Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants
Released: 2010-01-19T00:00:00

Introduction

Purpose and Organization

Coal-fired power plants currently account for about 80% of CO 2 emissions from the U.S. electric power industry and about 33% of all U.S. CO 2 emissions. Accordingly, reducing CO 2 emissions from coal plants is a focus of many proposals for cutting greenhouse gas emissions. Options include capturing and sequestering the CO 2 emitted by coal plants, and/or replacing coal-fired generation with low- and zero-carbon sources of electric power, such as wind or nuclear power.

Another option is to replace coal power with increased use of natural gas generation. Natural gas is not a zero-carbon fuel, but gas-fired power using modern generating technology releases less than half of the CO 2 per megawatt-hour (MWh) as a coal plant. Recent large increases in estimates of natural gas reserves and resources, especially from shale formations, have further fed interest in natural gas as a relatively low carbon energy option.

One proposal is that the nation can and should achieve near-term reductions in carbon emissions by making more use of existing natural gas plants. This argument was made at an October 2009 Senate Energy and Natural Resources Committee hearing on The Role of Natural Gas in Mitigating Climate Change . An executive for a large natural gas pipeline company stated that "Just as natural gas plays a key role in meeting U.S. energy demands, it can also play a key role in providing meaningful, immediate , and verifiable [CO 2 ] emission reductions." [emphasis added] The witness for Calpine, a large operator of gas-fired power plants, stated that:

I am here today to tell you that we could, today, simply through the increased use of existing natural-gas fired power plants, meaningfully reduce the CO 2 emissions of the power sector, immediately and for the foreseeable future. In other words, a near- and medium-term solution to our climate change challenge is at hand . No guesswork. No huge spending programs needed. That power would be reliable—available all day, every day. And if we embrace this solution with the right incentives, American business would continue to invest its own capital in existing proven technologies to build even more natural gas fired plants to dramatically further reduce emissions for the longer term. [emphasis added]

Both of these statements emphasize the claimed immediate carbon reductions that can result from increased use of natural gas. This would be accomplished by squeezing more electricity from existing gas-fired power plants, so that coal-fired plants can be operated less and CO 2 emissions quickly and substantially reduced.

This report provides an overview of the issues involved in displacing coal-fired generation with electricity from existing natural gas plants. This is a complex subject and the report does not seek to provide definitive answers. The report aims to highlight the key issues that Congress may consider in deciding whether to rely on, and encourage, displacement of coal-fired electricity with power from existing natural gas plants.

The balance of the report is organized as follows:

Background on gas-fired generation and capacity. Coal displacement feasibility issues. Policy considerations.

The report also includes two appendices. Appendix A , Background on the Electric Power System, may be of particular value to readers relatively new to the subject. Appendix B provides information on the gas-burning combined cycle generating technology discussed in the report.

Issues Not Considered in the Report

Several topics are beyond the scope of this report:

What would be the cost of a policy of displacing coal with natural gas ? The cost would depend on a host of uncertain variables, such as future natural gas and coal prices, any need to build additional pipeline and transmission line facilities, and the cost of carbon (if any). Could natural gas be burned on a large scale in existing coal plants? Assessing this option would require engineering analysis of the plants and determining how many coal plants have access to high capacity natural gas pipelines. How will circumstances change over time? For example, while existing natural gas plants may have enough excess capacity today to displace a material amount of coal generation, this could change in the future as load grows. What kind of existing natural gas plants could be used to displace coal? This report focuses on the potential for displacing coal generation with increased use of underutilized "combined cycle" generating plants, the most modern and efficient type of natural gas-fired power plants. Two other types of gas-fired plants have low utilization rates: peaking plants (stand-alone combustion turbines and diesel generators) and old steam-electric natural gas plants. These are not reviewed in the report because they are relatively inefficient and may not be designed or permitted for baseload operation.

Addressing these issues would require computer modeling and engineering analysis beyond the scope of this report. As noted in the concluding section of the report, these issues, if of interest to Congress, could be part of a more comprehensive review of the potential for displacing coal with natural gas.

