASU , G ASIFICATION , AND G AS C OOLING

DWG

. NO

. BB

- HMB

- CS

- 6

- PG

- 1 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Intercooled Air Compressor

Elevated Pressure

ASU Intercooled Nitrogen Compressor

Intercooled Oxygen Compressor

Milled Coal Sour Gas

Sour Water ASU VENT

Water Steam

Slag Removal Slag G ROSS P LANT P OWER : 673 MW E A UXILIARY L OAD : 177 MW E N ET P LANT P OWER : 497 MW E N ET P LANT E FFICIENCY , HHV : 31

. 2 % N ET P LANT H EAT R ATE : 10 , 924 BTU / KW E Dry Coal Coal Feeding Steam

Candle Filter Cyclone N 2 to GT Combustor

Boost Compressor

Recycle Compressor

Raw Syngas to Scrubber 519

. 9 T 625

. 0 P 551

. 7 H To Claus Plant

9 10 1

3

7

6

11 13 2 1 , 544 , 445 W 59

. 0 T 14

. 7 P 13

. 0 H 60 , 249 W 67

. 9 T 16

. 4 P 15

. 9 H

989 , 843 W 90

. 0 T 56

. 4 P 14

. 2 H 139 , 103 W 50

. 0 T 182

. 0 P

2

. 9 H

7 , 250 W

90

. 0 T 125

. 0 P 11

. 5 H 346 , 622 W 90

. 0 T 125

. 0 P 11

. 5 H

346 , 622 W

241

. 2 T 940

. 0 P 40

. 8 H 58 , 132 W

386

. 6 T 815

. 0 P 86

. 8 H

465 , 264 W 59

. 0 T 14

. 7 P 435 , 108 W 60

. 0 T 840

. 0 P 1 , 526

. 1 H

46 , 599 W 2 , 600

. 0 T

615

. 0 P 1 , 172 , 137 W

1 , 979

. 6 T

615

. 0 P 878

. 4 H

1 , 256 , 401 W 450

. 0 T 585

. 0 P 523

. 4 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB / HR H E NTHALPY , B TU / L B MW E P OWER , M EGAWATTS E LECTRICAL 687 , 451 W

385

. 0 T 384

. 0 P 87

. 2 H

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA 5

44 , 894 W 650

. 0 T 740

. 0 P 1 , 317

. 3 H

Coal Drying Incinerator

Syngas Slip Stream Incinerator Air Flue Gas / Combustion Products

Incinerator Exhaust

4 , 188 W

94

. 4 T 520

. 0 P 70

. 1 H 63 , 439 W

59

. 0 T 14

. 7 P 13

. 4 H 97 , 783 W

290

. 0 T 14

. 4 P

8 199

. 0 T 384

. 0 P 39

. 8 H

333 , 980 W 450

. 0 T 585

. 0 P 523

. 4 H

Syngas Quench Cooler

Quench Water

418 , 244 W

420

. 0 T 1 , 200

. 0 P

387

. 9 H

Shift Steam For WGF Reactors Saturated Steam To HRSG

HP BFW IP BFW N 2 Compressor N 2 to GT Combustor

Saturated Steam To HRSG

HP BFW 12

1 , 650

. 0 T 605

. 0 P 739

. 8 H 600

. 0 T 595

. 0 P 585

. 2 H 1 , 590 , 381 W 750

. 0 T 605

. 0 P 647

. 4 H 100

. 0 T 189

. 5 P 18

. 0 H

383 , 362 W 385

. 0 T 469

. 0 P 87

. 0 H

Syngas Cooler Duct Cooler

Steam Generation
Shell Gasifier 4

### Cost and Performance Baseline for Fossil Energy Plants

278 

## Exhibit 3

- 95 Case 6 Syngas Cleanup Heat and Mass Balance Schematic

N OTES :

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 6
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 6 S HELL G ASIFIER G AS C LEANUP S YSTEM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

Mercury Removal

Knock Out Drum Raw Syngas

Sour Drum

To Water Treatment Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur Sour Water

Reboiler Acid Gas

Tailgas Carbon Dioxide

Sour Gas

Sulfur Hydrogen

DWG

. NO

. BB

- HMB

- CS

- 6

- PG

- 2 P AGES 2 OF 3 Sour Stripper Syngas Scrubber

G ROSS P LANT P OWER : 673 MW E A UXILIARY L OAD : 177 MW E N ET P LANT P OWER : 497 MW E N ET P LANT E FFICIENCY , HHV : 31

. 2 % N ET P LANT H EAT R ATE : 10 , 924 BTU / KW E Water

13 16 17 22

23 24

1 , 256 , 401 W 450

. 0 T 585

. 0 P 523

. 4 H 27 , 484 W 100

. 0 T 799

. 5 P

3

. 6 H 436 , 986 W

550

. 0 T 800

. 0 P 1 , 254

. 1 H 1 , 594 , 881 W 484

. 5 T 565

. 0 P 423

. 7 H 1 , 266 , 974 W 94

. 4 T 520

. 0 P 19

. 1 H

Syngas Coolers 248 , 650 W 94

. 4 T 520

. 0 P 70

. 1 H

11 , 634 W 352

. 5 T 17

. 3 P

From ASU

3 , 022 W 227

. 6 T 65

. 0 P 370

. 2 H 36 , 563 W 450

. 0 T 12

. 3 P 479

. 1 H 37 , 925 W

119

. 0 T 23

. 7 P 36

. 5 H

Knock Out Tailgas to AGR 1 , 594 , 881 W 422

. 2 T 575

. 0 P 662

. 5 H

1 , 239 , 491 W 94

. 8 T 525

. 0 P 19

. 5 H P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB / HR H E NTHALPY , B TU / L B MW E P OWER , M EGAWATTS E LECTRICAL

9 , 080 W 114

. 5 T 10

. 6 P 40

. 3 H Treated Syngas

Slip Stream to Coal Dryer 18 Humidification 19 Humidified Fuel Gas 20

8

Shift Steam High Temperature

Shift # 1 Low Temperature

Shift # 2

Fuel Gas Humidification

1 , 157 , 895 W 375

. 6 T 580

. 0 P 435

. 0 H 385

. 6 T 575

. 0 P 439

. 1 H

477

. 9 T 560

. 0 P 420

. 7 H WGS and Steam Cycle Steam 14 15

Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Interstage Knockout CO 2 Product

21 Multistage Intercooled CO 2

Compressor 7 , 250 W 450

. 0 T 124

. 5 P 91

. 9 H

975 , 038 W 124

. 0 T 2 , 214

. 7 P 25

Tailgas Recycle Compressor Hydrogenation And Tail Gas

Cooling

### Cost and Performance Baseline for Fossil Energy Plants

279 

## Exhibit 3

- 96 Case 6 Combined Cycle Power Generation Heat and Mass Balance Schematic

N OTES :

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 6
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS B ASELINE S TUDY C ASE 6 S HELL G ASIFIER P OWER B LOCK S YSTEM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB / HR H E NTHALPY , B TU / L B MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen

Synthesis Gas HRSG

HP Turbine IP Turbine Nitrogen Dilution

Intake

Ambient Air Steam Seal Regulator IP Extraction Steam to 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Make

- up

Gland Steam Condenser Condensate to Gasification Island HP & IP BFW to Raw Gas Coolers

HP & IP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Humidified Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump Water Steam

DWG

. NO

. BB

- HMB

- CS

- 6

- PG

- 3 P AGES 3 OF 3 Advanced F

- Class

Gas Turbine

G ROSS P LANT P OWER : 673 MW E A UXILIARY L OAD : 177 MW E N ET P LANT P OWER : 497 MW E N ET P LANT E FFICIENCY , HHV : 31

. 2 % N ET P LANT H EAT R ATE : 10 , 924 BTU / KW E Flue Gas / Combustion Products

To Gasifier MP Flash Bottoms LP Flash Tops

From Gasifier Island Preheating

To Claus LP BFW

IP Pump

26 4

20 27 28

29

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H 333 , 100 W 380

. 0 T 460

. 0 P 609

. 1 H 1 , 070 , 813 W 199

. 0 T 384

. 0 P 39

. 8 H 8 , 418 , 047 W 1 , 043

. 2 T

15

. 2 P 372

. 4 H

1 , 146 , 042 W 993

. 2 T 1 , 814

. 7 P 1 , 475

. 5 H

1 , 911 , 334 W 102

. 8 T 120

. 0 P 71

. 1 H 23 , 308 W

585

. 0 T 2 , 000

. 7 P

592

. 9 H 8 , 328 W 298

. 0 T 65

. 0 P 1 , 178

. 6 H

1 , 393 , 094 W 439

. 8 T 65

. 0 P 1 , 252

. 2 H 8 , 418 , 047 W 270

. 0 T 15

. 2 P 159

. 6 H

1 , 911 , 334 W 235

. 0 T 105

. 0 P 203

. 3 H

506 , 076 W 59

. 0 T 14

. 7 P 27

. 1 H 1 , 169 , 363 W 278

. 8 T 2 , 250

. 7 P

251

. 9 H

1 , 911 , 334 W 101

. 1 T

1

. 0 P 69

. 1 H 1 , 400 W 614

. 2 T 65

. 0 P 1 , 338

. 3 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H 26 , 345 W

851

. 0 T 280

. 0 P 1 , 448

. 2 H

HOT WELL CONDENSER 217 , 834 W

298

. 0 T 65

. 0 P 1 , 178

. 6 H

### Cost and Performance Baseline for Fossil Energy Plants

280 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

281 

## Exhibit 3

- 97 Case 6 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,727 (5,428) 4.8 (4.5) 5,731 (5,432) ASU Air 21.2 (20.1) 21 (20) GT Air 96.2 (91.2) 96 (91) Water 80.2 (76.0) 80 (76) Auxiliary Power 636 (602) 636 (602) TOTAL 5,727 (5,428) 202.3 (191.7) 636 (602) 6,564 (6,222) Heat Out GJ/hr (MMBtu/hr) ASU Vent 1.0 (1.0) 1 (1) Slag 22 (21) 35.7 (33.8) 58 (55) Sulfur 49 (46) 0.6 (0.6) 50 (47) CO 2 

## - 71.5 (

- 67.8)

- 72 (

- 68) Cooling Tower Blowdown 28.4 (26.9) 28 (27) HRSG Flue Gas 1,418 (1,344) 1,418 (1,344) Condenser 1,335 (1,265) 1,335 (1,265) Non

- Condenser Cooling Tower Loads* 687 (651) 687 (651)
Process Losses** 635 (602) 635 (602) Power 2,424 (2,298) 2,424 (2,298) TOTAL 71 (67) 4,069 (3,857) 2,424 (2,298) 6,564 (6,222) * Includes ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, syngas

cooler (low level heat rejection) and extraction air cooler. ** Calculated by difference to close the energy balance

.

### Cost and Performance Baseline for Fossil Energy Plants

282 

## 3.4.10 Major equipment items for the Shell gasifier with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in th e cost estimates in Section Case 6

- Major Equipment List

3.4.11 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for h eads on pumps and fans.
ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 172 tonne/hr (190 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 345 tonne/hr (380 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 172 tonne (190 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 345 tonne/hr (380 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 345 tonne/hr (380 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 3 0

### Cost and Performance Baseline for Fossil Energy Plants

283 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/hr (90 tph) 3 0
2 Conveyor No. 6 Belt w/tripper 236 tonne/hr (260 tph) 1 0
3 Roller Mill Feed Hopper Dual Outlet 463 tonne (510 ton) 1 0
4 Weigh Feeder Belt 118 tonne/hr (130 tph) 2 0
5 Coal Dryer and Pulverizer Rotary 118 tonne/hr (130 tph) 2 0
6 Coal Dryer Feed Hopper Vertical Hopper 236 tonne (260 ton) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

284 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 987,992 liters (261,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,987 lpm @ 91 m H2O (2,110 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 551,115 kg/hr (1,215,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 7,987 lpm @ 27 m H2O (2,110 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 5,072 lpm @ 1,859 m H2O (1,340 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 1,211 lpm @ 223 m H2O (320 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 393 GJ/hr (372 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 140,817 lpm @ 21 m H2O (37,200 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 5,943 lpm @ 18 m H2O (1,570 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,953 lpm @ 268 m H2O (780 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single suction 4,656 lpm @ 49 m H2O (1,230 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 2,225,822 liter (588,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 2,082 lpm (550 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

285 

## ACCOUNT 4 GASIFIER, ASU AND AC CESSORIES INCLUDING LOW TEMPERATURE HEAT REC OVERY AND FUEL GAS S ATURATION Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry-feed, entrained bed 2,812 tonne/day, 4.2 MPa (3,100 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 396,893 kg/hr (875,000 lb/hr) 2 0

3 Synthesis Gas Cyclone High efficiency 313,432 kg/hr (691,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with pulse-jet cleaning metallic filters 2 0

5 Syngas Scrubber Including Sour Water Stripper Vertical upflow 313,432 kg/hr (691,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with condensate drain 397,801 kg/hr (877,000 lb/hr) 8 0

7 Raw Gas Knockout Drum Vertical with mist eliminator 309,804 kg/hr, 35°C, 3.7 MPa (683,000 lb/hr, 95°F, 530 psia) 2 0

8 Saturation Water Economizers Shell and tube 78 GJ/hr (74 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 83,007 kg/hr, 137°C, 3.6 MPa (183,000 lb/hr, 278°F, 520 psia) 2 0

10 Saturator Water Pump Centrifugal 1,893 lpm @ 12 m H2O (500 gpm @ 40 ft H2O) 2 2

11 Synthesis Gas Reheater Shell and tube 83,007 kg/hr (183,000 lb/hr) 2 0

12 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 313,432 kg/hr (691,000 lb/hr) syngas 2 0

13 ASU Main Air Compressor Centrifugal, multi-stage 5,267 m3/min @ 1.3 MPa (186,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,087 tonne/day (2,300 tpd) of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage 1,048 m3/min (37,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 6.5 MPa (940 psia) 2 0

16 Primary Nitrogen Compressor Centrifugal, multi-stage 3,483 m3/min (123,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

17 Secondary Nitrogen Compressor Centrifugal, single-stage 481 m3/min (17,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

18 Gasifier Purge Nitrogen Boost Compressor Centrifugal, single-stage 1,359 m3/min (48,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 3.2 MPa (470 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

286 

## ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 5B CO 2 

## COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE A ND AUXILIARIES Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 309,350 kg/hr (682,000 lb/hr) 35°C (95°F) 3.6 MPa (525 psia) 2 0

2 Sulfur Plant Claus type 139 tonne/day (154 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 397,801 kg/hr (877,000 lb/hr) 216°C (420°F) 4.0 MPa (580 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 121 GJ/hr (114 MMBtu/hr) Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two-stage Selexol 316,154 kg/hr (697,000 lb/hr) 35°C (94°F) 3.6 MPa (520 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 18,243 kg/hr (40,220 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 13,713 kg/hr (30,232 lb/hr) 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 CO2 Compressor Integrally geared, multi-stage centrifugal 1,096 m3/min @ 15.3 MPa (38,700 scfm @ 2,215 psia) 4 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 232 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

### Cost and Performance Baseline for Fossil Energy Plants

287 

## ACCOUNT 7 HRSG, DUCTING, AND S TACK

ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 285,910 kg/hr, 12.4 MPa/534°C (630,323 lb/hr, 1,800 psig/993°F) Reheat steam - 244,783 kg/hr, 3.1 MPa/534°C (539,654 lb/hr, 452 psig/993°F) 2 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 220 MW 12.4 MPa/534°C/534°C (1800 psig/ 993°F/993°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,467 GJ/hr (1,390 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

288 

## ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 439,108 lpm @ 30 m (116,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

/ 2437 GJ/hr (2310 MMBtu/hr) heat duty 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 223,339 liters (59,000 gal) 2 0
2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0
3 Slag Depressurizer Lock Hopper 12 tonne/hr (13 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 132,489 liters (35,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 60,567 liters (16,000 gal) 2
6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0
7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 189,271 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 60,567 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 433 m H2O (60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 816 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

289 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 240 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 74 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 46 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

290 

## 3.4.11 The cost estimating methodology was described previously in Section Case 6

- Cost Estimating 2.6

. Exhibit 3

- 98 shows the total plant capital cost summary organized by cost account and Exhibit 3

- 99 shows a more detailed breakdown of the capital costs along with owner’s costs, TOC and TASC

. Exhibit 3

- 100 shows the initial and annual O&M costs. The estimated TO C of the Shell gasifier with CO 2 

## capture is $ 3,904 /kW. Process contingenc y represents 3.4 percent of the TO C and p roject contingency r epresents 11.4 percent. The COE, including CO 2 

## TS&M costs of 5

. 7 mills/kWh, is 1 1 9. 5 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

291 

## Exhibit 3

- 98 Case 6 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 6 - Shell 500MW IGCC w/ CO2 Plant Size: 496.9 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $13,881 $2,580 $10,765 $0 $0 $27,226 $2,471 $0 $5,939 $35,636 $72

2 COAL & SORBENT PREP & FEED $109,935 $8,758 $18,287 $0 $0 $136,980 $11,879 $0 $29,772 $178,630 $360

3 FEEDWATER & MISC. BOP SYSTEMS $9,471 $7,207 $9,699 $0 $0 $26,377 $2,492 $0 $6,717 $35,585 $72

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $144,815 $0 $61,614 $0 $0 $206,430 $18,447 $28,271 $38,955 $292,103 $588 4.2 Syngas Cooling (w/4.1) w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $173,504 $0 w/equip. $0 $0 $173,504 $16,818 $0 $19,032 $209,354 $421 4.4-4.9 Other Gasification Equipment $25,591 $9,849 $15,118 $0 $0 $50,557 $4,851 $0 $11,805 $67,213 $135 SUBTOTAL 4 $343,911 $9,849 $76,732 $0 $0 $430,492 $40,115 $28,271 $69,793 $568,670 $1,145

5A Gas Cleanup & Piping $91,097 $3,993 $77,814 $0 $0 $172,904 $16,706 $26,070 $43,284 $258,964 $521

5B CO 2 REMOVAL & COMPRESSION $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $261 6.2-6.9 Combustion Turbine Other $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6 $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $266

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,709 $0 $4,793 $0 $0 $38,502 $3,661 $0 $4,216 $46,379 $93 7.2-7.9 Ductwork and Stack $3,380 $2,410 $3,156 $0 $0 $8,946 $829 $0 $1,591 $11,367 $23 SUBTOTAL 7 $37,089 $2,410 $7,949 $0 $0 $47,448 $4,490 $0 $5,807 $57,745 $116

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,934 $0 $4,000 $0 $0 $27,935 $2,680 $0 $3,061 $33,676 $68 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $9,162 $818 $6,331 $0 $0 $16,312 $1,486 $0 $3,487 $21,285 $43 SUBTOTAL 8 $33,096 $818 $10,332 $0 $0 $44,246 $4,166 $0 $6,549 $54,961 $111

9 COOLING WATER SYSTEM $9,932 $9,472 $8,108 $0 $0 $27,512 $2,555 $0 $6,134 $36,202 $73

10 ASH/SPENT SORBENT HANDLING SYS $18,585 $1,433 $9,223 $0 $0 $29,241 $2,805 $0 $3,501 $35,547 $72

11 ACCESSORY ELECTRIC PLANT $30,536 $12,099 $23,664 $0 $0 $66,300 $5,703 $0 $13,663 $85,666 $172

12 INSTRUMENTATION & CONTROL $11,002 $2,024 $7,089 $0 $0 $20,115 $1,823 $1,006 $3,823 $26,766 $54

13 IMPROVEMENTS TO SITE $3,346 $1,972 $8,255 $0 $0 $13,572 $1,340 $0 $4,474 $19,386 $39

14 BUILDINGS & STRUCTURES $0 $6,461 $7,281 $0 $0 $13,741 $1,250 $0 $2,463 $17,455 $35

TOTAL COST $821,717 $69,882 $293,196 $0 $0 $1,184,795 $110,031 $65,208 $220,470 $1,580,505 $3,181 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

292 

## Exhibit 3

- 99 Case 6 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,645 $0 $1,781 $0 $0 $5,427 $486 $0 $1,183 $7,095 $14 1.2 Coal Stackout & Reclaim $4,711 $0 $1,142 $0 $0 $5,853 $513 $0 $1,273 $7,639 $15 1.3 Coal Conveyors & Yd Crush $4,380 $0 $1,130 $0 $0 $5,510 $484 $0 $1,199 $7,192 $14 1.4 Other Coal Handling $1,146 $0 $261 $0 $0 $1,407 $123 $0 $306 $1,836 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,580 $6,450 $0 $0 $9,030 $865 $0 $1,979 $11,874 $24 SUBTOTAL 1. $13,881 $2,580 $10,765 $0 $0 $27,226 $2,471 $0 $5,939 $35,636 $72 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $41,765 $2,509 $6,086 $0 $0 $50,360 $4,346 $0 $10,941 $65,647 $132 2.2 Prepared Coal Storage & Feed $1,978 $473 $310 $0 $0 $2,762 $236 $0 $600 $3,598 $7 2.3 Dry Coal Injection System $65,103 $756 $6,046 $0 $0 $71,905 $6,193 $0 $15,620 $93,718 $189 2.4 Misc.Coal Prep & Feed $1,088 $792 $2,373 $0 $0 $4,253 $391 $0 $929 $5,573 $11 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $4,228 $3,471 $0 $0 $7,700 $713 $0 $1,683 $10,095 $20 SUBTOTAL 2. $109,935 $8,758 $18,287 $0 $0 $136,980 $11,879 $0 $29,772 $178,630 $360 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,492 $4,279 $2,259 $0 $0 $9,029 $836 $0 $1,973 $11,839 $24 3.2 Water Makeup & Pretreating $701 $73 $392 $0 $0 $1,167 $111 $0 $383 $1,661 $3 3.3 Other Feedwater Subsystems $1,363 $461 $415 $0 $0 $2,238 $201 $0 $488 $2,928 $6 3.4 Service Water Systems $401 $827 $2,869 $0 $0 $4,097 $400 $0 $1,349 $5,845 $12 3.5 Other Boiler Plant Systems $2,154 $835 $2,069 $0 $0 $5,057 $480 $0 $1,107 $6,644 $13 3.6 FO Supply Sys & Nat Gas $313 $591 $551 $0 $0 $1,454 $140 $0 $319 $1,913 $4 3.7 Waste Treatment Equipment $981 $0 $598 $0 $0 $1,579 $154 $0 $520 $2,252 $5 3.8 Misc. Power Plant Equipment $1,066 $143 $547 $0 $0 $1,756 $170 $0 $578 $2,503 $5 SUBTOTAL 3. $9,471 $7,207 $9,699 $0 $0 $26,377 $2,492 $0 $6,717 $35,585 $72 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries (Shell) $144,815 $0 $61,614 $0 $0 $206,430 $18,447 $28,271 $38,955 $292,103 $588 4.2 Syngas Cooling w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $173,504 $0 w/equip. $0 $0 $173,504 $16,818 $0 $19,032 $209,354 $421 4.4 LT Heat Recovery & FG Saturation $25,591 $0 $9,728 $0 $0 $35,319 $3,447 $0 $7,753 $46,519 $94 4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $1,406 $572 $0 $0 $1,978 $190 $0 $433 $2,601 $5 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $8,443 $4,818 $0 $0 $13,261 $1,214 $0 $3,619 $18,094 $36 SUBTOTAL 4. $343,911 $9,849 $76,732 $0 $0 $430,492 $40,115 $28,271 $69,793 $568,670 $1,145

### Cost and Performance Baseline for Fossil Energy Plants

293 

## Exhibit 3

- 99 Case 6 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $70,179 $0 $59,549 $0 $0 $129,728 $12,546 $25,946 $33,644 $201,864 $406 5A.2 Elemental Sulfur Plant $10,017 $1,996 $12,924 $0 $0 $24,937 $2,422 $0 $5,472 $32,831 $66 5A.3 Mercury Removal $1,410 $0 $1,073 $0 $0 $2,483 $240 $124 $569 $3,417 $7 5A.4 Shift Reactors $7,366 $0 $2,965 $0 $0 $10,330 $990 $0 $2,264 $13,585 $27 5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $2,125 $358 $201 $0 $0 $2,684 $255 $0 $588 $3,526 $7 5A.6 Fuel Gas Piping $0 $814 $570 $0 $0 $1,384 $128 $0 $303 $1,815 $4 5A.9 HGCU Foundations $0 $824 $532 $0 $0 $1,356 $125 $0 $444 $1,925 $4 SUBTOTAL 5A. $91,097 $3,993 $77,814 $0 $0 $172,904 $16,706 $26,070 $43,284 $258,964 $521 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75 SUBTOTAL 5B. $17,811 $0 $10,524 $0 $0 $28,335 $2,728 $0 $6,213 $37,276 $75 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $261 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $806 $892 $0 $0 $1,699 $159 $0 $557 $2,415 $5 SUBTOTAL 6. $92,026 $806 $7,475 $0 $0 $100,307 $9,507 $9,861 $12,339 $132,014 $266 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,709 $0 $4,793 $0 $0 $38,502 $3,661 $0 $4,216 $46,379 $93 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,733 $1,236 $0 $0 $2,969 $260 $0 $646 $3,875 $8 7.4 Stack $3,380 $0 $1,270 $0 $0 $4,650 $445 $0 $510 $5,605 $11 7.9 HRSG,Duct & Stack Foundations $0 $677 $650 $0 $0 $1,328 $124 $0 $435 $1,887 $4 SUBTOTAL 7. $37,089 $2,410 $7,949 $0 $0 $47,448 $4,490 $0 $5,807 $57,745 $116 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,934 $0 $4,000 $0 $0 $27,935 $2,680 $0 $3,061 $33,676 $68 8.2 Turbine Plant Auxiliaries $165 $0 $378 $0 $0 $543 $53 $0 $60 $656 $1 8.3 Condenser & Auxiliaries $4,579 $0 $1,463 $0 $0 $6,042 $578 $0 $662 $7,282 $15 8.4 Steam Piping $4,418 $0 $3,108 $0 $0 $7,526 $647 $0 $2,043 $10,215 $21 8.9 TG Foundations $0 $818 $1,383 $0 $0 $2,201 $209 $0 $723 $3,132 $6 SUBTOTAL 8. $33,096 $818 $10,332 $0 $0 $44,246 $4,166 $0 $6,549 $54,961 $111 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,867 $0 $1,249 $0 $0 $8,116 $773 $0 $1,333 $10,222 $21 9.2 Circulating Water Pumps $1,791 $0 $127 $0 $0 $1,919 $162 $0 $312 $2,393 $5 9.3 Circ.Water System Auxiliaries $151 $0 $21 $0 $0 $172 $16 $0 $28 $217 $0 9.4 Circ.Water Piping $0 $6,288 $1,630 $0 $0 $7,918 $716 $0 $1,727 $10,360 $21 9.5 Make-up Water System $381 $0 $544 $0 $0 $925 $89 $0 $203 $1,217 $2 9.6 Component Cooling Water Sys $742 $888 $632 $0 $0 $2,262 $212 $0 $495 $2,968 $6 9.9 Circ.Water System Foundations $0 $2,296 $3,904 $0 $0 $6,200 $588 $0 $2,037 $8,825 $18 SUBTOTAL 9. $9,932 $9,472 $8,108 $0 $0 $27,512 $2,555 $0 $6,134 $36,202 $73

### Cost and Performance Baseline for Fossil Energy Plants

294 

## Exhibit 3

- 99 Case 6 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $16,178 $0 $7,978 $0 $0 $24,156 $2,321 $0 $2,648 $29,125 $59 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $546 $0 $594 $0 $0 $1,139 $111 $0 $187 $1,437 $3 10.7 Ash Transport & Feed Equipment $732 $0 $177 $0 $0 $908 $85 $0 $149 $1,142 $2 10.8 Misc. Ash Handling Equipment $1,130 $1,385 $414 $0 $0 $2,929 $279 $0 $481 $3,689 $7 10.9 Ash/Spent Sorbent Foundation $0 $48 $61 $0 $0 $109 $10 $0 $36 $155 $0 SUBTOTAL 10. $18,585 $1,433 $9,223 $0 $0 $29,241 $2,805 $0 $3,501 $35,547 $72 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $901 $0 $891 $0 $0 $1,792 $171 $0 $196 $2,159 $4 11.2 Station Service Equipment $4,510 $0 $406 $0 $0 $4,916 $453 $0 $537 $5,906 $12 11.3 Switchgear & Motor Control $8,338 $0 $1,516 $0 $0 $9,854 $914 $0 $1,615 $12,383 $25 11.4 Conduit & Cable Tray $0 $3,873 $12,777 $0 $0 $16,650 $1,610 $0 $4,565 $22,826 $46 11.5 Wire & Cable $0 $7,400 $4,862 $0 $0 $12,262 $891 $0 $3,288 $16,442 $33 11.6 Protective Equipment $0 $679 $2,471 $0 $0 $3,150 $308 $0 $519 $3,976 $8 11.7 Standby Equipment $224 $0 $219 $0 $0 $443 $42 $0 $73 $558 $1 11.8 Main Power Transformers $16,564 $0 $136 $0 $0 $16,699 $1,263 $0 $2,694 $20,656 $42 11.9 Electrical Foundations $0 $147 $386 $0 $0 $534 $51 $0 $175 $760 $2 SUBTOTAL 11. $30,536 $12,099 $23,664 $0 $0 $66,300 $5,703 $0 $13,663 $85,666 $172 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,086 $0 $725 $0 $0 $1,811 $171 $91 $311 $2,384 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $250 $0 $160 $0 $0 $410 $39 $20 $94 $563 $1 12.7 Computer & Accessories $5,794 $0 $185 $0 $0 $5,979 $549 $299 $683 $7,510 $15 12.8 Instrument Wiring & Tubing $0 $2,024 $4,137 $0 $0 $6,161 $523 $308 $1,748 $8,740 $18 12.9 Other I & C Equipment $3,873 $0 $1,881 $0 $0 $5,753 $541 $288 $987 $7,570 $15 SUBTOTAL 12. $11,002 $2,024 $7,089 $0 $0 $20,115 $1,823 $1,006 $3,823 $26,766 $54

### Cost and Performance Baseline for Fossil Energy Plants

295 

## Exhibit 3

- 99 Case 6 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $105 $2,244 $0 $0 $2,349 $233 $0 $775 $3,356 $7 13.2 Site Improvements $0 $1,867 $2,481 $0 $0 $4,348 $429 $0 $1,433 $6,210 $12 13.3 Site Facilities $3,346 $0 $3,530 $0 $0 $6,876 $678 $0 $2,266 $9,820 $20 SUBTOTAL 13. $3,346 $1,972 $8,255 $0 $0 $13,572 $1,340 $0 $4,474 $19,386 $39 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,071 $2,950 $0 $0 $5,021 $462 $0 $822 $6,306 $13 14.3 Administration Building $0 $857 $622 $0 $0 $1,479 $132 $0 $242 $1,853 $4 14.4 Circulation Water Pumphouse $0 $161 $85 $0 $0 $246 $22 $0 $40 $308 $1 14.5 Water Treatment Buildings $0 $586 $572 $0 $0 $1,158 $105 $0 $189 $1,452 $3 14.6 Machine Shop $0 $439 $300 $0 $0 $739 $66 $0 $121 $926 $2 14.7 Warehouse $0 $709 $457 $0 $0 $1,166 $103 $0 $190 $1,460 $3 14.8 Other Buildings & Structures $0 $424 $330 $0 $0 $755 $67 $0 $164 $987 $2 14.9 Waste Treating Building & Str. $0 $949 $1,813 $0 $0 $2,762 $257 $0 $604 $3,623 $7 SUBTOTAL 14. $0 $6,461 $7,281 $0 $0 $13,741 $1,250 $0 $2,463 $17,455 $35

TOTAL COST $821,717 $69,882 $293,196 $0 $0 $1,184,795 $110,031 $65,208 $220,470 $1,580,505 $3,181
Owner's Costs Preproduction Costs 6 Months All Labor $13,300 $27 1 Month Maintenance Materials $2,951 $6 1 Month Non-fuel Consumables $378 $1 1 Month Waste Disposal $278 $1 25% of 1 Months Fuel Cost at 100% CF $1,621 $3 2% of TPC $31,610 $64 Total $50,138 $101 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,459 $27 0.5% of TPC (spare parts) $7,903 $16 Total $21,361 $43
Initial Cost for Catalyst and Chemicals $7,224 $15 Land $900 $2 Other Owner's Costs $237,076 $477

Financing Costs $42,674 $86 Total Overnight Costs (TOC) $1,939,878 $3,904 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,211,461 $4,451

### Cost and Performance Baseline for Fossil Energy Plants

296 

## Exhibit 3

- 100 Case 6 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 6 - Shell 500MW IGCC w/ CO2 Heat Rate-net (Btu/kWh): 10,924 MWe-net: 497 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $12.707 Maintenance Labor Cost $14,966,466 $30.122 Administrative & Support Labor $5,319,993 $10.707 Property Taxes and Insurance $31,610,092 $63.620 TOTAL FIXED OPERATING COSTS $58,210,058 $117.156 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $28,329,484 $0.00814

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,056 1.08 $0 $1,281,009 $0.00037

Chemicals

MU & WT Chem. (lbs) 0 24,163 0.17 $0 $1,221,101 $0.00035 Carbon (Mercury Removal) (lb) 117,815 161 1.05 $123,726 $49,490 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,470 4.43 498.83 $3,227,388 $645,478 $0.00019 Selexol Solution (gal) 289,068 92 13.40 $3,873,002 $360,241 $0.00010 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip. 1.93 131.27 $0 $74,040 $0.00002 Subtotal Chemicals $7,224,116 $2,350,349 $0.00068

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Spent Mercury Catalyst (lb.) 0 161 0.42 $0 $19,655 $0.00001 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 559 16.23 $0 $2,649,268 $0.00076 Subtotal-Waste Disposal $0 $2,668,923 $0.00077

By-products & Emissions

Sulfur (ton) 0 140 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $7,224,116 $34,629,764 $0.00995

Fuel (ton) 0 5,583 38.18 $0 $62,251,620 $0.01788

### Cost and Performance Baseline for Fossil Energy Plants

297 

## 3.5 IGCC CASE SUMMARY The performance results of the six IGCC plant configurations modeled in this study are summarized in Exhibit 3

- 101

. Exhibit 3

- 101 Estimated Performance and Cost Results for IGCC Cases

1 

### CF is 80% for all IGCC case s 2 

### COE and LCOE are defined in Section 2.7

. PERFORMANCE Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 CO2 Capture 0% 90% 0% 90% 0% 90% Gross Power Output (kWe) 747,800 734,000 738,200 703,700 737,000 673,400 Auxiliary Power Requirement (kWe) 125,750 190,750 113,140 190,090 108,020 176,540 Net Power Output (kWe) 622,050 543,250 625,060 513,610 628,980 496,860 Coal Flowrate (lb/hr) 466,901 487,011 459,958 484,212 436,646 465,264 Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A N/A N/A HHV Thermal Input (kWth) 1,596,320 1,665,074 1,572,582 1,655,503 1,492,878 1,590,722 Net Plant HHV Efficiency (%) 39.0% 32.6% 39.7% 31.0% 42.1% 31.2% Net Plant HHV Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924 Raw Water Withdrawal (gpm/MW net ) 7.6 10.7 7.0 11.1 6.6 11.3 Process Water Discharge (gpm/MW net ) 1.6 2.0 1.4 2.1 1.2 2.0 Raw Water Consumption (gpm/MW net ) 6.0 8.7 5.5 9.0 5.3 9.3 CO 2 Emissions (lb/MMBtu) 197 20 199 20 197 20 CO 2 Emissions (lb/MWh gross ) 1,434 152 1,448 158 1,361 161 CO 2 Emissions (lb/MWh net ) 1,723 206 1,710 217 1,595 218 SO 2 Emissions (lb/MMBtu) 0.0012 0.0022 0.0117 0.0022 0.0042 0.0021 SO 2 Emissions (lb/MWh gross ) 0.0090 0.0166 0.0852 0.0173 0.0290 0.0171 NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 NOx Emissions (lb/MWh gross ) 0.430 0.376 0.434 0.396 0.409 0.396 PM Emissions (lb/MMBtu) 0.0071 0.0071 0.0071 0.0071 0.0071 0.0071 PM Emissions (lb/MWh gross ) 0.052 0.055 0.052 0.057 0.049 0.057 Hg Emissions (lb/TBtu) 0.571 0.571 0.571 0.571 0.571 0.571 Hg Emissions (lb/MWh gross ) 4.16E-06 4.42E-06 4.15E-06 4.59E-06 3.95E-06 4.61E-06 COST Total Plant Cost (2007$/kW) 1,987 2,711 1,913 2,817 2,217 3,181 Total Overnight Cost (2007$/kW) 2,447 3,334 2,351 3,466 2,716 3,904 **Bare Erected Cost** 1,528 2,032 1,470 2,113 1,695 2,385 **Home Office Expenses** 144 191 138 199 156 221 **Project Contingency** 265 369 256 385 302 444 **Process Contingency** 50 119 50 120 63 131 **Owner's Costs** 460 623 438 649 500 723 Total Overnight Cost (2007$ x 1,000) 1,521,880 1,811,411 1,469,577 1,780,290 1,708,524 1,939,878 Total As Spent Capital (2007$/kW) 2,789 3,801 2,680 3,952 3,097 4,451 COE (mills/kWh, 2007$) 1,2 76.3 105.6 74.0 110.3 81.3 119.4 **CO2 TS&M Costs** 0.0 5.2 0.0 5.5 0.0 5.6 **Fuel Costs** 14.3 17.1 14.0 18.0 13.3 17.9 **Variable Costs** 7.3 9.3 7.2 9.8 7.8 9.9 **Fixed Costs** 11.3 14.8 11.1 15.5 12.1 16.7 **Capital Costs** 43.4 59.1 41.7 61.5 48.2 69.2 LCOE (mills/kWh, 2007$) 1,2 96.7 133.9 93.8 139.9 103.1 151.4 Integrated Gasification Combined Cycle GEE R+Q CoP E-Gas FSQ Shell

### Cost and Performance Baseline for Fossil Energy Plants

298 

## The components of TOC and the overall TASC of the six IGCC cases are shown in Exhibit 3

- 102 . The following TOC observations are made with the caveat that the differences between cases are less than the estimate accuracy (

- 15%/+30% ). However, all cases are evaluated using a common set of technical and economic assumptions allowing meaningful comparisons among the cases:

**•** CoP has the lowest TOC cost among the non

- capture cases. The E

- Gas technology has several features that lend it to being lower cost, such as:

o The firetube syngas co oler is much smaller and less expensive than a radiant section. E

- Gas can use a firetube boiler because the two

- stage design reduces the gas temperature (slurry quench) and drops the syngas temperature into a range where a radiant cooler is not needed.

o Th e firetube syngas cooler sits next to the gasifier instead of above or below it , which reduces the height of the main gasifier structure. The E

- Gas proprietary slag removal system, used instead of lock hoppers below the gasifier, also contributes to the l ower structure height.
The TO C of the GEE gasifier is about 4 percent greater than CoP and Shell is about 1 6 percent higher. Exhibit 3

- 102 Plant Capital Cost for IGCC Cases

**•** The GEE gasifier is the low cos t technology in the CO 2 

## capture cases, with CoP about 4 percent higher and Shell about 1 7 percent higher. The greatest uncertainty in all of the capital cost estimates is for the Shell capture case , which is based on a water quench process that has been proposed by Shell in a pa tent application [ 63 ]

. However , to date there have been no commercial application s of this configuration. 2,447 3,334

2,351 3,466
2,716 3,904

2,789 3,801

2,680 3,952

3,097 4,451

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000

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

GEE GEE w/ CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 CaptureTOC or TASC, $/kW (2007$) TASC Owner's Cost Process Contingency Project Contingency Home Office Expense Bare Erected Cost

### Cost and Performance Baseline for Fossil Energy Plants

299 

## • The ASU cost represents on average 12 percent of the TO C (range from 10.5

- 12.9 percent). The ASU cost includes oxygen and nitrogen compression, and in the non

capture cases, also includes the cost of the CT extraction air heat exc hanger. With nitrogen dilution used to the maximum extent possible, nitrogen compression costs are significant.

**•** The TOC premium for adding CO 2 

## capture averages 42 percent ($3,5 68 /kW versus $ 2 , 504 /kW). The COE is shown for the IGCC cases in Exhibit 3

- 103

. Exhibit 3

- 103 COE for IGCC Cases

The following observations can be made:

**•** The COE is dominated by capital costs, at least 5 6 percent of the total in all cases.

**•** In the non

- capture cases the CoP gasifier has the lowest COE, but the differential with Shel l is reduced (compared to the TO C) primarily because of the higher efficiency of the Shell gasifier. The Shell COE i s 10 percent higher than CoP (compared to 1 6 percent higher T O C). The GEE gasifier COE is about 3 percent higher than CoP.

**•** In the capture cases the variation in COE is small, however the order of the GEE and CoP gasifiers is reversed. The range is from 1 05

. 7 mills/kWh for GEE to 1 1 9

. 5 mills/kWh for Shell with CoP intermediate at 1 10

. 4 mills/kWh. The COE CO 2 

## capture premium for the IGCC cases averages 4 5 percent (range of 3 9 to 4 9 percent). 43.4 59.1
41.7 61.5 48.2 69.2 11.3 14.8

11.1 15.5

12.1 16.7

7.3 9.3

7.2 9.8

7.8 9.9

14.3 17.1

14.0 18.0

13.3 17.9 5.3 5.6 5.7

0 20 40 60 80 100 120 140 160

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 CaptureCOE, mills/kWh (2007$) CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs

### Cost and Performance Baseline for Fossil Energy Plants

300 

## • The CO 2 

## TS&M COE component comprises less than 5 .5 percent of the total COE in all capture cases. The effect of CF and coal price on COE is shown in Exhibit 3

- 104 and Exhibit 3

- 105 , respectively. The assumption implicit in Exhibit 3

- 104 is that each gasifier technology can achieve a CF of up to 90 percent with no additional capital equipment. The cost differential between technologies decreases as CF increases. At low CF t he capital cost differential is more magnified and the spread between technologies increases slightly. Exhibit 3

- 104 Capacity Factor Sensitivity of IGCC Cases

COE is relatively insensitive to fuel costs f or the IGCC cases as shown in Exhibit 3

- 105 . A tripling of coal price from 1 to $3/MMBtu results in an averag e COE increase of only about 19

- 25 percent for all cases. As presented in Section 2.4 the cost of CO 2 

## capture was calculated as an avoided cost . The results for the IGCC CO 2 

## capture cases are shown in Exhibit 3

- 106 . The first year cost of CO 2 

## avoided using each analogous IGCC non

- capture technology as the reference averages $52.9/tonne ( $ 48 /ton ) with a range of $43

- $61.7/tonne ( $ 39

- $ 56 /ton )

. The cost of CO 2 

## avoided is higher when using SC PC without CO 2 

## capture as the technology reference . Avoided costs average $75/tonne ( $ 68 /ton ) with a range of $66.1

- $86/tonne ( $ 60

- $ 7 8 /ton )

. T he avoided cost is elevated because SC PC without capture has a significantly lower COE than any IGCC technology

. 0 50 100 150 200 250 300

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

Capacity Factor, % Shell w/CO2 Capture CoP w/CO2 Capture GEE w/CO2 Capture Shell No Capture GEE No Capture CoP No Capture Coal = $1.64/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

301 

## Exhibit 3

- 105 Coal Price Sensitivity of IGCC Cases

Exhibit 3

- 106 Cost of CO 2 

## Avoided in IGCC Cases 0 20 40 60 80 100 120 140 160

0 0.5 1 1.5 2 2.5 3 3.5 4COE, mills/kWh (2007$)

Coal Price, $/MMBtu Shell w/CO2 Capture CoP w/CO2 Capture GEE w/CO2 Capture Shell No Capture GEE No Capture CoP No Capture Capacity factor = 80%

43 54 61 66 73 86

0 10 20 30 40 50 60 70 80 90 100

GEE CoP ShellFirst Year CO2Avoided Cost, $/tonne (2007$) Avoided Cost (Analogous Technology w/o Capture Reference) Avoided Cost (SC PC w/o Capture Reference)

### Cost and Performance Baseline for Fossil Energy Plants

302 

## The following observations can be made regarding plant performance:

**•** In the non

- carbon capture cases the dry fed Shell gasifier has the highest net plant efficiency ( 42 .1 percent), followed by the two

- stage CoP slurry fed gasifier (39. 7 percent) and the single

- stage GEE gasifier ( 39.0 percent). The absolute values of the GEE and CoP gasifiers are close to the r eported values per the vendors [ 59 , 60 ]

. The Shell efficiency is slightly lower than reported by the vendor in other recent presentations [ 62 ]

.

**•** In the CO 2 

## capture cases the efficiency of the three gasifiers rang es from 31. 0 to 32. 6 percent.

**•** The dry fed Shell gasifier experiences the largest energy penalty ( 25 .9 relative percent) primarily because addition of the steam required for the WGS reaction is provided as quench water to reduce the syngas temperature from 899 °C ( 1 , 65 0°F) to 399°C (750°F). Quench to 399°C (750°F) reduces the amount of heat recovered in the syngas c ooler relative to the non

- capture case where syngas recycle reduces the temperature to only 1 , 093 °C ( 2 , 000 °F) prior to the cooler. The CO 2 

## capture scheme used in this study for the Shell process is similar to one described in a recent Shell pate nt applica tion [ 63

**•** The CoP process experiences the second largest energy penalty ( 21

. 9 relative percent) primarily because, like the Shell case, a significant amount of water must be added to the syngas for the SGS reactions. ]

.

**•** The energy penalty for the GEE gasifier with CO 2 

## capture is 1 6. 3 relative percent. The smaller energy penalty results from the large amount of water already in the syngas from the quench step prior to SGS. While the quench limits the efficiency in the non

- capture case, it is the primary reaso n that the net efficiency is slightly greater than CoP and Shell in the CO 2 

## capture case.

**•** The assumed carbon conversion efficiency in this study for the three gasifiers results in differing amount of carbon in the slag. Exhibit 3

- 107 shows carbon conversion and slag carbon content. CO 2 

## capture efficiency is reported based on the amount of carbon entering the system with the coal less the carbon exiting the gasifier with the slag. Exhibit 3

- 107 Carbon Conversion Efficiency and Slag Carbon Content Gasifier Vendor Carbon Conversion, % Slag Carbon Content, wt% GEE 98.0 11.62 CoP 99.2 5.00 Shell 99.5 3.18

**•** Particulate emissions and Hg emissions are essentially the same for all six IGCC cases. The environmental target for particulate emissions is 0.0071 lb/MMBtu, and it was assumed that the combination of particulate control used by each technology could meet this limit. Similarly, the carbon beds used for mercury control were uniformly assumed to achieve 95 percent removal. The smal l variation in Hg emissions is due to a similar small variation in coal feed rate among the six cases. In all cases the Hg emissions are substantially below the NSPS requirement of 20 x 10 - 6 

## lb/MWh. Had 90 percent been

### Cost and Performance Baseline for Fossil Energy Plants

303 

## chosen for the Hg removal efficienc y, all six cases would still have had emissions less than half of the NSPS limit.

**•** Based on vendor data, it was assumed that the advanced F class turbine would achieve 15 ppmv NOx emissions at 15 percent O 2 

## for both “standard” syngas in the non

- capture case s and for high hydrogen syngas in the CO 2 

## capture cases. The NOx emissions are slightly lower in the three capture cases (compared to non

- capture) because of the lower syngas volume generated in high hydrogen syngas cases.

**•** The environmental target for SO 2 

## emissions is 0.0128 lb/MMBtu. Vendor quotes confirmed that each of the AGR processes, Selexol, refrigerated MDEA and Sulfinol

- M, could meet the limit. CoP E

- Gas has the highest SO 2 

## emissions ( 0.005 kg/GJ (0.012 lb/MMBtu ) ) of the six IGCC cases because r efrigerated MDEA has the lowest H 2 

## S removal efficiency of the AGR technologies. The two

- stage Selexol process used for each of the CO 2 

## capture cases resulted in lower SO 2 

## emissions because the unit was designed to meet the CO 2 

## removal requirement. Water withdrawal , process discharge, and water consumption , all normalized by net output, are presented in Exhibit 3

- 108 . The following observations can be made:

**•** Raw water usage for all cases is dominated by cooling tower makeup requirements, which accounts for 79

- 87 percent of raw water usage in non

- capture cases and 7 3

- 7 5 percent in CO 2 

## capture cases.

**•** Normalized water withdrawal for the GEE non

- capture case is 9 percent higher than the CoP non

- capture case and 15 percent higher than the Shell non

- capture case primarily because of the large quench water requirement. However, because much of the quench water is subsequently recovered as condensate as the syngas is cooled, the raw water consumption of the GEE process is only 9 percent higher than CoP and 13 percent higher than Shell.

**•** The Shell non

- capture case has the lowest normalized water withdrawal , but is approximately equal to CoP in normalized raw water consu mption because very little water is available to recover for internal recycle in the Shell system. The GEE normalized raw water consumption is slightly higher than CoP and Shell primarily because the larger steam turbine output leads to higher cooling tow er makeup requirements.

**•** The normalized water withdrawal for the three CO 2 

## capture cases varies by only 6 percent from the highest to the lowest. The variation between cases is small because each technology requires approximately the same amount of water i n the syngas prior to the shift reactors. The difference in technologies is where and how the water is introduced. Much of the water is introduced in the quench sections of the GEE and Shell cases while steam is added in the CoP case.

**•** The normalized raw water consumption in the CO 2 

## capture cases also shows little variation with GEE the lowest, CoP only 3. 4 percent higher and Shell about 7 percent higher.

### Cost and Performance Baseline for Fossil Energy Plants

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## Exhibit 3

- 108 Raw Water Withdrawal and Consumption in IGCC Cases

0 2 4 6 8 10 12

GEE GEE w/CO2 Capture CoP CoP w/ CO2 Capture Shell Shell w/ CO2 Capture 7.6 10.7

7.0 11.1

6.6 11.3

6.0 8.7

5.5 9.0

5.3 9.3Water, gpm/MWnet Raw Water Withdrawal Process Discharge Raw Water Consumption

### Cost and Performance Baseline for Fossil Energy Plants

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## 4. Four PC fired (PC) Rankine cycle power plant configurations were evaluated and the results are presented in this section. Each design is based on a market

- ready technology that is assumed to be commercially ava ilable in time for the plant startup date. All designs employ a one

- on - one configuration comprised of a state

- of

- the art PC steam generator firing Illinois No. 6 coal and a steam turbine. PULVERIZED COAL RANK INE CYCLE PLANTS

The PC cases are evaluated with and without CO 2 

## capture on a common 550 MWe net basis. The designs that include CO 2 

## capture have a larger gross unit size to compensate for the higher auxiliary loads. The constant net output sizing basis is selected because it provides for a meaningful side

- by

- sid e comparison of the results. The boiler and steam turbine industry ability to match unit size to a custom specification has been commercially demonstrated enabling common net output comparison of the PC cases in this study. As discussed in Section 0 , this was not possible in the IGCC cases because of the fixed output from the CT . However, the net output from the PC cases falls in the range of outputs from t he IGC C cases, which average 518 MW for CO 2 

## capture cases and 625 MW for non

- capture cases. Steam conditions for the Rankine cycle cases were selected based on a survey of boiler and steam turbine original equipment manufacturers (OEM), who were asked for the mo st advanced steam conditions that they would guarantee for a commercial project in the US with subcritical and SC PC units rated at nominal 550 MWe net capacities and firing Illinois No. 6 coal [ 64

 For subcritical cases (9 and 10)

– 16.5 MPa/566°C/566°C (2 , 400 psig/1 , 050°F/1 , 050°F) ]

. Based on the OEM responses, the following single

- reheat steam conditions were selected for the study:

 For SC cases (11 and 12)

– 24.1 MPa/593°C/593°C (3 , 500 psig/1 , 100° F/1 , 100°F) While the current DOE program for the ultra SC cycle materials development targets 732°C/760°C (1 , 350oF/1 , 400oF) at 34.5 MPa (5 , 000 psi) cycle conditions to be available by 2015, and a similar Thermie program in the European Union (EU) has targe ted 700°C/720°C (1 , 292oF/1 , 328oF) at about 29.0 MPa (4 , 200 psi) [ 65 ], steam temperature selection for boilers depends upon fuel corrosiveness. Most of the contacted OEMs were of the opinion that the steam conditions in this range would be limited to low su lfur coal applications (such as PRB). Their primary concern is that elevated temperature operation while firing high sulfur coal (such as Illinois No. 6) would result in an exponential increase of the material wastage rates of the highest temperature port ions of the superheater and RH due to coal ash corrosion, requiring pressure parts replacement outages approximately every 10 or 15 years. This cost would offset the value of fuel savings and emissions reduction due to the higher efficiency. The availabi lity/reliability of the more exotic materials required to support the elevated temperature environment for high sulfur/chlorine applications, while extensively demonstrated in the laboratory [ 66 ], has not been commercially demonstrated. In addition, the th ree most recently built SC units in North America have steam cycles similar to this study’s design basis, namely Genesee Phase 3 in Canada, which started operations in 2004 (25.0 MPa/570°C/568°C [3 , 625 psia/1 , 058°F/1 , 054°F]), Council Bluffs 4 in the United States, which started operation in 2007 (25.4 MPa/566°C/593°C [3 , 690 psia/1 , 050°F/1 , 100°F]), and Oak Creek 1 and 2, which are currently under construction (24.1 MPa/566°C [3 , 500 psig/1 , 050°F]).

### Cost and Performance Baseline for Fossil Energy Plants

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## The evaluation basis details, including site ambient conditio ns, fuel composition and the emissions control basis, are provided in Section 2 of this report.
4.1 PC COMMON PROCESS AR EAS The PC cases have process areas that are common to each plant configuration , such as coal receiving and storage, emissions control technologies, power generation, etc. As detailed descriptions of these process areas in each case section would be burdensome and repetitious, they are presented in this section for general background information. The performance features of these sections are then presented in the case

- specific sections.
4.1.1 The function of the coal portion of the Coal and Sorbent Receiving and Storage system for PC plants is identi cal to the IGCC facilities. It is to provide the equipment required for unloading, conveying, preparing, and storing the fuel delivered to the plant. The scope of the system is from the trestle bottom dumper and coal receiving hoppers up to the coal stor age silos. The system is designed to support short

- term operation at the 5 percent over pressure/valves wide open (OP/VWO) condition (16 hours) and long

- term operation of 90 days or more at the maximum continuous rating (MCR). Coal and Sorbent Receiving and Storage

The scope of the sorbent rec eiving and storage system includes truck roadways, turnarounds, unloading hoppers, conveyors and the day storage bin. Operation Description

- The coal is delivered to the site by 100

- car unit trains comprised of 91 tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the coal into two receiving hoppers. Coal from each hopper is fed directly i nto a vibratory feeder. The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which transfer the coal to either the long

- term storage pile or to the reclaim area. The conveyor passes under a magnetic plate separator to remove tramp iron and then to the reclaim pile. Coal from the reclaim pile is fed by two vibratory feeders, located under the pile, onto a belt conveyor, which transfers the coal to the coal surge bin located in the crusher tower. The coal is reduced in size to 2.5 cm x 0 (1" x 0) by the coal crushers. The coal is then transferred by conveyor to the transfer tower. In the transfer tower the coal is routed to the tripper that loads the coal into one of the six boiler silos. Limestone is delivered to the site using 23 tonne (25 ton) truck s. The trucks empty into a below grade hopper where a feeder transfers the limestone to a conveyor for delivery to the storage pile. Limestone from the storage pile is transferred to a reclaim hopper and conveyed to a day bin.
4.1.2 The steam generator for the subcritical PC plants is a drum

- type, wall

- fired, balanced draft, natural circulation, totally enclosed dry bottom furnace, with superheater, reheater, economizer and air

- heater. Steam Generator and Ancilla ries

The steam generator for the SC plants is a o nce - throug h, spiral

- wound, Benson

- boiler, wall

- fired, balanced draft type unit with a water

- cooled dry bottom furnace . It includes superheater, reheater, economizer, and air heater

.

### Cost and Performance Baseline for Fossil Energy Plants

307 

## It is assumed for the purposes of this study that the power plant is desi gned to be operated as a base

- loaded unit but with some consideration for daily or weekly cycling

. The combustion systems for both subcritical and SC steam conditions are equipped with LNBs and OFA. It is assumed for the purposes of this study that the po wer plant is designed for operation as a base

- load unit.

The steam generator includes the following for both subcritical and SC PCs: Scope

 Drum

- type evaporator (subcritical only)  Economizer  OFA system

 Once

- through type steam generator ( SC only)  Spray type desuperheater  Forced draft (FD) fans

 Startup circuit, including integral separators ( SC only)  Soot blower system  Primary air (PA) fans

 Water

- cooled furnace, dry bottom  Air preheaters (Ljungstrom type)  Induced draft (ID) fans

 Two

- stage superheater  C oal feeders and pulverizers  Reheater ( RH )  Low NOx Coal burners and light oil igniters /
warm - up system The steam generator operates as follows:

For the subcritical steam system FW enters the economizer, recovers heat from the combustion gases exiting the steam generator, and then passes to the boiler drum, from where it is distributed to the water wall circuits enclosing the furnace. After passing through the lower and upper furna ce circuits and steam drum in sequence, the steam passes through the convection enclosure circuits to the primary superheater and then to the secondary superheater. Feedwater and Steam

The steam then exits the steam generator en route to the HP turbine. Steam from the HP turbine returns to the steam generator as cold reheat and returns to the IP turbine as hot reheat. For the SC steam system FW enters the bottom header of the economize r and passes upward through the economizer tube bank, through stringer tubes , which support the primary superheater, and discharges to the economizer outlet headers. From the outlet headers, water flows to the furnace hopper inlet headers via external dow ncomers. Water then flows upward through the furnace hopper and furnace wall tubes. From the furnace, water flows to the steam water separator. During low load operation (operation below the Benson point), the water from the separator is returned to the economizer inlet with the boiler recirculating pump. Operation at loads above the Benson point is once through.

### Cost and Performance Baseline for Fossil Energy Plants

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## Steam flows from the separator through the furnace roof to the convection pass enclosure walls, primary superheater, through the first stage o f water attemperation, to the furnace platens. From the platens, the steam flows through the second stage of attemperation and then to the intermediate superheater. The steam then flows to the final superheater and on to the outlet pipe terminal. Two st ages of spray attemperation are used to provide tight temperature control in all high temperature sections during rapid load changes. Steam returning from the turbine passes through the primary reheater surface, then through crossover piping containing int er - stage attemperation. The crossover piping feeds the steam to the final reheater banks and then out to the turbine. Inter

- stage attemperation is used to provide outlet temperature control during load changes.

Combustion air f rom the FD fans is heated in Ljungstrom type air preheaters, recovering heat energy from the exhaust gases exiting the boiler. This air is distributed to the burner windbox as secondary air. Air for conveying PC to the burners is supplied by the PA fans. This air is heated in the Ljungstrom type air preheaters to permit drying of the PC , and a portion of the air from the PA fans bypasses the air preheaters to be used for regulating the outlet coal/air temperature leaving the mills. Air and Combustion Products

The PC and air mixtu re flows to the coal nozzles at various elevations of the furnace. The hot combustion products rise to the top of the boiler and pass through the superheater and reheater sections. The gases then pass through the economizer and air preheater. The gases exit the steam generator at this point and flow to the SCR reactor, fabric filter, ID fan, FGD system, and stack.

The crushed Illinois No. 6 bituminous coal is fed through feeders to each of the mills (pulverizers), where its size is reduced to a pproximately 72 percent passing 200 mesh and less than 0.5 percent remaining on 50 mesh [ Fuel Feed

67 ]

. The PC exits each mill via the coal piping and is distributed to the coal nozzles in the furnace walls using air supplied by the PA fans.

The furnace bottom comprises several hoppers, with a clinker grinder under each hopper. The hoppers are of welded steel construction, lined with refractory. The hopper design incorporates a water

- filled seal trough around the upper periphery for cooling and sealing. Water and ash discharged from the hopper pass through the clinker grinder to an ash sluice system for conveyance to hydrobins, where the ash is dewatered before it is transferred to trucks for offsite disposal. The description of the balance of the bott om ash handling system is presented in Secti on Ash Removal

4.1.9

. The steam generator incorporates fly ash hoppers under the economizer outlet and air heater o utlet.

A boiler of this capacity employs approximately 24 to 36 coal nozzles arranged at multiple elevations. Each burner is designed as a low

- NOx configuration, with staging of the coal combustion to minimize NOx formation. In addition, OFA nozz les are provided to further stage combustion and thereby minimize NOx formation. Burners

### Cost and Performance Baseline for Fossil Energy Plants

309 

## Oil

- fired pilot torches are provided for each coal burner for ignition, warm

- up and flame stabilization at startup and low loads.

Each steam generator is furnis hed with two vertical

- shaft Ljungstrom regenerative type air preheaters. These units are driven by electric motors through gear reducers. Air Preheaters

The soot

- blowing system utilizes an array of 50 to 150 retractable nozzles and lances that clean the fur nace walls and convection surfaces with jets of HP steam. The blowers are sequenced to provide an effective cleaning cycle depending on the coal quality and design of the furnace and convection surfaces. Electric motors drive the soot blowers through the ir cycles. Soot Blowers

4.1.3 The plant is designed to achieve the environmental target of 0.07 lb NOx/MMBtu. Two measures are taken to reduce the NOx. The first is a combination of LNB s and the introduction of staged OFA in the boiler. The LNB s and OFA reduce the emissions to about 0.5 lb/MMBtu. NO x 

## Control System

The second measure taken to reduce the NOx emissions is the installation of an SCR system prior to the air heater. SCR uses ammonia and a catalyst to reduce NOx to N 2 

## and H 2 

## O. The SCR system consists of thre e subsystems: reactor vessel, ammonia storage and injection, and gas flow control. The SCR system is designed for 86 percent reduction with 2 ppmv ammonia slip at the end of the catalyst life. This, along with the LNB s, achieves the emission limit of 0. 07 lb/MMBtu. The SCR capital costs are included with the boiler costs, as is the cost for the initial load of catalyst. Selective non

- catalytic reduction (SNCR) was considered for this application. However, with the installation of the LNB s and OFA system , the boiler exhaust gas contains relatively small amounts of NOx, which makes removal of the quantity of NOx with SNCR to reach the emissions limit of 0.07 lb/MMBtu difficult. SNCR works better in applications that contain medium to high quantities of NO x and require removal efficiencies in the range of 40 to 60 percent. SCR, because of the catalyst used in the reaction, can achieve higher efficiencies with lower concentrations of NOx.

The reactor vessel is designed to allow pro per retention time for the ammonia to contact the NOx in the boiler exhaust gas. Ammonia is injected into the gas immediately prior to entering the reactor vessel. The catalyst contained in the reactor vessel enhances the reaction between the ammonia and the NOx in the gas. Catalysts consist of various active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxide. The operating range for vanadium/titanium

based catalysts is 260°C (500 **°** F) to 455°C (850 **°** F). The boiler is equipped w ith economizer bypass to provide FG to the reactors at the desired temperature during periods of low flow rate, such as low load operation. Also included with the reactor vessel is soot

- blowing equipment used for cleaning the catalyst. SCR Operation Description

The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, dilution air skid, and injection grid.

### Cost and Performance Baseline for Fossil Energy Plants

310 

## The FG flow control consists of ductwork, dampers, and flow straightening devices required to route the boiler exhaust to the SCR reactor and then to the air heater. The economizer bypass and associated dampers for low load temperature control are also included.
4.1.4 The fabric filter (or baghouse) consists of two separate single

- stage, in

- line, multi

- compartment units. Each unit is of high (0.9

- 1.5 m/min [3

- 5 ft/min]) air

- to

- cloth ratio design with a pulse

- jet
on - line cleaning system. The ash is collected on the outside of the bags, which are supported by steel cages. The dust cake is removed by a pulse of comp ressed air. The bag material is polyphenylensulfide (PPS) with intrinsic Teflon Polytetrafluoroethylene (PTFE) coating [ Particulate Control

68

4.1.5 ]

. The bags are rated for a continuous temperature of 180°C (356°F) and a peak temperature of 210°C (410°F). Each compartment contai ns a number of gas passages with filter bags, and heated ash hoppers supported by a rigid steel casing. The fabric filter is provided with necessary control devices, inlet gas distribution devices, insulators, inlet and outlet nozzles, expansion joints, a nd other items as required.

Mercury removal is based on a coal Hg content of 0.15 ppmd. The basis for the coal Hg concentration was discussed in Section Mercury Removal

2.4 . The combination of pollution control technologies used in the PC plants, SCR, fabric filters and FGD, result in significant co

- benefit capture of mercury. The SCR promotes the oxidation of elemental mercury, which in turn enhances the mercury removal capability of the fabric filter and FGD unit. The mercury co

- benefit capture is assumed to be 90 percent for this combination of control technologies as described in Section 2.4. Co

- benefit c apture alone is sufficient to meet current NSPS mercury limits so no activated carbon injection is included in the PC cases.
4.1.6 The FGD system is a wet limestone forced oxidation positive pressure absorber non

- reheat unit, with wet

- st ack, and gypsum production. The function of the FGD system is to scrub the boiler exhaust gases to remove the SO 2 

## prior to release to the environment, or entering into the Carbon Dioxide Removal (CDR) facility. Sulfur removal efficiency is 98 percent in the FGD unit for all cases. For Cases 10 and 12 with CO 2 

## capture, the SO 2 

## content of the scrubbed gases must be further reduced to approximately 10 ppmv to minimize formation of amine heat stable salts ( HSS ) during the CO 2 

## absorption process. The CDR uni t includes a polishing scrubber to reduce the FG SO 2 

## concentration from about 44 ppmv at the FGD exit to the required 10 ppmv prior to the CDR absorber. The scope of the FGD system is from the outlet of the ID fans to the stack inlet (Cases 9 and 11) or t o the CDR process inlet (Cases 10 and 12). The system description is divided into three sections: Flue Gas Desulfurization

**•** Limestone Handling and Reagent Preparation

**•** FGD Scrubber

**•** Byproduct Dewatering

### Cost and Performance Baseline for Fossil Energy Plants

311 

## The function of the limestone reagent preparation sys tem is to grind and slurry the limestone delivered to the plant. The scope of the system is from the day bin up to the limestone feed system. The system is designed to support continuous base load operation. Reagent Preparation System

Operation Description

- Each day bin supplie s a 100 percent capacity ball mill via a weigh feeder. The wet ball mill accepts the limestone and grinds the limestone to 90 to 95 percent passing 325 mesh (44 microns). Water is added at the inlet to the ball mill to create limestone slurry. The reduc ed limestone slurry is then discharged into a mill slurry tank. Mill recycle pumps, two per tank, pump the limestone water slurry to an assembly of hydrocyclones and distribution boxes. The slurry is classified into several streams, based on suspended so lids content and size distribution. The hydrocyclone underflow with oversized limestone is directed back to the mill for further grinding. The hydrocyclone overflow with correctly sized limestone is routed to a reagent storage tank. Reagent distribution pumps direct slurry from the tank to the absorber module.

The FG exiting the air preheater section of the boiler passes through one of two parallel fabric filter units, then through the ID fans and into the one 100 percent capacity absorber mo dule. The absorber module is designed to operate with counter

- current flow of gas and reagent. Upon entering the bottom of the absorber vessel, the gas stream is subjected to an initial quenching spray of reagent. The gas flows upward through the spray zone, which provides enhanced contact between gas and reagent. Multiple spray elevations with header piping and nozzles maintain a consistent reagent concentration in the spray zone. Continuing upward, the reagent

laden gas passes through several levels of moisture separators. These consist of chevron

- shaped vanes that direct the gas flow through several abrupt changes in direction, separating the entrained droplets of liquid by inertial effects. The scrubbed FG exits at the top of the absorber vessel a nd is routed to the plant stack or CDR process. FGD Scrubber

The scrubbing slurry falls to the lower portion of the absorber vessel, which contains a large inventory of liquid. Oxidation air is added to promote the oxidation of calcium sulfite contained in the slurry to calcium sulfate (gypsum). Multiple agitators operate continuously to prevent settling of solids and enhance mixture of the oxidation air and the slurry. Recirculation pumps recirculate the slurry from the lower portion of the absorber vessel to the sp ray level. Spare recirculation pumps are provided to ensure availability of the absorber. The absorber chemical equilibrium is maintained by continuous makeup of fresh reagent, and blowdown of byproduct solids via the bleed pumps. A spare bleed pump is p rovided to ensure availability of the absorber. The byproduct solids are routed to the byproduct dewatering system. The circulating slurry is monitored for pH and density. This FGD system is designed for wet stack operation. Scrubber bypass or reheat, w hich may be utilized at some older facilities to ensure the exhaust gas temperature is above the saturation temperature, is not employed in this reference plant design because new scrubbers have improved mist eliminator efficiency, and detailed flow modeli ng of the flue interior enables the placement of gutters and drains to intercept moisture that may be present and convey it to a drain. Consequently, raising the exhaust gas temperature above the FGD discharge temperature of 57°C (135°F) (non

- CO 2 

## capture cases) or 32°C (89°F) (CO 2 

## capture cases) is not necessary.

### Cost and Performance Baseline for Fossil Energy Plants

312 

## The function of the byproduct dewatering system is to dewater the bleed slurry from the FGD absorber modules. The dewatering process selected for this plant is gypsum dewater ing producing wallboard grade gypsum. The scope of the system is from the bleed pump discharge connections to the gypsum storage pile. Byproduct Dewatering

Operation Description

- The recirculating reagent in the FGD absorber vessel accumulates dissolved and suspended solid s on a continuous basis as byproducts from the SO 2 

## absorption process. Maintenance of the quality of the recirculating slurry requires that a portion be withdrawn and replaced by fresh reagent. This is accomplished on a continuous basis by the bleed pump s pulling off byproduct solids and the reagent distribution pumps supplying fresh reagent to the absorber. Gypsum (calcium sulfate) is produced by the injection of oxygen into the calcium sulfite produced in the absorber tower sump. The bleed from the absorber contains approximately 20 wt% gypsum. The absorber slurry is pumped by an absorber bleed pump to a primary dewatering hydrocyclone cluster. The primary hydrocyclone performs two process functions. The first function is to dewater the slurry fro m 20 wt% to 50 wt% solids. The second function of the primary hydrocyclone is to perform a CaCO 3 

## and CaSO 4 

## •2H 2 

## O separation. This process ensures a limestone stoichiometry in the absorber vessel of 1.10 and an overall limestone stoichiometry of 1.05. This system reduces the overall operating cost of the FGD system. The underflow from the hydrocyclone flows into the filter feed tank, from which it is pumped to a horizontal belt vacuum filter. Two 100 percent filter systems are provided for redundant
c apacity.

