Rig Productivity is a Red Herring

Rig productivity and drilling efficiency are red herrings.

A red herring is something that ​takes ​attention away from a more ​important ​subject. Rig productivity and drilling efficiency distract from the truth that tight oil producers are losing money at low oil prices.

Pad drilling allows many wells to be drilled from the same location by a single rig. Rig productivity reflects the increased volume of oil and gas thus produced by each of a decreasing number of rigs. It does not account for the number of producing wells that continues to increase in all tight oil plays.

In other words, although the barrels produced per rig is increasing, the barrels per average producing well is decreasing (Figure 1).

Bakken Production Per Rig vs. Per Well 7 September 2015
Figure 1. Bakken oil production per rig vs. production per well.
Source: EIA, Drilling Info and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Rig productivity is a potentially deceptive measurement because it does not consider cost and apparently it always increases. It gives a best of all possible worlds outcome that seems to defy the laws of physics. Drilling productivity gives the false impression that as the rig count approaches zero, production approaches infinity.

Barrels per rig is interesting but the cost to produce a barrel of oil is what matters.

Similarly, drilling efficiency measures the decrease in the number of days to drill a certain number of feet. This is also interesting but, unless we know how it affects the cost to produce a barrel of oil, it is not useful.

The data contained in 10-Q and 10-K SEC forms provides a continuing view of a company’s financial position during the year. This allows us to determine a company’s cost per barrel and its components that rig productivity and drilling efficiency do not provide.

Pioneer, EOG and Continental SEC Filings for The First Half of 2015

First-half 2015 SEC filings for Pioneer, EOG* and Continental show that these companies are all losing money at an average realized crude oil price of $48 and range of $44-52 per barrel that includes hedges. I chose these companies to study because they have good positions in the best tight oil plays, and provide a weighted cross-section of Bakken, Eagle Ford and Permian production performance (Table 1).

Table 1. Play representation of Pioneer Natural Resources Company, EOG Resources, Inc. and Continental Resources, Inc.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

First, I looked at operating costs summarized in Table 2.

Table 2. Second quarter (Q2) and first half (H1) 2015 operating costs for Pioneer, EOG and Continental compared with the same periods in 2014.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Operating costs for Pioneer, EOG and Continental decreased by about 15%, 12% and 16%, respectively, in 2015 compared with 2014. This had nothing to do with rig productivity or drilling efficiency since those are capital costs we are talking here about operating costs.

Decreases were because of reduced staffing costs, lower taxes because of lower oil prices and revenues, and generally lower costs of doing midstream business as service providers lowered their prices to remain competitive in a lower oil-price environment.

Next, I investigated how production rates changed in response to lower oil prices. Continental’s production increased 12% in 2015. Both Pioneer’s and EOG’s 2015 daily production rates, however, were flat compared with 2014 as these companies apparently exercised discipline in the face of lower prices (Table 3).

Table 3. 2015 vs. 2014 daily production rate comparison for Pioneer, EOG and Continental.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

This is important because it means that capital expenditures by Pioneer and EOG in the first half of 2015 were to maintain rather than grow production.

Table 4 and Figure 2 summarize operating and maintenance capital costs for H1 2015 for these three companies along with their realized prices per barrel of oil equivalent (BOE) and calculated net margins per BOE. BOE prices represent a blend of crude oil ($44-52 per barrel), natural gas liquids ($15-16 per barrel) and natural gas ($2.45-2.53 per Mcf) prices.

Table 4. First half (H1) 2015 cost per barrel of oil equivalent summary for Pioneer, EOG and Continental.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Chart_H1 Cost Per BOE Summary
Figure 2. First half (H1) 2015 cost per barrel of oil equivalent summary for Pioneer, EOG and Continental.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Even though Continental’s capital expenditures were for both maintenance and growth, I used 80% of its capex for a potential comparison with Pioneer’s and EOG’s full maintenance capital costs.

All three companies lost money on a unit basis for H1 2015. EOG lost the least at $9.74 per Boe (28% of its realized price). Pioneer lost $23.48 (75% if its realized price per Boe) and, Continental, $24.04 (69% of its realized price per Boe).

Any analyst or journalist who says that tight oil companies are doing fine at lower oil prices because of rig productivity, drilling efficiency or any other factor needs to look at the data. For less substantial and less well-positioned companies than the three in this study, the losses are probably far worse.

