I hold part interest in mineral rights in the Smith Creek Unit of Chesapeake. I have a portion of a couple of sections that belonged to my family. That said, for years the lease was with Ellbogen in Casper who never did too much so when it renewed I did it with Chesapeake. Part of my lease included a pooling into the Smith Creek Unit, the first producing well went online in December with a sister well next door and 5 additional permits filed mid January of this year. The wells are producing both oil and gas and, of course, water.
I received my first division order last week and my percentage of production is very low, what are the ramifications of being pooled, or in my case being part of a much larger unit? Also I noticed that since initial production (started last August) a substantial proportion of gas has been lost and a smaller proportion of oil...is this common? Each month it appears that the losses are smaller however they are still there.
Any advice on someone who might manage this kind of thing, I never really planned on this ever producing but now it is.
Thanks,
John
John:
My name is John Linden and I am also a mineral owner in Converse County. We originally leased our minerals to Chesapeake and then became part of a B-L-M deep unity that Chesapeake applied for. For a number of months I have been trying to determine how participation is determined when the minerals are in a BLM Exporitory Unit. I have spoken with a person at the BLM and also at the Wy O&G Commission. Then I read a paper on the topic written by Anadarko employees. So I know a little more than I did about participation, but nothing that I am certain about. From what I can tell, participation in a BLM Deep Unit is not determined the same way as if the well was just governed by the Wyoming regulations for participation.
There have been three wells drilled in our unit and one is pumping. The pipeline for gas is not yet in place, so I think they are flaring the gas. Is that your situation?
Send me an e-mail at [email protected] with your contact info and we can compare what we know and probably don't know. If you give me your phone number in that e-mail, I'll give you a call.
Thanks
John
I would like to talk to you and compare notes.
John,
I will send you an e mail. I do not know too much about the Smith Creek Unit however the well that is now online is on our former property. (32/70). According to the reports on the gas commission web site the well from August thru December produced 32000 barrels of oil and 178000MCF of gas, all sold, so I assume the pipelines are in place. I had received notice late last year where they (Chesapeake) had applied to flare two wells for up to 6 months............. Both of those applications were withdrawn and the next I knew was the division order. The second well is due online soon and as I mentioned they pulled 4 more permits in mid January all very close to the producing well.
Gents, here is the short version. Caution, your specific situation is likely to be more complicated than this (especially within the BLM unit). Yet this example using round numbers may explain it in general;
Say you own 64 NET acres of minerals under section 1 (640 GROSS acres). So your share is 10% of the minerals under Section 1. If your lease calls for 20% royalty, you'd be paid for 2% of any oil produced (20% of your 10% interest) under Section 1.
When your Section 1 is unitized with nine other sections you still own the same 64 net acres. However, the ten sections in this Unit are a combined 6400 Gross acres. So your share (64 out of 6,400) is 1% of the minerals under this new Unit. If your lease calls for 20% royalty, you'd be paid for 0.2% of any oil produced (20% of your 1% interest) under any of the ten section unit.
This may be why your decimal interest seems so small. When in a Unit; You have a much smaller piece of a larger pie. They may never drill (or produce) from your Section 1, yet within a traditional Unit, you're still paid (your smaller percentage) for anything produced within those other nine sections.
CAUTION: Though as with everything, IT ALL DEPENDS UPON THE LANGUAGE IN YOUR SPECIFIC LEASE AGREEMENT and/or THE UNITIZATION AGREEMENT. What I've written is only to convey the general concept. Crunch your own numbers and seem if they appear correct. If you have an issue you will need to hire professional help to either understand it, or resolve it. Good Luck.
Thanks very much for the reply. What you stated is pretty much what I thought. My lease agreement came with the unit agreement and it is apparent that the unit agreement takes precedent over the actual lease agreement. At some point I will seek guidance from an attorney that specializes in this kind of thing..........
Another topic, what is considered a "good well" in the Converse County area; I know its not Saudi Arabia and that there are management things regarding pumping, getting rid of the water etc. The summary on the first well showed heavy production during the first couple of months, slacked off then built again until December which was low. Am I wrong in assuming that weather may have an impact?
