# Presentation: 340685

## Cost and Performance Baseline for Fossil Energy Plants

**Cost and Performance Baseline ****for Fossil Energy Plants**

**National Energy Technology Laboratory**

***May 15, 2007***
***Revised August 2007***

***Final Results***

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

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

## Objective

**Determine cost and performance estimates of near-term commercial offerings for power plants both with and without current technology for CO****2**** capture**
- Consistent design requirements
- Up-to-date performance and capital cost estimates
- Technologies built now and deployed by 2010-2012
**Provides baseline costs and performance **
- Compare existing technologies
- Guide R&D for advancing technologies within the FE Program

## Study Matrix

| Plant
Type | ST Cond.
(psig/°F/°F) | GT | Gasifier/
Boiler | Acid Gas Removal/
CO2 Separation / Sulfur Recovery | CO2
Cap |
| --- | --- | --- | --- | --- | --- |
| IGCC | 1800/1050/1050 (non-CO2 capture cases)

1800/1000/1000
(CO2 capture cases) | F Class | GE | Selexol / - / Claus |  |
|  |  |  |  | Selexol / Selexol / Claus | 90% |
|  |  |  | CoP
E-Gas | MDEA / - / Claus |  |
|  |  |  |  | Selexol / Selexol / Claus | 88%1 |
|  |  |  | Shell | Sulfinol-M / - / Claus |  |
|  |  |  |  | Selexol / Selexol / Claus | 90% |
| PC | 2400/1050/1050 |  | Subcritical | Wet FGD / - / Gypsum |  |
|  |  |  |  | Wet FGD / Econamine / Gypsum | 90% |
|  | 3500/1100/1100 |  | Supercritical | Wet FGD / - / Gypsum |  |
|  |  |  |  | Wet FGD / Econamine / Gypsum | 90% |
| NGCC | 2400/1050/950 | F Class | HRSG |  |  |
|  |  |  |  | - / Econamine / - | 90% |

- GEE – GE Energy
- CoP – Conoco Phillips

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

**Notes:**
Total 14 Cases.  3 Different gasifiers, subcritical and supercritical PC steam plants, Natural gas and SNG

## Design Basis: Coal Type

| Illinois #6 Coal Ultimate Analysis (weight %) |  |  |
| --- | --- | --- |
|  | As Rec’d | Dry |
| Moisture | 11.12 | 0 |
| Carbon | 63.75 | 71.72 |
| Hydrogen | 4.50 | 5.06 |
| Nitrogen | 1.25 | 1.41 |
| Chlorine | 0.29 | 0.33 |
| Sulfur | 2.51 | 2.82 |
| Ash | 9.70 | 10.91 |
| Oxygen (by difference) | 6.88 | 7.75 |
|  | 100.0 | 100.0 |
| HHV (Btu/lb) | 11,666 | 13,126 |

**Notes:**
Recent data from the Henry Hub Spot Price index indicate a natural gas price in the $8.80/MMBtu range.
This will have a tremendous affect on our results, since it is ~50% higher than our cost.
We should perform a sensitivity analysis of fuel price (including coal) vs. LCOE

## Environmental Targets

| Pollutant | IGCC1 | PC2 | NGCC3 |
| --- | --- | --- | --- |
| SO2 | 0.0128 lb/MMBtu | 0.085 lb/MMBtu | < 0.6 gr S /100 scf |
| NOx | 15 ppmv (dry) @ 15% O2 | 0.07   lb/MMBtu | 2.5 ppmv @ 15% O2 |
| PM | 0.0071 lb/MMBtu | 0.017 lb/MMBtu | Negligible |
| Hg | > 90% capture | 1.14       lb/TBtu | Negligible |