These observations are consistent with the trends in cash flow shown in Table 5.

Table 5. Cash flow summary for 2014 and 2015 for Pioneer, EOG and Continental.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

All three companies had negative free cash flow in H1 2015. Pioneer out-spent cash flow by $781 million; EOG out-spent cash flow by $966 million; and, Continental out-spent cash flow by $1.1 billion.

Table 5 also reveals that EOG was cash-flow positive in 2014 before oil prices collapsed although Pioneer and Continental lost money even at higher oil prices. I wanted to compare EOG’s costs when the company was cash-flow positive to more recent costs when it was cash-flow negative (Table 6).

Table 6. EOG Resources’ 2015 vs. 2014 costs per barrel of oil equivalent.
Source: Company SEC filings and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

I have already discussed the probable causes for lower operating costs but the 20% decrease in capital costs is significant and may be behind some of the claims that rig productivity and efficiency are important. I do not know what percentage of capex for 2014 was for growth vs. maintenance. My allocation of 85% of capex is, therefore, arbitrary but probably over-states the amount of capex savings between 2015 and 2014. It provides a net margin per BOE that is consistent with the positive cash flow for 2014 shown in Table 5, and with recent statements by the company that it would resume full drilling at around $60 per barrel oil prices.

One of my clients just drilled a well to more than 14,000 feet onshore Texas using a high-horse power top-drive rig designed for horizontal drilling. The day rate for the drilling rig decreased by almost 40% from the initial quote in the fall of 2014 to when the contract was signed in the spring of 2015.

This leads me to believe that most, if not all, of the recent capex savings by EOG and other tight oil producers is because of price deflation and not because of increases in rig productivity or efficiency.

The EIA Drilling Productivity Report

If we have learned anything watching the rig count fall since December 2014 without much corresponding fall in oil production, it is that rig count is a very poor predictor of anything except where capital is going. Drilling productivity is just another variant or derivative of rig count and comes burdened, therefore, with all of its vagaries.

At the same time, there are problems with how the EIA uses rig productivity in their monthly Drilling Productivity Report (DPR). EIA assumes a 2-month lag between well spud and first production for all unconventional plays but this is incorrect for the three most important tight oil plays.

Figure 3 shows that during the last 6 months of 2014, the average time from spud to first production for the Eagle Ford was at least 75 days; for the Bakken, 120 days; and, for the Permian “shale” plays, 90 days.

Bakken-Eagle Ford-Permian Spud to First Prod
Figure 3. Data analysis for well spud to first production for the Bakken, Eagle Ford and Permian basin tight oil plays.
Source: Drilling Info and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

There are additional problems with EIA’s DPR such as inclusion of considerable conventional oil production in the Permian basin, and with the broad definitions of play regions that include many wells and plays not relevant to the tight oil and shale gas plays of interest (EIA acknowledges these issues in its methodology explanation).


The best way to understand the details and changes in the cost of producing oil and gas is by evaluating data in 10-Q and 10-K SEC filings. Costs have declined since oil prices collapsed and hard times hit the industry. Most of this decrease in cost is part of a larger deflationary trend in commodities and currencies and not because of rig productivity and drilling efficiency as many believe.

To some extent, lower costs compensate for the lower price of oil but none of the tight oil companies evaluated in this study are profitable in the $44-52 per barrel range of reported realized oil prices. They are all losing money.

Rig productivity and drilling efficiency measurements do not account for declining average well productivity. They will only become useful if they can be related to the marginal cost of producing a barrel of oil. For now, they are distractions from the more important subject of tight oil profitability.

*I own EOG stock.


  • Kennet Larsson

    Hallo Art,
    I enjoy your writing! On average the production price for tight oil is 60, 65 or 70 dollar per barrel?? What do you think?
    Thank you!

    • Arthur Berman


      I can only comment on the three companies that I studied in this post. EOG needs about $60 per barrel, Pioneer needs about $75 and Continental, about $70. These are pretty rough since my calculations shown in Table 4 are in BOE but they give you some idea of the range anyway.

      This assumes, of course, the costs do not increase as oil prices rise and they will!

      All the best,


  • Nony

    In 2010, you said shale gas needed $10 gas prices to be competitive. We haven’t gotten over $4 for any sustained period for the last 5 years now. And shale gas has grown incredibly. Either you were wrong at the time (probably part of the answer) or productivity has increased (the rest of the answer).

