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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 (
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  • Implication Of Shale Gas Boom And Bust Examined 24 comments

    There is an ongoing controversy on shale gas boom and bust. The controversy is whether the shale gas is economical to produce. Critics say EURs (Estimated Ultimate Recovery) of shale wells were exaggerated using flawed models; and that the industry painted a rosy picture while the productions come out short of expectations.

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

    1. The life cycle total costs of exploration and production.
    2. The EUR, estimated ultimate recovery from each well.
    3. How fast is the gas produced and turned into revenue?
    4. The market prices of natural gas produced.

    I will discuss how the industry projects shale well declines; why the EURs are often over-estimated; and why the industry faces gloomy reality of non-profitability of shale gas wells. I will try to explain technical concepts using lay man's English to investors. If you are confused, just look at the pictures and then go to the conclusions.

    To B or not to B - That is the Question

    I once wondered what the b parameter was. Arthur Berman mentioned it when he criticized the hyperbolic models that shale gas experts use to calculate EURs. Berman claimed that such models over-estimated EURs.

    All natural gas (NG in brief) wells, conventional or shale gas, see highest daily production rates on day one. Production rates decline continuously throughout well life cycles. Shale gas wells could lose 80% of production rate in the first year. Thus modeling the declines correctly is the key to predict EURs. Since few shale wells have gone through whole life cycles, there is wigging room for experts to come up with different decline models.

    I developed my own shale gas decline model. The NG industry uses a formula first developed by Arps, called type curve formula. It is an empirical formula. Empirical means there is no physics support, but by experience the formula seems to match actual data nicely. My model and the Arps type curve model are compared below:

    (click to enlarge)

    (click to enlarge)

    As it comes, 0<b<1 is the reasonable range for the parameter. But the industry prefers to use b>1. This gives higher EUR values. But it also leads to infinity, which is not allowed in nature.

    Not willing to point fingers, I believe there is a perfect explanation why they tend to come up with b>1. Read my detailed discussion. The Arps model has too few freely adjustable parameters to fit the data, so b is biased and could be off the accepted range.

    But still, when b>1, the Arps type curve diverges to infinity. Thus it fails to model the long term decline of gas wells correctly.

    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 Marcellus shale wells.

    Profitability Case Study on Marcellus Shale Wells

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

    (click to enlarge)

    The D and b parameters were not given. But given the cumulative production at one, five and ten years, I easily found out the D and b used, and verified 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 came out that the claimed EUR of 3.75 BCF was the cumulative production after exactly 500 months. The daily production would drop to 0.095 MCF/day, or worth $228 at $2.40/mmBtu gas price, enough to pay one day's minimum wage.

    Did Chesapeake Energy (NYSE:CHK) honestly believe that shale gas wells could last that long and at such a low yield? In fact, as the function is divergent (b = 1.461 > 1), they could theoretically keep the wells running forever and brag about any high EUR number they like.

    Let me show what the Arps type curves look like, and how they compare with my model:

    (click to enlarge)

    The lines that go down represent production rates drop over time. The two lines that go up are cumulative productions. Tow red lines were from my model. The rest were from CHK Marcellus type curves and from sample Arps curves with different b values.

    As it shows, my model and the CHK model is similar at the beginning. It is hard to tell who is right from well production data in the first 10 or 12 years. The big difference starts to show up after 145 months, or 12 years. At the tail end, my model shows a reasonable terminal decline, while CHK's model shows almost no terminal decline. It keep going and going like the battery bunny.

    Limited natural resources should have a terminal decline phase. As the remaining resource is depleted, the volume that comes out is roughly proportional to what remains. In math, when the change rate of a quantity is proportional to the quantity that remains, it is known to be an exponential decline.

    (click to enlarge)

    The above chart is the same as the previous one, except that I reduced the time scale for a closer look.

    I replicated the Marcellus type curve and confirmed that my model works. I can use the data to calculate the profitability of Marcellus shale wells based on different gas prices and costs.

    Gloomy Profitability Reality of the Marcellus Shale Wells

    The industry produces shale gas to make money, not to provide a charity. Currently natural gas prices are deeply non-profitable. Most believe that the NG prices will recover. The question is, once the gas prices return to normal levels, say $4 or $5 per mmBtu, will the shale gas industry be able to make a profit?

