Wednesday, October 31, 2007

When An Agreement For A 640 Actually Means It Will Be A 1280

So, say a mineral owner (“MO”) executes a lease with an oil company (“OC”) that restricts the OC’s pooling authority to create a pool of not more than 640 acres, or in other words, restricting the OC to limit any spacing unit involving the lands to not more than 640 acres. Keep in mind that the state regs allow the creation of a 640 acre drilling unit for horizontal wells without any hearing, and any unit larger than 640 is considered an exception unit and requires a hearing. Then, say the OC requests that the NDIC create a 1280 acre drilling unit that includes the lands with the leases having the 640 acre pooling limitation, and the MO, citing the restrictive pooling provision in the lease, objects to the creation of the 1280 at the IC hearing. Oh, whatever shall the IC do in such a situation?

Well, that situation occurred at the IC hearings in September, and the IC said the lease provision was a m
atter between private parties. It said the proper venue for the dispute was the courts and not the IC, which has limited powers to regulate the orderly development of wells, etc., etc., etc., and not to resolve disputes between private parties. It then created the 1280 acre drilling unit. Now, it is apparently technically true as stated by the IC that the creation of a drilling unit (which was at issue here) does not actually effectuate the pooling of any interests, as that occurs when the IC creates a spacing unit after holding another hearing. But isn’t that like saying that a trespass only occurs after the trespasser chopped down your trees, as only at that later time was the trespass apparent?

As such, wasn’t the IC ignoring the practical effects of its order and the correlative rights of the MO who bargained for the restrictive pooling provision with the OC? In other words, by granting the order, the IC gave authority to the OC to drill a horizontal well across the 1280, and assuming the horizontal wellbore transverses both sections and is commercial, exactly how can a 640 acre spacing unit ever be created at a later time in such a situation? The answer is that it can’t, unless in the unlikely event the OC plugs back the lateral so that it does not extend beyond the hardline boundary for a 640 acre unit that contains the well site (and such a plug back order by the IC would inevitably lead to waste), or the IC deems the east or west halves of the two sections a 640 acre unit in the event the wellbore stays exclusively in the either half. However, I’m unaware that the IC has ever created a 640 acre spacing unit after a well was drilled on a 1280 drilling unit that was created for a single lateral.

Consequently, unless some bizarre series of events later occurred, the granting of the 1280 acre drilling unit effectively created a 1280 spacing unit. Thus, in a practical sense, the only stage in the regulatory process that the lease provision could prevent the creation of a 1280 spacing unit was at the initial hearing for the drilling unit.

So, it seems the only option for the MO after such an order is entered is to obtain an injunction to prevent the drilling of the well until the validity and effect of the lease provision can be determined by the courts. Now it should be noted that neither party may have standing, i.e., an actual “case or controversy,” to have a court hear the issue until after the IC issues an order either granting or denying the request for a 1280. But at bottom, the real and practical issue in this situation is whether the MO or the OC should have the burden of invoking a court’s review.

The IC could have found that the MO had an apparently valid lease provision (obviously an open question, although easily researched) that would be violated if it granted the OC’s request because a well transversing two sections cannot later be made into a 640 acre spacing unit, and accordingly, that it would deny the request because otherwise the correlative rights of the MO would be adversely affected. Then the OC, who is arguably attempting to breach a lease provision, would have the burden of going to court if it still wanted the 1280, instead of the MO having to go to court to rescind it after it already has been created.

My reading of this decision is that the IC is stating that it is the job of the courts to protect the correlative rights of the MO in this situation, rather than the job of the IC, although one of the primary duties of the IC’s O&G Division is to protect the correlative rights of all owners while regulating oil and gas development.

As it stands now, it appears that the MO must present evidence at the drilling unit hearing that the 1280 is not feasible on grounds independent of a contrary lease provision (geologic, economic reasons) in order to possibly prevent the creation of a 1280. In addition, shouldn’t the burden of proof be just a tab bit higher for the party seeking an exception to the rules, i.e., that the requesting party have a little higher burden in overcoming any objections to such a request in order to prevail? After all, there is a reason it is called an exception.

If the MO doesn’t seek an injunction and the well is drilled and later spaced at 1280, what damages does the MO have to prove in court? Well, that would be tricky, as the MO would have to present evidence of some difference in the amount of royalties between a 640 and the 1280. It’s likely that the breach of such a lease provision would be deemed a breach of a covenant and not a condition of the lease, the latter being a basis for terminating the lease, and the former being a basis for only collecting damages that resulted from the breach.

An even tricker situation is presented when there are multiple working interest owners in the proposed unit, and the OC that agreed to the restrictive pooling clause is not the same OC as is requesting the creation of the 1280. Does this “secondary” OC have any duty to abide by, or have its rights limited by, the terms of an agreement to which it wasn’t a party? Too many issues are raised there to be addressed here.

Now, it should be noted that the case last month involved special circumstances. The southern sections in the standup units to be created, which didn’t have the restrictive lease clauses, were entirely under the waters of Lake Sakajawea and over a half mile from shore. The northern sections that had the lease restrictions, however, had some terra firma available. Therefore, the only practical way to reach the offshore sections was to drill a long lateral through the sections that had the lease clause. Although that case involved peculiar circumstances, it doesn’t mean that the IC’s determination would have been any different in a "normal" case, since the legal principles involved are the same.

In any event, the apparent violation of a lease provision should be a factor that the IC considers when determining the size of a drilling or spacing unit, especially when the violation adversely effects a party’s correlative rights. Apparently the IC feels it shouldn’t be a factor.

