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Bakken Update: Williston Basin Estimated Ultimate Recoveries In North Dakota – Part I

October 31, 2012 | 94 commentsby: Michael Filloon | includes: CLR, COP, EOG, HK, KOG, OAS, SSN, WLL, XOM Disclosure: I am long KOG. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article. (More…)

The North Dakota/Montana Bakken may not be the best way to play the United States’ unconventional oil. The Williston Basin has high well costs, difficult weather conditions, and insufficient pipeline capacity. Both the middle Bakken and upper Three Forks are deep, which increases costs. Cold winters and spring floods can create a difficult environment for drilling wells or transporting fluids. Bakken crude trades at a significant discount to WTI, and forces some producers to send it by train to areas like St. James which has LLS differentials. Although Mountrail and McKenzie counties have produced some very good wells, it cannot compete with specific areas of the Eagle Ford.

We have been hearing these negatives for years, but still the Williston Basin remains an area of interest from some of the world’s best oil producers. What is important is its sheer size, and the number of barrels of oil it houses. All these oil producers need to figure out, is how to get a fraction of it out to be profitable. The Bakken formation covers approximately 200000 square miles. To put this into perspective, the Eagle Ford in Texas is 20000 square miles and is broken into three windows. Only approximately one third of this play is considered oil dominant, and only half the play is considered economic. The most expansive shale gas play in the United States is the Marcellus, which covers 95000 square miles.

The middle Bakken is not the only way to play the Williston Basin, as there are several pay zones here that are economic. The middle Bakken is not the top oil producer in North Dakota when cumulative historical production is used.

Total cumulative oil production through December of 2011 in the middle Bakken is 330,894,036 barrels, while the Madison has produced 923,137,262. The Madison has been a focus of vertical production over the years, and much of this was drilled on and around the Nesson Anticline. Other pay zones include the upper Three Forks which has not been as productive as the middle Bakken, but economic none the less. Below the upper Three Forks are three additional benches. The second bench is estimated to be as good as the first and covers roughly the same area. Continental Resources (CLR) and Burlington Resources (COP) have both completed productive wells in the second bench. There are tests being performed on the third and fourth bench, but there is little by way of information. The third and fourth benches are spottier in nature, with good and bad areas throughout the Basin. The interesting fact in these lower two is the thought both could be completed with one lateral, but this has not been substantiated. The thickest portion of the middle Bakken reaches 120 feet, while the Three Forks peaks at 270 feet.(click to enlarge)

The Pronghorn Sands has been productive in Billings and Stark Counties. This target was called the Sanish Sands, but recently received the name change. The Pronghorn has been worked by several Williston Basin producers, but Whiting seems to be setting the tone here. In the Mondak area, Slawson has done some work on the upper Bakken. In this area it has measured thickness in the thirty foot range. These wells produce low IP rates but deplete slower and are cheaper to drill and complete. The Red River is also emerging as a new way to play this basin. Operators like Whiting (WLL) and Continental are working it in Golden Valley County. This is a vertical play with lower costs.

Costs differ significantly from one source rock to another. Middle Bakken well cost range is $9.5 to $10.5 million in deeper areas. These wells will produce estimated ultimate recoveries or EURs in the 750 to 900 MBoe range. Red River well costs are in the $3.2 to $4.0 million range and produce EURs of 200 to 400 MBoe. It has been reported that the Red River play extends from Wibaux north to Sheridan counties in Montana. It has been rumored that Samson Oil and Gas (SSN) has accumulated acreage in Bottineau County for the purpose of working the Mission Canyon and Nisku formations. There are a significant number of targets and we should obtain clarity as these plays become economic with the rising price of oil.

Continental’s acreage is probably the best way to identify premium Bakken acreage. It could be said that Continental has acquired better acreage than any other producer when the scale of its acreage is considered. The core of its acreage (green/yellow) runs in a north to south configuration from southeast Divide to northwest Dunn. Above in green is Continental’s acreage that is held by production, while the yellow is not. It has focused its program identifying good acreage on and around the Nesson Anticline. Its core Montana acreage was done in the same fashion, with the majority of acreage being located in the Elm Coulee Field. This has been a very good plan as many of the best Bakken wells have been in northeast McKenzie and western Mountrail counties. Although there have been many upward revisions, currently Continental gives average North Dakota middle Bakken EURs of 608 MBoe. This says little about specific areas, but gives an idea of total resource to be garnered.