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

## Economic Assumptions

**Economic Assumptions**

**Startup****	****	****	****	****              2010**
**Plant Life (Years)****	****	****	****    20 **
**Capital Charge Factor, % **
**     ****High Risk **
**     ****(All IGCC, PC/NGCC with CO****2**** capture)****	**** 17.5**
**     ****Low Risk**
**     ****(PC/NGCC without CO****2**** capture)             16.4****	**** ****	****	****  **
**Dollars (Constant)****	****	****	**** 2007**
**Coal ($/MM Btu)****	****	****	****	****  1.80**
**Natural Gas ($/MM Btu)****	****	****	****  6.75**
**Capacity Factor**
**     ****IGCC****	****	****	****	****	****     80****	**
**     ****PC/NGCC****	****	****	****	****     85**

**Notes:**
No fancy economic tricks employed.  
Showing that assumptions are ‘in-line’ with what makes sense and what studies have reported.  
Further detailed assumptions are available and a detailed list can be provided for each case.  (I will have a list case by case assumptions on hand or will take peoples information and send them the details).
Grassroots plant unless noted otherwise

## Technical Approach

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

**2.  **_**Cost Estimation**_
-  **Inputs from process simulation** (Flow Rates/Gas Composition/Pressure/Temp.)
-  **Sources for cost estimation **
- Parsons
- Vendor sources where available
-  **Follow DOE Analysis Guidelines**

## Study Assumptions

**Capacity Factor assumed to equal Availability**
-  IGCC capacity factor = 80% w/ no spare gasifier
-  PC and NGCC capacity factor = 85%
**GE gasifier operated in radiant/quench mode**
**Shell gasifier with CO****2**** capture used water injection for cooling (instead of syngas recycle)**
**Nitrogen dilution was used to the maximum extent possible in all IGCC cases and syngas humidification/steam injection were used only if necessary to achieve approximately 120 Btu/scf syngas LHV**
**In CO****2**** capture cases, CO****2**** was compressed to 2200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,055 feet and monitored for 80 years**
**CO****2**** transport, storage and monitoring (TS&M) costs were included in the levelized cost of electricity (COE)**

## IGCC Power Plant

Current State-of-the-Art

***Current State-of-the-Art***

## Current TechnologyIGCC Power Plant

**Current Technology*****IGCC Power Plant***

***Emission Controls:***
_**PM:**_     Water scrubbing and/or candle filters to get 0.0071 lb/MMBtu
_**NOx:**_   N2 dilution to ~120 Btu/scf LHV to get **15 ppmv** @15% O2
_**SOx:**_   AGR design target of 0.0128 lb/MMBtu; Claus plant with tail gas recycle for ~99.8% overall S recovery
_**Hg:**_      Activated carbon beds for ~95% removal
_**Advanced F-Class CC Turbine:**_** **232 MWe
_**Steam Conditions:**_
- 	1800 psig/1050°F/1050°F (non-CO2 capture cases)
- 	1800 psig/1000°F/1000°F (CO2 capture cases)

**Notes:**
Three Additional Processes
CO2 Pressure Loss
Thermal Efficiency Loss 
     *Syngas Cooling

## GE Energy Radiant

**Coal Slurry**
**63 wt.%**

**95% O****2**

**Slag/Fines**

**Syngas **
- 410°F, 800 Psia
- _Composition (Mole%):_
- H2           26%
- CO         27%
- CO2        12%
- H2O        34%
- Other        1%
**H****2****O/CO = 1.3**

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

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

**To Acid Gas Removal**
**or**
**To Shift**

**Notes:**
Gasifier Sweet Cold Gas Efficiency ~75% HHV
Radiant Syngas Cooler w/ Quench/Scrubber @ outlet

## ConocoPhillips E-GasTM

**Coal Slurry**
**63 wt. %**

**Stage 2**

**95 % O****2**

**Slag Quench**

**Char**

**Slag/Water Slurry**

**Syngas**

**Syngas**
- 1,700°F, 614 psia
- _Composition (Mole%):_
- H2           26%
- CO         37%
- CO2        14%
- H2O        15%
- CH4          4%
- Other       4%
**H****2****O/CO = 0.4**

**(0.78)**

**(0.22)**

**Stage 1**
**2,500****o****F**
**614 Psia**

**To Fire-tube boiler**

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

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

**To Acid Gas Removal**
**or**
**To Shift**

**Notes:**
E-Gas (formerly Destec) coal gasifier is a slurry-fed, pressurized, up-flow, entrained two-stage slagging gasification process
About 75% of the coal is injected into stage 1.  

