The United States may have to build many new power plants to meet growing demand for electric power. For example, the Energy Information Administration (EIA) estimates that the nation will have to construct 226,000 megawatts of new electric power generating capacity by 2030. This is the equivalent of about 450 large power plants. Whatever the number of plants actually built, different combinations of fossil, nuclear, or renewable plants could be built to meet the demand for new generating capacity. Congress can largely determine which kinds of plants are actually built through energy, environmental, and economic policies that influence power plant costs. This report analyzes the factors that determine the cost of electricity from new power plants. These factors—including construction costs, fuel expense, environmental regulations, and financing costs—can all be affected by government energy and economic policies. Government decisions to influence, or not influence, these factors can largely determine the kind of power plants that are built in the future. For example, government policies aimed at reducing the cost of constructing power plants could especially benefit nuclear plants, which are costly to build. Policies that reduce the cost of fossil fuels could benefit natural gas plants, which are inexpensive to build but rely on an expensive fuel. The report provides projections of the possible cost of power for new fossil, nuclear, and renewable plants built in 2015. The projections illustrate how different assumptions, such as for the availability of federal incentives, change the cost rankings of the technologies. Key observations include the following: Government incentives can change the relative costs of the generating technologies. For example, federal loan guarantees can turn nuclear power from a high cost technology to a relatively low cost option. The natural gas-fired combined cycle power plant, the most commonly built type of large natural gas plant, is a competitive generating technology under a wide variety of assumptions for fuel price, construction cost, government incentives, and carbon controls. This raises the possibility that power plant developers will continue to follow the pattern of the 1990s and rely heavily on natural gas plants to meet the need for new power generation. With current technology, coal-fired power plants using carbon capture equipment are an expensive source of electricity in a carbon control case. Other power sources, such as wind, nuclear, geothermal, and the natural gas combined cycle plant without capture technology, currently appear to be more economical. None of the projections is intended to be a "most likely" case. Future uncertainties preclude firm forecasts. The value of this discussion is not as a source of point estimates of future power costs, but as a source of insight into the factors that can determine future outcomes, including factors that can be influenced by the Congress. The main body of report is divided into the following sections: Types of generating technologies; Factors that drive power plant costs; Financial analysis methodology; Analysis of power project costs. The report also includes the following appendixes: Appendix A presents power generation technology process diagrams and images. Appendix B and Appendix C provide the data supporting the capital cost estimates used in the economic analysis. Appendix C also shows how operating costs and plant efficiencies were estimated for certain carbon control technologies. Appendix D presents the financial and operating assumptions used in the power cost estimates. Appendix E is a list of acronyms used in the report. The first part of this section describes how the characteristics of electricity demand influence power plant choice and operation. The next part describes the generating technologies analyzed in the report. The demand for electricity ("load") faced by an electric power system varies moment to moment with changes in business and residential activity and the weather. Load begins growing in the morning as people waken, peaks in the early afternoon, and bottoms-out in the late evening and early morning. Figure 1 is an illustrative daily load curve. The daily load shape dictates how electric power systems are operated. As shown in Figure 1 , there is a minimum demand for electricity that occurs throughout the day. This base level of demand is met with "baseload" generating units which have low variable operating costs. Baseload units can also meet some of the demand above the base, and can reduce output when demand is unusually low. The units do this by "ramping" generation up and down to meet fluctuations in demand. The greater part of the daily up and down swings in demand are met with "intermediate" units (also referred to as load-following or cycling units). These units can quickly change their output to match the change in demand (that is, they have a fast "ramp rate"). Load-following plants can also serve as "spinning reserve" units that are running but not putting power on the grid, and are immediately available to meet unanticipated increases in load or to back up other units that go off-line due to