Shale Cost Reductions Are 10% Technology and 90% Industry Bust

Posted in The Petroleum Truth Report on March 22, 2017

I am tired of hearing about the unbelievable impact of technology on collapsing U.S. shale production costs. The truth is that these claims are unbelievable. The savings are real but only about 10% is from advances in technology. About 90% is because the oil industry is in a depression and oil field service companies have slashed prices to survive.

Zero Hedge posted an article yesterday called How OPEC Lost The War Against Shale, In One Chart that featured the chart shown below from a Goldman Sachs note.

Figure 1. Short-cycle shale has engendered a structural deflationary cycle. Source: Zero Hedge and Labyrinth Consulting Services, Inc.

Zero Hedge (and/or Goldman Sachs) erroneously states that “the cost curve has massively flattened and extended as a result of shale productivity.” If I read the chart correctly, the flat portion attributed to “shale” represents ~ 10 mmb/d but tight oil only produces ~3 mmb/d.

This little arithmetic problem and the fact that the entire 2017 cost curve has shifted downward ~$15/barrel from the 2014 curve indicates that the true point and message of the graph is that break-even costs for all producers have fallen almost 25%.

My business is working with clients who drill onshore U.S. oil and gas wells. Rig rates have fallen 40% since the oil-price collapse. One client had a bid for a drilling rig in September 2014 for $27,000 per day. By the time he signed the contract in March 2015, the rate was only $17,000 per day. Another client recently ran a special high-tech log in a well whose list price was $75,000 but he only paid $15000 after discounts were applied.

Most of the celebration of efficiency and productivity is really about a depression in the oil industry that has resulted in massive price deflation. I estimate that only about 10-12% of the cost reduction is because of technology and most of that was a one-time benefit in the first year or so it was used. Going forward, efficiency gains are a few percent at most.

“Our forecast assumes that productivity declines 8% by the end of 2018…We believe a significant portion of the productivity gains being experienced by the sector outside of the Permian are the result of high grading and will revert in future years. Cost pressures are already surfacing in the Permian, which will dampen capital efficiency going forward.”
—Bernstein E&Ps ( 10 March 2017)

Break-even price is mostly a function of well cost, flow rate and EUR.

I have already addressed well cost. Most companies and analysts routinely exclude G&A (General and Adminstrative costs or overhead), royalty payments, federal income taxes, depreciation and amortization (“EBITDAX”) from their costs. Excluding cost is an excellent way to reduce break-even price except that it does not accurately represent break-even price.

Even if we accept these break-even prices, does anyone knowingly invest in things that don’t make any money? Sorry, I forgot about negative interest rateEuropean bonds.

The EUR used for break-even prices in charts like Goldman Sachs’ are largely unknown but bigger EUR means lower break-even prices.

Companies routinely report EUR in barrels of oil equivalent (BOE) that use a natural gas-to-BOE conversion of 6:1 based on energy content but a value-based conversion including natural gas liquids is 15:1.

For gassy plays like the Eagle Ford and Permian basin, this conversion sleight-of-hand produces ~35% inflation in EUR. It is perfectly legal for reserve reporting but it is a dishonest way to represent break-even price since companies are getting ~$2.50/mmBtu for gas and not the $6.25/mmBtu implied by the 6:1 conversion.

Advances in technology have resulted in higher early production rates increasing net present value. In many cases, however, these are accompanied by increased decline rates and lower EUR. Figure 2 shows an example from the Bakken Shale play.

Figure 2. Comparison of 20-mMonth cumulative production and normalized decline rates for the Bakken Shale play. Source: North Dakota Pipeline Authority, Drilling Info and Labyrinth Consulting Services, Inc.

The chart on the left shows 20-month cumulative production data suggesting that well performance has improved every year. The chart on the right shows decline rates for the same years of production. It shows that, in fact, well performance is decreasing from 2014 through 2016 because of higher decline rates.

Technology does not create energy. The effect of better technology is a bigger spigot that produces the energy faster. The downside of the technology is that it increases the rate of resource depletion.

Costs have come down for all oil and gas producers since the oil-price collapse in 2014. Most of the savings are because of lower oil field service costs and not so much because of improved technology.

