Selling mineral rights in the Bakken field

Shales Bakken Shale
21

If a person could some how get a price for their minerals, any of them, that reflects the true value or even 80% of the value, then maybe you are right....if this idiom does not exist then it should, "Never sell your minerals" unless it is your last option....

Perhaps lease some of the acreage to use the bonus money to participate on the remaining unleased minerals.

But never sell.......I suppose without the math it is a matter of opinion...and minerals in McKenzie or Williams County...wow...no sale for sure unless the money was sweet......I would think hard if I could get $10,000 an acre on minerals I leased at 16%...but who is going to offer than much for just 16%.....like I said before...when you lease in ND and those minerals get produced during the lease, you just sold that remaining percentage to the operator...in the case of 16% that means 84% of the minerals got sold for probably $100 an acre and a pat on the back........non-consent is better than leasing in my opinion in most cases in Williams and McKenzie County.

You did say if the price was right........but who is going to offer the right price if we are talking about true value?

22

The oil companies usually use the excuse that they do not have to deal with title on state controlled mineral acres, so they pay less to lease privately owned mineral acres where they do have to be concerned with title.

If the oil company pays the state $10,000 per acre to lease their minerals in a good area, I see no reason that they could not pay a mineral owner $8,000 per acre for about 20 acres in the same good area, and use the $40,000 difference to run title on the privately owners acres.

I consider non-consent in a good area to be like flipping the script. The operator makes about 1/6th off the well by way of the risk penalty, the state makes 1/6th off the well in taxes and the mineral owner makes 2/3. For a poorer producing well, the mineral owner would make alot less than 2/3 [66%] but the well would have to be alot poorer to put you all the way down to royalty leasing percentages. This should not surprise, you have to have oil production to make decent money whether you pay up front participation, lease, or go non-consent. Leasing will not save you from a poor well, participation can be risky and in a poorer area it could be 10 years before your well pays off and retires the penalty for non-consent.

In my opinion, leasing then selling is the worst possible strategy. As Andrew says above, when you lease, you basically sold 80% to 84% / 87.5% of the oil in place once they drill a producing well on it.

One might ponder why, if someone would offer you $5,000 to $10,000 per acre to buy your mineral rights leased at 20% royalty, why the oil company did not offer to buy your interest for 5 times that amount? It's because in leasing, you are assuming risk with the operator! If they drill a rotten well barely worth producing, your lease royalty checks are going to be lunch money unless you had hundreds of net acres to lease. Usually the lease bonus is 1% or less of what the lessee thinks is there, and when you leased, you sold 80% for 1% or less, plus a royalty that may never amount to much. Don't let people tell you that leasing is risk free. The operator is 100% at risk for what he spends on the well and you are at risk that your royalty may be virtually worthless.

Operators frequently produce wells that do not even cover the cost of operations so they can keep your minerals because they may be able to "sell" by assigning your minerals to someone who wants to see if they have better luck than your operator. How big do you think your royalty checks will be if you get one of the above described wells? The promise of royalty is a risk that mineral owners take on when leasing. If you are on these forums for some time you will be amazed at how many threads there are on operators not paying, under paying, selling to an affiliate for half price and charging to death whatever is left over for post production costs and market enhancements. I consider leasing the riskiest activity you can engage in, in ND at least. In some states such as Texas or Wyoming you don't really have a choice except participation and they may not even allow that.

23

Never say never is my philosophy. I grew up hearing 'never sell minerals' but I sold some non-producing minerals in Montana and put the money in Prudhoe Bay Royalty Trust and it's done tremendously well, while Montana minerals have not performed well. On the flip side, I also sold minerals in Andrews County, TX in 2004, where I was desperate to pay a large drilling bill on a well that never did much gas in Okla. Those minerals are now putting gobs of money in someone else's account. So, every case is different and a careful investor has to go with their gut and accept the wins and losses.