    I agree that oil is tougher than gas, but the shale gas lesson should make you cautious. You were wrong there. May end up wrong on tight oil too.

    P.s. Slight tangent, but there is an interesting story about completion improvements starting to make the Haynesville competitive again, even at $2.50 pricing:


    • Arthur Berman


      This is a blog about 2015 financial data on 3 tight oil companies. I don’t see the relevance of your comments about something I said 5 years ago about shale gas.

      I prefer that you don’t waste my time or my readers’ by posting comments unless you have something to add to the conversation about this subject.

      Yes, I saw Russell’s article on the Haynesville Shale. It is pure speculation. Maybe someone will invent a way for humans to live to be a 1000. Same with the Haynesville Shale.


  • Nony

    Just read the whole thing. Nice work, actually. (I would say “sound analysis for a peaker” in the tone of “smart…for a Marine”, but I’m not sure if you have a sense of humor.) Anyhow. Pretty good.

    Zeits has a similar back of the envelope where he thinks Continental can get by at $60. Little lower than you, but same basic point. $45 is a nightmare. And he sees Continental as one of the better companies at cost control. (The higher capex and production growth is more related to developing SCOOP, which is a gas play.) If you assume Continental is one of the better ones (maybe not quite EOG, but still good), then you have to assume a lot of companies will be in very dire straights at anything under $90 (HK, Sandridge, etc. etc.)

    It’s a small nit and doesn’t impact your point, but I don’t like average production per well since it changes with time (population). New production per rig is not a bad one, but even then you really should watch for Pareto impact, below:

    A lot of the improvement is just from “culling the weakest”. Imagine you are a financier evaluating 100 geologists projects and you rank them all on NPV. Let’s say at $100, you have 50 projects that are positive NPV. [You are rational, so you finance all top 50 and none of the bottom 50.] A lot will go into what makes a project good/bad, but probably how much oil you get out of the rock is the major variable.

    Now imagine price drops to $60. Now only 25 of the projects are profitable. And those will be (in general) the ones with more productive rock (expense plays a role also).

    So if I compare the average productivity it of the top 25 to the top 50, I will see an apparent improvement in efficiency. But nothing changed other than picking the top projects. It’s just the Pareto 80-20 salesman effect. I didn’t improve fracks.

  • Stavros Hadjiyiannis

    If I understand correctly, these 3 companies are losing all that money, even with considerable hedging involved.

    Moreover, their reduced production costs are mostly (if not exclusively) down to reduced prices from hard-squeezed suppliers. Additionally, to the extent that US oil companies import equipment and raw materiel the strong US$ has also reduced costs in that department as well. But I am guessing that is a small portion of their overall costs.

    If the above is correct (and there is little evidence to prove otherwise) then it just goes on to show that mainstream financial media (as well as media in general) cannot really be taken seriously.

    • Arthur Berman


      I think you see it clearly. There are voices in the financial press who get it or get parts of it: Asjylyn Loder and a few of her colleagues at Bloomberg, and Ed Crooks at FT to name a few.

      It is hard to understand the signal because of all the noise, or the red herrings. It takes a lot of research and a resolve to get past the consensual wisdom–a scary place for sure.

      All the best,


  • Ryan


    Interesting article, but I’m curious who(in the media) is really selling rig productivity as a sign that Operators are making money? Most operators in all plays are taking a massive loss, but must continue drilling just to cover their fixed costs in place. Even at $20.00/barrell, drilling is the better than coming to a halt.


  • D

    Good job!
    You are right, same analysis for some of the smaller names yields some striking conclusions. The RHS of the curve including Whiting and Oasis gets wiped with oil at 60. But then again, this is what has to happen to pull back global over-production meaningfully in the next year or two, unless you buy demand surge in crisis stricken EM.
    Cheers, D.

    • Arthur Berman


      Thanks for your comments and insights on both tight oil and shale gas. I may take a stab at a similar analysis for some of the weaker players although this was an exhausting exercise!

