In this episode, we dive into one of the most unique and complex aspects of Texas oil and gas development: allocation wells and the state’s unique approach to pooling mineral interests. Unlike most oil-producing states that have robust forced pooling statutes, Texas takes a different approach that gives mineral owners more control but creates significant complexity in how royalties are calculated and paid.
We reveal how allocation wells calculate royalties based on the length of the wellbore traversing each property rather than total acreage, which can result in dramatically different payments compared to traditional pooling. Understanding whether your minerals are in a pooled unit, production sharing agreement well, or allocation well can mean the difference between receiving substantially more or less in monthly royalty checks based on the specific circumstances. We also provide practical guidance on how Texas mineral owners can identify what type of well is being drilled on their property using the Railroad Commission website, and when it makes sense to seek expert help to verify decimal interest calculations on division orders.
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Texas: It’s Like a Whole Other Country
I graduated high school in Texas in the mid 90’s and around that time I remember a Texas tourism ad campaign with the tag line “Texas: It’s Like a Whole Other Country.” I thought that was a fitting description of how Texas handles oil and gas pooling.
Texas stands apart from virtually every other oil and gas producing state in the country when it comes to pooling mineral interests. While states like Oklahoma, Colorado, New Mexico, and North Dakota have forced pooling statutes that allow operators to combine mineral tracts and obtain drilling permits even without unanimous consent from all mineral owners, Texas takes a fundamentally different philosophical approach rooted in stronger property rights protections.
As I explain in this episode, this difference becomes critically important in the era of horizontal drilling, where wells routinely traverse multiple properties and can extend for several miles underground, crossing dozens of different mineral ownership boundaries.
The foundation of Texas’s unique system traces back to a landmark 1961 court decision known as the Normanna case. In Atlantic Refining Company versus the Railroad Commission of Texas, the state’s Supreme Court addressed a dramatic inequity where a tiny 0.3-acre townsite lot was positioned to drain gas worth approximately $2.5 million over twenty years despite containing actual reserves worth only about $7,000 underneath the property. The court ruled that the allocation formula allowing this massive drainage from larger neighboring tracts was fundamentally unfair and failed to provide each producer a fair opportunity to recover their proportionate share of the reservoir.
This decision created an immediate crisis in Texas oil and gas development because it eliminated the favorable proration formulas that had previously benefited small tract owners, making many properties uneconomical to drill. In response, the Texas Legislature enacted the Mineral Interest Pooling Act (MIPA) in 1965, but they deliberately crafted it to reflect the state’s resistance to forced pooling. Unlike compulsory pooling statutes in other states, MIPA primarily encourages voluntary agreements and provides only limited authority for forced pooling under very specific and restrictive circumstances. The act requires applicants who want to pool interests to prove they made fair and reasonable offers to mineral owners before any compulsory action can even be considered, creating a cumbersome process that requires concerted good-faith negotiation efforts rather than simply mailing out a best-and-final lease offer.
The Birth of Allocation Wells: A Creative Solution
The restrictions imposed by MIPA and Texas’s general resistance to forced pooling created a significant challenge for operators as horizontal drilling technology matured and became mainstream around 2010. Operators needed a way to drill horizontal wells across multiple mineral tracts and obtain the necessary permits even when they couldn’t get unanimous consent or pooling authority from all mineral owners. Interestingly, the solution came through precedent-setting action by Devon Energy, which fundamentally changed how horizontal wells are permitted in Texas.
In 2010, Devon Energy attempted to secure a production sharing agreement from interest owners for a proposed horizontal well but couldn’t obtain the requisite sixty-five percent approval needed for a PSA well permit. Rather than abandoning the project, Devon applied for the permit anyway but labeled the well as an allocation well. The Texas Railroad Commission approved this permit, and with that decision, the allocation well was born. What made this revolutionary was that allocation wells don’t require approval from interest owners, unlike production sharing agreement wells that need consent from sixty-five percent of mineral and working interest owners in each tract crossed by the well.