## Shell Gasification

**Shell Gasification**

**Syngas**
- 350°F, 600 Psia
- _Composition (Mole%):_
- H2           29%
- CO         57%
- CO2           2%
- H2O          4%
- Other       8%
**H****2****O/CO = 0.1**

**Dry**
**Coal**

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

**Convective Cooler**
**Soot Quench**
**& Scrubber**

**95% O****2**

**HP Steam**

**650****o****F**

**Steam**

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

**Syngas Quench****2**

_**Notes**_:
- All gasification performance data estimated by the project team to be representative of Shell gasifier.
- CO2 capture incorporates full water quench instead of syngas quench.

**To Acid Gas Removal**
**or**
**To Shift**

**HP Steam**

**Slag**

**Gasifier**
**2,700****o****F**
**615 psia**

## IGCC Performance ResultsNo CO2 Capture

|  | GE Energy | E-Gas | Shell |
| --- | --- | --- | --- |
| Gross Power (MW) | 770 | 742 | 748 |
| Auxiliary Power (MW) |  |  |  |
| Base Plant Load | 23 | 25 | 21 |
| Air Separation Unit | 103 | 91 | 90 |
| Gas Cleanup | 4 | 3 | 1 |
| Total Aux. Power (MW) | 130 | 119 | 112 |
| Net Power (MW) | 640 | 623 | 636 |
| Heat Rate (Btu/kWh) | 8,922 | 8,681 | 8,304 |
| Efficiency (HHV) | 38.2 | 39.3 | 41.1 |

## IGCC Economic ResultsNo CO2 Capture

|  | GE Energy | E-Gas | Shell |
| --- | --- | --- | --- |
| Plant Cost ($/kWe)1 |  |  |  |
| Base Plant | 1,323 | 1,272 | 1,522 |
| Air Separation Unit | 287 | 264 | 256 |
| Gas Cleanup | 203 | 197 | 199 |
| Total Plant Cost ($/kWe) | 1,813 | 1,733 | 1,977 |
|  |  |  |  |
| Capital COE (¢/kWh) | 4.53 | 4.33 | 4.94 |
| Variable COE (¢/kWh) | 3.27 | 3.20 | 3.11 |
| Total COE2 (¢/kWh) | 7.80 | 7.53 | 8.05 |

- 1Total Plant Capital Cost (Includes contingencies and engineering fees)
- 2January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/106Btu

## IGCC Power Plant
With CO2 Capture

**With CO****2**** Capture**

## Current TechnologyIGCC Power Plant with CO2 Scrubbing

**Current Technology*****IGCC Power Plant with CO******2****** Scrubbing***

***Emission Controls:***
_**PM:**_     Water scrubbing and/or candle filters to get 0.007 lb/MMBtu
_**NOx:**_   N2 dilution to ~120 Btu/scf LHV to get **15 ppmv** @15% O2
_**SOx:**_   Selexol AGR removal of sulfur to < **28 ppmv **H2S in syngas
-    Claus plant with tail gas recycle for ~99.8% overall S recovery
_**Hg:**_      Activated carbon beds for ~95% removal
_**Advanced F-Class CC Turbine:**_** **232 MWe
_**Steam Conditions:**_** **1800 psig/1000°F/1000°F

**Notes:**
Three Additional Processes
CO2 Pressure Loss
Thermal Efficiency Loss 
     *Syngas Cooling
Why is the reheat for the steam cycle for the CO2 Capture cases only 1000F instead of 1050F?

