Federal Oil and Gas Royalty Management Act — ONRR Revenue Collection

The Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA) establishes the legal framework for valuing, collecting, and auditing royalties owed to the federal government from oil and gas production on federal and Indian lands. The Office of Natural Resources Revenue (ONRR) within the Department of the Interior administers the program, collecting $10–14 billion annually from roughly 40,000 leases — making it one of the largest non-tax revenue sources for the federal government. For tribes and individual Indian landowners, ONRR-collected royalties represent a significant share of income from trust lands, making accurate measurement and payment a matter of both economics and federal trust responsibility.

Current Law (2026)

Legal Authority

• 30 U.S.C. § 1701 — Findings: Congress found that royalty and production measurement systems were inadequate and that the federal government was losing substantial revenue due to underpayment and reporting failures
• 30 U.S.C. § 1711 — Audit and investigation authority: grants ONRR broad authority to audit lessee records, examine production measurement equipment, and investigate royalty underpayments; states may receive delegated audit authority
• 30 U.S.C. § 1712 — Production measurement: requires lessees to accurately measure and report all production; establishes standards for measurement equipment and allowable tolerances
• 30 U.S.C. § 1714 — Enforcement: authorizes civil penalties up to $25,000/day for knowing or willful underpayment; criminal penalties for intentional fraud
• 30 U.S.C. § 1721 — Interest on underpayments: requires payment of interest on late or under-remitted royalties, calculated from the date payment was due
• 30 U.S.C. § 1732 — Delegated states: allows states to enter cooperative agreements to conduct their own royalty audits of federal leaseholders, subject to federal oversight
• 30 U.S.C. § 1751 — Indian lands: separate provisions govern royalties on tribal and allotted lands; reinforces federal trust responsibility to ensure accurate collection and disbursement

Implementing Regulations

The ONRR regulations implementing FOGRMA live in Title 30 of the CFR:

• 30 CFR Part 1206 — Product Valuation (122 sections across 9 subparts): the operational heart of royalty compliance, setting out exactly how lessees must calculate the value of oil, gas, coal, geothermal, and other minerals for royalty payment purposes. Product valuation is where most royalty disputes arise — the question of which price to use and which costs are deductible determines how much each producer owes quarterly.

  Subpart C — Federal Oil (20 sections): oil produced from federal onshore and OCS leases must be valued at the higher of arm's-length or non-arm's-length benchmarks:

  • § 1206.101 — Arm's-length contract valuation: value equals gross proceeds from the arm's-length sale less applicable transportation and processing allowances; if the sale is to an affiliate or the price appears below market, ONRR may disregard the contract price
  • § 1206.102 — Non-arm's-length valuation: for oil not sold under arm's-length contracts (commonly intracompany transfers), lessee must use ONRR-approved index prices — NYMEX West Texas Intermediate (WTI) monthly average or ANS spot price — adjusted for quality differentials and location; this prevents producers from undervaluing royalty obligations by booking production at below-market intracompany prices
  • § 1206.104 / § 1206.105 — ONRR audit authority: if ONRR determines a lessee's reported value is inconsistent with the regulation, ONRR may direct a different value or independently calculate the royalty value using any relevant information including production reports, contract prices, market data, and comparables from similar properties

  Subpart D — Federal Gas (25 sections): unprocessed gas valued at gross proceeds under arm's-length contracts; processed gas valued either at residue gas + plant product proceeds (plant settlement method) or alternatively at the index spot price for the appropriate gas market; transportation allowances are the most litigated deduction:

  • § 1206.141 — Unprocessed gas valuation: if sold arm's-length before processing, value = gross proceeds; for non-arm's-length, index price at the relevant trading hub (Henry Hub, Waha, El Paso, Opal) published in ONRR-approved price bulletins
  • § 1206.142 — Processed gas valuation: lessee must pay royalties on residue gas and gas plant products (propane, ethane, butane, NGLs) separately when gas is processed before sale; lessee may elect alternative valuation by using index prices rather than actual plant proceeds
  • §§ 1206.152–1206.155 — Transportation allowances: ONRR allows deduction of reasonable, actual transport costs from lease to point off-lease; arm's-length transport contracts allow the actual cost as deduction; non-arm's-length or no-contract situations require cost allocation using ONRR's methodology (rate of return on investment × depreciated plant investment + operating costs)

  Subpart B — Indian Oil (16 sections): Indian oil valuation uses a stricter "major portion" pricing floor — the value for royalty is the higher of arm's-length gross proceeds or the IBMP (Indian Beneficial Major Portion) value, calculated quarterly by ONRR as the price paid for the major portion (more than 50% by volume) of like-quality production from the same field; this prevents lessees from arranging below-market sales that erode tribal royalty income below what the market would support.