This development occurred at a pivotal moment when horizontal drilling was transforming the industry and unlocking vast reserves in unconventional plays across Texas. Operators needed flexibility to develop these resources efficiently without being hamstrung by the inability to obtain unanimous consent from increasingly fragmented mineral ownership. As I note in the episode, originally the Railroad Commission would only issue allocation well permits if operators represented they had production sharing agreements from at least sixty-five percent of royalty owners. However, a few years later, the commission decided it could issue allocation well permits without requiring any production sharing agreements at all, removing a significant regulatory burden and making allocation wells even more attractive to operators.
How Allocation Wells Differ from Traditional Pooling
The fundamental distinction between allocation wells and traditional pooled units lies in how royalty payments are calculated, and this difference can have enormous financial implications for mineral owners. In a traditional pooled unit scenario, royalty calculations are straightforward and based on a tract participation factor. As I explain using a simple example, if you own one net mineral acre in a unit comprising two sections totaling 1,280 acres, and you’ve leased at a twenty-five percent royalty rate, your decimal interest would simply be one divided by 1,280 multiplied by 0.25. This calculation applies uniformly across all wells drilled within that pooled unit, making it easy for mineral owners to verify their interests and understand what they should be paid.
Allocation wells operate on an entirely different principle based on productive lateral length rather than total acreage. Instead of using a tract participation factor based on how much land you contribute to the unit, allocation wells calculate your interest based on how much of the horizontal wellbore actually traverses your specific mineral tract. The formula uses the lateral length of the horizontal wellbore on your tract as the numerator and the total horizontal wellbore length as the denominator. This is then multiplied by your lease royalty rate and your net mineral interest to determine your decimal interest in that specific well.
This distinction creates scenarios where allocation wells can be either significantly more advantageous or substantially less beneficial than traditional pooling depending on the geometry of your mineral tract relative to the wellbore path. In this episode, I walk through examples showing how if you own a large mineral tract but the horizontal well only passes through a small portion of your property, representing perhaps only ten percent of the total wellbore length, you would receive a much smaller proportional share under allocation methodology compared to what you would receive in a pooled unit where your entire acreage counts toward your participation factor. Conversely, if the wellbore runs through the majority of your tract, an allocation well could result in higher royalty payments than you would receive in a pooled unit of the same size.
The Railroad Commission’s justification for why allocation wells don’t require pooling authority rests on an interesting legal interpretation. According to the commission, horizontal wells are treated as vertical wells for purposes of oil and gas lease provisions. Under typical lease terms, a lessee has the option to drill vertical wells on any tracts they’ve leased, even if those tracts are adjacent to one another. By treating horizontal wells as if they were vertical wells, each tract is considered to hold a single well even though the horizontal wellbore traverses lease lines underground, and production is allocated accordingly based on the wellbore’s path through each tract.
Production Sharing Agreement Wells: The Middle Ground
Between traditional pooled units and allocation wells sits another category called production sharing agreement wells or PSA wells. These wells represent a hybrid approach where the operator must obtain signed agreements from at least sixty-five percent of mineral and working interest owners in each tract within the developmental unit specifying how production proceeds will be divided. Unlike allocation wells that require zero consent, PSA wells need substantial buy-in from royalty owners, but unlike traditional pooling through MIPA, they don’t require the same level of demonstrated good-faith negotiation or the ability to include every single mineral owner.
The key advantage of PSA wells for operators is that the wellbore doesn’t need to be perforated within each tract of the developmental unit, whereas allocation wells can only include tracts where the wellbore is actually perforated or from which the well is producing. This provides some operational flexibility while still giving a majority of mineral owners a say in how production will be allocated. For mineral owners, signing a production sharing agreement can provide more certainty about how royalties will be calculated and may include negotiated terms beyond what would exist in a pure allocation well scenario.
Despite the theoretical benefits of PSA wells, the data I share in this episode reveals they represent a small fraction of horizontal wells drilled in Texas. Since the start of 2022, the Railroad Commission has granted just under five thousand allocation well permits compared to fewer than six hundred PSA well permits. When you look at all horizontal well permits in Texas, allocation wells and PSA wells together constitute more than half of all permits issued, with allocation wells being by far the dominant category. This suggests that operators generally find it easier and more efficient to pursue allocation wells that require no mineral owner consent rather than attempting to secure sixty-five percent approval for production sharing agreements, especially in areas with highly fragmented mineral ownership.