      As I think you imply, the credit-fueled over-production of all commodities is ending although it is more-or-less apparent depending on the sector. Ed Crooks’ recent FT article is the first evidence I have seen that the capital for U.S. oil may be waning. A lot of people–like my commenter Nony–think that just because companies have been able to produce a commodity, whether it is cement in China or natural gas in the U.S., at a price below their cost of production for several years, that it must be commercial at that price. They miss the credit-fueled part on both the supply and demand sides. U.S. natural gas was less vulnerable to discovery than tight oil because it was, as you say, a “throw-away” but also not traded outside the U.S.

      My 2010 comment about $10 gas included lease costs that have now been forgotten in the never-land of write-downs and impairments and no longer show up in the balance sheets, but amounted to around $1 million per well in the heyday of the Haynesville Shale. In fairness, the industry has also gotten better with cost. The last time we did a comprehensive study of the shale gas plays, $6 +/- was the average break-even price for the core areas, less for the Marcellus and more for the Haynesville.

      I agree that $10 gas is probably in the somewhat distant future of a decade or so but prices will rise in advance of the EIA forecast. The important question is, What happens when the Marcellus peaks in 4 or 5 years? All the other shale gas plays are in decline, conventional gas is in terminal decline and the new plays, like the WV and eastern PA Utica are deep, super expensive, and have over-pressure issues that may result in a Haynesville death scenario of catastrophic decline once the pressure is bled off and the reservoir compacts. The pace of export and fuel switching to meet EPA coal regulation are the other important factors.

      I accept accountability for comments that I wrote years ago, but 5 years is an eternity in the dynamic world of energy!

      All the best,


  • D

    And not to switch topic here, but it was easy for gas to grow at $3 since it was essentially a throw (burn) away by-product. Same happens with copper/gold combined mines, until the price of the main commodity collapses. Then gas prices start to matter. We may not see $10 gas for a while (due to global LNG glut), but we may see much higher gas prices in a year or two.

  • J. Shamburger

    I own an engineering service company for drilling tools and drilling engineering. I am 60, and thus was hip deep in the last downturns.

    For a service company/supplier POV, things are the same as the last 2 downturns:

    There is no “efficiency” component. It is simple cost cutting by service companies to get work and stay alive. It is using the best prices and equipment that ‘will do the job’ instead of the latest and greatest service company tech or what is available in your project time window.

    Pad drilling is ancient tech, and thus a red herring – we have been using it for over 20 years where we could, to drop costs. It is in drilling that the costs savings can be made (such as they are) and where overruns usually occur. Canada is suffering worse than the US, and they use pad drilling almost exclusively due to soil and terrain conditions – this isn’t really an ‘efficiency’ that has significant impact relative to output per well.

    Instead of 2 or 3 directional drillers working a job, we go to one. Instead of two company men, day/night, we go to one who gets awakened quite a lot.

    Instead of one clerk per rig handling logistics and reporting, we go to one for 5 rigs or let the company men do it.

    Instead of an on-site mud engineer for each rig, we go to one mud engineer working 5 or maybe more wells in the field.

    Instead of using what is available (not much when rig count is at 1800+) irregardless of price, there is now a wealth of idle equipment and open schedules at lower rates, and we use and further leverage that.

    Instead of fixing an older rig because it is all you could get to make the project dates, you get a newer, better one – less NPT.

    Instead of maintaining their rigs, contractors switch to cannibal mode, just like in the 1984 crunch.

    Their is a lot of casing sitting around from cancelled projects, and it is ordered years in advance for big projects – now it is dirt cheap. You may have to change some hole sizes and cementing plans, but that is just drilling procedures.

    The ‘efficiency’ claims made by most firms or analysts are for their investors to stay put and hold the course in the face of crap market price, and hurricane force deflationary wind in the rest of the oil patch is only a temporary thing. There is an end to the low service company prices, either by company collapse or equipment shortages, as new stuff is not ordered when your cash flow and margins do not allow it. Last time we went from 11 drill bit suppliers to 5 over the course of 3-5 years of sustained crap prices. Same thing in directional drilling…

    The abundance of drill bits, mud, casing, etc. will last some time, but it does end. The rigs will get broken up and parts used elsewhere, because new makes no sense in this market. Then the rig availability is more inelastic and we get the inevitable price creep upwards again.

    Just a view from out here in the real world where I have been out of stocks for the last 6 years – no axe to grind – and am getting hammered.


