The United States has been an integral part of the global energy sector for many decades. It is a global leader in energy production, consumption, and technology, and its energy market is highly sophisticated. Its energy prices, for the most part, are determined in the marketplace and rise or fall with changes in supply and demand. The United States is a major producer of all forms of energy—oil, natural gas, coal, nuclear power, and renewable energy. Since the beginning of the 21 st century, the U.S. energy sector has transformed from a situation of declining production, especially of oil and natural gas, to one in which the United States is a growing producer. Exports of energy are rising while imports are falling. Prices, technology, and regulations have prompted changes in the energy mix. This report provides an overview of U.S. energy issues, and it serves as an initial resource document for related information, data, and CRS contacts. The report is organized around the major fuels and energy sources used in the United States. It also highlights the role of the federal government, particularly the use of federal lands in energy production. It does not focus on energy infrastructure, security, research and development, energy efficiency, or environmental issues, although those areas are also critical to the U.S. energy sector. Energy policy in the United States has generally focused on three major goals: assuring a secure supply of energy, keeping energy costs low, and protecting the environment. In pursuit of those goals, government programs have been developed to improve energy efficiency, to promote the domestic production of conventional energy sources, and to develop new energy sources, including advanced nuclear and renewable energy sources. Implementing these programs sometimes has been controversial because of the varying importance given to different aspects of energy policy by different stakeholders. For some, dependence on imports of energy, particularly from the Persian Gulf, is the primary concern; for others, the continued use of fossil fuels, whatever their origin, is of greatest concern. The extent to which human-induced global climate change warrants changing U.S. energy policy to reduce the production and use of fossil fuels is particularly controversial. Another dichotomy is between those who see government intervention in the energy sector as a positive force, and those who do not and seek to restrict government intervention as much as possible. Energy policy has often been legislated in large, complex bills that deal with a wide variety of issues, with debate spanning several sessions. The Energy Policy Act of 2005 (EPAct 2005; P.L. 109-58 ) was the most recent comprehensive general legislation, with provisions and authorizations in almost all areas of energy policy. The Energy Independence and Security Act of 2007 (EISA, P.L. 110-140 ) set new target fuel economy standards for cars and light trucks of 35 miles per gallon by 2020, and expanded the renewable fuels standard (RFS) to require 9.0 billion gallons of biofuels in transportation in 2008 (equivalent to 600,000 barrels per day), rising to 36 billion gallons by 2022 (equivalent to 2.4 million barrels per day). EISA also included energy efficiency standards for appliances and other equipment, and provisions on industrial and building efficiency, which have continued to be of interest in the 115 th Congress. In the 114 th Congress, both the House and Senate considered broad energy legislation, as well as specific topics of key interest. The two primary bills were S. 2012 , the Energy Policy and Modernization Act, and H.R. 8 , the North American Energy Security and Infrastructure Act of 2015. After the House passed S. 2012 with the text of H.R. 8 , a conference committee met to consider the two versions of S. 2012 but did not resolve the differences before the 114 th Congress adjourned. Both bills addressed a variety of energy topics, including energy efficiency in federal buildings, data centers, manufacturing, and schools; water conservation/efficiency; regulation and development of nonfederal hydropower; electric grid cybersecurity; and review of the Strategic Petroleum Reserve (SPR). In the 115 th Congress, a range of energy bills have been proposed. Most notably, the Arctic National Wildlife Refuge (ANWR) was opened to oil and gas development under the 2017 tax revision ( P.L. 115-97 ). The law directs the Secretary of the Interior to establish an oil and gas leasing program in ANWR's coastal plain. Other energy-related bills have been introduced, including S. 1460 , the Energy and Natural Resources Act of 2017. S. 1460 includes provisions on energy efficiency, energy and minerals supply, and energy infrastructure, among other provisions. (Many of the provisions in S. 1460 are similar or identical to provisions in the Senate version of S. 2012 in the 114 th Congress.) The Senate Committee on Energy and Natural Resources held hearings on the bill in September 2017, but no further action has been taken. Other bills in the 115 th Congress include House-passed bills to require federal agencies to coordinate on energy-efficient information technology ( H.R. 306 ), assist states with emergency energy planning ( H.R. 3050 ), and temporarily store nuclear waste ( H.R. 3053 ). The United States is the second largest producer and consumer of energy in the world, behind China. U.S. primary energy consumption (see Figure 1 ) has held relatively steady since 2000, falling 1%; however, the fuel mix has changed. While oil has remained at almost 40% of the fuel mix, natural gas and renewables have increased in both percentage and absolute terms at the expense of coal. Nuclear generation has stayed flat. The change in the U.S. fuel mix has centered on the electricity sector where there are fuel substitutes (see " The Electric Power Sector "). Electric power generation in 2017 came from coal (30%), natural gas (32%), nuclear (20%), renewables (17%), and petroleum (<1%), according the U.S. Energy Information Administration (EIA). This is a significant change from 2000, when coal accounted for 52% of the electricity fuel mix and natural gas was 16%, nuclear was still almost 20%, and renewables were 9%. Industrial use of energy has also experienced changes, but not to the same degree as electric power generation in recent years. On the other end of the spectrum, energy in transportation is dominated by petroleum, which made up 92% of the fuel used in transportation in 2017, down from 97% in 2000. U.S. energy production between 2000 and 2017 increased 23%, a significant amount, especially considering that historically the United States was viewed as a growing importer of energy. (See Figure 1 .) Renewable energy production has increased by 83% during the time frame, the largest increase of all fuel types. Oil production has risen the next fastest, growing 64%, followed by natural gas production at 42%. The increase in production of both these resources comes from innovations in extraction from unconventional (or tight ) formations, such as shale (see text box below, "Shale Resources Make the Difference"). Coal production, on the other hand, has declined during the time period by about 31%. Federal lands account for a significant amount of total U.S. energy production. For example, in 2017, as a percentage of total U.S. energy production, approximately 24% of crude oil and 13% of natural gas gross withdrawals came from federal lands. In 2016 (the latest year for this data), 40% of coal came from federal lands. Weighing energy production on federal lands against other resource values has long been a fundamental question for Congress. Much of the onshore federal estate is open to energy and mineral exploration and development, including Bureau of Land Management (BLM) and many Forest Service (FS) lands. However, many National Park Service (NPS) lands and areas within the National Wilderness Preservation System, as well as certain other federal lands, have been specifically withdrawn from exploration and development. One previously withdrawn area—the Arctic National Wildlife Refuge—was recently opened to oil and gas development under the Tax Cuts and Jobs Act ( P.L. 115-97 ). The law directs the Secretary of the Interior to establish an oil and gas leasing program in ANWR's coastal plain. Development of oil, natural gas, and coal on federal lands is governed primarily by the Mineral Leasing Act of 1920 (MLA). Geothermal leasing on federal lands is conducted under the authority of the Geothermal Steam Act of 1970, as amended. Development of solar and wind energy sources on BLM and FS lands is governed primarily by right-of-way authorities under Title V of the Federal Land Policy and Management Act (FLPMA). Offshore federal resources, within and beyond the U.S. Exclusive Economic Zone (EEZ), are also open for exploration and development. The federal government is responsible for