Legal Challenges and Court Decisions
The allocation well framework hasn’t gone unchallenged in Texas courts, and mineral owners who believed this system essentially constitutes forced pooling by another name have attempted to halt the practice through litigation. Justin and I discuss the most significant challenge that came in the case of Railroad Commission of Texas and Magnolia Oil and Gas Operating versus Opiela, which centered on a well drilled in South Texas where the mineral owners had lease provisions that explicitly prohibited pooling. The landowners argued that allocation wells and production sharing agreements were functionally no different from pooling and therefore violated their lease terms that forbade combining their interests with others.
The case wound its way through the Texas court system, and despite arguments that calling allocation wells something other than pooling was merely semantic gamesmanship, the courts ultimately sided with the Railroad Commission and the operator. As I explain, the courts determined that allocation wells are legally distinct from pooling because they don’t involve the same type of cross-conveyance that occurs in traditional pooling arrangements. In a pooled unit, there’s effectively a cross-conveyance where production from one tract constitutes constructive production from all tracts in the unit, and lessors receive royalties on all production from the entire unit based on their proportionate acreage contribution. With allocation wells, each mineral owner only receives royalties on production that’s actually attributable to their specific tract based on the wellbore path, without any cross-conveyance to other tracts.
This distinction matters because it means production from an allocation well doesn’t maintain leases on tracts where the wellbore doesn’t traverse, unlike pooled units where production from any well in the unit maintains all leases for all acreage in that unit. To keep a lease in force on a tract crossed by an allocation well, the operator must achieve actual production from perforations in that specific tract. This legal framework has withstood judicial scrutiny and appears to be firmly established in Texas law, although future cases reaching the Texas Supreme Court could potentially alter this landscape. For now, allocation wells remain the primary method by which operators in Texas develop horizontal wells across multiple unleased or unpooled tracts.
Calculating Your Interest in Allocation Wells
Understanding how to calculate your decimal interest in an allocation well is considerably more complex than verifying your interest in a traditional pooled unit, and this complexity creates opportunities for errors that can cost mineral owners significant money over the life of producing wells. I walk listeners through the process, explaining that the starting point is obtaining the as-drilled plat from the Texas Railroad Commission, which shows the actual path the horizontal wellbore took through the subsurface and indicates the first and last take points on each tract. Take points are the perforations in the well casing through which oil and gas flows from the formation into the wellbore, and the distance between the first and last take point on your tract represents the productive lateral length attributed to your property.
The plat will show measurements for each tract the wellbore crosses, and you need to identify your specific tract and note the productive lateral length running through your minerals. You then need to sum up the total productive lateral length for the entire well across all tracts. Your allocation factor is calculated by dividing your tract’s productive lateral length by the total productive lateral length for the entire well. This ratio is then multiplied by your net mineral interest in that tract and your lease royalty rate to arrive at your final decimal interest for that specific well.
The challenge is that these calculations require detailed technical information from the as-drilled plat, and operators don’t always make these calculations transparent or easy to verify on division orders. Texas requires mineral owners to sign division orders before being placed in pay status, so it’s critical to verify the decimal interest calculation is correct before signing. If you discover an error after signing a division order, you may have additional challenges correcting the mistake. For mineral owners who aren’t comfortable diving into the technical details or who want certainty they’re being paid correctly, I offer to help verify these calculations in my day job doing appraisals and valuations. Consulting with an expert who can verify the calculations against the railroad commission data provides valuable peace of mind, especially when the dollars at stake can be substantial over years of production.
Practical Implications for Texas Mineral Owners
For mineral owners in Texas, I emphasize that understanding whether a proposed well will be part of a pooled unit, a production sharing agreement well, or an allocation well should factor into lease negotiations and business decisions. If you’re negotiating a new lease, the pooling provisions you agree to can significantly impact your future rights and the leverage you’ll have when wells are proposed. Strong anti-pooling language in your lease can provide negotiating power, but it can also force operators toward the allocation well route, which may or may not be financially advantageous depending on where future wells are located relative to your minerals.
