AEIdeas

The public policy blog of the American Enterprise Institute

Subscribe to the blog

Discussion: (33 comments)

  1. MP: The revolutionary extraction technologies keep getting better, faster, and cheaper, and will continue to do so in the future.

    Yet the shale gas producers can’t make any money from those extraction technologies. And as the easy gas is extracted those technologies are applied to resources that are not economic because they are outside of the core areas where profit is possible. If you see the market transactions it looks as if the land prices in the sector are collapsing. Chesapeake just sold assets at less than half the price they were showing on the books a few months ago. If things were as you say that would not have happened.

    1. brian sahadak

      Seeing one side of a coin means you basically do not see at all. Those acres are not core acres at all. They had not been derisked. What you see is a company jumping in to an area that no one would of considered at that scale. It proved to be thermally immature in the bakken. Yes all fields have limits and this one has been found.

      1. Seeing one side of a coin means you basically do not see at all. Those acres are not core acres at all. They had not been derisked. What you see is a company jumping in to an area that no one would of considered at that scale. It proved to be thermally immature in the bakken. Yes all fields have limits and this one has been found.

        Reality is what it is, not what we may wish it to be. What I see is an industry that is moving away from the conventional fields that are depleting at an alarming rate into the marginal tight sands areas that were never worth bothering about. While there is some good money to be made on a few wells in the core areas the average well in the formation will not be profitable.

    2. Vangel, is you are speaking about natty (NG) then you are correct: however, if you are incorporating oilers as well then you are dead wrong, in your assertions..

      Companies earning a profits are CLR, TPZM, NOG and KOG.

      I suspect there are even more.

      Furthermore, they are now drilling multi-levels in the Bankkens, lead by the foremost leader, Continental Oil…
      This is allow for development for the unforeseen future.

      http://seekingalpha.com/article/1248431-bakken-the-downspacing-bounty-and-birth-of-array-fracking

  2. Well, somehow Northern Oil and Gas managed to make money from those extraction technologies, $19.4 million in Q4 (beating expectations) and $72.2 million for all of 2012, following net income of $40.6 million in 2011. Guess you missed that conference call?

    1. Well, somehow Northern Oil and Gas managed to make money from those extraction technologies, $19.4 million in Q4 (beating expectations) and $72.2 million for all of 2012, following net income of $40.6 million in 2011. Guess you missed that conference call?

      But if you decide to look some more try to think about what you are seeing. In the case of Northern it is interesting that a company that has been in the shale business for more than half a decade is still cash-flow negative and needs to add debt to fund its drilling. You would think that if the industry is as profitable as you claim and costs are as low as they are reported to be there wouldn’t be that many funding gaps that need to be filled by new financing or equity dilution.

      Note that the total income could easily be wiped out if the company has to account for EURs that are lower than what is being assumed. So it comes down to the same argument again; how much oil will each of the wells produce? And on that front I would say that reality does not support the industry assumptions.

      1. Vangel, NOG, is negative free cash flow because of the huge amount of expenditures of cap-ex and nothing more.

        This is the case for many new business, which are expanding at a very fast pace.

        What proof do you have in claiming their EURs will be lower than stated? Are you aware that EURs figures are generally produced by audit firms.

        And do not forget, that only about 10% of all oil is mined, with the remainder left for future redevelopment..

        These E&Os are building assets that will be worth millions, if ever sold…

    2. Ralph B

      If you look here https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf
      It looks like they are averaging 140 BPD. Not sure what they receive per BBL after operation and transportation costs, my WAG is $35 which makes payoff in 5 yrs or less

      1. The 140 bpd is due to the explosion of new wells that are being drilled every year. The decline begins from the IP, which is best calculated as the average production of the first three or four days and declines by around 50-85% depending on the area in the first year. By year 7 most of the wells are at stripper status. Give the $7-$10 million drilling cost, the royalty costs, leasing costs, overhead, and production costs you are not looking at much in the way of profit and that profit is declining rapidly from day one. Just to keep production level you need to replace about a quarter to one half of the existing wells in operation, which is why the shale companies are cash flow negative and will not make an economic profit once the accounting is adjusted to reflect the EURs that come from the production data. The shale bubble will burst on its own but is particularly vulnerable to an external shock that brings down prices of oil in the case of an economic contraction.

        1. marmico

          Give the $7-$10 million drilling cost, the royalty costs, leasing costs, overhead, and production costs you are not looking at much in the way of profit and that profit is declining rapidly from day one.

          NOG made $20 per barrel net with a depletion expense of $26 per barrel on revenue of $83 per barrel.

