# 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 green fi 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 con fi gurations are analyzed in the Bituminous Baseline Study. These six
con fi gurations include integrated gasi fi cation combined-cycle (IGCC) cases utilizing General Electric Energy (GEE), ConocoPhillips (CoP), and Shell gasi fi ers; four pulverized coal (PC) cases, two subcritical and two supercritical, and two natural gas combined-cycle (NGCC) plants. Each con fi 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 / CO 2 Separation / Sulfur Recovery CO 2 Capture (%)

IGCC 1,800/1,050/1,050

F-Class GEE Selexol/ - /Claus – CoP MDEA/ - /Claus – Shell Sul fi 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

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## Assumptions
Technical The IGCC cases are dual-train gasi fi 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 (CO 2 ), as well as compressors to raise the CO 2to the pipeline requirements of 15.3 MPa (2,215 psia). These CCS systems require a signi fi 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 con fi 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 (SO 2 ) 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 speci fi 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 con fi guration. For the CCS cases, CO 2is removed in an Econamine FG PlusTM process that imposes a signi fi cant auxiliary power load on the system and requires signi fi 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 CO 2is transported 50 miles via pipeline to a geologic sequestration fi eld for injection into a saline aquifer. In addition to transport and storage, the CO 2is monitored for 80-years. Table 3. Environmental Targets Pollutant IGCC PC NGCC SO 2 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 CO 2transport, 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 CO 2capture) 17.5 Low risk (PC/NGCC without CO 2 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 ef fi 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 ef

fi ciency of about 37 percent (HHV basis). Figure 1 shows the relative energy ef fi 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 ef fi ciency of the plants evaluated at over 40 percent (HHV basis). The signi fi cant energy penalty for the PC plants reduces the ef fi ciency to about 26 percent (HHV basis). IGCC has an ef fi ciency advantage over PC in the CCS cases primarily because the CO 2is more concentrated in IGCC syngas than in PC fl ue gas, thus requiring less energy to capture. The ef

fi ciency of the IGCC plants with CCS is about 32 percent (HHV basis). Figure 2. SO 2 , NOx, and PM Emissions



### Environmental All cases meet or exceed the environmental requirements set forth in the study design basis. The NGCCsystems 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 signi fi 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 CO 2than the coal-based systems. The uncontrolled coal-based systems emitted as much as 203 lb/MMBtu of CO 2 , but with CCS, emissions were reduced to about 20 lb/MMBtu. Figure 3 compares the results for CO 2emissions 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. CO 2 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 gasi fi 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 ef fi 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 CO 2 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 CO 2avoided was calculated for each CCS case and is shown in Figure 8. On an avoided cost of CO 2basis, 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 CO 2 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).