Background on Gas-Fired Generation and Capacity

The argument for displacing coal with natural gas rests on the fact that the United States has a large base of advanced technology, underutilized, gas-burning power plants. This section of the report describes how this reservoir of underutilized natural gas combined cycle (NGCC) plants came about, and why it may represent an option for reducing the use of coal plants.

Capacity Trends

From the 1990s into this century, gas-fired power plants have constituted the vast majority of new generating capacity built in the United States. This development is illustrated by Figure 1 for the period 1990 to 2007. Minimal new coal capacity was constructed and the growth in nuclear capacity was limited to uprates to existing plants. Only wind capacity has challenged the pre-eminence of natural gas as the source of new generating capacity, and then only in the latter part of the 2000s when total capacity additions declined sharply.

As shown in Figure 2 , this building boom doubled the natural gas share of total generating capacity between 1989 and 2007. Natural gas-fired capacity is now the largest component of the national generating fleet.

Although natural gas is the largest source of generating capacity, it trails far behind coal as a source of actual electricity generation. In 2008, coal accounted for 49% of all electricity produced, compared to 21% for natural gas, 20% for nuclear power, and 6% for hydroelectric generation. The remainder of this section will explain why so much new gas-fired generation was built and why it is underutilized.

Factors Supporting the Boom in Gas-Fired Plant Construction

Natural gas was the major source of new capacity in the 1990s and early 2000s in part by default. Nuclear and coal power have been burdened with cost, environmental, and (in the case of nuclear power) safety concerns. Oil-fired generation was essentially ruled out by the costs and supply risks of petroleum supplies. This left natural gas as the energy source for new non-renewable power plants. But in addition to the negatives that surrounded alternatives, gas fired capacity also grew because of favorable technological, cost, environmental, and power market characteristics.

Technology

The new gas-fired plants constructed in the 1990s and subsequently were built around the latest design of combustion turbines—a specialized form of the same kind of technology used in a jet engine, but mounted on the ground and used to rotate a generator. Stand-alone combustion turbines were built to serve as peaking units that would operate only a few hundred hours a year. However, the most important technological development was the application of combustion turbines in modern natural gas combined cycle power plants. (For additional information see Appendix B .) These plants were often intended to serve as baseload generators which would operate 70% or more of the time. The NGCC has three important characteristics:

The technology is very efficient , because it makes maximum use of the energy in the fuel through a two-step generating process that captures waste heat that would otherwise be lost. NGCC plants can be built r elatively quickly and cheaply . An NGCC plant costs roughly $1,200 per kilowatt of capacity, about half as much as for a coal-fired plant, and can be built in about two to three years from ground-breaking to operation. This compares to about to five to six years to build a coal plant. Coal plants also tend to have longer pre-construction planning and permitting phases. Combined cycle technology is suitable for relatively small scale and modular construction . NGCC plants can be economically built at unit sizes of about 100 MW, and larger projects can be constructed by adding units in a building block fashion over time. Coal plants in contrast are generally economical only at a unit size of several hundred megawatts. For the reasons discussed below, these characteristics made the NGCC an attractive technology option for the independent power producers that dominated the construction of new power plants in the 1990s and after.

Natural Gas Prices

The construction of new gas-fired capacity was also encouraged by relatively low natural gas prices in the 1990s. As illustrated by Figure 3 , the spot price for natural gas hovered around $2.00 to $3.00 per MMBtu (nominal dollars) through the decade, and a widely held expectation was that gas prices would remain low into the future.

Carbon Dioxide Emissions

The operation of NGCC plants, and natural gas plants generally, produce fewer harmful environmental impacts than coal-fired plants, and have been much easier to site and permit than coal plants. NGCC technology has fewer air emissions than coal plants in part because of the nature of the fuel, and in part because of the greater efficiency of the technology. For example, natural gas when burned inherently emits about half as much carbon dioxide as coal. However, because combined cycle plants are more efficient than typical existing coal plants in converting fuel into electricity, the difference in emissions is greater when measured in terms of CO 2 released per megawatt-hour of electricity produced. By this measure a modern combined cycle emits only about 40% of the CO 2 per MWh as a typical existing coal plant.

