Option clause bonus

William_Erickson · October 25, 2012, 7:28pm

I have two properties that are getting ready to start paying royalties - division orders received. I am trying to determine if the producer missed the option clause period on one of them - primary term 36 months with option clause for additional 2 year extension. Lease dated 17 January 2008. The lease shall be for a term of 36 months from date of signing for as long as substances covered are "produced in paying quantities" from the Leased Premises.

How do I determine the date a well started producing in paying quantities? What form do I find that date on?

Also I received a Shut-in Royalty from this well so I am assuming at some point this well started producing in paying quantities but the producer was unable to get the product to market. This Shut-in Royalty was for a dated period after the end of the 36 month primary term. 5/6/2011 - 5/6/2012. The check was for $9.50 and I did not cash it.

Any thoughts?

r_w_kennedy · October 25, 2012, 8:38pm

If you have a well that already produced on a property the 36 month term probably isn't as important as what your lease says about being shut in if you have already received the shut in payment. I don't think it matters if you cashed the shut in payment or not. Look at the shut in clause in your lease, many have no definite period so the lease can be maintained virtually forever as long as the shut in royalty is paid. Some leases have a shut in period of 2 years or a cumulative period of two or more years. You may also want to look at continuing operations clauses. If the operator started work to drill a well before the 36 months were up and continued to completion with no stoppages longer than the grace period in your continuing operations clause, the lessee did not need to pick up the option because the 36 month primary term was automatically extended. The continuing operations clause is usually 60 days, 90 days, 180 days or sometimes 1 year. I think that if you read your lease again bearing all this in mind that you will have answered most of your questions. Good luck with your wells.

William_Erickson · October 26, 2012, 2:03am

r w kennedy, Thanks for the reply. I do have a Continuous Drilling Obligations clause in my lease. I will send the entire clause here in a day or two but no time right now. Briefly it talks about commencing operations for reworking an existing well or for drilling an additional well within 90 days after completion of operations on such dry hole or within 90 days after cessation of all production. The first well was not a dry hole and they have not drilled any other wells in our pooled land. Maybe the following will help: the lease was signed on 1/17/2008. primary term ended 1/16/2011. According to the G-1 report (Gas well back pressure test, completion or recompletion report, and log) filed on 4/11/2012 the type of completion is New Well, permit to drill was issued 10/20/2010, drilling commenced on 9/1/2010 and was completed on 9/18/2010. It looks like the pipeline connection was completed on 2/23/2012 and the gas measurement data test was completed on 2/27/2012. The volume MCF/DAY was 6786.0. It looks to me like they didn't start producing in paying quantities until 2/27/2012. In any event they paid a Shut-In Royalty for the period 5/6/2011 to 5/6/2012. So in my mind something just doesn't add up. This is why I'm trying to determine the date the well started producing in paying quantities. I'm trying to clear this question up first. Thanks for your help.

r_w_kennedy · October 26, 2012, 5:25am

Mr. Erickson, it sounds like you were shut in appropriately for lack of a way to market your gas because the pipeline was not yet completed so they paid you the shut in royalty because they had drilled a well capable of producing but did not yet have a way to take production away, to market that is. I don't see anything that might be wrong that they couldn't plausably explain away. A court action would be expensive, possibly as much as $100,000. I believe that operators do extremely irregular things all the time, the thing is you have to prove that they did it and they are very slippery.

Penny_Macias · October 29, 2012, 3:28pm

William, do you mind sharing what state and country your property is located in? The reason I ask is because in Texas for example, if a well is capable of producing in paying quantities and the operator pays the shut in payment on time then the lease is held via that clause - no actual production is necessary. However, there's a lot of issue as to what "capable of producing in paying quantities" (e.g. is drilling the well sufficient to make it capable? or do you have to frac it and test it for it to be capable of producing?) and case law surrounding it. It gets very sticky.

William_Erickson · October 29, 2012, 4:45pm

Hi Penny, I apologize in advance as this response will be very lengthy. The quick answer to your question is the property is in Tarrant County, Texas. I am including 4 paragraphs of my lease for your review - Term, Option Clause, Shut-In Royalty, and Continuous Drilling Obligations. I have included the dates that I know in my previous posts. The questions I have are 1. With regard to the Term, when does "produced in paying quantities" begin? 2. With regards to Continuous Drilling Obligations, do pipeline connection operations satisfy this paragraph and if it does how can I determine when these operations started and ended? 3. with regards to Shut-In Royalty, if all these Lease requirements have been complied with - How would I determine when Shut-In Royalties should begin? And finally 4. If in fact Shut-In Royalties are to be paid isn't the anniversary of "said 90-day period" every 90 days?