Since this is a North Dakota forum: I have the same information as everyone else, and I'm engaged with it 40 hours a week, much of the best stuff comes from Continental Resources. So, they're saying at some point there will be up to 32 to 40 wells per spacing unit (spacing unit = 1280 acres). At this point, there is still an average of less than one well per 1280 acre unit across the 15,000 acre 'Bakken' play. That says to me there is tremendous upside out here as long as oil prices stay north of ~$70/barrel. But allow me to solidify my point, and always feel free to question anything I've said because this is a dynamic market and things change on a dime.

If 'Sue' owns 100 acres on a 1280 acre lease or drilling unit (keeping it uniform for comparison sake, though it rarely is) - she can lease to the oil company for $1,000/ac and 20% royalty.

Her bonus is $100,000 and monthly checks come in around $17,812 (100/1280 X .20 X 400 bbls X $95 oil X 30 days).

Assume the well produces the bulk of its oil, 300,000 barrels, in 5 years. Sue nets $445,000 from the well (300,000 bbls X $95 oil X (100/1280 X .20 royalty %) and $100,000 from the lease bonus for a total of $555,000.

Alternatively, she sells half her interest to Bill and participates in the well with the other half.

Sell 50 acres at $8,000 an acre and receive $400,000, no lease bonus this time.

Her cost to drill the well is ($8 million well X (50/1280)) = $312,000. She still has $88,000 left over to pay additional minor working interest bills that might come in.

Monthly checks will be around (50/1280 X 400 barrels X $95 oil X 30 days) = $44,531

In 5 years the well does 300,000 barrels and her net was: (300,000 X $95 oil X 50/1280) = $1,113,281.

Plus whatever is left over from the $88,000 above from selling half her interest.

Correct me, criticize me, shoot holes in it, all good, I'm trying to work up a win/win for the more adventurous out there -- but please don't bother correcting the assumptions - oil prices and drilling costs change but they are kept uniform here for comparison, so that should hold up. I got the $8,000 sale price for minerals from a recent letter I received from Brigham where they offered me that amount, of course I didn't sell it.

The most profitable outcome would be simply to participate but it costs a lot to play that game and won't apply to everyone. That is just one well, Sue would have the means to participate on any additional wells and Sue could end up quite wealthy in the long run. Imagine 32 more wells. This is a long-run game. There is one axiom that I find does hold pretty true - 'once you get in the oil business, it's real hard to ever get out.'

And I do not sign any leases (I've both leased and taken leases) for less than 20%. I also do not have problems with any operators not paying me, guess I'm lucky.

24

Ok so your assumptions on the numbers are off limits...but I sure would like to see the Bakken well that that produces 400 barrels a day for 30 days for 5 years.........Nobody said participation isn't the best way to go...but there exist the possibility that she could lose every cent of that $312,000 person must decide if they are cool with risking that amount in order to make an extra $150,000 because they didn't go no-consent.

The win/win for the "more adventurous" is to go non-consent or participate...not sell....no sell......and as far as being able to participate in future wells in that spacing with the chump change $88,000....forget it.

Wells are being drilled on pads now, 4 at a time......do the math on that money required to participate...once again non-consent is effectively leasing at 16% royalty without a bonus. Because there is no risk nor any cost for a good 2 to 3 years...then your checks become 6X bigger and you get bills each month and then you pick up the phone and hire an oil and gas experienced CPA...you have the money for it by the time you need it.

I think we also have a different definition of "recent" letter from Brigham?

I could see the following quick scenario for a healthy single guy age 55, who has 200 unleased acres in a spacing controlled by EOG...........sell 150acres and participate in the remaining 50...hire a great attorney to manage the LLC or Trust and then go travel the world and forget all about the oil business.

25

I have to agree with Andrew 400 bbl a day for 5 years may happen but is not a realistic number and if they drill 4 to 6 wells in the first 2 years, where does that participation money come from? If they just drill 2 at a time (fairly common), you are going to be $224,000 short on the second well.

If you had a good sized lump of cash around, you can participate for as many acres as you want and non-consent the rest, it's not all or nothing, they can't stop you from participating for only part of your acres. I have heard of people participating for just $100 worth as sort of an act of defiance so the operator will have more paperwork.

