During the 1990s, construction of natural gas-fired power plants have increased greatly as a result of deregulated natural gas markets, low fuel costs, and increased environmental regulations. Moreover, short construction lead times and low capital costs have given natural gas an advantage over its competitors.
6.3.1. Combined-Cycle Technology
The primary gas-fired technology for new baseload electricity generation is gas turbine combined cycle (GTCC). The combined cycle system is a combination of two
technologies: the gas turbine and the steam turbine. In a gas turbine, natural gas is burned in combination with a steady stream of high velocity compressed air. The hot combustion gas is then passed through an array of rotating and stationary airfoils that turn a generator to produce electricity. For the second or bottoming cycle, a heat recovery steam generation system (HRSG) and steam turbine are added to take advantage of the thermal energy produced from the first combustion cycle.
Modern gas turbine plants with a triple-pressure HRSG with steam reheat can reach efficiencies above 55 percent. ABB-Alstom claims 58 percent efficiency of a combined cycle plant built around its GT24/26 reheat gas turbines; the same efficiency is cited by Siemens, for the Westinghouse steam-cooled W501G/701G gas turbine or V94.3a gas turbine, combined with a triple pressure HRSG. A gas turbine, with steam cooling of the turbine blades and nozzles, combined with an advanced HRSG is expected to operate at an efficiency level of 60 percent in the near future. The goal of most world manufacturers is to reach overall thermal efficiencies of the combined plant of 60 percent in the short term, generally by increasing firing temperatures (Franco 2002, p. 1504).
DOE has recently cited the General Electric (GE) “H” class GTCC system for its performance promise. The new system is claimed to reach an overall thermal efficiency of 60 percent through its increased gas turbine firing temperature of 1430 degrees C with a pressure ratio of 23:1 (Corman 1996, p. 1).
In spite of manufacturer claims of 60 percent efficiency, most industry experts suggest efficiencies in the range of 55 to 58 percent would be a preferable range to account for plant-to-plant variation such as ambient air differences and other environmental factors (Claeson Colpier 2002, p. 313).
6.3.2. The Future of Gas Turbine Combined Cycle Technology
Research into increasing the efficiency of combined-cycle technology is proceeding with several developments that allow higher firing temperatures, better turbine performance, and more efficient recovery of heat. The engineering literature has paid considerable
attention to the optimization of HRSG. Two basic exhaust heat recovery processes can be used to increase efficiency: (1) recuperation, in which the recovered heat is used in the same gas turbine cycle; and (2) bottoming cycle, in which the exhaust is used as a heat source for a second and essentially independent power producing cycle (Heppenstall 1998, p. 838). In addition, basic optimization of HRSG parameters such as mass flow rates and heat exchanger efficiencies can produce substantial increases in overall efficiency. The efficiency increase can vary from 2 percent for HRSG optimization alone, to 6 to 7 percent using post
combustion reheating, inter-cooling, and gas-to-gas recuperation (Franco 2002, p. 1515). While significant increases in efficiencies are technically feasible, increased component and plant complexity could result in increased cost. The thermodynamic performance of a plant is usually reflected in the fuel cost. The fuel cost savings as a result of increases in thermal efficiency are shown in Table 6-2, which suggests that, on average, a
5 percentage-point increase in thermal efficiency will result in an 8 percent reduction in fuel cost. For example, at a 40 percent thermal efficiency, which is equivalent to a heat rate of 8,530 per kWh, and a $3.15 per MMBtu cost of gas, the fuel component of the levelized cost of electricity (LCOE) of a combined cycle plant would be $27 per MWh.
Table 6-2: Thermal Efficiency Effect on Fuel Cost of GTCC, $ per MWh, 2003 Prices Fuel Cost Contribution to LCOE,
in $ per MWh
At Fuel Pricea, in $ per MMBtu, of: Thermal Efficiency, Percent Heat Rate, Btu per kWh 3.15 3.75 4.70 40 8530 27 32 40 45 7582 24 28 36 50 6824 22 26 32 55 6204 20 23 29 60 5687 18 21 27 65 5249 17 20 25 a
Data generated using fuel price estimates from Smith and Hove (2003) and an average 2009 gas contract price from NYMEX (2003).
6.3.3. Breakdown of Costs by Capital, Fuel, and O&M
The cost of generating electricity with gas turbine combined cycles depends not only on the capital cost of the plant, but also the cost of fuel, thermal efficiency, load, and
operation and maintenance costs. In addition, differences in national and regional market characteristics and local site conditions can mask the influence of various factors. However, for the purposes of this chapter average values will be used.
Fuel cost is the primary consideration in assessing the LCOE for gas-fired generation. By most estimates it comprises nearly two-thirds of the total cost of generation. As discussed in Section 9.4, the natural gas price has been relatively volatile in recent years due to declines in productivity and proven reserves, among other, more transient factors. Accordingly, higher fuel prices could cause a reassessment of the economic viability of gas-fired generation. Natural gas price models and their forecasts are discussed in Section 7.3.
Deutsche Bank suggests average gas prices above $4 per MMBtu in the short run as a critical point at which fuel switching may occur (Smith and Hove 2003a, p. 22). Capital costs comprise less than one-third of the total cost of generation. An average estimate for a new combined cycle plant is $590 per kW (Smith and Hove 2003a, p. 77). The final
consideration is the cost of operation and maintenance (O&M), which includes costs of emission control. Generally gas-fired plants do not require additional pollution control equipment, which provides a significant O&M cost advantage, but O&M comprises less than 6 percent of the LCOE of gas-fired plants (Smith and Hove 2003a, p. 19). Table 6-3 shows Deutsche Bank’s present and future cost projections for gas plants.