managing energy resources in approximately 1.7 billion acres of waters belonging to the United States. These offshore resources are governed by the Outer Continental Shelf Lands Act of 1953 (OCSLA), as amended. Federal lands also are available for renewable energy projects. BLM manages the solar and wind energy programs on about 20 million acres for each program and has the authority to manage about 240 million acres for geothermal leasing on federal lands. Geothermal capacity on federal lands represents 40% of U.S. total geothermal electric generating capacity. Oil production fluctuated year-to-year on federal lands from 2008 to 2017 but overall it increased by 47% over the 10-year period. However, because crude oil production on nonfederal lands doubled over the decade (primarily due to improved extraction technology, favorable geology, and the ease of leasing), the share of total U.S. crude oil production from federal lands fell from its peak of nearly 36% in 2009 and 2010 to about 24% in 2017. While annual U.S. natural gas gross withdrawals rose by over 7 trillion cubic feet (TCF) to 33.2 TCF since 2008, annual production on federal lands fell by about 2 TCF (or nearly 32%) to 4.3 TCF over the same time period. The share of gross natural gas withdrawals from federal lands fell from almost 25% in 2008 to 13% in 2017. The big shale gas plays have been primarily on nonfederal lands and have attracted a significant portion of investment for natural gas development. The MLA authorizes the Secretary of the Interior—through BLM—to lease the subsurface rights to virtually all BLM and FS lands that contain fossil fuel deposits, with the federal government retaining title to the lands. Based on the federal government's 2008 inter-agency Phase III inventory report, 113 million acres of onshore federal lands are open and accessible for oil and gas development and about 166 million acres are off-limits or inaccessible. The accessible federal land contains an estimated 11.5 billion barrels of oil and 136.5 TCF of natural gas, representing 38% and 59% of the estimated total federal resource potential, respectively. Federal land off-limits to development contains an estimated 19 billion barrels of oil and 95 TCF of natural gas, or 62% and 41% of the total resource potential, respectively. In 2017, the BLM recorded production on 12.8 million acres out of 26 million acres of federal land leased for oil and gas development. For offshore oil and gas, OCSLA requires the Secretary of the Interior to submit five-year leasing programs that specify the time, location, and size of the areas to be offered. The Bureau of Ocean Energy Management (BOEM), which runs the offshore energy leasing program, administers approximately 2,700 active oil and gas leases on over 14 million acres in the outer continental shelf (OCS). In preparing its five-year programs under the OCSLA, BOEM must consider the resource potential of individual OCS regions and planning areas along with other factors, such as potential environmental and socioeconomic impacts of oil and gas leasing. The current five-year leasing program (2017-2022) scheduled 11 lease sales in about 6% of the acreage in the OCS planning areas, but including about 80% of the oil and gas undiscovered technically recoverable resources (UTRR). In January 2018, the Trump Administration introduced a new 5-Year Leasing Program proposal for 2019-2024. This Draft Proposed Program (DPP) includes 47 lease sales (a sale in each of the planning areas except the North Aleutian Basin in Alaska). The DPP would make available 90% of the acreage in the OCS planning areas and 98% of its UTRR. Under the OCSLA, the President may withdraw unleased lands on the OCS from leasing disposition. Congress also has established leasing moratoria; for example, the Gulf of Mexico Energy Security Act (GOMESA) established a moratorium on preleasing, leasing, and related activity in the eastern Gulf of Mexico through June 2022. According to BOEM, the U.S. OCS contains UTRR estimated at 89.9 billion barrels of oil and 327.5 TCF of natural gas. The Gulf of Mexico contains about 54% of the UTRR for oil and an estimated 43% of the natural gas, with the vast majority of the resources in the Central Gulf of Mexico. The OCS around Alaska has the second largest UTRR, and about 90% of Alaska's UTRR estimates for oil and 80% for natural gas are contained in the Chukchi and Beaufort Seas. Congress considers multiple issues related to offshore oil and gas exploration, including questions about allowing or deferring access to ocean areas and how increasing or restricting access may impact domestic energy markets and affect the risk of oil spills. Other issues concern the use of OCS revenues and the extent to which they should be shared with coastal states. There are 298 federal coal leases on about 459,000 acres on federal public domain lands. Coal production on federal lands has consistently accounted for about 40% of total U.S. coal production over the past decade. Production on federal lands peaked in 2008 at 487 million tons. Since then, federal coal production declined by 33% to 326 million tons in 2016, the latest year for this data. On January 16, 2016, President Obama announced a moratorium on federal coal leasing (issued as Secretarial Order 3338) to examine the federal coal leasing program and to determine whether it needs to be "modernized." The Secretary of the Interior directed BLM to prepare a programmatic environmental impact statement (PEIS) of the coal leasing program to serve as the basis for a comprehensive review. On January 11, 2017, the Obama Administration published its scoping report as a prelude to a comprehensive draft and final PEIS. However, on March 28, 2017, the Trump Administration issued an Executive Order that requires the Secretary of the Interior to "take all steps necessary and appropriate to amend or withdraw Secretary's Order 3338" and lift "any and all" moratoria on federal coal leasing. The moratorium has drawn both support and opposition in Congress. On March 29, 2017, Secretary of the Interior Zinke revoked Secretarial Order 3338 under Secretarial Order 3348, lifting the moratorium and ending the work on the PEIS. Secretarial Order 3348 directs the BLM to continue to process coal leasing applications on federal land. Geothermal energy is a renewable energy source produced from heat stored under the surface of the earth. BLM manages geothermal permitting and leasing requirements for federal lands, in consultation with FS. Geothermal capacity on federal lands represents 40% of U.S. total geothermal electric generating capacity. Wind and solar projects could require large tracts of land to replace or add significant electric generating capacity, in addition to new transmission capacity that may be needed. One issue for Congress is how to weigh solar and wind project applications against other land uses. For example, in 2013, BLM finalized a rule allowing temporary withdrawal of subsurface mineral claims in areas with pending wind and solar project applications. Another issue for Congress is how the leasing process for wind and solar energy projects should be managed. In December 2016, BLM finalized amendments of the regulations governing the process by establishing preferred areas for solar and wind energy development and establishing specific competitive right-of-way leases, among other provisions. Removing woody biomass from federal lands for energy production has received attention from stakeholders in the biomass supply chain for energy and wildfire management because of its potential widespread availability. Past administration efforts to promote and implement woody biomass energy production focused on developing policy principles, research and development, infrastructure, and capacity building. FS and BLM both award woody biomass utilization research grants pursuant to EPAct2005. Programs such as stewardship contracting and the collaborative forest landscape restoration program authorize both agencies to implement woody biomass utilization projects. BOEM is responsible for managing renewable ocean energy resources. BOEM has been in the process of estimating renewable ocean energy resources to facilitate leases for electricity generation from offshore wind, thermal power, and kinetic forces from ocean tides and waves. As of June 2018, BOEM had issued 13 offshore wind energy leases in areas off the coasts of Massachusetts, Rhode Island, Delaware, Maryland, Virginia, New York, North Carolina, and New Jersey. One lease within the Offshore Renewable Energy Program, the Block Island Wind Farm off the coast of Rhode Island, which is a five-turbine, 30-Megawatt (MW) wind farm developed by Deepwater Wind, has achieved commercial production. Congress has considered whether to facilitate the development of offshore wind and other renewables through steps such as grants for research and development, project loan guarantees, extension