Overview — Bituminous & Natural Gas to Electricity

Objective and Description 

The objective of the Cost and Performance Baseline for Fossil Energy Plants; Volume 1 (Bituminous Coal and Natural 

Gas to Electricity) is to determine cost and performance estimates of the near-term commercial offerings for 

power plants, both with and without current technology for carbon capture and sequestration (CCS). The study 

uses consistent design requirements for all technologies examined, as well as up-to-date performance and capital 

cost estimates. The study timeframe focuses on plants built now and commissioned in 2010. Each plant is built 

at a greenfi eld site in the midwestern United States.

The fossil energy plant cost and performance estimates presented in the study can be used as a baseline for 

additional comparisons and analyses. These systems analyses are a critical element of planning and guiding 

Federal Fossil Energy research, development, and demonstration.

Twelve different power plant confi gurations are analyzed in the Bituminous Baseline Study. These six 

confi gurations include integrated gasifi cation combined-cycle (IGCC) cases utilizing General Electric 

Energy (GEE), ConocoPhillips (CoP), and Shell gasifi ers; four pulverized coal (PC) cases, two subcritical and two 

supercritical, and two natural gas combined-cycle (NGCC) plants. Each confi guration was analyzed with and 

without CCS. The study matrix is provided in Table 1. 

Overview of Bituminous Baseline Study

Table 1. Study Matrix

Plant Type

Standard 

Conditions 

(psig/°F/°F)

Gas

Turbine Gasifi er / Boiler

Acid Gas Removal / 

CO2

 Separation / Sulfur 

Recovery

CO2

Capture

(%)

IGCC

1,800/1,050/1,050

F-Class

GEE Selexol/ - /Claus –

CoP MDEA/ - /Claus –

Shell Sulfi nol-M/ - /Claus –

1,800/1,000/1,000 GEE Selexol/Selexol/Claus 90

CoP Selexol/Selexol/Claus 88

Shell Selexol/Selexol/Claus 90

PC

2,400/1,050/1,050

–

Subcritical Wet fl ue gas desulfurization 

(FGD)/ - /Gypsum –

Wet FGD/Econamine/Gypsum 90

3,500/1,100/1,100 Supercritical Wet FGD/ - /Gypsum –

Wet FGD/Econamine/Gypsum 90

NGCC 2,400/1,050/950 F-Class Heat recovery steam 

generators

– –

- /Econamine/ - 90
Overview — Bituminous & Natural Gas to Electricity

B_Overview–2

Assumptions

Technical 

The IGCC cases are dual-train gasifi cation systems. Once the syngas is cleaned of acid gases and other 

contaminants, it is fed to two advanced F-Class combustion turbines (232 MWe gross output each) coupled 

with two heat recovery steam generators (HRSGs) and a single steam turbine to generate roughly 750 MWe 

gross plant output (about 630 MWe, net). The CCS cases require a water-gas-shift (WGS) and a two-stage 

Selexol system to capture the carbon dioxide (CO2), as well as compressors to raise the CO2 to the pipeline 

requirements of 15.3 MPa (2,215 psia). These CCS systems require a signifi cant amount of extraction steam 

and auxiliary power, which reduces the output of the steam turbine and reduces the net plant power to about 

520 MWe. Because the IGCC system is constrained by the discrete F-Class turbine size, the system cannot be 

scaled to increase the net output to match that of the 

cases without CCS. 

All four PC cases employ a one-on-one confi guration 

comprising a state-of-the-art PC steam generator and 

steam turbine. The boiler is a dry-bottom, wall-fi red unit 

that employs low-nitrogen oxides (NOx) burners with 

over-fi re air and selective catalytic reduction for NOx 

control, a wet-limestone, forced-oxidation scrubber 

for sulfur dioxide (SO2

) and mercury (Hg) control, and 

a fabric fi lter for particulate matter (PM) control. In 

the cases with CCS, the PC plant is equipped with the 

Econamine FG PlusTM process. The coal feed rate is 

increased in the CCS cases to increase the gross steam 

turbine output and account for the higher auxiliary 

load of carbon capture and compression. The ability 

of the boiler and steam turbine industry to match unit 

size to a custom specifi cation has been commercially 

demonstrated, enabling a common net output of 

550 MWe for the PC cases in this study. 

Both the IGCC and PC cases utilize Illinois No. 6 bituminous coal. An analysis of the coal used is provided in 

Table 2.

The NGCC cases use two F-Class turbines, each generating a gross 185 MWe. The two turbines are coupled 

with two HRSGs and one steam turbine generator in a multi-shaft 2x2x1 confi guration. For the CCS cases, 

CO2

 is removed in an Econamine FG PlusTM process that imposes a signifi cant auxiliary power load on the 

system and requires signifi cant extraction steam, reducing the steam turbine power output. Similar to the IGCC 

cases, the NGCC cases are constrained by the 

combustion turbine size. The NGCC cases have 

a total net power output of 560 MWe without 

CCS and 482 MWe with CCS. In all CCS cases, 

the compressed CO2 is transported 50 miles 

via pipeline to a geologic sequestration fi eld 

for injection into a saline aquifer. In addition to 

transport and storage, the CO2 is monitored for 

80-years.