The hydrocyclone is a simple and reliable device (no moving parts) designed to increase the slurry concentration in one step to approximately 50 wt%. This high slurry concentration is necessary to optimize operation of the vacuum be lt filter. Hydrocyclones

The hydrocyclone feed enters tangentially and experiences centrifugal motion so that the heavy particles move toward the wall and flow out the bottom. Some of the lighter particles collect at the center of the cyclone and flow out the top. The underflow is thus concentrated from 20 wt% at the feed to 50 wt%. Multiple hydrocyclones are used to process the bleed stream from the absorber. The hydrocyclones are configured in a cluster with a common feed header. The system has two hydrocyclone clu sters, each with five 15 cm (6 inch) diameter units. Four cyclones are used to continuously process the bleed stream at design conditions, and one cyclone is spare. Cyclone overflow and underflow are collected in separate launders. The overflow from the hydrocyclones still contains about 5 wt% solids, consisting of gypsum, fly ash, and limestone residues and is sent back to the absorber. The underflow of the hydrocyclones flows into the filter feed tank from where it is pumped to the horizontal belt vacu um filters.

The secondary dewatering system consists of horizontal vacuum belt filters. The pre

concentrated gypsum slurry (50 wt%) is pumped to an overflow pan through which the slurry flows onto the vacuum belt. As the va cuum is pulled, a layer of cake is formed. The cake is Horizontal Vacuum Belt Filters

### Cost and Performance Baseline for Fossil Energy Plants

313 

## dewatered to approximately 90 wt% solids as the belt travels to the discharge. At the discharge end of the filter, the filter cloth is turned over a roller where the solids are dislodged from the fil ter cloth. This cake falls through a chute onto the pile prior to the final byproduct uses. The required vacuum is provided by a vacuum pump. The filtrate is collected in a filtrate tank that provides surge volume for use of the filtrate in grinding the limestone. Filtrate that is not used for limestone slurry preparation is returned to the absorber.
4.1.7 A Carbon Dioxide Recovery (CDR) facility is used in Cases 10 and 12 to remove 90 percent of the CO 2 

## in the flue gas exitin g the FGD unit, purify it, and compress it to a SC condition. The flue gas exiting the FGD unit contains about 1 percent more CO 2 

## than the raw flue gas because of the CO 2 

## liberated from the limestone in the FGD absorber vessel. The CDR is comprised of th e flue gas supply, SO 2 

## polishing, CO 2 

## absorption, solvent stripping and reclaiming, and CO 2 

## compression and drying. Carbon Dioxide Recovery Facility

The CO 2 

## absorption/stripping/solvent reclaim process for Cases 10 and 12 is based on the Fluo r Econamine FG Plus SM 

## technology [ 69 , 70 Exhibit 4

- 1 ]

. A typ ical flowsheet is shown in

. The Econamine FG Plus process uses a formulation of MEA and a proprietary corrosion inhibitor to recover CO 2 

## from the flue gas . This process is designed to recover high

- purity CO 2 

## from LP streams that contain oxygen, such as flue gas from coal

- fired power plants, GT exhaust gas, and other waste gases. The Econamine process used in this study differs from previous studies, in cluding the 200 3 IEA study, [ 71

**•** The complexity of the control and operation of the plant is significantly decreased ] in the following ways:

**•** Solvent consumption is decreased

**•** Hard to dispose waste from the plant is greatly reduced The above are achieved at th e expense of a slightly higher steam requirement in the stripper (3,556 kJ/kg ) [1,530 Btu/lb] versus 3,242 kJ/kg [1,395 Btu/lb] used in the IEA study) [ 72 ]

.

### Cost and Performance Baseline for Fossil Energy Plants

314 

## Exhibit 4

- 1 Fluor Econamine FG Plus SM 

## Typical Flow Diagram

### Cost and Performance Baseline for Fossil Energy Plants

315 

## To minimize the accumulation of HSS , the incoming flue gas must have an SO 2 

## concentration of 10 ppmv or less. The gas exiting the FGD system passes through an SO 2 

## polishing step to achieve this objective. The polishing step consists of a non

- plugging, low

- differential

- pressure, spray - baffle

- type scrubber using a 20 wt% solution of sodium hydroxide (NaOH). A removal efficiency of about 75 percent is necessary to r educe SO 2 

## emissions from the FGD outlet to 10 ppmv as required by the Econamine process. The polishing scrubber proposed for this application has been demonstrated in numerous industrial applications throughout the world and can achieve removal efficienci es of over 95 percent if necessary. SO 2 

## Polishing and FG Cooling and Supply

The polishing scrubber also serves as the flue gas cooling system. Cooling water from the PC plant is used to reduce the flue gas temperature to below the adiabatic saturation temperature resulting in a reduction of the flue gas moisture content. Flue gas is cooled beyond the CO 2 

## absorption process requirements to 32°C (90°F) to account for the subsequent temperature increase of about 17°C (30°F) in the flue gas blower. Downstream from the Polishing Scrubber flue gas p ressure is boosted in the FG Blowers by approximately 0.014 MPa (2 psi) to overcome pressure drop in the CO 2 

## absorber tower.

Cooling water is provided from the PC plant CWS and returned to the PC plant cooling tower. The CDR facil ity requires a significant amount of cooling water for flue gas cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO 2 

## compression interstage cooling. The cooling water requirements f or the CDR facility in the two PC capture cases range from 1, 173,350

- 1, 286,900 lpm ( 310,000

- 340 ,000 gpm), which greatly exceeds the PC plant cooling water requirement of 643 , 450

- 757 , 00 0 lpm ( 170 ,000

- 2 0 0,000 gpm). Circulating Water System

The cooled flue gas enters the bottom of the CO 2 

## Absorber and flows up through the tower countercurrent to a stream of lean MEA

- based solvent. Approximately 90 percent of the CO 2 

## in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber section , absorbs the CO 2 

## from the FG and leaves the bottom of the absorber with the absorbed CO 2 

## . The FG Plus process also includes solvent interc ooling. The semi

- rich solvent is extracted from the column, cooled using cooling water, and returned to the absorber section just below the extraction point. The CO 2 

## carrying capacity of the solvent is increased at lower temperature, which reduces the so lvent circulation rate. CO 2 

## Absorption Section

The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The flue gas from the top of the CO 2 

## Absorption section is contacted with a re

- circulating stream of water for the removal of most of the lean solvent. The scrubbed gases, along with unrecovered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collec ted on a chimney tray. A portion of the water collected on the chimney tray spills over to Water Wash Section

### Cost and Performance Baseline for Fossil Energy Plants

316 

## the absorber section as water makeup for the amine with the remainder pumped via the Wash Water Pump , cooled by the Water Wash Cooler, and recirculated to the top o f the CO 2 

## Absorber. The wash water level is maintained by wash water makeup.

The rich solvent from the bottom of the CO 2 

## Absorber is preheated by the lean solvent from the Solvent Stripper in the Lean/Rich Cross Excha nger. The heated rich solvent is routed to the Solvent Stripper for removal of the absorbed CO 2 

## . The stripped solvent from the bottom of the Solvent Stripper is pumped via the Lean Solvent Pump to the Lean Solvent Cooler. A slipstream of the lean solven t is then sent through the Amine Filter Package to prevent buildup of contaminants in the solution. The filtered lean solvent is mixed with the remaining lean solvent from the Lean Solvent Cooler and sent to the CO 2 

## Absorber , completing the circulating so lvent circuit. Rich/Lean Amine Heat Exchange System

The purpose of the Solvent Stripper is to separate the CO 2 

## from the rich solvent feed exiting the bottom of the CO 2 

## Absorber. The rich solvent is collected on a chimney tray below the bottom packed section of the Stripper a nd routed to the Reboiler where the rich solvent is heated by steam, stripping the CO 2 

## from the solution. Steam is provided from the crossover pipe between the IP and LP sections of the steam turbine and is 0.5 MPa ( 74 psia) and 152 °C ( 306 °F) for the two PC cases. The hot wet vapor from the top of the stripper containing CO 2 

## , steam, and solvent vapor, is partially condensed in the Reflux Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to the Re flux Drum where the vapor and liquid are separated. The uncondensed CO 2 

## - rich gas is then delivered to the CO 2 

## product compressor . The condensed liquid from the Reflux Drum is pumped via the Reflux Pump where a portion of condensed overhead liquid is combi ned with the lean solvent entering the CO 2 

## Absorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system. Solvent Stripper

The low temp erature reclaimer technology is a recent development for the FG Plus technology. A small slipstream of the lean solvent is fed to the Solvent Reclaimer for the removal of high

boiling nonvolatile impurities including HSS, volatile acids and iron products from the circulating solvent solution. Reclaiming occurs in two steps, the first is an ion

- exchange process. There is a small amount of degradation products that cannot be removed via ion

- exchange, and a second atmospheric pressure reclaiming process is used to remove the degradation products. The solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank for disposal

. The quantity of spent solvent is greatly reduced from the previously used thermal reclaimer systems. Solvent Reclaimer

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Re claimer Condensate Drum and is level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Steam Condensate

### Cost and Performance Baseline for Fossil Energy Plants

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## Condensate Drum and returned to the steam cycle between BFW heaters 4 a nd 5 via the Solvent Reboiler Condensate Pumps

.
A proprietary corrosion inhibitor is intermittently injected into the CO 2 

## Absorber rich solvent bottoms outlet line. This additive is to help control the rate of corrosion througho ut the CO 2 

## recovery plant system. Corrosion Inhibitor System

In the compression section, the CO 2 

## is compressed to 15.3 MPa (2,215 psia) by a six

- stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable po wer distribution and discharge temperatures across the various stages as shown in Gas Compression and Drying System

Exhibit 4

- 2

. Exhibit 4

- 2 CO 2 

## Compressor Interstage Pressures Stage Outlet Pressure, MPa (psia) 1 0.36 (52) 2 0.78 (113) 3 1.71 (248) 4 3.76 (545) 5 8.27 (1,200) 6 15.3 (2,215)

Power consumption for this large compr essor was estimated assuming a polytropic efficie ncy of 86 percent and a mechanical efficiency of 98 percent for all stages . During compression to 15.3 MPa (2,215 psia) in the multiple

- stage, intercooled compressor, the CO 2 

## stream is dehydrated to a dewpoint of

- 40oC (

- 40°F) with triethylene glycol. The virtual ly moisture

- free SC CO 2 

## stream is delivered to the plant battery limit as sequestration ready. CO 2 

## TS&M costs were estimated and included in LCOE and COE using the methodology described in Section 2.7. Several alternatives to rejecting the heat of CO 2 

## compression to cooling water were investigated in a separ ate study [ 73 ]

. The first alternative consisted of using a portion of the heat to pre

- heat BFW while the remaining heat was still rejected to cooling water. This configuration resulted in an increa se in efficiency of 0.3 percentage points (absolute). The second alternative modified the CO 2 

## compression intercooling configuration to enable integration into a LiBr

- H 2 

## O absorption refrigeration system, where water is the refrigerant. In the CO 2 

## compres sion section, the single intercooler between each compression stage was replaced with one kettle reboiler and two counter current shell and tube heat exchangers. The kettle reboiler acts as the generator that rejects heat from CO 2 

## compression to the LiBr

- H 2 

## O solution to enable the separation of the refrigerant from the brine solution. The second heat exchanger rejects heat to the cooling water. The evaporator heat exchanger acts as the refrigerator and cools the CO 2 

## compression stream by vaporizing the r efrigerant. Only five stages of CO 2 

## compression were necessary for Approach 2. The compression ratios were increased from the reference cases to create a compressor outlet

### Cost and Performance Baseline for Fossil Energy Plants

318 

## temperature of at least 200°F to maintain a temperature gradient of 10°F in the ke ttle reboiler. This configuration resulted in an efficiency increase of 0.1 percentage points (absolute). It was concluded that the small increase in efficiency did not justify the added cost and complexity of the two configurations and hence they were no t incorporated into the base design.
4.1.8 The steam turbine is designed for long

- term operation (90 days or more) at MCR with throttle control valves 95 percent open. It is also capable of a short

- term 5 percent OP/VWO condition (16 hours). Power Generation

For the subcritical cases, the steam turbine is a tandem compound type, consisting of HP

- IP

- two LP (double flow) sections enclosed in three casings, designed for condensing single reheat operation, and equipped with non

- automatic extractions and four

- flow exhaust. The turbine drives a hydrogen

- cooled generator. The turbine has DC motor

- operated lube oil pumps, and main lube oil pumps, which are driven off the turbine shaft [ 74

The steam

- turbine generator systems for the SC plants are similar in design to the subcritical systems. The differences inclu de steam cycle conditions and eight extractions points versus seven for the subcritical design. ]

. The exhaust pressure is 50.8 cm (2 in) Hg in the single pressure condenser. There are seven extraction points. The condenser is two

- shell, transverse, single pressure with divided waterbox for each shell.

Turbine bearings are lubricated by a closed

- loop , water

- cooled pressurized oil system. Turbine shafts are sealed against air in

- leakage or steam blowout using a labyrinth gland arrangement connected to a LP steam seal system. The generator stator is cooled with a CL water system consisting of circulating pumps, shell and tube or plate and frame type heat exchangers, filters, and deionizers, all skid

- mounted. T he generator rotor is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft

. Operation Description

- The turbine stop valves, control valves, reheat stop valves, and intercept valves are controlled by an electro

- hydraulic control system. Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 16.5 MPa/566°C (2 , 400 psig/1 , 050oF) for the subcritical cases and 24.1MPa /593°C (3 , 500psig/1 , 100° F ) for the SC cases. The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to the boiler for reheating. The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 566°C (1 , 0 50oF) in the subcritical cases and 593°C (1 , 100°F) in the SC cases. After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the two LP sections. The steam divides into four paths and flows through the LP sec tions exhausting downward into the condenser. The turbine is designed to operate at constant inlet steam pressure over the entire load range.
4.1.9 The balance of plant components consist of the condensate, FW , main and reheat steam, extractio n steam, ash handling, ducting and stack, waste treatment and miscellaneous systems as described below. Balance of Plant

### Cost and Performance Baseline for Fossil Energy Plants

319 

## The function of the condensate system is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser an d the LP FW heaters. Each system consists of one main condenser; two variable speed electric motor

- driven vertical condensate pumps each sized for 50 percent capacity; one gland steam condenser; four LP heaters; and one deaerator with storage tank. Condensate

Conden sate is delivered to a common discharge header through two separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation line discharging to the condenser is provided downstream of the gland steam condenser t o maintain minimum flow requirements for the gland steam condenser and the condensate pumps. LP FW heaters 1 through 4 are 50 percent capacity, parallel flow, and are located in the condenser neck. All remaining FW heaters are 100 percent capacity shell a nd U

- tube heat exchangers. Each LP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. LP FW heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the condenser. Pneumatic le vel control valves control normal drain levels in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Pneumatic level control valves control dump line flow.

The function of the FW system is to pump the FW from the deaerator storage tank through the HP FW heaters to the economizer. One turbine

- driven BFW pump sized at 100 percent capacity is provided to pump FW through the HP FW heaters. One 25 percent motor

- driven BFW pump is provided for startup. The pumps are provided with inlet and outlet isolation valves, and individual minimum flow recirculation lines discharging back to the deaerator storage tank. The recirculation flow is controlled by automatic rec irculation valves, which are a combination check valve in the main line and in the bypass, bypass control valve, and flow sensing element. The suction of the boiler feed pump is equipped with startup strainers, which are utilized during initial startup an d following major outages or system maintenance. Feedwater

Each HP FW heater is provided with inlet/outlet isolation valves and a full capacity bypass. FW heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the deaera tor. Pneumatic level control valves control normal drain level in the heaters. High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection. Dump line flow is controlled by pneumatic level control valves. The deaerator is a horizontal, spray tray type with internal direct contact stainless steel (SS) vent condenser and storage tank. The boiler feed pump turbine is driven by main steam up to 60 percent plant load. Above 60 percent load, ex traction from the IP turbine exhaust (1.05 MPa/395°C [153 psig/743°F]) provides steam to the boiler feed pump steam turbine.

The function of the main steam system is to convey main steam from the boiler superheater outlet to the HP tu rbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the IP turbine stop valves. Main and Reheat Steam

### Cost and Performance Baseline for Fossil Energy Plants

320 

## Main steam exits the boiler superheater through a motor

- operated stop/check valve and a motor

operated gate valve and is routed in a single line feeding the HP turbine. A branch line off the IP turbine exhaust feeds the boiler feed water pump turbine during unit operation starting at approximately 60 percent load. Cold reheat steam exits the HP turbine, flows through a motor

- operated isolation gate valve and a flow control valve, and enters the boiler reheater. Hot reheat steam exits the boiler reheater through a motor

- operated gate valve and is routed to the IP turbin e. A branch connection from the cold reheat piping supplies steam to FW heater 7.

The function of the extraction steam system is to convey steam from turbine extraction points through the following routes: Extraction Steam

 From HP turbine exhaust (cold reheat) to heater 7  From IP turbine extraction to heater 6 and the deaerator (heater 5)  From LP turbine extraction to heaters 1, 2, 3, and 4 The turbine is protected from overspeed on turbine trip, from flash steam reverse flow from the heaters through the extraction piping to the turbine. This protection is provided by positive closing, balanced disc non

- return valves located in all extractio n lines except the lines to the LP FW heaters in the condenser neck. The extraction non

- return valves are located only in horizontal runs of piping and as close to the turbine as possible. The turbine trip signal automatically trips the non

- return valves through relay dumps. The remote manual control for each heater level control system is used to release the non

- return valves to normal check valve service when required to restart the system.

It is assumed that the plant is servic ed by a public water facility and has access to groundwater for use as makeup cooling water with minimal pretreatment. All filtration and treatment of the circulating water are conducted on site. A mechanical draft, wood frame, counter

- flow cooling tower is provided for the circulating water heat sink. Two 50 percent CWP s are provided. The CWS provides cooling water to the condenser, the auxiliary cooling water system, and the CDR facility in capture cases. Circulating Water System

The auxiliary cooling water system is a CL sys tem. Plate and frame heat exchangers with circulating water as the cooling medium are provided. This system provides cooling water to the lube oil coolers, turbine generator, boiler feed pumps, etc. All pumps, vacuum breakers, air release valves, instru ments, controls, etc. are included for a complete operable system. The CDR system in Cases 10 and 12 requires a substantial amount of cooling water that is provided by the PC plant CWS . The additional cooling load imposed by the CDR is reflected in the si gnificantly larger CWP s and cooling tower in those cases.

The function of the ash handling system is to provide the equipment required for conveying, preparing, storing, and disposing of the fly ash and bottom ash produced on a daily ba sis by the boiler. The scope of the system is from the baghouse hoppers, air heater and economizer hopper Ash Handling System

### Cost and Performance Baseline for Fossil Energy Plants

321 

## collectors, and bottom ash hoppers to the hydrobins (for bottom ash) and truck filling stations (for fly ash). The system is designed to support sho rt

- term operation at the 5 percent OP/VWO condition (16 hours) and long

- term operation at the 100 percent guarantee point (90 days or more). The fly ash collected in the baghouse and the air heaters is conveyed to the fly ash storage silo. A pneumatic tr ansport system using LP air from a blower provides the transport mechanism for the fly ash. Fly ash is discharged through a wet unloader, which conditions the fly ash and conveys it through a telescopic unloading chute into a truck for disposal. The bottom ash from the boiler is fed into a clinker grinder. The clinker grinder is provided to break up any clinkers that may form. From the clinker grinders the bottom ash is sluiced to hydrobins for dewatering and offsite removal by truck. Ash from the e conomizer hoppers and pyrites (rejected from the coal pulverizers) is conveyed using water to the economizer/pyrites transfer tank. This material is then sluiced on a periodic basis to the hydrobins.

One stack is provided with a single f iberglass

- reinforced plastic (FRP) liner. The stack is constructed of reinforced concrete. The stack is 152 m (500 ft) high for adequate particulate dispersion. Ducting and Stack

An onsite water treatment facility treats all runoff, c leaning wastes, blowdown, and backwash to within the U.S. EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals. Waste treatment equipment is housed in a separate building. The waste treatment system consists of a water collect ion basin, three raw waste pumps, an acid neutralization system, an oxidation system, flocculation, clarification/thickening, and sludge dewatering. The water collection basin is a synthetic

- membrane

- lined earthen basin, which collects rainfall runoff, ma intenance cleaning wastes, and backwash flows. Waste Treatment/Miscellaneous Systems

The raw waste is pumped to the treatment system at a controlled rate by the raw waste pumps. The neutralization system neutralizes the acidic wastewater with hydrated lime in a two

- stage system, consisting of a lime storage silo/lime slurry makeup system, dry lime feeder, lime slurry tank, slurry tank mixer, and lime slurry feed pumps. The oxidation system consists of an air compressor, which injects air through a sparger pipe into the second

- stage neutralizat ion tank. The flocculation tank is fiberglass with a variable speed agitator. A polymer dilution and feed system is also provided for flocculation. The clarifier is a plate

- type, with the sludge pumped to the dewatering system. The sludge is dewatered in filter presses and disposed offsite. Trucking and disposal costs are included in the cost estimate. The filtrate from the sludge dewatering is returned to the raw waste sump. Miscellaneous systems consisting of fuel oil, service air, instrument air, a nd service water are provided. A storage tank provides a supply of No. 2 fuel oil used for startup and for a small auxiliary boiler. Fuel oil is delivered by truck. All truck roadways and unloading stations inside the fence area are provided.

### Cost and Performance Baseline for Fossil Energy Plants

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## Foundations are provided for the support structures, pumps, tanks, and other plant components. The following buildings are included in the design basis: Buildings and Structures

 Steam turbine building  Fuel oil pump house  Guard house  Boiler building  Coal crusher building  Runoff water pump house  Administration and service building  Continuous emissions monitoring building  Industrial waste treatment building  Makeup water and pretreatment building  Pump house and electrical equipment building  FGD system buildings

4.1.10 The accessory electric plant consists of switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, and wire and cable. It also includes the main power transformer, required foundati ons, and standby equipment. Accessory Electric Plant

4.1.11 An integrated plant

- wide control and monitoring DCS is provided. The DCS is a redundant microprocessor

- based, functionally distributed system. The control room houses an array of multiple video moni tor and keyboard units. The monitor/keyboard units are the primary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to p rovide 99.5 percent availability. The plant equipment and the DCS are designed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are implemented as supervised manual, with operator selection of modular automation routines available. Instrumentation and Control

4.2 SUBCRITICAL PC CASES This section contains an evaluation of plant designs for Cases 9 and 10 , which are based on a subcritical PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 16.5 MPa/566°C/5 66°C (2400 psig/1050 **°** F/1050 **°** F) cycle. The only difference between the two plants is that Case 10 includes CO 2 

## capture while Case 9 does not. The balance of Section 4.2 is organized as follows:

**•** Process and System Description provides an overview of the technology operation as applied to Case 9. The systems that are common to all PC cases were covered in Section 4.1 and only features that are unique to Case 9 are discussed further in this section.

**•** Key Assumptions is a summary of study and modeling assumptions relevant to Cases 9 and 10.

**•** Sparing Philosophy is provided for both C ases 9 and 10.

### Cost and Performance Baseline for Fossil Energy Plants

323 

## • Performance Results provides the main modeling results from Case 9, including the performance summary, environmental performance, carbon/sulfur balances, water balance, mass and energy balance diagrams and energy balance table.

**•** Equipment Lis t provides an itemized list of major equipment for Case 9 with account codes that correspond to the cost accounts in the Cost Estimates section.

**•** Cost Estimates provides a summary of capital and operating costs for Case 9.

**•** Process and System Description, Pe rformance Results, Equipment List and Cost Estimates are discussed for Case 10.
4.2.1 In this section the subcritical PC process without CO 2 

## capture is described. The system description follows the BFD in Process Description

Exhibit 4

- 3 and stream numbers reference the same Exhibit. The tables in Exhibit 4

- 4 provide process data for th e numbered streams in the BFD. Coal (stream 8 ) and PA (stream 4) are introduced into the boiler through the wall

- fired burners. Additional combustion air, including the OFA , is provided by the FD fans (stream 1 ). The boiler operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is accounted for in stream 7

. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD and PA fan outlet streams to the boiler exha ust. FG exits the boiler thr ough the SCR reactor (stream 10) and is cooled to 169°C (337 °F) in the comb ustion air preheater before passing through a fabric filter fo r particulate removal (stream 12 ). An ID fan increases the FG temperature to 181°C (357 °F) and provides the motive f orce for the FG (stream 13 ) to pass through the FGD unit. FGD inputs and outputs include makeup water (stream 15), oxidation air (stream 16), limestone slurry (stream 14) and product gypsum (stream 17 ). The clean, saturated FG e xiting the FGD unit (stream 18 ) passes to the plant stack and is discharged to atmosphere.

### Cost and Performance Baseline for Fossil Energy Plants

324 

## Exhibit 4

- 3 Case 9 Block Flow Diagram, Subcritical Unit without CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

325 

## Exhibit 4

- 4 Case 9 Stream Table, Subcritical Unit without CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1447 0.0000 0.1447 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0868 0.0000 0.0868 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7325 0.0000 0.7325 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0250 0.0000 0.0250 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 51,817 51,817 1,535 15,918 15,918 2,191 1,195 0 0 72,904 0 72,904 V-L Flowrate (kg/hr) 1,495,285 1,495,285 44,287 459,336 459,336 63,217 34,480 0 0 2,168,255 0 2,168,255 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 198,391 3,848 15,390 15,390 0
Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 Enthalpy (kJ/kg) A 

### 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 327.06

--- 308.70 Density (kg/m 3 

### ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- 0.8

--- 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- 29.741

--- 29.741
V-L Flowrate (lb mol 

### /hr) 114,237 114,237 3,383 35,092 35,092 4,830 2,634 0 0 160,726 0 160,726 V-L Flowrate (lb/hr) 3,296,540 3,296,540 97,637 1,012,663 1,012,663 139,369 76,015 0 0 4,780,183 0 4,780,183 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 437,378 8,482 33,929 33,929 0
Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 Enthalpy (Btu/lb) A 

### 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- 140.6

--- 132.7 Density (lb/ft 3 

### ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- 0.050

--- 0.049 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

326 

## Exhibit 4

- 4 Case 9 Stream Table, Subcritical Unit without CO 2 

## Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 V-L Mole Fraction

Ar 0.0087 0.0000 0.0000 0.0128 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1447 0.0000 0.0000 0.0005 0.0004 0.1350 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0868 1.0000 1.0000 0.0062 0.9995 0.1517 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 

### 0.7325 0.0000 0.0000 0.7506 0.0000 0.6808 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0250 0.0000 0.0000 0.2300 0.0000 0.0243 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 72,904 2,530 10,275 775 188 79,300 93,366 85,851 85,851 76,805 77,739 V-L Flowrate (kg/hr) 2,168,255 45,571 185,106 22,509 3,383 2,287,903 1,682,017 1,546,628 1,546,628 1,383,663 1,400,483 Solids Flowrate (kg/hr) 0 19,690 0 0 30,645 0 0 0 0 0 0
Temperature (°C) 181 15 15 167 57 57 566 363 566 38 39 Pressure (MPa, abs) 0.11 0.10 0.10 0.31 0.10 0.10 16.65 4.28 3.90 0.01 1.69 Enthalpy (kJ/kg) A 

### 320.79

--- -46.80 177.65

--- 297.69 3,472.33 3,120.82 3,594.06 2,016.19 165.31 Density (kg/m 3 

### ) 0.8

--- 1,003.1 2.5

--- 1.1 47.7 15.7 10.3 0.1 993.3 V-L Molecular Weight 29.741

--- 18.015 29.029

--- 28.851 18.015 18.015 18.015 18.015 18.015
V-L Flowrate (lb mol 

### /hr) 160,726 5,577 22,652 1,709 414 174,826 205,837 189,269 189,269 169,326 171,384 V-L Flowrate (lb/hr) 4,780,183 100,467 408,090 49,625 7,459 5,043,963 3,708,212 3,409,730 3,409,730 3,050,454 3,087,536 Solids Flowrate (lb/hr) 0 43,410 0 0 67,561 0 0 0 0 0 0
Temperature (°F) 357 59 59 333 135 135 1,050 686 1,050 101 103 Pressure (psia) 15.3 15.0 14.7 45.0 14.8 14.8 2,415.0 620.5 565.5 1.0 245.0 Enthalpy (Btu/lb) A 

### 137.9

--- -20.1 76.4

--- 128.0 1,492.8 1,341.7 1,545.2 866.8 71.1 Density (lb/ft 3 

### ) 0.052

--- 62.622 0.154

--- 0.067 2.977 0.983 0.643 0.004 62.010

### Cost and Performance Baseline for Fossil Energy Plants

327 

## 4.2.2 System assumptions for Cases 9 and 10 , subcritical PC with and without CO 2 

## capture, are compiled in Key System Assumptions

Exhibit 4

- 5

. Exhibit 4

- 5 Subcritical PC Plant Study Configuration Matrix Case 9 w/o CO 2 

## Capture Case 10 w/CO 2 

## Capture Steam Cycle , MPa/°C/°C ( psig /°F/°F) 16.5/566/566 ( 2400 /1050/1050) 16.5/566/566 ( 2400 /1050/1050) Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg ( in Hg ) 50.8 ( 2 ) 50.8 ( 2 ) Boiler Efficiency , % 8 8 8 8 Cooling water to condenser, °C (oF) 16 (60) 16 (60) Cooling water from condenser, °C (oF) 27 (80) 27 (80) Stack temperature, °C (°F) 57 (135) 32 (89)
SO 2 

## Control Wet Limestone Forced Oxidation Wet Limestone Forced Oxidation FGD E fficiency , % (A) 98 98 (B , C ) NOx Control LNB w/OFA and SCR LNB w/OFA and SCR SCR Efficiency, % (A) 86 86 Ammonia Slip (end of catalyst life), ppmv 2 2 Particulate Control Fabric Filter Fabric Filter Fabric Filter efficiency, % (A) 99.8 99.8 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20% Mercury Control Co

- benefit Capture Co

- benefit Capture Mercury removal efficiency, % (A) 90 90 CO 2 

## Control N/A Econamine Overall CO 2 

## Capture (A) N/A 90 .2 %
CO 2 

## Sequestration N/A Off

- site Saline Formation A. Removal efficiencies are based on the FG content B. An SO 2 

### polishing step is included to meet more stringent SOx content limits in the FG (< 10 ppmv) to reduce formation of amine HSS during the CO 2 

### absorption process C. SO 2 

### exiting the post

- FGD polishing step is absorbed in the CO 2 

### capture process making stack emiss ions negligible



## The balance of plant assumptions are common to all cases and are presented in Balance of Plant

– Cases 9 and 10 Exhibit 4

- 6

.

### Cost and Performance Baseline for Fossil Energy Plants

328 

## Exhibit 4

- 6 Balance of Plant Assumptions Recirculating Wet Cooling Tower Cooling system Fuel and Other storage Coal 30 days Ash 30 days Gypsum 30 days Limestone 30 days Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt Motors between 250 hp and 5,000 hp 4,160 volt Motors above 5,000 hp 13,800 volt Steam and GT generators 24,000 volt Grid Interconnection voltage 345 kV Water and Waste Water Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater , and is assumed to be in sufficient quantities to meet plant makeup requirements

. Makeup for potable, process, and DI water is drawn from municipal sources

. Process Wastewater Storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge. Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant is sized for 5.68 cubic meters per day (1,500 gallons per day) Water Discharge Most of the process wastewater is recycled to the cooling tower basin. Blowdown will be treated for chloride and metals, and discharged.

### Cost and Performance Baseline for Fossil Energy Plants

329 

## 4.2.3 Single trains are used throughout the design with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems: Sparing Philosophy

**•** One dry

- bottom, wall

- fired PC subcritical boiler (1 x 100%)

**•** Two SCR reactors (2 x 50%)

**•** Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50%)

**•** One wet limestone forced oxidation positive pressure absorber (1 x 100%)

**•** One steam turbine (1 x 100%)

**•** For Case 10 only, two parallel Econamine CO 2 

## absorption systems, with each system consisting of two absorbers, stripp ers and ancillary equipment (2 x 50%)

4.2.4 The plant produces a net output of 550 MWe at a net plant efficiency of 3 6

. 8 percent (HHV basis). Overall performance for the plant is summarized in Case 9 Performance Results

Exhibit 4

- 7 , which include s auxiliary power requirements.

### Cost and Performance Baseline for Fossil Energy Plants

330 

## Exhibit 4

- 7 Case 9 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminal s, kWe) Steam Turbine Power 582,600 TOTAL (STEAM TURBINE) POWER, kWe 582,600 AUXILIARY LOAD SUMMARY, kWe Coal Handling and Conveying 450 Pulverizers 2,970 Sorbent Handling & Reagent Preparation 950 Ash Handling 570 Primary Air Fans 1,400 Forced Draft Fans 1,780 Induced Draft Fans 7,540 SCR 50 Baghouse 70 Wet FGD 3,180 Miscellaneous Balance of Plant 2,3 

## 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 890 Circulating Water Pump 5,250 Ground Water Pumps 530 Cooling Tower Fans 2,720 Transformer Losses 1,830 TOTAL AUXILIARIES, kWe 32,580 NET POWER, kWe 550, 0 2 0 Net Plant Efficiency (HHV) 3 6

. 8 % Net Plant Heat Rate , kJ/kWh (Btu/kWh) 9,7 88 (9, 277 ) CONDENSER COOLING DUTY 10 6 

## kJ /h r (10 6 

## Btu /h r ) 2,566 (2,432) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 198,391 ( 437,378 ) Limestone Sorbent Feed, kg/h r (lb/h r ) 19, 691 (43, 410 ) Thermal Input, kWt 1 

## 1,495,379 Raw Water Withdrawal, m 3 

## /min (gpm) 22.3 (5,89 6 ) Raw Water Consumption, m 3 

## /min (gpm) 17.7 (4,6 80 )
1. HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2. Boiler feed pumps are turbine driven 3. Includes plant control systems, lighting, HVAC , and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

331 

## The environmental targets for emissions of Hg, N Ox, SO 2 , 

## and PM were presented in Section 2.4. A summary of the plant air emissions for Case 9 is presented in Environmental Performance

Exhibit 4

- 8

. Exhibit 4

- 8 Case 9 Air Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)

SO 2 

## 0.037 (0.086) 1,479 (1,630) 0.341 (.75) NOx 0.030 (0.070) 1,206 (1,330) 0.278 (.613) Particulates 0.006 (0.0130) 224 (247) 0.052 (.114)
Hg 4.91E

- 7 (1.14E

- 6) 0.020 (0.022) 4.54E

- 6 (1.00E

- 5)

CO 2 

## 87.5 (203.5) 3,507,605 (3,866,472) 809 (1,783)

CO 2 1 

## 856 (1,888)

1 

### CO 2 

### emissions based on net power instead of gross power


## SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. The wallboa rd grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated FG exiting the scrubber is vented through the plant stack. NOx emissions are controlled to ab out 0.5 lb/10 6 

## Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 

## Btu. Particulate emissions are controlled using a pulse jet fabric filter , which operates at an efficiency of 99.8 perc ent. Co

- benefit capture results in a 90 percent reduction of mercury emissions. CO 2 

## emissions represent the uncontrolled discharge from the process. The carbon balance for the plant is shown in Exhibit 4

- 9

. The carbon input to the plant consists of carbon in the coal , carbon in the air , and carbon in the limestone reagent used in the FGD

. Carbon in the air is not neglected here since the Aspen model ac counts for air components throughout. Carbon leaves the plant mostly as CO 2 

## through the stack but also leaves as gypsum.

### Cost and Performance Baseline for Fossil Energy Plants

332 

## Exhibit 4

- 9 Case 9 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 126,464 (278,805) Stack Gas 128,563 (283,434) Air (CO 2 

## ) 275 (607) FGD Product 174 (383) FGD Reagent 1,998 (4,405) Total 128,737 (283,817) Total 128,737 (283,817)

Exhibit 4

- 10 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum and sulfur emitted in the stack gas. Exhibit 4

- 10 Case 9 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 4,973 (10,963) Stack Gas 99 (219) FGD Product 4,873 (10,743) Total 4,973 (10,963) Total 4,973 (10,963)

Exhibit 4

- 11 shows the water balance for Case 9. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and is re

used as interna l recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as FDG makeup, BFW makeup, and cooling tower makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source.

### Cost and Performance Baseline for Fossil Energy Plants

333 

## Exhibit 4

- 11 Case 9 Water Balance

Water Use Water Demand,

m 3 

## /min (gpm) Internal Recycle, m 3 

## /min (gpm) Raw Water Withdrawal,
m 3 

## /min (gpm) Process Water Discharge,

m 3 

## /min (gpm) Raw Water Consumption,
m 3 

## /min (gpm)

FGD Makeup 3.9 (1,017) 0.0 (0) 3.9 (1,017) 0.0 (0) 3.9 (1,017) BFW Makeup 0.3 (74) 0.0 (0) 0.3 (74) 0.0 (0) 0.3 (74) Cooling Tower 20.5 (5,404) 2.3 (600) 18.2 (4,804) 4.6 (1,215) 13.6 (3,589)
Total 24.6 (6,495) 2.3 (600) 22.3 (5,896) 4.6 (1,215) 17.7 (4,680)

A heat and mass balance diagram is shown for the Case 9 PC boiler, the FGD unit , and steam cycle as shown in Heat and Mass Balance Diagrams

Exhibit 4

- 12 and Exhibit 4

- 13

. An overall plant energy balance is provided in tabular form in Exhibit 4

- 14 . The pow er out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4

- 7 ) is calculated by multiplying the power out b y a generator efficiency of 98.6 percent.

### Cost and Performance Baseline for Fossil Energy Plants

334 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

335 

## Exhibit 4

- 12 Case 9 Heat and Mass Balance, Subcritical PC Boiler without CO 2 

## Capture

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal /Ash Slurry

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 1 OF 2 B ITUMINOUS B ASELINE S TUDY C ASE 9 S UBCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- 9

- PG

- 1 

### Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR

COAL ASH From Feedwater Heaters Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

437 , 378 W 77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 3 , 708 , 212 W 1 , 050

. 0 T 2 , 415

. 0 P 1 , 492

. 8 H

3 , 409 , 730 W

1 , 050

. 0 T

565

. 5 P 1 , 545

. 2 H

Single Reheat Extraction from

HP Turbine

1 , 012 , 663 W 59

. 0 T 14

. 7 P 13

. 0 H 3 , 296 , 540 W 59

. 0 T 14

. 7 P 13

. 0 H 76 , 015 W

59

. 0 T 14

. 7 P 13

. 0 H 4 , 814 , 113 W 337

. 0 T 14

. 4 P 140

. 6 H

8 , 482 W 33 , 929 W

3 , 409 , 730 W 686

. 0 T 620

. 5 P 1 , 341

. 7 H

3 , 708 , 212 W 484

. 4 T 3 , 100

. 5 P

469

. 5 H 5 5 , 043 , 963 W 135

. 0 T 14

. 8 P 128

. 0 H

1 2

4 7

9 ID FANS 4 , 780 , 183 W 337

. 0 T 14

. 2 P 132

. 7 H

Gross Plant Power : 583 MWe Auxiliary Load : 33 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 36

. 8 % Net Plant Heat Rate : 9 , 277 BTU / KWe Lime /Ash
Flue Gas OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15

14 11 357

. 4 T 15

. 3 P 137

. 9 H

143 , 877 W 59

. 0 T 15

. 0 P 49 , 625 W 332

. 9 T 45

. 0 P 408 , 090 W 59

. 0 T 14

. 7 P

75 , 020 W 135

. 0 T 14

. 8 P 

### Baghouse

3

6

8 10 12 13 16

17

18 19

20 21

DOE / NETL
SC PC P LANT C ASE 9

### Cost and Performance Baseline for Fossil Energy Plants

336 

## Exhibit 4

- 13 Case 9 Heat and Mass Balance, Subcritical Steam Cycle

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 2 OF 2 DWG

. NO

. BB

- HMB

- CS

- 9

- PG

- 2 B ITUMINOUS B ASELINE S TUDY C ASE 9 S UBCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL

P

- 1028 P

- 1048 To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam

Single Reheat

Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 3 , 708 , 212 W

1 , 050

. 0 T 2 , 415

. 0 P 1 , 492

. 8 H

226 , 208 W 915

. 9 T 323

. 0 P 1 , 480

. 7 H 254 , 026 W

682

. 6 T 589

. 7 P 1 , 341

. 7 H 3 , 409 , 730 W 686

. 0 T 620

. 5 P 1 , 341

. 7 H620.5P620.5P620.5P350.5P167.7P167.7P 154 , 414 W 734

. 9 T 164

. 3 P 1 , 393

. 4 H

154 , 414 W 126

. 1 T

2

. 0 P 1 , 097

. 1 H 2 , 388 , 619 W 101

. 1 T

1

. 0 P 1 , 017

. 1 H

2 , 793 W 212

. 0 T 14

. 7 P 179

. 9 H64.2P41.6P11.8P

101

. 4 T 250

. 0 P 70

. 0 H 2 , 793 W 712

. 8 T 167

. 7 P 1 , 381

. 9 H 3 , 087 , 536 W 101

. 1 T

1

. 0 P 69

. 1 H

3 , 087 , 536 W 102

. 5 T 245

. 0 P 71

. 1 H 3 , 087 , 536 W 152

. 8 T 240

. 0 P 121

. 2 H

501 , 326 W 112

. 5 T

1

. 4 P 80

. 4 H 370 , 446 W

162

. 8 T

5

. 1 P 130

. 6 H 3 , 087 , 536 W 284

. 7 T 220

. 0 P 253

. 9 H

480 , 234 W

364

. 6 T 323

. 0 P 337

. 0 H 3 , 087 , 536 W 257

. 7 T 230

. 0 P 226

. 5 H

254 , 026 W

436

. 2 T 366

. 7 P 414

. 3 H

3 , 708 , 212 W 426

. 2 T 3 , 105

. 5 P 406

. 0 H

DEAERATOR

BOILER FEED PUMPS 3 , 708 , 212 W 484

. 4 T 3 , 100

. 5 P 469

. 5 H 3 , 409 , 730 W

1 , 050

. 0 T 565

. 5 P 1 , 545

. 2 H

80 , 030 W 267

. 7 T 40

. 3 P 236

. 3 H 267 , 224 W 200

. 5 T 11

. 7 P 168

. 3 H

3 , 087 , 536 W 190

. 5 T 235

. 0 P 158

. 8 H 177 , 524 W

728

. 1 T 130

. 0 P 1 , 391

. 5 H 80 , 030 W 524

. 8 T 57

. 3 P 1 , 294

. 9 H 187 , 193 W 439

. 2 T 37

. 1 P 1 , 255

. 2 H 103 , 223 W 228

. 6 T 10

. 5 P 1 , 159

. 5 H 130 , 880 W 157

. 8 T

4

. 5 P 1 , 120

. 2 H2,415.0P 3 , 037 , 555 W 734

. 9 T 164

. 3 P 1 , 393

. 4 H 2 , 883 , 141 W 734

. 9 T 164

. 3 P 1 , 393

. 4 H5.0P Steam Turbine Makeup

354

. 6 T 3 , 110

. 5 P 330

. 9 H 3 , 708 , 212 W 347

. 3 T 130

. 0 P 318

. 5 H 3 , 301 W 712

. 8 T 167

. 7 P 1 , 381

. 9 H

Gross Plant Power : 583 MWe Auxiliary Load : 33 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 36

. 8 % Net Plant Heat Rate : 9 , 277 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 6 , 805 W 712

. 8 T 167

. 7 P 1 , 381

. 9 H 19

23

DOE / NETL
SC PC P LANT C ASE 92,415.0P

211,850.0P

Single Reheat Extraction to

Boiler

20 3 , 442 , 057 W 1 , 048

. 6 T 565

. 5 P 1 , 544

. 4 H

37 , 082 W 59

. 0 T 14

. 7 P 27

. 1 H

### Cost and Performance Baseline for Fossil Energy Plants

337 

## Exhibit 4

- 14 Case 9 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,383 (5,102) 4.5 (4.3) 5,388 (5,107) Air 60.1 (57.0) 60.1 (57.0) Raw Water Withdrawal 84.0 (79.6) 84.0 (79.6) Limestone 0.22 (0.21) 0.22 (0.21) Auxiliary Power 117 (111) 117 (111) Totals 5,383 (5,102) 148.8 (141.1) 117 (111) 5,649 (5,355) Heat Out GJ/hr (MMBtu/hr) Bottom Ash 0.5 (0.4) 0.5 (0.4) Fly Ash + FGD Ash 1.9 (1.8) 1.9 (1.8) Flue Gas 681 (646) 681 (646) Condenser 2,566 (2,432) 2,566 (2,432) Cooling Tower Blowdown 34.2 (32.4) 34.2 (32.4) Process Losses* 269 (255) 269 (255) Power 2,097 (1,988) 2,097 (1,988) Totals 0 (0) 3,552 (3,367) 2,097 (1,988) 5,649 (5,355) * Process losses are estimated to match the heat input to the plant. Process losses include

losses from: turbines, gas cooling, etc.

### Cost and Performance Baseline for Fossil Energy Plants

338 

## 4.2.5 Major equipment items for the subcritical PC plant with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 9

– Major Equipment List

4.2.6 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 COAL AND SORBENT HAN DLING Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 163 tonne/hr (180 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 327 tonne/hr (360 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 163 tonne (180 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 327 tonne/hr (360 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 327 tonne/hr (360 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 726 tonne (800 ton) 3 0

19 Limestone Truck Unloading Hopper N/A 36 tonne (40 ton) 1 0
20 Limestone Feeder Belt 82 tonne/hr (90 tph) 1 0 21 Limestone Conveyor No. L1 Belt 82 tonne/hr (90 tph) 1 0 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0 23 Limestone Reclaim Feeder Belt 64 tonne/hr (70 tph) 1 0 24 Limestone Conveyor No. L2 Belt 64 tonne/hr (70 tph) 1 0 25 Limestone Day Bin w/ actuator 263 tonne (290 ton) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

33 9 

## ACCOUNT 2 COAL AND SORBENT PRE PARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or equivalent 36 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 22 tonne/hr (24 tph) 1 1
4 Limestone Ball Mill Rotary 22 tonne/hr (24 tph) 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 83,279 liters (22,000 gal) 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1,401 lpm @ 12m H2O (370 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 341 lpm (90 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1
9 Limestone Slurry Storage Tank with Agitator Field erected 469,391 liters (124,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 984 lpm @ 9m H2O (260 gpm @ 30 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

340 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,112,911 liters (294,000 gal) 2 0

2 Condensate Pumps Vertical canned 25,741 lpm @ 213 m H2O (6,800 gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage Tank Horizontal spray type 1,850,203 kg/hr (4,079,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed Pump/Turbine Barrel type, multi-stage, centrifugal 31,040 lpm @ 2,530 m H2O (8,200 gpm @ 8,300 ft H2O) 1 1

5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multi-stage, centrifugal 9,085 lpm @ 2,530 m H2O (2,400 gpm @ 8,300 ft H2O) 1 0

6 LP Feedwater Heater 1A/1B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 771,107 kg/hr (1,700,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1,850,657 kg/hr (4,080,000 lb/hr) 1 0
11 HP Feedwater Heater 7 Horizontal U-tube 1,850,657 kg/hr (4,080,000 lb/hr) 1 0

12 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

13 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

14 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

16 Closed Cycle Cooling Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

18 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1

19 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1

20 Raw Water Pumps Stainless steel, single suction 6,549 lpm @ 18 m H2O (1,730 gpm @ 60 ft H2O) 2 1

21 Ground Water Pumps Stainless steel, single suction 2,612 lpm @ 268 m H2O (690 gpm @ 880 ft H2O) 5 1

22 Filtered Water Pumps Stainless steel, single suction 2,006 lpm @ 49 m H2O (530 gpm @ 160 ft H2O) 2 1

23 Filtered Water Tank Vertical, cylindrical 1,919,204 liter (507,000 gal) 1 0

24 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 606 lpm (160 gpm) 1 1

25 Liquid Waste Treatment System -- 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

341 

## ACCOUNT 4 BOILER AND ACCESSORI ES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Boiler Subcritical, drum wall-fired, low NOx burners, overfire air 1,850,657 kg/hr steam @ 17.9 MPa/574°C/574°C (4,080,000 lb/hr steam @ 2,600 psig/1,065°F/1,065°F) 1 0

2 Primary Air Fan Centrifugal 252,651 kg/hr, 3,446 m3/min @ 123 cm WG (557,000 lb/hr, 121,700 acfm @ 48 in. WG) 2 0

3 Forced Draft Fan Centrifugal 822,363 kg/hr, 11,222 m3/min @ 47 cm WG (1,813,000 lb/hr, 396,300 acfm @ 19 in. WG) 2 0

4 Induced Draft Fan Centrifugal 1,192,494 kg/hr, 25,114 m3/min @ 91 cm WG (2,629,000 lb/hr,

886,900 acfm @ 36 in. WG) 2 0

5 SCR Reactor Vessel Space for spare layer 2,385,896 kg/hr (5,260,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air Blower Centrifugal 142 m3/min @ 108 cm WG (5,000 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 155,202 liter (41,000 gal) 5 0

9 Ammonia Feed Pump Centrifugal 30 lpm @ 91 m H2O (8 gpm @ 300 ft H2O) 2 1

### Cost and Performance Baseline for Fossil Energy Plants

342 

## ACCOUNT 5 FLUE GAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE/A CCESSORIES N/A Equipment No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter Single stage, highratio with pulse-jet online cleaning system 1,192,494 kg/hr (2,629,000 lb/hr) 99.8% efficiency 2 0

2 Absorber Module Counter-current open spray 47,912 m3/min (1,692,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 166,558 lpm @ 64 m H2O (44,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 4,240 lpm (1,120 gpm) at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 84 m3/min @ 0.3 MPa (2,960 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 1,060 lpm (280 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 34 tonne/hr (37 tph) of 50 wt % slurry 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 644 lpm @ 12 m H2O (170 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 416,395 lpm (110,000 gal) 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 3,407 lpm @ 21 m H2O (900 gpm @ 70 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

343 

## ACCOUNT 7 HRSG, DUCTING & STA CK

ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x 5.8 m (19 ft) diameter 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 613 MW 16.5 MPa/566°C/566°C (2400.3 psig/ 1050°F/1050°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 680 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum pumps 2,828 GJ/hr (2,680 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 526,200 lpm @ 30 m (139,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

/ 2944 GJ/hr (2790 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

344 

## ACCOUNT 10 ASH/SPENT SORBENT RE COVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- -- 2 0

3 Clinker Grinder

-- 4.5 tonne/hr (5 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 151 lpm @ 17 m H2O (40 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1

9 Hydrobins

-- 151 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- -- 10 0

12 Air Blower

-- 16 m3/min @ 0.2 MPa (550 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced concrete 998 tonne (1,100 ton) 2 0

14 Slide Gate Valves

-- -- 2 0
15 Unloader

-- -- 1 0

16 Telescoping Unloading Chute

-- 91 tonne/hr (100 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

345 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3- ph, 60 Hz 1 0

2 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 34 MVA, 3- ph, 60 Hz 1 1

3 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

346 

## 4.2.6 The cost estimating methodology was described previously in Section 2.6. Case 9

– Cost Estimating Exhibit 4

- 15 shows the total plant capital cost summary organized by cost account and Exhibit 4

- 16 shows a more detailed breakdown of the capital costs along with owner’s costs, TOC and TASC

. Exhibit 4

- 17 shows the initial and annual O&M costs. The estimated TO C of the subcritical PC boiler with no CO 2 

## capture is $1, 996 /kW. No process contingency is included in this case because all elements of the technology are commercially proven. The project contingency is 9.1 percent of the TOC. The COE is 59

. 4 mills/kWh

.

### Cost and Performance Baseline for Fossil Energy Plants

347 

## Exhibit 4

- 15 Case 9 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 9 - 1x550 MWnet SubCritical PC Plant Size: 550 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $17,068 $4,598 $10,229 $0 $0 $31,895 $2,862 $0 $5,214 $39,970 $73

2 COAL & SORBENT PREP & FEED $11,494 $665 $2,916 $0 $0 $15,075 $1,321 $0 $2,459 $18,855 $34

3 FEEDWATER & MISC. BOP SYSTEMS $39,707 $0 $19,059 $0 $0 $58,766 $5,391 $0 $10,518 $74,674 $136

4 PC BOILER 4.1 PC Boiler & Accessories $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486

5 FLUE GAS CLEANUP $83,799 $0 $28,488 $0 $0 $112,287 $10,747 $0 $12,303 $135,338 $246

5B CO 2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71 SUBTOTAL 7 $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $49,912 $0 $6,242 $0 $0 $56,154 $5,380 $0 $6,153 $67,688 $123 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $23,604 $1,092 $12,657 $0 $0 $37,354 $3,294 $0 $5,668 $46,316 $84 SUBTOTAL 8 $73,516 $1,092 $18,900 $0 $0 $93,508 $8,674 $0 $11,822 $114,004 $207

9 COOLING WATER SYSTEM $13,230 $6,710 $12,250 $0 $0 $32,189 $3,030 $0 $4,784 $40,003 $73

10 ASH/SPENT SORBENT HANDLING SYS $4,573 $145 $6,114 $0 $0 $10,833 $1,042 $0 $1,222 $13,096 $24

11 ACCESSORY ELECTRIC PLANT $17,808 $6,355 $18,529 $0 $0 $42,692 $3,765 $0 $5,747 $52,203 $95

12 INSTRUMENTATION & CONTROL $8,665 $0 $8,786 $0 $0 $17,451 $1,582 $0 $2,338 $21,371 $39

13 IMPROVEMENTS TO SITE $2,974 $1,710 $5,995 $0 $0 $10,679 $1,054 $0 $2,347 $14,079 $26

14 BUILDINGS & STRUCTURES $0 $23,479 $22,248 $0 $0 $45,727 $4,125 $0 $12,463 $62,315 $113

TOTAL COST $425,899 $45,804 $252,606 $0 $0 $724,309 $68,082 $0 $100,043 $892,433 $1,622 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

348 

## Exhibit 4

- 16 Case 9 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,508 $0 $1,602 $0 $0 $5,110 $457 $0 $835 $6,402 $12 1.2 Coal Stackout & Reclaim $4,533 $0 $1,027 $0 $0 $5,561 $487 $0 $907 $6,954 $13 1.3 Coal Conveyors $4,215 $0 $1,016 $0 $0 $5,231 $458 $0 $853 $6,543 $12 1.4 Other Coal Handling $1,103 $0 $235 $0 $0 $1,338 $117 $0 $218 $1,673 $3 1.5 Sorbent Receive & Unload $140 $0 $42 $0 $0 $183 $16 $0 $30 $229 $0 1.6 Sorbent Stackout & Reclaim $2,269 $0 $416 $0 $0 $2,685 $234 $0 $438 $3,357 $6 1.7 Sorbent Conveyors $810 $175 $199 $0 $0 $1,183 $102 $0 $193 $1,479 $3 1.8 Other Sorbent Handling $489 $115 $257 $0 $0 $860 $76 $0 $140 $1,077 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $4,308 $5,435 $0 $0 $9,743 $915 $0 $1,599 $12,257 $22 SUBTOTAL 1. $17,068 $4,598 $10,229 $0 $0 $31,895 $2,862 $0 $5,214 $39,970 $73 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,014 $0 $393 $0 $0 $2,407 $210 $0 $393 $3,009 $5 2.2 Coal Conveyor to Storage $5,158 $0 $1,126 $0 $0 $6,284 $549 $0 $1,025 $7,858 $14 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $3,857 $166 $801 $0 $0 $4,824 $420 $0 $787 $6,031 $11 2.6 Sorbent Storage & Feed $465 $0 $178 $0 $0 $643 $57 $0 $105 $805 $1 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $499 $419 $0 $0 $917 $85 $0 $150 $1,153 $2 SUBTOTAL 2. $11,494 $665 $2,916 $0 $0 $15,075 $1,321 $0 $2,459 $18,855 $34 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $16,257 $0 $5,611 $0 $0 $21,868 $1,915 $0 $3,567 $27,351 $50 3.2 Water Makeup & Pretreating $4,751 $0 $1,529 $0 $0 $6,280 $594 $0 $1,375 $8,248 $15 3.3 Other Feedwater Subsystems $5,318 $0 $2,248 $0 $0 $7,566 $678 $0 $1,237 $9,480 $17 3.4 Service Water Systems $931 $0 $507 $0 $0 $1,438 $135 $0 $315 $1,888 $3 3.5 Other Boiler Plant Systems $6,259 $0 $6,179 $0 $0 $12,438 $1,181 $0 $2,043 $15,662 $28 3.6 FO Supply Sys & Nat Gas $256 $0 $320 $0 $0 $575 $54 $0 $94 $724 $1 3.7 Waste Treatment Equipment $3,221 $0 $1,836 $0 $0 $5,057 $492 $0 $1,110 $6,659 $12 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,715 $0 $829 $0 $0 $3,544 $341 $0 $777 $4,662 $8 SUBTOTAL 3. $39,707 $0 $19,059 $0 $0 $58,766 $5,391 $0 $10,518 $74,674 $136 4 PC BOILER & ACCESSORIES 4.1 PC Boiler & Accessories $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $134,824 $0 $86,704 $0 $0 $221,527 $21,582 $0 $24,311 $267,420 $486

### Cost and Performance Baseline for Fossil Energy Plants

349 

## Exhibit 4

- 16 Case 9 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $58,362 $0 $12,564 $0 $0 $70,926 $6,762 $0 $7,769 $85,456 $155 5.2 Other FGD $3,046 $0 $3,451 $0 $0 $6,497 $631 $0 $713 $7,840 $14 5.3 Bag House & Accessories $16,493 $0 $10,467 $0 $0 $26,959 $2,598 $0 $2,956 $32,513 $59 5.4 Other Particulate Removal Materials $1,116 $0 $1,194 $0 $0 $2,310 $224 $0 $253 $2,788 $5 5.5 Gypsum Dewatering System $4,783 $0 $812 $0 $0 $5,595 $533 $0 $613 $6,741 $12 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $83,799 $0 $28,488 $0 $0 $112,287 $10,747 $0 $12,303 $135,338 $246 5B CO 2 REMOVAL & COMPRESSION 5B.1 CO 2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO 2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5B. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $9,097 $0 $5,845 $0 $0 $14,942 $1,303 $0 $2,437 $18,682 $34 7.4 Stack $9,145 $0 $5,351 $0 $0 $14,496 $1,396 $0 $1,589 $17,481 $32 7.9 Duct & Stack Foundations $0 $1,049 $1,192 $0 $0 $2,241 $210 $0 $490 $2,941 $5 SUBTOTAL 7. $18,242 $1,049 $12,388 $0 $0 $31,679 $2,908 $0 $4,516 $39,104 $71 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $49,912 $0 $6,242 $0 $0 $56,154 $5,380 $0 $6,153 $67,688 $123 8.2 Turbine Plant Auxiliaries $348 $0 $746 $0 $0 $1,094 $107 $0 $120 $1,321 $2 8.3 Condenser & Auxiliaries $7,251 $0 $2,295 $0 $0 $9,545 $913 $0 $1,046 $11,504 $21 8.4 Steam Piping $16,005 $0 $7,891 $0 $0 $23,896 $2,008 $0 $3,886 $29,790 $54 8.9 TG Foundations $0 $1,092 $1,726 $0 $0 $2,818 $267 $0 $617 $3,701 $7 SUBTOTAL 8. $73,516 $1,092 $18,900 $0 $0 $93,508 $8,674 $0 $11,822 $114,004 $207

### Cost and Performance Baseline for Fossil Energy Plants

350 

## Exhibit 4

- 16 Case 9 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $9,783 $0 $3,046 $0 $0 $12,829 $1,227 $0 $1,406 $15,461 $28 9.2 Circulating Water Pumps $2,033 $0 $128 $0 $0 $2,161 $182 $0 $234 $2,578 $5 9.3 Circ.Water System Auxiliaries $531 $0 $71 $0 $0 $602 $57 $0 $66 $725 $1 9.4 Circ.Water Piping $0 $4,210 $4,080 $0 $0 $8,290 $776 $0 $1,360 $10,427 $19 9.5 Make-up Water System $462 $0 $618 $0 $0 $1,080 $103 $0 $177 $1,361 $2 9.6 Component Cooling Water Sys $421 $0 $335 $0 $0 $755 $72 $0 $124 $951 $2 9.9 Circ.Water System Foundations & Structures $0 $2,500 $3,972 $0 $0 $6,471 $612 $0 $1,417 $8,500 $15 SUBTOTAL 9. $13,230 $6,710 $12,250 $0 $0 $32,189 $3,030 $0 $4,784 $40,003 $73 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $612 $0 $1,885 $0 $0 $2,497 $245 $0 $274 $3,017 $5 10.7 Ash Transport & Feed Equipment $3,961 $0 $4,058 $0 $0 $8,019 $767 $0 $879 $9,664 $18 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $145 $171 $0 $0 $317 $30 $0 $69 $416 $1 SUBTOTAL 10. $4,573 $145 $6,114 $0 $0 $10,833 $1,042 $0 $1,222 $13,096 $24 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,602 $0 $260 $0 $0 $1,862 $173 $0 $153 $2,187 $4 11.2 Station Service Equipment $2,904 $0 $954 $0 $0 $3,858 $361 $0 $316 $4,535 $8 11.3 Switchgear & Motor Control $3,339 $0 $567 $0 $0 $3,906 $362 $0 $427 $4,695 $9 11.4 Conduit & Cable Tray $0 $2,093 $7,238 $0 $0 $9,331 $903 $0 $1,535 $11,769 $21 11.5 Wire & Cable $0 $3,950 $7,625 $0 $0 $11,575 $975 $0 $1,882 $14,432 $26 11.6 Protective Equipment $270 $0 $918 $0 $0 $1,188 $116 $0 $130 $1,434 $3 11.7 Standby Equipment $1,279 $0 $29 $0 $0 $1,308 $120 $0 $143 $1,571 $3 11.8 Main Power Transformers $8,414 $0 $172 $0 $0 $8,587 $652 $0 $924 $10,162 $18 11.9 Electrical Foundations $0 $312 $765 $0 $0 $1,077 $103 $0 $236 $1,416 $3 SUBTOTAL 11. $17,808 $6,355 $18,529 $0 $0 $42,692 $3,765 $0 $5,747 $52,203 $95 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $446 $0 $267 $0 $0 $713 $67 $0 $117 $898 $2 12.7 Distributed Control System Equipment $4,504 $0 $787 $0 $0 $5,291 $491 $0 $578 $6,360 $12 12.8 Instrument Wiring & Tubing $2,442 $0 $4,844 $0 $0 $7,285 $621 $0 $1,186 $9,092 $17 12.9 Other I & C Equipment $1,273 $0 $2,888 $0 $0 $4,161 $403 $0 $456 $5,021 $9 SUBTOTAL 12. $8,665 $0 $8,786 $0 $0 $17,451 $1,582 $0 $2,338 $21,371 $39

### Cost and Performance Baseline for Fossil Energy Plants

351 

## Exhibit 4

- 16 Case 9 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $50 $1,000 $0 $0 $1,050 $104 $0 $231 $1,385 $3 13.2 Site Improvements $0 $1,660 $2,061 $0 $0 $3,721 $367 $0 $818 $4,906 $9 13.3 Site Facilities $2,974 $0 $2,933 $0 $0 $5,908 $582 $0 $1,298 $7,788 $14 SUBTOTAL 13. $2,974 $1,710 $5,995 $0 $0 $10,679 $1,054 $0 $2,347 $14,079 $26 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,519 $7,491 $0 $0 $16,010 $1,439 $0 $4,362 $21,811 $40 14.2 Turbine Building $0 $12,310 $11,473 $0 $0 $23,784 $2,144 $0 $6,482 $32,409 $59 14.3 Administration Building $0 $587 $621 $0 $0 $1,208 $110 $0 $329 $1,647 $3 14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $302 $27 $0 $82 $411 $1 14.5 Water Treatment Buildings $0 $603 $549 $0 $0 $1,152 $104 $0 $314 $1,570 $3 14.6 Machine Shop $0 $393 $264 $0 $0 $657 $58 $0 $179 $893 $2 14.7 Warehouse $0 $266 $267 $0 $0 $533 $48 $0 $145 $727 $1 14.8 Other Buildings & Structures $0 $217 $185 $0 $0 $403 $36 $0 $110 $548 $1 14.9 Waste Treating Building & Str. $0 $416 $1,263 $0 $0 $1,680 $159 $0 $460 $2,299 $4 SUBTOTAL 14. $0 $23,479 $22,248 $0 $0 $45,727 $4,125 $0 $12,463 $62,315 $113

TOTAL COST $425,899 $45,804 $252,606 $0 $0 $724,309 $68,082 $0 $100,043 $892,433 $1,622
Owner's Costs Preproduction Costs 6 Months All Labor $7,104 $13 1 Month Maintenance Materials $859 $2 1 Month Non-fuel Consumables $956 $2 1 Month Waste Disposal $251 $0 25% of 1 Months Fuel Cost at 100% CF $1,524 $3 2% of TPC $17,849 $32 Total $28,543 $52 Inventory Capital 60 day supply of fuel and consumables at 100% CF $13,824 $25 0.5% of TPC (spare parts) $4,462 $8 Total $18,287 $33
Initial Cost for Catalyst and Chemicals $0 $0 Land $900 $2 Other Owner's Costs $133,865 $243

Financing Costs $24,096 $44 Total Overnight Costs (TOC) $1,098,124 $1,996 TASC Multiplier (IOU, low-risk, 35 year) 1.134 Total As-Spent Cost (TASC) $1,245,272 $2,264

### Cost and Performance Baseline for Fossil Energy Plants

352 

## Exhibit 4

- 17 Case 9 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 9 - 1x550 MWnet SubCritical PC Heat Rate-net (Btu/kWh): 9,276 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 14.0 14.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,524,319 $10.043 Maintenance Labor Cost $5,842,145 $10.621 Administrative & Support Labor $2,841,616 $5.166 Property Taxes and Insurance $17,848,664 $32.449 TOTAL FIXED OPERATING COSTS $32,056,744 $58.280 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $8,763,218 $0.00214

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,245.12 1.08 $0 $1,424,619 $0.00035

Chemicals MU & WT Chem.(lbs) 0 20,549 0.17 $0 $1,103,371 $0.00027 Limestone (ton) 0 521 21.63 $0 $3,496,290 $0.00085 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,249.89 $0 $0 $0.00000 NaOH (tons) 0 0 433.68 $0 $0 $0.00000 H2SO4 (tons) 0 0 138.78 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 Activated Carbon (lb) 0 0 1.05 $0 $0 $0.00000 Ammonia (19% NH3) ton 0 78 129.80 $0 $3,136,289 $0.00077 Subtotal Chemicals $0 $7,735,950 $0.00189

Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.33 5,775.94 $0 $592,641 $0.00014 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $592,641 $0.00014
Waste Disposal Fly Ash (ton) 0 407 16.23 $0 $2,049,540 $0.00050 Bottom Ash (ton) 0 102 16.23 $0 $512,385 $0.00013 Subtotal-Waste Disposal $0 $2,561,926 $0.00063 By-products & Emissions Gypsum (tons) 0 811 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $21,078,354 $0.00515 Fuel (ton) 0 5,248 38.18 $0 $62,175,757 $0.01518

### Cost and Performance Baseline for Fossil Energy Plants

353 

## 4.2.7 The plant configuration for Case 10, subcritical PC, is the same as Case 9 with the exception that the Econamine technology was added for CO 2 

## capture. The nominal net output was maintained at 550 MW by increasing the boiler size and turbine/generator size to accoun t for the greater auxiliary load imposed by the CDR facility. Unlike the IGCC cases where gross output was fixed by the available size of the CT s, the PC cases utilize boilers and steam turbines that can be procured at nearly any desired output making it possible to maintain a constant net output. Case 10

– PC Subcritical Unit with CO 2 

## Capture

The process description for Case 10 is essentially the same as Case 9 with one notable exception , the addition of CO 2 

## capture. A BFD and stream tables for Case 10 are shown in Exhibit 4

- 18 and Exhibit 4

- 19 , respectively. Since the CDR facility process description was provided in Section 4.1.7 , it is not repeated here.
4.2.8 The Case 10 modeling assumptions were presented previously in Section Case 10 Performance Results 4.2.2

. The plant produces a net output of 550 MW at a net plant efficiency of 26.2 percent (HHV basis). Overall plant performance is summarized in Exhibit 4

- 20 , which includes auxiliary power requirements. The CDR facility, including CO 2 

## compression, accounts for over half of the auxiliary plant load. The CWS ( CWP s and cooling tower fan) accounts for over 14 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facility.

