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Mark Anthony, is an IT professional and who had a scientific research background before joining the information revolution. Visit his blog: Stockology (http://stockology.blogspot.com/)
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  • Shale Gas Type Curves And Profitability Explained 20 comments
    Jun 12, 2012 5:45 AM | about stocks: CHK, SD, APC, ECA, UNGQ, PCXCQ, ACI, ANR, BTU, KOL

    There is an important controversy on shale gas boom and burst. The controversy focuses on whether the shale gas is economical to produce or not. Critics say the shale industry exaggerated the EUR (estimated ultimate recovery) of shale wells and painted a rosy picture while the productions come out far short of expectations.

    Whether a shale gas well is economical or not relies on these things:

    1. The life cycle total cost of exploration and production.
    2. The EUR, estimated ultimate recovery from each well.
    3. How fast can the gas be recovered and revenue realized.
    4. What is the market price of natural gas produced.

    I will discuss how the industry models shale well declines. Why they often over-estimate the EUR, and why the industry faces gloomy reality when it comes to the profitability of shale gas wells.

    To B Or Not to B - That is The Question

    If you have read Arthur Berman, the outspoken critic of the shale gas industry, you might have wondered what was the b parameter. Berman often referred to the b parameter when he criticized the hyperbolic decline models that shale gas experts use to calculate EUR. Berman believes that such models lead to EUR over-estimates.

    All natural gas wells, whether conventional or shale gas, have their highest daily production rate on day one. They continue to decline throughout their life cycles. The declines of shale gas wells are very steep. Thus correctly modeling the decline is the key to correctly project the EURs. Since few shale wells have gone through a whole life cycle, it leaves plenty of wigging rooms for experts to come up with all sorts of decline models and push for more optimistic results.

    I have developed my own shale gas decline model. The gas industry uses a formula first developed by Arps. They call it type curve. It is an empirical formula. Empirical means it is not supported by physics, but merely by the experience that it seems to give good results.

    My decline model and the Arps type curve model is compared below:

    (click to enlarge)

    As you can see, 0<b<1 is the reasonable range for the parameter. But the industry prefers to use b>1. This often leads to much higher EUR estimates. But it is problematic as it leads to infinity. Nature does not allow infinity.

    Do experts deliberately use a parameter that looks ridiculous from basic physics, in order to intentionally over-estimate EUR? I think I have a more reasonable explanation without pointing fingers. The Arps formula is inadequate that it has only three freely adjustable parameters. When you remove the IP (initial production rate), which is a trivial parameter confined by the total production, you are left with two parameters, initial decline rate D and parameter b. The D can be removed by scaling the time. Thus b is the only adjustable parameter. When b=0, it is just exponential decay. When when a wells decline does not follow simple exponentially decay, which is mostly the case, you have to push b away from 0 for a better data fitting. This often leads to b being pushed too high and b>1.

    But the shale gas industry experts should know better! They should know that the Arps formula has its limit and can no describe the long term trend beyond the first few years, as it has only three freely adjustable parameters. They should have learned from school that the b>1 should not be allowed in the Arps formula as it leads to divergence and infinity.

    I think my own model, with one more parameter than Arps', can better describe the shale gas declines. To verify, I used Berman's chart on Haynesville shale. I super-imposed my own model and CHK's type curve onto the chart, to see how good they match:

    (click to enlarge)

    My model seems to match the data better than the CHK model did. There is no long term Marcellus well data yet. But in long term, the CHK model is problematic as it has virtually no terminal decline:

    (click to enlarge)

    Arthur Berman pointed out that during early well productions; models with vastly different b values all look similar. The differences only show up in the long term, leading to vastly different EUR values.

    Since there is insufficient long term data to tell which model works better, let me run both models to analyze some data.

