10 Net Acres Inherited in Divide Cty North Dakota - What to Do?

Oil and Gas Leasing Help
1

I am brand new to this subject of leasing and have found this site most useful. Thanks to everyone.

We are heirs to 10 net acres in Divide Township 161NR95W33, which is spread among two blocks. It was willed to us in 1954, and we just found out about it two weeks ago through a Landman who has offered to send a lease agreement. We would appreciate everyone’s advice on what to do with it. As I said, we are ignorant of this whole business.

Our section will be pooled with 3 others - 28, 21, and 16. One well (17275) has been producing since 2008 and the Landman said the royalties due us are in a suspense account, subject to a 50% penalty on cost as a risk payment. We are one of only a few owners who have not leased. Looking at the GIS map, it looks like most activity in Divide is west and east of us.

We would appreciate everyone’s thoughts on what to do. Any reason not to try and get at the royalties due us? Should we lease now, or wait? What range of bonus and royalty would be reasonable to accept? The inheritance is split among 2 sides of the family. Any benefit to negotiate as one, rather than two parties? Any advantage or disadvantage of putting the Standard 88 Lease on our own paper rather than signing the one being offered to us? Thanks in advance!

2

William, the 50% risk penalty only applies if someone has already refused a lease offer and also refused participation. If the landman just found and contacted you, you could not have refused to either lease or participate and you have to refuse both for the risk penalty to be valid. Maybe, Continental would like you to take 16% statutory royalty and accept a 50% penalty. At 108,858 barrels as of February, this well is probably paid out so if you participated, you hand them a check and they hand you a bigger check, and you collect 100% less cost of production from now on. Ask the landman who refused the lease or to participate, if you were just found? Either they lied or don’t know what they are talking about, period. NDCC 38-08-08 is recommended reading, you can find it online.

The first well was not that bad, considering the state of completion techniques of its day and their porpoising in and out of the desired zone, they learned a lot from this well. The next well should be considerably better. The existing well is in the Three Forks formation, the next will probably be Bakken. They said they had fair oil shows in the Lodgepole formation also but the Mission Canyon appears to be bare. They did not say how many frack stages they used but I believe it would be low for wells of that time frame, possibly 10 stages. They didn’t go overboard with the use of sand either which probably isn’t significant because sand fracks at that depth aren’t very effective anyway. Continental drilled a poor well that will produce for decades to come because the oil can’t get into the wellbore very fast. I have 5 wells just like it.

If it were mine, I would want to participate in it, since it’s paid off. Collect 100% less cost of production, take the tax write offs myself. I would put back at least 20% of the net income against future expenses. I would be ok with that as it’s probably at least 300% as much as a 20% lease. If the bills ever got higher than the well is paying, by law you can give your interest to the operator, you will be paid salvage value for your part of the well and no longer be responsible for the wells bills, you don’t have to worry about being operated to death.

The first well was on and will remain on 1280 acre spacing. Continental has received 2560 acre spacing for future wells in Sections 16, 21, 28 and 33. Continental has 6 wells permitted in the 2560 acre spacing. I would hope the next wells would be better with all they learned from the early wells. Continental has drilled 14 wells just south of your Section 33 so evidently there is some oil in the area.

Frankly, I would not lease, 10 acres is not going to scare them off. Your acres I would judge by the intended 6 wells and not the early, poorly drilled well that still makes money. I would participate or be non-consent. The newer wells are going to be lower cost since they are in a 2560 spacing, you can decide to participate or be non-consent on a well by well basis.

If you wanted to get out from under it entirely, you probably have a brief window to sell a working interest with a profitable well and 6 wells planned.

In my opinion it’s poor strategy to lease and then sell, it’s like driving a new car off the lot, having it depreciate 80% immediately and then selling it. If you lease, drain it to the dregs because that’s the most money you will get from it after leasing.

