North Dakota is the third-largest producer of oil and fifth-largest producer of gas from federal lands. Over the last decade companies have produced $27.6 billion worth of oil and gas from federal lands in North Dakota. Yet because federal leasing terms were set at below-market rates, taxpayers did not receive the full value of those publicly owned resources and may be left to shoulder substantial future cleanup costs.
If federal leases in North Dakota had carried an 18.75 percent royalty rate instead of the 12.5 percent federal rate,¹ royalty collections would have been $1.8 billion higher over the last decade. Since roughly half of federal royalties are returned to producing states, nearly a billion dollars of that additional revenue would have flowed directly to North Dakota. That funding could have supported schools, hospitals, and other public infrastructure.
This is not a projection of future production. The oil was produced. The gas was sold. The only difference was how much of that value was returned to federal and North Dakota taxpayers instead of remaining with operators.
North Dakota is a Major Producer of Federal Oil and Gas
At the end of Fiscal Year (FY) 2025, 647,958 acres of federal land in North Dakota were leased for oil and gas development.² Out of this total acreage, 589,702 acres, or 91 percent of leased acreage, were actively producing oil or gas.
From 2016 through 2025 companies produced 394 million barrels of oil and 985 billion cubic feet of federal natural gas in North Dakota, representing 10 percent and 2.7 percent, respectively, of all production on federal land.³
If this production had been assessed at the market-based royalty rate of 18.75 percent, federal and North Dakota taxpayers would have received substantially more revenue. Outdated and below-market leasing terms not only limited much-needed revenue for taxpayers, but also allowed oil and gas operators to avoid fully covering the costs of reclaiming well sites after operations cease, potentially leaving taxpayers to cover cleanup costs.
The Federal Oil and Gas Leasing Program Fails American Taxpayers
Federal taxpayers own mineral resources across the United States, including a 700-million-acre onshore subsurface mineral estate. The Bureau of Land Management (BLM), within the Department of the Interior (DOI), oversees the subsurface mineral estate and is charged with managing the development of those resources. Yet, despite the substantial value of taxpayer-owned resources extracted from federal lands every year, taxpayers continue to receive pennies on the dollar because of outdated and below-market leasing terms.
DOI initially grants leases to the highest bidder in a competitive auction, provided the bid meets or exceeds the legal per-acre minimum, with the resulting revenue known as “bonus bid” revenue. If parcels at auction receive no bids, operators may be able to obtain leases after the sale noncompetitively. The federal government then charges rent to leaseholders for holding the lease before production begins. Once a lease begins producing oil or gas, the leaseholder pays a fixed percentage of the production value, known as a royalty.
For decades, the federal leasing system has operated under fiscal rates set decades ago, and in some cases more than a century ago. In 2022, Congress raised rental rates to $3 per acre for the first two years of the lease, $5 per acre for years three through eight, and no less than $15 per acre thereafter and raised the minimum bid to $10 per acre. Congress also raised the onshore royalty rate, which was established in 1920, from a minimum of 12.5 percent to 16.67 percent, eliminated noncompetitive leasing, and created a new expression-of-interest (EOI) fee for entities nominating federal land for competitive lease sales. However, updates to the royalty rates, the repeal of noncompetitive leasing, and the creation of an EOI fee were rescinded in 2025.⁴
Since July 4, 2025, taxpayers have lost roughly $1.7 billion in projected future royalty revenue from anticipated production on new leases compared to what they would have received under the temporarily raised 16.67% rate. Losses are even higher when compared to an 18.75% royalty, which is more in line with what is charged on state and private lands.
After production ends, oil and gas producers operating on federal land are required to plug their wells and clean up the surrounding sites. To guarantee that the cleanup of these potentially hazardous and environmentally harmful sites is paid for, producers must post a bond before they start drilling. If a company abandons its wells on a federal lease or goes bankrupt, the bond is forfeited and used to cover reclamation expenses.
BLM accepts two types of bonds: individual lease bonds with a minimum value of $150,000 and statewide bonds, covering all of an operator’s wells in a state, with a minimum value of $500,000. Higher bond values may be required if an operator has a history of violations, if BLM anticipates unusually high reclamation costs, or if other risk factors are present.
