Tuesday, October 2, 2012

Eighteen (18) More Permits in The Williston Basin, North Dakota; BEXP Has A Huge Well In "New" Area; SM Energy Has a Huge Well;

RBN Energy: update on natural gas experience and pipelines in the Northeast; how distribution patterns have changed in the US with the Marcellus

Bakken Operations

It looks like they are doing more with less. More permits, more drilling, more oil, less rigs. But we're holding steady with 189 rigs. Just for idle chatter: I expect to see a gradual decrease to 175 rigs during the winter, and then after the new Congress gets in place, and folks get a better idea of where things are headed, the rig count will stabilize or go back to 195.

The wells that came off the confidential list today have been posted. Some very, very nice wells.
Comment: last night there was a short exchange in the comments regarding the "wow" factor has not been reached for me regarding the Three Forks. I attributed much of that to the fact that compared to the middle Bakken, not a lot of TF wells have been completed. Today, three very nice Three Forks were reported. In addition, another reader wrote in to remind us of some nice Three Forks completed a year or so ago and are reporting great production.

A permit was canceled:
  • 23444, PNC, Hess, EN-Pederson 154-94-0409H-6, Alkali Creek, 
That's an interesting permit to cancel; it's on one of six wells on a single pad.

Eighteen more permits:
  • Operators: BEXP (7), Petro-Hunt (4), KOG (2), Oasis (2), Triangle,  Marathon, Strike Oil
  • Fields: Kanu (Bottineau), Stony Creek (Williams), Elk (McKenzie), Mondak (McKenzie), Avoca (Williams), Bailey (Dunn), Lucy (Burke), Banks (McKenzie), Eagle Nest (Dunn), Tyrone (Williams)
Producing wells completed:
  • 20053, 994, SM Energy, Nelson 15-11H, wildcat, t4/12; cum 60K 8/12; it may be a wildcat, but all for intents and purposes, it's in Siverston oil field; completion data not yet available; background gas ranged as high as 7,000 units; 60K in less than four full months from IP
  • 20899, 2,980, BEXP, Eldridge 29-20 1TFH, Briar Creek, t8/12; cum 8K 8/12; this is about as far west in North Dakota as you can get before you are in Montana; south of the river, just west of the confluence; this is a huge well for this area!
  • 22021, 1,135, BEXP, Bill 14-23 2TFH, Alexander, t8/12; cum 6K 8/12; 
  • 22036, 1,904, BEXP, Strobeck 27-34 4H, Alger, t8/12; cum 6K 8/12;
  • 22078, 92, Hess, AV-Wrigley Brothers -164-94-3130H-1, Forthun, t9/12; cum 1,396 bbls 8/12;
  • 22854, 888, Whiting, Estvold 44-26TFH, Sanish, t8/12; cum 5K 8/12; 
Comment: when I see that great SM Energy well and those three nice BEXP wells, and think of those companies complaining about high costs of drilling in the Bakken, all I can think of is: when the going gets tough, the tough get going.
"Interestingly enough, in Spanish there's really no word for wilderness. The notion here (in Mexico) is, nature has to pay its own way or there is no justification for its existence." 
CRC, who comments regularly on this blog, understands exactly what that means, I assume.

That statement was made by the wife of Mexico's leading environmentalist, Homero Aridjis, Betty Aridjis. -- The Eye of the Whale, Dick Russell, p. 73,

What I Learned Today: LNG Processing Units -- Trains

This was the lede in an Oil and Gas Journal story today:
Norwegian producer Statoil ASA and its partners have cited lack of sufficient natural gas discoveries in the Snohvit license area in the Barents Sea as the main reason for the decision to halt any plans to expand the project. Statoil stated Oct. 2 that the partners will instead focus on optimizing and upgrading the existing single-train, 4.3 million tonne/year gas liquefaction facility on Melkoya off Hammerfest.
That article holds exactly "zero" interest for me. Nada. Zilch. None.

But I was curious based on the headline. Yesterday that first paragraph would have made less sense to me. Today, I get a bit more out of it.

This is what I would not have been able to understand yesterday: "focus on optimizing and upgrading the existing single-train, 4.3 million tonne/year gas liquefaction facility."

"Single-train"? Say, what?

But earlier today I linked a story on LNG posted at The Oil Drum. In that article, this paragraph:
Most LNG plants have on site more than one processing unit — called trains. The trains operate independent of each other, running in parallel to liquefy methane. Qatar hosts the world's largest trains — the biggest can handle about 1 billion cubic feet of natural gas per day. Qatar's most massive plant, at the Ras Laffan complex, features two such trains plus four smaller ones that together can process about 5 bcf a day. That's about twice the volume as has been discussed for an LNG plant that could process Alaska North Slope gas. Alaska's Nikiski plant is relatively small, with capacity to handle about 200 million cubic feet a day.
So, today I learned that a liquefaction processing unit -- a train -- is different than the Bakken unit train.