3

Mr. Kennedy: Whew! I just read this, and we inheriting siblings all are going to spend the next few hours trying to comprehend what you have written and what you recommend. Plus we will download NDCC 38-08-08 and study that as well. We thank you for your timely response and hope we can come up with some intelligent additional questions. We truly appreciate your expertise and the personal time you have put into this!! Thanks again and regards, Bill

r w kennedy said:

William, the 50% risk penalty only applies if someone has already refused a lease offer and also refused participation. If the landman just found and contacted you, you could not have refused to either lease or participate and you have to refuse both for the risk penalty to be valid. Maybe, Continental would like you to take 16% statutory royalty and accept a 50% penalty. At 108,858 barrels as of February, this well is probably paid out so if you participated, you hand them a check and they hand you a bigger check, and you collect 100% less cost of production from now on. Ask the landman who refused the lease or to participate, if you were just found? Either they lied or don’t know what they are talking about, period. NDCC 38-08-08 is recommended reading, you can find it online.

The first well was not that bad, considering the state of completion techniques of its day and their porpoising in and out of the desired zone, they learned a lot from this well. The next well should be considerably better. The existing well is in the Three Forks formation, the next will probably be Bakken. They said they had fair oil shows in the Lodgepole formation also but the Mission Canyon appears to be bare. They did not say how many frack stages they used but I believe it would be low for wells of that time frame, possibly 10 stages. They didn’t go overboard with the use of sand either which probably isn’t significant because sand fracks at that depth aren’t very effective anyway. Continental drilled a poor well that will produce for decades to come because the oil can’t get into the wellbore very fast. I have 5 wells just like it.

If it were mine, I would want to participate in it, since it’s paid off. Collect 100% less cost of production, take the tax write offs myself. I would put back at least 20% of the net income against future expenses. I would be ok with that as it’s probably at least 300% as much as a 20% lease. If the bills ever got higher than the well is paying, by law you can give your interest to the operator, you will be paid salvage value for your part of the well and no longer be responsible for the wells bills, you don’t have to worry about being operated to death.

The first well was on and will remain on 1280 acre spacing. Continental has received 2560 acre spacing for future wells in Sections 16, 21, 28 and 33. Continental has 6 wells permitted in the 2560 acre spacing. I would hope the next wells would be better with all they learned from the early wells. Continental has drilled 14 wells just south of your Section 33 so evidently there is some oil in the area.

Frankly, I would not lease, 10 acres is not going to scare them off. Your acres I would judge by the intended 6 wells and not the early, poorly drilled well that still makes money. I would participate or be non-consent. The newer wells are going to be lower cost since they are in a 2560 spacing, you can decide to participate or be non-consent on a well by well basis.

If you wanted to get out from under it entirely, you probably have a brief window to sell a working interest with a profitable well and 6 wells planned.

In my opinion it’s poor strategy to lease and then sell, it’s like driving a new car off the lot, having it depreciate 80% immediately and then selling it. If you lease, drain it to the dregs because that’s the most money you will get from it after leasing.

4

Mr. Kennedy:

Thanks again for the great information. We will take your advice and plan to participate in the existing well. In order to do so, would we contact the well owner, or would we go to the State to start the process?

We looked closely at the production of 108,858 barrels you quoted for the well and note that production came in at 250 BPOD but has since leveled out at 50 BPOD, declining rapidly in the first year. Is this production curve (attached) generally characteristic of these wells? And based on your knowledge of advances since 2008 when this well was drilled, what might we expect from the 6 additional wells to be drilled on 2560 spacing in Sections 16, 21, 28, and 33?

We are making an attempt to get a feel for what a market-related lease bonus for our acreage might be. We note that leases at auction have gone for $1,000-3,000 due west of us, $2,500 due north, and $3,000-5,000 south and west. Would this information, along with our guesstimate of production rate, have bearing on a reasonable lease bonus for our acreage? What would you say our acreage should bring?

Thanks again for your time! Regards, Bill

1854-ProductionCurve.doc (26 KB)

5

Bill, your well, 108,000 barrels is right on the money for a November 2008 well, in my opinion.