Kodiak Oil and Gas (KOG) is another way to play the Bakken. It developed its completion style while working the non-operated end of a JV with XTO Energy, a company purchased by Exxon Mobil (XOM). Kodiak is known for using the best well design, and has helped to elevate the company to one of the best producers in the Bakken. The picture below shows Kodiak’s prospects in North Dakota and Montana.

Bakken Update: Riding The Refiners Tue, Feb 5 Bakken Update: Triangle Petroleum is A 2013 Top Bakken Stock Pick Mon, Jan 28 Bakken Update: 2013 Top Bakken Stock Picks, Part 3 Fri, Jan 25 Bakken Update: 2013 Top Bakken Stock Picks, Part 2 Tue, Jan 22 Bakken Update: 2013 Top Bakken Stock Picks Sun, Jan 13 Share this articleShort URL: 33inShare1 Comments (94) All (94) Author’s Picks () Register or Login to rate comments » rjj1960 Comments (880) Mike, great review as usual, appreciate the work you do with all the Bakken companies. 31 Oct 2012, 06:58 AMReplyLike3 Atticvs Research Comments (159)

If you get the opportunity I’d be interested sometime in the future in seeing a schematic for each/most major driller in the Bakken showing, over the past, say, 18 months or so (the time factor is useful in indicating the company’s direction), what their all-in fully loaded costs per barrel is i.e. down to the profit before tax line.

As you know, maybe better than anyone, some companies have great wells whilst others have cheap wells and for investors there is a line to be walked in terms of what’s great for an engineer or geologist and what’s great for an investor.

The reason I ask this – and I know it’s a big ask (sorry!) – is that whilst I see the logic for oil prices staying in the Brent $100-$110 range and WTI around $80-$90, I do have some concerns that the sheer volume of oil shale production in the next couple of years should, at least for periods, exert some downward pressures on the oil prices. Certainly, given the damage that higher oil does to economic activity, I cannot see any realistically higher oil prices aside from some ultra-brief spike. Besides, the after-tax returns available to virtually all oil shale producers are much higher than industry norms – and history suggests that substantially above average returns tends to attract more capital and over time this drives down the available returns. I’m not predicting a collapse here (no way), just lower profitability – hence the kernel of my opening request to try and identify the all-in cost per barrel of the various producers. For simplicity and in order to concentrate on operational efficiency alone I’d ignore hedging.

It’s a big exercise, but I believe it would serves as an extremely useful reference point for investors and, over time, it could be updated to keep the information current. It would be especially valuable during those periods when oil shale stocks dip, as they have done sharply this past two summers. This article, more than most others, nicely portrays the significant potential of the Williston Basin. Greater drilling efficiencies along with improved well productivity will yield consistent excellent economic returns for decades to come. 31 Oct 2012, 08:31 AMReplyLike3 Bob de’Long Comments (495) Michael, I never have understood the emphasis on EUR. All that really counts is the production in years 1-3. Production falls rapidly. Discounting cash flow further eats away PV of future production. It’s sort of a double geometric-decline in PV of future production.

These E&P CEOs and CFOs talk a fancy game of IRRs and EURs. But, back-of-the-envelope, they just look at gross production in some short time frame (3 years is my guess) and multiply it by $50/bbl net/net (another guess).

I look almost exclusively at payout. Take a Red River well costing $3.5 million. If WLL gives us IPP and average production at 30, 60, and/or 90 days, I can guestimate a payout. Fantastic is 6-9 months. Over 18 months is getting pretty marginal in today’s boom. 31 Oct 2012, 09:20 AMReplyLike5 Economic analyses have always been pretty comprehensive and sophisticated; they’re even more so for the new resource plays. Time frames typically span 30, sometimes 50 years of total production forecasting.

While production rates associated with the ultra-low permeability reservoirs decline rapidly early-on, they level off to a sustained decline of 2% – 3% per annum for decades.

So, if payback occurs anywhere from 6 – 18 months, there will be decades of fairly stable & consistent net cash flow, ‘free and clear’.

