OIL, GAS, AND COAL 

ROYALTIES

Raising Federal Rates 

Could Decrease 

Production on Federal 

Lands but Increase 

Federal Revenue

Report to Congressional Committees

June 2017

GAO-17-540

United States Government Accountability Office
United States Government Accountability Office

Highlights of GAO-17-540, a report to 

congressional committees

June 2017

OIL, GAS, AND COAL ROYALTIES

Raising Federal Rates Could Decrease Production on 

Federal Lands but Increase Federal Revenue

What GAO Found

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.

View GAO-17-540. For more information, 

contact Frank Rusco at (202) 512-3841 or 

ruscof@gao.gov.

Why GAO Did This Study

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. 
Page i GAO-17-540 Oil, Gas, and Coal Royalties

Letter 1

Background 5

Studies and Stakeholders Suggest Raising Federal Royalty Rates 

Could Decrease Production on Federal Lands 16

Studies and Stakeholders Suggest Raising Federal Royalty Rates 

Could Increase Federal Revenues 22

Agency Comments 24

Appendix I Federal and Indian Production and Revenue Data from Oil, 

Gas, and Coal Development 25

Appendix II GAO Contact and Staff Acknowledgments 31

Tables

Table 1: Federal and State Royalty Rates for New Onshore Oil, 

Gas, and Coal Leases, as of March 2017 9

Table 2: Major Tight Oil and Shale Gas Plays, Federal Agency 

Ownership, and Overlap of Federal and Tribal Lands, 

2016 27

Table 3: Major Coal Basins, Federal Agency Ownership, and 

Overlap of Federal and Tribal Lands, 2013 27

Table 4: Federal Offshore, Onshore, and American Indian 

Royalties, Fiscal Years 2015 and 2016 28

Table 5: Federal Offshore, Onshore, and American Indian Bonus 

Bids and Rental Revenue, Fiscal Years 2015 and 2016 29

Table 6: Federal Offshore, Onshore, and American Indian Oil, 

Gas, and Coal Production, Fiscal Years 2015 and 2016 30

Figures

Figure 1: Royalty Revenue, Rental Payments, and Bonus Bids 

Associated with Onshore Oil, Gas, and Coal Production 

on Federal Lands, Fiscal Year 2016 11

Figure 2: Federal Lands and Major Tight Oil and Shale Gas Plays 13

Figure 3: Federal Lands and Major Coal Basins 15

Figure 4: Production and Royalty Payments from Onshore Oil, 

Gas, and Coal Development on Federal Lands, Fiscal 

Year 2007 through 2016 26

Contents
Page ii GAO-17-540 Oil, Gas, and Coal Royalties

Abbreviations

BLM Bureau of Land Management

CBO Congressional Budget Office

CEA Council of Economic Advisers

EIA Energy Information Administration

Interior Department of the Interior

ONRR Office of Natural Resources Revenue

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

without further permission from GAO. However, because this work may contain 

copyrighted images or other material, permission from the copyright holder may be 

necessary if you wish to reproduce this material separately.
Page 1 GAO-17-540 Oil, Gas, and Coal Royalties

441 G St. N.W.

Washington, DC 20548

June 20, 2017

The Honorable Lisa Murkowski

Chairman

The Honorable Tom Udall

Ranking Member

Subcommittee on Interior, Environment, and Related Agencies

Committee on Appropriations

United States Senate

The Honorable Ken Calvert

Chairman

The Honorable Betty McCollum

Ranking Member

Subcommittee on Interior, Environment, and Related Agencies

Committee on Appropriations

House of Representatives

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.1 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.2 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 

 1

The focus of this report is on the onshore production of resources on federal lands and 

excludes offshore production in federal waters. For the purpose of this report, we refer to 

money collected from the leasing of federal lands for energy production as revenue. See 

appendix I for information on offshore production and revenue data. 

2

Approximately half of the revenue collected from the development of onshore resources 

is to be paid to the state in which the resource was extracted. The exception is Alaska, 

where the state share is 88 percent for leases outside the National Petroleum Reserve 

and 50 percent for leases within the reserve. 30 U.S.C. § 191; 42 U.S.C. § 6506a(l).

Letter
Page 2 GAO-17-540 Oil, Gas, and Coal Royalties

criteria for removal from our High-Risk List, Interior has taken some steps 

to strengthen how it manages federal oil and gas resources.3 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 2013.4 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.5

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.6 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.7 In reexamining aspects of how 

it collects revenues associated with oil, gas, and coal production on 

 3

In our 2017 update, we reported that Interior had implemented some of our 

recommendations to address these challenges, but needs to do more to meet its 

responsibilities to manage federal oil and gas resources. See GAO, High-Risk Series: 

Progress on Many High-Risk Areas, While Substantial Efforts Needed on Others, 

GAO-17-317 (Washington, D.C.: Feb. 15, 2017).