Some mineral owners use pooling provisions strategically as a bargaining chip during lease negotiations. You might agree to allow pooling in exchange for a higher royalty rate, no post-production deductions, or other favorable lease terms. The key is understanding that pooling isn’t automatically bad for mineral owners, and in many scenarios, being included in a pooled unit with proportionate allocation based on acreage can result in higher royalty payments than allocation well methodology. Everything depends on the specific geometry of the unit, where wells are drilled, and how much of the wellbore traverses your particular tract.
When you receive notice of proposed drilling activity or when wells are permitted near your minerals, visiting the Texas Railroad Commission website should be your first step. I point listeners to episode 226 of the Mineral Rights Podcast, which includes a detailed video tutorial I created on how to navigate the commission’s website, search for wells by geographic location, and download the relevant permits and plats. You can find this on my YouTube channel by searching for Matt Sands Mineral Rights and going to the how-to video section, or visit MineralRightsPodcast.com and look up episode 226. The permit documents will clearly indicate whether a well is designated as an allocation well, PSA well, or part of a pooled unit. Pooled units typically have a P-12 form showing all the different tracts and their allocation percentages, while allocation wells will be specifically labeled as such on the permit and the as-drilled plat.
Justin and I discuss what happens if you find yourself as an unleased co-tenant in a situation where operators are drilling allocation wells through your minerals without your consent. You do have options beyond simply accepting the working interest burden that comes with the co-tenant relationship. In active drilling areas, particularly in West Texas where horizontal development is robust, you may be able to negotiate a lease even after drilling has begun because other operators or investors want working interest exposure in productive areas and your unleased minerals provide that opportunity. The trade-off of going the non-consent co-tenant route is that operators can typically recoup between one hundred and two hundred percent of drilling and completion costs before you back into receiving your proportionate share of revenues, and during that payback period you receive nothing while bearing potential liability for future plugging and abandonment costs.
Why Allocation Wells Matter for Texas Oil Production
From a broader industry perspective, allocation wells have become essential to maintaining Texas’s position as America’s leading oil and gas producer. I share data showing the dramatic increase in Texas oil production from approximately 1.45 million barrels of crude oil per day in 2011 when allocation wells first appeared, to over 5.1 million barrels per day by 2019, representing more than a three hundred percent increase. While this growth can’t be attributed solely to allocation wells, this permitting framework allows operators to efficiently develop horizontal wells without the constraints that would exist if MIPA were the only option.
Without allocation wells, operators holding leases on adjacent tracts that couldn’t be pooled would face difficult choices. Texas Railroad Commission spacing rules prevent wells from being drilled closer than 467 feet to property lines, lease lines, or subdivision lines without special exceptions. An operator might be forced to drill two separate wells and leave hydrocarbons stranded in the ground near lease boundaries simply because the acreage is too close to the property line. Allocation wells eliminate this problem by allowing a single horizontal wellbore to efficiently drain reserves from multiple tracts, reducing costs, minimizing surface disturbance, increasing ultimate recovery, and preventing waste of natural resources.
The policy arguments in favor of allocation wells emphasize alignment with Texas constitutional provisions declaring that conservation and development of natural resources are public rights and duties. Allocation wells reduce waste through more efficient development, and Texas courts have consistently expressed favor for waste-reducing innovations in oil and gas production. The alternative of strictly limiting operators to MIPA’s voluntary pooling would likely result in significant reserves being left in the ground undeveloped in areas where operators can’t obtain unanimous consent or demonstrate the exhaustive good-faith negotiation process MIPA requires, ultimately harming both mineral owners who would forego royalty income and the state that would lose production taxes and economic activity.
Conclusion
The allocation well framework demonstrates how Texas’s oil and gas regulatory system has evolved to accommodate modern horizontal drilling technology while respecting the state’s strong property rights traditions. By understanding how allocation wells work, how they differ from traditional pooling, and how to verify you’re being paid correctly, you can hopefully now ask the right questions and advocate for the option that gives you the most benefit.
Resources
- Texas Mineral Interest Pooling Act Proposals
- Regulatory & Legislative Update related to Allocation Wells, Production Sharing Agreements, and MIPA.
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Disclaimer: This episode and accompanying show notes are provided for general information purposes and should not be construed as financial, legal, or investment advice. For guidance specific to your situation, please consult with qualified legal and financial professionals.
