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Discussion: (52 comments)

  1. MacDaddyWatch

    Fracking…the bridge to the future.

    Permanent bridge.

    Bye, bye windmills ands solar machines.

    1. not if the obama tree huggers and climate freaks have their way!.,. The lies they put out are believed by too many of the UN_INFORMED LEFT!

      1. I suggest that everyone take a deep breath and look at the Bakken data. It shows the average well production rate dropping even though drilling has produced a record number of new wells which have their highest production in the first few days after they start producing. What this data shows is that problem that is created by the depletion rate. While some of the wells in the sweet spots are fabulous and will produce massive amounts of oil and gas over their lifetimes the average shale well is a consumer of capital. No wonder no primary producer of shale gas and oil has been able to generate positive cash flows from operations.

        https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf

        1. Mr Vangel as others past has a point, CHK pulled out, DHS pulled out True down to 1 rig, No stuck pipe Few Few if any blow-outs compared to 08-11, We are lucky the middle east is bogged down in wars and Iran has lost it Production status, But be sure All Booms go Bust, As thee exploratory driller in 07 Bakken program, As we turn into Total production field Pressure is relieved” Everyone’s Straw in the same Cup theory””Even if its a shaken can of fluid” After awhile you will reach a Peak-. Secondly
          Storage and Pipelines are at there max, So what to do ?’ Sell Cheaper! Can’t because it will effect drilling and completion cost-won’t be feasible WILL Cause major Drilling Reduction program Mini-Shock bust, So we are Quickly coming to a point in this boom, it’s smart to Sell
          Prices Will not come down as fast as a Bust cycle-Causing a Crime and welfare and Defualt Bubble that is devasting, Man Camp will be Abandon Dumps along your drive. Already If you look you can see some businesses oilfield in Williston sneeking out Not Hiring or just holding on attitude, Don’t be fooled it’s not well managed, The confrences I’ve attended in Houston OKC all bitch about 2 things in North Dakota-The Expense of doing biz here And the cold But Don’t be Fooled they the Big Boys have a solution=Suck it out as fast as we Can and Get out…Really that’s life in a Rat race, Sad it don’t need to be like that, And the state could make So Much more money but.., “The way to Conquer the kingdom is-Wine and Dine the King..!” thanks let’s chat

          1. My point Al is simpler. When I look at the 10-Ks I do not see any operation that is truly profitable if we use the proper depreciation schedules. All of the primary producers show negative cash flows years after they should have begun to generate surplus cash. All of them show funding gaps that are being filled by more borrowing, share issues, or asset sales. To me this looks a lot like Nortel and Lucent in the 1990s; what you have are reported profits that are generated by not depreciating assets properly. That means that we will have to see a massive write-down of the balance sheets that will drive most of the producers into bankruptcy and at that point those work camps will turn into ghost towns.

  2. The Unknown One

    I think it’s waaay too early to say how long this will last. I’ve read some petroleum geologists who say the wells in these shale plays aren’t going to last nearly as long as the companies who drill them say they will, and that most of them will only last maybe 5 years or 10 at the most before they peter out. But these plays are all so new, I don’t really think anyone knows for sure.

    One thing I do think will happen is, at some point the companies drilling these wells will start selling off the older ones whose production has gone way down (by then they’ll have more than paid for themselves), and you’ll get companies who specialize in stripper well maintenance and secondary recovery buying them at a big discount. Maybe by then technology will have emerged to get more oil from these wells than current technology allows.

    1. Breaker Morant

      The Unknown One>>>>and that most of them will only last maybe 5 years or 10 at the most before they peter out.<<<<

      Hmm, well if your experts are right-a significant number of the 2007 wells should be done by now and the 2008 wells should be starting to be done now too.

      Are they?

      1. Hmm, well if your experts are right-a significant number of the 2007 wells should be done by now and the 2008 wells should be starting to be done now too.

        Are they?

        Yes they are. That is exactly why the explosion of drilling in the Bakken has done little to increase the average production rate.

        1. Che is dead

          “Yes they are.” — Vag

          Where’s the evidence supporting this assertion?

        2. MacDaddyWatch

          BS

          1. “BS”- MacDaddy

            Where’s the evidence supporting that assertion?

            Here’s some more data driven analysis for you to poo-poo.