Just south of you there is a well completed in November of 2010 and it has produced 105,000 barrels although it is two years newer. That is the difference 2 years improvement in completion tech makes. I don’t think they have come as far in the last two years but I’m sure they have made some improvements.

Bill, negotiating the lease bonus can be subjective. You ought to be able to get at least as much as anyone else in the area got. I would start at $5,000, 20% no deductions for marketing or post production costs. That’s if you want to lease. They aren’t going to spend 42 million or more in that spacing because they don’t plan to get it back with a handsome profit.

6

Mr. Kennedy:

Thanks once again for the prompt, interesting, and useful reply. I really like your analysis that says $5,000 might be a good starting point.

To gain a full understanding of forced pooling, I have read NDCC 38-08 about 10 times and have focused on your discussions with Sara on the Group Forum. I am trying to make sure I understand the incentive for the developer to get owners to lease (rather than simply relying on forced pooling), and thereby what we have as leverage when negotiating the lease. Is the following the right way to look at our leverage?

We own 10 acres in a 2560-acre pool. Assuming we have been formally approached to lease, is the leverage we have with the developer = 10 acres/2560 acres X $7.5M MAFFE X 50% penalty = $14,650 per well? In other words, if they go ahead with six wells and have everyone leased up except for us, then they must pay a penalty of $14,650 X 6 = $87,900. And then, they can recover that amount from our royalty stream only after the well is paid up? Do I have this right?

Also, is it true that if we are non-consent, then our royalty is paid at 16%, rather than a negotiated rate of, say 20%, thereby lessening our leverage further with the developer?

Thanks again for all your help!

r w kennedy said:

Bill, your well, 108,000 barrels is right on the money for a November 2008 well, in my opinion.

Just south of you there is a well completed in November of 2010 and it has produced 105,000 barrels although it is two years newer. That is the difference 2 years improvement in completion tech makes. I don’t think they have come as far in the last two years but I’m sure they have made some improvements.

Bill, negotiating the lease bonus can be subjective. You ought to be able to get at least as much as anyone else in the area got. I would start at $5,000, 20% no deductions for marketing or post production costs. That’s if you want to lease. They aren’t going to spend 42 million or more in that spacing because they don’t plan to get it back with a handsome profit.

7

Bill, if you are force pooled, yours would be a “carried interest,” the operator drills the well and pays for your part out of his own pocket. For doing this, not knowing that the well will be profitable and that the operator will get his money back, the state will allow the operator to impose a 50% of actual cost of drilling and completing risk penalty which may only be recovered from production. You never owe anything out of pocket until you have a working interest receiving 100%, less cost of production.

You receive 16% from the first barrel and 84% goes to pay for your part of the well and pay off the 50% of actual cost of drilling and completing of the well penalty. Many people look at this penalty and think 50%, that’s huge, but really it’s not. By my calculations, it would be about $29,300 per well X 50% just under $44,000. Sounds like a lot of money, and it is. You have to remember that 2/3 of that is for work done and physical property. You own that part of the well, not just the minerals. Your acres might have to produce 60 barrels of oil each to pay off that amount. Compared to the poor well you already have, which has already produced 84.3 barrels per acre and probably has decades of life left in it, does that sound so bad? Especially when we are talking about hundreds of barrels per acre over a period of decades.

Operators do not drill wells for a 50% penalty, they expect a much greater return than that, 300% or more is not unusual. Let’s do the math 50% goes into 300% 6 times, or 1/6 which is what operators offer mineral owners frequently, so by not leasing, you basically trade paychecks with an oil company on your acres. You make what the oil company would have made, or more. Believe me, they don’t like it one bit.

The most terrible thing of all is that it’s at no, out of pocket risk to you. In fact, you get paid 75% or more of what everyone who did lease gets, until your well pays out and recovers the penalty.

