This section describes (1) electricity generation and consumption in the United States, (2) federal and state actions that have influenced electricity generation and consumption, (3) electricity reliability, and (4) federal and state regulation. The electricity system includes four distinct functions: generation, transmission, distribution, and system operations (see fig. 1). Electricity may be generated at power plants by burning fossil fuels; through nuclear fission; or by harnessing renewable sources such as wind, solar, geothermal energy, or hydropower. Once electricity is generated, it is sent through the electricity grid, which consists of high-voltage, high- capacity transmission systems, to areas where it is transformed to a lower voltage and sent through the local distribution system for use by industrial, commercial, residential, and other consumers.process, system operations are managed by a system operator, such as a local utility, that must constantly balance the generation and consumption of electricity. To do so, system operators monitor electricity consumption from a centralized location using computerized systems and send minute-by-minute signals to power plants to adjust their output to match changes in consumption. Various federal and state actions have influenced electricity generation. Regarding federal actions, in April 2015, we found that from fiscal year 2004 through 2013, federal programs aided the development of new electricity-generating capacity through various means, including outlays, loan programs, and tax expenditures. In more recent years, federal actions have been targeted toward renewable sources such as wind and solar, although there has also been federal support for coal, nuclear, and natural gas-fueled generation. For example, two tax credits—the Production Tax Credit (PTC) and the Investment Tax Credit (ITC)—and a related program that provided payments in lieu of these tax credits supported wind and solar electricity by lowering the costs associated with electricity generation and providing an incentive to those firms engaged in the construction and operation of wind and solar projects. The Department of the Treasury estimated that these two tax credits resulted in almost $12 billion in revenue losses for the federal government from fiscal year 2004 through 2013. In addition, the related payment program provided almost $17 billion in outlays from fiscal year 2004 through 2013. EIA recently estimated that wind, solar, and other renewables, accounted for about 72 percent of all electricity-related direct federal financial interventions and subsidies in fiscal year 2013. Regarding state actions, our April 2015 report found that key state supports aided the development of electricity generation projects— particularly renewable ones—in most states, from fiscal year 2004 For example, we found that as of September 2014, 38 through 2013.states and the District of Columbia had established renewable portfolio standards or goals.service providers obtain a minimum portion of the electricity they sell from renewable sources, creating additional demand for renewables. Retail service providers meet these requirements in various ways, such as by building renewable generating capacity or purchasing renewable generation from other producers through long-term contracts known as power purchase agreements. Such policies mandate or set goals that retail Federal and state activities have also encouraged energy efficiency, which can reduce the consumption of electricity. For example, Treasury estimated that energy-efficiency-related federal tax expenditures, such as for household energy efficiency improvements and the purchase of energy efficient equipment, amounted to over $15 billion in forgone revenue for the federal government from fiscal year 2000 through 2013. State governments have also played an important role in encouraging energy efficiency. According to the American Council for an Energy- Efficient Economy, as of April 2014, 25 states had fully funded policies in place that establish specific energy savings targets that utilities or nonutility program administrators must meet through customer energy efficiency programs. In March 2014, we found that the federal government has also made efforts to facilitate activities that encourage customers to reduce demand when the cost to generate electricity is high, known as demand-response activities. These efforts have included actions to fund the installation of advanced electricity meters that facilitate these demand-response activities, as well as regulatory efforts to encourage demand-response activities. Specifically, Treasury estimated that forgone revenue associated with the credit for energy efficiency improvements to existing homes amounted to $10.36 billion, the credit for residential energy efficiency property amounted to $3.08 billion, and the exclusion of utility conservation subsidies amounted to $2.04 billion from fiscal 2000 through 2013. easily and inexpensively stored, electricity generated must be matched with demand, which varies significantly depending on the time of day and year. To maintain a reliable supply of electricity, system operators take steps to ensure that power plants will be available to generate electricity when needed. In doing so, system operators typically ensure available capacity exceeds estimated demand so that any unexpected increases in demand or power plant or transmission outages can be accommodated without consumers losing access to electricity. Maintaining a reliable supply of electricity is a complex process requiring the system operator to coordinate three broad types of services as follows: Capacity: Operators procure generating capacity—long-term commitments to have available specific amounts of electricity- generating capacity to ensure that there will be sufficient electricity to reliably meet expected future electricity needs. Procuring capacity may involve operators of power plants committing that existing or new power plants will be available to generate electricity in the future, if needed. Energy: Operators schedule which power plants will generate electricity throughout the day—referred to as energy scheduling—to maintain the balance of electricity generation and consumption. Ancillary services: Operators procure several ancillary services to maintain a reliable electricity supply. Ancillary services generally involve resources being available on short notice to increase or decrease their generation or consumption. These and other services are needed to ensure supply and demand remain in balance so that electricity can be delivered within technical standards—for example, at the right voltage and frequency—to keep the grid stable and to protect equipment that needs to operate at specific voltage and frequency levels. Responsibility for regulating electricity prices is divided between the states and the federal government. Most electricity consumers are served by retail markets that are regulated by the states, generally through state public utility commissions or equivalent organizations. As the primary regulator of retail markets, state commissions approve many aspects of utility operations, such as the siting and construction of new power plants, as well as the prices consumers pay and how those prices are set. Prior to being sold to retail consumers, electricity may be bought, sold, and traded in wholesale electricity markets by a variety of market participants, including companies that own power plants, as well as utilities and other retail service providers that sell electricity directly to retail consumers. Wholesale electricity markets