    • Arthur Berman


      Many thanks for your point-of-view. There is a lot of important history, detail and perspective in your comments. I’m a few years older than you and, therefore, have been through those same downturns and see the behavior and propaganda themes repeated today.

      As I look through company investor presentations from 10 years ago, they were making all the same efficiency claims then as now but they never showed up in the balance sheets or income statements because we were on the rising side of the price curve then.

      There is a clear floor to the savings. The land rig quote example that I used in my post was $500/day above stacking price so there is not much room to go lower (and this was one of the biggest drilling companies). The next step is what you describe–bankruptcies and consolidation but eventually, the surplus parts and reduced personnel reaches a threshold and service costs must increase.

      All the best,


  • Don Westlund


    You werent’ the only one predicting higher prices. I like Henry Groppe response to his prediction which was also wrong about higher prices. How can you forcast people throwing money away??


    From the Globe and Mail…

    Yet Mr. Groppe’s other bearish call on shale fuel – four years ago he was predicting an imminent demise of the shale-gas boom (for similar reasons as his shale oil call) that would sent natural gas prices soaring to $8 per million British thermal units within months – has proved, at very least, ill-timed. Only recently has shale gas output begun to slow and prices begun to recover.

    Mr. Groppe steadfastly insists he was (and is) right on that call. It was the shale-gas producers who were wrong. They kept expanding production, he said, “with almost a complete disregard to economics.”

    He said that despite low gas prices that should have made the relatively expensive shale-gas production unattractive, the rush to lock up land leases, helped by low interest rates and eager investors who maintained ample funds available to producers, kept the shale gas frenzy going for far longer than the underlying economics would justify. Once the industry woke up to the economic realities, tens of billions of dollars had been poured into the ground, much of it at a loss.

    “The capital destruction was unprecedented,” he said. “We don’t know how to forecast uneconomic investment on a huge scale.”

    • Arthur Berman


      Henry Groppe is a friend, mentor and colleague of mine. And he is exactly right: there was no way to anticipate the unprecedented capital that be available to fund sub-commercial shale gas and tight oil development. I naively assumed that only commercial ventures would continue to receive funding when I made the statements about shale gas in 2010. I have learned a few things since then!

      Thanks for your comments,


  • Chris Baynas (geologist)

    Nony must be one of those “GO Haynesville” fringe fanatics (royalty owner) that haven’t a clue. Haynesville economic at $2.50 OMG! I’ve followed your views on the Haynesville, and you are spot on. Numbers don’t lie.

  • Nony

    Art: Fair enough. I will try to stick to oil topic. (not gas stuff.)

    My bias is towards cornucopianism, but I think one has to be fair.

    a. I agree that a lot of the cost savings are from the slowdown. Obviously that is excess capacity, is not sustainable. Maybe some of it is if service company profits were 30%. But if they are basically cannibalizing or selling at variable cost, that can’t last. Eventually capacity will exit the market and things will rebalance at some sustainable level (i.e. costs will increase over what they are right now).

    b. The point about Pareto impact is also anti-cornucopian. What I’m responding to are claims about massive innovations in completion techniques that yield double production from wells. I think what is happening instead is that the number of wells getting drilled is cut in half. And that the wells cut when they do that are the lower half. So of course the average went up. But it doesn’t mean that they suddenly invented some better technique (on the spur of the moment and different than the very slow gradual improvements before….actually which were tailing off, not accelerating.)

    c. The Zeits article is similar to yours. He sees CLR getting by at $60 and you require $70. So you can analyze the reasons for the differences. Or just look at it versus cornies who think they are fine at $40 or peakers who think they were in trouble at $100. (And both exist.) And in those cases, you analyses support each other. Anyhow, I just thought you would be interested intellectually in similar work: http://seekingalpha.com/article/3421446-continental-resources-cash-flow-positive-in-2016-at-60-oil

    P.s. There is a point about gas other than calling out your predictions. More along the “could what happened to shale gas, happen to shale oil”. Not to say it will, but is reasonable question. I hear analysts discuss this idea.

  • Steve

    Nony, just cause Art made a Buddhist, “Is that so?” reply to your natgas barbs does not make your assumptions correct. Most realize it will not be a monster well in the sweetest part of the NE setting the HH price of natgas several years out, but production from Haynes or Barnett.