  Subpart F — Federal Coal (15 sections): surface-mined coal valued at gross proceeds under arm's-length contracts; non-arm's-length coal valued at arm's-length prices for like-quality coal in the region; coal transported beyond a reasonable distance may require a two-contract valuation comparing mine-mouth value to delivered value.

  Subpart H — Geothermal Resources (17 sections): electricity-generating geothermal royalties are based on the value of electricity at the plant gate; direct-use geothermal (heating, aquaculture, resort applications) royalty is based on the value of the thermal energy delivered.

  The arm's-length vs. non-arm's-length distinction runs through all Part 1206 subparts and is the central compliance question: producers who sell to affiliates or subsidiaries at intracompany transfer prices must use index or market-based benchmarks rather than their internal accounting prices, because ONRR treats below-market intracompany transfers as royalty evasion. Audit lookback is 7 years under Part 1207 — operators must retain all records supporting valuation determinations for that period.

• 30 CFR Part 1219 — Distribution and Disbursement of Royalties, Rentals, and Bonuses: the payment-out side of the royalty cycle — how ONRR transmits collected royalty revenues to states, Indian tribes, and Indian allottees after collection:

  • § 1219.100 — State payments: ONRR pays each state its share of mineral leasing revenues no later than the last business day of the month in which the U.S. Treasury receives the funds; for most onshore federal leases, states receive 50% of royalties collected from leases within their borders — a significant revenue stream for Wyoming ($1.5B/yr), New Mexico ($1.2B/yr), Colorado, Montana, and other energy-producing states; late payments accrue interest, with ONRR paying the state its interest share subject to appropriations
  • § 1219.103 — Indian account transfers: royalties collected from Indian leases are transferred by ONRR to the appropriate BIA-managed Indian accounts; BIA then disburses to tribal accounts or individual Indian Money (IIM) accounts; 100% of Indian land royalties goes to tribes and allottees (not split with the state), reflecting the federal trust responsibility
  • § 1219.104 — Explanation of Payments: ONRR provides monthly Explanation of Payment (EOP) reports to states and BIA, breaking down collections by lease, commodity, and time period; the EOPs are the primary reconciliation tool for state auditors and tribal financial managers verifying that payments match lease-level production reports

• 30 CFR Part 1218 — Collection of Royalties, Rentals, Bonuses, and Other Monies Due the Federal Government: the payment mechanics for all federal and Indian mineral lease revenues — establishing due dates, payment methods, interest rules, and how collections are transmitted to states and tribes:

  • § 1218.100 — Royalty and rental payments: lessees must pay all royalties and rentals as specified in the lease on or before the due date; payments are made to ONRR via the Minerals Revenue Management system; the minimum payment threshold is $10 (amounts less than $10 accrue but are not separately due until the threshold is crossed); the lessee remains obligated for all royalties even if the lessee did not receive payment from the purchaser
  • § 1218.102 — Late payment and underpayment charges: any failure to make timely or proper payment of royalties or rentals triggers interest from the due date at a rate determined by reference to the underpayment rate under 26 U.S.C. § 6621 (the federal short-term tax underpayment rate plus 3 percentage points); interest accrues daily on the unpaid balance; ONRR may also require escrow deposits from lessees with a history of late payments
  • § 1218.103 — Payments to states: ONRR must pay each state its share of federal mineral lease revenues no later than the last business day of the month following the month of collection; for most onshore federal leases, states receive 50% of royalties collected within their borders; the 50% state share is a critical revenue stream for Wyoming, New Mexico, Colorado, Montana, and North Dakota — and a political flashpoint when ONRR adjusts royalty rates or valuation rules
  • § 1218.104 — State exemption from interest and penalties: states are exempt from late payment interest charges if ONRR fails to timely distribute state shares — the interest obligation runs against the federal government (ONRR must pay interest on late state disbursements), not against states for delays in collecting their share from producers
  • § 1218.150 — OCS royalties: royalties on outer continental shelf (offshore) production are paid at the rate specified in the lease; ONRR collects OCS royalties separately from onshore royalties with different due dates and payment allocation rules (OCS revenues are shared with adjacent coastal states and deposited in the Land and Water Conservation Fund)
  • § 1218.155 — Method of payment: all royalty payments of $25 or more must be made by electronic funds transfer (EFT) to the ONRR lockbox at a designated federal reserve bank; paper checks are only accepted for payments below $25; EFT payment must reach ONRR's lockbox by the due date — a transfer initiated on the due date but received the next business day is a late payment subject to interest
  • § 1218.200 — Indian lease payments: lessees on Indian tribal and allotted lands must pay royalties, rentals, and deferred bonuses as specified in the Indian mineral lease; payment goes to ONRR; ONRR transfers collected Indian mineral funds to the appropriate BIA-managed tribal or Individual Indian Money (IIM) accounts; 100% of Indian lease revenues flows to tribes and allottees (no state share)