## Water-Gas Shift Reactor System

**Water-Gas Shift Reactor System**

| H2O/CO Ratio1 |  |
| --- | --- |
| GE | 1.3 |
| E-Gas  | 0.4 |
| Shell | 1.5 |

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

**775****o****F**

**450****o****F**

**500****o****F**

**450****o****F**

**Cooling**

|  | Relative HP* Steam Flow | Steam Turbine Output (MW) |
| --- | --- | --- |
| GE | 1.0 | 275 |
| E-Gas  | 2.4 | 230 |
| Shell | 0.9 | 230 |

**455****o****F**

**Steam**

**Steam**

**H****2****O + CO****	****CO****2**** + H****2**

- *High Pressure Steam

- 1 Prior to shift steam addition

**Notes:**
Add approximate shift cost (total and % of total cost and capture cost).
Add steam producing arrows.

## IGCC Performance Results

|  | GE Energy |  |
| --- | --- | --- |
| CO2 Capture | NO | YES |
| Gross Power (MW) | 770 | 745 |
| Auxiliary Power (MW) |  |  |
| Base Plant Load | 23 | 23 |
| Air Separation Unit | 103 | 121 |
| Gas Cleanup/CO2 Capture | 4 | 18 |
| CO2 Compression | - | 27 |
| Total Aux. Power (MW) | 130 | 189 |
| Net Power (MW) | 640 | 556 |
| Heat Rate (Btu/kWh) | 8,922 | 10,505 |
| Efficiency (HHV) | 38.2 | 32.5 |
| Energy Penalty1 | - | 5.7 |

- _1__CO__2__ Capture Energy Penalty_  = Percent points decrease in net power plant efficiency due to CO2 Capture

****** ****in ASU air comp. load w/o CT integration**

**Steam for Selexol**

**Includes H****2****S/CO****2**** Removal in Selexol Solvent**

## IGCC Performance Results

|  | GE Energy |  | E-Gas |  | Shell |  |
| --- | --- | --- | --- | --- | --- | --- |
| CO2 Capture | NO | YES | NO | YES | NO | YES |
| Gross Power (MW) | 770 | 745 | 742 | 694 | 748 | 693 |
| Auxiliary Power (MW) |  |  |  |  |  |  |
| Base Plant Load | 23 | 23 | 25 | 26 | 21 | 19 |
| Air Separation Unit | 103 | 121 | 91 | 109 | 90 | 113 |
| Gas Cleanup/CO2 Capture | 4 | 18 | 3 | 15 | 1 | 16 |
| CO2 Compression | - | 27 | - | 26 | - | 28 |
| Total Aux. Power (MW) | 130 | 189 | 119 | 176 | 112 | 176 |
| Net Power (MW) | 640 | 556 | 623 | 518 | 636 | 517 |
| Heat Rate (Btu/kWh) | 8,922 | 10,505 | 8,681 | 10,757 | 8,304 | 10,674 |
| Efficiency (HHV) | 38.2 | 32.5 | 39.3 | 31.7 | 41.1 | 32.0 |
| Energy Penalty1 | - | 5.7 | - | 7.6 | - | 9.1 |

- _1__CO__2__ Capture Energy Penalty_  = Percent points decrease in net power plant efficiency due to CO2 Capture

## IGCC Economic Results

|  | GE Energy |  | E-Gas |  | Shell |  |
| --- | --- | --- | --- | --- | --- | --- |
| CO2 Capture | NO | YES | NO | YES | NO | YES |
| Plant Cost ($/kWe)1 |  |  |  |  |  |  |
| Base Plant | 1,323 | 1,566 | 1,272 | 1,592 | 1,522 | 1,817 |
| Air Separation Unit | 287 | 342 | 264 | 329 | 256 | 336 |
| Gas Cleanup/CO2 Capture | 203 | 414 | 197 | 441 | 199 | 445 |
| CO2 Compression | - | 68 | - | 69 | - | 70 |
| Total Plant Cost ($/kWe) | 1,813 | 2,390 | 1,733 | 2,431 | 1,977 | 2,668 |
|  |  |  |  |  |  |  |
| Capital COE (¢/kWh) | 4.53 | 5.97 | 4.33 | 6.07 | 4.94 | 6.66 |
| Variable COE (¢/kWh) | 3.27 | 3.93 | 3.20 | 4.09 | 3.11 | 3.97 |
| CO2 TS&M COE (¢/kWh) | 0.00 | 0.39 | 0.00 | 0.41 | 0.00 | 0.41 |
| Total COE2 (¢/kWh) | 7.80 | 10.29 | 7.53 | 10.57 | 8.05 | 11.04 |
| Increase in COE (%) | - | 32 | - | 40 | - | 37 |
| $/tonne CO2 Avoided | - | 35 | - | 45 | - | 46 |