Who wudda guessed?

I assume RNB Energy has mentioned this -- the liquefaction "train" -- in one of their highly educational articles but simply missed it.

For Investors Only: If He Had To Name Just One Stock For 4Q12 -- Union Pacific


Of course, most agree that Jim never seems to get it right. But that's neither here nor there. It's just idle chatter.

But on September 17, 2012, at the MDW was posted:
So, if the outlook is so downbeat, why am I in a good mood about the stock market? A buying opportunity. And where do I find best buying opportunities? What do I like? High-dividend payers. Energy. Railroads. I think one of the bigger surprises will be the earnings coming out of Bakken-centric companies. Lots of talk about cutting costs. We'll see. The recent reports of Bakken premium to WTI is very, very interesting.
Idle chatter.

Disclaimer: this is not an investment site. At best, just idle chatter some days.

UPS Experience With LNG: Beaver, UT, to Salt Lake City, UT/Las Vegas, NV

The Oil Drum has a long article explaining liquid natural gas (LNG). Very, very basic. After reading it, be sure to read the comments. The best comment provided an overview of the UPS experience in Utah:
  • 36 long-haul trucks 
  • the day shift: from Beaver, UT, to Las Vegas, NV (225 miles) 
  • the night shift: from Beaver UT, to Salt Lake City, UT (200 miles)
  • US government kicked in $4 million for buying the trucks 
  • biggest drawback, according to the drivers: frequent refueling
  • with diesel, one full tank would nearly be enough for a complete round trip. Now they have to re-fuel at each stop. [Diesel tank about 200 gallons; one gallon of diesel = 1.7 gallons of LNG; total LNG capacity is 190 LNG gallons; translates to 111 gallons of diesel equivalent (DGE -- diesel gallon equivalent).]
  • fueling: only with a certified individual; must wear a helmet with large plastic face guard to protect against splashing (-260 degrees temperature)
  • typically a LNG truck will cost between $30,000-$100,000 more than a typical diesel semi-tractor
  • the mileage these UPS trucks are averaging is about 5-5.2 mpg on gallon of DGE of LNG. It turns out to be about 8-10% less than typical diesel engines
Comment: some of the math didn't ring true for me (diesel truck tank, 200 gallons; barely enough to make a 400-mile trip?]. Other than that, seemed to be a great article and reasonable comments.

Comment: as "good"as CNG/LNG sounds, I just did not get a warm fuzzy for using CNG/LNG as a transportation fuel after reading this article and/or the comments. It really will be interesting to see how it all plays out in North Dakota with Heckmann/Power Fuels.

Seven Wells Reporting; BR Reports A Huge TF Well; Whiting With Two Nice TF Wells; Helis With Another Huge Well; OXY With Another OXY Well -- October 2, 2012

Active rigs:
Faster drilling, pad drilling, winter coming.
Wells coming off confidential list tomorrow:
21542, 2,978, BR, Ivan 11-29TFH, Elidah, t7/12; cum 95K 6/14;
21844, 140, OXY USA, Keary Kadrmas 1-32-29H-142-96, Russian Creek, t4/12; cum 64K 6/14;
22026, 1,040, Whiting, Stubstad 13-6TFX, Sanish, t4/12; cum 157K 6/14;
22027, 1,969, Whiting, Stubstad 14-6TFX, Sanish, t4/12; cum 173K 6/14;
22375, 814, CLR, Chicago 2-26H, Banks, t6/12; cum 143K 6/14;
21456, 2,014, Helis, TAT 13-35/26H, Grail, t7/12; cum 241K 6/14;
21478, 1,171, MRO, MHA USA 11-4H, Reunion Bay, t7/12; cum 195K 6/14;

Crude by rail: Nice story in Bloomberg BusinessWeek on Bakken, crude-by-rail, barge (reader sent in link, thank you):
Since 2008, Musket has been buying oil from the wellhead in North Dakota and railing it straight to the Gulf Coast refiners.  
“We were probably one of the very first people to make that move,” says Fjeld-Hansen. Initially, Musket sold its North Dakota barrels into Cushing. But Fjeld-Hansen says he hasn’t sold a drop of oil at Cushing in more than a year.  
Recently he’s also been sending it to the East Coast by rail, where refiners are stuck taking more expensive imported oil. He’s up to about 40,000 barrels per day.  
“Why would I sell into Cushing when the price is so depressed there?” he says. “Let’s say it costs me $9 to rail from North Dakota to Cushing, but it costs me $12 to go all the way to the Gulf Coast. If I can get an extra $10 to $15 at the Gulf Coast than what I would get at Cushing, why in the world wouldn’t I just keep going?”  
In an odd step back in time, railroads are moving more crude these days than they have since the early part of the 20th century. In 2009 railroads moved a total of about 7.5 million barrels. In the second quarter of 2012 alone they moved more than 36 million barrels. 
The trend has given a boost to railroad companies such as BNSF and Union Pacific. Rather than sign long-term contracts with pipeline companies, big oil producers such as Phillips 66, Statoil, and Hess are starting to lease and purchase their own rail cars. In a September note to clients, Goldman Sachs Energy analyst David Greely wrote that rail is starting to overtake the reversed Seaway as the biggest means of clearing out the Midwestern oil supply.