  The Part 1218 payment framework is the settlement infrastructure for the entire federal and Indian mineral leasing system. The EFT requirement, lockbox system, and state disbursement deadlines create a cash flow cycle that moves billions of dollars monthly: producers pay ONRR; ONRR splits the funds and distributes to the U.S. Treasury, state governments, tribal accounts, and the Land and Water Conservation Fund, all within the same calendar month. Any disruption to this pipeline — a rulemaking challenge, a royalty rate change, or a major lessee insolvency — affects state budgets, tribal program funding, and the federal deficit simultaneously.

• 30 CFR Part 1241 — Penalties: the ONRR civil penalty framework for royalty underpayments and reporting violations:

  • Notice of Noncompliance (NONC): issued when a lessee or operator fails to comply with FOGRMA reporting requirements, a lease term, or an ONRR order; the NONC is a warning notice with a deadline to correct; if corrected in time, no penalty is assessed
  • Failure to Correct Civil Penalty (FCCP): if the lessee does not correct within the NONC deadline, ONRR issues an FCCP at $500 per day per violation (civil penalty for failure to correct after notice); penalties accrue even if the lessee requests a hearing
  • Knowing or Willful Underpayment / Failure to Disclose (ILCP — Immediate Liability Civil Penalty): ONRR may issue an ILCP of up to $25,000 per day per violation (implementing 30 U.S.C. § 1719) for knowing or willful underpayment of royalties or knowing failure to make required production reports; ILCPs do not require a prior NONC — the violation's willful nature triggers immediate penalty liability
  • § 1241.10 — Judicial review: after exhausting the Interior Board of Land Appeals (IBLA) administrative process, lessees may seek judicial review in Federal District Court within 30 days of the IBLA decision; the penalty continues to accrue during judicial review unless the court issues a stay

• 30 CFR Parts 1227 and 1229 + 43 CFR Part 3190 — State and Tribal Delegation of Royalty Oversight Functions: FOGRMA § 205 (30 U.S.C. § 1735) authorizes the Secretary to delegate specific royalty management functions to states and Indian tribes that have the legal authority and resources to perform them effectively. Two overlapping ONRR regulatory frameworks govern these delegations:

  30 CFR Part 1227 (the current ONRR delegation rule) and 30 CFR Part 1229 (an older predecessor framework) both cover delegation of royalty management functions — auditing, production accountability, compliance monitoring, and collection activities — from ONRR to states. 43 CFR Part 3190 covers delegation of BLM's oil and gas inspection functions (field-level site inspections, production measurement verification) to states and tribes. Together, these three Parts form the cooperative federalism framework for federal royalty oversight.

  Key provisions:

  • Delegable functions (Part 1227, § 1227.101): ONRR may delegate royalty audit and compliance activities, collection of royalties, civil penalties and other amounts due, and production accountability functions; Indian lands delegations require separate written tribal consent — states cannot conduct delegated activities on tribal lands without the affected tribe's permission
  • Non-delegable functions (§ 1227.102): ONRR retains exclusive authority over certain functions regardless of delegation — setting royalty rates, establishing valuation policy, issuing regulations, making final royalty payment determinations on appeals, and conducting criminal investigations; delegation is always of implementation functions, not rulemaking or appellate authority
  • Delegation proposal requirements (§ 1227.103): a state seeking delegation must submit a proposal identifying the specific functions it wants, the legal authority under state law to perform them, its staffing and organizational capacity, proposed standards and procedures, and funding sources; ONRR holds a public hearing on the proposal before acting
  • Delegation agreements (§ 1227.110): approved delegations run for 3-year renewable terms; performance standards must be met for renewal; ONRR may revoke a delegation if the state fails to maintain an effective program
  • BLM inspection delegations (Part 3190): states or tribes with federal or Indian oil/gas production may receive delegation of BLM's site inspection authority — sending state or tribal inspectors to check wellheads, meters, site security, and production handling instead of BLM inspectors; tribal inspectors must be BLM-certified before conducting independent inspections on Indian leases (§ 3192.14)
  • Civil penalty sharing (§ 3190.3): 50% of any civil penalty ONRR collects as a result of activities carried out by a state under delegation is paid to that state — creating a financial incentive for states to pursue active enforcement programs
  • Proprietary data protection (§ 3190.1): states and tribes that receive production data, financial records, and other proprietary operator information under delegation agreements are bound by strict confidentiality rules — the same protections that apply to ONRR staff apply to state delegatees; improper disclosure subjects the state agency to civil liability