It would also keep your options open. When you lease, since they already have found oil, your options will be severely truncated, sell or keep the acres or possibly sell your royalty stream for a term. If you don’t lease, you will probably have the opportunity in the future, I still get offers from the operator, I wonder why that is? It’s because they are barely going to make any money off my acres. I could participate in future wells, I could enter into a farm out agreement with a partner for future wells. After my wells pay out I would sell a working interest in a single wellbore, retaining my mineral rights and a royalty and so on, and so on. You have all those rights right now as long as they have not sent the owner a lease agreement that was refused AND sent an AFE well proposal which was also refused or which lapsed after 30 days.

Yes, being non-consent you would miss out on the bonus, yes you will spend a few years receiving 75% of what others receive but you will make that up quickly when you start receiving 400% more than being leased would pay you.

Why do you think they pay a bonus? It’s the enticement to do something that is against your best interest.

It’s up to you, you can be making what the oil company would have made in a few years and be paid 75% or more what everyone who leased gets in royalty while you wait or you can lease, take the bonus and give the oil company 80%. Put another way, you have 10 acres, do you want to be paid a bonus and for the oil under 2 acres or no bonus and for the oil under 10 acres after expenses? I think you will have to be a tough and skillful negotiator to get $5,000 per acre, which is roughly 60 42 gallon drums per acre of oil. Imagine an acre with 60 drums on it, there is still a lot of empty space left. You already have a poor well that produced 83 per acre and is still going with decades to go. Can they buy you out with your own money?

8

Mr. Kennedy:

Thanks again for an excellent analysis. I finally get it. We are leaning toward forced pooling.

I see where you get the $44,000 per well, which will be paid off with 84% of our gross revenue less expense. My question is what is a good number to use for expense. I presume it includes all direct operating costs, maintenance, taxes and insurance, transportation, and marketing expense. Does it also include a number that represents amortization of future well workovers?

Forced pooling looks too good to be true. Even if we got $5,000 per acre paid-up bonus, leasing still loses out. What are the downsides of forced pooling other than a potentially poor producing well?

Thanks again for all your time and expert guidance!

Regards, Bill

9

Bill, there are some downsides but they are not as far down as leasing and losing the upside forever. Let’s look at them.

If there were no oil, you would have never received a bonus, but you already have a producing well and know there is oil there.

If there were no oil, the operator could place a lien against the production of your minerals that could only be recovered from someone finding and producing your minerals, you never owe out of pocket until you are receiving 100% less cost of production.

Mechanical failure: There is a slight chance they could lose the wellbore and abandon or have to do some serious work on the well. I have one like that, where they had to drill a new horizontal wellbore in a different formation. It’s rare but it can happen. You are going to get multiple wells though, your risk will be spread in a lesser way the same way the operator’s risk is spread, over multiple wells. If you get a dud, the good wells will have to pay off the bad. Continental drills a lot of wells and has a lot of money invested, you can count on them to do everything possible to make a profitable well. Unless half of the new wells are duds, you should still come out way ahead; if half of them are duds, you will probably make as much as leasing anyway.

Suppose, worst case, that the well pays off you are entitled to your 100% less cost and they notify you they intend to plug the well the next day? By law you can give your interest in that particular well to the operator who has to pay you salvage value for your part of the well and then you are no longer responsible for the well’s bills. You can actually get paid for the capping of your well!

Worst case the wells never pay off, you will always receive the 16% statutory royalty. It’s all about protecting the future upside. There may be other producible formations, 7 wells may not be able to drain that 2560 effectively. If you look around, people are happy with the initial flush production and dismayed when the production declines. As the production declines, your wells are paying off and you have a second, much longer period to look forward to where you may get several years of checks larger than those with 10 acres who leased. The odds are greatly in your favor that nothing very far wrong will go wrong with any of these six wells; if something did happen to one, you still will make more, just not quite as much more from the rest of the wells. The only guarantees are 16% royalty and you never pay anything out of pocket until you are receiving 100% less expenses.

The expenses can be laughably low. I have a 4-year-old well producing 2,000 barrels of oil a month that costs $1.40 a month per acre to operate, that was after the cost increase. That will not be your bill anyway until you are receiving 100% less cost of production. You don’t have to pay anyone a 20% royalty, you are making as much as 1/3 more than the operator, with that extra money, if you can’t pay the well’s bills, the operator will be in a much worse position. If the well was losing that much money, I think the operator would choose to abandon it and if he does not, you can give it back to him and he pays you the salvage value of your part.

