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

Fast Facts:
The federal government collected $2.5 billion in revenue from onshore oil, gas, and coal production on federal lands in fiscal year 2016, including about $2 billion from royalties. While the federal royalty rates for coal production are generally the same or higher than state rates, federal rates for oil and gas production are generally lower than state rates.
We reviewed studies and interviewed stakeholders about federal royalty rates and found that increasing these rates may slightly decrease production on federal lands. However, it could increase revenue by millions of dollars annually.

Highlights:
section_title: Why GAO Did This Study
paragraphs: In fiscal year 2016, the federal government collected about $2.5 billion in revenue associated with onshore oil, gas, and coal production on federal lands, including about $2 billion from royalties. Federal royalty rates sometimes differ from the rates states charge for production on state lands. For example, state oil and gas rates tend to be higher than federal royalty rates and state coal rates are generally the same as federal rates in the six states representing more than 90 percent of federal oil, gas, and coal production in fiscal year 2015.
The explanatory statement accompanying the Consolidated Appropriations Act for fiscal year 2016 includes a provision for GAO to review issues related to royalty rates. This report describes what is known about how raising federal royalty rates would affect (1) oil, gas, and coal production on federal lands and (2) the federal revenue associated with such production. GAO reviewed an extensive list of studies and selected for more in-depth review four that modeled the effects of raising federal royalty rates—one study conducted by the Congressional Budget Office, one by the Council of Economic Advisers in the Executive Office of the President, one prepared for the Bureau of Land Management, and one by researchers. GAO also interviewed officials from federal and state agencies, industry groups, non-governmental organizations, academia, and other knowledgeable stakeholders.
GAO is not making recommendations in this report. Interior reviewed a draft of this report and provided technical comments that GAO incorporated as appropriate.
section_title: What GAO Found
paragraphs: Raising federal royalty rates—a percentage of the value of production paid to the federal government—for onshore oil, gas, and coal resources could decrease oil, gas, and coal production on federal lands but increase overall federal revenue, according to studies GAO reviewed and stakeholders interviewed. However, the extent of these effects is uncertain and depends, according to stakeholders, on several other factors, such as market conditions and prices.
Production . One study GAO reviewed found that oil and gas production could decrease by less than 2 percent per year if royalty rates increased from their current 12.5 percent to 22.5 percent, based on fiscal year 2016 production data. Another study stated the effect on production could be “negligible” over 10 years if royalty rates increased to 18.75 percent, particularly if the increased federal royalty rate remained equal to or below the royalty rates for production on state or private lands. Regarding coal, one study suggested that raising the federal royalty rate for coal to 17 percent would decrease production on federal lands by up to 3 percent after changes were fully implemented after 2025, while a second study said that increasing the effective rate—the rate actually paid by companies after processing and transportation allowances have been factored in, along with any royalty rate reductions—might decrease production on federal lands by less than 1 percent per year. Some stakeholders said that several other factors could influence the extent to which oil, gas, and coal production might decline. For example, some stakeholders said current market conditions, the cost advantages of different resources, and the regulatory burden associated with production on federal lands could influence the extent to which production might decline.
Revenue . The oil and gas studies that GAO reviewed estimated that raising the federal royalty rate could increase net federal revenue between $5 million and $38 million per year. One of the studies stated that net federal revenue would increase under three scenarios that modeled raising the royalty rate from the current 12.5 percent to 16.67 percent, 18.75 percent, or 22.5 percent, while the other study noted that the effect on federal revenue would initially be small but would increase over time. Both coal studies suggested that a higher royalty rate could lead to an increase in federal revenues. One of the studies suggested that raising the royalty rate to 17 percent or 29 percent might increase federal revenue by up to $365 million per year after 2025. The other study suggested that increasing the effective rate could bring in an additional $141 million per year in royalty revenue. Stakeholders GAO interviewed cited other factors that could influence the extent to which raising federal royalty rates could increase revenues—in particular, how bonus bids, another revenue source, could be affected. Some of the stakeholders stated that companies would be more likely to offer lower bids to obtain a lease for the rights to extract resources if they had to pay higher royalties.