4

GAO, Oil and Gas Resources: Actions Needed for Interior to Better Ensure a Fair Return, 

GAO-14-50 (Washington, D.C.: Dec. 6, 2013).

5

GAO, Coal Leasing: BLM Could Enhance Appraisal Process, More Explicitly Consider 

Coal Exports, and Provide More Public Information, GAO-14-140 (Washington, D.C.: Dec. 

18, 2013).

6

Beginning in January 2016, Secretarial Order 3338 placed a “pause” on federal coal 

leasing, with limited exceptions, during the completion of the programmatic environmental 

impact statement. However, on March 29, 2017, Secretarial Order 3348 revoked 

Secretarial Order 3338, lifting the moratorium on federal coal lease sales, and ending

work on the programmatic environmental impact statement effective immediately.

7

According to the charter, the Committee may also advise on the potential impact of 

proposed policies and regulations related to revenue collection from such development. 
Page 3 GAO-17-540 Oil, Gas, and Coal Royalties

federal lands, BLM has solicited and received public comments.8 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.9 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).

 8

In April 2015, BLM issued an Advance Notice of Proposed Rulemaking and sought 

comment on a number of potential reforms to the oil and gas leasing process, including 

setting royalty rates. 80 Fed. Reg. 22,148 (Apr. 21, 2015). Regarding coal, as stated

above, in January 2016, the Secretary of the Interior announced the preparation of a 

programmatic environmental impact statement, a comprehensive review of potential 

leasing and management reforms to the federal coal leasing program. 

9

Section 4 of the Consolidated Appropriations Act, 2016, Pub. L. No. 114-113 (2015), 

provides that the explanatory statement accompanying the act and printed in the 

Congressional Record shall have the same effect as if it were a joint explanatory 

statement of a committee of conference.
Page 4 GAO-17-540 Oil, Gas, and Coal Royalties

• 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.10 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 2015.11 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.

 10Not all of the stakeholders we interviewed addressed every issue discussed in this 

report.

11We interviewed state and BLM officials from Colorado, Montana, New Mexico, North 

Dakota, Oklahoma, South Dakota, Texas, Utah, and Wyoming.
Page 5 GAO-17-540 Oil, Gas, and Coal Royalties

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.12 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.

BLM leases federal lands to private companies for the production of 

onshore oil, gas, and coal resources, generally through a competitive 

bidding process.13 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.14 For coal leases, BLM requires a minimum bid of $100 per 

 12ONRR is responsible for managing and collecting revenues from companies that 

produce or extract resources from federal leases. EIA is a statistical agency within the 

Department of Energy that provides independent data, forecasts, and analyses. The U.S. 

Extractive Industries Transparency Initiative is a global standard that promotes open and 

accountable management of natural resources.

13For onshore leases, BLM’s current leasing processes were established under the 

Mineral Leasing Act of 1920, as amended. BLM regulations for oil and gas leasing and 

coal management are codified at 43 C.F.R. Parts 3100 and 3400, respectively.

1443 C.F.R. § 3120.1-2(c). According to Interior officials, most competitive bids for oil and 

gas are higher than the required minimum. For example, in fiscal year 2015, the average

bonus bid per acre for all the acres leased (both competitive and noncompetitive leases) 

was $139, and for fiscal year 2016, the average bonus bid per acre was $213.

Background
Page 6 GAO-17-540 Oil, Gas, and Coal Royalties

acre, and the bid must meet or exceed BLM’s estimate of the fair market 

value of the lease.15

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.16 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.17 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.18

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.19 For coal, the rental rate is at least $3 per acre.

20 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.21 Coal parcels are leased for an initial 20-year period and may 

be extended if certain conditions are met.22

 1543 C.F.R. § 3422.1(c). Coal bonus bids are based on the recoverable reserves estimate 

calculated prior to the lease sale and submission of the bonus bid. Coal bonus bids in 

fiscal year 2015 averaged $940 per acre; and in fiscal year 2016, there were no significant 

competitive lease sales because of Secretarial Order 3338.