          The NOG Form 10-K is here.

          1. NOG made $20 per barrel net with a depletion expense of $26 per barrel on revenue of $83 per barrel.

            Here’s your chance to advance specific numeracy. The NOG Form 10-K is here. Take us through, step by step.

            I do not believe that it made $20 per barrel net because I do not know what EURs NOG is using and how they compare to the URs that can be calculated from the actual production data. The previous analysis that I cited showed that the industry was overstating the EURs by around 100%, which meant that the depreciation costs were understated. If they are understated you can produce any return you want.

            Look at the link that you provided. Do you see the Statement of Cashflow Information? The company has been in operation since 2007 but has yet to generate sufficient cash flow from operations to finance its drilling operations. I see that $112 million were spent in 2008 and 2009 yet the 2010 cash flow from operations came out to $73 million. In 2010 the company spent a further $208 million yet the 2011 cash flow from operations was only $85 million. In 2011 the company used another $300 million yet only managed to generate $198 million. You would think that an operation that had a high IP from its wells and saw a 50% or more decline in the first year would be able to generate better cash flows.

            Now to be fair I have not looked deeply into the numbers. But from what I see this looks like a long term loser. It consumes a lot of cash but generates so little from operations. This is the same thing we saw from the gas companies, many of which were actually reporting accounting profits even though they were not able to self finance. In the end reality caught up and some had to sell off assets at much lower prices than the book value while others wrote off a portion of their investments. At best, shale oil is marginal in the better areas of the formation. More likely is the fact that we will see capital destruction yet again as operations move from the low hanging fruit in the core areas into the more typical areas of the formations.

            Net Cash Provided By Operating Activities
            $ 198,527 $ 85,150 $ 73,307 $ 9,813 $ 2,506
            Net Cash Used For Investing Activities
            $ (532,172 ) $ (300,868 ) $ (207,893 ) $ (71,849 ) $ (40,358 )
            Net Cash Provided By Financing Activities
            $ 340,754 $ 69,887 $ 280,464 $ 67,488 $ 28,520

          2. marmico

            I thought that your main argument was that depletion expenses were too low, therefore profitability was overstated. The basis of that assertion is that the EUR is overstated. NOG depleted 31% of every barrel produced.

            Is the consensus not that at $60 per barrel, the Bakken is not profitable for the average producer? It appears that NOG is an average producer.

            So NOG is supposed to be capable of increasing year over year production by 95% strictly from cash flow? That’s a patently unreasonable position.

          3. I thought that your main argument was that depletion expenses were too low, therefore profitability was overstated. The basis of that assertion is that the EUR is overstated. NOG depleted 31% of every barrel produced.

            Is the consensus not that at $60 per barrel, the Bakken is not profitable for the average producer? It appears that NOG is an average producer.

            So NOG is supposed to be capable of increasing year over year production by 95% strictly from cash flow? That’s a patently unreasonable position.

            My position is that the stated profits are based on assumptions about the ultimate recovery from each well. I have already cited a number of reports that show that the industry is overstating the EURs by a significant amount. We also know that a typical well in the better areas of the formation produces around 80,000 barrels in the first year and that depletion is significant. Based on the production curves we are more likely to see an ultimate recovery of 200,000 barrels or less than the 500,000 barrels that the industry is hoping to get. That changes the economics significantly and means that outside of the core areas the oil production is unlikely to be economic once all of the costs are properly accounted for. Things would work out better for the producers if the government saw the light and got rid of royalties but that will not happen in an environment where the companies are seen as evil.

            For the record, I do not expect production to increase sharply without borrowing. My point is that I expected the borrowing to produce a great deal more cash flow given the claims and what we know about depletion and a great deal more if depletion were less than what I am saying.

            As I said before many times, this is all about the EURs. We saw the same thing for shale gas where the EURs were significantly overstated. Unless the producers got a lot more honest I think that it is a safe bet that we will see write-downs some time over the next few years, particularly when the production data has shown that the Bakken peaked some time during the late 2012 early 2014 period.

            The biggest problem that you have has been pointed out by PeakTrader and Ralph.

            http://www.theoildrum.com/files/fig04Bakkenspecificprodandwellsaddedmonthly.PNG

          4. marmico

            One day you will have to deal with the depletion issue.

            NOG is dealing specifically with the depletion expense issue. It’s 31%. You are generalizing.

            For the record, I do not expect production to increase sharply without borrowing.

