A recent reply by a MS member reporting a new lease offer at lower than previous terms and a discussion about the possibility of TMS development re-starting made me consider whether a discussion on the future of the TMS Play might be in order.
The State of the Play
If the million acres under lease by all the TMS operators were to be drilled to hold the leases in force it would take about 550 wells. So far less than 90 unit wells have been drilled. Since the play has become uneconomic due to low commodity prices it appears likely that somewhere in the neighborhood of 200,000 acres will be HBP (Held By Production) leaving 800,000 prospective acres, in both states, where many leases will expire unless extension options exist and are executed.
The majority of projections for future commodity prices, particularly crude in the case of the TMS, do not see $100/barrel for many years perhaps a decade or more. There's been a lot of speculation about the minimum price required to make the TMS an attractive investment. I don't know what that number is and I expect it is somewhat different for each TMS operator. Most of the potential future events that could impact the price of crude would add to the existing over supply and prolong the period of depressed prices.
It should be understood that regardless of the reduction in well cost brought on by the collapse in commodity prices the TMS will likely remain a play with one of the highest, if not the highest, well costs relative to all the other plays owing to its extreme depth. In other words there currently does not appear to be any future events that would make TMS investment attractive short of an unexpected and significant increase in the global price of crude.
Mineral owners in the prospective TMS areas should consider whether they wish to help make the development economics work for the companies that have made a commitment to the Play. At the original lease terms for bonus and royalty the TMS is not an attractive investment at $60, $70 or maybe even $80 crude prices depending on specific location. Lower bonus and royalty terms are not what any mineral owner wishes to contemplate. The interests and needs of mineral owners vary quite a bit. My business is built in large part on assisting mineral owners to get fair and beneficial lease terms so I do not broach this subject lightly. It is possible that for the foreseeable future development of the TMS may hinge upon mineral owners accepting lesser terms to facilitate development. I am not advocating just signing the standard lease form. There are lease terms other than bonus and royalty that should remain priorities.
Considering the significant differences in the MS and LA Mineral Codes, LA mineral owners have more to consider and MS mineral owners are subject to laws limiting their ability to negotiate. I am curious of the opinions of the members and look forward to reading your replies.
Great summary on the "State of the Play". Appreciate all your input and help both here and on other topic forums
Thanks, Rock Man. I'm curious to see what members think. Are they better off making some concessions and getting their minerals produced in the near term. Or are they better off waiting to some future date when global oil prices are much greater and lease offers better As some like to say, that oil/gas under my feet isn't going anywhere.
True that the O&G isn't going anywhere but the present owners may not be around to see it being produced.
The ultimate wild card here is what it will take to produce these assets economically. Will there be a break through in drilling and completion technology that will significantly lower costs to tap these assets?
Personally I don't see that happening - the driving force will most likely be O&G prices.
But I do agree that a trade off needs to be considered by mineral owners when you look at lease bonus prices versus potential future O&G royalties.
"As some like to say, that oil/gas under my feet isn't going anywhere."
True, but think of all the landowners of shallow conventional oil deposits who said the same thing and now find that oil company now have no desire to drill for that oil and that oil most likely will never be extracted.
I have no idea what next big thing could make shale obsolete, but that doesn't mean its not out there for somebody to think of or discover.
tc - I think you are mistaken re-shallow conventional - my crystal ball says that due to the low cost of playing that game, it will be one of the first areas to see new activity, assuming the location is reasonably favorable to getting it to market.
I think that is correct...I am seeing an increase in conventional plays in South Louisiana.
There are always exceptions, but I think the TMS is dead until we have stable $75 dollar oil.
Good point, William. S LA and the GOM shelf appear to still hold opportunities for conventional plays. In N LA the opportunities are fewer for conventional plays except where low permeability, over pressure and liquids combine to make horizontal drilling economic. The Cotton Valley wet gas plays have managed to remain profitable and the Terryville Field is experiencing an amazing rebirth owing to technology.
Depending on how costs rebound $75 might make the better TMS rock worth the investment however the low number of wells leaves much of the acreage untested.
If $75 was a reality and costs didn't get out of hand with increased domestic drilling, would mineral owners consider making the profit margin marginally better for TMS operators by accepting lease terms somewhat less than those offered when oil was $100/barrel?
Thanks for starting an interesting discussion, I learn quite a bit from folk like you and TC and others. Unfortunately I just don't know enough about the O&G stuff to really participate at an educated or high level in these discussions, but I can add some neophyte thoughts.
In the end the same thing that is hampering the TMS might end up contributing to it being developed in a different manner than the "plays" that we have seen roar for years; namely the cost. Many of the companies that came in did not spend outrageous sums on the "land" in the TMS and that might save them and or some other operator going forward.
I did some rough calculations using what I believe are going to be close to average land and royalty costs in the TMS to what some of those costs might be in the other more developed plays and assuming the oil in the TMS can get "got" consistently and the wells become somewhat more repeatable I think the TMS could possibly be viable.
For instance I would imagine that quite a few leases are going to lapse and the new terms on these leases will probably be bonus money between $100-200 an acre and 3/16th royalties will be offered. That is 18.75%. Whereas in some of these other plays royalties are probably close to 25% and the bonus money paid out at the height of the good times might have been, probably on average, around $4000 an acre.
Using 350K EUR for a well on a 1500 acre unit, with a $4.00 premium on LLS (for the TMS) at $61.00 a barrel for oil the difference in costs for the wells is above $5.5 million dollars on 350K EUR.
I do not think the common mineral owner in the TMS will see 20-25% royalties offered again nor bonus money over symbolic amounts. If the price of oil stabilizes between $65-80 over time, there will likely be some ongoing or continued development at a slower pace by smaller operators that can work off lower profits/returns. But who knows as the lending environment is going to be much, much different going forward.
That's a good way for a mineral owner/lessor to think about their mineral assets. There is no income from minerals that are not produced. If I owned TMS minerals, particularly those in a proven location I would consider a lower royalty and bonus however I would attempt to trade my acceptance of those terms for better terms elsewhere in the lease. I would not execute the "standard lease" without a good Exhibit A page. For those who missed the opportunity to get horizontal and vertical Pugh clauses, no cost royalty (not necessarily the language supplied by the land company), surface use limitations/compensations, etc. the second time around provides the opportunity to address those important considerations.
I'm unsure that well costs will come down enough, and stay down, to make a 350K EUR work. Hopefully the decline rate will support something above that figure.
Cathy, at the end of the primary term, usually 3 years, the lease agreement will terminate unless there is an extension clause and the lessee chooses to pay the extension price per acre. If there is no extension clause the lessee may negotiate an extension of the term with the mineral lessor prior to the expiration date. If the lease is allowed to expire, which I think will be common, and the operator wishes to attempt development in the future they may offer a new lease. That appears to be the case in the example I cite in the discussion introduction. A member's lease expired without a well being drilled, I do not recall if there was an extension clause, and the land company representing the operator offered a new lease at slightly less bonus and royalty. The member was understandably disappointed but being a MS mineral owner he had the added concern of being force pooled under MS mineral law at the lower lease terms.
Thank you Skip for the reply. I apologize for the delay, in sending you my appreciation.