Peak Oil is You

Donate Bitcoins ;-) or Paypal :-)

Page added on December 27, 2014

Bookmark and Share

The Dangerous Economics of Shale Oil

The Dangerous Economics of Shale Oil thumbnail

For years, we’ve been warning here at that the economics of the US ‘shale revolution’ were suspect. Namely, that they’ve only been made possible by the new era of ‘expensive’ oil (an average oil price of between $80-$100 per barrel). We’ve argued that many players in the shale industry simply wouldn’t be able to operate profitably at lower prices.

Well, with oil prices now suddenly sub-$60 per barrel, we’re about to find out.

Using the traditional corporate income statement, it is difficult to determine if shale drilling companies make money. There are a lot of moving parts, some deliberate obfuscation at some companies, and the massive decline rates make analysis difficult – since so much of reported profitability depends on assumptions made regarding depreciation and depletion.

So, can shale oil be profitable? If so, at what price? And under what conditions?

I try to deconstruct all this here.


A shale well consists of a vertical shaft that drives down into the earth to get to the right geological layer where the oil is located. Then the shaft bends 90 degrees, and extends horizontally 5000-10000 feet. It is in the horizontal section where the magic takes place. At intervals along the horizontal section, the “frac stages” happen, each of which fracture the surrounding rock to release the oil locked inside the rock.

Constructing a shale well happens in two stages. First both the vertical and horizontal sections of the well are drilled, and that costs around $4 million taking perhaps 20 days. Then, the well is “completed” – this is where the frac stages are placed. Each frac stage costs around $70k, and there are often 20-30 frac stages per well. The entire completion process costs around $4M. Once completed, the well starts producing oil and gas.

The initial production (IP) of a new well is a critical number for estimating the total amount of oil likely to be produced over the lifetime of the well (“Estimated Ultimate Recovery” = EUR), along with the expected decline rate. While the EUR is a theoretical number and assumes a recovery time of 10-30 years, from a practical standpoint, companies need to recoup the costs of drilling the well within 3 years.

Shale drilling has dramatically improved over the past five years. Horizontal lengths have doubled, upgraded drill rigs result in fewer breakdowns and faster drilling speeds, pad drilling has eliminated the downtime required to move the drill.

Today’s wells (vs wells drilled in 2008-2011) have horizontal sections twice as long, with three times more frac stages, with closer frac groupings, and the wells are drilled in about half the time. This results in wells that produce about twice as much, and take half the time to drill. However at the same time, many of the best spots have already been drilled, so the significant improvements in drilling efficiency have only been able to increase per-well production by a modest amount – perhaps 7%.

Regions, Geography, Decline Rates

There are three primary geographical regions where shale oil drilling takes place: Bakken, Eagle Ford, and the Permian Basin. Total production in these three areas: 4.6 mbpd, or 92% of shale-region oil production in the US. Shale regions provide all the growth in US domestic oil production.

Of these three areas, Bakken and Eagle Ford are the most productive oil shale areas, and of these two regions, I’ve selected the Bakken for a more detailed analysis.

Decline Rates

The decline rate of shale is the defining characteristic of a shale well, and a shale region. Decline rates vary by region. On average, the Eagle Ford region has a 62% decline rate, the Bakken region overall has a 54% rate, and the Permian region (many wells there are not horizontal wells) declines at a 33% rate.

Individual wells decline more rapidly, and most steeply in their first year of production: Bakken wells decline at a 72% rate for the first year, and then more slowly in the following years. Many Permian wells are vertical wells, and so their decline rates are much more gradual, accounting for the slower Permian region decline rate.

If a well’s IP (initial production) is 1000 bbl/day, a 72% well decline rate means that one year later, that well will only be producing 280 bbl/day. With the IP=1000, the first year production is 205k bbls, and the EUR (lifetime theoretical) is 650k bbls. Here is a look at changes in the decline rates of the different regions over time. [source:]

Drilling Rights

In order to acquire the right to drill on a particular patch of land, the drilling company must purchase these rights from the landowner, and/or another drilling company that has already bought the rights. In the most productive areas such as the Bakken shale, rights are expensive, with recent transactions priced around $10k per acre.

After a fair amount of experimentation, drillers have determined they can put from 1-3 wells on one square mile before the wells start interfering with each other. There are 640 acres per square mile, therefore drilling rights are about $6.4M/square mile. This makes land costs to be around $2M-$6M per well.

Before you can drill, you have to get the rights. Typically, you go into debt in order to buy the rights, then you start drilling to recoup your investment and pay the interest costs on all that debt. Maybe you can even sell those rights to someone else for a profit. That’s the ponzi aspect of shale: buying land rights with junk bond financing for $2000/acre, and selling those right off to an unsuspecting oil major for $10,000/acre.