            See the video presentation.
            http://www.energybulletin.net/media/2012-06-20/after-goldrush-learning-us-shale-gas-experience

    2. brian sahadak

      I believe the person writing this comment should rename themselves to the “Unknowing One” for the sake of accuracy.

      First, a wrong comparison is made. 100 years is indicative of how long it will take to fully develop the field; Not how long individual wells are expected to produce.

      Second, Five to ten years is ridiculous. The earlier estimates were 19-20 years. Today most companies estimate production to last in the 29-30 year range. These estimates are based on real world data and the margin for error does not come close to only five to ten years of production. In addition some of the first wells have already been re-fracked with better technology to improve production. I have also read that it has been estimated that up to six re-fracs could occur on each well over its life span. This will undoubtably increase each wells longevity. The real question is how many wells will be drilled in each layer will it be one, two, four, eight, or sixteen. I have seen presentations suggesting all of these possibilities. This is why 100 years may be likely to fully develop this play with its many layers.

      So much more can be said, it is good to remember that in just the bakken layer it is estimated that 20-40 million
      barrels are in place in each square mile. Many bright minds will do whatever it takes to get the oil out of the ground, as long as profitability is possible 100 years…sure. Don’t forget Three forks, Tyler, Red River, lodgepole, the shale layers themselves, CO2 Floods, etc.
      Maybe a hundred years is a bit conservative. Five to ten simply moronic.

      1. The Unknown One

        I didn’t say the people who are saying the wells will only last 50-10 years *were* right, I said they *could* be right. They could also be wrong. My point was, nobody really knows right now how long this will last. Anyone certain it will only last another 5 years doesn’t really know, and anyone saying it will last 100 years doesn’t really know. At this point it’s just guessing.

        1. The Unknown One

          “I didn’t say the people who are saying the wells will only last 50-10 year”

          Oops I meant 5-10 years.

          Wish you could edit your posts on these blogs.

        2. If you look at the analysis I cited you will find that most of the companies had no wells older than 80 months. And the data indicated that the producers were making assumptions about EURs and hyperbolic decline rates not supported by the data.

          But keep in mind that when you have a pile of data it is easy to use statistical methods to prove whatever you want to prove. If you avoid looking at the wells that failed very early, add data from wells that have been restimulated, and accept the very noisy data from the initial few months as more important than it should be you can come up with any type of decline that you want. But as I have said before, you cannot change the reality of negative cash flows and huge funding gaps that have to be filled by issuing new shares, adding more debt, or selling off assets.

      2. Agreed that new technology will arrive. To take an older Example the Kern River field in Ca was found in 1899 and before thermal recovery it produced about 10% of the original oil in place. Starting in the 1960s they began to use Steam Flooding and today Chevron has a goal of 100% of the original oil in place being produced. It should be noted that the produced water is treated and used for irrigation since it is not salt water.
        So we see that new technologies will arrive to increase production over time. It is not clear for example what steam flooding might or might not do in the Bakken, but if you wanted to do it, wind power might be an ideal way to boil the water, since the steam flooding need not be continious.

  3. morganovich

    well, the king of fracking was just deposed by his board and key investors.

    http://www.reuters.com/article/2013/01/30/us-chesapeake-mcclendon-idUSBRE90S15920130130

    sure, some of this has to do with his own personal dirtbaggery, but what the investors are really up in arms about is the massive debt accumulation and cash flow shortfalls that are now necessitating asset sales.

    The empire that he built was based on far higher gas prices, both for Chesapeake and for him through the Founder Well Participation Program. So given that outlook, it’s not a surprise he is stepping down,” said Mark Hanson, an oil and gas analyst at Morningstar Inc in Chicago.

    “At the end of the day, it’s no longer the company that it once was. The board is really not with him these days. If you have done things a certain way for 23 years and then all of a sudden things change as radically as they have in the last six months, it’s hard to get used to.”

    Hefty spending on oil and gas acreage in the nation’s shale formations and a prolonged period of low natural gas prices have left Chesapeake saddled with debt and a funding shortfall.