### Cost and Performance Baseline for Fossil Energy Plants

354 

## Exhibit 4

- 18 Case 10 Block Flow Diagram , Subcritical Unit with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

355 

## Exhibit 4

- 19 Case 10 Stream Table , Subcritical Unit with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 72,691 72,691 2,163 22,330 22,330 3,063 1,680 0 0 102,289 0 102,289 102,289 3,643 V-L Flowrate (kg/hr) 2,097,642 2,097,642 62,415 644,374 644,374 88,396 48,482 0 0 3,042,405 0 3,042,405 3,042,405 65,636 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 278,956 5,410 21,640 21,640 0 0 28,403
Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 327.39

--- 308.96 322.83

--- Density (kg/m 3 ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- V-L Flowrate (lb mol /hr) 160,256 160,256 4,768 49,229 49,229 6,753 3,704 0 0 225,509 0 225,509 225,509 8,032 V-L Flowrate (lb/hr) 4,624,510 4,624,510 137,601 1,420,601 1,420,601 194,880 106,884 0 0 6,707,354 0 6,707,354 6,707,354 144,703 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 614,994 11,927 47,708 47,708 0 0 62,618
Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0 Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- 140.8

--- 132.8 138.8

--- Density (lb/ft 3 ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- 0.050

--- 0.049 0.052

--- A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

356 

## Exhibit 4

- 19 Case 10 Stream Table , Subcritical Unit with CO 2 Capture (Continued)
15 16 17 18 19 20 21 22 23 24 25 26 27 28 V-L Mole Fraction

Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0000 0.0005 0.0004 0.1350 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 14,732 1,049 269 111,453 83,996 13,598 13,566 48,632 48,632 131,223 121,115 121,115 60,504 61,816 V-L Flowrate (kg/hr) 265,393 30,461 4,845 3,213,261 2,366,318 597,086 596,497 876,112 876,112 2,364,021 2,181,912 2,181,912 1,089,994 1,113,634 Solids Flowrate (kg/hr) 0 0 43,806 0 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 15 181 58 58 32 21 35 296 151 566 363 566 38 39 Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.90 16.65 4.28 3.90 0.01 1.69 Enthalpy (kJ/kg) A -46.80 191.62

--- 301.43 93.86 19.49 -211.71 3,054.75 636.27 3,472.33 3,120.82 3,594.06 2,028.64 165.87 Density (kg/m 3 ) 1,003.1 2.4

--- 1.1 1.1 2.9 795.9 2.0 916.0 47.7 15.7 10.3 0.1 993.3 V-L Molecular Weight 18.015 29.029

--- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015
V-L Flowrate (lb mol /hr) 32,478 2,313 593 245,711 185,179 29,979 29,907 107,214 107,214 289,297 267,012 267,012 133,388 136,281 V-L Flowrate (lb/hr) 585,092 67,154 10,682 7,084,027 5,216,839 1,316,349 1,315,051 1,931,497 1,931,497 5,211,774 4,810,293 4,810,293 2,403,024 2,455,142 Solids Flowrate (lb/hr) 0 0 96,577 0 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 59 357 136 136 89 69 95 565 304 1,050 686 1,050 101 103 Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 130.0 2,415.0 620.5 565.5 1.0 245.0 Enthalpy (Btu/lb) A -20.1 82.4

--- 129.6 40.4 8.4 -91.0 1,313.3 273.5 1,492.8 1,341.7 1,545.2 872.2 71.3 Density (lb/ft 3 ) 62.622 0.149

--- 0.067 0.070 0.184 49.684 0.122 57.183 2.977 0.983 0.643 0.004 62.007

### Cost and Performance Baseline for Fossil Energy Plants

357 

## Exhibit 4

- 20 Case 10 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Steam Turbine Power 672,700 TOTAL (STEAM TURBINE) POWER, kWe 672,700 AUXILIARY LOAD SUMMARY, kWe Coal Handling and Conveying 540 Pulverizers 4,180 Sorbent Handling & Reagent Preparation 1,370 Ash Handling 800 Primary Air Fans 1,960 Forced Draft Fans 2,500 Induced Draft Fans 12,080 SCR 70 Baghouse 100 Wet FGD 4,470 Econamine FG Plus Auxiliaries 22,400 CO 2 

## Compression 48,790 Miscellaneous Balance of Plant 2,3 

## 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 700 Circulating Water Pumps 11,190 Ground Water Pumps 1,020 Cooling Tower Fans 5,820 Transformer Losses 2,350 TOTAL AUXILIARIES, kWe 122, 74 0 NET POWER, kWe 5 49,96 0 Net Plant Efficiency (HHV) 26.2 % Net Plant Heat Rate , kJ/kWh (Btu/kWh ) 13,764 (13,046 ) CONDENSER COOLING DUTY 10 6 

## kJ /h r (10 6 

## Btu /h r ) 2,034 (1,928) CONSUMABLES As

- Received Co al Feed, kg/h r (lb/h r ) 278,956 (614,994) Limestone Sorbent Feed, kg/h r (lb/h r ) 28,404 ( 62,618 ) Thermal Input, kWt 1 

## 2, 102,643 Raw Water Withdrawal, m 3 

## /min (gpm) 42.5 (11,224) Raw Water Consumption, m 3 

## /min (gpm) 32.6 (8,620)
1. HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2. Boiler feed pumps are turbine driven 3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads.

### Cost and Performance Baseline for Fossil Energy Plants

358 

## The environmental targets f or emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 10 is presented in Environmental Performance

Exhibit 4

- 21

. Exhibit 4

- 21 Case 10 Air Emissions

kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)
SO 2 

## 0.001 (0.002) 40 (44) 0.008 (.02) NOx 0.030 (0.070) 1,696 (1,870) 0.339 (.747) Particulates 0.006 (0.0130) 315 (347) 0.063 (.139) Hg 4.91E

- 7 (1.14E

- 6) 0.028 (0.031) 5.53E

- 6 (1.22E

- 5) CO 2 

## 8.8 (20.4) 493,198 (543,658) 98 (217)
CO 2 1 

## 120 (2 66 )
1 

## CO 2 

## emissions based on net power instead of gross power
SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The SO 2 

## emissions are fur ther reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO 2 

## is essentially completely removed in the CDR absorber vessel resulting in very low SO 2 

## emissions. NOx emissions are controlled to about 0.5 lb/10 6 

## Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 

## Bt u. Particulate emissions are controlled using a pulse jet fabric filter , which operates at an efficiency of 99.8 percent. Co

- benefit capture results in a 90 percent reduction of mercury emissions. Ninety percent of the CO 2 

## in the FG is removed in CDR facility. The carbon balance for the plant is shown in Exhibit 4

- 22

. The carbon input to the plant consists of carbon in the coal in addition to carbon in the air and limestone for the FGD . Carbon in the air is not neglected here since the Aspen model accounts for air components throughout. Carbon leaves the plant as CO 2 

## in the stack gas, carbon in the FGD product , and the captured CO 2 

## product. The CO 2 

## capture efficiency is defined by the following fraction: 1

- [(Stack Gas Carbon

- Air Carbon)/(Total Carbon In

- Air Carbon)] or [1

- ( 39 ,853

- 850) /( 399,230

- 850 ) *100 ] or 90. 2 percent

### Cost and Performance Baseline for Fossil Energy Plants

359 

## Exhibit 4

- 22 Case 10 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 177,820 (392,026) Stack Gas 18,077 (39,853) Air (CO 2 

## ) 386 (850) FGD Product 317 (699) FGD Reagent 2,882 (6,354) CO 2 

## Product 162,694 (358,679) Total 181,088 (399,230) Total 181,088 (399,230)

Exhibit 4

- 23 shows the su lfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum , sulfur emitted in the stac k gas , and sulfur removed in the polishing scrubber

. Exhibit 4

- 23 Case 10 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 6,992 (15,414) FGD Product 6,852 (15,106) Stack Gas 3 (6) Econamine Polishing Scrubber/H S S 137 (302)
Total 6,992 (15,414) Total 6,992 (15,414)

Exhibit 4

- 24 shows the overall water balance for the plant. The exhibit is presented in an identical manner as was for Case 9. Exhibit 4

- 24 Case 10 Water Balance

Water Use Water Demand,

m 3 

## /min (gpm) Internal Recycle, m 3 

## /min (gpm) Raw Water Withdrawal,
m 3 

## /min (gpm) Process Water Discharge,

m 3 

## /min (gpm) Raw Water Consumption,
m 3 

## /min (gpm)

Econamine 0.2 (39) 0.0 (0) 0.2 (39) 0.0 (0) 0.2 (39) FGD Makeup 5.5 (1,460) 0.0 (0) 5.5 (1,460) 0.0 (0) 5.5 (1,460) BFW Makeup 0.4 (104) 0.0 (0) 0.4 (104) 0.0 (0) 0.4 (104) Cooling Tower 43.8 (11,580) 7.4 (1,959) 36.4 (9,621) 9.9 (2,604) 26.6 (7,017)
Total 49.9 (13,182) 7.4 (1,959) 42.5 (11,224) 9.9 (2,604) 32.6 (8,620)

### Cost and Performance Baseline for Fossil Energy Plants

360 

## A heat and mass balance diagram is shown for the Case 10 PC boiler, the FGD unit, CDR system and steam cycle in Heat and Mass Balance Diagrams

Exhibit 4

- 25 and Exhibit 4

- 26

. An overall plant energy balance is provided in tabular form in Exhibit 4

- 27

. The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4

- 20 ) is calculated by multiplying the power o ut by a generator efficiency of 98.4 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser heat out stream. The CO 2 

## compressor intercoo ler load is included in the Econamine pro cess heat out stream.

### Cost and Performance Baseline for Fossil Energy Plants

361 

## Exhibit 4

- 25 Case 10 Heat and Mass Balance, Subcritical PC Boiler with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

362 

## Exhibit 4

- 26 Case 10 Heat and Mass Balance, Subcritical Steam Cycle

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 2 OF 2 DWG

. NO

. BB

- HMB

- CS

- 10

- PG

- 2 B ITUMINOUS B ASELINE S TUDY C ASE 10 S UBCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL

P

- 1028 P

- 1048 To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam

Single Reheat

Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 211 , 774 W

1 , 050

. 0 T 2 , 415

. 0 P 1 , 492

. 8 H

493 , 596 W 916

. 3 T 323

. 0 P 1 , 480

. 9 H 357 , 025 W

682

. 6 T 589

. 7 P 1 , 341

. 7 H 4 , 810 , 293 W 686

. 0 T 620

. 5 P 1 , 341

. 7 H620.5P620.5P620.5P350.5P75.0P75.0P 284 , 197 W 564

. 7 T 73

. 5 P 1 , 313

. 3 H

284 , 197 W 126

. 1 T

2

. 0 P 1 , 088

. 1 H 1 , 715 , 276 W 101

. 1 T

1

. 0 P 1 , 020

. 0 H

2 , 793 W 212

. 0 T 14

. 7 P 179

. 9 H64.2P41.6P11.8P

101

. 4 T 250

. 0 P 70

. 0 H 2 , 793 W 634

. 8 T 75

. 0 P 1 , 347

. 9 H 2 , 455 , 142 W 101

. 1 T

1

. 0 P 69

. 1 H

2 , 455 , 142 W 102

. 8 T 245

. 0 P 71

. 3 H 2 , 455 , 142 W 152

. 8 T 240

. 0 P 121

. 2 H

397 , 457 W 112

. 8 T

1

. 4 P 80

. 6 H 293 , 413 W

162

. 8 T

5

. 1 P 130

. 6 H 2 , 455 , 142 W 284

. 7 T 220

. 0 P 253

. 9 H

850 , 621 W

319

. 4 T 323

. 0 P 289

. 8 H 2 , 455 , 142 W 257

. 7 T 230

. 0 P 226

. 5 H

357 , 025 W

436

. 2 T 366

. 7 P 414

. 3 H

5 , 211 , 774 W 426

. 2 T 3 , 105

. 5 P 406

. 0 H

DEAERATOR

BOILER FEED PUMPS 5 , 211 , 774 W 484

. 4 T 3 , 100

. 5 P 469

. 5 H 4 , 810 , 293 W

1 , 050

. 0 T 565

. 5 P 1 , 545

. 2 H

63 , 337 W 267

. 7 T 40

. 3 P 236

. 3 H 211 , 580 W 200

. 5 T 11

. 7 P 168

. 3 H

2 , 455 , 142 W 190

. 5 T 235

. 0 P 158

. 8 H 26 , 631 W

577

. 8 T 70

. 0 P 1 , 320

. 0 H 63 , 337 W 535

. 0 T 57

. 3 P 1 , 300

. 0 H 148 , 243 W 448

. 7 T 37

. 1 P 1 , 259

. 8 H 81 , 833 W 236

. 1 T 10

. 5 P 1 , 163

. 0 H 104 , 045 W 157

. 8 T

4

. 5 P 1 , 116

. 3 H2,415.0P 4 , 325 , 282 W 564

. 7 T 73

. 5 P 1 , 313

. 3 H 2 , 109 , 588 W 564

. 7 T 73

. 5 P 1 , 313

. 3 H5.0P Steam Turbine Makeup

309

. 4 T 3 , 110

. 5 P 284

. 6 H 5 , 211 , 774 W 302

. 9 T 70

. 0 P 272

. 3 H 3 , 301 W 634

. 8 T 75

. 0 P 1 , 347

. 9 H

Gross Plant Power : 673 MWe Auxiliary Load : 123 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 26

. 2 % Net Plant Heat Rate : 13 , 046 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 3 , 145 W 634

. 8 T 75

. 0 P 1 , 347

. 9 H 24

28

DOE / NETL
SC PC P LANT C ASE 102,415.0P

261,850.0P

Single Reheat Extraction to

Boiler

25 4 , 842 , 620 W 1 , 049

. 0 T 565

. 5 P 1 , 544

. 6 H

52 , 118 W 48

. 0 T 11

. 4 P 16

. 1 H Econamine

Steam

Econamine Condensate

1 , 931 , 497 W 304

. 0 T 130

. 0 P 273

. 5 H 1 , 931 , 497 W 564

. 7 T 73

. 5 P 1 , 313

. 3 H

### Cost and Performance Baseline for Fossil Energy Plants

363 

## Exhibit 4

- 27 Case 10 Overall Energy Balance ( 0°C [ 32°F ] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 7,570 (7,175) 6.3 (6.0) 7,576 (7,181) Air 84.3 (79.9) 84.3 (79.9) Raw Water Makeup 159.9 (151.5) 159.9 (151.5) Limestone 0.32 (0.30) 0.32 (0.30) Auxiliary Power 442 (419) 442 (419) Totals 7,570 (7,175) 250.9 (237.8) 442 (419) 8,262 (7,831) Heat Out GJ/hr (MMBtu/hr) Bottom Ash 0.7 (0.6) 0.7 (0.6) Fly Ash + FGD Ash 2.6 (2.5) 2.6 (2.5) Flue Gas 222 (211) 222 (211) Condenser 2,034 (1,928) 2,034 (1,928) CO 2 

## - 126 (

- 120)

- 126 (

- 120) Cooling Tower Blowdown 73.2 (69.4) 73.2 (69.4) Econamine Losses 3,585 (3,398) 3,585 (3,398) Process Losses* 49.6 (47.0) 49.6 (47.0) Power 2,422 (2,295) 2,422 (2,295) Totals 0 (0) 5,841 (5,536) 2,422 (2,295) 8,262 (7,831) * Process losses are estimated to match the heat input to the plant. Process losses include

losses from: turbines, gas cooling, etc.

### Cost and Performance Baseline for Fossil Energy Plants

364 

## 4.2.9 Major equipment items for the subcritical PC plant with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 10

– Major Equipment List

4.2.10 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 FUEL AND SORBENT HAN DLING
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1
9 Feeder Vibratory 227 tonne/hr (250 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 463 tonne/hr (510 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 227 tonne (250 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 463 tonne/hr (510 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 463 tonne/hr (510 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 998 tonne (1,100 ton) 3 0

19 Limestone Truck Unloading Hopper N/A 36 tonne (40 ton) 1 0
20 Limestone Feeder Belt 118 tonne/hr (130 tph) 1 0 21 Limestone Conveyor No. L1 Belt 118 tonne/hr (130 tph) 1 0 22 Limestone Reclaim Hopper N/A 27 tonne (30 ton) 1 0 23 Limestone Reclaim Feeder Belt 91 tonne/hr (100 tph) 1 0 24 Limestone Conveyor No. L2 Belt 91 tonne/hr (100 tph) 1 0 25 Limestone Day Bin w/ actuator 372 tonne (410 ton) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

365 

## ACCOUNT 2 COAL AND SORBENT PRE PARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 54 tonne/hr (60 tph) 6 0

2 Coal Pulverizer Ball type or equivalent 54 tonne/hr (60 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 31 tonne/hr (34 tph) 1 1
4 Limestone Ball Mill Rotary 31 tonne/hr (34 tph) 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 121,133 liters (32,000 gal) 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 2,006 lpm @ 12m H2O (530 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 492 lpm (130 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1
9 Limestone Slurry Storage Tank with Agitator Field erected 673,803 liters (178,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,401 lpm @ 9m H2O (370 gpm @ 30 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

366 

## ACCOUNT 3 FEE DWATER AND MISCELLAN EOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,563,375 liters (413,000 gal) 2 0

2 Condensate Pumps Vertical canned 20,441 lpm @ 213 m H2O (5,400 gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage Tank Horizontal spray type 2,600,445 kg/hr (5,733,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed Pump/Turbine Barrel type, multi-stage, centrifugal 43,532 lpm @ 2,591 m H2O (11,500 gpm @ 8,500 ft H2O) 1 1

5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multi-stage, centrifugal 12,870 lpm @ 2,591 m H2O (3,400 gpm @ 8,500 ft H2O) 1 0

6 LP Feedwater Heater 1A/1B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 612,350 kg/hr (1,350,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 2,599,084 kg/hr (5,730,000 lb/hr) 1 0
11 HP Feedwater Heater 7 Horizontal U-tube 2,599,084 kg/hr (5,730,000 lb/hr) 1 0

12 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

13 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

14 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

15 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

16 Closed Cycle Cooling Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

17 Closed Cycle Cooling Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

18 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1

19 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1

20 Raw Water Pumps Stainless steel, single suction 12,265 lpm @ 18 m H2O (3,240 gpm @ 60 ft H2O) 2 1

21 Ground Water Pumps Stainless steel, single suction 4,921 lpm @ 268 m H2O (1,300 gpm @ 880 ft H2O) 5 1

22 Filtered Water Pumps Stainless steel, single suction 2,953 lpm @ 49 m H2O (780 gpm @ 160 ft H2O) 2 1

23 Filtered Water Tank Vertical, cylindrical 2,839,059 liter (750,000 gal) 1 0

24 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 1,022 lpm (270 gpm) 1 1

25 Liquid Waste Treatment System -- 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

367 

## ACCOUNT 4 BOILER AND ACCESSORI ES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Boiler Subcritical, drum wall-fired, low NOx burners, overfire air 2,599,084 kg/hr steam @ 17.9 MPa/574°C/574°C (5,730,000 lb/hr steam @ 2,600 psig/1,065°F/1,065°F) 1 0

2 Primary Air Fan Centrifugal 354,256 kg/hr, 4,837 m3/min @ 123 cm WG (781,000 lb/hr, 170,800 acfm @ 48 in. WG) 2 0

3 Forced Draft Fan Centrifugal 1,153,485 kg/hr, 15,744 m3/min @ 47 cm WG (2,543,000 lb/hr,

556,000 acfm @ 19 in. WG) 2 0

4 Induced Draft Fan Centrifugal 1,673,302 kg/hr, 35,314 m3/min @ 104 cm WG (3,689,000 lb/hr,

1,247,100 acfm @ 41 in. WG) 2 0

5 SCR Reactor Vessel Space for spare layer 3,347,512 kg/hr (7,380,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air Blower Centrifugal 198 m3/min @ 108 cm WG (7,000 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 219,554 liter (58,000 gal) 5 0

9 Ammonia Feed Pump Centrifugal 42 lpm @ 91 m H2O (11 gpm @ 300 ft H2O) 2 1

### Cost and Performance Baseline for Fossil Energy Plants

368 

## ACCOUNT 5 FLUE GAS CLEANUP

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter Single stage, highratio with pulse-jet online cleaning system 1,673,302 kg/hr (3,689,000 lb/hr) 99.8% efficiency 2 0

2 Absorber Module Counter-current open spray 66,913 m3/min (2,363,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 230,910 lpm @ 64 m H2O (61,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 6,095 lpm (1,610 gpm) at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 117 m3/min @ 0.3 MPa (4,130 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 1,514 lpm (400 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 48 tonne/hr (53 tph) of 50 wt % slurry 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 908 lpm @ 12 m H2O (240 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 605,666 lpm (160,000 gal) 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 4,883 lpm @ 21 m H2O (1,290 gpm @ 70 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

369 

## ACCOUNT 5B CARBON DIOXIDE RECOV ERY

ACCOUNT 6 COMBUSTION TURBINE/A CCESSORIES N/A

ACCOUNT 7 HRSG, DUCTING & STAC K

ACCOUNT 8 STEAM TURBINE GENERATOR AN D AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Econamine FG Plus Amine-based CO2 capture technology 1,767,196 kg/h (3,896,000 lb/h) 20.6 wt % CO2 concentration 2 0

2 Econamine Condensate Pump Centrifugal 18,435 lpm @ 52 m H2O (4,870 gpm @ 170 ft H2O) 1 1

3 CO2 Compressor Integrally geared, multi-stage centrifugal 327,872 kg/h @ 15.3 MPa (722,834 lb/h @ 2,215 psia) 2 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x 5.8 m (19 ft) diameter 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 708 MW 16.5 MPa/566°C/566°C (2400.3 psig/ 1050°F/1050°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 790 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum pumps 2,237 GJ/hr (2,120 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

370 

## ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 1,128,100 lpm @ 30 m (298,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

/ 6299 GJ/hr (5970 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

371 

## ACCOUNT 10 ASH/SPENT SORBENT RE COVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- -- 2 0

3 Clinker Grinder

-- 6.4 tonne/hr (7 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H2O (60 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1

9 Hydrobins

-- 227 lpm (60 gpm) 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- -- 10 0

12 Air Blower

-- 22 m3/min @ 0.2 MPa (770 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced concrete 1,451 tonne (1,600 ton) 2 0

14 Slide Gate Valves

-- -- 2 0
15 Unloader

-- -- 1 0

16 Telescoping Unloading Chute

-- 136 tonne/hr (150 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

372 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3- ph, 60 Hz 1 0

2 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 134 MVA, 3- ph, 60 Hz 1 1

3 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 20 MVA, 3- ph, 60 Hz 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

373 

## 4.2.10 The cost estimating methodology was described previously in Section Case 10

– Cost Estimating 2.7

. Exhibit 4

- 28 shows the total plant capital cost summary organized by cost account and Exhibit 4

- 29 shows a more detailed breakdown of the capital costs along with own er’s costs, TOC , and TASC

. Exhibit 4

- 30 shows the initial and annual O&M costs. The estimated TO C of the subcritical PC boiler with CO 2 

## capture is $ 3, 610 /kW. Process contingency represents 2.9 percent of the TO C and project contingency represents 10.2 percent. The COE, including CO 2 

## TS&M costs of 5

. 9 mills/kWh, is 1 09

. 7 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

374 

## Exhibit 4

- 28 Case 10 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 10 - 1x550 MWnet SubCritical PC w/ CO2 Capture Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $21,191 $5,688 $12,662 $0 $0 $39,542 $3,548 $0 $6,463 $49,553 $90

2 COAL & SORBENT PREP & FEED $14,465 $844 $3,675 $0 $0 $18,984 $1,664 $0 $3,097 $23,744 $43

3 FEEDWATER & MISC. BOP SYSTEMS $52,748 $0 $25,315 $0 $0 $78,063 $7,174 $0 $14,102 $99,339 $181

4 PC BOILER 4.1 PC Boiler & Accessories $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617

5 FLUE GAS CLEANUP $107,581 $0 $36,768 $0 $0 $144,350 $13,816 $0 $15,817 $173,983 $316

5B CO 2 REMOVAL & COMPRESSION $247,434 $0 $75,421 $0 $0 $322,855 $30,869 $56,959 $82,137 $492,819 $896

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76 SUBTOTAL 7 $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $55,209 $0 $6,905 $0 $0 $62,114 $5,951 $0 $6,806 $74,871 $136 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,840 $1,213 $15,303 $0 $0 $43,356 $3,796 $0 $6,701 $53,853 $98 SUBTOTAL 8 $82,049 $1,213 $22,207 $0 $0 $105,470 $9,747 $0 $13,507 $128,724 $234

9 COOLING WATER SYSTEM $22,313 $10,599 $19,714 $0 $0 $52,626 $4,953 $0 $7,745 $65,324 $119

10 ASH/SPENT SORBENT HANDLING SYS $5,525 $176 $7,387 $0 $0 $13,088 $1,258 $0 $1,477 $15,823 $29

11 ACCESSORY ELECTRIC PLANT $25,948 $11,057 $31,311 $0 $0 $68,316 $6,043 $0 $9,343 $83,703 $152

12 INSTRUMENTATION & CONTROL $9,942 $0 $10,082 $0 $0 $20,024 $1,816 $1,001 $2,805 $25,646 $47

13 IMPROVEMENTS TO SITE $3,344 $1,922 $6,739 $0 $0 $12,006 $1,184 $0 $2,638 $15,828 $29

14 BUILDINGS & STRUCTURES $0 $25,775 $24,432 $0 $0 $50,207 $4,529 $0 $8,210 $62,947 $114

TOTAL COST $783,055 $58,343 $398,903 $0 $0 $1,240,301 $117,071 $57,960 $203,025 $1,618,357 $2,942 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

375 

## Exhibit 4

- 29 Case 10 Total Plant Cost Details Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,333 $0 $1,979 $0 $0 $6,313 $564 $0 $1,031 $7,908 $14 1.2 Coal Stackout & Reclaim $5,600 $0 $1,269 $0 $0 $6,869 $601 $0 $1,120 $8,590 $16 1.3 Coal Conveyors $5,207 $0 $1,255 $0 $0 $6,462 $566 $0 $1,054 $8,083 $15 1.4 Other Coal Handling $1,362 $0 $290 $0 $0 $1,653 $144 $0 $270 $2,067 $4 1.5 Sorbent Receive & Unload $178 $0 $54 $0 $0 $231 $20 $0 $38 $289 $1 1.6 Sorbent Stackout & Reclaim $2,869 $0 $526 $0 $0 $3,395 $296 $0 $554 $4,244 $8 1.7 Sorbent Conveyors $1,024 $221 $251 $0 $0 $1,496 $129 $0 $244 $1,869 $3 1.8 Other Sorbent Handling $618 $145 $324 $0 $0 $1,088 $96 $0 $178 $1,361 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $5,322 $6,714 $0 $0 $12,036 $1,130 $0 $1,975 $15,141 $28 SUBTOTAL 1. $21,191 $5,688 $12,662 $0 $0 $39,542 $3,548 $0 $6,463 $49,553 $90 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,523 $0 $492 $0 $0 $3,014 $263 $0 $492 $3,768 $7 2.2 Coal Conveyor to Storage $6,459 $0 $1,410 $0 $0 $7,869 $688 $0 $1,283 $9,840 $18 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,894 $211 $1,016 $0 $0 $6,121 $533 $0 $998 $7,652 $14 2.6 Sorbent Storage & Feed $590 $0 $226 $0 $0 $815 $72 $0 $133 $1,021 $2 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $633 $531 $0 $0 $1,164 $108 $0 $191 $1,463 $3 SUBTOTAL 2. $14,465 $844 $3,675 $0 $0 $18,984 $1,664 $0 $3,097 $23,744 $43 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $20,624 $0 $7,119 $0 $0 $27,743 $2,430 $0 $4,526 $34,699 $63 3.2 Water Makeup & Pretreating $7,503 $0 $2,415 $0 $0 $9,919 $938 $0 $2,171 $13,028 $24 3.3 Other Feedwater Subsystems $6,747 $0 $2,851 $0 $0 $9,599 $860 $0 $1,569 $12,027 $22 3.4 Service Water Systems $1,471 $0 $800 $0 $0 $2,271 $214 $0 $497 $2,982 $5 3.5 Other Boiler Plant Systems $8,081 $0 $7,979 $0 $0 $16,060 $1,526 $0 $2,638 $20,224 $37 3.6 FO Supply Sys & Nat Gas $278 $0 $348 $0 $0 $626 $59 $0 $103 $788 $1 3.7 Waste Treatment Equipment $5,087 $0 $2,900 $0 $0 $7,987 $777 $0 $1,753 $10,517 $19 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,955 $0 $903 $0 $0 $3,858 $371 $0 $846 $5,075 $9 SUBTOTAL 3. $52,748 $0 $25,315 $0 $0 $78,063 $7,174 $0 $14,102 $99,339 $181 4 PC BOILER 4.1 PC Boiler & Accessories $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $171,007 $0 $109,973 $0 $0 $280,980 $27,374 $0 $30,835 $339,189 $617

### Cost and Performance Baseline for Fossil Energy Plants

376 

## Exhibit 4

- 29 Case 10 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $74,713 $0 $16,084 $0 $0 $90,797 $8,656 $0 $9,945 $109,399 $199 5.2 Other FGD $3,899 $0 $4,418 $0 $0 $8,317 $807 $0 $912 $10,037 $18 5.3 Bag House & Accessories $21,582 $0 $13,697 $0 $0 $35,279 $3,400 $0 $3,868 $42,546 $77 5.4 Other Particulate Removal Materials $1,461 $0 $1,563 $0 $0 $3,023 $293 $0 $332 $3,648 $7 5.5 Gypsum Dewatering System $5,926 $0 $1,007 $0 $0 $6,933 $660 $0 $759 $8,352 $15 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $107,581 $0 $36,768 $0 $0 $144,350 $13,816 $0 $15,817 $173,983 $316 5B CO 2 REMOVAL & COMPRESSION 5B.1 CO 2 Removal System $218,463 $0 $66,332 $0 $0 $284,795 $27,229 $56,959 $73,796 $442,779 $805 5B.2 CO 2 Compression & Drying $28,971 $0 $9,089 $0 $0 $38,060 $3,640 $0 $8,340 $50,040 $91 SUBTOTAL 5B. $247,434 $0 $75,421 $0 $0 $322,855 $30,869 $56,959 $82,137 $492,819 $896 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $10,193 $0 $6,549 $0 $0 $16,743 $1,460 $0 $2,730 $20,933 $38 7.4 Stack $9,316 $0 $5,451 $0 $0 $14,766 $1,422 $0 $1,619 $17,807 $32 7.9 Duct & Stack Foundations $0 $1,069 $1,214 $0 $0 $2,283 $214 $0 $499 $2,996 $5 SUBTOTAL 7. $19,509 $1,069 $13,214 $0 $0 $33,792 $3,095 $0 $4,848 $41,735 $76 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $55,209 $0 $6,905 $0 $0 $62,114 $5,951 $0 $6,806 $74,871 $136 8.2 Turbine Plant Auxiliaries $387 $0 $828 $0 $0 $1,215 $119 $0 $133 $1,467 $3 8.3 Condenser & Auxiliaries $6,154 $0 $2,549 $0 $0 $8,702 $835 $0 $954 $10,490 $19 8.4 Steam Piping $20,300 $0 $10,009 $0 $0 $30,310 $2,547 $0 $4,928 $37,784 $69 8.9 TG Foundations $0 $1,213 $1,917 $0 $0 $3,130 $296 $0 $685 $4,111 $7 SUBTOTAL 8. $82,049 $1,213 $22,207 $0 $0 $105,470 $9,747 $0 $13,507 $128,724 $234 9 COOLING WATER SYSTEM 9.1 Cooling Towers $16,661 $0 $5,188 $0 $0 $21,850 $2,090 $0 $2,394 $26,333 $48 9.2 Circulating Water Pumps $3,467 $0 $260 $0 $0 $3,727 $315 $0 $404 $4,446 $8 9.3 Circ.Water System Auxiliaries $839 $0 $112 $0 $0 $951 $90 $0 $104 $1,146 $2 9.4 Circ.Water Piping $0 $6,653 $6,448 $0 $0 $13,101 $1,226 $0 $2,149 $16,476 $30 9.5 Make-up Water System $680 $0 $909 $0 $0 $1,589 $152 $0 $261 $2,002 $4 9.6 Component Cooling Water Sys $665 $0 $529 $0 $0 $1,194 $113 $0 $196 $1,503 $3 9.9 Circ.Water System Foundations & Structures $0 $3,946 $6,269 $0 $0 $10,214 $966 $0 $2,236 $13,417 $24 SUBTOTAL 9. $22,313 $10,599 $19,714 $0 $0 $52,626 $4,953 $0 $7,745 $65,324 $119

### Cost and Performance Baseline for Fossil Energy Plants

377 

## Exhibit 4

- 29 Case 10 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $739 $0 $2,278 $0 $0 $3,017 $296 $0 $331 $3,645 $7 10.7 Ash Transport & Feed Equipment $4,786 $0 $4,902 $0 $0 $9,688 $926 $0 $1,061 $11,676 $21 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $176 $207 $0 $0 $383 $36 $0 $84 $502 $1 SUBTOTAL 10. $5,525 $176 $7,387 $0 $0 $13,088 $1,258 $0 $1,477 $15,823 $29 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,742 $0 $283 $0 $0 $2,025 $188 $0 $166 $2,379 $4 11.2 Station Service Equipment $5,148 $0 $1,691 $0 $0 $6,839 $639 $0 $561 $8,039 $15 11.3 Switchgear & Motor Control $5,918 $0 $1,006 $0 $0 $6,924 $642 $0 $757 $8,322 $15 11.4 Conduit & Cable Tray $0 $3,710 $12,830 $0 $0 $16,540 $1,601 $0 $2,721 $20,862 $38 11.5 Wire & Cable $0 $7,001 $13,516 $0 $0 $20,517 $1,729 $0 $3,337 $25,582 $47 11.6 Protective Equipment $270 $0 $918 $0 $0 $1,188 $116 $0 $130 $1,434 $3 11.7 Standby Equipment $1,370 $0 $31 $0 $0 $1,401 $128 $0 $153 $1,682 $3 11.8 Main Power Transformers $11,500 $0 $191 $0 $0 $11,691 $886 $0 $1,258 $13,835 $25 11.9 Electrical Foundations $0 $345 $846 $0 $0 $1,191 $114 $0 $261 $1,566 $3 SUBTOTAL 11. $25,948 $11,057 $31,311 $0 $0 $68,316 $6,043 $0 $9,343 $83,703 $152 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $512 $0 $307 $0 $0 $819 $77 $41 $141 $1,077 $2 12.7 Distributed Control System Equipment $5,168 $0 $903 $0 $0 $6,071 $563 $304 $694 $7,632 $14 12.8 Instrument Wiring & Tubing $2,802 $0 $5,558 $0 $0 $8,359 $712 $418 $1,423 $10,913 $20 12.9 Other I & C Equipment $1,460 $0 $3,314 $0 $0 $4,774 $463 $239 $548 $6,024 $11 SUBTOTAL 12. $9,942 $0 $10,082 $0 $0 $20,024 $1,816 $1,001 $2,805 $25,646 $47

### Cost and Performance Baseline for Fossil Energy Plants

378 

## Exhibit 4

- 29 Case 10 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $56 $1,124 $0 $0 $1,180 $117 $0 $260 $1,557 $3 13.2 Site Improvements $0 $1,866 $2,318 $0 $0 $4,184 $413 $0 $919 $5,516 $10 13.3 Site Facilities $3,344 $0 $3,298 $0 $0 $6,642 $655 $0 $1,459 $8,756 $16 SUBTOTAL 13. $3,344 $1,922 $6,739 $0 $0 $12,006 $1,184 $0 $2,638 $15,828 $29 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $9,158 $8,054 $0 $0 $17,212 $1,547 $0 $2,814 $21,573 $39 14.2 Turbine Building $0 $13,420 $12,507 $0 $0 $25,927 $2,337 $0 $4,240 $32,503 $59 14.3 Administration Building $0 $646 $684 $0 $0 $1,330 $121 $0 $218 $1,668 $3 14.4 Circulation Water Pumphouse $0 $176 $140 $0 $0 $317 $28 $0 $52 $397 $1 14.5 Water Treatment Buildings $0 $952 $868 $0 $0 $1,819 $164 $0 $297 $2,281 $4 14.6 Machine Shop $0 $432 $290 $0 $0 $723 $64 $0 $118 $905 $2 14.7 Warehouse $0 $293 $294 $0 $0 $587 $53 $0 $96 $736 $1 14.8 Other Buildings & Structures $0 $239 $204 $0 $0 $443 $40 $0 $72 $555 $1 14.9 Waste Treating Building & Str. $0 $458 $1,391 $0 $0 $1,849 $176 $0 $304 $2,329 $4 SUBTOTAL 14. $0 $25,775 $24,432 $0 $0 $50,207 $4,529 $0 $8,210 $62,947 $114

TOTAL COST $783,055 $58,343 $398,903 $0 $0 $1,240,301 $117,071 $57,960 $203,025 $1,618,357 $2,942
Owner's Costs Preproduction Costs 6 Months All Labor $10,547 $19 1 Month Maintenance Materials $1,534 $3 1 Month Non-fuel Consumables $1,789 $3 1 Month Waste Disposal $353 $1 25% of 1 Months Fuel Cost at 100% CF $2,143 $4 2% of TPC $32,367 $59 Total $48,733 $89 Inventory Capital 60 day supply of fuel and consumables at 100% CF $20,189 $37 0.5% of TPC (spare parts) $8,092 $15 Total $28,281 $51
Initial Cost for Catalyst and Chemicals $2,712 $5 Land $900 $2 Other Owner's Costs $242,754 $441

Financing Costs $43,696 $79 Total Overnight Costs (TOC) $1,985,432 $3,610 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,263,393 $4,115

### Cost and Performance Baseline for Fossil Energy Plants

379 

## Exhibit 4

- 30 Case 10 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 10 - 1x550 MWnet SubCritical PC w/ CO2 Capture Heat Rate-net (Btu/kWh): 13,044 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,444,907 $11.718 Maintenance Labor Cost $10,429,543 $18.962 Administrative & Support Labor $4,218,612 $7.670 Property Taxes and Insurance $32,367,148 $58.848 TOTAL FIXED OPERATING COSTS $53,460,210 $97.199 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $15,644,314 $0.00382

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 0 8,081 1.08 $0 $2,711,996 $0.00066

Chemicals

MU & WT Chem.(lbs) 0 39,119 0.17 $0 $2,100,447 $0.00051 Limestone (ton) 0 751 21.63 $0 $5,043,346 $0.00123 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 1,117 1.58 2,249.89 $2,513,263 $1,105,563 $0.00027 NaOH (tons) 79 7.89 433.68 $34,221 $1,061,704 $0.00026 H2SO4 (tons) 75 7.53 138.78 $10,450 $324,217 $0.00008 Corrosion Inhibitor 0 0 0.00 $154,511 $7,358 $0.00000 Activated Carbon (lb) 0 1,892 1.05 $0 $616,433 $0.00015 Ammonia (19% NH3) ton 0 110 129.80 $0 $4,446,378 $0.00109 Subtotal Chemicals $2,712,445 $14,705,446 $0.00359

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.46 5,775.94 $0 $831,516 $0.00020 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $831,516 $0.00020
Waste Disposal

Fly Ash (ton) 0 572 16.23 $0 $2,881,846 $0.00070 Bottom Ash (ton) 0 143 16.23 $0 $720,462 $0.00018 Subtotal-Waste Disposal $0 $3,602,308 $0.00088 By-products & Emissions

Gypsum (tons) 0 1,159 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,712,445 $37,495,580 $0.00916

Fuel(ton) 0 7,380 38.18 $0 $87,425,787 $0.02135

### Cost and Performance Baseline for Fossil Energy Plants

380 

## 4.3 SUPERCRITICAL PC CAS ES This section contains an evaluation of plant designs for Cases 11 and 12 , which are based on a SC PC plant with a nominal net output of 550 MWe. Both plants use a single reheat 24.1 MPa/593°C/593°C (3 , 500 psig/1 , 100 **°** F/1 , 100 **°** F) cycle. The only difference between the two plants is that Case 12 includes CO 2 

## capture while Case 11 does not. The balance of Section 4.3 is organized in an analogous manner to the subcritical PC section:

**•** Process and System Description for C ase 11

**•** Key Assumptions for Cases 11 and 12

**•** Sparing Philosophy for Cases 11 and 12

**•** Performance Results for Case 11

**•** Equipment List for Case 11

**•** Cost Estimates for Case 11

**•** Process and System Description, Performance Results, Equipment List and Cost Estimates f or Case 12
4.3.1 In this section the SC PC process without CO 2 

## capture is described. The system description is nearly identical to the subcritical PC case without CO 2 

## capture but is repeated here for completeness. The description follows th e BFD in Process Description

Exhibit 4

- 31 and stream numbers reference the same Exhibit. The tables in Exhibit 4

- 32 provide process data for the numbered streams in the BFD. Coal (stream 8 ) and PA (stream 4) are introduced into the boiler through the wall

- fired burners. Additional combustion air, including the OFA , is provided by the FD fans (stream 1 ). The boiler operates at a slight negative pressure so air leakage is into the boiler, and the infiltration air is accounted for in stream 5. Streams 3 and 6 show Ljungstrom air preheater leakages from the FD and PA fan outlet streams to the boiler exhaust. FG exits the boiler t hrough the SCR reactor (stream 10) and is cooled to 169°C (337 °F) in the combu stion air preheater before passing through a fabric filter fo r particulate removal (stream 12 ). An ID fan increas es the FG temperature to 181°C (357 °F) and provides the motive f orce for the FG (stream 13 ) to pass through the FGD unit. FGD inputs and outputs include makeup water (stream 15), oxidation air (stream 16), limestone slurry (stream 14 ) , and product gypsum (stream 17 ). The clean, saturated FG exiting the FGD unit (stream 18 ) passes to the plant stack and is discharged to the atmosphere

.

### Cost and Performance Baseline for Fossil Energy Plants

381 

## Exhibit 4

- 31 Case 11 Block Flow Diagram , Su perc ritical Unit without CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

382 

## Exhibit 4

- 32 Case 11 Stream Table , Su per critical Unit without CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 CO 2 

### 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 N 2 

### 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 O 2 

### 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 48,414 48,414 1,434 14,872 14,872 2,047 1,119 0 0 68,126 0 68,126 V-L Flowrate (kg/hr) 1,397,067 1,397,067 41,378 429,164 429,164 59,064 32,284 0 0 2,026,262 0 2,026,262 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 185,759 3,603 14,410 14,410 0
Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 Enthalpy (kJ/kg) A 

### 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 327.37

--- 308.94 Density (kg/m 3 

### ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- 0.8

--- 0.8 V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743
V-L Flowrate (lb mol 

### /hr) 106,734 106,734 3,161 32,787 32,787 4,512 2,466 0 0 150,191 0 150,191 V-L Flowrate (lb/hr) 3,080,006 3,080,006 91,224 946,145 946,145 130,215 71,175 0 0 4,467,142 0 4,467,142 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 409,528 7,942 31,769 31,769 0
Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 Enthalpy (Btu/lb) A 

### 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- 140.7

--- 132.8 Density (lb/ft 3 

### ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- 0.050

--- 0.049 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

383 

## Exhibit 4

- 32 Case 11 Stream Table , Su per critical Unit without CO 2 

## Capture (Continued) 13 14 15 16 17 18 19 20 21 22 23 V-L Mole Fraction

Ar 0.0087 0.0000 0.0000 0.0128 0.0000 0.0082 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.1450 0.0000 0.0000 0.0005 0.0004 0.1353 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 

### O 0.0870 1.0000 1.0000 0.0062 0.9995 0.1517 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 

### 0.7324 0.0000 0.0000 0.7506 0.0000 0.6808 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 

### 0.0247 0.0000 0.0000 0.2300 0.0000 0.0240 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 

### 0.0021 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 68,126 2,369 9,597 726 176 74,091 92,389 76,591 76,591 69,891 69,891 V-L Flowrate (kg/hr) 2,026,262 42,682 172,898 21,076 3,168 2,137,881 1,664,421 1,379,803 1,379,803 1,259,099 1,259,099 Solids Flowrate (kg/hr) 0 18,437 0 0 28,694 0 0 0 0 0 0
Temperature (°C) 181 15 15 167 57 57 593 354 593 38 39 Pressure (MPa, abs) 0.11 0.10 0.10 0.31 0.10 0.10 24.23 4.90 4.52 0.01 1.69 Enthalpy (kJ/kg) A 

### 321.02

--- -46.80 177.65

--- 297.66 3,476.62 3,082.88 3,652.22 1,985.85 165.59 Density (kg/m 3 

### ) 0.8

--- 1,003.1 2.5

--- 1.1 69.2 18.7 11.6 0.1 993.3 V-L Molecular Weight 29.743

--- 18.015 29.029

--- 28.855 18.015 18.015 18.015 18.015 18.015
V-L Flowrate (lb mol 

### /hr) 150,191 5,223 21,158 1,601 387 163,343 203,684 168,854 168,854 154,082 154,082 V-L Flowrate (lb/hr) 4,467,142 94,099 381,174 46,465 6,985 4,713,221 3,669,421 3,041,946 3,041,946 2,775,839 2,775,839 Solids Flowrate (lb/hr) 0 40,646 0 0 63,259 0 0 0 0 0 0
Temperature (°F) 357 59 59 333 135 135 1,100 669 1,100 101 103 Pressure (psia) 15.3 15.0 14.7 45.0 14.8 14.8 3,514.7 710.8 655.8 1.0 245.0 Enthalpy (Btu/lb) A 

### 138.0

--- -20.1 76.4

--- 128.0 1,494.7 1,325.4 1,570.2 853.8 71.2 Density (lb/ft 3 

### ) 0.052

--- 62.622 0.154

--- 0.067 4.319 1.165 0.722 0.004 62.009

### Cost and Performance Baseline for Fossil Energy Plants

384 

## 4.3.2 System assumptions for Cases 11 and 12 , SC PC with and without CO 2 

## capture, are compiled in Key System Assumptions

Exhibit 4

- 33

. Exhibit 4

- 33 Supercritical PC Plant Study Configuration Matrix Case 11 w/o CO 2 

## Capture Case 1 2 w/CO 2 

## Capture Steam Cycle , MPa/°C/°C ( psig /°F/°F) 24.1/593/593 (35 00 /1100/1100) 24.1/593/593 (35 00 /1100/1100) Coal Illinois No. 6 Illinois No. 6 Condenser pressure, mm Hg ( in Hg ) 50.8 ( 2 ) 50.8 ( 2 ) Boiler Efficiency , % 88 8 8 Cooling water to condenser, °C ( oF ) 16 (60) 16 (60) Cooling water from condenser, °C ( oF ) 27 (80) 27 (80) Stack temperature , °C (°F) 57 (135) 32 (89)
SO 2 

## Control Wet Limestone Forced Oxidation Wet Limestone Forced Oxidation FGD E fficiency , % (A) 98 98 (B , C ) NOx Control LNB w/OFA and SCR LNB w/OFA and SCR SCR E fficiency , % (A) 86 86 Ammonia S lip (end of catalyst life), ppm v 2 2 Particulate Control Fabric Filter Fabric Filter Fabric Filter efficiency , % (A) 99.8 99.8 Ash Distribution, Fly/Bottom 80% / 20% 80% / 20% Mercury Control Co

- benefit Capture Co

- benefit Capture Mercury removal efficiency , % (A) 90 90 CO 2 

## Control N/A Econamine Overall CO 2 

## Capture (A) N/A 90 .2 %
CO 2 

## Sequestration N/A Off

- site Saline Formation A. Removal efficiencies are based on the FG content 

## B. An SO 2 

### polishing step is included to meet more stringent SOx content limits in the FG (< 10 ppmv) to reduce formation of amine HSS during the CO 2 

### absorption process 

## C. SO 2 

### exiting the post

- FGD polishing step is absorbed in the CO 2 

### capture process making stack emissions negligible


## The balance of plant assumptions are common to all cases and were presented previously in Balance of Plant

– Cases 11 and 12

Exhibit 4

- 6

.

### Cost and Performance Baseline for Fossil Energy Plants

385 

## 4.3.3 Single trains are used throughout the design with exceptions where equipment capacity requires an additional train. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems: Sparing Philosophy

**•** One dry

- bottom, wall

- fired PC SC boiler (1 x 100%)

**•** Two SCR reactors (2 x 50%)

**•** Two single

- stage, in

- line, multi

- compartment fabric filters (2 x 50%)

**•** One wet limestone forced oxidation positive pressure absorber (1 x 100%)

**•** One steam turbine (1 x 100%)

**•** For Case 12 only, two parallel Econamine CO 2 

## absorption systems, with each system consisting of two absorbers, strippers , and ancillary equipment (2 x 50%)
4.3.4 The plant produces a net output of 550 MWe a t a net plant efficiency of 39.3 percent (HHV basis). Case 11 Performance Results

Overall performance for the plant is summarized in Exhibit 4

- 34 , which includes auxiliary power requirements.

### Cost and Performance Baseline for Fossil Energy Plants

386 

## Exhibit 4

- 34 Case 11 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Steam Turbine Power 580,400 TOTAL (STEAM TURBINE) POWER, kWe 5 80 , 400 AUXILIARY LOAD SUMMARY, kWe Coal Handling and Conveying 440 Pulverizers 2,780 Sorbent Handling & Reagent Preparation 890 Ash Handling 530 Primary Air Fans 1,300 Forced Draft Fans 1,660 Induced Draft Fans 7,050 SCR 50 Baghouse 70 Wet FGD 2,970 Miscellaneous Balance of Plant 2,3 

## 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 800 Circulating Water Pum ps 4,730 Ground Water Pumps 48 0 Cooling Tower Fans 2,440 Transformer Losses 1,820 TOTAL AUXILIARIES, kWe 30, 41 0 NET POWER, kWe 5 49 , 99 0 Net Plant Efficiency (HHV) 3 9

. 3 % Net Plant Heat Rate , kJ/kWh (Btu/kWh) 9,16 5 (8,68 7 ) CONDENSER COOLING DUTY, 10 6 

## kJ /h r (10 6 

## Btu /h r ) 2,298 (2,178) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 185,759 (409,528) Limestone Sorbent Feed, kg/h r (lb/h r ) 18, 437 (40, 646 ) Thermal Input, kWt 1 

## 1, 4 00 , 1 62 Raw Water Withdrawal, m 3 

## /min (gpm) 20.1 (5,321) Raw Water Consumption, m 3 

## /min (gpm) 16.0 (4,227)
1. HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2. Boiler feed pumps are turbine driven 3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

387 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 11 is presented in Environmental Performance

Exhibit 4

- 35

. Exhibit 4

- 35 Case 11 Air Emissions

kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)
SO 2 

## 0.037 (0.086) 1,385 (1,526) 0.320 (.71) NOx 0.030 (0.070) 1,130 (1,245) 0.261 (.576) Particulates 0.006 (0.0130) 210 (231) 0.049 (.107) Hg 4.91E

- 7 (1.14E

- 6) 0.018 (0.020) 4.27E

- 6 (9.41E

- 6)
CO 2 

## 87.5 (203.5) 3,284,245 (3,620,261) 760 (1,675)

CO 2 1 

## 80 2 (1,7 68 )

1 

### CO 2 

### emissions based on net power instead of gross power


## SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The saturated FG exiting the scrubber is vented through the plant stack. NOx emissions are controlled to about 0.5 lb/10 6 

## Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 

## Btu. Particulate emissions are controlled using a pulse jet fabric filter , which operates at an efficiency of 99.8 percent. Co

- benefi t capture results in a 90 percent reduction of mercury emissions. CO 2 

## emissions represent the uncontrolled discharge from the process. The carbon balance for the plant is shown in Exhibit 4

- 36

. The carbon input to the plant consists of carbon in the coal , carbon in the air , and carbon in the limestone reagent used in the FGD. Carbon in the air is not neglected here since the Aspen model accounts for ai r components throughout. Carbon leaves the plant mostly as CO 2 

## through the stack but also leaves as gypsum. Exhibit 4

- 36 Case 11 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 118,411 (261,052) Stack Gas 120,377 (265,385) Air (CO 2 

## ) 257 (567) FGD Product 163 (358 ) FGD Reagent 1,871 (4,124) Total 120,539 (265,744) Total 120,539 (265,744)

### Cost and Performance Baseline for Fossil Energy Plants

388 

## Exhibit 4

- 37 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes sulfur emitted in the stack gas and the sulfur recovered from the FGD a s gypsum.

Exhibit 4

- 37 Case 11 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 4,656 (10,264) Stack Gas 93 (205) FGD Product 4,563 (10,059) Total 4,656 (10,264) Total 4,656 (10,264)

Exhibit 4

- 38 s hows the overall water balance for the plant. Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and is re

- used as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 p ercent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such as FDG makeup, BFW makeup, and cooling tower makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the wa ter source from which it was withdrawn. Water consumption represents the net impact of the plant process on the water source balance. Exhibit 4

- 38 Case 11 Water Balance

Water Use Water Demand,

m 3 

## /min (gpm) Internal Recycle, m 3 

## /min (gpm) Raw Water Withdrawal,
m 3 

## /min (gpm) Process Water Discharge,

m 3 

## /min (gpm) Raw Water Consumption,
m 3 

## /min (gpm)

FGD Makeup 3.6 (951) 0.0 (0) 3.6 (951) 0.0 (0) 3.6 (951) BFW Makeup 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) 0.0 (0) Cooling Tower 18.4 (4,863) 1.9 (492) 16.5 (4,370) 4.1 (1,094) 12.4 (3,277)
Total 22.0 (5,813) 1.9 (492) 20.1 (5,321) 4.1 (1,094) 16.0 (4,227)

### Cost and Performance Baseline for Fossil Energy Plants

389 

## A heat and mass balance diagram is shown for the Case 11 PC boiler, the FGD unit and steam cycle in Heat and Mass Balance Diagrams

Exhibit 4

- 39 and Exhibit 4

- 40

. An overall plant energy balance is provided in tabular form in Exhibit 4

- 41 . The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4

- 34 ) is calculated by multiplying the power out by a generator efficiency of 98.4 percent.

### Cost and Performance Baseline for Fossil Energy Plants

390 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

391 

## Exhibit 4

- 39 Case 11 Heat and Mass Balance, Supercritical PC Boiler without CO 2 

## Capture

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Ash Slurry

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 1 OF 2 B ITUMINOUS B ASELINE S TUDY C ASE 11 S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- 11

- PG

- 1 

### Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR

COAL ASH From Feedwater Heaters Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

409 , 528 W 77

. 8 T 16

. 1 P 17

. 5 H 66

. 4 T 15

. 3 P 14

. 8 H 3 , 669 , 421 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 494

. 7 H

3 , 041 , 946 W

1 , 100

. 0 T

655

. 8 P 1 , 570

. 2 H

Single Reheat Extraction from

HP Turbine

946 , 145 W 59

. 0 T 14

. 7 P 13

. 0 H 3 , 080 , 006 W 59

. 0 T 14

. 7 P 13

. 0 H 71 , 175 W

59

. 0 T 14

. 7 P 13

. 0 H 4 , 498 , 911 W 337

. 0 T 14

. 4 P 140

. 7 H

7 , 942 W 31 , 769 W

3 , 041 , 946 W 669

. 2 T 710

. 8 P 1 , 325

. 4 H

3 , 669 , 421 W 556

. 6 T 4 , 185

. 0 P

552

. 5 H 5 4 , 713 , 221 W 135

. 0 T 14

. 8 P 128

. 0 H

1 2

4 7

9 ID FANS 4 , 467 , 142 W 337

. 0 T 14

. 2 P 132

. 8 H

Gross Plant Power : 580 MWe Auxiliary Load : 30 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 39

. 3 % Net Plant Heat Rate : 8 , 687 BTU / KWe Lime /Ash
Flue Gas OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15

14 11 357

. 4 T 15

. 3 P 138

. 0 H

134 , 744 W 59

. 0 T 15

. 0 P 46 , 465 W 332

. 9 T 45

. 0 P 381 , 174 W 59

. 0 T 14

. 7 P

70 , 244 W 135

. 0 T 14

. 8 P 

### Baghouse

3

6

8 10 12 13 16

17

18 19

20 21

DOE / NETL
SC PC P LANT C ASE 11

### Cost and Performance Baseline for Fossil Energy Plants

392 

## Exhibit 4

- 40 Case 11 Heat and Mass Balance, Supercritical Steam Cycle

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 2 OF 2 DWG

. NO

. BB

- HMB

- CS

- 11

- PG

- 2 B ITUMINOUS B ASELINE S TUDY C ASE 11 S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL

P

- 1028 P

- 1048 To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 3 , 669 , 421 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 494

. 7 H2,900.0P

169 , 635 W 888

. 4 T 300

. 8 P 1 , 467

. 0 H 327 , 489 W

663

. 9 T 689

. 5 P 1 , 323

. 6 H Single Reheat Extraction to

Boiler 3 , 041 , 946 W 669

. 2 T 710

. 8 P 1 , 325

. 4 H710.8P1,115.5P

269 , 128 W

772

. 0 T 1 , 085

. 0 P 1 , 367

. 5 H710.8P710.8P310.1P137.7P137.7P 223 , 857 W 687

. 5 T 134

. 9 P 1 , 370

. 8 H

223 , 857 W 126

. 1 T

2

. 0 P 1 , 093

. 5 H 2 , 775 , 839 W 101

. 1 T

1

. 0 P 853

. 8 H

2 , 793 W 212

. 0 T 14

. 7 P 179

. 9 H72.7P19.2P8.4P

101

. 4 T 250

. 0 P 70

. 0 H 2 , 793 W 713

. 5 T 137

. 7 P 1 , 383

. 8 H 2 , 775 , 839 W 101

. 1 T

1

. 0 P 69

. 1 H

2 , 775 , 839 W 102

. 6 T 245

. 0 P 71

. 2 H 2 , 775 , 839 W 141

. 4 T 240

. 0 P 109

. 8 H

480 , 444 W 112

. 6 T

1

. 4 P 80

. 5 H 388 , 060 W

151

. 4 T

3

. 9 P 119

. 2 H 2 , 775 , 839 W 296

. 9 T 225

. 0 P 266

. 5 H

766 , 252 W

369

. 5 T 172

. 2 P 341

. 9 H 2 , 775 , 839 W 218

. 0 T 230

. 0 P 186

. 4 H

596 , 617 W

429

. 6 T 342

. 2 P 407

. 0 H 269 , 128 W

511

. 5 T 753

. 7 P 501

. 2 H 3 , 669 , 421 W 419

. 6 T 4 , 195

. 0 P 400

. 2 H 3 , 669 , 421 W 501

. 5 T 4 , 190

. 0 P 488

. 9 H

DEAERATOR

BOILER FEED PUMPS 3 , 669 , 421 W 556

. 6 T 4 , 185

. 0 P

552

. 5 H 3 , 041 , 946 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 2 H

200 , 638 W 228

. 0 T 20

. 0 P 196

. 0 H 299 , 542 W 188

. 4 T

9

. 0 P 156

. 2 H

2 , 775 , 839 W 178

. 4 T 235

. 0 P 146

. 7 H 127 , 330 W

696

. 6 T 133

. 6 P 1 , 375

. 5 H 200 , 638 W 545

. 6 T 69

. 0 P 1 , 304

. 2 H 98 , 904 W 293

. 8 T 18

. 2 P 1 , 188

. 3 H 88 , 519 W 211

. 3 T

8

. 1 P 1 , 152

. 2 H 92 , 383 W 146

. 4 T

3

. 4 P 1 , 077

. 8 H2,900.0P 2 , 762 , 263 W 687

. 5 T 134

. 9 P 2 , 538 , 406 W 687

. 5 T 134

. 9 P 1 , 370

. 8 H3.5P2,900.0P

359

. 5 T 4 , 200

. 0 P

337

. 6 H 3 , 669 , 421 W 349

. 4 T 133

. 6 P 320

. 7 H 3 , 301 W 713

. 5 T 137

. 7 P 1 , 383

. 8 H

Gross Plant Power : 580 MWe Auxiliary Load : 30 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 39

. 3 % Net Plant Heat Rate : 8 , 687 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 7 , 482 W 713

. 5 T 137

. 7 P 1 , 383

. 8 H 19

20 21

22

23

DOE / NETL
SC PC P LANT C ASE 11

### Cost and Performance Baseline for Fossil Energy Plants

393 

## Exhibit 4

- 41 Case 11 Overall Energy Balance ( 0°C [ 32°F ] Reference)
HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,041 (4,778) 4.2 (4.0) 5,045 (4,782) Air 56.2 (53.2) 56.2 (53.2) Raw Water Makeup 76.8 (72.8) 76.8 (72.8) Limestone 0.21 (0.20) 0.21 (0.20) Auxiliary Power 110 (104) 110 (104) Totals 5,041 (4,778) 137.4 (130.3) 110 (104) 5,288 (5,012) Heat Out GJ/hr (MMBtu/hr) Bottom Ash 0.4 (0.4) 0.4 (0.4) Fly Ash + FGD Ash 1.7 (1.7) 1.7 (1.7) Flue Gas 636 (603) 636 (603) Condenser 2,298 (2,178) 2,298 (2,178) Cooling Tower Blowdown 30.8 (29.2) 30.8 (29.2) Process Losses* 231 (219) 231 (219) Power 2,089 (1,980) 2,089 (1,980) Totals 0 (0) 3,198 (3,031) 2,089 (1,980) 5,288 (5,012)

* Process losses are estimated to match the heat input to the plant. Process losses include

losses from: turbines, gas cooling, etc.