    Some NG executives claimed they were profitable even at $2/mmBtu gas prices. They probably did not count costs like land leasing, G&A expenses, and interests on loans. They probably expected to produce the wells for 40 or 50 years. (CHK used 500 months life span to obtain 3.75 BCF EUR for Marcellus wells). They might not have calculated inflation and depreciation of currency. I want to use data to find out.

    Spending $15M to drill a well and break even in 30 or 50 years is not profitability. Profitability means there is a reasonable hope that when all dollars and cents are counted, you recover all the costs within a reasonably time period, and then begin to make a reasonable profit.

    Let's start with lifetime total costs of Marcellus wells. CHK gave $3.6M drilling cost, $1.12/mmBtu finding cost for an EUR of 3.75 BCF. That makes $7.8M. The actual figures are higher when you count in all the excluded costs. The figures were provided several years ago. Consider how much gold and other commodities have gone up, it is safe to say the costs are proportionally higher today.

    I think a lifetime per well cost of $15M is reasonable for calculation. There are also interest costs. Let's say the interest rate is 5%.

    Maintaining production and delivering the gas also has costs. I will assume $30K per month for that. My profitability model starts with $15M in debt. As gas revenue comes in, the debt is gradually paid off. Where the lines cross the X axis are the break even points.

    Here are the results. I added a line representing $18M cash that bears 5% interest for a comparison:

    (click to enlarge)

    The result is pretty distressful. Remember I used CHK's own model:

    • To reach break even in 10 years, CHK's model requires $9.84/mmBtu gas price. My model requires $9.94/mmBtu.
    • After breaking even at 10 years, the CHK model continued to match upwards as if there was no terminal decline.
    • My model has a terminal decline. It made a small $2M net profit 20 years after $15M was invested. It went downhill afterwards, dashing any hope of profitability. At 35 years it reached another break even point, on the way down.
    • The guy who deposited $15M to earn 5% interest saw his money doubled in 14 years. CHK, even using its rosy model projection, did not see $15M in profit until 40 years. That was a meager 1.7% annual return for 40 years.

    The above assumed gas price could reach nearly $10/mmBtu. Ten years just to break even is unacceptable. Let's see higher NG prices:

    (click to enlarge)

    At $12/mmBtu, things looked better. Both CHK and my projection reached the break even point in 5th year, and continued to make profits. But in no time did either model do better than the $15M cash earning 5%. Some one sits at home was earning more interest than the companies who work in the wild to produce gas could profit.

    At $13.05/mmBtu, CHK finally caught up with the performance of cash deposits in 12 years, but only momentarily. Even at $14/mmBtu gas prices, my model still lost the competition to the cash deposit at 19 years, time period that Jean Valjean served for stealing bread. Oh les Misérables!

    The Reality Could Be Worse As Real EURs Are Much Lower

    The projections were bad enough. But the reality could be worse!

    The discussions above were based on a model that the industry provided. The model has exaggerated the EUR and under-estimated the steep decline of gas wells. Even my model tried to match the industry model, instead of the actual production data. The real data could portrait a gloomier picture.

    Using Arps formula with a b>1 is bad enough. What made things worse is that the industry experts simply tried to fit the first 120 or 180 days of well production data with a set of parameters. Then they calculate the EUR based on the parameter set.

    But during early stage of a well's production, ANY parameter set could fit the data! So there is room to push for a very high b value and make it look fits. The higher the b value, the higher is EUR.

    Here is one example originally from Ultra, another gas producer in the Marcellus play. See the type curve chart where I superimposed my own data fits:

    (click to enlarge)

    Based on the fit by Ultra engineers, the b is as high as b=1.522 and they obtained EUR=3.75BCF. The dotted blue line was my fit to show that I replicated their red fit curve. However I have another fit, as the magenta line. My fit seems to match the well production data better, especially look at the mid-section. But my fit would suggest a EUR of only 1.8 BCF by 500 months.

    Making matters worse is NG producers have racked up mountains of debts developing shale gas wells. The shale gas over-drilling, over production, the decade low NG prices and the subsequent capital destruction is destroying the US NG industry.

    America still needs natural gas. The NG industry as a sector will not go away. But there are serious questions on whether shale gas is really a viable energy source, or is hydraulic fracturing technology really effective in the long term. People have too many questions, but the industry refuses to tell the full truth. Even today, there is still no disclosure on what is contained in the hydraulic fluid used.

    Do you feel comfortable investing in a sector where you do not know the full truth? I don't.

    The Implication for Investors

    In recently times we heard a lot of talks of abundant, cheap and clean natural gas to replacing dirty and filthy coal. Coal is dirty. But we do not have a choice. Coal is still the cheapest and most abundant fossil fuel we can count on. Old king coal is not going away any time soon. I am convinced the deeply discounted coal sector is the best investment opportunity in 2012.

    I am bullish in natural gas prices. The NG industry needs to keep drilling to maintain overall production, but they are losing capital selling gas at a deep loss. This is unsustainable:

    (click to enlarge)

    But I do not recommend United States Natural Gas (NYSEARCA:UNG) or any ETF based paper future contracts.

    I continue to caution people to pay attention to the unfolding drama of capital destruction in the natural gas sector. A lot of shale gas players need to go belly up. There will be a time when all the nasty stuffs are put out for all to see. At that time there might be some survivors worth picking up. But avoid these names now:

    • Chesapeake Energy Corp. [CHK]
    • Constellation Energy (CEP)
    • Cabot Oil & Gas Corp. (NYSE:COG)
    • ConocoPhillips (NYSE:COP)
    • Anadarko Petroleum Corp. (NYSE:APC)
    • EOG Resources Inc (NYSE:EOG)
    • Devon Energy Corp. (NYSE:DVN)
    • Baker Hughes Inc. (NYSE:BHI)
    • Southwestern Energy Co. (NYSE:SWN)
    • Sand Ridge Energy (NYSE:SD)
    • Pioneer Natural Resources (NYSE:PXD)
    • Magnum Hunter Resources (MHR)
    • Kinder Morgan Energy Partners (NYSE:KMP)
    • Enerplus Resource Fund (NYSE:ERF)
    • Carrizo Oil & Gas (NASDAQ:CRZO)
    • Callon Petroleum (NYSE:CPE)
    • Enterprise Products Partners LP (NYSE:EPD)
    • Goodrich Petroleum (GDP)
    • GMX Resources (GMXR)
    • IDT Corp (NYSE:IDT)
    • Lucas Energy (NYSEMKT:LEI)
    • Rex Energy (NASDAQ:REXX)
    • Approach Resources (NASDAQ:AREX)
    • Natural Gas Services Group (NYSE:NGS)
    • Breitburn Energy Partners (BBEP)
    • National Fuel Gas (NYSE:NFG)
    • Range Energy Resources (NYSE:RRC)
    • Petroquest Energy (NYSE:PQ)
    • Unit Corp. (NYSE:UNT)

    I maintain that the US coal sector is a much better investment opportunity, due to strong international demands, recovering demands and aggressive production curtailments by coal producers, and finally but not the least, the ongoing capital destruction in the shale gas industry is leading to drilling activity falling off a cliff. A natural gas shortage could be loom in a few months. That outcome is extremely bullish for both NG and coal. But since coal prices are only moderately below profitable margin, coal producers stand to benefit the most, when a natural gas price rally shifts demands back to coal in a few months.

    I continue to recommend these great values in coal:

    • James River Coal Company (JRCC)
    • Patriot Coal (PCX)
    • Arch Coal Inc. (ACI)
    • Cloud Peak Energy (NYSE:CLD)
    • Alpha Natural Resources (ANR)
    • Consol Energy (NYSE:CNX)
    • Black Hills Corp. (NYSE:BKH)
    • Walter Energy (NYSE:WLT)
    • Westmoreland Coal (NASDAQ:WLB)
    • Peabody Energy (BTU)
    • Nacco Industries (NYSE:NC)
    • Alliance Resource Partners LP (NASDAQ:ARLP)
    • Market Vectors Coal ETF (NYSEARCA:KOL)

    I am getting cash to buy more coal stocks.

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

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Comments (24)
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  • Paulo Santos
    , contributor
    Comments (34886) | Send Message
    I do think you need to revise the well cost lower. Or perhaps provide a table considering several possible well costs, from $5 million upwards.
    12 Jun 2012, 03:54 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3595) | Send Message
    Author’s reply » Paulo:


    I consider the profitability question as a question whethere there is enough incentive for people to invest money in the shale gas exploration and production. Thus ALL costs must be included.


    Think about a hypothetical situation where Warren Buffet has cash to invest in some business sector, and you are to try to pitch shale gas as a sector with attractive profit potential. You can not get away with hiding certain costs. You can not get away telling him that hopefully in 20 years he will break even, and before the well runs dry in 50 years he will make a 50% return for thos 50 years.


    So keep that in mind, what would you consider as the per well cost. If it is your money to put in the industry don't you worry about EVERY cost?


    Now the $15M figure. Based on CHK's fugure, $3.7M to drill the well, $1.12/mmBtu (at 3.75 BCF EUR) finding cost figures into another $4.2M. Total $7.9M. This figure is ONLY what CHK is willing to tell you. It is an out dated number and it excludes all other associated business costs.
    12 Jun 2012, 04:14 PM Reply Like
  • Smilin Bob
    , contributor
    Comments (96) | Send Message
    Sparky (Mark) – Tisk, tisk, tisk… deleting my posts, that bring up legitimate criticisms only helps prove that you are a fraud. You keep deleting and I’ll keep posting.


    As Daniel Patrick Moynihan reportedly said “everyone is entitled to his own opinion, but not his own facts.”


    You make way to many assumptions about well costs that are not based in reality, and you know what they say happens when you assume (you make an @$# out of you and me). As I have repeatedly told you, well costs are highly dependent on the type of well, the operator, and the resource play among other things. In the first part of your article you seem to be interchanging the Marcellus and the Haynesville Shale.


    You realize that these are different formations in different parts of the country don’t you?


    You realize that the Haynesville is essentially all dry gas, while the Marcellus has a wet gas portion don’t you?


    You realize that NGL’s make a difference in the profitability of a well don’t you?


    You realize that most companies have shifted away from dry gas and focusing on more liquid rich plays don’t you?


    You realize that the majority of dry gas wells being drilled are only in order to HBP the acreage and that the number of dry gas wells being drilled are dramatically declining don’t you?


    You realize that CHK is only one company and you cannot use their numbers in one resource play to extrapolate well costs for the entire industry across all resource plays don’t you?


    No one is going to argue with you that natural gas is profitable at its current low price because it isn’t, but you have made up/skewed well costs to fit your thesis, so what else are you making up?
    12 Jun 2012, 04:20 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (775) | Send Message
    You are just trying to make too many points in one article. If you are trying to prove that even with the industry's model, the wells are still not economic because of "real" well costs then there is no need to revise the model to make your point. But then you need to make a compelling case about well costs.


    In any event, this is a low return business. If an oil & gas company is making its cost of capital +1%, it is doing a fantastic job -- unless it has monopoly access to resources. This is just the history of oil & gas.
    12 Jun 2012, 04:32 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3595) | Send Message
    Author’s reply » Jeremy:


    Yes there should be two separate points to argue. One point is the industry's production decline model is flawed and over-estimate the EUR, ultimate production volume. The second point to argue is that even with the industry's rosy production model, shale gas is deeply un-profitable even at very high prices.


    I have submitted another piece, with some better graphics, and with discussion of my own production decline model removed. I hope they can publish it soon.
    12 Jun 2012, 09:30 PM Reply Like
  • ook
    , contributor
    Comments (138) | Send Message
    The b is not really so important. There have already been Barnett shale wells producing long enough to reach decline rates of 6% despite high initial declines, so we know it happens.


    Your article would be clearer if you used standard financial math... in oil they use PV 10 (or sometimes less like PV 8) to calculate the present value of drilling from discounted cash flows. They don't arbitrarily double the cost of the well upfront to represent required return, that's not the proper mathematical way to do it. So for example if in year 20 the small amount of gas they claim to get isn't there it hardly matters because the 10% discount rate to the 20th power says to multiply by 15%. It's 85% ignored already.


    Also while we might not know exactly how much gas there will be 10 or 20 years out, we do know the type curves have consistently underestimated the amount of gas produced in the first few years. This is a combination of type curves being conservative plus continued technological advances. For example they now know in some places to use more sand or different proppant or fluids or more stages, or even what direction to drill or propagate the frac.


    As for costs, it is not appropriate to use well costs or initial production from a few years ago. Costs have declined and are still declining while IPs are still rising. A well that used to take a month to drill might now take 2 weeks. I would also not use cost of land because all that tells you is if someone made a mistake in how much they paid for the land. It doesn't tell you how to value reserves, but it does tell you bad decisions were made in purchasing the land at high value years ago. Maybe it's a good way to evaluate management's prior decisions, but it's not a good way to value a company.


    Some quick math will show your required breakeven cost is too high. It only takes a few years for half of the projected gas to be produced. At $10, subtract $2 for lifting costs and G&A. Take a Haynesville well which are not the best and have some of the higher decline rates. Say 8bcf EUR for $8 million. Lets take off 2 from the EUR for royalty (the royalties in Texas are quite high). And now lets divide the EUR by 2, giving us 3bcf produced in only a few years. 3bcf * $8/mcf gives $24 million. That's pretty good on an $8mm investment, not to mention the well will keep producing something after even if the b is off. And for the first few years there's no guesswork about b, there are many wells producing this long in the Haynesville.


    I've read many of your articles before and you have many good ideas, but the best way to learn oil and gas is to go directly to the presentations of these companies and read about falling drilling costs and look at the charts of actual production vs the type curve to see that it's not about theoretical values of b. It's about a triumph of technology that's moving so fast that if you read things from 4 years ago or even 2 years ago the numbers will not make sense.
    13 Jun 2012, 02:16 AM Reply Like
  • Mark Anthony
    , contributor
    Comments (3595) | Send Message
    Author’s reply » ook:


    The high EUR estimates are unrealistic. 8 BCF EUR is pure nonsense. None of such high EURs have ever been confirmed by actual well production data. Even a few wells are exceptionally good, they are not representative of the average. When looking at the big picture, the average matters.


    I was looking at some EIA data. On the past 7 years, from 2005 to 2011 that data is available, US drilled a total of 163,726 gas wells. More than 80% are shale gas wells. So there are an estimated 18,800 new wells per year. You look at US gas well profiles. There are 18,800 wells in first years of production. 18,800 wells in second year, etc, all the way to 7 year.


    So each year, you produce roughly 18,800 of EURs of shale wells, assuming from year one to year 7 is almost the entire EUR. But according to EIA, out of annual 24 TCF of gas production, shale gas is roughly 22%, or 5280 BCF annually from shale gas. I already said we produce 18,800 EURs of shale gas each year. So 5280 BCF total production, divided by 18,800 wels. The average EUR is then merely 0.280 BCF, a far cry from 8 BCF per well.
    13 Jun 2012, 02:38 AM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (775) | Send Message
    The actual BCF is totally irrelevant. In fact, any of these numbers in isolation has no real relevance. You need a systematic approach such as a well-based IRR to see the interplay between the amount of NG produced, the initial cost and the ultimate profit.


    8 BCF is a high number but so is $8 million a well. But the ratio is roughly correct. In the Fayetteville, you are are looking at 2.5 BCF and $2.8 million for a well. As ook said, the land cost is irrelevant for future economics, because the land costs change based on the price on NG. Royalties can also come under pressure if NG stays low for a period. Both of these items in any case are really pure profits, they just go to a different set of people/entities than the driller.


