GAO (2017): Federal Oil and Gas Royalty Rates — Production Versus Revenue

Summary

Oil, Gas, and Coal Royalties: Raising Federal Rates Could Decrease Production on Federal Lands but Increase Federal Revenue (GAO-17-540, June 2017, 36 pp.) is a report by the U.S. Government Accountability Office to the House and Senate Interior appropriations subcommittees. It asks what is known about how raising federal onshore royalty rates would affect production and revenue, and it answers with a two-sided finding that its title states: higher rates could reduce output on federal lands and could raise federal revenue.[1] The onshore oil and gas rate that GAO examined was the statutory floor of 12.5 percent of the value of production, set under the Mineral Leasing Act.[1][2]

The rate has since moved twice in the statute: up to 16⅔ percent for new leases in August 2022, and back to 12½ percent in July 2025.[2] What follows is that statutory history, GAO's finding with its stated limits, the current advocacy debate, and an interpretive note on what the debate shows about royalties as an instrument for capturing resource rent.

The Rate and Its History

A royalty is a fixed percentage of the value (or amount) of production, paid to the landowner once production starts. On federal onshore land it is paid alongside up-front bonus bids and annual rentals (pp. 5–6), and GAO reports that royalties supplied about 80 percent of the roughly $2.5 billion collected from onshore oil, gas and coal in fiscal year 2016 (p. 10).[1] For oil and gas the royalty is calculated on wellhead value, with allowances deducted after the rate is applied (p. 7).[1]

Three qualifications on the history:

• The 1920 enactment itself. GAO attributes the 12.5 percent competitive floor to the 1920 Act. The Cornell LII code notes reproduce the floor in the pre-1987 text but not the 1920 enactment, and they record that a 1946 amendment set 12½ percent for lands outside known producing structures. The rate applying to such lands before 1946 is not established by the sources cited, so "unchanged since 1920" is best read as shorthand for the competitive-lease floor.[1][2]
• Only part of the 2022 package was reversed. The LII notes list §50262(a) and (e) as repealed. The current statutory text still carries the 2022 $10-per-acre minimum bid and the higher rental schedule.[2]
• Existing leases. A rate change in the statute applies to leases issued after it. GAO stresses that a royalty increase "would apply only to new leases" (fn. 44, p. 16).[1] The sources cited do not address whether leases issued at 16⅔ percent between 2022 and 2025 kept those terms.

Offshore. For federal waters, 43 U.S.C. §1337(a)(1) followed the same path. The pre-2022 text set "not less than 12½ per centum"; the 2022 Act (§50261) substituted a range of not less than 16⅔ and not more than 18¾ percent for ten years and not less than 16⅔ thereafter; the 2025 Act (§50102(d)) repealed that and instead wrote a range of "not less than 12½ percent, but not more than 16⅔ percent" into the same clauses.[3]

State rates. GAO's Table 1 (p. 9) gives rates for new leases in six states as of March 2017: Colorado 20, Montana 16.67, New Mexico 12.5 to 20, North Dakota 16.67 or 18.75, Utah 12.5 to 16.67, and Wyoming 12.5 or 16.67 percent. State officials told GAO that oil and gas rates "tend to be higher" than federal ones, and GAO notes that the table omits rentals, allowances and deductions.[1] Published reports cited by GAO put private-lease royalties between 12.5 and 25 percent (pp. 8–9).[1]

What GAO Found

Method. GAO screened an extensive literature and selected four studies for in-depth review, two on oil and gas and two on coal: a Congressional Budget Office analysis (April 2016), an Enegis LLC study prepared for BLM (April 2011), a Council of Economic Advisers coal study (June 2016), and a working paper by Haggerty, Lawson and Pearcy (October 2016). It also interviewed 26 stakeholders. GAO made no recommendations.[1] The central limitation is stated on p. 4: "no recent historical data exist describing the direct effect of changing royalty rates on oil, gas, and coal production on federal lands" or on revenues, so the studies "used simulations with assumptions."[1] Everything below is model output plus stakeholder opinion, not observed response to a rate change.