of federal tax credits for renewable energy production, or oversight of regulatory issues for these emerging industries. The federal government collects revenues from onshore and offshore energy development through a variety of laws. Revenues are derived from development of several energy resources—including oil, gas, coal, geothermal, wind, and solar—and are collected at several stages of the development process. Companies pay bonus bids to secure development rights, rents on energy leases prior to production, royalties during production, and other fees. For offshore energy development, the Outer Continental Shelf Lands Act (OCSLA, 43 U.S.C. §§1331-1356b) provides for limited revenue-sharing with coastal states. States receive 27% of revenues from oil, gas, and renewable energy leases within 3 nautical miles of state waters (43 U.S.C. § 1337(g) and (p)). Also, the Gulf of Mexico Energy Security Act (GOMESA, 43 U.S.C. §1331 note) provides for revenue-sharing with the Gulf coastal states of Alabama, Louisiana, Mississippi, and Texas. These four Gulf coastal states receive 37.5% of revenues on qualified leases, up to an annual cap of $375 million. In addition to revenue-sharing with states, various laws also direct portions of federal offshore oil and gas revenues to specific federal programs such as the Land and Water Conservation Fund Act (LWCF Act; 54 U.S.C. §§200301 et seq.) and the Historic Preservation Fund. Separately, GOMESA disburses to the LWCF state assistance program a further 12.5% of revenues on qualified Gulf leases, up to an annual cap of $125 million. Under OCSLA, the remainder of offshore revenues are deposited as miscellaneous receipts in the U.S. Treasury. For onshore revenues, the Mineral Leasing Act (MLA) provides for the State of Alaska to receive 90% of the revenue derived from federal onshore fossil energy (oil, gas, and coal) leases within the state, except for leases held in the coastal plain of ANWR. Alaska receives 50% of the ANWR–related lease sales revenue and 50% is deposited in the U.S. Treasury. All other states receive 50% (minus a 2% cost-sharing deduction) of the revenues derived from fossil energy leases within their states, while 40% of the revenues are deposited in the Reclamation Fund. The balance stays within the U.S. Treasury as miscellaneous receipts. For geothermal energy on federal land, the MLA provides 50% of the revenues to the state and 25% to the counties from which geothermal energy is produced. The balance of 25% is deposited in the U.S. Treasury. Other renewable energy on federal land such as wind and solar is developed under Title V of the Federal Land Policy Management Act, under which all revenues derived from its development are deposited in the U.S. Treasury. Production of oil in the United States rose in the latter half of the time period 2000-2017, while consumption fluctuated. The rise in production is attributed to increased production from unconventional or "tight" formations, discussed above. Petroleum is mostly consumed in transportation (71%), industrial use (24%), residential and commercial use (5%), and electric power generation (1%). Approximately 92% of transportation fuels come from petroleum. No other sector in the U.S. economy is so dominated by one fuel source as is transportation, which is why fuel efficiency of vehicles (see text box "Fuel Efficiency Standards for Vehicles") is so significant to energy policy. Energy independence and energy security are more associated with petroleum than with any other fuel. The petroleum refining industry processes crude oil and other petroleum-based liquids to produce transportation fuels (including motor gasoline, diesel fuel, aviation gasoline, and jet fuel), home heating oil, petrochemical feedstocks, lubricants, and other products. The United States is the top-producing country of refined products. In 2017, most of the product mix was composed of transportation fuels, with home heating oil, petrochemical feedstocks, lubricants, and other products from liquefied refinery gases to asphalt and road oil making up the rest. While the number of U.S. refineries (see Table 1 ) declined by 23, or 15%, since 2000, the industry's refining capacity has not been in decline. Capital investment in new technologies and processes has resulted in refinery capacity increasing by about 13% since 2000. The data suggest that refineries are becoming larger on average and more efficient. Utilization rates in the industry, which are the ratio of petroleum that runs through a refinery and its operating capacity, are high and relatively stable. However, the economic downturn that began in 2008-2009 resulted in reduced demand for petroleum products, keeping utilization rates below 90% until 2014. The oil and natural gas producing industries and the petroleum refining industry are closely related because of their complementary relationship. There are few, if any, consumer uses for unrefined crude oil, and refiners must use crude oil to produce the useful products the refining process yields. Because of this symbiotic relationship, many times the sectors' contributions to the national economy are combined. For example, according to a 2017 American Petroleum Institute report, the oil and natural gas industries, which included production and refining, supported about 10.3 million jobs and accounted for 8% of U.S. gross domestic product in 2015. The U.S. refining industry draws on crude oil supplies from around the world as well as domestic production. Table 2 shows key sources of industry supply. The data in Table 2 show that from 2000 to 2008 U.S. production of crude oil was generally declining while U.S. imports of crude oil were increasing. Over the period, U.S. imports from the Organization of the Petroleum Exporting Countries (OPEC) were also generally increasing. This period was consistent with increasing oil import dependence and declining energy security. In 2009, U.S. production of crude oil began to increase, as did Canadian supplies of crude oil to the United States, which crossed the 2 million barrels per day (Mb/d) rate in 2011. As a result, U.S. imports from OPEC began to decline and the United States entered a period of declining oil import dependence and increasing energy security. The rise in crude oil production, in part, prompted a call from industry to lift restrictions on exporting crude oil. At the end of 2015, President Obama signed the Consolidated Appropriations Act, 2016 ( P.L. 114-113 ), which lifted the restrictions on crude oil exports. Crude oil exports have risen steadily since the restrictions were lifted, reaching a new high of 1.76 Mb/d in April 2018. In addition to unrefined crude oil, the United States also imports refined products (mostly gasoline), although the primary source of petroleum products for U.S. consumers remains the U.S. refining industry. Recently, the refining industry has increased its presence in foreign markets with increasing exports of refined products; the United States became a net exporter of petroleum products in 2011. The data in Table 3 show that since 2007, U.S. dependence on the world market for petroleum products has been declining. In addition, U.S. refiners now allocate over 28% of their operable capacity to supply buyers in the world market. Without considering both U.S. crude oil imports and increasing petroleum product exports, the raw data may give a somewhat distorted picture of U.S. dependence on imported oil. This is because some of U.S. crude oil imports enter the refining industry for processing and re-enter the world market as petroleum product exports. Continued reliance on the world oil market for crude oil supplies and petroleum products, as well as increasing U.S. exports of both crude oil and petroleum products, suggests that any change in U.S. tariff policy will affect the refining industry. The effects of changing U.S. tariff policy might result in a changing pattern of nations that the United States deals with for imports and exports, risking retaliation against U.S. goods, as well as affecting consumer prices for gasoline and other products. Oil prices and the availability of various grades of crude oil will continue to affect the economic performance of the refining industry. Oil prices peaked at over $140 per barrel in 2008 and then began a steep decline that saw the price fall to below $40 per barrel in 2009 before rising above $100 per barrel for much of the early 2010s. Prices dropped again in 2014, reaching a low of less than $30 per barrel in 2016. In September 2018, the price had risen to approximately $70 per barrel. Refiners need an oil price predictable enough so that they can make economically rational petroleum product pricing decisions. However, the price needs to be high enough that it remains profitable for oil producers to continue to invest in production and expand market supply to satisfy demand, and low enough to encourage consumption. Environmental