In this episode we answer listener questions about decline rates for unconventional oil and gas plays, leasing vs. forced pooling, and what happens when one operator buys an oil and gas lease from another operator.
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Now, let’s get to the questions:
I have a question; I know the production of a fracked natural gas well falls off greatly over the first few years, how long does it take before the well production flattens and stays consistent with very little decreases in daily output? Thanks in advance for your help! Butch.
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Hi Butch – to answer your question – it depends. That is, each formation has slightly different characteristics as to how steep the initial decline rate is and what the shape of the curve is. Generally speaking, most unconventional oil and gas wells start out with production fitting a hyperbolic decline (where the decline rate changes over time) – this is where you see the steep drop in production from month to month as you suggest. Then, once the decline rate reaches a certain amount, it should generally stay there until the well stops producing or becomes uneconomic to continue to operate (e.g. 7% or 8% is used by most investors/operators to model the exponential “terminal decline rate” for the Niobrara Formation in the Denver-Julesburg basin). As an example (in the DJ Basin again), the current parameters being used to forecast future production don’t show this changeover occurring until a decade or more after the well started producing. Other formations/plays may see this happen much sooner or much later.
Also, there may be variability depending on exactly where you are in a particular basin, with some wells having a more shallow decline in production over time vs. others in the same formation/basin. Another thing to keep in mind is that the decline rates may continue to increase as well spacing increases and we may find that this changeover to exponential decline occurs many years earlier as we continue to increase well density in these unconventional plays. In fact, the Wall Street Journal had an article that talks about this.
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My name is Crystal I would love to know the process start to finish on how and when the lease company is supposed to contact the land owner. I would like to know how long I have to respond, before I have no say or choice in the matter. I would be grateful to know more details in the process of leasing start to finish from the perspective of both the landowner and the leasing agent. What I have found online has only left me confused and scratching my head- the exception being the information you have graciously provided. The podcast has given me so much clarity, it has been like a breath of fresh air after suffocating in the unknown that is the “oil & gas lease perpetual saga”. Nevertheless, as a completely “new to the game” landowner with the potential for a lease, there are still gaps in my understanding of this process, I attribute this to the chain of events to my particular situation. Please allow me to give my set of circumstances and maybe you can offer insight.
(To paraphrase, she was contacted by the State’s commissioner of conservation regarding what sounds like a pooling order. A couple of months later she was contacted by a landman with a lease offer. 3 year primary term, $1000/acre for ⅕ royalty and says the company is planning on drilling in a couple of months…She contacted an attorney and her attorney has already had a lease that was similarly negotiated and agreed upon by that operator...
She also says: “With 1 acre it’s not worth anyone’s time- at least that’s what i’m getting out of it, nevertheless, my concern is for the potential liability I may be forced into. Also I’ve been contacted late in the game, or so that’s what I feel has happened, I don’t feel like I have the option to negotiate. What If i’m too late? What kind of liability will i incur if I don’t sign and I become a “silent partner” would i be better off signing or not? I feel like I will have to retain an attorney if i’m forced into being a silent partner, so this will be costing me money, and I don’t feel like I could profit enough to justify that expenditure. I’m really just not sure what to do, or if it’s worth it to do anything.” -Thank you –Crystal
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Hi Crystal,
Thank you so much for the feedback! I’m glad the podcast has been helpful. I’ll look into making a flow chart as you suggested.
I did a quick search on Louisiana statutes related to statutory pooling and found specific requirements outlined. If not, you can search for your state name and then “statutory pooling” to see if you can find the specific state statutes/regulations.
First of all, it sounds like you are doing all the right things. Your attorney should be able to advise on specific timing but it sounds like you have already given notice to the operator that you would like to sign a lease. Most operators want to ensure that they have “title clearance” to drill the well so they are not trespassing with respect to any unleased mineral tracts (as it sounds like happened in 2009). Since you have a lease that your attorney knows they have accepted in the past you should be well on your way. As a side note, even if they have signed leases with your neighbors, until they are filed of record with the county clerk they aren’t “official”. Based on that, it sounds like they are still wrapping up loose ends in your area and you likely still have plenty of time. I would imagine the last thing the operator wants to do is force pool you and have a disgruntled mineral owner on their hands. It is probably just easier for them to sign a lease with you (especially for only 1 NMA).
By becoming a nonconsenting mineral owner (e.g. forced pooled), in some jurisdictions you would then receive the statutory minimum royalty rate until which time the operator has recouped 200% (or whatever the penalty is in your state) of the initial drilling & completions costs. At that time, you would then back into 100% of the royalty in terms of a working interest (e.g. you would go from 12.5% royalty on 1 net mineral acre (if that were the state minimum) to 100% royalty on 1 net mineral acre); you would then also be liable for your share of the operating costs.
This is how things are structured here in Colorado but Louisiana (or your state) may be totally different so check with your attorney.
Generally speaking, most mineral owners are best off signing a lease and taking the royalty payment and lease bonus. You can check out our episode 6 on Leasing or Episode 8 Forced pooling for more information (if you haven’t listened to them already). Also, Episode 7: Working Interests for Mineral Owners, we talk about what happens if you decide to participate in a well…
That way, you don’t have to worry about any future financial liabilities and you can secure the highest royalty rate up front since most of the oil & gas is produced in the first few years of any new unconventional well. So your best outcome is to try to get the highest royalty rate so that your royalty payments are maximized. Also, the value of your mineral rights (should you ever decide to sell) is directly proportional to the royalty rate. For example if your royalty rate is 12.5%, a mineral buyer is generally going to only be willing to pay you ½ of what they would pay for the same tract if it were leased at 25%!
Anyway, I hope this helps. Good luck with everything and please let me know how things end up!
Matt
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Good Morning Matt, Great podcast, I found out about your podcast when you hosted for Mark LaCour. I have two leases in production in the Unita Basin and my question is, once your lease is in production can a new operator ( Encana ) change the lease agreement from the original operator ( Newfield ) lease? Thanks, Tom
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Thanks for your question Tom! You can hear Episode 158 of Oil & Gas This Week Podcast where Justin and I took over for Jake Corley and Mark LaCour and we answered some Mineral Rights Questions. I would encourage you to give it a listen!
Anyway, thanks for listening! First, let me say that I’m not an attorney so am not qualified to give you legal advice so definitely consult an attorney licensed in the jurisdiction where you own minerals if you need specific help. That said, in general when an oil & gas lease is assigned from one party to another, the terms of the lease do not change (whether it is still within the primary term or held by production).
I you are finding that you are running into an issue with Encana, I would suggest contacting their owner relations department and send them a copy of your lease. It may be that there was an error made with you account when that lease was input into the new operator’s system. Whenever a new operator is involved, it is always a good time to check your royalty checks to make sure they haven’t made a mistake with your deductions, royalty rate, etc.
I hope this helps!
Note: this information is being shared for informational purposes only.
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