    Profitability Case Study on Marcellus Shale Wells

    I have studied an EIA document and obtained a type curve chart for Marcellus shale wells. I could use the parameters to construct the same Arps type curve for calculation comparison with my model:

    (click to enlarge)

    The D and b parameters were not given. But given one year, five year and ten year cumulative production and a 3.75 BCF EUR, I could easily found out the D and b used, and verify that I had the correct values:

    • D = 1/3 per month; b = 1.461 (b>1!); IP = 4.11 MCF/day. I obtained the same 1 year, 5 year and 10 year productions.

    It comes out that the claimed EUR of 3.75 BCF is the cumulative production after exactly 500 month, or 40 years and 20 months. The daily production will drop to 0.095 MCF a day. It could fetch $228 at $2.40/mmBtu gas price, enough to pay one day's minimum wage.

    Does Chesapeake Energy (CHK) honestly believe a shale gas well can be produced for that long. at such a low yield? As a matter of fact, since the function is divergent for b = 1.461 > 1, they could let the well run a thousand year and brag about any arbitrarily high EUR number they like. In 1000 years the EUR would be 11.56 BCF:-)

    My calculation results:

    (click to enlarge)

    As can be seen, my model can match the early stage of decline behavior nicely. But my model can also reflect the terminal decline correctly, but CHK's Marcellus type curve can not. The Marcellus type curve is no longer useful after the first 10 years, as it does not reflect the terminal decline phase correctly.

    (click to enlarge)

    The above is the same chart like last one, but with a different time scale to have a closer look at short term pattern of the curves.

    Once the production decline is known, I can proceed to calculate the profitability of Marcellus shale wells. I assume the following for calculations:

    1. Based on numbers contains in CHK's Marcellus type curve chart, they have a drilling cost of $3.6M, finding cost of $1.12/mmBtu * 3.75 BCF. Total $7.8M per well. They excluded many costs. The numbers are several years old so when you add real inflation the numbers are much higher. I assume $15M per well cost for the calculation.
    2. I assume the per month production maintenance cost is $30K.
    3. I start with a debt of $15M for completing the well. The debt carries a 5% annual interest cost.
    4. I assume the principal of the debt is paid off as fast as possible. I tally the number for each month. When there is a debt I subtract interest cost. When there is cash, I add 5% interest income from teh cash.

    Here are the results.

    (click to enlarge)

    I will explain later.

    (click to enlarge)

    Further reading: Hamilton. Read Arthur Berman on Marcellus. Stay tuned on my main SA article which has been submitted. Cheers!

    Disclosure: I am long JRCC, PCX, ACI, ANR, BTU.

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Comments (20)
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  • Paulo Santos
    , contributor
    Comments (18822) | Send Message
     
    Nice work, but still needs a lot of polish to become clearer. Focusing in the physical impossiblity of the parameter used by CHK would also be useful, as it shows there's something clearly wrong in all of this.
    10 Jun 2012, 05:45 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Arthur Berman has been pounding on the table to claim that using hyperbolic decline is wrong. Now I understand the reason. In teh Arps type curve, if the parameter B>1, you have a function that diverges to infinity. That should not be allowed. The shale gas industry should never have used b>1. It was a big joke. They did so because it allows them to claim a much bigger EUR than it really is.
    12 Jun 2012, 05:48 AM Reply Like
  • Jack Wildcat
    , contributor
    Comments (164) | Send Message
     
    $15 million per well is too high...
    12 Jun 2012, 10:57 AM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Based on CHK's own figure, drilling cost was $3.7M, finding cost is another $1.12/mmBtu * 3.75 BCF = $4.2M. Total $7.9M. That was old figure a few years ago. Adding all other related business costs and consider depreciation of the US dollar and inflation in the last 5 or 6 years since CHK proposed the number, I think $15M is a reasonable total figure of well costs.