            Once again, cash flow cannot increase year over year production by 95%. NOG borrowed $4 to increase annual cash flow by $1. You expect cash flow to payback capex in 1 year. Another patently unreasonable position.

            The range of estimates of EUR in the Bakken is the USGS of 3.7 billion bbls (now under review), the EIA of 5 billion bbls, the North Dakota Department of Resources of 7-15 billion bbbls and the industry (Hamm, CEO of Continental) of 24 billion bbls.

            What’s your EUR?

          5. NOG is dealing specifically with the depletion expense issue. It’s 31%. You are generalizing.

            I am not generalizing. I am being very clear that the depreciation is CHOSEN by the company when it states the EUR. We have had similar arguments in the past about shale gas when some argued that the EURs were too high and others believed the industry. The losses were not just because of the price declines but because wells stopped producing a long time before they were ‘supposed to’ and required abandonment or expensive refracking.

            Once again, cash flow cannot increase year over year production by 95%. NOG borrowed $4 to increase annual cash flow by $1. You expect cash flow to payback capex in 1 year. Another patently unreasonable position.

            No I do not. But a 500,000 EUR should give you payback in just over two years. I would say that close to 80% of the production takes place in the first two years. That should lessen the need for such extensive borrowing and should make the Net Cash Provided By Operating Activities category look much better than it does. And how many more years will you be looking at such large amounts of borrowings before you start to question why the operations are not self financing?

            The range of estimates of EUR in the Bakken is the USGS of 3.7 billion bbls (now under review), the EIA of 5 billion bbls, the North Dakota Department of Resources of 7-15 billion bbbls and the industry (Hamm, CEO of Continental) of 24 billion bbls.

            What’s your EUR?

            Given the fact that I don’t believe that it is possible for 70% of the wells to return a reasonable profit I would take the under. And I do not care about some aggregate EUR figure. I care about something that is a lot easier to see; the EUR for each well. On that front I have provided plenty of links to analysis that shows that the EURs have been overstated.

        2. butasha

          Today the data that we are talking about is so limited and variable you can’t really do anything with a hyperbolic decline. In reality well data is being impacted by things like temporary shut downs for maintenance, working on another well on the pad, pipeline capacity, trucking and rail limitations etc. this lack of accurate historical data makes it extremely difficult to reliably estimate the hyperbolic parameter.

          You can “smooth” the data, but then your approach to smoothing ends up determining the parameter you are trying to estimate. Example: We have one well that produced very well for the first six months or so and then experienced a large paraffin build up that limited the output significantly. Once this well is cleaned up it will actually increase production rather than decrease. So in reality, for now anyway, all the brilliant minds on numerous blogs and forums are just stating opinions.

          Believe me as a royalty owner I would love to know what the EUR will be for the current and future wells on our family leases.

          1. The problem with shale wells is their huge variation in performance. If investors have properties that are in the core areas it is possible to make huge returns on their investment even as the land owners get a potful of money in royalties. The problem is that in most of the non-core areas you are looking at a loss for investors even as the land owners get their share of the proceeds for the oil produced.

        3. Again, Vangel, IP rates are not an average of 3 or 4 days, but the first 24 hours…

          Bankken’s typical oil well cost, as stated by Professor Perry, are closing to 8m, rather than the figures you stated.

          Moreover, despite the numbers that you have published, it is a well known fact, that the cost for BOCs is about 50 to $55 pb…At that level, most producers will earn income.

          1. Again, Vangel, IP rates are not an average of 3 or 4 days, but the first 24 hours…

            I know that. But because of the fracking process the first 24 hours tend to be very volatile and do not yield very good data. You can see what I mean in the production data charted below.

            http://static.cdn-seekingalpha.com/uploads/2012/12/14/121744-13555306922582495-Mark-Anthony_origin.png

            Bankken’s typical oil well cost, as stated by Professor Perry, are closing to 8m, rather than the figures you stated.

            The drilling costs are around $7 to $10 million depending on where you are and how long your laterals are. Of course, there are other costs that you and Mark are ignoring that would have to be added to do the proper analysis. The leases are not free. Neither are the corporate jets, the collection/gathering equipment and infrastructure, etc.

            Moreover, despite the numbers that you have published, it is a well known fact, that the cost for BOCs is about 50 to $55 pb…At that level, most producers will earn income.

            It is not well known at all. Those are claims that do not show up in the real world data, which is what counts. I find it strange that people who saw the shale gas companies overstate EURs and underestimate their depreciation costs accept the claims made by the same companies about EURs and depreciation costs for shale liquids. You have to stop hyping up bubbles and start looking at the actual numbers.