Question: Where is Black Cat Proppant Manufactured


October 3, 2012: for a great answer to the question below, click here.

Original Post

A reader sent in a comment asking if I knew where Black Cat proppant was manufactured. The company headquarters is in Ft Worth, Texas, but that doesn't mean manufacturing plants are there.

There are at least four distribution points in the Bakken for Black Cat proppant.

I originally opined that, based on the CARBO Ceramics story, the proppant was manufactured in Russia, but now that I see there is a distribution point in Seattle, WA, most likely this proppant is coming from China. It's "funny" no one corrected me when I first blogged about it so long ago.

Random Look at Case 18793, NDIC Hearing Dockets, October 24, 2012; Some Great Petro-Hunt Wells

Link here to quick summary of the cases.

It was hard not to notice case no. 18793. In its entirety:
Application of Petro-Hunt, L.L.C. for an order amending the applicable orders for the Charlson-Bakken Pool to:
  • (i) authorize up to seven horizontal wells to be drilled on a 640-acre spacing unit described as Section 27, T.153N., R.95W., McKenzie County, ND; 
  • (ii) authorize up to five horizontal wells to be drilled on an existing 1280-acre spacing unit consisting of Sections 4 and 9, T.153N., R.95W.; 
  • (iii) establish one new overlapping 1280-acre spacing unit consisting of Sections 16 and 17, T.153N., R.95W., and allow one horizontal well to be drilled on such spacing unit; 
  • (iv) establish two new overlapping 1280-acre spacing units consisting of Sections 3 and 10; and Sections 14 and 23, T.153N., R.95W., and authorize up to two horizontal wells to be drilled on each such spacing unit; 
  • (v) establish an overlapping 1920-acre spacing unit consisting of Sections 7, 17 and 18, T.153N., R.95W., and authorize one horizontal well to be drilled on such spacing unit; 
  • (vi) establish four overlapping 2560-acre spacing units consisting of Sections 4, 5, 8 and 9; Sections 5, 6, 7 and 8; Sections 21, 22, 27 and 28, T.153N., R.95W.; and Sections 6 and 7, T.153N., R.95W. and Sections 1 and 12, T.153N., R.96W., and authorize one additional horizontal well to be drilled on Sections 4, 5, 8 and 9; Sections 21, 22, 27 and 28; and Sections 6, 7, 1 and 12 and up to two additional horizontal wells to be drilled on Sections 5, 6, 7 and 8; and 
  • (vii) such other relief as is appropriate. 
So, what's the history of section 27-153-95?
  • 1951, Petro-Hunt, a Madison well; last production in 2009; t9/58; cum 523K;
  • 2259, Texaco, a Madison well; PA; t5/59; cum 114K;
  • 2421, Texaco, a Madison well; PA; t12/59; cum 520K;
  • 2394, Petro-Hunt, a Madison well; PA; t8/59; cum 206K;
  • 6207, Prosper Energy, a Silurian well; PA; t2/78; cum 118K;
  • 6366, Petro-Hunt, a Madison/Silurian well; t5/78; still active; cum 344K from the Silurian; cum 130K from the Madison; 
  • 6514, Prosper, a Silurian well; PA, t7/78; cum 47K;
  • 6592, Petro-Hunt, a Silurian well; PA; t12/78; cum 321K;
  • 10086, Petro-Hunt, a Madison well; TA; t6/83; cum 136K; 
  • 10771, Amerada Hess, DRY, a Silurian well; I guess one can only squeeze so much blood out of a turnip;
  • 11735, Thomas A. Haugen Operating, a Red River well; PNC
  • 11802, Filco, Silurian/Red River/Bakken; still active but doing almost nothing; cum 23K from the Bakken; 62K from the Silurian; Red River DRY; 
  • 17400, 546, Petro-Hunt, Bakken, Sherven Trust 27B-2-4H, t3/09; cum 141K 8/12; 
So, although most of the wells are no longer active or doing much, this one section has produced almost 2.7 million bbls of oil with few misses.  Now, Petro-Hunt wants to drill another six horizontal wells, with a potential of another three million bbls of oil (and that's primary production). One section with the potential of 6 million bbls or more. (Most folks accept EURs of 500K in the better Bakken; some suggest as much as 1 million bbl-EURs in the best Bakken. The Charlson seems to be between "better" and "best.")

