BLM leases federal lands to private companies for the production of onshore oil, gas, and coal resources, generally through a competitive bidding process. BLM offers for lease parcels of land nominated by industry and the public, as well as some parcels that BLM itself identifies. If BLM receives any bids, called bonus bids, on an offered lease that are at or above a minimum acceptable bid amount, the lease is awarded to the highest bidder, and, for oil and gas, a lump-sum payment in the amount of the bid is due to ONRR when BLM issues the lease. For coal, the winning bidder pays the bonus bid in five equal payments, with one of the payments being paid at the time of the lease sale. For oil and gas leases, BLM requires a uniform national minimum acceptable bid of $2 per acre. For coal leases, BLM requires a minimum bid of $100 per acre, and the bid must meet or exceed BLM’s estimate of the fair market value of the lease. In addition to the competitive bidding process, companies may obtain leases through two additional processes. For oil and gas, tracts of land that do not receive a bid in the initial offer are made available noncompetitively the next day and remain available for noncompetitive leasing for a period of 2 years after the initial competitive auction, with priority given to offers based on the date and time of filing. For coal, companies may request that a certain amount of contiguous land be added to an existing lease in what is called a lease modification process. Lands acquired through lease modification are added to the existing lease without a competitive bidding process, but the federal government must receive the fair market value of the lease of the added lands either by cash payment or adjustment of the royalty applicable to the lands added to the lease. Leases specify a rental rate—a fixed annual charge until production begins on the leased land, or, when no production occurs, until the end of the period specified in the lease. For oil and gas leases, generally the rental rate is $1.50 per acre for the first 5 years and $2 per acre each year thereafter. For coal, the rental rate is at least $3 per acre. Oil and gas parcels are generally leased for a primary term of 10 years, but lease terms may be extended if, for example, oil or gas is produced in paying quantities. Coal parcels are leased for an initial 20-year period and may be extended if certain conditions are met. Once production of the resource starts, the federal government is to receive royalty payments based on a percentage of the value of production—known as the royalty rate. For onshore oil and gas leases, the Mineral Leasing Act of 1920 sets the royalty rate for competitive leases at not less than 12.5 percent of the amount or value of production. However, until January 2017, BLM regulations generally established a fixed royalty rate of 12.5 percent. For noncompetitive leases, the act, as amended, sets the royalty rate at a fixed rate of 12.5 percent. For coal, royalty rates depend on the type of mine—surface or underground. BLM is authorized to establish royalty rates above 12.5 percent for surface mines, but according to agency officials, BLM generally sets the rate at 12.5 percent, the statutory and regulatory minimum royalty rate. For underground mines, BLM sets the rate at 8 percent, the rate prescribed in regulation. Royalties for oil and gas are calculated based on the value of the resource at the wellhead, and any deductions or allowances are taken after the royalty rate is applied. For coal, certain costs are deducted from the price of coal at the first point of sale, including transportation and processing allowances, before the amount is calculated for royalty purposes. The royalty rate paid by the coal company after such allowable deductions have been factored in, along with any royalty rate reductions, is called the effective royalty rate. Federal royalty rates differ from the royalty rates that state governments charge for production on state lands and the rates that companies pay for production on private lands. Table 1 shows federal royalty rates and rates for six states that represented more than 90 percent of federal oil, gas, and coal production in fiscal year 2015. According to state officials, as of March 2017, royalty rates for oil and gas production charged by these states vary but tend to be higher than federal royalty rates, while royalty rates for coal production charged by these states are generally the same as federal rates. Less is known about the royalty rates for production on private lands because of the proprietary nature of lease contracts, but a few published reports suggest that private royalty rates range from 12.5 percent to 25 percent for oil and gas production and from 3 percent to 10 percent for coal production. In fiscal year 2016, approximately 157 million barrels of oil, 3.14 trillion cubic feet of gas, and 295 million tons of coal were produced on federal lands, according to ONRR data. These numbers represented about 6 percent of total U.S. onshore oil