### Cost and Performance Baseline for Fossil Energy Plants

394 

## 4.3.5 Major equipment items for the SC PC plant with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 11

– Major Equipment List

4.3.6

. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 FUEL AND SORBENT HAN DLING
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 36 tonne (40 ton) 2 1
9 Feeder Vibratory 154 tonne/hr (170 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 308 tonne/hr (340 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 154 tonne (170 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 308 tonne/hr (340 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 308 tonne/hr (340 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 726 tonne (800 ton) 3 0

19 Limestone Truck Unloading Hopper N/A 36 tonne (40 ton) 1 0
20 Limestone Feeder Belt 82 tonne/hr (90 tph) 1 0 21 Limestone Conveyor No. L1 Belt 82 tonne/hr (90 tph) 1 0 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0 23 Limestone Reclaim Feeder Belt 64 tonne/hr (70 tph) 1 0 24 Limestone Conveyor No. L2 Belt 64 tonne/hr (70 tph) 1 0 25 Limestone Day Bin w/ actuator 245 tonne (270 ton) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

395 

## ACCOUNT 2 COAL AND SORBENT PRE PARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 36 tonne/hr (40 tph) 6 0

2 Coal Pulverizer Ball type or equivalent 36 tonne/hr (40 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 20 tonne/hr (22 tph) 1 1
4 Limestone Ball Mill Rotary 20 tonne/hr (22 tph) 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 75,708 liters (20,000 gal) 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1,287 lpm @ 12m H2O (340 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 341 lpm (90 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1
9 Limestone Slurry Storage Tank with Agitator Field erected 439,108 liters (116,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 908 lpm @ 9m H2O (240 gpm @ 30 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

396 

## ACCOUNT 3 FEEDWA TER AND MISCELLANEOU S SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,101,555 liters (291,000 gal) 2 0

2 Condensate Pumps Vertical canned 23,091 lpm @ 213 m H2O (6,100 gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage Tank Horizontal spray type 1,830,699 kg/hr (4,036,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed Pump/Turbine Barrel type, multi-stage, centrifugal 30,662 lpm @ 3,444 m H2O (8,100 gpm @ 11,300 ft H2O) 1 1

5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multi-stage, centrifugal 9,085 lpm @ 3,444 m H2O (2,400 gpm @ 11,300 ft H2O) 1 0

6 LP Feedwater Heater 1A/1B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 693,996 kg/hr (1,530,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0
11 HP Feedwater Heater 7 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U-tube 1,832,513 kg/hr (4,040,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

15 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

17 Closed Cycle Cooling Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

18 Closed Cycle Cooling Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

19 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1

20 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1

21 Raw Water Pumps Stainless steel, single suction 5,943 lpm @ 18 m H2O (1,570 gpm @ 60 ft H2O) 2 1

22 Ground Water Pumps Stainless steel, single suction 2,385 lpm @ 268 m H2O (630 gpm @ 880 ft H2O) 5 1

23 Filtered Water Pumps Stainless steel, single suction 1,893 lpm @ 49 m H2O (500 gpm @ 160 ft H2O) 2 1

24 Filtered Water Tank Vertical, cylindrical 1,816,998 liter (480,000 gal) 1 0

25 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 606 lpm (160 gpm) 1 1

26 Liquid Waste Treatment System -- 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

397 

## ACCOUNT 4 BOILER AND ACCESSORI ES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Boiler Supercritical, drum, wall-fired, low NOx burners, overfire air 1,832,513 kg/hr steam @ 25.5 MPa/602°C/602°C (4,040,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 0

2 Primary Air Fan Centrifugal 235,868 kg/hr, 3,220 m3/min @ 123 cm WG (520,000 lb/hr, 113,700 acfm @ 48 in. WG) 2 0

3 Forced Draft Fan Centrifugal 768,385 kg/hr, 10,486 m3/min @ 47 cm WG (1,694,000 lb/hr, 370,300 acfm @ 19 in. WG) 2 0

4 Induced Draft Fan Centrifugal 1,114,476 kg/hr, 23,469 m3/min @ 91 cm WG (2,457,000 lb/hr,

828,800 acfm @ 36 in. WG) 2 0

5 SCR Reactor Vessel Space for spare layer 2,227,139 kg/hr (4,910,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air Blower Centrifugal 133 m3/min @ 108 cm WG (4,700 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 147,631 liter (39,000 gal) 5 0

9 Ammonia Feed Pump Centrifugal 28 lpm @ 91 m H2O (7 gpm @ 300 ft H2O) 2 1

### Cost and Performance Baseline for Fossil Energy Plants

398 

## ACCOUNT 5 FLUE GAS CLEANUP

ACCOUNT 6 COMBUSTION TURBINE/A CCESSORIES N/A Equipment No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter Single stage, highratio with pulse-jet online cleaning system 1,114,476 kg/hr (2,457,000 lb/hr) 99.8% efficiency 2 0

2 Absorber Module Counter-current open spray 44,769 m3/min (1,581,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 155,202 lpm @ 64 m H2O (41,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 3,975 lpm (1,050 gpm) at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 78 m3/min @ 0.3 MPa (2,770 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 984 lpm (260 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 32 tonne/hr (35 tph) of 50 wt % slurry 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 606 lpm @ 12 m H2O (160 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 378,541 lpm (100,000 gal) 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 3,180 lpm @ 21 m H2O (840 gpm @ 70 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

399 

## ACCOUNT 7 HRSG, DUCTING & STAC K

ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x 5.6 m (19 ft) diameter 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 611 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 680 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum pumps 2,532 GJ/hr (2,400 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 1 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 473,200 lpm @ 30 m (125,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

/ 2648 GJ/hr (2510 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

400 

## ACCOUNT 10 ASH/SPENT SORBENT RE COVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- -- 2 0

3 Clinker Grinder

-- 3.6 tonne/hr (4 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 151 lpm @ 17 m H2O (40 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1

9 Hydrobins

-- 151 lpm (40 gpm) 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- -- 10 0

12 Air Blower

-- 14 m3/min @ 0.2 MPa (510 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced concrete 907 tonne (1,000 ton) 2 0

14 Slide Gate Valves

-- -- 2 0
15 Unloader

-- -- 1 0

16 Telescoping Unloading Chute

-- 91 tonne/hr (100 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

401 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3- ph, 60 Hz 1 0

2 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 32 MVA, 3- ph, 60 Hz 1 1

3 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 5 MVA, 3-ph, 60 Hz 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

402 

## 4.3.6 The cost estimating methodology was described previously in Sec tion Case 11

– Costs Estimating Results 2.7

. Exhibit 4

- 42 shows the total plant capital cost summary organized by cost account and Exhibit 4

- 43 shows a more de tailed breakdown of the capital costs as well as owner’s costs, TOC, and TASC

. Exhibit 4

- 44 shows the initial and annual O&M costs. The estimated TO C of the SC PC boiler with no CO 2 

## capture is $ 2,02 4 /kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project contingency is 8.7 percent of the T OC. The COE is 5 8

. 9 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

403 

## Exhibit 4

- 42 Case 11 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 11 - 1x550 MWnet SuperCritical PC Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $16,381 $4,414 $9,819 $0 $0 $30,614 $2,747 $0 $5,004 $38,365 $70

2 COAL & SORBENT PREP & FEED $11,008 $637 $2,793 $0 $0 $14,438 $1,265 $0 $2,356 $18,059 $33

3 FEEDWATER & MISC. BOP SYSTEMS $42,453 $0 $19,927 $0 $0 $62,380 $5,705 $0 $11,064 $79,149 $144

4 PC BOILER 4.1 PC Boiler & Accessories $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539

5 FLUE GAS CLEANUP $79,643 $0 $27,049 $0 $0 $106,692 $10,211 $0 $11,690 $128,593 $234

5B CO 2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68 SUBTOTAL 7 $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $51,625 $0 $6,866 $0 $0 $58,491 $5,606 $0 $6,410 $70,507 $128 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $22,954 $1,089 $12,590 $0 $0 $36,633 $3,228 $0 $5,580 $45,441 $83 SUBTOTAL 8 $74,579 $1,089 $19,456 $0 $0 $95,124 $8,833 $0 $11,990 $115,948 $211

9 COOLING WATER SYSTEM $12,303 $6,296 $11,466 $0 $0 $30,066 $2,830 $0 $4,475 $37,370 $68

10 ASH/SPENT SORBENT HANDLING SYS $4,409 $140 $5,895 $0 $0 $10,444 $1,004 $0 $1,178 $12,627 $23

11 ACCESSORY ELECTRIC PLANT $17,541 $6,187 $18,041 $0 $0 $41,769 $3,682 $0 $5,617 $51,068 $93

12 INSTRUMENTATION & CONTROL $8,739 $0 $8,862 $0 $0 $17,601 $1,596 $0 $2,358 $21,555 $39

13 IMPROVEMENTS TO SITE $2,969 $1,707 $5,984 $0 $0 $10,660 $1,052 $0 $2,342 $14,054 $26

14 BUILDINGS & STRUCTURES $0 $22,720 $21,552 $0 $0 $44,272 $3,994 $0 $7,240 $55,506 $101

TOTAL COST $444,675 $44,192 $250,892 $0 $0 $739,759 $69,584 $0 $96,558 $905,901 $1,647 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

404 

## Exhibit 4

- 43 Case 11 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,368 $0 $1,538 $0 $0 $4,906 $438 $0 $802 $6,146 $11 1.2 Coal Stackout & Reclaim $4,352 $0 $986 $0 $0 $5,338 $467 $0 $871 $6,676 $12 1.3 Coal Conveyors $4,046 $0 $976 $0 $0 $5,022 $440 $0 $819 $6,282 $11 1.4 Other Coal Handling $1,059 $0 $226 $0 $0 $1,284 $112 $0 $209 $1,606 $3 1.5 Sorbent Receive & Unload $135 $0 $41 $0 $0 $175 $15 $0 $29 $219 $0 1.6 Sorbent Stackout & Reclaim $2,176 $0 $399 $0 $0 $2,574 $224 $0 $420 $3,218 $6 1.7 Sorbent Conveyors $776 $168 $190 $0 $0 $1,135 $98 $0 $185 $1,418 $3 1.8 Other Sorbent Handling $469 $110 $246 $0 $0 $825 $73 $0 $135 $1,032 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $4,136 $5,218 $0 $0 $9,354 $879 $0 $1,535 $11,767 $21 SUBTOTAL 1. $16,381 $4,414 $9,819 $0 $0 $30,614 $2,747 $0 $5,004 $38,365 $70 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $1,929 $0 $376 $0 $0 $2,305 $201 $0 $376 $2,881 $5 2.2 Coal Conveyor to Storage $4,939 $0 $1,078 $0 $0 $6,017 $526 $0 $981 $7,524 $14 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $3,695 $159 $768 $0 $0 $4,622 $402 $0 $754 $5,778 $11 2.6 Sorbent Storage & Feed $445 $0 $171 $0 $0 $616 $55 $0 $101 $771 $1 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $478 $401 $0 $0 $879 $81 $0 $144 $1,105 $2 SUBTOTAL 2. $11,008 $637 $2,793 $0 $0 $14,438 $1,265 $0 $2,356 $18,059 $33 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 FeedwaterSystem $18,623 $0 $6,016 $0 $0 $24,638 $2,153 $0 $4,019 $30,810 $56 3.2 Water Makeup & Pretreating $4,460 $0 $1,436 $0 $0 $5,895 $557 $0 $1,291 $7,743 $14 3.3 Other Feedwater Subsystems $5,701 $0 $2,409 $0 $0 $8,111 $727 $0 $1,326 $10,163 $18 3.4 Service Water Systems $874 $0 $476 $0 $0 $1,350 $127 $0 $295 $1,772 $3 3.5 Other Boiler Plant Systems $6,807 $0 $6,721 $0 $0 $13,528 $1,285 $0 $2,222 $17,035 $31 3.6 FO Supply Sys & Nat Gas $255 $0 $319 $0 $0 $574 $54 $0 $94 $723 $1 3.7 Waste Treatment Equipment $3,024 $0 $1,724 $0 $0 $4,747 $462 $0 $1,042 $6,251 $11 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,709 $0 $828 $0 $0 $3,536 $340 $0 $775 $4,652 $8 SUBTOTAL 3. $42,453 $0 $19,927 $0 $0 $62,380 $5,705 $0 $11,064 $79,149 $144 4 PC BOILER 4.1 PC Boiler & Accessories $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $157,253 $0 $88,235 $0 $0 $245,488 $23,891 $0 $26,938 $296,317 $539

### Cost and Performance Baseline for Fossil Energy Plants

405 

## Exhibit 4

- 43 Case 11 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $55,471 $0 $11,942 $0 $0 $67,413 $6,427 $0 $7,384 $81,224 $148 5.2 Other FGD $2,895 $0 $3,280 $0 $0 $6,175 $599 $0 $677 $7,452 $14 5.3 Bag House & Accessories $15,622 $0 $9,914 $0 $0 $25,536 $2,461 $0 $2,800 $30,797 $56 5.4 Other Particulate Removal Materials $1,057 $0 $1,131 $0 $0 $2,189 $212 $0 $240 $2,641 $5 5.5 Gypsum Dewatering System $4,598 $0 $781 $0 $0 $5,379 $512 $0 $589 $6,480 $12 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $79,643 $0 $27,049 $0 $0 $106,692 $10,211 $0 $11,690 $128,593 $234 5B CO 2 REMOVAL & COMPRESSION 5B.1 CO 2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO 2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $8,675 $0 $5,574 $0 $0 $14,249 $1,242 $0 $2,324 $17,816 $32 7.4 Stack $8,721 $0 $5,103 $0 $0 $13,824 $1,331 $0 $1,516 $16,671 $30 7.9 Duct & Stack Foundations $0 $1,000 $1,137 $0 $0 $2,137 $200 $0 $467 $2,804 $5 SUBTOTAL 7. $17,397 $1,000 $11,814 $0 $0 $30,211 $2,773 $0 $4,307 $37,291 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $51,625 $0 $6,866 $0 $0 $58,491 $5,606 $0 $6,410 $70,507 $128 8.2 Turbine Plant Auxiliaries $347 $0 $744 $0 $0 $1,091 $107 $0 $120 $1,317 $2 8.3 Condenser & Auxiliaries $6,712 $0 $2,288 $0 $0 $9,000 $861 $0 $986 $10,848 $20 8.4 Steam Piping $15,895 $0 $7,837 $0 $0 $23,732 $1,994 $0 $3,859 $29,585 $54 8.9 TG Foundations $0 $1,089 $1,721 $0 $0 $2,810 $266 $0 $615 $3,691 $7 SUBTOTAL 8. $74,579 $1,089 $19,456 $0 $0 $95,124 $8,833 $0 $11,990 $115,948 $211 9 COOLING WATER SYSTEM 9.1 Cooling Towers $9,084 $0 $2,829 $0 $0 $11,913 $1,139 $0 $1,305 $14,358 $26 9.2 Circulating Water Pumps $1,887 $0 $116 $0 $0 $2,003 $169 $0 $217 $2,389 $4 9.3 Circ.Water System Auxiliaries $498 $0 $66 $0 $0 $565 $54 $0 $62 $680 $1 9.4 Circ.Water Piping $0 $3,950 $3,828 $0 $0 $7,779 $728 $0 $1,276 $9,783 $18 9.5 Make-up Water System $438 $0 $585 $0 $0 $1,024 $98 $0 $168 $1,290 $2 9.6 Component Cooling Water Sys $395 $0 $314 $0 $0 $709 $67 $0 $116 $892 $2 9.9 Circ.Water System Foundations& Structures $0 $2,346 $3,727 $0 $0 $6,073 $575 $0 $1,330 $7,977 $15 SUBTOTAL 9. $12,303 $6,296 $11,466 $0 $0 $30,066 $2,830 $0 $4,475 $37,370 $68

### Cost and Performance Baseline for Fossil Energy Plants

406 

## Exhibit 4

- 43 Case 11 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $590 $0 $1,818 $0 $0 $2,408 $236 $0 $264 $2,909 $5 10.7 Ash Transport & Feed Equipment $3,819 $0 $3,912 $0 $0 $7,731 $739 $0 $847 $9,317 $17 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $140 $165 $0 $0 $305 $29 $0 $67 $401 $1 SUBTOTAL 10. $4,409 $140 $5,895 $0 $0 $10,444 $1,004 $0 $1,178 $12,627 $23 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,598 $0 $260 $0 $0 $1,858 $172 $0 $152 $2,182 $4 11.2 Station Service Equipment $2,824 $0 $928 $0 $0 $3,752 $351 $0 $308 $4,410 $8 11.3 Switchgear & Motor Control $3,247 $0 $552 $0 $0 $3,798 $352 $0 $415 $4,565 $8 11.4 Conduit & Cable Tray $0 $2,035 $7,038 $0 $0 $9,073 $878 $0 $1,493 $11,445 $21 11.5 Wire & Cable $0 $3,841 $7,414 $0 $0 $11,255 $948 $0 $1,830 $14,034 $26 11.6 Protective Equipment $260 $0 $885 $0 $0 $1,146 $112 $0 $126 $1,383 $3 11.7 Standby Equipment $1,277 $0 $29 $0 $0 $1,306 $120 $0 $143 $1,568 $3 11.8 Main Power Transformers $8,335 $0 $172 $0 $0 $8,507 $646 $0 $915 $10,068 $18 11.9 Electrical Foundations $0 $311 $763 $0 $0 $1,074 $103 $0 $235 $1,412 $3 SUBTOTAL 11. $17,541 $6,187 $18,041 $0 $0 $41,769 $3,682 $0 $5,617 $51,068 $93 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $450 $0 $270 $0 $0 $720 $68 $0 $118 $906 $2 12.7 Distributed Control System Equipment $4,543 $0 $794 $0 $0 $5,337 $495 $0 $583 $6,415 $12 12.8 Instrument Wiring & Tubing $2,463 $0 $4,885 $0 $0 $7,348 $626 $0 $1,196 $9,170 $17 12.9 Other I & C Equipment $1,284 $0 $2,913 $0 $0 $4,197 $407 $0 $460 $5,064 $9 SUBTOTAL 12. $8,739 $0 $8,862 $0 $0 $17,601 $1,596 $0 $2,358 $21,555 $39

### Cost and Performance Baseline for Fossil Energy Plants

407 

## Exhibit 4

- 43 Case 11 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $50 $998 $0 $0 $1,048 $104 $0 $230 $1,382 $3 13.2 Site Improvements $0 $1,657 $2,058 $0 $0 $3,715 $366 $0 $816 $4,897 $9 13.3 Site Facilities $2,969 $0 $2,928 $0 $0 $5,897 $581 $0 $1,296 $7,774 $14 SUBTOTAL 13. $2,969 $1,707 $5,984 $0 $0 $10,660 $1,052 $0 $2,342 $14,054 $26 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,281 $7,282 $0 $0 $15,564 $1,399 $0 $2,544 $19,507 $35 14.2 Turbine Building $0 $11,828 $11,024 $0 $0 $22,851 $2,060 $0 $3,737 $28,648 $52 14.3 Administration Building $0 $586 $620 $0 $0 $1,206 $109 $0 $197 $1,513 $3 14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $301 $27 $0 $49 $378 $1 14.5 Water Treatment Buildings $0 $566 $516 $0 $0 $1,081 $97 $0 $177 $1,356 $2 14.6 Machine Shop $0 $392 $264 $0 $0 $656 $58 $0 $107 $821 $1 14.7 Warehouse $0 $266 $267 $0 $0 $532 $48 $0 $87 $668 $1 14.8 Other Buildings & Structures $0 $217 $185 $0 $0 $402 $36 $0 $66 $504 $1 14.9 Waste Treating Building & Str. $0 $416 $1,262 $0 $0 $1,678 $159 $0 $276 $2,112 $4 SUBTOTAL 14. $0 $22,720 $21,552 $0 $0 $44,272 $3,994 $0 $7,240 $55,506 $101

TOTAL COST $444,675 $44,192 $250,892 $0 $0 $739,759 $69,584 $0 $96,558 $905,901 $1,647
Owner's Costs Preproduction Costs 6 Months All Labor $7,258 $13 1 Month Maintenance Materials $895 $2 1 Month Non-fuel Consumables $892 $2 1 Month Waste Disposal $235 $0 25% of 1 Months Fuel Cost at 100% CF $1,427 $3 2% of TPC $18,118 $33 Total $28,826 $52 Inventory Capital 60 day supply of fuel and consumables at 100% CF $12,944 $24 0.5% of TPC (spare parts) $4,530 $8 Total $17,474 $32
Initial Cost for Catalyst and Chemicals $0 $0 Land $900 $2 Other Owner's Costs $135,885 $247

Financing Costs $24,459 $44 Total Overnight Costs (TOC) $1,113,445 $2,024 TASC Multiplier (IOU, low-risk, 35 year) 1.134 Total As-Spent Cost (TASC) $1,262,647 $2,296

### Cost and Performance Baseline for Fossil Energy Plants

408 

## Exhibit 4

- 44 Case 11 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 11 - 1x550 MWnet SuperCritical PC Heat Rate-net (Btu/kWh): 8,686 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 9.0 9.0 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 14.0 14.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $5,524,319 $10.044 Maintenance Labor Cost $6,088,905 $11.070 Administrative & Support Labor $2,903,306 $5.279 Property Taxes and Insurance $18,118,017 $32.941 TOTAL FIXED OPERATING COSTS $32,634,546 $59.333 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $9,133,357 $0.00223

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 3,884 1.08 $0 $1,303,324 $0.00032

Chemicals

MU & WT Chem.(lbs) 0 18,799 0.17 $0 $1,009,427 $0.00025 Limestone (ton) 0 488 21.63 $0 $3,273,667 $0.00080 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 0 0 2,249.89 $0 $0 $0.00000 NaOH (tons) 0 0 433.68 $0 $0 $0.00000 H2SO4 (tons) 0 0 138.78 $0 $0 $0.00000 Corrosion Inhibitor 0 0 0.00 $0 $0 $0.00000 Activated Carbon (lb) 0 0 1.05 $0 $0 $0.00000 Ammonia (19% NH3) ton 0 74 129.80 $0 $2,960,869 $0.00072 Subtotal Chemicals $0 $7,243,963 $0.00177

Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.31 5,775.94 $0 $553,798 $0.00014 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $553,798 $0.00014
Waste Disposal

Fly Ash (ton) 0 381 16.23 $0 $1,919,038 $0.00047 Bottom Ash (ton) 0 95 16.23 $0 $479,759 $0.00012 Subtotal-Waste Disposal $0 $2,398,797 $0.00059

By-products & Emissions

Gypsum (tons) 0 759 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $20,633,239 $0.00504 Fuel (ton) 0 4,914 38.18 $0 $58,217,892 $0.01422

### Cost and Performance Baseline for Fossil Energy Plants

409 

## 4.3.7 The plant configuration for Case 12, SC PC, is the same as Case 11 with the exception that the Econamine CDR technolog y was added for CO 2 

## capture. The nominal net output is maintained at 550 MW by increasing the boiler size and turbine/generator size to account for the greater auxiliary load imposed by the CDR facility. Unlike the IGCC cases where gross output was fixed by the available size of the CT s, the PC cases utilize boilers and steam turbines that can be procured at nearly any desired output making it possible to maintain a constant net output. Case 12

– Supercritical PC with CO 2 

## Capture

The process description for Case 12 is essentially the same as Case 11 with one notable exception , the addition of CO 2 

## capture. A BFD and stream tables for Case 12 are shown in Exhibit 4

- 45 and Exhibit 4

- 46 , respectively. Since the CDR facility process description was provided in Section 4.1.7 , it is no t repeated here.
4.3.8 The Case 12 modeling assumptions were presented previously in Section Case 12 Performance Results 4.3.2

. The plant produces a net output of 5 50 MW at a net plant efficiency of 28.4 percent (HHV basis). Overall plant performance is summarized in Exhibit 4

- 47 , which includes auxiliary power requirements. The CDR facility, including CO 2 

## compression, accounts for approximately 58 percent of the auxiliary plant load. The CWS ( CWP s and cooling tower fan) accounts for over 1 3 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facili ty

### Cost and Performance Baseline for Fossil Energy Plants

410 

## Exhibit 4

- 45 Case 12 Block Flow Diagram , Su per critical Unit with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

411 

## Exhibit 4

- 46 Case 12 Stream Table , Su per critical Unit with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 66,876 66,876 1,990 20,544 20,544 2,818 1,546 0 0 94,107 0 94,107 94,107 3,385 V-L Flowrate (kg/hr) 1,929,852 1,929,852 57,422 592,830 592,830 81,325 44,605 0 0 2,799,052 0 2,799,052 2,799,052 60,975 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 256,652 4,977 19,910 19,910 0 0 25,966
Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 327.40

--- 308.96 322.83

--- Density (kg/m 3 ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- V-L Flowrate (lb mol /hr) 147,437 147,437 4,387 45,291 45,291 6,213 3,408 0 0 207,471 0 207,471 207,471 7,462 V-L Flowrate (lb/hr) 4,254,595 4,254,595 126,595 1,306,967 1,306,967 179,291 98,338 0 0 6,170,854 0 6,170,854 6,170,854 134,426 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 565,820 10,973 43,893 43,893 0 0 57,245
Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0 Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- 140.8

--- 132.8 138.8

--- Density (lb/ft 3 ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- 0.050

--- 0.049 0.052

--- A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

412 

## Exhibit 4

- 46 Case 12 Stream Table , Su per critical Unit with CO 2 

## Capture (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 V-L Mole Fraction

Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0000 0.0005 0.0004 0.1350 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 13,485 975 250 102,548 77,286 12,511 12,481 44,922 44,922 126,511 103,236 103,236 49,304 49,304 V-L Flowrate (kg/hr) 242,941 28,289 4,498 2,956,531 2,177,293 549,344 548,802 809,288 809,288 2,279,133 1,859,826 1,859,826 888,227 888,227 Solids Flowrate (kg/hr) 0 0 40,138 0 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 40 Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.92 24.23 4.90 4.52 0.01 1.69 Enthalpy (kJ/kg) A -46.80 191.58

--- 301.43 93.86 19.49 -211.71 3,045.10 636.31 3,476.62 3,081.81 3,652.22 2,115.77 166.72 Density (kg/m 3 ) 1,003.1 2.4

--- 1.1 1.1 2.9 795.9 2.0 916.0 69.2 18.7 11.6 0.1 993.2 V-L Molecular Weight 18.015 29.029

--- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015
V-L Flowrate (lb mol /hr) 29,730 2,148 550 226,080 170,387 27,582 27,516 99,037 99,037 278,909 227,597 227,597 108,697 108,697 V-L Flowrate (lb/hr) 535,592 62,368 9,916 6,518,034 4,800,109 1,211,096 1,209,902 1,784,175 1,784,175 5,024,628 4,100,215 4,100,215 1,958,206 1,958,206 Solids Flowrate (lb/hr) 0 0 88,488 0 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 59 357 136 136 89 69 95 556 304 1,100 668 1,100 101 103 Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 133.6 3,514.7 710.8 655.8 1.0 245.0 Enthalpy (Btu/lb) A -20.1 82.4

--- 129.6 40.4 8.4 -91.0 1,309.2 273.6 1,494.7 1,324.9 1,570.2 909.6 71.7 Density (lb/ft 3 ) 62.622 0.149

--- 0.067 0.070 0.184 49.684 0.123 57.184 4.319 1.166 0.722 0.004 62.002

### Cost and Performance Baseline for Fossil Energy Plants

413 

## Exhibit 4

- 47 Case 12 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Steam Turbine Power 662,800 TOTAL (STEAM TURBINE) POWER, kWe 662,800 AUXILIARY LOAD SUMMARY, kWe Coal Handling and Conveying 510 Pulverizers 3,850 Sorbent Handling & Reagent Preparation 1,250 Ash Handling 740 Primary Air Fans 1,800 Forced Draft Fans 2,300 Induced Draft Fans 11,120 SCR 70 Baghouse 100 Wet FGD 4,110 Econamine FG Plus Auxiliaries 20,600 CO 2 

## Compression 44,890 Miscellaneous Balance of Plant 2,3 

## 2,000 Steam Turbine Auxiliaries 400 Condensate Pumps 560 Circulating Water Pumps 10,100 Ground Water Pumps 91 0 Cooling Tower Fans 5,230 Transformer Losses 2,290 TOTAL AUXILIARIES, kWe 112,83 0 NET POWER, kWe 5 49 , 9 7 0 Net Plant Efficiency (HHV) 28.4 % Net Plant Heat Rate , kJ/kWh (Btu/kWh) 12, 663 (12 , 002 ) CONDENSER COOLING DUTY, 10 6 

## kJ /h r (10 6 

## Btu /h r ) 1,737 (1,646 ) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 256,652 (565,820) Limestone Sorbent Feed, kg/h r (lb/h r ) 25,96 6 ( 57 , 245 ) Thermal Input, kWt 1 

## 1,934,519 Raw Water Withdrawal, m 3 

## /min (gpm) 38.1 (10,071 ) Raw Water Consumption, m 3 

## /min (gpm) 29.3 (7,733 )
1. HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2. Boiler feed pumps are turbine driven 3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

414 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section Environmental Performance

2. 4 . A summary of the plant air emissions for Case 12 is presented in Exhibit 4

- 48

. Exhibit 4

- 48 Case 12 Air Emissions
kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)

SO 2 

## 0.001 (0.002) 36 (40) 0.007 (.02)
NOx 0.030 (0.070) 1,561 (1,720) 0.316 (.697)
Particulates 0.006 (0.0130) 290 (319) 0.059 (.129) Hg 4.91E

- 7 (1.14E

- 6) 0.025 (0.028) 5.16E

- 6 (1.14E

- 5)
CO 2 

## 8.8 (20.4) 453,763 (500,188) 92 (203)
CO 2 1 

## 11 1 (2 44 )

1 

### CO 2 

### emissions based on net power instead of gross power


## SO 2 

## emissions are controlled using a wet limestone forced oxidation scrubber that achieves a removal efficiency of 98 percent. The byproduct calcium sulfate is dewatered and stored on site. The wallboard grade material can potentially be marketed and sold, but since it is highly dependent on local market conditions, no byproduct credit was taken. The SO 2 

## emissions are further reduced to 10 ppmv using a NaOH based polishing scrubber in the CDR facility. The remaining low concentration of SO 2 

## is essentially completely removed in the CDR absorber vessel resulting in very low SO 2 

## emissions. NOx emissions are controlled to about 0.5 lb/10 6 

## Btu through the use of LNBs and OFA. An SCR unit then further reduces the NOx concentration by 86 percent to 0.07 lb/10 6 

## Bt u. Particulate emissions are controlled using a pulse jet fabric filter , which operates at an efficiency of 99.8 percent. Co

- benefit capture results in a 90 percent reduction of mercury emissions. Ninety percent of the CO 2 

## in the FG is removed in CDR facil ity. The carbon balance for the plant is shown in Exhibit 4

- 49

. The carbon input to the plant consists of carbon in the coal in addition to carbon in the air and limestone for the FGD. Carbon in the air is not neglected here since the Aspen model accou nts for air components throughout . Carbon leaves the plant as CO 2 

## in the stack gas, carbon in the FGD product, and the captured CO 2 

## product. The carbon capture efficiency is defined by the following fraction: 1

- [(Stack Gas Carbon

- Air Carbon)/(Total Car bon In

- Air Carbon)] or [1

- (36, 667

- 783 ) /( 367,272

- 7 83 ) * 100 ] or 90. 2 percent

### Cost and Performance Baseline for Fossil Energy Plants

415 

## Exhibit 4

- 49 Case 12 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Coal 163,602 (360,680) Stack Gas 16,632 (36,667) Air (CO 2 

## ) 355 (783) FGD Product 274 (605) FGD Reagent 2,635 (5,809) CO 2 

## Product 149,685 (329,999) Total 166,592 (367,272) Total 166,592 (367,272)

Exhibit 4

- 50 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered from the FGD as gypsum , sulfur emitted in the stac k gas , and sulfur removed in the polishing scrubber

. Exhibit 4

- 50 Case 12 Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/hr (lb/hr) Coal 6,433 (14,182) FGD Product 6,304 (13,898) Stack Gas 2 (5) Econamine Polishing Scrubber/HS S 126 (278 )
Total 6,433 (14,182) Total 6,433 (14,182)

Exhibit 4

- 51 s hows the overall water balance for the plant. The exhibit is presented in an identical manner as for Case 11. Exhibit 4

- 51 Case 12 Water Balance

Water Use Water Demand,

m 3 

## /min (gpm) Internal Recycle, m 3 

## /min (gpm) Raw Water Withdrawal,
m 3 

## /min (gpm) Process Water Discharge,

m 3 

## /min (gpm) Raw Water Consumption,
m 3 

## /min (gpm)

Econamine 0.1 (36) 0.0 (0) 0.1 (36) 0.00 (0) 0.1 (36) FGD Makeup 5.1 (1,340) 0.0 (0) 5.1 (1,340) 0.00 (0) 5.1 (1,340) BFW Makeup 0.0 (0) 0.0 (0) 0.0 (0) 0.00 (0) 0.0 (0) Cooling Tower 39.4 (10,399) 6.5 (1,703) 32.9 (8,696) 8.9 (2,339) 24.1 (6,357)
Total 44.6 (11,774) 6.5 (1,703) 38.1 (10,071) 8.9 (2,339) 29.3 (7,733)

### Cost and Performance Baseline for Fossil Energy Plants

416 

## A heat and mass balance diagram is shown for the Case 12 PC boiler, the FGD unit, CDR system , and steam cycle in Heat and Mass Balance Diagrams

Exhibit 4

- 52 and Exhibit 4

- 53

. An overall plant energy balance is provided in tabular form in Exhibit 4

- 54 . The power out is the steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 4

- 47 ) is calculated by multiplying the power out by a generator efficiency of 98.5 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient via the cooling tower. The same is true of the condenser heat out stream. The CO 2 

## compressor intercooler load is included in the Econamine process heat out stream.

### Cost and Performance Baseline for Fossil Energy Plants

417 

## Exhibit 4

- 52 Case 12 Heat and Mass Balance, Supercritical PC Boiler with CO 2 

## Capture

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal /Ash Slurry

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 1 OF 2 B ITUMINOUS B ASELINE S TUDY C ASE 12 S UPERCRITICAL P ULVERIZED C OAL B OILER AND G AS C LEANUP S YSTEMS

DWG

. NO

. BB

- HMB

- CS

- 12

- PG

- 1 

### Pulverized Coal Boiler SCR AMMONIA

INFILTRATION AIR

AIR

AIR

COAL

ASH From Feedwater Heaters

Single Reheat To IP Turbine Throttle Steam To HP Turbine 

### FGD

ASH

FORCED DRAFT FANS

PRIMARY AIR FANS STACK

565 , 820 W 77

. 8 T 16

. 1 P 17

. 5 H

66

. 4 T 15

. 3 P 14

. 8 H 5 , 024 , 628 W 1 , 100

. 0 T 3 , 514

. 7 P 1 , 494

. 7 H

4 , 100 , 215 W 1 , 100

. 0 T

655

. 8 P 1 , 570

. 6 H

Single Reheat Extraction from

HP Turbine

1 , 306 , 967 W 59

. 0 T 14

. 7 P 13

. 0 H 4 , 254 , 595 W 59

. 0 T 14

. 7 P 13

. 0 H 98 , 338 W

59

. 0 T 14

. 7 P 13

. 0 H 6 , 214 , 747 W 337

. 0 T 14

. 4 P 140

. 8 H

10 , 973 W 43 , 893 W

4 , 100 , 215 W 668

. 4 T 710

. 8 P 1 , 324

. 9 H

5 , 024 , 628 W 545

. 5 T 4 , 185

. 0 P

539

. 3 H 5 6 , 518 , 034 W 135

. 8 T 14

. 9 P 129

. 6 H

1 2

4 7

8 9 ID FANS 6 , 170 , 854 W 337

. 0 T 14

. 2 P 132

. 8 H

Gross Plant Power : 663 MWe Auxiliary Load : 113 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 28

. 4 % Net Plant Heat Rate : 12 , 002 BTU / KWe Lime / Ash
Flue Gas OXIDATION AIR MAKE

- UP WATER

LIMESTONE

SLURRY GYPSUM 15

14 11 360

. 4 T 15

. 4 P 138

. 8 H

191 , 671 W 59

. 0 T 15

. 0 P 62 , 368 W 357

. 4 T 45

. 0 P 82

. 4 H 535 , 592 W 59

. 0 T 14

. 7 P

98 , 404 W 135

. 8 T 14

. 9 PSTRIPPERABSORBER FLUE GAS Acid Gas

ECONAMINE FG +

ECONAMINE CONDENSATE 18

252 , 068 W 306

. 3 T 73

. 5 P 1 , 181

. 0 H 1 , 784 , 175 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H

1 , 784 , 175 W 304

. 0 T 133

. 6 P 273

. 6 H ECONAMINE

STEAM 1 , 209 , 902 W 95

. 0 T 2 , 214

. 5 P 1 , 211 , 096 W 69

. 0 T 23

. 5 P 8

. 4 H 4 , 800 , 109 W 88

. 8 T 14

. 7 P 40

. 4 H CO 2 COMPRESSION ( INTERSTAGE

COOLING )

CO 2 PRODUCT 

### Baghouse

21

22 20 3

6 10 12 13 16

17

19

23 24

25 26

DOE / NETL
SC PC P LANT C ASE 12

### Cost and Performance Baseline for Fossil Energy Plants

418 

## Exhibit 4

- 53 Case 12 Heat and Mass Balance, Supercritical Steam Cycle

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas Sour Gas

Sour Water

Water Steam

P AGES 2 OF 2 DWG

. NO

. BB

- HMB

- CS

- 12

- PG

- 2 B ITUMINOUS B ASELINE S TUDY C ASE 12 S UPERCRITICAL P ULVERIZED C OAL P OWER B LOCK S YSTEMS LP TURBINE GENERATOR HP TURBINE IP TURBINE

CONDENSER

HOT WELL

P

- 1028 P

- 1048 To Boiler BOILER FEED PUMP TURBINE DRIVES

STEAM SEAL REGULATOR Throttle Steam Single Reheat Extraction From Boiler

GLAND SEAL CONDENSER CONDENSATE PUMPS 5 , 024 , 628 W

1 , 100

. 0 T 3 , 514

. 7 P 1 , 494

. 7 H2,900.0P

285 , 001 W 803

. 0 T 211

. 9 P 1 , 426

. 1 H 612 , 527 W

665

. 2 T 700

. 8 P 1 , 323

. 6 H Single Reheat Extraction to

Boiler

4 , 100 , 215 W 668

. 4 T 710

. 8 P 1 , 324

. 9 H710.8P1,115.5P

281 , 028 W

763

. 9 T 990

. 5 P 1 , 367

. 5 H710.8P710.8P221.9P75.0P75.0P 375 , 024 W 556

. 3 T 73

. 5 P 1 , 309

. 2 H

126

. 1 T 2

. 0 P 1 , 085

. 4 H

1 , 337 , 035 W 101

. 1 T

1

. 0 P 1 , 009

. 5 H

2 , 793 W 212

. 0 T 14

. 7 P 179

. 9 H29.0P11.4P4.5P

101

. 4 T 250

. 0 P 70

. 0 H 2 , 793 W 674

. 7 T 75

. 0 P 1 , 367

. 7 H 1 , 958 , 206 W 101

. 1 T

1

. 0 P 69

. 1 H

1 , 958 , 206 W 103

. 1 T 245

. 0 P 71

. 7 H 1 , 958 , 206 W 123

. 8 T 240

. 0 P 92

. 2 H

240 , 053 W 113

. 1 T

1

. 4 P 81

. 0 H 202 , 990 W

133

. 8 T

2

. 5 P 101

. 6 H 1 , 958 , 206 W 235

. 0 T 225

. 0 P 203

. 5 H

1 , 178 , 556 W 321

. 8 T 91

. 9 P 291

. 8 H 1 , 958 , 206 W 190

. 2 T 230

. 0 P 158

. 5 H

893 , 554 W

398

. 7 T 243

. 6 P 373

. 2 H 281 , 028 W

513

. 3 T 765

. 9 P 503

. 4 H 5 , 024 , 628 W 388

. 7 T 4 , 195

. 0 P

367

. 8 H 5 , 024 , 628 W 503

. 3 T 4 , 190

. 0 P 491

. 0 H

DEAERATOR

BOILER FEED PUMPS 5 , 024 , 628 W 545

. 5 T 4 , 185

. 0 P

539

. 3 H 24 4 , 100 , 215 W 1 , 100

. 0 T 655

. 8 P 1 , 570

. 6 H

83 , 560 W 200

. 2 T 11

. 6 P 168

. 0 H 155 , 189 W 161

. 0 T

4

. 9 P 128

. 7 H

1 , 958 , 206 W 151

. 0 T 235

. 0 P 119

. 3 H 103 , 690 W

595

. 3 T 70

. 0 P 1 , 328

. 7 H 83 , 560 W 370

. 1 T 25

. 0 P 1 , 223

. 5 H 71 , 629 W 216

. 1 T 10

. 4 P 1 , 153

. 6 H 47 , 801 W 156

. 0 T

4

. 3 P 1 , 123

. 0 H 37 , 063 W 128

. 8 T

2

. 2 P 1 , 054

. 1 H2,900.0P 3 , 731 , 302 W 556

. 3 T 73

. 5 P 1 , 309

. 2 H 1 , 572 , 104 W 556

. 3 T 73

. 5 P 1 , 309

. 2 H2.3P2,900.0P

311

. 8 T 4 , 200

. 0 P 289

. 0 H 5 , 024 , 628 W 302

. 9 T 70

. 0 P 272

. 3 H 3 , 301 W 674

. 7 T 75

. 0 P 1 , 367

. 7 H

Gross Plant Power : 663 MWe Auxiliary Load : 113 MWe Net Plant Power : 550 MWe Net Plant Efficiency , HHV : 28

. 4 % Net Plant Heat Rate : 12 , 002 BTU / KWe FWH 1 FWH 2 FWH 3 FWH 4 FWH 6 FWH 7 FWH 8 4 , 985 W 674

. 7 T 75

. 0 P 1 , 367

. 7 H 1 , 784 , 175 W 304

. 0 T 133

. 6 P 273

. 6 H ECONAMINE CONDENSATE

23 1 , 784 , 175 W 556

. 3 T 73

. 5 P 1 , 309

. 6 H ECONAMINE

STEAM

22

25 26

28

DOE / NETL
SC PC P LANT C ASE 12

### Cost and Performance Baseline for Fossil Energy Plants

419 

## Exhibit 4

- 54 Case 12 Overall Energy Balance ( 0°C [ 32°F ] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 6,964 (6,601) 5.8 (5.5) 6,970 (6,606) Air 77.6 (73.6) 77.6 (73.6) Raw Water Makeup 144.9 (137.3) 144.9 (137.3) Limestone 0.29 (0.28) 0.29 (0.28) Auxiliary Power 406 (385) 406 (385) Totals 6,964 (6,601) 228.6 (216.7) 406 (385) 7,599 (7,203) Heat Out GJ/hr (MMBtu/hr) Bottom Ash 0.6 (0.6) 0.6 (0.6) Fly Ash + FGD Ash 2.4 (2.3) 2.4 (2.3) Flue Gas 204 (194) 204 (194) Condenser 1,737 (1,646) 1,737 (1,646) CO 2 

## - 116 (

- 110)

- 116 (

- 110) Cooling Tower Blowdown 65.8 (62.3) 65.8 (62.3) Econamine Losses 3,298 (3,126) 3,298 (3,126) Process Losses* 21.3 (20.2) 21.3 (20.2) Power 2,386 (2,262) 2,386 (2,262) Totals 0 (0) 5,213 (4,941) 2,386 (2,262) 7,599 (7,203) * Process losses are estimated to match the heat input to the plant. Process losses include losses from:

turbines, HRSGs, combustion reactions, gas cooling, etc.

### Cost and Performance Baseline for Fossil Energy Plants

420 

## 4.3.9 Major equipment items for the SC PC plant with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 12

– Major Equipment List

4.3.10 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
ACCOUNT 1 FUEL AND SORBENT HANDLING
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 54 tonne (60 ton) 2 1
9 Feeder Vibratory 209 tonne/hr (230 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 426 tonne/hr (470 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 209 tonne (230 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3 in x 0 - 1-1/4 in x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 426 tonne/hr (470 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 426 tonne/hr (470 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 907 tonne (1,000 ton) 3 0

19 Limestone Truck Unloading Hopper N/A 36 tonne (40 ton) 1 0
20 Limestone Feeder Belt 109 tonne/hr (120 tph) 1 0 21 Limestone Conveyor No. L1 Belt 109 tonne/hr (120 tph) 1 0 22 Limestone Reclaim Hopper N/A 18 tonne (20 ton) 1 0 23 Limestone Reclaim Feeder Belt 82 tonne/hr (90 tph) 1 0 24 Limestone Conveyor No. L2 Belt 82 tonne/hr (90 tph) 1 0 25 Limestone Day Bin w/ actuator 345 tonne (380 ton) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

421 

## ACCOUNT 2 COAL AND SORBENT PRE PARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Coal Feeder Gravimetric 45 tonne/hr (50 tph) 6 0

2 Coal Pulverizer Ball type or equivalent 45 tonne/hr (50 tph) 6 0

3 Limestone Weigh Feeder Gravimetric 28 tonne/hr (31 tph) 1 1
4 Limestone Ball Mill Rotary 28 tonne/hr (31 tph) 1 1

5 Limestone Mill Slurry Tank with Agitator N/A 109,777 liters (29,000 gal) 1 1

6 Limestone Mill Recycle Pumps Horizontal centrifugal 1,855 lpm @ 12m H2O (490 gpm @ 40 ft H2O) 1 1

7 Hydroclone Classifier 4 active cyclones in a 5 cyclone bank 454 lpm (120 gpm) per cyclone 1 1

8 Distribution Box 2-way N/A 1 1
9 Limestone Slurry Storage Tank with Agitator Field erected 617,022 liters (163,000 gal) 1 1

10 Limestone Slurry Feed Pumps Horizontal centrifugal 1,287 lpm @ 9m H2O (340 gpm @ 30 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

422 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT
Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 1,506,594 liters (398,000 gal) 2 0

2 Condensate Pumps Vertical canned 16,277 lpm @ 213 m H2O (4,300 gpm @ 700 ft H2O) 1 1

3 Deaerator and Storage Tank Horizontal spray type 2,507,005 kg/hr (5,527,000 lb/hr), 5 min. tank 1 0

4 Boiler Feed Pump/Turbine Barrel type, multi-stage, centrifugal 42,018 lpm @ 3,505 m H2O (11,100 gpm @ 11,500 ft H2O) 1 1

5 Startup Boiler Feed Pump, Electric Motor Driven Barrel type, multi-stage, centrifugal 12,492 lpm @ 3,505 m H2O (3,300 gpm @ 11,500 ft H2O) 1 0

6 LP Feedwater Heater 1A/1B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

7 LP Feedwater Heater 2A/2B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

8 LP Feedwater Heater 3A/3B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

9 LP Feedwater Heater 4A/4B Horizontal U-tube 489,880 kg/hr (1,080,000 lb/hr) 2 0

10 HP Feedwater Heater 6 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0
11 HP Feedwater Heater 7 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0

12 HP Feedwater heater 8 Horizontal U-tube 2,508,366 kg/hr (5,530,000 lb/hr) 1 0

13 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

14 Fuel Oil System No. 2 fuel oil for light off 1,135,624 liter (300,000 gal) 1 0

15 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

16 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

17 Closed Cycle Cooling Heat Exchangers Shell and tube 53 GJ/hr (50 MMBtu/hr) each 2 0

18 Closed Cycle Cooling Water Pumps Horizontal centrifugal 20,820 lpm @ 30 m H2O (5,500 gpm @ 100 ft H2O) 2 1

19 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 88 m H2O (1,000 gpm @ 290 ft H2O) 1 1

20 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 64 m H2O (700 gpm @ 210 ft H2O) 1 1

21 Raw Water Pumps Stainless steel, single suction 11,016 lpm @ 18 m H2O (2,910 gpm @ 60 ft H2O) 2 1

22 Ground Water Pumps Stainless steel, single suction 4,429 lpm @ 268 m H2O (1,170 gpm @ 880 ft H2O) 5 1

23 Filtered Water Pumps Stainless steel, single suction 2,725 lpm @ 49 m H2O (720 gpm @ 160 ft H2O) 2 1

24 Filtered Water Tank Vertical, cylindrical 2,619,505 liter (692,000 gal) 1 0

25 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly, electrodeionization unit 984 lpm (260 gpm) 1 1

26 Liquid Waste Treatment System -- 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

423 

## ACCOUNT 4 BOILER AND ACCESSORI ES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Boiler Supercritical, drum, wall-fired, low NOx burners, overfire air 2,508,366 kg/hr steam @ 25.5 MPa/602°C/602°C (5,530,000 lb/hr steam @ 3,700 psig/1,115°F/1,115°F) 1 0

2 Primary Air Fan Centrifugal 326,133 kg/hr, 4,449 m3/min @ 123 cm WG (719,000 lb/hr, 157,100 acfm @ 48 in. WG) 2 0

3 Forced Draft Fan Centrifugal 1,061,406 kg/hr, 14,484 m3/min @ 47 cm WG (2,340,000 lb/hr,

511,500 acfm @ 19 in. WG) 2 0

4 Induced Draft Fan Centrifugal 1,539,493 kg/hr, 32,491 m3/min @ 104 cm WG (3,394,000 lb/hr,

1,147,400 acfm @ 41 in. WG) 2 0

5 SCR Reactor Vessel Space for spare layer 3,079,892 kg/hr (6,790,000 lb/hr) 2 0

6 SCR Catalyst

-- -- 3 0

7 Dilution Air Blower Centrifugal 184 m3/min @ 108 cm WG (6,500 acfm @ 42 in. WG) 2 1

8 Ammonia Storage Horizontal tank 200,627 liter (53,000 gal) 5 0

9 Ammonia Feed Pump Centrifugal 39 lpm @ 91 m H2O (10 gpm @ 300 ft H2O) 2 1

### Cost and Performance Baseline for Fossil Energy Plants

424 

## ACCOUNT 5 FLUE GAS CLEANUP

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Fabric Filter Single stage, highratio with pulse-jet online cleaning system 1,539,493 kg/hr (3,394,000 lb/hr) 99.8% efficiency 2 0

2 Absorber Module Counter-current open spray 61,561 m3/min (2,174,000 acfm) 1 0

3 Recirculation Pumps Horizontal centrifugal 215,768 lpm @ 64 m H2O (57,000 gpm @ 210 ft H2O) 5 1

4 Bleed Pumps Horizontal centrifugal 5,565 lpm (1,470 gpm) at 20 wt% solids 2 1

5 Oxidation Air Blowers Centrifugal 109 m3/min @ 0.3 MPa (3,840 acfm @ 37 psia) 2 1

6 Agitators Side entering 50 hp 5 1

7 Dewatering Cyclones Radial assembly, 5 units each 1,401 lpm (370 gpm) per cyclone 2 0

8 Vacuum Filter Belt Horizontal belt 44 tonne/hr (49 tph) of 50 wt % slurry 2 1

9 Filtrate Water Return Pumps Horizontal centrifugal 833 lpm @ 12 m H2O (220 gpm @ 40 ft H2O) 1 1

10 Filtrate Water Return Storage Tank Vertical, lined 567,812 lpm (150,000 gal) 1 0

11 Process Makeup Water Pumps Horizontal centrifugal 4,467 lpm @ 21 m H2O (1,180 gpm @ 70 ft H2O) 1 1

### Cost and Performance Baseline for Fossil Energy Plants

425 

## ACCOUNT 5C CARBON DIOXIDE RECOV ERY

ACCOUNT 6 COMBUSTION TURBINE/A CCESSORIES N/A

ACCOUNT 7 HRSG, DUCTING & STAC K

ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Econamine FG Plus Amine-based CO2 capture technology 1,626,129 kg/h (3,585,000 lb/h) 20.6 wt % CO2 concentration 2 0

2 Econamine Condensate Pump Centrifugal 16,959 lpm @ 52 m H2O (4,480 gpm @ 170 ft H2O) 1 1

3 CO2 Compressor Integrally geared, multi-stage centrifugal 301,656 kg/h @ 15.3 MPa (665,037 lb/h @ 2,215 psia) 2 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack Reinforced concrete with FRP liner 152 m (500 ft) high x 5.6 m (18 ft) diameter 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 698 MW 24.1 MPa/593°C/593°C (3500 psig/ 1100°F/1100°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 780 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,910 GJ/hr (1,810 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

426 

## ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 1,014,500 lpm @ 30 m (268,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

/ 5655 GJ/hr (5360 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

427 

## ACCOUNT 10 ASH/SPENT SORBENT RE COVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Economizer Hopper (part of boiler scope of supply) -- -- 4 0

2 Bottom Ash Hopper (part of boiler scope of supply) -- -- 2 0

3 Clinker Grinder

-- 5.4 tonne/hr (6 tph) 1 1

4 Pyrites Hopper (part of pulverizer scope of supply included with boiler) -- -- 6 0

5 Hydroejectors

-- -- 12

6 Economizer /Pyrites Transfer Tank -- -- 1 0

7 Ash Sluice Pumps Vertical, wet pit 227 lpm @ 17 m H2O (60 gpm @ 56 ft H2O) 1 1

8 Ash Seal Water Pumps Vertical, wet pit 7,571 lpm @ 9 m H2O (2000 gpm @ 28 ft H2O) 1 1

9 Hydrobins

-- 227 lpm (60 gpm) 1 1

10 Baghouse Hopper (part of baghouse scope of supply) -- -- 24 0

11 Air Heater Hopper (part of boiler scope of supply) -- -- 10 0

12 Air Blower

-- 20 m3/min @ 0.2 MPa (710 scfm @ 24 psi) 1 1

13 Fly Ash Silo Reinforced concrete 1,270 tonne (1,400 ton) 2 0

14 Slide Gate Valves

-- -- 2 0
15 Unloader

-- -- 1 0

16 Telescoping Unloading Chute

-- 127 tonne/hr (140 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

428 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type Design Condition Operating Qty. Spares

1 STG Transformer Oil-filled 24 kV/345 kV, 650 MVA, 3- ph, 60 Hz 1 0

2 Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 123 MVA, 3- ph, 60 Hz 1 1

3 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 18 MVA, 3- ph, 60 Hz 1 1

4 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

5 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

6 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

7 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

429 

## 4.3.10 The cost estimating methodology was described previously in Section Case 12

– Cost Estimating Basis 2.7

. Exhibit 4

- 55 shows the total plant capital cost summary organized by cost account and Exhibit 4

- 56 shows a more detailed breakdown of the capital costs as well as owner’s costs, TOC , and TASC

. Exhibit 4

- 57 shows the initial and annual O&M costs. The estimated TO C of the SC PC boiler with CO 2 

## capture is $ 3,570 /kW. Process contingency represents 2.8 percent of the TO C and project contingency rep resents 10.2 percent. The COE, including CO 2 

## TS&M costs of 5

. 7 mills/kWh, is 10 6

. 6 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

430 

## Exhibit 4

- 55 Case 12 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 Capture Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $20,098 $5,400 $12,019 $0 $0 $37,517 $3,366 $0 $6,132 $47,015 $85

2 COAL & SORBENT PREP & FEED $13,673 $796 $3,473 $0 $0 $17,942 $1,572 $0 $2,927 $22,442 $41

3 FEEDWATER & MISC. BOP SYSTEMS $54,851 $0 $25,849 $0 $0 $80,700 $7,397 $0 $14,455 $102,552 $186

4 PC BOILER 4.1 PC Boiler & Accessories $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671

5 FLUE GAS CLEANUP $101,027 $0 $34,490 $0 $0 $135,517 $12,971 $0 $14,849 $163,336 $297

5B CO2 REMOVAL & COMPRESSION $235,366 $0 $71,742 $0 $0 $307,108 $29,363 $54,181 $78,130 $468,782 $852

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68 SUBTOTAL 7 $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $56,794 $0 $7,537 $0 $0 $64,331 $6,165 $0 $7,050 $77,546 $141 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $27,360 $1,200 $15,331 $0 $0 $43,892 $3,826 $0 $6,848 $54,565 $99 SUBTOTAL 8 $84,154 $1,200 $22,868 $0 $0 $108,222 $9,991 $0 $13,898 $132,111 $240

9 COOLING WATER SYSTEM $20,722 $9,941 $18,443 $0 $0 $49,106 $4,622 $0 $7,236 $60,965 $111

10 ASH/SPENT SORBENT HANDLING SYS $5,276 $168 $7,053 $0 $0 $12,497 $1,202 $0 $1,410 $15,108 $27

11 ACCESSORY ELECTRIC PLANT $25,213 $10,656 $30,191 $0 $0 $66,060 $5,843 $0 $9,029 $80,931 $147

12 INSTRUMENTATION & CONTROL $10,017 $0 $10,157 $0 $0 $20,174 $1,829 $1,009 $2,826 $25,838 $47

13 IMPROVEMENTS TO SITE $3,321 $1,909 $6,692 $0 $0 $11,921 $1,176 $0 $2,620 $15,717 $29

14 BUILDINGS & STRUCTURES $0 $24,782 $23,519 $0 $0 $48,301 $4,357 $0 $7,899 $60,557 $110

TOTAL COST $787,159 $55,813 $388,298 $0 $0 $1,231,270 $116,235 $55,190 $199,329 $1,602,023 $2,913 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

431 

## Exhibit 4

- 56 Case 12 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $4,115 $0 $1,880 $0 $0 $5,995 $536 $0 $980 $7,510 $14 1.2 Coal Stackout & Reclaim $5,318 $0 $1,205 $0 $0 $6,523 $571 $0 $1,064 $8,158 $15 1.3 Coal Conveyors $4,944 $0 $1,192 $0 $0 $6,137 $538 $0 $1,001 $7,676 $14 1.4 Other Coal Handling $1,294 $0 $276 $0 $0 $1,569 $137 $0 $256 $1,963 $4 1.5 Sorbent Receive & Unload $168 $0 $51 $0 $0 $218 $19 $0 $36 $273 $0 1.6 Sorbent Stackout & Reclaim $2,709 $0 $496 $0 $0 $3,205 $279 $0 $523 $4,007 $7 1.7 Sorbent Conveyors $967 $209 $237 $0 $0 $1,413 $122 $0 $230 $1,765 $3 1.8 Other Sorbent Handling $584 $137 $306 $0 $0 $1,027 $91 $0 $168 $1,285 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $5,054 $6,376 $0 $0 $11,430 $1,074 $0 $1,876 $14,379 $26 SUBTOTAL 1. $20,098 $5,400 $12,019 $0 $0 $37,517 $3,366 $0 $6,132 $47,015 $85 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,388 $0 $465 $0 $0 $2,853 $249 $0 $465 $3,567 $6 2.2 Coal Conveyor to Storage $6,113 $0 $1,334 $0 $0 $7,447 $651 $0 $1,215 $9,313 $17 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,617 $199 $959 $0 $0 $5,774 $503 $0 $942 $7,219 $13 2.6 Sorbent Storage & Feed $556 $0 $213 $0 $0 $769 $68 $0 $126 $963 $2 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $597 $501 $0 $0 $1,098 $102 $0 $180 $1,380 $3 SUBTOTAL 2. $13,673 $796 $3,473 $0 $0 $17,942 $1,572 $0 $2,927 $22,442 $41 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $22,860 $0 $7,384 $0 $0 $30,244 $2,643 $0 $4,933 $37,820 $69 3.2 Water Makeup & Pretreating $6,997 $0 $2,252 $0 $0 $9,249 $875 $0 $2,025 $12,149 $22 3.3 Other Feedwater Subsystems $6,998 $0 $2,958 $0 $0 $9,956 $892 $0 $1,627 $12,475 $23 3.4 Service Water Systems $1,372 $0 $746 $0 $0 $2,118 $199 $0 $463 $2,780 $5 3.5 Other Boiler Plant Systems $8,675 $0 $8,565 $0 $0 $17,240 $1,638 $0 $2,832 $21,709 $39 3.6 FO Supply Sys & Nat Gas $276 $0 $345 $0 $0 $621 $59 $0 $102 $781 $1 3.7 Waste Treatment Equipment $4,744 $0 $2,704 $0 $0 $7,448 $725 $0 $1,635 $9,808 $18 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,930 $0 $895 $0 $0 $3,825 $368 $0 $838 $5,031 $9 SUBTOTAL 3. $54,851 $0 $25,849 $0 $0 $80,700 $7,397 $0 $14,455 $102,552 $186 4 PC BOILER 4.1 PC Boiler & Accessories $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $195,902 $0 $109,921 $0 $0 $305,822 $29,763 $0 $33,559 $369,144 $671

### Cost and Performance Baseline for Fossil Energy Plants

432 

## Exhibit 4

- 56 Case 12 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $70,185 $0 $15,109 $0 $0 $85,294 $8,132 $0 $9,343 $102,768 $187 5.2 Other FGD $3,663 $0 $4,150 $0 $0 $7,813 $758 $0 $857 $9,428 $17 5.3 Bag House & Accessories $20,190 $0 $12,813 $0 $0 $33,003 $3,180 $0 $3,618 $39,801 $72 5.4 Other Particulate Removal Materials $1,366 $0 $1,462 $0 $0 $2,828 $274 $0 $310 $3,413 $6 5.5 Gypsum Dewatering System $5,623 $0 $955 $0 $0 $6,579 $626 $0 $720 $7,925 $14 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $101,027 $0 $34,490 $0 $0 $135,517 $12,971 $0 $14,849 $163,336 $297 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $207,807 $0 $63,097 $0 $0 $270,904 $25,901 $54,181 $70,197 $421,183 $766 5B.2 CO2 Compression & Drying $27,558 $0 $8,646 $0 $0 $36,204 $3,462 $0 $7,933 $47,599 $87 SUBTOTAL 5. $235,366 $0 $71,742 $0 $0 $307,108 $29,363 $54,181 $78,130 $468,782 $852 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $9,165 $0 $5,889 $0 $0 $15,054 $1,313 $0 $2,455 $18,822 $34 7.4 Stack $8,376 $0 $4,901 $0 $0 $13,277 $1,278 $0 $1,456 $16,011 $29 7.9 Duct & Stack Foundations $0 $961 $1,092 $0 $0 $2,052 $192 $0 $449 $2,693 $5 SUBTOTAL 7. $17,541 $961 $11,881 $0 $0 $30,383 $2,783 $0 $4,359 $37,526 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $56,794 $0 $7,537 $0 $0 $64,331 $6,165 $0 $7,050 $77,546 $141 8.2 Turbine Plant Auxiliaries $382 $0 $819 $0 $0 $1,202 $118 $0 $132 $1,451 $3 8.3 Condenser & Auxiliaries $5,509 $0 $2,030 $0 $0 $7,540 $722 $0 $826 $9,088 $17 8.4 Steam Piping $21,469 $0 $10,585 $0 $0 $32,054 $2,693 $0 $5,212 $39,959 $73 8.9 TG Foundations $0 $1,200 $1,896 $0 $0 $3,096 $293 $0 $678 $4,067 $7 SUBTOTAL 8. $84,154 $1,200 $22,868 $0 $0 $108,222 $9,991 $0 $13,898 $132,111 $240 9 COOLING WATER SYSTEM 9.1 Cooling Towers $15,451 $0 $4,811 $0 $0 $20,262 $1,938 $0 $2,220 $24,419 $44 9.2 Circulating Water Pumps $3,219 $0 $248 $0 $0 $3,467 $293 $0 $376 $4,136 $8 9.3 Circ.Water System Auxiliaries $787 $0 $105 $0 $0 $892 $85 $0 $98 $1,075 $2 9.4 Circ.Water Piping $0 $6,243 $6,050 $0 $0 $12,293 $1,151 $0 $2,017 $15,460 $28 9.5 Make-up Water System $641 $0 $857 $0 $0 $1,498 $144 $0 $246 $1,888 $3 9.6 Component Cooling Water Sys $624 $0 $496 $0 $0 $1,120 $106 $0 $184 $1,410 $3 9.9 Circ.Water System Foundations & Structures $0 $3,698 $5,876 $0 $0 $9,575 $906 $0 $2,096 $12,577 $23 SUBTOTAL 9. $20,722 $9,941 $18,443 $0 $0 $49,106 $4,622 $0 $7,236 $60,965 $111

### Cost and Performance Baseline for Fossil Energy Plants

433 

## Exhibit 4

- 56 Case 12 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $706 $0 $2,175 $0 $0 $2,881 $283 $0 $316 $3,480 $6 10.7 Ash Transport & Feed Equipment $4,570 $0 $4,681 $0 $0 $9,250 $885 $0 $1,014 $11,149 $20 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $168 $198 $0 $0 $365 $34 $0 $80 $479 $1 SUBTOTAL 10. $5,276 $168 $7,053 $0 $0 $12,497 $1,202 $0 $1,410 $15,108 $27 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,727 $0 $280 $0 $0 $2,008 $186 $0 $165 $2,358 $4 11.2 Station Service Equipment $4,957 $0 $1,629 $0 $0 $6,585 $616 $0 $540 $7,741 $14 11.3 Switchgear & Motor Control $5,699 $0 $969 $0 $0 $6,667 $618 $0 $729 $8,014 $15 11.4 Conduit & Cable Tray $0 $3,573 $12,354 $0 $0 $15,926 $1,542 $0 $2,620 $20,089 $37 11.5 Wire & Cable $0 $6,742 $13,014 $0 $0 $19,756 $1,664 $0 $3,213 $24,633 $45 11.6 Protective Equipment $261 $0 $888 $0 $0 $1,149 $112 $0 $126 $1,388 $3 11.7 Standby Equipment $1,360 $0 $31 $0 $0 $1,391 $128 $0 $152 $1,670 $3 11.8 Main Power Transformers $11,209 $0 $189 $0 $0 $11,398 $864 $0 $1,226 $13,488 $25 11.9 Electrical Foundations $0 $342 $837 $0 $0 $1,179 $113 $0 $258 $1,550 $3 SUBTOTAL 11. $25,213 $10,656 $30,191 $0 $0 $66,060 $5,843 $0 $9,029 $80,931 $147 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $516 $0 $309 $0 $0 $825 $78 $41 $142 $1,085 $2 12.7 Distributed Control System Equipment $5,207 $0 $910 $0 $0 $6,117 $567 $306 $699 $7,689 $14 12.8 Instrument Wiring & Tubing $2,823 $0 $5,599 $0 $0 $8,422 $718 $421 $1,434 $10,995 $20 12.9 Other I & C Equipment $1,471 $0 $3,339 $0 $0 $4,810 $466 $241 $552 $6,069 $11 SUBTOTAL 12. $10,017 $0 $10,157 $0 $0 $20,174 $1,829 $1,009 $2,826 $25,838 $47

### Cost and Performance Baseline for Fossil Energy Plants

434 

## Exhibit 4

- 56 Case 12 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $56 $1,116 $0 $0 $1,172 $116 $0 $258 $1,546 $3 13.2 Site Improvements $0 $1,853 $2,301 $0 $0 $4,154 $410 $0 $913 $5,477 $10 13.3 Site Facilities $3,321 $0 $3,275 $0 $0 $6,595 $650 $0 $1,449 $8,694 $16 SUBTOTAL 13. $3,321 $1,909 $6,692 $0 $0 $11,921 $1,176 $0 $2,620 $15,717 $29 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,851 $7,784 $0 $0 $16,635 $1,495 $0 $2,719 $20,849 $38 14.2 Turbine Building $0 $12,808 $11,937 $0 $0 $24,746 $2,230 $0 $4,046 $31,023 $56 14.3 Administration Building $0 $643 $680 $0 $0 $1,324 $120 $0 $217 $1,660 $3 14.4 Circulation Water Pumphouse $0 $176 $139 $0 $0 $315 $28 $0 $51 $395 $1 14.5 Water Treatment Buildings $0 $887 $809 $0 $0 $1,697 $153 $0 $277 $2,127 $4 14.6 Machine Shop $0 $430 $289 $0 $0 $719 $64 $0 $117 $901 $2 14.7 Warehouse $0 $292 $292 $0 $0 $584 $53 $0 $96 $732 $1 14.8 Other Buildings & Structures $0 $238 $203 $0 $0 $441 $40 $0 $72 $553 $1 14.9 Waste Treating Building & Str. $0 $456 $1,384 $0 $0 $1,840 $175 $0 $302 $2,317 $4 SUBTOTAL 14. $0 $24,782 $23,519 $0 $0 $48,301 $4,357 $0 $7,899 $60,557 $110

TOTAL COST $787,159 $55,813 $388,298 $0 $0 $1,231,270 $116,235 $55,190 $199,329 $1,602,023 $2,913

Owner's Costs Preproduction Costs 6 Months All Labor $10,579 $19 1 Month Maintenance Materials $1,541 $3 1 Month Non-fuel Consumables $1,637 $3 1 Month Waste Disposal $325 $1 25% of 1 Months Fuel Cost at 100% CF $1,971 $4 2% of TPC $32,040 $58 Total $48,094 $87 Inventory Capital 60 day supply of fuel and consumables at 100% CF $18,563 $34 0.5% of TPC (spare parts) $8,010 $15 Total $26,573 $48
Initial Cost for Catalyst and Chemicals $2,496 $5 Land $900 $2 Other Owner's Costs $240,304 $437

Financing Costs $43,255 $79 Total Overnight Costs (TOC) $1,963,644 $3,570 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,238,554 $4,070

### Cost and Performance Baseline for Fossil Energy Plants

435 

## Exhibit 4

- 57 Case 12 Initial and Annual Operating and Maintenance Costs

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 12 - 1x550 MWnet Super-Critical PC w/ CO2 Capture Heat Rate-net (Btu/kWh): 12,002 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,444,907 $11.719 Maintenance Labor Cost $10,481,104 $19.058 Administrative & Support Labor $4,231,503 $7.694 Property Taxes and Insurance $32,040,467 $58.260 TOTAL FIXED OPERATING COSTS $53,197,981 $96.731 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $15,721,656 $0.00384

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water(/1000 gallons) 0 7,324 1.08 $0 $2,457,806 $0.00060

Chemicals MU & WT Chem.(lbs) 0 35,452 0.17 $0 $1,903,577 $0.00046 Limestone (ton) 0 687 21.63 $0 $4,610,586 $0.00113 Carbon (Mercury Removal) lb 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 1,028 1.46 2,249.89 $2,312,307 $1,017,164 $0.00025 NaOH (tons) 73 7.26 433.68 $31,484 $976,789 $0.00024 H2SO4 (tons) 69 6.93 138.78 $9,615 $298,293 $0.00007 Corrosion Inhibitor 0 0 0.00 $142,156 $6,769 $0.00000 Activated Carbon (lb) 0 1,741 1.05 $0 $567,144 $0.00014 Ammonia (19% NH3) ton 0 102 129.80 $0 $4,090,854 $0.00100 Subtotal Chemicals $2,495,562 $13,471,176 $0.00329

Other Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.43 5,775.94 $0 $765,005 $0.00019 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $765,005 $0.00019
Waste Disposal Fly Ash (ton) 0 527 16.23 $0 $2,651,418 $0.00065 Bottom Ash (ton) 0 132 16.23 $0 $662,855 $0.00016 Subtotal-Waste Disposal $0 $3,314,273 $0.00081 By-products & Emissions Gypsum (tons) 0 1,062 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $2,495,562 $35,729,917 $0.00873 Fuel (ton) 0 6,790 38.18 $0 $80,434,598 $0.01964

### Cost and Performance Baseline for Fossil Energy Plants

436 

## 4.4 PC CASE SUMMARY The performance results of the four PC plant configurations are summarized in Exhibit 4

- 58

. Exhibit 4

- 58 Estimated Performance and Cost Results for Pulverized Coal Cases

1 

### Capacity factor is 8 5% for all PC cases 2 

### COE and LCOE are defined in Section 2.7

. PERFORMANCE Case 9 Case 10 Case 11 Case 12 CO2 Capture 0% 90% 0% 90% Gross Power Output (kWe) 582,600 672,700 580,400 662,800 Auxiliary Power Requirement (kWe) 32,580 122,740 30,410 112,830 Net Power Output (kWe) 550,020 549,960 549,990 549,970 Coal Flowrate (lb/hr) 437,378 614,994 409,528 565,820 Natural Gas Flowrate (lb/hr) N/A N/A N/A N/A HHV Thermal Input (kWth) 1,495,379 2,102,643 1,400,162 1,934,519 Net Plant HHV Efficiency (%) 36.8% 26.2% 39.3% 28.4% Net Plant HHV Heat Rate (Btu/kWh) 9,277 13,046 8,687 12,002 Raw Water Withdrawal (gpm/MW net 

### ) 10.7 20.4 9.7 18.3 Process Water Discharge (gpm/MW net 

### ) 2.2 4.7 2.0 4.3 Raw Water Consumption (gpm/MW net 

### ) 8.5 15.7 7.7 14.1 CO 2 

### Emissions (lb/MMBtu) 204 20 204 20 CO 2 

### Emissions (lb/MWh gross 

### ) 1,783 217 1,675 203 CO 2 

### Emissions (lb/MWh net 

### ) 1,888 266 1,768 244 SO 2 

### Emissions (lb/MMBtu) 0.0858 0.0017 0.0858 0.0016 SO 2 

### Emissions (lb/MWh gross 

### ) 0.7515 0.0176 0.7063 0.0162 NOx Emissions (lb/MMBtu) 0.070 0.070 0.070 0.070 NOx Emissions (lb/MWh gross 

### ) 0.613 0.747 0.576 0.697 PM Emissions (lb/MMBtu) 0.0130 0.0130 0.0130 0.0130 PM Emissions (lb/MWh gross 

### ) 0.114 0.139 0.107 0.129 Hg Emissions (lb/TBtu) 1.143 1.143 1.143 1.143 Hg Emissions (lb/MWh gross 

### ) 1.00E-05 1.22E-05 9.41E-06 1.14E-05 COST Total Plant Cost (2007$/kW) 1,622 2,942 1,647 2,913 Total Overnight Cost (2007$/kW) 1,996 3,610 2,024 3,570 **Bare Erected Cost** 

### 1,317 2,255 1,345 2,239 **Home Office Expenses** 

### 124 213 127 211 **Project Contingency** 

### 182 369 176 362 **Process Contingency** 

### 0 105 0 100 **Owner's Costs** 

### 374 667 377 657 Total Overnight Cost (2007$ x 1,000) 1,098,124 1,985,432 1,113,445 1,963,644 Total As Spent Capital (2007$/kW) 2,264 4,115 2,296 4,070 COE (mills/kWh, 2007$) 1,2 

### 59.4 109.6 58.9 106.5 **CO2 TS&M Costs** 

### 0.0 5.8 0.0 5.6 **Fuel Costs** 

### 15.2 21.3 14.2 19.6 **Variable Costs** 

### 5.1 9.2 5.0 8.7 **Fixed Costs** 

### 7.8 13.1 8.0 13.0 **Capital Costs** 

### 31.2 60.2 31.7 59.6 LCOE (mills/kWh, 2007$) 1,2 

### 75.3 139.0 74.7 135.2 Pulverized Coal Boiler PC Subcritical PC Supercritical

### Cost and Performance Baseline for Fossil Energy Plants

437 

## The components of TOC and overall TASC are shown for each PC case in Exhibit 4

- 59

. The following observations about TOC can be made:

**•** The TO C of the non

- capture SC PC case is only incrementally greater than non - capture subcritical P C (less than 2 percent). The TO C of subcritical PC with CO 2 

## capture is approximately 1 percent greater than SC PC with CO 2 

## capture

.

**•** The TOC penalty for adding CO 2 

## capture in the subcritical case is 8 1 percent and is 7 6 percent in the SC case. The Econamine cost includes a process contingency of approximately $100/kW in both the subcritical and SC cases. Eliminating the process contingency results in a CO 2 

## capture cost penalty of 76 and 7 1 percent for the su bcritical and SC PC cases, respectively. In addition to the high cost of the Econamine process, there is a significant increase in the cost of the coo ling towers and CWP s in the CO 2 

## capture cases because of the larger cooling water demand discussed previously. In addition, the gross output of the two PC plants increases by 9 0 MW (subcritical) and 8 2 MW ( SC ) to maintain the net output at 550 MW. The increased gross output results in higher coal flow rate and consequent higher costs for all cost accounts in the estimate.

Exhibit 4

- 59 Plant Capital Cost for PC Cases

1,996 3,610

2,024 3,570

2,264 4,115

2,296 4,070

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

TOC TASC TOC TASC TOC TASC TOC TASC
Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 CaptureTOC or TASC, $/kW (2007$) TASC Owner's Cost Process Contingency Project Contingency Home Office Expense Bare Erected Cost

### Cost and Performance Baseline for Fossil Energy Plants

438 

## The COE is shown for the four PC cases in Exhibit 4

- 60 . The following observations can be made:

**•** Capital costs represent the largest fraction of COE in all cases, but particularly so in the CO 2 

## capture cases. Fuel cost is the second largest component of COE, and cap ital charges and fuel costs combined represent 7 4 to 78 percent of the total in all cases.

**•** In the non

- capture case the slight increase in capital cost in the SC case is more than offset by the efficiency gain so that t he COE for SC PC is 1 percent less tha n subcritical despite having a nearly 2 percent higher TO C.

**•** In the CO 2 

## capture case, the cost differential between subcritical and SC PC is negligible ( about 1 percent), but the SC PC has a 3 percent lower COE because of the higher efficiency.

Exhibit 4

- 60 COE for PC Cases

31.2 60.2

31.7 59.6 7.8 13.1

8.0 13.0

5.1 9.2

5.0 8.7

15.2 21.3

14.2 19.6 5.9 5.7

0 20 40 60 80 100 120 140

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 CaptureCOE, mills/kWh (2007$) CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs

### Cost and Performance Baseline for Fossil Energy Plants

439 

## The sensitivity of COE to capacity factor is shown in Exhibit 4

- 61 . Implicit in the curves is the assumption that a capacity factor of greater than 85 percent can be achieved without the expenditure of additional capital. The subcritical and SC cases with no CO 2 

## capture are nearly identical making it difficult to distinguish between the two lines. The COE increases more rapidly at low CF because the relatively high capital component is spread over fewer kilowatt

hours of generation. The sensitivity of COE to coal price is shown in Exhibit 4

- 62 . As in the IGCC cases, the COE in the PC cases is relatively insensitive to coal price. As presented in Section 2.4 the first year cost of CO 2 

## avoided was calculated, and t he results for the PC CO 2 

## capture cases are shown in Exhibit 4

- 63

. The cost of CO 2 

## avoided using the analogous non

- capture technology as the reference is nearly identical for the subcritical and SC PC cases. Using SC PC as the non

- capture reference case in creases the avoided cost of subcritical PC with CO 2 

## capture because subcritical PC has the higher COE of the two capture technologies

. Exhibit 4

- 61 Sensitivity of COE to Capacity Factor for PC Cases

0 50 100 150 200 250 300

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

Capacity Factor, % Subcritical w/CO2 Capture Supercritical w/CO2 Capture Subcritical No Capture Supercritical No Capture

Coal price = $1.64/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

440 

## Exhibit 4

- 62 Sensitivity of COE to Coal Price for PC Cases

Exhibit 4

- 63 First Year Cost of CO 2 

## Avoided in PC Cases 0 20 40 60 80 100 120 140

0 0.5 1 1.5 2 2.5 3 3.5 4COE, mills/kWh (2007$)

Fuel Price, $/MMBtu Subcritical w/CO2 Capture
Supercritical w/CO2 Capture
Subcritical No Capture
Supercritical No Capture Capacity Factor = 85%

68 69 75

69

0 10 20 30 40 50 60 70 80 90 100

Subcritical PC Supercritical PCCO2Avoided Cost, $/tonne (2007$) Avoided Cost (Analogous Technology w/o Capture Reference) Avoided Cost (SC PC w/o Capture Reference)

### Cost and Performance Baseline for Fossil Energy Plants

441 

## The following observations can be made regarding plant performance with reference to Exhibit 4

- 58 :

**•** The efficiency of the non - capture, SC PC plant is 2. 5 absolute perce ntage points higher than the equivalent subcritical PC plant (39. 3 percent compared to 36.8 percent). The efficiencies are comparable to those reported in other studies once steam cycle conditions are considered. For example, in an EPA study [ 75

Similar results from an EPRI study using Illinois No. 6 coal were reported as follows : [ ] comparin g PC and IGCC plant configurations the subcritical PC plant using bituminous coal had an efficiency of 35.9 percent with a steam cycle of 16.5 MPa/538°C/538°C (2 , 400 psig/1 , 000°F/1 , 000°F). The higher steam cycle temperature in this study 566°C/566°C (1 , 05 0°F/1 , 050°F) is one factor that results in a higher net efficiency. The same study reported a SC plant efficiency of 38.3 percent with a steam cycle of 24.1 MPa/566°C/566°C (3 , 500 psig/1 , 050°F/1 , 050°F). Again, the more aggressive steam conditions in this study, 593°C/593°C (1 , 100°F/1 , 100°F) are one factor resulting in a higher net efficiency.

76

o Subcritical PC efficiency of 35.7 percent with a steam cycle of 16.5 MPa/53 8°C/538°C (2 , 400 psig/1 , 000°F/1 , 000°F). ]

o SC PC efficiency of 38.3 percent with a steam cycle of 24.8 MPa/593°C/593°C (3 , 600 psig/1 , 100°F/1 , 100°F).

**•** The addition of CO 2 

## capture to the two PC cases results in a relative efficiency penalty of 28.9 percent in th e subcritical PC case and 27

. 6 percent in the SC PC case . The efficiency is negatively impacted by the large auxiliary loads of the Econamine process and CO 2 

## compression, as well as the large increase in cooling water requirement, which increases the CWP and cooling tower fan auxiliary loads. The auxiliary load increases by 9 0 MW in the subcritical PC case and by 8 2 MW in the SC PC case.

**•** NOx, PM , and Hg emissions are the same for all four PC cases on a heat input basis because of the environmental target assumptions of fixed removal efficiencies for each case (86 percent SCR efficiency, 99.8 percent baghouse efficiency and 90 percent co

benefit capture). The emissions on a mass basis or normalized by gross output are higher for subcritical cases than SC c ases and are higher for CO 2 

## capture cases than non

- capture cases because of the higher efficiencies of SC PC and non

- capture PC cases.

**•** SO 2 

## emissions are likewise constant on a heat input basis for the non

- capture cases, but the Econamine process polishing scrubber and absorber vessel result in negligible SO 2 

## emissions in CO 2 

## capture cases. The SO 2 

## emissions for subcritical PC are higher than SC on a mass basis and when normalized by gross output because of the lower efficiency.

**•** Uncontrolled CO 2 

## emissions on a mass basis are greater for subcritical PC compared to SC because of the lower efficiency. The capture cases result in a 90 percent reduction of CO 2 

## for both subcritical and SC PC.

**•** Raw water consumption for all cases is dominated by cooling tower makeup requirements, which accounts for about 77 percent of raw water in non

- capture cases and 81 percent of raw water in CO 2 

## capture cases. The amount of raw water consumption in

### Cost and Performance Baseline for Fossil Energy Plants

442 

## the CO 2 

## capture cases is greatly increased by the cooling water requ irements of the Econamine process. Cooling water is required to:

o Reduce the FG temperature from 57°C (135°F) (FGD exit temperature) to 32°C (89°F) (Econamine absorber operating temperature), which also requires condensing water from the FG that comes satu rated from the FGD unit.

o Remove the heat input by the stripping steam to cool the solvent

o Remove the heat input from the auxiliary electric loads

o Remove heat in the CO 2 

## compressor intercoolers The normalized water withdrawal , process discharge and raw water consumption are shown in Exhibit 4

- 64 for each of the PC cases. In the CO 2 

## capture cases, additional water is recovered from the FG as it is cooled to the absorber temperature of 32°C (89°F). The condensate is treated and also used as cooling tower makeup. Exhibit 4

- 64 Raw Water Withdrawal and Consumption in PC Cases

10.7 20.4

9.7 18.3

8.5 15.7

7.7 14.1

0 5 10 15 20 25

Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 CaptureWater, gpm/MWnet Raw Water Withdrawal Process Discharge Raw Water Consumption

### Cost and Performance Baseline for Fossil Energy Plants

443 

## 5. Two NGCC power plant configurations were evaluated and are presented in this section. Each design is based on a market

- ready technology that is assumed to be commercially ava ilable in time to support start up . Each design consists of two advanced F class CTG s , two HRSG’s and one STG in a multi

- shaft 2x2x1 config uration. NATURAL GAS COMBINED CYCLE PLANTS

The NGCC cases are evaluated with and without CO 2 

## capture on a common thermal input basis. The NGCC designs that include CDR have a smaller plant net output resulting from the additional CDR facility auxiliary loads. Like in the IGCC cases, th e sizes of the NGCC designs were determined by the output of the commercially available CT . Hence, evaluation of the NGCC designs on a common net output basis was not possible. The Rankine cycle portion of both designs uses a single reheat 16.5 MPa/566° C/5 66 °C (2400 psig/1050 **°** F/10 50 **°** F) steam cycle. A more aggressive steam cycle was considered but not chosen because there are very few HRSGs in operation that would support such conditions [ 64 ]

. 5.1 NGCC COMMON PROCESS AREAS The two NGCC cases are nearly identical in configuration with the exception that Case 14 includes CO 2 

## capture while Case 13 does not. The process areas that are common to the two plant configurati ons are presented in this section.
5.1.1 It was assumed that a natural gas main with adequate capacity is in close proximity (within 16 km [10 miles]) to the site fence line and that a suitable right of way is available to install a branch line to the site. For the purposes of this study it was also assumed that the gas will be delivered to the plant custody transfer point at 3.0 MPa (435 psig) and 38°C (100oF), which matches the advanced F Class fuel system requirements. Hence, neither a pressure reducing station with gas preheating (to prevent moisture and hydrocarbon condensation), nor a fuel booster compressor are required. Natural Gas Supply System

A new gas metering station is assumed to be added on the site, adjacent to the new CT . The meter may be of the rate

- of

- flow type, with input to the plant computer for s umming and recording, or may be of the positive displacement type. In either case, a complete time

- line record of gas consumption rates and cumulative consumption is provided.
5.1.2 The combined cycle plant is based on two CTG’s. The CTG is representative of the advanced F Class turbines with an ISO base rating of 184,400 kW when firing natural gas [ Combustion Turbine

77

Each CTG is provided with inlet air filtration systems; inlet silencers; lube and control oil systems including cooling; electric motor starting systems; acoustical enclosures including heating and ventilation; control systems including supervisory, fire protectio n, and fuel systems. No back up fuel was envisioned for this project. ]

. This machine is an axial flow, single spool, constant speed unit, with variable IGV s , and dry LNB combustion system.

### Cost and Performance Baseline for Fossil Energy Plants

444 

## The CTG is typically supplied in several fully shop

- fabricated modules, complete with all mechanical, electrical, and control systems required for CTG operation. Site CTG installation involves module interconnection and linking CTG modules to the plant systems. The CTG package scope of supply for combined cycle application, while project specific, does not vary much from project

- to

- project. A typical scope of supply is presented in Exhibit 5

- 1

. Exhibit 5

- 1 Combustion Turbine Typical Scope of Supply
System System Scope
ENGINE ASSEMBLY Coupling to Generator, Dry Chemical Exhaust Bearing Fire Protection System, Insulation Blankets, Platforms, Stairs and Ladders Engine Assembly with Bedplate Variable IGV System, Compressor, Bleed System, Purge Air System, Bearing Seal Air System, Combustors, Dual Fuel Nozzles, Turbine Rotor Cooler Walk

- in acoustical enclosure HVAC, Lighting, and LP CO 2 Fire Protection System MECHANICAL PACKAGE HVAC , Lighting, Air Compressor for Pneumatic System, LP CO 2 Fire Protection System
Lubricating Oil System and Control Oil System Lube Oil Reservoir, Accumulators, 2x100% AC Driven Oil Pumps, DC Emergency Oil Pump with Starter, 2x100% Oil Coolers, Duplex Oil Fil ter, Oil Temperature and Pressure Control Valves, Oil Vapor Exhaust Fans and Demister, Oil Heaters, Oil Interconnect Piping (SS and CS), Oil System Instrumentation, Oil for Flushing and First Filling

ELECTRICAL PACKAGE HVAC , Lighting, AC and DC Motor Control Centers, Generator Voltage Regulating Cabinet, Generator Protective Relay Cabinet, DC Distribution Panel, Battery Charger, Digital Control System with Local Control Panel (all control and monitoring functions as well as da ta logger and sequence of events recorder), Control System Valves and Instrumentation Communication link for interface with plant DCS Supervisory System, Bentley Nevada Vibration Monitoring System, LP CO 2 Fire Protection System, Cable Tray and Conduit Prov isions for Performance Testing including Test Ports, Thermowells, Instrumentation and DCS interface cards
INLET AND EXHAUST SYSTEMS Inlet Duct Trash Screens, Inlet Duct and Silencers, Self Cleaning Filters, Hoist System For Filter Maintenance, Evaporative Cooler System, Exhaust Duct Expansion Joint, Exhaust Silencers Inlet and Exhaust Flow, Pressure and Temperature Ports and Instrumentation FUEL SYSTEMS

N. Gas System Gas Valves Including Vent, Throttle and Trip Valves, Gas Filter/Separator, Gas Supply I nstruments and Instrument Panel STARTING SYSTEM Enclosure, Starting Motor or Static Start System, Turning Gear and Clutch Assembly, Starting Clutch, Torque Converter

GENERATOR Static or Rotating Exciter (Excitation transformer to be included for a static system), Line Termination Enclosure with CTs, VTs, Surge Arrestors, and Surge Capacitors, Neutral Cubicle with CT, Neutral Tie Bus, Grounding Transformer, and Secondary Resistor, Generator Gas Dryer, Seal Oil System (including Defoaming Tank, Reservoir, S eal Oil Pump, Emergency Seal Oil Pump, Vapor Extractor, and Oil Mist Eliminator), Generator Auxiliaries Control Enclosure, Generator Breaker, Iso

- Phase bus connecting generator and breaker, Grounding System Connectors

Generator Cooling Totally Enclosed W ater

- to

- Air

- Cooled ( TEWAC ) System (including circulation system, interconnecting piping and controls), or Hydrogen Cooling System (including H 2 to Glycol and Glycol to Air heat exchangers, liquid level detector circulation system, interconnecting piping and controls)

MISCELLANEOUS Interconnecting Pipe, Wire, Tubing and Cable Instrument Air System Including Air Dryer On Line and Off Line Water Wash System LP CO 2 Storage Tank Drain System Drain Tanks Coupling, Coupling Cover and Associated Hardware

### Cost and Performance Baseline for Fossil Energy Plants

445 

## The generators would typically be provided with the CT package. The generators are assumed to be 24 kV, 3

- phase, 60 hertz, constructed to meet Ameri can National Standards Institute (ANSI) and National Electrical Manufacturers Association (NEMA) standards for turbine

- driven synchronous generators. The generator is TEWAC, complete with excitation system, cooling, and protective relaying.
5.1.3 The HRSG is configured with HP, IP, and LP steam drums, and superheater, reheater, and economizer sections. The HP drum is supplied with FW by the HP boiler feed pump to generate HP steam, which passes to the superheater section for heatin g to 566°C (1050°F). The IP drum is supplied with FW by the I P boiler feed pump. The IP steam fro m the drum is superheated to 566 °C ( 1050 °F) and mixed with hot reheat steam from the reheat sec tion at 566 °C ( 1050oF). The combined flows are admitted into the IP section of the steam turbine. The LP drum provides steam LP turbine. Heat Recovery Steam Generator

The economizer sections heat condensate and FW (in separate tube bundles). The HRSG tubes are typically comprised of bare surface and/or finned tubing or pipe material. The high

temperature portions are type P91 or P22 ferritic alloy material; the low

- temperature portions (< 399°C [750°F]) are CS . Each HRSG exhausts directly to the stack, which is fabricated from CS plate materials and lined with Type 409 SS . The stack for the NGCC cases is assumed to be 46 m (150 ft) high, and the cost is included in the HRSG account.
5.1.4 This reference plant is designed to achieve 2.5 ppmvd NOx emissions (expressed as NO 2 

## and referenced to 15 percent O 2 

## ). Two measures are taken to reduce the NOx. The first is a DLN burner in the CTG. The DLN burners are a low NOx design and reduce the emissions to about 25 ppmvd (referenced to 15 percent O 2 

## ) [ NOx Control System

78 The second measure taken to reduce the NOx emissions was the installation of a SCR system. SCR uses ammonia and a catalyst to reduce NOx to N 2 

## and H 2 

## O. The SCR system consists of reactor, and ammonia supply and storage system. The SCR system is designed for 90 percent reduction while firing natural gas. This along with the dry LN B achieves the emission limit of 2.5 ppmvd (referenced to 15 percent O 2 

## ). ]

.

Operation Description

- The SCR reactor is located in the FG path inside the HRSG between the HP and IP sections. The SCR reactor is equipped with one catalyst layer consisting of
c atalyst modules stacked in line on a supporting structural frame. The SCR reactor has space for installation of an additional layer. Ammonia is injected into the gas immediately prior to entering the SCR reactor. The ammonia injection grid is arranged i nto several sections, and consists of multiple pipes with nozzles. Ammonia flow rate into each injection grid section is controlled taking into account imbalances in the FG flow distribution across the HRSG. The catalyst contained in the reactor enhances the reaction between the ammonia and the NOx in the gas. The catalyst consists of various active materials such as titanium dioxide, vanadium pentoxide, and tungsten trioxide. The optimum inlet FG temperature range for the catalyst is 260°C (500 **°** F) to 3 43°C (650 **°** F). The ammonia storage and injection system consists of the unloading facilities, bulk storage tank, vaporizers, and dilution air skid.

### Cost and Performance Baseline for Fossil Energy Plants

446 

## 5.1.5 A CDR facility is used in Case 14 to remove 90 percent of the CO 2 

## in the F G exiting the HRSG, purify it, and compress it to a SC condition. It is assumed that all of the carbon in the natural gas is converted to CO 2 

## . The CDR is comprised of FG supply, CO 2 

## absorption, solvent stripping and reclaiming, and CO 2 

## compression and dr ying. Carbon Dioxide Recovery Facility

The CO 2 

## absorption/stripping/solvent reclaim process for Case 14 is based on the Fluor Econamine FG Plus SM 

## technology as previously described in Section 4.1.7 with the exception that no SO 2 

## polishing step is required in the NGCC case. If the pipeline natural gas used in this study contained the maximum amount of sulfur allowed per EPA specifications (0.6 gr S/100 scf), the FG would contain 0.4 ppmv of SO 2 

## , whi ch is well below the limit where a polishing scrubber would be required (10 ppmv). A description of the basic process steps is repeated here for completeness with minor modifications to reflect application in an NGCC system as opposed to PC.

The function of the FG cooling and supply system is to transport FG from the HRSG to the CO 2 

## absorption tower, and condition FG pressure, temperature and moisture content so it meets the requirements of the Econamine process. Temperature and hen ce moisture content of the FG exiting the HRSG is reduced in the Direct Contact FG Cooler, where FG is cooled using cooling water. FG Cooling an d Supply

The water condensed from the FG is collected in the bottom of the Direct Contact FG Cooler section and re

- circulated to the top of the Direct Contact FG Cooler section via the FG Circulation Water Cooler, which rejects heat to the plant CWS . Level in the Direct Contact FG Cooler is controlled by directing the excess water to the cooling water return line. In the Direct Conta ct FG Cooler, FG is cooled beyond the CO 2 

## absorption process requirements to 33°C (91°F) to account for the subsequent FG temperature increase of 14°C (25°F) in the FG blower. Downstream from the Direct Contact FG Cooler FG pressure is boosted in the FG b lowers by approximately 0.01 MPa (2 psi) to overcome pressure drop in the CO 2 

## absorber tower.

Cooling water is provided from the NGCC plant CWS and returned to the NGCC plant cooling tower. The CDR facility requires a significant amount of cooling water for FG cooling, water wash cooling, absorber intercooling, reflux condenser duty, reclaimer cooling, the lean solvent cooler, and CO 2 

## compression interstage cooling. The cooling water requirements for the CDR facility in the NGCC c apture case is about 594,308 lpm (1 57 ,000 gpm), which greatly exceeds the NGCC plant cooling water requirement of about 200,626 lpm ( 53 ,000 gpm). Circulating Water System

The cooled FG enters the bottom of the CO 2 

## Absorber and flows up through the tower countercurrent to a stream of lean MEA

- based solvent called Econamine. Approximately 90 percent of the CO 2 

## in the feed gas is absorbed into the lean solvent, and the rest leaves the top of the absorber section and flows into the water wash section of the tower. The lean solvent enters the top of the absorber, absorbs the CO 2 

## from the flue gas and leaves the bottom of the absorber with the absorbed CO 2 

## . CO 2 

## Absorption

### Cost and Performance Baseline for Fossil Energy Plants

447 

## The purpose of the Water Wash section is to minimize solvent losses due to mechanical entrainment and evaporation. The FG from the top of the CO 2 

## Absorption section is contacted with a re

- circulating stream of water for the removal of most of the lean solvent. The scrubbed gases, along with unreco vered solvent, exit the top of the wash section for discharge to the atmosphere via the vent stack. The water stream from the bottom of the wash section is collected on a chimney tray. A portion of the water collected on the chimney tray spills over to t he absorber section as water makeup for the amine with the remainder pumped via the Wash Water Pump and cooled by the Wash Water Cooler, and recirculated to the top of the CO 2 

## Absorber. The wash water level is maintained by water makeup from the Wash Wate r Makeup Pump. Water Wash Section

The rich solvent from the bottom of the CO 2 

## Absorber is preheated by the lean solvent from the Solvent Stripper in the Rich Lean Solvent Exchanger. The heated rich solvent is routed to the Solvent Strip per for removal of the absorbed CO 2 

## . The stripped solvent from the bottom of the Solvent Stripper is pumped via the Hot Lean Solvent Pumps through the Rich Lean Exchanger to the Solvent Surge Tank. Prior to entering the Solvent Surge Tank, a slipstream o f the lean solvent is pumped via the Solvent Filter Feed Pump through the Solvent Filter Package to prevent buildup of contaminants in the solution. From the Solvent Surge Tank the lean solvent is pumped via the Warm Lean Solvent Pumps to the Lean Solvent Cooler for further cooling, after which the cooled lean solvent is returned to the CO 2 

## Absorber, completing the circulating solvent circuit. Rich/Lean Amine Heat Exchange System

The purpose of the Solvent Stripper is to separate the CO 2 

## from the rich solvent feed exiting the bottom of the CO 2 

## Absorber. The rich solvent is collected on a chimney tray below the bottom packed section of the Solvent Stripper and routed to the Solvent Stripper Reboilers where the rich solvent is heated by steam, stripping the CO 2 

## from the solutio n. Steam is provided from the crossover pipe between the IP and LP section s of the steam turbine at about 0. 51 MPa ( 73.5 psia) and 152 °C ( 306 °F). The hot wet vapor from the top of the stripper containing CO 2 

## , steam, and solvent vapor, is partially conden sed in the Solvent Stripper Condenser by cross exchanging the hot wet vapor with cooling water. The partially condensed stream then flows to the Solvent Stripper Reflux Drum where the vapor and liquid are separated. The uncondensed CO 2 

## - rich gas is then del ivered to the CO 2 

## product compressor. The condensed liquid from the Solvent Stripper Reflux Drum is pumped via the Solvent Stripper Reflux Pumps where a portion of condensed overhead liquid is used as make

- up water for the Water Wash section of the CO 2 

## Ab sorber. The rest of the pumped liquid is routed back to the Solvent Stripper as reflux, which aids in limiting the amount of solvent vapors entering the stripper overhead system. Solvent Stripper

A small slipstream of the lean solvent from the S olvent Stripper bottoms is fed to the Solvent Stripper Reclaimer for the removal of high

- boiling nonvolatile impurities (HSS), volatile acids , and iron products from the circulating solvent solution. The solvent bound in the HSS is recovered by reaction w ith caustic and heating with steam. The solvent reclaimer system reduces corrosion, foaming and fouling in the solvent system. The reclaimed solvent is returned Solvent Stripper Reclaimer

### Cost and Performance Baseline for Fossil Energy Plants

448 

## to the Solvent Stripper and the spent solvent is pumped via the Solvent Reclaimer Drain Pump to the Solvent Reclaimer Drain Tank.

Steam condensate from the Solvent Stripper Reclaimer accumulates in the Solvent Reclaimer Condensate Drum and level controlled to the Solvent Reboiler Condensate Drum. Steam condensate from the Solvent Stripper Reboilers is also collected in the Solvent Reboiler Condensate Drum and returned to the steam cycle just downstream of the deaerator via the Solvent Reboiler Condensate Pumps. Steam Condensate

A proprietary corrosion inhibitor is contin uously injected into the CO 2 

## Absorber rich solvent bottoms outlet line, the Solvent Stripper bottoms outlet line and the Solvent Stripper top tray. This constant injection is to help control the rate of corrosion throughout the CO 2 

## recovery plant system. Corrosion Inhibitor System

In the compression section, the CO 2 

## is compressed to 15.3 MPa (2,215 psia) by a six

- stage centrifugal compressor. The discharge pressures of the stages were balanced to give reasonable power distribution and discharge tem peratures across the various stages as shown in Gas Compression and Drying System

Exhibit 5

- 2

. Power consumption for this large compr essor was estimated assuming a polytropic efficiency of 86 percent and a mechanical efficiency of 98 percent for all stages . During compression to 15.3 MPa (2,215 psia) in the multiple

- stage, intercooled compressor, the CO 2 

## stream is dehydrated to a dewpoint of

- 40oC (

- 40°F) with triethylene glycol. The virtually moist ure - free SC CO 2 

## stream is delivered to the plant battery limit as sequestration ready. CO 2 

## TS&M costs were estimated and included in LCOE and COE using the methodology described in Section 2.7.
5.1.6 The steam turbine consists of an HP section, an IP section, and one double

- flow LP section, all connected to the generator by a common shaft. The HP and IP sections are contained in a single span, opposed

- flow casing, with the double

- flow LP section in a separate casing. Steam Turbine

Main steam from the boiler p asses through the stop valves and control valves and enters the turbine at 16.5 MPa/566°C (2400 psig/1050°F). The steam initially enters the turbine near the middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The reh eat steam flows through the reheat stop valves and intercept valves and enters the IP section at 2.5 MPa/5 66 °C (3 60 psia/ 10 50°F). After passing through the IP section, the steam enters a
cross - over pipe, which transports the steam to the LP section. A br anch line equipped with combined stop/intercept valves conveys LP steam from the HRSG LP drum to a tie

- in at the
cross - over line. The steam divides into two paths and flows through the LP sections exhausting downward into the condenser.

### Cost and Performance Baseline for Fossil Energy Plants

449 

## Exhibit 5

- 2 CO 2 

## Compressor Interstage Pressures Stage Outlet Pressure, MPa (psia) 1 0.36 (52) 2 0.78 (113) 3 1.71 (248) 4 3.76 (545) 5 8.27 (1,200) 6 15.3 (2,215)

Turbine bearings are lubricated by a CL , water

- cooled pressurized oil system. Turbine shafts are sealed against air in

- leakage or steam blowout using a modern positive pressure variable clearance shaft sealing design arrangement connected to a LP steam seal system. The generator is a hydrogen

- cooled synchronous type, generating power at 24 kV. A static, transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation system using fans mounted on the generator rotor shaft . The STG is controlled by a triple

- redu ndant microprocessor

- based electro

- hydraulic control system. The system provides digital control of the unit in accordance with programmed control algorithms, color monitor/operator interfacing, and datalink interfaces to the balance

- of

- plant DCS, and inc orporates on

- line repair capability.
5.1.7 Water and Steam Systems

The function of the condensate system is to pump condensate from the condenser hotwell to the deaerator, through the gland steam condenser; and the low

- temperature economizer section in the HRSG. Condensate

The system consists of one main condenser; two 50 percent capacity, motor

- driven vertical multistage condensate pumps (total of two pumps for the plant); one gland steam condenser; condenser air removal vacuum pumps, condensate polisher, and a low

- temperature tube bundle in the HRSG. Condensate is delivered to a common discharge header through two separate pump discharge lines, each with a check valve and a gate valve. A common minimum flow recirculation line discharging to the condenser is pr ovided to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

The function of the FW system is to pump the various FW streams from the deaerator storage tank in the HRSG to the respective steam drums. One 1 00 percent capacity motor

- driven feed pump is provided per each HRSG (total of two pumps for the plant). The FW pumps are equipped with an interstage takeoff to provide IP and LP FW . Each pump is provided with inlet and outlet isolation valves, outlet ch eck valves, and individual minimum flow recirculation lines Feedwater

### Cost and Performance Baseline for Fossil Energy Plants

450 

## discharging back to the deaerator storage tank. The recirculation flow is controlled by pneumatic flow control valves. In addition, the suctions of the boiler feed pumps are equipped with startu p strainers, which are utilized during initial startup and following major outages or system maintenance.

The steam system is comprised of main, reheat, intermediate, and LP steam systems. The function of the main steam system is to convey ma in steam from the HRSG superheater outlet to the HP turbine stop valves. The function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG reheater and from the HRSG reheater outlet to the turbine reheat stop valves. Steam System

Main steam exits the HRSG superheater through a motor

- operated stop/check valve and a motor

operated gate valve, and is routed to the HP turbine. Cold reheat steam exits the HP turbine, and flows through a motor

- operated isolation gate valve to the HRSG reheater. Ho t reheat steam exits at the HRSG reheater through a motor

- operated gate valve and is routed to the IP turbines.

The function of the CWS is to supply cooling water to condense the main turbine exhaust steam, for the auxiliary cool ing system and for the CDR facility in Case 14. The system consists of two 50 percent capacity vertical CWP s (total of two pumps for the plant), a mechanical draft evaporative cooling tower, and interconnecting piping. The condenser is a single pass, hor izontal type with divided water boxes. There are two separate circulating water circuits in each box. One

- half of the condenser can be removed from service for cleaning or plugging tubes. This can be done during normal operation at reduced load. Circulating Water System

The a uxiliary cooling system is a CL system. Plate and frame heat exchangers with circulating water as the cooling medium are provided. The system provides cooling water to the following systems: 1. CTG lube oil coolers 2. CTG air coolers 3. STG lube oil coolers 4. STG h ydrogen coolers 5. Boiler feed water pumps 6. Air compressors 7. Generator seal oil coolers (as applicable) 8. Sample room chillers 9. Blowdown coolers 10. Condensate extraction pump

- motor coolers The CDR system in Case 14 requires a substantial amount of cooling water that is provided by the NGCC plant CWS . The additional cooling load imposed by the CDR is reflected in the significantly larger CWP s and cooling tower in that case.

### Cost and Performance Baseline for Fossil Energy Plants

451 

## Structures assumed for NGCC cases can be summarized as follows: Buildings and Str uctures

1. Generation Building housing the STG 2. CWP House 3. Administration / Office / Control Room / Maintenance Building 4. Water Treatment Building 5. Fire Water Pump House
5.1.8 Th e accessory electric plant consists of all switchgear and control equipment, generator equipment, station service equipment, conduit and cable trays, wire, and cable. It also includes the main transformer, required foundations , and standby equipment. Accessory Electric Plant

5.1.9 An integrated plant

- wide DCS is provided. The DCS is a redundant microprocessor

- based, functionally distributed system. The control room houses an array of video monitors and keyboard units. The monitor/keyboard units are the pri mary interface between the generating process and operations personnel. The DCS incorporates plant monitoring and control functions for all the major plant equipment. The DCS is designed to provide 99.5 percent availability. Inst rumentation and Control

The plant equipment and the D CS are designed for automatic response to load changes from minimum load to 100 percent. Startup and shutdown routines are implemented as supervised manual procedures with operator selection of modular automation routines available.

### Cost and Performance Baseline for Fossil Energy Plants

452 

## 5.2 NGCC CASES This section contains an evaluation of plant designs for Cases 13 and 14. These two cases are similar in design and are based on an NGCC plant with a constant thermal input. Both plants use
a single reheat 16.5 MPa/566°C/566 °C (2400 psig/1050 **°** F/10 50 **°** F) c ycle. The only difference between the two plants is that Case 14 includes CO 2 

## capture while Case 13 does not. The balance of Section 5.2 is organized as follows:

**•** Process and System Description provides an overview of the technology operation as applied to Case 13. The systems that are common to all NGCC cases were covered in Section 5.1 and only features that are unique to Case 13 are discussed further in this section.

**•** Key Assumptions is a summary of study and modeling assumptions rele vant to Cases 13 and 14.

**•** Sparing Philosophy is provided for both Cases 13 and 14.

**•** Performance Results provides the main modeling results from Case 13, including the performance summary, environmental performance, carbon balance, water balance, mass and ene rgy balance diagrams , and energy balance table.

**•** Equipment List provides an itemized list of major equipment for Case 13 with account codes that correspond to the cost accounts in the Cost Estimates section.

**•** Cost Estimates provides a summary of capital and operating costs for Case 13.

**•** Process and System Description, Performance Results, Equipment List and Cost Estimates are reported for Case 14.
5.2.1 In this section the NGCC process without CO 2 

## capture is described. The system description fol lows the BFD in Process Description

Exhibit 5

- 3 and str eam numbers reference the same e xhibit. The tables in Exhibit 5

- 4 provide process data for the numbered streams in the BFD. The BFD shows only one of the two CT /HRSG combinations, but the flow rates in the stream table are the total for two systems. Ambient air (stream 1) and natural gas (stream 2) are combined in the dry LNB, which is operated to control the rotor inlet temperature at 1371°C (250 0°F). The FG exits the turbine at 629°C (1163 °F) (stream 3) and passes into the HRSG. The HRSG generates both the main steam and reheat steam for the steam turbine. FG exits the HRSG at 10 6 °C (22 2 °F) and passes to the plant stack

### Cost and Performance Baseline for Fossil Energy Plants

453 

## Exhibit 5

- 3 Case 13 Block Flow Diagram, NGCC without CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

454 

## Exhibit 5

- 4 Case 13 Stream Table, NGCC without CO 2 

## Capture
1 2 3 4 5 6 V-L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 0.0000 0.0000 CH 4 

### 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 C 2 

### H 6 

### 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 C 3 

### H 8 

### 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 C 4 

### H 10 

### 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 

### 0.0003 0.0100 0.0404 0.0404 0.0000 0.0000 H 2 

### O 0.0099 0.0000 0.0867 0.0867 1.0000 1.0000 N 2 

### 0.7732 0.0160 0.7432 0.7432 0.0000 0.0000 O 2 

### 0.2074 0.0000 0.1209 0.1209 0.0000 0.0000 SO 2 

### 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol 

### /hr) 109,323 4,380 113,831 113,831 21,589 28,545 V-L Flowrate (kg/hr) 3,154,735 75,901 3,230,636 3,230,636 388,927 514,240 Solids Flowrate (kg/hr) 0 0 0 0 0 0
Temperature (°C) 15 38 629 106 566 38 Pressure (MPa, abs) 0.10 3.10 0.11 0.10 16.65 0.01 Enthalpy (kJ/kg) A 

### 30.23 46.30 835.81 248.81 3,472.36 160.61 Density (kg/m 3 

### ) 1.2 22.2 0.4 0.9 47.7 992.9 V-L Molecular Weight 28.857 17.328 28.381 28.381 18.015 18.015
V-L Flowrate (lb mol 

### /hr) 241,016 9,657 250,954 250,954 47,595 62,930 V-L Flowrate (lb/hr) 6,955,000 167,333 7,122,333 7,122,333 857,437 1,133,706 Solids Flowrate (lb/hr) 0 0 0 0 0 0
Temperature (°F) 59 100 1,163 222 1,050 101 Pressure (psia) 14.7 450.0 15.2 14.7 2,414.7 1.0 Enthalpy (Btu/lb) A 

### 13.0 19.9 359.3 107.0 1,492.8 69.1 Density (lb/ft 3 

### ) 0.076 1.384 0.025 0.057 2.977 61.982 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

455 

## 5.2.2 System assumptions for Cases 13 and 14 , NGCC with and without CO 2 

## capture, are compiled in Key System Assumptions

Exhibit 5

- 5

. Exhibit 5

- 5 NGCC Plant Study Configuration Matrix Case 13 w/o CO 2 

## Capture Case 1 4 w/CO 2 

## Capture Steam Cycle , MPa/°C/°C ( psig /°F/°F) 16.5/566/566 ( 2400 /1050/10 50) 16.5/566/566 ( 2400 /1050/10 50) Fuel Natural Gas Natural Gas Fuel Pressure at Plant Battery Limit MPa (psia ) 3.1 (450) 3.1 (450)
Condenser P ressure, mm Hg ( in Hg ) 50.8 ( 2 ) 50.8 ( 2 ) Cooling W ater to C ondenser, °C ( oF ) 16 ( 60 ) 16 ( 60 ) Cooling W ater from C ondenser, °C ( oF ) 27 ( 80 ) 27 ( 80 ) Stack T emperature , °C (°F) 106 (222 ) 29 (85) SO 2 

## Control Low Sulfur Fuel Low Sulfur Fuel NOx Control LNB and SCR LNB and SCR SCR E fficiency , % (A) 90 90 Ammonia S lip ( E nd of C atalyst L ife), ppm v 10 10
Particulate Control N/A N/A Mercury Control N/A N/A CO 2 

## Control N/A Econamine Overall CO 2 

## Capture (A) N/A 90 .7 %
CO 2 

## Sequestration N/A Off

- site Saline Formation A. Removal efficiencies are based on the FG content

The balance of plant assumptions are common to both NGCC cases and are presented in Balance of Plant

– Cases 13 and 1 4

Exhibit 5

- 6

.

### Cost and Performance Baseline for Fossil Energy Plants

456 

## Exhibit 5

- 6 NGCC Ba lance of Plant Assumptions Recirculating Wet Cooling Tower Cooling S ystem Fuel and Other Storage Natural Gas Pipeline supply at 3.1 MPa (450 psia) and 38°C (100°F) Plant Distribution Voltage Motors below 1 hp 110/220 volt Motors between 1 hp and 250 hp 480 volt Motors between 250 hp and 5,000 hp 4,160 volt Motors above 5,000 hp 13,800 volt Steam and GT generators 24,000 volt Grid Interconnection voltage 345 kV Water and Waste Water Makeup Water The water supply is 50 percent from a local POTW and 50 percent from groundwater , and is assumed to be in sufficient quantities to meet plant makeup requirements

. Makeup for potable, process, and DI water is drawn from municipal sources

. Process Wastewater Storm water that contacts equipment surfaces is collected and treated for discharge through a permitted discharge. Sanitary Waste Disposal Design includes a packaged domestic sewage treatment plant with effluent discharged to the industrial wastewater treatment system. Sludge is hauled off site. Packaged plant is sized for 5.68
m 3 

## /d (1,500 gpd ) Water Discharge Most of the process wastewate r is recycled to the cooling tower basin. Blowdown is treated for chloride and metals, and discharged.

5.2.3 Dual trains are used to accommodate the size of commercial GT s. There is no redundancy other than normal sparing of rotating equipment. The plant design consists of the following major subsystems: Sparing Philosophy

**•** Two advanced F class CTG s (2 x 50%)

**•** Two 3

- pressure reheat HRSGs with self supporting stacks and SCR systems (2 x 50%)

**•** One 3

- pressure reheat, triple

- admission STG (1 x 100%)

**•** Two trains of Econamine CO 2 

## capture (2 x 50%) (Case 14 only)

### Cost and Performance Baseline for Fossil Energy Plants

457 

## 5.2.4 The plant produces a net output of 5 55 MW at a net plant efficiency of 50. 2 percent (HHV basis). Case 13 Performance Results

Overall plant performance is summarized in Exhibit 5

- 7 , which includes auxiliary power requirements. Exhibit 5

- 7 Case 13 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Gas Turbine Power 362,200 Steam Turbine Power 202,500 TOTAL POWER, kWe 564,700 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 170 Boiler Feedwater Pumps 2,720 Circulating Water Pump 2,300 Ground Water Pumps 210 Cooling Tower Fans 1,190 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 

## 500 Transformer Losses 1,720 TOTAL AUXILIARIES, kWe 9,620 NET POWER, kWe 555,080 Net Plant Efficiency (HHV) 50.2% Net Plant Efficiency (LHV) 55.7% Net Plant Heat Rate (HHV) , kJ/kWh (Btu/kWh ) 7,172 (6,798) Net Plant Heat Rate (LHV) , kJ/kWh ( Btu/kWh ) 6,466 (6,129) CONDENSER COOLING DUTY, 10 6 

## kJ/h r (10 6 

## Btu/h r ) 1,139 (1,080) CONSUMABLES Natural Gas Feed Flow , kg/hr (lb/hr) 75,901 (167,333) Thermal Input (HHV) , kW th 

## 1,105,812 Thermal Input (LHV) , kW th 

## 997,032 Raw Water Withdrawal , m 3 

## /min (gpm) 8.9 (2,362) Raw Water Consumption , m 3 

## /min (gpm) 6.9 (1,831) 1. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

458 

## The environmental targets for emissions of NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 13 is presented in Environmental Performance

Exhibit 5

- 8

. Exhibit 5

- 8 Case 13 Air Emissions

kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)

SO 2 

## Negligible Negligible Negligible
NOx 0.004 (0.009) 1 15 (127 ) 0.027 (0.060)
Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligible

CO 2 

## 51 (118 ) 1,507,427 (1,661,654) 359 (790 )

CO 2 1 

## 365 (804 )

1 

### CO 2 

### emissions based on net power instead of gross power 

## The operation of the modern, state

- of

- the

- art GT fueled by natural gas, coupled to a HRSG, results in very low levels of NOx emissions and negligible levels of SO 2 

## , particulate and Hg emissions. As noted in Section 2.4, if the fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 

## emissions would be 21 tonnes/yr (23 tons/yr) at 85 percent CF , or 0.00195 lb/MMBtu. The low level of NOx production (2.5 ppmvd at 15 percent O 2 

## ) is achieved by utilizing a dry LNB cou pled with an SCR system. CO 2 

## emissions are reduced relative to those produced by burning coal given the same power output because of the higher heat content of natural gas, the lower carbon intensity of gas relative to coal, and the higher overall efficien cy of the NGCC plant relative to a coal

- fired plant. The carbon balance for the plant is shown in Exhibit 5

- 9

. The carbon input to the plant consists
o f carbon in the natural gas and carbon as CO 2 

## in the CT air

. Carbon leaves the plant as CO 2 

## through the stack. Exhibit 5

- 9 Case 13 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Natural Gas 54,822 (120,863) Stack Gas 55,251 (121,808) Air (CO 2 

## ) 429 (946) Total 55,251 (121,808) Total 55,251 (121,808)

### Cost and Performance Baseline for Fossil Energy Plants

459 

## A sulfur balance is not included for Case 13 because the sulfur concentration of the natural gas feed is negligible. Consequently, sulfur emissions are also negligible, as shown in Exhibit 5

- 8 , despite the use of no sulfur control technology. Exh ibit 5

- 10 sh ows the water balance for Case 13 . Water demand represents the total amount of water required for a particular process. Some water is recovered within the process and is re

us ed as internal recycle. The difference between demand and recycle is raw water withdrawal. Raw water withdrawal is defined as the water removed from the ground or diverted from a surface

- water source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from groundwater. Raw water withdrawal can be represented by the water metered from a raw water source and used in the plant processes for any and all purposes, such
as condenser and cooling tower makeup. The difference between water withdrawal and process water discharge is defined as water consumption and can be represented by the portion of the raw water withdrawn that is evaporated, transpired, incorporated into products or otherwise not returned to the water source f rom which it was withdrawn. Water consumption represents the net impact of the plant process on the water source balance. Exhibit 5

- 10 Case 13 Water Balance

Water Use Water Demand,

m 3 

## /min (gpm) Internal Recycle, m 3 

## /min (gpm) Raw Water Withdrawal,
m 3 

## /min (gpm) Process Water Discharge,

m 3 

## /min (gpm) Raw Water Consumption,
m 3 

## /min (gpm)

Condenser Makeup BFW Makeup 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23)

Cooling Tower BFW Blowdown 8.9 (2,362) 0.0 (0) 0.1 (23) 0.1 (23) 8.9 (2,339)

- 0.1 (

- 23) 2.0 (531) 6.8 (1,808)

Total 9.0 (2,385) 0.1 (23) 8.9 (2,362) 2.0 (531) 6.9 (1,831)

A heat and mass balance diagram is shown for the NGCC in Heat and Mass Balance Diagrams Exhibit 5

- 11

. An overall plant energy balance is provided in tabular form in Exhibit 5

- 12 . The p ower out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 5

- 7 ) is calculated by multiplyi ng the power out by a combined generator efficiency of 98.4 percent.

### Cost and Performance Baseline for Fossil Energy Plants

460 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

461 

## Exhibit 5

- 11 Case 13 Heat and Mass Balance, NGCC without CO 2 

## Capture

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Nitrogen Natural Gas

Carbon Dioxide

Water Steam

P AGES 1 OF 1 N ATURAL GAS COMBINED CYCLE PLANT C ASE 13 2 X ADVANCED F
- CLASS GT 2400 / 1050 / 1050

DWG

. NO

. BB

- HMB

- CS

- 13

- PG

- 1 Flue Gas

A MBIENT

A IR 1 6 , 955 , 000 W 59

. 0 T 14

. 7 P 12

. 9 H Gross Plant Power : 565 MWe Auxiliary Load : 10 MWe Net Plant Power : 555 MWe Net Plant Efficiency , HHV : 50

. 2 % Net Plant Heat Rate : 6 , 798 BTU / KWe A DVANCED F C LASS G AS T URBINES

COMBUSTOR N ATURAL GAS 167 , 333 W

100

. 0 T 450

. 0 P 19

. 9 H 2

7 , 122 , 333 W 222

. 4 T 14

. 7 P 106

. 9 H 7 , 122 , 333 W

1 , 163

. 5 T

15

. 2 P 359

. 3 H GENERATOR

CONDENSATE PUMPS8,801W1,302W

101

. 3 T 130

. 0 P 69

. 5 H 1 , 133 , 706 W 101

. 1 T

1

. 0 P 69

. 1 H

1 , 400 W 581

. 0 T 75

. 0 P 1 , 321

. 3 H 1 , 017 , 200 W 641

. 4 T 75

. 0 P 1 , 351

. 1 H 1 , 110 , 400 W 632

. 6 T 75

. 0 P 1 , 346

. 8 H

1 , 110 , 400 W 101

. 1 T

1

. 0 P 1 , 032

. 6 H

HOT WELL CONDENSER

S TACK 4 S TEAM T URBINE MAKEUP
11 , 337 W

59

. 0 T 14

. 7 P 27

. 1 H

AIR INLET

FILTER 3

HP PUMP 1 , 133 , 706 W 253

. 0 T 100

. 0 P 221

. 9 HBLOWDOWN

94 , 141 W

300

. 1 T 95

. 0 P 269

. 4 H 173 , 467 W

300

. 7 T 400

. 0 P 270

. 7 H 866 , 098 W

305

. 3 T 2 , 540

. 0 P 279

. 3 H11,337W GLAND SEAL CONDENSER 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H LP TURBINE

9 , 569 W

1 , 133 , 706 W 103

. 9 T 120

. 0 P 72

. 1 H

Three Pressure Heat Recovery Steam Generator ( HRSG ) 829 , 777 W 1 , 055

. 0 T 360

. 0 P 1 , 553

. 4 H

A A 171 , 732 W 1 , 055

. 0 T 360

. 0 P 1 , 553

. 4 HHOT REHEAT

C OLD R EHEAT

829 , 777 W

587

. 9 T 390

. 0 P 1 , 300

. 6 H STEAM SEAL REGULATOR

93 , 200 W

537

. 0 T 80

. 0 P 1 , 299

. 1 H 16 , 993 W

970

. 1 T 1 , 850

. 0 P 1 , 459

. 8 H HP TURBINE IP TURBINE852,917W 2 , 654 W 1 , 050

. 0 T 2 , 414

. 7 P 1 , 492

. 8 H1,018,502WMAIN STEAM

857 , 437 W 1 , 050

. 0 T 2 , 414

. 7 P 1 , 492

. 8 H 5

10 , 969 W866W IP STEAM

IP PUMP

LP PUMP 6

DOE / NETL
SC PC P LANT C ASE 13

### Cost and Performance Baseline for Fossil Energy Plants

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## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

463 

## Exhibit 5

- 12 Case 13 Overall Energy Balance ( 0°C [ 32°F ] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Natural Gas 3,981 (3,773) 2.7 (2.5) 3,984 (3,776) GT Air 95.4 (90.4) 95 (90) Raw Water Withdrawal 33.6 (31.9) 34 (32) Auxiliary Power 35 (33) 35 (33) Totals 3,981 (3,773) 131.6 (124.8) 35 (33) 4,147 (3,931) Heat Out GJ/hr (MMBtu/hr) Cooling Tower Blowdown 14.9 (14.2) 15 (14) Stack Gas 804 (762) 804 (762) Condenser 1,141 (1,082) 1,141 (1,082) Process Losses* 154 (146) 154 (146) Power 2,033 (1,927) 2,033 (1,927) Totals 0 (0) 2,114 (2,004) 2,033 (1,927) 4,147 (3,931) * Process Losses are calculated by difference and reflect various turbine, and other heat and

work losses.

### Cost and Performance Baseline for Fossil Energy Plants

464 

## 5.2.5 Major equipment items for the NGCC plant with no CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 13

– Major Equipment List

5.2.6 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HAN DLING N/A

ACCOUNT 2 FUEL AND SORBENT PRE PARATION AND FEED

Equipment No. Description Type Operating Qty. Spares

1 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 16 km (10 mile) 0

2 Gas Metering Station

-- 1 0 Design Condition

63 m3/min @ 3.1 MPa (2,216 acfm @ 450 psia) 41 cm (16 in) standard wall pipe

63 m3/min (2,216 acfm)

### Cost and Performance Baseline for Fossil Energy Plants

465 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

4 Auxiliary Boiler Shop fabricated, water tube 1 0

5 Service Air Compressors Flooded Screw 2 1

6 Instrument Air Dryers Duplex, regenerative 2 1

7 Closed Cycle Cooling Heat Exchangers Plate and frame 2 0

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

9 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

10 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

11 Raw Water Pumps Stainless steel, single suction 2 1

12 Filtered Water Pumps Stainless steel, single suction 2 1

13 Filtered Water Tank Vertical, cylindrical 1 0

14 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly and electro-deionization unit 1 0

15 Liquid Waste Treatment System 1 0 Design Condition
678,767 liters (179,310 gal) 4,732 lpm @ 110 m H2O (1,250 gpm @ 360 ft H2O)

13 MMkJ/hr (13 MMBtu/hr) 3 Boiler Feedwater Pump Horizontal, split case, multi-stage, centrifugal, with interstage bleed for IP and LP feedwater

5,300 lpm @ 21 m H2O (1,400 gpm @ 70 ft H2O) 2 HP water: 3,634 lpm @ 2,103 m H2O (960 gpm @ 6,900 ft H2O) IP water: 719 lpm @ 283 m H2O (190 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F) 13 m3/min @ 0.7 MPa (450 scfm @ 100 psig) LP water: 379 lpm @ 24.4 m H2O (100 gpm @ 80 ft H2O) 1

143,847 liter (38,000 gal)

341 lpm (90 gpm)

10 years, 24-hour storm 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 4,921 lpm @ 18 m H2O (1,300 gpm @ 60 ft H2O)

151 lpm @ 49 m H2O (40 gpm @ 160 ft H2O)

13 m3/min (450 scfm)

### Cost and Performance Baseline for Fossil Energy Plants

466 

## ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES N/A

ACCOUNT 5 FLUE GAS CLEANUP N/A

ACCOUNT 6 COMBUSTION TURBINE G ENERATORS AND AUXILI ARIES

ACCOUNT 7 WASTE HEAT BOILER, D UCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class w/ dry low-NOx burner 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

184 MW
200 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase



### Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 2 0

3 SCR Reactor Space for spare layer 2 0

4 SCR Catalyst

-- 1 layer 0

5 Dilution Air Blowers Centrifugal 2 1

6 Ammonia Feed Pump Centrifugal 2 1

7 Ammonia Storage Tank Horizontal tank 1 0 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 249,852 kg/h, 2.4 MPa/566°C (550,830 lb/h, 345 psig/1,050°F) Design Condition
46 m (150 ft) high x 7.5 m (25 ft) diameter Main steam - 213,910 kg/h, 16.5 MPa/566°C (471,590 lb/h, 2,400 psig/1,050°F)

1,778,084 kg/h (3,920,000 lb/h) Space available for an additional catalyst layer 11 m3/min @ 107 cm WG (390 scfm @ 42 in WG)

3.8 lpm @ 91 m H2O (1 gpm @ 300 ft H2O)
68,138 liter (18,000 gal)

### Cost and Performance Baseline for Fossil Energy Plants

467 

## ACCOUNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 ASH/SPENT SORBENT RECOVERY AND HANDLING N/A Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Tandem compound,HP, IP, and twoflow LP turbines 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1 0 Design Condition
213 MW 16.5 MPa/566°C/566°C (2,400 psig/ 1050°F/1050°F)

1,254 MMkJ/hr, (1,190 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase
50% steam flow @ design steam conditions

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition 230,912 lpm @ 30.5 m (61,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT 1,283 MMkJ/hr (1,217 MMBtu/hr) heat load

### Cost and Performance Baseline for Fossil Energy Plants

468 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

3 Auxiliary Transformer Oil-filled 1 1

4 Low Voltage Transformer Dry ventilated 1 1

5 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

6 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

7 Medium Voltage Switchgear Metal clad 1 1

8 Low Voltage Switchgear Metal enclosed 1 1

9 Emergency Diesel Generator Sized for emergency shutdown 1 0 Design Condition 24 kV/345 kV, 200 MVA, 3-ph, 60 Hz 24 kV/345 kV, 230 MVA, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 4.16 kV/480 V, 1 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV/4.16 kV, 09 MVA, 3-ph, 60 Hz 2 STG Transformer Oil-filled 1 0

Equipment No. Description Type Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 Design Condition

Operator stations/printers and

engineering stations/printers

0

Fully redundant, 25% spare 1 2 DCS - Processor Microprocessor with redundant input/output N/A

### Cost and Performance Baseline for Fossil Energy Plants

469 

## 5.2.6 The cost estimating methodology was described previously in Section Case 13

– Cost Estimating 2.7

. Exhibit 5

- 13 shows the total plant capital cost summary organized by cost account and Exhibi t 5

- 14 shows a more detailed breakdown of the capital costs. Exhibit 5

- 15 shows the initial and annual O&M costs. The estimated TO C of the NGCC with no CO 2 

## capture is $ 718 /kW. No process contingency was included in this case because all elements of the technology are commercially proven. The project contingency is 8.6 percent of TOC. The COE is 58

. 9 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

470 

## Exhibit 5

- 13 Case 13 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 13 - 1x555 MWnet 2x1 7FB NGCC Plant Size: 555.1 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

3 FEEDWATER & MISC. BOP SYSTEMS $22,444 $4,461 $6,516 $0 $0 $33,421 $2,819 $0 $5,782 $42,022 $76

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $172 6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3 SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $176

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $80 7.2-7.9 SCR System, Ductwork and Stack $1,243 $950 $1,118 $0 $0 $3,311 $282 $0 $583 $4,176 $8 SUBTOTAL 7 $34,200 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $88

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,774 $0 $3,855 $0 $0 $27,630 $2,374 $0 $3,000 $33,005 $59 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,304 $798 $5,509 $0 $0 $14,611 $1,190 $0 $2,164 $17,965 $32 SUBTOTAL 8 $32,078 $798 $9,365 $0 $0 $42,241 $3,565 $0 $5,164 $50,970 $92

9 COOLING WATER SYSTEM $5,524 $4,298 $3,854 $0 $0 $13,677 $1,137 $0 $2,106 $16,920 $30

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $16,639 $3,671 $8,860 $0 $0 $29,170 $2,237 $0 $3,330 $34,737 $63

12 INSTRUMENTATION & CONTROL $5,778 $593 $4,801 $0 $0 $11,173 $930 $0 $1,387 $13,490 $24

13 IMPROVEMENTS TO SITE $1,722 $935 $4,582 $0 $0 $7,238 $640 $0 $1,576 $9,455 $17

14 BUILDINGS & STRUCTURES $0 $4,155 $4,417 $0 $0 $8,571 $697 $0 $1,390 $10,658 $19

TOTAL COST $193,680 $20,581 $53,339 $0 $0 $267,599 $22,400 $0 $34,366 $324,365 $584 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

471 

## Exhibit 5

- 14 Case 13 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,426 $2,499 $2,055 $0 $0 $6,980 $576 $0 $1,133 $8,690 $16 3.2 Water Makeup & Pretreating $1,466 $153 $766 $0 $0 $2,384 $203 $0 $517 $3,105 $6 3.3 Other Feedwater Subsystems $1,106 $374 $314 $0 $0 $1,794 $144 $0 $291 $2,229 $4 3.4 Service Water Systems $173 $357 $1,157 $0 $0 $1,687 $147 $0 $367 $2,201 $4 3.5 Other Boiler Plant Systems $1,162 $450 $1,043 $0 $0 $2,655 $225 $0 $432 $3,313 $6 3.6 Natural Gas, incl. pipeline $14,667 $505 $440 $0 $0 $15,612 $1,323 $0 $2,540 $19,476 $35 3.7 Waste Treatment Equipment $529 $0 $302 $0 $0 $831 $72 $0 $181 $1,084 $2 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $915 $122 $439 $0 $0 $1,477 $128 $0 $321 $1,925 $3 SUBTOTAL 3. $22,444 $4,461 $6,516 $0 $0 $33,421 $2,819 $0 $5,782 $42,022 $76 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

### Cost and Performance Baseline for Fossil Energy Plants

472 

## Exhibit 5

- 14 Case 13 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $172 6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $3 SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $176 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $80 7.2 SCR System $1,243 $522 $733 $0 $0 $2,498 $215 $0 $407 $3,120 $6 7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2 SUBTOTAL 7. $34,200 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $88 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $23,774 $0 $3,855 $0 $0 $27,630 $2,374 $0 $3,000 $33,005 $59 8.2 Turbine Plant Auxiliaries $161 $0 $369 $0 $0 $530 $46 $0 $58 $634 $1 8.3 Condenser & Auxiliaries $4,108 $0 $1,226 $0 $0 $5,334 $457 $0 $579 $6,370 $11 8.4 Steam Piping $4,035 $0 $2,653 $0 $0 $6,688 $513 $0 $1,080 $8,281 $15 8.9 TG Foundations $0 $798 $1,261 $0 $0 $2,059 $175 $0 $447 $2,680 $5 SUBTOTAL 8. $32,078 $798 $9,365 $0 $0 $42,241 $3,565 $0 $5,164 $50,970 $92 9 COOLING WATER SYSTEM 9.1 Cooling Towers $3,880 $0 $496 $0 $0 $4,377 $373 $0 $475 $5,224 $9 9.2 Circulating Water Pumps $1,142 $0 $63 $0 $0 $1,205 $91 $0 $130 $1,425 $3 9.3 Circ.Water System Auxiliaries $93 $0 $12 $0 $0 $105 $9 $0 $11 $126 $0 9.4 Circ.Water Piping $0 $2,713 $657 $0 $0 $3,370 $272 $0 $546 $4,189 $8 9.5 Make-up Water System $229 $0 $305 $0 $0 $534 $46 $0 $87 $667 $1 9.6 Component Cooling Water Sys $180 $215 $143 $0 $0 $539 $45 $0 $88 $672 $1 9.9 Circ.Water System Foundations $0 $1,370 $2,177 $0 $0 $3,547 $301 $0 $770 $4,618 $8 SUBTOTAL 9. $5,524 $4,298 $3,854 $0 $0 $13,677 $1,137 $0 $2,106 $16,920 $30

### Cost and Performance Baseline for Fossil Energy Plants

473 

## Exhibit 5

- 14 Case 13 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $4,068 $0 $2,444 $0 $0 $6,513 $552 $0 $530 $7,594 $14 11.2 Station Service Equipment $1,208 $0 $102 $0 $0 $1,310 $108 $0 $106 $1,525 $3 11.3 Switchgear & Motor Control $1,489 $0 $253 $0 $0 $1,742 $145 $0 $189 $2,076 $4 11.4 Conduit & Cable Tray $0 $712 $2,194 $0 $0 $2,905 $251 $0 $474 $3,630 $7 11.5 Wire & Cable $0 $2,266 $1,391 $0 $0 $3,657 $236 $0 $584 $4,477 $8 11.6 Protective Equipment $0 $563 $1,916 $0 $0 $2,480 $217 $0 $270 $2,966 $5 11.7 Standby Equipment $103 $0 $94 $0 $0 $197 $17 $0 $21 $235 $0 11.8 Main Power Transformers $9,770 $0 $146 $0 $0 $9,916 $673 $0 $1,059 $11,648 $21 11.9 Electrical Foundations $0 $130 $319 $0 $0 $449 $38 $0 $98 $585 $1 SUBTOTAL 11. $16,639 $3,671 $8,860 $0 $0 $29,170 $2,237 $0 $3,330 $34,737 $63 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $735 $0 $458 $0 $0 $1,193 $101 $0 $194 $1,488 $3 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $220 $0 $132 $0 $0 $351 $30 $0 $57 $438 $1 12.7 Computer & Accessories $3,514 $0 $105 $0 $0 $3,619 $298 $0 $392 $4,308 $8 12.8 Instrument Wiring & Tubing $0 $593 $1,134 $0 $0 $1,727 $130 $0 $279 $2,136 $4 12.9 Other I & C Equipment $1,310 $0 $2,972 $0 $0 $4,282 $372 $0 $465 $5,120 $9 SUBTOTAL 12. $5,778 $593 $4,801 $0 $0 $11,173 $930 $0 $1,387 $13,490 $24

### Cost and Performance Baseline for Fossil Energy Plants

474 

## Exhibit 5

- 14 Case 13 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $92 $1,837 $0 $0 $1,929 $172 $0 $420 $2,520 $5 13.2 Site Improvements $0 $843 $1,047 $0 $0 $1,890 $167 $0 $411 $2,469 $4 13.3 Site Facilities $1,722 $0 $1,698 $0 $0 $3,419 $302 $0 $744 $4,465 $8 SUBTOTAL 13. $1,722 $935 $4,582 $0 $0 $7,238 $640 $0 $1,576 $9,455 $17 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1 14.2 Steam Turbine Building $0 $1,972 $2,626 $0 $0 $4,598 $378 $0 $746 $5,722 $10 14.3 Administration Building $0 $455 $308 $0 $0 $763 $61 $0 $124 $947 $2 14.4 Circulation Water Pumphouse $0 $152 $75 $0 $0 $227 $18 $0 $37 $281 $1 14.5 Water Treatment Buildings $0 $316 $288 $0 $0 $605 $49 $0 $98 $752 $1 14.6 Machine Shop $0 $394 $252 $0 $0 $647 $51 $0 $105 $803 $1 14.7 Warehouse $0 $255 $154 $0 $0 $408 $32 $0 $66 $507 $1 14.8 Other Buildings & Structures $0 $76 $56 $0 $0 $132 $11 $0 $21 $164 $0 14.9 Waste Treating Building & Str. $0 $298 $533 $0 $0 $831 $69 $0 $135 $1,036 $2 SUBTOTAL 14. $0 $4,155 $4,417 $0 $0 $8,571 $697 $0 $1,390 $10,658 $19

TOTAL COST $193,680 $20,581 $53,339 $0 $0 $267,599 $22,400 $0 $34,366 $324,365 $584
Owner's Costs Preproduction Costs 6 Months All Labor $2,880 $5 1 Month Maintenance Materials $388 $1 1 Month Non-fuel Consumables $146 $0 1 Month Waste Disposal $0 $0 25% of 1 Months Fuel Cost at 100% CF $4,509 $8 2% of TPC $6,487 $12 Total $14,410 $26 Inventory Capital 60 day supply of consumables at 100% CF $180 $0 0.5% of TPC (spare parts) $1,622 $3 Total $1,802 $3
Initial Cost for Catalyst and Chemicals $0 $0 Land $300 $1 Other Owner's Costs $48,655 $88

Financing Costs $8,758 $16 Total Overnight Costs (TOC) $398,290 $718 TASC Multiplier (IOU, low-risk, 33 year) 1.075 Total As-Spent Cost (TASC) $428,162 $771

### Cost and Performance Baseline for Fossil Energy Plants

475 

## Exhibit 5

- 15 Case 13 Initial and Annual Operating and Maintenance Cost Summary
INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 13 - 1x555 MWnet 2x1 7FB NGCC Heat Rate-net (Btu/kWh): 6,798 MWe-net: 555 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 1.0 1.0 Operator 2.0 2.0 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 5.0 5.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $1,972,971 $3.554 Maintenance Labor Cost $2,635,374 $4.748 Administrative & Support Labor $1,152,086 $2.076 Property Taxes and Insurance $6,487,309 $11.687 TOTAL FIXED OPERATING COSTS $12,247,740 $22.065 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $3,953,061 $0.00096

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0.00 1700.64 1.08 $0 $570,718 $0.00014

Chemicals

MU & WT Chem. (lbs) 0.00 10131.92 0.17 $0 $544,027 $0.00013 MEA Solvent (ton) 0.00 0.00 2249.89 $0 $0 $0.00000 Activated Carbon (lb) 0.00 0.00 1.05 $0 $0 $0.00000 Corrosion Inhibitor 0.00 0.00 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.07 5775.94 $0 $129,612 $0.00003 Ammonia (19% NH3) ton 0.00 6.06 129.80 $0 $244,142 $0.00006 Subtotal Chemicals $0 $917,781 $0.00022

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases, N2 etc.(/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Waste Disposal $0 $0 $0.00000
By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $0 $5,441,560 $0.00132

Fuel (MMBtu) 0 90,562 6.55 $0 $183,973,460 $0.04451

### Cost and Performance Baseline for Fossil Energy Plants

476 

## 5.2.7 The plant configuration for Case 14 is the same as Case 13 with the exceptio n that the Econamine CDR technology was added for CO 2 

## capture. The nominal net output decreases to 4 74 MW because, like the IGCC cases, the CT fixes the output and the CDR facility significantly increases the auxiliary power load and reduces the steam turbine output

. Case 14

– NGCC with CO 2 

## Capture

The process description for Case 14 is essentially the same as Case 13 with one notable exception , the addition of CO 2 

## capture. A BFD and stream tables for Case 14 are shown in Exhibit 5

- 16 and Exhibit 5

- 17 , respectively. Since the CDR facility process description was provided in Section 5.1.5 , it is not repeated here.
5.2.8 The Case 14 modeling assumptions were presented previously in Section Case 14 Performance Results 5.2.2

. The plant produces a net output of 4 74 MW at a net plant efficiency of 42.8 percent (HHV basis). Overall plant performance is summarized in Exhibit 5

- 18 , which includes auxiliary power requirements. The CDR facility, including CO 2 

## compression, accounts for over 6 6 percent of the auxiliary plant load. The CWS ( CWP s and cooling tower fan) acc ounts for nearly 18 percent of the auxiliary load, largely due to the high cooling water demand of the CDR facility.

