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Michael Filloon  

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  • Bakken Update: Halcon Well Results Improve While Kodiak Buys The Best In West Williams County [View article]

    Not trying to be rude, but I havent looked at your articles. I don't make comparisons, nor do I comment on other author's work. If you want a comparison you will have to make it yourself. Have a good night.
    Jun 25, 2013. 10:04 PM | 12 Likes Like |Link to Comment
  • Bakken Update: 2015 May Be A Difficult Year For This Bakken Non-Operator [View article]

    We could take the other side of your argument as well. If we were shorting NOG right now, we would most certainly get one comment that said we were trying to push the price of the stock down for our own benefit (which is virtually impossible when you consider how many investors read these articles). We try to stay away from writing pieces about names our firm is invested in. We don't own any E&Ps right now, as we don't like the space short term.
    I am unsure where the comment on hatred for the industry is coming from, but its not from us. If you look back at my articles historically they have been very bullish. For every trade there is someone on each side, it just happens that we are more bearish than bullish going into next year.
    Nov 20, 2014. 12:58 AM | 10 Likes Like |Link to Comment
  • Bakken Update: Frac Sand Pricing Could Go Parabolic In Q3 2014 [View article]

    Thanks for commenting, I always appreciate your insite. I think I may have confused you with some of the points I was trying to make with this article. The first point is with respect to these areas being "identical". I don't think I have ever used the word identical to describe source rock from one square mile to the next. The reason for this is a geologist (I am not one) would tell you that it is highly unlikely that one would find identical rock anywhere with in a play. It could be said the rocks from these fields are more like one another than in Antelope, Tarpon, or other fields outside southwest Mountrail County. When comparing well results from one area to the next it is important to at least be somewhat close or use a comparable area. That is what makes comparing well results so difficult, there are just too many variables. I can only do my best to compare areas that are more like one another, as this is the best we have for formulating a comparison. What you would want to focus on here is EOG as an operator and what the numbers tell us with respect to completion design. Whiting and EOG are an excellent comparison based on well design because both have historically used much different methods. EOG focuses on source rock stimulation to create as much fracturing as possible along the lateral. In doing so it requires much more sand and fluids to get the desired results. Whiting has historically been very good at keeping well costs down, and in so had used much less proppant. I believe WLL would have used more proppant if they had stimulated the rock well enough to need it, but for what ever reason used differing methods. Looking at the Eagle Ford, the same is true. These areas are more like one another. One thing I think you should do Josh, is go through EOG's well results throughout the Bakken and Eagle Ford and look at the neighboring operators, then compare the results. You will find the EOG's results have been better throughout the entire play. This includes in the Bakken, western Williams (Liberty had some comparable results, but used slickwater fracs which could be an article in itself), and Northeast McKenzie County. I have documented this in quite a few articles and the research is not only sound, but extensive. Here is the research:
    These results are not just initial production from one day but over a significant period. It shows that EOG has done this where ever its acreage has been. No disrespect, but I see you commenting on articles being the Devil's Advocate at times and I think this is great. We need to have differing views as I think it makes the site better and provides a different viewpoint. But when you do, maybe you shouldn't use a word like identical when that is not the word used in the article. Also, provide some links to go to that show the readers that your views are true. Saying you have spoken to someone at MHR, PVA, or WLL does little for the readers as I could say I called and spoke to anyone and say what ever I wanted to. Plus, you may want to provide links for why the geology is different. I am not saying you are trying to mislead anyone (I know you wouldnt do that), just saying everyone here would really appreciate reading all of the research you have done. That said, this article has more to do with how better source rock stimulation has led us to the increased use of frac sand per foot, providing for better overall well results. Not so much about a very specific article on how identical the source rock is from one field to the next. In reality, it would be impossible to find two areas that are identical to compare along the full length of a lateral, as each stage differs from one another within each lateral. Have a great day Josh, always appreciate your comments.
    Mar 6, 2014. 11:32 AM | 9 Likes Like |Link to Comment
  • Bakken Update: Whiting's Outstanding Q3 Is Driven By A Better Completion Design [View article]