As for the legal part, consult a lawyer, I am satisfied with what mine tells me, but I am not going to give legal advice. I will give a piece of business advice, after you become a working interest, form an LLC and lease your interest to it, 90% royalty or so, with all the clauses in your favor. If someone sues the LLC, they get your lease and still have to pay you the royalty. If the LLC does not make enough money to pay the bills, you can loan it the money. Chesapeake sets up LLCs to do business from and keeps it broke to limit their liability; if they can do it, you can do it. If you want to figure out how to protect yourself, watch the crooks.

10

Mr. Kennedy:

Thanks for this great analysis of the downside business risk of going non-consent. We are now looking to find a lawyer from North Dakota to help us with the legal risks of doing so, to include the benefits of drawing an LLC to hold our interests.

We would appreciate your input on the economic model we have used to justify non-consent vs. lease. Our simple constant dollar model looks at the economics over a 20 year horizon, using well Elveida 1-33-H for the production curve and a whole host of assumptions.

We find that under the most realistic circumstances - $100/Bbl LLS USGC posted price and production costs of $20/Bbl, non-consent wins over leasing by $17,500 for our 10 acres, which would say we would be indifferent to lease vs. non-consent at a negotiated bonus of $2,750/acre for well#1 (1,000 + 1,750). What is your immediate reaction to this?

The independent variable most affecting the analysis is production cost. For this model we assumed $20/Bbl – comprised of $2/Bbl of well operating cost, $5/Bbl gathering and throughput expense, $12/Bbl rail transportation cost, and $1/Bbl marketing expense.

We have attached results from this model and would really appreciate your input.

Thanks once again!!

r w kennedy said:

Bill, there are some downsides but they are not as far down as leasing and losing the upside forever. Let’s look at them.

If there were no oil, you would have never received a bonus, but you already have a producing well and know there is oil there.

If there were no oil, the operator could place a lien against the production of your minerals that could only be recovered from someone finding and producing your minerals, you never owe out of pocket until you are receiving 100% less cost of production.

Mechanical failure, There is a slight chance they could lose the wellbore and abandon or have to do some serious work on the well. I have one like that, where they had to drill a new horizontal wellbore in a different formation. It’s rare but it can happen. You are going to get multiple wells though, your risk will be spread in a lesser way the same way the operators risk is spread, over multiple wells. If you get a dud, the good wells will have to pay off the bad. Continental drills a lot of wells and have a lot of money invested, you can count on them to do everything possible to make a profitable well. Unless half of the new wells are duds, you should still come out way ahead, if half of them are duds, you will probably make as much as leasing anyway.

Suppose, worst case that the well pays off you are entitled to your 100% less cost and they notify you they intend to plug the well the next day? By law you can give your interest in that particular well to the operator who has to pay you salvage value for your part of the well and then you are no longer responsible for the wells bills. You can actually get paid for the capping of your well!

Worst case the wells never pay off, you will always receive the 16% statutory royalty. It’s all about protecting the future upside. There may be other producible formations, 7 wells may not be able to drain that 2560 effectively. If you look around, people are happy with the initial flush production and dismayed when the production declines. As the production declines, your wells are paying off and you have a second, much longer period to look forward to where you may get several years of checks larger than those with 10 acres who leased. The odds are greatly in your favor that nothing very far wrong will go wrong with any of these six wells, if something did happen to one, you still will make more, just not quite as much more from the rest of the wells. The only guarantees are 16% royalty and you never pay anything out of pocket until you are receiving 100% less expenses.

The expenses can be laughably low. I have a 4 year old well producing 2,000 barrels of oil a month that cost $1.40 a month per acre to operate, that was after the cost increase. That will not be your bill anyway until you are receiving 100% less cost of production. You don’t have to pay anyone a 20% royalty, you are making as much as 1/3 more than the operator, with that extra money, if you can’t pay the wells bills, the operator will be in a much worse position. If the well was losing that much money, I think the operator would choose to abandon it and if he does not, you can give it back to him and he pays you the salvage value of your part.

