My brother and I have just been made an offer on NE/4 & NW/4 Sec. 34, 21N-04W, and Sec. 15 21N-04W, of $450.00 per acre, and 3/16ths.[This in my 1/8; my brother has twice as much on the same section(s)]. This is substantially the same offer we had a few months ago, but I like talking to this guy (out of Edmond), as opposed to the last guy (out of Norman) who was an insufferable jerk. We are tempted to go with this offer; Are there any pitfalls to look for in the contract that we should know about? Thanks everyone.
No options to extend , get depth clause , no deduction except taxes. Devon is becoming active in 21n-4w and was ordered to pay $550 for 3/16 in the pooling on section 5 & 8 that I found so far. There is one well I found in section 36 that tested 404 BOD & 606 MCF of gas Take your time. I'll look some more.
There are wells drilled or drilling from Sept to now, but no completion reports,under sections 6,8,23,24,25,26. 21n-4w there is one under 17 that tested 205 BOD 785 MCF of gas through a 40/64 choke . Take you time they can't go to the dance without you. In 22n3w they were up to $600. I'll look some more tomorrow.
This fellow in Edmond told me this is the only way he can get in as, according to him, through my brother and I, as Devon has the rest of it sewed up. He also told me that he only wants to drill a shallow one. The supposed representative of Devon, in Norman, whose offer we turned down, also offered us $450.00, and absolutely refused to go any more, unless we dropped the percentage to 1/8, and then he would go $650.00, if I remember correctly. This fellow, in Edmond, said $450.00 is the most he can go, with the 3/16ths. We (my brother and I) were about ready to go to Edmond and sign, until I saw the reply from you, Ron. I think that I should at least email him, and advise him that we can't go ahead at the moment, and that I'll get back to him later. By the way, I get the part about no options to extend, but I don't get the depth clause (and some other things). Also, this fellow in Edmond told me that he didn't think that the deep ones would pay off and that is why he just wanted to drill a shallow one. Most of what he told me went over my head, so I wasn't sure if was just blowing smoke. Thanks, Ron.
Tell him your thinking about leasing him the shallow interest and waiting on Devon to force pool the formations they want because they have been ordered to pay $550 for 3/16 in their last few poolings. If you lease to Edmond guy here are a few thing that could happen. He might drill the shallow formatiions but if Devon pools the deeper formation he would have two options. Lease to Devon for what looks like $550 for 3/16 and make a $100 on the lease and get the shallow formations for free if he kept them. Or take a Working interest in the well and pay his share of the drilling cost and get his share of the well. Or he could take the lease option with some of the interest and W.I. with some. You could tell him you are going to do a little more research on what they are leasing the shallow formations for and ask him what formations he had an interest in. The depth clause states they can only hold the formations drilled down to during the term of the lease (3 yrs. ) which you would get if they pooled you. There are other things you get if your pooled that you have to ask for if you lease. More on that latter. I am going to look around a little more. Any questions.
As I mentioned before, presently in 21N-4W there are 5 wells in various stages of drilling or production, but with no test results as of yet. They have a permit for a well in Sec. 25, a permit hearing today on Sec. 6, a pooling order dated 12/6/12 on Sec. 5, a filing for spacing on Sec. 33. On Sec. 25 the pooling order required them to offer $300 for 3/16th or $0 for 1/4th. Sec. 26 ordered $350 for 3/16th or $0 for 1/4th. When they report production on 23, 24, 25 & 26 the cash bonus figures should increase. To give you an idea of how the different royalty interest and cash bonuses mentioned above affect the people leasing, I am going to give you the test figures for Sec. 17 & Sec. 36 and show you what you would be paid after selecting the various options on the previously mentioned pooling orders. We will assume that the operators produce the well at 70% of the test volume. We will also use $80 for a barrel of oil & $3 per mcf (1,000 cubic feet of gas). In Section 17 the well tested at 205 bbl/day & 785mcf per day. Producing at 70% this well would produce an annual revenue of $4,807,000, which would be an annual revenue of $7,500 per acre. Based on those figures for 1 acre, a 3/16th interest would pay you $1,408 annually, and 1/4th interest would pay you $1,877. In Section 36 the well tested at 404 bbl/day & 606 mcf per day. Producing at 70% this well would produce an annual revenue of $8,760,000, which would be an annual revenue of $13,687 per acre. Based on those figures for 1 acre, a 3/16th interest would pay you $2,566 annually, and 1/4th interest would pay you $3,422. You can use these figures and multiply them by how many acres you have in a section to give you an idea of what you could expect with the different interests. These well cost $4,000,000 to drill. Let me know if you have any questions.
