Tuesday, February 12, 2008

In The News

It's a good thing that the newspapers are keeping things going when I'm to busy to write something.

03/03 update: An article from the Grand Forks Herald about record high oil prices in ND.

02/27 update: An article from MinnPost.com: Booming Oil Patch Lights Up North Dakota Rangeland

02/25 update: In Barron's, Kopin Tan has article about the Bakken from an investment prospective (starts in the middle of p. 2). It contains one of the best passages in recent memory: Exploration stocks are risky prospects. Booms can turn into busts, and oil found may not be easily extracted. Wait too long for data and shares would have already run up. Jump in too early and you're one sunburn away from that crazy guy combing the beach with a metal detector.

02/13 update: Another one today in the Bismarck Tribune about a huge turnout in Killdeer for an informational meeting.

The Bismarck Tribune has reported on the the state lease sale in Mercer Co.

In addition,the Bismarck Tribune had a story on the uneven effects of development.

Then the Minot Daily News has another "boom" article. However, I have yet to see anyone show where there is currently more than a half billion barrels of potentially recoverable reserves in ND, now yet 400 billion, or what's going to happen to all the acreage in the dead zone consisting of most of Williams and McKenzie Counties (or how much, or little, is going to be recovered from that huge area).


Anonymous said...

Teegue in a recent comment you said that Tracker was going to do an offset to the Thomas sec3 144n 97w. Have they filed this yet and/or do you know which direction the offset was going to be? I also noticed that Marathon was requesting that the Murphy field extend west another mile with 3 potential sites. Thank you for your efforts, as this is a wonderful site for those of us that are nascent to the oil business and are trying to understand how this is going to play out.

Teegue said...

Mikey, Tracker requested and was granted a 1280 acre drilling unit sometime late last year for secs. 3 and 10, just east of their first well (Thomas well is in sec. 4 & 9), and a mile west of the recent units requested by Marathon that you mentioned. (email me if you want more info about the application). Tracker hasn't gotten a drilling permit though and that may relate to the fact that they had well less than half interest in the unit and they may be trying to work out some agreement with the other working interest owner(s) (Windsor was the largest interest owner I think). I believe Ansbro has most everything tied up to the south of these Tracker and Marathon units, unless it has since changed hands.

Anonymous said...

what does "dead zone" mean?

Teegue said...

Dead zone: look at the map on the right-hand side of the blog. See that huge area west of the area circled (Nesson Anticline area) and the very few red dots between there and the MT border? Those red dots are mid-Bakken wells drilled in the last couple of years that were less then stellar, and there has been virtually no drilling in that area since. How many hundreds of billions of bbls underlying that area (assuming Price's calculations) isn't prospective right now?

Anonymous said...

1. For decades, western North Dakota has desperately needed economic development to improve incomes and increase tax revenues. Now that this has been happening in energy, the locals are grumbling about losing what was there before. To me this makes little sense.
2. You can now actually find roads in Mountrail county that lead to places where the only way to get there was a summer trail before. I think this is wonderful, but a small number of the locals want to complain about now having roads where none existed before.

3. The new pipelines will tear up the land a bit, but this should be temporary, and within a year or two most people will probably not even be able to tell the pipeline is there.

4. As a result of 3, the issues related to road use by trucks picking up oil should largely disappear

5. A single well with a long diagonal lateral on 640 acres it seems to me does minimal damage to the environmnent or to the appearance of the land relative to what might have happened had the field been developed with much smaller spacings. Drive through the old Plaza field nearby developed a couple of decades ago versus the Parshall field and see if you dont agree.

6. In one or two instances, wells probably have ended up uncomfortably close to farmsteads, but by and large the wells are located in remote spots on each section The 640 acre spacing has tended to "spread the wealth" in very equitable ways relative to what might have happened had smaller spacings been chosen.

7. To me the well sites in large measure seem to be very neat and well laid out to minimize negative visual impacts on the surrounding landscape. I haven't heard yet but I assume there will be less need for 8 big tanks at each well once the pipeline is operational.