    As to the issue of the decline curve, I will reiterate and amplify something ook said. There are fraq'd vertical Barnett shale wells that have been in production for 15 years, and horizontals for 10 years. The out year decline curves are known from empirical evidence. So the guess work here is more limited than you imply. Also its relevance is limited, because the PV of 100 BCF of gas in 15 years is very small.
    13 Jun 2012, 11:21 AM Reply Like
  • ook
    , contributor
    Comments (138) | Send Message
    Look at page 22 of this Goodrich Petroleum presentation:


    This is what actual Haynesville wells look like (the yellow line is an avg of many wells). Examine the first 24 months production to see that the wells produce on average 4000 mcf/day. Multiply by 730 days and you get over 2.9 bcf. These are real wells. And not even the best wells....look at page 25 and the restricted choke program. It turns out the pressure in the Haynesville was so high that the sand was being blown out of the fracks. Everyone figured out if you produce them slower to begin with you get the lost production back and more in only a couple of years. This is also not theoretical. Year 10 might be a bit off and year 20 a wild guess, but years 1 and 2 actually happened already, and the next several years are easy to guess based on the pressures . The first 2 years production on the improved wells is easily in excess of 3bcf, and the production and the pressure (indicative of future production) are higher than wells without the restricted choke.


    This isn't a theoretical exercise or an extrapolation from history. If the question is how much does a Haynesville shale well produce in 2 years, here is the answer. Costs work the same way, there is no need to look at costs in 2008 and adjust for the price of gold. These are actual costs and differ from other costs in the economy because of the technology involved. Give someone $8mm and they will poke a hole in the ground and frac it. Give them $10mm and they will drill a deeper one or one with an even longer lateral just like you see in the presentation. I would say the reported costs have been pretty flat, but what you get for your $$ has been increasing noticeably ($ per lateral foot), so in that sense well costs are declining.


    I fully appreciate the claim that year 10+ cannot be known because it never happened yet. But it doesn't matter, the economic value of the well is pretty much over after year 10... look I remember reading your stuff on FSLR when I was wondering about how they could possibly plate the world with something rare like gold and I found you making the same argument to those who refused to believe (in the end it turned out it wasn't even economical to plate the world with cheap Tellurium compared to silicon). That was you, right? But now I just want to make the helpful suggestion that your entire thesis is at risk because you are using the wrong sources for data. If companies lied about actual production like this they would go to jail. It's much different than picking improper b's. Other companies are reporting the same thing, this is just the first one I found today. Petrohawk was saying the same thing last year when they were acquired. If this was all made up BHP might have had something to say.


    And the Haynesville wells are not the most economic. Check out the Marcellus. In particular check out what COG is accomplishing in the very core of the play.... let me add one thing, that production doesn't peak on day one due to the frack water being produced first, so that skews first year data even more.
    13 Jun 2012, 12:23 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (775) | Send Message
    You need to publish this in his published article:



    I don't have the time to refute all the unsupported assumptions...
    13 Jun 2012, 01:39 PM Reply Like
  • Paulo Santos
    , contributor
    Comments (34886) | Send Message
    Tell me something, if the wells pay themselves off so fast, why is the company carrying so much debt and no cash?


    Indeed, they're saying they'll have a $250 million capex program going, they better get someone to lend them the money.
    13 Jun 2012, 02:43 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (775) | Send Message
    The source of cash and the use of cash are two different items. There is no reason OCF needs to equal ICF - (some number) for an E&P. You can pay a dividend, build up cash, or reinvest your cash in the ground. Especially for smaller E&Ps, there is no reason to have "free cash flow" which is basically a useless number for an E&P anyway because you are in the business of selling your fixed assets off, every day.


    For management, if you think land/oil/gas/etc prices are too high, sure you make the capital allocation decision to build cash. If you think they are fair, then you reinvest. Unless you can find an unidentified play that requires prices much lower than market to be profitable. This is rare. Large companies like XOM or CVX have a different problem. One, they are not only E&Ps and refiners/chemical makers and have different economics. Two, sometimes they generate too much cash to effectively reinvest it, no matter what they feel about the market due to lack of opportunities. This is why they mostly have declining production profiles.


