That is exactly why you should not be based on gross proceeds. An operator selling to affiliate will sell at a discounted price and no royalty will be paid based on the real market value and their artificially set low market value. A good royalty provision will take care of that.
Buddy
Susan B said:
My CHK checkstub is impossible to read. Dry gas in Tarrant County selling at over 50% less per mcf than a similar Devon Barnett Shale dry gas well. Then, the marketing and production fees deducted. Of course, the gas is being purchased by a CHK "affiliated" purchaser.
I have to disagree with Buddy on this. Gross proceeds is not the problem but the lack of language that the royalty would be calculated from the first third party arms length transaction.
No argument with your post and I'm giving it consideration but I believe that to sell to a true, arms length third party that product would need to be of marketable quality.
John B Gustavson said:
And I would add: ... after the product has attained marketable quality.
I think that we are on the same page. I am thinking of the many cases, where natural gas needs additional treatment to reach pipeline quality. Examples are wet gas and sour gas.
r w kennedy said:
No argument with your post and I'm giving it consideration but I believe that to sell to a true, arms length third party that product would need to be of marketable quality.
John B Gustavson said:
And I would add: ... after the product has attained marketable quality.
I was just reading old posts today. I have this clause in my lease, added by my attorney in the addendums. I guess it is sufficient?
1. The royalties payable to Lessor hereunder shall never be charged with any part of the costs and expenses for exploration, drilling, development, production, storage, processing, compressing, marketing or transportation, except that Lessor's royalties shall bear its proportionate share of any severance, ad valorem, windfall profits or other excise taxes attributable to the production of oil and/or gas from the leased premises or lands pooled therewith
I think that we are agreeing. The devil is in the details, which is the language. I rarely do this, but this is an excerpt of the royalty provision of my Superior Professional Form:
3.(b) Affiliate of Lessee. For purposes of this Lease, an "Affiliate of Lessee" is any corporation, firm or other entity in which Lessee, or any parent company, subsidiary or affiliate of Lessee, owns an interest of more than ten percent (10%), whether by stock ownership or otherwise, or over which Lessee or any parent company or Affiliate of Lessee exercises any degree of control, directly or indirectly, by ownership, interlocking directorate, or in any other manner; and any corporation, firm or other entity which owns any interest in Lessee, whether by stock ownership or otherwise, or which exercises any degree of control, directly or indirectly, over Lessee, by stock ownership, interlocking directorate, or in any other manner.
3. (c) Gross Proceeds. For purposes of this Lease, “Gross Proceeds” means the total consideration paid by the first purchaser which is not an Affiliate of Lessee for oil and gas produced from the Leased Premises, except that (1) Lessor's royalty shall bear its proportionate part of severance taxes actually paid by Lessee attributable to production from the Leased Premises.In addition:
(i) If gas produced from the Leased Premises is processed for the recovery of liquefiable hydrocarbon products prior to sale, and if such processing plant is not owned by Lessee or any Affiliate of Lessee, “Gross Proceeds” shall include (a) the consideration received by Lessee (or any Affiliate of Lessee) from Lessee's (or any Affiliate of Lessee's) sale of such liquefiable hydrocarbons plus (b) the total consideration received by Lessee (or any Affiliate of Lessee) from the sale of all residue gas, less Lessor's proportionate part of severance taxes thereon. (ii) If gas produced from the Leased Premises is processed for the recovery of liquefiable hydrocarbon products prior to sale, and if such processing plant is owned by Lessee or an Affiliate of Lessee, “Gross Proceeds” shall include (a) 80% of the total consideration received by Lessee (or any Affiliate of Lessee) from the sale of all products extracted from such gas, plus (b) the total consideration received by Lessee (or any Affiliate of Lessee).
r w kennedy said:
I have to disagree with Buddy on this. Gross proceeds is not the problem but the lack of language that the royalty would be calculated from the first third party arms length transaction.
Buddy, I liked it best with your language (I'm paraphrasing here) that should post production costs or market enhancements be deducted for any reason that they would be added back in before the royalty was calculated. I considered that an elegant solution. I thank you also for a good definition of "affiliate".
RW, I know this a older post but, I received this by email ad would like to ask what should be added or deleted to this clause so a lessor can present it to the company. Thanks D.T.
Gross Proceeds
It is agreed between the Lessor and Lessee that, notwithstanding any language herein to the contrary, royalties payable on gas and gaseous substances, including casinghead gas, shall be based upon the MMBTu value of unprocessed gas at the wellhead, free of all costs, charges or deductions of producing, treating, compressing, transporting and marketing said gas to such purchaser, which royalty, however, shall be subject to such production and severance taxes as are properly allocable thereto.
DT, I think you need more language to pin down the price to Published field price or if there is no published field price, then the price from the nearest field where there is a published field price. What you have makes me think they could sell to an affiliate at a sweetheart price or simply tell you it sold for whatever they feel like.
It does look like it gets you away from them being able to charge your royalty with whatever amount they feel like at any given moment but you have to pin down where the price is set.
