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Michael Filloon  

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  • Bakken Update: Continental Resources Completes Mega-Frac [View article]
    Thanks Augustus!
    Jul 16, 2015. 10:31 AM | Likes Like |Link to Comment
  • Bakken Update: Continental Resources Completes Mega-Frac [View article]

    I think it will, but wont probably see this to any great affect until next year. Right now most operators are behind in the development of a very intensive source rock stimulation program. Operators like EOG are well ahead and have set the bar (but they self source sand), but others aren't using it much at all (or maybe they are trying it in other plays or areas I have not scanned yet). So really, many will just starting to try long laterals using just 6 million pounds and most wells will continue to use 4 million. Others like QEP are pushing hard and fast to catch up and doing an excellent job. The nice thing about the increase of sand volumes per foot, is operators will have to do this to survive in a low realized oil price environment. It may be the only way to make wells in the outer core areas of plays economic. So in a nutshell, we should start to see this happen next year and by 2017 the sand companies may find it difficult to meet demand again (just an estimate on our part)
    Jul 16, 2015. 10:31 AM | 2 Likes Like |Link to Comment
  • Bakken Update: Continental Resources Completes Mega-Frac [View article]

    Thanks for sharing your knowledge. Very interesting stuff.
    Jul 16, 2015. 10:25 AM | 1 Like Like |Link to Comment
  • Bakken Update: Continental Resources Completes Mega-Frac [View article]
    lol wut,

    My opinion of the Rollefstad unit would take an article like the one above to summarize properly. Most people like to look at straight production numbers and say the operator either failed or succeeded, but its not that simple. We are looking at a well pad that is a 4/3/4/3 configuration. This means there are 4 middle Bakken, 3 TF1, 4 TF2, and 3 TF3 wells. Two of the middle Bakken and one TF1 were drilled long before the pad was completed in the beginning of 2014. Since wells had already been drilled the results of the other wells will be slight muted as the first well generally releases the most energy (think of a section as a bottle of pop, the first time you twist is when the most energy is released). Since three of the best wells were already completed, the pad looks to have produced terribly, but remember there are a large number of lower TF wells completed in 2014. This means the results will not be as good (not nearly as good). The Antelope has fantastic geology, but that fantastic geology is isolated to MB and TF1. TF2 is better than TF3 but not economic at today's prices. Looking at the frac jobs done there was a higher proppant average but there was nothing special here. It still used just 30 stage fracs (quite long compared to newer Mega-Fracs) and I would like to see something closer to the 50+ stages being used). So well design was not spectacular although it was good. So the results weren't terrible considering the number of lower TF wells completed, but the lower TF shouldn't be developed until realized oil prices increase. That's not just for CLR but for any operator. But the Antelope is still good under normal well design in both the MB and TF1 right now, but is very good if operators utilize an optimal Mega-Frac. Hope this helps
    Jul 16, 2015. 01:04 AM | Likes Like |Link to Comment
  • Bakken Update: Continental Resources Completes Mega-Frac [View article]

    I don't know if anyone has used natural gas from another well to help pressurize another. It is possible this could help to push more fluids from well A in a shorter period of time, but I don't have any specific data to back that assertion.
    Jul 15, 2015. 08:07 PM | 2 Likes Like |Link to Comment
  • Bakken Update: EOG Well Pad Produces Revenue Over $200 Million In 2.5 Years [View article]
    Thanks Gregg,

    That is really nice of you to say. Its been a long road, but a good one.
    Jul 14, 2015. 09:50 PM | Likes Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]

    We think EOX has some pretty big hurdles ahead without oil prices going significantly higher. If I was to provide any guidance for EOX, I would have them do a coiled tubing frac with a high density sand frac to see if it would improve results enough to provide economic well results. We think anyone should be very careful with the name as it has a lot of risk. Good luck to you!
    Jul 7, 2015. 09:56 PM | 1 Like Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]