What???? OK, let's examine what's really going on and dispense with all the conjecture. The Devon-Vaverka 1-26MH (Sec 26-T21N-R4W) commenced producing 12/3/12 via ESP and flaring gas. It has produced 9350 BO in its first 33 days with significant decline and has averaged 75-100 BOPD the last few days. Gas sales commenced 1/4/13 at 650 Mcfgpd, 1/3 of original volume being flared. Based upon this short-term performance it would be reasonable to assume that this well will not likely payout, or if it does it'll be a significant number of years. Some of the acreage was acquired by Barton Land back in 2010, which was typically $75-$150 per acre bonus consideration range and 3/16 royalty. It was pooled for $350, representing the highest bonus consideration paid within contiguous acreage. The $550 you refer to (Sec 5,6 and 8-T21N-R4W) resulted from acreage contiguous to that and acquired by Chesapeake before they "pulled in their horns." That value has little if anything to do with this. Other activity: Williams 1-23WH (spud 12/11/12), Williams 1-24MH (spud 10/31/12), Wiliams 1-25WH, Geihsel 1-6MH, Geihsel 1-8MH (spud 12/31/12) and yet to be named horizontal via the Geihsel pad (Sec 6) in Section 5-T21N-R4W, are all either pre-spud, drilling, or awaiting completion. The McKee No. 1-36H (Sec 36-T21N-R4W) and Schoeling 1-17H (Sec 17-T21N-R4W) have been producing since 5/13/12 and 7/31/12, respectively. They have respectively recovered 20,000 BO/54,600 Mcfg and 12,000 BO/117,500 Mcfg. Therefore, I see little to support the "expected" cash flow numbers above. The other wells add little credence to the discussion in economic terms and are speculative by nature due to their status. Pertinent to the question: The Vaverka 1-26MH, which is a direct offset to this acreage. Would you offset this well? $4,000,000 D&C costs coupled with acreage and lifting costs... My point is: by inferring that Devon will pool this acreage and drill a well, given reality, is highly distortive and coercive. It is also incorrect to patently dismiss a viable offer to lease, particularly given the economic picture, and suggest that said offer is in some way manipulative (with an example extrapolating values from an inadmissible distance away) is equally disingenuous. I'm all for opinion and advice as this discussion allows, but I'm also an advocate for the truth, not baseless conjecture...which is exceedingly inappropriate.
Devon just started a well in 5 & 8 . 6 was to have a pooling hearing 1/8/12 . I don't know anything about what CHK. did but $550 was what Devon was ordered to pay and I bet they will be ordered to pay for 6. The wells you mentioned as pre spud, drilling or waiting on completions, 5 wells at a cost of $ 20,000,000 . What is Devon thinking they have ? The expected cash flow above was to show what a 1/4th & a 3/16th would pay because 34 would be subject to 1/4th if someone wanted it on all or part of their interest. 75 BOD and 650 MCF from sec.26 at $80 a B & $3 a MCF that would be somewhere around $2,862,000 a year. Half of that would would pay for a 5,000,000 well in less then 4 years. As for offset of Vaverka 1-26MH, Devon looks like they are drilling three. The well in 36 at $80 a BO and $3 an MCF would be $3,200,000 in 7 months . The well in 17 would be $1,300,000 in 5 months.
http://superioroilandgas.com/mississippi-limestone-emerging-as-top-...
http://newsok.com/northern-oklahoma-oil-field-has-growing-potential...
http://www.rigzone.com/news/oil_gas/a/118598/Osage_Updates_Ops_at_N...
http://www.ugcenter.com/US-Shales/New-Gulf-Resources-Ramp-Mississip...
http://www.oerb.com/Default.aspx?tabid=242
Goggle it and see what you can find. It's your money so do you research.