### Cost and Performance Baseline for Fossil Energy Plants

477 

## Exhibit 5

- 16 Case 14 Block Flow Diagram, NGCC with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

478 

## Exhibit 5

- 17 Case 14 Stream Table, NGCC with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 V-L Mole Fraction

Ar 0.0092 0.0000 0.0089 0.0089 0.0098 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CH 4 0.0000 0.9310 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 2 H 6 0.0000 0.0320 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 3 H 8 0.0000 0.0070 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 C 4 H 10 0.0000 0.0040 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0003 0.0100 0.0404 0.0404 0.0045 0.9893 1.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0099 0.0000 0.0867 0.0867 0.0339 0.0107 0.0000 1.0000 1.0000 1.0000 1.0000 N 2 0.7732 0.0160 0.7432 0.7432 0.8187 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.2074 0.0000 0.1209 0.1209 0.1332 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 109,323 4,380 113,831 113,831 103,333 4,185 4,140 17,887 17,887 21,589 13,482 V-L Flowrate (kg/hr) 3,154,735 75,901 3,230,636 3,230,636 2,933,892 183,013 182,203 322,243 322,243 388,927 242,889 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 15 38 629 143 30 21 51 152 151 566 38 Pressure (MPa, abs) 0.10 3.10 0.11 0.10 0.10 0.16 15.27 0.51 0.49 16.65 0.01 Enthalpy (kJ/kg) A 30.23 46.30 835.81 288.61 83.96 26.65 -164.90 2,746.79 635.72 3,472.36 160.61 Density (kg/m 3 ) 1.2 22.2 0.4 0.8 1.1 2.9 653.5 2.7 915.8 47.7 992.9 V-L Molecular Weight 28.857 17.328 28.381 28.381 28.393 43.731 44.010 18.015 18.015 18.015 18.015
V-L Flowrate (lb mol /hr) 241,016 9,657 250,954 250,954 227,809 9,226 9,127 39,435 39,435 47,595 29,724 V-L Flowrate (lb/hr) 6,955,000 167,333 7,122,333 7,122,333 6,468,125 403,474 401,689 710,425 710,425 857,437 535,480 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 59 100 1,163 290 85 69 124 306 304 1,050 101 Pressure (psia) 14.7 450.0 15.2 14.7 14.7 23.5 2,214.7 73.5 71.0 2,414.7 1.0 Enthalpy (Btu/lb) A 13.0 19.9 359.3 124.1 36.1 11.5 -70.9 1,180.9 273.3 1,492.8 69.1 Density (lb/ft 3 ) 0.076 1.384 0.025 0.052 0.071 0.183 40.800 0.169 57.172 2.977 61.982 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

479 

## Exhibit 5

- 18 Case 14 Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) 

## Gas Turbine Power 362,200 Steam Turbine Power 148,800 TOTAL POWER, kWe 511,000 AUXILIARY LOAD SUMMARY, kWe Condensate Pumps 80 Boiler Feedwater Pumps 2,710 Amine System Auxiliaries 9,600 CO 2 

## Compression 15,200 Circulating Water Pump 4,360 Ground Water Pumps 360 Cooling Tower Fans 2,250 SCR 10 Gas Turbine Auxiliaries 700 Steam Turbine Auxiliaries 100 Miscellaneous Balance of Plant 1 

## 500 Transformer Losses 1,560 TOTAL AUXILIARIES, kWe 37,430 NET POWER, kWe 473,570 Net Plant Efficiency (HHV) 42.8% Net Plant Efficiency (LHV) 47.5% Ne t Plant Heat Rate (HHV), kJ/kWh (Btu/kWh ) 8,406 (7,968) Net Plant Heat Rate (LHV), kJ/kWh (Btu/kWh ) 7,579 (7,184) CONDENSER COOLING DUTY, 10 6 

## kJ/h r (10 6 

## Btu/h r ) 528 (500) CONSUMABLES Natural Gas Feed Flow, kg/hr (lb/hr) 75,901 (167,333) Thermal Input (HHV), kW th 

## 1,105,812 Thermal Input (LHV) , kW th 

## 997,032 Raw Water Withdrawal, m 3 

## /min (gpm) 15.1 (3,980) Raw Water Consumption, m 3 

## /min (gpm) 11.3 (2,985)

1. Includes plant control systems, lighting, HVAC , and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

480 

## The environmental targets for emissions of NOx, SO 2 

## , and PM were presented in Section 2.4. A summary of the plant air emissions for Case 14 is presented in Environmental Performance

Exhibit 5

- 19

. Exhibit 5

- 19 Case 14 Air Emissions

kg/GJ (lb/10 6 

## Btu) Tonne/year (ton/year) 85% CF kg/MWh (lb/MWh)
SO 2 

## Negligible Negligible Negligible NOx 0.004 (0.00 8 ) 105 ( 115 ) 0. 027 (0. 061 ) Particulates Negligible Negligible Negligible Hg Negligible Negligible Negligible CO 2 

## 5

. 1 (11

. 8) 150,743 (166,165) 40 (87) CO 2 1 

## 4 3 (94)

1 

### CO 2 

### emissions based on net power instead of gross power 

## The operation of the modern, state

- of

- the

- art GT fueled by natural gas, coupled to a HRSG, results in very low levels of NOx emissions and negligible levels of SO 2 

## , particulate , and Hg emissions. As not ed in Section 2.4, if the fuel contains the maximum amount of sulfur compounds allowed in pipeline natural gas, the NGCC SO 2 

## emissions would be 21 tonnes/yr (23 tons/yr) at 85 percent CF , or 0.00195 lb/MMBtu. The low level of NOx production (2.5 ppmvd at 1 5 percent O 2 

## ) is achieved by utilizing a dry LNB coupled with an SCR system. Ninety percent of the CO 2 

## in the FG is removed in CDR facility. The carbon balance for the plant is shown in Exhibit 5

- 20

. The carbon input to the plant consists of carbon in the natural gas in addition to carbon in the CT air. Carbon leaves the plant as CO 2 

## in the stack gas and the captured CO 2 

## product. The CO 2 

## capture efficiency is defined by the following fraction: (CO 2 

## Product Carbon)/(Natural Gas Carbon)*100 or ( 109,628 ) /( 120,863 ) * 100 or 90. 7 percent Exhibit 5

- 20 Case 14 Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/hr (lb/hr) Natural Gas 54,822 (120,863) Stack Gas 5,525 (12,181) Air (CO 2 

## ) 429 (946) CO 2 

## Product 49,726 (109,628) Total 55,251 (121,808) Total 55,251 (121,808)

### Cost and Performance Baseline for Fossil Energy Plants

481 

## A sulfur balance is not included for Case 14 because the sulfur concentration of natural gas is negligible. Consequently, sulfur emissions are also negligible, as shown in Exhibit 5

- 19 , despite the use of no sulfur control technology. Exhibit 5

- 21 s hows the overall water balance for the plant. The exhibit is presented in an identical manner as was for Case 13. Exhibit 5

- 21 Case 14 Water Balance

Water Use Water Demand,

m 3 

## /min (gpm) Internal Recycle, m 3 

## /min (gpm) Raw Water Withdrawal,
m 3 

## /min (gpm) Process Water Discharge,

m 3 

## /min (gpm) Raw Water Consumption,
m 3 

## /min (gpm)

Econamine 0.04 (12) 0.0 (0) 0.04 (12) 0.0 (0) 0. 0 4 (12) Condenser Makeup BFW Makeup 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23) 0.1 (23) 0.0 (0) 0.1 (23)

Cooling Tower BFW Blowdown Flue Gas Condensate 17.0 (4,477) 2.0 (520) 0.1 (23) 1.9 (497) 15.0 (3,958)

- 0.1 (

- 23)

- 1.9 (

- 497) 3.8 (1,007) 11.2 (2,951)

CO 2 

## Product Condensate 0. 0 3 (8)

- 0. 0 3 (

- 8)

Total 17.1 (4,5 12 ) 2.0 (52 8 ) 15.1 (3,9 92 ) 3.8 (1,007) 11.3 (2,985)

A heat and mass balance diagram is shown for the NGCC in Heat and Mass Balance Diagrams Exhibit 5

- 22

. An overall plant energy balance is provided in tabular form in Exhibit 5

- 23

. The power out is the combined CT and steam turbine power prior to generator losses. The power at the generator terminals (shown in Exhibit 5

- 18 ) is calculated by multiplying the power out by a combined generator efficiency of 98.3 percent. The Econamine process heat out stream represents heat rejected to cooling water and ultimately to ambient vi a the cooling tower. The same is true of the condenser heat out stream. The CO 2 

## compressor intercooler load is included in the Econamine process heat out stream.

### Cost and Performance Baseline for Fossil Energy Plants

482 

## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

483 

## Exhibit 5

- 22 Case 14 Heat and Mass Balance, NGCC with CO 2 

## Capture

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

H EAT AND M ATERIAL F LOW D IAGRAM 

### P LANT 

### P ERFORMANCE 

### S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Nitrogen Natural Gas

Carbon Dioxide

Water Steam

P AGES 1 OF 1 N ATURAL GAS COMBINED CYCLE PLANT C ASE 14 2 X ADVANCED F
- CLASS GT 2400 / 1050 / 1050

DWG

. NO

. BB

- HMB

- CS

- 14

- PG

- 1 Flue Gas

401 , 689 W

123

. 8 T 2 , 214

. 7 P

CO 2 PRODUCT

A MBIENT

A IR 1 6 , 955 , 000 W 59

. 0 T 14

. 7 P 12

. 9 H CO 2 COMPRESSION ( INTERSTAGE COOLING ) & DRYING 403 , 474 W

69

. 0 T 23

. 5 P 11

. 5 H KNOCKOUT

WATER 248 , 601 W

85

. 1 T 14

. 7 P 8

. 6 H Gross Plant Power : 511 MWe Auxiliary Load : 37 MWe Net Plant Power : 474 MWe Net Plant Efficiency , HHV : 42

. 8 % Net Plant Heat Rate : 7 , 968 BTU / KWe A DVANCED F C LASS G AS T URBINES

COMBUSTOR N ATURAL GAS 167 , 333 W

100

. 0 T 450

. 0 P 19

. 9 H 2

6 , 468 , 125 W 85

. 1 T 14

. 7 P 36

. 0 H 7 , 122 , 333 W 289

. 7 T 14

. 7 P 124

. 0 H

7 , 122 , 333 W

1 , 163

. 5 T

15

. 2 P 359

. 3 H GENERATOR

CONDENSATE PUMPS8,801W1,302W

101

. 3 T 130

. 0 P 69

. 5 H 535 , 480 W

101

. 1 T

1

. 0 P 69

. 1 H

5 1 , 400 W 581

. 0 T 75

. 0 P 1 , 321

. 3 H 1 , 017 , 200 W 641

. 4 T 75

. 0 P 1 , 351

. 1 H 512 , 174 W 622

. 2 T 75

. 0 P 1 , 341

. 7 H

512 , 174 W 101

. 1 T

1

. 0 P 1 , 029

. 8 H

HOT WELL CONDENSER

S TACK 4REBOILER CONDENSATE

CONDENSATE PUMPS S TEAM T URBINE MAKEUP 11 , 337 W

59

. 0 T 14

. 7 P 27

. 1 H

AIR INLET

FILTER 3

HP PUMP 535 , 480 W

253

. 0 T 100

. 0 P 221

. 9 HBLOWDOWN

94 , 141 W

300

. 1 T 95

. 0 P 269

. 4 H 173 , 467 W

300

. 7 T 400

. 0 P 270

. 7 H 866 , 098 W

305

. 3 T 2 , 540

. 0 P 279

. 3 H11,337WSTRIPPERABSORBER FLUE GAS ACID GAS

ECONAMINE FG + BLOWER

598 , 226 W 641

. 4 T 75

. 0 P 1 , 351

. 1 H WATER 1 , 785 W 100

. 0 T 14

. 7 P GLAND SEAL CONDENSER 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H LP TURBINE

S TEAM TO REBOILER

710 , 425 W

306

. 2 T 73

. 5 P 1 , 180

. 9 H 9 , 569 W

535 , 480 W

106

. 8 T 120

. 0 P 75

. 0 H

Three Pressure Heat Recovery Steam Generator ( HRSG ) 829 , 777 W 1 , 055

. 0 T 360

. 0 P 1 , 553

. 4 H

A A 171 , 732 W 1 , 055

. 0 T 360

. 0 P 1 , 553

. 4 HHOT REHEAT

C OLD R EHEAT

829 , 777 W

587

. 9 T 390

. 0 P 1 , 300

. 6 H STEAM SEAL REGULATOR

93 , 200 W

537

. 0 T 80

. 0 P 1 , 299

. 1 H 16 , 993 W

970

. 1 T 1 , 850

. 0 P 1 , 459

. 8 H HP TURBINE IP TURBINE852,917W 2 , 654 W 1 , 050

. 0 T 2 , 414

. 7 P 1 , 492

. 8 H1,018,502WMAIN STEAM

857 , 437 W 1 , 050

. 0 T 2 , 414

. 7 P 1 , 492

. 8 H

6

7

8

9 10

10 , 969 W866W IP STEAM

598 , 226 W 303

. 9 T 73

. 5 P 273

. 3 H

IP PUMP

LP PUMP 710 , 425 W 303

. 9 T 71

. 0 P 273

. 3 H DOE / NETL
SC PC P LANT C ASE 14 11

### Cost and Performance Baseline for Fossil Energy Plants

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## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

485 

## Exhibit 5

- 23 Case 14 Overall Energy Balance (0°C [32°F] Reference)

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Natural Gas 3,981 (3,773) 2.7 (2.5) 3,984 (3,776) GT Air 95.4 (90.4) 95 (90) Raw Water Withdrawal 56.7 (53.7) 57 (54) Auxiliary Power 0.0 (0.0) 135 (128) 135 (128) Totals 3,981 (3,773) 154.7 (146.6) 135 (128) 4,270 (4,048) Heat Out GJ/hr (MMBtu/hr) CO 2 

## - 30.0 (

- 28.5)

- 30 (

- 28) Cooling Tower Blowdown 28.3 (26.8) 28 (27) Econamine Losses 1,010 (957) 1,010 (957) CO 2 

## Compression Intercooling 84.9 (80.5) 85 (81) Stack Gas 246 (233) 246 (233) Condenser 532 (504) 532 (504) Process Losses* 560 (530) 560 (530) Power 1,840 (1,744) 1,840 (1,744) Totals 0 (0) 2,431 (2,304) 1,840 (1,744) 4,270 (4,048) * Process Losses are calculated by difference and reflect various boiler, turbine, and other

heat and work losses. Aspen flowsheet balance is within 0.5 percent.

### Cost and Performance Baseline for Fossil Energy Plants

486 

## 5.2.9 Major equipment items for the NGCC plant with CO 2 

## capture are shown in the following tables. The accounts used in the equipment list correspond to the account numbers used in the cost estimates in Section Case 14 Major Equipment List

5.2.10 . In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

ACCOUNT 1 COAL AND SORBENT HAN DLING N/A

ACCOUNT 2 FUEL AND SORBENT PRE PARATION AND FEED

Equipment No. Description Type Operating Qty. Spares

1 Gas Pipeline Underground, coated carbon steel, wrapped cathodic protection 16 km (10 mile) 0

2 Gas Metering Station

-- 1 0 Design Condition

63 m3/min @ 3.1 MPa (2,216 acfm @ 450 psia) 41 cm (16 in) standard wall pipe

63 m3/min (2,216 acfm)

### Cost and Performance Baseline for Fossil Energy Plants

487 

## ACCOUNT 3 FEEDWATER AND MISCEL LANEOUS SYSTEMS AND EQUIPMENT Equipment No. Description Type Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 2 0

2 Condensate Pumps Vertical canned 2 1

4 Auxiliary Boiler Shop fabricated, water tube 1 0

5 Service Air Compressors Flooded Screw 2 1

6 Instrument Air Dryers Duplex, regenerative 2 1

7 Closed Cycle Cooling Heat Exchangers Plate and frame 2 0

8 Closed Cycle Cooling Water Pumps Horizontal centrifugal 2 1

9 Engine-Driven Fire Pump Vertical turbine, diesel engine 1 1

10 Fire Service Booster Pump Two-stage horizontal centrifugal 1 1

11 Raw Water Pumps Stainless steel, single suction 2 1

12 Filtered Water Pumps Stainless steel, single suction 2 1

13 Filtered Water Tank Vertical, cylindrical 1 0

14 Makeup Water Demineralizer Multi-media filter, cartridge filter, RO membrane assembly and electro-deionization unit 1 0

15 Liquid Waste Treatment System 1 0 1

143,847 liter (38,000 gal)

341 lpm (90 gpm)

10 years, 24-hour storm 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O)

2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 8,328 lpm @ 18 m H2O (2,200 gpm @ 60 ft H2O)

151 lpm @ 49 m H2O (40 gpm @ 160 ft H2O)

13 m3/min (450 scfm) 2 HP water: 3,634 lpm @ 2,103 m H2O (960 gpm @ 6,900 ft H2O) IP water: 719 lpm @ 283 m H2O (190 gpm @ 930 ft H2O)

18,144 kg/h, 2.8 MPa, 343°C (40,000 lb/h, 400 psig, 650°F) 13 m3/min @ 0.7 MPa (450 scfm @ 100 psig) LP water: 379 lpm @ 24.4 m H2O (100 gpm @ 80 ft H2O) 3 Boiler Feedwater Pump Horizontal, split case, multi-stage, centrifugal, with interstage bleed for IP and LP feedwater Design Condition
677,594 liters (179,000 gal) 2,233 lpm @ 110 m H2O (590 gpm @ 360 ft H2O)

13 MMkJ/hr (13 MMBtu/hr)

5,300 lpm @ 21 m H2O (1,400 gpm @ 70 ft H2O)

### Cost and Performance Baseline for Fossil Energy Plants

488 

## ACCOUNT 4 GASIFIER, BOILER AND ACCESSORIES N/A

ACCOUNT 5B CARBON DIOXIDE RECOV ERY

ACCOUNT 6 COMBUSTION TURBINE G ENERATORS AND AUXILI ARIES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Econamine FG Plus Amine-based CO2 capture technology 1,776,723 kg/hr (3,917,000 lb/hr) 6.3 wt % CO2 concentration 2 0

2 CO2 Compressor Integrally geared, multi 100,244 kg/hr @ 15.3 MPa (221,000 lb/hr @ 2,215 psia) 2 0

Equipment No. Description Type Operating Qty. Spares

1 Gas Turbine Advanced F class w/ dry low-NOx burner 2 0

2 Gas Turbine Generator TEWAC 2 0 Design Condition

180 MW
200 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase

### Cost and Performance Baseline for Fossil Energy Plants

489 

## ACCOUNT 7 WASTE HEAT BOILER, D UCTING, AND STACK

Equipment No. Description Type Operating Qty. Spares

1 Stack CS plate, type 409SS liner 2 0

3 SCR Reactor Space for spare layer 2 0

4 SCR Catalyst

-- 1 layer 0

5 Dilution Air Blowers Centrifugal 2 1

6 Ammonia Feed Pump Centrifugal 2 1

7 Ammonia Storage Tank Horizontal tank 1 0 2 0 2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Reheat steam - 249,852 kg/h, 2.4 MPa/566°C (550,830 lb/h, 345 psig/1,050°F) Design Condition
46 m (150 ft) high x 6.4 m (21 ft) diameter Main steam - 213,910 kg/h, 16.5 MPa/566°C (471,590 lb/h, 2,400 psig/1,050°F)

1,614,791 kg/h (3,560,000 lb/h) Space available for an additional catalyst layer 11 m3/min @ 107 cm WG (390 scfm @ 42 in WG)

3.8 lpm @ 91 m H2O (1 gpm @ 300 ft H2O)
68,138 liter (18,000 gal)

### Cost and Performance Baseline for Fossil Energy Plants

490 

## ACCO UNT 8 STEAM TURBINE GENERA TOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

ACCOUNT 10 ASH/SPENT SORBENT RE COVERY AND HANDLING N/A Equipment No. Description Type Operating Qty. Spares

1 Steam Turbine Tandem compound,HP, IP, and twoflow LP turbines 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitation 1 0

3 Steam Bypass One per HRSG 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1 0 Design Condition
157 MW 16.5 MPa/566°C/566°C (2,400 psig/ 1050°F/1050°F)

580 MMkJ/hr, (550 MMBtu/hr), Inlet water temperature 16°C (60°F),

Water temperature rise 11°C (20°F) 170 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase
50% steam flow @ design steam conditions

Equipment No. Description Type Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 1 0 Design Condition 435,326 lpm @ 30.5 m (115,000 gpm @ 100 ft) 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

613 MMkJ/hr (582 MMBtu/hr) heat load

### Cost and Performance Baseline for Fossil Energy Plants

491 

## ACCOUNT 11 ACCESSORY ELECTRIC P LANT

ACCOUNT 12 INSTRUMENTATION AND CONTROL

Equipment No. Description Type Operating Qty. Spares

1 CTG Transformer Oil-filled 2 0

2 STG Transformer Oil-filled 1 0

3 High Voltage Auxiliary Transformer Oil-filled 2 0

4 Medium Voltage Transformer Oil-filled 1 1

5 Low Voltage Transformer Dry ventilated 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 1 0

8 Medium Voltage Switchgear Metal clad 1 1

9 Low Voltage Switchgear Metal enclosed 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 1 0 Design Condition 24 kV/345 kV, 200 MVA, 3-ph, 60 Hz

345 kV/13.8 kV, 8 MVA, 3-ph, 60 Hz 24 kV/345 kV, 150 MVA, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

24 kV, 3-ph, 60 Hz

4.16 kV, 3-ph, 60 Hz

480 V, 3-ph, 60 Hz 4.16 kV/480 V, 3 MVA, 3-ph, 60 Hz

750 kW, 480 V, 3-ph, 60 Hz

24 kV/4.16 kV, 23 MVA, 3-ph, 60 Hz

Equipment No. Description Type Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) 1 0

3 DCS - Data Highway Fiber optic 1 0 1 0

Fully redundant, 25% spare Design Condition

Operator stations/printers and

engineering stations/printers

2 DCS - Processor Microprocessor with redundant input/output N/A

### Cost and Performance Baseline for Fossil Energy Plants

492 

## 5.2.10 The cost estimating methodology was described previously in Section Case 14

– Cost Estimating 2.7

. Exhibit 5

- 24 shows the total plant capital cost summary organized by cost account and Exhibit 5

- 25 shows a more detailed breakdown of the capital costs. Exhibit 5

- 26 shows the initial and annual O&M costs. The estimated TO C of the NGCC with CO 2 

## capture is $1, 497 /kW. Process contingency represents 4.0 percent of the TO C and project contingency represents 10.8 percent. The COE, including CO 2 

## TS&M costs of 3 .2 mills/kWh, is 85 .9 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

493 

## Exhibit 5

- 24 Case 14 Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 14 - 1x475 MWnet 2x1 7FB NGCC w/ CO2 Capture Plant Size: 473.6 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

2 COAL & SORBENT PREP & FEED $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

3 FEEDWATER & MISC. BOP SYSTEMS $23,934 $4,864 $7,962 $0 $0 $36,760 $3,106 $0 $6,447 $46,312 $98

4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Other gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5A GAS CLEANUP & PIPING $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

5B CO2 REMOVAL & COMPRESSION $121,638 $0 $37,053 $0 $0 $158,691 $13,593 $27,994 $40,056 $240,334 $507

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $202 6.2-6.9 Combustion Turbine Other $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6 $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $206

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $94 7.2-7.9 SCR System, Ductwork and Stack $1,243 $950 $1,118 $0 $0 $3,311 $282 $0 $583 $4,176 $9 SUBTOTAL 7 $34,201 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $103

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $19,229 $0 $3,465 $0 $0 $22,694 $1,951 $0 $2,465 $27,110 $57 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $6,570 $637 $4,691 $0 $0 $11,898 $958 $0 $1,824 $14,680 $31 SUBTOTAL 8 $25,799 $637 $8,156 $0 $0 $34,592 $2,909 $0 $4,289 $41,791 $88

9 COOLING WATER SYSTEM $8,569 $6,296 $5,689 $0 $0 $20,554 $1,708 $0 $3,140 $25,403 $54

10 ASH/SPENT SORBENT HANDLING SYS $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

11 ACCESSORY ELECTRIC PLANT $20,769 $5,564 $12,124 $0 $0 $38,458 $2,957 $0 $4,473 $45,888 $97

12 INSTRUMENTATION & CONTROL $6,272 $644 $5,211 $0 $0 $12,127 $1,010 $606 $1,575 $15,318 $32

13 IMPROVEMENTS TO SITE $1,724 $936 $4,588 $0 $0 $7,248 $641 $0 $1,578 $9,467 $20

14 BUILDINGS & STRUCTURES $0 $3,982 $4,121 $0 $0 $8,103 $658 $0 $1,314 $10,075 $21

TOTAL COST $318,200 $24,594 $95,849 $0 $0 $438,642 $36,957 $28,600 $76,502 $580,701 $1,226 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

494 

## Exhibit 5

- 25 Case 14 Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.2 Coal Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.3 Coal Conveyors & Yd Crush $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.4 Other Coal Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 1. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.3 Slurry Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 2. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $2,426 $2,499 $2,055 $0 $0 $6,980 $576 $0 $1,133 $8,690 $18 3.2 Water Makeup & Pretreating $2,123 $222 $1,109 $0 $0 $3,453 $294 $0 $750 $4,497 $9 3.3 Other Feedwater Subsystems $1,106 $374 $314 $0 $0 $1,794 $144 $0 $291 $2,229 $5 3.4 Service Water Systems $251 $517 $1,676 $0 $0 $2,444 $213 $0 $531 $3,188 $7 3.5 Other Boiler Plant Systems $1,683 $652 $1,511 $0 $0 $3,846 $326 $0 $626 $4,798 $10 3.6 Natural Gas, incl. pipeline $14,652 $476 $415 $0 $0 $15,543 $1,317 $0 $2,529 $19,389 $41 3.7 Waste Treatment Equipment $766 $0 $437 $0 $0 $1,203 $105 $0 $262 $1,569 $3 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $927 $124 $445 $0 $0 $1,496 $129 $0 $325 $1,951 $4 SUBTOTAL 3. $23,934 $4,864 $7,962 $0 $0 $36,760 $3,106 $0 $6,447 $46,312 $98 4 GASIFIER & ACCESSORIES 4.1 Gasifier, Syngas Cooler & Auxiliaries $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.2 Syngas Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 LT Heat Recovery & FG Saturation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Misc. Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Other Gasification Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

### Cost and Performance Baseline for Fossil Energy Plants

495 

## Exhibit 5

- 25 Case 14 Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 MDEA-LT AGR $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.2 Elemental Sulfur Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.3 Mercury Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.4 COS Hydrolysis $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.5 Blowback Gas Systems $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Fuel Gas Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.9 HGCU Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B CO2 REMOVAL & COMPRESSION 5B.1 CO2 Removal System $107,387 $0 $32,583 $0 $0 $139,970 $11,989 $27,994 $35,991 $215,943 $456 5B.2 CO2 Compression & Drying $14,251 $0 $4,471 $0 $0 $18,721 $1,604 $0 $4,065 $24,390 $52 SUBTOTAL 5. $121,638 $0 $37,053 $0 $0 $158,691 $13,593 $27,994 $40,056 $240,334 $507 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $75,294 $0 $4,804 $0 $0 $80,098 $6,800 $0 $8,690 $95,589 $202 6.2 Combustion Turbine Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $719 $744 $0 $0 $1,462 $122 $0 $317 $1,901 $4 SUBTOTAL 6. $75,294 $719 $5,548 $0 $0 $81,561 $6,922 $0 $9,007 $97,490 $206 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $32,958 $0 $4,279 $0 $0 $37,237 $3,170 $0 $4,041 $44,448 $94 7.2 SCR System $1,243 $522 $733 $0 $0 $2,498 $215 $0 $407 $3,120 $7 7.3 Ductwork $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.4 Stack $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.9 HRSG,Duct & Stack Foundations $0 $428 $385 $0 $0 $813 $68 $0 $176 $1,057 $2 SUBTOTAL 7. $34,201 $950 $5,397 $0 $0 $40,548 $3,453 $0 $4,624 $48,624 $103 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $19,229 $0 $3,465 $0 $0 $22,694 $1,951 $0 $2,465 $27,110 $57 8.2 Turbine Plant Auxiliaries $141 $0 $317 $0 $0 $458 $40 $0 $50 $548 $1 8.3 Condenser & Auxiliaries $2,393 $0 $714 $0 $0 $3,107 $266 $0 $337 $3,711 $8 8.4 Steam Piping $4,035 $0 $2,653 $0 $0 $6,688 $513 $0 $1,080 $8,281 $17 8.9 TG Foundations $0 $637 $1,007 $0 $0 $1,644 $139 $0 $357 $2,140 $5 SUBTOTAL 8. $25,799 $637 $8,156 $0 $0 $34,592 $2,909 $0 $4,289 $41,791 $88 9 COOLING WATER SYSTEM 9.1 Cooling Towers $6,077 $0 $777 $0 $0 $6,854 $584 $0 $744 $8,182 $17 9.2 Circulating Water Pumps $1,780 $0 $106 $0 $0 $1,887 $142 $0 $203 $2,232 $5 9.3 Circ.Water System Auxiliaries $136 $0 $18 $0 $0 $154 $13 $0 $17 $184 $0 9.4 Circ.Water Piping $0 $3,968 $962 $0 $0 $4,930 $399 $0 $799 $6,128 $13 9.5 Make-up Water System $313 $0 $418 $0 $0 $730 $63 $0 $119 $912 $2 9.6 Component Cooling Water Sys $264 $315 $210 $0 $0 $788 $66 $0 $128 $983 $2 9.9 Circ.Water System Foundations $0 $2,013 $3,198 $0 $0 $5,211 $442 $0 $1,130 $6,783 $14 SUBTOTAL 9. $8,569 $6,296 $5,689 $0 $0 $20,554 $1,708 $0 $3,140 $25,403 $54

### Cost and Performance Baseline for Fossil Energy Plants

496 

## Exhibit 5

- 25 Case 14 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.2 Gasifier Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.7 Ash Transport & Feed Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 10. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $5,372 $0 $3,228 $0 $0 $8,600 $728 $0 $700 $10,028 $21 11.2 Station Service Equipment $1,980 $0 $167 $0 $0 $2,147 $177 $0 $174 $2,498 $5 11.3 Switchgear & Motor Control $2,440 $0 $415 $0 $0 $2,855 $237 $0 $309 $3,402 $7 11.4 Conduit & Cable Tray $0 $1,166 $3,595 $0 $0 $4,761 $412 $0 $776 $5,949 $13 11.5 Wire & Cable $0 $3,713 $2,280 $0 $0 $5,993 $386 $0 $957 $7,337 $15 11.6 Protective Equipment $0 $563 $1,916 $0 $0 $2,480 $217 $0 $270 $2,966 $6 11.7 Standby Equipment $98 $0 $90 $0 $0 $188 $16 $0 $20 $224 $0 11.8 Main Power Transformers $10,878 $0 $136 $0 $0 $11,014 $747 $0 $1,176 $12,937 $27 11.9 Electrical Foundations $0 $121 $298 $0 $0 $419 $36 $0 $91 $546 $1 SUBTOTAL 11. $20,769 $5,564 $12,124 $0 $0 $38,458 $2,957 $0 $4,473 $45,888 $97 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $797 $0 $498 $0 $0 $1,295 $110 $65 $220 $1,690 $4 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $238 $0 $143 $0 $0 $381 $32 $19 $65 $497 $1 12.7 Computer & Accessories $3,814 $0 $114 $0 $0 $3,928 $323 $196 $445 $4,892 $10 12.8 Instrument Wiring & Tubing $0 $644 $1,230 $0 $0 $1,874 $141 $94 $316 $2,426 $5 12.9 Other I & C Equipment $1,422 $0 $3,226 $0 $0 $4,648 $404 $232 $528 $5,813 $12 SUBTOTAL 12. $6,272 $644 $5,211 $0 $0 $12,127 $1,010 $606 $1,575 $15,318 $32

### Cost and Performance Baseline for Fossil Energy Plants

497 

## Exhibit 5

- 25 Case 14 Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $92 $1,839 $0 $0 $1,931 $172 $0 $421 $2,524 $5 13.2 Site Improvements $0 $844 $1,049 $0 $0 $1,893 $167 $0 $412 $2,472 $5 13.3 Site Facilities $1,724 $0 $1,700 $0 $0 $3,424 $302 $0 $745 $4,471 $9 SUBTOTAL 13. $1,724 $936 $4,588 $0 $0 $7,248 $641 $0 $1,578 $9,467 $20 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $236 $125 $0 $0 $361 $28 $0 $58 $447 $1 14.2 Steam Turbine Building $0 $1,639 $2,183 $0 $0 $3,822 $314 $0 $620 $4,756 $10 14.3 Administration Building $0 $462 $313 $0 $0 $775 $62 $0 $125 $962 $2 14.4 Circulation Water Pumphouse $0 $147 $73 $0 $0 $220 $17 $0 $36 $272 $1 14.5 Water Treatment Buildings $0 $458 $418 $0 $0 $876 $71 $0 $142 $1,089 $2 14.6 Machine Shop $0 $401 $256 $0 $0 $657 $52 $0 $106 $815 $2 14.7 Warehouse $0 $259 $156 $0 $0 $415 $33 $0 $67 $515 $1 14.8 Other Buildings & Structures $0 $77 $56 $0 $0 $134 $11 $0 $22 $166 $0 14.9 Waste Treating Building & Str. $0 $303 $541 $0 $0 $845 $70 $0 $137 $1,052 $2 SUBTOTAL 14. $0 $3,982 $4,121 $0 $0 $8,103 $658 $0 $1,314 $10,075 $21

TOTAL COST $318,200 $24,594 $95,849 $0 $0 $438,642 $36,957 $28,600 $76,502 $580,701 $1,226
Owner's Costs Preproduction Costs 6 Months All Labor $4,163 $9 1 Month Maintenance Materials $612 $1 1 Month Non-fuel Consumables $273 $1 1 Month Waste Disposal $0 $0 25% of 1 Months Fuel Cost at 100% CF $4,509 $10 2% of TPC $11,614 $25 Total $21,170 $45 Inventory Capital 60 day supply of consumables at 100% CF $357 $1 0.5% of TPC (spare parts) $2,904 $6 Total $3,260 $7
Initial Cost for Catalyst and Chemicals $823 $2 Land $300 $1 Other Owner's Costs $87,105 $184

Financing Costs $15,679 $33 Total Overnight Costs (TOC) $709,039 $1,497 TASC Multiplier (IOU, high-risk, 33 year) 1.078 Total As-Spent Cost (TASC) $764,344 $1,614

### Cost and Performance Baseline for Fossil Energy Plants

498 

## Exhibit 5

- 26 Case 14 Initial and Annual Operating and Maintenance Cost Summary

INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 14 - 1x475 MWnet 2x1 7FB NGCC w/ CO2 Capture Heat Rate-net (Btu/kWh): 7,968 MWe-net: 474 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 1.0 1.0 Operator 3.3 3.3 Foreman 1.0 1.0 Lab Tech's, etc. 1.0 1.0 TOTAL-O.J.'s 6.3 6.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $2,497,781 $5.274 Maintenance Labor Cost $4,162,295 $8.789 Administrative & Support Labor $1,665,019 $3.516 Property Taxes and Insurance $11,614,024 $24.524 TOTAL FIXED OPERATING COSTS $19,939,120 $42.104 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $6,243,443 $0.00177

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0.00 2,865.60 1.08 $0 $961,666 $0.00027

Chemicals

MU & WT Chem.(lbs) 0.00 17,072.41 0.17 $0 $916,693 $0.00026 MEA Solvent (ton) 344.71 0.48 2,249.89 $775,561 $337,908 $0.00010 Activated Carbon (lb) 0.00 578.27 1.05 $0 $188,408 $0.00005 Corrosion Inhibitor 0.00 0.00 0.00 $47,225 $2,249 $0.00000 SCR Catalyst (m3) w/equip. 0.07 5,775.94 $0 $129,612 $0.00004 Ammonia (19% NH3) (ton) 0.00 6.06 129.80 $0 $244,142 $0.00007 Subtotal Chemicals $822,786 $1,819,011 $0.00052

Other

Supplemental Fuel (MBtu) 0.00 0.00 0.00 $0 $0 $0.00000 Gases,N2 etc. (/100scf) 0.00 0.00 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Other $0 $0 $0.00000
Waste Disposal

Flyash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Bottom Ash (ton) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal Waste Disposal $0 $0 $0.00000
By-products

Sulfur (tons) 0.00 0.00 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000

TOTAL VARIABLE OPERATING COSTS $822,786 $9,024,121 $0.00256

Fuel (MMBtu) 0 90,562 6.55 $0 $183,972,091 $0.05217

### Cost and Performance Baseline for Fossil Energy Plants

499 

## 5.3 NGCC CASE SUMMARY The performance results of the two NGC C plant configurations modeled in this study are summarized in Exhibit 5

- 27

. Exhibit 5

- 27 Estimated Performance and Cost Results for NGCC Cases

1 

### Capacity f actor is 85% for all NGCC cases 2 

### COE and LCOE are defined in Section 2.7

. PERFORMANCE Case 13 Case 14 CO2 Capture 0% 90% Gross Power Output (kWe) 564,700 511,000 Auxiliary Power Requirement (kWe) 9,620 37,430 Net Power Output (kWe) 555,080 473,570 Coal Flowrate (lb/hr) N/A N/A Natural Gas Flowrate (lb/hr) 167,333 167,333 HHV Thermal Input (kWth) 1,105,812 1,105,812 Net Plant HHV Efficiency (%) 50.2% 42.8% Net Plant HHV Heat Rate (Btu/kWh) 6,798 7,968 Raw Water Withdrawal (gpm/MW net ) 4.3 8.4 Process Water Discharge (gpm/MW net ) 1.0 2.1 Raw Water Consumption (gpm/MW net ) 3.3 6.3 CO 2 Emissions (lb/MMBtu) 118 12 CO 2 Emissions (lb/MWh gross ) 790 87 CO 2 Emissions (lb/MWh net ) 804 94 SO 2 Emissions (lb/MMBtu) Negligible Negligible SO 2 Emissions (lb/MWh gross ) Negligible Negligible NOx Emissions (lb/MMBtu) 0.009 0.008 NOx Emissions (lb/MWh gross ) 0.060 0.061 PM Emissions (lb/MMBtu) Negligible Negligible PM Emissions (lb/MWh gross ) Negligible Negligible Hg Emissions (lb/TBtu) Negligible Negligible Hg Emissions (lb/MWh gross ) Negligible Negligible COST Total Plant Cost (2007$/kW) 584 1,226 Total Overnight Cost (2007$/kW) 718 1,497 **Bare Erected Cost** 482 926 **Home Office Expenses** 40 78 **Project Contingency** 62 162 **Process Contingency** 0 60 **Owner's Costs** 133 271 Total Overnight Cost (2007$ x 1,000) 398,290 709,039 Total As Spent Capital (2007$/kW) 771 1,614 COE (mills/kWh, 2007$) 1,2 58.9 85.9 **CO2 TS&M Costs** 0.0 3.2 **Fuel Costs** 44.5 52.2 **Variable Costs** 1.3 2.6 **Fixed Costs** 3.0 5.7 **Capital Costs** 10.1 22.3 LCOE (mills/kWh, 2007$) 1,2 74.7 108.9 NGCC Advanced F Class

### Cost and Performance Baseline for Fossil Energy Plants

500 

## The components of TOC and overall TASC are shown for the two NGCC cases in Exhibit 5

- 28

. The TOC of the non

- capture case, $ 718 /kW, is the lowest of all technologies studied by at least 5 0 percent. Addition of CO 2 

## capture more than doubles the TOC cost, but NGCC with capture is still the least c apital intensive of all the capture technologies by at least 5 5 percent. The process contingency included for the Econamine process totals $ 59 /kW, which repr esents approximately 4 percent of the TO C. The COE for NGCC cases is heavily dependent on the price of natural gas as shown in Exhibit 5

- 29 . The fuel component of COE represents 7 6 percent of the total in the non - capture case and 61 percent of the total in the CO 2 

## capture case. Because COE has a small capital component, it is less sensitive to CF than the more capital intensive PC and IGCC cases. The decrease in net kilowatt

- hours (kWh) produced is nearly of fset by a corresponding decrease in fuel cost. The CO 2 

## TS&M component of COE is only 4 percent of the total in the CO 2 

## capture case. Exhibit 5

- 28 Plant Capital Cost for NGCC Cases

718 1,497

771 1,614

0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

TOC TASC TOC TASC

NGCC NGCC w/ CO2 CaptureTOC or TASC, $/kW (2007$) TASC Owner's Cost Process Contingency Project Contingency Home Office Expense Bare Erected Cost

### Cost and Performance Baseline for Fossil Energy Plants

501 

## Exhibit 5

- 29 COE of NGCC Cases

The sensitivity of NGCC to CF is shown in Exhibit 5

- 30 . Unlike the PC and IGCC case, NGCC is relatively insensitive to CF but highly sensitive to fuel cost as shown in Exhibit 5

- 31 . A 33 percent increase in natural gas price (from $6 to $8/MMBtu) results in a COE increase of 25 percent in the non

- capture case and 20 percent in the CO 2 

## capture case. Because of the higher capital cost in the CO 2 

## capture case, the impact of fuel price changes is slightly diminished. As presented in Section 2.4 the first year cost of CO 2 

## avoided cost was calculated . In the NGCC capture case the cost of CO 2 

## avoided using NGCC without CO 2 

## capture as the reference is $69.5/tonne ( $ 6 3 /ton )

. The high cost relative to PC and IGCC technologies is mainly due to the much smaller amount of CO 2 

## generated by NGCC and therefore captured in the Econamine process. The cost of CO 2 

## avoided is $35.3/tonne ( $ 3 2 /ton ) when using SC PC without capture as the reference. This is due to the smaller difference in COE and larger difference in CO 2 

## emissions be tween the SC PC non - capture and NGCC capture cases

. 10.1 22.3 3.0 5.7
1.3 2.6 44.5 52.2 3.2

0 20 40 60 80 100 120 140 160

NGCC NGCC w/ CO2 CaptureCOE, mills/kWh (2007$) CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs

### Cost and Performance Baseline for Fossil Energy Plants

502 

## Exhibit 5

- 30 Sensitivity of COE to Capacity Factor in NGCC Cases

Exhibit 5

- 31 Sensitivity of COE to Fu el Price in NGCC Cases 0 20 40 60 80 100 120 140 160

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

Capacity Factor, % NGCC w/CO2 Capture

NGCC No Capture Natural gas price = $6.55/MMBtu

0 20 40 60 80 100 120 140

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

Natural Gas Price, $/MMBtu NGCC No Capture
NGCC w/CO2 Capture

Capacity factor = 85%

### Cost and Performance Baseline for Fossil Energy Plants

503 

## The following observations can be made regarding plant performance with reference to Exhibit 5

- 27 :

**•** The efficiency of the NGCC case with no CO 2 

## capture is 50.2 percent (HHV basis). Gas Turbine World provides estimated performance for an advanced F class turbine operated on natural gas in a combined cycle mode, and the reported efficien cy is 57.5 percent (LHV basis) [ 79

**•** The efficiency penalty to add CO 2 

## capture in the NGCC case is 14

. 7 relative percent. The efficiency reduction is caused primarily by the auxiliary loads of the Econami ne system and CO 2 

## compression as well as the significantly increased cooling water requirement, which increases the auxiliary load of the CWP s and the cooling tower fan. CO 2 

## capture results in a 28 MW increase in auxiliary load compared to the non

capture case. ]

. Adjusti ng the result from this study to an LHV basis results in an efficiency of 55.7 percent.

**•** The energy penal ty for NGCC is less than PC ( 14.7 relative percent for NGCC compared to 28.9 and 27.6 relative percent for subcritical and SC PC respectively ) and IGCC (21.4 relative percent) mainly because natural gas has a lower carbon intensity t han coal and NGCC has a higher efficiency than PC or IGCC . In the PC cases, about 589,670 kg/h r (1.3 million lb/h r ) of CO 2 

## must be captured and compressed while in the NGCC case only about 181,437 kg/h r (400,000 lb/h r ) is captured and compressed.

**•** A study assumption is that the natural gas contains no PM or Hg, resulting in negligible emissions of both.

**•** This study also assumes that the natural gas contains no sulfur compounds, resulting in negligible emissions of SO 2 

## . As noted previously in the report, if the natural gas contained the maximum allowable amount of sulfur per EPA’s pipeline natural gas specification, the resulting SO 2 

## emissions would be 21 tonnes/yr (23 tons/yr), or 0.00195 lb/MMBtu.

**•** NOx emissions are nearly identical for the two NGCC cases on a heat input and mass basis. This is a result of the fixed output from the GT (25 ppmv at 15 percent O 2 

## ) and the fixed efficiency of the SCR (90 percent). The normalized water withdrawal , process discharge and raw water consumption are shown in Exhibit 5

- 32 for the NGCC cases. The following observations can be made:

**•** Normalized water withdrawal increases 95 percent and normalized raw water consumption 9 1 percent in the CO 2 

## capture ca se. The high cooling water demand of the Econamine process results in a large increase in cooling tower makeup requirements.

**•** Cooling tower makeup comprises approximately 99 percent of the raw water consumption in both NGCC cases. The only internal recycl e stream in the non

capture case is the BFW blowdown, which is recycled to the cooling tower. In the CO 2 

## capture case condensate is recovered from the FG as it is cooled to the absorber temperature of 32°C (89°F) and is also recycled to the cooling tower.

### Cost and Performance Baseline for Fossil Energy Plants

504 

## Exhibit 5

- 32 Raw Water Withdrawal and Consumption in NGCC Cases

4.3 8.4

3.3 6.3

0 1 2 3 4 5 6 7 8 9

NGCC NGCC w/ CO2 CaptureWater, gpm/MWnet Raw Water Withdrawal Process Discharge Raw Water Consumption

### Cost and Performance Baseline for Fossil Energy Plants

505 

## 6.
This supplementary chapter presents sensitivities of the economic p erformance to higher natural gas prices and dispatch

- based CF s. Sections EFFECT OF HIGHER NAT URAL GAS PRICES AND DISPATCH

- BASED CAPACITY FACTORS

6.1 through 6.3 discuss the sensitivity to higher natural gas prices (at a constant CF ) 10 

## 6.4 while Sections through 6.8 examine dispatch

- based CF s. 6.1 INCREASING NATURAL G AS PRIC ES An investigation was conducted because of the potential for natural gas prices to increase over the long

- term. Regulations limiting the emissions of CO 2 

## may cause natural gas to become an increasingly attractive fuel source for power generation. Natur al gas is preferred in many cases because of its lower carbon intensity relative to coal: burning natural gas emits less CO 2 

## than an equivalent amount of coal . When compared to the average IGCC and PC non

- capture cases in this study, NGCC emits 52 percent and 56 percent less CO 2 

## on a lb/net

- MWh basis, respectively. As demand increases the natural gas supply has the potential to become constrained. Gas resources within the U.S. are mature and much of the low

- cost gas has already been produced. Drilling a nd exploration will need to be done to find alternative sources of natural gas. Producers will have to drill higher cost wells with lower deliverability requiring high

- cost technology to meet increased demand. Additional pipelines will have to be built a s this gas will come from increasingly remote areas. The recently accessible Marcellus shale formation still must overcome environmental obstacles to be viable. The cost to produce the same volume of gas will increase causing the consumer to pay more for natural gas. As domestic production costs increase, an alternative source for natural gas is imported liquefied natural gas (LNG). LNG is increasingly becoming a worldwide commodity as the supply and availability increase. As of 2009, there are only sev en import terminals in the U.S. If imported LNG is to become a viable fuel source for the U .S. , more terminal facilities will have to be built to keep up with the increasing demand. There is significant lag time between planning, permit acquisition, and construction of these large

- scale facilities. This lag time , along with competition for LNG resources between other nations as the U

. S

. enters the market , will further limit the supply to the U. S

. 6.2 PRICE METHODOLOGY The baseline natural gas price used in t his report is $6.55/MMBtu ( June 2007 dollars). Two other natural gas prices are evaluated in this chapter to judge the sensitivity of the results to higher gas prices. The first is the EIA’s AEO 2008 “High Price” projection for 2010. The “High Price” is $7.54/MMBtu in 2007 dollars 11

10 

### It is acknowledged that changes in fuel pricing will likely have an i m pact on capacity factor. However fo r the purposes of this example, capacity factor is assumed to remain constant at a relatively high value of 85 percent in the face of changing fuel prices. 

## .

11 

### The AEO 2008 “Hi gh Price” is reported as $7.31/MMBtu in 2006 dollars. This value was escalated to $7.54/MMBtu in 2007 dollars by using the GDP chain

- type price index from AEO 2008.

### Cost and Performance Baseline for Fossil Energy Plants

506 

## The second natural gas cost is derived from applying the historical correlation between natural gas and West Texas Intermediate (WTI) crude oil [ 80 NG Price ($/MMBtu) =

- 0.4744 + 0.1543 x (Oil Price WTI ($/bbl)) ]

.

The AEO “Hi gh Price” projection cost for imported crude oil in 2010 is $71.33/bbl in 2007 dollars 12



## 6.3 COST OF ELECTRICITY . Using the “High Price” in the correlation equation results in a natural gas price of $10.53/MMBtu. Using the Oil Correlation again, a $51.94/bbl price would be neede d to have a $7.54/MMBtu price for natural gas.

The COE results are shown in Exhibit 6

- 1 with the capital costs, fixed operating cost, variable operating cost, and fuel cost shown separately. In capture cases the CO 2 

## TS&M costs are also shown as a separate bar segment. Fuel cos t is the dominant component of COE in all NGCC cases and therefore fuel price increases have a significant impact. The following conclusions can be drawn:

**•** In non

- capture cases, the NGCC “High Price” case still has a lower COE ( 65.6 mills/kWh) than any of the IGCC cases (average 77.2 mills/kWh), but the NGCC Oil Correlation Price cost ( 86.0 mills/kWh) represents the highest COE of all the non

- capture cases.
**•** In capture cases, the NGCC baseline cost ( 8 5

. 9 mills/kWh) is the lowest capture case cost in the init ial study, and the NGCC “High Price” cost ( 93. 8 mills/kWh) is still the lowest COE.

**•** When the natural gas price increases to $10.53/MMBtu in the Oil Correlation case, NGCC becomes the most expensive technology with CO 2 

## capture. This differs from the baseli ne results where NGCC with capture was the lowest cost.

**•** For the three NGCC cases without CO 2 

## capture, the fuel component of COE ranges from 76 percent to 83 percent. For captur e cases, the fuel component of COE ranges from 61 percent to 71 percent.

**•** For th e NGCC non

- capture cases, an increase in the natural gas price of 15.1 percent for “High Price” and 60.8 percent for the Oil Correlation price cause an increase of 11 p ercent and 46 percent in the COE, respectively. The COE in the NGCC CO 2 

## capture cases i ncreases by 9 percent and 37 percent, respectively. First year CO 2 

## a voided costs are shown in Exhibit 6

- 7 and are calculated using both analogous technologies and non

- capture SC PC as references. The IGCC and PC cases were averaged to emphasize the NGCC cases at different natural gas prices. The following conclusions can be drawn:

**•** For NGCC cases, the first year CO 2 

## avoided costs increase with the price of natural gas

. This is consistent with the COE trend as NGCC cases are predominately affected by fuel price.

12 

### The AEO “High Price” is reported as $69.19/bbl in 2006 dollars. This value was escalate d to $71.33 in 2007 dollars by using the GDP chain

- type price index from AEO 2008.

### Cost and Performance Baseline for Fossil Energy Plants

507 

## • At the baseline natural gas price of $6.55/MMBtu, the NGCC cases have a higher first year CO 2 

## avoi ded cost per ton than PC or IGCC when compared to the analogous non

capture technology

. However, NGCC has the lowest first year avoided cost relative to a
non - capture SC PC plant except at the highest natural gas price case.

### Cost and Performance Baseline for Fossil Energy Plants

508 

## Exhibit 6

- 1 COE By Cost Component

44.4 63.3

31.2 60.2

31.7 59.6

10.1 22.3 10.1 22.3 10.1 22.3 11.5 15.7

7.8 13.1

8.0 13.0

3.0 5.7

3.0 5.7

3.0 5.7 7.4 9.7

5.1 9.2

5.0 8.7

1.3 2.6

1.3 2.6

1.3 2.6 13.9 17.7

15.2 21.3

14.2 19.6

44.5 52.2

51.3 60.1

71.6 83.9 5.5 5.9 5.7

3.2 3.2 3.2

77.2 111.8

59.4 109.7

58.9 106.6

58.9 85.9

65.6 93.8

86.0 117.7



### 0 20 40 60 80 100 120 140

IGCC Average IGCC Average w/ CO2 Capture Subcritical PC Subcritical PC w/ CO2 Capture Supercritical PC Supercritical PC w/ CO2 Capture NGCC NGCC w/ CO2 Capture NGCC High Price NGCC High Price w/ CO2

Capture NGCC Oil Correlation NGCC Oil Correlation w/ CO2 CaptureCOE, mills/kWh (2007$) 

### CO2 TS&M Costs Fuel Costs Variable Costs Fixed Costs Capital Costs

### Cost and Performance Baseline for Fossil Energy Plants

509 

## Exhibit 6

- 2 First Year CO 2 

## Avoided Costs

52 69 84 88 98

75 72

36 46 77



### 0 20 40 60 80 100 120

IGCC Average PC Average NGCC Baseline NGCC "High Price" NGCC Petroleum CorrelationFirst Year CO2Avoided Cost, $/tonne (2007$) 

### FY Avoided Cost (Analogous Technology w/o Capture Reference) FY Avoided Cost (SC PC w/o Capture Reference)

### Cost and Performance Baseline for Fossil Energy Plants

5 10 

## Exhibit 6

- 3 shows the COE sensitivity to fuel costs for the non

- capture cases. The solid line is the COE of NGCC as a function of natural gas cost. The points on the line represent the natural gas cost s that would be required to make the COE of NGCC equal to PC or IGCC at a given coal cost. The coal prices shown ($1.23, $1.64 and $2.05/MMBtu) represent the baseline cost and a range of ±25 percent around the baseline. The vertical lines represent the n atural gas prices highlighted in this section. At the AEO “High Price” o f $7.54/MMBtu NGCC has a lower COE than all IGCC cases at any of the coal prices. At this natural gas price for non

- capture cases PC is the most cost effective method for producing el ectricity. For IGCC cases to compete with NGCC cases at the highest studied coal price, the cost of natural gas would have to be $9. 75 /MMBtu. Fuel cost sensitivity is presented for the CO 2 

## capture cases in Exhibit 6

- 4 . Even at the lowest coal cost shown ($1.23/MMBtu), the COE of NGCC at the “High Price” is lower than both the IGCC cases and PC cases. At a natural gas price 52 percent higher than the baseline price of $6.55/MMBtu, the NGCC case is statistically equal to the PC cases at a coal cost of 25 percent more than the baseline price ($2.05/MMBtu). Exhibit 6

- 3 COE Sensitivity to Fuel Costs in Non

- Capture Cases

40 50 60 70 80 90 100

3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu NGCC PC w/ coal at $1.23/MMBtu PC w/ coal at $1.64/MMBtu PC w/ coal at $2.05/MMBtu IGCC w/ coal at $1.23/MMBtu IGCC w/ coal at $1.64/MMBtu IGCC w/ coal at $2.05/MMBtu

Baseline Study Price

-

$6.55/MMBtu AEO "High Price"

- $7.54/MMBtu Petroleum Correlation Price

- $10.53/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

511 

## Exhibit 6

- 4 COE Sensitivity to Fuel Costs in CO 2 

## Capture Cases

The sensitivity of COE to CF is shown for all non capture technologies in Exhibi t 6

- 5 and for all capture technologies in Exhibit 6

- 6 . The baseline PC and IGCC cases for non

- capture and capture were averaged to highlight the comparison with the NGCC cases. The average PC plant with capture and the average IGCC plant with capture are nearly identical so that the two curves appear as a single curve on the graph. The CF is plotted from 30 to 90 percent. The baseline CF is 80 percent for IGCC cases with no spare gasifier and is 85 percent for PC and NGCC cases. The curves plotted in Exhibit 6

- 5 and Exhibit 6

- 6 for IGCC cases assume that the CF could be extended to 90 percent with no spare gasifie r. Similarly, the PC and NGCC curves assume that the CF could reach 90 percent with no additional capital equipment. 40 50 60 70 80 90 100 110 120 130 140

3 4 5 6 7 8 9 10 11 12 13COE, mills/kWh (2007$)

Natural Gas Price, $/MMBtu NGCC PC w/ coal at $1.23/MMBtu PC w/ coal at $1.64/MMBtu PC w/ coal at $2.05/MMBtu IGCC w/ coal at $1.23/MMBtu IGCC w/ coal at $1.64/MMBtu IGCC w/ coal at $2.05/MMBtu

Baseline Study Price

-

$6.55/MMBtu AEO "High Price"

- $7.54/MMBtu Petroleum Correlation Price

- $10.53/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

512 

## Exhibit 6

- 5 COE Sensitivity to Capacity Factor in Non

- Capture Cases

40 60 80 100 120 140 160 180 200

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

Capacity Factor, % Avg. IGCC no capture
Avg. PC no capture NGCC no capture Petroleum Correlation NGCC no capture "High Price"
NGCC no capture

Coal = $1.64/MMBtu Natural Gas = $6.55/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

513 

## Exhibit 6

- 6 COE Sensitivity to Capacity Factor in Capture Cases

The NGCC curves are flatter than the coal curves because for NGCC the fuel cost, rather than the capital cost, is the dominant component of COE, eve n at baseline natural gas prices. Conclusions that can be drawn from Exhibit 6

- 5 and Exhibit 6

- 6 include:

**•** At high CF s, coal based technologies with and without CO 2 

## capture can be competitive with NGCC depending on the price of natural gas. As the CF falls among the non

capture technologies , IGCC becomes less compe titive first, followed by PC. IGCC and PC with CO 2 

## capture become less competitive together as the CF decreases.

**•** At low CF s, the coal based IGCC and PC technologies are affected to a greater extent than NGCC. At a CF less than 45 percent, NGCC is the most economic option at each natural gas price examined.
6.4 DISPATCH

- BASED CAPACITY FACTO RS The baseline assumption in this report was that all technologies would always be dispatched when available , making CF and availabili ty factor equivalent. In reality the marginal production cost would determine dispatch order and hence CF . The balance of this chapter examines the determination and impact of a dispatch

- based CF

. Estimates are provided for th e plant dispatch expected in cases without CO 2 

## capture, if these units were to compete for electric sales with the other 1,706 generators that would provide the generation to supply the demand of the PJM Interconnection ( PJM ) control region in 2010. The 40 60 80 100 120 140 160 180 200 220 240 260 280 300

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

Capacity Factor, % Avg. IGCC w/CO2 capture
Avg. PC w/CO2 capture
NGCC w/ CO2 capture Petroleum Correlation NGCC w/ CO2 capture "High Price"
NGCC w/CO2 capture

Coal = $1.64/MMBtu Natural Gas = $6.55/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

514 

## basis for projecting the expe cted CF of each of the units without CO 2 

## capture is provided, along with the financial implications of that dispatch. The estimated year 2010 CF s earned in the PJM operating region for the units examined are listed in Exhibit 6

- 7 . The bases for these estimates are discussed later in this chapter. Exhibit 6

- 7 Dispatch Based Capacity Factors for Cases without CO 2 

## Capture

Case Year 2010 Capacity Factor
Case 1

- GE IGCC 51.5% Case 3

- CoP IGCC 54.1% Case 5

- Shell IGCC 62.0% Case 9

– Subcritical PC 73.4% Case 11

- SC PC 85.0% Case 13

– NGCC 16.5%

The annual CF of an electric generating unit is the ratio of its actual generation (that is, the unit’s annual kWh) to the kWh it would generate if, hypothetically, it could operate a t full capacity for every hour of the year without interruption. The CF is a measure of how much the unit is used , and is an important measure for assessing the potential for profitable financial return from the investment in the purchase of the generating equipment. About Capacity Factor

No generating unit can run all of the time; thus, the CF of a unit is alw ays less than 1.00. Reasons for the unit not running all of the time include:

**•** The unit is removed from service for planned maintenance.

**•** The unit is forced to temporarily decrease output due to a partial equipment failure that limits output, which requires unplanned maintenance that can be accomplished with the unit running at partial load.

**•** The unit is forced to be completely removed from service due to equipment failures and subsequent required unplanned maintenance.

**•** The unit runs only at part load becaus e of grid variations in the demand for power. The ability of the unit to follow the demand makes this unit the most economical to turndown compared to the other units running at the same time.

**•** The unit costs more to operate than competing units, therefore it is displaced by units that are either more efficient or use less costly fuel. Since the unit’s production costs are higher than competing units that could meet the system power demand at a given period

### Cost and Performance Baseline for Fossil Energy Plants

515 

## of time, the unit is dropped for periods of time f rom the dispatch order since it is not needed. Units that have lower production costs then meet the demand, and the unit remains idle until once again the system demand rises high enough so that the unit rejoins the dispatch order as the most cost effecti ve unit available for service at that given level of demand.
A unit cannot have a CF greater than its equivalent availability (defined as the fraction of time that the unit is available accounting only for planned maintenance and forced outages ) . The equi valent availability thus forms the upper bound on the CF . Of course, the unit may have a lower CF when there are periods of time where competing units with lower production costs can win the competitive bidding to meet demand, forcing the less economical unit to be idle.

For the most part, a generating unit can only provide a financial return to its investors when it is running. While a unit can earn revenue even if it is not providing output, selling ancillary
se rvices, such as providing reserve power and other standby services, overwhelmingly, the investment in the unit is made with anticipation of revenue from unit operations; the more hours the unit runs

— that is, the higher its CF

— the greater potential retur n from its operations. Financial Implications of Capacity Factor

An electric generating unit’s CF has a dramatic impact on the annual fixed operating costs

. These costs must be paid whether or not the unit is operating and earning revenue. These fixed costs include property tax, paying off the capital investment to the investment bankers, salaries for the operations staff who need to be there whether the p lant is running or not, and others. The greater the CF (the number of hours that a unit operates, and thus earns revenue), the greater the period over which these fixed operating costs can be amortized, and the lower the percentage impact on the total ann ual costs of production for the unit.

PJM Interconnection is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia , and the District of Columbia. As an Independent System Operator , in 2006, PJM dispatche d the generation of 1,706 sources for meeting demand. It is an excellent choice for modeling the dispatch prospects of the units modeled in this study , since: Unit Dispatch in the PJM Control Region

**•** PJM is the largest control region in the world, eclipsing Japan, and of France, the next larger regions.

**•** PJM dispatches a diverse mix of generation.

**•** PJM is a m odel for competitive electric power dispatch operations ; m ore than 70 nations have sent delegates to PJM to learn about its market model and its operation of the electric grid.

### Cost and Performance Baseline for Fossil Energy Plants

516 

## This analysis of unit dispatch within PJM for the cases in this study was performed with consideration for the following: Method Used to Estimate Unit Dispatch in PJM in Year 2010

**•** Hour

- by

- hour forecast of expected electric demand within the control region in 2010

.

**•** Forecast of fuel costs for the units competing for electric sales with in the region in 2010

.

**•** Assessment of the seasonal availability of the competing fleet of generating units.

**•** Estimate s for each of the generating units competing for electric sales within the control region :

**−** Variable operating costs for each.

**−** Fuel and other p roduction costs for each

.

**•** Forecast the hour

- by

- hour unit dispatch that would result in the most competitive mix of units for each hour of operation throughout the target study year 2010

.

To update the ex amined cases , dispatched based CF s were determined for the six cases without CO 2 

## capture through modeling the dispatch of the units in the P J M ISO. The remainder of this chapter provides: Dispatch

- Based Capacity Factor

– What is Discussed

**•** The modeling results of the six non

- capture cases within this regio n.

**•** A description of the PJM ISO

.

**•** A review of the modeling method and assumptions that w ere used to develop these estimates.

**•** A listing of the case economics at the anticipated CF levels estimated in this c hapter.
6.5 DISPATCH MODELING RESULTS WITHIN PJM Year 2010 unit dispatch modeling in the PJM control region was performed under two scenarios:

**•** Natural gas price fixed at the EIA

- predicted value for 2010 of $6.55/MMBtu.

**•** Varying the natural gas price over the range of $0 to $2 0/MMBtu. The generating unit disp atch stack, including a list of generating units ordered by production costs, for the fixed natural gas price case is shown in Exhibit 6

- 8 and illustrates the increase in production cost with increase d cumulative production from the system. Additionally, this plot shows the fuel type of the plants within the stack. As expected, the fuel price dominates the stacking order with the technolog ies using the lower cost (or no cost) fuels being dispatched first, then coal, then natural gas; those with the most expensive fuel, No. 2 oil, are dispatched last.

### Cost and Performance Baseline for Fossil Energy Plants

517 

## Exhibit 6

- 8 Estimated Stacking Order in P JM for Year 2010 Based on First Year Production Costs

The stack curve in Exhibit 6

- 8 would change with variations in the natural gas price. For
exam ple, as the price of natural gas decreases, the production cost of the natural gas

- fired units would decrease . This could eventually lead to a drop below the bituminous coal

- fired unit ’ s production costs. In this case, the natural gas units would shift t o the left of the bituminous coal

fired units and be dispatched first. Based on the uncertainty of natural gas prices in 2010, the initial dispatch modeling was performed as a scan of the natural gas price ranging from $0 to $20/MMBtu. At low natural gas prices, $2.50/MMBtu , the natural gas units in the PJM fleet are dispatched prior to the coal

- fired units. The most efficient coal unit, SC PC, achieves the lowest production cost and therefore is the first to be dispatched with increasing natural gas pric es. This results in the SC PC unit having the highest CF , as shown in Exhibit 6

- 9

. Exhibit 6

- 9 further shows that the dispatch of the units is not significantly impacted by natural gas prices in the range of $6

- $10/MMBtu. When the price of natural gas is above $12.50/MMBtu, the production cost of the NGCC unit is above that of the oil

- fired units in the fleet, so the CF continues to drop. 0 50 100 150 200 250 300

0 20000 40000 60000 80000 100000 120000 140000 160000Production Cost ($/MWh)



### Cumulative Production (MW) Natural Gas Wind Landfill Gas Hydro Coal No 2 Oil Black Liquor MSW Other Gas Wood Solids No. 6 Oil Nuclear Natural Gas Price = $6.55/MMBtu Coal Price = $1.64/MMBtu

### Cost and Performance Baseline for Fossil Energy Plants

518 

## Exhibit 6

- 9 Capacity Factors of Replacement Units Dispatched into PJM

The fuel cost s used in this study (coal at $1.64/MMBtu and natural gas at $6.55/MMBtu) lead to the CF s listed in Exhibit 6

- 10

. Exhibit 6

- 10 Dispatch Based Capacity Factors Assuming N o CO 2 

## Capture Case CF Case 1

- GE IGCC 51.5 % Case 3

- CoP IGCC 54.1 % Case 5

- Shell IGCC 62.0 % Case 9

– Subcritical PC 73.4% Case 11

- SC PC 85.0 % Case 13

- NGCC 16.5%

Exhibit 6

- 11 illustrates the desired unit dispatch factor, which ignores availability and is therefore the percentage of time that a unit would be dispatched if it is 100 percent available , as a function of the production cost of the entire PJM fleet. For the coal

- based cases, there is a high sensitivity of the dispatch factor on the production cost; that is if the production cost changes a 0 20 40 60 80 100

$0 $5 $10 $15 $20Capacity Factor (%)



### NG Price ($/MMBtu) PC Supercritical PC Subcritical
IGCC

- Shell
IGCC

- CoP
IGCC

- GE
NGCC

- F Class

### Cost and Performance Baseline for Fossil Energy Plants

519 

## small amount the dispatch factor changes significantly. Addition ally , the high efficiency of the SC PC leads to this unit being very competitive compared to the existing PJM portfolio. Exhibit 6

- 11 Summary of Prospective Facility Parameters for Modeling

The dispatch based CF s were used to revise the economic analyses for the cases without CO 2 

## capture. The impact o f dispatch based CF s on the LCOE are summarized in Exhibit 6

- 12 and Exhibit 6

- 13 . These exhibits compare the “must run” LCOEs (“initial”) determined with the CF s initially assumed in this report to the LCOEs determined with the dispatch

- based CF (“calculated”) for 2010 operations in PJM. In the comparison, it is important to note that variable costs (fuel and variable O&M) are the same while the fixed costs (capital charges and fixed O&M) vary.