 


24 comments on this entry


  1. Indeed Art

    This hiding of costs is not simply applied in the shale industry but has been adopted across the oil business where ever depletion is a significant factor. Basically, given rapid depletion these companies are excluding CAPEX from their accounting model by hiding it in cost of sales, depreciation and impairments. I know of a UK company operating in Trinidad on a field that Texaco abandoned in 1986 whose wells deplete 80-90% within a year yet they claim to be ‘profitable’ down to $20 a barrel.

    When you look at the GAAP Losses of most of these companies then the amounts down the drain are simply mind boggling.


  2. Simon,

    Misleading reporting of costs and profit margins have characterized the oil industry for as long as I have been in it.The same bogus claims that technology is reducing costs pre-date shale plays. If you believe this stuff, the oil should be paying the companies to get out of the ground.

    The confusing part is that seemingly smart investors actually believe this stuff. My interpretation is that investors fundamentally believe a peak oil scenario that will vindicate their bets on otherwise questionable companies and plays.

    All the best,

    Art


  3. Right again! I will point colleagues to this concise refutation when they start talking about the magical technologic cost reductions


  4. Coach,

    Thank you for your comments.

    Art


  5. All speak about progress in technology, but nobody can provide examples. May be the only
    new thing is the proppant-gedon with its world record 50 million pound of sand multistage fracturing introduced by Chesapeake. It is just a very expensive circus without any chances to get accepted by the industry.


  6. Simon,

    The main cost-cutting advance was drilling multiple wells from a single surface location. That was basically a one-time benefit that sporead over the period required to convert all drilling to this approach. The idea that every well drills perfectly and just like the last one is bogus. Operational risk drilling wells cannot be overcome.

    The other advances like bigger fracks and longer laterals cost more so their relative benefits must be measured against potential improvements in performance.

    All the best,

    Art


  7. Art – thanks again! I was hoping you’d weigh in on this latest sleight of hand.

    I was also wondering if you’d opine on what the EUR’s they must be using are? they must be too high, by every calculation I can make in my very simple spreadsheet model, I cannot get to a $50 break even price (even!) unless the EUR is ~420,000 bbl/well (and that’s using super accommodating assumptions too…)

    I know from your work that the average wells are going to be a lot less than that…more in the range of 200k to 300k per well.

    Any comments there?


  8. Chris,

    Thanks for your comments and question.

    It is no surprise that there is no single break-even price or corresponding EUR for tight oil plays. Each play has different average EUR and different wellhead oil prices.

    Several prominent operators in the Bakken and Permian basin plays–e.g. Continental Resources and Pioneer Natural Resources–claim average EURs of 900,000 BOE or more. Although there are some wells that good, I cannot get close to those numbers for any key operator even using 6:1 gas-to-BOE conversions. For the Bakken, an average of 400,000 BOE is required to break even at $50 wellhead oil prices. For the Bone Spring–the most economically attractive play in the Permian basin–an average of 290,000 BOE is required.

    The average EUR for the 5 major operators in the Bone Spring is about 290,000 BOE so that play breaks even at $50 wellhead prices–right now, wellhead prices are ~$44/barrel. The average EUR for the 8 major operators in the Bakken is 370,000 BOE so no company is breaking even at $50 oil prices and current wellhead prices are ~$37/barrel. This comparison explains why the Permian basin is the preferred place to be right now.

    All the best,

    Art


  9. As more service companies shake out, vendors will have a better bargaining position. After the mortgage meltdown, starving appraisers got low fees, many closed shop. There are about 1/3 less appraisers. Last summer’s hot markets in Oregon, Denver, Seattle, etc. saw appraisers charging triple prices for ASAP work. Once the demand increases and many small service companies are gone, the cost structure will change.
    Further, as one Okie oilman put it, “They ain’t making money. They are milking money from Chinese and Korean investors who think oil prices will go to $80 a bbl.”


  10. Does the BE cost include the $50,000/acre lease cost some are paying? It seems that a 10,000′ lateral will drain 120 acres (or 500′ range lateral spacing). So to develop two sections you would spend $64,000,000 land cost and 60-$100,000,000 drilling cost and another 5-10 million in infrastructure. That could mean $17,000,000/well to recover before BE. Using a 75% NRI and a 6% tax the producer would net 69% at best to recover cost if opex was 0$. $17,000,000/0.69 means at around $25,000,000 (8/8) to BE or at $48/bbl around +500 MBO. The players that have HBP or low cost acreage would fair much better but the ones paying that kind of lease money have a long row to hoe. One the reserve side the reserve ratio most tout is on the order of 5 on initial rate of a fracd tite well producing all out…that is high. I won’t go into what they put in the tail that inflates the EUR number but has in reality it has very little NPV10. On to OPEX the reason it is reported so low is these are new producers..as the play ages the avg production per well will tail off greatly yet fixed opex will stay the same or possibly get worse with workovers etc.