Rights only last from 5-10 years. Failure to drill = wasted money.

Shale Economics

To understand the economics of shale, we view company performance through the lens of accounting. A good accountant is a historian, honestly assessing the success or failure of a particular venture. (A bad accountant – at Enron, for example – is a fiction writer).

So first, some accounting terms:

  • Revenues: barrels of oil sold x the price of oil. Its pretty simple.
  • Capex: capital expenditures. In shale, this is all the costs involved in drilling and completing wells, purchasing equipment, land drilling rights, and other long-lived assets required to run the business.
  • Opex: operating expenses. In shale, this includes all the other expenses the business has:
    • well operations: insurance, repairs, maintenance, pumping costs, etc
    • G&A: general & administrative costs – including paying the CEO
    • interest expense: for bonds, bank loans, preferred stock dividends
    • transport: getting the oil to market
    • royalties: paying the landowner a chunk of your revenues
    • production taxes: paying the state a chunk of your revenues
  • depreciation/depletion: a fraction of capex – it should be the decline rate of each well multiplied by the cost of the land plus the cost to drill & complete.
  • Income = revenuesopexdepreciation
    • here is where the funny stuff happens. If you want your company to look profitable, you will tell your accountant to write a work of fiction rather than be a historian. Instead of having her use your actual 72% well decline rate, you will instead tell her to use, say, 10%.
    • Key concept: understating depreciation increases reported profits. Why would you do this? Well, if you wanted to sell your shale properties to a greater fool, you probably want to look profitable in the meantime. Or if you wanted to get a bank loan, or sell junk bonds, you probably want to look profitable too. Banks are more clever than junk bond buyers, however; they use ratios that depend on EBITDA, not phony “profits.”
  • EBITDA: revenues – opex
    • Simply put, this is “earnings before accounting/depletion fraud.”
    • This is the number I use to study profitability in the shale world. I can then apply my own depreciation based on decline rates and figure out for myself how the business is really doing.

All right, armed with your new degree in shale accounting, let’s look at a simple fictional example. The hypothetical One-Well Shale Company obtains property for $10k/acre, then drills and completes a Bakken shale well costing $9M, with an IP of 500 bbl/day, 1st year production: 102k bbl, decline rate 72%. Further, we assume an eventual 3 wells per square mile, and an oil price of $99/bbl.

The income statement shows that with honest accounting, we are barely profitable just looking at the 3-year P&L statement. The price I selected wasn’t an accident – I searched for the break-even price and found it at around $99/bbl.

However, will this well at $99/bbl ever make back its drilling costs? It won’t, since in the following years, the “fixed costs” for the company will be a heavier and heavier burden on the well whose production declines every year. Likely, $99/bbl is even too low. We can call it a “best case scenario” – only if we assume One Well Shale sells the well to someone else for $986k (the remaining depreciation) at the end of year 3.

What’s more, companies have already spent huge sums accumulating land, on which they’ve drilled a relatively smaller number of wells, so this “One-Well” shale company is definitely fictional. Take OAS, which has 468 wells in production (45k bbl/day = 98 bbl/well) and 779 square miles of land they’ve bought for $1.8 billion. That’s only 0.6 wells per square mile. However, they’ve already spent the money for the land, so from a “cash flow basis”, they don’t really count the land cost when answering the question: “do I want to drill a well here or not.” At this point, money to buy the land is gone, so from a corporate survival standpoint, all they ask is, “if I drop a well, will it pay me back in 3 years?” And in the current environment, they probably only look at year 1 when making this analysis.

But from an overall economic analysis of shale profitability over the longer term, land cost really is an important factor, so we include it in our accounting. If we were to be hard-nosed, we would probably assume a “wells per sq mile” of 0.6, since that’s the “actual debt burden” on the real drillers like OAS.

Now lets drop the oil price to $55/bbl and see what happens to One-Well Shale.

Its a sea of red ink. Clearly this well loses money. It cost $9M to drill, and we get back $2M in EBITDA at the end of year 1, the best year for the well. By the end of year 3, EBITDA is negative. It is definitely not worthwhile to drill this well, not even if we assume the land is free.

This represents the average well in the Bakken. At current prices, the average well loses money, no matter how you slice it. So how will this affect capex budgets in 2015? Here’s one data point from OAS, a company for whom 100% of their production comes from the Bakken: they are cutting their capex budget in half, choosing only to drill in their better properties. [Source: an awesome, detailed, fact-filled investor document that Google located for me – one wonders if they meant to release it to the public:]


Shale producers don’t want to expose themselves to bouncing oil prices – they have fixed costs, and so they’d prefer to have fixed revenues too. So they typically engage in oil price hedging to eliminate one big variable from their business plan. One-Well Shale certainly had big problems when oil dropped to $55/bbl; if One-Well had engaged in hedging, it might have been able to ride out the low prices at least for a time.