8. It looks to me like the players (EOG and others) have no plans to abandon the field any time soon, and it seems to me the locals need to try and make the best of the situation they now find themselves in rather than grumble and complain about what is happening. This "sour grapes" attitude is not going to do anyone any good. Mountrail county may soon end up being a county that experiences significant population growth rather than the long term decline that had been going on for 50 years or more. For starters, they have only recently gotten to a point where they don't have enough kids to keep many of the schools open, and houses in many of the little towns on the outskirts of the field were practically worthless, as no one wanted to live there but this could quickly change. Could this new energy-related development somehow be bad not good?

Anonymous said...

Teguee, what about north of the Tracker and Marathon units who has the majority of the working interest? Since the Tracker well backs up against the Little Knife oil field is it correct to assune that Petro Hunt and Cheveron control those acreages?

Nick H said...

What is the reason for the 'dead zone' in Williams and McKenzie counties. What are the geological differences between the 'dead zone' and Elm Coulee, Parshall, Dunn County, etc?

Anonymous said...

Having a regular road to replace the section line prairie trail leading to my grandparent's homestead will be a positive addition.

No longer will I need to remember where the rocks are hidden among the weeds and worry about bottoming out or getting stuck in a slough crossing and having to walk to a neighbor to get a tractor to pull me out.

I suspect the vast majority of residents consider the oil boom a positive event. Remember it is the newspaper and TV reporters who like to find one person who is whining and then report their story over and over again.

Anonymous said...

can some one here tell me what this means about royalty checks. [“The law in North Dakota requires a well be spaced and the spacing unit pooled before royalty division orders can be issued and payment made.]

Teegue said...

Mikey, in very general terms, Marathon likely has most of the acreage for the first several miles north of that area, and a strong minority interest from Continental/Burlington, with the latter two companies having almost all the interest as you go further north closer to the mountains. And yeah, Petro-Hunt would have most of the acreage to the west held by production (Chevron sold out to P-H).

Nick, very likely just not as good permeability and matrix porosity, which would be caused by different marine deposition environments than in the other areas you listed. For example, the dead zone probably has less dolomitic facies and instead has more cementing agents filling the pore space where oil otherwise would reside. What kind of sedimentary rock you end up with in a given area depends on how deep the sea was, how close to shore it was, etc., etc. Also, probably less natural fracturing and/or the frac technology being unable to do the job adequately (or companies not knowing what they are doing). One of my favorite sayings is that even a good frac job can't salvage poor geology (which is subject to change with new technology of course). Research of some cores of the mid-Bakken in the area will speak volumes as to whether these problems exist.

Teegue said...

royalty payments: in short, it means that before royalties can be paid, the size of the unit must be established so that royalties can be paid in shares proportionate to the owners share in the unit. After a well is deemed to be productive, a title opinion is done on all the tracts in the unit to determine all the owners and how much they own and their royalty rate.

This is then expressed as a decimal percentage in a division order that the company sends to the mineral owner, who must then sign it to receive any payments. For example, if spacing is set at 640 acres and an owner owns 320 acres in that unit, with a 20% royalty, their division order would indicate their share of production as 0.10% (320/640= 0.5 [acreage share in unit] X 0.20 [royalty] = 0.10 percent share of production in the 640 acre unit). Spacing size is supposed to be set within a certain time after a well is completed (unless that new well is part of an existing field where a huge area has already been spaced).

What I'm trying to say here is payments can't be made until the legal boundaries of the well spacing is determined, which of course will determine who shares in that well. If the well was drilled within the boundaries of an existing field (where spacing already exist), the only delay will likely relate to getting the title opinion done. Wildcat discoveries will take longer because that well will have to go through the process of being spaced, which will usually also include surrounding lands that is planned to be developed in the future.

Anonymous said...