    Chesapeake sold or agreed to sell about $12 billion in oil and gas properties last year. In 2013, it plans to sell up to $7 billion to fill a spending gap that JPMorgan estimates at $5.5 billion.”

    track their margins.

    chk has 37% gross margins in 2009.

    they were 30% by 2011.

    in 2012, they fell off a cliff and were 14% in q3.

    low gas prices and increasingly marginal wells have them in a pincer.

    debt is up $5 billion in a year. capx is up and profits have turned to losses.

    CHK is a fracking pioneer and one of the best in the business.

    i am by no means an oil and gas expert and this is the result of about 10 minutes of work, but if you can find this much cause for concern in 10 minutes, then i’m not so sure we can call this fracking boom an economic slam dunk.

    this may be a boom like real estate or .com that gives a hobson’s choice to producers.

    don’t invest and get killed int he public markets or invest badly and get hurt in the long run.

    the equity prices of guys like chk, hek, and xco sure do not seem as optimistic as these reports.

    when the “frack king” is losing his shirt and then his throne as a result, i would be very careful making assumptions about just how economic this trend is.

    again, i am far from an expert here, but in general when faced with a choice between believing the reported results of large public companies and the published models of the energy dept, well, i’m going to go with the public companies.

    somehting sure sucked all the profit out of the big leaders in fracking. if these wells pay for themselves as rapidly as claimed, that seems odd as does the massive debt accumulation to fund big capx surges in the face of collapsing margins.

    somehting seems a little fishy here.

    1. Che is dead

      “Major investors Carl Icahn, who now has a Chesapeake stake of nearly 9 percent, and Mason Hawkins, with 13.5 percent, took control of the nine-member board last June … Icahn said he believed history would prove McClendon was right about the ultimate value of natural gas and praised the assets assembled by the former CEO … Chesapeake has been forced to sell billions of dollars worth of acreage … Chesapeake sold or agreed to sell about $12 billion in oil and gas properties last year. In 2013, it plans to sell up to $7 billion to fill a spending gap that JPMorgan estimates at $5.5 billion.”

      It looks as though Chesapeake’s troubles are tied as much to land speculation as they are to the current price of natural gas. What’s more, they made the transition to oil and associated liquids later than many of their competitors. The same competitors who are now buying the properties that Chesapeake borrowed so heavily to acquire.

      Are they selling these properties at a loss? The article doesn’t say, but I doubt that investors like Icahn and Hawkins would have gotten involved if they didn’t see enormous unrealized potential in Chesapeake.

      Either way, the fortunes of any given company may say very little about the potential of an industry as a whole, especially when that company was being run by a man with a track record of excessive risk taking.

      1. Che is dead

        “Over the past five years Chesapeake has entered into 600,000 leases covering 9 million acres, paying out $9 billion in lease bonuses to landowners in the process—so much land that it would take Chesapeake 30 years to drill it all. And the more new shale plays uncovered, the more land McClendon continues to acquire. Chesapeake has piled on $10 billion in long-term debt and raised billions more through financial finagling to gobble up its acres. McClendon argues it’s money well spent because there’s only a small window to get good acreage for low prices. As Jeff Mobley, his investor relations spokesman, explains: “If we lived within cash flow we’d miss the opportunity.”Forbes

        It’s clear that Chesapeake and others are borrowing in order to lock in properties at what they consider to be good prices relative to the long term potential for oil and natural gas. Whether they are right or not, or whether some have become over extended and fail as a result of their speculation, says nothing about the ultimate potential of these reserves since that potential will either be realized by these companies or companies that secure these properties at some point in the future at market clearing prices.

        1. Chesapeake has been borrowing for years. And it has yet to make a real profit from its shale gas operations. Given the fact that it was too optimistic before, as many of us pointed out, why should we think that they are so much more reasonable now? Shale gas has been a great destroyer of capital. Why should we expect shale oil to be much different?

          1. Che is dead

            The capital that you keep saying has been “destroyed” has actually been invested in oil and gas properties.

            No one knows what the future value of that investment will be, but making those purchases with gas prices at historically low levels would seem to imply a potential for tremendous future return.

            I know, I know, you’ve figured it all out and your cyrstal ball tells you that natural gas prices will remain low forever and ever – we got it.

          2. The capital that you keep saying has been “destroyed” has actually been invested in oil and gas properties.

            Yes.

            No one knows what the future value of that investment will be, but making those purchases with gas prices at historically low levels would seem to imply a potential for tremendous future return.

