Release of a portion of a lease?

Oil and Gas Leasing Help
1

I have a signed Oil & Gas Lease dated 1952 in which 2 locations are listed on the lease:

NE/4 of Section 27 T26N R26W and NE/4 of Section 34 T26N R26W. Both in Harper County, Oklahoma. There is a current producing well on Section 27. On Section 34, there was a well drilled in November 1978 and plugged in January 1979.

I have someone interested in leasing Section 34. My question is: Is there any way to get the operator to release Section 34 since there has been no drilling activity for 25 years? It is such an old lease so not many good clauses included.

Is there a statue that covers this? I need some help on whether there is any way to get it released.

Thanks to all that can help!

2

I don't see anything specific that includes wording of a Pugh Clause. I have read the lease over and over but not sure what type of wording I am looking for besides something obvious. Thanks for the input.

3

Mineral Joe,

Thanks for the input. Can you explain "outside the spacing unit". In this case there are 2 locations listed on the lease. Would each of those be independent of each other? If they only have activity on one location and nothing on the other, they have to release the one with no activity. I will definitely call the operator for a release but could I get some professional input on the right verbiage to use so I don't get the run around? I want to have a good understanding of why they should release this portion of the lease (i.e., state law, statute, etc). I guess I'm also a bit confused how they could have a lease from 1952 and do nothing on Section 34 until 25 years later. They were well beyond the Primary term (10 Years) and still drilled. Based on the information I have supplied (Lease dated 1952, 10 year Primary Term lease, Plugged Well 1979 on Section 34) would you say they had no rights to drill in 1978 in Section 34? This will be my first contact with any operator on our newly acquired Mineral Rights and I want to sound like I know what I am talking about so they don't tell me something that is incorrect like telling me they don't have to release a portion because they have drilled on Section 27 (Also listed on lease) and that makes the lease still active. Thank you so much for your help it is so appreciated.

4

As to the 2 pieces of property listed on this lease, one currently producing and one no production for 25 years. Per verbatim from the 1952 lease:

"This lease shall remain in force for a term of 10 years and as long thereafter as oil, gas, casinghead gas, casinghead gasoline and minerals or any of them is or can be produced from the lands hereinabove described"

Would that be considered a 1952 Pugh Clause, being one is producing and one has had no production for 25 years. Would that specify the release of the non producing portion of the lease?

5

Yeah, seems a bit open ended. Thanks for the input Pete! I really appreciate it.

6

"Can be" would be virtually forever. 1,000 years from now oil and or gas might possibly "can be" produced.

7

If your lease does not have a pugh clause or any other language that would result in a division of the lease if the minerals are pooled and/or a release of lands outside producing units you're probably stuck with the lease. Oklahoma's statutory pugh clause automatically applies to all leases executed after 5/25/1977, and since your lease was executed 25 years before that the statute won't do you any good.

The clause below is not a Pugh clause. To the contrary, this clause is what has the effect of allowing production from any part of your lease to hold the entire lease. If you want that acreage released you would have to file suit claiming the lessee has breached their implied covenants (i.e. to further explore).

"This lease shall remain in force for a term of 10 years and as long thereafter as oil, gas, casinghead gas, casinghead gasoline and minerals or any of them is or can be produced from the lands hereinabove described"

8

RW,

I think the "can be" is referring to shut-in wells which are "capable of producing in paying quantities" but are awaiting a market, rework, etc. Also, if offset wells are being drilled into the same formation as a current producer(s), the producer will usually be shut in during the alternate well drilling and completion operations. The "can be" wording allows the lease to remain in force during such (brief, supposedly) periods of non-production.

r w kennedy said:

"Can be" would be virtually forever. 1,000 years from now oil and or gas might possibly "can be" produced.

9

Andrew is correct and I didn't see the year you leased until after I replied and then deleted once I did and didn't have time to rewrite. You should call and nicely ask them to do a release on the tract that doesn't have a producing well first before doing anything else and they might go for it, some good people will.

10

I'm not a lawyer and I'm not giving legal advice but I was just today reading case law about contract language being construed in it's popular meaning. If it quacks like a duck, it's probably a duck. At the very least it could be a legal hurdle. If you have to get and or depend on people agreeing with your definitions, you may not have an unwinnable case but if you have more than 2 or 3 such hurdles, think long and hard before you start anything or before signing your next contract.

11

I have to say this is the most I have learned in one day on the leasing issue. Thank You all so much.

I do have another question and let's see if I can word this correctly. If an operator is looking to drill a well in a section, do they have to either obtain leases or pool the remaining interests to gather all interest in that section?

Thanks Again Everyone!