Thanks in Advance
John
Eastern MT said:
Gents, here is the short version. Caution, your specific situation is likely to be more complicated than this (especially within the BLM unit). Yet this example using round numbers may explain it in general;
Say you own 64 NET acres of minerals under section 1 (640 GROSS acres). So your share is 10% of the minerals under Section 1. If your lease calls for 20% royalty, you'd be paid for 2% of any oil produced (20% of your 10% interest) under Section 1.
When your Section 1 is unitized with nine other sections you still own the same 64 net acres. However, the ten sections in this Unit are a combined 6400 Gross acres. So your share (64 out of 6,400) is 1% of the minerals under this new Unit. If your lease calls for 20% royalty, you'd be paid for 0.2% of any oil produced (20% of your 1% interest) under any of the ten section unit.
This may be why your decimal interest seems so small. When in a Unit; You have a much smaller piece of a larger pie. They may never drill (or produce) from your Section 1, yet within a traditional Unit, you're still paid (your smaller percentage) for anything produced within those other nine sections.
CAUTION: Though as with everything, IT ALL DEPENDS UPON THE LANGUAGE IN YOUR SPECIFIC LEASE AGREEMENT and/or THE UNITIZATION AGREEMENT. What I've written is only to convey the general concept. Crunch your own numbers and seem if they appear correct. If you have an issue you will need to hire professional help to either understand it, or resolve it. Good Luck.
John, don't know specifics about typical Converse Co well, but yes weather can be a factor along with several other things. All wells produce their most initially, then have a natural decline curve which is steepest within the first couple of years... 200 bbls per day, 100 bbls per day, to 40 bbls per day, etc... Yet after that drastic drop a typical well may produce at a relative stable level for another 20 or even 40 years.
There are multiple reasons a well might have a rise in production after an initial decline; Possibly weather, the switch from a flowing well to one on a pump, increased production after addressing a lack of transportation (hooking into pipeline), and water disposal issues as you mentioned... Well I'd better get back to work. Hope this helps some.
The only time you win on a pooling or unitization agreement is if you don't have oil and gas under your property and you get the income off of other properties in the unit. We learned the hard way in the 1980's with Phillips 66. They pooled and unitized our properties with federal lands that the wells were dry on, we had the only producing wells and most of our production benefited the federal government - not us.
In our most recent Converse County lease, we reserved the right to approve unitization and pooling efforts and we also required payment for all gas used on site, whether flaring or to run their pumps. Some companies are using up tp 40 - 50 % of the production for the running of their equipment, pumps and compressors.
Good luck,
Ray
After hunting around for a week it appears to me that all of the new plays in Converse are in BLM Units. Appears that the BLM Unit Agreement takes precedent over an individual minerals agreement and although ones percentage remains the same, they are significantly diluted. As mentioned by another correspondent, a smaller piece of a larger pie. Further, if one elects not to participate in the unit agreement and they drill into your minerals, you will still be paid however all other benefits of the larger piece of the pie are lost, a catch 22!
John
We also hold interest in Smith Creek. A couple of questions: The sister well that you mentioned...any idea when we will receive a division order for that one? And secondly, when/if they (Chesapeake) drill in your actual section of the Unit is your percentage the actual percentage in your lease agreement or is it still diluted?
Thanks!
Jackie
Jackie:
You use the term "drill in your actual section". As John Giehm has pointed out in his Feb 19th response, most of the wells Chesapeake is drilling are located in BLM Exploratory Units. Smith Creek is a BLM Unit. One of the reasons Chesapeake has applied for these BLM Units is to drill a longer horizontal well which may start in one section and end in another section. As an example, in the BLM Unit we are a part of, a well is sited in Section 20. There is no well shown for Section 29 which is directly South of Section 20. But when you look at the map attached to the well permit documents, you can see that only about 1/3 of the well is in Section 20 and the other 2/3rds is in Section 29. In the BLM Documents, it is clear that well participation will not be in accordance with Wyoming law. The BLM and the Oil company will determine which mineral owners are participating in a given well. The BLM has a method they will use. But back to our example. The royalty for the owner of minerals is still 18.75%. But when Chesapeake sends you the Division Order, if your minerals are only 1/3 of the minerals being drained by the well, your participation will be adjusted accordingly. The calculation is shown on the Division Order.
As more of us receive Division Orders, hopefully we will be able to learn enough to post accurate information of how participation is calculated. In my case, it is too early and I am not yet certain how it will all work out. I'll keep folks posted as I learn.
John Linden