1643 C.F.R. § 3110.1(b); 43 C.F.R. § 3110.2.

1743 C.F.R. Subpart 3432.

1843 C.F.R. § 3432.2(c).

1943 C.F.R. § 3103.2-2(a).

2043 C.F.R. § 3473.3-1(a).

2143 C.F.R. § 3120.2; 43 C.F.R. Part 3107.

2243 C.F.R. § 3475.2.
Page 7 GAO-17-540 Oil, Gas, and Coal Royalties

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.23 However, until January 2017, BLM regulations generally 

established a fixed royalty rate of 12.5 percent.24 For noncompetitive 

leases, the act, as amended, sets the royalty rate at a fixed rate of 12.5 

percent.25 For coal, royalty rates depend on the type of mine—surface or 

underground.26 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.27 For underground mines, BLM sets the rate at 8 

percent, the rate prescribed in regulation.28 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.29 For 

coal, certain costs are deducted from the price of coal at the first point of 

sale, including transportation and processing allowances, before the 

 2330 U.S.C. § 226(b)(1). 

2443 C.F.R. § 3103.3-1 (2015). In November 2016, BLM issued regulations amending this 

section to mirror BLM’s statutory authority for competitive leases, providing BLM with the 

flexibility to set royalty rates at or above 12.5 percent. This rule became effective in 

January 2017. Department of the Interior, Bureau of Land Management, Waste 

Prevention, Production Subject to Royalties, and Resource Conservation, Final Rule, 81 

Fed. Reg. 83008, (Nov. 18, 2016). As of March 2017, BLM officials said they had not yet 

used this flexibility to increase royalty rates above 12.5 percent.

2530 U.S.C. § 226(c).

26Two primary methods are used to mine coal: surface mining and underground mining. In 

surface mining, where coal deposits are buried within a few hundred feet of the surface, 

soil and rock above the coal are blasted with explosives and removed using large 

equipment, and the uncovered coal is then extracted. Deeper coal resources require use 

of underground mining, which entails digging a series of mine entries and shafts and using 

equipment to extract the coal and transport it to the surface. Underground mining is more 

expensive than surface mining. Mining on federal leases involves both surface and 

underground mining.

2730 U.S.C § 207 (a); 43 C.F.R. § 3473.3-2(a)(1).

2843 C.F.R. § 3473.3-2(a)(2).

29An allowance is an allowable deduction from the value of a mineral for royalty purposes. 

Royalty Rates for Federal 

and Nonfederal Lands
Page 8 GAO-17-540 Oil, Gas, and Coal Royalties

amount is calculated for royalty purposes.30 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.31

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 

 30On July 1, 2016, ONRR issued a final rule amending its regulations concerning 

valuation, for royalty purposes, of oil and gas produced from federal onshore and offshore 

leases and coal produced from federal and Indian leases. Department of the Interior, 

Office of Natural Resources Revenue, Consolidated Federal Oil and Gas and Federal and 

Indian Coal Valuation Reform, Final Rule, 81 Fed. Reg. 43338 (2016) (2017 Valuation 

Rule). The rule, effective January 1, 2017, addressed, among other things, royalty 

valuation for transactions between affiliated parties. On Feb. 27, 2017, ONRR postponed 

the effective date of the 2017 Valuation Rule citing, among other things, pending litigation 

over the rule that had been initiated in December 2016. Department of the Interior, Office 

of Natural Resources Revenue, Postponement of Effectiveness of the Consolidated 

Federal Oil and Gas and Federal and Indian Coal Valuation Reform 2017 Valuation Rule, 

82 Fed. Reg. 11823 (2017). On April 4, 2017, ONRR issued a proposed rule proposing to 

repeal in its entirety the 2017 Valuation Rule. Department of the Interior, Office of Natural 

Resources Revenue, Repeal of Consolidated Federal Oil and Gas and Federal and Indian 

Coal Valuation Reform, Proposed Rule, 82 Fed. Reg. 16323 (2017). Concurrently with the 

proposed repeal, ONRR published an Advance Notice of Proposed Rulemaking seeking 

public comment on whether revisions are needed to the pre-existing regulations governing 

royalty values, including whether the 2017 Valuation Rule should be retained or repromulgated, in whole or in part. 82 Fed. Reg. 16325 (2017).

31Royalty rate reductions may be approved by BLM in cases where a reduction is needed 

to promote mining development. In 2013, we found that the effective rate averaged about 

11 percent from fiscal year 1990 through fiscal year 2012 (see GAO-14-140).
Page 9 GAO-17-540 Oil, Gas, and Coal Royalties

percent to 25 percent for oil and gas production and from 3 percent to 10 

percent for coal production.32

Table 1: Federal and State Royalty Rates for New Onshore Oil, Gas, and Coal 

Leases, as of March 2017

Percentages

Federal rate Oil and gas Coal surface Coal underground

Onshore 12.5a 12.5 8

Selected state rates

Colorado 20.0 12.5 8

Montana 16.67 12.5b 10

New Mexico 12.5 to 20.0c 12.5 8 

North Dakota 16.67 or 18.75 Variesd Variesd

Utah 12.5 to 16.67e 8.0f 8f

Wyoming 12.5 or 16.67g 12.5 8 

Sources: GAO analysis of federal laws and regulations, and state officials. | GAO-17-540

Notes: These six states represented over 90 percent of total federal oil, gas, and coal production in 

fiscal year 2015. Other aspects of federal and state leasing processes, such as rental rates, 

allowances, and deductions, are not included in this table.