The following are the paragraphs from my Lease:

2. Term. Subject to the other provisions contained herein, this Lease shall be for a term of thirty-six (36) months from the date hereof (the "primary term"), and for as long thereafter as oil or gas or other substances covered hereby are produced in paying quantities from the Leased Premises or from lands pooled therewith, or this Lease is otherwise maintained in effect pursuant to the provisions hereof.

3. Option Clause. Notwithstanding anything to the contrary herein, Lessee is hereby granted the exclusive option, to be exercised prior to the date which this Lease or any portion thereof would expire in accordance with its terms and provisions, of extending this Lease for an additional period of two (2) years as to all or any portion of the acreage of the Leased Premises. The only action required by Lessee to exercise this option being payment to Lessor of an additional consideration of the sum equal to the original cash bonus paid to Lessor as a bonus for signing the Lease, which payment shall cover the entire two (2) year extended primary term. Should this option be exercised as herein provided, it shall be considered for all purposes as though this Lease originally provided for a primary term of five (5) years. If this Lease is extended as to only a portion of the acreage then covered thereby, Lessee shall designate such portion by a recordable instrument.

6. Shut-in Royalty. If at the end of the primary term or any time thereafter one or more wells on the leased premises or lands pooled therewith are capable of producing oil or gas or other substances covered hereby in paying quantities, but such well or wells are either shut-in or production therefrom is not being sold by Lessee, such well or wells shall nevertheless be deemed to be producing in paying quantities for the purpose of maintaining this Lease. A well that has been drilled but not fraced shall be deemed incapable of producing in paying quantities. If for a period of ninety (90) consecutive days such well or wells are shut-in or production therefrom is not being sold by Lessee, then Lessee shall pay shut-in royalty of twenty five dollars ($25.00) per acre then covered by this Lease on or before the end of said 90-day period and thereafter on or before each anniversary of the end of said 90-day period while the well or wells are shut-in or production therefrom is not being sold by Lessee; provided, however, that if this Lease is otherwise being maintained by operations, or if production is being sold by Lessee from another well or wells on the leased premises or lands pooled therewith, no shut-in royalty shall be due until the end of the 90-day period next following cessation of such operations or production. Notwithstanding anything to the contrary herein, it is expressly understood and agreed that after the expiration of the primary term, Lessee shall not have the right to continue this Lease in force by payment of shut-in royalty for more than one single period of up to two (2) consecutive years.

8. Continuous Drilling Obligations. If Lessee drills a well which is incapable of producing in paying quantities (a "dry hole") on the Leased Premises or lands pooled therewith, or if all production (whether or not in paying quantities) permanently ceases from any cause, including a revision of unit boundaries pursuant to the provisions of Section 9 or the action of any governmental authority, then in the event this Lease is not otherwise being maintained in force it shall nevertheless remain in force if Lessee commences operations for reworking an existing well or for drilling an additional well or for otherwise obtaining or restoring production on the Leased Premises or lands pooled therewith within ninety (90) days after completion of operations on such dry hole or within ninety (90) days after such cessation of all production. If at the end of the primary term, or at any time thereafter, this Lease is not otherwise being maintained in force but Lessee is then engaged in drilling, reworking or any other operations reasonably calculated to obtain or restore production therefrom, this Lease shall remain in force so long as anyone or more of such operations are prosecuted with no cessation of more than ninety (90) consecutive days, and if any such operations results in the production of oil or gas or other substances covered hereby, as long thereafter as there is production in paying quantities from the Leased Premises or lands pooled therewith. After completion of a well capable of producing in paying quantities hereunder, Lessee shall drill such additional wells on the Leased Premises or lands pooled therewith as a reasonably prudent operator would drill under the same or similar circumstances (a) to develop the Leased Premises as to formations then capable of producing in paying quantities on the Leased Premises or lands pooled therewith, or (b) to protect the Leased Premises from uncompensated drainage by any well or wells located on other lands not pooled therewith. There shall be no covenant to drill exploratory wells or any additional wells except as expressly provided herein.