From today's Bismarck Tribune it seems the State is flush with cash that it can send back to the oil producing counties to pay for the infrastructure repairs and upgrades.


"North Dakota's state government has pulled in nearly twice the oil tax revenue it expected between last summer and the end of January."

"the state has collected $122 million in oil tax revenue since June, compared to a forecast of $67 million. That represents an 82 percent difference"

"So where is all this extra money going? After about $26 million flowed to counties and cities, the state has collected $122 million. By mid-November, $71 million had flooded into the general fund, capping out its allocation until June 2009. The remaining $51.6 million has been deposited into a legal and budgetary creation known as the Permanent Oil Tax Trust Fund."

Anonymous said...

The Schedule:
Warning--the estimated times at each point generally are minimums and these can lengthen at any point along the way.

1. Surface owner contacted to get permission to survey for a well on the property. If the surface owner objects, legal action can be taken to ensure that owners of the mineral interest can get access to the minerals. The surface owner is compensated for land required and damage to property, with the going rate apparently being about $6,000 for a new Parshall field well.
2. Permit issued for well by the ND dmr. I'm not sure of time between survey and permit here but my best guess is probably 4-6 weeks
after the survey is complete
Watch for the well permit on the dmr daily activity Web page
3. Drilling rig shows up and drilling (spudding) commences (2-4 months after permit is issued, but can be considerably longer)
4. Main drilling rig in place (for 40-60 days after spudding). Tanks appear at approximately the same time the well drilling is begun (at least this is what happens in the Parshall field)
5.Completion rig (30 days)
Assuming the well is good
6. Pump is set. Test Production. Well begins production for sale (perhaps 15-30 days from when pump is set).
At this point the driller has had no contact with anyone other than the surface owner.
7. Announcement of division order pooling the mineral interests of all owners on the spacing on the dmr hearing schedule (docket) site with a specific hearing date scheduled.
(typically 30-45 days after initial production for sale begins). Shortly after the hearing is scheduled in Bismarck all known mineral interest owners on the spacing will receive legal documents from Bismarck lawyers representing the driller informing them of the hearing and asking them to attend if you have objections to the proposed pooling. These pooling hearings generally proceed w/o objections from the mineral interest owners. The dmr streams the hearings live over the Internet on the hearing day and you can listen into the hearing if you want. Other states no doubt do something very similar.
8. Letter from driller with form informing you of their calculations of what % of the gross value of the oil and gas from the well you will receive to sign if you agree. The factors that affect this are your mineral acres on the spacing, the % your mineral acres are of the spacing and the specifcs of the lease you signed, which for old leases are typically 1/8 but very recent leases can be as high as 3/16. Example: suppose you own all the mineral rights on a quarter of land with a well on a 640 acre spacing and had a 1/8 lease. Your % will be (160/640)* 1/8 = 1/32th or 3.125% of the gross wellhead value of the production less the severance tax (11.5% of the gross amount). Your gross monthly check for a well producing 10K bbl a month and $82 oil (again, typical Parshall field numbers) would be $25,625 less the severance tax for a net of $22,678.

Oil is priced based on what the driller actually sells it for. In the Williston basin LIght sweet crude is $15-$20 more than sour crude. In the Parshall field, which produces light sweet crude the monthly pricing is approximately $6 below the average oil price reported almost continuously on the cable network CNBC during the month. Parshall field oil has been selling for $82-$85 a bbl in recent months and will likely approach $90 if the CNBC price stays above $95 (as it was this morning)

9. Royalty payments begin. (first check issued about 120 days after production for sale begins) These generally are paid out for production that occurred from the well for the month begining 2 1/2 months prior.

If an owner is really lucky all the way along and everything proceeds according to schedule, a mineral interest owner COULD see the first royalty check (generally the first check is issued for the entire first 2 1/2-3 months of production) from a well permitted in January '08 by mid December '08, with monthly checks following for each month for the month ending 45 days prior. But everything would have to go very smoothly for this to happen. I realize that ND has a law that says royalty owners should receive a check 90 days after first production takes place, but that would be very very fast given the amount of legal paperwork involved. Don't get too upset if everything moves slower as the royalty owners will eventually get paid what they are owed on a monthly basis.