a

As of January 2017, BLM regulations permit royalty rates of not less than 12.5 percent for 

competitive leases, giving BLM the flexibility to issue a rate over 12.5 percent. All noncompetitive 

leases have a fixed rate of 12.5 percent. In March 2017, officials told us that BLM had not yet used 

this flexibility and that all leases issued since the regulations have been at 12.5 percent.

b

The Montana royalty rate is generally set at 12.5 percent for surface coal mining, but is not less than 

10 percent.

c

The oil and gas royalty rates in New Mexico are on a sliding scale based on the geographic location 

of the lease.

d

The coal royalty rates in North Dakota are determined on a mine-by-mine basis and assessed on fair 

market price.

e

The oil and gas royalty rates in Utah can change with the approval of the Director of the Utah Trust 

Lands Administration.

f

The coal royalty rate in Utah is generally 8 percent, though there are currently two exploration 

agreements for surface mining at 12 percent.

 32In 2015, BLM’s Advance Notice of Proposed Rulemaking stated that private royalty rates 

for oil and gas generally were between 12.5 percent and 25 percent. A 2016 Federal 

Reserve Bank of Kansas City study, which analyzed private lease data from the data 

source DrillingInfo, found private royalty rates for oil and gas varied from 13.2 percent to 

21.2 percent in 2014. A 2016 National Mining Association report, suggested private royalty 

rates for coal are generally between 3 percent and 10 percent. See Federal Reserve Bank 

of Kansas City, Capturing Rents from Natural Resource Abundance: Private Royalties 

from U.S. Onshore Oil and Gas Production (Kansas City, MO: July 2016) and National 

Mining Association, Federal Coal Leasing Moratorium: An Examination of the Reasons 

Driving a Disruptive Policy (Washington, D.C.: July 2016).
Page 10 GAO-17-540 Oil, Gas, and Coal Royalties

g

The oil and gas royalty rates vary in Wyoming based on demand. 

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.33 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.34 The federal government collected 

approximately $2.5 billion in gross revenue from the production of these 

resources on federal lands in fiscal year 2016.35 The majority of this 

revenue generally has come from royalties—about $2 billion, or 80 

percent of total revenues in fiscal year 2016.36 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.)

 33ONRR gas production numbers include natural gas liquids. Natural gas liquids are not 

produced at the wellhead; they are a byproduct of processing that produces revenue for 

the lessees, according to ONRR. For coal, these production numbers include coal, 

leonardite (a low rank coal with lower energy content), and coal waste. 

34Both ONRR and EIA gas production data include natural gas liquids. ONRR data are

reported by fiscal year, which runs from October through September. EIA data are 

reported monthly and can be added together in fiscal years or calendar years. To compare 

EIA data with ONRR data, we added EIA monthly data by fiscal year. 

35This figure includes revenue associated with natural gas liquids production.

36Although total royalty, rental, and bonus revenues were lower in fiscal year 2016 than in 

recent years, mainly because of decreased prices or decreased production, the 

percentage that royalty revenues constituted of total royalty, rental, and bonus revenues 

has been fairly constant for oil, gas, and coal over the last 10 years: around 83 percent.

Production on Federal and 

Nonfederal Lands
Page 11 GAO-17-540 Oil, Gas, and Coal Royalties

Figure 1: Royalty Revenue, Rental Payments, and Bonus Bids Associated with 

Onshore Oil, Gas, and Coal Production on Federal Lands, Fiscal Year 2016

Note: Oil and gas royalties include amounts associated with natural gas liquids production.
Page 12 GAO-17-540 Oil, Gas, and Coal Royalties

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.37 During that same period, federal onshore oil production 

increased by 59 percent while federal onshore gas production declined by 

18 percent.38 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.39

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.40

 37Total U.S. oil and gas production numbers are from EIA and are presented in calendar 

years.

38Federal onshore oil and gas production numbers are from ONRR and are presented in 

fiscal years.

39According to EIA, a play is a set of known or postulated oil and gas accumulations 

sharing similar geologic, geographic, and temporal properties, such as source rock, 

migration pathway, and hydrocarbon type. Oil and natural gas are found in a variety of 

geologic formations distributed across the country, such as shale or tight sandstone

formations—also referred to as “tight oil” or “shale gas.” Shale is a sedimentary rock that 

is predominantly composed of consolidated clay-sized particles. Hydraulic fracturing (also 

known as fracking) is commonly defined as an oil or gas well completion process that 

directs pressurized fluids to penetrate tight rock formations, such as shale or coal 

formations, in order to stimulate and extract the oil or gas in the formation. The fluids 

typically contain a combination of water, proppant, and added chemicals. 

