Post-production deductions refer to costs incurred after the extraction of oil or gas. These costs include gathering, transportation, processing, compression, dehydration and marketing. Typically, these expenses can be deducted from the royalty payments owed to mineral and royalty owners unless the lease specifically prohibits such deductions.

Historically, lessees in North Dakota and other states have often deducted these costs, especially when leases contain ambiguous language about royalties, such as “market value at the well.” This practice has resulted in significant revenue losses for royalty owners and has led to legal disputes over the fairness and legality of these deductions.

In 2019, the North Dakota Supreme Court issued a landmark ruling in the case of Newfield Exploration Co. v. State of North Dakota. This case involved the sale of natural gas, where the lessee had been deducting processing and transportation costs prior to calculating royalty payments.

The Court ruled that, under the state’s standard lease, which states that royalties are based on "gross proceeds" and the "full value of all consideration", post-production deductions are not permitted. This decision clarified that when a lease requires royalties to be paid on gross proceeds, no costs can be deducted from the calculation between the wellhead and the point of sale.

For state-owned minerals, these ruling safeguards royalty payments from reductions due to downstream costs. It represents a significant shift in favor of royalty owners, particularly when strong language supports their claims.

The Newfield decision applies to state leases, but private leases are still governed by their specific terms. In the 2021 case Blasi v. Bruin E&P Partners, the Court upheld deductions based on a lease that stated gas was to be valued "free of cost into the pipeline." The Court determined that this language permitted deductions for costs incurred beyond the pipeline connection point.

This situation underscores the importance for private mineral owners in North Dakota to carefully negotiate and review their lease agreements. A lease that does not explicitly prohibit deductions is still likely to allow them, even after the Newfield decision.

In 2017 and 2023, the North Dakota Legislature examined the issue of protections for private royalty owners but ultimately decided not to implement new measures. While acknowledging the growing concerns, lawmakers chose to allow existing contract law and court rulings to remain in effect.

However, royalty owner groups are advocating several key changes:

The North Dakota Industrial Commission and other agencies now encourage clearer reporting and audits but have not established strict limits on deductions.

Key Takeaways for Royalty Owners:

Post-production deductions are not going away, but North Dakota royalty owners are more empowered than ever to contest unfair practices. The Newfield decision laid a legal foundation, and future advancements will rely on education, advocacy, and stronger lease terms. With this current momentum legislators are now revisiting where they left off to address the issue of post-production deductions.

Below is a comparative overview of how North Dakota, Texas, Oklahoma and Wyoming handle post-production deductions in oil and gas royalty structures. Since much depends on lease language and judicial interpretation, this comparison highlights statutory or case law defaults, major shifts, and key cautionary points.

According to the North Dakota Century Code § 38-08-06.3, anyone making royalty payments to a royalty owner is required to provide an information statement that details any deductions made (including transportation, processing, compression, and administrative costs) along with the purpose for each deduction. Failure to comply with this requirement is classified as a Class B misdemeanor.

The North Dakota Administrative Code (NDAC) Chapter 43-02-06 implements these reporting and transparency requirements.

Additionally, the ND Legislative Committee Memorandum on Postproduction Deductions includes a model royalty clause that states leases may specify:

“…provided, however, that there shall be no deductions from the value of the lessor’s royalty for any required processing, transportation, or other expenses related to marketing such gas.”

Even though this clause exists, many royalty owners in lease negotiations will find it difficult to come to an agreement with the lessee.

Texas has historically recognized that royalties tied to "market value at the well" allow for the deduction of reasonable post-production costs. This approach, often referred to as the net-back or work-back method, is used to value gas at the well.

However, Texas also accepts leases based on "proceeds" or "amount realized," where royalties are determined by the price received from downstream sales. Generally, these leases prohibit deductions unless specifically permitted.

The Texas Prompt Payment Act (Texas Natural Resources Code §§ 91.401–91.406) regulates the timely payment of royalties and disclosure practices, although it does not directly address deductions.

In Texas, careful lease drafting is essential. A “gross royalty” or "free of cost" clause may block deductions; otherwise, courts may permit them under "at the well" valuations. The presence of a downstream "amount realized/proceeds" clause is typically interpreted as barring deductions.

Fuel gas used for processing, compression, or treatment can be deducted under "at the well" leases. Even in cases with "free of cost" clauses, Texas courts will assess the context of the contract and determine whether the clause is sufficiently broad to prohibit downstream costs.

Some recent Texas opinions have determined that "add-back" of downstream costs, which third-party purchasers have deducted, may be required. As a result, the royalties owed may exceed the lessee's net receipt.

Under Oklahoma law regarding oil and gas, there is an implied duty for lessees to market production reasonably. Many Oklahoma leases do not allow for deductions of gathering, transportation, compression, dehydration, or blending costs if these costs are necessary to make the product marketable, unless the lease explicitly permits such deductions.

Additionally, it may be possible to recover improperly deducted costs through contract or tort claims.

Many attorneys representing mineral owners in Oklahoma argue that deductions for downstream costs are not permissible unless explicitly stated in the lease. However, some leases do contain clauses that allow deductions. The enforceability of these clauses often depends on interpretation and the context of the contract.

Oklahoma law tends to favor lessors (royalty owners) by limiting the lessee's ability to pass all downstream costs onto royalty owners. However, this protection is not absolute; if a lease explicitly allows for deductions, the lessee may be able to enforce them.

Wyoming has historically been more permissive regarding the allocation of gathering or pipeline costs, particularly under traditional leases and valuation methods. For example, in the article “Royalty Dethroned: Wyoming’s Approach to Gathering Costs,” by Rickey Turner suggests that Wyoming’s courts have allowed the deduction of certain downstream costs based on contract language.

In Wyoming, the interpretation of the royalty clause often governs legal decisions. Courts typically examine where the value is intended to be determined, whether at the wellhead or the point of sale and whether downstream costs are the responsibility of the lessee or lessor.

Under Wyoming law and case precedent, a lease that specifies royalties to be delivered “into the pipeline” or “free of cost” may limit or prohibit deductions when clearly drafted. However, ambiguous leases or those that do not define valuation or cost allocation may allow for the deduction of downstream processing, transportation, or gathering costs.

In Wyoming, lessors should ensure that royalty clauses explicitly specify the valuation point and treatment of downstream costs. The default Wyoming case law may not favor royalty owners if lease language is vague. Additionally, Wyoming provides less statutory protection for royalty owners compared to North Dakota’s reporting statute, making contract terms and court interpretations particularly significant.

Post-production deductions are an issue found in every state, not just North Dakota, as each state has attempted to tackle this matter through specific laws.

A royalty owner depends on a producer, and the relationship is reciprocal. The key question is: when does a royalty owner qualify as an operator if they equally share the costs of marketing products derived from their assets?

I believe that most royalty owners would be in favor of a reasonable cost-sharing approach; however, they probably wouldn’t agree to a blanket equal sharing arrangement. If we can reach a consensus on this point, implementing a cap on the deductions imposed on royalty owners may be the most reasonable solution to this escalating issue. This approach would also help prevent regulators from disrupting established precedents in contract law.

Article written by Russ Murphy, CMM, CTFA, Senior Wealth Advisor and Mineral & Estate Specialist.