    Art, sorry for this post on natgas. Hope you will do more blog posts on it cause US-natgas pricing seems to have a lot more upside than world-oil several years out given the growth projections. Plus, seems to be a lot more fictional writing….like below –


    Haynesville Rig Count: -2 to 20


    “Last week marks the first time since the summer of 2011 that Anadarko hasn’t operated a rig in the Texas side of the Haynesville Shale.”

    Doesn’t Anadarko know about the 20% returns on $2.50 natgas?? How about all the others?

    ….and they are making these types of decisions based on go-forward costs…some facing penalties for returning rigs in advance, or not filling pipeline commitments or lease obligations…and they still walk!

  • J. Shamburger

    My opinion, FWIW, is that our oilpatch may be the first really big industry casualty of “Peak Debt”. Reserves and depletion curves don’t lie, but people do – hence the entire “forward looking statements” lingo. The issue today is that while we may have shale oil in relative abundance, it ain’t cheap. A case can be made that the 2008/9 market unwinding was an adjustment, from cheap and easy to more expensive and difficult oil, filtering into and finally saturating the world economy.

    As it stands, very few can make money at today’s prices, and those that can are in heart-o-trend or conventional, not unconventional. Apache made money for years in the OCS, working as a ‘gleaner’ on stranded and smaller prospects. There is a reason that Fieldwood was formed and spun – everything to do with reduced potentials. There is always a reason for divestitures, and it usually involves reduced potentials or excessive debts. Today, we are certainly at “Peak Debt” levels no matter where you look in the oilpatch, and it appears to be happening in other mining operations as well.

    One can look at reserves and many other things in our business, but debt is a serious issue and the entire world is swimming in more of today than in the previous 4-5 centuries COMBINED.

  • Nony


    1. Good point on the Haynesville rig numbers. I agree that the CRK approach and the WSJ article are just little snippets and what matters in the end is overall production.

    2. I agree with you that it is local production that matters for HH (TX, LA, AR). Transco Leidy and Tennessee zone 4 (NE and SE PA) are both at ~$1 right now. I have heard of worse in eastern Ohio. (So Appalachia is sort of like stranded gas.) Until the pipelines are built, that won’t change and what is stopping the pipelines is not money or time to do the work, but the politics (obstruction).

  • Nony

    Small nit (but very related to the content):

    Production per well is not a good metric as it changes with the age of the population of wells. New oil per well is more relevant. New oil per rig is decent too. Either of these in conjunction with the well (or rig) count can give you new production per month. Then comparing this to decline, you can see if you are outrunning the Red Queen or falling behind. This is the method EIA uses and is quite good (and should actually appeal to peakers who want to think about declines).

    • Arthur Berman


      You need to focus on the subject of the post and the informed objections by other readers to your comments.

      People read my posts because I am an expert on oil and gas. You are not by your own admission–you called yourself a “civilian” in an earlier comment.

      This comment area is not a forum for you to express your views and “nits” about my work but to discuss the issues that I raise in my posts. You are welcome to disagree, state why and support your views with data.

      I do not write posts as term papers for you to grade.

      I moderate the comments on my blog and have been gracious by not disapproving your comments because they are, frankly, often inappropriate, irrelevant or just annoy other readers.


  • Heinrich Leopold


    In my view the real test for companies will come when revenue falls below cash costs (operating costs). The losses companies have so far do not affect real cash flow as these losses are just accounting losses and impact mostly equity prices as future profits will be curtailed. So the current losses do not affect day to day operations. However when oil prices fall below cash costs, companies have to use new debt to pay interest rates and other cash expenses. Two weeks ago when WTI prices fell below 40 USD per barrel, which is for many shale companies receiving less than 30 USD per barrel the point when they have to stop production.

    • Arthur Berman


      I cannot agree with your position. By definition, cash flow is the difference between what is earned from operating activities and what is spent in capital costs.

      Everything in Tables 4 and 5 relates to cash flow and it is quite negative. The accounting or “non-cash” items that I think you refer to like impairments, DD&A, etc. were excluded from these numbers.

      Table 4 is essentially a profit and loss statement and, when companies are losing $10-24 on every barrel of oil they produce and sell, that makes day-to-day operations very difficult.

      Table 5 is a cash flow statement and the numbers are super-negative for 2015.

      I do not understand how you somehow think this is not about real money and cash flow. Just because there is a margin between realized price and operating cost does not mean that other expenses like capital expenditures are not paid in real money.