    Another thing you need to understand about oil & gas is that at heart it is very low return business. It is extremely capital intensive. Where some players did good is that they found deposits that others didn't fully understand and drove efficiencies that were not recognized by the land market and other players. They were able to produce the resource way under market price. Now, even if the market price of NG were still $10, over time these companies would still be low return businesses. Why? Because drillers would be willing to pay higher royalties and more for the lease rights until they drove returns down to their cost of capital. If there was enough of the resource, the price of it would also come down.
    13 Jun 2012, 03:41 PM Reply Like
  • ook
    , contributor
    Comments (138) | Send Message
    Haynesville isn't economic under $4-$5, certainly not at $2.20. 25% royalty. $2 lifting G&A and interest. And F&D is over a buck per mcf, so even $4 doesn't create value. Wouldn't touch Goodrich. A lot of the Haynesville companies took on debt to drill to hold the acreage then they found out the Marcellus was better and the liquids shales are more economic too and all of a sudden the Haynesville looked expensive. Each year they drilled expecting to receive certain prices and then the price fell. Their costs kept falling, but they accumulated debt because they kept budgeting for higher prices


    Some companies continue to drill the Haynesville to hold acreage. It is value destroying but they are doing it anyway. Encana believes in a few years it can get pad drilling of the Haynesville to be economic closer to $3.


    COG is more interesting because it has the lowest cost dry gas. $3 can turn them a profit.
    13 Jun 2012, 03:45 PM Reply Like
  • Paulo Santos
    , contributor
    Comments (34886) | Send Message
    Jeremy, these companies put themselves into a position where if their bankers want to, they can take the assets next day. And there are many like these, which is weird for all those fast-paying wells.
    13 Jun 2012, 03:56 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (775) | Send Message
    Where I won't disagree with you is that certain companies made bad investment decisions. But you can paint a lot of good companies bad by just looking at free cash flow in the oil and gas business.


    Also, debt is certainly more risky than equity, but equity isn't always available. So some companies took the risk to keep expanding as fast as possible by using debt. They will have to pay the price. Ultimately what is funny is that some companies are in trouble basically due to their (and other players) own successes. The price of NG came down because you can get it out of the ground more cheaply than assumed just a few years ago.
    13 Jun 2012, 04:03 PM Reply Like
  • Paulo Santos
    , contributor
    Comments (34886) | Send Message
    So now we know that production was expanded by a bunch of drunken debt sailors, to the point where shale gas represents 35-40% of the overall natural gas production.


    Which means that now the sailors will find it hard to find financing (the bankers will certainly be scared with $2 gas), no one else will step into their shoes and drill heavily, and shale gas will see rapid production drops.


    The consequence will be a temporary natural gas shortage somewhere down the road (I'm guessing 2013 given the production declines).
    13 Jun 2012, 04:08 PM Reply Like
  • ook
    , contributor
    Comments (138) | Send Message
    Absolutely. Production is already starting to roll over. There has been a backlog of unfracked wells which have been hiding the decline in rigs. There is some shut in production which will come back (2bcf/day?) and as price approaches $5/mcf coal will come back in full force as well as will gas drilling. A really cold winter would sure make things interesting ! Goldman Sachs has been recommending buying the spring 2013 futures based on this idea.
    13 Jun 2012, 04:19 PM Reply Like
  • Jeremy Johnson, CFA
    , contributor
    Comments (775) | Send Message
    Not necessarily. There are plenty of well capitalized E&Ps that can take up the slack. However, $2 gas is too low. I think for the market to clear you need $4. But, look at the forward curve by Jan 2014, you are at $3.80.


    Also, you still have easy to get dry gas in the ground and everyone knows exactly where it is and the infrastructure is in place. With the high IPs, it would not take long to bring new gas to market, but you would need the price up to get the ball rolling. So from a trading perspective, perhaps the market is ripe for a bounce. But a shortage for winter of 12-13 is just crazy. There are too many levers an E&P can pull to increase production from existing assets in the short-term. This is also why storage will not fill up. It's not like you drill a well and it all comes out and you have no control of the flow rate. You don't even have to start producing the well once its drilled. Just cap it. Not a big deal really.
    13 Jun 2012, 04:20 PM Reply Like
  • 21793061
    , contributor
    Comments (1281) | Send Message
    Paulo: The drunken sailors had to endure their hangovers (the companies that overpaid for land). But in terms of the supply to market itself, the long term price expectation has been consistently dropping, when weather gyrations are excluded.