There is no doubt up front production is very important, but models used to develop EURs are as well. Most models produce half of total production in about 5.5 years. If we look at the better wells (and there are a large number of them now) which will produce EURs of 1000 MBoe, then 500 MBoe is yet to be produced after those 5.5 years have past. I agree with you on the Red River play, but vertical production is hard to come by these days. What might be more interesting about the Red River is what others areas in the Williston Basin are productive for this source rock. It’s interesting to me that, despite analysts concerns, whiting (WLL) has actually been able to improve production metrics as they have moved away from sanish and into pronghorn, lewis & clark (three forks) and hidden bench (middle bakken and three forks). http://bit.ly/TXmXhk

Watch the COP profit on the superior economics of their eagle ford acreage.

I would agree that they are increasing production, but have focused on adding stages and not so much water and ceramic proppant. It has kept been able to keep well costs down, looks to have one of the better payback timeframes, but longer term these wells will deplete faster. A good tutorial on the Bakken region and what is working and what isn’t. I keep coming away with the view that almost everything is working at present oil prices, and when the price differentials finally come close to disappearing almost of these wells are going to be earning a lot of money for a lot of years.

My biggest worry is the one that Atticvs outlines above. Will the flow of oil from all the shale drilling push down the price of oil overall? So far it hasn’t–though I think it has somewhat restrained the rise in oil’s price.

I am not as worried about increased US oil production pushing down the price of oil internationally, as I am a double dip recession. I think many of the firms that have said they think WTI could slip to $60 next year are forcasting problems in Europe will worsen, and the US stock market will have another large pullback. Some think China has been untruthful about its growth as well. I dont think this will happen, but I am a little worried about the short term. 1 Nov 2012, 01:20 AMReplyLike3 Squire Comments (5) The international economy is critical to demand, though it is hard to get a handle on it. I do not focus so much on Europe any more, and more the third world, for I think the majority of growth will come from there. I might also point out, that the oil drilling techniques that are being developed in the shale areas, are lending new life to old US wells, as they are applied to those areas. So, overall US production will increase not just from these new area, but also the old well areas.

That would depend on the particular company, but $60 oil is needed for the good parts of the Bakken play, but I have heard some companies say $55/Bbls are breakeven. There are alternate routes to get LLS premiums or NYMEX premiums if the differential continues. they are already doing this and the midstream capacity to move it east and west or all the way to gulf coast is only going to increase as time goes on.

What isn’t being factored in are the advances in recovery methods that will occur over time. The well bores, collection systems, water disposal systems, etc., will alll be there when the technology advances to get a higher % of the oil out of the ground. There is a LOT of the oil (90% plus) being left in place that will be recovered with new technology and at lower cost per barrel as the well and the infrastructure will already be in place. One company was delivering up to 40,000 barrels per day of cheap crude from North Dakota’s Bakken shale play by rail to Phillips 66′s 238,000 barrels-per-day (bpd) Bayway refinery in Linden, New Jersey, double the amount shipped in the second quarter.

I’m very confused on this subject. EOG is saying the Bakken won’t see enough pipes for at least the next 5-8 years, so crude-by-rail is the ONLY way, and worse still, they see east coast destinations only being viable after 3-5 years.

This seems like a slow motion train wreck for WTI, and the Bakken spread. EOG says they need $90 WTI to make their cash flow #s to keep up w/ their cap ex. Also, it is my understanding that US crude is NOT allowed to be sold outside the US, and the Gulf coast can only take another 750Kbbl/day (by stopping foreign imports), and they can’t build enough new refineries (I don’t think), so isn’t this a disaster in the making??

Mark G. Papa – Chairman and Chief Executive Officer

Yes, Bob, I really think that crude-by-rail is going to be around for a long time in EOG’s system. I think the lag time on getting pipelines built is really something like 5 to maybe 8 years. So it’s — the crude-by-rail is not just to stop gap measure, in my opinion. In other words — and I see the crude-by-rail destinations perhaps changing 3 years, 5 years from now, such that perhaps Louisiana is not the optimum destination to deliver the crude to depending on what market conditions are at that point in time there. So but I would guess that 5 years from now, 10 years from now, crude-by-rail is still a significant kind of a market uplift for EOG’s crude marketing. And did you have a second part to the question there?

Bob Brackett – Sanford C. Bernstein & Co., LLC., Research Division

Yes. What’s the sort of payback period on a loading terminal?

