Held By Production: How It Impacts Leases, Royalties, and Taxes

Oil and gas leases often contain a “Held By Production” (HBP) clause, allowing the lease to remain active as long as the well continues producing. This has significant financial implications for mineral rights owners, energy companies, and state governments relying on production-based revenue.

Understanding how HBP affects lease terms, royalty payments, and tax obligations is essential for anyone involved in oil and gas agreements.

Lease Continuation Criteria

For a lease to remain active under an HBP clause, production must meet legal and contractual standards. Extracting minimal amounts of oil or gas is not always sufficient. Courts and regulators typically require production in “paying quantities,” meaning revenue must exceed operating expenses over a reasonable period. This prevents operators from holding leases indefinitely with unprofitable output.

State laws define paying quantities differently. In Texas, courts assess whether a well generates profit over several months to a year. If a well consistently operates at a loss, the lease may be terminated. Oklahoma and Louisiana apply similar principles but also consider market conditions and production trends.

Temporary production halts can impact lease status. Many leases include a “cessation of production” clause, giving operators 60 to 90 days to restore output before the lease expires. Without such a clause, even brief disruptions could lead to termination. Some states provide statutory grace periods, though these vary widely.

Royalty Calculations

Royalty payments depend on the lease’s specified rate and how revenue is calculated. Most leases set a fixed percentage, typically between 12.5% and 25%, applied to either gross or net proceeds. Whether royalties are based on gross revenue before deductions or net revenue after expenses significantly impacts payouts.

Post-production costs—such as transportation, processing, and marketing—often become points of contention. Some leases prohibit these deductions, ensuring owners receive a percentage of the total sales price, while others allow them, reducing final payouts. Court rulings vary by state. Texas enforces lease terms as written, while West Virginia has restricted excessive deductions.

The pricing method for royalty calculations also affects payments. Some agreements use the “at the wellhead” method, valuing production before processing and transport, while others use an “arms-length sale” approach, based on the price received from third-party buyers. Market fluctuations, contract terms, and regional pricing differences all influence final royalty amounts.

Taxation Approach for Production Income

Revenue from producing wells is subject to multiple layers of taxation. Severance taxes, imposed by states on resource extraction, vary. Texas applies a 4.6% oil production tax and a 7.5% natural gas production tax, while North Dakota has a 5% production tax plus an additional extraction tax that fluctuates with market prices. Some states offer exemptions or reduced rates for low-producing or high-cost wells to encourage continued development.

Income tax obligations depend on how production revenue is categorized. Mineral rights owners typically report royalties as ordinary income, subject to federal and state taxes. The IRS allows percentage depletion deductions, letting qualifying taxpayers write off a portion of gross income from resource extraction—currently capped at 15% for oil and gas. This deduction helps offset declining well output over time, though high earners may face limitations under the alternative minimum tax (AMT).

Operators also pay ad valorem taxes, assessed annually on the value of reserves still in the ground. These property taxes, levied at the county level, fluctuate based on production history, remaining reserves, and commodity prices. Some jurisdictions reassess values annually, while others use multi-year averaging to smooth volatility, leading to cost differences between regions.