    Consider the contract for DEC2018 natgas. Far enough out that current weather is not a factor. At the time of your comment in JUN12, it was trading at ~$5. Now it is trading at $3.

    16 May, 03:20 AM Reply Like
  • Paulo Santos
    , contributor
    Comments (34886) | Send Message
    Yes, things change and get delayed. Who'd say we'd get a couple more QEs and more debt binging still?
    16 May, 06:20 AM Reply Like
  • Mark Anthony
    , contributor
    Comments (3595) | Send Message
    Author’s reply » I made an incredible discovery on CHK's Marcellus Type Curve Model.


    As you know, the Arps formula has only THREE parameters:


    IP: Initial daily production rate in MCF/month.
    D: Initial decline rate, per month
    b: The b factor. A dimension-less number.


    CHK gives that cumulation productions are:
    1-year: 0.67 BCF
    5-year: 1.55 BCF
    10-year: 2.11 BCF
    EUR: 3.75 BCF (at 500 months)


    In mathematics, if you have three parameters you can try to fit three data points but can not fit all four data points.


    But CHK seems to accomplished the impossible. I find the perfect fitting parameters:


    IP = 4.1206448422025
    D = 0.33548851011934
    b = 1.4627542788695


    Using the above fit parameters, the productions are calculated as:


    01-year: 0.6700000000000
    05-year: 1.5500000000000
    10-year: 2.1100000000000
    500Mon: 3.7500112359297


    The numbers are precise to 13 effective digits. The first three numbers are not surprising, because I try to fit three parameters to the precise numbers.


    The last one, cumulative production at 500 months, which CHK took as the EUR, surprisingly, also came to be almost an exact number, 3.7500112359297. It only differ from the exactly number, 3.75, beginning on the 6th digits.


    The odd that happens, is one out of a million.


    Incredible! Does that mean CHK did not get these numbers from surveying actual well productions, but fabricated it using a computer program?
    13 Jun 2012, 10:12 PM Reply Like
  • Paulo Santos
    , contributor
    Comments (34886) | Send Message
    It might well mean that, and the plot might thicken a lot in the following days. Just wait for my next article ...
    13 Jun 2012, 10:37 PM Reply Like
  • Mark Anthony
    , contributor
    Comments (3595) | Send Message
    Author’s reply » Here is the formula derived from Arps type curves:


    Define U = IP*30/(D*(B-1)) = 796.266317 MCF
    Define function A( = (1+bDT)^((b-1)/b)
    A( = (1+0.49073725368861813...


    Cum. Production P( = U*(A(


    1-Year: T=12 (months)
    P(12) = U*(A(12)-1) = 669.99999997 = 670


    5-year: T=60 (month)
    P(60) = U*(A(60)-1) = 1550


    10-year: T = 120
    P(120) = 2110


    500-month: T=500
    P(500) = 3750.011


    This is precisely the EUR CHK gave 3.75 BCF


    Is it a miracle or not?


    Use this web site to calculate arp curve, if you hate to calculate it yourself:
    14 Jun 2012, 12:08 AM Reply Like
  • Mark Anthony
    , contributor
    Comments (3595) | Send Message
    Author’s reply » With the above parameters you can use the online calculator to calculate the Arps formula:



    IP = 4.1206448422025
    D = 0.33548851011934
    b = 1.4627542788695


    Define U = IP*30/(D*(B-1)) = 796.266317 MCF


    Example to calculate 1-year cumulative production. We should get 0.670 BCF. The time is 12 months.


    Step1. Take D multiplied by 12 (month). Thie result is
    4.025862 Enter it into box1 on the above web site.
    Step 2. Enter b value into box2: 1.4627542788695
    Click "calculate". The result in box3 is


    Step 3: Manually calculate:
    (Box1*Box2 + 1)*box3 - 1
    = (4.025862 * 1.4627542788695 + 1) * 0.26730555168749875 - 1
    = 6.8888465 * 0.26730555168749875 - 1
    = 0.8414265


    Step 4. The above result times U gives the result:
    U * 0.8414265
    = 796.266317 MCF * 0.8414265
    = 669.99996 MCF
    = 0.67 BCF


    Have fun!
    14 Jun 2012, 12:50 AM Reply Like
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