production, 10 percent of total U.S. onshore gas production, and 40 percent of total U.S. coal production, according to our analysis of EIA data. The federal government collected approximately $2.5 billion in gross revenue from the production of these resources on federal lands in fiscal year 2016. The majority of this revenue generally has come from royalties—about $2 billion, or 80 percent of total revenues in fiscal year 2016. As figure 1 shows, royalties comprised a larger percentage of the total revenue from oil and gas production than from coal production in 2016. (See appendix I for additional data on production and revenues from oil, gas, and coal development on federal and American Indian lands from fiscal year 2007 through 2016.) Private companies develop oil, gas, and coal on federal lands within the context of broader energy markets, and conditions in those markets have changed. Overall oil and gas production has increased after decades of decline or general stability—between 2008 and 2016, total U.S. oil production increased by 77 percent and gas production increased by 35 percent. During that same period, federal onshore oil production increased by 59 percent while federal onshore gas production declined by 18 percent. According to EIA, almost all of the increase in overall oil and gas production has centered on oil and gas plays located in shale and other tight rock formations, spurred by advances in production technologies such as horizontal drilling and hydraulic fracturing. However, as figure 2 shows, major tight oil and shale gas plays—those plays that, according to EIA data, have represented more than 90 percent of growth in oil and gas development from 2011 to 2016—are mostly located on nonfederal lands. In 2016, about 15 percent of the major tight oil and shale gas plays in the contiguous United States overlapped federal lands, according to our analysis of EIA and the U.S. Geological Survey data. In contrast to oil and gas production, both federal and total U.S. coal production have declined since 2008. Federal coal production declined 19 percent from 2008 to 2015, while total U.S. coal production declined more than 23 percent in the same period. According to EIA, the decline in total U.S. coal production can be attributed to a lower international demand for coal, increased environmental regulations, and low natural gas prices (natural gas is an alternative for coal in the electricity market). As figure 3 shows, about 5 percent of the major coal basins in the contiguous United States overlapped federal lands in 2013, according to our analysis of EIA and U.S. Geological Survey data. Major coal basins that overlap with federal lands are primarily concentrated in the Powder River Basin in parts of Wyoming and Montana. Raising federal royalty rates for onshore oil, gas, and coal could decrease production on federal lands, according to studies we reviewed and stakeholders we interviewed. Increasing royalty rates would increase the total costs for producers, thus making production on federal lands less attractive to companies, according to some stakeholders. Companies may respond by producing less on federal lands and more on nonfederal lands. However, stakeholders disagreed about the extent to which production could decrease because they said other factors may influence energy companies’ development decisions. Oil and gas. We identified two studies—one by the CBO and one by Enegis, LLC—that modeled the effects of different policy scenarios on oil and gas production on federal lands. Both studies suggested that a higher royalty rate could decrease production on federal lands by either a small amount or not at all. The CBO study concluded that raising the royalty rate to 18.75 percent would lead to “reductions in production would be small or even negligible” over 10 years, particularly if the increased federal royalty rate remained equal to or below the royalty rates for production on state or private lands. As discussed above, the current 12.5 percent federal royalty rate is generally the same or lower than rates charged by the six states in which more than 90 percent of federal oil and gas was produced in fiscal year 2015. In addition, the Enegis, LLC, study showed that demand for new federal competitive leases—or the extent to which oil and gas companies would compete for new leases—would generally decrease over 25 years if the royalty rate were raised to 16.67 percent, 18.75 percent, or 22.5 percent. For each of these three royalty rate increases, the study examined several different scenarios that varied with respect to key factors, including company costs and company responses. The study showed declines in production under all scenarios except those in which companies completely absorbed the higher costs resulting from higher royalty rates. In scenarios in which companies could absorb the costs—potentially in market conditions in which higher oil and gas prices help buffer companies from the effects of increased royalty rates—there would be no change in production levels.