Electric Power Industry Restructuring and Overbuilding

Restructuring of the electric power industry (beginning in the late 1970s and accelerating in the 1990s) included federal and state policies that encouraged the separation of power generation and power plant construction from other utility functions. In the 1990s, new independent power producers (IPPs) bought power plants from utilities and constructed most of the new generating capacity. Because these companies sold power into competitive markets and did not have the security of regulated rates and guaranteed markets, they generally sought to minimize risks by constructing relatively low cost, quick-to-build, power plants.

For these reasons, independent power producers built many NGCC plants, largely to meet baseload demand. As shown in Table 1 , between 1990 and 2007 over 168,000 MW of NGCC capacity was built at 345 plant sites. This was an enormous building program, equivalent to adding 23% to the entire national generating fleet that existed in 1990. However, the growth in generating capacity did not stop with new combined cycle plants. As also shown in Table 1 , another 89,843 MW of less efficient stand-alone peaking turbines were constructed, plus another 56,939 MW of other generating technologies. When all of this capacity is added together, generating capacity grew by 43% between 1990 and 2007.

By the mid-2000s it was apparent that the combined cycle building boom had resulted in excess and underutilized generating capacity. Too many plants were built, in part because of questionable investment decisions by independent developers operating in an immature restructured power market. The capacity glut was compounded by a dramatic increase in gas prices after 2000. (See Figure 3 .) Even the high efficiency of the combined cycle plants could not compensate for gas prices that at times peaked above $10.00 per MMBtu, compared to $2.00 to $3.00 per MMBtu prices (nominal dollars) in the 1990s.

The consequence of the combined cycle building boom and bust is that the fleet of NGCC plants has a large amount of unused generating capacity, as illustrated in Table 2 for a "study group" of large combined cycle plants defined for this report. Baseload operation can be reasonably defined as operation at an annual capacity factor of 70% or greater. As shown in Table 2 , only 13% of combined cycle capacity in the study group operated in this range in 2007. A third of the combined cycle capacity had a utilization rate of less than 30%; that is, the plants were the equivalent of idle more than 70% of the time.

In 2007 the study group of NGCC plants had an average capacity factor of 42%. In contrast, the study group of coal plants had an average capacity factor of 75%. It is this mismatch between combined cycle and coal plant operating patterns—the former, low carbon emitting but underutilized; the latter, high carbon emitting and highly utilized—that creates the interest and perceived opportunity for displacing coal power with gas generation from existing plants.

Coal Displacement Feasibility Issues

Estimates of Displaceable Coal-Fired Generation and Emissions

The maximum coal-fired generation and emissions that may be displaceable by existing NGCC plants is estimated in Table 3 and Table 4 . As noted above, the plants in the NGCC study group had an average capacity factor of 42% in 2007. As shown in the tables, if the utilization of this capacity could be essentially doubled to 85%, it would generate additional power equivalent to 32% of all coal-fired generation in 2007, and could displace about 19% of the CO 2 emissions associated with coal-fired generation of electricity. Although these calculations suggest that at most about a third of current (2007) coal-fired generation could be displaced by existing NGCC plants, it is unlikely that this maximum could actually be achieved.

This section of the report will discuss issues that relate to the feasibility of actually displacing coal with gas from existing power plants. The issues are:

Transmission system factors; System dispatch factors; Natural gas supply and price; and Natural gas transportation and storage.

Transmission System Factors

If an NGCC generating unit is located at the same plant site as a coal-fired generating unit, it is probably fair to assume that the NGCC unit can use the same transmission lines as the coal unit and can transmit its power to any load the coal unit is used to meet. However, in most cases coal units and NGCC units are built at separate locations and rely on different transmission paths to move their power. This means that there is no guarantee that the NGCC plant can send its power to the same loads as the coal plant and by doing so displace coal-fired generation.

Even on a regional level, coal and NGCC plants are not necessarily located in the same areas. The maps in Figure 4 and Figure 5 show, respectively, the location of large coal and NGCC plants in the conterminous states. The maps show that in some cases coal and NGCC plants are in the same regions, such as east Texas. On the other hand, California has many NGCC plants and no coal plants, while the Ohio River valley has a dense concentration of coal plants and only a handful of NGCC plants.

This section of the report will discuss three types of transmission system constraints that can prevent one power plant from meeting the load currently served by another plant. These limits on the "transmission interchangeability" of coal and NGCC plants are:

Isolation of the Interconnections; Limited long-distance transmission capacity; and Transmission system congestion.