are overseen by the Federal Energy Regulatory Commission (FERC). During the last 2 decades, some states and the federal government have taken steps to restructure electricity markets with the goal of increasing competition. The electricity industry has historically been characterized by utilities that were integrated and provided the four functions of electricity service—generation, transmission, distribution, and system operations— to all retail consumers in a specified area. In much of the Western, Central, and Southeastern United States, retail electricity delivery continues to operate under this regulatory approach, and these regions are referred to as traditionally regulated regions. In parts of the country where states have taken steps to restructure retail electricity markets, new entities called retail service providers compete with utilities to provide electricity to retail consumers by offering electricity plans with differing prices, terms, and incentives. Beginning in the late 1990s, FERC took a series of steps to restructure wholesale electricity markets, and wholesale electricity prices are now largely determined by the interaction of supply and demand rather than regulation. In addition, FERC encouraged the voluntary creation of new entities called Regional Transmission Organizations (RTO) to manage regional networks of electric transmission lines as system operators—functions that had traditionally been carried out by local utilities. In addition to its role in regulating aspects of the electricity market, FERC is also responsible for approving and enforcing standards to ensure the reliability of the bulk power system—generally the generation and transmission systems. FERC designated the North American Electric Reliability Corporation (NERC) to develop and enforce these reliability standards, subject to FERC review. These standards outline general requirements for planning and operating the bulk power system to ensure reliability. For example, one reliability standard requires that system planners plan and develop their systems to meet the demand for electricity even if equipment on the bulk power system, such as a single generating unit or transformer, is damaged or otherwise unable to operate. According to our analysis of SNL data, the mix of energy sources used to generate electricity has generally shifted to include more natural gas, wind, and solar, but less coal and nuclear, from 2001 through 2013, though the extent of these changes varied by region. Growth in electricity consumption has generally slowed, with key differences among different types of consumers and regions. Natural gas, wind, and solar sources provided larger portions of the nation’s electricity mix from 2001 through 2013 in terms of both generating capacity and actual generation, while coal and nuclear sources provided smaller portions, according to our analysis of SNL data (see fig. 2). At the time of our analysis, 2013 was the most recent year with complete data for both generating capacity and generation. The growth or decline in specific energy sources varied over this time period and across U.S. regions. (See app. III for additional information on electricity-generating capacity and actual generation by region.) SNL data on power plants under construction and planned for retirement suggest that these recent trends are likely to continue. Generating capacity and actual generation from natural-gas-fueled power plants increased across the nation from 2001 through 2013, with different regions seeing varying levels of growth, according to our analysis of SNL data. Natural-gas-fueled generating capacity increased by about 181,000 MW during this period, and accounted for 72 percent of the new generating capacity added from all sources.capacity resulted from the construction of about 270,000 MW during this period offset by a smaller amount of retirements. Regarding actual generation, electricity generated from natural-gas-fueled power plants generally increased throughout this period, with a pronounced jump from 2011 through 2012 when generation increased by about 21 percent (see This increase in gas-fueled fig. 3). The average utilization of natural-gas-fueled capacity—a measure of the intensity with which capacity was operated—varied over this period, declining from about 30 percent in 2001 to a low of about 20 percent in 2003 before generally increasing to about 27 percent in 2013.Increases in gas-fueled capacity and generation led to natural gas accounting for a larger share of the nation’s electricity mix, increasing from 17 percent of generation in 2001 to 26 percent in 2013. All but one region of the country experienced increases in the amount of electricity generated from natural gas over this period. Specifically, electricity generated from natural gas declined in Alaska and increased in the rest of the United States, ranging from an increase of 5 percent in Texas to almost 200 percent in some regions in the East. In some regions, natural gas became an increasingly significant energy source in the generation mix. For example, in New England, natural gas increased from 31 percent of the region’s electricity generation in 2001 to 42 percent in 2013. According to EIA, lower natural gas prices, regional environmental initiatives, and other factors have contributed to increases in gas-fueled electricity generation. As the use of natural gas to generate electricity has increased since 2001, the mix of technologies used in gas-fueled power plants has also changed. Specifically, combined-cycle plants, which use a combustion turbine in conjunction with a steam turbine to generate electricity, have become an increasingly common technology for generating electricity— growing from 7 percent of total electricity generation in 2001 to 23 percent in 2013, according to SNL data (increasing from 42 percent of electricity generated from gas in 2001 to 86 percent in 2013).expensive to build initially, such plants are more fuel-efficient than simpler combustion turbine plant designs. This efficiency can make it economically feasible to generate electricity with natural gas for sustained periods. As a result, these plants can be economically operated like traditional baseload generation such as coal and nuclear plants, which often run continuously for long periods of time. Trends in the utilization of combined-cycle and other gas-fueled power plants differed over this period. Utilization decreased for all gas-fueled capacity in the early 2000s, but while it has increased since 2003 for combined-cycle capacity (from 34 percent in 2003 to almost 44 percent in 2013), utilization has declined somewhat for other gas-fueled technologies (from 12 percent in 2003 to 8 percent in 2013). Generating capacity and actual generation from wind and, to a lesser extent, solar power plants increased from 2001 through 2013, with most of the increase occurring since 2007. (See fig. 4.) We have previously found that various federal and state actions have contributed to increases in wind and solar power plant capacity, including financial supports and state renewable portfolio standards. These increases led to wind and, to a lesser extent, solar accounting for a larger share of the nation’s energy mix, increasing from just over 0 percent of electricity generation in 2001 to 4 percent in 2013. Regarding wind, generating capacity increased about sixteen fold over this period, with 57,000 MW of capacity added from 2001 through 2013 and wind’s share of total generating capacity increasing from just over 0 percent in 2001 to 5.4 percent in 2013. However, these plants operate less intensively than some other sources