### Cost and Performance Baseline for Fossil Energy Plants

520 

## Exhibit 6

- 12 Comparison of COE as a Function of C apacity Factor Breakdown of COE ($/MWh) COE $/MWh CF Capital Costs Fixed O&M Variable O&M Fuel
Case 1 GE IGCC Initial 80.0% $43.39 $11.28 $7.30 $14.36 $76.32 Calc ulated 51.5% $67.40 $17.52 $7.30 $14.36 $106.57 Case 3 CoP IGCC Initial 80.0% $41.68 $11.08 $7.20 $14.08 $74.05 Calc ulated 54.1% $61.64 $16.39 $7.20 $14.08 $99.31 Case 5 Shell IGCC Initial 80.0% $48.16 $12.16 $7.75 $13.28 $81.35 Calc ulated 62.0% $62.14 $15.69 $7.75 $13.28 $98.86 Case 9 Subcritical PC Initial 85.0% $33.31 $7.83 $5.15 $15.21 $61.50 Calc ulated 73.4% $38.57 $9.07 $5.15 $15.21 $68.00 Case 11 SC PC Initial 85.0% $33.78 $7.97 $5.04 $14.25 $61.03 Calc ulated 85.0% $33.78 $7.97 $5.04 $14.25 $61.03 Case 13 NGCC Initial 85.0% $10.11 $2.96 $1.32 $44.53 $58.92 Calculated 16.5% $52.08 $15.27 $1.32 $44.53 $113.20

### Cost and Performance Baseline for Fossil Energy Plants

521 

## Exhibit 6

- 13 Impact of Dispatched Based Capacity Factors on the Cost of Electricity

$0 $25 $50 $75 $100 $125 $150Cost of Electricity ($/MWh) Capital Costs Fixed O&M Variable O&M Fuel natural gas 

### coal

GEE IGCC ConocoPhilips IGCC Shell IGCC Subcritical PC Supercritical PC NGCC CF = 80% CF = 52%

CF = 80%
CF = 85% CF = 85% CF = 73% CF = 85% CF = 62%

CF = 80% CF = 54% CF = 17%

CF = 85% Left Collumn

- Assumed Capacity Factor Right Collumn

- Dispatch Calculation Based Capacity Factor

### Cost and Performance Baseline for Fossil Energy Plants

522 

## 6.6 PJM INDEPENDENT SYST EM OPERATOR PJM was formed in 1927 in order to share the resources of three utilities, Philadelphia Electric Co mpany (PECO), Pennsylvania Power & Light Co mpany (PP&L), and Public Service Electric & Gas Co mpany (PSE&G), thus allowing them to increase operational effic iencies. This became the world’s first power pool. PJM became the first fully functioning Independent System Operator in 1998, responsible for both the safety and reliability of the transmission system and overseeing the administration of a competitive w holesale electric power market. The scope of the PJM East and PJM West operations includes:

**•** 51 million people served

**•** 144,644 MW of peak load

**•** 164,905 MW of generation capacity

**•** 729,000 GWh (gigawatt

- hour) of energy per year

**•** 1,706 generation sources of diverse types

**•** 56,250 miles of transmission lines

**•** 450+ members

**•** $71 billion in energy and energy service trades since 1997 PJM is a limited liability company that operates on a profit neutral basis. PJM’s Operating Agreement and Tarif f provide that it can recoup its operating expenses from its member companies. Debt service is included in the operating expenses that PJM bills to members on a monthly basis. It is a non

- stock corporation owned by its members and governed by the Federal Energy Regulatory Commission (FERC) in cooperation with the state regulatory boards in which it operates. Other income comes from studies and interconnection fees, membership dues, and interest. Today, PJM has evolved to become more of a process than a specific region, though its physical region is expanding rapidly , as well. The recent issues in wholesale trading and stalled unregulated retail initiatives have demonstrated the need to provide a uniform set of operating principles that allow s the forces of supply and demand to work freely in a transparent manner while encouraging participation by new, non

- utility participants. PJM has shown it has the technology (notably a suite of Internet scheduling and trading tools) and organizational structure to a ccomplish this while maintaining system reliability. PJM’s operating territory as of February 2008 is shown in Exhibit 6

- 14 [ 81 ]

.

### Cost and Performance Baseline for Fossil Energy Plants

523 

## Exhibit 6

- 14 The PJM Operating Territor y

6.6.1 PJM is its region’s RTO with responsibility to act in several roles, including: PJM Roles and Responsibilities

**•** Control area operator

**•** Transmission provider

**•** Market administrator

**•** Regional transmission planner

**•** NERC security coordinator PJM is responsible for the region’s electric integrity, unit dispatch and reliability, and administering the pricing mechanisms for delivery of all power. With the implementation of the PJM Open Access Transmission Tariff in 1997, PJM began operating the nation’s first regi onal bid

- based energy market, and now operates six competitive markets selling energy, capacity and ancillary services. PJM enables participants to buy and sell energy, schedule bilateral electric sale transactions, and reserve transmission service. PJM provides the accounting and billing services for these transactions. Each day, PJM forecasts how much electricity will be needed and receives offers to supply electricity from producers and other suppliers of electricity. PJM decides what offers to accept

### Cost and Performance Baseline for Fossil Energy Plants

524 

## by selecting which plants will make electricity over the next period . PJM bases its decisions on the overall least cost for the whole region, considering the pattern of demand and availability of supply. PJM directs the operation of the generation plants by agreements with their owners. The electricity actually flows th rough transmission lines (high tower, high voltage lines) to local utilities’ distribution station and from there is sent on local electric lines to homes, factories and businesses. PJM also anticipates electricity needs years ahead and makes plans to ens ure that enough electri city will be there as the region grows [ 82
6.6.2 ]

.

Generation capacity in PJM is currently 187,172 MW based on the stacking o rder compiled in January 2008 for the year 2006. The mix of fuels in PJM as indicated in the stacki ng order is shown in Exhibit 6

- 15

. Generation Mix

Exhibit 6

- 15 PJM Installed Capacity by Fuel Type

6.6.3 PJM is dedicated to making all facets of electric generation service th at are practicable available on a competitive market basis, thus providing accurate pricing signals and access to these products for all participants in a deregulated electricity environment. PJM’s spot and ancillary markets offer market flexibility in that they support bilateral transactions by providing liquidity and risk management instruments, allow ing self

- s cheduling of supply, and providing spot mark et access. Based on the short but significant history of this effort, it would appear that PJM has PJM Markets Coal , 38.8

Natural Gas, 27.4 Nuclear, 16.5 Distilate/Residual

Fuel Oil and Oil Based Fuels, 7.7 Hydro, 3.3 Biomass and Municipal Waste, 1.1 Wind, 1.6 Other, 3.7

### Cost and Performance Baseline for Fossil Energy Plants

525 

## succeeded in creating rational markets with the ability to adapt as market power or reliability issues arise. PJM currently operates six markets:

**•** Day

- ahead energy market

**•** Real

- time energy market

**•** Daily capacity market

**•** Monthly/multi

- monthly (interval) capacity market

**•** Regulation market

**•** Monthly FTR auction market
6.6.4 Generation owners in PJM can sell the output from their units in three ways: bid into the PJM day

- ahead market, self

- schedule their output to serve their own load, or sell their output directly (bilaterally) to another party. PJM Energy Markets

PJM was a net exporter of energy on a monthly basis for every month in 200 6 , and exported an average of 1.5 mi llion MW h . Imports into the region and exports out of the region respond to market prices. As detailed in the PJM Interconnection State of the Market Report

– 200 6 , this activity supports the view that the PJM energy market is liquid, and exists in the c ontext of a much broader energy marketplace. All anticipated generation and load in PJM must be scheduled through PJM at least the day before. Generators are contacted the day before and advised as to which (if any) of their bids were accepted, the hours they must run, and the amounts that they will be required to provide each hour. If a generator fails to supply the generation when required, it must replace that energy by purchasing it

– either bilaterally or from the real

- time energy market. PJM runs t wo energy markets: the day

- ahead market and the real

- time market. All transactions made in the day

- ahead market are financially binding, with adjustments for actual generation and usage made using the real

- time market.
6.6.5 This study assum es that the units modeled in this study would be selling their output to the PJM day

- ahead market. The day

- ahead energy market is a financial market and is used to provide a hedge against price fluctuations (primarily congestion charges) in the real

- time market. Based on load schedules submitted by all load

- serving entities (LSEs) at least the day before the Operating Day, PJM calculates the expected energy needed at various locations (major busses) throughout the system, and accepts both sell and buy bid s for the total amount needed each hour plus reserves. Then PJM stacks the sell bids in low

- to

- high price (or economic) order and assigns a price for electricity for each hour at each location for the following day in dollars per megawatt ($/MW) . The pri ce for one megawatt of power during each hour the next operating day in the day

- ahead market will be the lowest price bid satisfying the anticipated load requirement for that hour, plus any congestion charges expected to occur at that location. This hourl y price is known as the Locational Marginal Price, or LMP. All successful bidders for that hour receive the price accepted, regardless of the price they bid. Day

- Ahead Market

PJM defines LMP as the “cost of supplying the next MW of load at a specific location, considering generation marginal cost, cost of transmission congestion, and losses.” LMP values

### Cost and Performance Baseline for Fossil Energy Plants

526 

## are the result of security

- constrained economic dispatch operations, a method system operators have used to manage congestion for years. A least

- cost security constrained dispatch algorithm determines the least expensive way to serve load while respecting transmission limits. During periods of low demand, the LMP is generally the same at all locations. That is, none of the transmission capability is constrained. During p eriods of high demand, equipment problems, or system irregularities, the LMP can vary significantly from one location to another. This is especially so during peak system days. Day

- Ahead Energy Market Timeline

**•** Up to 12 noon

– PJM receives bids and offers for energy for next Operating Day.

**•** 12 noon to 4 pm

– Day

- ahead market is closed for evaluation by PJM.

**•** 4 pm

– PJM posts day

- ahead and hourly schedules.

**•** 4 pm to 6 pm

– Re

- bidding period. Re

- bidding period is for generation not selected for day

- ahead marke t and lets them re

- bid for regulation, operating, and spinning reserves. PJM desires to give preference to uncommitted capacity first.

**•** PJM continually re

- evaluates and sends out individual generation schedule updates as required throughout the Operating D ay. The maximum and minimum day ahead electricity prices for the PJM ISO region for the year 2006 are shown in Exhibit 6

- 16

. Exhibit 6

- 16 PJM East Day

- Ahead LMP for 2006

$0 $50 $100 $150 $200 $250 $300 $350 $400

Jan

- 06 Feb

- 06 Mar

- 06 Apr

- 06 May

- 06 Jun

- 06 Jul

- 06 Aug

- 06 Sep

- 06 Oct

- 06 Nov

- 06 Dec

- 06Day Ahead LMP ($/MWh) DA LMP Minimum DA LMP Maximum

### Cost and Performance Baseline for Fossil Energy Plants

527 

## 6.6.6 There is a strong correlation between price and demand in the PJM markets. Exhibit 6

- 17 illustrates day

- ahead high and low prices, and daily high and low loads for the year 2006. Prices and Demand

Exhibit 6

- 17 PJM Load and Day

- Ahead LMP for 2006

Exhibit 6

- 18 and Exhibit 6

- 19 sh ow the correlation between price and demand over a one

- year period. They also show a rational association between the two, supporting the viewpoint that PJM has been effective at creating competitive energy markets. $0 $100 $200 $300 $400 $500 $600

0 25 50 75 100 125 150

Jan

- 06 Feb

- 06 Mar

- 06 Apr

- 06 May

- 06 Jun

- 06 Jul

- 06 Aug

- 06 Sep

- 06 Oct

- 06 Nov

- 06 Dec

- 06DA-LMP ($/MWh)Demand (GW) PJM Demand

- Minimum

PJM Demand

- Maximum

DA LMP Minimum

DA LMP Maximum

### Cost and Performance Baseline for Fossil Energy Plants

528 

## Exhibit 6

- 18 PJM Day

- Ahead LMP vs. Demand for 2006

Exhibit 6

- 19 PJM Price/Load Distribution for 2006

### Cost and Performance Baseline for Fossil Energy Plants

529 

## 6.7 DESCRIPTION OF THE P JM REGIONAL MODELING The analysis tools used to predict economic dispatch are a series of databases and calculations designed to model future dispatching of power generation facilit ies taking into account:

**•** Fuel Cost

**•** Additional new generation

**•** Changes in demand

**•** Changes in legislation The se procedures emulate the competitive dispatch of units. Outputs from the modeling include:

**•** CF s for competing units

**•** Individual and fleet wide emissions The analysis method is based on modeling the current conditions in a power generation network and then pr ojecting the operation of the system into the future. Modeling of a current generation system requires :

**•** The demand of the generation system on an hourly basis

**•** The selling price of electricity within the generation system on an hourly basis

**•** Identifying pow er generation units in the system with their operating parameters including:

**−** Nameplate capacity

**−** Fuel type

**−** Heat rate

**−** Emission intensities

**−** Variable operating and maintenance costs

**−** Delivered fuel costs To project the existing system into the future, the exis ting conditions are modified by projections of future:

**•** Fuel Prices

**•** Demand

**•** Change in generation unit portfolio

**•** Changes in legislation This data above is acquir ed through a variety of public ly available databases and internal modeling methods. The dispatch of prospective units is determined through :

**•** Determining the dispatch order of the existing plants in a system based on the production costs of the individual units. These electricity production costs are determined from the fuel costs, plant efficiency, the variable operating and maintenance costs, and penalties that are related to the generation of electricity such as for CO 2 

## emissions. In the case of modeling the PJM region, 1,706 units are characterized. The list of plants and their

### Cost and Performance Baseline for Fossil Energy Plants

530 

## infor mation, ordered by production cost, is referred to as the “stack ”. The units are then inserted into this mix of generating units, and ordered based upon their specific production costs.

**•** Identifying the marginal production cost of the last

- dispatched unit for a given hour through comparing the hourly demand for the generation system to the cumulative generation in the stack. The last facility dispatched to meet the demand sets the production cost for that hour.

**•** Determin ing if a prospective unit is dispatc hed in an hour by comparing the plant production cost to the production cost of the last plant dispatched. If the prospective unit’s production cost is less, then the unit is dispatched.

**•** Sum the hourly results for the prospective power plants to determine the CF for each unit during the year.

o For the non

- capture technologies, the CF s of the facilities , listed earlier in Exhibit 6

- 7 , were determined through dispatch modeling of these units into the PJM ISO.
6.8 WPLANET MODEL INPUTS The inputs for the model were obtained from standard databases containing generation information for the year 2006. Exhibit 6

- 20 provides a summary of the sources used to obtain the required information for 2006. Exhibit 6

- 20 Data Sources for Electricity Generation in the PJM Region in Year 2006 Generation System Parameter for 2006 Data Source Comments Hourly System

- Wide Demand PJM website database Electricity Selling Price ( D A

- LMP 1 

## ) PJM website database Not required for current calculations 

## Contributing Power Generation Unit Names PJM website database
Generation Unit Parameters 

## 2006 UDI Database 2 

### Fuel Type 

## 2006 UDI Database Nameplate Capacity 

## 2006 UDI Database Heat rate 

## 2006 eGrid Database Emission Intensities 

## 2006 eGrid Database Not required for current calculations Variable O&M Costs 

## P ower plant operations models Delivered Fuel Costs 2006 FERC Form 423
1 

### DA

- LMP is Day Ahead Locational Marginal Price 2 

### UDI World Electric Power Plants Database 2006 , available from www.platts.com

### Cost and Performance Baseline for Fossil Energy Plants

531 

## This data is cast into the future for projections of the fuel prices, generation demand, and additions to the generation facility portfolio. The assumptions for the projections and the data sources used are summarized in Exhibit 6

- 21

. Exhibit 6

- 21 Assumptions for Projecting PJM Year 2006 into 2010

Fuel Prices Natural Gas EAO 2007

- $6.55/MMBtu Bituminous Coal EAO 2007

- $1.64/MMBtu Subbituminous Coal Scaled Bituminous Coal Price Diesel Fuel Oil 2006 delivered fuel costs scaled to 2010 by futures market prices. Other Fuels Fixed at previous study prices. Demand Forecast 1.44 % increase per year based on 2006 EIA

- 411 projected demand growth for RFC Reliability Region. Changes in Generation Facility Portfolio Data from future power generation studies on PJM website. Summarized in Exhibit 6

- 22
The additional facilities that are planned or under construction and expected to be in service in 2010 amount to an additional 10,000 MW of generating capability. The breakdown of these technologies by fuel type is shown in Exhibit 6

- 22

. Exhibit 6

- 22 Breakdown of Additional Generation in the PJM ISO by Fuel Type

Coal, 51.4

Coal IGCC, 10.5 Natural Gas, 10.5 Wind, 24.6 Other (Biomass, Solar, Refuse,

Wood), 3

### Cost and Performance Baseline for Fossil Energy Plants

532 

## The characteristics of the non

- carbon capture units are listed in Exhibit 6

- 23 . These costs are based on the AEO 2008 projections of the 2007 natural gas and coal prices, $6.55/MMBtu and $1.64/MMBtu respectively. The SC PC facility has the lowest production costs (fuel and variable O&M costs) from the high efficiency and the low fuel cost. In spite of the greater efficiency and lower O&M cost of the natural gas - fired combined cycle system, the natural gas fired unit has the greatest operating cost by a factor of two because of the greater fuel cost. Exhibit 6

- 23 Summary of Prospective Facility Parameters Bituminous Baseline Facility Types Fuel Type Fuel Cos t ($/MMBtu) O&M ( mills / k Wh) Production Costs ( mills / k Wh) Heat Rate (Btu/kWh) Nameplate Capacity Case 1 IGCC GEE Bit Coal $1.64 $7.30 $21.66 8,756 622 Case 3 IGCC CoP Bit Coal $1.64 $7.20 $21.28 8,585 625 Case 5 IGCC Shell Bit Coal $1.64 $7.75 $21.03 8,099 629 Case 9 PC Sub Bit Coal $1.64 $5.15 $20.36 9,276 550 Case 11 PC Super Bit Coal $1.64 $5.04 $19.28 8,686 550 Case 13 NGCC F

- Class NG $6.55 $1.32 $45.84 6,798 555

### Cost and Performance Baseline for Fossil Energy Plants

533 

## 7. This supplementary chapter examines the impact of dry and parallel cooling systems on the cost and performance of six plant configurations: DRY AND PARALLEL COOLING

**•** IGCC (CoP) without CO 2 

## capture

**•** IGCC (CoP) with CO 2 

## capture

**•** SC PC without CO 2 

## capture

**•** SC PC with CO 2 

## capture

**•** NGCC without CO 2 

## capture

**•** NGCC with CO 2 

## capture Parallel and dry cooling systems don’t have universal definitions. In this study the systems are defined as follows: Parallel Cooling: Steam exiting the LP turbine is divided equally between a conventional condenser using cooling water as the cooling medium and an air

- cooled condenser using ambient air as the cooling medium. Additional cooling loads use cooling water , which rejects heat to an evaporative co oling tower. Dry Cooling:

The cooling system definition results i n significant load on an evaporative cooling tower in PC and NGCC cases with CO 2 

## capture even in the dry cooling scenarios because of the large Econamine cooling water requirement. Since the cooling water temperature achieved in an air

cooled cooler would be significantly higher than in an evaporative cooling tower, the Econamine performance would also be affected. The quote basis for the Econamine process is for 16°C (60°F) cooling water and no data were available to estimate performance characteristics at higher temperatures. Hence the decision to maintain an evaporative cooling tower for non

- condenser loads even in the dry cooling cases. Steam exiting the LP condenser is condensed entirely in an air

- cooled condenser. Additional miscellaneous cooling loads use cooling water that rejects heat to an evaporative cooling tower.

The study ambient design conditions are the same as ISO conditions and were presented previously in Exhibit 2

- 1 . The ambient conditions and additional study assumptions result in the following design basis:

**•** Coal feed rate was maintained constant relative to the baseline case for bo th the parallel and dry cooling scenarios, which resulted in constant gross output but different net output for each case (different auxiliary loads for an air

- cooled condenser).

**•** The condenser approach temperature in the baseline study was 12°C (21°F). Th e approach temperature for the air

- cooled condenser was assumed to be 23°C (42°F)[ 83 ], which maintained a constant condenser temperature and pressure of 38°C (101°F) and 0.0068 MPa (0.9823 psia) for all cases.

### Cost and Performance Baseline for Fossil Energy Plants

534 

## • The power requirement for the air

- cooled conde nser fans is 3.5 times greater than for evaporative cooling tower fans when the air

- cooled condenser and cooling tower have
e quivalent heat duty [ 84

**•** The baseline study accounted for cooling loads that were modeled such as the steam turbine condenser; the CO 2 

## capture process; compressor intercoolers; low temperature syngas cooling and sour water stripper condenser (IGCC cases); and an allowance for miscellaneous loads. The miscellaneous loads assigned to each technology were 100 MMBtu/hr for PC and 25 MMBt u/hr for IGCC and NGCC. These loads were maintained at the same values for the parallel and dry cooling cases and were assigned to the evaporative cooling tower. ]

.

The cost accounts affected by the change in cooling system are shown in Exhibit 7

- 1 along with the process parameter used for cost scaling and the scaling exponent. Exhibit 7

- 1 Cost Accounts Affected by Change in Cooling System

Cost Account Scaling Parameter Scaling Exponent Account 3.2: Water Makeup and Pretreating Raw water makeup 0.71 Account 3.4: Service Water Systems Raw water makeup 0.71 Account 3.7: Waste Treatment Equipment Raw water makeup 0.71 Account 8.3a: Condenser and Auxiliaries Condenser duty 0.67 Account 8.3b: Air

- Cooled Condenser Air

- cooled condenser duty 0.70 Account 9.1: Cooling Towers Cooling tower duty 0.70 Account 9.2 : CWP s Circulating water flow rate 0.86 Account 9.3: CWS Auxiliaries Circulating water flow rate 0.65 Account 9.4: Circulating Water Piping Circulating water flow rate 0.65 Account 9.5: Makeup Water System Raw water makeup 0.60 Account 9.6: Component Cooling Water System Circulating water flow rate 0.65

Account 9.9: CWS Foundations and Structures Circulating water flow rate 0.60

Account 14.4: Circulation Water Pumphouse Circulating water flow rate 0.60

Account 14.5: Water Treatment Buildings Raw water makeup 0.66 Account 14.9: Waste Treatment Building and Structures Raw water makeup 0.07

### Cost and Performance Baseline for Fossil Energy Plants

535 

## 7.1 STUDY RESULTS Dry and parallel cooling systems result in decreased water consumption at the expense of increased cost and reduced efficiency. There is a net increase in capital cost because of the addition of the air

- cooled condenser, which is greater than the reductions realized from the reduced cooling water flow rate and cooling tower duty. The O&M costs change minimally because an increase in fixed O&M costs (maintenance labor and materials) is approximately offset by a decrease in variable O&M costs (raw water and water treatment chemicals). The normalized raw water withdrawal for the baseline, parallel , and dry cases is shown in Exhibit 7

- 2 . In each case the raw water withdrawal (in gpm ) is normalized by the net unit output (in MWs ). In Exhibit 7

- 3 the absolute net reduction in raw water withdrawal (in gpm ) for the parallel and dry cooling systems is s hown. The raw water source continues to be 50 percent from groundwater and 50 percent from a municipal water supply. The following conclusions can be drawn:

**•** The greatest impact on raw water withdrawal is for PC and NGCC non

- capture cases using dry coolin g. The steam turbine condenser duty represents over 95 percent of the cooling duty in those cases, and the use of an air

- cooled condenser leaves very little remaining load for the cooling tower. Water demand for FGD in the PC case and for BFW makeup in t he PC and NGCC cases is relatively small, resulting in low normalized water withdrawal. The impact is not quite as dramatic in the IGCC non

- capture case because there are additional cooling loads besides the steam turbine condenser, namely low temperature syngas cooling, the ASU Main Air Compressor ( MAC ) intercoolers, the AGR process, and the SWS condenser.

**•** The smallest impact of dry and parallel cooling on water withdrawal is for PC and NGCC CO 2 

## capture cases. The Econamine process requires significantly more cooling water than the two

- stage Selexol process used in IGCC cases, and the capture process cooling load is assigned to an evaporative cooling tower. Therefore, the cases using the Econamine process continue to have significant evaporative and blow down losses from the cooling tower , which diminishes the water savings of the parallel and dry systems.

**•** NGCC has the lowest normalized raw water withdrawal for CO 2 

## capture cases using conventional wet cooling. The same is true using a parallel cooling system. However, when using a dry cooling system, the IGCC capture plant has the lowest normalized raw water withdrawal primarily due to the higher steam turbine output of the IGCC plant (240 MW) compared to the NGCC plant (149 MW) and the associ ated cooling duty. In all cases the use of parallel and dry cooling has a significant impact on water withdrawal. The absolute water savings ranges from 537 gpm for NGCC with CO 2 

## capture using parallel cooling to 4,649 gpm for SC PC without capture using dry cooling. The reduction in water withdrawal comes with a performance and cost penalty. The net plant output decreases slightly because the increase in auxiliary load due to the air

- cooled condenser fan is greater than the decrease due to a reduction in the cooling tower fan and CWP loads.

### Cost and Performance Baseline for Fossil Energy Plants

536 

## Exhibit 7

- 2 Normalized Raw Water Withdrawal for Baseline, Parallel and Dry Cooling Cases

7.0

4.7

2.4 11.1

8.4

5.6 9.8

5.6

1.4 18.3

15.1

11.9

4.3

2.2

0.1 8.4
7.3
6.1

0 2 4 6 8 10 12 14 16 18 20

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/CaptureNormalized Raw Water Withdrawal, gpm/net-MW

### Cost and Performance Baseline for Fossil Energy Plants

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## Exhibit 7

- 3 Absol ute Decrease in Raw Water Withdrawal for Parallel and Dry Cooling Cases

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture 1,432 2,863

1,424 2,848

2,324 4,649

1,753 3,510

1,154 2,309

537 1,075Water Withdrawal Reduction, gpm

### Cost and Performance Baseline for Fossil Energy Plants

538 

## The impact on net plant output relative to the baseline (wet cooling) cases is shown in Exhibit 7

- 4 . The plant de

- rate is greatest for the dry cooling cases because the air

- cooled condenser load increases faster than the cooling tower fan/ CWP load decreases. The de

- rate ranges from 100 kW for NGCC with CO 2 

## capture using parallel cooling to 1,059 kW for SC PC without CO 2 

## capture using dry cooling. The impact on net plant efficiency is relatively small with the largest decrease less than 0.3 percentage points when going from wet to dry cool ing for the SC PC without CO 2 

## capture case.
Exhibit 7

- 4 Net Output Reduction Relative to the Baseline (Wet Cooling) Case

Technology/Cooling System Net Output Reduction, kW (No CO 2 

## Capture) Net Plant Efficiency, % Net Output Reduction, kW (With CO 2



## Capture) Net Plant Efficiency, %

IGCC/Wet N/A 39.75 N/A 31.02

IGCC/ Parallel

- 290 39.73

- 280 31.01 IGCC/Dry

- 690 39.70

- 670 30.98
SC PC/Wet N/A 39.28 N/A 28.67

SC PC/ Parallel

- 500 39.25

- 300 28.40
SC PC/Dry

- 1,059 39.21

- 630 28.40
NGCC/Wet N/A 50.20 N/A 42.83

NGCC/ Parallel

- 270 50.17

- 100 42.82 NGCC/Dry

- 497 50.15

- 200 42.81 The cost impact is more significant than the performance impact. The capital cost of the air

cooled condenser is only partially offset by the reduction in cost of the cooling tower, CWS , and other water systems impacted by the reduction in water usage. B ecause there are always miscellaneous cooling loads assigned to the evaporative cooling tower, the cooling tower and CWS s are never eliminated, even in the dry cooling cases. The TOC for each case is shown in Exhibit 7

- 5

. The increase in TOC ranges from $46/kW for NGCC with CO 2 

## capture using parallel cooling to $109/kW for SC PC with CO 2 

## capture using dry cooling. The TOC delta between parallel and dry cooling cases i s smallest for SC PC with no capture. The increase in cost of the air

- cooled condenser is more nearly offset by reductions in other water related accounts because of the very large decrease in water withdrawal, which decreases from 3,080 gpm in the parall el cooling case to 770 gpm in the dry cooling case.

### Cost and Performance Baseline for Fossil Energy Plants

539 

## The O&M costs stay approximately constant for all cases as discussed at the beginning of Section 7.1 . The TOC and O&M costs were used to calculate a COE for each of the cases. The impact on the COE is shown in Exhibit 7

- 6 . The range of COE increase is from 0.83 mills / k Wh (NGCC with capture using parallel cooling) to 2.16 mills/k Wh (IGCC with CO 2 

## ca pture using dry cooling). The COE actually shows a slight decrease when going from parallel to dry coolin g for the SC PC no capture case for several reasons:

**•** The TOC increase is small because of the large reduction in water requirements as discussed above.

**•** The decrease in variable operating cost is more significant because of the large decrease in water withd rawal.

### Cost and Performance Baseline for Fossil Energy Plants

540 

## Exhibit 7

- 5 Total Overn ight Cost for Baseline, Parallel and Dry Cooling Cases

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture 2,351 2,351 2,351 3,466 3,466 3,466

2,024 2,024 2,024 3,570 3,570 3,570

718 718 718 1,497 1,497 1,497 57 77 72 103

82 92 65 109

56 73 46 66TOC, $/kW (2007$) TOC Baseline, $/kW TOC Increase, $/kW

### Cost and Performance Baseline for Fossil Energy Plants

541 

## Exhibit 7

- 6 COE for Baseline, Parallel and Dry Cooling Systems

0 20 40 60 80 100 120 140

Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry Wet Hybrid Dry IGCC No Capture IGCC w/Capture SCPC No Capture SCPC w/Capture NGCC No Capture NGCC w/Capture 74.0 74.0 74.0 110.4 110.4 110.4

58.9 58.9 58.9 106.6 106.6 106.6

58.9 58.9 58.9 85.9 85.9 85.9 1.25 1.60 1.56 2.16

1.41 1.38 1.08 1.82

0.94 1.14 0.83 1.14COE, mills/kWh (2007$) 

### Baseline COE (Wet Cooling)
Incremental COE (Hybrid/Parallel Cooling)

### Cost and Performance Baseline for Fossil Energy Plants

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## 7.2 SENSITIVITY CASE The assumptions made in this study resulted in a constant fuel feed rate and constant condenser operating condition for all cases. The constant condenser temperature and pressure are the result of assuming ISO ambient conditions. In reality fossil energy plants are designed for summer and winter temperature extremes. The SC PC case without CO 2 

## capture was used to examine the effect on a dry and wet cooling system of designing for a high ambient s ummer temperature. The ambient design conditions used for the sensitivity study are shown in Exhibit 7

- 7 and are representative of summerti me at Chicago’s O’Hare Airport [ 85 83 ]

. For the dry cooling case a 50°F approach to the dry bulb temperature was assumed [ ] , which results in a condenser temperature of 138°F. For the w et cooling case the following assumptions result in a condenser temperature of 118°F:

**•** Circulating water is cooled to within 5°F of the WB temperature

**•** The cooling water temperature range is 20°F

**•** The condenser temperature approach is 20°F
Exhibit 7

- 7 Design Ambient Conditions for SC PC Sensitivity Case Elevation, m (ft) 0 Barometric Pressure, MPa (psia) 0.10 (14.696) Design Ambient Temperature, Dry Bulb, °C (°F) 31 (88) Design Ambient Temperature, WB , °C (°F) 23 (73) Design Ambient Relative Humidity, % 47
In both cases the net output was maintained at approximately 550 MW, which required an increase in coal feed rate relative to the baseline SC PC cases. The results, presented below, show that the cost and performance penalties of a dry cooling system are greater than when using ISO design conditions. The normalized water usage for the wet system at high ambient temperature design conditions is 10.3 gpm/MW(net) and for the dry system is 1.4 gpm/MW(net), or a reduction of 86 percent. The performance penalty is 1.45 percentage points (38.23 to 36.78 percent). The dry cooling case requires an i ncrease in coal feed rate of 3.9 percent to maintain the same net power output as the wet cooling case. The cost penalty is also greater than in the ISO ambient condition case. The TOC increases by $145/kW in the dry cooling case compared to $92/kW for dry cooling at ISO conditions. The high ambient temperature case results in cost increases for all cost accounts ( rather than just water based accounts) because of the in crease in coal feed rate. The COE increases by 3.05 mills/k Wh in the dry cooling case at high ambient temperature compared to only 1.38 mills / k Wh at IS O conditions. The increase in COE represents a 5.1 percent increase over the wet cooling

### Cost and Performance Baseline for Fossil Energy Plants

543 

## case at high ambient temperature. The COE includes the increased fuel cost to maintain a nominal 550 MW net output.
7.3 CONCLUSIONS Parallel and dry cooling have a significant impact on water consumption for all fossi l energy technologies examined. The amount of water saved relative to a conventional wet cooling system ranges from 240

- 2,077 million gallons per year. The cost and performance penalty for dry and parallel cooling systems at ISO conditions is less than at a higher summer ambient design temperature that would represent a typical power plant design point. The performance penalty (net plant efficiency) at ISO conditions ranges from 0.006 to 0.270 percentage points and is 1.45 percentage points at the high temperature ambient condition. The cost penalty is primarily capital cost and ranges from 0.83 to 2.16 mills / k Wh at ISO conditions and is 3.05 mills / k Wh at high ambient temperature using SC PC with no capture and a dry cooling system.

### Cost and Performance Baseline for Fossil Energy Plants

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### Cost and Performance Baseline for Fossil Energy Plants

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## 8. GEE offers three design configuration s for their gasification system [ GEE IGCC IN QUENCH

- ONLY CONFIGURATION W ITH CO 2 

## CAPTURE 86

**•** Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of water to quench the temperature to approximately 288°C (550°F) before entering the syngas scrubber. It is the simplest and lowest capital cost design, but also the least efficient. ] :

**•** Radiant Only: In this configuration, the hot syngas exiting the gasifier passes thr ough a radiant syngas cooler where it is cooled from about 1 , 316°C (2 , 400°F) to 677°C (1 , 250°F), then through a water quench where the syngas is further cooled to about 232°C (450°F) prior to entering the syngas scrubber. Relative to the quench configurat ion, the radiant only design offers increased net power output, higher efficiency, improved reliability/availability relative to the radiant

- convective configuration described below, and results in the lowest COE . This configuration was chosen by GEE and Bechtel for the design of their reference plant.

**•** Radiant

- Convective: In this configuration, the hot syngas exiting the gasifier passes through a radiant syngas cooler where it is cooled from about 1 , 316°C (2 , 400°F) to 677°C (1 , 250°F), then passes over a pool of water where particulate is removed but the syngas is not quenched, then through a convective syngas cooler where the syngas is further cooled to about 371°C (700°F) prior to entering additional heat exchangers or the scrubber. This configuration h as the highest overall efficiency, but at the expense of highest capital cost and the lowest availability. This is the configuration used at Tampa Electric’s Polk Power Station. Chapter 0 of this report examined the radiant only version of the GEE gasifier in both non

capture and capture configurations (Cases 1 and 2). This supplementary chapter examines the performance of the GEE gasifier operated in the quench on ly mode with carbon capture (Case 2A). The balance of this chapter is organized analogously to Section 3.2 of the original report ( GEE IGCC Cases), and more specifi cally Section 3.2.8 , which covers the GEE IGCC with CO 2 

## capture. However, only deviations from the original chapter are presented here to avoid needless repetitio n:

**•** Process and System Description provides an overview of the technology operation as applied to the GE IGCC operated in quench only mode. The systems that are common to all gasifiers were covered in Section 3.1 and features unchanged from the radiant only operation were covered in Section 3.2.8 . Only features that are uniq ue to quench only operation are discussed further in this section.

**•** Key Assumptions is a summary of study and modeling assumptions relevant to the GEE IGCC cases.

**•** Sparing Philosophy is unchanged from the radiant only cases and not repeated here.

**•** Performance Results provides the main modeling results from quench only configuration, including the performance summary, environmental performance, carbon balance, sulfur

### Cost and Performance Baseline for Fossil Energy Plants

546 

## balance, water balance, mass and energy balance diagrams , and mass and energy balance tables.

**•** E quipment List provides an itemized list of major equipment for Case 2A.

8.1 CASE 2 A

– GEE IGCC IN QUENCH O NLY MODE WITH CO 2 

## CAPTURE Case 2A is configured to produce electric power with CO 2 

## capture. The plant configuration is the same as the GEE IGCC Case 2 with the exception that the gasifier is operated in quench only mode. The gross power output from the plant is constrained by the capacity of the two CT s, and since the CO 2 

## capture proc ess increases the auxiliary load on the plant, the net output is significantly reduced relative to Case 1. The process description for Case 2A is similar to Case 2 with exception of the gasifier operating mode. A BFD and stream tables for Case 2A are show n in Exhibit 8

- 1 and Exhibit 8

- 2 , respectively. Instead of repeating the en tire process description, only differences from Case 2 are reported here.

The gasification process is the same as Case 2 with the exception that the syngas exiting the gasifier passes through a water quench where the temperature is reduced fro m 1 , 316°C (2 , 400°F) to 288°C (550°F). The total coal feed to the two gasifiers is 5,301 tonnes/day (5,844 TPD) (stream 6) and the ASU provides 4,343 tonnes/day (4,787 TPD) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5). Gasification

Particulate is largely removed in the quench tank and no additional heat recovery occurs prior to the syngas scrubber. Raw Gas Cooling/Particulate Removal

The outlet temperature from the syngas scrubber is 227°C (440°F) (stream 10). Syngas Scrubber/Sour Water Stripper

The SGS process is the same as described for Case 2 with a 97 percent overall conversion of the CO to CO 2 

## . The warm syngas from the second stage of SGS (stream 12) is cooled to 244°C (471°F) by heating the syngas entering the fir st shift reactor. The syngas is then cooled to 193°C (380°F) by producing IP steam that is sent to the RH in the HRSG. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following the second SG S cooler the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds. Sour Gas Shift (SGS)

### Cost and Performance Baseline for Fossil Energy Plants

547 

## Exhibit 8

- 1 Case 2A Block Flow Diagram, GEE Quench Only IGCC with CO 2 

## Capture

### Cost and Performance Baseline for Fossil Energy Plants

548 

## Exhibit 8

- 2 Case 2A Stream Table, GEE Quench Only IGCC with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 V-L Mole Fraction

Ar 0.0092 0.0165 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0053 0.0000 0.0053 CH 4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0007 0.0000 0.0007 CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2197 0.0000 0.0061 CO 2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.0848 0.0000 0.2985 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2093 0.0000 0.4229 H 2 O 0.0099 0.1355 0.0000 0.0003 0.0000 0.0000 0.9997 0.0000 0.1369 0.4700 1.0000 0.2562 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0001 0.0000 0.0001 H 2 S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0045 0.0000 0.0046 N 2 0.7732 0.7077 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0043 0.0000 0.0043 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0019 0.0013 0.0000 0.0013 O 2 0.2074 0.1349 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 27,367 1,660 97 20,045 5,526 0 5,037 0 23,121 37,625 0 37,625 V-L Flowrate (kg/hr) 789,731 45,607 3,132 562,472 177,815 0 90,741 0 465,209 726,195 0 726,195 Solids Flowrate (kg/hr) 0 0 0 0 0 220,888 0 24,235 0 0 0 0
Temperature (°C) 15 18 32 93 32 15 146 1,316 1,316 227 288 250 Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.62 5.58 5.52 5.45 Enthalpy (kJ/kg) A 30.23 35.62 26.67 92.50 26.67

--- 0.00

--- 2,631.86 1,479.52 2,918.18 1,017.26 Density (kg/m 3 ) 1.2 1.5 11.0 24.4 11.0

--- 867.1

--- 8.5 25.9 25.6 24.5 V-L Molecular Weight 28.857 27.479 32.181 28.060 32.181

--- 18.015

--- 20.121 19.301 18.015 19.301
V-L Flowrate (lb mol /hr) 60,334 3,659 215 44,193 12,182 0 11,105 0 50,972 82,948 0 82,948 V-L Flowrate (lb/hr) 1,741,060 100,545 6,906 1,240,039 392,015 0 200,050 0 1,025,611 1,600,986 0 1,600,986 Solids Flowrate (lb/hr) 0 0 0 0 0 486,976 0 53,430 0 0 0 0
Temperature (°F) 59 65 90 199 90 59 295 2,400 2,400 440 550 481 Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 815.0 810.0 800.0 790.0 Enthalpy (Btu/lb) A 13.0 15.3 11.5 39.8 11.5

--- --- 1,131.5 636.1 1,254.6 437.3 Density (lb/ft 3 ) 0.076 0.091 0.687 1.521 0.687

--- 54.131

--- 0.530 1.619 1.597 1.529 A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

549 

## Exhibit 8

- 2 Case 2A Stream Table, GEE Quench Only IGCC with CO 2 

## Capture (C ontinued)
13 14 15 16 17 18 19 20 21 22 23 24 V-L Mole Fraction

Ar 0.0071 0.0071 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000 CH 4 0.0009 0.0009 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 0.0082 0.0081 0.0130 0.0130 0.0002 0.0023 0.0000 0.0061 0.0000 0.0000 0.0000 0.0000 CO 2 0.4017 0.4053 0.0501 0.0501 0.9948 0.5218 0.0000 0.6606 0.0003 0.0083 0.0083 0.0000 COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.5690 0.5647 0.9133 0.9133 0.0048 0.1029 0.0000 0.2596 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0012 0.0012 0.0001 0.0001 0.0000 0.0225 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000 HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 S 0.0061 0.0061 0.0000 0.0000 0.0000 0.3472 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000 N 2 0.0058 0.0065 0.0105 0.0105 0.0000 0.0008 0.0000 0.0574 0.7732 0.7541 0.7541 0.0000 NH 3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 27,963 28,357 17,424 17,424 10,414 496 0 394 110,253 139,653 139,653 20,010 V-L Flowrate (kg/hr) 552,101 564,705 90,455 90,455 456,190 17,654 0 12,604 3,181,557 3,834,485 3,834,485 360,491 Solids Flowrate (kg/hr) 0 0 0 0 0 0 5,523 0 0 0 0 0
Temperature (°C) 35 35 35 195 51 48 178 38 15 562 132 534 Pressure (MPa, abs) 5.17 5.1 5.137 3.172 15.270 0.163 0.119 5.512 0.101 0.105 0.105 12.512 Enthalpy (kJ/kg) A 36.94 36.2 194.924 1,117.278 -162.292 74.702

--- 5.842 30.227 834.643 343.500 3,432.968 Density (kg/m 3 ) 41.0 41.2 10.2 4.2 641.8 2.2 5,280.6 77.3 1.2 0.4 0.9 36.7 V-L Molecular Weight 19.744 20 5.191 5.191 43.804 35.590

--- 31.966 28.857 27.457 27.457 18.015
V-L Flowrate (lb mol /hr) 61,647 62,516 38,414 38,414 22,960 1,094 0 869 243,066 307,881 307,881 44,115 V-L Flowrate (lb/hr) 1,217,174 1,244,961 199,419 199,419 1,005,728 38,921 0 27,786 7,014,133 8,453,593 8,453,593 794,747 Solids Flowrate (lb/hr) 0 0 0 0 0 0 12,177 0 0 0 0 0
Temperature (°F) 95 95 95 383 124 119 352 100 59 1,044 270 994 Pressure (psia) 750.0 745.0 745.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7 Enthalpy (Btu/lb) A 15.9 15.6 83.8 480.3 -69.8 32.1

--- 2.5 13.0 358.8 147.7 1,475.9 Density (lb/ft 3 ) 2.562 3 0.636 0.261 40.065 0.137 329.655 4.823 0.076 0.026 0.053 2.293

### Cost and Performance Baseline for Fossil Energy Plants

550 

## Mercury removal and the AGR process are the same as in Case 2. Mercury Removal and Acid Gas Removal

The AGR process in Case 2A is a two stage Selexol process where H 2 

## S is removed in the first stage and CO 2 

## in the second stage of absorption as previously described in Section 3.1.5 . The process results in three product streams, the clean syngas, a CO 2 

## - rich stream and an acid gas feed to the Claus plant. The acid gas (stream 18) contains 35 percent H 2 

## S and 52 percent CO 2 

## with the balance primarily H 2 

## .

The CO 2 

## compression and dehydration scheme is the same as for Case 2. CO 2 

## Compression and Dehydration

The C laus plant is the same as Case 2 with the following exceptions: Claus Unit

**•** 5,523 kg/h r (12,177 lb/h r ) of sulfur (stream 19) are produced

**•** The waste heat boiler generates 12,957 kg/h r (28,564 lb/h r ) of 3.0 MPa (430 psia) steam.

Clean syngas from the AGR pla nt is heated to 241°C (465°F) using first hot water from the syngas scrubber followed by HP BFW before passing through an expansion turbine. The clean syngas (stream 16) is diluted with nitrogen (stream 4) and then enters the CT burner. There is no integ ration between the CT and the ASU in this case. The exhaust gas (stream 22) exits the CT at 562°C (1 , 044°F) and enters the HRSG where additional heat is recovered. The FG exits the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant sta ck. The steam raised in the HRSG is used to power an advanced commercially available steam turbine using a nominal 12.4 MPa/538°C/538°C (1800 psig/1000°F/1000°F) steam cycle. Power Block

The same elevated pressure ASU is used in Case 2A and produc es 4,343 tonnes/day (4,787 TPD) of 95 mol% oxygen and 14,595 tonnes/day (16,087 TPD) of nitrogen. There is no integration between the ASU and the CT

. Air Separation Unit

8.1.1 System assumptions for Case 2A are shown in Key System Assumptions Exhibit 8

- 3

.

### Cost and Performance Baseline for Fossil Energy Plants

551 

## Exhibit 8

- 3 GEE IGCC Plant Study Configuration Matrix Case 2 A Gasifier Pressure, MPa (psia) 5.6 (815) O 2 

## :Coal Ratio, kg O 2 

## /kg dry coal 0.9 1 Carbon Conversion, % 98 Syngas HHV at Gasifier Outlet, kJ/Nm 3 

## (Btu/scf) 8, 655 (2 32 ) Steam Cycle, MPa/°C/°C (psig/ **°** F/ **°** F) 12.4/53 4 /53 4 (1800/ 994 / 994 ) Condenser Pressure, mm Hg (in Hg) 51 (2.0)

CT 2x Advanced F Class (232 MW output each) Gasifier Technology GEE Quench Only Oxidant 95 vol% Oxygen Coal Illinois No. 6 Coal Slurry Solids Con t ent, % 63 COS Hydrolysis Occurs in SGS SGS Yes H 2 

## S Separation Selexol 1 st 

## Stage Sulfur Removal, % 99.8 Sulfur Recovery Claus Plant with Tail Gas Recycle to Selexol/ Elemental Sulfur
Particulate Control Water Quench, Scrubber, and AGR Absorber Mercury Control Carbon Bed NOx Control MNQC (LNB) and N 2 

## Dilution CO 2 

## Separation Selexol 2 nd 

## Stage CO 2 

## Capture 90.2 % CO 2 

## Sequestration Off

- site Saline Formation

### Cost and Performance Baseline for Fossil Energy Plants

552 

## 8.1.2 The plant produces a net output of 494 MW at a net plant efficiency of 29.7 percent (HHV basis). Overall performance for the entire plant is summarized in Case 2 A Performance Results

Exhibit 8

- 4 , which includes auxiliary power requirements. The ASU accounts for 60 percent of the auxiliary load between the main air compressor, the nitrogen compressor, the oxygen compressor , and ASU a uxiliaries. The two

- stage Selexol process and CO 2 

## compression account for an additional 26 percent of the auxiliary power load. The BFW pumps and cooling water system ( CWP s and cooling tower fan) comprise about 5 percent of the load, leaving 9 percent of the auxiliary load for all other systems.

### Cost and Performance Baseline for Fossil Energy Plants

553 

## Exhibit 8

- 4 Case 2A Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Case 2 Case 2A Gas Turbine Power 464,000 464,000 Sweet Gas Expander Power 6,500 6,600 Steam Turbine Power 263,500 213,600 TOTAL POWER, kWe 734,000 684,200 AUXILIARY LOAD SUMMARY, kWe Coal Handling 470 470 Coal Milling 2,270 2,270 Sour Water Recycle Slurry Pump 190 200 Slag Handling 1,160 1,160 Air Separation Unit Auxiliaries 1,000 1,000 Air Separation Unit Main Air Compressor 67,330 67,350 Oxygen Compressor 10,640 10,640 Nitrogen Compressors 35,640 35,630 CO 2 

### Compressor 31,160 31,130 Boiler Feedwater Pumps 4,180 2,620 Condensate Pump 280 230 Quench Water Pump 540 1,270 Circulating Water Pump 4,620 4,810 Ground Water Pumps 530 550 Cooling Tower Fans 2,390 2,490 Scrubber Pumps 230 480 Acid Gas Removal 19,230 19,210 Gas Turbine Auxiliaries 1,000 1,000 Steam Turbine Auxiliaries 100 100 Claus Plant/TGTU Auxiliaries 250 250 Claus Plant TG Recycle Compressor 1,780 1,800 Miscellaneous Balance of Plant 2 

### 3,000 3,000 Transformer Losses 2,760 2,600 TOTAL AUXILIARIES, kWe 190,750 190,260 NET POWER, kWe 543,250 493,940 Net Plant Efficiency, % (HHV) 32.6 29.7 Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,458) 12,135 (11,502) CONDENSER COOLING DUTY 10 6 

### kJ/h r (10 6 

### Btu/h r ) 1,509 (1,430) 1,467 (1,390) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 220,904 (487,011) 220,888 (486,976) Thermal Input, kWt 1 

### 1,665,074 1,664,954 Raw Water Withdrawal, m 3 

### /min (gpm) 22.0 (5,815) 23.2 (6,117) Raw Water Consumption, m 3 

### /min (gpm) 17.9 (4,739) 18.9 (4,993)
1

- HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2

- Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

554 

## The environmental targets for emissions of Hg, NOx, SO 2 

## , and PM were presented in Section Environmental Performance

2.4 . A summary of the plant air emissions for Case 2A is presented in Exhibit 8

- 5

. Exhibit 8

- 5 Case 2A Air Emissions kg/GJ (lb/10 6 

## Btu) Tonne/year (tons/year) @ 80% CF kg/MWh (lb/MWh)
SO 2 

## 0.001 (0.002) 39 (43) 0.008 (.018) NOx 0.021 (0.049) 878 (968) 0.183 (.404) Particulates 0.003 (0.0071) 128 (141) 0.027 (.059) Hg 2.46E

- 7 (5.71E

- 7) 0.010 (0.011) 2.15E

- 6 (4.74E

- 6) CO 2 

## 8.5 (19.8) 358,390 (395,058) 75 (165) CO 2 1 

## 104 (228)

1 

### CO 2 

### emissions based on net power instead of gross power



## The low level of SO 2 

## emissions is achieved by capture of the sulfur in the gas by the two

- stage Selexol AGR process. As a result of achieving the 90 percent CO 2 

## removal target, the sulfur compounds are removed to an extent that exceeds the environmental target in Section 2.4 . The clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv . This results in a concentration in the FG of less than less tha n 1 ppmv . The H 2 

## S

- rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species to H 2 

## S and then recycled back to the Selexol process, thereby eliminat ing the need for a tail gas treatment unit. NO x emissions are limited by nitrogen dilution to 15 ppmvd (as NO 2 

## @15 percent O 2 

## ). Ammonia in the syngas is removed with process condensate prior to the low

- temperature AGR process. This helps lower NO x levels as well. Particulate discharge to the atmosphere is limited to extremely low values by the use of the syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR absorber. The particulate emissions represent filterable particul ate only. Ninety five percent of mercury is captured from the syngas by an activated carbon bed. Ninety percent of the CO 2 

## from the syngas is captured in the AGR system and compressed for sequestration. The carbon balance for the plant is shown in Exhibit 8

- 6 . The carbon input to the plant consists of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since the Aspen model acco unts for air components throughout. Carbon leaves the plant as unburned carbon in the slag and as CO 2 

## in the stack gas, ASU vent gas, and the captured CO 2 

## product. The CO 2 

## capture efficiency is defined as the amount of carbon in the CO 2 

## product stream re lative to the amount of carbon in the coal less carbon contained in the slag , represented by the following fraction:

### Cost and Performance Baseline for Fossil Energy Plants

555 

## (Carbon in CO 2 

## Product)/[(Carbon in the Coal)

- (Carbon in Slag)] or 274,397 /( 310,421

- 6,208 ) * 100 or 90. 2 percent Exhibit 8

- 6 Case 2A Carbon Balance Carbon In, kg/hr (lb/hr) Carbon Out, kg/h r (lb/hr) Coal 140,805 (310,421) Slag 2,816 (6,208) Air (CO 2 

## ) 540 (1,191) Stack Gas 13,957 (30,770) ASU Vent 107 (237) CO 2 

## Product 124,464 (274,397) Total 141,345 (311,612) Total 141,345 (311,612)

Exhibit 8

- 7 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur co

- sequestered with the CO 2 

## product, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 8

- 7 Case 2A Sulfur Balance Sulfur In, kg/hr (lb/hr) Sulfur Out, kg/h r (lb/hr) Coal 5,536 (12,206) Elemental Sulfur 5,523 (12,177) Stack Gas 3 (6) CO 2 

## Product 10 (23) Total 5,536 (12,206) Total 5,536 (12,206)

Exhibit 8

- 8 shows the overall water balance for the plant. Raw water is obtained from groundwater (50 percent) and from municipal sources (50 percent). Water demand represents the total amount of water required for a particular process. Some water is recovered within the process, primarily as syngas condensate, and that water is re

- used as internal recycle. Raw water withdrawal is the difference between water demand and internal recycle. Some process water is returned to the source via cooling tower and sour water stripper blowdown. The difference between raw water withdrawal and process water discharge is raw water consumption, or the net impact on the water source.

### Cost and Performance Baseline for Fossil Energy Plants

556 

## Exhibit 8

- 8 Case 2A Water Balance

Water Use Water Demand m 3 

## /min (gpm) Internal Recycle m 3 

## /min (gpm) Raw Water Withdrawal
m 3 

## /min (gpm) Process Water Discharge

m 3 

## /min (gpm) Raw Water Consumption
m 3 

## /min (gpm)

Slag Handling 0.53 (139 ) 0.53 (139 ) 0.0 (0) 0.0 (0) 0.0 (0) Slurry Water 1.5 (400) 1.5 (400) 0.0 (0) 0.0 (0) 0.0 (0) Quench Water 6.7 (1,759) 1.9 (493) 4.8 (1,267) 0.0 (0) 4.8 (1,267)
SWS Blowdown 0.0 (0) 0.0 (0) 0.0 (0) 0.04 (10)

- 0.04 (

- 10) Condenser Makeup Gasifier Steam Shift Steam BFW Makeup 0.15 (40)

0.15 (40) 0.0 (0) 0.15 (40)

0.15 (40) 0.0 (0) 0.15 (40)

Cooling Tower Makeup BFW Blowdown SWS Blowdown SWS Excess 18.8 (4,954) 0.54 (143)
0.15 (40) 0.39 (103) 18.2 (4,811)

- 0.15 (

- 40)

- 0.39 (

- 103) 4.2 (1,114) 14.0 (3,697)

Total 27.6 (7,292) 4.4 (1,174) 23.2 (6,117) 4.3 (1,124) 18.9 (4,993)

A plant heat and material balance is presented in Energy Balance Exhibit 8

- 9 through Exhibit 8

- 11 with a n overall plant energy balance presented in tabular form in Exhibit 8

- 12

.

### Cost and Performance Baseline for Fossil Energy Plants

557 

## Exhibit 8

- 9 Case 2A Coal Gasification and Air Separation Unit Heat and Mass Balance Schematic

N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 2 A
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 2 A GEE G ASIFIER ( Q UENCH O NLY ) ASU AND G ASIFICATION

DWG

. NO

. BB

- HMB

- CS

- 2 A

- PG

- 1 P LANT P ERFORMANCE S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 1 OF 3 Ambient Air

Four Stage Air Compressor

Elevated Pressure

ASU Four Stage N 2 Compressor

Four Stage O 2 Compressor ASU Vent

Water Steam

Gross Plant Power : 684 MWe Auxiliary Load : 190 MWe Net Plant Power : 494 MWe Net Plant Efficiency , HHV : 29

. 7 % Net Plant Heat Rate : 11 , 502 BTU / KWe N 2 to GT Combustor 1 , 741 , 060 W 59

. 0 T 14

. 7 P 13

. 0 H

392 , 015 W 90

. 0 T 125

. 0 P 11

. 5 H

392 , 015 W 241

. 2 T 940

. 0 P 40

. 8 H To Claus Plant 6 , 906 W

90

. 0 T 125

. 0 P 11

. 5 H 100 , 545 W 64

. 7 T 16

. 4 P 15

. 3 H

1 , 083 , 228 W 90

. 0 T 56

. 4 P 14

. 2 H

156 , 811 W 50

. 0 T 182

. 0 P

2

. 9 H 5 1

3 2

Slurry Mix

Tank Milled Coal

Slag 486 , 976 W 59

. 0 T 14

. 7 P

200 , 050 W

295

. 0 T 840

. 0 P 240

. 4 H

53 , 430 W 2 , 400

. 0 T

815

. 0 P 677 , 288 W 385

. 0 T 384

. 0 P 87

. 2 H

687 , 025 W

159

. 8 T 840

. 0 P 2 , 952

. 8 H 100

. 0 T 189

. 5 P 18

. 0 H

6 677 , 288 W 199

. 0 T 384

. 0 P 39

. 8 H

N 2 to GT Combustor N 2 Boost Compressor 562 , 752 W

199

. 0 T 384

. 0 P 39

. 8 H 562 , 752 W 385

. 0 T 469

. 0 P 87

. 0 H

Black Water Flash Tank Knockout Drum Vent To Claus Unit Raw Fuel Gas

CWS CWR

Fines Process Water From Sour Water Stripper Syngas Scrubber

Slag Quench

Section

Drag Conveyor 4

1 , 025 , 611 W

2 , 400

. 0 T

815

. 0 P 1 , 131

. 5 H 1 , 600 , 986 W 440

. 0 T 810

. 0 P 636

. 1 H

Syngas Quench 1 , 905 , 234 W 550

. 0 T 815

. 0 P 761

. 0 H

8 9 10 Sour Water

7

HP BFW

Saturated Steam

To HRSG HP Superheater Radiant Syngas Cooler

### Cost and Performance Baseline for Fossil Energy Plants

558 

## Exhibit 8

- 10 Case 2A Syngas Cleanup Heat and Mass Balance Schematic

Mercury Removal

Knock Out Drum Syngas Preheater

Sour Drum

Process Condensate to Syngas Scrubber Makeup Water Claus Plant

Tail Gas Furnace Catalytic Reactor Beds

Sulfur

Knock Out From ASU Syngas Coolers

Sour Stripper 1 , 600 , 986 W 440

. 0 T 810

. 0 P 636

. 1 H 1 , 244 , 961 W 94

. 6 T 745

. 0 P 15

. 6 H 38 , 921 W 119

. 0 T 23

. 7 P 199 , 419 W 383

. 2 T 460

. 0 P 480

. 3 H

12 , 177 W 36 , 693 W 450

. 0 T 12

. 3 P 467

. 0 H

3 , 043 W 246

. 5 T 65

. 0 P 500

. 1 H 6 , 906 W 90

. 0 T 125

. 0 P 11

. 5 H N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 2 A
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 2 A GEE G ASIFIER ( Q UENCH O NLY ) G AS CLEANUP SYSTEM

DWG

. NO

. BB

- HMB

- CS

- 2 A

- PG

- 2 P LANT P ERFORMANCE S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 2 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 684 MWe Auxiliary Load : 190 MWe Net Plant Power : 494 MWe Net Plant Efficiency , HHV : 29

. 7 % Net Plant Heat Rate : 11 , 502 BTU / KWe 19

13 20 CO 2 Tailgas

30 , 265 W

120

. 0 T 10

. 6 P 112

. 7 H 1 , 217 , 174 W 94

. 9 T 750

. 0 P 15

. 9 H

8 , 907 W 114

. 5 T 10

. 6 P 40

. 3 H 3 27 , 786 W

100

. 0 T 799

. 5 P

Raw Syngas 15 199 , 419 W 94

. 6 T 745

. 0 P 83

. 8 H

Claus Oxygen Preheater 6 , 906 W 450

. 0 T 124

. 5 P 91

. 9 H 18 Fuel Gas Expander Fuel Gas To GT

16 199 , 419 W

465

. 0 T 740

. 0 P 595

. 4 H

High Temperature

Shift # 1 Low Temperature

Shift # 2

Shift Steam

12 11

COS Hydrolysis

Preheater 1 , 600 , 986 W 450

. 0 T 805

. 0 P 621

. 4 H 0 W 1 , 600 , 986 W 449

. 7 T 800

. 0 P 621

. 4 H
781

. 7 T 800

. 0 P 606

. 0 H 425

. 0 T 800

. 0 P 440

. 0 H 1 , 600 , 986 W 481

. 4 T 790

. 0 P 437

. 3 H

1 , 600 , 986 W 471

. 1 T 785

. 0 P 432

. 6 H Two

- Stage Selexol Clean Gas

CO 2 Acid Gas

Multistage Intercooled CO 2

Compressor

Interstage Knockout CO 2 Product

17

10 14

1 , 005 , 728 W 123

. 8 T 2 , 214

. 7 P

Tail Gas Recycle

Compressor Hydrogenation and Tail Gas

Cooling

### Cost and Performance Baseline for Fossil Energy Plants

559 

## Exhibit 8

- 11 Case 2A Combined Cycle Power Generation Heat and Mass Balance Schematic

HRSG

HP Turbine IP Turbine Nitrogen Diluent

Intake

Ambient Air Steam Seal Regulator Ip Extraction Steam To 250 PSIA Header LP Process Header

Blowdown

Flash

To WWT

Gland Steam Condenser Condensate to Gasification Island HP BFW to Radiant Syngas Cooler

HP Saturated Steam to HRSG Superheater

LP Turbine Stack

Expander Compressor Fuel Gas Deaerator

IP BFW

Generator Generator

Condensate Pump HP Pump

Steam Turbine LP Pump

Advanced F

- Class

Gas Turbine MP Flash Bottoms LP Flash Tops

7 , 014 , 133 W 59

. 0 T 14

. 7 P 13

. 0 H 1 , 523 , 839 W 101

. 1 T

1

. 0 P 69

. 1 H 8 , 453 , 593 W 269

. 6 T 15

. 2 P 147

. 7 H

199 , 419 W

383

. 2 T 460

. 0 P 480

. 3 H 8 , 453 , 593 W 1 , 043

. 8 T

15

. 2 P 358

. 8 H From Gasifier Island Preheating

To Claus LP BFW 794 , 747 W

993

. 8 T 1 , 814

. 7 P 1 , 475

. 9 H 6 , 774 W 298

. 0 T 65

. 0 P 1 , 179

. 0 H

813 , 698 W 278

. 8 T 2 , 250

. 7 P

252

. 3 H

18 , 959 W

585

. 0 T 2 , 000

. 7 P

593

. 3 H

1 , 491 , 866 W 441

. 1 T 65

. 0 P 1 , 252

. 8 H

1 , 523 , 839 W 103

. 2 T 120

. 0 P 71

. 4 H 1 , 523 , 839 W 235

. 0 T 105

. 0 P 203

. 7 H

1 , 400 W 614

. 9 T 65

. 0 P 1 , 338

. 7 H 1 , 400 W 212

. 0 T 14

. 7 P 179

. 9 H IP Pump N OTES :

1

. E NTHALPY REFERENCE POINT IS NATURAL STATE AT 32 °F AND 0

. 08865 PSIA

DOE / NETL
D UAL T RAIN IGCC P LANT C ASE 2 A
H EAT AND M ATERIAL F LOW D IAGRAM
B ITUMINOUS BASELINE S TUDY C ASE 2 A GEE G ASIFIER ( Q UENCH O NLY ) P OWER B LOCK S YSTEM

DWG

. NO

. BB

- HMB

- CS

- 2 A

- PG

- 3 P LANT P ERFORMANCE S UMMARY L EGEND

P A BSOLUTE P RESSURE , PSIA F TEMPERATURE , °F W F LOWRATE , LB M / HR H E NTHALPY , BTU / LB M MW E P OWER , M EGAWATTS E LECTRICAL Air

Oxygen Nitrogen Coal / Char / Slurry / Slag

Synthesis Gas

P AGES 3 OF 3 Sour Gas

Sour Water

Water Steam

Gross Plant Power : 684 MWe Auxiliary Load : 190 MWe Net Plant Power : 494 MWe Net Plant Efficiency , HHV : 29

. 7 % Net Plant Heat Rate : 11 , 502 BTU / KWe 21 22

24

16 23

Flue Gas

HOT WELL CONDENSER Make

- up 19 , 812 W

59

. 0 T 14

. 7 P 27

. 1 H 9 , 025 W 660

. 6 T 501

. 4 P 1 , 334

. 6 H 9 , 761 W 614

. 9 T 65

. 0 P 1 , 338

. 7 H 33 , 608 W

851

. 8 T 280

. 0 P 1 , 448

. 6 H 798 W 993

. 8 T 1 , 814

. 7 P 1 , 475

. 9 H 1 , 337 W 504

. 7 T 65

. 0 P 1 , 284

. 4 H

### Cost and Performance Baseline for Fossil Energy Plants

560 

## This pag e intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

561 

## Exhibit 8

- 12 Case 2A Overall Energy Balance

HHV Sensible + Latent Power Total Heat In GJ/hr (MMBtu/hr) Coal 5,994 (5,681) 5.0 (4.7) 5,999 (5,686) ASU Air 23.9 (22.6) 24 (23) GT Air 96.2 (91.2) 96 (91) Water 87.1 (82.5) 87 (83) Auxiliary Power 685 (649) 685 (649) TOTAL 5,994 (5,681) 212.1 (201.1) 685 (649) 6,891 (6,531) Heat Out GJ/hr (MMBtu/hr) ASU Vent 1.6 (1.5) 2 (2) Slag 92 (88) 37.8 (35.9) 130 (123) Sulfur 51 (49) 0.6 (0.6) 52 (49) CO 2 

## - 74.0 (

- 70.2)

- 74 (

- 70) Cooling Tower Blowdown 31.3 (29.7) 31 (30) HRSG Flue Gas 1,317 (1,248) 1,317 (1,248) Condenser 1,452 (1,377) 1,452 (1,377) Non

- Condenser Cooling Tower Loads 1 

## 794 (753) 794 (753) Process Losses 2 

## 723 (686) 723 (686) Power 2,463 (2,335) 2,463 (2,335) TOTAL 144 (136) 4,284 (4,061) 2,463 (2,335) 6,891 (6,531)

1 

### Includes ASU compressor intercoolers, CO 2 

### compressor intercoolers, sour water stripper condenser, and syngas cooler (low level heat rejection)

2 

### Calculated by difference to close the energy balance


## 8.1.3 Major equipment items for the GEE quench only gasifier with CO 2 

## capt ure are shown in the following tables. In general, the design conditions include a 10 percent contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans. Case 2 A

– Major Equipment List

### Cost and Performance Baseline for Fossil Energy Plants

562 

## ACCOUNT 1 COAL HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 572 tonne/hr (630 tph) 2 0
3 Conveyor No. 1 Belt 1,134 tonne/hr (1,250 tph) 1 0
4 Transfer Tower No. 1 Enclosed N/A 1 0
5 Conveyor No. 2 Belt 1,134 tonne/hr (1,250 tph) 1 0

6 As-Received Coal Sampling System Two-stage N/A 1 0

7 Stacker/Reclaimer Traveling, linear 1,134 tonne/hr (1,250 tph) 1 0
8 Reclaim Hopper N/A 45 tonne (50 ton) 2 1
9 Feeder Vibratory 181 tonne/hr (200 tph) 2 1
10 Conveyor No. 3 Belt w/ tripper 363 tonne/hr (400 tph) 1 0
11 Crusher Tower N/A N/A 1 0
12 Coal Surge Bin w/ Vent Filter Dual outlet 181 tonne (200 ton) 2 0

13 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0 (3" x 0 - 1-1/4" x 0) 2 0

14 As-Fired Coal Sampling System Swing hammer N/A 1 1

15 Conveyor No. 4 Belt w/tripper 363 tonne/hr (400 tph) 1 0
16 Transfer Tower No. 2 Enclosed N/A 1 0

17 Conveyor No. 5 Belt w/ tripper 363 tonne/hr (400 tph) 1 0

18 Coal Silo w/ Vent Filter and Slide Gates Field erected 816 tonne (900 ton) 3 0

### Cost and Performance Baseline for Fossil Energy Plants

563 

## ACCOUNT 2 COAL PREPARATION AND FEED

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 82 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/tripper 245 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 118 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 118 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with Agitator Field erected 299,883 liters (79,220 gal) 2 0

7 Slurry Water Pumps Centrifugal 833 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 172 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with Agitator Field erected 392,285 liters (103,630 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,407 lpm (900 gpm) 2 2

11 Slurry Storage Tank with Agitator Field erected 1,176,894 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,435 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive displacement 3,407 lpm (900 gpm) 2 2

### Cost and Performance Baseline for Fossil Energy Plants

564 

## ACCOUNT 3 FEEDWATER AND MISCELLANEOUS SYSTEMS AND EQUIPMENT

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water Storage Tank Vertical, cylindrical, outdoor 810,078 liters (214,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,397 lpm @ 91 m H2O (1,690 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ HRSG) Horizontal spray type 464,932 kg/hr (1,025,000 lb/hr) 2 0

4 Intermediate Pressure Feedwater Pump Horizontal centrifugal, single stage 6,587 lpm @ 27 m H2O (1,740 gpm @ 90 ft H2O) 2 1

5 High Pressure Feedwater Pump No. 1 Barrel type, multi-stage, centrifugal HP water: 3,520 lpm @ 1,859 m H2O (930 gpm @ 6,100 ft H2O) 2 1

6 High Pressure Feedwater Pump No. 2 Barrel type, multi-stage, centrifugal IP water: 1,590 lpm @ 223 m H2O (420 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water tube 18,144 kg/hr, 2.8 MPa, 343°C (40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air Compressors Flooded Screw 28 m3/min @ 0.7 MPa (1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cylce Cooling Heat Exchangers Plate and frame 451 GJ/hr (428 MMBtu/hr) each 2 0