As for the legal part, consult a lawyer, I am satisfied with what mine tells me, but I am not going to give legal advice. I will give a piece of business advice, after you become a working interest, form an LLC and lease your interest to it, 90% royalty or so, with all the clauses in your favor. If someone sues the LLC, they get your lease and still have to pay you the royalty. If the LLC does not make enough money to pay the bills, you can loan it the money. Chesapeake sets up LLC to do business from and keeps it broke to limit their liability, if they can do it, you can do it. If you want to figure out how to protect yourself, watch the crooks.

1852-Leasevs.NonConsent.doc (69 KB) 1853-ProductionCurve.doc (26 KB)

11

Bill, I think your numbers are somewhat pessimistic, but that is a good thing.

You left out an important factor, tax deductions. A good CPA will make you far more than he costs.

I believe that takeaway capacity is increasing and that the cost to transport oil is going to improve somewhat.

You also left out the gas which presumably will be sold when they drill another 6 or more wells. Gas is not a huge datum but it does add up.

The ELVEIDA, poor but profitable well that it is, is steadily approaching stripper well status at which point it will qualify for tax reductions.

I normally estimate production and severance tax combined to be 11.5% where you have 10.5% but I like to be on the conservative side.

I also believe that Continental, being in the production phase and having the benefit of up-to-date completion techniques and specific knowledge of the geology from wells drilled in the area, that the next wells will be better. I don’t think they are coming back to drill 6 more ELVEIDA type wells, but if they did it should still be profitable.

12

Mr. Kennedy:

I really appreciate your spending time with this. It means a lot and will go a long way in helping us maximize the value of our mineral rights.

I have recorded gas sold and will add that to the income stream. I will plan to put a value on it by applying a $/MSCF. Or would it be better to treat it as an EFO bbl with the thought that gas will eventually find its value on a BTU basis?

We will search around and get some preliminary free advice on tax treatment.

I will add some sensitivities showing lower total costs - down to say $15/Bbl.

As you previously recommended, I am looking at the production curves for wells completed after Elveida to see how much better they may be producing, thereby potentially improving economics of future wells. Of course we have no idea about geology of the formation, but at least will have something to look at. I am looking at all of Continental’s wells in the adjacent Upland field.

Thanks again for your help. Would appreciate any additional input you may have.

13

Luke:

Thanks for your advice. I will plan to construct a simple A.T. DCF analysis looking at this from the carried interest owner’s perspective, then compare it to the royalty owner. I have done many economic analyses for downstream assets, but none for the upstream, so would appreciate your advice - and everybody else’s advice - on what goes into a DCF analysis for upstream assets. A few specific questions:

  1. What should I assume for economic life. I plan to use 20 years, with straight line depreciation against a $7.5MM single well expenditure

  2. What is a good tax rate to use against net BT income?

  3. How do I treat salvage value? Does a well get sold off in stripper status late in life and is that the salvage value? Or is salvage value assumed to be simply the value of used equipment. What is a good number to use?

  4. Do all well capital investments get treated the same. For example do pumps, above ground piping, tanks, compressors, etc. get treated the same as the well itself? What is a good number for the investment split between the well and the well auxiliaries?

  5. It would be very enlightening to get an example well AFE, including accompanying economic justification, as a model to use in doing our analysis. Do you know how I can get ahold of one?

Thanks again for your advice!

14

Bill, gas is hard to quantify. Mine has sold for anywhere between $5 and $9 a MCF for the last couple years. You can’t be certain if it will sell and for how much. On a typical group of my wells I received $5.21 per MCF sold in March.

While I am not privy to Continental’s geologists reports and the Bakken is not as homogenous as many people think, I am capable of evaluating what I see on the GIS map.

To answer your question about salvage value, it is the equipment, pump, casing, tanks and so on.