A major source of delay is simply in finding mineral interest owners due royalty checks on a spacing. Even 50 year ago it was not uncommon for a previous owner to retain a half share of the mineral interest on a piece of land being sold with no time restriction. The name of that owner may be on the deed, but that owner likely is dead and the royalties belong to the heirs. But no one may have looked at that deed in 50 years let alone there be any addresses for locating the heirs. Finding the rightful royalty interest owners who should be receving checks may be both difficult and time consuming.

Anonymous said...

You wrote:
"A major source of delay is simply in finding mineral interest owners due royalty checks on a spacing."

Is is not the case that before a driller even considers drilling a well, they (and their partners in the well) have already leased all of the mineral rights in the land planned for drilling. Thus, the drillers know before they start drilling the names and % interest of the mineral rights owners.

Anonymous said...

I used to think that was the case, but as I understand it, on occasion land can be drilled even though all mineral interest owners have not been located. If I am wrong on that, please let me know. I'm not certain exactly what happens to royalty payments if a mineral interest owner on a piece of property simply cannot be located. Perhaps these payments go into a pot held by the state for a period of time and then go to the state if the rightful owner cannot be found after a sufficient length of time. Someone else reading this may know more about this than I do, but there has to be a way to allow for drilling in a situation where one or more mineral interest owners cannot be found without delaying things for everyone else.

Anonymous said...

If a mineral rights owner cannot be found, then the ND statutes allow the surface rights owner to take possession of those mineral rights after proper public notice has been given.

In recent weeks the Mountrail County Promoter has been publishing many of those notices.

Until the surface rights owner legally succeeds the abandoned mineral rights owner, I would think any royalty payments due the abandoned rights owner would be held in escrow by the driller for eventual payment to the surface rights owner.

Here is the statute:
"38-18.1-02. Statement of claims - Recording - Reversion. Any mineral interest is, if unused for a period of twenty years immediately preceding the first publication of the notice required by section 38-18.1-06, deemed to be abandoned, unless a statement of claim is
recorded in accordance with section 38-18.1-04. Title to the abandoned mineral interest vests in
the owner or owners of the surface estate in the land in or under which the mineral interest is
located on the date of abandonment. The owner of the surface estate in the land in or under which the mineral interest is located on the date of abandonment may record a statement of succession in interest indicating that the owner has succeeded to ownership of the minerals under this chapter."

Anonymous said...

Here is the statute regarding payment of royalties.

47-16-39.1. Obligation to pay royalties - Breach. The obligation arising under an oil
and gas lease to pay oil or gas royalties to the mineral owner or the mineral owner's assignee, or
to deliver oil or gas to a purchaser to the credit of the mineral owner or the mineral owner's
assignee, or to pay the market value thereof is of the essence in the lease contract, and breach
of the obligation may constitute grounds for the cancellation of the lease in cases where it is
determined by the court that the equities of the case require cancellation. If the operator under
an oil and gas lease fails to pay oil or gas royalties to the mineral owner or the mineral owner's
assignee within one hundred fifty days after oil or gas produced under the lease is marketed and
cancellation of the lease is not sought, the operator shall pay interest on the unpaid royalties at
the rate of eighteen percent per annum until paid, except that the commissioner of university and
school lands may negotiate a rate to be no less than the prime rate as established by the Bank of
North Dakota plus four percent per annum with a maximum of eighteen percent per annum, for
unpaid royalties on minerals owned or managed by the board of university and school lands.
Provided, that the operator may remit semiannually to a person entitled to royalties the aggregate
of six months' monthly royalties where the aggregate amount is less than fifty dollars. The district
court for the county in which the oil or gas well is located has jurisdiction over all proceedings
brought pursuant to this section. The prevailing party in any proceeding brought pursuant to this
section is entitled to recover any court costs and reasonable attorney's fees. This section does
not apply when mineral owners or their assignees elect to take their proportionate share of
production in kind or in the event of a dispute of title existing that would affect distribution of
royalty payments; however, the operator shall make royalty payments to those mineral owners
whose title and ownership interest is not in dispute.