11 Closed Cycle Cooling Water Pumps Horizontal centrifugal 162,016 lpm @ 21 m H2O (42,800 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire Pump Vertical turbine, diesel engine 3,785 lpm @ 107 m H2O (1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster Pump Two-stage horizontal centrifugal 2,650 lpm @ 76 m H2O (700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single suction 5,867 lpm @ 18 m H2O (1,550 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single suction 2,915 lpm @ 268 m H2O (770 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single suction 3,899 lpm @ 49 m H2O (1,030 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,862,423 liter (492,000 gal) 2 0

18 Makeup Water Demineralizer Anion, cation, and mixed bed 227 lpm (60 gpm) 2 0

19 Liquid Waste Treatment System 10 years, 24-hour storm 1 0

### Cost and Performance Baseline for Fossil Energy Plants

565 

## ACCOUNT 4 GASIFIER, ASU AND ACCESSORIES INCLUDING LOW TEMPERATURE HEAT RECOVERY

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, entrained bed 2,903 tonne/day, 5.6 MPa (3,200 tpd, 814.96 psia) 2 0

2 Synthesis Gas Quench Pressurized quench tank 255,826 kg/hr (564,000 lb/hr) 2 0

3 Syngas Scrubber Including Sour Water Stripper Vertical upflow 475,365 kg/hr (1,048,000 lb/hr) 2 0

4 Raw Gas Coolers Shell and tube with condensate drain 399,615 kg/hr (881,000 lb/hr) 8 0

5 Raw Gas Knockout Drum Vertical with mist eliminator 304,360 kg/hr, 35°C, 5.2 MPa (671,000 lb/hr, 95°F, 755 psia) 2 0

6 Synthesis Gas Reheater Shell and tube 49,895 kg/hr (110,000 lb/hr) 2 0

7 Flare Stack Self-supporting, carbon steel, stainless steel top, pilot ignition 475,365 kg/hr (1,048,000 lb/hr) syngas 2 0

8 ASU Main Air Compressor Centrifugal, multi-stage 5,947 m3/min @ 1.3 MPa (210,000 scfm @ 190 psia) 2 0

9 Cold Box Vendor design 2,359 tonne/day (2,600 tpd) of 95% purity oxygen 2 0

10 Oxygen Compressor Centrifugal, multi-stage 1,189 m3/min (42,000 scfm) Suction - 0.9 MPa (130 psia) Discharge - 6.5 MPa (940 psia) 2 0

11 Primary Nitrogen Compressor Centrifugal, multi-stage 3,794 m3/min (134,000 scfm) Suction - 0.4 MPa (60 psia) Discharge - 2.7 MPa (390 psia) 2 0

12 Secondary Nitrogen Compressor Centrifugal, single-stage 538 m3/min (19,000 scfm) Suction - 1.2 MPa (180 psia) Discharge - 2.7 MPa (390 psia) 2 0

13 Syngas Dilution Nitrogen Boost Compressor Centrifugal, single-stage 1,982 m3/min (70,000 scfm) Suction - 2.6 MPa (380 psia) Discharge - 3.2 MPa (470 psia) 2 0

### Cost and Performance Baseline for Fossil Energy Plants

566 

## ACCOUNT 5 SYNGAS CLEANUP

ACCOUNT 5B CO 2 

## COMPRESSION

ACCOUNT 6 COMBUSTION TURBINE AND AUXILIARIES

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber Sulfated carbon bed 303,453 kg/hr (669,000 lb/hr) 35°C (95°F) 5.2 MPa (750 psia) 2 0

2 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

3 Water Gas Shift Reactors Fixed bed, catalytic 399,615 kg/hr (881,000 lb/hr) 232°C (450°F) 5.5 MPa (800 psia) 4 0

4 Shift Reactor Heat Recovery Exchangers Shell and Tube Exchanger 1: 154 GJ/hr (146 MMBtu/hr) Exchanger 2: 4 GJ/hr (4 MMBtu/hr) 4 0

5 Acid Gas Removal Plant Two-stage Selexol 310,711 kg/hr (685,000 lb/hr) 35°C (95°F) 5.1 MPa (745 psia) 2 0

6 Hydrogenation Reactor Fixed bed, catalytic 18,308 kg/hr (40,363 lb/hr) 232°C (450°F) 0.1 MPa (12.3 psia) 1 0

7 Tail Gas Recycle Compressor Centrifugal 13,878 kg/hr (30,597 lb/hr) 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 CO2 Compressor Integrally geared, multi-stage centrifugal 1,130 m3/min @ 15.3 MPa (39,900 scfm @ 2,215 psia) 4 1

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Gas Turbine Advanced F class 230 MW 2 0

2 Gas Turbine Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

3 Syngas Expansion Turbine/Generator Turbo Expander 49,759 kg/h (109,700 lb/h) 5.1 MPa (740 psia) Inlet 3.2 MPa (460 psia) Outlet 2 0

### Cost and Performance Baseline for Fossil Energy Plants

567 

## ACCOUNT 7 HRSG, DUCTING AND STACK

ACCOUNT 8 STEAM TURBINE GENERATOR AND AUXILIARIES

ACCOUNT 9 COOLING WATER SYSTEM

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS liner 76 m (250 ft) high x 8.5 m (28 ft) diameter 1 0

2 Heat Recovery Steam Generator Drum, multi-pressure with economizer section and integral deaerator Main steam - 198,270 kg/hr, 12.4 MPa/534°C (437,111 lb/hr, 1,800 psig/994°F) Reheat steam - 265,278 kg/hr, 3.1 MPa/534°C (584,838 lb/hr, 452 psig/994°F) 2 0

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Steam Turbine Commercially available advanced steam turbine 225 MW 12.4 MPa/534°C/534°C (1800 psig/ 994°F/994°F) 1 0

2 Steam Turbine Generator Hydrogen cooled, static excitiation 250 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 1 0

3 Steam Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

4 Surface Condenser Single pass, divided waterbox including vacuum pumps 1,593 GJ/hr (1,510 MMBtu/hr), Inlet water temperature 16°C (60°F), Water temperature rise 11°C (20°F) 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 Circulating Water Pumps Vertical, wet pit 484,533 lpm @ 30 m (128,000 gpm @ 100 ft) 2 1

2 Cooling Tower Evaporative,mechanical draft, multicell 11°C (51.5°F) wet bulb / 16°C (60°F) CWT / 27°C (80°F) HWT

/ 2690 GJ/hr (2550 MMBtu/hr) heat duty 1 0

### Cost and Performance Baseline for Fossil Energy Plants

568 

## ACCOUNT 10 SLAG RECOVERY AND HANDLING

Equipment No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 253,623 liters (67,000 gal) 2 0
2 Slag Crusher Roll 14 tonne/hr (15 tph) 2 0
3 Slag Depressurizer Lock Hopper 14 tonne/hr (15 tph) 2 0
4 Slag Receiving Tank Horizontal, weir 151,416 liters (40,000 gal) 2 0
5 Black Water Overflow Tank Shop fabricated 68,137 liters (18,000 gal) 2
6 Slag Conveyor Drag chain 14 tonne/hr (15 tph) 2 0
7 Slag Separation Screen Vibrating 14 tonne/hr (15 tph) 2 0
8 Coarse Slag Conveyor Belt/bucket 14 tonne/hr (15 tph) 2 0
9 Fine Ash Settling Tank Vertical, gravity 215,768 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 38 lpm @ 14 m H2O (10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 68,137 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 227 lpm @ 564 m H2O (60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 998 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 109 tonne/hr (120 tph) 1 0

### Cost and Performance Baseline for Fossil Energy Plants

569 

## ACCOUNT 11 ACCESSORY ELECTRIC PLANT

ACCOUNT 12 INSTRUMENTATION AND CONTROLS

Equipment No. Description Type Design Condition Operating Qty. Spares

1 CTG Step-up Transformer Oil-filled 24 kV/345 kV, 260 MVA, 3-ph, 60 Hz 2 0

2 STG Step-up Transformer Oil-filled 24 kV/345 kV, 250 MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary Transformer Oil-filled 345 kV/13.8 kV, 80 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Auxiliary Transformer Oil-filled 24 kV/4.16 kV, 48 MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct and Tap Bus Aluminum, self-cooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency shutdown 750 kW, 480 V, 3-ph, 60 Hz 1 0



### Equipment No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main Control Monitor/keyboard; Operator printer (laser color); Engineering printer (laser B&W) Operator stations/printers and engineering stations/printers 1 0

2 DCS - Processor Microprocessor with redundant input/output N/A 1 0

3 DCS - Data Highway Fiber optic Fully redundant, 25% spare 1 0

### Cost and Performance Baseline for Fossil Energy Plants

570 

## 8.1.4 The cost estimating methodology was described previously in Section Case 2 A

– Cost Estimating 2.7

. Exhibit 8

- 13 shows the TPC summary organized by cost account and Exhibit 8

- 14 shows a more detailed breakdown of the capital costs. Exhibit 8

- 15 shows the initial and annual O& M costs. The estimated TOC of the GEE gasifier with CO 2 

## capture in quench

- only configuration is $3,375/kW. Pr ocess contingency represents 3.4 percent of the TOC and project contingency represents 11.0 percent. The COE, including CO 2 

## TS& M costs of 5

. 8 mil ls/kWh, is 1 08

. 5 mills/kWh. For comparison, the TOC and COE for Case 2, GEE in radiant

- only configuration with CO 2 

## capture are $3,334/kW and 1 05

. 7 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

571 

## Exhibit 8

- 13 Case 2A Total Plant Cost Summary

Case: Case 2A - GEE Quench 495 MWnet IGCC w/ CO2 Plant Size: 493.9 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $14,279 $2,654 $11,074 $0 $0 $28,007 $2,542 $0 $6,110 $36,659 $74

2 COAL & SORBENT PREP & FEED $21,755 $4,448 $17,256 $0 $0 $43,459 $3,959 $1,577 $9,799 $58,794 $119

3 FEEDWATER & MISC. BOP SYSTEMS $8,849 $6,224 $9,449 $0 $0 $24,521 $2,324 $0 $6,359 $33,204 $67

4 GASIFIER & ACCESSORIES 4.1 Quench Gasifier System $66,598 $0 $57,069 $0 $0 $123,667 $11,556 $16,201 $23,572 $174,996 $354 4.2 Syngas Scrubber Sys. w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $472 4.4-4.9 Other Gasification Equipment $7,097 $2,671 $2,230 $0 $0 $11,999 $1,125 $0 $2,892 $16,016 $32 SUBTOTAL 4 $266,741 $2,671 $59,299 $0 $0 $328,712 $31,392 $16,201 $47,640 $423,945 $858

5A GAS CLEANUP & PIPING $97,698 $3,331 $82,513 $0 $0 $183,542 $17,795 $27,526 $45,888 $274,751 $556

5B CO2 COMPRESSION $18,242 $0 $11,182 $0 $0 $29,424 $2,834 $0 $6,452 $38,709 $78

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $262 6.2-6.9 Combustion Turbine Other $5,547 $887 $1,748 $0 $0 $8,182 $775 $0 $1,650 $10,607 $21 SUBTOTAL 6 $97,573 $887 $8,331 $0 $0 $106,791 $10,123 $9,861 $13,432 $140,206 $284

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,413 $3,652 $0 $4,206 $46,271 $94 7.2-7.9 SCR System, Ductwork and Stack $3,375 $2,406 $3,152 $0 $0 $8,933 $828 $0 $1,588 $11,350 $23 SUBTOTAL 7 $37,006 $2,406 $7,934 $0 $0 $47,346 $4,480 $0 $5,795 $57,621 $117

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $24,314 $0 $4,162 $0 $0 $28,476 $2,732 $0 $3,121 $34,329 $69 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $8,443 $830 $5,626 $0 $0 $14,898 $1,367 $0 $3,064 $19,330 $39 SUBTOTAL 8 $32,756 $830 $9,788 $0 $0 $43,374 $4,099 $0 $6,185 $53,659 $109

9 COOLING WATER SYSTEM $10,625 $10,049 $8,616 $0 $0 $29,290 $2,720 $0 $6,524 $38,535 $78

10 ASH/SPENT SORBENT HANDLING SYS $14,733 $8,238 $14,937 $0 $0 $37,909 $3,652 $0 $4,476 $46,037 $93

11 ACCESSORY ELECTRIC PLANT $31,380 $12,503 $24,392 $0 $0 $68,275 $5,874 $0 $14,086 $88,234 $179

12 INSTRUMENTATION & CONTROL $10,977 $2,019 $7,072 $0 $0 $20,068 $1,819 $1,003 $3,814 $26,704 $54

13 IMPROVEMENTS TO SITE $3,371 $1,987 $8,317 $0 $0 $13,675 $1,350 $0 $4,508 $19,533 $40

14 BUILDINGS & STRUCTURES $0 $6,539 $7,369 $0 $0 $13,909 $1,265 $0 $2,492 $17,666 $36

TOTAL COST $665,985 $64,787 $287,529 $0 $0 $1,018,301 $96,229 $56,168 $183,558 $1,354,257 $2,742

### Cost and Performance Baseline for Fossil Energy Plants

572 

## Exhibit 8

- 14 Case 2A Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,750 $0 $1,832 $0 $0 $5,582 $500 $0 $1,216 $7,299 $15 1.2 Coal Stackout & Reclaim $4,846 $0 $1,175 $0 $0 $6,020 $528 $0 $1,310 $7,858 $16 1.3 Coal Conveyors & Yd Crush $4,505 $0 $1,162 $0 $0 $5,668 $498 $0 $1,233 $7,398 $15 1.4 Other Coal Handling $1,179 $0 $269 $0 $0 $1,448 $127 $0 $315 $1,889 $4 1.5 Sorbent Receive & Unload $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.6 Sorbent Stackout & Reclaim $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.7 Sorbent Conveyors $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.8 Other Sorbent Handling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 1.9 Coal & Sorbent Hnd.Foundations $0 $2,654 $6,635 $0 $0 $9,289 $890 $0 $2,036 $12,215 $25 SUBTOTAL 1. $14,279 $2,654 $11,074 $0 $0 $28,007 $2,542 $0 $6,110 $36,659 $74 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0 $0 2.2 Prepared Coal Storage & Feed $1,602 $383 $251 $0 $0 $2,236 $191 $0 $485 $2,913 $6 2.3 Slurry Prep & Feed $19,273 $0 $12,273 $0 $0 $31,546 $2,874 $1,577 $7,199 $43,196 $87 2.4 Misc.Coal Prep & Feed $881 $641 $1,922 $0 $0 $3,443 $316 $0 $752 $4,512 $9 2.5 Sorbent Prep Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.6 Sorbent Storage & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $3,423 $2,811 $0 $0 $6,234 $577 $0 $1,362 $8,174 $17 SUBTOTAL 2. $21,755 $4,448 $17,256 $0 $0 $43,459 $3,959 $1,577 $9,799 $58,794 $119 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 Feedwater System $1,916 $3,291 $1,737 $0 $0 $6,944 $643 $0 $1,517 $9,105 $18 3.2 Water Makeup & Pretreating $744 $78 $416 $0 $0 $1,237 $118 $0 $406 $1,761 $4 3.3 Other Feedwater Subsystems $1,048 $354 $319 $0 $0 $1,722 $155 $0 $375 $2,252 $5 3.4 Service Water Systems $426 $876 $3,042 $0 $0 $4,343 $424 $0 $1,430 $6,197 $13 3.5 Other Boiler Plant Systems $2,284 $885 $2,193 $0 $0 $5,362 $509 $0 $1,174 $7,045 $14 3.6 FO Supply Sys & Nat Gas $315 $596 $556 $0 $0 $1,467 $141 $0 $322 $1,930 $4 3.7 Waste Treatment Equipment $1,040 $0 $634 $0 $0 $1,674 $163 $0 $551 $2,388 $5 3.8 Misc. Power Plant Equipment $1,076 $144 $552 $0 $0 $1,772 $171 $0 $583 $2,527 $5 SUBTOTAL 3. $8,849 $6,224 $9,449 $0 $0 $24,521 $2,324 $0 $6,359 $33,204 $67 4 GASIFIER & ACCESSORIES 4.1 Quench Gasifier System $66,598 $0 $57,069 $0 $0 $123,667 $11,556 $16,201 $23,572 $174,996 $354 4.2 Syngas Scrubber Sys. w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.3 ASU/Oxidant Compression $193,046 $0 w/equip. $0 $0 $193,046 $18,712 $0 $21,176 $232,934 $472 4.4 Low Temperature Cooling $7,097 $0 $0 $0 $0 $7,097 $671 $0 $1,554 $9,321 $19 4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Flare Stack System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Gasification Foundations $0 $2,671 $2,230 $0 $0 $4,902 $454 $0 $1,339 $6,695 $14 SUBTOTAL 4. $266,741 $2,671 $59,299 $0 $0 $328,712 $31,392 $16,201 $47,640 $423,945 $858

### Cost and Performance Baseline for Fossil Energy Plants

573 

## Exhibit 8

- 14 Case 2A Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

5A GAS CLEANUP & PIPING 5A.1 Double Stage Selexol $74,127 $0 $62,899 $0 $0 $137,026 $13,252 $27,405 $35,537 $213,219 $432 5A.2 Elemental Sulfur Plant $10,328 $2,058 $13,325 $0 $0 $25,712 $2,498 $0 $5,642 $33,851 $69 5A.3 Mercury Removal $1,372 $0 $1,044 $0 $0 $2,417 $233 $121 $554 $3,325 $7 5A.4 Shift Reactors $10,045 $0 $4,044 $0 $0 $14,089 $1,351 $0 $3,088 $18,527 $38 5A.5 Particulate Removal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5A.6 Blowback Gas Systems $1,826 $0 $346 $0 $0 $2,172 $265 $0 $487 $2,924 $6 5A.7 Fuel Gas Piping $0 $632 $443 $0 $0 $1,075 $100 $0 $235 $1,410 $3 5A.9 HGCU Foundations $0 $640 $413 $0 $0 $1,053 $97 $0 $345 $1,495 $3 SUBTOTAL 5A. $97,698 $3,331 $82,513 $0 $0 $183,542 $17,795 $27,526 $45,888 $274,751 $556 5B CO2 COMPRESSION 5B.1 CO2 Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5B.2 CO2 Compression & Drying $18,242 $0 $11,182 $0 $0 $29,424 $2,834 $0 $6,452 $38,709 $78 SUBTOTAL 5B. $18,242 $0 $11,182 $0 $0 $29,424 $2,834 $0 $6,452 $38,709 $78 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator $92,026 $0 $6,583 $0 $0 $98,609 $9,348 $9,861 $11,782 $129,599 $262 6.2 Syngas Expander $5,547 $0 $766 $0 $0 $6,313 $600 $0 $1,037 $7,951 $16 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $887 $982 $0 $0 $1,868 $175 $0 $613 $2,656 $5 SUBTOTAL 6. $97,573 $887 $8,331 $0 $0 $106,791 $10,123 $9,861 $13,432 $140,206 $284 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator $33,631 $0 $4,782 $0 $0 $38,413 $3,652 $0 $4,206 $46,271 $94 7.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $0 $1,730 $1,234 $0 $0 $2,964 $260 $0 $645 $3,869 $8 7.4 Stack $3,375 $0 $1,268 $0 $0 $4,643 $445 $0 $509 $5,597 $11 7.9 HRSG, Duct & Stack Foundations $0 $676 $649 $0 $0 $1,326 $123 $0 $435 $1,884 $4 SUBTOTAL 7. $37,006 $2,406 $7,934 $0 $0 $47,346 $4,480 $0 $5,795 $57,621 $117 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $24,314 $0 $4,162 $0 $0 $28,476 $2,732 $0 $3,121 $34,329 $69 8.2 Turbine Plant Auxiliaries $171 $0 $393 $0 $0 $564 $55 $0 $62 $681 $1 8.3 Condenser & Auxiliaries $4,853 $0 $1,425 $0 $0 $6,277 $600 $0 $688 $7,565 $15 8.4 Steam Piping $3,419 $0 $2,405 $0 $0 $5,825 $500 $0 $1,581 $7,906 $16 8.9 TG Foundations $0 $830 $1,403 $0 $0 $2,233 $212 $0 $733 $3,178 $6 SUBTOTAL 8. $32,756 $830 $9,788 $0 $0 $43,374 $4,099 $0 $6,185 $53,659 $109

### Cost and Performance Baseline for Fossil Energy Plants

574 

## Exhibit 8

- 14 Case 2A Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $7,359 $0 $1,339 $0 $0 $8,697 $828 $0 $1,429 $10,954 $22 9.2 Circulating Water Pumps $1,919 $0 $141 $0 $0 $2,060 $174 $0 $335 $2,569 $5 9.3 Circ.Water System Auxiliaries $160 $0 $23 $0 $0 $183 $17 $0 $30 $230 $0 9.4 Circ.Water Piping $0 $6,671 $1,729 $0 $0 $8,400 $759 $0 $1,832 $10,991 $22 9.5 Make-up Water System $400 $0 $572 $0 $0 $972 $93 $0 $213 $1,278 $3 9.6 Component Cooling Water Sys $787 $942 $670 $0 $0 $2,399 $225 $0 $525 $3,149 $6 9.9 Circ.Water System Foundations $0 $2,437 $4,143 $0 $0 $6,579 $624 $0 $2,161 $9,364 $19 SUBTOTAL 9. $10,625 $10,049 $8,616 $0 $0 $29,290 $2,720 $0 $6,524 $38,535 $78 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Slag Dewatering & Cooling $12,136 $6,692 $13,595 $0 $0 $32,423 $3,129 $0 $3,555 $39,107 $79 10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.5 Slag Handling System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $589 $0 $641 $0 $0 $1,229 $119 $0 $202 $1,551 $3 10.7 Ash Transport & Feed Equipment $790 $0 $190 $0 $0 $980 $91 $0 $161 $1,232 $2 10.8 Misc. Ash Handling Equipment $1,219 $1,494 $446 $0 $0 $3,160 $301 $0 $519 $3,980 $8 10.9 Ash/Spent Sorbent Foundation $0 $52 $65 $0 $0 $117 $11 $0 $39 $167 $0 SUBTOTAL 10. $14,733 $8,238 $14,937 $0 $0 $37,909 $3,652 $0 $4,476 $46,037 $93 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $909 $0 $899 $0 $0 $1,809 $173 $0 $198 $2,179 $4 11.2 Station Service Equipment $4,668 $0 $421 $0 $0 $5,089 $469 $0 $556 $6,114 $12 11.3 Switchgear & Motor Control $8,630 $0 $1,570 $0 $0 $10,199 $946 $0 $1,672 $12,817 $26 11.4 Conduit & Cable Tray $0 $4,009 $13,225 $0 $0 $17,234 $1,667 $0 $4,725 $23,626 $48 11.5 Wire & Cable $0 $7,660 $5,033 $0 $0 $12,693 $922 $0 $3,404 $17,018 $34 11.6 Protective Equipment $0 $686 $2,496 $0 $0 $3,182 $311 $0 $524 $4,017 $8 11.7 Standby Equipment $226 $0 $221 $0 $0 $446 $43 $0 $73 $562 $1 11.8 Main Power Transformers $16,946 $0 $137 $0 $0 $17,084 $1,292 $0 $2,756 $21,132 $43 11.9 Electrical Foundations $0 $149 $391 $0 $0 $540 $52 $0 $177 $769 $2 SUBTOTAL 11. $31,380 $12,503 $24,392 $0 $0 $68,275 $5,874 $0 $14,086 $88,234 $179 12 INSTRUMENTATION & CONTROL 12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $1,084 $0 $724 $0 $0 $1,807 $171 $90 $310 $2,379 $5 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $249 $0 $160 $0 $0 $409 $39 $20 $94 $561 $1 12.7 Computer & Accessories $5,780 $0 $185 $0 $0 $5,965 $548 $298 $681 $7,492 $15 12.8 Instrument Wiring & Tubing $0 $2,019 $4,128 $0 $0 $6,147 $521 $307 $1,744 $8,720 $18 12.9 Other I & C Equipment $3,864 $0 $1,876 $0 $0 $5,740 $540 $287 $985 $7,552 $15 SUBTOTAL 12. $10,977 $2,019 $7,072 $0 $0 $20,068 $1,819 $1,003 $3,814 $26,704 $54

### Cost and Performance Baseline for Fossil Energy Plants

575 

## Exhibit 8

- 14 Case 2A Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $106 $2,261 $0 $0 $2,366 $235 $0 $780 $3,382 $7 13.2 Site Improvements $0 $1,881 $2,500 $0 $0 $4,381 $432 $0 $1,444 $6,257 $13 13.3 Site Facilities $3,371 $0 $3,557 $0 $0 $6,928 $683 $0 $2,283 $9,894 $20 SUBTOTAL 13. $3,371 $1,987 $8,317 $0 $0 $13,675 $1,350 $0 $4,508 $19,533 $40 14 BUILDINGS & STRUCTURES 14.1 Combustion Turbine Area $0 $265 $150 $0 $0 $414 $36 $0 $90 $541 $1 14.2 Steam Turbine Building $0 $2,096 $2,986 $0 $0 $5,081 $468 $0 $832 $6,381 $13 14.3 Administration Building $0 $862 $625 $0 $0 $1,487 $132 $0 $243 $1,863 $4 14.4 Circulation Water Pumphouse $0 $162 $86 $0 $0 $247 $22 $0 $40 $310 $1 14.5 Water Treatment Buildings $0 $622 $606 $0 $0 $1,228 $111 $0 $201 $1,540 $3 14.6 Machine Shop $0 $441 $302 $0 $0 $743 $66 $0 $121 $930 $2 14.7 Warehouse $0 $712 $460 $0 $0 $1,172 $104 $0 $191 $1,467 $3 14.8 Other Buildings & Structures $0 $427 $332 $0 $0 $759 $68 $0 $165 $992 $2 14.9 Waste Treating Building & Str. $0 $954 $1,823 $0 $0 $2,776 $259 $0 $607 $3,642 $7 SUBTOTAL 14. $0 $6,539 $7,369 $0 $0 $13,909 $1,265 $0 $2,492 $17,666 $36

TOTAL COST $665,985 $64,787 $287,529 $0 $0 $1,018,301 $96,229 $56,168 $183,558 $1,354,257 $2,742
Owner's Costs Preproduction Costs 6 Months All Labor $12,023 $24 1 Month Maintenance Materials $2,632 $5 1 Month Non-fuel Consumables $400 $1 1 Month Waste Disposal $318 $1 25% of 1 Months Fuel Cost at 100% CF $1,697 $3 2% of TPC $27,085 $55 Total $44,154 $89 Inventory Capital 60 day supply of fuel and consumables at 100% CF $14,085 $29 0.5% of TPC (spare parts) $6,771 $14 Total $20,856 $42
Initial Cost for Catalyst and Chemicals $7,292 $15 Land $900 $2 Other Owner's Costs $203,139 $411

Financing Costs $36,565 $74 Total Overnight Costs (TOC) $1,667,163 $3,375 TASC Multiplier (IOU, high-risk, 35 year) 1.140 Total As-Spent Cost (TASC) $1,900,566 $3,848

### Cost and Performance Baseline for Fossil Energy Plants

576 

## Exhibit 8

- 15 Case 2A Initial and Annual Operating and Maintenance Costs
INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 2A - GEE Quench 495 MWnet IGCC w/ CO2 Heat Rate-net (Btu/kWh): 11,502 MWe-net: 494 Capacity Factor (%): 80 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Skilled Operator 2.0 2.0 Operator 10.0 10.0 Foreman 1.0 1.0 Lab Tech's, etc. 3.0 3.0 TOTAL-O.J.'s 16.0 16.0 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,313,507 $12.782 Maintenance Labor Cost $12,922,767 $26.163 Administrative & Support Labor $4,809,068 $9.736 Property Taxes and Insurance $27,085,142 $54.835 TOTAL FIXED OPERATING COSTS $51,130,484 $103.516 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $25,263,935 $0.00730

Consumables Consumption Unit Initial Fill Initial Fill /Day Cost Cost Water (/1000 gallons) 0 4,404 1.08 $0 $1,391,076 $0.00040
Chemicals

MU & WT Chem. (lbs) 0 26,239 0.17 $0 $1,326,020 $0.00038 Carbon (Mercury Removal) (lb) 79,195 108 1.05 $83,168 $33,267 $0.00001 COS Catalyst (m3) 0 0 2,397.36 $0 $0 $0.00000 Water Gas Shift Catalyst (ft3) 6,443 4.41 498.83 $3,213,847 $642,769 $0.00019 Selexol Solution (gal) 298,200 95 13.40 $3,995,355 $371,115 $0.00011 SCR Catalyst (m3) 0 0 0.00 $0 $0 $0.00000 Ammonia (19% NH3) (ton) 0 0 0.00 $0 $0 $0.00000 Claus Catalyst (ft3) w/equip 2.01 131.27 $0 $77,204 $0.00002 Subtotal-Chemicals $7,292,370 $2,450,376 $0.00071
Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 Gases, N2 etc. (/100scf) 0 0 0.00 $0 $0 $0.00000 L.P. Steam (/1000 pounds) 0 0 0.00 $0 $0 $0.00000 Subtotal-Other $0 $0 $0.00000 Waste Disposal

Spent Mercury Catalyst (lb.) 0 108 0.42 $0 $13,212 $0.00000 Flyash (ton) 0 0 0.00 $0 $0 $0.00000 Slag (ton) 0 641 16.23 $0 $3,037,649 $0.00088 Subtotal Waste Disposal $0 $3,050,861 $0.00088 By-products & Emissions

Sulfur (ton) 0 146 0.00 $0 $0 $0.00000 Subtotal By-products $0 $0 $0.00000
TOTAL VARIABLE OPERATING COSTS $7,292,370 $32,156,247 $0.00929

Fuel (ton) 0 5,844 38.18 $0 $65,156,652 $0.01882

### Cost and Performance Baseline for Fossil Energy Plants

577 

## 9.

Studies of PC plants with post combustion capture of CO 2 

## for the 2009 NETL Bituminous and Low Rank Baselines Studies are based on a performance and cost estimate for an Econamine CO 2 

## capture system provided by Fluor in 2005 [ SENSITIVITY TO MEA S YSTEM PERFORMANCE AN D COST BITUMINOUS BASELINE CASE 12A

87 ]

. A recent Fluor pu blication [ 88

The Fluor publication [ ] indicates that Fluor has improved the Econamine system. According to Fluor, the improved system is able to achieve a reboiler steam requirement of 1,270 Btu/lb CO 2 

## as compared to the 1,530 Btu/lb CO 2 

## used in the baseline studies. Fluor also i ndicated concurrent reductions in auxiliary electrical power requirements and capital costs. 88 ] indicates the improvements in performance and cost are enabled by an improved solvent formulation with an MEA concentration greater than 30 percent and improved corrosion inhibitors. Fluor states that the improved solvent results in increased reaction r ates enabling less absorber packing and lower capital cost. Also, the higher solvent carrying capacity results in lower solvent circulation rates, lower steam requirements, and lower capital cost of solvent circulation equipment. C ost and performance data on the improved system were unavailable directly from Fluor. Using a commercial AGR software package, the CO 2 

## removal process was simulate d using higher MEA concentrations, but the confiden ce in the generated results and any associated equipment sizing o r costing changes were not adequate for use in this analysis. Therefore, a sensitivity analysis was performed using published data from Fluor and best engineering judgment to estimate the impact of an improved MEA CO 2 

## capture system on the performance and cost of a SC boiler firing bituminous coal with back

- end CO 2 

## capture.
9.1 BASIS FOR SENSITIVIT Y ANALYSIS The sensitivity analysis was performed on Case 12 of the Bituminous Baseline Study. This case used a SC PC plant burning bituminous (Illinois #6) coal at ISO conditions. The sensitivity case was labeled Case 12A. It was assumed, based on qualitative statements by Fluor, that the improved performance and reduced cost were achieved by increasing the MEA concentration from 30 wt% to 36 wt%. It was further assumed that Econamine reboiler steam requirements, power requirements and capital cost were inversely proportional to the increase in MEA concentration. The reboiler steam requirement and electrical auxiliary requirements were reduced by the ratio o f 30 /36 = 0.83. The Econamine plant capital cost was scaled using two factors

- the first based on the amount of CO 2 

## capture d to the 0.6 power and the second based on the ratio of the increased solvent concentration to the 0.7 power

. The Aspen model for Case 12 was modified for the reduced reboiler steam requirement and calculations were adjusted for the reduced auxiliary power requirement. Performance and cost estimates for Case 12A as compared to Case 12 are included in the following sections.
9.2 PERFORMANCE The BFD , Stream Tables and Performance Summary for Case 12A are shown in Exhibit 9

- 1 , Exhibit 9

- 2 , and Exhibit 9

- 3 . The Performance Summary from Case 12 is also included in

### Cost and Performance Baseline for Fossil Energy Plants

578 

## Exhibit 9

- 3 for comparison. The net plant efficiency for Case 12A is 29.8 percent compared to 28.4 percent for Case 12. The auxiliary power for Case 12A is 104 MW compared to 113 MW for Case 12. Gross output was reduced for Case 12A by 9 MW to maintain a 550 MW net output for both cases. The reduction in auxiliary power results primarily from reductions in the Econamine and CO 2 

## compressor auxiliaries with minor reductions in most other auxiliary loads resulting from a slightly smaller gross plant size.

### Cost and Performance Baseline for Fossil Energy Plants

579 

## Exhibit 9

- 1 Case 12A Block Flow Diagram , Su per critical Unit with CO 2 

## Capture (MEA Sensitivity)

### Cost and Performance Baseline for Fossil Energy Plants

580 

## Exhibit 9

- 2 Case 12A Stream Table , Su per critical Unit with CO 2 

## Capture
1 2 3 4 5 6 7 8 9 10 11 12 13 14 V-L Mole Fraction

Ar 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0092 0.0000 0.0000 0.0087 0.0000 0.0087 0.0087 0.0000 CO 2 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0003 0.0000 0.0000 0.1450 0.0000 0.1450 0.1450 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0099 0.0000 0.0000 0.0870 0.0000 0.0870 0.0870 1.0000 N 2 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.7732 0.0000 0.0000 0.7324 0.0000 0.7324 0.7324 0.0000 O 2 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.2074 0.0000 0.0000 0.0247 0.0000 0.0247 0.0247 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0021 0.0000 0.0021 0.0021 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 63,824 63,824 1,899 19,606 19,606 2,690 1,475 0 0 89,812 0 89,812 89,812 3,349 V-L Flowrate (kg/hr) 1,841,767 1,841,767 54,801 565,772 565,772 77,613 42,569 0 0 2,671,294 0 2,671,294 2,671,294 60,334 Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 244,938 4,750 19,001 19,001 0 0 24,719
Temperature (°C) 15 19 19 15 25 25 15 15 15 169 15 169 182 15 Pressure (MPa, abs) 0.10 0.11 0.11 0.10 0.11 0.11 0.10 0.10 0.10 0.10 0.10 0.10 0.11 0.10 Enthalpy (kJ/kg) A 30.23 34.36 34.36 30.23 40.78 40.78 30.23

--- --- 327.40

--- 308.96 322.83

--- Density (kg/m 3 ) 1.2 1.2 1.2 1.2 1.3 1.3 1.2

--- --- 0.8

--- 0.8 0.8

--- V-L Molecular Weight 28.857 28.857 28.857 28.857 28.857 28.857 28.857

--- --- 29.743

--- 29.743 29.743

--- V-L Flowrate (lb mol /hr) 140,708 140,708 4,187 43,224 43,224 5,930 3,252 0 0 198,001 0 198,001 198,001 7,383 V-L Flowrate (lb/hr) 4,060,401 4,060,401 120,816 1,247,313 1,247,313 171,108 93,850 0 0 5,889,196 0 5,889,196 5,889,196 133,014 Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 539,995 10,472 41,890 41,890 0 0 54,497
Temperature (°F) 59 66 66 59 78 78 59 59 59 337 59 337 360 59 Pressure (psia) 14.7 15.3 15.3 14.7 16.1 16.1 14.7 14.7 14.7 14.4 14.7 14.2 15.4 15.0 Enthalpy (Btu/lb) A 13.0 14.8 14.8 13.0 17.5 17.5 13.0

--- --- 140.8

--- 132.8 138.8

--- Density (lb/ft 3 ) 0.076 0.078 0.078 0.076 0.081 0.081 0.076

--- --- 0.050

--- 0.049 0.052

--- A - Reference conditions are 32.02 F & 0.089 PSIA

### Cost and Performance Baseline for Fossil Energy Plants

581 

## Exhibit 9

- 2 Case 12A Stream Table , Su per critical Unit with CO 2 

## Capture (Continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 V-L Mole Fraction

Ar 0.0000 0.0128 0.0000 0.0081 0.0108 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 CO 2 0.0000 0.0005 0.0004 0.1351 0.0179 0.9961 0.9985 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 H 2 O 1.0000 0.0062 0.9996 0.1537 0.0383 0.0039 0.0015 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 N 2 0.0000 0.7506 0.0000 0.6793 0.9013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 O 2 0.0000 0.2300 0.0000 0.0238 0.0316 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 SO 2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000
V-L Flowrate (kg mol /hr) 12,734 913 236 97,848 73,741 11,940 11,911 35,621 35,621 120,750 98,499 98,499 53,856 53,856 V-L Flowrate (kg/hr) 229,411 26,510 4,260 2,821,044 2,077,415 524,270 523,755 641,731 641,731 2,175,344 1,774,495 1,774,495 970,240 970,240 Solids Flowrate (kg/hr) 0 0 38,244 0 0 0 0 0 0 0 0 0 0 0
Temperature (°C) 15 181 58 58 32 21 35 291 151 593 354 593 38 39 Pressure (MPa, abs) 0.10 0.31 0.10 0.10 0.10 0.16 15.27 0.51 0.92 24.23 4.90 4.52 0.01 1.69 Enthalpy (kJ/kg) A -46.80 191.58

--- 301.42 93.86 19.49 -211.71 3,045.10 636.31 3,476.62 3,081.96 3,652.22 2,111.17 166.38 Density (kg/m 3 ) 1,003.1 2.4

--- 1.1 1.1 2.9 795.9 2.0 916.0 69.2 18.7 11.6 0.1 993.2 V-L Molecular Weight 18.015 29.029

--- 28.831 28.172 43.908 43.971 18.015 18.015 18.015 18.015 18.015 18.015 18.015
V-L Flowrate (lb mol /hr) 28,074 2,013 521 215,717 162,571 26,323 26,260 78,532 78,532 266,208 217,154 217,154 118,733 118,733 V-L Flowrate (lb/hr) 505,766 58,445 9,392 6,219,337 4,579,917 1,155,818 1,154,682 1,414,774 1,414,774 4,795,812 3,912,091 3,912,091 2,139,012 2,139,012 Solids Flowrate (lb/hr) 0 0 84,314 0 0 0 0 0 0 0 0 0 0 0
Temperature (°F) 59 357 136 136 89 69 95 556 304 1,100 669 1,100 101 103 Pressure (psia) 14.7 45.0 14.9 14.9 14.7 23.5 2,214.5 73.5 133.6 3,514.7 710.8 655.8 1.0 245.0 Enthalpy (Btu/lb) A -20.1 82.4

--- 129.6 40.4 8.4 -91.0 1,309.2 273.6 1,494.7 1,325.0 1,570.2 907.6 71.5 Density (lb/ft 3 ) 62.622 0.149

--- 0.067 0.070 0.184 49.685 0.123 57.184 4.319 1.165 0.722 0.004 62.004

### Cost and Performance Baseline for Fossil Energy Plants

582 

## Exhibit 9

- 3 Case 12A Plant Performance Summary POWER SUMMARY (Gross Power at Generator Terminals, kWe) Bituminous Baseline Case 12 12A Steam Turbine Power 662,800 654,200 TOTAL (STEAM TURBINE) POWER, kWe 662,800 654,200 AUXILIARY LOAD SUMMARY, kWe Coal Handling and Conveying 510 500 Pulverizers 3,850 3,670 Sorbent Handling & Reagent Preparation 1,250 1,190 Ash Handling 740 700 Primary Air Fans 1,800 1,720 Forced Draft Fans 2,300 2,190 Induced Draft Fans 11,120 10,610 SCR 70 60 Baghouse 100 90 Wet FGD 4,110 3,920 Econamine FG Plus Auxiliaries 20,600 16,400 CO 2 

## Compression 44,890 42,840 Miscellaneous Balance of Plant 2,3 

## 2,000 2,000 Steam Turbine Auxiliaries 400 400 Condensate Pumps 560 610 Circulating Water Pumps 10,100 9,390 Ground Water Pumps 920 850 Cooling Tower Fans 5,230 4,860 Transformer Losses 2,290 2,240 TOTAL AUXILIARIES, kWe 112,840 104,240 NET POWER, kWe 549,96 0 549 ,96 0 Net Plant Efficiency (HHV) 28.4 % 2 9.8 % Net Plant Heat Rate , kJ/kWh (Btu/kWh) 12,663 (12 , 002 ) 12,085 (11,455) CONDENSER COOLING DUTY, 10 6 

### kJ/h r (10 6 

### Btu/h r ) 

## 1,737 (1,646) 1,893 (1,794) CONSUMABLES As

- Received Coal Feed, kg/h r (lb/h r ) 256,652 (565,820) 244,938 (539,995) Limestone Sorbent Feed, kg/h r (lb/h r ) 25,966 (57,245) 24, 720 ( 54,497 ) Thermal Input, kWt 1 

## 1,934,519 1,846,224 Raw Water Withdrawal, m 3 

## /min (gpm) 38.1 (10,071 ) 35.4 (9,350) Raw Water Consumption, m 3 

## /min (gpm) 29.3 (7,733 ) 27.2 (7,177)
1. HHV of As

- Received Illinois No. 6 coal is 27,135 kJ/kg (11,666 Btu/lb) 2. Boiler feed pumps are turbine driven 3. Includes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

### Cost and Performance Baseline for Fossil Energy Plants

583 

## 9.3 COST ESTIMATING The cost estimating methodology was described in Section 2. 7 of this report. Exhibit 9

- 4 shows the TPC summary organized by cost account and Exhibit 9

- 5 shows a more detailed breakdown of the capital costs including the TOC and TASC. Exhibit 9

- 6 shows the initial and annual O&M costs. The TPC was estimated using a factored cost method with Case 12 as the reference. Account 5B.1 was scaled based on CO 2 

## captured to the 0.6 power and additionally reduced by 12 percent as discussed previ ously to account for capital cost reductions resulting from the reduced solvent circulation rate

. The estimated TOC for Case 12A is $3,364/kW. This represents a reduction from Case 12 of 6 percent . Process contingency represents 2.6 percent of the TOC an d project contingency represents 10.0 percent. The COE, including CO 2 

## TS&M cost s of 5

. 3 mills/kWh, is 1 00

. 8 mills/kWh. This COE is 5 .5 percent less than the Baseline Case 12 COE of 10 6

. 6 mills/kWh.

### Cost and Performance Baseline for Fossil Energy Plants

584 

## Exhibit 9

- 4 Case 12A Total Plant Cost Summary

Client: USDOE/NETL Report Date: 2010-Jan-14 Project: Bituminous Baseline Study

Case: Case 12A - 1x550 MWnet Super-Critical PC w/ CO2 Capture (MEA Sensitivity) Plant Size: 550.0 MW,net Estimate Type: Conceptual Cost Base (Jun) 2007 ($x1000)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

1 COAL & SORBENT HANDLING $19,514 $5,244 $11,671 $0 $0 $36,429 $3,268 $0 $5,955 $45,652 $83

2 COAL & SORBENT PREP & FEED $13,252 $772 $3,366 $0 $0 $17,391 $1,524 $0 $2,837 $21,753 $40

3 FEEDWATER & MISC. BOP SYSTEMS $52,950 $0 $24,940 $0 $0 $77,890 $7,138 $0 $13,939 $98,967 $180

4 PC BOILER 4.1 PC Boiler & Accessories $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4-4.9 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4 $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650

5 FLUE GAS CLEANUP $97,431 $0 $33,251 $0 $0 $130,682 $12,508 $0 $14,319 $157,509 $286

5B CO 2 REMOVAL & COMPRESSION $204,675 $0 $62,416 $0 $0 $267,091 $25,537 $46,378 $67,801 $406,807 $740

6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2-6.9 Combustion Turbine Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2-7.9 HRSG Accessories, Ductwork and Stack $17,413 $958 $11,797 $0 $0 $30,168 $2,764 $0 $4,326 $37,258 $68 SUBTOTAL 7 $17,413 $958 $11,797 $0 $0 $30,168 $2,764 $0 $4,326 $37,258 $68

8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $56,268 $0 $7,467 $0 $0 $63,735 $6,108 $0 $6,984 $76,827 $140 8.2-8.9 Turbine Plant Auxiliaries and Steam Piping $26,997 $1,189 $15,089 $0 $0 $43,276 $3,779 $0 $6,723 $53,778 $98 SUBTOTAL 8 $83,265 $1,189 $22,556 $0 $0 $107,010 $9,887 $0 $13,707 $130,605 $237

9 COOLING WATER SYSTEM $19,662 $9,537 $17,647 $0 $0 $46,846 $4,410 $0 $6,916 $58,171 $106

10 ASH/SPENT SORBENT HANDLING SYS $5,135 $163 $6,865 $0 $0 $12,163 $1,169 $0 $1,372 $14,705 $27

11 ACCESSORY ELECTRIC PLANT $24,767 $10,309 $29,247 $0 $0 $64,322 $5,686 $0 $8,780 $78,788 $143

12 INSTRUMENTATION & CONTROL $9,915 $0 $10,054 $0 $0 $19,969 $1,811 $998 $2,798 $25,575 $47

13 IMPROVEMENTS TO SITE $3,281 $1,886 $6,612 $0 $0 $11,779 $1,162 $0 $2,588 $15,529 $28

14 BUILDINGS & STRUCTURES $0 $24,540 $23,290 $0 $0 $47,830 $4,315 $0 $7,822 $59,967 $109

TOTAL COST $740,888 $54,598 $370,114 $0 $0 $1,165,600 $109,989 $47,376 $185,644 $1,508,610 $2,743 TOTAL PLANT COST SUMMARY

### Cost and Performance Baseline for Fossil Energy Plants

585 

## Exhibit 9

- 5 Case 12A Total Plant Cost Details

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 1 COAL & SORBENT HANDLING 1.1 Coal Receive & Unload $3,998 $0 $1,826 $0 $0 $5,823 $520 $0 $952 $7,295 $13 1.2 Coal Stackout & Reclaim $5,166 $0 $1,171 $0 $0 $6,337 $554 $0 $1,034 $7,925 $14 1.3 Coal Conveyors $4,803 $0 $1,158 $0 $0 $5,961 $522 $0 $973 $7,456 $14 1.4 Other Coal Handling $1,257 $0 $268 $0 $0 $1,525 $133 $0 $249 $1,907 $3 1.5 Sorbent Receive & Unload $163 $0 $49 $0 $0 $212 $19 $0 $35 $265 $0 1.6 Sorbent Stackout & Reclaim $2,625 $0 $481 $0 $0 $3,106 $270 $0 $506 $3,883 $7 1.7 Sorbent Conveyors $937 $203 $230 $0 $0 $1,369 $118 $0 $223 $1,710 $3 1.8 Other Sorbent Handling $566 $133 $297 $0 $0 $995 $88 $0 $162 $1,245 $2 1.9 Coal & Sorbent Hnd.Foundations $0 $4,909 $6,192 $0 $0 $11,101 $1,043 $0 $1,822 $13,966 $25 SUBTOTAL 1. $19,514 $5,244 $11,671 $0 $0 $36,429 $3,268 $0 $5,955 $45,652 $83 2 COAL & SORBENT PREP & FEED 2.1 Coal Crushing & Drying $2,315 $0 $451 $0 $0 $2,766 $241 $0 $451 $3,458 $6 2.2 Coal Conveyor to Storage $5,927 $0 $1,294 $0 $0 $7,221 $631 $0 $1,178 $9,030 $16 2.3 Coal Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.4 Misc.Coal Prep & Feed $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.5 Sorbent Prep Equipment $4,471 $193 $929 $0 $0 $5,593 $487 $0 $912 $6,991 $13 2.6 Sorbent Storage & Feed $539 $0 $206 $0 $0 $745 $66 $0 $122 $933 $2 2.7 Sorbent Injection System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.8 Booster Air Supply System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 2.9 Coal & Sorbent Feed Foundation $0 $579 $486 $0 $0 $1,066 $99 $0 $175 $1,339 $2 SUBTOTAL 2. $13,252 $772 $3,366 $0 $0 $17,391 $1,524 $0 $2,837 $21,753 $40 3 FEEDWATER & MISC. BOP SYSTEMS 3.1 FeedwaterSystem $22,174 $0 $7,163 $0 $0 $29,337 $2,564 $0 $4,785 $36,686 $67 3.2 Water Makeup & Pretreating $6,639 $0 $2,137 $0 $0 $8,776 $830 $0 $1,921 $11,526 $21 3.3 Other Feedwater Subsystems $6,789 $0 $2,869 $0 $0 $9,658 $865 $0 $1,578 $12,101 $22 3.4 Service Water Systems $1,301 $0 $708 $0 $0 $2,009 $189 $0 $440 $2,638 $5 3.5 Other Boiler Plant Systems $8,379 $0 $8,272 $0 $0 $16,651 $1,582 $0 $2,735 $20,968 $38 3.6 FO Supply Sys & Nat Gas $273 $0 $341 $0 $0 $613 $58 $0 $101 $772 $1 3.7 Waste Treatment Equipment $4,501 $0 $2,566 $0 $0 $7,066 $688 $0 $1,551 $9,305 $17 3.8 Misc. Equip.(cranes,AirComp.,Comm.) $2,894 $0 $884 $0 $0 $3,779 $363 $0 $828 $4,970 $9 SUBTOTAL 3. $52,950 $0 $24,940 $0 $0 $77,890 $7,138 $0 $13,939 $98,967 $180 4 PC BOILER 4.1 PC Boiler & Accessories $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650 4.2 SCR (w/4.1) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.3 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.4 Boiler BoP (w/ ID Fans) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 4.5 Primary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.6 Secondary Air System w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.8 Major Component Rigging $0 w/4.1 w/4.1 $0 $0 $0 $0 $0 $0 $0 $0 4.9 Boiler Foundations $0 w/14.1 w/14.1 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 4. $189,629 $0 $106,401 $0 $0 $296,030 $28,810 $0 $32,484 $357,324 $650

### Cost and Performance Baseline for Fossil Energy Plants

586 

## Exhibit 9

- 5 Case 12A Total Plant Cost Details ( C ontinued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW
5 FLUE GAS CLEANUP 5.1 Absorber Vessels & Accessories $67,660 $0 $14,566 $0 $0 $82,226 $7,839 $0 $9,006 $99,071 $180 5.2 Other FGD $3,531 $0 $4,001 $0 $0 $7,532 $731 $0 $826 $9,089 $17 5.3 Bag House & Accessories $19,454 $0 $12,346 $0 $0 $31,801 $3,065 $0 $3,487 $38,352 $70 5.4 Other Particulate Removal Materials $1,317 $0 $1,409 $0 $0 $2,725 $264 $0 $299 $3,289 $6 5.5 Gypsum Dewatering System $5,469 $0 $929 $0 $0 $6,398 $609 $0 $701 $7,708 $14 5.6 Mercury Removal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 5.9 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 5. $97,431 $0 $33,251 $0 $0 $130,682 $12,508 $0 $14,319 $157,509 $286 5B CO 2 REMOVAL & COMPRESSION 5B.1 CO 2 Removal System $177,879 $0 $54,009 $0 $0 $231,888 $22,171 $46,378 $60,087 $360,524 $656 5B.2 CO 2 Compression & Drying $26,796 $0 $8,406 $0 $0 $35,202 $3,367 $0 $7,714 $46,283 $84 SUBTOTAL 5B. $204,675 $0 $62,416 $0 $0 $267,091 $25,537 $46,378 $67,801 $406,807 $740 6 COMBUSTION TURBINE/ACCESSORIES 6.1 Combustion Turbine Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 6.2 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.3 Compressed Air Piping $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 6.9 Combustion Turbine Foundations $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SUBTOTAL 6. $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7 HRSG, DUCTING & STACK 7.1 Heat Recovery Steam Generator N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 7.2 HRSG Accessories $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 7.3 Ductwork $9,063 $0 $5,823 $0 $0 $14,886 $1,298 $0 $2,428 $18,611 $34 7.4 Stack $8,350 $0 $4,886 $0 $0 $13,236 $1,274 $0 $1,451 $15,962 $29 7.9 Duct & Stack Foundations $0 $958 $1,088 $0 $0 $2,046 $192 $0 $448 $2,685 $5 SUBTOTAL 7. $17,413 $958 $11,797 $0 $0 $30,168 $2,764 $0 $4,326 $37,258 $68 8 STEAM TURBINE GENERATOR 8.1 Steam TG & Accessories $56,268 $0 $7,467 $0 $0 $63,735 $6,108 $0 $6,984 $76,827 $140 8.2 Turbine Plant Auxiliaries $379 $0 $812 $0 $0 $1,191 $116 $0 $131 $1,438 $3 8.3 Condenser & Auxiliaries $5,837 $0 $2,151 $0 $0 $7,988 $765 $0 $875 $9,629 $18 8.4 Steam Piping $20,781 $0 $10,247 $0 $0 $31,028 $2,607 $0 $5,045 $38,680 $70 8.9 TG Foundations $0 $1,189 $1,879 $0 $0 $3,069 $290 $0 $672 $4,031 $7 SUBTOTAL 8. $83,265 $1,189 $22,556 $0 $0 $107,010 $9,887 $0 $13,707 $130,605 $237

### Cost and Performance Baseline for Fossil Energy Plants

587 

## Exhibit 9

- 5 Case 12A Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW 9 COOLING WATER SYSTEM 9.1 Cooling Towers $14,675 $0 $4,570 $0 $0 $19,245 $1,840 $0 $2,109 $23,194 $42 9.2 Circulating Water Pumps $3,023 $0 $233 $0 $0 $3,255 $275 $0 $353 $3,884 $7 9.3 Circ.Water System Auxiliaries $754 $0 $100 $0 $0 $854 $81 $0 $94 $1,029 $2 9.4 Circ.Water Piping $0 $5,974 $5,789 $0 $0 $11,763 $1,101 $0 $1,930 $14,794 $27 9.5 Make-up Water System $613 $0 $819 $0 $0 $1,433 $137 $0 $235 $1,805 $3 9.6 Component Cooling Water Sys $597 $0 $475 $0 $0 $1,072 $102 $0 $176 $1,350 $2 9.9 Circ.Water System Foundations& Structures $0 $3,563 $5,661 $0 $0 $9,224 $873 $0 $2,019 $12,116 $22 SUBTOTAL 9. $19,662 $9,537 $17,647 $0 $0 $46,846 $4,410 $0 $6,916 $58,171 $106 10 ASH/SPENT SORBENT HANDLING SYS 10.1 Ash Coolers N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.2 Cyclone Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.3 HGCU Ash Letdown N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.4 High Temperature Ash Piping N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.5 Other Ash Recovery Equipment N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 10.6 Ash Storage Silos $687 $0 $2,117 $0 $0 $2,804 $275 $0 $308 $3,387 $6 10.7 Ash Transport & Feed Equipment $4,448 $0 $4,556 $0 $0 $9,004 $861 $0 $986 $10,851 $20 10.8 Misc. Ash Handling Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 10.9 Ash/Spent Sorbent Foundation $0 $163 $192 $0 $0 $356 $33 $0 $78 $467 $1 SUBTOTAL 10. $5,135 $163 $6,865 $0 $0 $12,163 $1,169 $0 $1,372 $14,705 $27 11 ACCESSORY ELECTRIC PLANT 11.1 Generator Equipment $1,714 $0 $278 $0 $0 $1,993 $185 $0 $163 $2,341 $4 11.2 Station Service Equipment $4,791 $0 $1,574 $0 $0 $6,366 $595 $0 $522 $7,483 $14 11.3 Switchgear & Motor Control $5,508 $0 $936 $0 $0 $6,445 $597 $0 $704 $7,746 $14 11.4 Conduit & Cable Tray $0 $3,454 $11,941 $0 $0 $15,395 $1,490 $0 $2,533 $19,418 $35 11.5 Wire & Cable $0 $6,517 $12,580 $0 $0 $19,097 $1,609 $0 $3,106 $23,811 $43 11.6 Protective Equipment $261 $0 $888 $0 $0 $1,149 $112 $0 $126 $1,388 $3 11.7 Standby Equipment $1,352 $0 $31 $0 $0 $1,383 $127 $0 $151 $1,660 $3 11.8 Main Power Transformers $11,140 $0 $187 $0 $0 $11,327 $859 $0 $1,219 $13,405 $24 11.9 Electrical Foundations $0 $339 $830 $0 $0 $1,168 $112 $0 $256 $1,536 $3 SUBTOTAL 11. $24,767 $10,309 $29,247 $0 $0 $64,322 $5,686 $0 $8,780 $78,788 $143 12 INSTRUMENTATION & CONTROL 12.1 PC Control Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.2 Combustion Turbine Control N/A $0 N/A $0 $0 $0 $0 $0 $0 $0 $0 12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0 $0 12.4 Other Major Component Control $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0 $0 12.6 Control Boards,Panels & Racks $511 $0 $306 $0 $0 $816 $77 $41 $140 $1,074 $2 12.7 Distributed Control System Equipment $5,154 $0 $901 $0 $0 $6,055 $561 $303 $692 $7,611 $14 12.8 Instrument Wiring & Tubing $2,794 $0 $5,542 $0 $0 $8,336 $710 $417 $1,420 $10,883 $20 12.9 Other I & C Equipment $1,456 $0 $3,305 $0 $0 $4,761 $462 $238 $546 $6,007 $11 SUBTOTAL 12. $9,915 $0 $10,054 $0 $0 $19,969 $1,811 $998 $2,798 $25,575 $47

### Cost and Performance Baseline for Fossil Energy Plants

588 

## Exhibit 9

- 5 Case 12A Total Plant Cost Details (Continued)

Acct Equipment Material Labor Sales Bare Erected Eng'g CM Contingencies TOTAL PLANT COST No. Item/Description Cost Cost Direct Indirect Tax Cost $ H.O.& Fee Process Project $ $/kW

13 IMPROVEMENTS TO SITE 13.1 Site Preparation $0 $55 $1,103 $0 $0 $1,158 $115 $0 $255 $1,528 $3 13.2 Site Improvements $0 $1,831 $2,274 $0 $0 $4,105 $405 $0 $902 $5,411 $10 13.3 Site Facilities $3,281 $0 $3,235 $0 $0 $6,516 $642 $0 $1,432 $8,590 $16 SUBTOTAL 13. $3,281 $1,886 $6,612 $0 $0 $11,779 $1,162 $0 $2,588 $15,529 $28 14 BUILDINGS & STRUCTURES 14.1 Boiler Building $0 $8,791 $7,731 $0 $0 $16,522 $1,485 $0 $2,701 $20,708 $38 14.2 Turbine Building $0 $12,699 $11,836 $0 $0 $24,535 $2,211 $0 $4,012 $30,758 $56 14.3 Administration Building $0 $637 $673 $0 $0 $1,310 $119 $0 $214 $1,644 $3 14.4 Circulation Water Pumphouse $0 $168 $134 $0 $0 $302 $27 $0 $49 $378 $1 14.5 Water Treatment Buildings $0 $842 $768 $0 $0 $1,610 $145 $0 $263 $2,018 $4 14.6 Machine Shop $0 $426 $286 $0 $0 $712 $63 $0 $116 $892 $2 14.7 Warehouse $0 $289 $290 $0 $0 $578 $52 $0 $95 $725 $1 14.8 Other Buildings & Structures $0 $236 $201 $0 $0 $437 $39 $0 $71 $547 $1 14.9 Waste Treating Building & Str. $0 $452 $1,372 $0 $0 $1,825 $173 $0 $300 $2,298 $4 SUBTOTAL 14. $0 $24,540 $23,290 $0 $0 $47,830 $4,315 $0 $7,822 $59,967 $109

TOTAL COST $740,888 $54,598 $370,114 $0 $0 $1,165,600 $109,989 $47,376 $185,644 $1,508,610 $2,743 BEC, Categories 1-12 $1,105,992 Owner's Costs Preproduction Costs 6 Months All Labor $10,153 $18 1 Month Maintenance Materials $1,457 $3 1 Month Non-fuel Consumables $1,478 $3 1 Month Waste Disposal $309 $1 25% of 1 Months Fuel Cost at 100% CF $1,882 $3 2% of TPC $30,172 $55 Total $45,451 $83 Inventory Capital 60 day supply of fuel and consumables at 100% CF $18,151 $33 0.5% of TPC (spare parts) $7,543 $14 Total $25,694 $47
Initial Cost for Catalyst and Chemicals $2,383 $4 Land $900 $2 Other Owner's Costs $226,291 $411

Financing Costs $40,732 $74 Total Overnight Costs (TOC) $1,850,062 $3,364 TASC Multiplier (IOU, low risk, 35 year) 1.140 Total As-Spent Cost (TASC) $2,109,071 $3,835

### Cost and Performance Baseline for Fossil Energy Plants

589 

## Exhibit 9

- 6 Case 12A Initial and Annual Operating and Maintenance Costs
INITIAL & ANNUAL O&M EXPENSES Cost Base (Jun): 2007 Case 12A - 1x550 MWnet Super-Critical PC w/ CO2 Capture (MEA Sensitivity) Heat Rate-net (Btu/kWh): 11,455 MWe-net: 550 Capacity Factor (%): 85 OPERATING & MAINTENANCE LABOR Operating Labor Operating Labor Rate(base): 34.65 $/hour Operating Labor Burden: 30.00 % of base Labor O-H Charge Rate: 25.00 % of labor

Total Operating Labor Requirements(O.J.)per Shift: 1 unit/mod. Plant Skilled Operator 2.0 2.0 Operator 11.3 11.3 Foreman 1.0 1.0 Lab Tech's, etc. 2.0 2.0 TOTAL-O.J.'s 16.3 16.3 Annual Cost Annual Unit Cost $ $/kW-net Annual Operating Labor Cost $6,444,907 $11.719 Maintenance Labor Cost $9,800,561 $17.820 Administrative & Support Labor $4,061,367 $7.385 Property Taxes and Insurance $30,172,197 $54.863 TOTAL FIXED OPERATING COSTS $50,479,031 $91.787 VARIABLE OPERATING COSTS $/kWh-net Maintenance Material Cost $14,863,811 $0.00363

Consumables Consumption Unit Initial Initial /Day Cost Cost Water(/1000 gallons) 0 6,801 1.08 $0 $2,282,387 $0.00056
Chemicals MU & WT Chem.(lb) 0 32,922 0.17 $0 $1,767,714 $0.00043 Limestone (ton) 0 654 21.63 $0 $4,389,274 $0.00107 Carbon (Mercury Removal) (lb) 0 0 1.05 $0 $0 $0.00000 MEA Solvent (ton) 981 1.39 2,249.89 $2,208,132 $971,338 $0.00024 NaOH (tons) 69 6.93 433.68 $30,065 $932,782 $0.00023 H2SO4 (tons) 66 6.62 138.78 $9,181 $284,854 $0.00007 Corrosion Inhibitor 0 0 0.00 $135,751 $0 $0.00000 Activated Carbon(lb) 0 1,662 1.05 $0 $541,593 $0.00013 Ammonia (28% NH3) ton 0 97 129.80 $0 $3,904,140 $0.00095 Subtotal Chemicals $2,383,130 $12,791,695 $0.00312
Other

Supplemental Fuel (MBtu) 0 0 0.00 $0 $0 $0.00000 SCR Catalyst (m3) w/equip. 0.41 5,775.94 $0 $730,089 $0.00018 Emission Penalties 0 0 0.00 $0 $0 $0.00000 Subtotal Other $0 $730,089 $0.00018 Waste Disposal

Fly Ash (ton) 0 502 16.23 $0 $2,524,978 $0.00062 Bottom Ash (ton) 0 125 16.23 $0 $628,224 $0.00015

Subtotal-Waste Disposal $0 $3,153,202 $0.00077 By-products & Emissions

Gypsum (tons) 0 1,013 0.00 $0 $0 $0.00000 Subtotal By-Products $0 $0 $0.00000
TOTAL VARIABLE OPERATING COSTS $2,383,130 $33,821,185 $0.00826 Fuel(ton) 0 6,480 38.18 $0 $76,766,172 $0.01875

### Cost and Performance Baseline for Fossil Energy Plants

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## This page intentionally left blank

### Cost and Performance Baseline for Fossil Energy Plants

591 

## 10. The initial issue of this report was published on May 15, 2007. Subsequent to the issue date, updates have been made to various report sections. These additions were made for clarification and aesthetic purposes and to correct an error made in determinin g the Econamine cooling water requirement in the PC and NGCC CO 2 

## capture cases. The water balances and water consumption comparison exhibits were updated accordingly. In addition, the PC and NGCC energy balance tables contained errors , which have been co rrected in this version of the report. None of the changes affect the conclusions in version 1 of the report

. REVISION CONTROL

Th is second revision to this report includes more extensive changes. In the two years since the first version was released, improved modeling al gorithms were developed, additional vendor information became available and numerous minor errors were identified. S everal studies were initiated that build on the baseline results generated here. Th e studies include:

**•** Impact of parallel and dry cooling s ystems

**•** Performance of a GE IGCC with CO 2 

## capture operated in a quench only mode

**•** COE sensitivity to Econamine cost and reboiler steam requirements

**•** Natural gas price sensitivity analysis

**•** Impact of dispatch

- based CF s All of these studies are reported as supp lemental chapters to the original report. Because they were not part of the original study, they are not addressed in the Executive Summary or elsewhere throughout the report. Exhibit 10

- 1 contains information added, changed or deleted in successive revisions. Exhibit 10

- 1 Record of Revisions
Revision Number Revision Date Description of Change Comments

1 8/23/07 Added disclaimer to Executive Summary and Introduction Disclaimer involves clarification on extent of participation of technology vendors.

Removed reference to Cases 7 and 8 in Exhibits ES

- 1 and 1

- 1. SNG cases moved to Volume 2 of this report as explained in the Executive Summary and Section 1.

Added Section 2.8 Explains differences in IGCC TPC estimates in this study versus costs reported by other
sources.

### Cost and Performance Baseline for Fossil Energy Plants

592 

## Revision Number Revision Date Description of Change Comments

Added Exhibit ES

- 14 Mercury emissions are now shown in a separate exhibit from SO 2 

## , NOx and PM because of the different y

- axis scale.

Corrected PC and NGCC CO 2 

## capture case water balances The Econamine process cooling water requirement for the PC and NGCC CO 2 

## capture cases was overstated and has been revised.
Replaced Exhibits ES

- 4, 3

- 121, 4

- 52 and 5

- 30 The old water usage figures were in gpm (absolute) and in the new figures the water numbers are normalized by net plant output. Updated Selexol process description Text was added to Section 3.1.5 to describe how H 2 

## slip was handled in the models.

Revised PC and NGCC CO 2 

## capture case energy balances (Exhibits 4

- 21, 4

- 42 and 5

- 21) The earlier version of the energy balances improperly accounted for the Econamine process heat losses. The heat removed from the Econamine process is rejected to the cooling tower.

Corrected Exhibit 5

- 12 and Exhibit 5

- 23

. Sensible heat for combustion air in the two NGCC cases was for only one of the two
c ombustion turbines

– corrected to account for both turbines

2 10/ 27 /10 Updated circulating water flow rate values in Section 4.1.7

. Revision 1 changes to Econamine cooling water flow rate were not made in the text in Section 4.1.7 (Circulating Water System).
Added Supplmental Chapter 6 “Effect of Higher Natural Gas Prices and Dispatch

- Based Capacity Factors”

### Cost and Performance Baseline for Fossil Energy Plants

593 

## Revision Number Revision Date Description of Change Comments

Added Supplemental Chapter 7 “Dry and Parallel Cooling”

Added Supplemental Chapter 8 “GEE IGCC in Quench

- Only Configuration with CO 2 

## Capture”
Added Supplemental Chapter 9 “Sensitivity to MEA System Performance and Cost Bituminous Baseline Case 12A ”

Updated Aspen models Major Aspen model updates included:

**•** Converting FORTRAN code based steam cycles to Aspen blocks

**•** Using the Peng

- Robinson property method in the Aspen gasifier section

**•** Modifying the AGR used in the IGCC cases to more closely represent commercially available technology

**•** Increasing the capture efficiency of the CoP plant with capture to achieve 90 percent

**•** Correct ing a steam condition error in the supercritical PC cases with capture

Updated case performance results Major updates included:

**•** Revising the water balances to include withdrawal and consumption

**•** CAD

- based HMB diagrams were replaced with Visio versions

### Cost and Performance Baseline for Fossil Energy Plants

594 

## Revision Number Revision Date Description of Change Comments

Completed updating case economic results Major updates included:

**•** Adding owner’s costs to the total plant costs to generate total overnight cost

**•** Updating fuel costs

**•** Revising the TS&M methodology to include the July, 2007 Handy

- Whitman Index , pore space acquisition costs, and liability costs

**•** R e - costing of cases based on the updated performance results

**•** Switching to COE as the primary cost metric (as opposed to levelized COE) Updated report tables, figures and text to reflect the revision 2 changes

### Cost and Performance Baseline for Fossil Energy Plants

59 5 

## 11.

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