james, lacking appropriate no cost language in your exhibit your lessee may choose to deduct a number of costs per mcf associated with gathering, treating and transporting your gas to the sales point.
Maybe so. But if someone has 5 acres, there is just no way they can take the risk of hiring the "right legal team" to litigate over their 5 acres. That "certain lessee" knows this.
The reason I'm asking is that the lease I signed (see attach "exhibit A") has a cost free royalty clause (see paragraph #24) but I know other landowners in the same section as me and their lease does not have paragraph #24. I was wondering if, more likely than not, they would probably have royalty deductions since our leases differ in that respect but I should be in pretty good shape.....
Although I can't open the attachment, I can say that if the no cost clause was provided by the lessee or the land company representing them, the language is highly likely to be insufficient based on existing case law.
Here's the exact wording... I believe I could litigate that myself. It's pretty specific.
24. Lessor royalty herein is free of all charges and cost whatsoever including but not limited to production, compression, cleaning, dehydration, metering, detoxification, transportation, accounting, and marketing except that lessor royalty will be responsible for it's pro rata share of all taxes imposed on severance or production by any municipal, parish or federal agency.
You shouldn't assume that it would hold up in a court. The case law on the subject of deductions is complicated and only an experienced O&G attorney could provide an opinion of whether your specific language would be supported.
I think you need to also read the part of your lease about where in the chain the gas is sold. If the "certain lessee" (aka Chesapeake) sells the gas right out of the ground to its affiliated company, then you are not paying for "production, compression, cleaning....," because those things will occur later. However, you are getting a bad price for your gas, because it has not undergone all those good things. So it might be possible that you, technically, aren't paying for those things because your gas was sold (for a low price) before those things happened. But in reality you are paying for those things, because your gas was sold for a low price.
If you lease does not explicitly stipulate something about you getting the price after those things have happened, or state something about getting a price that would result from a transaction between unaffiliated parties, or a price that would be appropriate for sale into the interstate pipelines, then you may be stuck.p
It takes two things to make sure you get the good price - defining the correct point of sale, and the stipulation that you aren't paying for all those deductions.
Skip is right. Make sure you have an experienced attorney give you this language that will hold up in court.
(My Haynesville land has been leased twice, and never been drilled. When the second lease came up, I did not just re-use the Appendix A language my attorney gave me on the first lease. I figured that after 3 years, there was a lot more case law, and knowledge of what worked and what didn't work. So I asked him to update my Appendix A, with the latest legal thinking. It was worth the money to have peace of mind.)
I didn't think CEMI was still involved. I was under the impression that all Haynesville gathering, treating and transportation services had been taken over by The Williams Companies.
Excerpt from CHK Press Release
Chesapeake Energy Corporation Announces New Haynesville and Dry Gas Utica Gathering Agreements with the Williams Companies
Tuesday, September 08, 2015
Doug Lawler, Chesapeake’s Chief Executive Officer, commented, “Chesapeake’s operating efficiencies across the entire portfolio over the last two years have resulted in lower costs, higher production rates and higher recovery rates. Our improved performance in the Haynesville is the primary reason that we were able to negotiate new gathering rates. These agreements will result in lower gathering rates and lower differentials, making these assets even more competitive within our portfolio. In this capital constrained environment, we will benefit from these higher-return assets and expect to allocate incremental capital to these areas, while enabling Williams to more fully utilize its gathering systems. The commercial solution these new contracts provide will only enhance what we have already achieved with our operating performance. This is truly a win-win for both companies, and we continue to work with Williams to further enhance the value of our respective assets.”
Chesapeake will move to a fixed-fee agreement in the Haynesville Shale beginning in January 2016. Gas gathering fees in the Haynesville will be reduced on a unit basis, and the existing minimum volume obligations are expected to be met with the consolidation of two gathering systems and a projected increase in Haynesville area volumes. Inclusive of previously expected MVC shortfall payments, the company’s gas production is expected to see improved gathering rates of approximately $0.20 per mcf in 2016 and 2017 and approximately $0.30 per mcf in 2018 and beyond. As part of the transaction, and consistent with Chesapeake’s current operating plans, the company committed to turn 140 equivalent wells online before the end of 2017. This commitment is projected to result in significant production growth in the Haynesville Shale asset over the next two years, thus also increasing Williams’ revenue from the area.
Sorry Skip, at no place does the press release say that Chesapeake Operating does not sell the NG to CEMI at the wellhead at a price that deducts the G&T paid by CEMI(the press release just refers to the company lowering its costs with Williams or whoever the G&T provider is). CHK will do everything it can to report a price at the wellhead net of all the post production costs so the royalty owner bears it's share--even if the lessor has a "no cost" clause and particularly if it has a market enhancement exception. This is even though the NG is certainly not marketable until gathered and treated. With the overcapacity in pipeline, there is ample "market" at the tailgate of the gas plant. CHK sells NG to itself by having COI transfer to CEMI at the wellhead. It is bookkeeping!
