Two’s a Crowd: Cotenancy in Texas - Part II
Happy New Year! Welcome back to the OG Energy Blog presented by Childers Hewett Slagle PLLC. In Part II of this series, we’ll take a look at how unleased cotenants are accounted for when oil and gas is produced from a commonly owned tract of land in Texas. You’ll see how unleased cotenants can transcend to a whole new level of getting something for doing nothing.
Shown above: A triggered division order analyst no longer taking shit from entitled owners bitching about their mailbox money.
To recap a few points of law discussed in Part I of this series, each cotenant has the right to enter onto the commonly owned tract of land to drill for and develop oil and gas with or without the consent of the other cotenants. The lessee under an oil and gas lease granted by a cotenant steps into the shoes of the lessor cotenant. Accordingly, no distinction needs to be made between the lessor cotenant or its lessee for the purposes of this post—the terms “producing cotenant” and “drilling cotenant” refer to both. Courts generally treat drilling a well as an inherently speculative endeavor. As a result, the drilling cotenant bears the risk that the operations will not be successful, and, if drilling results in a dry well or production otherwise never results in a profit, the drilling cotenant ends up eating the cost. If drilling results in oil or gas production, then the producing cotenant must account for each non-producing cotenant’s proportionate share of net profits from the sale of production. “Net profits” in this context means the market value of the produced oil and/or gas less any and all “necessary” and “reasonable” costs incurred by the producing cotenant in producing and marketing the same. This means that the the drilling cotenant is entitled to recoup all costs of drilling the well and marketing the production before sharing anything with the non-producing cotenant … as long as the incurred costs getting to that point are reasonable and necessary.
Have your secretary hold all of your calls—you’re going to want to read all about this. And if you still have a secretary, welcome to 2021! Can I borrow your time machine so I can get the hell out of here?
Once the producing cotenant has recouped all of those necessary and reasonable costs of drilling the well, termed “payout” in this context, the non-producing cotenants are then entitled to a proportionate share of net profits from production. Reaching payout requires that production be obtained and then sold, so the first step in accounting for non-producing cotenants is determining how that production can—or should—be valued. The valuation can be based solely on the actual gross proceeds when the production is sold, or it can be based on the current market price. This distinction is largely irrelevant if the sale price of the production tracks relatively closely with the market value at the time of the sale. But, if there is a sizeable disparity between the sale price and market price (which may be the case if there is a contract in place that provides for a price much lower than market), the producing cotenant must consider the risk that it could be stuck with paying non-producing cotenants the difference between the sale price and the market price. There’s no authority suggesting that the non-producing cotenant’s share could be reduced if the sale price is substantially higher than the market price, however.
Oh, it gets better.
Though it may seem desirable for the producing cotenant to have a juiced NRI before payout, consider that the production allocated to the non-producing cotenant is not burdened by a lease royalty—assuming the producing cotenant is a lessee under an oil and gas lease, that lessee is entitled to a net amount of production after the lease royalty is accounted for, while the unleased, non-producing cotenant is entitled to the gross amount of production attributable to their undivided interest without any reduction by a lease royalty. So, depending on the economics of the well, a lessee can quickly find itself operating a well after payout with revenues (and thus profits) taking a big hit even if it owns a majority working interest. We can see a contractual check against this type of undesirable situation in most operating agreements where the parties agree to an additional after payout penalty imposed on non-elective interests. There is unfortunately no such penalty imposed on non-producing cotenants. And before any of you entertain a Falling Down-esque fantasy of spitefully dumping the non-producing cotenant’s share of production on their front lawn, the producing cotenant can’t require the non-producing cotenant to accept production in kind because the non-producing cotenant is entitled to net profits. It’s gotta be cash money.
Still gets better.
Texas courts have been consistent in their application of the method of cotenant accounting allowing the producing cotenant to recoup all reasonable and necessary costs of drilling before the non-producing cotenant gets paid. As you may have anticipated, the determination of what costs qualify as “reasonable” and “necessary” is not particularly clear or straightforward. A big reason for this lack of clarity is because determining “reasonable” and “necessary” throws judicial review into the arena of “What is equitable?” a/k/a “What are the ‘facts’ and how do they make me feel?”. And, because the determination necessarily involves questions of fact, it’s commonly going to be decided by a jury. Before you get that glazed-over look that all of us get whenever an attorney starts yapping about academic legal standards (yes, despite willingly burning at least three years of our lives in law school and not-as-willingly subjecting ourselves to hours and hours of continuing legal education courses every year, even attorneys tend to not like listening to other attorneys talk about the law), just try to look at these multi-million-dollar, often make-or-break drilling efforts like it’s all a gameshow. We’ve got a grab-bag of bigtime costs that may or may not qualify. We’ve got jurors who are only slightly less informed than the courts in reported cases. And we get to enjoy the spectacle of folks from outside of our industry mercilessly imposing their hot sports opinions on oil and gas drillers that are just trying to pull some damned oil and gas out of the ground (at their sole risk to boot). Who wouldn’t want to watch that?