Mark G. Papa – Chairman and Chief Executive Officer

There, at least in EOG’s experience so far, it’s in months rather than years. 17 Nov 2012, 01:40 AMReplyLike1 Michael Filloon Comments (2921)

I think some of this talk about not having an appropriate amount of pipe has to do with a fear the Keystone won’t get done. Personally, I think it will be but politics could hold it up for a while. I think by the end of next year pipe will catch up, at least for the Bakken. This will be wrong if oil prices move upward from here. If we see average WTI prices of $100/barrel there are a significant number of areas in the Bakken that will be developed. Much of these estimates have to do with the price of oil. 17 Nov 2012, 12:25 PMReplyLike3 Craig Cooper Comments (1558) Ari, East coast rail shipments are already viable. You’re interpreting too much from Papa’s comments; he’s not saying it’s an all – or – none scenario.

http://bit.ly/TZESFU

http://reut.rs/ULS05q

http://bo.st/TZEUO0 17 Nov 2012, 12:35 PMReplyLike4 Aricool Comments (1460) Craig, I understand it costs $10-15 to rail it to the east coast, but I can see how getting Brent pricing there can make up for that. However, based on CLRs presentation and the below snip from Chevron (for their west coast refineries) it is apparently difficult and costly to accept rail deliveries for coastal refineries used to getting it from tanker ships. They may have to retool their refineries to deal with the different (even though very similar) crude.

So, this makes me think that the Bakken crude to railed to east coast would have to get a substantial discount to Brent to make it worthwhile to build the infrastructure and retool. I suspect this is not viable to scale up in the near term, but would take time, which new pipelines might make unprofitable by 2014/15, which should make it even less likely that they’ll be willing to invest in new rail off-loading/processing terminals.

see snip:

http://bit.ly/URE98m

You can get Bakken crude up into the Pacific Northwest via rail. You then have the challenge of how do you get it down to the West Coast. You can do that with barge, you can do it with further rail and so you have got trans-shipment costs. And then you have got to have the offloading capability in your refineries and our refineries really weren’t set up for large rail-based receipts of crudes. 20 Nov 2012, 04:03 PMReplyLike0 rlp2451 Comments (903) You might find this interesting from RBC Energy:

As far as destinations for Bakken crude go, the number of options has broadened with all the rail terminals. One of the most impressive consequences of this year’s effort to get increasing crude production out of landlocked North Dakota is the number and variety of routes and destinations that ingenious marketers are devising to accomplish the task. Here’s a list (by no means exhaustive) that we have come across in our research:

Pipeline – the two main routes out of North Dakota – via Clearbrook, MN to Flanagan IL and on to Cushing, OK or via Guernsey to Wood River IL. Rail North across the border to Canada and then over to the East Coast of Canada – destination the Irving St John refinery in New Brunswick (Statoil are delivering up to 70 Mb/d) South to Cushing, OK (with Cushing prices still in the dog house, no longer a popular option)South to the Louisiana Gulf Coast and one of the new terminals at St James, LA (Nustar, US Development) South to the Texas Gulf Coast at Houston or to the Savage Port Arthur Crude Terminal (PACT) West to Washington State – the Tesoro Anacortes and Phillips 66 Ferndale refineries West to California – the US Development rail terminal at Bakersfield Rail to Albany, NY then onto barges for destinations along the East CoastSunoco Eagle Point Terminal near to the Phillips 66 Bayway refinery Camden, NJ Hess terminal to deliver to the Hess Woodbridge refinery The Nustar terminal at Paulsboro NJ for delivery to the PBF Paulsboro refinery Philadelphia Sunoco/Carlyle (rail receipt terminal in construction) Plains All American Yorktown, PA terminal on the Chesapeake Bay Rail to the Midwest and then by Barge to the Gulf Coast via St Louis, MO terminal operated by Kirby Corporation Hennepin, IL and Hayti, MO terminals operated by Marque Port Catoosa near Tulsa, OK terminal (High Plains) Rail and Pipeline South by rail to St James, LA then north via the Capline pipeline to the Valero Memphis refinery.