            You are missing the point. The SEC filings tell us about the past. You drill off a well that costs around $10 million. You assume a hyperbolic decline that gives that well a 25 to 30 year life. But the actual production data shows that the decline is not hyperbolic but linear after a while and the life of the well falls to 7 years. Instead of the EUR of 3.0 Bcf you have produced 1.3 Bcf and can only get a further 0.2 Bcf over then next four years. That capital has been destroyed. Period. End of story.

            You are making some assumptions about the future that are little more than unsupported wild guesses. History shows much hype about shale but very little in the way of economic profit. As such it is hard to sell the ‘it is different this time’ line, particularly when we have so much great data that shows us that reality is very different than what you thought it was.

            I know, I know, you’ve figured it all out and your cyrstal ball tells you that natural gas prices will remain low forever and ever – we got it.

            I do not need a crystal ball because I have the data that you have so conveniently ignored. For several years now I have asked all of you shale supporters to find a few companies that are self financing in the sector. Which companies have fields that produce much more revenues than the consume. I have yet to hear from any of you except to cite some well in some area that was very profitable. I already know that you can have great wells in the core areas. My point is about the average well in the average formation because that is what we have to deal with when making the type of projections that Mark keeps providing.

          3. Che is dead

            “You assume a hyperbolic decline that gives that well a 25 to 30 year life. But the actual production data shows that the decline is not hyperbolic but linear after a while and the life of the well falls to 7 years.” — Vag

            “Production decline results strongly suggest hyperbolic decline. Particularly, the b value ranges from 1.3 to 1.6. First-year decline rate ranges from 56% to 74%. Thirty-year cumulative production ranges from 2.0 to 3.0 Bscf. The Best 12-month average gas rate and first 24-month cumulative gas production show a consistent trend and correlate very well with the predicted 30-year cumulative gas production.” — The Bottom-Line of Horizontal Well Production Decline in the Barnett Shale, Society of Petroleum Engineers

            The decline rates are hyperbolic.

          4. We have already covered this part in one of the citations provided to you. As Berman put it, “Type curves that are commonly used to support strong hyperbolic flattening are misleading because they incorporate survivorship bias and rate increases from re-stimulations that require additional capital investment. Comparison of individual and group decline-curve analysis indicates that group or type-curve methods substantially over-estimate recoverable reserves.” If you are not counting the wells that fail early and ignore the fact that you have to spend a lot more money to restimulate other wells that you throw into the data pile you can come up with a hyperbolic decline. But you still won’t be able to get the EURs that the papers are talking about.

            And keep in mind that the operators agree with me. Had the wells been able to keep producing for 30-40 years as the hyperbolic rates would imply the shale gas companies would not be in such a hurry to reposition themselves as shale liquids players because they would be swimming in cash and very profitable. The fact that they have to sell off decent assets to close the funding gaps supports my side of this debate, not yours.

    2. track their margins.

      chk has 37% gross margins in 2009.

      they were 30% by 2011.

      in 2012, they fell off a cliff and were 14% in q3.

      If you do not properly depreciate your wells it is easy to come up with any margin that you want. Nortel was reporting high profit margins because it was not writing off worthless assets. In the end it had to restate. Note that Arthur Berman dealt with the problem in the report that got him fired. He showed that the actual production data did not support the assumptions of hyperbolic declines that guaranteed long life wells. He actually showed that the EURs had been overestimated by 50-100% and that if you included all of the costs the shale companies needed around $7.50 just to break even. None of these issues have been covered in the accounting, which is why good old Aubrey finally lost his job. The problem for Chesapeake is that its plans to sell assets come at a time when many companies also want to sell because none of their projects are self financing and they have trouble getting loans because of their balance sheets. I think that Chesapeake will probably go under or get taken out by a conventional player looking to hide the fact that its conventional reserves are falling sharply. (A 6:1 boe conversion ratio has a way of hiding that fact for quite some time.)