concerns affect the refining industry, including air, water, and land pollution. Permitting a new refinery is an expensive, slow process due to environmental and other challenges, which helps explain why it is more common to expand the capacity of existing facilities rather than construct new facilities. The United States became a net exporter of natural gas in 2017, the first time since 1957. The second U.S. liquefied natural gas (LNG) export terminal opened in 2018, with additional facilities under construction. Since prices peaked in 2008, domestic gas production has risen significantly. (See " U.S. Supply " below.) Improvements in technologies such as hydraulic fracturing and horizontal drilling made the development of unconventional natural gas resources such as shale and other lower-permeability rock formations possible. Improved efficiency has lowered production costs, making shale gas economically competitive at almost any price and enabling large-scale exports. As U.S. production increased and prices fell, U.S. consumption of natural gas grew, rising over 16% from 2000 to 2017. (See " U.S. Consumption " below.) The rise in consumption, though, did not keep pace with production, so companies turned to exports, first by pipeline to Mexico and then as LNG to other parts of the world. (See " U.S. Exports ," below.) As shown in Figure 3 , production and imports (supply) of natural gas were still greater than consumption and exports (demand) in 2017, in part because of increasing amount of natural gas held in storage. The United States is the world's largest producer of natural gas. Since 2005, U.S. natural gas production rose every year until 2016, even as prices declined. Production in 2017 was down from the 2015 peak total of 27,065 billion cubic feet (BCF). 2016 showed the first decline since 2005. The large increase in natural gas production between 2005 and 2017 is mostly attributed to the development of shale gas resources, specifically in the Marcellus and Utica formations in the northeastern United States. The two formations have accounted for 85% of the increase in natural gas production between 2012 and 2015. The United States is the largest consumer of natural gas in the world, using about 24,800 BCF in 2017. Electric power generation made up 37% of U.S. natural gas consumption in 2017; industrial use accounted for 32%, residential use for 18%, and commercial use for 13%. (See Figure 4 .) Low natural gas prices, due to the growth of domestic gas resources, contributed to a significant rise in the use of natural gas for electric power generation. Additionally, some federal and state policies promote the use of fuels with lower greenhouse gas emissions. Demand for natural gas for power generation has grown nearly 80% since 2000, and is expected to continue to grow through 2050. The U.S. industrial sector increased its consumption of natural gas by 16% between 2010 and 2017, and the sector is expected to account for the majority of growth in natural gas consumption through 2050. As the United States continues to expand its natural gas resource base, the industrial sector will see a wider array of fuel and feedstock choices, and manufacturing industries could also experience further growth. Between 2000 and 2008, the United States prepared to increase imports of LNG based on forecasts of growing consumption and lack of supply, and companies began constructing LNG import terminals. However, the rise in prices gave the industry incentive to bring more domestic gas to market, reducing the need for import terminals. Imports in 2017 were 34% below their peak in 2007. Because of the expanded U.S. natural gas production, there has been a push for modification and expansion of existing LNG import terminals for export, as well as construction of new terminals, in order to expand U.S. export capacity. The first LNG shipments from the lower 48 occurred in February 2016 from the Sabine Pass LNG Terminal in Louisiana to Brazil, India, and the United Arab Emirates. Most wells produce a variety of hydrocarbons, including natural gas, oil, and NGLs, as well as other gases and liquids such as nitrogen, hydrogen sulfide, water, and particulate matter. Natural gas liquids (NGLs) have taken on a greater prominence as the price for dry gas dropped, primarily because of the increase in supply. In response to the price drop, the natural gas industry produced more wet gas in order to bolster the value it receives per unit of natural gas produced. Historically, individual NGL products have been priced against oil, except for ethane. When oil prices were high relative to dry gas, it drove an increase of wet gas production, thereby maintaining production of dry gas as a "byproduct" despite its low price. Natural gas is the cleanest-burning of the fossil fuels. Unlike coal or oil, its combustion produces no sulfur oxides or other hazardous air pollutants that would require pollution controls, except for NOx (nitrogen oxides). By contrast, coal combustion is the leading source of sulfur dioxide emissions and also produces about 20 hazardous air pollutants, including mercury. Combustion of natural gas also produces fewer emissions of greenhouse gases (GHGs, primarily carbon dioxide, CO 2 ) than other fossil fuel—about half the amount generated by coal in producing an equivalent amount of heat or power. However, the primary component of natural gas, methane, is more than 25 times as potent a greenhouse gas as CO 2 . Thus, concerns have arisen regarding the release or leaks of methane from production, transmission, and processing of natural gas. As the use of natural gas continues to expand in the United States, reducing emissions of methane has become a more significant concern for policymakers. The electric power industry is in the process of transformation. The electricity infrastructure of the United States is aging, and uncertainty exists around how to modernize the grid, and what technologies and fuels will be used to produce electricity in the future. Unresolved questions about transmission and reliability of the grid also are arising due to potential cybersecurity threats as well as continuing interest in harnessing renewable energy and other low carbon sources of electricity. Concerns about reliability and electricity prices are complicated by environmental regulations and the rising production of electric power from unconventional resources such as shale gas. Congress has played a role already in this process (e.g., tax credits for renewable energy), and may continue to be faced with policy issues regarding how the modernization of this industry will unfold. States have also played major roles in this area through renewable portfolio standards (RPS), and regional emissions trading programs, such as the Regional Greenhouse Gas Initiative (RGGI), among other programs. The electric power sector of the United States consists of all the power plants generating electricity, together with the transmission and distribution lines, and their associated transformers and substations which bring power to end-use customers. Electricity must be available upon demand, is rarely stored in bulk, and is generally consumed as soon as it is produced. Approximately two-thirds of U.S. electricity consumers live in regions of the country that are served by competitive wholesale electricity markets, where utilities compete to supply electricity to consumers at lowest cost. The remaining third of consumers are served by electric utilities that operate under what is called the "traditional model," where rates for electricity are established by a state regulatory body based on the utility's cost of providing electric power to customers (e.g., its cost-of-service). Electric power generation in the United States is currently dominated by the use of combustible fossil fuels, such as natural gas and coal. These fuels are burned to produce steam in boilers to turn steam turbine-generators or, in the case of natural gas, burned directly in a combustion turbine to produce electricity. Another major source of electricity is nuclear power (see " Nuclear Power: An Industry Facing Stress "), which uses heat from the fission of radioactive elements to produce steam to turn a generator. However, electricity can also be generated mechanically by wind turbines and hydropower, or by solar photovoltaic panels which convert light into electricity. Geothermal energy power plants use heat from underground to generate steam to run steam turbines. Generally, electricity must be used as soon as it is produced because the technologies and regulatory regimes to facilitate large-scale, economic energy storage are not yet widely available. The choice of power generation technology in the United States is heavily influenced by the cost of fuel. Historically, the use of fossil fuels has provided some of the lowest prices for generating electricity. As a result, fossil fuels (coal and natural