40The percentage is approximate because the federal lands mapping layer provided by 

EIA represents those federal lands where the government holds surface land ownership of 

mineral rights. This does not include 57 million acres, or about 9 percent of the lands 

mapped, where the federal government owns mineral resources on or below state and 

private lands.
Page 13 GAO-17-540 Oil, Gas, and Coal Royalties

Figure 2: Federal Lands and Major Tight Oil and Shale Gas Plays

Notes: These major tight oil and shale gas plays constituted more than 90 percent of oil and gas 

production growth from 2011 to 2016, according to Energy Information Administration data, although 

there is production from conventional resources in other plays and basins. The federal lands mapped 

here represent federal surface land ownership and do not include 57 million acres, or about 9 percent 

of the lands mapped, where the federal government owns mineral resources below private lands. 

Alaska and Hawaii are not depicted because they contain no major tight oil or shale plays.

a

The Marcellus and Utica plays geographically overlap to some degree and are therefore reported 

together.
Page 14 GAO-17-540 Oil, Gas, and Coal Royalties

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.41 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.42 Major coal basins 

that overlap with federal lands are primarily concentrated in the Powder 

River Basin in parts of Wyoming and Montana.

 41Federal coal production numbers are from ONRR and are presented in fiscal years, 

while total U.S. coal production numbers are from EIA and are presented in calendar 

years.

42The coal fields mapping layer is provided by the U.S. Geological Survey, and the latest 

version of the layer is from 2013. The percentage is approximate because the mapping 

layer represents federal lands where the government holds surface land ownership of 

mineral rights. The federal lands mapped here represent federal surface land ownership 

and do not include 57 million acres, or about 9 percent of the lands mapped, where the 

federal government owns mineral resources on or below state and private lands.
Page 15 GAO-17-540 Oil, Gas, and Coal Royalties

Figure 3: Federal Lands and Major Coal Basins

Note: These four coal basins represented more than 80 percent of total U.S. coal production in 2015, 

based on Energy Information Administration data. Federal lands mapped here represent federal 

surface land ownership. However, for an additional 57 million acres, or about 9 percent of the lands 

mapped, the federal government owns mineral resources below private lands. We did not include 

Alaska or Hawaii because they had no federal coal production in the last 10 years.
Page 16 GAO-17-540 Oil, Gas, and Coal Royalties

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.43 Both studies suggested that a 

higher royalty rate could decrease production on federal lands by either a 

small amount or not at all.44 The CBO study concluded that raising the 

royalty rate to 18.75 percent would lead to “reductions in production [that] 

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.45 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 

 43Congressional Budget Office, Options for Increasing Federal Income From Crude Oil 

and Natural Gas on Federal Lands (Washington, D.C.: April 2016) and Enegis, LLC, 

Benefit-Cost and Economic Impact Analysis of Raising the Onshore Royalty Rates 

Associated with New Federal Oil and Gas Leasing (Washington, D.C.: April 2011). The 

Enegis, LLC, report was completed under a contract for BLM. 

44The studies discuss results 10 or more years into the future. A royalty rate increase 

would apply only to new leases, and production on a new lease might not begin until near 

the end of the lease term. Therefore, the effects of a royalty rate increase on production 

and revenue would only begin to be realized within the first 10 years, according to CBO.

45The CBO study included other policy scenarios not related to a change in the royalty 

rate, including (1) auctioning leases through a sealed-bid process, (2) allowing Interior to 

set lease-specific fiscal terms for leases with great potential for oil and gas reserves, (3) 

increasing the minimum bid, and (4) imposing a fee on non-producing leases.

Studies and 

Stakeholders Suggest 

Raising Federal 

Royalty Rates Could 

Decrease Production 

on Federal Lands
Page 17 GAO-17-540 Oil, Gas, and Coal Royalties

responses.46 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.

47

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, 

 46In addition to the flat-rate increases to the royalty rate (i.e., 16.67 percent, 18.75 

percent, or 22.5 percent), the Enegis study also included 24 sliding-scale royalty rate 

scenarios that modeled how changes to royalty rates would be triggered by future 

commodity price thresholds. 

47Executive Office of the President of the United States, Council of Economic Advisers, 

The Economics of Coal Leasing on Federal Lands: Ensuring a Fair Return to Taxpayers

(Washington, D.C.: June 2016). The CEA study used results from a series of Integrated 

Planning Model scenarios with higher royalty rates. The Integrated Planning Model is a 

well-established energy and electricity system model that the U.S. government has used 

extensively for many years in support of rulemakings. The CEA study consisted of four 

scenarios that looked at calculating the market value of coal for royalty purposes based on 

per-Btu (British thermal unit) market prices of (1) nearby regional coal, (2) nationwide 

nonfederal coal and (3) natural gas. The fourth scenario looked at maximizing the return to 

taxpayers; this scenario was used to illustrate how high the royalty rate could go before 

royalty revenues began to decrease because of reduced production. We are not 

discussing the results for this scenario because it was not meant as a policy suggestion.
Page 18 GAO-17-540 Oil, Gas, and Coal Royalties

predicted that federal production would decrease by 7 percent.48 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.49 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.50