breakdowns. The highest daily loads are met with peaking units. These units are typically the most expensive to operate, but can quickly startup and shutdown to meet brief peaks in demand. Peaking units also serve as spinning reserve, and as "quick start" units able to go from shutdown to full load in minutes. A peaking unit typically operates for only a few hundred hours a year. The generating units available to meet system load are "dispatched" (put on-line) in order of lowest variable cost. This is referred to as the "economic dispatch" of a power system's plants. For a plant that uses combustible fuels (such as coal or natural gas) a key driver of variable costs is the efficiency with which the plant converts fuel to electricity, as measured by the plant's "heat rate." This is the fuel input in British Thermal Units (btus) needed to produce one kilowatt-hour of electricity output. A lower heat rate equates with greater efficiency and lower variable costs. Other things (most importantly, fuel and environmental compliance costs) being equal, the lower a plant's heat rate, the higher it will stand in the economic dispatch priority order. Heat rates are inapplicable to plants that do not use combustible fuels, such as nuclear and non-biomass renewable plants. As an illustration of economic dispatch, consider a utility system with coal, nuclear, geothermal, natural gas combined cycle, and natural gas peaking units in its system: Nuclear, coal, and geothermal baseload units, which are expensive to build but have low fuel costs and therefore low variable costs, will be the first units to be put on line. Other than for planned and forced maintenance, these baseload generators will run throughout the year. Combined cycle units, which are very efficient but use expensive natural gas as a fuel, will meet intermediate load. These cycling plants will ramp up and down during the day, and will be turned on and off dozens of times a year. Peaking plants, using combustion turbines, are relatively inefficient and burn expensive natural gas. They run only as needed to meet the highest loads. An exception to this straightforward economic dispatch are "variable renewable" power plants—wind and solar—that do not fall neatly into the categories of baseload, intermediate, and peaking plants. Variable renewable generation is used as available to meet demand. Because these resources have very low variable costs they are ideally used to displace generation from gas-fired combined cycle plants and peaking units with higher variable costs. However, if wind or solar generation is available when demand is low (such as a weekend or, in the case of wind, in the evening), the renewable output could displace coal generation. Power systems must meet all firm loads at all times, but variable renewable plants do not have firm levels of output because they are dependent on the weather. They are not firm resources because there is no guarantee that the plant can generate at a specific load level at a given point in time. Variable renewable generation can be made firm by linking wind and solar plants to electricity storage, but with current technology, storage options are limited and expensive. As discussed above, baseload units run more often than cycling units, and peaking units operate the least often. The utilization of a generating unit is measured by its "capacity factor." This is the ratio of the amount of power generated by a unit for a period of time (typically a year) to the maximum amount of power the unit could have generated if it operated at full output, non-stop. For example, the maximum amount of power a 1,000 megawatt (MW) unit can generate in a year is 8.76 million megawatt-hours (Mwh), calculated as: 1,000 MW x 8,760 hours in a year = 8.76 million Mwh. If this unit actually produced only 4.0 million Mwh its capacity factor would be 46% (calculated as 4.0 million Mwh divided by 8.76 million Mwh). Note in this calculation the distinction between capacity and energy . Capacity is the potential instantaneous output of a generating unit, measured in watts. Energy is the actual amount of electricity generated by a power plant during a time period, measured in watt-hours. The units are usually expressed in thousands (kilowatts and kilowatt-hours) or millions (megawatts and megawatt-hours). The difference between actual and theoretical maximum output is caused by planned maintenance, mechanical breakdowns (forced outages), and any instances in which the plant is backed-down from maximum output due to lack of load or because the plant's power is more expensive than that from other plants. It is rare for a plant to have a capacity factor of 100%. Baseload plants typically have capacity factors of about 70% or greater, peaking plants about 25% or less, and cycling plants fall in the middle. The types of generating technologies discussed in this report are often referred to as "utility scale" plants for baseload or intermediate service. These technologies generate large amounts of electricity at a single site for transmission to customers. In 2006, large baseload and intermediate service power plants accounted for about 86% of total power generation in the United States.