The concluding part of this section presents an analysis of potential coal displacement by gas using the proximity of coal and existing NGCC plants as a proxy for transmission interchangeability.

Isolation of the Interconnections

The electric power grid covering the conterminous states is divided into three "interconnections," Eastern, Western, and the ERCOT Interconnection that covers most of Texas ( Figure 6 ). These three interconnections operate in most respects as independent systems. There are only a handful of limited, low capacity links between the interconnections. Consequently, surplus capacity in one interconnection cannot be used to meet load in another interconnection.

To illustrate with a hypothetical example, assume 1,000 MW of surplus NGCC capacity in the northern part of the ERCOT Interconnection, and a desired use for that capacity to displace coal in Oklahoma, which is in the Eastern Interconnection. Although the regions are adjacent, from the standpoint of the power grid they are electrically isolated from each other because, with very limited exceptions, the ERCOT and Eastern Interconnections are not linked. Therefore the displacement cannot take place.

Limited Long-Distance Transmission Capacity

Within each interconnection the network of power lines, generating plants, and electricity consumers are linked together. The grid operates in some respects like a single giant machine in which, for example, a disturbance in the operation of the transmission system in Maine is detectible by system monitors in Florida.

Although all generators and loads within an interconnection are linked by the grid, the power grid is not designed to move large amounts of power long distances. The grid was not built in accordance with a "master plan," analogous to the Interstate Highway System. Transmission lines were first built in the early 20 th century by single utilities to move electricity to population centers from nearby power plants. As generation and transmission technology advanced, the distances between power plants and loads increased, but the model of a single entity building lines within its service territory to supply its own load still predominated.

Over time the local grids began to interconnect, due to utilities building jointly owned power plants and because power companies began to grasp the economic and reliability benefits of being able to exchange power. Nonetheless, this pattern of development did not emphasize the construction of very long-distance inter-regional lines. Consequently, the capacity to move power long distances within interconnections is limited. For example, while a generator in Maine and a load in Florida are connected by the grid, it is not feasible to send power from Maine to Florida because the transmission lines do not have enough capacity to move the electricity.

Additionally, over distances of hundreds of miles, losses occur with transmission of electricity, making the transfer uneconomic. Power can be moved long distances most efficiently by the highest voltage transmission lines, but only a small portion of the national grid consists of these types of lines. Much of the debate over the proposed increased use of renewable power involves how to build and pay for the new transmission lines that would be needed to move wind and solar power from remote locations to population centers, in part to displace fossil-fueled power plants. Coal displacement by existing gas-fired generators is a similar type of problem. If the existing transmission network does not have sufficient capacity in the right places, then it may not be practical to move gas-powered electricity to loads currently served by coal plants without investing in upgraded or new power lines.

Transmission System Congestion

Even across relatively short distances, options for moving power can be restricted by transmission line congestion. Transmission congestion occurs when use of a power line is limited to prevent overloading that can lead to failure of the line. Congestion can occur throughout a power system:

Regional congestion: for example, power flows are limited between the eastern and western parts of the PJM power pool (covering much of the Midwest and middle Atlantic regions) by congestion. In the western states, examples of congested links include power flows between Montana and the Pacific Northwest, and between Utah and Nevada. State-level congestion: for example, congestion restricts power flows into and out of southwestern Connecticut. Local congestion: These are "load pockets" with limited ability to import power. New York City is an example of a load pocket.

Transmission congestion can increase costs to consumers by forcing utilities to depend on nearby inefficient power plants to meet load instead of importing power from more distant but less costly units. Studies suggest that the annual costs of transmission congestion range from the hundreds of millions to billions of dollars. However, for the purposes of this report the key aspect of transmission system congestion is not the cost impact, but the restrictions it imposes on power flows. Because of congestion, it may not be possible to ship power from an underutilized NGCC plant to a load served by coal power, because the transmission path available to the combined cycle is too congested to carry the electricity.

The solution for congestion is not necessarily massive transmission construction. For example, DOE found that in the Eastern Interconnection "a relatively small portion of constrained transmission capacity causes the bulk of the congestion cost that is passed through to consumers. This means that a relatively small number of selective additions to transmission capacity could lead to major economic benefits for many consumers." However, in the absence of this construction, congestion remains a constraint on the choice of power plants available to meet a load.