because wind power plants only generate electricity when the wind is blowing. As such, wind’s share of the nation’s actual generation increased from just over 0 percent in 2001 to about 4 percent in 2013. Generation from wind increased by over 160 million MWh from 2001 through 2013, the second largest increase in actual generation of all energy sources after natural gas. Most of this increase, 136 million MWh (or 84 percent of the total increase), occurred since 2007. The average utilization of wind power plants fluctuated over this period between 26 and 33 percent. Electricity generated from wind is concentrated in a few states; as shown in table 1, 74 percent of total electricity generated from wind came from 10 states in 2013. In addition, wind can contribute a substantial portion of generation in some areas. For example, in the Upper Midwest region of the country, including states such as Minnesota and Iowa, about 14 percent of the region’s electricity came from wind power plants. In addition, representatives from one utility told us they have had hours where 60 percent of the electricity produced on their system came from wind sources, and their system has experienced longer periods with over 50 percent wind generation. By contrast, other regions of the country, such as the southeastern United States, produced less than 1 percent of their total electricity from wind in 2013. Regarding solar, generating capacity increased by about 7,000 MW, or about eighteen-fold, from 2001 through 2013 at larger power plants with capacities of at least 1 MW. This trend accelerated in 2014 with the addition of over 3,000 MW of solar generating capacity, and total solar generating capacity reached about 10,000 MW. Regarding actual generation, electricity generated at large solar power plants increased about 7 fold—by about 5 million MWh—from 2001 through 2013. The average utilization of solar power plants fluctuated over this period between 16 percent and 25 percent. Despite the growth in solar capacity and generation, large solar power plant generation contributed less than 0.2 percent of total electricity generation nationwide in 2013. More so than wind generation, generation from solar power plants was concentrated in a small number of states. For example, California and Arizona accounted for over half of electricity generation from large solar power plants in 2013. Association, Solar Market Insight Report 2014 Q4 (Mar. 4, 2015). In addition, since 2010, EIA has collected data on solar and other generating capacity that is “net metered”— when consumers can use electricity they generate that is in excess of their consumption at some times to offset consumption at other times. Though these data have limitations, they suggest that distributed net-metered solar capacity has been a large portion of total solar capacity. Generating capacity and actual generation from coal-fueled power plants declined from 2001 through 2013 as plants retired and in some cases, witnessed changes in their usage patterns, according to our analysis of SNL data. Coal-fueled electricity-generating capacity was stable for most of this period, but declined over the last couple years as aging plants retired and little new capacity was added. Specifically, from 2001 through 2013, about 29,500 MW of coal-fueled generating capacity retired, with about 75 percent of those retirements occurring from 2009 through 2013. In our October 2012 and August 2014 reports, we found that a number of factors have contributed to companies retiring coal-fueled power plants, including comparatively low natural-gas prices, the potential need to invest in new equipment to comply with environmental regulations, increasing prices for coal, and low expected growth in demand for electricity. We found that the facilities that power companies have retired or plan to retire are generally older, smaller, and more polluting, and some had not been used extensively. Actual generation from coal declined—in particular since 2008—as natural gas prices fell and made coal-fueled power plants comparatively less competitive (see fig 5). Generation from coal declined in most regions of the country. Several regions, such as New England, experienced large decreases as they shifted away from coal. As coal- fueled generation has declined, coal-fueled power plants have, in general, been utilized less intensively. The average utilization of coal-fueled capacity fluctuated around 70 percent from 2001 through 2008 and then began a general decline to about 59 percent in 2013. For example, representatives from the system operator ISO New England told us that their region no longer regularly uses its coal-fueled power plants to generate baseload electricity. plants are more often used to generate electricity during peak periods or when other resources are not available. Retirements of some coal- fueled power plants and the decrease in usage among others led to coal accounting for a smaller share of the nation’s generating capacity and generation. ISO New England serves Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. Generating capacity and actual generation from nuclear power plants both increased from 2001 through 2013, but the share of nuclear in the national electricity mix declined because other sources increased by a larger amount, according to our analysis of SNL data. No new nuclear power plants were built during this period, and four nuclear power plants retired in the last 2 years, accounting for about 4,200 MW of capacity. However, nuclear generating capacity increased by 5 percent from 2001 through 2013 because of capacity increases at some existing plants as owners upgraded equipment or undertook other changes. Regarding actual generation, electricity generated at nuclear power plants increased by 3 percent. The average utilization of nuclear power plants fluctuated around 90 percent throughout this period. Since nuclear plants tend to be larger capacity plants that run continuously for long periods of time, the retirement of a single plant can have significant effects on a regional power system. For example, representatives at ISO New England said that the Vermont Yankee nuclear power plant, which retired in December 2014, had generated about 5 percent of total electricity generation in their region in 2014. Since nuclear generating capacity and generation did not increase as much as gas, wind, and solar, nuclear accounted for a slightly smaller share of the national electricity mix, decreasing from 21 percent of generation in 2001 to 20 percent in 2013. The contributions of other energy sources to the nation’s energy mix have also changed according to our analysis of SNL data, as follows: Hydropower: Generating capacity and actual generation from hydropower plants increased from 2001 through 2013, by 3,600 MW and 68 million MWh respectively. Generation from hydropower plants varies from year to year based on a region’s weather, particularly the amount of rain or snow, according to EIA. The western region generates more electricity from hydropower than any other region and accounted for 57 percent (about 39 million MWh) of the increase in generation during this period. The average utilization of hydropower capacity fluctuated between 28 percent and 38 percent throughout this period. While hydropower generating capacity increased in absolute terms through new construction and increases in capacity at existing hydropower plants, its share of capacity declined because hydropower generating capacity did not increase as much as other sources, such as natural gas and wind. Other sources: Generating capacity and actual generation from other