You will be going non-consent (or leasing) anyway for the bulk of the wells and now you only have half the acreage. Maybe not the best plan.

Not criticizing your numbers but just a thought to ponder I would consider 100 bbl a day for wells that are more than3 years old, 150 bbl a day if you are in the best areas and are optimistic. I would not forget well downtime either, it can cinsiderably lower the average. At the operators discretion, he may not operate the well/s at their greatest productive capacity, it's totally out of your hands.

Mr. Barton, I like the direction you are thinking but it seems your plan is predicated on a single, extremely productive well that is paid out before you receive a second AFE. I won't say it can't happen but it will probably be as rare as wells that average 400 bbl a day for 5 years in the Bakken as the most productive acres are mostly drilled as multiwell units from the beginning and are also the favored spacings for the infill wells.

I would rather eventually be paid for 66% (after taxes) of the oil produced from all my non-consent acres (because I am in very good areas) than be paid for 100% of the oil from half my acres, because I sold half to participate in one well.

I consider participation to be the better deal, but many of us do not have the money to participate up front. I think selling half in a good area is a losing proposition and in a poorer area you may only get enough money to participate for 1/4 of the acres if you sold half. You would also be at much greater risk in those acres outside of the sweet spot.

26

No guys, never 400 barrels a day for 5 years! That would add up to a 720,000 barrel well in 5 years, I've never seen one like that in our ND portfolio at least. I'm talking normal well decline curve, 400 bbls first month and a half maybe. A superb well in my opinion would do 300,000 in 5 years. One would fund the development wells easily out of cash flow, unless they drilled 32 wells at a time! Now I think Continental sounds like a hype machine sometimes, but I also give them credit: Continental, Whiting, Brigham, Oasis, Hess and many more are performing very well and steadily moving up the technology curve. So, 32 wells in a 1280 could happen and that alone keeps me from selling, although we think it about it at times.

If you had 32 wells in a 1280 and owned the 20 acres that Ms. Liberatore has, let's see what it would be perhaps worth, if it were all in one 1280 acre lease or unit.

32 wells and 200,000 barrels each (not sure here but I can't get my head around that many wells in a 1280 anyway) X $80 oil = $512,000,000 per 1280 drilling unit, gross value. Her value in the ground would be about 1.6% of that total or $8,192,000. Call it net after costs and taxes, maybe 45% of that: $3.6 million. Remember though, I don't know the acreage on her lease, it would be easy for her to plug that in for her lease and figure out the potential value.

So, I've seen large deals being done higher than $30k per acre. The above states that gross value in the ground is $400k per acre but if I account for costs and discount it back 20 years (@ 6%), it's about $43k an acre. So, that tells me we will have those large well numbers (up to 32?!), although I have no great insight about how long it will take, how they will accomplish the engineering of it or total recovery per well.

Anything I referenced from CLR (Continental) came from their website. There are a lot of great analyses of this play and others on seekingalpha.com, one writer Michael Filloon is on the ground out there and is really good.

27

Bart, I know you said not to complain about your numbers in your pervious post but you also said to shoot holes in it. I think you left an important item out, Capital gains tax. $400,000 is not $400,000 after 15% capital gains tax, it's $340,000 which minus $312,000 drilling and completion cost leaves $28,000.

I sure hope that well comes in under budget. You do know the penalty contained in most JOA's if you don't pay your part, don't you?

Maybe you had better sell 60 acres and not 50, just to be safe. I realise that 40 acres is not as attractive but that is reality. Also, if the well proposed is more expensive, some of the best producing wells cost 10 or 11 million dollars and you would have to sell more acres to have enough to participate in one of those. I have noticed that in the better areas you get a better well because they spent more on it, like more frack stages or 100% ceramic sand, expecting a better return. I would not expect a great well if they only spent $8 million on it.

I could easily see you selling 60 acres to participate in 40 acres an 11 million dollar well, maybe more if you want to have some cushion. $11,000,000 (40/1280) = $343,750 X 1.15 for capital gains tax = $395,312. Because you have to have some cushion and selling 60 acres would leave almost $85,000 left over as a safety net.