And, the relevant history of sections 4/9-153-95?
  • 12031, 407, Petro-Hunt, Silurian 54-1; t5/87; cum 530K 8/12 (but not doing much any more)
  • 20342, 1,430, Petro-Hunt, USA 153-95-4B-9-1H, a Three Forks well; 25 stages, 3 million lbs sand, t1/11; cum 472K 6/14
In section 28-153-95 (a reader alerted me to this one, thank you):
  • 19845, 1,084, Petro-Hunt, Van Hise Trust 153-95-28C-21-1H, Charlson, t8/11; cum 211K 8/12; wow, > 200K in a year!
As I mentioned to the reader who alerted me to this well, I am really impressed with Petro-Hunt: a lot of permits/wells and very good wells to boot.

Enquiring Minds Want To Know -- Random Notes From Another Planet -- Page 2

February 7, 2013: "... premium members get production figures in advance." One can get production numbers from "basic services" for $50/month. Production numbers are also free in a monthly report but they lag about a month. Regardless, here are the oil production/runs for the four wells requested for December, 2012:
  • 19585: 16 days -- 2,023 / 1,991
  • 20980: 31 days -- 7,435 / 6,860
  • 21006: 31 days -- 9,472 / 9,784
  • 21007: 31 days -- 9,881 / 9,671
February 2, 2013: I see enquiring minds are talking about commingling. My two cents' worth. I can guarantee the enquiring minds that the operators know exactly how much oil is coming out of each well. The production from each well is measured/valved before it goes into the tanks. One reason permission to commingle is required dates back to when various grades of oil from different formations were commingled. The crude oil from each of these commingled Bakken wells may vary, but if they do, the variance is minimal. This will not affect one iota one's royalty payments. The second issue raised by the second comment at this thread raises the issue of spacing, which, of course, has nothing to do with commingling. The comment suggesting that spacing favors the operator and not the mineral rights owner(s) is an opinion, not based in fact. Here's an easy example: if the spacing made a proposed well uneconomical, it wouldn't get drilled in the first place. Mineral rights owners in the Bakken are doing just fine, and they are going to do even better going forward. Most never expected one well on their land, much less fourteen wells. 'Nuf said. [Update: Teegue says the operators don't necessarily track each individual well once they are allowed to commingle oil from multiple wells. I assume that's accurate; Teegue is a credible source. I find it incredible that oil companies would be able to get away with this; it seems incredibly easy to measure/monitor oil coming from each well before it is commingled. It seems it would be in the operator's best interest to know how a particular well is doing.]
January 31, 2013:  this comment was sent in by CRC earlier today:
Outside of the Bakken and the Williston Basin the rebirth of the Permian Basin is very interesting. The way the Cline and other tight shale oil formation are developed will be a nice example of the old way of drilling by vertical wells spread all over the place in a section of land and the new spacing units with all the wells on one pad. I'm sure they are doing that in the Eagle Ford because it is a tremendous savings in drilling and developing of the wells.
This is a very interesting observation. Dufus and others would have placed 6 vertical wells over each section for 160-acre spacing rather than on one pad. We would have had six (or more) pads on each section of land; we would have had individual roads to each pad. The expense would have been incredible, but worse, the amount of farmland lost would have been incredible. Whether smart or lucky, the NDIC did the right thing for the majority of North Dakotans. Those NoDaks who hate oil wells could have easily seen six or more pads on each section instead of one pad with multiple wells had other folks been in charge. Just an observation.

January 30, 2013: if there is one thing enquiring minds do not like, it is posts about the stock market, investments, and investors. I learned that the first time I posted. Smile. So, it was with some interest when I read a post from Dufus about OXY some time ago, and now we see another individual posting on Hess as an investment Handle with care.

January 25, 2013: speaking of amusing sites, enquiring minds are developing a very nice thread on the potential of the Bakken. Hopefully the moderator will allow the thread to develop. Smile. One expert argues that additional wells will negatively impact neighboring wells. A year from now we should have some data, starting with the fourteen wells CLR is drilling in one spacing unit in the Antelope oil field. The simplest data point to follow if looking at Bakken potential: the takeaway capacity. The consensus is that North Dakota oil takeaway capacity will be 1.5 million bopd by the end of the year (2013). I forget when such capacity is to double to 3 million bopd but I think its by 2017 if not a whole lot earlier. But the 1.5 million bopd by the end of 2013 was quoted just a few days ago by a reputable source. [It has been argued that the oil companies have said they could effectively drain one spacing unit with one well; that seems to have been a stretch in hindsight, but if one well could effectively drain one spacing unit, it sure would have taken a lot of time. I suppose taken to its extreme, one could argue that one well could effectively drain the entire Bakken, it being a continuous reservoir. Now, that's amusing.]