sources—including oil, biomass, and geothermal together—declined overall from 2001 through 2013. This decline was primarily driven by declines in oil-fueled power plants, where generation declined by over 80 percent and average utilization declined over the period. Two regions, New England and Florida, accounted for a large portion of the decline in oil-fueled power plant generation. Although oil was a relatively small portion of overall generation in the beginning of the period, its share of generation declined further as oil prices rose in the mid-2000s. Generating capacity and actual generation from biomass, geothermal, and other sources increased overall from 2001 through 2013. These changes had little effect on the overall national electricity generation mix, as these other sources represent a small and stable portion of generation—about 2 percent of the national total in both 2001 and 2013. Our analysis of SNL data on generating capacity currently under construction and companies’ plans to retire generating capacity suggests that these general changes in the electricity generation mix are likely to continue. Figure 6 shows the amount of generating capacity under construction, the amount planned for retirement from 2015 through 2025, and the net change (capacity under construction minus planned for retirement), and highlights that natural gas, wind, and solar capacity may continue to increase. There is no coal capacity under construction, and while about 6,000 MW of nuclear capacity is under construction, more nuclear capacity (about 15,000 MW) is planned for retirement than is under construction.construction-planning stages or that has not formally announced retirement. Continuing a long-term trend, growth in electricity consumption slowed from 2001 through 2014. According to EIA data on annual national electricity retail sales—a proxy for end-use consumption—the rate of growth of electricity consumption has slowed in each decade since the 1950s, from growing almost 9 percent per year in the 1950s, to over 2 percent per year in the 1980s and 1990s. This decreasing growth trend continued in the 2000s, with electricity retail sales growing by over 1 percent per year from 2001 through 2007, and fluctuating, but remaining largely flat from that time through 2014. These overall trends mask differences in consumption patterns for different types of consumers, in different regions, and during peak periods of consumption. Regarding consumers, industrial electricity consumption has decreased since 2001, while commercial and residential consumption have increased. Specifically, industrial consumption decreased by 4 percent over the period from 2001 through 2014, and the sector’s share of total electricity consumption declined from 29 percent to 26 percent. Meanwhile, residential electricity consumption increased 17 percent, and commercial consumption increased 25 percent over this period. Regarding regional differences, consumption patterns have varied across the country. For example, consumption declined by almost 5 percent in the Northeast (Mid-Atlantic and New England states) since the recession of 2007 and through 2014, while it increased by over 9 percent in the West South Central states of Texas, Louisiana, Oklahoma and Arkansas over that same period. (See app. IV for additional information on consumption by consumer type and region.) In contrast to the slowdown in the growth of overall electricity consumption, peak consumption has, in some cases, increased. Peak consumption refers to the level of electricity consumed when the overall system usage is at its highest, such as during hot days when air conditioning usage is high.in some instances, differed from changes in total consumption over the course of a year. For example, in New England, while overall consumption has declined, peak consumption has risen according to EIA. Distributed generation and electricity consumption data Growth in distributed generation such as rooftop solar may have also contributed to changes shown in EIA’s data on retail electricity sales. Households and commercial facilities that generate some of their own electricity displace some electricity sales. Therefore, actual electricity consumption may be higher than suggested by retail electricity sales data. According to EIA, this effect is difficult to measure because data on electricity generated from distributed generation sources are not readily available. Changes in the economy: Changes in electricity consumption are often closely linked to the economy, according to EIA.the economic recession from late 2007 through 2009 was associated with a large drop in electricity consumption in the industrial sector. Since many industrial operations operate more evenly throughout the year, declines in industrial operations could lead to reduced electricity consumption throughout the year. Efficiency improvements: Overall improvements in the efficiency of technologies powered by electricity—such as household appliances and others—have slowed the growth of electricity consumption, according to EIA. For example, according to EIA, a new refrigerator purchased today uses less than a third as much electricity as one purchased in the late 1970s, despite the larger size of today’s refrigerators. Changes in the uses of electricity: Consumer uses of electricity have changed over the last decades, affecting the nature of electricity consumption. For example, the growing use of computers and home entertainment devices has increased the use of electricity. In addition, air conditioning has become more widely used in U.S. households. As a result, a heat wave—often associated with peak levels of electricity consumption—may lead to more electricity consumption during peak periods than in the past. Demand-response activities: Another factor that may have affected consumption trends, particularly peak consumption, is the increasing use of demand-response activities—steps taken to encourage consumers to reduce consumption during periods of high demand when the costs to generate electricity are high. For example, system operators may call on industrial consumers to reduce their electricity usage during periods of high demand in exchange for a payment or other financial incentive. In March 2014, we cited FERC data suggesting that the extent of demand-response activities had increased overall—more than doubling from 2005 to reach about 8.5 percent of potential reduction in peak consumption in 2011. According to literature we reviewed and stakeholders we interviewed, changes in electricity generation and consumption have required system operators to take additional actions to maintain reliability. Changes in generation and consumption, together with additional actions system operators have taken to maintain reliability, have affected consumer electricity prices to varying extents, though the net effect on prices is unclear. According to several stakeholders we interviewed and literature we reviewed,operators to take additional actions to reliably provide electricity to consumers, as follows: changes in generation and consumption have led system Increased reliance on natural gas: The increased reliance on natural gas to generate electricity in some regions of the country has sometimes required system operators to take additional actions to maintain reliability. Although all fuel-based electricity generation can face fuel supply challenges, natural-gas-fueled power plants face different challenges than sources such as coal, oil, and nuclear. For example, natural gas is not easily stored on site, so the ability of a natural-gas-fueled power plant to generate electricity