12

The statutory pugh clause is found at 52 O.S. s87.1(b):

(b) In case of a spacing unit of one hundred sixty (160) acres or more, no oil and/or gas leasehold interest outside the spacing unit involved may be held by production from the spacing unit more than ninety (90) days beyond expiration of the primary term of the lease.

13

Pete Wrench said:

No, an Operator does not have to obtain leases from or pool all interests in a section in order to drill. But they must gather enough mineral acreage to equal or exceed the minimum size specified by law or regulation in that state AND to equal or exceed the minimum size specified in the Oil and Gas Lease.

I think this a myth commonly perpetuated by landmen, either innocently or not. Any unleased mineral owner or lease owner, apparently no matter how large the tract, can request that the State of Oklahoma unitize and force pool acreage. 52 O.S. s87.1(a) provides in part:

Any order issued pursuant to the provisions hereof may be entered after a hearing upon the petition of any person owning an interest in the minerals in lands embraced within such common source of supply, or the right to drill a well for oil or gas on the lands embraced within such common source of supply, or on the petition of the Conservation Officer of the State of Oklahoma.

14

"So what are you saying, that an Operator does not have to gather enough mineral acreage together to equal or exceed the minimum size specified by law or regulation in that state? The Operator can go lease five acres for a pad site, drill a vertical well, and tell the surrounding mineral owners, "Hey, if you want in on this well go to the State of Oklahoma and have them make us unitize and force-pool you guys. Until then, have a nice day?"

That is apparently correct. Unless someone with the right to drill on a larger proportion of the acreage in the prospective unit protests the application, then any amount of acreage is legally sufficient to apply for a pooling order. At least, that's what the statute says as I read it. I couldn't find any requirement of minimum acreage in the statute.

The "myth" I was referring to was the commonly-held misconception that a company has to have a certain percentage of drilling rights in order to form a unit. To be fair, I was speaking more from my experience in Louisiana, where that misconception runs rampant. However, Oklahoma and Louisiana have extremely similar conservation statutes, including the relevant language quoted above, which leads me to conclude that Oklahoma, like Louisiana, has no such minimum requirement. Of course, requirements for unit formation and forced pooling will vary widely among the states; it just so happens that Oklahoma and Louisiana have very similar conservation laws.

Now, as a practical matter, it wouldn't likely be profitable for a company to drill a well in a unit without the majority of mineral acreage under lease, so it is certainly uncommon, but not legally impossible. Again, this is just what I gather from reading the statute, and those with more experience in OK may correct me.

15

I was talking solely about Oklahoma. Texas's pooling and unitization rules are totally different. Everything I said above in this thread pertains to Oklahoma only. Texas's asinine rules are discussed in the other thread you and I have hijacked this evening.

16

I apologize, as I apparently overlooked a portion of your post.

You don't need the whole section. I was assuming from the question that the whole "section" meant the whole "unit" since unit and section boundaries commonly overlap.

You're correct that, in general some states do specify a minimum acreage amount to allow pooling. I thought this topic was restricted to Oklahoma, which does not have any such minimum requirement.

I'm not familiar with any lease that sets a minimum size for leased acreage. Maximum sizes, I'm certainly familiar with. It is also common to provide that the a minimum amount of the leased acreage is included in a unit. But I don't see why a lessor would want a minimum unit size. Ideally, the lessor would want the unit to be one acre, and that it be made entirely of their one acre, right?

As for Oklahoma regulations, there are none that I'm aware of that proscribe a minimum acreage size to form a unit. The regulations deal with spacing, allowables, reporting, etc. Pooling and unitization are dealt with by statute.

I would be shocked if an Operator in Oklahoma or virtually any other state can drill a well with only five acres assigned to a well.

Yes, you can technically do this by drilling a non-unit well on a lease basis. To prevent drainage, most states including Oklahoma have spacing rules that prevent a well being located within a certain distance from neighboring property lines. Oklahoma's minimum offset distance is 330 feet from the neighboring property line, so you could technically drill a well in a 330' x 330' square, which would equal exactly 2.5 acres in a square if you were so inclined to form a unit that small. If the offsetting owners were displeased, they would be free to drill their own wells 330' from the property line and 600' from the now-existing well producing on the 2.5 acres.

If you were in the dead center of a large tract with no wells, you could form a 1 acre unit. But obviously, no one would do that, they would drill the well on a lease basis or form a voluntary unit.

17

Can I jump in and ask what is the difference between "Unit" and "Section"? Knowing this will answer many questions I have when I am reading some of these old leases to figure out what they mean, i.e. "A producing unit". Is "Unit" the spacing unit assigned by the OCC? Does a spacing unit ever include something unusual besides say 2 sections together, etc?