  In practice, Wyoming, Colorado, and New Mexico operate the most active delegated royalty programs. Wyoming's Oil and Gas Conservation Commission (WOGCC) and New Mexico's Oil Conservation Division (OCD) conduct significant royalty audit activity under their delegation agreements. The financial stakes are high: a state that audits actively and finds underpayments keeps 50% of the recovered penalties, making delegation agreements a net revenue generator for states with large federal leasing programs. For operators, a delegated state audit carries the same compliance force as an ONRR direct audit — both can result in back royalty assessments with interest and penalties.

• 30 CFR Part 1204 — Alternatives for Marginal Properties (22 sections — ONRR's relief program for oil and gas leases where standard royalty reporting requirements impose compliance costs disproportionate to the production value of marginal properties — low-output wells where production economics are fragile and conventional royalty accounting creates disproportionate administrative burden):

  • § 1204.1 — Purpose: allows lessees or designees of Federal onshore or Outer Continental Shelf (OCS) oil and gas leases to obtain prepayment or accounting and auditing relief for production from qualifying marginal properties; the program recognizes that standard ONRR reporting requirements — designed for high-volume commercial wells — can cost more to administer than the royalties at stake for marginally producing wells
  • § 1204.4 — Qualifying marginal property: a property qualifies if its combined equivalent production (BOE — barrels of oil equivalent, converting gas at 6 MCF per BOE) during the base period (July 1 through June 30 immediately preceding the calendar year) was no more than 15 BOE per day per producing well; properties with higher production don't qualify even if prices are depressed; Indian leases are excluded from Part 1204 regardless of production levels
  • § 1204.10 — Prepayment option: a qualifying lessee may make a prepayment — a single annual royalty payment at the start of the calendar year rather than monthly payments; the prepayment is based on the estimated annual production from the marginal property; at year end, the lessee reconciles actual vs. estimated production and either receives credit or makes a true-up payment; prepayment eliminates 11 of 12 monthly reporting cycles for that property, dramatically reducing administrative burden for small operators
  • § 1204.20 — Accounting and auditing relief (Subpart C): ONRR may grant accounting and auditing relief — adjusting or waiving specific reporting requirements for marginal properties on a case-by-case basis; relief may include simplified valuation methods, reduced audit frequency, or alternative production measurement approaches; applications for relief are submitted to ONRR with documentation of the property's marginal production status and the specific relief requested
  • § 1204.30 — Recordkeeping: even under the prepayment or relief options, lessees must maintain production records sufficient to verify compliance; records must be retained for 7 years; ONRR retains full audit rights — the relief program reduces administrative burden prospectively but does not immunize past production from audit

  The marginal property relief program reflects ONRR's recognition that strict uniform reporting requirements can drive marginal wells into premature abandonment — if compliance costs exceed the royalty value, operators have an economic incentive to plug and abandon wells that might otherwise continue producing for years. By reducing administrative burden for low-output properties, Part 1204 extends the productive life of marginal federal and OCS leases while preserving the royalty revenue stream, however modest. Recent rulemakings: most recently amended at 78 FR 30200 (May 2013) and 69 FR 55088 (Sep. 2004).