I would be in no hurry to get rid of a stripper well unless it consistently lost money. The well may sit without the pump running for a month to allow oil to migrate into the wellbore where it can be pumped out in a couple of days. Possibly one third of the well’s total production may come after the well has stripper status and a tax reduction.

15

Mr. Kennedy:

Thanks.

I will assign gas a value of $6.00/MSCF then play with it to see effect on the bottom line.

At your earlier suggestion, I looked at wells that had been completed later than our existing well to see what increase in production, if any has been realized. I found that for all 13 wells in the Upland field that have been completed 18 - 24 months after Elveida 1-33H (in the adjacent Sadler field), average monthly production data indicates that they produce more and produce earlier. The attached curve shows the findings.

In my DCF analysis, I will use 10% of AFE capital cost as salvage value.

Thanks again for all your help!

Regards, Bill

r w kennedy said:

Bill, gas is hard to quantify. Mine has sold for anywhere between $5 and $9 a MCF for the last couple years. You can’t be certain if it will sell and for how much. On a typical group of my wells I received $5.21 per MCF sold in March.

While I am not privy to Continental’s geologists reports and the Bakken is not as homogenous as many people think, I am capable of evaluating what I see on the GIS map.

To answer your question about salvage value, it is the equipment, pump, casing, tanks and so on.

I would be in no hurry to get rid of a stripper well unless it consistently lost money. The well may sit without the pump running for a month to allow oil to migrate into the wellbore where it can be pumped out in a couple of days. Possibly one third of the well’s total production may come after the well has stripper status and a tax reduction.

16

Luke:

Thanks again for your input. I appreciate it very much.

I did find that younger wells in Upland produce slightly more than our existing Elveida 1-33H well, so will include higher production as a sensitivity in my analysis.

For write-off, I will use your recommendation to write off 80% of the AFE year one, thus providing tax-free income for that year, then write off the remaining 20% on a straight line, 19-year timeframe, if that sounds right.

On salvage value, I will use a 10% figure, but 10% of 20% in year 20 will be nil in the DCF analysis.

For direct operating and maintenance cost I was assuming $2.00/Bbl, which is considerably less than the $10-25K you are suggesting. What should I assume comprises the higher figure?

Thanks again for your help!

Bill

Luke Aafedt said:

Bill,

  1. Use the same production curve as your first model. Also, 80% of the initial AFE will be intangibles and written-off immediately; the tangibles can be placed on your depreciation schedule. (Accountants may use an arbitrary 70/30 split, if you do not break down the AFE and each subsequent invoice yourself)

  2. Assume $0

  3. At this point, don’t make a final decision before the operator sends you the AFE. You will have 30 days from receipt to make a decision.

Bill, are you adding in monthly operating costs? These average $10k-$25K per month.

17

Mr Kennedy, Mr Aafedt:

Thanks so much for helping me prepare an economic analysis of leasing vs. non-consent, from the perspective of a mineral rights owner. I have completed an AT cash flow model and would appreciate your thoughts on what it says.

Attached files “Well Assumptions” and “Upland Well Production” show the basis for the model, and “AT Cash Flow” shows three cumulative cash flow curves - one for a non-consent owner, one for a lessor owner with a negotiated bonus of $1,000/acre, and one for a lessor with $0 bonus.

The analysis takes depreciation into consideration, assuming an immediate 80% write-off, with 20% written off over 20 years. We have taken no other tax breaks into consideration.

The analysis is in constant dollars. Cumulative AT cash flow for the non-consent owner exceeds that for a zero bonus lessor after 100 months, and after 150 months for a $1000/Acre lessor. The relevance of zero bonus is wells 2 through 6 that will be drilled on our property.

Looking at this analysis in then current dollars and applying a risk/discount factor of anything over 5% will immediately favor the lessor.

I would appreciate any comments you may have on this. We are meeting next week with an attorney to get a good feel for legal implications of being a carried interest partner, so that will enter to our decision as well.

Thanks in advance!!