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.51

We previously reported that underground mining, which is mostly 

concentrated in the eastern region, is more costly than surface mining, 

 48According to CEA officials, the results of the study assumed that the Clean Power Plan

would take effect beginning in 2022, which is set to reduce emissions from the electric 

power sector through many compliance approaches, including switching fuel sources from 

coal and other carbon intensive fuels to less carbon intensive ways to produce electricity. 

Without the Clean Power Plan, officials stated that the modeled production effects might

change.

49Haggerty, 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). This study examines the impact of an effective increase in the royalty rate. 

The authors generate an effective rate increase by positing a change in the valuation point 

of coal royalties from a lower effective rate based on delivered prices to a potentially 

higher statutory rate based on reported prices. Our focus is on the hypothetical effect on 

production and royalties of an increase in the effective royalty rate. We did not assess the 

validity of the empirical valuation methodology that is claimed by the authors to generate a 

higher effective royalty rate.

50This study calculated the average difference in the effective and statutory rates for nine 

states from 2008 to 2014, which ranged between 0 and 3.6 percent.

51These average market prices do not include captive market transactions, or sales

between two affiliated parties.
Page 19 GAO-17-540 Oil, Gas, and Coal Royalties

resulting in a higher sale price.52 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 2017.53 In addition, according to a few 

stakeholders we interviewed and a 2015 report by the Congressional 

 52GAO-14-140.

53More specifically, oil prices averaged $101 per barrel in March 2014 compared with an 

average of $50 per barrel in March 2017. Increasing royalty rates from 12.5 percent to 

16.67 percent would raise the cost of production by about $4 per barrel at oil prices as of 

March 2014 and $2 per barrel at oil prices prevailing in March 2017. If nothing else had 

changed, producers in March 2014 would still be receiving a net additional $49 per barrel 

because of the higher price.
Page 20 GAO-17-540 Oil, Gas, and Coal Royalties

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.54 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.55 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.56 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.57

• 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 

 54Congressional Research Service, Mineral Royalties on Federal Lands: Issues for 

Congress (Washington, D.C.: January 2015). This report specifically states that a higher 

royalty rate coupled with low oil and gas prices could negatively impact high-cost marginal 

producers.

55GAO, Electricity: Significant Changes Are Expected in Coal-Fueled Generation, but Coal 

Is Likely to Remain a Key Fuel Source, GAO-13-72 (Washington, D.C.: Oct. 29, 2012).

56In fiscal year 2012, there were six coal lease sales; in fiscal year 2013, two; in fiscal year 

2014, one; and in fiscal year 2015, two. According to BLM officials, there were no 

successful coal lease sales in fiscal year 2016.

57GAO-14-140.
Page 21 GAO-17-540 Oil, Gas, and Coal Royalties

we previously reported has lower extraction and production costs.58 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.59 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 

 58EIA’s data include coal production from federal, state, and private lands. GAO-14-140.

59GAO-14-140.
Page 22 GAO-17-540 Oil, Gas, and Coal Royalties

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.

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).60 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 

 60Net federal revenue is the revenue retained by the federal government after 

approximately half of revenues are returned to the states in which the resources were 

produced, and after any other disbursements.

Studies and 

Stakeholders Suggest 

Raising Federal 

Royalty Rates Could 

Increase Federal 

Revenues
Page 23 GAO-17-540 Oil, Gas, and Coal Royalties

royalty rate to 16.67 percent, 18.75 percent, or 22.5 percent.61 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.62 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 

 61Net changes to state and federal revenues were also positive under the sliding scale 

scenarios in the Enegis study.

62Under the other scenario, which maximized the return to taxpayers, the study estimated 

that government revenue would increase by up to $3.1 billion annually after 2025. As 

noted earlier, according to CEA officials, this study assumed that the Clean Power Plan 

would take effect in 2022. Without the Clean Power Plan, the federal revenue effects may 

vary. 
Page 24 GAO-17-540 Oil, Gas, and Coal Royalties

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.

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.

Frank Rusco

Director, Natural Resources and Environment

Agency Comments
Appendix I: Federal and Indian Production and 

Revenue Data from Oil, Gas, and Coal 

Development

Page 25 GAO-17-540 Oil, Gas, and Coal Royalties

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.1 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 2016.2

 1

The tribal lands overlap was determined using a U.S. Census map layer. 

2

The Office of Natural Resources Revenue (ONRR) reports data on oil, gas, and coal 

production on American Indian lands, but these numbers are not included in federal 

onshore totals.