      1. morganovich

        v-

        sure, but it does come back to haunt you at some point.

        che-

        it’s not just one company. hek, xco, and lots of others having the same issues.

        think about it this way:

        a fracked well suffers from very rapid production declines. i think we all agree there. in 2 years, they are producing maybe 10% of what they were.

        thus, you really need to get your payback on a well in less than 2 years, especially on an NPV basis if things are debt financed.

        if the payback is that rapid, then why are the fracking companies experiencing such nasty margin compression, slipping into unprofitably, and running up so much debt?

        it seems unlikely to me that if unit economics on a well are as good as claimed, that we would be seeing financial results like this.

        gas may be low, but oil is not.

        i am certainly no expert here, but the financials being reported do seem consistent with the notion that e/p guys are moving into more marginal wells with lower output and poor economics. capx is way up and not generating much additional revenue. chk had been paying down bedt, but it has gone up by 50% in the last year. margins are collapsing across the industry and many producers have slipped into the red.

        something is wrong here. gas and oil production is way up in the us, but this does not seem to be generating profits for the producers.

        1. sure, but it does come back to haunt YOU at some point.

          You are thinking about this from a logical postion and use the proper accounting and financial analysis to come up with a conclusion. But I think that you tend to forget that you have not quite gotten a handle on who the you is and what the incentives are.

          Think of it from the perspective of an oil company executive. Given the state of the conventional reservoirs you find yourself in an industry that is facing some serious headwinds and face a lot of competition for your job. You move to the shale sector and find yourself with a pile of money to play with. Given the optimism the money flows in and you are compensated as much in three years as you would be in 15 at a typical oil company. The results are not good because you know that the EURs are way too high. But the accounting rules permit you to keep making the optimistic estimates as long as you are honest about most of the other requirements.

          So you keep using a very low depreciation cost to produce a ‘profit’ even though you cannot self finance and need to keep going to lenders or the equity markets to stay afloat. Wouldn’t YOU as the executive keep playing the game until the bubble burst and retire with as much in earnings as you could have made in a lifetime on another job?

          The people who run the companies do not often have the same interests as the investors who put up the capital. That is why we have to be very skeptical and think on our own rather than accept the narratives that feed us with the type of stories that we wish were true.

          1. morganovich

            v-

            are you seriously trying to teach me about perverse incentives for public companies?

            believe me, i get it. i’ve seen it time and time again in lots of industries. you jam the stock for a couple years, sell a ton, and retire before everyone figures out the emperor has no clothes.

            seen it in telcom, internet, alt energy, you name it.

            i understand completely why a certain kind of ceo is attracted to such behavior.

            i’m surprised you feel like this would somehow be news to me.

          2. i understand completely why a certain kind of ceo is attracted to such behavior.

            i’m surprised you feel like this would somehow be news to me.

            I don’t think that it is. But I think that your explanations at times ignore what you know of human nature and the way that the markets work. No offence was intended.

        2. Che is dead

          This chart, from Wells Fargo, shows the breakeven point for a number of companies on a dry gas basis. At current prices about 1/4 to 1/3 of US shale gas is profitable to produce as a pure gas play. Of course, the numbers improve after factoring in associated liquids. And gas becomes an offset when produced while drilling for oil. But it’s clear that those companies, like CHK, dependent on natural gas production are having a difficult time.

          That is not true for oil producers, as “this article highlighted previously by Dr. Perry points out:

          “Eagle Ford wells cost $7 million to $10 million, but Yeager said they pay back within half a year. “The Eagle Ford has become the most profitable field in the world,” Yeager (CEO of BHP Billiton Petroleum) said. “Fifty percent of every well is oil, and we get $100 a barrel for that oil.” Becca Followill of U.S. Capital Advisors LLC said companies operating in Gonzales, DeWitt and Karnes counties have seen initial rates of return higher than 50 percent, with some wells as high as a 70 percent. … More than 70 percent of the rigs working in the Eagle Ford are drilling primarily for oil, while 23 percent are focused on gas, according to Baker Hughes.”

          Even the Saudis have conceded that at a price of $72-$80 a barrel almost all US shale oil wells are profitable.