Table 3. Environmental Targets

Pollutant IGCC PC NGCC

SO2 0.0128 

lb/MMBtu

0.085 lb/

MMBtu

Negligible

NOx 15 ppmvd 

@ 15% Oxygen

0.07 lb/MMBtu 2.5 ppmvd 

@ 15% Oxygen

PM (fi lterable) 0.0071 

lb/MMBtu

0.013 lb/

MMBtu

Negligible

Hg > 90% capture 1.14 lb/TBtu N/A

Table 2. Coal Analysis

Rank Bituminous

Seam Illinois No. 6 (Herrin)

Source Old Ben Mine

Proximate Analysis (weight %)1

As 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

Higher heating value, Btu/lb 11,666 13,126

Lower heating value, Btu/lb 11,252 12,712

1

The above proximate analysis assumes sulfur as a volatile 

matter.
Overview — Bituminous & Natural Gas to Electricity

B_Overview–3

Environmental 

The environmental approach for the study was to choose 

environmental targets for each technology that meet or exceed 

regulatory requirements. The IGCC targets were chosen 

to match the design basis of the Electric Power Research 

Institute for their CoalFleet for Tomorrow Initiative. Best Available 

Control Technology was applied to each of the PC and NGCC 

cases, and the resulting emissions were compared to 2006 

New Source Performance Standards limits and recent permit 

averages. 

Economic

The total plant cost (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. Total plant cost includes all equipment (complete with initial chemical and catalyst loadings), materials, 

labor (direct and indirect), engineering and construction management, and contingencies (process and project). 

Owner’s costs are not included.

The cost estimates carry an accuracy of ±30 percent, consistent with the screening study level of design 

engineering applied to the various cases in this study. All cases were evaluated under the same set of technical 

and economic assumptions allowing meaningful comparisons among the cases evaluated. 

Table 4 lists the major economic assumptions. In this study, dual trains were used only when equipment capacity 

required an additional train, and no redundancy was employed other than normal sparing of rotating equipment.

For those cases that feature CCS, capital and operating costs were estimated for CO2

 transport, storage, and 

monitoring. These costs were then levelized over a 20-year period.

This study assumes that each new plant would be dispatched at the time it becomes available and would be 

capable of generating maximum capacity when online. Therefore, capacity factor (CF) is assumed to equal 

availability. The CF is 80 percent for IGCC cases and 85 percent for both PC and NGCC cases.

Table 4. Major Economic Assumptions

Startup date 2010

Cost year (U.S. dollars) 2007

Coal cost ($/MMBtu) 1.80

Natural gas cost ($/MMBtu) 6.75

Capacity factor (%)

 IGCC 80

 PC/NGCC 85

Capital charge factor (%):

High risk (All IGCC PC/ 

NGCC with CO2

 capture) 17.5

 Low risk (PC/NGCC 

 without CO2

 capture) 16.4

Plant life (years) 30

Figure 1. Plant Effi ciency
Overview — Bituminous & Natural Gas to Electricity

B_Overview–4

Results

Technical

For cases without CCS, the energy effi ciency of NGCC is on the order of 50 percent (higher heating value, HHV 

basis); followed by supercritical PC and IGCC, both about 40 percent (HHV basis); and subcritical PC, with an 

effi ciency of about 37 percent (HHV basis). Figure 1 shows the relative energy effi ciency of each technology 

case.

With CCS, the energy penalty is 12 percentage points for PC plants, 7 percentage points for NGCC, and 

6-9 percentage points for IGCC. Even with CCS, NGCC still maintains the highest effi ciency of the plants 

evaluated at over 40 percent (HHV basis). The signifi cant energy penalty for the PC plants reduces the effi ciency 

to about 26 percent (HHV basis). IGCC has an effi ciency advantage over PC in the CCS cases primarily because 

the CO2

 is more concentrated in IGCC syngas than in PC fl ue gas, thus requiring less energy to capture. The 

effi ciency of the IGCC plants with CCS is about 32 percent (HHV basis). 

Figure 2. SO2, NOx, and PM Emissions

Environmental

All cases meet or exceed the environmental requirements set forth in the study design basis. The NGCC 

systems are the cleanest types of fossil power plants due to the low sulfur content and lower carbon-tohydrogen ratio of the methane fuel. IGCC plants are the cleanest coal-based systems, with signifi cantly lower 

levels of criteria pollutants than the PC plants. Figure 2 compares the results for these pollutant emissions for 

the various technology cases.

All CCS cases were required to remove 90 percent of the carbon present in the syngas. Due to a higher 

methane content of the syngas in the CoP case, carbon capture was 88.4 percent. NGCC plants produce 

40 percent less CO2

 than the coal-based systems. The uncontrolled coal-based systems emitted as much as 

203 lb/MMBtu of CO2, but with CCS, emissions were reduced to about 20 lb/MMBtu. Figure 3 compares the 

results for CO2

 emissions for the various technology cases.

