I would like to know if anybody could provide approximately what % it costs the operator of the well to produce the oil? My main intention is to get an idea of what percentage they will take from my 100% after I'm force pooled, pay my percent of drilling the well cost and penalty and begin receiving 100% royalty, any help would be appreciated. Thank you.
Mike,
Every well operating cost will be different. Operating cost is influenced by the efficiency of the operator, success of the completion process, geology, product impurities, transportation, marketing, and every other non-fixed cost. The operator will charge an overhead fee that is predictable for a period of time until it is changed to meet the needs of the operator to provide the overhead attention to the well. The more "skin" the operator has in the game (Net Revenue Interest), the better the well will be operated and the better off the working interest owner will be. For a good well the total operating costs will start out as a small percentage of revenue then gradually increase to a very large portion of the working interest revenue. Find a local petroleum engineer familiar with well operations (not exploration) in the area to provide you with info to more accurately assess your risk vs reward potential. Short answer, only deal with the highest quality operators as a working interest owner.
Under Ohio law with forced pooling you would get about 12%, no signing bonus, and no protection from any lease clauses.
Helo guys:
I'm really not sure how I got here from the Fayette County Texas Group; but, the discussion about forced pooling caught my eye. I know very little about "forced pooling"; but, I attended a Texas R/R Commission meeting a couple of months ago on the subject of Mandatory Forced Pooling. Anything with the word "forced" makes the hair roll up on the back of my head, so in my opinion if at all possible, from the mineral owners, perspective, it is best to stay away from it. The way I understand the ruling here in Texas is that the minerals that are force pooled will be alloted a 1/8 th (12 1/2%) working interest which will be held in trust for the mineral owner. I'm not sure how this works; but, I doubt there will be any money put into the trust until the well is totally paid off and all the expenses deducted. Remember that the oil company has the ability to hire accountants that are wizards with the pencil. Even though forced pooling gives me a tummy ache, I do believe there is a place for it; but, not even close to the way it is administered today. My thoughts are and I addressed these directly to the R/R Commission and sent these written comments to Barry Smitherman at the Texas R/R Commission during the comment period.
1. Forced pooling can be used only after every other negotiation tool is exausted.
2. Working interest royalty shall never be a consideration, too many opportunities to "cook" the books.
3. Royaly interest shall be equal to the average of the other pooled minerals.
In order to wrap this up, Mandatory Pooling is a hugh issue that could be developed into a workable situation without using it as a punishment or money grab tool.
Gary L. Hutchinson said:
Mike,
Every well operating cost will be different. Operating cost is influenced by the efficiency of the operator, success of the completion process, geology, product impurities, transportation, marketing, and every other non-fixed cost. The operator will charge an overhead fee that is predictable for a period of time until it is changed to meet the needs of the operator to provide the overhead attention to the well. The more "skin" the operator has in the game (Net Revenue Interest), the better the well will be operated and the better off the working interest owner will be. For a good well the total operating costs will start out as a small percentage of revenue then gradually increase to a very large portion of the working interest revenue. Find a local petroleum engineer familiar with well operations (not exploration) in the area to provide you with info to more accurately assess your risk vs reward potential. Short answer, only deal with the highest quality operators as a working interest owner.
Gary L. Hutchinson
Minerals Management
Force Pooling vs. Leasing
Force Pooling to a sophisticated person in the business need not cause a belly ache and has many advantages over leasing depending on the number of parcels controlled, the amount of risk capital available, time to monitor, and geologic pay zones in the area, the quality of the regulatory body setting the rates, to name a few. I have had clients that use force pooling as a part of the minerals management business plan. They set lease terms that eliminate the huge bellyache of leasing and loosing control of the minerals so that force pooling, if taken, can be as good or better than leasing under their terms. Force pooling also serves to provide fair treatment by operators. In my experience, Texas is the fairest, Colorado the most subject to politics, and North Dakota seems to favor the mineral owner while Oklahoma favors the operator.
Gary L Hutchinson
I agree that Oklahoma favors the operator. I have seen several situations recently where, under pooling, the first option was 1/8 royalty @ $700 per acre, followed by 3/16 royalty @ $600/acre, etc. A number of respondents "could not be found", and they were of course saddled with a 1/8 royalty. To me, this is almost inconceivable in an area of solid production possibilities.
In another situation, in a very hot area, I was aware that numerous people had been offered $2250 per acre for a 3/16 royalty, and $850 per acre for a 1/4 royalty. When the pooling order came it, it offered considerably less than this: $1500 for 3/16 royalty, and $0 for 1/4 royalty.
Do you know the process by which Oklahoma determines these operator-friendly figures? Or have I answered my own question.....