          1. morganovich

            che-

            i do not think those are typical numbers. 6 month payback is wildly uncommon if it does exist. eagle ford is generally described as the best of all shale plays, so, perhaps such payback is possible, but if it is, i imagine leases are not cheap. but i do not think you can take the head and shoulders best field and use it to stand for the whole.

            this chart is data from about 3700 wells in the bakken.

            http://i603.photobucket.com/albums/tt118/we_are_toast/DKOS/Bakkendeclinecurve_Bernstein.png

            these are horizontal oil wells.

            in the first 2 years they throw off about $8.7mm in production at $80 oil or $9.8mm at $90 oil.

            such a well costs $10 million to drill.

            after operating costs, transit costs, etc, no way they pay for themselves in even 2 years. note also that you have not yet recovered lease or land purchase costs nor the costs of the exploration and 3d seismic you did before you drilled.

            all in i think you might get your money out in 3-4 years (assuming interest costs etc) at which point you are left with a well that produces maybe 7000 bbls/yr.

            i’m sure we could find a few wells that are exceptions, but this is the norm and it’s going to head down, not up as core areas get depleted.

            i have no idea what to make of that saudi claim. at $72, bakken does not look terribly profitable and there are many worse fields than that one.

          2. Even the Saudis have conceded that at a price of $72-$80 a barrel almost all US shale oil wells are profitable.

            Of course they would be profitable if the EURs and the hyperbolic rate assumptions turned out to be true. But that is the problem; you have production data that is telling us that they are not true. This is why you have to look at the earnings statements very carefully and pay a lot more attention to the cash flow and balance sheet.

            And you have to keep in mind that we were told exactly the same story for shale gas a few years ago that we are told about shale oil today. If the promoters got shale gas so wrong what makes you trust them to be right about shale oil given the fact that there isn’t enough data to support them and what data there is seems to be supporting different conclusions?

  4. Production from a typical Bakken well declines rapidly but on average produces modest amounts of oil for 45 years and earns a profit of $20 million.

    Given the fact that the production increases that are being touted are driven by horizontal wells and fracking that began recently how can we talk about a ‘typical’ Bakken well in that category? The chart that Mark shows looks exactly the same as the chart for the Elm Coulee did. Drilling was near zero in 2000 but by 2006 had exploded and created an exponential production curve. The problem was that was the top. Since then production fell off a cliff because of depletion. It is not hard to figure out how much drilling you will need to keep production flat. It is not hard to figure out how much that would cost. And it is not hard to figure out what happens to cash flows for producers in the area.

    1. Che is dead

      Depletion rates at this stage of development may be entirely misleading. The vast majority of fracked wells have been vertical as opposed to horizontal wells. Vertical wells, while cheaper to drill and frack, have a very small contact surface which can be a real problem if the reservoir layer is thin. Horizontal wells, on the other hand, can have a contact surface running the entire length of the reservoir layer. That is why accurate reservoir mapping is so important. Horizontal wells remove oil and gas from a reservoir over a long producing zone at relatively low rates while vertically drilled and fracked wells produce greater initial flows with very fast depletion rates. No one knows, at this point, how long a modern horizontal well will produce, but estimates exceed 30 years.

      This EIA animation shows: Cumulative natural gas wells drilled in Pennsylvania, January 2005-April 2012, vertical versus horizontal

      1. Depletion rates at this stage of development may be entirely misleading. The vast majority of fracked wells have been vertical as opposed to horizontal wells.

        How many companies that you know would frack a formation that is only a few dozen feet thick without using horizontal wells. If you have followed along and looked at my past citations you will have seen that my comments were for horizontal wells. Their depletion rates are higher than first stated. As Berman showed, the EURs were twice what the production data indicated that ultimate recovery would be.

        Horizontal wells, on the other hand, can have a contact surface running the entire length of the reservoir layer. That is why accurate reservoir mapping is so important. Horizontal wells remove oil and gas from a reservoir over a long producing zone at relatively low rates while vertically drilled and fracked wells produce greater initial flows with very fast depletion rates. No one knows, at this point, how long a modern horizontal well will produce, but estimates exceed 30 years.

        Once again, my comments are about horizontal wells. I think that somewhere down the line you have been misinformed about recovery rates and well life cycles. As I said before, you let me choose the depreciation rate and I can give you the margins and earnings that you want to see. But there is no way for me to change reality and the true picture will always be shown to those that choose to look at the balance sheets and cash flow statements.