William Buckalew said:

Luke:

Thanks again for your input. I appreciate it very much.

I did find that younger wells in Upland produce slightly more than our existing Elveida 1-33H well, so will include higher production as a sensitivity in my analysis.

For write-off, I will use your recommendation to write off 80% of the AFE year one, thus providing tax-free income for that year, then write off the remaining 20% on a straight line, 19 year timeframe, if that sounds right.

On salvage value, I will use a 10% figure, but 10% of 20% in year 20 will be nil in the DCF analysis.

For direct operating and maintenance cost I was assuming $2.00/Bbl, which is considerably less than the $10-25K you are suggesting. What should I assume comprises the higher figure?

Thanks again for your help!

Bill

Luke Aafedt said:

Bill,

  1. Use the same production curve as your first model. Also, 80% of the initial AFE will be intangibles and written-off immediately; the tangibles can be placed on your depreciation schedule. (Accountants may use an arbitrary 70/30 split, if you do not breakdown the AFE and each subsequent invoice yourself)

  2. Assume $0

  3. At this point, don’t make a final decision before the operator sends you the AFE. You will have 30 days from receipt to make a decision.

Bill, are you adding in monthly operating costs? These average $10k-$25K per month.

-luke

1848-WellAssumptions.xls (17 KB) 1849-UplandWellProduction.doc (25 KB) 1850-ATCashFlow.doc (25.5 KB)

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Mr. Kennedy:

This post has guided us for the past three years. I thank you again for the sage advice.

We used a law firm in Fargo to manage the probate process and it is finally complete. We are about to approach operator Continental, and would appreciate your thoughts:

  1. At your recommendation, we are going to ask Continental to send AFE’s for both the existing well and the six new wells. Based on your experience, is this a normal practice for owners like us, or will there be reluctance from Continental to accommodate us?

  2. Also at your recommendation, we will likely choose to Participate. Will the AFE for the well drilled in 2008 be subject to escalation to account for inflation, to include our up-front investment?

  3. If any of the heirs choose to lease in the earlier well, will they receive the lease bonus as well as the royalty payments, and if so, will those monies in arrears be escalated for inflation?

Thanks again for all of your help. We appreciate it very much.

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William, Continental would be very happy to send you an AFE, it is one of the prerequisites before they could seek to impose the non-consent risk penalty.

Secondly, the cost of the well is the cost of the well, there is no interest you owe on the costs to drill and complete the well. You may well have accumulated several years of operating expenses and that will be a second bill.

If any heirs choose to lease, they can still negotiate a lease with whomever they like, it need not be Continental, there is no deadline until after they receive the AFE and at that point they will have 30 days to negotiate a lease, participate or be non-consent. Being non-consent doesn’t mean you have to be non-consent in later wells.

The above is not to say that a lease could not be negotiated more than 30 days after receiving the AFE, just that after that point, you could only lease to Continental and I doubt that with a lack of competition that they would be making the best offer. My operators send me letters with each new AFE, with a lease offer or telling me if I would consider leasing to contact them.

Not being overburdened with money I had to be non-consent in several wells. It was galling to miss out on extremely good investments but I and my brother have recently participated in drilling of a new well and we will continue to do so in the future. I personally have bootstrapped my way into the business so I know it can be done.

It looks like Continental has 6 permits in Section 21, three of them named Elveida. Continental could drill 3 North and 3 South through your spacing. Three are named Bliss and three are named Elveida. I would say that Continental thinks the area has promise. I hope this helps.

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Mr. Kennedy.

This is exactly the information I was seeking. Thank you very much.

We are now ready to send all of the probate documents to Continental, with a cover letter asking them to send AFE’s for both the existing well, Elveida 1-33H, and for the six new wells (the three new Bliss’s and three new Elveida’s).

We are not flush with cash either, so participating may not be possible for us. It just depends on what the AFE’s tell us. I guess the question is how long it will take for the non-consent option to overtake the economics of leasing - and whether we will be around long enough to benefit from it.

Thanks again for all your help over the last three years. We would never have gotten this far without it.