Horizontal Drilling and the Forensic Audit Gap

The horizontal drilling revolution transformed the economics of American energy production. It also quietly transformed the economics of royalty underpayment — for reasons that are rarely discussed outside of operator revenue accounting departments.

Every forensic audit issue that existed before horizontal drilling still exists. Improper post-production deductions, below-market affiliate pricing, understated production volumes, silent decimal changes on division orders — none of these problems were invented by the shale era. What horizontal drilling did was change the scale: larger units, far higher production volumes, more complex allocation methodologies, and a dramatically higher dollar value attached to every percentage point of error.

The Scale Problem: Why the Math Changes

Consider a mineral owner with 10 net mineral acres (NMA) in an active Oklahoma county. Under traditional vertical well development, that 10 NMA would sit in a 160-acre spacing unit. Under horizontal development in the same county, that same 10 NMA is now part of a 1,280-acre unit. The NRI is smaller — but the well produces dramatically more.

Assumptions: $50/BOE equivalent, 1/5th royalty. Estimates for illustration only.

The owner’s decimal is much smaller in the horizontal scenario — but the dollar amounts are far larger. A 10% underpayment that cost $37.50 per month on a vertical well costs $750 per month on a high-volume horizontal. Over a 24-month lookback period, that single error represents roughly $18,000 in recoverable royalties from one well. A portfolio with five such wells and multiple operators compounds quickly.

Seven Specific Audit Issues That Horizontal Drilling Amplifies

The Cross-Unit Allocation Problem in Detail

Of all the issues horizontal drilling introduces, wellbore allocation across spacing units is the least visible and the hardest to challenge. When a horizontal lateral — today commonly 2–3 miles, and in some formations exceeding 5 miles — crosses multiple spacing units, the operator must decide what share of production to assign to each unit. Common allocation methods include:

Emerging Technologies: New Revenue Streams, New Audit Frontiers

The forensic audit framework extends to technologies that are moving from concept to commercial reality in the same basins where mineral owners hold traditional oil and gas interests.

Carbon Capture and Subsurface Storage (CCUS)

Operators and industrial companies are actively acquiring pore-space rights for CO₂ sequestration beneath producing formations. In several states, courts and legislatures have not settled whether those subsurface storage rights belong to the surface owner or the mineral owner. For families holding inherited interests, an existing oil and gas lease executed before CCUS was commercially viable may or may not convey storage rights — and the answer turns on the specific lease language and applicable state law. This is a property rights question, but it begins with the same lease-document review that forms the foundation of every forensic audit.

Underground Natural Gas Storage

Operators and pipeline companies are converting depleted reservoirs and salt caverns into natural gas storage facilities. Like CCUS, this creates a new commercial use for the subsurface pore space beneath a mineral owner’s acreage. The property rights question — whether the mineral owner must be compensated for storage use, and whether that compensation is royalty-bearing — is litigated differently in each state. An existing oil and gas lease that says nothing about storage was almost certainly drafted before storage became a significant revenue use.

Blue Hydrogen from Natural Gas

“Blue hydrogen” is produced by reforming natural gas with CO₂ capture to offset the emissions. Operators are positioning existing natural gas production as a hydrogen feedstock. The question for mineral owners is whether the royalty is calculated on the value of the natural gas at the wellhead or on the derived hydrogen product — and whether the conversion and processing costs are deductible under the existing lease. As with NGL processing, the answer depends on lease-specific language and state law, and the dollar difference can be substantial.

Geothermal Development

Operators and independent developers are now targeting geothermal energy in basins where the geologic heat gradient supports commercial production. Whether a geothermal developer needs a mineral owner’s consent, whether an existing oil and gas lease covers geothermal activity, and whether depth severance clauses limit geothermal rights are open questions in most producing states. Oklahoma and Texas have both seen legislation and litigation addressing these questions in the last five years.

Helium Extraction from Natural Gas Streams

Helium is present at commercial concentrations in some natural gas fields, particularly in the Texas Panhandle, Kansas, and Colorado. It is extracted during natural gas processing. Whether helium is covered by an oil and gas lease — and therefore whether the royalty owner is entitled to a share of helium revenue — turns on how broadly the lease defines “minerals” or “gaseous substances.” Most legacy leases were silent on helium entirely; operators have routinely treated helium revenue as their own.

Lithium and Critical Minerals from Produced Water

Produced water from oil and gas operations — particularly in the Permian, Anadarko, and Smackover basins — contains lithium, bromine, strontium, and other critical minerals at potentially commercial concentrations. Operators are beginning to extract these materials as a byproduct revenue stream. Whether that revenue is a royalty-bearing production stream, a separate mineral right, or operator income with no royalty obligation is unresolved in most states. Arkansas has begun addressing bromine and lithium extraction rights specifically; most other states have not. Mineral owners whose leases predate this technology have no explicit contractual protections.

Direct Air Capture (DAC) and Pore Space Competition

Direct Air Capture removes CO₂ from the atmosphere and injects it into deep saline formations or depleted reservoirs for permanent storage. Unlike CO₂-EOR, DAC does not enhance production — it competes with the subsurface for storage space. As commercial DAC projects scale, the question of who owns the pore space beneath producing formations will become a significant title issue for mineral owners, surface owners, and operators simultaneously.

What Mineral Owners and Trustees Should Do Now

Horizontal development and emerging technologies do not require a fundamentally different response — they require the existing forensic audit framework to be applied with greater urgency and specificity. The steps are the same; the stakes are higher.