        1. Che is dead

          “Production decline results strongly suggest hyperbolic decline. Particularly, the b value ranges from 1.3 to 1.6. First-year decline rate ranges from 56% to 74%. Thirty-year cumulative production ranges from 2.0 to 3.0 Bscf. The Best 12-month average gas rate and first 24-month cumulative gas production show a consistent trend and correlate very well with the predicted 30-year cumulative gas production.” — The Bottom-Line of Horizontal Well Production Decline in the Barnett Shale, Society of Petroleum Engineers

          The decline rates are hyperbolic.

  5. Bill Burleigh

    Disappointing to see someone with academic credentials in finance and economics citing unattributed “projections” in a newspaper article (and headlining his post with them). The basic assumption supporting this optimistic view is that future wells will produce at the same rate as current ones and that the entire “thermally mature” part of the Bakken formation is just waiting for the oil companies to drill more gushers. It also assumes that costs will remain level and that an unlimited water supply will be available to frack the thousands of wells yet to be drilled. The oil industry in North Dakota will likely do OK in the long term, but to suggest the “boom” will continue for over 100 years is just bullish hyperbole.

    1. Che is dead

      “The basic assumption supporting this optimistic view is that future wells will produce at the same rate as current ones and that the entire “thermally mature” part of the Bakken formation is just waiting for the oil companies to drill more gushers. It also assumes that costs will remain level and that an unlimited water supply will be available to frack the thousands of wells yet to be drilled.” — Bill Burleigh

      Actually, costs are coming down significantly and in the future they probably will not need water:

      Chimera Energy develops fracking technique that uses no water

      1. Bill Burleigh

        “Rapidly escalating well costs consumed capital spending budgets faster than many companies anticipated and uncertainty surrounding future federal policies on taxation and hydraulic fracturing impacted capital investment decisions.” Quote from the North Dakota Director of Mineral Resources regarding recent decline in production.

        1. He forgot to mention the depletion problem. As I said, all this is about is simple math and we do not require to overthink the problem. When companies are spending more than they can make the companies run out of money and have to reduce their drilling activity. When they drill less they cannot offset the huge depletion rates and production falls off. This is nothing new. We saw a version of it with the Elm Coulee field, which was actually somewhat profitable.

          This graph tells us what the problem really is. If you look, you see that the exponential rise in the drilling of $7-$10 million wells was not been able to get the average production higher. Given the fact that the production rate in the first few days is the highest that a well ever produces the alarm bells should be ringing to anyone who can understand grade 9 or 10 math even if we do not try to understand the hyperbolic rate debate.

  6. MacDaddyWatch

    So you anti-frackers, how is your solution going?

    The current list of faltering or bankrupt green-energy companies:

    1. Evergreen Solar ($24 million)*

    2. SpectraWatt ($500,000)*

    3. Solyndra ($535 million)*

    4. Beacon Power ($69 million)*

    5. AES’s subsidiary Eastern Energy ($17.1 million)

    6. Nevada Geothermal ($98.5 million)

    7. SunPower ($1.5 billion)

    8. First Solar ($1.46 billion)

    9. Babcock and Brown ($178 million)

    10. EnerDel’s subsidiary Ener1 ($118.5 million)*

    11. Amonix ($5.9 million)

    12. National Renewable Energy Lab ($200 million)

    13. Fisker Automotive ($528 million)

    14. Abound Solar ($374 million)*

    15. A123 Systems ($279 million)*

    16. Willard and Kelsey Solar Group ($6 million)

    17. Johnson Controls ($299 million)

    18. Schneider Electric ($86 million)

    19. Brightsource ($1.6 billion)

    20. ECOtality ($126.2 million)

    21. Raser Technologies ($33 million)*

    22. Energy Conversion Devices ($13.3 million)*

    23. Mountain Plaza, Inc. ($2 million)*

    24. Olsen’s Crop Service and Olsen’s Mills Acquisition Company ($10 million)*

    25. Range Fuels ($80 million)*

    26. Thompson River Power ($6.4 million)*

    27. Stirling Energy Systems ($7 million)*

    28. LSP Energy ($2.1 billion)*

    29. UniSolar ($100 million)*

    30. Azure Dynamics ($120 million)*

    31. GreenVolts ($500,000)

    32. Vestas ($50 million)

    33. LG Chem’s subsidiary Compact Power ($150 million)

    34. Nordic Windpower ($16 million)*

    35. Navistar ($10 million)

    36. Satcon ($3 million)*

    *Denotes companies that have filed for bankruptcy.