There are many types of hedges available – our friendly banking establishment stands ready to provide all sorts of financial tools to shale companies to help them out. For a fee, of course. I’ll start with the simple ones, and gradually get more complicated.

  • Swaps: buyer locks in a fixed price for oil. No upside, complete downside protection – you know exactly what price you’ll get, and on what date. Low cost. This is why futures markets exist. Speculators take the risk, and companies get to operate in a more predictable world.
  • Puts: complete downside protection, unlimited upside. The higher the floor and the longer the date, the higher the cost. Puts are relatively expensive.
  • Collars: complete downside protection, lower cost, limited upside. Buyer writes a call, and buys a put. Upside available up to the call strike price, and the call helps make the put less expensive. As with the standard put, the higher the put’s strike price and the farther out the date, the more expensive it is.
  • 3-Way Collars: limited downside protection, limited upside, usually free cost. Buyer writes a call and a put, and buys another put. This complicated beast generally ends up being free, but only is good for maybe $10-$15 of coverage. It’s probably a banker’s delight. It sounds vaguely salacious.

When you look at the company hedge book, which they report in their 10-Q, understanding just what sort of coverage they have is quite important. Swaps provide perfect coverage, while 3-way collars only protect against a fraction of the drop we’ve just experienced. And its important to match up the number of barrels of coverage to the oil production, to see the percentage of coverage the company has in place. A survey of shale companies shows a range of from 20-60% coverage, at an oil price of about 90.

Looking at our favorite Bakken company OAS, we see their hedge book below, helpfully provided in their investor document. It looks complicated. So we just look for key words: first, what type of hedges? Swaps, puts, & 2-way collars. Great, that’s 100% coverage. Second, how much production do they represent? 1H 2015: 32k bbl day, and 2H 2015: 15k bbl/day. Let’s assume OAS keeps production steady at 45k bbl/day. That’s a 71% coverage for 1H 2015, and a 33% coverage for 2H 2015 at “around” $90/bbl. Looks like they’ll be mostly ok for 1H 2015, but for 2H 2015 they will definitely be losing money if oil stays at $55/bbl.

Hedges can be cashed in at any time. A company with a trader as a CEO, or one that needs to raise cash to stay in business today might well decide to “go naked” and take their chances with market oil prices and close out their positions. One company did this just recently. CLR sold their entire hedge book in Q3 2014, raking in a cool $420 million. They did this (from what I can tell) when oil was trading at about $77 – about $20/bbl too early. They left $500 million on the table. Maybe more. And now they’re fully exposed to $55 oil. Factoid: $420 million will fund one month of 3Q capex at CLR.

Shale History & Accumulated Debt

One-Well Shale’s “honest income statement” shows that 2014 shale technology is economical at $100 oil, assuming “average well production” – an IP of 500 is average in the Bakken.

Of course, shale companies must survive today, with oil at $55/bbl. Let’s assume OAS gets serious, and drills only in their really hot areas. Viewed through the One Well Shale P&L statement, if I set the IP=750, and I set the oil price to $87/bbl, cash flow is $9M in the first year and a 3-year ROI of 67%. Through 1H 2015, OAS will be all right if they can just drill their best opportunities, and rely on their hedge book to keep them afloat.

That’s not the the same thing as asking if the wells they drill will be “profitable long term” since that $87/bbl price obtained via hedges will only last through 1H 2015. Once the hedges run out, those IP=750 wells will be just barely above break-even (after 3 years!) at $55/bbl. But for the moment, OAS can stay above water.

I’m deliberately avoiding the question of how long-lived the shale resource is. I am just answering the question: what is the break-even oil price for drilling a Bakken shale well. The answer is, with an average well (IP=500) at a company with an average cost structure is long-term break-even at about $99/bbl, best case, assuming 3 wells per square mile and a property cost of $10k/acre.

Bottom line: the average US shale oil well is uneconomical even with hedging in place, since most hedging is around $90/bbl and the break-even is $99/bbl.

44 Comments on "The Dangerous Economics of Shale Oil"

  1. Nony on Sat, 27th Dec 2014 5:37 pm 

    This thing is a mess:

    Depreciation is a non-cash expense!!! It’s GOOD in that it reduces your tax bill. The more, the faster, the better. [The reason it’s allowed is because you DON’T get to expense the capital cost immediately…even though that IS an immediate cash expense.] This has a major impact on the fellow’s analysis. Essentially he’s giving the investment a double penalty by considering both capital investment (cash expense) and depreciation (noncash…actually helps aftertax cash) as negative.