DOI is responsible for overseeing valuable taxpayer-owned mineral resources and ensuring taxpayers receive a fair return. Yet for decades, taxpayers have been shortchanged. The federal onshore oil and gas leasing system must be brought into the 21st century. Recently reduced royalty rates, the return of noncompetitive leasing, and threats to revert to outdated bonding standards risk failing to protect taxpayers or ensure a fair return from the sale of publicly owned resources.
Without permanent market-rate leasing terms and stronger oversight, taxpayers could lose billions more while facing growing long-term cleanup costs.
Taxpayers Lost $1.8 Billion in Revenue from Oil and Gas Production in North Dakota
For nearly a century, the federal onshore royalty rate was fixed at 12.5 percent for all federal lands, including those in North Dakota.⁵ Nearly all leases were issued at the statutory minimum rate. In 2022, Congress temporarily raised the rate to 16.67 percent for new leases but lowered it back to 12.5 percent in 2025.
Royalty revenue makes up the overwhelming share of federal oil and gas receipts. The Office of Natural Resources Revenue (ONRR) collected $3.1 billion in royalties over the last decade, 2016-2025, from oil and gas produced on federal lands sold in North Dakota.⁶ Because the revenue is split with producing states, every percentage point in the royalty rate affects how much funding reaches Bismarck and local communities.
The federal government charges a 12.5 percent royalty rate for production on federal land, significantly lower than what is charged on state lands in North Dakota and other major oil- and gas-producing states. If an 18.75 percent royalty rate had been applied to the $27.6 billion worth of oil and gas produced from federal lands in North Dakota over the last decade, federal and North Dakota taxpayers would have received an additional $1.8 billion in revenue.⁷
An 18.75 percent royalty rate is not unusual. Texas and New Mexico, two top oil and gas-producing states, charge royalties of up to 25 percent on state lands. North Dakota charges 16.67% to 18.75% on state lands. The record shows that competitive royalty rates do not halt or slow production. They determine how much of the value extracted from public land returns to the public.
Federal leasing over the last decade has made this plain. Production on federal lands continued, regardless of the royalty rate. Companies invested, drilled, and bid in competitive lease sales under both the higher 16.67 percent royalty rate and the lower 12.5 percent rate. In fact, average bids across the country were higher in 2023 and 2024 under the updated rate ($978 and $2,149 per acre respectively) than they had been during the preceding decade ($41 per acre from 2013-2022). The pace of development did not change. The public’s share of the profits did.
Increased productivity and overall production make the impact of royalty rates even clearer. Offering more land at discounted rates will not drive an increase in leasing or production. But lowering royalty rates will directly reduce how much taxpayers receive from that production.
Proposed Bond Minimums Risk Leaving Taxpayers Exposed to a $229 Million Shortfall
North Dakota faces significant cleanup liabilities from orphaned and inactive wells. When oil and gas operators drill on federal land, they are required to post bonds intended to ensure wells are plugged and sites restored once production ends. In practice, historic federal bonding requirements have often been insufficient to cover the full costs of reclamation, leaving taxpayers exposed to cleanup costs.
In 2024, federal bonding requirements were updated. But earlier this year, DOI proposed a return to outdated standards—$10,000 for an individual lease and $25,000 for all wells in a state—which would leave taxpayers exposed to billions in future reclamation liabilities from currently producing wells.
Prior to recent reforms, federal bonding rules for onshore wells lagged far behind real-world reclamation costs. Reclaiming wells is expensive. BLM reported an average cost of $71,000⁸ per well nationwide, although estimates can range from $20,000⁹ to $200,000¹⁰. The minimum bond was $10,000 for individual leases, $25,000 for statewide coverage, and $150,000 for nationwide coverage. Although DOI has the discretion to charge higher bond amounts, it has rarely exercised such discretion, and minimum bond amounts are often accepted. The Government Accountability Office reported that BLM held an average bond value of just $2,122 per well in 2018, covering only 3 percent of the estimated cost of plugging orphaned wells.¹¹
In 2023, BLM reported that there were 1,500 bonds covering approximately 110,000 existing wells nationwide.¹² Average coverage varied depending on bond type, with a high of $5,864 per well on statewide bonds and a low of just $671 per well on nationwide bonds.¹³ Across all bond types, existing wells had an average bond coverage of $3,873 per well, covering only 5 percent of estimated reclamation costs.