Dang ! I wish I had all this knowledge before I signed that lease. I guess the difference between a wise man and a dummy is the wise man asks the questions before making the decisions and the dummy does it my way. You live and lean. Too bad you go thru life acquiring so much knowledge and then you "kick the bucket". Thanks again for all the info. Hopefully I'll get to use some of it or pass it along before it's too late......
No wells,..... I'm in 8N/12W/14 & 15. This is also the second time I've been leased but so far no drilling activity. This time though I think the chances are pretty good that something will happen.
There is a recently completed Vine O&G well in Section 4 and also alternate well applications by Vine for Section 9 and a Cross Unit Lateral well between 4 and 9. If you do get a well and your royalty receives deductions you can find out the person responsible for the pay deck on your well and send them a registered letter with a copy of your lease pointing out the appropriate clause. Never hurts to ask.
When royalty owners (yes I am one of those) complain about deductions, there is never any discussion about the huge investment the operator has made to allow the royalty owners gas to be sold at the sales point. Operators have invested a lot of money to get our gas to market. The company I work for does a lot of drilling in the deepwater Gulf of Mexico. We will spend $100 MM on drilling a well, but the cost of getting that oil to market may be five times that. We are paid when/if this oil/gas gets to the market site, not at the discovery site. The royalty owner in this case is the federal government (i.e. the taxpayer). They don't get paid until/if the oil/gas gets to the market site. Usually there are a lot of toll tags along the way to market. Just some perspective from the industry.
Hey Jay, I know you are a free market guy, as are all O&G guys until they want their next subsidy from the Feds or the State. BUT, the free market said the best offer we had in January 2008 was $150/acre bonus and an 1/8 royalty and a 3+2 year option. We got $20+/acre, plus 25% and only 3 year, no options.That is a free market!
In the spring of 2008 as the market accelarated, HK and CHK started promoting their stock and IP rates. Along the way, the smart(or big acreage and/or and well represented) landowners were told that the market would give you a "no cost" addendum. Aubrey and Floyd were ever onward and CHK would sign anything to get the deal done. CHK ultimately went to 38 or 39 rigs and AM said it would be 60 next year. Floyd said the same, but was smart enough to sell his company. Both Floyd and AM bought Gathering and Treating and pipeline capacity far beyond their vision.
Mostly, it didn't matter what your "no cost" lease said with CHK, COI sold the NG to itself(CEMI) at a price that deducted 100% of the G&T and Transport, and reported it "net" on the royalty statement so you never saw the hidden deduction of post production expenses prohibited by the "no cost" addendum.
I see your free market industry jargon about offshore among sophisticated people spending billions offshore. Plain and simple, among people who had enough acreage or smarts to demand a "going market" bonus, royalty and "no cost" clause, CHK cheated them. So then you can spend money to sue(got to have a lot of acreage or other assets) or compromise and take less than you bargained for. For his family, I am sorry AM is dead, but I hope he is very hot.
In January 2008 only two companies had generated the science to know that the Haynesville Shale was economic. That leaves about a dozen or more companies actively leasing in the same general area that knew nothing of the shale. For at least a couple of years previous to that date a number of those energy companies, large and small, were leasing for Cotton Valley development. Any claim that those other companies knew about the shale prior to CHK's April press release is not supported by any evidence I have seen.
A $150/acre bonus was quite common but only those foregoing professional assistance would think a one eighth royalty was the going rate. Once the shale announcement was made Floyd and Aubrey did go head to head in the area of their existing Cotton Valley acreage, south Caddo/north DeSoto. Their competition quickly made a quarter royalty the standard everywhere and bonuses increased based on how aggressive operators chose to be in their areas of interest. The lessors that received over $20,000/acre were a minority and most were large land owners. Most owners of modest acreage received $5,000-$10,000/acre which in fact was so far beyond the historic range that some companies simply refused to compete for leases. Of course CHK and others piled on the debt in order to continue their land rush. Big mistake, but that's all in the rear view mirror now.
Traditionally lessors were carried cost free to the well head and then paid their share of cost to treat and transport the gas to the point of sale. Owners of large land holding with good attorneys were getting custom leases with no cost language, Pugh clauses and royalty greater than one eighth as far back as the early 1970s. The crux of the problems regarding deductions are non-arms length marketing transactions (w. r.'s CEMI example), traditional charges that may not be applicable in some cases to dry Haynesville gas (dehydration) and the deducting of non-traditional costs such as stand by charges or recovery of capital costs to construct gathering systems.
If you wren't in CV area of interest, you probably never had an offer prior to 2008. That was my first ever experience after decades of cutting timber every 10 years and perhaps a hunting lease. So, in less than seven months, our offers went from $150 to $20+. I would only disagree with one thing, I would add a "non" in front of "arms length." To say that one wholly owned subsidiary of CHK, COI, negotiated with another wholly owned subsidiary of CHK, CEMI, when there was only one guy in charge of both, AM, seems a step to far.