Oil, Gas, and Coal Royalties: Raising Federal Rates Could Decrease Production on Federal Lands but Increase Federal Revenue
Released: 2017-06-20T00:00:00

Letter

Background

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.

Royalty Rates for Federal and Nonfederal Lands

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.

Production on Federal and Nonfederal Lands

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.

Studies and Stakeholders Suggest Raising Federal Royalty Rates Could Decrease Production on Federal Lands

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. The three increased royalty rates modeled resulted in oil production declines ranging from 0 barrels to approximately 70 million barrels over 25 years (or, about 2.8 million barrels per year—the equivalent of about 1.8 percent of fiscal year 2016 onshore federal oil production). The three increased royalty rates modeled also resulted in gas production declines over 25 years ranging from 0 cubic feet to 85 billion cubic feet (or about 3.4 billion cubic feet per year—the equivalent of less than 1 percent of onshore federal gas production in fiscal year 2016).

Coal. We also identified two studies that analyzed the effects of different policy scenarios on coal production on federal lands. The first study, by the CEA, examined how raising the federal royalty rate could affect coal production on federal lands after 2025 using a series of scenarios. Under the first scenario, equivalent to raising royalty rates to 17 percent in 2025, the study predicted that federal production would decrease by 3 percent once the changes were fully implemented. The other two scenarios, each equivalent to raising royalty rates to 29 percent in 2025, predicted that federal production would decrease by 7 percent. The second study, by Mark Haggerty, Megan Lawson, and Jason Pearcy, modeled an increase in the effective royalty rate, which is the rate companies actually pay after processing and transportation allowances are factored in. The study found that the modeled increase in the effective royalty rate led to a decrease in federal coal production of less than 1 percent per year.

Results of the two studies differed in how an increase in coal royalty rates might affect nonfederal coal production. The CEA study determined that an increase in federal royalty rates would raise the national price of coal, improving the competitiveness of nonfederal coal and slightly increasing nonfederal coal production. According to the CEA study, coal mines in Wyoming and Montana—representing more than 86 percent of federal coal production in fiscal year 2015—are some of the largest, most productive, and lowest-cost mines. According to EIA, in 2015 the average market price of coal from the Appalachian region, which comes primarily from production on state and private lands, was $60.61 per ton, while the average market price of coal from the Powder River Basin, where the majority of federal coal is produced, was $13.12 per ton.

We previously reported that underground mining, which is mostly concentrated in the eastern region, is more costly than surface mining, resulting in a higher sale price. At the same time, eastern coal has more heat, or energy, content per ton than western coal, which raises the value of eastern coal. CEA concluded that raising the royalty rate would decrease this price gap between Appalachian and Powder River Basin coal, thus making Appalachian and other nonfederal coal slightly more competitive.

The study by Haggerty, Lawson, and Pearcy states that substitution between federal and nonfederal coal could occur, but is unlikely for several reasons, including federal ownership in western states and the inherent difference in the qualities of coal. The study states that substitution between federal and nonfederal coal could occur if federal and nonfederal coal are in close proximity. However, the authors note that where federal ownership of coal dominates, in states like Wyoming, Montana, and Colorado where the majority of federal coal is produced, states tend to adopt federal policy changes. Also according to the study, transportation from the mine to the power plant is highly specialized, and power plants are engineered to maximize efficiency of the specific type of coal in the region. Switching from one type of coal to another could involve substantial conversion costs for coal power plants.

Stakeholders we interviewed suggested that several factors could influence the extent to which oil, gas, and coal production might be affected if federal royalty rates were increased, including the following.

Market conditions and prices. Some stakeholders noted that market conditions and prices play an important role in determining whether raising federal royalty rates could affect production on federal lands. BLM officials suggested that raising federal royalty rates is less likely to have a negative effect on production when oil and gas prices are high. For example, increasing royalty rates from 12.5 percent to 16.67 percent would increase the cost of producing oil by about $2 a barrel at oil prices as of March 2017. In addition, according to a few stakeholders we interviewed and a 2015 report by the Congressional Research Service, any negative effect on production from higher rates could be limited to or affect areas with marginal oil and gas wells, which are usually wells with low production rates and/or higher production costs. As for coal, some stakeholders said that in an already challenging market, increased costs could further discourage production. According to EIA data, total U.S. coal production declined 23 percent from 2008 to 2015. In a 2012 report, we found that various market and regulatory factors may influence the future use of coal, including the price of natural gas, demand for electricity, and environmental regulations. A few stakeholders we interviewed said there has been little interest in further coal development in their regions, which include the western and midwestern regions of the country. Since fiscal year 2012, the number of coal lease sales on federal lands has generally declined. We previously reported that there was limited competition for coal leases because of the significant capital investment and time required; additionally, from January 2016 to March 2017 the Secretary of the Interior placed a pause on significant new federal coal leasing decisions, with limited exemptions and exclusions.