Weak bonding requirements do not eliminate cleanup costs. They simply increase the chances those costs are eventually borne by taxpayers. According to BLM, 3,408 oil and gas wells were producing on federal land in North Dakota at the end of FY2025.¹⁴ If outdated bonding requirements returned and BLM once again held average bond coverage of just $3,873 per well, the federal government would hold only $13.2 million in financial assurances for wells that may cost roughly $242 million to reclaim, leaving taxpayers exposed to approximately $229 million in potential future liabilities.¹⁵
Proposed federal bonding requirements—which would return financial assurance minimums to $10,000 for an individual lease and $25,000 for all wells in a state—would leave federal standards falling short of North Dakota’s state-level requirements. North Dakota requires operators to post a $50,000 per well bond¹⁶ or a $100,000 blanket bond, with limitations on the number of abandoned and other high-risk wells that can be covered. This means that wells on federal land, which may sit less than a mile from wells on nonfederal land and are not less expensive to reclaim, may have four to ten times less financial assurance.¹⁷
Insufficient bonding increases the likelihood that cleanup costs will fall on state and federal taxpayers. Communities that host drilling activity may ultimately face the long-term environmental and fiscal consequences when wells are left behind and the bills come due.
Noncompetitive Leasing Shortchanges Taxpayers
Not all leasing follows the competitive model. The noncompetitive leasing process, a loophole in federal policy, allows oil and gas companies to acquire leases that go unsold at auction for pennies per acre. According to BLM data, more than a third of the acreage currently leased for oil and gas development in North Dakota was leased noncompetitively—more than 90% of which was issued before 1987.¹⁸
Under the noncompetitive leasing process, parcels that receive no bids at auction are relisted the very next day and awarded to the first applicant willing to pay an administrative fee – a minimum of $75 regardless of acreage, set by BLM – and the first year’s rent. No bonus bid is required. This process, repealed by Congress in 2022, was reinstated in 2025 and enables companies to bypass market competition entirely.
Noncompetitive leases not only cost taxpayers lost bid revenue, but they are also less likely than competitive leases to ever enter production. Nationwide, only 1% of noncompetitive leases issued between FY2003 and FY2009 entered production within ten years.¹⁹ Nonproducing leases block other uses of federal land that could have greater value for taxpayers, including recreation, conservation, and the development of other mineral or energy resources.
The lack of bonus bids in the noncompetitive leasing process, alongside decreased royalty revenues from lack of oil and gas production, has cost taxpayers billions of dollars in potential revenue. According to a GAO analysis of 100,300 competitive and noncompetitive onshore leases, competitive leases generated nearly five times as much revenue as noncompetitive leases—$259.87 per acre compared to $52.80 per acre—between fiscal years 2003 and 2019.²⁰
Federal Leasing Decisions in North Dakota Directly Impact State and Federal Taxpayers
Taxpayers entrust the federal government with the management of federal lands and the valuable resources contained within them. Yet current policies fail to provide a fair return to taxpayers from oil and gas development on federal lands in North Dakota. Adding insult to injury, current policies leave taxpayers to shoulder long-term cleanup liabilities from orphaned wells.
For North Dakota, the stakes are immediate and measurable. Revenue from federal oil and gas production helps fund schools, infrastructure, and other public priorities. When that revenue falls short, the impact is felt in state and local budgets. And when cleanup costs are not fully covered by industry, the financial burden can shift directly onto taxpayers and communities.
North Dakota’s record shows why federal leasing policy must account for both production and taxpayer return. Congress and DOI should maintain market-rate royalties, preserve bonding requirements tied to likely reclamation costs, use competitive auctions to test the value of federal leases, and provide the public with clearer information about whether leased acreage ultimately produces. These safeguards would not prevent responsible development. They would ensure that taxpayers receive a fair return when publicly owned resources are developed and are not left paying to clean up afterward.