- 1Total Plant Capital Cost (Includes contingencies and engineering fees)
- 2January 2007 Dollars, 80% Capacity Factor, 17.5% Capital Charge Factor, Coal cost $1.80/106Btu

## Comparison to PC and NGCC

Current State-of-the-Art

***Current State-of-the-Art***

## Current TechnologyPulverized Coal Power Plant*

_**PM Control:**_**   **Baghouse to achieve 0.013 lb/MMBtu (99.8% removal)
_**SOx Control:**_**   **FGD to achieve 0.085 lb/MMBtu (98% removal)
_**NOx Control:**_**   **LNB + OFA + SCR to maintain 0.07 lb/MMBtu
_**Mercury Control:**_**  **Co-benefit capture ~90% removal
_**Steam Conditions (Sub):**_** **2400 psig/1050°F/1050°F
_**Steam Conditions (SC):**_** **3500 psig/1100°F/1100°F

**********Orange Blocks Indicate Unit Operations Added for CO******2****** Capture Case***

**Notes:**
Challenge:  Large volume of dilute flue gas (12.8 Mol % CO2) containing low levels of SO2, NOx and Particulates.  
Sox control to 10 ppm for CO2 Capture Cases (Uses a polishing unit)

## Current TechnologyNatural Gas Combined Cycle*

**Current Technology*****Natural Gas Combined Cycle****

_**NOx Control:**_**   **LNB + SCR to maintain 2.5 ppmvd @ 15% O2
_**Steam Conditions:**_** **2400 psig/1050°F/950°F

**********Orange Blocks Indicate Unit Operations Added for CO******2****** Capture Case***

**HRSG**

**MEA**

**Combustion Turbine**

**CO****2**** **
**Compressor**

**Stack**

**Direct Contact**
**Cooler**

**Blower**

- Natural Gas

- Air

- Cooling Water

- Stack Gas

- CO2
- 2200 psig

- Reboiler Steam

- Condensate Return

**Notes:**
Challenge:  Large volume of dilute flue gas (12.8 Mol % CO2) containing low levels of SO2, NOx and Particulates.  
Sox control to 10 ppm for CO2 Capture Cases (Uses a polishing unit)

## PC and NGCC Performance Results

|  | Subcritical |  | Supercritical |  | NGCC |  |
| --- | --- | --- | --- | --- | --- | --- |
| CO2 Capture | NO | YES | NO | YES | NO | YES |
| Gross Power (MW) | 583 | 680 | 580 | 663 | 570 | 520 |
|  |  |  |  |  |  |  |
| Base Plant Load | 29 | 48 | 26 | 43 | 10 | 13 |
| Gas Cleanup/CO2 Capture | 4 | 30 | 4 | 27 | 0 | 10 |
| CO2 Compression | - | 52 | - | 47 | 0 | 15 |
| Total Aux. Power (MW) | 33 | 130 | 30 | 117 | 10 | 38 |
| Net Power (MW) | 550 | 550 | 550 | 546 | 560 | 482 |
| Heat Rate (Btu/kWh) | 9,276 | 13,724 | 8,721 | 12,534 | 6,719 | 7,813 |
| Efficiency (HHV) | 36.8 | 24.9 | 39.1 | 27.2 | 50.8 | 43.7 |
| Energy Penalty1 | - | 11.9 | - | 11.9 | - | 7.1 |

- _1__CO__2__ Capture Energy Penalty_  = Percent points decrease in net power plant efficiency due to CO2 Capture