    The article is not bullish EOX. None of the results I have posted provide positive data on current EOX wells. Do you understand the content? Please read it and address any specific questions you may have about the results. Well results can be very difficult to interpret, but I would like to help you through the process. Have a great night!
    Jul 7, 2015. 09:54 PM | Likes Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]
    shallow sand,

    Looks like you had the right idea about not being optimistic on oil pricing. Big roll over today. Thanks for spending the time as well.
    Jul 6, 2015. 10:08 PM | Likes Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]

    Thanks, Im glad you enjoyed it. The site is about learning something, and that includes me as well. Have a great night!
    Jul 6, 2015. 10:07 PM | Likes Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]
    Hi Elaine,

    Always great hearing from you! Don't know if you remember, but we did cover the name back in November. You don't have to read the article, but we were bearish.

    Our viewpoints since then haven't changed. Looking at Emerald from a well result standpoint, things do not look good. The geology of its acreage is not that good, and while they completed the 90 stage frac in hopes of getting a spectacular result, they didn't. We would not have owned the stock in November, and definitely would not buy it now. In all fairness, we did like the name some after the completion of its first Pirate well, but many people were. The problem with a name like this, is it was probably fine with oil at $100/bbl. Most areas in ND were with the exception of maybe Burke County, but at the latter part of last year many names started to look like they may not have the well economics, and that continues to be correct. Have a great night!
    Jul 6, 2015. 10:05 PM | 1 Like Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]
    Shallow Sand,

    We do use debt to PV10 some, and think it is valuable but we place tend to stick with geology and well design as the main driver. We take a look at where they are currently drilling and the specific results garnered from the core right now. Many are "holding on for dear life" by high-grading, and some may be able to through next year. But things get real tricky now that most of the barrels are not hedged and we will really start to see how good wells are as operators start to have trouble making debt payments. If an operator has enough core acreage to make it through 2016, then things get less cloudy with respect to production/oil prices. Some of these operators go away. Others drop leasehold that isn't economic, and can buy up some operators that still have good acreage but not good enough to survive for pennies on the dollar. The problem is names have to be washed out, and when that production is off the table, things stabilize somewhat. The problem is $60/bbl oil is still pretty good in core areas, so those are pretty much what everyone is drilling. When the cores are drilled up, we find an entirely new oil price needed, and operators have to focus on B grade type acreage. There is still plenty of core to drill and that is why we kept saying that production in the US wasn't going to drop much unless we can get down below $50/bbl.

    So basically we take the number of locations drilled and figure out where those wells are. Then develop a production model for the well, and try to estimate revenues from production/hedges. Then we look at whether debt payments can be made. The thing operators like CLR and WLL have going for them is a fairly sizeable position in decent areas, the issue to watch with those names are the uneconomic areas. They will try to get some of those areas held by production so they don't lose initial investment, but that could be an expensive proposition if they cannot find a well design that will be productive there. If I were to guess (estimate) a longer term approach to names, it would be down in the short term until we find a bottoming of prices. After this, many of those names will probably recover and provide for a pretty good year. Then we see worries about acreage that will be let go and a re-evaluation what companies are really valued at. This could produce some pressure to the downside. Then to the victor go the spoils, because at some point he world economy improves and those that are left standing will see much better prices and will begin to acquire large leaseholds again. Geopolitical issues could throw all that out the window of course, but we think there are still very good opportunities in the sector, but it will be a very difficult landscape for those that do not know the industry well.

    Again I would like to say thanks. You have added some very good color here. Hope others have enjoyed it.
    Jul 4, 2015. 12:30 PM | 1 Like Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]

    OAS isnt bad either, some of those numbers may be a little skewed given both have oil service and midstream. Seems to help keep some of those costs lower.
    Jul 3, 2015. 03:17 PM | Likes Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]
    shallow sand,

    Thats great! Thanks for doing that, most people just make statements and dont back it up with anything tangible. I will also say our numbers differ some from yours, but we dont generally share a full breakdown of costs with the general public (which is available to investors/shaletrader subscribers). One thing I would say, is if you would like more accurate numbers (like LOEs broken down by play), companies will sometimes share those (at least they do with us). This is why we just calculate how long it takes for a well to payback D&C. But thanks again, the readers do enjoy this type of information as it provides a starting point. The one thing about calculating out costs is everyone has an idea of how to do it, its not rocket science.