January 20, 2013: This question has been resolved at the link, noted at 9:45 pm est, January 21, 2013: an enquiring mind has the same question I do. How does one sort out mineral rights with 5,000-foot laterals on 160-acre spacing that is about 2,500 feet x 2,500 feet. See also the January 16, 2013, note below. Of all the folks who post at that discussion board, I think there is only one who might have the answer. It will be interesting if ell1949 gets an answer. [Several hours later, 3:40 pm: no response to ell1949's question; not unexpected.] [January 29, 2013: I see Dufus is back. Regardless of which side you are on regarding spacing units in the Bakken, two things jump out at me: a) there is a lot of 20/20 hindsight by folks who are making out like bandits with 14 wells on their acreage; and, b) everyone was on a steep learning curve with regard to developing the Bakken. Iraq had their way of dealing with oil wealth; North Dakota had its way. We're all on earth for only a few short years. Those of us fortunate to have it so good, should enjoy it, instead of calculating "what might have been" with another 0.0000003% royalty. IWWJWD.]

January 18, 2013: either I will learn something, or there is some wishful thinking by some (usually I'm wrong, so maybe I will learn something, but I digress. An enquiring mind says that #20502, Hagen 23-13H, sited in section 13-148-101, is a directional/horizontal well that goes southeast into section 24-148-101.  This is a Madison well, and according to the NDIC site, the spacing is yet to be determined (ICO). The enquiring mind says the well extends into sections 14 and 23 to the west; I don't see that at all. I have no idea why someone would think that a Madison well in sections 13/24 would be associated with sections 14/23. It will be interesting to see how this one is answered, assuming someone answers. [It has been explained; the enquiring mind was looking at the Bakken spacing, when in fact, this is a Madison well. Had this been a Bakken well, yes, the other sections would have come into play. A good question, in hindsight.]

January 16, 2013: elsewhere they continue to discuss spacing in the Williston Basin. It should be noted that some folks continue to compare apples with oranges. In this case the Bakken Pool is being compared with an entirely different pool. Also, comparing apples to oranges, horizontal wells are being compared to vertical wells. In addition, I never see the economics of the well worked out from the oil companies' point of view when this issue is discussed in this context. Beating a dead horse. From my perspective, the NDIC is doing a great job for the citizens of North Dakota when it comes to the Bakken. They seem to "get it." [Update: second post at the link above -- wow, even folks who have followed the Bakken for quite some time, don't understand the issue with flaring. I am (negatively) impressed. Wow. And suggesting the NDIC is pushing too much drilling. Yeah, I guess "we" need more regulation; let the regulators determine how oilmen manage their assets. Wow.][With SSN's permits for four (4) Bakken wells with 160-acre spacing posted January 18, 2013, will further the discussion. Smile.]

January 4, 2013: a contributor has remarked on EOG's results with regard to water injection

January 2, 2013: an enquiring mind wants to know the difference between "IP" and "IP-30." Apparently this question has flummoxed the discussion group, so I will jump in. The "IP" as generally reported is a self-determined (determined by the operator) production of oil coming from a well in the first 24 hours. Different operators have different ways of calculating this initial 24-hour production. The "IP-30" production is the average amount of oil a well produces over the first 30 days of production. Some analysts also track the 60-day average and the 90-day average, which, I suppose, is written as IP-60 and IP-90 in shorthand. Note: be careful to note the difference between "bopd": barrels of oil per day; and "boepd," barrels of oil equivalent per day, which includes natural gas in addition to oil. [By the way, that question was posted at the discussion board on December 31, 2012. As of January 3, no one had answered the question. Speaks volumes about the contributors to the group. No doubt, folks have found the answer. Smile.]

December 22, 2012: an enquiring mind is wondering whether #22952, Hess, GO-Dahl A-156-97-2536H-2, is a middle Bakken well or a Three Forks well The enquiring mind says the file report suggests this is a Three Forks well. I've made the same mistake in the past: mis-reading a sundry form. A sundry form does mention "Three Forks" but it is referencing a neighbor well for "comparison" purposes. But this well is most definitely a middle Bakken well; see the geologist's summary. Additional information: the well was spud July 8, 2012, and reached vertical depth on July 17. Total depth was reached on August 4. Fracked in 30 stages; 2.3 million lbs sand. Along the horizontal gas values were 75 - 7,500 and "several gas tests were done to ensure the accuracy of the equipment." The report did not mention the height of the flare, unless I missed it.