Power Plant Proximity Analysis

Transmission system limitations on coal displacement can be rigorously analyzed using sophisticated computer models. Such an analysis is beyond the scope of this report. However, a first approach to the significance of transmission factors can be made by examining how close coal plants are to existing NGCC plants. The assumption behind such a "proximity analysis" is that the closer an NGCC plant is to a coal plant, the more likely that the NGCC plant will connect to the same transmission lines as the coal plant. If the NGCC plant has this comparable transmission access—that is, the combined cycle is "transmission interchangeable" with the coal plant—it potentially could serve the same load as the coal plant and supplant the coal generation.

CRS performed a proximity analysis for the coal plants and NGCC plants in the study groups defined for this report. The analysis was conducted as follows, in all cases using 2007 data (the most recent pre-recession year for which complete data were available):

(1) Study groups of large coal plants and NGCC plants were defined. The plants in these groups accounted for the great majority of power plant coal generation and NGCC generation in 2007. (2) The latitude and longitude of each plant (provided by EIA) was entered into a geographical information system (GIS). (3) The GIS was used to identify all coal plants with one or more existing NGCC plants within a ten mile radius. The hypothetical surplus generation for each NGCC plant within the ten-mile radius was calculated and assumed to displace generation from the coal plant. If one NGCC plant was within ten miles of two or more coal plants, it was allocated first to the coal plant with the largest estimated CO 2 emissions in 2007. (4) A second version of Step 3 was performed which included all NGCC plants within 25 miles of a coal plant. The maps in Figure 7 and Figure 8 show the locations of the coal plants assumed to have generation displaced by existing NGCC plants.

This analysis is not a forecast. It is a first approach to estimating coal displacement potential based on one factor, the proximity of coal and existing NGCC plants. Many other factors, including, for example, how utility systems are dispatched, the configuration and capacity of the electric power transmission system, fuel cost and availability, natural gas transportation capacity, and power system reliability requirements, would influence actual coal displacement potential. These other factors could increase or decrease the potential displacement. Table 5 , which gives the results of the proximity analysis, shows in column 4 that existing NGCC plants located near coal plants might be able to achieve 15% to 28% of the potential maximum coal generation and CO 2 emissions displacement. However, the displaceable coal generation and emissions (see Table 3 and Table 4 ) are only a fraction of total U.S. coal generation and CO 2 . As shown in Table 5 , column 5, the hypothetical displaced coal generation and emissions are equivalent to 5% to 9% of total U.S. coal generation, and 3% to 5% of the associated CO 2 emissions. Given its limitations, the analysis suggests that existing NGCC plants near coal plants may be able to account for something on the order of 30% or less of the displaceable coal-fired generation and CO 2 emissions. Greater displacement of coal by existing NGCC plants would depend on more distant NGCC plants which would be less clearly "transmission interchangeable" with coal plants. This emphasizes the importance that the configuration and capacity of the transmission system will likely play in determining the actual potential for displacing coal with power from existing NGCC plants.

System Dispatch Factors

System dispatch refers to the pattern in which power plants are turned on and off, and their power output ramped up and down, to meet changing load patterns. (For additional discussion, see Appendix A .) The concept of displacing coal generation with power from existing NGCC plants assumes that the NGCC plants are underutilized or idle when coal plants are operating. However, this is not necessarily the case. This can be illustrated by examining the monthly utilization of the coal and gas-fired plants in the study groups ( Figure 9 ). As shown in the figure, the utilization of coal and combined cycle plants follows a similar pattern: utilization is highest in the summer and, to a lesser degree, in the winter, and lowest in the "shoulder" months of the spring and fall. The figure illustrates that when coal plant operation is at its highest and the most coal power can be displaced, NGCC plant operation is also at its highest and surplus gas-fired generation is therefore at its lowest.