• 30 CFR Part 1208 — Sale of Federal Royalty Oil (17 sections, implementing 30 U.S.C. § 181): governs ONRR taking royalties in kind as crude oil rather than cash, then selling it to eligible small refiners. The Secretary may take oil in kind when market conditions favor directing crude supply to independent refiners unable to compete with major integrated companies:

  • § 1208.4: Secretary evaluates market conditions and decides whether taking royalties in kind serves public interest; operators notified at least 45 days in advance by certified mail
  • § 1208.5: ONRR issues public "Notice of Availability of Royalty Oil" specifying volume, delivery points, pricing formula, application period, and eligibility criteria
  • §§ 1208.6–1208.7: eligible refiners submit Form MMS-4070; receive an allotment — a proportional share based on each applicant's refinery capacity relative to all eligible applicants
  • § 1208.11: before execution, purchaser must furnish surety instrument equal to estimated value of royalty oil to be delivered — protecting against default
  • § 1208.15: ONRR may audit accounts of lessees, operators, and purchasers annually
  • § 1208.17: Secretary may suspend in-kind sales for national emergencies upon DoD/DOE recommendation and Presidential approval Part 1208 is largely dormant — most royalties are collected in cash. The authority remains in place from the post-1973 energy crisis era. Recent rulemakings: 88 FR 53793 (Aug. 2023).

• 30 CFR Part 1220 — Accounting for Net Profit Share Leases on the OCS (17 sections, implementing 43 U.S.C. § 1337): accounting framework for Net Profit Share Leases (NPSLs) — OCS leases where the government takes a profit share after the lessee recovers its capital investment, rather than a fixed royalty rate. NPSLs were an experimental OCS bidding system from the 1970s-1980s; no new NPSLs have been issued in decades but legacy tracts remain producing:

  • § 1220.010 — NPSL capital account: lessee maintains a capital account debited with allowable costs and credited with production revenues; the capital recovery period ends when the account flips from debit to credit balance — government profit share payments begin only then
  • § 1220.011 — Allowable costs: includes lease rentals, drilling, platform construction, operating costs, and transportation; bonus payments, income taxes, and depreciation are unallowable
  • § 1220.012 — Overhead allowance: 4% of allowable costs during capital recovery period; drops to 3% in the production phase
  • § 1220.020 — Capital recovery allowance: risk premium — lessee earns a return on unamortized capital (analogous to interest), compensating for the risk that the lease may not recover costs
  • §§ 1220.021–1220.022 — Net profit share payment: when cumulative credits exceed debits (plus capital recovery allowance), the positive balance is the net profit share base; payment = base × the net profit share rate in the lease Recent rulemakings: 75 FR 61087 (Oct. 2010) — capital recovery calculation clarifications.

• 30 CFR Part 1243 — Suspensions Pending Appeal and Bonding (17 sections, implementing 30 U.S.C. § 181): governs how lessees may stay compliance with ONRR orders while appealing to the Interior Board of Land Appeals — and what bond or surety they must post to protect the government's interest:

  • § 1243.1: applies to lessees and order recipients who have appealed under 30 U.S.C. § 1724; explains how to suspend compliance without triggering immediate enforcement
  • § 1243.2: covers all federal mineral leases onshore and OCS, and federally-administered mineral leases on Indian tribal and allotted lands
  • § 1243.10: if a lessee posted bond and loses the appeal, ONRR collects against the bond immediately — even if the lessee seeks further judicial review
  • §§ 1243.100–1243.101: surety instruments must meet ONRR form requirements; bond-approving officer determines adequate amount to guarantee payment of assessed royalties, interest, and penalties; surety amount decisions are final and not appealable
  • § 1243.200 — Financial solvency alternative: large lessees may demonstrate solvency (audited balance sheet + up to 3 years of tax returns) instead of posting bond; solvency determination by bond-approving officer is also final and not appealable The framework balances government interest in prompt royalty collection (especially for tribal lessors depending on royalty income) against lessees' interest in not paying disputed assessments before an appeal is decided.

How It Works

Operators producing oil or gas from federal or Indian leases must report production volumes and values monthly to ONRR and pay royalties on the gross proceeds from sales, minus certain allowable deductions for transportation and processing costs. The valuation methodology is where most disputes arise: ONRR requires royalties to be paid on market value at the point of production (the wellhead or a nearby sales point), and operators frequently argue that transportation and processing costs should be deducted from the royalty base. ONRR has issued detailed valuation rules specifying which costs are deductible and how to calculate them, but litigation over these rules is common. Royalties are due on the last day of the month following production — operators who pay late owe interest at a prescribed rate from the due date.

ONRR audits a portion of leases each year, using statistical sampling and risk-based targeting to focus resources on the most complex or high-value producers. Audits can look back 7 years, and the agency has collected hundreds of millions of dollars in back royalties and penalties from major producers over the program's history. States with large federal leasing programs — Wyoming, New Mexico, Colorado, Montana, North Dakota — can enter cooperative agreements to conduct their own royalty audits under ONRR oversight; the state keeps a share of any recoveries. The DOI Inspector General also audits ONRR's own administration of the program.