Cost advantages of different resources. A few stakeholders told us that the competitiveness of federal lands for development depends less on the royalty rate charged and more on the location of the best resources—such as areas with low exploration and production costs. For example, as discussed above, most of the areas with major U.S. tight oil and shale gas plays and major U.S. coal basins do not overlap with federal lands. A few stakeholders suggested that an increase in the federal royalty rates for coal would not cause companies to switch from federal to nonfederal coal because of the cost advantages of federal coal, which is primarily concentrated in surface mines in the West. According to EIA data, all coal extracted from the Powder River Basin in 2015 was from surface mining, which we previously reported has lower extraction and production costs. In contrast, the majority of coal production from the Appalachian region in 2015 was from underground production, which we previously reported is more costly to extract. Increasing the royalty rate on federal lands would not cause operators to switch from federal to nonfederal coal, according to a few stakeholders, because companies producing coal on federal lands would still have a cost advantage over companies producing coal on nonfederal lands.

Regulatory burden of federal development. Some stakeholders we spoke with stated that there is already a higher regulatory burden for oil and gas companies to develop resources on federal lands than on nonfederal lands, and one stakeholder noted that an increase in federal royalty rates would decrease the competitiveness of federal lands versus state or private lands. In addition, BLM officials noted that about half the public comments BLM received through its 2015 Advance Notice of Proposed Rulemaking also noted there is a higher regulatory burden on federal lands. According to BLM officials, when federal and nonfederal coal are located on adjoining tracts the cost of production will be identical unless the nonfederal land has a different royalty rate, which officials say is unlikely. Assuming the royalty rate is the same, officials stated that the main difference between federal and nonfederal coal is the additional regulatory burden of producing on federal lands. In addition, a few stakeholders stated that companies may avoid mining federal lands for coal when possible in order to avoid the required environmental assessments, which add time to the leasing process.

Officials from two state offices we interviewed said that the history of increasing royalty rates for oil and gas production on state lands suggests that increasing the federal royalty rate would not have a clear impact on production. In particular, officials from Colorado and Texas said that they have raised their state royalty rates without a significant effect on production on state lands. In February 2016, Colorado increased its royalty rate for oil and gas production from 16.67 percent to 20 percent, and, according to state officials, there had been no slowdown in interest in new leases as of August 2016. In fact, Colorado state officials said they were unsure whether the higher royalty rate played much of a role in companies’ decision making. Additionally, Texas officials told us that over 30 years ago, Texas began charging a 25-percent royalty for most oil and gas leases on state lands, and this increase has not had a noticeable impact on production or leasing. Officials at BLM said about half of the public comments they received through BLM’s 2015 Advance Notice of Proposed Rulemaking suggested that an increase in royalty rates would not have a clear impact on production.

Studies and Stakeholders Suggest Raising Federal Royalty Rates Could Increase Federal Revenues

Raising federal royalty rates for onshore oil, gas, and coal could increase overall federal revenues, according to studies we reviewed and stakeholders we interviewed. Higher rates could have two opposing effects on federal revenues. First, as discussed above, raising royalty rates could lead to decreased production on federal lands, and, consequently, decreased revenues. Second, revenues would increase on any production that does occur because of higher royalty rates on that production. The studies we reviewed show that raising federal royalty rates could increase federal revenues for oil, gas, and coal. Some stakeholders we interviewed said any effects on federal revenue would depend on how increasing royalty rates for oil, gas, and coal would affect bonus bid revenue, while others said overall market conditions, among other factors, need to be considered.