All cases were required to control Hg emissions. The environmental target for Hg removal is greater than 

90 percent capture for IGCC plants and an emission rate of 1.14 lb/TBtu for PC plants. Figure 4 depicts the Hg 

emissions results for each case.

Water usage among the plants without CCS is lowest in the NGCC cases. The IGCC plants use about one-anda-half times as much water as do the NGCC cases, and the PC cases use more than twice the amount of water.
Overview — Bituminous & Natural Gas to Electricity

B_Overview–5

Figure 3. CO2 Emissions

Figure 4. Mercury Emissions

Figure 5. Plant Raw Water Usage
Overview — Bituminous & Natural Gas to Electricity

B_Overview–6

In all CCS cases, water usage increases. Water usage for IGCC cases is similar to an NGCC with CCS, whereas 

the PC case with CCS plants requires three to four times more water. Figure 5 shows the respective water 

usage rates for each technology case.

Economic

The coal-based plants have a much higher TPC than NGCC, both with and without CCS. For IGCC, the TPC is 

about $1,800/kWe, varying somewhat based on the gasifi er type. This is about 20 percent higher than the TPC 

for a PC supercritical plant, which is about $1,500/kWe.

With CCS, the TPC for NGCC and PC plants ($/kW) increases by about 110 and 85 percent respectively. The 

TPC for the IGCC plant increases by around 35 percent. The NGCC plant capital requirement is over 

$1,000/kWe, while the IGCC plants cost approximately $2,400 to $2,600/kWe, and the PC plants cost over 

$2,800/kWe. Figure 6 shows the TPC for each technology case.

Cost-of-electricity (COE), which accounts for both effi ciency and capital cost, is levelized over a 20-year period 

and expressed in mills/kWh (one mill is one-tenth of a cent). The electricity cost for cases without CCS ranges 

from about 63 mills/kWh for PC to 68.4 mills/kWh for NGCC and an average of 77.9 mills/kWh for IGCC.

With CCS, IGCC is the least expensive coal-based option for CO2

 removal with a levelized cost-of-electricity 

(LCOE) ranging from 102.9 mills/kWh to 110.4 mills/kWh. This is about 9 percent lower than PC plants 

equipped with CCS, which generate electricity at a cost of 114.8 mills/kWh to 118.8 mills/kWh. Figure 7 breaks 

out the LCOE costs for each technology case.

The cost of CO2

 avoided was calculated for each CCS case and is shown in Figure 8. On an avoided cost of 

CO2 basis, IGCC is the least expensive option overall ($32–$42/ton) while NGCC is the most expensive option 

($83/ton).

Figure 9 illustrates that at near 80 percent CF, the LCOE for PC cases is less than the LCOE for NGCC cases. 

With increased CF, the gap in LCOE between IGCC cases and other technologies narrows. For cases with CCS, 

even at higher CFs, the PC LCOE always remains the highest.

Figure 6. Plant Capital Requirements
Overview — Bituminous & Natural Gas to Electricity

B_Overview–7

The LCOE sensitivity to fuel costs for the cases with and without CCS is shown in Figure 10. The solid line is 

the LCOE of NGCC without CCS as a function of natural gas cost. The dashed line is the LCOE of NGCC 

with CCS as a function of natural gas cost. The points on the lines represent the natural gas cost that would be 

required to make the LCOE of NGCC equal to the respective PC or IGCC technologies at a given coal cost. 

Figure 7. Levelized Cost-of-Electricity

Figure 8. Cost of CO2

 Avoided

The coal prices shown ($1.35, $1.80, and $2.25/MMBtu) represent the baseline cost and a range of ±25 percent 

around the baseline.

Figure 9. Average LCOE Sensitivity to Capacity Factor
Overview — Bituminous & Natural Gas to Electricity

B_Overview–8

Reference: Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. 

Overview_051607

Julianne M. Klara

Senior Analyst

National Energy Technology Laboratory

626 Cochrans Mill Road

P.O. Box 10940

Pittsburgh, PA 15236

412-386-6089

julianne.klara@netl.doe.gov

Contacts

John G. Wimer

Systems Analysis Team Lead

National Energy Technology Laboratory

3610 Collins Ferry Road

P. O. Box 880

Morgantown, WV 26507

304-285-4124

john.wimer@netl.doe.gov

Figure 10. LCOE Sensitivity to Fuel Costs

Without CCS, at the baseline coal cost of $1.80/MMBtu, the LCOE for PC cases equals that of NGCC case at a 

natural gas price of $6.15/MMBtu; and LCOE for IGCC cases equals that of NGCC case at a gas price of 

$7.96/MMBtu. With CCS, for the coal-based technologies at a baseline coal cost of $1.80/MMBtu, to be equal 

to the NGCC case, the cost of natural gas would have to be $7.73/MMBtu (IGCC cases) and $8.87/MMBtu (PC 

cases).