    Drilling results have been the issue. When I have taken Whiting well results in a particular field and compared that it competitors, Whiting has lagged over the first year of production. It has masked these results by using a wider choke which increases it IP rates initially. Whiting will report the IP rate, but experience a higher level of depletion. Whiting has historically used much lower volumes of proppant and water. This is also a problem, and the reason for the much higher rate of depletion. Whiting masks this by also using longer laterals (one of the first operators to do this in the Bakken). By using longer laterals, its EURs seem higher, although its production is much lower on a per foot basis. The fractures are not adequately propped open, shutting of resource and again increasing depletion because it doesn't use enough water and proppant. When looking at the top 20 cumulative oil producing wells in the Bakken, Whiting only has two. This wouldn't be a big deal if its acreage was not as good, but the Sanish Field is some of the best in North Dakota and should be out producing or at least in line with all other fields. The under utilization of water and proppant also keeps well costs low. By doing this it claims very high 24-Hour IP rates and low well costs. In reality it has been an average operator at best with respect to its completion design. Its new completion design will improve longer term IP rates by 30% to 40% as a worst case scenario (if we use EOG's results as an example since it adopted this method). The first well EOG used this method on in the Parshall Field modeled a top 5 cumulative producer in the Bakken all time. It is difficult to know how much this will improve Whiting's production because we do not know how quickly it will be able to move to this design on all or most of its wells. This design has worked very well in the Eagle Ford, Wolfcamp, Bakken and now the Niobrara, so it seems to be affective in the majority of areas. I would guess the analysts will be aiming a little low over the next few quarters so we should see decent share price gains in the short term.
    Jul 26, 2013. 10:50 PM | 9 Likes Like |Link to Comment
  • Recent Commentary on Northern Oil & Gas: A Short Retort - All Smoke, No Gun [View article]
    Great article Zman. I appreciate your commitment to the truth.
    Mar 28, 2011. 11:51 AM | 9 Likes Like |Link to Comment
  • Bakken Update: The Red Queen Is Just A Fairy Tale Part III [View article]

    The 24 hour IP rate was a generalization that I should have been more clear on. Because of the varied size of chokes 24 hour IP rates can be all over the board. So 24 hour IP rates or even 30 day IP rates can be misleading and should not be used to formulate an idea of production for the life of the well. Most production models use at the very least 90 day IP rates because of this. One thing I would say about arguments on depletion is the glass is half full or half empty. Unconventional wells produce a huge amount of resource in the beginning of well life. About half of all well production is produced in the first 5.5 years. These wells produce for 32 to 40 years. You can focus on the depletion number and the negative or you could focus on how quickly these wells pay back. This is a financial site and we focus on economics and how those economics will pay back investors. Try to keep in mind that some of the best oil companies in the world are developing the Bakken, and they aren't doing this because they are losing money. Have a great night and thank you for the comments.
    Oct 18, 2012. 08:42 PM | 8 Likes Like |Link to Comment
  • Bakken Update: Is Whiting For Sale? Part I [View article]
    I finally got a chance to look over the article, which I must say was a lot of work. The author does seem to have some knowledge in this area, and I do commend the time he took to do an article that took some time. Although there was a lot of info, I did think this info was missing some things, and could've done a much better job if he just bounced some questions of a couple of people that know what is going on the ground. The first problem with doing a general work in the Basin has to do with formation. There are a significant number of wells that have targetted the Red River and Madison formation. These wells are vertical and don't fit with his findings. He made an interesting point as to the average amount of oil produced per day per well. This average has not changed much since 2006, but we have to remember that wells, until recently had a very high rate of depletion. This is not to say the horizontal wells don't deplete quickly, because they do, but the change has been significant in producers like Kodiak, Burlington, Continental, etc. It has taken years for producers to find the value of using more and better proppant, more water, and increased stages. One of his points was that most of the sweet spots have been drilled, and this leads him to believe only poorer areas remain. This couldn't be further from the truth. Only a small fraction of the best areas have been worked. Looking at the map you will see one well drilled per mile to get the acreage held by production. It could be argued, each mile will support at least 8 wells in the better areas but QEP would argue it supports 12.
    Figure 6 was very interesting, as it proves my point that Whiting's use of less water and proppant is hurting long term production moreso than other producers. The 40% decline has to do with cheap well design and does not show what the majority of producers are doing and have done. I didn't like the use of Marathon either, as it has treated this play as an afterthought, and is focusing on other areas. Brigham on the other hand is a good choice, but should be noted that it wasn't just working the best areas and has considerable completions in shallower less productive areas that are much cheaper to drill.
    The idea that a larger number of wells need to be drilled to increase production is true, but he doesn't calculate these wells will only deplete to a certain point and produce the same rate for about a decade and a half. It also doesn't cover recompletions which are much less expensive and will increase production from these wells significantly. After that we will have waterfloods, which have been effective for EOG. Also, having no data after Aug of 2011 could have caused a big hole in this information. Around that time, most of the producers increased stages, water, etc. I think we would see the last year as a big move in the Bakken.
    When the price of oil needed was figured he said gas sales were marginal, but forgot about natural gas liquids which are definately not marginal. The question is, how much would this effect the price of oil needed? In northeast McKenzie County it is 11% of total well production. Prices move around a bit but look at this price as approximately $40/barrel. It would constitute about 5% of total production.
    Also, when looking at an oil price needed to make the Bakken viable there are other ways to look at this. Continental estimates EURs are 604 MBoe. This is the middle Bakken in North Dakota across its acreage. The cost to drill in deeper areas is about 10 to 11 million. In western Williams and southern Divide this number is about $2 million less. These areas are lower pressured and produce lower initial IP rates, but deplete at a slower wait. About half of all well production is produced in the first 5 to 5.5 years. Going back to the EUR of 604MBoe, we would get about 302 MBoe in the first five years. Of this about 270000 would be barrels of oil. Multiply this by $80 oil and you get $21.6 million in revenue. I would also remember the Kodiak has a Koala well the produced 1200 Boe/d for the first 90 days. Thats 108000 barrels of oil equivalent in three months.
    Sep 28, 2012. 11:47 PM | 8 Likes Like |Link to Comment
  • Oil Service Companies Are Cheaper, May Be Safe Way to Invest in Oil [View article]
    Tom, Craig, and IgnisFatuus,
    I am very sorry for the mistake but I did not disclose the positions I have in both BEXP and KOG. I did send a message to the editorial team for this oversite to be fixed. I used both companies as an example not to say they were a poor investment, but to say they were very good investments that an investor may be wary of as they are more levered to the price of oil than an oil service company. Again I am sorry, and I thank those who gave me the benefit of the doubt, I appreciate it.
    Aug 12, 2011. 12:57 PM | 8 Likes Like |Link to Comment
  • Investing in the Bakken (Part I): 8 Companies With a Market Cap Under $1B [View article]
    Thanks Joe,
    You are totally right about the pullback, its just a matter of when. But when it does happen I am loading up. Have a great day.
    Mar 6, 2011. 10:32 AM | 8 Likes Like |Link to Comment
  • It's About Time Halliburton Got Some Love [View article]
    Thank you for your kind words and honesty. I couldnt have said it better myself.
    Feb 10, 2011. 11:51 AM | 8 Likes Like |Link to Comment
  • Bakken Update: Well In Western Williams County Produces 6-Month Payback [View article]