Appendix I: Federal and Indian Production 

and Revenue Data from Oil, Gas, and Coal 

Development
Appendix I: Federal and Indian Production and 

Revenue Data from Oil, Gas, and Coal 

Development

Page 26 GAO-17-540 Oil, Gas, and Coal Royalties

Figure 4: Production and Royalty Payments from Onshore Oil, Gas, and Coal Development on Federal Lands, Fiscal Year 2007 

through 2016
Appendix I: Federal and Indian Production and 

Revenue Data from Oil, Gas, and Coal 

Development

Page 27 GAO-17-540 Oil, Gas, and Coal Royalties

Table 2: Major Tight Oil and Shale Gas Plays, Federal Agency Ownership, and 

Overlap of Federal and Tribal Lands, 2016

Play

Percentage of 

federal land overlap Agency ownership

Percentage of 

tribal land overlap 

Bakken 9 Interior, Forest 

Service

15.5

Eagle Ford 0 Interior, other 0.0

Haynesville 9 Interior, Forest 

Service, other

1.5

Marcellus/Utica 6 Interior, Forest 

Service, other

0.0

Niobrara 39 Interior, Forest 

Service, other

0.0

Permian 15 Interior, other 0.0

Sources: GAO analysis of Energy Information Administration data, U.S. Geological Survey data, and U.S. Census Bureau data. ׀ GAO-17-540

Notes: The Marcellus and Utica plays geographically overlap to some degree and are therefore 

reported together. “Other” in the agency ownership column represents all other federal agencies apart 

from Department of the Interior and the U.S. Forest Service. The percentage of tribal land overlap 

reflects those boundaries reported to the U.S. Census Bureau and in effect as of January 1, 2010. 

These boundaries are for Census Bureau statistical data collection and tabulation purposes only; their 

depiction and designation for statistical purposes do not constitute a determination of jurisdictional 

authority or rights of ownership or entitlement.

Table 3: Major Coal Basins, Federal Agency Ownership, and Overlap of Federal and 

Tribal Lands, 2013

Basin

Percentage of 

federal land overlap Agency ownership

Percentage of 

tribal land overlap 

Northern 

Appalachia 4.7

Interior, Forest 

Service

0.0

Central 

Appalachia 8.7

Forest Service 0.0

Illinois 0.2 Forest Service, other 0.0

Powder River

19.2

Interior, Forest 

Service

0.1

Sources: GAO analysis of Energy Information Administration data, U.S. Geological Survey data, and U.S. Census Bureau data. ׀ GAO-17-540

Note: “Other” in the agency ownership column represents all other federal agencies apart from the 

Department of the Interior and the U.S. Forest Service. The percentage of tribal land overlap reflects

those boundaries reported to the U.S. Census Bureau and in effect as of January 1, 2010. These 

boundaries are for Census Bureau statistical data collection and tabulation purposes only; their 

depiction and designation for statistical purposes do not constitute a determination of jurisdictional 

authority or rights of ownership or entitlement. The most recent coal layer data available are from 

2013.
Appendix I: Federal and Indian Production and 

Revenue Data from Oil, Gas, and Coal 

Development

Page 28 GAO-17-540 Oil, Gas, and Coal Royalties

Table 4: Federal Offshore, Onshore, and American Indian Royalties, Fiscal Years 

2015 and 2016

Dollars in millions

Resource Fiscal Year 2015

royalties

Fiscal Year 2016

royalties

Oil

Federal offshore 3,734.14 2,216.47 

Federal onshore 1,269.60 793.12

American Indian 601.84 379.27

Gas

Federal offshore 516.11 253.52

Federal onshore 1,069.31 653.35

American Indian 149.98 96.25

Coal

Federal onshore 682.70 536.46

American Indian 74.39 58.49

Source: Office of Natural Resources Revenue data. ׀ GAO-17-540

Notes: The revenue data for gas include natural gas liquids revenues. The Office of Natural 

Resources Revenue reports data on oil, gas, and coal production on American Indian lands, but 

these numbers are not included in federal onshore totals.
Appendix I: Federal and Indian Production and 

Revenue Data from Oil, Gas, and Coal 

Development

Page 29 GAO-17-540 Oil, Gas, and Coal Royalties

Table 5: Federal Offshore, Onshore, and American Indian Bonus Bids and Rental 

Revenue, Fiscal Years 2015 and 2016

Dollars in millions

Resource Fiscal Year 2015 Fiscal Year 2016 

Oil and gas

Federal offshore—bonus bids 642.04 159.86 

Federal offshore—rentals 225.51 158.03 

Federal onshore—bonus bids 112.65 122.91 

Federal onshore—rentals 30.89 21.47 

American Indian—bonus bids 0

a 0a

American Indian—rentals 4.06 4.06 

Coal

Federal onshore—bonus bids 453.87 384.07 

Federal onshore—rentals 1.29 1.31 

American Indian—bonus bids 0.20 5.50 

American Indian—rentals 0.06 0.21 

Source: Office of Natural Resources Revenue data. ׀ GAO-17-540

Notes: Production of natural gas liquids does not produce bonus bid or rental revenues and natural 

gas liquids therefore are not included in these revenue data. The Office of Natural Resources 