http://bit.ly/UgjxrY 20 Nov 2012, 05:14 PMReplyLike1 Aricool Comments (1460) with rail, of course, all kinds of destinations are possible; however, how many bpd are cost effective and how much can be readily taken via rail by refiners? see my comment above re this. Spot rail cargos here and there are not likely going to be a solution, esp. as production rises from here. 20 Nov 2012, 08:31 PMReplyLike0 Aricool Comments (1460) I wonder if the east coast economics will get worse as the Bakken/WTI discount narrows b/c I came across #s that put it as marginally economic with a $20 discount. Currently, it is closer to $5-10, so questionable based on this early in ’12:

http://bit.ly/P9OPA0

“Recall that the Bakken-to-Cushing-to-Gulf Coast differentials average in the high $20s, occasionally spiking much higher (see Bakken’ and a Rollin’ and Perfect Storm). East coast refineries have the highest priced crude in the country. So lets’ assume the differential is $28/bbl on average. It takes about $2/bbl to load the rail car. Another $12 to move the car to Albany. Then another $2/bbl to unload into a barge. Finally $5/bbl for the barge leg. Add on another dollar for the cost of the car, and you are up to $22/bbl. At a $28/bbl differential that is $6/bbl to be split somehow between the producer, transporter and refiner. Manifest volumes will be more expensive than this. But regular, term shipments of standardized unit trains can be a lot cheaper. Perhaps getting up to $10/bbl in margin or more.”

So, (excepting for “standardized unit trains”) Bakken to Brent spread has to be at least $25-28 to make the EC rail option viable. Isn’t that a problem based on recent #s? 21 Nov 2012, 06:56 PMReplyLike1 Michael Filloon Comments (2921) Aricool,

Thanks for the info, very interesting. Shows how important EOG’s St. James unloading facility is. 22 Nov 2012, 01:39 PMReplyLike1

I appreciate your follow up on my question about the Bakken and Three Forks levels. You always provide a through evaluation. Have you heard any more about transportation of oil from the area. I understand that more pipelines are coming into the area, but that quite a bit is still trucked, and that there are still some bottle necks with the pipelines. Any idea when some of these distribution problems might be addressed?

Bill 1 Nov 2012, 09:27 AMReplyLike1 Michael Filloon Comments (2921) Hi Bill,

From what I understand, we will see Bakken differentials tighten up in the fourth quarter of next year. I have heard estimates of $4 to $6 per barrel. This is just an estimate, as I don’t have numbers to validate this 2 Nov 2012, 01:48 AMReplyLike0 rlp2451 Comments (903) From Baytex Energy’s Third Quarter CC: Yeah, I think this is a good example of what we’ve been talking about in the previous question kind of led into this. Baytex has been a forefront of maximizing our returns to our shareholders and maximizing the benefit of price realizations on our crude through the use of rail as transportation has become a major topic over the past couple of years.

Rail is really stepped up to fill that gap. You’re typically seeing right now differentials almost to the $30 WTI compared to WCS. We fully expected the differential to be higher this time a year as it is the refining turnaround season. But in particular, we’ve had a couple of issues happened here with the pipeline interruption that happened as well as an extension of a turnaround at the couple the refineries and one of the expansions that was scheduled to come on with a bit late.The combination of those things did have a little bit bigger effect on the differential this quarter. But as those things get corrected as we move into the first Q and second Q of 2013, we fully expect the differentials to close back down to the levels that represent what should be the true value of the crude, which is the transportation it takes to get into market, as well as the discount and quality of any crude one has relative to the value of other crudes being processed in the refining network across North America, which has greatly shifted to a preference to heavy crude.

Petrobakken 3rd Qrtr:
Oil differentials did improve each month during the quarter as the growth in railing capacity helped alleviate product congestion and in September differentials were slightly narrower than the historical average. October and November differentials continued to look narrow but we do expect them to widen out again due to significant refinery turnarounds occurring late in the fourth quarter and into the first quarter of 2013.

Enerplus:
We currently ship 70% of our Bakken crude by pipeline on the Enbridge and Duke systems with the remaining 30% being shipped by rail to the Gulf Coast. Differentials continue to be very volatile.

We’ve seen Fort Berthold field differentials tighten from a $15 barrel discount to WTI in the first half of the year to less than $10 in September. And in October, we saw differentials in the $2 per barrel range.

While differentials remain tight in November, we continue to expect volatility in the region and are continuing to forecast wider differentials in 2013.

For our planning purposes we continue to use an average of 10% off WTI for differentials to work out for the volatility in the market.