    Don't take this the wrong way, but I write this way because it is easier to understand for my readers. I appreciate your experience, but this is a venue for investors. I am happy you took the time to read the article, but most of the points you are touching on have little to do with what points the article is trying to make.
    Jun 23, 2013. 03:54 PM | 7 Likes Like |Link to Comment
  • Bakken Update: Depletion Of The Top 20 Oil Producing Wells In The Bakken [View article]

    Its not misleading. No matter what the 24 hour or peak IP rate is, they would still produce the same amount of resource if the 90-Day IP rate is the same. There is too much focus on the depletion over a very short period of time, when the numbers that matter are how many barrels are produced for the full year. I suppose one could focus on how much less oil is produced over the first 90-days, but it does little to show how economic a well is. Besides, EOG wells do not produce huge IP rates in the Bakken (although some of their wells have been big) but these wells deplete slower and will catch up to the wells with bigger chokes. Focus should be placed on how quickly these wells pay back, as that is what we want to know with respect to our investment.
    Mar 19, 2013. 01:36 PM | 7 Likes Like |Link to Comment
  • My Take On SandRidge [View article]

    I appreciate it, its good to know you benefitted from this article. I will say it was easy to write, Sandridge (SD) is a great story. I bought into a position just after I wrote it. Have a great weekend.
    Apr 20, 2012. 04:53 PM | 7 Likes Like |Link to Comment
  • My Take On SandRidge [View article]

    I think the Dynamic acquisition is summed up by Mr. Ward quite well. During our discussion, he stated the purchase of Dynamic was one of value and not as much a perfect "fit" with respect to its holdings. When he calculated the acquisition in terms of oil, it was much cheaper than purchasing anything in the Permian.

    He did the same thing when he purchased the Permian and Mississippian acreages. The Permian (conventional oil) was out of favor at the time, as everyone was buying tight gas assets. The Mississippian was thought to not be economic due to its very high water production. He was right about that asset as well.

    I guess Dynamic was one of the same type of investments, and if history repeats itself this will turn out a winner as well.
    Apr 20, 2012. 04:51 PM | 7 Likes Like |Link to Comment
  • Bakken Update: 2015 May Be A Difficult Year For This Bakken Non-Operator [View article]

    NOG is fairly well hedged when compared to the majority of operators. Most are only 50% hedged in 1H15, with the number decreasing to 25% to 30% in 2H15. NOG is approximately 67% hedged at $90/bbl in 2015. The real pain for NOG would occur as operators of its leases cancel permits. Lets say CLR cancels a permit to drill in central McKenzie County for which NOG has a non-operated interest. That production doesn't occur. CLR is able to recoup by drilling on a better section of its leasehold, but more than likely NOG wont have interest in the new permit and thus lose a100% of its estimated production.
    Nov 20, 2014. 01:18 AM | 6 Likes Like |Link to Comment