EDITED by Admin: This is not the place to solicit business...........Please use this discussion to share leasing tips and rates.
EDITED by Admin: This is not the place to solicit business...........Please use this discussion to share leasing tips and rates.
. . and your offer is?
. . or is this another "best deal" we can get kinda thing?
You approached ME by soliciting me in this forum. Put your best deal out here and let us be the judge about what you are calling "best deal" and "performance".
'cause "forcepooling" isn't all that bad in Colorado either.
Mineral brokers generally agree on a baseline for lease bonus and royalty. Then if they can negotiate better terms for you over the baseline, we split those 50/50. They also try to obtain surface use terms which are acceptable to the owner. Bonus and royalty is always relative to location of the minerals, percent of mineral interest owned, and amount of net mineral acres owned. So no one can legitimately put out a specific offer without having this information first. There is better success negotiating on behalf of larger parcels, or on smaller ones if grouped together. As to forced pooling, my view is that you lose your leverage on bonus, royalty and surface use, and end up with the lessee's standard form lease. I've been in the industry since 1979 and never saw a mineral owner who was happy to be force pooled. I'm sure there are some situations that work out however.
So, "standard" Landman offers are 1/8 or 3/16th mineral rights. (12.5% and 18.75%) . . . .AFTER "administrative" costs for that property's percentage of the overall section.
Colorado law requires property owners who are "force-pooled" receive 12.5% (min and can be contested to whatever the current rates are being paid out) multiplied by the pctg of property owned in the section pooled (600 acre standard sections),
So, a 100 acre owner in that section would receive 12.5x.06 = .75 % of that sections TOTAL output without any deductions for well or corporate costs. . . and after the well has doubled it's initial cost ($1.5 mil well would have to hit $3mil) a force pooled property owner would begin to receive a working interest in the well (less well costs) itself while a leased owner would remain in a fixed rights position( they would actually end up getting their percentage after the force-pooled person received theirs).
As far as surface use, Oil companies have NO right to access a force-pooled property short of a surface use agreement.
Sorry, in my opinion, all you're asking is for me to negotiate giving you a portion of a "bonus" then I end up taking a smaller royalty in the end. . could be mistaken, I have before. . but the lease allows more hands to get into the mix and that just doesn't make sense.
-not trying to be confrontational, just putting the facts out there for mineral rights owners to review as this forum is designed to operate. Please feel free to correct me as needed. I'm not above mistakes.
The nature of your question brings up issues that require a fairly lengthy answer. There are two main components to oil and gas revenue from a well. One is working interest and the other is royalty interest. In the typical scenario where a mineral owner executes a lease, he is paid lease bonus (X dollars-per-acre) upfront, and a specified share of production if the well is completed. Under this scenario the mineral owner does not participate in the costs of drilling or completing the well, yet still receives revenue from production. That is why this payment is called a royalty.
A working interest owner pays his share of drilling and completion costs, and in return receives a working interest share of the production after deduction of all royalties. The amount of gross working interest owned, less royalty, is called a net revenue interest. Usually the well operator and his partners own the working interest. For example, assume a simplified situation where there are four mineral owners, each of whom owns 25% of the minerals under a 640-acre drillsite spacing unit (the present size of Niobrara spacing units):
100% working interest in the well
(18%) royalty interest retained by mineral owner under the lease
82% net revenue interest to the well operator
From the first barrel of oil produced, each mineral owner gets paid 18% X 25% or a net 4.5% of production, typically after deduction of certain expenses (of transportation and gathering, but not of drilling or completion). The working interest owners get 82%. However the mineral owners have paid nothing to drill and complete the well, only the working interest owners have. In other words the mineral owners have not advanced any risk capital. If the well is not a producer, they don’t lose anything.
Due to the risk inherent in drilling oil and gas wells, the pro forma projections used by operators must justify the risk. They look for multiples in term of return on risk capital. In that way, the cost of dry holes is spread over the revenue of producing wells, and in the final analysis they make money.
Few mineral owners own enough minerals to be exposed to multiple wells, and even fewer have the risk capital available to drill and complete wells (Niobrara completions range between $3 to $5 million at present). Under the above scenario, a 25% working interest would be charged $750,000 and $1.25 million for drilling and completion costs. Say the well paid out 3 to 1 under an 82% net revenue interest with oil at $100/bbl. Over time, not allowing for cash discounting, the 25% working interest would receive $2.25 million before severance and other production taxes. Say this working interest owner had participated in a 3 well drilling program and one was a dry hole. The total investment would be $3 million and the total revenue would be $4.5 million (to a 25% working interest) for a 50% return on investment. There are no guarantees in oil and gas exploration, so is that return worth the risk even if you could afford it? Say two of the three wells were dry holes? Then you are upside down.
The mandate of the Colorado Oil & Gas Conservation Commission is the orderly development of natural resources. Therefore they have a forced pooling statute which makes it more difficult for mineral owners to block the drilling of wells by refusing to lease. Using the assumptions above, for a non-consenting mineral owner to obtain his 25% working ownership interest he would pay 25% of the drilling and completion costs, and in exchange would receive 25% of production revenues. But because most mineral owners cannot afford to pay such costs, the statute permits the operator to advance the non-consenting mineral owner’s expenses. In return the operator is entitled to recover, out of the non-consenting mineral owner’s working interest, 100% of his proportionate share operating expenses and off-site equipment, and 200% of his proportionate costs of drilling the well, before the mineral owner is paid his proportionate share of working interest revenue. During this time period the mineral owner receives a 1/8 (12.5%) royalty proportionately reduced to his mineral interest.