          2. Vangel, I try to be a sober investor…There are over 50 E&G firms in the Bankkens and they are not there to lose their shirts and pants, for that matter.

            The EURs in that play are increasing as we speak and the cost that I mention comes from the state of North Dakota.

            I strongly suspect, that the average EUR is now somewhere between 400k to 500k…

            You may make your claims that this play is a money loser , however, fortunes are going to be made…

            The only thing that will kill the Bankken play, are the Enviros, Federal government or low goo prices…

          3. Vangel, I try to be a sober investor…There are over 50 E&G firms in the Bankkens and they are not there to lose their shirts and pants, for that matter.

            They didn’t try to lose their shirts on gas either. But they did.

            The EURs in that play are increasing as we speak and the cost that I mention comes from the state of North Dakota.

            No, they are not. There is no evidence to suggest that the ultimate recovery from new wells will match the recovery from those wells that were drilled in the productive core areas. You can make a lot of money from a Bakken well drilled in a sweet spot but that is not what happens for the average well. If you look at the industry as a whole it is driven by what happens to the average well, not by a few dry wells or a few really good ones.

            I strongly suspect, that the average EUR is now somewhere between 400k to 500k…

            The data I have looked at is suggesting 200K to 300K. Obviously it matters what the real ultimate recovery we get because that will show us if the depreciation costs are real or have been overstated. I suspect that most people will wind up losing money on shale oil just as they have on shale gas.

            You may make your claims that this play is a money loser , however, fortunes are going to be made…

            Perhaps if you have wells that are only in the core areas of the Bakken but there are few of those left because most of the better locations have already been exploited and are no longer capable of producing profitable production.

            The only thing that will kill the Bankken play, are the Enviros, Federal government or low goo prices…

            I think that you forgot a contraction that cuts off financing for an industry that cannot self finance its operations. And reality itself.

  3. Actually by moving to a multiple well pad, the environmental impact is also minimized in that no matter how to look at it a well drill site has at least some impact, all be it possibly temporary. They are taking a page here from the Barnet in Texas which since it sits under Ft. Worth, they have to do multiple wells from one site, since a lot of the rights do not include surface access (in fact you can’t get a home loan in Tx without a waver of surface rights, if you don’t own the minerals which most homeowners do not, the bank wants to ensure that its collateral does not loose value this way)

  4. PeakTrader

    It seems, technological advances or productivity improvements isn’t enough to offset the diminishing returns of shale oil production. So, a rising trend in oil prices is needed.

    1. PeakTrader
      1. PeakTrader

        It looks like more Peak Oil, because at some point the number of new Bakken wells will decline, and so will oil production:

        “The “average” well now yields around 85,000 Bbls during the first 12 months of production and then experiences a year over year decline of 40%.”

        http://www.theoildrum.com/node/9748

        1. There is a bigger problem that most of the optimists are ignoring. The easy oil in the core areas has been mostly developed without generating much in the way of profit for the shale companies. The newer wells are outside of the core areas, which is probably the reason why the average production rate has not gone up even though so many new wells have been drilled off.

          1. Written by Mr Filloon, perhaps one of the foremost experts regarding the Bankken play…

            http://seekingalpha.com/article/964181-bakken-update-williston-basin-estimated-ultimate-recoveries-in-north-dakota-part-i

          2. Written by Mr Filloon, perhaps one of the foremost experts regarding the Bankken play…

            http://seekingalpha.com/article/964181-bakken-update-williston-basin-estimated-ultimate-recoveries-in-north-dakota-part-i

            Thanks for the link but I have a problem with the way that Mr. Filloon looks at the data. He ignores the fact that by deliberately choosing an artificially low IP the industry can choose a decline rate that would provide the type of flat curve that their models need to get high EURs. A better approach is the one that I cited before; you fit the model parameters to the actual production data and see what the EUR turns out to be. The difference can be seen when you integrate to get cumulative production over time. The models used by the industry and accepted by Mr. Filloon show an EUR that is about 50%-100% greater than figure that is produced by the actual production data.

            I believe that the example I cited showed one of the best wells in the Bakken, which was showing around 500K barrels of ultimate production. In the same link it was shown that the average producing well in the Bakken was showing a EUR of less than 300K barrels and was experiencing a decline rate of around 9-10% per month. While the well that could produce 500,000 barrels in a lifetime would turn out to be very profitable if the company could get $95-$100 per barrel there was no way for the AVERAGE well to be profitable given what was shown by the production data.