Figure 9 is a national, monthly picture of power plant dispatch. System dispatch actually takes place moment-to-moment, and at this level of detail the complexities in displacing coal with gas become further evident. Figure 10 graphically illustrates hourly dispatch at Plant Barry, a power plant in Alabama that has both coal and NGCC units at the same site. The data is for November 2007, the month in which the NGCC units at Plant Barry had their lowest generation for the year and therefore, in principle, the most excess capacity available to displace coal. However, the graphic illustrates that even during this low utilization month for the NGCC units, there are still periods when the units were running near maximum output (e.g., November 6 to 9, and 27 to 30). While there were periods when coal plant output was high and the NGCC units were shut down (e.g., November 4), creating the maximum opportunity to displace coal with gas, there were also periods when the NGCC units were available but potential coal displacement was reduced by limited operation of the coal units (e.g., November 18). These examples illustrate the level of detailed analysis required to realistically estimate the potential for changing plant dispatch to displace coal with natural gas.

Natural Gas Supply and Price

Large scale displacement of coal-fired generation by existing NGCC plants could result in a significant increase in U.S. gas demand. Table 6 compares the actual demand for natural gas for all purposes in 2007 with an illustrative estimate of the additional gas supplies needed if all of the displaceable coal-fired generation (see Table 3 ) were actually replaced by existing NGCC plants. As discussed above, this maximum displacement of coal by existing NGCC plants may be unachievable, so results are also shown for a half and a quarter of the maximum.

Total U.S. natural gas demand in 2007 was the third highest on record. The illustrative estimates of increased gas demand for coal displacement would increase the already high level of demand in 2007 by another 5% to 20% ( Table 6 , line 3).

This increased demand might be met with a combination of increased domestic production, pipeline imports from Canada, Alaskan supplies if the trans-Alaskan gas pipeline is built, and imports of liquefied natural gas by tanker from overseas. For example, one reason for the interest in coal displacement by gas is the recent increase in natural gas available from shale formations and other "unconventional" sources of gas. The combination of higher production (up a projected 3.7% for 2009) and reduced demand due to the 2008-2009 recession has contributed to a sharp decline in gas prices from the peaks experienced earlier in the 2000s (see Figure 3 ). For the longer term, there is widespread optimism concerning the gas supply and price outlook. An example is a late 2009 assessment by the Federal Energy Regulatory Commission (FERC):

The long-term [gas production] story is one of abundance. In June, the Potential Gas Committee, an independent group that develops biennial assessments of gas resources, raised its estimate to over 2 quadrillion cubic feet, one-third more than its previous level and almost 100 years of gas production at current consumption levels. The large increase is almost entirely due to improvements in our ability to harvest gas from shale and get it to markets at a reasonable cost…. As we have indicated before, gas production is becoming more like mining and manufacturing with high probability of production from each well drilled. This environment should have profound effects on the traditional boom and bust cycle of gas production.

EIA's most recent long-term forecasts of natural gas wellhead prices for 2020 and 2030 have dropped, respectively, 13% and 11% from its prior forecast, "due to a more rapid ramping up of shale gas production, particularly after 2015. [The forecast] assumes a larger resource base for natural gas, based on a reevaluation of shale gas and other resources…."

Even with the current optimism concerning natural gas supplies and prices, it is important to note that natural gas markets have historically been exceptionally difficult to forecast. According to an EIA self-assessment of its long-term projections, "The fuel with the largest difference between the projections and actual data has generally been natural gas." In the 1990s gas prices were expected to be low; by 2004 prices were much higher than expected and major gas buyers were reported to be "increasingly critical of the nation's system for forecasting natural gas supply and demand." Subsequently, as shown in Figure 3 , prices plummeted. In the October 2009 Senate hearing on natural gas, a cautionary note was sounded by the witness for Dow Chemical Company:

Although increased supply from shale gas appears to have changed the production profile, we have seen similar scenarios occur after past spikes. In 1998, significant new imports from Canada came on line; in 2002-2003, there were new supplies from the Gulf of Mexico and in 2005, new discoveries in the Rockies were brought into play. In each case, the initial hopes were too high and production increases were not as large as initially expected.

In 2009, as in 2002, 2004 and 2006, drilling has declined dramatically as price has fallen. After each trough, natural gas demand and price rise once the economy turns, signaling the production community to increase drilling. During the lag between the pricing signals and new production, only one mechanism exists to rebalance supply and demand: demand destruction brought about by price spikes. Demand destruction is an antiseptic economic term for job destruction.