    1. Ahh the irony. You rightfully point out the capital destruction in the alternatives sector yet you ignore the same in the shale gas and oil sector. Both shale and the alternatives are not viable solutions except in some small niche areas.

      1. MacDaddyWatch

        Read ‘em and weep !! You are looking at broadly based failures for the future.

        EV sales off to slow start in 2013…Detroit News

        Electric vehicles and plug-in electric hybrids are off to a tough start in January after a disappointing 2012.

        General Motors Co., Toyota Motor Corp. and Nissan Motor Co. all reported much lower sales of EVs and plug-in hybrids in January over December, citing lower inventory and the decision of many customers to buy before the end of the tax year.

        GM said sales of its plug-in hybrid Chevrolet Volt rose 89 percent to 1,140 over January 2012.

        But that’s still much lower than recent months — including the 2,633 Volts sold in December. It’s the lowest number of Volts sold in a month since February 2012, when GM sold just 1,023.

        That’s hard data evidence…now suppose you share yours!! Otherwise, monkeys are flying out of your butt.

        There is only one socket into which you can plug in that extension cord…and you know where that is.

        1. Read ‘em and weep !! You are looking at broadly based failures for the future.

          EV sales off to slow start in 2013…Detroit News

          The fact that EV sales are low and that electric cars make no sense in most markets is hardly news or hardly surprising so what is your point other than to remind the lefties how stupid Obama’s administration is. (Of course Bush had his thing with ethanol, solar, wind, etc., so the GOP is hardly blameless when it comes to wasting taxpayer revenues so that it can buy votes.)

          That’s hard data evidence…now suppose you share yours!! Otherwise, monkeys are flying out of your butt.

          What evidence are you looking for? We have already seen all the shale gas players admit that they can’t make money and try to sell themselves as shale liquids plays. We have already seen that their 10-Ks show that they have been kept in business by adding massive amounts of new debt, selling off assets that have some value, or diluting existing shareholders. Good old Aubrey has been fired just as I have been calling for and Rex should be fired for the stupid purchase of XTO energy. (At least Rex has finally admitted to Exxon losing its shirt on natural gas from shale.)

          Encana and BG Group Plc both took write-downs on shale last year. Many other companies will follow suit this year.

          As for the ‘liquids as saviour’ story all that is needed to refute it is this chart.

  7. Michael Shaw

    I traveled to the Bakken and spent several days there documenting man camps, strip clubs, rig sites and campgrounds, immersing myself in the culture and interviewing as wide a variety of people as possible. Here is a link to the story, published on an online Bozeman, MT news journal. Its the first article, “Inside the Belly of the Bakken”:
    http://bozeman-magpie.com/perspective-full-article.php?article_id=588

    1. Michael,

      I read your articlen very informative, I would like to ask you a few questions.

      Is there a good way to reach you?

      Thanks
      Scott C

  8. Great discussion. Just an observer on the great fraccing debate, but it stands to reason that the free volume in shattered rock is considerably less than that in a pool of liquid oil, so that more drilling should be required. But investors are a funny bunch. If they sense that they are drilling dry (drier) holes, they have the ability to disappear just like that. If the data were that suggestive, why aren’t they doing just that, or when will they start?

  9. Outstanding story there. What occurred after? Takee care!

    1. The growth in Bakken production has already slowed to a crawl even though billions of new investment went into the region. The hyperbolic declines are too hard to overcome and given the actual EURs there is no way to recover much of the investment made in the sector. This is turning out into a capital destroying process, just like shale gas.

  10. D. Wells

    I hear all this B. S. coming from the ever present know-it-all about Fracking. Fracking has been arround for over 60 years, don’t you know. I Fracked wells in the early sixties and was there on some of the first wells fracked with H2O along with other fluids and co wrote a paper on the advantages of high sand concentrations for proping the formation. Halliburton developed the Crosslength Gelling agent that enabled this to be done and my field crew performed one of the first jobs. Giving the name FATHER OF FRACKING to someone that has recently arrived is a gross misnomer. Recognition goes to Halliburton and other Service Companies involved in the early years.

    1. It is not the technology but the economics that is the problem. It is a fact that none of the primary producers can generate positive cash flows outside of the small core areas in the better formation.

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