December 14, 2012: enquiring minds have been uncharacteristically quiet lately -- I can understand why.

December 11, 2012: please, do not mention this site elsewhere; you will be kicked off the board.  As my daughter would text, LOL.

December 11, 2012: some interesting reading today over at the other board. Of course, some of it does not make sense because several messages have been deleted. Whatever you do, don't mention the MDW at that discussion group; you will be "voted off the island."

December 10, 2012:  Not often do we get such an informative post elsewhere.  When you get to the link, scroll down about six posts, and read the post by "Degas." This is an excellent resource for newbies.

December 8, 2012: In the process of looking for something else, I ran across this lively discussion: reading through this discussion is entertaining. It is amazing how far "we" have come. As just one example:  "My belief is that a good separation for laterals is ~ 4,000 feet and a good lateral length should be based on economics." -- posted March 4, 2012. I remember that discussion so well. Suzanne had asked a simple question and by the time the discussion was over, she was apologizing for getting so many people upset. So many of the original contributors to that discussion group have gone by the wayside. Just reminiscing on a Saturday night. Some folks appear to have evolved with the Bakken; others not so much. 

November 29, 2012: So much for confidentiality, link here.

November 25, 2012: an enquiring mind wants to know why sections 1, 2, 3, 11, and 12, in McLean County are not yet permitted. Of course, not surprisingly, critical information, LIKE THE TOWNSHIP, is missing. But it is obvious it is T150N-R90W.  These sections are under the river; there are a lot of sections under the river that are still not permitted. No conspiracy theories. I wonder if it might have to do with who owns the mineral rights under the river: US government (US Army Corps of Engineers); the state; private landowners)?

November 24, 2012: some time ago I referred to some of us being on different planets when it comes to thinking about the Bakken. I think Dave's position about sums it up best at this post. Some folks must not be following the permitting activity or the monthly NDIC dockets.

November 21, 2012: elsewhere they are talking about how long it takes to get a permit approved. The answer is very, very enlightening and raises an interesting question in the process. First, the very interesting answer: it rarely takes more than a few days to get a permit approved once the application is received. That is interesting: do you think that will hold true when the federal government regulates fracking in the Bakken? Remember, if the federal government regulates fracking, the in-box will contain hundreds of permit applications received daily from all across the nation. Just thinking about the bureaucracy is Halloween-scary. But I digress. But then this interesting question: once the first well is drilled, all further wells in that spacing unit are "discretionary." It is asked, rhetorically, if the first permit holds the entire spacing unit by production, why are seven more permits/wells required. (And, of course, in the future, it could be more than seven).  I thought I misunderstood the question, but it is explained in further detail here. I would love to comment but I have no dog in this fight. It is what it is. I wonder if there are Solomonic decisions needed based on the differences of pools vs continuous reservoirs? I wonder if North Dakota is unique (compared to Texas, Oklahoma, Pennsylvania) with regard to spacing units in continuous reservoirs elsewhere?

November 9, 2012: I hope Tami's question is answered. It will help educate folks on royalties. Tami claims she was told "her well" is on a 640-acre spacing unit, though now she is told it is on a 1280-acre spacing unit. She calls it the "1-Osmund well." That's why permit numbers are so helpful. The spelling was wrong; there is no "1-Osmund" well. It is the Osmond 1-3H well, #19090, East Fork field.  The spacing is "two sections" and if she goes to the NDIC site, she will find the spacing on this well is 1,331 acres.

This phrase in her post does not make sense: "I was told I had 160 acres on 640 spacing with 20 net
acres." How does one get 20 net acres out of "I had 160 acres on 640-acre spacing"? So, if this question gets answered I will learn something.

Her question: "I was told I had 160 acres on 640 spacing with 20 net acres and 3/16 base royalty which gives me a decimal of 0.005859375 -- they show me having royalty at 0.00093380, which is nowhere close to what I was told from Landman. The guy from Continental said it was 1280 spacing, however even with this, it doesn't reflect a correct royalty int number."

Working backwards. The 3/16 is likely correct.

(her net acres/total acres in the spacing unit) * 3/16 = 0.005859375
(her net acres/total acres in the spacing unit) * 0. 1875 = 0.00589375
(her net acres/total acres in the spacing unit) = 0.031433
So, if the spacing unit was 640 acres: 0.0314333 * 640 = 20 net acres (her figure)

If the spacing unit was 1280 acres:
(20 net acres/1280) * 3/16 =
(20 net acres/1280) * 0. 1875 = 0.002929, which, is, of course, exactly half of the above figure, and like Tami says, nowhere close to the CLR figure.