    One thing I would like to address (not trying to be argumentative, just throwing out some general data). "From my reading, the typical ND Bakken well will produce about 220,000 barrels of oil and about 200,000 mcf of gas in 5 years." This is real interesting, because we do hear this alot with respect to well performance in the Bakken and whether it is still economic at today's prices. Your data is correct, but includes a lot of older wells that did not perform well due to design. It also includes a large number of wells in Burke, Divide, northwest Mountrail, southern Dunn, Stark, Billings, Western McKenzie, north and western Williams. Much of these areas were looking just ok at $100/bbl. Many of the bears focus on this, but it doesnt account for current production and how these wells produce. I agree with you that IP rates (especially 24 hour through 60 days) are very misleading, but EURs are as well. As you know, IP rates can be skewed through choke size and other factors. EURs can also be skewed depending on math. When we model a well off of current production numbers (not the arps method) and figure the decline curve. We use wells that are in the area and model off of past production. Granted those models are probably conservative given the big push to shorten stages, break up rock closer to the wellbore, increase proppant and fluids but it probably better than using a straight calculation. I have heard many say Bakken wells produce half of all resource in the first year, but average producton number (including older, less productive wells only produce 19%). This average (which seems to be improving) produces half of all resource at around 3 years and 9 months. Another issue clouding the industry is how the decline curve deviates later in well life. Many calculate well declines that are exagerated (thats and assumption) which would end well life abruptly. Using vertical fracs as an example we see something different. Those wells produce 35 to 40 years (usually) and something very interesting (which you may know) happens roughly 8 years out. The induced fractures stop producing. So many think, thats it and we are all done, but it hasnt been the case. At that time the shale matrix begins to produce. This does not have a heavy decline (keep in mind, this is research not me) but declines at only 6%. That is why the decline curve has its shape and why many believe these wells will produce longer. You may also know that vertical fracs in gassy areas have produced for a hundred years, which leads us to believe the gas continues after the liquids production stops. When these wells become uneconomic is anyones guess, but you probably also know that costs are very low once a well achieves payback so high rates are not as important (although wanted).

    What we have seen from operators drilling wells in 2014 and 2015 are a large increase in production from high intensity fracs. We focus on this when looking at specific names to invest in because the economics have changed so much. I do agree with you that some of the Bakken is not economic, and will not be until we see $80/bbl oil again. Since we dont plan to see this real soon, we expect operators to go under and lose leasehold. Some with just be let go in the hopes they can get their hands on it when oil prices improve again. But some areas are still very good. This article is not a good example of this as the company has significant issues, as do many others. Currently, most operators are fine in the Bakken core which includes southeastern Williams, northeastern McKenzie, southwest Mountrail, and northwest Dunn, including Parshall and Sanish Field. But there is a fairly large disconnect between operators that have figured out how to better fracture the shale.

    I dont think you are being flip, or even rude. To tell you the truth, these types of conversations generally turn out to be the best for those following. Usually commentors like yourself add alot to the process and I hope you keep commenting. We have been doing this for a long time, and the portfolio managers do a very good job of keeping on top of how these plays are changing. Hope you have a great Fourth! God Bless the USA and all of those that have sacrificed to keep the world free and safe.
    Jul 3, 2015. 03:15 PM | 1 Like Like |Link to Comment
  • Bakken Update: Emerald Completes 90 Stage Frac In Stark County [View article]
    Rig counts up 12 this week, reversing 29 straight weeks of declines.
    Jul 2, 2015. 03:41 PM | 1 Like Like |Link to Comment