Production. GAO reports that both oil-and-gas studies "suggested that a higher royalty rate could decrease production on federal lands by either a small amount or not at all" (p. 16).[1] CBO, as GAO quotes it, concluded that at 18.75 percent "reductions in production [that] would be small or even negligible" would follow over ten years, particularly if the federal rate stayed at or below state and private rates (p. 16).[1][5] The Enegis study modelled 16.67, 18.75 and 22.5 percent over 25 years and found declines in every scenario except those in which companies fully absorbed the higher cost. The largest oil decline was about 70 million barrels over 25 years, roughly 1.8 percent of fiscal-year-2016 onshore federal output per year (p. 17).[1] The Highlights page reports one study finding a decline of under 2 percent a year at 22.5 percent.[1] Stakeholders disagreed about the size of any effect, citing market prices, the location of the best resources (most major tight-oil plays lie off federal land, p. 12) and the regulatory burden of federal leasing (pp. 19–21).[1] Colorado and Texas officials said their own increases (Colorado from 16.67 to 20 percent in 2016; Texas to 25 percent more than 30 years earlier) had no noticeable effect on leasing or production (pp. 21–22), which GAO reports as officials' statements.[1]

Revenue. GAO states that "Higher rates could have two opposing effects on federal revenues" (p. 22): less production, and more revenue on the production that remains.[1] The oil and gas studies estimated net federal revenue gains of $5 million to $38 million a year, or roughly 0.7 to 5.2 percent of net oil and gas royalties in fiscal year 2016. CBO's estimate for a rise from 12.5 to 18.75 percent was $200 million over ten years "and potentially by much more" in the following decade, because the change touches only new leases, and only 6 percent of 2013 royalties came from leases issued in the preceding ten years (p. 22).[1] The Enegis range was $125 million to $939 million over 25 years (pp. 22–23).[1]

Caveats GAO carries.

• New leases only, with a long lag. The studies' results are 10 or more years out, and production on a new lease may not start until near the end of its term (fn. 44, p. 16).[1]
• Bonus bids could offset revenue. Some stakeholders said companies would offer lower bonus bids if they faced higher royalties; a few thought the net effect would be minimal because royalties are the larger share. In fiscal year 2016 bonus bids were 8 percent of onshore oil and gas revenue, against 42 percent for coal (pp. 23–24).[1]
• Marginal wells are the exposed margin. Some stakeholders said "any negative effect on production from higher rates could be limited to or affect areas with marginal oil and gas wells" (pp. 19–20), and a Congressional Research Service report cited in fn. 54 says higher royalties combined with low prices could hurt high-cost marginal producers.[1] GAO also computes that going from 12.5 to 16.67 percent raises the cost of producing a barrel by about $2 at March 2017 prices ($50) and about $4 at March 2014 prices ($101) (fn. 53, p. 19).[1]
• Coal differs. GAO's coal findings (a 3 to 7 percent production decline in one study, under 1 percent in another) rest on different market conditions and are not carried over to the oil and gas findings.[1]

The Current Debate: The "Royalty Rip-Off" Framing

The budget-watchdog and advocacy organisation Taxpayers for Common Sense (TCS) released a report in September 2026 titled Royalty Rip-Off. It argues that the 12.5 percent floor is "grossly outdated" and urges Congress to raise the minimum to 18.75 percent (pp. 1, 5).[4] TCS is the origin of the "rip-off" framing and of the figures below; they are its own arithmetic, not an official estimate.

• The $25 billion figure. TCS reports that the Office of Natural Resources Revenue recorded $47 billion of royalties on $402 billion of federal oil and gas sales from 2016 to 2025. It applies 18.75 percent to those sales, deducts $3.4 billion of approved allowances, and subtracts the $47 billion collected, arriving at roughly $25 billion, split about evenly between the federal Treasury and states (p. 3, fns. 7–8).[4] The arithmetic is internally consistent (0.1875 × 402 = 75.4; 75.4 − 3.4 − 47 ≈ 25).
• What the figure is. It is a static, retroactive counterfactual. It holds volumes and prices at their actual levels, and it applies the higher rate to production from leases issued at 12.5 percent. It therefore embodies no production response, which is the very thing GAO's title flags. It also depends on TCS's own accounting of allowances.[4][1]
• TCS's reading of GAO. TCS quotes GAO as finding that raising rates would increase revenue while reducing production "by a small amount or not at all," and headlines the section "Royalty Rates Don't Impact Leasing and Production Decisions" (p. 4).[4] The quoted phrase appears at p. 16 of GAO's report, where it describes what two studies suggested; GAO's own headline and its stakeholder and marginal-well caveats are more qualified.[1]
• State rates. TCS summarises Texas at 20 to 25 percent, New Mexico at 18.75 to 25 percent and Colorado, North Dakota, Oklahoma, Pennsylvania, Utah and Wyoming at 16.67 to 20 percent (p. 3, fns. 10–21).[4] These are TCS's characterisations of state leasing practice, compiled from state statutes and lease documents; they have not been independently verified, and they are not like-for-like with the federal floor (the statutory minimum in some states is lower than the typical rate TCS reports, and rentals and bonus practice differ).
• Bids after 2022. TCS reports higher average competitive bids per acre in 2023 and 2024 ($2,149 and $1,085) than the 2013–2022 average ($288) and reads this as showing the 2022 increase did not deter bidding (p. 4, fn. 27, its own analysis).[4] The comparison does not control for prices or for which parcels were offered, so it is suggestive at most.