This is Bob Barker reminding you to help control the unleased cotenant population – have your cotenants spayed or neutered.
Some costs are easier to peg as reasonable and necessary. For example, the producing cotenant can typically recover costs for equipment, machinery, facilities, labor, materials, electricity, and upkeep directly incurred in the drilling of a well. But whether these costs can be deducted can get iffy if the producing cotenant already owns the machinery, equipment, and the like used to drill the well—the entire cost of those items probably can’t be deducted from the non-producing cotenant’s portion, but depreciation of such can likely be deducted. Similarly, the producing cotenant should be able to deduct “reasonable compensation” for services it rendered in drilling the well. Producing cotenants have been successful in arguing that certain leasehold, land, and legal expenses like lease bonuses, recording fees, landman fees, and title opinion fees can be deducted, even if on a pooled unit basis. These expenses were justified deductions when the court found that the common estate, and thus the non-producing cotenant, benefited from them. Certain overhead costs like administration, office services, and warehousing may also be deducted provided that the reasonable and necessary standard is satisfied.
Make sure you fix that glitch in the paydeck department first.
But the deductibility of overhead costs should not be assumed. There is conflicting authority as to what overhead costs can be deducted and to what extent. For example, two reported appellate cases illustrate this point in their opposite holdings on the deductibility of COPAS overhead costs. While the split in these cases appears to be primarily sourced from how the parties made their arguments at trial and how the trial court holding was appealed, both cases reinforce the idea that the more direct the relationship of overhead costs to the drilling of specific wells, the more likely those costs can be deducted. If the cost is something that would have occurred regardless of whether the well or wells were drilled (e.g., indefinitely recurring office administrative costs that existed before the wells were drilled and did not change during or after), it probably can’t be deducted.
Like how basically nothing is deductible for federal income and business tax purposes anymore.
What about charging interest and deducting it from the non-producing cotenant’s share? After all, the producing cotenant fronts the money and bears all of the risk in drilling the well. Texas courts haven’t been swayed—a producing cotenant can’t apply interest to money spent drilling a well and then deduct that interest from the non-producing cotenant’s share. The reasoning here is that interest is derived from debt and therefore requires that a party obligate itself to pay another (whether by contract or implied by law). So, unless a non-producing cotenant lost his or her damned mind and agreed otherwise, interest charged on money spent to drill does not qualify as a recoupable cost of production. For similar reasons, a different court held that interest based on monthly weighted average cost of capital could not be deducted. The producing cotenant argued that interest on capital is a cost of development and should therefore be able to be deducted. In rejecting this argument, the court reasoned that the recovery of costs by the producing cotenant is not in the capacity of a creditor—the producing cotenant recovers its costs, not debt.
This is me when I have to ignorantly dip my toes into finance when researching the law. It’s how I imagine many of you reading these posts, too.
These examples are informative, but looking at them individually and out of context does not account for the complex reality of oil and gas exploration and production. Rarely is a singular well drilled on a tract. Even with a single well, an operator may test more than one zone, and there may be distinct drilling efforts to produce from different parts of the property and from different depths made via the same wellbore. The cost of drilling will vary from well to well, just as the rate of production is likely to vary. It’s not uncommon for a well, after obtaining production from one zone or formation, to be either plugged back or deepened in an effort to produce from different zones or formations. The variables are many. The point here being that the analysis gets complicated very quickly when a producing cotenant conducts multiple drilling operations in the same tract.
You want to allocate what?? With how many wells?? And you want contractual and record title reported?? Sign us up!
This overall analysis always falls back to whether the costs were reasonable and necessary in order to obtain production, but a nuance emerges within the analysis where “necessary” morphs into a question of how effectively the activity (which costs money) can be pegged as a reason (or cause) for the production. To put it another way: Can the activity be logically tied to eventual production even if the activity itself did not directly result in production? And to flip the question: Was the activity intended to obtain or eventually obtain production and was it successful in doing so? Unfortunately for producing cotenants, this question is generally answered by a jury, which is full of people unable to think logically enough to get out of jury duty, so there are no guarantees or slam dunks that any given cost can be deducted even if it’s painfully obvious that the underlying activity directly or proximately resulted in production.