Although multiple options may exist to meet the additional natural gas demand created by a coal displacement policy, the significance of the potential increase in demand should not be underestimated. The lowest level of increased gas demand shown in Table 6 , 1,194 trillion Btus (TBtus), would raise total demand to 24,886 TBtus. In its most recent Reference Case forecast, the U.S. Energy Information Administration (EIA) does not envision this demand level being reached until after 2028. The middle estimate of increased gas demand shown in Table 6 would raise total gas demand to 26,080 TBtus, which is larger than EIA's forecast for 2035. A policy of rapid change from coal to gas could therefore involve a significant acceleration of gas demand growth compared to EIA's current estimates.

Natural Gas Transportation and Storage

Gas-fired power plants and other gas consumers receive fuel through a vast national pipeline network. At the end of 2008 the network consisted of 293,000 miles of interstate and intrastate pipelines with the capacity to move up to 215 billion cubic feet (BCF) of gas daily. The capacity of this system is sized to meet peak loads, such as during the winter residential heating season. Peak demands are also supported by a system of natural gas storage facilities connected to the pipeline network. These storage facilities hold gas which is produced during lower demand periods until it is needed to meet peak demand.

It seems unlikely that on a national, aggregate scale, pipeline capacity would be a constraint on coal displacement by existing NGCC plants. The natural gas consumption required for the maximum potential coal displacement by existing NGCC plants (see Table 3 ) equate to about 15 BCF per day of natural gas, or about 7% of existing pipeline capacity. A 7% increase in peak demand would appear manageable given the planned expansions to the pipeline system (see below). But irrespective of national system-wide capacity, a different question is whether increased use of gas-fired plants could overstress the specific pipelines and storage facilities that serve those plants. This may be an important issue because the increase in gas demand from existing NGCC plants for coal displacement could be large relative to the amount of gas currently used for power generation. As shown in Table 7 , illustrative estimates of this increase range from 16% to 66%, which means that the facilities serving those plants could have to handle a material increase in gas demand.

A balancing factor is that the natural gas industry has been effective at adding large amounts of capacity to the pipeline system. Capacity additions in 2007 and 2008 were, respectively, 14.9 and 44.6 BCF per day, and as of mid-2009, 31.9 BCF per day was under construction or approved for construction and completion in 2009. Another 62.1 BCF per day of capacity additions are planned for 2010 and 2011, which is equivalent to almost 30% of current capacity. It appears that, given sufficient lead time, the natural gas industry has the ability to install large amounts of additional transportation capacity to meet increased demand.

Policy Considerations

As discussed in this report, the potential for displacing coal consumption in the power sector by making greater use of existing NGCC power plants depends on numerous factors. These include:

The amount of excess NGCC generating capacity available; The current operating patterns of coal and NGCC plants, and the amount of flexibility power system operators have for changing those patterns; Whether or not the transmission grid can deliver power from existing NGCC plants to loads currently served by coal plants; and Whether there is sufficient natural gas supply, and pipeline and gas storage capacity, to deliver large amounts of additional fuel to gas-fired power plants; and consideration of the environmental impacts of increasing gas production.

All of these factors have a time dimension. For example, while existing NGCC plants may have sufficient excess capacity today to displace a material amount of coal generation, this could change in the future as load grows. Therefore a full analysis of the potential for gas displacement of coal must take into account future conditions, not just a snapshot of the current situation.

There is also the question of cost which, as discussed in the introduction, is beyond the scope of this report. Clearly, the cost of a coal displacement by gas policy is highly uncertain, and depends on such factors as future natural gas and coal prices, any need to build additional pipeline and transmission line facilities, and the cost of carbon (if any). The economic impacts of a coal displacement by gas policy could also spill over to other parts of the economy. For example, increased power sector demand could drive up the price of natural gas, to the detriment of other residential, commercial, and industrial users. Decreased production of coal and increased production of natural gas would pose varying costs and benefits for states and regions.