gas) have accounted for about two-thirds of electricity generation since 2000. Figure 5 illustrates the changing mix of fuels used for electric power generation from 2000 to 2017. Beginning in 2016, natural gas surpassed coal as a percentage of net electricity generation. The overtaking of coal by natural gas in 2016 reflects the changing economics of power generation. Electricity production has largely been influenced by regional resources and policies at the state level. Historically, since coal was readily available across a large part of the United States, coal power plants were able to dominate electricity production for many decades. However, improvements in natural gas combined-cycle generation technology since 2000, and the costs of compliance with environmental regulations (discussed later in this section), have led to older, less-efficient coal plants being used less or retired from service. Also as discussed earlier, the use of hydraulic fracturing and directional drilling technology since 2008 has led to an increased supply and availability of natural gas. The resulting cheaper prices for natural gas have added market pressure to shift away from coal to natural gas for power generation. For many years, the growth in sales of electricity could be directly related to growth in the economy. However, with energy efficiency in homes and appliances increasing, a decoupling of growth in electricity demand from growth in gross domestic product (GDP) has occurred. According to EIA, the linkage has been declining over the last 60 years, as U.S. economic growth is outpacing electricity use. The trend is illustrated by Figure 6 , which shows growth in electricity use and economic growth over the period. EIA's projections point to a continued decline in electricity use relative to economic growth. While there may be years of relative growth in the future, EIA does not expect a "sustained return to the situation between 1975 and 1995, when the two growth measures were nearly equal in value, or the earlier period in which the growth rate in electricity use far exceeded the rate of economic growth." EIA attributes several factors as drivers of this trend, including "slowing population growth, market saturation of major electricity-using appliances, improving efficiency of several equipment and appliance types in response to standards and technological change, and a shift in the economy toward less energy intensive industry." With growth in demand for electricity having been essentially flat for many years, the need for new power plants has been delayed in many parts of the country. The projections for future demand growth in most regions of the United States are declining. The electric power sector is a large, but declining, source of air pollution in the United States. Fossil fuel-fired power plants emit conventional pollutants as a result of combustion such as mercury, sulfur dioxide, and nitrogen oxides, as well as greenhouse gas emissions (GHGs). As of 2016 (the most recent data), electric power generation was responsible for 28% of U.S. domestic greenhouse gas emissions, down from 34% in 2008. With the passage of the Clean Air Act amendments in 1970 and major amendments in 1977 and 1990, Congress required EPA to establish standards to reduce potential health and environmental impacts of air pollution by limiting emissions. These environmental regulatory requirements have been evolving in the last decade as EPA continues implementation of the act's requirements. Recently, the Trump Administration announced the initiation or consideration of a number of regulatory changes to rules promulgated under previous administrations. Under President Trump, the EPA has signaled the possibility of modification to or repeal of several rules impacting electric power sector emissions, including the Mercury and Air Toxics Standard (MATS), the ambient air quality standards for ozone, and rules for GHG emissions for new and existing power plants. Recent attention has focused on the announced replacement of the Clean Power Plan (CPP) with the Affordable Clean Energy (ACE) Rule. Promulgated in 2015 under the Obama Administration, the CPP would require states to submit plans to curtail carbon dioxide (CO 2 ) emissions from predominantly coal- and gas-fired power plants. EPA proposed to replace the CPP with the ACE rule on August 21, 2018. ACE would be a less stringent rule focused on improving on-site efficiency of affected plants. It would allow states more input on how to best reduce GHG emissions from the power sector and would revise the New Source Review permitting process, which would affect emissions from existing power plant upgrades or expansions. By contrast, the CPP, in addition to promoting efficiency improvements, would have encouraged states to move towards cleaner-burning natural gas plants or carbon-free sources of electricity, such as wind, solar, or nuclear. The EPA has suggested that the replacement of the CPP with the ACE rule would result in more coal-burning plants remaining open; however, some industry observers have expressed doubt that the new rule will significantly impact the rate of coal plant retirements. The EPA estimates that, under the ACE rule, CO 2 emissions would decline by 0.7% to 1.5% by 2030 compared to a scenario without CO 2 emissions curtailment. Some preliminary analyses have suggested that CO 2 emissions and associated conventional pollutants may actually increase in some states as a result of the rule if it leads to coal plants operating more often than they would otherwise. In seeking to address environmental issues, some utilities are increasing their deployment of renewable energy technologies to meet a portion of their power demands. Proponents of renewable energy contend that it has the potential to provide inexpensive, almost limitless electricity with minimal adverse environmental impacts. However, some of the technologies used today to generate electricity from renewable energy sources, like wind and solar, are variable in nature, which provides challenges for their integration into grid operations. Nuclear power is also considered to be a carbon-free source of electricity. The Trump Administration has made it clear that it would like to help revive the U.S. coal industry. The Administration has rolled back or initiated reversing several coal-related regulations that were finalized under the Obama Administration, including the Clean Power Plan (discussed above). This effort coincided with the emergence of three of the largest coal producers from Chapter 11 bankruptcy, higher coal prices, lower inventories, and higher natural gas prices—factors that could lead to coal being more competitive as a fuel source for electricity generation. Coal will likely remain an essential component in the U.S. energy supply picture, but how big a role it will play is an open question. The United States has the largest coal reserves and resources in the world. EIA estimated in 2017 that there were about 254 billion short tons of recoverable domestic coal reserves. The total demonstrated U.S. resource base (DRB) was estimated at about 476 billion short tons. According to the National Mining Association, the federal government owns about one-third of U.S. domestic reserves. EIA statistics show that more than half of U.S. coal reserves are located in the West, with Montana and Wyoming together accounting for 42%. The top five producing states—Wyoming, West Virginia, Kentucky, Illinois, and Pennsylvania—account for nearly 70% of U.S. coal production. Even though U.S. coal production had remained strong until 2014 (at or near 1 billion short tons per year), and reached its highest level of production in 2008 (1.17 billion short tons), coal is losing its share of overall U.S. energy production, primarily to natural gas in electricity generation. Coal production declined precipitously in 2015 and 2016—a record decline of about 28% over the two-year period (see Table 4 ). EIA short-term projections show coal production under 800 million tons in both 2018 and 2019. The softening of demand for coal has been attributed to utilities opting for low-cost natural gas, declining costs for renewable energy options, increasing regulatory cost associated with coal-fired power plants, a warmer-than-usual winter heating season in 2015 (which resulted in high coal inventories), and lower demand for U.S. coal exports (see Table 4 ). In 2017, coal exports rebounded significantly, up to 96.9 million short tons (much higher than previous EIA projections). Higher demand from Asian countries, particularly India, for U.S. coal fueled this uptick. The EIA projects long-term demand growth in the Asian coal market, but long-term penetration of U.S. coal exports into this market remains uncertain. Coal mining employment declined from 169,300 in 1985 to 71,500 in 2000 (a 57% decline), then rose to a recent high of 86,100 in 2010 before falling again to 51,796 in 