Claeson Colpier et al.’s (2002) analysis suggests that the great reduction in gas-fired electricity costs through the 1990s was the result of a worldwide increase in installed
capacity and attendant experience with combined cycle technology in electricity generation. If GTCCs become the generation technology of choice, the trend would likely continue, moderated by declining marginal returns to learning, discussed in Chapter 4. According to Claeson Colpier et al., holding the fuel price constant, the stable progress ratio for the cost of generating electricity is approximately 94 percent. That is, at the next point where installed capacity doubles, the capital cost should fall by 6 percent, or a 6 percent learning effect in the terminology of Chapter 4. The likelihood, however, of a further doubling of capacity in the short term is small, and therefore its effect on the overall cost of electricity minor compared to gains in thermal efficiency and fuel cost.
Table 6-3: Cost Estimates for New Gas Plants
2003 Long Terma
Plant Size (MW) 300 300
Capital Cost ($ per kW) 590 450
Lead Time (Years) 3 3
Fuel Price ($ per MMBtu)b 3.75 3.15
Fuel Cost ($ per MWh) 23.6 19.9
Total O&M Cost ($ per MWh) 2.6 2.6
Annual Capital Cost ($ per
MWh) 10.2 7.8
Levelized Cost ($ per MWh)c 36.4 30.3
Source: Smith and Hove (2003). a
Long term is the length of time required for fuel prices to reach an equilibrium, approximately 2006 (p. 77).
b
Fuel price based on 2003 EIA estimate, plant efficiency set at 54 percent; price does not include post-combustion emissions control.
c
Levelized cost is the sum of fuel, O&M, and annuitized capital costs.
6.3.4. Natural Gas Emissions, Control Technology, and Costs
When compared with emissions from coal-fired plants, combined cycle plants
produce significantly less of the six criteria pollutants established by the 1990 Clean Air Act. Natural gas produces no sulfur dioxide or ash, and smaller quantities of volatile organics, CO2, and NOX gases. However, for the purposes of this report, only nitrogen oxides (NOX) will be considered. NOX gas emissions are formed during the combustion of natural gas and other fossil fuels by high temperature oxidation of atmospheric nitrogen. CO2 is a natural byproduct of fossil fuel combustion and is currently not a federally regulated gas.
In general, NOX emissions from gas-fired electricity generation are lower than most current limits. As discussed in Section 8.5.2., there is regional variation among NOX
standards, and some states such as California and Texas require additional emissions control technology. Similarly to coal-based technology, gas-fired generation can employ low-NOX burners (LNBs) and selective catalytic reduction systems (SCR) to achieve standards as low as 2.5 parts per million (PPM). In addition, should carbon sequestration be required, its effect on gas-fired electricity costs probably would be much lower than the effect on coal- fired costs as a result of the lower carbon emissions from natural gas. Carbon emissions are discussed in more detail in Chapter 8.
6.3.5. Summary of Future Gas Generation Cost Estimates
The future competitiveness of natural gas-fired generation lies in its fuel cost, which is nearly two-thirds of the overall cost of gas LCOE. Two main factors affect the fuel cost: thermal efficiency and the fuel price. A 5 percentage-point increase in thermal efficiency can reduce the fuel cost by 8 percent. However, the most important cost consideration for gas generation remains the fuel price. Since 1998, supply problems have resulted in volatile fuel prices. Table 6-4 shows the sensitivity of gas-fired LCOE to fuel price.
Table 6-4: Effect of Fuel Price on Gas LCOE, $ per MWh Gas Price Thermal Efficiency, Percent $3.00 $3.40 $3.80 $4.20 $4.60 $5.00 50 33 35 38 41 43 46 55 31 33 36 38 41 43 60 29 32 34 36 39 41
Source: Smith and Hove (2003).
Assuming the gas supply infrastructure is stabilized in the near term and new supply options such as LNG are realized, the current cost advantage of natural gas generation should continue. A forecast of the future cost of generation can be calculated using an estimate of the fuel price and future thermal efficiency. Assuming that a 5 percentage-point increase in thermal efficiency can be achieved by 2020, the cost of gas-based generation could be expected to be approximately $30 per MWh. Should environmental regulations tighten for NOX and greenhouse gases such as CO2, LCOE would likely increase as indicated in Table 6-5.
Table 6-5: Effect of Environmental Controls on 2020 Gas-Fired LCOEa 2020 2020 w/ 2.5 ppm NOx Limit 2020 w/ 2.5 ppm NOx + CO2 Capture Plant Size (MW) 300 300 300
Capital Cost ($ per MW) 450,000 450,000 450,000
Lead Time (Years) 3 3 3
Fuel Price ($ per MMBtu) 3.78 3.78 3.78
Fuel Cost ($ per MWh) 20.3 20.3 20.3
Total O&M Cost ($ per MWh)b 2.6 4.0c 6.3b,d
Capital Cost ($ per MWh)e 7.8 7.8 7.8
Levelized Cost ($ per MWh) 30.7 32.1 44.4
a
2020 Thermal efficiency set at 63 percent, estimated fuel cost taken from Table 6-4, capital cost and O&M cost values taken from Smith and Hove (2003).
b
Incremental emissions control costs include cost of capital and O&M but are reflected in total O&M cost.
c
Additional SCR unit for NOx control adds $1.4 per MWh (Onsite Syscom Energy Corp., 1999, p. 4).
d
Additional monoethanolamine (MEA) unit for CO2 capture adds $2.3 per MWh (David 2000a, p. 3).
e
Annual capital cost = depreciation cost/depreciation term. Depreciation cost is determined using a weightedaverage cost of capital (WACC) of 11.3 percent. Depreciation term is 25 years. (Smith and Hove 2003a, p. 75.)