Wow, I would hate to be her landman when Tami telephones. My hunch: Tami inherited the acres, but so did a few other children/grandchildren over the years, or her grandparents sold a few of the mineral acres some time ago. The landman did not know about the other heirs. Idle chatter. I may be way off on this but it will be a learning lesson.

By the way, on 1,331-acre spacing, CLR's decimal of 0.0093380 works out to about 66 acres.

November 6, 2012: the boys have noted what Oasis is doing in the Cottonwood field: asking for 23 more 1280-acre spacing units and 8 wells on each. MDW posted that several days ago

November 3, 2012: enquiring minds don't dare mention the MDW blogsite by name elsewhere -- otherwise they would be booted off -- but I have to chuckle. After months (almost two years) of no one talking about potash mining in North Dakota, I see that enquiring minds are talking about it. I posted the same update some weeks ago. I am flattered. Thank you, guys. We need to spread the word even if we don't reference the source.

November 1, 2012: NDIC defines Bakken/Three Forks down to the Birdbear. That's where it's always been scientifically/geologically. 

October 31, 2012: still lots of chit-chat about the stratigraphic limits, but now they are simply plain nuts. My hunch is that if NDIC does not approve the requests, the oil companies will simply wait "them" out. Most of their leases are now held by production. If mineral owners want to see more wells, they might want to work with the oil companies. Otherwise, the oil companies will simply wait them out. These guys are nuttier than fruit cakes. I think Dufus is the worst. They need to move this discussion over to the water cooler. What used to be a pretty good discussion group has become a) entertainment; and, b) an exercise in futility. Again, it makes me glad not to be a mineral owner. Life is too short.

I'm Going Slightly Mad, Queen

October 11, 2012: an inquiring mind wonders about the sharp drop-off in production of a particular well in August; the well was taken off line for twelve days in August -- of course, there is never an explanation in real-time, but my hunch: they're putting in a pump.

October 10, 2012: an inquiring mind wants to know about
  • 19051, drl, Surge, Eidsvold 1-10H, Wildcat, a Spearfish well; spud 6/8/10;
NDIC sent the operator a letter indicating that the well has not been completed or produced in over a year, and is in violation of Section 43-02-03-55 of the North Dakota Administrative Code (Abandonment of Wells). The rule that states that the failure to produce a well for a period of one year constitutes abandonment of the well. Any such well must be plugged and the site reclaimed. And the letter goes on. 

October 9, 2012: enquiring minds noted the dry holes on today's daily activity report. Except for the Samson Resources Lodgepole well, it appears these are changes in the operators' plans; not "true" dry holes in the sense that I think when I see "dry" holes. This gives us a chance to see how life on another planet sees this one. [Update, October 10, 2012: so far, they've missed the reason for the "dry holes."]

October 5, 2012: enquiring minds are debating the issue of "free" vs the $50 annual basic subscription rate. I agree with David. And I own no mineral rights.

October 2, 2012: time for this discussion to be moved over to "the water cooler." I'm waiting for the results of the hearing regarding the requests to alter the definition of the Bakken/Three Forks stratigraphic limits.

Halcon To Add Four to Six Rigs in the Bakken, East Texas

From Yahoo!In-Play:
Halcon Resources provides operational update; co estimates that it will add four to six operated drilling rigs to its resource style drilling program by year end 2012. 
The recently closed acquisitions of GeoResources, Inc. and assets in East Texas were structured to bolster the Company's production profile and reserve base while providing additional growth opportunities in liquids-rich regions. 
Halcon continues to transition from the leasehold acquisition phase of its development into the drilling phase with 11 operated drilling rigs currently running on resource style assets. The Company estimates that it will add four to six operated drilling rigs to its resource style drilling program by year end 2012. Halcon Field Services LLC, a midstream subsidiary of Halcon, continues to work on infrastructure construction and solutions in all areas of activity.
How many of those would go to the Bakken was not mentioned in the note.

For Investors Only: At Barron's -- Oasis --Top

From Barron's:
While we may be in the later innings of the long-oil/short-gas trade, we believe we are not yet in the bottom of the ninth. We believe well-capitalized operators with sufficient scale in oil basins and/or optionality on natural gas should continue to outperform.  
We reiterate Energen and Pioneer Natural Resourcesas our top large-cap picks, and Oasis Petroleum as our top small-cap pick.
Thousands of energy companies from which to pick out there, and obscure little ol' Oasis gets picked up by at least one analyst as "our top small-cap pick."

Disclaimer: this is not an investment site. I simply aggregate obscure (my word for the day) news stories while waiting for real news to break.