I have yet to see any persuasive evidence that a single long lateral adequately drains the entire width of a 1280 acre unit. Some companies are saying they need a 1280 for a single well because such a well drains the entire unit, but then say, but hey, if it’s a good well, we will drill another well on the unit. And for some reason the IC buys it. There is only one thing here that we know for sure - - there will be one well on the unit. So therefore, why doesn’t the IC start with the premise that there will be only one well and create a 640, and then a create a second 640 when and if a second well is planned.

I find it especially ironic that the IC doesn’t want to get involved in private lease matters regarding a restrictive pooling clause, and yet everyone knows the unspoken motive for the 1280 requests is so the companies can tie up a lot of leases by drilling a single well. Doesn’t the IC consider it to be getting involved in private lease matters when it creates larger units than necessary and thus allows leases to be held by production when they should otherwise expire if a second well isn’t drilled?

Monday, October 29, 2007

Major Discovery Announced By EOG North Of Parshall Field

EOG released its 3rd Quarter results today and confirmed two high volume wells with IPs around 2K bopd about a dozen miles north of Parshall Field and one in the northern portion of the existing field. Those wells are the two Austin wells in secs 2 and 3, 154N, 90W, and the Wenco well in sec. 30, 153N, 89W, Mountrail Co. It goes without saying that there are a lot of development well locations between these two areas assuming the reservoir is continuous. The company also plans to increase its rig count from six to eight by early next year.


Wednesday, October 24, 2007

Time For A Reality Rant

You know, I get just a little tired of companies trolling for investors and general media reports that keep bringing up the hundreds of billions of barrels that supposedly exist in the Bakken everytime the formation is mentioned. My question to them is "so what?" Instead, why not tell me what percentage of that figure is recoverable, as isn't that what's really important? For the ignorant, these reports make it sounds like all that previously unknown oil is just waiting down there for whomever wants to put a straw into this vast underground pool like Spindletop and then just let it flow. That is hardly the case.

These enormous estimates are generated by calculating the oil in place on a section basis times the areal extent of the Bakken. Most companies are estimating about 3-5 MM bbls/section, which is open to debate, but is certainly reasonable. Now the tricky part comes in calculating what percentage of that amount is recoverable. A ten percent recovery rate would yield between 300-500K bbls/section. This certainly appears to be a reasonable rate in areas of exceptional formation quality, such as in the Parshall area, although the jury is still out as to the long term producibility of those wells. But again, it is certainly not an unreasonable calculation for that area based on the scant production history that exists. In other areas currently being developed with less favorable geology, perhaps half that, or five percent, is a reasonable recovery rate, as 300K is an often used estimate for 1280 acre units. However, in some fringe areas, the recovery rate with current technology is only a fraction of one percent, and a number of those wells will be hard pressed to ever make 100K, or even 50K, even after twenty years of production.

So what's the point here, you may ask. The point is: how much of the Bakken acreage being used to calculate hundreds of billions of bbls has poor geologic factors that has a recovery rate with current technology of less than one percent? My guess is a lot of it. Consequently, the hundreds of billions suddenly become hundreds of millions in relevant terms. Marathon and EOG both guess that they have recoverable reserves of roughly 100 MM bbls on their acreage. New technology in the next ten years could double or triple that, who knows. Now, is a couple hundred million bbls that nobody thought could be produced five years ago something to take lightly? Of course not. It's the equivalent of finding new Billings Nose, Little Knife, and MonDak Fields. It is hardly hundreds of billions of bbls though.

So if anybody tells me they think there are 800 trillion bbls down there, I really don't care. Tell me how many of those bbls you can economically put in a tank, then I'll care.

UPDATE 10/29: In today's Bismarck Tribune, while speaking at an energy expo in Bismarck, a Sr. VP for Marathon stated that the middle Bakken is a "'marginal play,' one that requires the company to move quickly from one well to the next with fewer people." Yeah, but the economics have changed rapidly what with the current hundred dollar oil. Now, 100K of recoverable reserves can gross ten million dollars in future revenue, as opposed to half that with fifty dollar oil. Marathon's original economic model was based on forty to fifty dollar oil. But I don't think anyone wants to make any hedges on what the price will be a year from now, as with a world recession, it could be thirty or less.

Tuesday, October 23, 2007

Rig Count Keeps Climbing

With the state rig count having risen to 55, that is the highest number in over two decades. All except maybe a dozen of those (including a rank test way over east in Wells Co.) are exploiting the Bakken. Mountrail Co. currently has fifteen of those rigs and EOG remains very active in that county with six rigs, and Hess, Whiting, and Hunt each adding a few each. A dozen rigs are in Dunn Co., with Marathon utilizing six of those and Continental and Burlington using another four. In fact, there recently was an article about H & P's new flex rigs being used by Marathon.

In a related note, EOG is requesting its first 1280 acre unit within Parshall Field that is to encompass secs. 2 and 3, 152N, 90W, in Mountrail Co. There already are existing producers in each of these sections on 640 acre spacing, the Patten and Bartelson wells, which have produced 68K and 112K, respectively, through this past August.

Monday, October 15, 2007

Some Recent Parshall Completions

EOG has completed the Hoff 1-10H, sec. 10, 152N, 90W, in Mountrail Co. for 1,678 bbls/day and a little over a half million cfg/day. This well has produced 66K bbls from June through August of this year. The company also completed the N&D 1-05H in sec. 5 of the same township for 1,285 bbls and 404 mcfg/day. The well made just over 53K for the two months of July and August. Total field production up to and including August from wells off confidential status is just over 800K bbls.

Also, of interest, an article about leasing in western Ward County:

Wednesday, October 10, 2007

The Low Murmur Of Excitement Begins To Build

It appears that people are beginning to realize that this thing is going to a significant event, at least in some select areas of the state.

“It’s just incredible what’s going on there (in Mountrail) and Dunn County,” Ness said.

And the boom in gas processing plants in the state: