Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on February 12, 2013 at 15:04

No, the Supremes have not refused writs in the Webb case as far as I know.  However they have previously refused writs in a series of appellate rulings which are important to the interpretation of Louisiana mineral law.  In a new paradigm of energy exploration and production the mineral codes are insufficient to give legal clarity to a number of issues.  The legislature should review and revamp the codes but there is little political will to take up that challenge.  Lacking new legislation, the judiciary will have to sort things out.  Refusing to provide clarity through Supreme Court rulings leaves the job to the appellate courts, particularly the 2nd. Circuit which has jurisdiction for the bulk of contemporary cases arising from the Haynesville Shale development.  IMO the court lacks sufficient members with experience in the legal complexities of mineral law.  I sat in on one 2nd. Circuit appeal and felt the ruling was not in accordance with the testimony.  The ruling agreed with all the points made on behalf of the plaintiff and then found for the defendant.  It seemed an extreme legal contortion in order to avoid ruling against the energy industry.

• ▶ Reply

Permalink Reply by Andrew on February 13, 2013 at 16:08

At the risk of sounding wonky, even if there were gaps in the mineral code for new situations proper analysis and interpretation of the code as a whole should still address any new problems not foreseen when the code was enacted in 1974. Even if not, the Civil Code should fill in any gaps that still remain. Now, what a court actually chooses to do is another matter, but as far as I'm aware the Mineral Code in conjunction with the Civil Code should have the answers to most questions.

Do you know of any specific issues where you feel like the Mineral Code is lacking?

• ▶ Reply

Permalink Reply by Steve P on February 13, 2013 at 17:34

many years ago, I won a case at the district court level involving ownership of mineral rights, and the other side appealed.  as the case progressed before the 2nd Circuit, I realized that all 3 of the judges were former prosecutors or trial lawyers.  None knew anything about property or mineral law.  It was not a good outcome for my clients or me. Stated succinctly, real estate lawyers, and especially oil and gas lawyers, are very unlikely to run for or be appointed to judicial seats.  Considering what's important to Louisiana jurisprudence (and Louisiana business) right now, I'd say having a handle on mineral rights is a bit more relevant than whether possession of XX grams of meth is "intent to distribute" or simple possession.  but that's where we are.

• ▶ Reply

Permalink Reply by Skip Peel - Mineral Consultant on February 13, 2013 at 16:50

Okay. Wonky is good. LOL!

I buy mineral rights covered by a lease to Petrohawk. Three days before the expiration of the lease term Petrohawk spuds a well permitted for the section/unit in question. However the surface location is in an adjoining section. The well is spud before expiration but not on the leased lands. The horizontal wellbore will not enter the leased lands until days after the lease has expired. Petrohawk might argue that they spud the well permitted for that specific unit before the lease expired. The owner of the minerals might argue that the lease has expired and that Petrohawk should be required to execute a new lease and pay a bonus.

The Mineral Code never anticipated horizontal development.

• ▶ Reply

Permalink Reply by Andrew on February 13, 2013 at 18:15

I agree that such a situation is not directly anticipated by the mineral code, and is a hard one to deal with, but in my view the deficiency lie in the lease form. The mineral lease would be the proper place to determine the rights of the parties in this situation, because it contains its own conditions which would allow the lease to remain enforced beyond the primary term. For example, a typical north Louisiana Bath Lease provides:

If at the expiration of the primary term or at the expiration of the ninety (90) day period provided for in the preceding sentence, oil, gas, sulphur or other mineral is not being produced on said land or on land pooled therewith, but Lessee is then engaged in operations for drilling, completion or reworking thereon, or operations to achieve or restore production, or if production previously secured should cease from any cause after the expiration of the primary term, this lease shall remain in force so long thereafter as Lessee either (a) is engaged in operations for drilling, completion or reworking, or operations to achieve or restore production, with no cessation between operations or between such cessation of production and additional operations of more than ninety (90) consecutive days; or (b) Is producing oil, gas, sulphur or other mineral from said land hereunder or from land pooled therewith. If sulphur be encountered on said premises or on land pooled therewith, this lease shall continue in force and effect so long as Lessee is engaged with due diligence in explorations for and/or erecting a plant for the production of sulphur and thereafter subject to the foregoing provisions hereof so long as oil, gas, sulphur or other mineral is produced from said land hereunder or from land pooled therewith.

In the situation you described, it appears the conditions of this paragraph are not met because the lessee is not conducting operations for drilling on the lease tract or "lands pooled therewith" (assuming the drillsite tract in the adjacent section is not covered by the soon-to-expire lease). Therefore I would say the condition on extending the primary term hasn't been met and some lease bonus or a free carry would be in order.

Issues which arise from a surface location being outside of a unit are usually a matter of what is in the lease clauses and not a matter of regulation or the mineral code. To my knowledge, most or all of these adjacent-section locations that were authorized by the Commissioner where on leases that had "adjacent lands clauses" which allowed the lessee to use that land to access adjacent lands upon which they also had leases.

• ▶ Reply

Permalink Reply by Skip Peel - Mineral Consultant on February 14, 2013 at 3:04

I agree excepting your last about "adjacent lands clauses".  I don't think the Commissioner reviews or takes into account in any way lease terms in the process of granting a field order.  Heck, the state does not even require the unit applicant to have a minimum percentage of the unit acres under lease. The only right/permission required of an off-unit drill site is surface use and a sub-surface easement.  In the HS operators regularly granted both for operators of adjacent units.

How about "cross unit laterals"?

• ▶ Reply

Permalink Reply by Andrew on February 14, 2013 at 7:39

You're totally right, the commissioner is almost certainly not policing that, although this is something that should at least be asked before an adjacent unit location is approved.

Cross unit laterals are also a matter of the Conservation act and your lease. The typical Bath lease provides:

no one operating unit shall, in the case of gas, including condensate, embrace more than six hundred forty (640) acres, and in the case of oil, including casinghead gas, embrace more than eighty (80) acres; and provided further, however, that if any spacing or other rules and regulations of the State or Federal Commission, Agency, or regulatory body having or claiming jurisdiction has heretofore or shall at any time hereafter permit or prescribe a drilling or operating unit or spacing rule in the case of gas, including condensate, greater than six hundred forty (640) acres, or in the case of oil or casinghead  gas greater than  eighty (80) acres, then the unit or units herein contemplated may have, or may be redesigned so as to have, as the case may be, the same surface content as, but not more than, the unit or the acreage in the spacing rule so prescribed or permitted. 

That clause is what allows cross-unit lateral as I understand it, because it effectively allows the Commissioner to authorize pooling both units together. The conservation act (30:9) provides that royalties be paid proportionately to the acreage inside the unit or pool. 

• ▶ Reply

Permalink Reply by Andrew on February 14, 2013 at 7:42

I've got a Mineral Code doozy for you though: What happens to a mineral owner whose lease is terminated or released after unit operations have commenced? Does he get a carry for the costs before termination? Does that free the leaseholder from plugging liability?

Granted, the Mineral Code doesn't address this because I doubt it happens very often, but there's potential for some conniving operators to release non-drillsite tract leases when a unit well isn't going to pay out so they don't have to pay those royalties.

• ▶ Reply

Permalink Reply by Skip Peel - Mineral Consultant on February 14, 2013 at 7:59

The language regarding cross unit laterals would seem to be pretty clear on the face of it.  However now that technology can monitor flow per perf cluster it may get a little sticky.  Is the arbitrary course of calculating production payments by the percentage of the lateral in each unit just?  What if perf clusters in one unit contribute 20% of production and the perfs in the other unit contribute 80%?  What if 6 months into production all the perfs in one unit cease to produce?  Will the state monitor percentage production by unit?  Or require the operator to do so? 

Yep, that is a doozy.  IMO the Mineral Code should prohibit termination or release after operations have commenced.  I think any operator would be foolish to take such a course without some basis in law to defend their action.  Litigation would surely follow such action as the lessor would probably have a number of O&G law firms willing to take the case on contingency.  The publicity alone would be worth it.  LOL!

• ▶ Reply

Permalink Reply by Andrew on February 14, 2013 at 8:20

The Mineral Code makes clear that termination is not a favored remedy because it's too harsh, but says nothing about a lessee releasing the lease. Once again, the Bath form allows the lessee to release any or all of the lease at any time. 

Say a lessee drills a well in the center of a 640 acre gas unit and the whole unit is leased to him. If the well completes and is a disappointment, i.e. it will never pay out, he could release all the non-drillsite leases. At that point he would have legal argument that those (now unleased) mineral owners are entitled to 8/8ths of their share of production after payout. He gets everything until payout, and because payout probably won't happen, he just minimizes his investment loss by keeping the royalties.

I've looked high and low, and I've concluded that there simply is no answer in the law for what the mineral owner is to do in that situation. When that happens the courts are supposed to just go with the equitable (fair) solution, but who only knows where we might end up in such a complicated situation. That said, such a scenario is remarkably unfair to the mineral owner, and given how strongly Louisiana's public policy favors the mineral owner I only see this happening once before a law is changed.

• ▶ Reply

Permalink Reply by Skip Peel - Mineral Consultant on February 14, 2013 at 8:25

It would certainly be a desperation measure.  Only contemplated as a last act before getting out of the business.  The chances of acquiring future lease rights might be negatively impacted.

• ▶ Reply

• ‹ Previous
• 1
• 2
• Next ›
• Page