Just some thoughts. I hope you take it as constructive because it would be great if some of these mineral owners who have been missing in action without leases would have better options. I imagine unleased acres with good producing wells already would sell at a premium making some sort of sell to participate for half plausable but I don't see as many of them as I did 2 years ago.

28

r w, I like where you're going with this. Capital gains tax is part of the picture. I would say that each 'deal' would be different depending on the operators in the area and well control (the characteristics of previously drilled wells in the area) would factor in. I was generalizing but yes, any type of transaction would need to be customized for that particular area and the needs of the mineral owner; and frankly, all your input has been well thought out. We could only do smaller deals, call it =/< 1000 acres.

I should also clarify my valuation comment for people that want to sell out to realize profit for whatever reason (to pursue a career they love for instance). These smaller, non-operated deals are worth less than the publicized large operated deals I referenced above so I don't see any of us getting $30,000 an acre. But I would carefully consider selling mine at $20,000 an acre and certainly give it serious thought at $15,000/ac. Maybe even $13,500/ac.

29

Roughly where in the Bakken are your producing acres,, I had heard that a good wells' acreage value was 5-$10,000!

30

In reality, Buyers are not buying acres, they are buying proven, probable, and possible reserves. In other words, Inventory of oil and gas in the ground that can be extracted at a profit. The transactions just get recorded in acres within legal descriptions.

In the Bakken System, location is important only as it relates to the risk evaluation of the Inventory including production, surrounding wells, and operator. The specific scientific details that reflect the value of the reserves include:

  1. Resistivity logs through the Bakken layers
  2. Formation pressures in the Bakken layers
  3. Electronic logs indicating the presence of oil in the Three Forks and upper Logdepole zones
  4. The penetration and production details of all producing formations in the System
  5. Permeability techniques used by operator and a judgment of the efficiency of those systems when compared to newer techniques.
  6. Subsurface structural features that may effect Investory

More subjective determinations are also taken into consideration by buyers including, rates of decline, probability of offset wells, price projections, estimated ultimate recover per ell, drilling and completion technique advancement, and undiscovered formation exploration and development. If working interests are being purchased, operator efficiency and cost projections must also be addressed.

Well financed and sophisticated buyers have already done the above studies in setting their targets and know what they will pay in today's dollars for risk adjusted future income. They won't offer that but will discount it heavily in hopes of capturing more of the upside left on the table by the seller.

Buyers will not take title risk in individual transactions but will use any uncertainties found in title searches to further discount prices per acre prior to closing.

Opportunists, flippers and short term buyers, rely on sellers using averages to satisfy their rationalizations for selling. Uneducated sellers think they got good deal when they really only got the best of the lowest average range of prices offered per acre vs. scientifically determined Inventory Value. Its not a perfect market or a retail business.

A recent evaluation of a small segment of Williams county with limited production, yielded long term value ranges of from $10K to $60K/acre. However, if current exploration efforts prove to be scientifically feasible, those values could double in 4 years or triple in 7 years. Think about what you knew of the Bakken in 2006 compared to today.

Sellers should have confidence in their title and know their inventory before making a selling decision.

31

Do we have a Hall of Fame for posts on this site?

Yours above Gary, should be in it. Brilliant.

32

Opinions, Opinions...here are some numbers. An average "good" Bakken well should CUM 500,000 BBLS over it's life, 30Years maybe. Therefore, each mineral acre leased at 1/6th (pretty common for Bakken) is going to yield $6,100 dollars over the life of the well based on simple math.

UNIT SIZE CUM $/BBL Total $ Total Royalty $/ac
over Life $ over life @ 1/6th
1280 500,000 $95.00 $47,500,000.00 $7,918,250.00 $6,186.13

The real question is the how many wells is an operator going to drill in a given unit, but more importantly when. I am sick of this HORSECOCKY that all buyers are trying to ripoff uneducated sellers. What about the Market Price? What about the time value of money? If a buyer pays $6500/ac and only one well gets drilled the SELLER WINS and BUYER LOSES. If the buyer pays $60,000/ac and only 9 wells get drilled the SELLER STILL WINS and the buyer loses.

There is no right answer, only a market, and the prices being paid in that "competitive" market is what the mineral rights are worth…period. The rest is only opinions and we all know what those are like.

But hey, that is just my opinion…...

33

Opinions are not all created equal.....compare and contrast Gary's and those that have followed so far.

Never understood the axiom that opinions have the same body part in common....they certainly aren't in this thread.

34

I agree with you Hunter. The idea that all info traded here for the stakeholders (mineral owners, lessee's or lessors of minerals, etc) is good info and appropriate for this site, hope that it grows. I will share some data to augment what you posted. I wanted to see what my exit strategy would be if I wanted one.

So, I took an asset (the one that is the furthest along in development, and the most contiguous) and engineered it. Here (as Hunter did) I will use one drilling unit of 1280 acres leased at 1/5 for comparison. In and around Hawkinson Unit, Dunn Co, ND.

The engineering firm and the credit market are in sync and pretty conservative. They're projecting 493,000 barrels per well and that's average of the 37 total wells drilled so far, spread over 2+ sections (this agrees with your reserves). They give credit for 14 wells per spacing unit only in the Hawkinson Unit and 9 wells in the other units we're in.

But I've heard CLR reps speaking at corporate functions about cramming 40 wells in a drilling unit out here and it's not in any way a major technological hurdle, just a capital challenge really but the growth of production takes care of that. I also notice higher and higher ultimate recoveries and completion rates as time goes on (there will be an upper limit at some point).

We bought our minerals before any of this kicked on about 10 years ago, in other words quite cheap but like you said, at the market rate. The market for an asset like this is unique of course but I'm also looking at ways to leverage it (asset-backed securities, straight debt, etc and more on that another time).

At it's peak cash flow of 40 wells, a drilling unit leased at 20% would return about $300,000 per mineral acre (yes it's speculative but I'm personally betting it will happen). Even at the current bleeding edge of technology at 14 wells which we have now in Hawkinson Unit, you're still looking at $105,000 a net mineral acre in cash flow. So, then enters time value of money (6% discount rate at 16 years to produce the bulk of it) and today's value per acre is more like $40,000 a net mineral acre. (I didn't include price risk and I used $97/barrel, that's too high for long term analysis, so adjust to preference).

If I could even convince anyone to give me $40k an acre (limited market of buyers for me as I'm not operating), it would still be an unlikely decision to take the cash. The main problem is I'd be giving up about $50k an acre in discounted cash flow, in probables/possibles, for free. Companies do it all the time. But I wouldn't given the operator and other factors I mention.

Also, I'd then have to go and find a comparable asset to replace that and pay taxes. Since I couldn't see a good reason to exit, I began to focus on the Permian/Delaware since it is much more immature than the Williston and acreage costs are much lower and I reinvest the cash flows. Permian is an even longer term play than Williston.

I suppose if someone would give me a fair price for the probables, I'd sell. I'm bullish on oil for the 20 years that I need out there, so that's my take on Williston production. (As you can see based on my previous comments, my outlook has changed somewhat over time!)

35

In your calculations, don't forget your gas sales on the positive side and your risk penalties on the negative side.

36

Of course. The gas in the deal above averages 500 million cu ft per well, another $2.5 million in revenue over the life. That would be an additional 6% revenue. Maybe it balances out as I don't know how to assess a risk premium, but 6% for risk?

A Correction: the data above was actually using $85 oil today declining to $75 in 16 yrs. No idea why I said $97. Also, wanted to add the recent $46k an acre transaction below for evidence of current deal valuations.

MDU Announces $200 Million Divestiture Of Bakken Assets

MDU Resources Group Inc. (NYSE: MDU) announced July 21 its indirect wholly owned subsidiary, Fidelity Exploration & Production Co., is selling certain oil and natural gas production assets in Mountrail County, N.D., for $200 million. The assets sold consist of about 4,363 net acres with net daily production of about 2,000 barrels per day (bbl/d) of oil from 81 gross wells, 49 of which are operated by Fidelity. MDU Resources, based in Bismarck, N.D., will continue to hold 12,000 net acres in Mountrail County.

37

Gary, correct me if I am wrong, but if you are leased and went non consent, you pay 200% of your portion of the drilling costs according to your acreage and if you are not leased and non-consent you pay 50% of your portion of the drilling costs. If you are working interest, then you pay 100% of your portion.

So for 1 acre, leased and non-consent: 1/1280x10,000,000 (well cost Drill & Complete example) x2= $15624 per well. Someone check my thought process and correct please. Don't they take your share out of your royalty checks until your penalty is paid off? What about additional wells?

38

If you own minerals....you can lease, sell, do nothing.

Lease, followed by producing well, then as lessor you have royalty interest until all production stops in the spacing covered by the lease....you can't participate, nor go non-consent...that is only an option for the lessee...that person can get the 200% penalty for not participating....

I don't think it is accurate to say that they "take your share out" of your royalty checks. Until you have paid off your well cost, and retired the penalty, you have a royalty interest (16%) Nothing on your monthly check shows any well cost deduction, no information regarding operating cost that month.

Every well is treated separately...the only thing is that if you leased, you are done at that point...you aren't leasing wells...you leased the minerals, doesn't matter how many straws they put in to get them.....

39

If you hold the right to exploit the oil and gas by having leased it from someone and do not participate, yes the penalty is 200% and you are correct that you would receive nothing until the well payed out and recovered the penalty.

I helped someone who was in that position, they inherited the lease, not the minerals themselves but the lease of them, on just under 100 acres and had not the cash to participate. Three very good wells were drilled and the operator was laughing and offering to buy them out for what they paid and 5% royalty. There were three more wells being drilled and I informed this person that you have to farm out your lease to someone else who could participate or, as good as the wells were, it would be a long time before you ever saw anything from them. He did take my advice and did find someone interested in a joint venture and the operator stopped laughing and raised their offer from $115,000 and 5% to $2,000,000 and 3% on all wells from first production. Sometimes you have to hit them where they live.

M Barnes said:

Gary, correct me if I am wrong, but if you are leased and went non consent, you pay 200% of your portion of the drilling costs according to your acreage and if you are not leased and non-consent you pay 50% of your portion of the drilling costs. If you are working interest, then you pay 100% of your portion.

So for 1 acre, leased and non-consent: 1/1280x10,000,000 (well cost Drill & Complete example) x2= $15624 per well. Someone check my thought process and correct please. Don't they take your share out of your royalty checks until your penalty is paid off? What about additional wells?

40

I can't deny that 1/6 is pretty common in the Bakken, but no more common than 3/16 and 1/5 taken together and all the buy offers I receive stipulate that they are only valid if I have a royalty interest of 3/16 or greater. I think you should only use 1/6 in figures if that is the royalty you have, otherwise it looks like you are skewing the numbers to justify your opinion.

You can't just throw a blanket over the Bakken and say it's all the same either. My best well which I am assured cost 14 million dollars has produced 314,596 barrels oil in 2.5 years. I seriously doubt any of the four wells that have been drilled in that spacing in the Bakken and Three Forks are going to top out at 500k barrels.

My worst well, on which I have all the information there is to be known about it and I mean all, cost 5.4 million dollars and has produced 90,433 in 4 years. The worst well was just enough well to hold the spacing, 10 stages with beach sand. There are more than one offset well in close proximity with 20 frack stages with ceramic that did better than 20,000 barrels in their first month. While it might look like a good idea to sell out in the spacing of my worst well, the great production on all sides of it tell me it would be a poor business decision. You have to take all the factors you can find into account.

If one thinks that the buyer will lose out at $6,500 per acre, by all means, do not buy. You would be crazy to buy against your better judgement, but I think you will anyway.