generally depends on the real-time delivery of natural gas through a network of pipelines. Some regions have recently experienced challenges in maintaining the delivery of natural gas supplies to power plants. For example, in January 2014, a severe cold weather event know as a “polar vortex” affected much of the central and eastern United States, causing significant outages at plants using various fuel sources and leading to higher than normal demand for natural gas for both electricity generation and home heating. According to FERC, there were no widespread electricity outages. However, challenges delivering fuel to natural-gas-fueled power plants posed significant concerns and resulted in outages at some natural-gas-fueled power plants. System operators took various steps to limit the effect of this event, including relying on power plants that utilize other fuel sources that were more readily available at that time, such as coal and oil, issuing public appeals for conservation, utilizing demand-response resources, and implementing certain emergency procedures. Going forward, several stakeholders raised concerns about the sufficiency of natural gas pipeline capacity in some regions to meet potential greater future needs. However, FERC has reported that actions taken since the 2013–2014 winter—including improved communications between the electricity and natural gas industries and additional cold-weather preparation—led to better operational performance during the 2014– 2015 winter, which also presented extremely challenging cold-weather conditions. In addition, a recent Department of Energy (DOE) study suggests that the future needs for interstate natural gas pipelines may be modest relative to the historical level of pipeline capacity additions. Effects of distributed generation on system operations to maintain reliability The addition of distributed generation such as rooftop solar can present unique challenges that system operators must manage to maintain reliability. Several stakeholders told us that because distributed generation occurs behind a consumer’s meter, such as at an individual residence or business, changes in generation are not visible to or controllable by the system operator without the installation of specialized technology. Regarding the lack of visibility, increases in distributed generation would be seen by the system operator as decreases in demand, since the electricity generated is used on-site and displaces electricity that would have been provided through the grid. Because system operators only see the net effect of these changes, it is more difficult for them to understand and predict demand. Regarding lack of control, if distributed generation results in more electricity than customers can use on site, electricity flows can exceed equipment technical specifications, which could require equipment upgrades. Additionally, if there is more distributed generation than can be used by all customers, the imbalance of supply and demand could put the stability of the grid at risk. Accommodating increased distributed generation may therefore require system operators to, among other things, use models to predict distributed generation patterns or install advanced controls to make distributed generation visible to and controllable by the utility in order to maintain electric reliability. GAO-12-635. the polar vortex. According to ISO New England’s system plan, preserving the reliable operation of the system will become increasingly challenging as a result of expected retirements, and the region is in a precarious position for the next several winters as retirements continue and actions to address retirements—such as investments in the addition of new transmission and power plants— are years away from completion. Changes in electricity consumption. Changes in electricity consumption may require system operators to take additional actions to maintain reliability both in the long and short-term. Over the long- term, system operators need to ensure they have sufficient generating and transmission capacity to meet forecasted consumer electricity needs. This means that a system operator may need to continually add more transmission or generation capacity when peak demand is rising, even if average consumption is stable or declining. In the short- term, system operators may need to take actions to increase or decrease the use of power plants and demand-response resources to address deviations between forecasted and actual consumption. According to NERC, the electricity industry faces several challenges in forecasting electricity consumption, because conservation programs, distributed generation, and other changes in electricity consumption have increased the uncertainty of traditional forecasting methods used in long-term and short-term planning. The degree to which system operators have had to take additional actions to maintain reliability in response to changes in generation and consumption varies regionally based on the extent of these changes and other characteristics. For example, the extent to which system operators manage the grid in response to wind and solar growth will depend on factors such as the relative amount of generation from wind and solar power plants compared to traditional power plants, the size of a region’s grid and how interconnected it is with neighboring grids, and other factors. In this regard, representatives of Midcontinent Independent System Operator said they have been able to reliably accommodate larger amounts of wind generation without major operational challenges or the need for significant additional ancillary services because the large size of their grid and its extensive connections to neighboring grids provide a broad base of power plants that system operators can use to balance variations in the output of wind power plants.literature we reviewed and representatives of the largest utility in Hawaii, while that state has been able to reliably integrate high levels of wind and solar, its isolated island grids means it has no neighboring grids to turn to for balancing variations in the output of wind and solar electricity generation. Therefore, system operators there have fewer backup resources to turn to in the event of an unexpected change in wind and solar output than system operators managing larger, more integrated grids. Changes in generation and consumption, together with associated actions system operators have taken to maintain reliability, have influenced consumer electricity prices in complex, interrelated, and sometimes contradictory ways, and the net effect of these changes on consumer prices is unclear, based on our review of literature and discussions with stakeholders. National average real consumer electricity prices were nearly 11 percent higher in 2014 than 2001, but prices over this period fell in 5 years, rose in 6 years, and were relatively stable in 2 years (see fig.7). Prices and trends vary by consumer type and region. (App. V provides additional information on prices by consumer type and region.) Several stakeholders we interviewed and literature we reviewed highlighted several ways changes in generation and consumption, together with associated actions system operators have taken to maintain reliability, have influenced electricity prices. In many cases, these changes in generation and consumption affect prices at the wholesale level. The extent to which and how quickly such wholesale price changes flow through to retail consumer prices depends on a region’s regulatory structure, individual retail contracts, consumer type, and other factors. A complete assessment of these factors and their