Revenue reports data on oil, gas, and coal production on American Indian lands, but these numbers 

are not included in federal onshore totals.

a

There were no bonus bids reported for oil and gas on American Indian lands in fiscal year 2015 or 

2016.
Appendix I: Federal and Indian Production and 

Revenue Data from Oil, Gas, and Coal 

Development

Page 30 GAO-17-540 Oil, Gas, and Coal Royalties

Table 6: Federal Offshore, Onshore, and American Indian Oil, Gas, and Coal 

Production, Fiscal Years 2015 and 2016

Resource Fiscal Year 2015 Fiscal Year 2016

Oil (barrels)

Federal offshore 554,720,979 553,683,961

Federal onshore 174,555,096 157,030,533

American Indian 63,899,859 57,732,193

Gas (thousand cubic feet)

Federal offshore 1,357,562,938 1,255,384,917

Federal onshore 3,378,237,142 3,138,734,185

American Indian 316,435,483 316,841,943

Coal (tons)

Federal onshore 389,606,150 295,871,233

American Indian 19,101,776 13,857,277

Source: Office of Natural Resources Revenue data. ׀ GAO-17-540

Notes: Gas production numbers include natural gas liquids volumes. The Office of Natural Resources 

Revenue reports data on oil, gas, and coal production on American Indian lands, but these numbers 

are not included in federal onshore totals.
Appendix II: GAO Contact and Staff 

Acknowledgments

Page 31 GAO-17-540 Oil, Gas, and Coal Royalties

Frank Rusco, (202) 512-3841 or ruscof@gao.gov

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.

Appendix II: GAO Contact and Staff 

Acknowledgments

GAO Contact

Staff 

Acknowledgments

(100960)
The Government Accountability Office, the audit, evaluation, and investigative 

arm of Congress, exists to support Congress in meeting its constitutional 

responsibilities and to help improve the performance and accountability of the 

federal government for the American people. GAO examines the use of public 

funds; evaluates federal programs and policies; and provides analyses, 

recommendations, and other assistance to help Congress make informed 

oversight, policy, and funding decisions. GAO’s commitment to good government 

is reflected in its core values of accountability, integrity, and reliability.

The fastest and easiest way to obtain copies of GAO documents at no cost is 

through GAO’s website (http://www.gao.gov). Each weekday afternoon, GAO 

posts on its website newly released reports, testimony, and correspondence. To 

have GAO e-mail you a list of newly posted products, go to http://www.gao.gov

and select “E-mail Updates.”

The price of each GAO publication reflects GAO’s actual cost of production and 

distribution and depends on the number of pages in the publication and whether 

the publication is printed in color or black and white. Pricing and ordering 

information is posted on GAO’s website, http://www.gao.gov/ordering.htm. 

Place orders by calling (202) 512-6000, toll free (866) 801-7077, or 

TDD (202) 512-2537.

Orders may be paid for using American Express, Discover Card, MasterCard, 

Visa, check, or money order. Call for additional information.

Connect with GAO on Facebook, Flickr, LinkedIn, Twitter, and YouTube.

Subscribe to our RSS Feeds or E-mail Updates. Listen to our Podcasts.

Visit GAO on the web at www.gao.gov and read The Watchblog.

Contact:

Website: http://www.gao.gov/fraudnet/fraudnet.htm

E-mail: fraudnet@gao.gov

Automated answering system: (800) 424-5454 or (202) 512-7470

Katherine Siggerud, Managing Director, siggerudk@gao.gov, (202) 512-4400, 

U.S. Government Accountability Office, 441 G Street NW, Room 7125, 

Washington, DC 20548

Chuck Young, Managing Director, youngc1@gao.gov, (202) 512-4800

U.S. Government Accountability Office, 441 G Street NW, Room 7149 

Washington, DC 20548

James-Christian Blockwood, Managing Director, spel@gao.gov, (202) 512-4707

U.S. Government Accountability Office, 441 G Street NW, Room 7814, 

Washington, DC 20548

GAO’s Mission

Obtaining Copies of 

GAO Reports and 

Testimony

Order by Phone

Connect with GAO

To Report Fraud, 

Waste, and Abuse in 

Federal Programs

Congressional 

Relations

Public Affairs

Strategic Planning and 

External Liaison

Please Print on Recycled Paper.