Penny Macias said:

William, do you mind sharing what state and country your property is located in? The reason I ask is because in Texas for example, if a well is capable of producing in paying quantities and the operator pays the shut in payment on time then the lease is held via that clause - no actual production is necessary. However, there's a lot of issue as to what "capable of producing in paying quantities" (e.g. is drilling the well sufficient to make it capable? or do you have to frac it and test it for it to be capable of producing?) and case law surrounding it. It gets very sticky.

Penny_Macias · October 29, 2012, 5:10pm

Here's my disclaimer: I am not licensed to practice in Texas so don't rely on this as legal advice. I would recommend you contact a good TX oil & gas attorney - I'm sure you can find someone good in the Dallas area considering the Barnett Shale activity there.

This lease actually answers the questions I raised in my previous post as to when is a well capable of producing in paying quantities. It specifically says if it's drilled but not fraced then it is not capable of producing in paying quantities (second sentence of paragraph 6). Based upon that you're looking at when the well was frac'd - did it happen in time and if so was your royalty payment correct?

If you received a SI payment of $9.50 that would suggest you own 0.38 net acres (since SI payments are to be $25/ac). If you own more than that you might want to discuss with an attorney that the $ amount wasn't correct for the SI payment. There are aso many layers here and you should consider waiting to get your first royalty check to see if it's worth paying an attorney to fight over. You really have to balance the cost/benefit when you're talking about this sort of thing - find a calculator that will estimate your planned income over the life of the well and then see if that's enough to justify pursuing this any further.

One more thing - if you're entitled to drilling or production data under the terms of your lease make sure you get a copy of whatever you are entitled to. Sometimes a company won't provide it unless you make a demand for it or sometimes the lease says they only have to provide upon written demand. Look at your lease and see if you are entitled to that data. An attorney will want to see all activity with dates to put a good timeline together and having it ready and in order will save time and costs that it would take an attorney to put together.

Hope I've been of some sort of help.

William_Erickson · October 29, 2012, 7:22pm

Thank you for your quick response and your time. So I understand what I am NOW looking for is the fracing date. Where would I be able to find that? I will request that but I need to know what to request first (form). Also you are correct on the .38 net acres per Schedule "A" of the Lease. However, according to the P-12 Certificate of Pooling Authority dated 4/10/2012 I have .46 acres. This also concurs with the current interest number on the "Exhibit to Division Order" dated 10/9/12. I won't pursue that difference until I get an opinion on the other questions. Do you have an opinion on questions 2. and 4.?

Not holding you to "legal advice" just an opinion. I'm just trying to figure out if the producer is complying with the Lease. Not any easy task!! Thank you.

Penny Macias said:

Here's my disclaimer: I am not licensed to practice in Texas so don't rely on this as legal advice. I would recommend you contact a good TX oil & gas attorney - I'm sure you can find someone good in the Dallas area considering the Barnett Shale activity there.
This lease actually answers the questions I raised in my previous post as to when is a well capable of producing in paying quantities. It specifically says if it's drilled but not fraced then it is not capable of producing in paying quantities (second sentence of paragraph 6). Based upon that you're looking at when the well was frac'd - did it happen in time and if so was your royalty payment correct?
If you received a SI payment of $9.50 that would suggest you own 0.38 net acres (since SI payments are to be $25/ac). If you own more than that you might want to discuss with an attorney that the $ amount wasn't correct for the SI payment. There are aso many layers here and you should consider waiting to get your first royalty check to see if it's worth paying an attorney to fight over. You really have to balance the cost/benefit when you're talking about this sort of thing - find a calculator that will estimate your planned income over the life of the well and then see if that's enough to justify pursuing this any further.

One more thing - if you're entitled to drilling or production data under the terms of your lease make sure you get a copy of whatever you are entitled to. Sometimes a company won't provide it unless you make a demand for it or sometimes the lease says they only have to provide upon written demand. Look at your lease and see if you are entitled to that data. An attorney will want to see all activity with dates to put a good timeline together and having it ready and in order will save time and costs that it would take an attorney to put together.
Hope I've been of some sort of help.