     

    We are talking about profitability, thus all costs must be counted for.
    12 Jun 2012, 12:13 PM Reply Like
  • Paulo Santos
    , contributor
    Comments (18822) | Send Message
     
    Inflation adds very little. 10-20% or so tops.
    12 Jun 2012, 12:54 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Paulo:

     

    Consider gold was around $600 in 2008 and oil was at $36-ish, today gold is comfortably above $1600 and oil around $100-ish. Price of everthing went up. Coal was very profitable at $36 5 years ago. Today $60/ton is barely profitable. Again price of everything went up a lot.

     

    So if you were given a dollar figure 5 or 6 years old, you can easily add 50% or 75% to the price tag. We are making projection not just for today, but for the next year and next few years. So inflation is a big consideration.
    12 Jun 2012, 03:56 PM Reply Like
  • Paulo Santos
    , contributor
    Comments (18822) | Send Message
     
    Those are just singular examples, overall inflation was much lower, and inflation in goods and services pertaining to drilling and fracking would really be what's at stake here. Some things could have gotten a bit more expensive, but inflating more than 10-20% seems wildly excessive.
    12 Jun 2012, 04:02 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Paulo:

     

    You are detached from reality. Have you go grocery shopping or bought stuff lately? Do you remember how much was one roll of toilet paper, for example. A roll of TP costed 16 cents when it was on discount, last I remember. Now it hardly costs less than $1.

     

    Icecream is up from $2 to $5 or $6 a can.

     

    Gasoline price used to be 10 cents per gallon. Now it's $4. I know it's been a long while since we last sawy 10 cents per gallon gasoline. But an inflation of 40 times over 50 years, is an average of 7.6% annual inflation. That means price adds another 45% in 5 years and that was only the 50 years average. Recent inflation must be higher than 7.6% annually.

     

    Since the CHK figure was 5 years old, add in hidden cost and inflation I can easily justify adjusting CHK's $7.7M per well, to $15M instead. I consider that conservative.

     

    Think about the profitability question as the one you ask yourself if you want to put money to run a shale gas company, or you have better use of your own money. Then the shenanigans on clever accounting tricks will go away.
    12 Jun 2012, 09:54 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (779) | Send Message
     
    For inflation, what you are trying to get at is replacement cost. For NG wells, replacement costs on a volume basis are falling. In other words, a negative inflation rate. For the sake of argument, you could call it flat. You cannot just apply an economy-wide inflation rate to oil & gas companies.

     

    In terms the actual analysis you have done, the majority of the case rests on assumptions you have made outside of the decline rate. The is no need to fully cost each well -- $15 million is just drawn from thin air. You are only looking for a delta between case A and B. The interest cost and debt is also superfluous. If I run an IRR on a hypothetical well between these two decline curves:

     

    http://bit.ly/MA6Hia

     

    I get a difference of one percentage point (assuming the higher is 12.8%, the lower would be 11.9%). Production rates in year 15 are basically meaningless for the IRR. You also have no idea what type of EOR can be done in the out years.
    12 Jun 2012, 01:56 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Jeremy:

     

    No, replacement cost is NOT enough. When consider profitability, consider the question when you have $1B or more. Are you willing to put your money down to explore and produce shale gas, and at what price are you willing to do it?

     

    Investing $1B in the industry and hopefully in 20 or 30 years you get $1.5B or $2B back in 20, 30, 40 years, does not sound like a very encouraging proposition to any investor.

     

    Don't you think profitability means you should be better off than earning a minimum cash deposit interest rate from a bank account?

     

    Let me propose the question like this:

     

    Warren Buffet has $50B cash to invest and is wondering where he puts the money. Now have an opportunity to pitch shale gas as a profitable investment to him, at certain gas price assumption.

     

    Do you think you can get away omitting some of the cost? Do you think you can get away with an investment case weaker than cash deposit earning interest? I Don't think so. All costs and cost of opportunity to earn interest some where else, all needs to be disclosed to old Warren, to make your case compelling to him.
    12 Jun 2012, 03:59 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (779) | Send Message
     
    You are mixing up two issues in your response. The inflation aspect is quite deterministic. All you have to look at is well drilling costs in NG for the last 5 years. Roughly speaking they have not increased -- and certainly have not increased on a volume basis, or in other words, well cost per unit of production. At least this my read of the data I have seen from industry players.