2016 (the lowest number on record since EIA began collecting data in 1978). A similar pattern was true for the number of coal mines, as the vast majority of the decline occurred between 1985 and 2000, when the number of coal mines fell by 55% (from 3,355 to 1,513) before declining further by 54% from 2000 to 2015 (from 1,513 to 695). The number of coal mining firms has decreased in the United States, while the size of the average mine and output per mine and per worker have increased. Coal consumption in the United States was consistently near or over 1 billion short tons per year since 2000 (peaking in 2007 at 1.128 billion short tons) until 2012, when demand fell below 900 million short tons (pre-1990 levels). As shown in Table 4 , consumption has declined further since then, reaching a low of 729 million short tons in 2016. The EIA projects annual coal consumption to be below 700 million short tons through 2019. Power generation is the primary market for coal, accounting for over 90% of total consumption. With the retirement of many coal-fired power plants and the building of new gas-fired plants, accompanied by lower demand for electricity, there has been a structural shift in demand for U.S. coal. A structural shift would mean long-term reduced capacity for coal-fired electric generation. Thus, coal would likely be a smaller portion of total U.S. energy consumption for years to come, replaced by natural gas and renewable energy, particularly as fuel used for power generation. As noted earlier, in 2016, natural gas overtook coal as the number one energy source for power generation. EIA projects a range of coal consumption into the year 2050—from less than 400 million short tons/year (based on the Obama Administration's Clean Power Plan) to about 800 million short tons/year. But in either case (declining or flat), coal is projected to be a smaller share of the total U.S. energy mix, with or without new rules governing power plant emissions. One of the big questions for the industry is how to penetrate the overseas coal market, particularly for steam coal, to compensate for declining domestic demand. EIA forecasts coal exports to continue declining in the short term (2018-2020) but to increase to 85 million tons annually by 2040 in the EIA reference case. Exports to the Asian market are expected to increase, but there are potential bottlenecks such as infrastructure (e.g., port development and transportation) that could slow export growth. Several key factors are likely to influence how much coal will be exported from the United States in the future, one of which is the building of export terminals, particularly for coal from the Powder River Basin (PRB) in Wyoming and Montana. Another major factor is the level of global demand for metallurgical (met) coal, which is used to make steel. Historically, met coal has been the primary coal exported by the United States and primarily to the European market. The European market has been in decline, but experienced a significant uptick in both steam and met coal imports from the United States in 2017. Some PRB coal is exported from Canadian terminals at Roberts Bank (near Vancouver, British Columbia) and Ridley Terminal at Prince Rupert, British Columbia. PRB coal is transported to both facilities for export via railway. However, the Canadian export terminals have reached capacity. PRB coal producers have been searching for a potential domestic export link to the growing Asian market through the Pacific Northwest, so far without success. Three port terminal projects for exporting coal in Washington and Oregon had permit applications before the U.S. Army Corps of Engineers (the Corps), although none have advanced. Two, the Gateway Pacific Terminal and Coyote Island Terminal projects, have been cancelled due to permit denials. Washington State's Department of Ecology, in its final environmental impact statement, rejected the application for a Clean Water Act Certification (for water pollution discharges) for the Millennium Bulk Terminal. Millennium Bulk Terminal filed an appeal with the Pollution Control Hearing Board, but on August 15, 2018, the Board upheld the Department of Ecology's decision in a Summary Judgment. In addition, the State of Washington denied the Millennium project a permit to build on state land. The U.S. coal industry is highly concentrated, with a handful of major producers operating primarily in five states (Wyoming, West Virginia, Kentucky, Illinois, and Pennsylvania). In 2016, the top five coal mining companies were responsible for about 53% of U.S. coal production, led by Peabody Energy Corp., with 19.6%, and Arch Coal, Inc., with 13.2% (see Table 5 ). Other major producers include Cloud Peak Energy, Murray Energy Corp., and Contura Energy Inc. Three of the top five coal producers filed for Chapter 11 bankruptcy protection between 2015 and 2016: Alpha Natural Resources, LCC (August 2015), Arch (February 2016), and Peabody (April 2016). Other major producers, such as Patriot Coal, Walter Energy, James River Coal, Armstrong Energy, and FirstEnergy Solutions have filed as well. All told, over 50 coal producers have filed for bankruptcy, with more than $19.3 billion in debt being reorganized. The top-two largest producers, both of which filed for bankruptcy, accounted for nearly 33% of U.S. coal production in 2016. Arch Coal, ANR Inc., and Peabody Energy have emerged from Chapter 11 bankruptcy with a plan to move forward, all three shedding substantial debt. Opponents are critical of the plan and of the long-term viability and reliability of the coal industry. A major challenge for the coal industry will be to get the level of financing needed for new or expanded projects and to become profitable. As U.S. energy policy and environmental regulations are debated, there is ongoing congressional interest in the role of coal in meeting U.S. and global energy needs. The question may not be whether the domestic production of coal will continue, rather, how much U.S. coal will be burned, what type, and under what regulatory framework. Nuclear power has supplied about one-fifth of annual U.S. electricity generation during the past three decades. In 2017, nuclear reactors generated 20% of U.S. electricity supply, behind only coal and natural gas. Ninety-eight reactors are currently operating at 59 plant sites in 30 states. They generated electricity at 92.2% of their total capacity in 2017, the highest rate of any generation source. Total net generation of nuclear power in 2016 was 805 billion kilowatt-hours. One new power reactor began commercial operation in 2016: Watts Bar 2 in Tennessee, the first new U.S. reactor since its twin unit began operating in 1996. Two more power reactors are currently under construction in Georgia at the Vogtle plant site. Ten additional new reactors have received licenses from the Nuclear Regulatory Commission (NRC), but construction of those projects is uncertain. No further license applications are under review. Despite the strong operational performance of existing nuclear plants, the U.S. nuclear industry has faced significant stress recently. Seven reactors have permanently closed since 2013, and the owners of 12 more have announced their permanent closure by the mid-2020s. Construction of two new reactors at the Summer plant site in South Carolina was cancelled following a bankruptcy filing in 2017 by the project's lead contractor, Westinghouse Electric Company. Most of the closed and threatened nuclear power plants sell their electricity at competitive market prices, in contrast to plants that recover their costs (including a reasonable rate of return) through regulated rates. Nuclear plants that rely on power markets have seen falling wholesale power prices and stagnant demand, combined with relatively high operating and capital costs in some cases, particularly at plants with a single reactor. (For more information, see CRS Report R44715, Financial Challenges of Operating Nuclear Power Plants in the United States , by [author name scrubbed] and [author name scrubbed].) Some contend that electricity markets are undervaluing the reliability of nuclear generation, its role in diversifying the nation's power supply, and its importance in reducing CO 2 emissions. Nuclear power accounted for 56% of U.S. sources considered to be zero-carbon electricity generation in 2017. A major government effort to preserve nuclear power as a non-direct carbon emitting electricity source is being implemented by the state of New York, which is providing payments in the form of zero emission credits (ZECs) to four upstate reactors that had been at risk of retirement. The state of Illinois enacted legislation in December 2016 to provide ZECs to prevent the planned closure of three at-risk reactors. Nuclear power incentives at the federal level have also been proposed, such as an investment tax credit. A federal nuclear energy production tax credit was extended by the