Links From Today's WSJ, and Elsewhere -- October 2, 2012

In light of the recent discussions regarding the re-distribution of federal monies, this little nugget is interesting and why reading the WSJ is so pleasurable. From the October 2, 2012, print edition of the WSJ, page B2:
The Washington Post buys a majority stake in Celtic Healthcare, a provider of home health care. The deal comes as the Post's longtime cash cow, the Kaplan's higher-education unit, is suffering from tighter government regulations on the for-profit college sector, helping to send operating profit down 84% in the second quarter. 
The home health-care industry and for-profit colleges have parallel business models, in the sens that they both lean heavily on government funds. The overwhelming majority of students in for-profit colleges take out student loans, and the federal government makes or guarantees the overwhelming majority of student loans. -- WSJ, page B2.
Google the 60th vote regrets for a nice op-ed in the WSJ on how ObamaCare was passed -- for those who don't remember the story.
Elizabeth Warren, the first woman of color admitted to Harvard Law School, running for Senate in Massachusetts says she could work with GOP Indiana Senator Dick Lugar; he's out of office in three months. Okay. Maybe Luger will return to Capitol Hill as a lobbyist. From the Drudge Report. Wow, I'm glad I didn't watch that debate, and I won't be watching the presidential debates either.


The Ryder Cup: American Team -- all 12 members of the US team attended college, some of them elite colleges. UK team -- just two members of Europe's team attended college (in the US). Google golfers should cut class
"Oregon State is the surprise of the college-football season so far, upsetting No. 13 Wisconsin and Arizona en route to a No. 14 ranking. But if anything can derail the Beavers' hopes, it's not their anemic run game or brutal schedule, it's this: their proximity to an In-N-Out Burger." -- The WSJ.  Google Oregon State's hamburger helper.

Remember that XOM-DNR deal? At the same time that deal was being hammered out: In a separate agreement, Denbury will either purchase CO2 from the LaBarge Field from XOM or will purchase an interest in reserves in the field. The $1.6 billion in cash from Exxon will be reduced by the amount of the CO2 agreement. Hold that thought; you will see it referenced again, below. 

A random comment on Willie Nelson's Red-Headed Stranger. This is an incredibly original album and has gotten better over time. I remember reading that when the record company front office bosses heard this album, it was mostly, "are you kidding?" The rest is history. Every genre of music is featured, I suppose, except orchestral/symphony -- but if I listen long enough, I will probably hear that also. As I write that I think back to the XOM-DNR deal. Yesterday we saw an analysis of the deal, Part I, and waiting for Part II.

This is my take on the XOM-DNR deal; this is what I think happened:
a) The facts, stretched: DNR's wells were 15 to 20% less "good" than Oasis wells (earlier SeekingAlpha story). DNR in North Dakota didn't fit DNR's strategic vision. EOR in North Dakota is a ways off (years from now). And no CO2 infrastructure (pipelines). North Dakota is also a miserable place to have to fly to for the DNR folks who are mostly in Texas, Wyoming. North Dakota was a thorn in their side: a) remote; b) less than great wells; c) not in their EOR vision; d) no CO2 infrastructure -- in short, a nuisance. 
b) So DNR went to someone with deep pockets -- they didn't care who, just someone with deep pockets. XTO was already there, so they said, "What the heck, let's ask XOM if they are interested in our Bakken property -- and, oh, by the way, XOM has some acreage down where we (DNR) have some EOR property. Wow, what a great fit. Let's see if XOM is game. (Some recent MBA graduate working at DNR probably put 2+2 together -- XOM acreage in DNR's backyard in Texas and Wyoming, and XTO in the Bakken -- "Hey, isn't XTO a subsidiary of XOM now?" It was probably over a 3-martini lunch.) 
c) DNR pitches it to XOM. A 10-minute PowerPoint presentation. XOM/CEO fiddling on back of envelope during presentation: 
i) It will cost me $1.6 billion in cash 
ii) Gee, I (XOM/CEO) have $20 billion in cash; $60 billion in operating cash flow; and a market cap of $425 billion. And this is going to cost me $1.6 billion at most. Let me check my wallet. 
iii) Why am I even listening to this 10-minute presentation? I could be out golfing. $1.6 billion for more acreage for my XTO boys to fool around with? Ah, why not? Sure, if DNR wants to dump 200,000 acres on us, that's fine. It's a bullet on some (XOM) slide down the road. Shoot: the Bakken may be important if Harold Hamm becomes SecEnergy. 
iv) Gotta make it look like I'm good at negotiating. Let's say I take DNR's deal with the understanding that DNR buys my (XOM) CO2. That brings the price down to $1.5 billion. Maybe less.
iv) Where do I sign? Let's go golfing.
d) And that's the way it happened.