Teegue said...

A few clarifications. The title opinion for the division order (usually called a drilling title opinion) is much more thorough (and done by an attorney) than the title search done by a landman for leasing. Companies are extremely careful not to shortchange someone in royalty payments as that is not looked upon kindly by a number of entities. Royalties for unknown MOs are held by the company in a suspense account until it is distributed to someone after ownership is resolved.

All the minerals in a drilling unit do not have to be leased before drilling can began. If unleased, these owners are considered working interests and are asked to participate in their proportionate share of the well costs before drilling begins (just like any other working interest). If they refuse, the operator can request that these interests before forced pooled whereby their share of costs are withheld from their share of the production. If a risk penalty is imposed (for not wanting to participate in the costs upfront, which leaves the risk of a dry hole on the operator), that is an additional 50% of the amount of their share of costs for unleased MOs and 150% for leased working interest owners (the risk penalty money goes to the operator).

For the surface owner to obtain an abandoned mineral interest, the minerals must be "unused" for 20 years, and then go through the process of attempted contact at the last known address and if unsuccessful, notice in the official county paper. A lease of the minerals is a use. Such mineral owners can also protect themselves by filing a notice that do not intend to abandon their minerals in the court house (at least every 20 yrs), which of course lists their address so they can be contacted. Usually the surface owner knows nothing about this until a landman advises them of it.

Anonymous said...

Thanks Teegue

You have explained why some of the steps in the process end up taking longer than a mineral owner might expect.
This whole series of comments are quite interesting, and should prove very useful to anyone with a mineral interest in a spacing that has just had a well permitted and iis interested is extimating how long it might take to actually see a royalty check in the mailbox. I trust that Bakken mineral interest owners will find this discussion and find the collection of information very useful in understanding what might happen at each step in the process of getting from initial survey and permit to a producing well generating royalty payments.

Anonymous said...

More news

My quick calculations tell me that an average well in the parshall field is worth about $135 per month per mineral acre net of the 11.5 % severance tax. If these numbers apply to the well drilled in the section containing the town with a 1/2 acre lot would get about $65 per month and a 1/4 acre lot closer to $35 a month royalty.

Not a lot of money.

Parshall takes up most of the E 1/2 of Section 25 152-90 I believe. Section 26 immediately west has already been permitted for a well in the NW corner of Section 26. If a well goes on Section 25 it will probably end up on the NW corner as well, away from town.

Anonymous said...

According to this news report, Mountrail County's December 2007 oil production almost reached 418,000 barrels.

If the drillers continue having success, Mountrail County's December 2008 oil production should be in the range of 1,250,000 barrels.


Unknown said...

Hi all...I am one of the landowners of the Thomas 4-1H well on section 4 T144N R97W, and also one of the mineral owners. We just received the division order on Saturday, but the decimal interest is incorrect by .0021. Also, the division order has an "N" by Gas, although it is producing gas and selling gas for Petro-Hunt, and also, my name is spelled incorrectly. How do I get these items corrected? I don't want to sign the papers until everything is accurate. Haven't gotten much news about the well, as I don't live in North Dakota anymore, so I've been out of the loop on what is going on with the well. Any info you all could provide would be appreciated.

Teegue said...

Dean, I would just send a short letter by certified/registered mail to the company indicating the discrepancies and what you believe is the correct info (how many mineral acres you own, etc.). It wouldn't also hurt to request a copy of their title opinion on your tract. If they are a reputable company, they will provide info that justifies what is on the DO. If you still believe their info is in error, I suppose you will need an attorney if want to pursue it further. Your payments will be held by the company until they receive a signed division order or the dispute is otherwise resolved (just as they have been since first sales). These large units contain a higher risk of error because there are normally more tracts and owners involved than those in a 160 acre unit, for example.