Bipartisan Budget Act of 2018 ( P.L. 115-123 , Sec. 40501). However, some others contend that such drawbacks as accident risk, high costs, and disposal of radioactive waste outweigh the technology's benefits. Focusing on renewable energy and energy efficiency would be far more effective in reducing carbon emissions, they argue. It is not clear, however, that these alternatives can provide sufficient baseload power supplies to replace nuclear. All but three of today's 98 nuclear power reactors ( Figure 7 ) began operating before 1990, and most started commercial operation before 1980. They were initially licensed by NRC to operate for 40 years, a period that for more than half of U.S. reactors expires before 2020. However, most reactors have been issued 20-year license renewals, pushing back the license expiration of almost all nuclear plants at least to the 2030s. Further 20-year renewals, for a total operating life of 80 years, are also allowed. Two plants have submitted license renewal applications for a second 20-year renewal, and another two have indicated their intent to submit in the next several years. Federal policies supporting the use of renewable energy date mainly back to the mid-1970s, the years following the 1973 oil embargo and energy price volatility that resulted. At that time, support for renewable energy was generally oriented towards achieving energy security goals. Although energy security remains a policy objective, much of the current debate about supporting renewable energy deployment is related to environmental policies, such as reducing GHG emissions from electric power plants. While renewable energy is currently a relatively small portion of the total U.S. energy sector, renewables production and consumption have increased since 2000. Renewable energy consumption increased 113% between 2001 and 2017, as illustrated in Figure 8 . During this same period, the contribution of renewable energy to total primary energy more than doubled, rising from 5.4% to approximately 11.3%. Unlike other energy commodities, such as crude oil, renewable energy is available in a variety of distinct forms that use different conversion technologies to produce usable energy products (e.g., electricity, heat, and liquid fuels). Hydroelectric, biofuels, wood biomass, wind, waste, solar, and geothermal are the renewable energy categories that are tracked and reported by the EIA. Each energy product derived from renewable sources has unique market and policy considerations. Renewable energy is consumed within the electric power, industrial, transportation, residential, and commercial sectors. As indicated in Table 6 , the contribution of the different renewable energy sources to each sector varies. For example, nearly all hydro is consumed in the electric power sector and most of the industrial sector renewable energy use is in the form of biomass energy generation. Much of the growth in renewable energy consumption since 2001 has been within the electric power—mostly non-hydro renewable electricity generation—and transportation (renewable fuels) sectors. The industrial sector is the second-largest renewable energy consumer, although consumption levels have been in a relatively narrow range from 1985 to 2016 and, as mentioned above, the majority of renewable energy consumed in the sector is biomass-generated. It is beyond the scope of this report to include either detailed descriptions or analysis of each renewable energy source or a comprehensive assessment of each consumption sector. Rather, the following sections discuss renewable transportation fuels and renewable electricity generation trends since 2001 and provide some context about the policy and market dynamics that have contributed to the growth of these separate and distinct markets. Renewable energy production and consumption in the transportation sector is in the form of two primary types of renewable fuels: ethanol and biodiesel. The primary use of ethanol is as a blending component of motor gasoline. Generally, although it can vary by vehicle type and access to high level ethanol-gasoline blends, ethanol content represents approximately 10% of gasoline by volume. Biodiesel is a direct substitute for diesel fuel refined from petroleum. U.S. ethanol and biodiesel production and consumption in the United States have experienced growth over the last 16 years. Significant growth occurred following the establishment and expansion of the Renewable Fuel Standard—a mandate that U.S. transportation fuel contain a minimum volume of biofuel. U.S. ethanol production has steadily increased from approximately 1.8 billion gallons in 2001 to just under 16 billion gallons in 2017. Ethanol consumption increased from 1.7 billion gallons in 2001 to more than 14 billion gallons in 2017. During the same period biodiesel production increased from 9 million gallons in 2001 to approximately 1.6 billion gallons in 2017. Biodiesel consumption increased from 10 million gallons in 2001 to approximately 2.0 billion gallons in 2017. 2017 ethanol consumption volumes are more than seven times that of biodiesel. U.S. renewable electricity generation, including hydropower and non-hydro renewables, more than doubled between 2001 and 2017. The contribution of renewable energy to the U.S. power sector increased from 9% in 2001 to 17% in 2017. While hydroelectricity generation has represented 6% to 8% of total U.S. electric power generation since 2001, essentially all of the growth in renewable electricity generation during this period was from non-hydro renewables. Non-hydro renewable energy (i.e., wind, solar, geothermal, and biomass) as a fuel source for electricity generation has been supported by policies at both the state and federal level. Renewable portfolio standard (RPS) policies instituted in many states have been the demand catalyst for renewable power. Tax incentives—in the form of investment and production tax credits, as well as accelerated depreciation—have provided a federal-level financial incentive that has resulted in renewable electricity being financially attractive to both project investors and power purchasers. As a result of these state and federal programs and incentives, in addition to technology cost declines and conversion efficiency improvements, the use of non-hydro renewable sources of energy to generate electric power in the United States increased considerably between 2001 and 2017. In 2017 non-hydro renewable energy sources provided more than 9% of total U.S. electric power generation (see Figure 9 ). Wind and solar have dominated growth in non-hydro renewable electricity generation, while generation from biomass and geothermal has remained essentially flat. Electricity generation from wind energy increased by a factor of 37 between 2001 and 2017, growing from less than 7 million Megawatt-hours (MWh) to more than 254 million MWh. Electricity generation from solar energy increased by more than a factor of 97 between 2001 and 2017, growing from 0.6 million MWh to nearly 53 million MWh (see Figure 9 ). In terms of new utility-scale electric power capacity additions, non-hydro renewable electricity installations—the majority being solar and wind—has exceeded that of coal and natural gas combined every year since 2014. During calendar year 2017, approximately 50% of gross capacity additions were non-hydro renewables (see Figure 10 ). The relatively large contribution of non-hydro renewable energy electricity capacity additions in recent years can be attributed to multiple factors. First, prior to Congress passing a multi-year extension and phase-out of tax credits for wind and solar electricity in 2015, project developers for wind and solar power projects accelerated development activities in order to capture tax credit incentives before their scheduled expiration date. Second, the cost of electricity generated by wind and solar technologies has declined, primarily due to improvements in conversion efficiency and equipment cost reductions. Finally, the U.S. electricity sector is a mature market; overall sector growth is projected to be small. U.S. electric power demand has been relatively flat for several years and is projected to continue along a rather flat trajectory in the near to medium term. As a result, the amount of new power generation capacity needed each year has declined. This low-growth market, combined with increased capacity installations motivated by state requirements and federal financial incentives, has led to large contributions by renewable electricity to annual capacity additions. In addition to the increased use of solar energy for utility-scale electric power, distributed solar electricity generation—solar power generated at a residential, commercial, or industrial location—has also increased significantly. Distributed solar generation grew by a factor of 186 between 2001 (129 million kilowatt-hours, kWh) and 2017 (24,139 million kWh). This rapid growth is the result of several policy and market factors, including (1) state-level policies that encourage residential solar development (solar "carve-outs" and net-metering policies), (2) federal tax incentives, (3) decreasing costs of solar electricity generation equipment, (4) price competition with retail prices instead of lower wholesale prices, and (5) solar leasing business models that eliminate the need for homeowners and commercial users to pay for the upfront cost of a solar generation system, such as rooftop solar panels. Appendix A. Key U.S. Government Agencies Army Corps of Engineers (Corps) —part of the Department of Defense, the Army Corps of Engineers manages both federal water resource development projects and regulated activities affecting certain waterways and wetlands, including activities associated with infrastructure. Corps permits are required where energy infrastructure crosses certain waterways, Corps projects, or Corps-controlled lands. Bureau of Land Management (BLM) —part of the Department of the Interior, BLM has oversight of federal lands and manages onshore oil and natural gas operations. Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) —part of the Department of the Interior, BOEMRE oversees the safe and environmentally responsible development of energy and mineral resources on the Outer Continental Shelf. U.S. Coast Guard —part of the Department of Homeland Security, the Coast Guard has oversight of marine terminals used for the import and export of oil and natural gas as well as the security of certain hazardous fuel shipments by water. U.S. Commodity Futures Trading Commission (CFTC) —CFTC has oversight of futures markets, including those for energy. CFTC was given additional oversight responsibilities for futures and derivatives under Dodd-Frank legislation. U.S. Department of Energy (DOE) —a Cabinet-level agency responsible for developing and implementing national energy policy, energy research and development, basic science, energy emergency preparedness and security, and defense-related nuclear activities. Energy Information Administration (EIA) —an agency within DOE, it provides independent data and analysis on the U.S. energy sector. Environment al Protection Agency (EPA) —EPA has a broad range of responsibilities regarding energy as it enforces environmental regulations and sets national standards. EPA has oversight/enforcement of all or part of the Oil Pollution Act, Resource Conservation and Recovery Act (RCRA), Clean Water Act, Clean Air Act, Energy Policy Act, Energy Independence and Security Act, Shore Protection Act, among other laws. Federal Energy Regulatory Commission (FERC) —an independent federal agency which regulates the interstate transmission of electricity, natural gas, and oil. FERC also issues permits for LNG terminals and interstate natural gas pipelines as well as licensing nonfederal hydropower projects. U.S. Fish and Wildlife Service —Fish and Wildlife has responsibilities for environmental oversight on energy issues such as wind and hydropower production, and pipeline rights-of-way through jurisdictional lands. U.S. Forest Service —part of the Department of Agriculture, the Forest Service is responsible for managing energy and mineral resources, and infrastructure development on federal onshore areas that it owns. Maritime Administration (MARAD) —an agency within the Department of Transportation that regulates offshore LNG and oil terminals. National Oceanographic and Atmospheric Administration (NOAA) —part of the Department of Commerce, NOAA has jurisdiction over pipeline project construction in coastal and/or ocean areas. Nuclear Regulatory Commission (NRC) —an independent regulatory commission responsible for licensing and regulation of nuclear power plants and other nuclear facilities. Office of Fossil Energy —part of the Department of Energy focusing on production from U.S. oil fields. It also has input into the construction of liquefied natural gas import and export terminals. Office of Nuclear Energy —part of the Department of Energy responsible for nuclear energy research and federal nuclear waste storage and disposal facilities. Office of Energy Efficiency and Renewable Energy (EERE) —part of the Department of Energy that focuses on energy efficiency, such as appliance standards, and renewable energy. Pipeline and Hazardous Materials Safety Administration (PHMSA) —part of the Department of Transportation, PHMSA administers the regulatory program, through the Office of Pipeline Safety (OPS), to assure the safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. OPS develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities. Appendix B. Key Energy Laws Appendix C. 2016 U.S. Energy Consumption

Summary: Since the start of the 21st century, the U.S. energy system has seen tremendous changes. Technological advances in energy production have driven changes in energy consumption, and the United States has moved from being a growing net importer of most forms of energy to a declining importer—and possibly a net exporter in the near future. The United States remains the second largest producer and consumer of energy in the world, behind China. The U.S. oil and natural gas industry has gone through a "renaissance" of production. Technological improvements in hydraulic fracturing and horizontal drilling have unlocked enormous oil and natural gas resources from unconventional formations, such as shale. Oil has surpassed levels of production not seen since the 1970s. Natural gas has set new production records almost every year since 2000. In conjunction with the rise in oil and natural gas production, U.S. production of natural gas liquids has also increased. The rise in production of these fuel sources has also corresponded with increased consumption and exports of each. The rise in U.S. oil and natural gas production has taken place mostly onshore and on nonfederal lands. Crude oil production from nonfederal land has doubled over the past decade. While production on federal land has increased, it has not grown as fast as oil production on nonfederal land, causing the federal land share of total U.S. crude oil production to fall from its peak of nearly 36% in 2009 to about 24% in 2017. U.S natural gas production shifted even more dramatically, with total U.S. dry production growing 33% since 2008, while gross withdrawals on federal lands declined by almost 32% over the same time period. The federal land share of total gross withdrawals decreased from 25% in 2008 to 13% in 2017. The electric power industry is transforming. Growth in demand for electricity has essentially been flat for many years, and the amount of new power generation capacity needed has declined each year in many parts of the country. The projections for future demand growth in most regions of the United States are declining. Natural gas edged out coal to become the primary electric generation fuel in 2016 and the growth in wind and solar energy has shown little sign of abating. The electricity infrastructure of the United States is aging. Uncertainty exists about how to modernize the grid and what technologies and fuels will be used to produce electricity in the future. Unresolved questions about transmission and reliability of the grid are arising due to potential cybersecurity threats and continuing interest in renewable energy and other low carbon sources of electricity. Concerns about reliability and electricity prices are complicated by environmental regulations, the intermittent nature of wind and solar power, and the rising availability of natural gas for electric power production. Renewables production and consumption have increased since 2000. As a source of total primary energy, renewable energy increased 80% between 2000 and 2017. Unlike some other energy commodities (e.g., crude oil), renewable energy is available in a variety of distinct forms that use different conversion technologies to produce usable energy products (e.g., electricity, heat, and liquid fuels). Therefore, it is important to distinguish between renewable fuel sources and uses. The United States has the largest coal resources in the world. Coal is used primarily for electricity generation. Although its prices have stayed low, coal has faced increasing competition from natural gas and renewables. U.S. coal consumption peaked in 2007 and has since declined by 39%. Coal currently supplies approximately 30% of electricity generation. Nuclear-generated electricity output has stayed flat during the same time period, and faces significant challenges as a future source of electric power generation. Energy production and consumption have been issues of interest to Congress for decades. Current topics of concern to Congress include independence, exports, imports, prices, security, infrastructure, efficiency, the environment, and geopolitics. Legislation has been introduced in both houses of Congress to address these issues and others.