You could run hypothetical numbers on this scenario as well. I just don’t want to take up the room here.
Because many producing wells have a steep decline curve, the non-consenting owner’s working interest may not be paid much money until the most productive portion of the well is exhausted. Moreover, typical royalty percentages today are 1/6 (16.67% and north). If you own the surface, you also have less control over negotiations that could result in a favorable outcome to you for drillsite location, roadways, and other surface-related drilling operations. More favorable results arise from an equal bargaining position up front, in my experience,
Fortunately, forced pooling is a last resort for operators who have already acquired leases to most of the acreage they intend to drill. Last year the commission received only 62 forced pooling applications.
Based on the risk/reward scenario inherent in oil and gas exploration, the cost of drilling and completion, the 200% non-consent penalty applied to the non-consenting mineral owner’s working interest, the reduced royalty percentage, and the limitations on surface use negotiations, I don’t really see an upside to electing to go non-consent and be force pooled. The only situation would be if your minerals happen to be in a true sweet spot where the well produces high multiples of expenses, or where you own enough minerals that you are under multiple wells. Otherwise I just don’t see it. Hope this helps.
I am currrently very pressed for time, but. . .
I'm sorry, but I see several "holes" in your statement. . .where to start. .(no one is contesting the company's recovering their overhead for rig and service, so the contesting of capital is not an issue. The issue at hand is whether to use a landman to obtain a better deal than the offers as required in Section 7,d)
First, if you are force pooled, you are not paying ANYTHING out of pocket for the well drilling. It is all paid for "off the top" while you are receiving compensation for the minerals removed (just as it comes "off the top" for consenting lesees). Also, wells today are typically placed at section lines and more often than not, at corners allowing 4 sections to be "pulled from" at once (if it were possible to remove minerals from only under an individual section). Even a "consenting" or leased owner "pays" for the costs of production. . it is removed prior to his "share" of the mineral rights compensation or check for his portion of the royalties (as outlined in Section 7c of the State pooling guidelines).
Second, we are not talking about shallow, near surface drawn minerals, we are talking deep, multiple pumped wells off a single location, placed on section lines, not indescriminately throughout a section with no exploratory holes. Further, with today's technology, there is nothing you can say that convinces me that they leave a well "dry", they continue on a horizontal plane until reaching the mineral they were after (and prior research recognized it's presence). This new method of drilling reduces the number of wells (including dry hits) and the fewer wells that reach a larger area are also what aid in the reduction of the number of force pools as fewer land use contracts are required and thus reducing the number of "hold-outs" or non-consenting property owners.
That said, once the companies obtain section line owners (primarily corner owners), they can then attempt to get the majority of the property owners for that section to let their attys hash out which companies get which sections then apply to the State for the spacing units (as CHK did in Feb/Apr 2011). Which is another step toward force pooling. The amt of force pooling apps is only relative to the amt of property owners in the area attempting to be harvested. So in larger areas of say, Weld County, where property owners are owning large acreage, the amt of apps for force pooling would be dramatically reduced.
Best of luck with getting anyone to sign in the area, Red Sky left a sour taste in everyone's mouth that hasn't already signed on (apprently SOME are still waiting for their signing bonus checks from CHK).
I think there is some confusion over the interpretation of the forced pooling statute, and in practical terms how things happen in the day-to-day workings of the oil patch. Good luck!
In Araphao County, where I just upped a $2000 PAB and 3/16ths offer for 3 and 3 with the three kicker to be $2K, to a $3500 PAB plus 1/5th deal for 3+2 with the 2 being 150% on approximately 70 acres,-----
your share would be 1/2 of 70 of 1500, or approximately $50K, for the lease bonus,
plus (20-18.75) *.50= .625% for your share of the royalty increase,
plus 70*2500*.5=$87,500 for your share of the kicker?
Tell me that I did not get that right, because I am clearly doing something wrong.
Jeff Lavenhar said:
What we generally do is to agree on a baseline for lease bonus and royalty. Then if we can negotiate better terms for you over the baseline, we split those 50/50. We also try to obtain surface use terms which are acceptable to the owner. Bonus and royalty is always relative to location of the minerals, percent of mineral interest owned, and amount of net mineral acres owned. So no one can legitimately put out a specific offer without having this information first. There is better success negotiating on behalf of larger parcels, or on smaller ones if grouped together. As to forced pooling, my view is that you lose your leverage on bonus, royalty and surface use, and end up with the lessee's standard form lease. I've been in the industry since 1979 and never saw a mineral owner who was happy to be force pooled. I'm sure there are some situations that work out however.
OK, Buddy. . I got lost in some of that, but I want YOU in my corner ! LoL
Based on your input, am I correct in assuming that force-pooling is not the worst thing and that I can get them to tweak the numbers? I know that exploration has all but ceased here in Elbert Co, CO while the county commissioners get greedy and want rare, unique restrictions on the sites.
Thanks for your comment, I'm gonna try to work my way through your math (see you in a week- LoL)