net effect was outside the scope of this report. Nevertheless, literature and stakeholders highlighted the following ways changes have influenced prices: Wholesale electricity prices and natural gas prices have tended to move in tandem. Increases in gas-fueled generation have influenced electricity prices, and average annual prices of natural gas and wholesale electricity—electricity for resale—at key hubs have generally moved in tandem since 2002, the earliest year for which data are available. (Fig. 8 shows real annual average natural gas prices and electricity prices at a key wholesale gas hub and a key electricity hub.) Specifically, natural gas prices more than doubled from 2002 to a peak in 2005, declined somewhat, and peaked again in 2008. According to EIA, these increases in prices were initially due to increasing demand for natural gas and hurricanes that disrupted Gulf Coast natural gas production, among other factors. Natural gas prices dropped in 2009 and have remained low since—the result of lower demand due to the economic recession and increasing natural gas production from development of shale gas resources, among other factors. These changing natural gas prices generally contributed first to higher and then lower wholesale electricity prices since 2002. Additionally, as discussed previously, pipeline constraints and competing demands have affected the delivery of natural gas in some regions. This situation has influenced natural gas and wholesale electricity prices during the winter months. For example, during January 2014, the month a polar vortex occurred, monthly natural gas and wholesale electricity prices in New England—a region heavily dependent on natural gas for generating electricity—reached their highest levels, according to available historical data. Prices moderated the following winter, with January 2015 wholesale electricity prices in New England around 60 percent lower than prices the previous January. More generally, FERC reported that wholesale electricity prices were more moderate in January and February 2015 compared to January and February 2014, helped by more stable and less volatile natural gas prices. Negative wholesale electricity prices In some instances, wholesale electricity markets experience negative prices—that is, power plant owners paying consumers to take their electricity. For example, owners of certain power plants are sometimes unwilling or unable to reduce their generation even if there is little or no demand for the electricity they generate. This can be the case for owners of wind plants, which may receive $23 per MWh of electricity generated from the federal Production Tax Credit, sometimes making it economically beneficial for these wind plants to pay consumers to take their electricity so they can continue to receive the credit. It can also be the case for power plants that are costly to shut down and restart, such as nuclear plants. Owners of these power plants may be willing to accept negative prices for a short time in order to avoid the cost of shutting the plant down. Our analysis of available hourly data at electricity hubs within U.S. regional transmission organizations indicates that negative prices occurred on average 0.7 percent of the time from 2005 through 2014. Specific trends in instances of negative prices varied by electricity hub, and the annual percent of negative prices varied across the hubs, ranging from 0 percent to 9.8 percent over that time period. In most cases, any payment consumers might receive as a result of these negative prices is more than offset by the cost of purchasing electricity in other hours. However, negative prices could affect the profitability of individual power plants in areas where negative prices occur. expected to contribute to lower prices.regionally and over time based on, among other things, what alternative power plants exist in a region, the cost of those alternatives, and the amount of federal and state financial support for wind and solar development. For example, according to a DOE study published in 2014, the average cost of procuring electricity from wind power plants was lower than the cost of purchasing electricity through the wholesale markets in 2005—a time of high natural gas and wholesale electricity prices. Conversely, in 2009, after the price of natural gas and wholesale electricity had dropped, the average cost of procuring electricity from wind power plants was higher than the cost of purchasing electricity through the wholesale markets. Some of the costs of wind and solar projects are paid for by taxpayers, which can offset the prices that some retail consumers may have otherwise had to pay for electricity generated from wind and solar. According to this DOE study, prices for procuring wind have been lower as a result of federal and, in some cases, state tax incentives. Second, as with the addition of other new power plants, the effect of new wind and solar sources on consumer prices also depends on the relative costs of any transmission and ancillary services system operators determine are needed to reliably integrate wind and solar sources into the grid. To the extent that additional ancillary services and transmission upgrades are needed, these costs may be passed on to consumers, contributing to higher electricity prices. For example, Texas recently completed a significant transmission project primarily designed to move electricity generated by wind power plants in remote parts of the state to population centers, such as Dallas and Austin. The project has cost close to $7 billion, which will be recovered from Texas electricity consumers through retail electricity prices. Traditional power plants also face grid integration costs. Taken all together, the addition of wind and solar sources could have contributed to higher or lower consumer electricity prices at different times and in different regions. Financial viability of baseload power plants Lower utilization and lower electricity prices have affected the financial viability of some power plants that have traditionally operated as baseload plants in restructured regions, according several stakeholders we interviewed and literature we reviewed. In some instances, baseload plants have been utilized less often in recent years as natural gas-fueled plants have become more cost competitive and the levels of wind and solar generation have increased. Additionally, lower annual wholesale electricity prices starting in 2009 have reduced the revenue power plants earn when they are operating. According to several stakeholders and literature, these factors have sometimes made it difficult for baseload power plants to recover their costs and earn a profit. These difficulties can be exacerbated if additional investment is needed to continue to operate the power plant, for example, the installation of pollution controls to comply with environmental regulations. Some baseload coal and nuclear plants have retired in recent years, with these factors reportedly influencing their decision. For example, Entergy retired its 604 MW Vermont Yankee nuclear plant in 2014, which company financial filings attributed to sustained low natural gas and wholesale electricity prices and high power plant costs, among other factors. According to several stakeholders and literature, if plant utilization and wholesale prices remain low, owners could choose to retire more unprofitable plants in the future, which could raise reliability and price concerns. The effect of retirements on prices may vary. The effect of power plant retirements on prices may vary, depending on the cost of the retiring power plant compared to the