            What gets to me is that the data is out there. We know how many wells are operating in any given month and how many of them were operating the month before. That gives us a great view of the decline rates for the average well in the formation and will shed a great deal of light if we want to learn about the facts.
            http://seekingalpha.com/instablog/121744-mark-anthony/1435031-the-real-eur-of-eog-s-bakken-shale-wells?source=kizur

            http://seekingalpha.com/instablog/121744-mark-anthony/1378351-the-true-economy-of-bakken-shale-oil

            http://seekingalpha.com/instablog/121744-mark-anthony/1398581-financial-state-of-the-natural-gas-industry?source=kizur

  5. MacDaddyWatch

    America is benefiting from the creative expansion, enhancement and creation of capital. Wealth and prosperity will always follow.

    As the broad and deep application of technology accelerates, we simply get more bang for the buck. Productivity is enhanced and output gets advanced. As costs decline and output increases, we simply get more bang for the buck. This has happened in every segment of our economy and the oil patch is no exception.

    The broad and deep application of technology is a proven productivity enhancer and this process is just beginning. Ultimately, this process translates in greater wealth and prosperity for all of America.

    1. $80.00/BBl X 125,000 BBls = $10,000,000.00 =well cost
      assume 20% Owner Royalties & operating costs
      of 10%. $3,000,000.00/$80.00.00 = BBls.
      total BBls = 162,000. Better wells one year,good wells 18 months,mediocre wells two years. Now you have 70 to 80 % profit. EUR 500,000 bbls =500-162=338,000bbls times $80 =27million times 70 percent or $18 million +/- profit. Interest on 10,000,000 for two years may be 1,000,000. There is a lot of profit for drilling when there are ZERO DRY HOLES!!!
      .

      1. $80.00/BBl X 125,000 BBls = $10,000,000.00 =well cost
        assume 20% Owner Royalties & operating costs
        of 10%. $3,000,000.00/$80.00.00 = BBls.
        total BBls = 162,000. Better wells one year,good wells 18 months,mediocre wells two years. Now you have 70 to 80 % profit. EUR 500,000 bbls =500-162=338,000bbls times $80 =27million times 70 percent or $18 million +/- profit. Interest on 10,000,000 for two years may be 1,000,000. There is a lot of profit for drilling when there are ZERO DRY HOLES!!!

        Great job except for one thing. If the producers are so profitable why can’t they self finance? Why aren’t companies like Northern Oil and Gas paying any dividends if the wells that they have drilled off are so profitable? Why is it that they need more and more financing to increase their cash flow from operations?

        Until you can answer all those questions I think that you need to keep questioning the EURs. A well that produces 80,000 barrels in the first year and depletes–even at what is a low rate for a shale formation–of 40% has an EUR of around 200,000 less than half the 500,000 that you are assuming. And if the EUR is overstated the return that you are using is way too high because the costs of drilling have to be written down over a much shorter period.

        We are down to the EURs again. And a lot of wishful thinking on the part of companies and their investors. I recall how I was pounded by people on Mark’s old blog about shale liquids and profitability and was told that Range and other companies would make a lot of money not from gas but from liquids. What they failed to mention was that the hunt for NGLs meant more frac stages and longer laterals. In the end that translated to more NGLs but in a market that did not need them. The companies wound up taking a beating on NGLs and are back with the same problem of capital destruction. Oil will not turn out any better except in the few core areas where it makes sense. You guys can get back to me when the companies become self financing and show us that their earnings are real by paying some of them out as dividends. Until then I see nothing to get excited about.

  6. Benjamin Cole

    Drilling for shale will go global, and people will get better and better at it.

    My question is whether oil can stay high enough to justify it. Oil may crumple at some point.

    The US Navy bought a lot of kerosene lately, at $3 and change, that had been made from natural gas. One more market oil is going to lose….

    1. Kerosene from methane. That sounds like the more wasteful way to go. I guess the $15/gal bio-diesel thing that we bought year before last, didn’t work out too well. Kerosene, on the other hand, that’s a good stuff. It’s still more economical to obtain kerosene from cracking big ones into littler ones, than alkyl reforming from methane. Sure, it will yield the same result But, reforming is the more costly process. Easier to get more kerosene economically, from the oil, than the methane. Count on the government to require the more expensive alkylation process, and still the result it still comes in 3 dollars and change cheap. Impressive. I’ll bet that it was one of those big, “evil” oil companies, which filled the order so cheaply.

Comments are closed.

Sort By:

Refine Content:

Scholar

Additional Keywords:

Refine Results

or to save searches.

Open
Refine Content