  11. Whenever I see this (or previous iterations) of the GS “break-even” graph I am stuck by the fact it is (at best) a simple snapshot. Even putting to one side your very valid points about creative cost accounting, the fact that today, productive wells in the Permian break-even at or below $40/bbl, does not mean that the subsequent 10mmbbls/day will work at that cost. We know that in the downturn, all activity has been focused on the sweetest of sweetspots – a very rational reaction. In addition, the cost-base has been taken down to its barest bones, where service companies provide services at, or in some cases, below cost.

    This is clearly neither sustainable nor scalable. As activity picks up, service costs will increase – and here we will see the real meaning of “short cycle”, I expect there to be no latency in the ramp up of prices. In parallel, op cos will move out beyond the sweetspots where productivity and hence returns will be lower.

    So the GS graph (1) should show a steep diagonal, not a flat line for all those incremental barrels, and (2) that diagonal line will move up as industry wide costs inflate and impact even the 40$ break-even starting point that works today…

    just my 2 cents worth!


  12. EXCELLENT ARTICLE ART, I showed to my friends in Calgary and they still believe the Majors will produce at very low costs.

    All of your points are valid but I guess with the large oil companies time will tell. Thank you


  13. The oil companies are just passing along these pie in the sky economic evaluations to the oil and gas publications with no way to check them unless one has a working interest in the wells. This of course is to keep raising money. This is like Enron. As long as they can keep the money flowing in they can keep going which is quite awhile but it will end like Enron and it already has for quite a number of them.


  14. Trican is making a friendly bid for Canyon services and Savanah is being pursued by Total and western energy. Consolidation taking place in the Canadian service space

    http://www.jwnenergy.com/article/2017/3/six-important-insights-about-tricans-acquisition-canyon-gmp-firstenergy/


  15. To be fair Art, the data can be manipulated (especially in the less mature plays) in a number of ways to support whatever point one would like to make including discrediting the “efficiency argument”. Let’s just use the Delaware Basin for instance- If you look at Wolfcamp EUR’s in Reeve’s County the calculations would change dramatically if you included legacy wells (let’s just say pre-2015) in your aggregate data for a blended type curve. It’s not technology or efficiency so much as it is learning through the drill bit and understanding where to land the well, completion technique etc. Improvements are limited to the transient flow stage of the well in most cases and the tail becomes more predictable. As best practices become adopted the EUR’s improve dramatically although mostly upfront. In the more mature plays EF, Bakken, it is easier to understand the economics but still – calculating a type curve for an operator in these plays can vary widely depending on data set. It is difficult to find apples to apples inputs for that equation. I share a lot of the same sentiments regarding the shale biz as you. Obfuscating EUR’s, not including full cycle costs, all these things obscure the big picture (which is that, at best, shale offers pretty low returns). I just think it is a bit of a stretch to argue that the industry can’t improve and optimize.


  16. Ryan,

    Thanks for your thoughtful comments.

    When evaluating the performance of any business, it is convenient to focus only on their most recent, successful efforts but that is not a meaningful measure of my risk in that investment. I have been in the oil and gas business for nearly 4 decades and investor calls and presentations have been characterized by “this time it’s different” assurances for that entire duration.

    There are ways of determining type curves that are more or less accurate. Without at least 24 months of production history, any attempt is wrong.

    Our methods involve a separate group decline profile (type curve, if you must) for each operator for each group of wells by year of first production. The EURs determined from these separate and specific series of decline curve analysis are then weighted by the number of wells in each annual vintaged group to determine a weighted average EUR for each operator. This allows an apples-to-apples evaluation.

    The industry always optimizes and improves and I never argued that they don’t or can’t. There are, however, limits to the degree of this improvement. Oil and gas is a 150-year old extractive industry with a dizzying array of complex and inter-related components. It is unrealistic to imagine that improvement in one area like drilling efficiency will make a substantive quantitative change in the entire system.

    Unconventional-Oil-Resulted-in-a-200-Increase-in-Oil-Prices-From-2004-to-2014

    Consider the automobile industry as a similar older business. Improvements are made all the time and cars are more efficient than ever. When was the last time you traded in a model after a year or two and paid less? Never in my experience. Why should oil and gas wells be different?

