“No-Cost” vs. no NGL’s…Pick your poison?

Oil and Gas Leasing Help
1

Hello. Wondering if anyone here has wrestled with this decision?

My family has multiple leases with Antero in Tyler and Wetzel Counties in West Virginia. Some were signed and expired, then resigned and/or renewed. Five or six are now producing royalties. So, essentially the number of leases has been more than a dozen at a minimum.

Initial contracts pre-dated the issue of “post-production” costs. Subsequent agreements included those costs. we successfully negotiated them out of most, but not all agreements. So, we have both. First, we encountered “Market enhancement” language, which has since morphed to “Gross proceeds”, metered at the well head" language. All have significant different meaning. For the newbies, those differences are difficult to comprehend until you see the results on a royalty statement. And by then, it is what it is.

We have now seen those royalty statements, and basically, it appears to boil down to this with respect to “No Cost” negotiations…

Contracts where the lessor agrees to their share of post-production costs, the royalty checks will include a commensurate share of the valuable NGL’s (Non-Gas liquids)…as well as substantial deductions for post production costs…

Contracts negotiated as, “Gross Proceeds”, “metered at the well head” agreements, will not have post-production deductions… but also will not share in the NGL’s.

Gas in this area is among the best “wet gas” in the nation. The NGL’s are plentiful and valuable…sometimes more valuable than the gas itself.

My son has run the numbers on the wells. His analysis on our samples indicated those wells where we pay post-production costs and share in NGL’s payed out 5-7% more in royalties than those wells where we payed no post-production costs but did not share in the NGL’s…

So…my question…is it, in fact, always better to negotiate a “No cost” lease if you give up your share of the NGL’s in wet gas areas?

Or…has anyone successfully found lease language where the lessor avoids post-production costs and still shares in the NGL’s?..

It seems the producers have found a heads you lose, tails we win scenario.

Thanks

2

If you have high BTU content then you have to live with some post-production costs. Operator’s will carry you to the plant but it’s heads up from there. Why would they pay the cost of a royalty owner’s plant products when it’s third party dependent? Again really depends on BTU content, but getting gross proceeds at the well head on wet gas will come at an extreme detriment to your royalty check.

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Thanks for the reply.

In all the threads on this forum I have read, this is the first time I can recall any argument FOR sharing post-production costs. It’s essentially a given to negotiate a “No cost” contract.

Very interesting.

May I ask what you consider to be “high BTU” content?

Thanks

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Well by textbook definition: High-BTU gas is a type of natural gas that contains more energy than normal natural gas. This happens because it has more heavier gases mixed in, such as ethane, propane, and butane. Regular natural gas usually provides about 1,000 to 1,050 BTUs of energy per cubic foot, while high-BTU gas provides about 1,080 to 1,150 or more. Specific gravity tells you how heavy a gas is compared with air. Regular natural gas is lighter than air, with a specific gravity of about 0.60 to 0.65. High-BTU gas is heavier, usually about 0.70 to 1.50, because of the extra heavier gases in the mix.

Appalachia isn’t in my wheelhouse. Not sure how much vertical integration a company like Antero has. If they own both the smaller processing plants and the downstream fractionation hubs (unlikely)… then possibly there is an argument to be made that a true gross proceeds negotiation is viable.

I’ve worked on both sides of this game and very specific debate about this with LO attorney in Texas. For the most part, midstream companies own the smaller plants and then sometimes it is further carried to somewhere like Mont Belvieu. The operator may have marketing agreements but it essentially is out of their hands to make these various plant products viable. Why would they be on the hook for the royalty owner’s share of that? This has been hard to explain to people, especially with three phase wells. (condensate/wet gas/residual dry gas). That’s why a good negotiation strategy is to have the operator carry you to the plant and then you are heads up. Should be no cost for transportation, on-lease processing, etc. Your oil component can be sold cost-free at wellhead.

Again, not sure about NE but your NGL cut should add a lot more than 5-7%. It typically doubles or triples my effective gas rate in Texas depending on circumstances. So, your only real alternative of a true “cost free” clause would be to sell the gas at the mouth of the well w/ no deducts and get a differential of NYMEX spot which of course means… no NGL’s.