## PC and NGCC Economic Results

|  | Subcritical |  | Supercritical |  | NGCC |  |
| --- | --- | --- | --- | --- | --- | --- |
| CO2 Capture | NO | YES | NO | YES | NO | YES |
| Plant Cost ($/kWe)1 |  |  |  |  |  |  |
| Base Plant  | 1,302 | 1,689 | 1,345 | 1,729 | 554 | 676 |
| Gas Cleanup (SOx/NOx) | 246 | 323 | 229 | 302 | - | - |
| CO2 Capture | - | 792 | - | 752 | - | 441 |
| CO2 Compression | - | 89 | - | 85 | - | 52 |
| Total Plant Cost ($/kWe) | 1,549 | 2,895 | 1,575 | 2,870 | 554 | 1,172 |
|  |  |  |  |  |  |  |
| Capital COE (¢/kWh) | 3.41 | 6.81 | 3.47 | 6.75 | 1.22 | 2.75 |
| Variable COE (¢/kWh) | 2.99 | 4.64 | 2.86 | 4.34 | 5.62 | 6.70 |
| CO2 TS&M COE (¢/kWh) | 0.00 | 0.43 | 0.00 | 0.39 | 0.00 | 0.29 |
| Total COE2 (¢/kWh) | 6.40 | 11.88 | 6.33 | 11.48 | 6.84 | 9.74 |
| Increase in COE (%) | - | 85 | - | 81 | - | 43 |
| $/tonne CO2 Avoided | - | 75 | - | 75 | - | 91 |

- 1Total Plant Capital Cost (Includes contingencies and engineering fees)
- 2January 2007 Dollars, 85% Capacity Factor, 16.4% (no capture) 17.5% (capture) Capital Charge Factor, Coal cost $1.80/106Btu, Natural Gas cost $6.75/106Btu

## Environmental Performance Comparison

IGCC, PC and NGCC

***IGCC, PC and NGCC***

## Criteria Pollutant Emissions for All Cases

## CO2 Emissions for All Cases

## Raw Water Usage Comparison

IGCC, PC and NGCC

***IGCC, PC and NGCC***

## Raw Water Usage per MWnet (Absolute)

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

## 
Economic Results for All Cases

**Economic Results for All Cases**

## CO2 Mitigation Costs

## Total Plant Cost Comparison

- Total Plant Capital Cost includes contingencies and engineering fees

## Cost of Electricity Comparison

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

- cents/kWh ($2007)

## Highlights

## NETL Viewpoint

**Most up-to-date performance and costs available in public literature to date**
**Establishes baseline performance and cost estimates for current state of technology **
**Improved efficiencies and reduced costs are required to improve competitiveness of advanced coal-based systems**** **
- In today’s market and regulatory environment
- Also in a carbon constrained scenario
**Fossil Energy RD&D aimed at improving performance and cost of clean coal power systems including development of new approaches to capture and sequester greenhouse gases**

## Result Highlights:  Efficiency & Capital Cost

**Coal-based plants using today’s technology are efficient and clean**
- IGCC & PC:  39%, HHV (without capture on bituminous coal)
- Meet or exceed current environmental requirements
- Today’s capture technology can remove 90% of CO2, but at significant increase in COE
**Total Plant Cost:  ****IGCC ~20% higher than PC capex**
- NGCC:  $554/kW
- PC:        $1561/kW (average)
- IGCC:    $1841/kW (average)
**Total Plant Cost with Capture:  ****PC > IGCC capex**
- NGCC:  $1169/kW
- IGCC:   $2496/kW (average)
- PC:       $2788/kW (average)

## Results Highlights:  COE

**20 year levelized COE:  ****PC lowest cost generator**
- PC:   64 mills/kWh (average)
- NGCC:  68 mills/kWh
- IGCC:  78 mills/kWh (average)
**With CCS:  ****IGCC lowest coal-based option **
- NGCC:  96 mills/kWh
- IGCC:  105 mills/kWh (average)
- PC:  116 mills/kWh (average)
**Breakeven LCOE* when natural gas price is:**
- No Capture      IGCC:  $7.99/MMBtu     PC:  $6.15/MMBtu
- With Capture   IGCC:  $7.73/MMBtu     PC:  $8.87/MMBtu
- * At baseline coal cost of $1.80/MMBtu

## 
Summary Table for All Cases

**Summary Table for All Cases**

## Summary Table