As a step toward addressing these questions, Congress may consider chartering a rigorous study of the potential for displacing coal with power from existing gas-fired power plants. Such a study would require sophisticated computer modeling to simulate the operation of the power system, to determine whether there is sufficient excess gas fired capacity and the supporting transmission and other infrastructure to displace a significant volume of coal over the near term. This kind of study might also estimate the direct costs of a gas for coal policy, such as the impact on electric rates. Because of the large number of uncertainties, such as the future price of natural gas, the study would have to consider several scenarios. Such a study could help Congress judge whether there is sufficient potential to further explore a policy of replacing coal generation with increased output from existing gas-fired plants.

Congress may also consider chartering an analysis of the potential for directly using gas in existing coal-fired plants, either as a supplemental or primary fuel. As noted in the introduction, large scale use of gas in coal plants raises engineering issues and the question of how many coal plants have adequate pipeline connections. However, burning gas in coal plants would make it possible to displace coal while still using existing transmission lines to meet load, which could be a significant advantage.

Appendix A. Background on the Electric Power System

This appendix provides background on the components and operation of the electric power system. Readers familiar with these topics may wish to skim or skip this appendix.

Power Plants and Power Lines

Power plants, transmission systems, and distribution systems constitute the major components of the existing electric power system, as briefly described and illustrated below ( Figure A -1 ):

Generating plants produce electricity, using either combustible fuels such as coal, natural gas, and biomass; or non-combustible energy sources such as wind, solar energy, or nuclear fuel. Transmission lines carry electricity from power plants to demand centers. The higher the voltage of a transmission line the more power it can carry and the fewer the line losses during transmission. Current policy discussions focus on the high voltage network (230 kilovolts (kV) rating and greater) used to move large amounts of power long distances. Near customers a step-down transformer reduces voltage so the power can be carried by low voltage distribution lines for final delivery.

Capacity and Energy

Capacity is the potential instantaneous output of a generating or storage unit, measured in watts. Energy is the actual amount of electricity generated by a power plant or released by a storage device 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). For example, the maximum amount of power a 1,000 megawatt (MW) power plant 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.

Capacity Factor

Capacity factor is a standard measure of how intensively a power plant is utilized. It is the ratio of how much electricity a power plant produced over a period of time, typically a year, compared to how much electricity the plant could have produced if it operated continuously at full output. For example, as shown in the prior paragraph, the maximum possible output of a 1,000 MW power plant in one year is 8.76 million MWh. Assume that during a year the plant actually produced only 7.0 million MWh. In this case the plant's capacity factor would be 7.0 million MWh ÷ 8.76 million MWh = 81%.

Generation and Load

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 A -2 shows an illustrative daily load curve.

The daily load shape dictates how electric power systems are operated. As shown in Figure A -2 , 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 is 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 start up and shut down 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.

Economic Dispatch and Heat Rate

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:

(1) 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. (2) Combined cycle units, which are very efficient but use more 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. (3) Peaking plants, using combustion turbines, are relatively inefficient and burn 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 depend 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.

Appendix B. Combined Cycle Technology

The combined cycle achieves a high level of efficiency by capturing waste heat that would otherwise be lost in the generating process. As shown in Figure B -1 for a combined cycle unit fueled by natural gas, the gas is fed into a combustion turbine which burns the fuel to power a generator. The exhaust from the combustion turbine is then directed to a specialized type of boiler (the heat recovery steam generator or HRSG) where the heat in the exhaust gases is used to produce steam, which in turn drives a second generator. In combined heat and power (CHP) applications, part of the steam is used to support an industrial process or to provide space heating, further increasing the total energy efficiency of the system.

Combined cycles are built in different configurations, depending in part on the amount of capacity needed. Figure B -1 illustrates a configuration in which one combustion turbine feeds one HRSG; this is referred to as "1x1" design. In higher capacity 2x1 or 3x1 designs, multiple combustion turbines feed a single HRSG. These options illustrate the modular (or "building block") nature of combined cycles, which facilitates rapid and flexible construction of new generating units to match changes in demand.

In the United States the predominant fuel used in combined cycle plants is natural gas. Combined cycles can also be designed to use fuel oil as a primary or backup fuel. Gasified coal can also be used as the fuel in an integrated gasification combined cycle (IGCC) plant. There are currently two prototype IGCC plant operating in the United States and a commercial-scale unit is under construction in Indiana.