I think it likely, knowing producers as I do that all of those charges will be taken out of your first check, to see if you will complain and if you don't complain, those charges will be taken out forever.
DT said:
RW, I know this a older post but, I received this by email ad would like to ask what should be added or deleted to this clause so a lessor can present it to the company. Thanks D.T.
Gross Proceeds
It is agreed between the Lessor and Lessee that, notwithstanding any language herein to the contrary, royalties payable on gas and gaseous substances, including casinghead gas, shall be based upon the MMBTu value of unprocessed gas at the wellhead, free of all costs, charges or deductions of producing, treating, compressing, transporting and marketing said gas to such purchaser, which royalty, however, shall be subject to such production and severance taxes as are properly allocable thereto.
For Texas specifically (but recommended to all others), I would never want "value" and "mouth of the well" in the same sentence. You would want to calculate the production volume at the mouth of the well, but the value would be calculated based on gross proceeds, defined by additional terms - similar to what r w was explaining. This should help narrow down the fact that you want to be paid for all gas produced, including gas used for compression or other use on/off the lease, and also for gas that is lost in transmission. You will pay me on the production (number) measured at the well, but the value (price) at the market. While some states have better laws than others, Texas is not friendly when "valuing at the mouth of the well" because any additional clauses restricting deductions for compression, gathering, treating, etc., become useless. What makes me so angry about Texas is, there are no regulations (limiting the charges) for "local gathering lines" so they can deduct whatever amount they want for transportation if you are valued at the mouth of the well. In areas like here in the Barnett Shale where we have 1080 BTU gas, there really is no "treatment" necessary, but operators have taken advantage of a particular court case that says "if its valued at the mouth of the well, the operator can deduct charges for gathering, treating, compression, transmission" etc. I'm sorry but they are not treating anything here, we have great gas! But because the law allows, they rip us off due to the loop hole.
For the record, this issue and the battle continues. My mineral interests are primarily in Oklahoma. I have just received a lease that says:
In consideration of the premises the said Lessee covenants and agrees: to deliver to the credit of Lessor free of cost, in the pipeline to which it may connect its wells, a 3/16th part of all oil (including but not limited to condensate and distillate) produced and saved from the leased premises. To pay Lessor for gas (including casinghead gas) and all other substances covered hereby, a royalty of 3/16th of the proceeds realized by Lessee from the sale thereof, less a proportionate part of the production, severance and other excise taxes and the cost incurred by Lessee in processing gathering, treating, compressing, dehydrating, transporting, and marketing, or otherwise making such gas or other substances ready for sale or use, said payments to be made monthly.
I countered with an Exhibit "A," that said "Processing and transportation charges may be deducted only if they are reasonable and necessary and if they enhance the value of an already marketable product. In no event shall the Lessor be paid a price more or less than the price paid to Lessee by a nonaffiliated purchaser, provided that Lessee and it's joint interest partners alone shall bear any of the costs set forth above that are required to produce oil and gas and other minerals to get them in marketable condition."
I was informed my Exhibit "A" was unacceptable based on that clause. I believed I was being more than fair and reasonable. In the future, my Exhibit "A" will also include a clause that gives me the right to inspect meters and to audit.
I agree with you. And I do not like their phrase "...to deliver to the credit of Lessor free of cost, in the pipeline to which it may connect its wells,..." .
It opens up all the problems of what is a "pipeline". I testified as an expert many years ago in the Bridenstein case in Oklahoma, which dealt with that problem. Your choice of the term "marketable product" is good. The bottom line should always be that your royalty should be calculated at the first point at which the product is marketable.
Hi everyone I have been in the group for awhile now.
my family just finished probates and have 2 leases diff companies, we just received 5 years of royalty from 1 oil comp They charged us everything! Transportation to gasheads Our lease is for us not to pay that's what our leases say and now we find out the ATTORNEY that we have had all along says they cant go after the oil company for ripping us of because they work for them A BIG CONFLICT OF INTEREST PLEASE HELP!
Time to find another attorney. Your current attorney should be able to help you with that. If not, let me know which state you're in and I'll try to find someone for you. I'm a licensed WV attorney. No pressure to use me if you're in WV, by the way. You have to find someone you're comfortable with. There are several competent attorneys around, and you can find recommendations here on MRF if you search the forum.
I'm a unit holder in South Texas, a part of a pretty large and active operation. There are two numbers I see every year that no one has been able to explain to me why they are so different. First is the production volumes of oil and gas operators report to the Texas RRC each month. The second is the Supplemental K-1 I get every year that ties volumes sold that are reflected in my royalty payments. I've compared these numbers for the past 3 years. What I found was that only 40% of the oil reported to the RRC every makes it to my K-1. Only 23% of the gas reported to the RRC makes it to my K-1. I sure would like to know where it all went. Granted, there is going to be some processing loss but this is pretty significant. The percentages don't deviate more than a couple percent year to year. Any Ideas?