First of all, to clarify, the pooling applicant (in an uncontested case) provides testimony regarding their opinion of the values presented in the cause. In such a case the OCC generally finds on the basis of the applicant’s determination of values and consequent testimony. The applicant’s attorney actually prepares the order for OCC execution. So an “order” is derived from the applicant’s testimony, the OCC does not undermine values in such cases and it is basically procedural. So, in the cause you cite, Devon was “ordered” to pay based upon their testimony; so it’s not as if there was some arbitrary finding on the part of the OCC which determined values; the values were determined by Devon. And, of course values in 6 will parallel 5 and 8, they’re contiguous. I’m not entering this discussion to answer the question of “why” or “what.” Who knows…why did the chicken cross the road? … people bought subprime mortgage derivatives, too…so go figure. I noticed, upon inspecting the posts, that there was a high degree of naïve behavior and oversimplification. One post suggested, based upon published IP data, that the well would “payout” in less than 6 months. When in reality, the well will never payout. Otherwise the posts are replete with gross exaggerations, misinformation and patently naïve projection. Therefore, I thought it might serve mineral owners better to have at their disposal some cold, hard facts instead of a steady diet of garbage. Beyond that, I have interspersed opinion of economic viability based upon evidence, not fantasy. As an example: “75 BOD and 650 MCF from sec.26 at $80 a B & $3 a MCF that would be somewhere around $2,862,000 a year. Half of that would would pay for a 5,000,000 well in less then 4 years.” This well has declined 85% oil/67% gas in 1-month. The last 24 hrs 447.1 Mcfg, which if not a mechanical glitch, would be another decline of 200 Mcfgpd since 1/4/13. Do you really believe you can credibly extrapolate cash flow for a year, much less 4 years? And to profess to all who’re reading this that such is the case is absurd and a disservice to an intellectually honest discussion. Another example: “The well in 36 at $80 a BO and $3 an MCF would be $3,200,000 in 7 months . The well in 17 would be $1,300,000 in 5 months.” Respectfully, net to WI cash flow would approximate $1,400,000 and $1,000,000. Mind you, GPT is withheld (even though a horizontal credit is available for partial reimbursement) and operating expenses are, in some cases, very high. Therefore, this approximate revenue bears myriad additional costs which further erode profitability. If I take the lowest expectation of average reserves per well from the E&P players’ websites of 300 Mboe, then it’s not rocket science to conclude that all these wells that we have empirical data on are below average expectation. The well in 17 was an extremely expensive well due to mechanical complications, costing north of $6,000,000. These are facts, not speculative conjecture. So, I’m not trying to ruin the day, but you’re grossly distorting reality and anybody with a vested interest would be far better served by the truth, which will hopefully result in that person being able to make a better judgment call on how to play their hand: What are the consequences of results which fall short of expectation? Could that have a bearing on the leasehold market? If I have foreknowledge of this, might I want to extract the best lease terms I can as opposed to risking that my acreage will be force pooled, or not, in the future? What acreage is applicable in determining values under a force pooling? How will spacing units affect my minerals? These are the kind of real-world decisions people have to make and questions they seek answers to, as in some cases herein. Don’t handicap their options by spewing expectations and numbers which are ridiculous. Businesses are in business to make an “evil” profit…knowing if they are, or not, within a geographic area is kinda important. If you’d rather not have facts to make intelligent decisions, then say so. I’ll gladly resign from posting further.
Devon's testimony is under oath and their determination of values are to reflex the rates paid in the eight unit around the unit being pooled. that is" why" or "what". You have several Oil Co.s drilling as many as twenty well or more per Township as fast as they can . You are going to compare this to twenty or thirty years ago. All these Companies and none of them are making money and none know what they are doing ? The well in 36 is going from $3,200,000 to $1,400,000 because of R.I., G.P.T. and L.O.E.? How did you get that ? What would the average reserve have to be to make it all work ? What % of the 300 MBOE is Oil ? What kind of pay out would you be looking for ? In several Countries they came back and reduced cost by drilling several wells per location and Multiunit wells after they drilled the first well to hold the lease . I am not sure what you mean by spacing on these wells going to affect the minerals . Moving on I have an interest in a section, and in the section next to it they drilled the first well came back in the same year and drilled 6 more wells and are drilling my section now. That was not in this County, but my point is with a 1/4 th royalty I would get 33% more royalty then 3/16th on 6 well . Makes me look at that one time cash bonus different. Bonus started at about $350 about two years ago are at $1600 now The terms of the lease are as important as the bonus. There is a lot to think about and can be a lot of money at stake. Nothing is for sure do your research . Go to other County forums and read up . Stephens has a lot or people that will try to help with lease terms or anything like that, but there are others. Look around ask questions.