Relation to the Georgist Case

Interpretation, not a finding of GAO or TCS.

A royalty is a share of gross output, not a charge on rent. Economic rent is what a deposit yields above all costs, including a normal return on capital. A fixed percentage of revenue bears no fixed relation to that surplus. On a rich deposit a 12.5 percent royalty can leave most of the rent with the lessee, and on a marginal deposit, where rent is near zero, the same percentage is a cost that can shut production. Mason Gaffney made this argument for oil leasing in 1977: a well-designed rent instrument takes more from flush deposits and less or nothing from marginal ones, and so leaves lessees more incentive than "a blunt instrument such as a royalty"; his Alaska report proposed an ad valorem charge on proven reserves instead.[6] Mintz and Chen reach a compatible conclusion from mainstream public finance: the efficient royalty is one levied after costs are deducted.[7]

GAO's caveats read as the two halves of that argument. The marginal-well exposure GAO records is the over-taxation half: a higher percentage bites hardest where rent is thinnest. TCS's observation that its estimated forgone revenue peaked in 2022 as prices spiked is consistent with the under-collection half: if unit costs do not rise in step with price, a fixed share of price captures a shrinking share of rent. Neither observation is in the sources as a rent calculation, and neither source estimates the rent on federal leases.

The bonus-bid offset is capitalisation. Bidders price the royalties they expect to pay into what they offer up front, so part of any royalty increase is expected to return as lower bonus bids, which is what the stakeholders GAO interviewed suggested (pp. 23–24).[1] This is the same logic by which a recurring charge on land is capitalised into its sale price, and it is one reason the revenue gain from a higher royalty is smaller than the rate change alone implies.

The 12.5 percent versus state-rate debate concerns the level of a blunt instrument. Whether the federal floor should be 12.5, 16.67 or 18.75 percent is a question about how large a gross-output share to take, and the GAO trade-off between lost production and added revenue is the trade-off a percentage royalty forces. A charge that fell on rent net of costs would, in principle, leave the marginal well's production decision unchanged; that is the design rationale behind the cash-flow tax and the instrument comparison in the IMF windfall note. The alternatives carry their own difficulties, since a net-rent charge needs verified cost data and has proved hard to administer (see Australia's MRRT).

Nuances and Limits

• Simulation, not experiment. GAO's own statement is that there was no recent historical variation in federal rates to study (p. 4). The 2022–2025 episode is the first real variation in decades, and GAO's 2017 report predates it.[1]
• Age and scope. The report is from June 2017, at $50 oil, and reviews studies dated 2011 and 2016. The oil and gas evidence is two studies; the CBO study is known only through GAO's quotations and figures.
• Mixed by design. GAO's title and highlights say "could decrease production" and "increase federal revenue." Quoting only the "small amount or not at all" phrase, or only the production-loss half, omits the other side of the report.
• Net revenue, not rent. The revenue figures are royalty and related receipts, not an estimate of the resource rent on federal leases or of the share the public captures.
• Advocacy figures. TCS's $25 billion and its state-rate table are advocacy-organisation calculations from public data, cited as such.
• Not an argument for or against Georgism. The finding concerns the level of a royalty on new federal oil and gas leases. It does not test a rent-based charge, and it is not evidence on the efficiency of land-value taxation.