section_title: Letter
paragraphs: Production of oil, gas, and coal on federal lands is an important part of the  nation’s energy portfolio and generates billions of dollars annually in  revenue for the federal government. In fiscal year 2016, the Department  of the Interior (Interior) reported collecting about $2.5 billion associated  with onshore oil, gas, and coal production on federal lands. These  revenues came primarily from royalties paid on the value of the resources  produced. Interior’s Bureau of Land Management (BLM) has the  responsibility to manage and lease federal lands—about 700 million  mineral acres held by BLM, the U.S. Forest Service, and other federal  agencies and surface owners.
Since 2011, we have designated Interior’s management of federal oil and  gas resources as a high-risk area vulnerable to fraud, waste, abuse, and  mismanagement. During that time, we have made recommendations to  Interior related to oil, gas, and coal royalties. Although it has not met the criteria for removal from our High-Risk List, Interior has taken some steps  to strengthen how it manages federal oil and gas resources. For  example, Interior adopted regulations that provide BLM with the flexibility  to make timely changes to onshore oil and gas royalty rates, as we  recommended in December 2013. In addition, after we recommended in  December 2013 that BLM revise its guidance regarding management of  the coal program, the agency revised its guidance to better ensure it  obtains a fair market value for federal coal resources.
Interior has undertaken other actions intended to improve its  management of federal oil, gas, and coal resources. For example, in  2016, BLM began preparing a programmatic environmental impact  statement of the federal coal program that included reviewing an option to  raise the federal royalty rate, among other alternatives. Work on the  programmatic environmental impact statement was terminated in March  2017, and in the same month, the Secretary of the Interior signed a  charter establishing a Royalty Policy Committee to provide regular advice  on the fair market value of federal and Indian mineral and energy leases  and the collection of revenues from them. In reexamining aspects of how  it collects revenues associated with oil, gas, and coal production on  federal lands, BLM has solicited and received public comments. In  addition, a few stakeholders have stated that current federal royalty rates  are too low to ensure a fair return on public resources, while others have  stated that raising royalty rates would cause production to shift to state  and private lands.
The explanatory statement accompanying the Consolidated  Appropriations Act for fiscal year 2016 includes a provision for us to  review the potential effects of increasing federal royalty rates for oil, gas,  and coal production on federal lands. This report examines what is  known about how raising federal royalty rates for oil, gas, and coal could  affect (1) production on federal lands and (2) the federal revenue  associated with such production.
To do this work, we identified an extensive list of studies and other  literature through a literature search based on parameters designed to  include a wide range of published information about the effects of altering  royalty rates for oil, gas, and coal development on federal lands. We  supplemented this list with suggestions from knowledgeable  stakeholders, including agency officials, and our subject matter experts  then narrowed the list to studies directly relevant to our reporting  objectives. From the studies identified, we selected for more in-depth  review four studies—two that address oil and gas and two that address  coal—that we determined used reasonable and comprehensive  methodologies and assumptions for describing the range of potential  effects of raising federal royalty rates. Three of these studies were  conducted by or for federal agencies, and one was conducted by  researchers:
Congressional Budget Office (CBO), Options for Increasing Federal  Income from Crude Oil and Natural Gas on Federal Lands  (Washington, D.C.: April 2016).
Enegis, LLC, Benefit-Cost and Economic Impact Analysis of Raising  the Onshore Royalty Rates Associated with New Federal Oil and Gas  Leasing (Prepared for BLM, Washington, D.C.: April 2011).
Executive Office of the President of the United States, Council of  Economic Advisers (CEA), The Economics of Coal Leasing on  Federal Lands: Ensuring a Fair Return to Taxpayers (Washington,  D.C.: June 2016).
Haggerty, Lawson, and Pearcy, Steam Coal at an Arm’s Length: An  Evaluation of Proposed Reform Options for U.S. Coal Used in Power  Generation (Working paper, October 2016).
Each of these studies addresses the relationship between royalty rates  and production or federal royalty revenue. However, because federal  onshore royalty rates for oil, gas, and coal production on federal lands  have not changed in decades, no recent historical data exist describing  the direct effect of changing royalty rates on oil, gas, and coal production  on federal lands or the effect of such changes on federal revenues. In the  absence of such data, these studies used simulations with assumptions;  therefore, their estimates of the effects of changes in royalty rates depend  on various uncertain factors. We determined that these four studies are  reasonable for describing what is known about the range of potential  effects.
Additionally, we interviewed and summarized the views of knowledgeable  stakeholders representing 26 entities—such as officials from federal and  state agencies, industry groups, academia, and other nongovernmental  organizations—to capture various viewpoints on the potential effects of  raising federal royalty rates. We identified stakeholders on the basis of  their authorship of studies on the issue, referrals by other stakeholders, or  service on relevant panels and advisory groups. We interviewed state and  federal officials in states or regions that represented over 95 percent of  oil, gas, and coal production on federal lands in fiscal year 2015. We  strived to achieve balance by interviewing stakeholders representing  different viewpoints, but their views are not generalizable to those we did  not interview. Throughout this report, we use the modifiers “a few” to refer  to two to five stakeholders and “some” to refer to six to nine stakeholders.
We analyzed data from Interior’s Office of Natural Resources Revenue  (ONRR), the Energy Information Administration (EIA), and the U.S.  Extractive Industries Transparency Initiative on trends in oil, gas, and coal  production and the associated revenues. We assessed the reliability of  these data by analyzing relevant documentation and interviewing officials  about the steps they take to maintain the relevant databases. We  determined that these data were sufficiently reliable for the purposes of  our report.
We conducted this performance audit from June 2016 to June 2017 in  accordance with generally accepted government auditing standards.  Those standards require that we plan and perform the audit to obtain  sufficient, appropriate evidence to provide a reasonable basis for our  findings and conclusions based on our audit objectives. We believe that  the evidence obtained provides a reasonable basis for our findings and  conclusions based on our audit objectives.
subsections: section_title: Background
paragraphs: 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.
subsections: section_title: Royalty Rates for Federal and Nonfederal Lands
paragraphs: 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.
section_title: Production on Federal and Nonfederal Lands
paragraphs: 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.
section_title: Studies and Stakeholders Suggest Raising Federal Royalty Rates Could Decrease Production on Federal Lands
paragraphs: 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.
section_title: Studies and Stakeholders Suggest Raising Federal Royalty Rates Could Increase Federal Revenues
paragraphs: 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.
section_title: Agency Comments
paragraphs: 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.
section_title: Appendix I: Federal and Indian Production and Revenue Data from Oil, Gas, and Coal Development
paragraphs: 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.
section_title: Appendix II: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
section_title: Staff Acknowledgments
paragraphs: 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.