For Indian lands, ONRR's role takes on additional dimensions under the federal trust responsibility. One hundred percent of royalties collected from tribal and allotted lands goes directly to the tribe or individual Indian landowner, rather than being shared with the state. Errors in measurement or valuation on Indian lands directly harm beneficiaries who may depend on these payments as their primary income. ONRR maintains separate systems for Indian land accounting and has faced criticism — including major litigation and a cobell-era class action context — over the accuracy of Indian trust funds generally.

Key Numbers / Thresholds

• $10–14 billion collected annually (largest non-tax revenue source for the federal government)
• 16.67% onshore royalty rate on federal lands (raised from 12.5% by the Inflation Reduction Act in 2022 — first increase in 100 years)
• 18.75% royalty rate on offshore leases (Outer Continental Shelf)
• 50% of most onshore federal royalties distributed to the state of production
• 100% of Indian land royalties distributed to tribes/individual allottees
• 7-year audit lookback period for royalty underpayments
• Up to $25,000 per day civil penalty for knowing or willful underpayment
• ~40,000 active leases on federal and Indian lands

How It Affects You

If you're an oil and gas producer operating on federal or Indian lands: FOGRMA's reporting and audit regime applies to every barrel and mcf you produce on federal leases. You must file monthly production and royalty reports with ONRR, value your production under ONRR's valuation rules (not necessarily the price you actually received, if you sell to affiliates), and retain records for a 7-year audit lookback period. A knowing or willful underpayment can generate civil penalties up to $25,000 per day. The IRA-mandated increase from 12.5% to 16.67% onshore royalties took effect in August 2022 for new leases — model the cost difference if you are bidding on new federal acreage versus holding legacy 12.5% leases.

If you're in state government in a royalty-producing state: Wyoming, New Mexico, Colorado, Utah, Montana, and other western states receive 50% of federal onshore royalty collections from production within their borders — a revenue stream in the hundreds of millions to billions annually. ONRR's valuation rules, audit outcomes, and any changes to royalty rates directly affect state budget projections. When ONRR proposes a rule change — like the 2025 natural gas royalty valuation proposal — your state mineral revenue office should be in the comment process. ONRR also has state audit delegation agreements that let state agencies conduct royalty audits on behalf of the federal government and share in recovered underpayments.

If you're a tribal nation or individual Indian allottee: 100% of royalties from trust land oil and gas production flows to you — not split with the state. ONRR manages the collection and payment under its Indian trust responsibility, which courts have held to a higher fiduciary standard than its management of federal (non-Indian) royalties. If your tribe or allotment has active oil and gas production, ONRR's Trust Reporting and Production system (TRAPS) and periodic ONRR audits directly affect what you receive. Tribal nations may also negotiate alternative royalty arrangements through Tribal Energy Development Organization agreements under ITEDSA.

Recent Developments

The Inflation Reduction Act (2022) made the most significant structural change to federal royalty rates in a century, raising the onshore rate from 12.5% — set by the Mineral Leasing Act of 1920 — to 16.67%. The Act also raised minimum bid requirements for oil and gas lease sales, increased bonding requirements for offshore leases, and directed ONRR to update its royalty valuation rules for natural gas. Environmental groups and some economists had argued for years that the 12.5% rate was too low relative to state and private royalty norms (many state programs require 18.75% or higher), and the IRA change partially closed that gap.

In 2025–2026, ONRR faced competing pressures: the Trump administration's push to maximize domestic energy production created interest in lowering regulatory friction for producers, while watchdog groups continued to press for stricter measurement standards and more aggressive auditing of methane venting and flaring (which affects royalty calculations). A 2025 ONRR proposed rule on natural gas royalty valuation — addressing how to calculate royalties when gas is sold below market value to affiliated pipelines — drew significant industry pushback. ONRR also began implementing IRA-mandated changes to offshore royalty rates for leases issued after August 2022.

Related Topics

• Mineral Leasing Act — Oil, Gas & Coal on Federal Lands
• Federal Mining Law & Mineral Resources
• Outer Continental Shelf Lands Act & Offshore Energy
• Inflation Reduction Act — Climate, Clean Energy & Health Provisions
• Geothermal Steam Act — Federal Geothermal Energy Leasing