    If the author understood the basics of valuation (free cash flow, discounted cash flow, NPV, yada yada) he would not make this error. I would refer him to the book on Valuation by Koller (it’s not that tough a read…I think the author knows the basics of accounting and could handle it…he would then learn how to do the basics of getting to free cash flow).

    2. He needs to run it all the way through the taxes. Taxes are a real cash cost. ~39% is a reasonable estimate of marginal tax rate (35% federal corporate tax plus 6-7% state franchise tax, minus 35% of the 6-7% [state tax is deductible from federal]

    3. EBITDA is incorrectly labeled. These aren’t just terms to sound cool. If you want to include interest pre-tax, then it’s EBTDA. EBIT, EBT, EBITDA…they are all meant to just mean something…not to sound all financey cool.

    4. How is the principle of the loan being paid off?

    5. A more standard approach would be to leave interest out of the cost structure. Include it in financing instead. It’s really not opex because if you shut the well down, you lose revenue and opex…but interest expenses remain. Also, the investment needs to make a certain return whether you have debt financing or equity. This is handled by something called the WACC.


    Nothing I am saying is fancy. It is garden variety finance basics.

  2. Nony on Sat, 27th Dec 2014 5:50 pm 

    And note the WACC includes the aspect of tax deductibility of interest:

  3. Nony on Sat, 27th Dec 2014 6:01 pm 

    There’s an outright mistake in the numbers: well operation costs [and the G&A allocation] are not scaling by volume in years 2 and 3.

    It’s a mess.

  4. Plantagenet on Sat, 27th Dec 2014 6:01 pm 

    What a bogus analysis.

    First of all it doesn’t cost half a million dollars a year to “operate” a well and another 600,000 for overhead. Those numbers are wildly inflated.

    Second, this analysis is based on a 9.5% interest rate, so that annual interest payments are over a million dollars per year. Another wildly inflated number—interest rates are currently around 4-5%.

    Its too bad this analysis is so bogus—it would be interesting to see how a real shale well pencils out based on real numbers.

  5. eugene on Sat, 27th Dec 2014 6:22 pm 

    I think the bottom line is shale is not the “wonder” solution that has been so endlessly hyped in fantasy land. But as far as I can tell, Americans greatly prefer fantasy to reality. And I’ll add bitching. Plenty of that.

  6. Harquebus on Sat, 27th Dec 2014 6:29 pm 

    Economics is not the dismal science. It is just dismal.

  7. Nony on Sat, 27th Dec 2014 6:35 pm 

    Yeah, Continental Resources has long term debt for the bulk of their notes at 5%. Granted that will go up now, but the author’s whole point was looking at status quo ante and comparing it to now after the price crash. And CLR actually had pretty good debt to equity, but even risky companies were getting lower than 9.5. After all, there is some collateral of a sort…

  8. Apneaman on Sat, 27th Dec 2014 6:47 pm 

    Smells like Econ 101 and reads like Latin. Probably because economics was conjured up to fill the void left by the old Latin speaking priest class. Looking forward to the day they string em up with their masters 😉 I hope it’s live streamed.

  9. Makati1 on Sat, 27th Dec 2014 7:10 pm 

    Shale oil is over…

  10. Nony on Sat, 27th Dec 2014 7:15 pm 

    Nothing is over…


  11. jjhman on Sat, 27th Dec 2014 9:00 pm 

    I’m an engineer, not an accountant but the numbers did not look right to me either. Can one of you financial types re-do the numbers to be more realistic? The author seems to have provided pretty good raw materials.

  12. Nony on Sat, 27th Dec 2014 9:41 pm 


    I actually flew down with a plant manager, had another plant manager in a room. Created a DCF model from scratch in a day. (extracting all the key info from them). And demanding estimates, sources, pdf files, etc. About 12 sheets of excel. One case for each plant (several millions of investment on the line). and subordinate sheets for the important factors (depreciation, personnel, government incentives, move costs, facility costs, buildouts, facility sale, etc.)

    *Now I will go back to hiding and acting like a troll*

    I get paid some good money for stuff like that. Sounds simple, but you would be surprised how many companies can not do it on their own…and who sure can’t do it on the spur of the moment in a hostile, politically charged environment.

    I would do your model for you, but honest…even if I do it for free, you would not appreciate it. People value things more when they are paying a couple thousand a day for the help. Rock would understand. 😉

  13. Ron Patterson on Sat, 27th Dec 2014 9:44 pm 

    Plant says:
    “Another wildly inflated number—interest rates are currently around 4-5%.”

    Well no:
    “The average yield on U.S. junk bonds has now climbed to 7.1 percent, the highest level in more than two years. That compares with about 2.3 percent for the broader bond index.”

  14. Nony on Sat, 27th Dec 2014 9:49 pm 

    Except the author was clearly writing about PRE oil price rise in his beginning. Yawn…

  15. Nony on Sat, 27th Dec 2014 9:51 pm 

    Oh…and in any case the dude used 9.5%!!!!

  16. DMyers on Sat, 27th Dec 2014 9:56 pm 

    “….America Merrill Lynch index data show. Non-investment grade energy bond yields average 8.54 percent, the most since July 2010, from a low this year of 5.68 percent in June.

    Halcon Resources’s $1.15 billion of 9.75 percent securities issued in April 2013…”

    The interest paid on junk bonds and other shale funding is probably higher than normal, as indicated in the above excerpt. As far as inclusion of taxes as a cash expense, some taxes would survive a loss but most probably would not. In most of the cases presented, i.e., there would be virtually no tax expenditure to account for.

    I have to agree with Nony, at first glance, about the inclusion of depreciation on the income statement. This does not seem to belong with the other expenses listed. It does, however, have a big impact on the result, making the difference between RED and BLACK.

    I assume Martenson would not throw an erroneous number into the analysis, as the accusation stands. I note that Martenson has emphasized depletion in his consideration. Furthermore, he used depletion as a proxy for depreciation, as he states in the article (not exactly in those words).

    With respect to depreciation, Nony himself states: “The reason it’s allowed is because you DON’T get to expense the capital cost immediately…even though that IS an immediate cash expense.” I understand this to say that depletion is, in effect, an immediate cash expense.

    That would seem to be the way Martenson is treating it. He is forcing an accounting of depletion in a proper analysis, as this depletion has a profound affect on longer term viability.

  17. Plantagenet on Sat, 27th Dec 2014 10:04 pm 

    @Ron Patterson

    What part of this math don’t you understand? The analysis above assumes interest rates of 9.5%. You yourself note that even junk bonds are only at 7.1%. That means the interest rate assumption in the analysis is bogus.

    AND, for companies with good credit, money can be had for 4-5% interest rates. Again, if you’ll pay attention to the math you’ll see that 4-5% is much less then the 9.1% assumed in this bogus analysis.

    Finally, some companies like Continental are highly profitable and fund their drilling using money from ongoing production and previous operations. They have ZERO interest expenses. Again, 0 is a lot less then the bogus 9.!% assumed in this analysis.

    Get it now?

    Let me review it for you one more time, just looking at the numbers. Are you ready? OK. 0 is less than 9.1. Are you with me. OK, 4-5 is less than 9.1. And even the 7.1 number you put forward is less then then 9.1 number used in this analysis. Is that clear now?

    Wheeeeee! Math is fun!

  18. Nony on Sat, 27th Dec 2014 10:17 pm 

    Depr/letion is a non-cash expense. The purpose is (1) for accounting…to have some ongoing idea of how you damage your capital. [and note this is accounting, non-cash] and (2) for tax effects. Only 2 matters for doing a valuation. And it actually HELPS you on a valuation.

    The point of the valuation is that you make an initial investment (11 million) and then you erode it’s value over time. Tax law lets you deduct the “cost” of that erosion. But it’s NOT a cash expense. The initial investment was the cash expense.

    This is really finance 101. Really truly.

  19. coffeeguyzz on Sat, 27th Dec 2014 10:18 pm 

    Yeah, this whole piece could have been instructive to many of us if the numbers were more realistic.
    The writer is using more relevant (2012-2014) operational parameters as distinct from the maddeningly obsolete pre-2011 methods so often modelled by many ‘analysts’. He does not touch upon the newest generation of frac’ing like that being implemented with coiled tubing and the latest iteration of Bottom Hole Tools. These are now regularly frac’ing 20 to 40 stages in less than a day. Of much more consequence, the output is increasing substantially – 50% or more.
    The piece quotes a 205k barrel output after one year with an initial IP of 1,000 bbl. $50/bbl pricing pegs that at 10 million gross. Not too shabby.
    .6 wells per sq. mile is pure fantasy.
    Where the middle Bakken, benches 1,2, and possibly 3 of the underlying Three Forks are prospective (potentially/actually productive, there is one more bench – TF4), the ultimate number of future wells is simply unknowable at present. Ten to thirty, as ridiculous as that may sound, is way more probable than .6 per sq. mile.
    Land costs @ 10k per acre??? I gotta couple of bridges to sell ya at those rates. EOG paid $400/$450 per sq acre for virtually all their Eagle Ford acreage. There is a reason these guys do not want to be late in the land grab phase.
    @90% of the Original Oil in Place (OOIP) still in the ground when these methods/nodelling are done, one never hears about re-frac’ing (getting underway in all the shales at present), and the Enhanced Oil Recovery (EOR) potential which is now being feverishly pursued on – quite literally – a worldwide basis. The EERC, affiliated with the University of North Dakota, has lab results on EOR that are so impressive, I will not repeat them here, but their work is publicly accessible online.

  20. Nony on Sat, 27th Dec 2014 10:21 pm 


    I just looked at the 10k for CLR. They have about 5 billion of debt. The vast majority is at a very favorable rate. About 5%. They actually had investment grade debt for a while (pre down turn). They have a fair amount of equity and are in much better shape than Halcon or Goodrich.

    But they don’t have “zero interest”. Don’t let Ron find something to divert the point (from this dude having a crazy 9.5% estimate).

  21. Nony on Sat, 27th Dec 2014 10:27 pm 

    Martenson didn’t write the analysis. It was some goober on his site.

    Not that Chris is all that. But he’s not this bad.

  22. Bloomer on Sat, 27th Dec 2014 11:22 pm 

    Bottom line is the 3 yr projected revenue doesn’t even cover the cost of drilling the damn well. I wouldn’t invest in these enterprises and neither would many other investors hence why their stock prices are tumbling. Shale Oil is the newest hyped bubble following the fiasco and the housing mirage.

  23. Plantagenet on Sat, 27th Dec 2014 11:34 pm 

    Hi Nony:

    CLR had net income of 764 million last year. Obviously they can do whatever they want with that money. If they choose to use some of their revenue to drill new wells, then the interest payments on those wells are nil. And no doubt some of CLRs huge cash flow has been going to drill new wells.

    You are correct that they have some debt to service at ca. 5%. That ist unusual—most corporations have some debt.
    But the bottom line is that the 9.1% interest rate assumed in this analysis for Bakken companies like CLR is completely bogus.


  24. Nony on Sat, 27th Dec 2014 11:55 pm 

    CLR has a good balance sheet. I just don’t want on of the yipyaps to get distrscted on the 9.5% with you making a mistake. They have a debt to TEV ratio of 20%

    Very safe (arguably too safe) balance sheet, but not “no debt”. It’s still got ~ 4 billion in debt.

  25. Nony on Sat, 27th Dec 2014 11:57 pm 

    Bloomer: there’s no bottome line when it’s a screwed up model. You don’t know what the bottom line is. For one thing, there’s just a MATH ERROR. The guy does not scale operating cost by volume on year 2 and 3.

  26. FloridaGirl on Sun, 28th Dec 2014 1:21 am 

    According to CLR’s most recent 10-Q SEC filing, their debt increased from about $4.7 billion to $5.8 billion in the 9 months from 12/31/13 to 9/30/14. That doesn’t sound profitable at all to me and that 9 months is in a period of relatively high oil prices (NYMEX average $100). The point of this article is that companies like this make it look like they are profitable by using an unrealistically low depreciation rate.

  27. Northwest Resident on Sun, 28th Dec 2014 1:48 am 

    Tempest in a teapot dudes. If it waddles like a loser, quacks like a loser and makes its living by scraping the scum off the bottom of the pond (er, barrel), then it is a loser.

    Nitpick the details all you want in this article. Here’s all you need to know: 20% of global oil production investment went to shale extraction in 2013 and resulted in a pathetic 4% of global oil supply.

    Does that sound like a winner to anybody here?

    Shale is unsustainable, a debt driven junk bond feasting loser making its money off of hype and land sales, a puny insignificant contributor to global energy needs (4% — what a JOKE!!), and that’s all it has ever been — except that it has also been a great creator of jobs and a GDP booster and a driver of economic activity for a while. And THAT is most likely all it was ever meant to be.

    The party is over guys. Tear this article to shreds, why not, you nitpick every other article and/or post that vividly points out how big a loser shale is. You guys that are so resolute in defending shale and pretending like it is a viable business amuse me to no end.

    20% of global oil production investment to get a measly sickly little 4% of total global production. WTF!? And that’s drilling all the sweet spots first. Going forward into the bright energy independent American future provided by shale oil extraction, what’s next? 40% of global oil production investment to produce 2% of global supply. Hot damn! Get the shale oil cheerleaders on stage and let’s all do the rah rah rah. Those numbers are smokin’ hot!

  28. Go Speed Racer on Sun, 28th Dec 2014 2:33 am 

    I see the scam clearly. Its all about the hedging. The hedging is like insurance. So when everybody thought the oil would stay high, the hedge fund investors, invested into a presumption the oil would stay high. Now that the oil went down, the hedge fund investors got screwed. Probably Saudi Arabia invested into shorts on hedge funds and then kept their wells pumping to bankrupt the hedge funds and make bank on their short shares.

    Isn’t it obvious? Whether the oil is running out is irrelevant. Its about who gets to be the biggest roach on the top of the dung pile.

  29. Makati1 on Sun, 28th Dec 2014 7:20 am 

    As I said, shale/frak oil is over. A dead man walking. The Saudi’s put a knife in it’s back and is twisting the blade. Some like Nony and others don’t want to see the facts. Must have invested their life savings in the bubble.

  30. oilystuff on Sun, 28th Dec 2014 7:24 am 

    There is a good bit of relevant information in this article that is being overlooked because of nonybs and because, I am convinced, people simply will not quit on this shale stuff. Being a contrarian on a peak oil blog gives them a sense of self importance. They like to pick fights, little else.

    Northwest is correct, shale oil extraction does not work economically, period. It barely worked at 100 dollar oil and it absolutely does not work at 55 dollar oil. the shale oil industry has not, in nearly 8 years now, made a dime.

    Y’all can yak away interest rates and 40 stage fracs down CT in one day (yeow!!), the bottom line is all of you pro shale oil nuts like to watch other people pissing their money off….but you would not for one second spend your own money to drill and complete a shale well. I don’t mean buying stock in CLR, I mean plopping 10 million dollars down and drilling your own big boy Bakken well for a 2.32% weighted annual rate of return on initial investment over the life of the well. You sure wouldn’t do it with borrowed money.

    Nony, there are enough believers, CLR followers, on this site, get a JOA together, farm in to a CLR location (I am sure they will gladly do any deal right now you’ve got), go get you a Nabors rig and some steering tools, a CT unit to frac with, and get it! You clearly have the know how, go get ‘er done. There is money to be made out there in the shale business; there is a revolution underway! Put your own money where your mouth is.

  31. bobinget on Sun, 28th Dec 2014 7:55 am 

    Here’s the spoiler boy and girls;
    Because Venezuela is becoming a de facto colony
    of China, no longer the US.

    USA loses at least half of Venezuela’s exports
    in 2015. (debt service)
    That’s about one million BB p/d that Canada, Mexico and Saudi Arabia need make up.

    The UK also dependent on Venezuela’s LNG

    There is no question ultra deep sea exploration is expensive. No doubts about oil sands expenses.
    Why question costs of wringing oil/gas from concrete like rock?

    Besides all of the above are still in experimental
    mode. Who says a learning curve won’t come closer to the decline?

    Above all, don’t confuse market manipulations by Saudi Arabia/Russia as having
    ANYTHING to do with lack of demand or surplus
    of supply.

    Anytime a rocket costing a few hundred dollars
    can change history, that underling historic foundation is made of highly flammable material.

  32. Kenz300 on Sun, 28th Dec 2014 9:15 am 

    Shale, tar sands and deep water are the high cost producers and are pulling back investments in new projects………

    Risky and expensive projects will be cut first.

    Depletion will continue….. and prices will stabilize.

    Enjoy the lower oil prices while they last. It will give a much needed boost to the world economy adding to the GDP.

    Seems like the Keystone is just a pipe dream…….

  33. shortonoil on Sun, 28th Dec 2014 10:12 am 

    One item that is often overlooked for the Bakken is the increasing lift cost as water cut increases. The chart below is calculated for an 11,200 foot well in Mackenzie County. It assumes 65% pump effecienies, and uses the average world cost of energy (2014 – 5,869 BTU/$). It allows for a 3% frictional loss in the pipe.

    WC% $/barrel

    No piece of rock found in the ground is monolithic. It all includes a vast network of nature fissures that were placed there through seismic activity over the eons. Water flows through those fissures, and during the pumping of a well the hydrostatic pressure between the well, and the water reservoir increase, thus increasing the flow of water. Unlike a fraced area that is limited to a few hundred feet, ground water can travel for many miles through its fissure network.

    Many Bakken wells have an initial water cut of 50% or more. As the wells are pumped, and the pressure differential between the water reservoir, and the well bore increases most fraced areas that intersect with natural fissures will see increasing water cut. Whereas a conventional 4000 foot well will usually be shut-in with a WOR (water oil ratio) of 40 to 45: 1 (water cut >98%) these much deeper wells will probably experience shut-in at much lower values. Well life expectancy is likely to be much shorter than generally assumed, and depreciation schedules need to be adjusted accordingly.

  34. Nony on Sun, 28th Dec 2014 11:28 am 

    Hey Oily:

    There are technical aspects to putting these numbers together. Running a rig doesn’t make you know valuation. And doing a valuation doesn’t make you know how to run a crew safely.

    I actually agree the fellow took a decent swing at it and there is some value in his approach. Heck, you could start by just fixing the model. The sensitivity about finding faults in someone on your side bothers me though. You should want to get the numbers right no matter what.

  35. Nony on Sun, 28th Dec 2014 11:53 am 


    Data so far shows some gentle trend in increasing* water cut but nothing like the high water cuts in your chart.

    *Both by year of well start (probably worse rock) and over well lifetime (not clear what drives that and why onset differs by year…other than perhaps the rock quality also.)

  36. oilystuff on Sun, 28th Dec 2014 12:02 pm 

    Nony, I understand. I have to do both.

    I have all the numbers I need to know that shale oil extraction doesn’t work at 55 dollars. One of the first things you learn in exploration is to know when to quit; unfortunately most of those shale well manufacturers, the DR Hortons’ of shale oil, cannot drill themselves out of the problem they got themselves into.

    I think that most folks who just cannot accept that have not been thru these kinds of things before… those “things” being brilliant ideas that often lead to economic failures because the price of oil never seems to cooperate. It’s just the oil business.

    Keep a bind on it!

  37. Jerry McManus on Sun, 28th Dec 2014 12:27 pm 

    Where is the Rockman when we need him?

  38. Nony on Sun, 28th Dec 2014 12:42 pm 

    oily, I agree that shale does not work at 55. That’s not in contest.

    The guy makes several large mistakes even in his estimation of income at 100/bbl. Look at the “well operations” line of the guy’s model. Isn’t it strange how the cost is exactly the same year after year?

  39. Nony on Sun, 28th Dec 2014 12:44 pm 

    “where is the Rockman?”

    Rockman likes to swagger and play big frog on a small pond. He’s gotten his butt spanked by rocdoc on the boards for basic mistakes in reserve estimation. He likes to play old salt, but when you check real data and analysis, he’s off a lot.

  40. rockman on Sun, 28th Dec 2014 3:34 pm 

    Jerry my boy: “Where is the Rockman when we need him?” Actually I’m on a well in S Texas at the moment recompleting it.

    I’m not really sure what points everyone is trying to make. Hopefully for the last time: there is no price at which “shale wells work” or “kills the shale plays”. There are shale wells worth drilling at $60/bbl and shale wells that won’t recover their entire cost at $120/bbl. For Dog’s sake stop the f*cking generalizations already. LOL.

    Likewise there’s no specific interest rate on borrowed capex that allows a company to drill any well. Those circumstances are very company specific.

    But if everyone wants to stick with generalizations here you go: fewer shale wells will be drilled and frac’d when oil is at $60/bbl then when oil is $100/bbl. If there’s any specific questions just ask and I’ll get to them between swab runs. As they say: those that can…do. Those that don’t just speculate about what those that can actually do. LOL.

    BTW those lifting costs, if that actually what he’s referring to, are utter bullsh*t.

  41. rockman on Sun, 28th Dec 2014 3:39 pm 

    “He’s gotten his butt spanked by rocdoc on the boards for basic mistakes in reserve estimation.” Go ahead, make my day and post one specify incorrect estimate the Rockman has made. And not what you say the Rockman said but his exact words.

    Well, are you feeling lucky, punk?

  42. shortonoil on Sun, 28th Dec 2014 6:07 pm 

    Data so far shows some gentle trend in increasing* water cut but nothing like the high water cuts in your chart.

    Your usual obfuscation, or else you can’t read! That chart shows the calculated lifting cost for an 11,200 ft well by water cut. It is not talking about the water cut of Bakken wells in general. Although, in some areas wells are now commonly coming in with 60%+ water cuts. See the North Dakota data.

  43. Nony on Sun, 28th Dec 2014 6:52 pm 


    I was referring to the chart in the article I linked! Not to your conceptual chart.

    What I’m saying is the majority of wells (these are actual wells) have less water cut than the more extreme parts of your conceptual chart.

    Hint: click the link that I made and go read.

  44. jeep on Sun, 28th Dec 2014 7:26 pm 

    “Go ahead, make my day and post one specify incorrect estimate the Rockman has made. And not what you say the Rockman said but his exact words.

    Well, are you feeling lucky, punk?”

    He didn’t say you misdid an estimate. But you hosed up a terminology or a concept in a discussion. And this was while you were bragging about working here. And Rockdoc called you out on it and said something to the effect of being concerned that you worked in this area given the mistake.

    Does this strike a chord? [You did not respond to his remark.]

Leave a Reply

Your email address will not be published. Required fields are marked *