costs of existing power plants and power plants built to replace retiring power plants, among other things. If retiring plants are less expensive than existing and replacement power plants, their retirement would generally be expected to raise prices. For example, according to EIA, after the initial shutdown of San Onofre Nuclear Generation Station in 2012—a large nuclear power plant in Southern California that produced low- cost electricity—prices in Southern California increased in 2012 and 2013, a change that EIA said is likely attributable in part to the need for more expensive generation in that region to fill the shortage from San Onofre’s closure. Alternately, if retiring power plants are replaced by power plants with similar or lower costs, prices could remain unchanged or decline in some hours. The relative cost of retiring and new power plants depends on the specific circumstances of the retiring and potential replacement plants, and may change over time with changing fuel prices and other market factors. Lower electricity consumption could reduce prices. Lower consumption of electricity—whether in all hours or, particularly, at peak times—can lower the price of electricity in wholesale markets, a decline that may translate into lower prices for retail consumers. Electricity consumption could decline in a given hour, for example, because of demand-response activities in which consumers reduce their electricity consumption in response to prices or other incentives. Electricity consumption could also decline over a longer time period— for example because of reduced consumption due to a slowdown in economic growth or increased adoption of energy efficient technologies. These declines in consumption could lower prices in some or all hours by reducing use of the highest cost plants. According to PJM Interconnection, demand-response activities served as an alternative to generating additional electricity during a heat wave in 2012, which lowered prices. We provided drafts of this product to DOE and FERC for review and comment. The agencies provided technical comments on early or final drafts, which we incorporated as appropriate. As agreed with your offices, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies to the appropriate congressional committees, the Secretary of Energy, the Chairman of FERC, and other interested parties. In addition, the report will be available at no charge on the GAO website at http://www.gao.gov. If you or your staff members have any questions about this report, please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report. GAO staff who made key contributions to this report are listed in appendix VI. This report examines changes in electricity markets. Our objectives were to describe what is known about (1) how electricity generation and consumption have changed since 2001, and (2) the implications of these changes on efforts to maintain reliability, and on electricity prices. To conduct this work, we analyzed data on electricity generation and consumption; reviewed literature, including studies by federal agencies, electricity grid operators, and consultants; and summarized the results of interviews with a nonprobability sample of 21 stakeholders. To describe changes in electricity generation, we primarily used data from SNL Financial (SNL), current as of April 3, 2015. We generally present data on changes from 2001 through 2013 because 2013 is the most recent year for which complete data are available, though in some instances we present more recent data. We obtained SNL data on power plants with capacities of at least 1 megawatt that are connected to the grid and intend to sell electricity to retail customers or retail service providers. We used the SNL-identified primary energy source for the most recent year for each generating unit at a given power plant and used data for each generating unit for our calculations, where available.these generating unit level data to calculate total generating capacity and percentage of total generating capacity for each year from 2001 through 2014 (the most recent year with complete data). We calculated similar totals and percentages for actual generation for each year from 2001 through 2013 (the most recent year with complete data). However, some power plants provide generation data at the more detailed generating unit level, while others only provide data for the entire plant.generation calculations, and this unit data accounted for 71 percent of total generation in 2013. When generating unit data were not available, we identified the total actual generation for the year at a given plant and divided it among the units based on share of total generating capacity for each generating unit. These plant level data accounted for the remaining 29 percent of actual generation in 2013. This approach implicitly assumes that all units at a given plant are used with the same intensity to generate electricity, an assumption that may not be appropriate on average. To examine changes in the intensity with which power plants are operated, or their utilization, we analyzed annual capacity factor data—the ratio of actual generation to the maximum potential to generate electricity. Where available, we used the generating unit data for our actual To describe changes in electricity consumption and electricity prices, we examined EIA data on retail sales of electricity to consumers. Retail electricity prices can be difficult to determine, according to EIA, as they depend on a customer’s rate structure, which can differ from utility to utility. EIA does not directly collect data on retail electricity rates. However, using data collected on revenues and electricity sold, EIA calculates average retail revenue per kilowatt hour as a proxy for retail electricity prices. To determine the frequency that negative prices occurred in markets of regional transmission organizations, we analyzed price data from hubs at each of the seven regional transmission organizations.hubs and starting-time periods for the data varied with each regional transmission organization. We obtained hourly wholesale electricity prices The number of from SNL for each regional transmission organization and calculated the number and percentage of occurrences of negative prices in each. We took several steps to assess the reliability of SNL and EIA data. We reviewed relevant documentation, interviewed EIA and SNL representatives, and compared some data elements to those available from other sources. We determined the data were sufficiently reliable for the purposes of this report. To identify the implications of changes, we reviewed literature and interviewed stakeholders. We identified literature by conducting a literature search and obtaining suggestions from the stakeholders we interviewed. Specifically, we searched sources including Proquest Environmental Science Professional, PolicyFile, Web of Science, and the web sites of system operators and federal agencies from December through March 2015. Stakeholders included power plant owners, grid operators, a state regulator, non-governmental organizations, and federal agencies. We identified stakeholders through our research and analysis of changes in generation and consumption, using our past work, and by considering the suggestions of other stakeholders. We selected stakeholders to represent different perspectives and experiences regarding changes in the industry, and to maintain balance with respect to sources of electricity and stakeholders’ roles in the market. Because this was a nonprobability sample, the views of stakeholders we selected are not generalizable to all potential