Bears On

• Benefit (as a limit): Capturing resource rent works — where institutions are strong. The federal onshore case shows how a blunt royalty, fixed at lease issue and applied to gross value, makes rent capture a negotiation over a rate rather than a charge that tracks rent. GAO's modelled results are mixed and are not cited there as support for high-rate capture.
• Concept: Resource Rents. A worked example of royalty design, its statutory history and its production-versus-revenue trade-off.

See Also

• Resource Rents
• Capturing resource rent works — where institutions are strong
• Gaffney (1977): Oil and Gas Leasing Policy for Alaska — the ad valorem alternative to a royalty
• Gaffney: Objectives of Government Policy in Leasing Mineral Lands & Oil and Gas: The Unfinished Tax Reform
• Mintz & Chen: Capturing Economic Rents from Resources through Royalties and Taxes
• Taxing Windfall Profits in the Energy Sector (Baunsgaard & Vernon, IMF)
• Australia's Mining Tax System: State Royalties, the PRRT, and the Failed MRRT
• Cash-Flow Tax
• Economic Rent

Sources

1. U.S. Government Accountability Office, Oil, Gas, and Coal Royalties: Raising Federal Rates Could Decrease Production on Federal Lands but Increase Federal Revenue, GAO-17-540, June 2017, 36 pp. gao.gov/products/gao-17-540 · PDF — used for the finding, method, caveats, Table 1 state rates, stakeholder views and all page-number quotations (printed page numbers; the Highlights page is unnumbered). Read in full at last review (2026-09-30). Tier 1, official audit body (B-claim for the modelled effects, which are simulation results; A-claim for the descriptive and statutory statements).
2. 30 U.S.C. §226, "Lease of oil and gas lands," with amendment and editorial notes, Cornell Legal Information Institute. law.cornell.edu/uscode/text/30/226 — used for the onshore royalty text, the 1946, 1987, 2022 (Pub. L. 117-169, §50262) and 2025 (Pub. L. 119-21, §50101) amendment history, and the residual 2022 provisions. Read at last review (2026-09-30). Tier 1, statute text and codifier's notes; the 1920 enactment is not reproduced there (A-claim).
3. 43 U.S.C. §1337, "Leases, easements, and rights-of-way on the outer Continental Shelf," with amendment and editorial notes, Cornell Legal Information Institute. law.cornell.edu/uscode/text/43/1337 — used for the offshore royalty range and its 2022 (§50261) and 2025 (§50102(d)) changes. Read at last review (2026-09-30). Tier 1 (A-claim).
4. Taxpayers for Common Sense, Royalty Rip-Off: How below-market federal oil and gas royalty rates cost taxpayers $25 billion over a decade, September 2026, 7 pp. taxpayer.net · PDF — used only as the proponent statement of the "rip-off" framing, for its own $25 billion arithmetic (p. 3, fns. 7–8), its summary of state rates (p. 3) and its bid comparison (p. 4). Read in full at last review (2026-09-30). Tier 2 advocacy organisation; figures are its own calculations, not independently verified (D-claim as to framing; B-claim as to arithmetic, which reconciles internally). The underlying ONRR sales data and the BLM and state documents it cites were not re-checked.
5. Congressional Budget Office, Options for Increasing Federal Income From Crude Oil and Natural Gas on Federal Lands, April 2016. cbo.gov/publication/51421 — used only for the findings as quoted and reported by GAO (pp. 16, 22): "small or even negligible" production reductions and $200 million in net federal revenue over ten years at 18.75 percent. The CBO report was not obtained directly at last review; nothing beyond GAO's account is attributed to it. Tier 1 via GAO (B-claim, second-hand).
6. Mason Gaffney, "Oil and Gas Leasing Policy: Alternatives for Alaska in 1977," report to the State of Alaska, February 1977 — wiki summary · PDF — used for the argument that a rent instrument takes more from flush and less from marginal deposits than a royalty does, and for the ad valorem charge alternative. Tier 1 on Gaffney's standing; a commissioned consulting report, design argument rather than econometric estimate (D-claim).
7. Jack Mintz & Duanjie Chen (2012), "Capturing Economic Rents from Resources through Royalties and Taxes," SPP Research Papers 5(30), University of Calgary — wiki summary · PDF — used for the point that the efficient royalty is one levied after costs are deducted (C-claim; peer-group public-finance paper, not a Georgist source).