     

    The second issue is what amount of return you require. I have some news for you, returns on capital in the oil & gas business are very low -- basically at the cost of capital which is ~8% nominal. It has been this way for decades. This is probably why Mr. Buffet doesn't own any oil & gas companies. Of course, if you buy an oil & gas company when oil or gas prices are low, and the company has at risk (wrt price) production then you can make good returns as an investor on the increase in the value of the "inventory" (in the ground). However, prices usually go up because costs go up, so as you deplete your current production, replacement cost goes up. It is a one-time windfall only.

     

    In a way this gets back to the main issue with the shale plays. The decline rate accounting may be a little off, but it is a very minor issue. Shale gas companies will get into trouble when they run out of new plays to exploit. This is the curse of the (well known) decline rates of shale, you always have to be drilling and looking for new plays. So when I look at shale companies, I look at all the data around the newest wells and you get good reporting each quarter to do so. When the economics of new wells start to turn, then you will know when the shale companies will be in trouble and/or when NG prices need to increase so that a new, lower quality group of potential plays become economic.
    12 Jun 2012, 04:23 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (779) | Send Message
     
    And also, I agree with you on the endpoint of full cost accounting. But the purpose of your article (I assume), is to shown the economic difference between your model and the "industry's". You don't need full cost accounting to do that. It makes your case more difficult in any case because now you have to explain all the assumptions there.

     

    With respect to deflated F&D costs due to inflated EURs, you need to recompute a precise figure showing the numerator and denominator if you want to make that adjustment. But, you don't need to go that far to make your point.
    12 Jun 2012, 04:27 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » I intended to publish a full SA article on this topic. Unfortunately they declined to publish it. So I have posted the article as an instablog:

     

    http://seekingalpha.co...

     

    It is very important to read. The shale gas industry requires surprising high gas price to be profitable, well into the $10/mmBtu.
    12 Jun 2012, 03:53 PM Reply Like
  • tatonka82
    , contributor
    Comments (2) | Send Message
     
    Mark,

     

    It is pretty hard to apply decline curve analysis to shale gas as the wells are in transient flow for many years, thus your method, like Arps, is very inaccurate. Perhaps you should read, SPE 144436, Advancements in Shale Gas Production Forecasting- A Marcellus Case Study.
    15 Aug 2012, 05:40 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Tatonka82:

     

    I would like to see tha SPE 144436 paper you mentioned. Unfortunately it is paid subscription and I do not want to pay to get something which may not be so valuable.

     

    The problem with Arps Type Curves, or any such attempts to model shale gas production decline, is that they all atempt to count on just the first few month's data and attempt to extrapolate it to several decades out. The method itself is simpli frauded no matter what math model you use. The first few months of production data simply does NOT contain enough information to make meaningful prediction of future production decline.

     

    In another word, the extrapolation is garbage-in-garbage-out. It does not help even if you think you use a pretty smart math formula.

     

    Read my criticism here and my take on the US gas reserve estimate:
    http://seekingalpha.co...
    16 Aug 2012, 01:01 PM Reply Like
  • tatonka82
    , contributor
    Comments (2) | Send Message
     
    Also, your comment about the 1000 yrs of EUR is incorrect as this is a gas well it cannot produce below a certain pressure, even with compression. Of coure the EUR is ultimately determined by the well being profitable. After the well is drilled the capital costs are sunk, and the well will be at the mercy of the LOE, taxes and royalties. What I can see that is sinking the marcellus, even at it lower cost exposure is some of the deals that have been stuck. For example, EOG's deal with Scenca, from what I read, which they pay a 20% ORRI on a group of prospects. If the deal cut with mineral owner is 20%, EOG is left with a 100% WI and a 60% NRI (probably). Hard to make a profit on that sort of deal.
    15 Aug 2012, 05:42 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Tatonka82:

     

    When I said 100 years of production I was just trying to point out how ridiculous the Arps type curve is in predicting long term production, especially with a b>1. It could lead to arbitrarily large EUR. The NG industry is ridiculous in using Arps type curve and then extraploate out to 40 or 50 years.
    16 Aug 2012, 12:52 PM Reply Like
  • jad248
    , contributor
    Comments (2) | Send Message
     
    Mark, I had to comment on this. It seems that you are misled about how the industry is using the Arps equation on estimating reserves from shale wells. Here are the few points I want to point out:

     

    1) Yes, the industry is using hyperbolic declines for shale gas wells with b factors greater than 1. HOWEVER, those wells do not exhibit a hyperbolic decline forever. In fact, the industry is setting the type curve to go into exponential decline (b=0) after a few years of production (2-5 years) depending on what we see in offset wells.

     

    2) We have enough production data on shale gas wells to fit hyperbolic decline curves. In fact, where I work, we have 3 years worth of production data and we cannot fit a type curve with b < 1. It has to be greater than 1 to fit the curve. But as I said, those wells will not stay in hyperbolic decline forever. They will turn to exponential decline (b=0) after a few years and eventually have a nominal decline rate of 5-10% per year. Every single oil company takes this into account, including CHK that you quoted in this post. To estimate the reserves, or EUR, the Arps equation with b > 1 is used for the first 2-5 years, then after that, it's nothing but an exponential decline at b=0 and Dn=5-10%.

     

    3) The reason for these wells to first exhibit a hyperbolic decline with b > 1 in the first years is that initially they will be producing from the fractures. Once the fractures are drained, we start producing from the matrix which will give an exponential decline with low production rates.

     

    3) Shale gas wells will definitely have a life cycle of more than 50 years. If vertical wells produce for more than 50 years, why can't horizontal wells produce for more than 50 years too? But again, the wells will be producing exponentially in their later life cycles, and not hyperbolically as you might think. No technical professional in the industry believes that shale gas wells will produce hyperbolically forever. The decline curve changes to an exponential one once the fractures are drained. And with the help of artifical lift systems, we can maintain those wells for more than 50 years.
    30 Sep 2012, 05:36 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3601) | Send Message
     
    Author’s reply » Jad248:

     

    There are conventional natural gas wells that can keep producing for 50 years as they have very low decline rate. But shale gas well are very different as there is low permiability. You also admitted that after a few initial years there will be a terminal decline of 5-1% per year. How much will the production rate be if it keeps declining 5-10% for 50 years? You can't keep producing that long as the low productivity makes it not worth keeping the well.

     

    CHK's Arps Type Curves allow no terminal decline. They calculated EUR and released the number, using un-modified Arps formula and extended it for 500 months. I know that is what they did as I did precisely teh same calculation and come up with precisely the same numerical results.
    30 Sep 2012, 11:41 PM Reply Like
  • jad248
    , contributor
    Comments (2) | Send Message
     
    Mark, trust me, I am operating tight gas vertical wells in the Rocky Mountains that have been producing since the 1970 and they're still producing. Yes, they are making less than 50 MCFD, but that's enough to keep them making a positive cash flow even at $3/MCF gas price. They paid out long time ago and they can produce for many years to come with artificial lift, even at rates less than 20 MCFD. These tight gas vertical wells have permeability in the order of microdarcy (just like shale gas wells) and they also have to be hydraulically fractured in order to flow (again, just like shale gas wells!). In fact, today we're drilling & completing horizontal wells in the same field and we have no doubt that those horizontal wells will produce for 50+ years, because guess what? We have vertical wells that have. Horizontal wells will only be better, not worse.
    1 Oct 2012, 01:27 AM Reply Like
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