Anonymous said...

Dean, you should call them, and ask to speak to the division order persons, (Landowner Relations Dept) they will listen and take care of all the discrepancies
for you...Petro-Hunt is good to get along with most of the time...

Teegue said...

Tracker is the operator, not Petro-Hunt.

Anonymous said...

Thanks for the great site! This is very informative. I see you image on the front page...but it is hard to "zoom in". I've seen chat about the "daed zone" to the west of the n/s high density of wells. Would something in sec T156N R91W Sec 27 be considered in the "dead zone"?. This location just had some 3d seismographing occur or is planned soon. Thanks for any info. Keep up the great work.

Unknown said...

Thanks for the info. I called them, and found out that there are 1322 acres in the two sections, not 1280 as I thought. Apparently the lots are larger. Contacted a land man in Dickinson, ND who confirmed the total acreage in those two sections as 1322. This made the decimal interest exactly as written on the division order, out to the 8th place. Impressed with the accuracy considering the number of owners out there. They did have my name spelled incorrectly, but can just change it slightly on the division order. Thanks for the help. Still hoping that the well comes through. I believe they are having some difficulty getting it to flow.

Anonymous said...

this is some very helpful information.

Teegue said...

Anon 10:14, keep in mind this is my characterization of that area and what's important is what the company you're leased to thinks, and not what I think. All I'm saying is very few wells have been drilled in that entire area, and they didn't turn out very well, and there has been virtually no drilling in there for the past year. A bigger version of the map you referenced is in my 12/08/07 post and you should be able to find the township you indicated on that one. The 3D seismic: seems to me there was a Red River discovery around there somewhere this past year that may explain that.

Dean, glad it worked out for you. I or someone else should have recognized that the quarter sections along the north (in your case) and west sides of a township may not be 160 acres because of the whole "lot" thing.

Anonymous said...

Last time I drove by they still were working on the Thomas well. If they are having trouble getting it to flow do you think we are finding the western edge of the Murphy field ? Thanks for any comments in advance.

Teegue said...

Technically, that well is incorporated in the Little Knife Field boundaries, but I think I know what you mean. I wouldn't put much emphasis on what's going on while it's still testing. Most of these wells don't flow that long before they need a pump. A lot of things can vary from well to well, including the geology, mechanical issues and how much of the lateral stayed in zone, etc. There really is no edges to any of these Bakken fields, certainly not in the classic sense of vertical wells in the Madison formation, for example. Often times drilling stops only because a company that is developing an area doesn't have any more leases there, and nobody else has jumped in.

Debbie said...

Thanks to all of you for taking the time to provide all of this very helpful information! I see the 20 year re-claim thing is in ND, hoping it's not in MT also, which is where I have my mineral rights. At least now I have places to start looking thanks to Teegue & ya'll. I have worked in the oilfield (office) myself for 10years but was never looking at any of it from the perspective of the mineral owners, even though I was myself a mineral owner. If I knew then what I know now I would have paid more attention and asked a lot more questions!! Man....the things we DON'T know can really cost ya, huh? AGAIN THANK YOU!!!

Anonymous said...

My parents have mineral rights in Dunn County.Does anyone know what happens when a section is added to an oil field? This area is potentially being added to the Murphy Creek field. A lease has been signed and I am assuming that there was some sort of pooling agreement (?) in the lease. Would a well have to be drilled before being added to the pooling/royalty payments?

Unknown said...

Thanks for this blog.A reader left the following comment concerning the NDIC hearing held today to determine temporary spacing for the Murex well in sec. 36, 154N-91W, Mountrail Co. The well is about 3-4 miles northwest of activity in the "south" Parshall Field area and about the same distance southwest of activity in the "Austin" area.
Buy Stock