Are you willing to take the “business risk”? A favorite of chickenshit attorneys everywhere—push it back on the client as a business risk!
So, I know I’ve said several times that a drilling cotenant is not able to recoup the costs of drilling a dry hole or unprofitable well. But what if the drilling cotenant drills additional wells that produce and are profitable—can the drilling costs of the first well be deducted from the production obtained from the subsequent wells? If the first well is a legitimate dry hole and produced no oil or gas, the answer is most likely no. But, if the first well produced some amount of oil or gas, it is possible that the cost of drilling that well could be deducted from production obtained from subsequent wells. The producing cotenant would need to show that the drilling of the first well benefited the common estate in order to recoup its costs (e.g., drilling the well cockblocked drainage from the common property or set up the property for further exploration through geologic data or means of future reentry) and hope that the reviewing court subscribes to a tract-wide approach for deducting drilling costs rather than a well-by-well basis.
But they really do matter. In their own special way.
The distinction between the tract-wide and well-by-well approaches for deducting drilling costs is part of the wider unresolved issue as to whether payout should be calculated across the entire tract or for each well individually. Consider a scenario where a cotenant drills multiple wells, and each is profitable—are the non-producing cotenants entitled to their share of production for each individual well after each hits payout or do they have to wait for the overall proceeds from the wells to outstrip the total cost of drilling all of the wells on the common tract? Although it appears that a tract-wide basis of accounting may prevail, there is no Texas case directly deciding this point of law. Because the distinction is an equitable one, the prevailing approach will likely hinge on which one the courts consider “fairer”. But it’s not necessarily a zero-sum game—the application of one approach over the other may end up being on a case-by-case basis that is dictated by the particular circumstances at issue, which would be much like the component analysis of what costs are reasonable and necessary.
Again with the reasonable and necessary mess? HOO-AH!
The well-by-well approach of determining payout between cotenants mimics the typical setup in an operating agreement where the participating parties recoup all costs of drilling each proposed well before the non-participating parties are entitled to any proceeds. The well-by-well approach is also in line with reported cases holding that the drilling cotenant gets nothing if a well doesn’t pan out. Under this approach, the non-producing cotenant also gets to enjoy sharing in the proceeds sooner and without regard to the producing cotenant’s future plans for the tract. While seemingly fairer for the non-producing cotenant, the well-by-well approach could be considered inequitable towards the producing cotenant if the producing cotenant must develop the entire property in order to accumulate the profits necessary to justify the endeavor. Additionally, there’s no after payout penalty imposed on a non-producing cotenant, which further squeezes the producing cotenant financially. Looking at each well in a vacuum also ignores many of the less specific costs of drilling like the construction, maintenance, and/or operation of roads, power lines, and on-site facilities that can benefit subsequent wells (but wouldn’t be reflected in their cost to drill on a well-by-well basis).
And it also makes the creative accounting that much harder.
The tract-wide basis of determining payout avoids these issues but does present others. Instead of sharing in proceeds upon payout of the first well, the non-producing cotenant now has to wait longer—potentially considerably longer—before proceeds outstrip the cost of drilling and equipping all of the wells on the tract. While that may not be as “fair” to the non-producing cotenant, being able to spread the cost of drilling out over multiple wells could be considered fairer to the producing cotenant. Further, while the non-producing cotenant may have to wait longer for their money, the ultimate share of the proceeds paid out to the non-producing cotenant should be about the same so long as all wells drilled are profitable. In deciding fairness, it should also be considered that the non-producing cotenant is taking on none of the risk of drilling but gets to eventually share in the reward irrespective the basis being tract-wide or well-by-well. Finally, from a policy standpoint, if the objective is maximum recovery of hydrocarbons, a tract-wide basis should generally encourage full development of any given tract of land, while a well-by-well basis might hinder or outright prohibit such development.
Mostly.
That does it for our series Two’s a Crowd: Cotenancy in Texas. If you’re (still) reading this, you made it through 2020 alive and are well enough to spend time reading the store brand version of an oil and gas law blog, so I’ll take that as a win for all of us. Here’s to a healthy and prosperous 2021. Thanks for reading!