[1] From August 2022 until July 2025, new onshore leases were issued with a 16.67 percent royalty rate. These leases are unlikely to have entered production over the last decade
[2] Bureau of Land Management (BLM), “Fiscal Year 2025 Statistics,” accessed October 2026. https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/oil-and-gas-statistics
[3] Office of Natural Resources Revenue (ONRR), Query Data, accessed October 2026. https://onrr.gov/
[4] Changes to rental rates and the minimum bid apply to leases issued between August 2022 and August 2032. The higher royalty rate similarly would have applied to leases issued between August 2022 and August 2032 but was later lowered in July 2025.
[5] Nearly all leases were issued at the statutory minimum royalty rate of 12.5%.
[6] ONRR, “Calendar year federal sales data, 2013-2025”, accessed October 2026, https://revenuedata.onrr.gov/downloads/federal-sales/.
[7] Taxpayers for Common Sense (TCS) calculation applies an 18.75% royalty rate to the reported sales value, less allowances, as reported by ONRR.
[8] BLM, “Fluid Mineral Leases and Leasing Process,” Federal Register, July 25, 2023, https://www.federalregister.gov/documents/2023/07/24/2023-14287/fluid-mineral-leases-and-leasing-process#p-82.
[9] Government Accountability Office (GAO), “Oil and Gas: Bureau of Land Management Should Address Risks from Insufficient Bonds to Reclaim Wells,” September 2019, https://www.gao.gov/products/ gao-19-615.
[10] BLM, “Fluid Mineral Leases and Leasing Process,” Federal Register, July 25, 2023, https://www. federalregister.gov/documents/2023/07/24/2023-14287/fluid-mineral-leases-and-leasing-process#p-82.
[11] GAO, “Oil and Gas: Bureau of Land Management Should Address Risks from Insufficient Bonds to Reclaim Wells,” September 18, 2019, https://www.gao.gov/products/gao-19-615.
[12] BLM, “Fluid Mineral Leases and Leasing Process,” July 24, 2023, https://www.federalregister.gov/ documents/2023/07/24/2023-14287/fluid-mineral-leases-and-leasing-process.
[13] TCS calculation divides the average bond amount per bond type by the average number of wells per bond type, as reported in the BLM proposed “Fluid Mineral Leases and Leasing Process” rule.
[14] BLM, Oil and Gas Statistics, Fiscal Year 2025 Statistics, https://www.blm.gov/programs-energy and-minerals-oil-and-gas-oil-and-gas-statistics.
[15] TCS calculation multiplies the number of producing wells in the state (3,408) by the estimated cost of reclamation ($71,000) less the average bond value per well held by DOI in 2023 ($3,873.39).
[16] Wells drilled to a total depth of less than two thousand feet [609.6 meters] may be bonded in a lesser amount if approved by the director.
[17] On the low end, if an operator has many wells across the state, it is required to submit a $25,000 federal statewide bond or $100,000 blanket state bond, so North Dakota’s state bond coverage is four times the federal coverage. On the high end, if an operator has two wells on a lease, it is required to post a $10,000 federal lease bond which will cover both wells or a $100,000 blanket state bond (or 2 $50,0000 per well state bond), making North Dakota’s state bond coverage ten times the federal coverage.
[18] BLM, “BLM Natl MLRS Oil and Gas Leases,” accessed June 12, 2026. https://gbp-blm-egis.hub.arcgis.com/datasets/BLM-EGIS::blm-natl-mlrs-oil-and-gas-leases/
[19] GAO, “Oil and Gas: Onshore Competitive and Noncompetitive Lease Revenues,” November 2020, Page 16, https://www.gao.gov/assets/gao-21-138.pdf.
[20] GAO, “Oil and Gas: Onshore Competitive and Noncompetitive Lease Revenues,” November 2020, Page 11, https://www.gao.gov/assets/gao-21-138.pdf.