stakeholders, but they illustrate a range of views. Throughout the report we use the indefinite quantifier, “several” when three or more stakeholder and literature sources combined supported a particular idea or statement. Identifying and examining federal agency actions to address the challenges identified was beyond the scope of this review. We conducted this performance audit from November 2014 to May 2015 in accordance with generally accepted government auditing standards. Those standards require that we plan and perform the audit to obtain sufficient, appropriate evidence to provide a reasonable basis for our findings and conclusions based on our audit objectives. We believe that the evidence obtained provides a reasonable basis for our findings and conclusions based on our audit objectives. Figure 9 shows the territories of eight regional reliability entities that set and enforce reliability standards for the electricity industry and four sub- regions for the Western Electricity Coordinating Council. Table 2 provides generating capacity and annual generation by source in these regions as well as Alaska and Hawaii for select years. Regional Transmission Organizations (RTO) manage regional networks of electric transmission lines as system operators, including operating organized markets for buying and selling electricity and other needed services to operate the grid, such as ancillary services. Figure 10 shows the RTOs in the United States, and table 3 provides generating capacity and actual generation by source for each RTO and generating capacity and actual generation by source outside of RTO regions. Table 4 provides annual generating capacity and generation by regulatory status and source for select years. Table 5 provides generating capacity additions and retirements by source. Table 6 below shows retail electricity sales—a proxy for electricity consumption—by consumer type, and table 7 shows retail electricity sales by region. Table 8 shows average retail revenue per kilowatt hour—a proxy for electricity prices—by consumer type, and table 9 shows average retail revenue per kilowatt hour by region. In addition to the individual named above, Jon Ludwigson (Assistant Director), Eric Charles, Philip Farah, Quindi Franco, Cindy Gilbert, Paige Gilbreath, Michael Kendix, Armetha Liles, Alison O’Neill, MaryLynn Sergent, Maria Stattel, and Barbara Timmerman made key contributions to this report. Electricity Generation Projects: Additional Data Could Improve Understanding of the Effectiveness of Tax Expenditures. GAO-15-302. Washington, D.C.: April 28, 2015. Energy Policy: Information on Federal and Other Factors Influencing U.S. Energy Production and Consumption from 2000 through 2013. GAO-14-836. Washington, D.C.: September 30, 2014. EPA Regulations and Electricity: Update on Agencies’ Monitoring Efforts and Coal-Fueled Generating Unit Retirements. GAO-14-672. Washington, D.C.: August 15, 2014. Electricity Markets: Demand-Response Activities Have Increased, but FERC Could Improve Data Collection and Reporting Efforts. GAO-14-73. Washington, D.C.: March 27, 2014. Wind Energy: Additional Actions Could Help Ensure Effective Use of Federal Financial Support. GAO-13-136. Washington, D.C.: March 11, 2013. Electricity: Significant Changes Are Expected in Coal-Fueled Generation, but Coal is Likely to Remain a Key Fuel Source. GAO-13-72. Washington, D.C.: October 29, 2012. Solar Energy: Federal Initiatives Overlap but Take Measures to Avoid Duplication. GAO-12-843. Washington, D.C.: August. 30, 2012. EPA Regulations and Electricity: Better Monitoring by Agencies Could Strengthen Efforts to Address Potential Challenges. GAO-12-635. Washington, D.C.: July 17, 2012. Electricity Grid Modernization: Progress Being Made on Cybersecurity Guidelines, but Key Challenges Remain to be Addressed. GAO-11-117. Washington, D.C.: January 12, 2011. Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional Transmission Organizations’ Benefits and Performance. GAO-08-987. Washington, D.C.: September 22, 2008.

Summary: Electricity in the United States has traditionally been generated largely from coal, natural gas, nuclear, and hydropower energy sources. More recently, various federal and state policies, tax incentives, and research and development efforts have supported the use of renewable energy sources such as wind, solar, and geothermal. In addition, consumption of electricity has been affected by federal efforts to improve energy efficiency, changes in the economy, and other factors. GAO was asked to provide information on changes in the electricity industry. This report examines what is known about (1) how electricity generation and consumption have changed since 2001 and (2) the implications of these changes on efforts to maintain reliability, and on electricity prices. GAO analyzed data on electricity generation, consumption, and prices and reviewed literature. GAO also interviewed 21 stakeholders, including government officials, and industry representatives, selected to represent different perspectives and experiences regarding changes in the industry. GAO is not making recommendations in this report. The Department of Energy and Federal Energy Regulatory Commission reviewed a draft of this report and provided technical comments that GAO incorporated as appropriate. The mix of energy sources for electricity generation has changed, and the growth in electricity consumption has slowed. As shown in the figure below, from 2001 through 2013, natural gas, wind, and solar became larger portions of the nation's electricity generation, and the share of coal has declined. These changes have varied by region. For example, the majority of wind and solar electricity generation is concentrated in a few states—in 2013, California and Arizona accounted for over half of electricity generated at solar power plants. Regarding consumption, national retail sales of electricity grew by over 1 percent per year from 2001 through 2007 and remained largely flat from that time through 2014. The literature GAO reviewed and stakeholders GAO interviewed identified the following implications of these changes: Maintaining Reliability : System operators, such as utility companies, have taken additional actions to reliably provide electricity to consumers. For example, some regions have experienced challenges in maintaining the delivery of natural gas supplies to power plants. In particular, severe cold weather in the central and eastern U.S. in 2014 led to higher than normal demand for gas for home heating and to generate electricity. Challenges delivering fuel to natural-gas-fueled power plants resulted in outages at some plants. System operators took various steps to limit the effect of this event, including relying on power plants that utilize other fuel sources that were more readily available at the time, such as coal and oil-fueled power plants, and implementing certain emergency procedures. Prices : Increased gas-fueled generation has influenced electricity prices, with wholesale electricity prices and gas prices generally fluctuating in tandem over the past decade. The effect of the increased use of wind and solar sources on consumer electricity prices depends on specific circumstances. Among other things, it depends on the relative cost of wind and solar compared with other sources, as well as the amount of federal and state financial support for wind and solar development that can offset some of the amount that consumers might otherwise pay. Taken together, the addition of wind and solar sources could have contributed to higher or lower consumer electricity prices at different times and in different regions.