    All the best,

    Art


  17. Art,

    Are well abandonment cost included in breakeven cost for shale oil wells?

    Thanks, Tony


  18. Tony,

    No and neither are lease costs.

    All the best,

    Art


  19. Art,

    First off I completely agree that few companies can make enough at current prices to justify drilling decisions. But, with all due respect, in contrast to what you’re saying I think there has been a lot of improvement in efficiency, effectiveness, and output over time. So I challenge you to calculate wells drilled per horizontal rig over time in the Permian and oil output per horizontal well over time in the Permian. Also while service costs have gone down massively, it’s a mistake to assume they’re all going to magically recover. Some things, like rigs, will have permanently lower prices, though still potentially higher than where we are today. Other things (things that more easily break) like frac spreads are likely to recover closer to their old prices. Sand will be permanently lower as people realize they can work with local sand, since the vast majority of the cost is logistics.

    Unfortunately microeconomics leads me to believe that over time all but the best of acreage is destined to not make back its cost of capital over time excluding acreage cost (once these cost are included no one will). This has little to do with performance of wells and everything to do with the fact that this is now (in contrast to the old oligopolistic structure of the majors) a perfectly competitive industry. Worse it’s a perfectly competitive industry in an equity bubble, quite similar to the .com bubble. This means that capital continues to enter even though there are no returns on capital. These Riverstone deals with Papa and Hackett are prime examples. It’s the greater fool theory. And that’s all that’s left. The majors haven’t had much choice in their decisions because they also don’t have anything that works at current prices. Shell wants to tell you that LNG and pre-salt Brazil still work (ridiculous), the rest have embraced shale. So if you can’t beat’em, join’em. And any hope that we will somehow see prices correct upwards to make these wells “work” is flawed logic. Take a look at Exxon’s March 1st presentation and see how much they’re planning to spend on shale wells over the next few years. These are the kinds of numbers that would make the independents who ran the last cycle in the Eagle Ford and Bakken blush. We are up 600k bbl/d in the US in the last 5 months at a $50-55 price deck, that’s amazing!

    Nat gas is the perfect parallel. You have been saying that no one can make money at prices much higher than today’s since we first spoke (about 7 years ago), and while this has always been pretty much true, it’s precisely because all efficiency gains are passed on to the consumer, and not because there have been no efficiency gains. In other words, despite the fact that shale is an amazing technological breakthrough (and we can certainly argue about the length of the runway here), it doesn’t benefit producers, it just benefits consumers – just the way of the economic world.

    Don’t know what will break the bubble. Could be higher interest rates, could be another dip below $30, once OPEC wakes up and realizes they can’t keep taking capacity out, or it could be some other strange event (the debt statistics on COP and APC are rather precarious), but until it breaks, the industry will not even make it’s costs of capital. After that we should see an oil price spike and maybe costs of capital over time. But the majors are not going to make the 20-35% returns they used to make with little leverage. Good hunting to all…

    Best,
    HS


  20. Yes, a lot of cost efficiency is from the activity drop (from the price drop). Also from high grading. However, some portion is small. After all we are still learning the techniques (maybe not as in new to the world, but certainly as in being very practiced at them). Also, we are still learning the geology. (If not, why was the Permian late to the party, Utica gas, etc.)

    It is fine to react against hype, but you Art, have a history of overreacting. 7 years ago, you said “the Marcellus will disappoint”. I don’t think Marcellus growth from 2010 to 2017 can be construed as disappointing! Also, you predicted a drop of 0.6 MM bpd of LTO from JAN-JUN 2015. Eventually we dropped, but with a longer lag and slower drop than you predicted (although still very significant–still notice you were wrong in the direction of overskepticism.)

    Finally, a little more humble attitude is in order. The whole thing is a puzzle. We don’t know everything and can’t calculate it exactly (for instance if companies buy leases based on option value as well as immediate prospects). Instead of saying, I am the super expert, perhaps consider that others who are sharpening their pencils come to a different answer than you. Could be you are right (and OK to say you are puzzled), but just be open to idea that you might be wrong.


  21. Anonymous,

    I have only un-approved one commenter in the rather long history of this website and you may become the second if you continue to comment anonymously.

    If you want want to post your own views or preach about how I should express my positions on my own site, get your own blog but don’t hide behind the cowardly mask of Anonymous.

    Art


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