Oil and gas. The studies we reviewed for oil and gas estimate that raising the federal royalty rate could increase net federal revenue between $5 million and $38 million per year (equivalent to around 0.7 percent to around 5.2 percent of net oil and gas royalties in fiscal year 2016). According to the CBO study, the effect on federal revenue would initially be small but would increase over time because a change in the royalty rate would apply only to new leases and the affected parcels would not go into production immediately. For example, CBO found that 6 percent of royalties collected in 2013 came from leases issued in the previous 10 years. CBO estimated that if the royalty rate for onshore oil and gas parcels were raised from 12.5 percent to 18.75 percent, net federal revenue would increase by $200 million over the first 10 years, and potentially by much more over the following decade, depending on market conditions. Similarly, according to the Enegis study, net federal revenues would increase under the scenarios that modeled raising the royalty rate to 16.67 percent, 18.75 percent, or 22.5 percent. Under these scenarios, estimated increases in net federal revenue range from $125 million to $939 million over 25 years.

Coal. Both studies for coal also suggested that a higher royalty rate could lead to an increase in federal revenues. For example, the modeling scenarios in the CEA study that raised the royalty rate to the equivalent of 17 percent or 29 percent predicted a range of increases in government revenues from $0 to $730 million annually after 2025, with approximately half of that revenue going to the federal government. By comparison, in fiscal year 2016, the federal government collected more than $536 million in coal royalty payments, according to ONRR data. The revenue range included zero to take into account the possibility that bonus bids could be lost entirely, but the study stated that this was an extremely conservative assumption, and that the increase in royalty revenue would be vastly larger than any decrease in bonus bid revenue. The study by Haggerty, Lawson, and Pearcy suggested that total average royalty revenues could increase by $141 million per year if the effective royalty rate were raised. This study did not consider the effect on bonus bid revenue from a royalty rate increase.

Stakeholders we interviewed also suggested that the effect on bonus bid revenue could influence the extent to which raising federal royalty rates would increase revenues from oil, gas, and coal production. For example, some stakeholders stated that companies would be more likely to offer lower bonus bids if they had to pay higher royalty payments, but a few stakeholders believed that the net impact on federal revenue would be minimal because royalties are a more significant portion of total revenues than bonus bids. For oil and gas, royalties could offset losses from other revenue sources, such as bonus bids and rents. Although royalties also constitute the majority of revenue for coal, bonus bids represent a larger percentage of total revenue in comparison with oil and gas revenue. For example, in fiscal year 2016 only 8 percent of total revenue from oil and gas development on federal lands was from bonus bids, while in the same year the comparable figure for coal was 42 percent. However, a few stakeholders said that any decrease in bonus bids from an increase in coal royalty rates would likely be offset by a larger increase in royalty revenue.

In addition, BLM officials stated that raising the royalty rate could make some federal coal uneconomical to mine, resulting in fewer royalty payments to the federal government. BLM officials stated that an operator can justify a capital investment to produce coal on federal lands if the potential for revenue outweighs the cost of production. According to officials, increasing the royalty rate would add to the cost of production, which could cause an operator to bypass federal coal, thus causing the government to miss out on revenue. As discussed above, some stakeholders said any effects on federal revenue would depend on how increasing royalty rates for oil, gas, and coal would affect bonus bid revenue, and others said overall market conditions, among other factors, need to be considered.

Agency Comments

We provided a draft of this report to Interior for review and comment. The agency provided technical comments, which we incorporated as appropriate.

We are sending copies of this report to the appropriate congressional committees, the Secretary of the Interior, and other interested parties. In addition, the report is 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 II.

Appendix I: Federal and Indian Production and Revenue Data from Oil, Gas, and Coal Development

Figure 4 shows trends in onshore oil, gas, and coal production and revenue on federal lands over the last 10 years. Tables 2 and 3 show which federal agencies have ownership over the associated federal surface lands that overlap the major tight oil and shale gas plays and major coal basins, as well as which major plays and basins are on tribal lands. Tables 4, 5, and 6 show royalty and other revenues and oil, gas, and coal production on federal lands; on American Indian lands; and, for comparison, in federal offshore areas for fiscal years 2015 and 2016.

Appendix II: GAO Contact and Staff Acknowledgments

GAO Contact

Staff Acknowledgments

In addition to the contact named above, Quindi Franco (Assistant Director), Richard Burkard, Greg Campbell, Colleen Candrl, Tara Congdon, Cindy Gilbert, Michael Kendix, Courtney Lafountain, Jessica Lewis, John Mingus, Cynthia Norris, Caroline Prado, Sara Sullivan, Kiki Theodoropoulos, Barbara Timmerman, and Amy Ward-Meier made key contributions to this report.