CLR:

We’ve also seen significant improvement in oil price differentials in the third quarter. This primarily relates to the steady increase in rail shipments of oil out of the Bakken. With the rail infrastructure now in place, we can optimize our oil shipments. In November for instance, 65% of our operated Bakken oil will be shipped by rail.

As a result, oil differentials improved significantly in the third quarter, dropping to $9.45 per barrel. September was even better at $5.19 per barrel. Our 2013 guidance on oil differentials allows for some continued volatility, but we believe the situation going forward will be more favorable than our experience during 2012.

NOG:
In addition to realized hedging gains during the quarter, the sequential quarter improvement of realized pricing was driven by a drop in Bakken crude oil differentials. Comparing the second quarter of 2012 to the third quarter of 2012, the average oil differentials declined by $3.54 and averaged $10.18 per barrel of oil equivalent. We remain highly oil-weighted with 92% of oil production being crude oil during the third quarter.

(It appears from reading thorugh many companies’ transcripts, a lot of them use a differential of 10% of WTI as a budgeting target.) 17 Nov 2012, 01:23 PMReplyLike2 Aricool Comments (1460) Rlp, nice con call snips. I wonder how well that 10% target will hold up as shale oil (incl. Bakken) ramps up a lot in 2013 and all competes for very limited OK, TX, and gulf coast refiners, esp. wrt to light sweet. I understand it is pretty cheap to build a rail loading terminal for the E&Ps, however, seems like it is VERY expensive for the refiners to build an offloading facility, and many are used to processing heavy/sour grades.

Seems like the east coast (EC) refiners are going to be the wildcard on Bakken discounts closing or widening in 2013, until the big EC pipes come in 2014/15. Have you heard anything interesting on that front? CLR did a lot of arm waving about rail to EC refiners, but no hard #s. 17 Nov 2012, 07:29 PMReplyLike0 rlp2451 Comments (903) Hess said today: “I think with regard to EURs, we continue to think that 500 to 600 is a good average used for the entire acreage position. However, as we focus on higher quality parts of the play in 2013, we expect EURs in the Middle Bakken to be closer to 600,000 to 700,000 barrels.” 2 Nov 2012, 02:14 PMReplyLike2 Pablomike Comments (138) EEP says their Berthold rail will increase from 10,000 barrels a day to 80,000 barrels Q1 ’13. They have a bunch of pipeline projects coming in ’13 and ’14 to move Bakken production. Kinder Morgan says they are going to move Permian oil through the El Paso pipeline to California thus easing the Cushing glut.

Michael: CHK took an impairment charge on their Bakken acreage and never said another word about it. Since they are so cash poor, and it’s not core to them, where is their acreage and who might they sell it to? 2 Nov 2012, 02:54 PMReplyLike2 g8trgr8t Comments (382) http://bit.ly/Slwgb9 with some info on CHK WIlliston basin. Looks like Stark County, SW ND and mostly gas but CHK isn’t exactly the best operator out there so who knows. 2 Nov 2012, 03:27 PMReplyLike1 Pablomike Comments (138) Thanks g8tr. I had forgotten about them not paying for leases. Nice job Aubrey. I was hoping they had acres adjacent to something I already own. They have a lot of acres but apparently not in the good areas. 3 Nov 2012, 04:51 PMReplyLike1 Carl Martin Comments (911) Great article, Michael. They just keep getting better. I’ll contact you soon about some of this new stuff coming out…. 2 Nov 2012, 04:53 PMReplyLike1 Michael Filloon Comments (2921) Thanks Carl, Look forward to hearing from you. 2 Nov 2012, 09:26 PMReplyLike0 bikerron1 Comments (305) Thanks for the update. I enjoy your work. I started buying HK at 6.80 and lower. Hope it works out for me. 2 Nov 2012, 05:59 PMReplyLike1 ZGgreen Comments (2) Mike,

Do you have any update on the productivity of new wells in the Stark County area? I have heard both positive and negative news coming from people in the area and was wondering if you believe companies will continue to move rigs to the South?

Thanks 6 Nov 2012, 02:17 AMReplyLike2 Michael Filloon Comments (2921) ZGreen,

The big change I have seen in this area is are results getting more consistent. I like what Whiting has done here, as some of these wells have had big IP rates. I would guess we will start seeing more rigs barring a spike lower in the price of oil. 8

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