      All the best,


  • William E

    You are doing a great job Arthur,this can only grow.
    Thanks for sharing your knowledge.

  • Steve

    Wow! Had not seen this info on costs from BEG/UT and am trying to get more data Dr. Foss. Add this current cost data to their ongoing study on sweetspot depletion – well , I’ll just quote one of the members of the team (Tad Patzek) The results are “bad news”).

    This is in line with what Art has been writing/speaking about for years; Dr. Foss has over 3 decades of experience and the university is the heart of oil and gas country (ie, not an enviro organization)

    It is about both oil AND natgas as it is hard to separate the two (unless you are a refiner;)

    $80 for US shale oil
    $8 required for US dry shale gas
    implies 10% roi for investors


    …so, few of these companies will make money for years and what is the upside to just buying and holding the commodity itself…let’s see…today’s pricing –

    Nov/2019 WTIC is at $59
    Nov/2019 natgas is at $3.26

    The cure for low prices (during QE/zirp) was not low prices – but debt covenants. Looks like the market will be adjusting capital spending to cash flows.
    Most these wells are 90% depleted within 3 years.

    Just as the old members of the go-forward-cost club (E&Ps, service providers) exit;
    the new members will be joining (LNG/pipeline exporters, chemical/mfg plants) who will have the opposite effect on HH pricing.

  • Andrew Rudenko


    There is an interesting comment to a repost of this article on oilprice.com – one by oildusk which is as follows:


    Interesting thoughts, but you completely missed the big picture.

    You are using average numbers to try and draw conclusions. The reality is that you have to look at the marginal numbers.

    The existing production, excluding any production brought on by new wells, is only charged with the monthly operating costs – and not the capital costs. The challenge with those numbers is that these wells were drilled at a time when the expectation was that these wells would be produced throughout the life of the well at $100 a barrel. Hence, the existing production is cash flow positive since the price obtained in the market exceeds the operating costs.

    For new well production, you could be right that the capital costs being paid will not rationalize drilling wells in a $40 price environment, but the fact that there are wells being drilled suggests that these wells are also probably cash flow positive. What is being lost or given up, is the associated “sunk costs” of any leasing expenses previously paid for these assets that are clearly in some sweet spot.

    It is a financial tragedy that the previous investments that these companies have made in drilling capital expenses and leasing/land capital expenses are not getting adequately compensated in the current oil price environment. If the stock of existing debt is high enough from these previous investments, some of these companies will not make it. But, even if a few companies go bankrupt, the shale reservoirs are still there and another U.S. oil company will end up holding that asset.

    The shale industry has tremendous flexibility to bring on additional wells when oil prices warrant it. ”

    Being a trader, I am not very familiar with upstream accounting conventions. My instinctive assessment of the situation is that low porosity of LTO reservoirs combined with fast decline rates place it in the “very expensive to produce” tier, regardless of how you distribute these costs/expense between capital and operating costs. What oildusk is referring to appears to be an accounting trick – financial statements of many frackers do not show any meaningful FCF, however they keep going. Perhaps you would like to comment on oildusk’s statement – I am really interested in your opinion.

    • Arthur Berman


      Here is the comment that I left for oildusk.


      I am fully aware of what you call the “big picture.”

      It is the world of magical thinking in which real money is never spent and breaking even means paying for your lease operating costs with the revenue from selling the oil and gas produced, and pretending you have no other costs.

      This is like applying for a loan and only showing your paycheck and your costs to get to work each day but omitting your mortgage payment, all household expenses, food, loans, credit card debt, etc.

      That’s the marginal cost of working but it sure isn’t your marginal cost of living. And it won’t fly with the bank.

      I understand what marginal cost means. Do you?

      The “big picture” that you miss is that for EOG and Pioneer, operating costs plus capital costs ARE the marginal cost of producing the next unit to keep production flat.

      Why do you suppose that oil and gas companies are laying off staff, cutting capital programs and selling assets? By your logic, they are doing great and shouldn’t have to do this as long as revenues from oil and gas sales cover operating costs.

      In your world, cash flow and income statements are irrelevant.

      I wonder why the SEC requires that all public companies file them every quarter and people go to jail if they are not true? Because they are irrelevant and no one cares about them?

      The economic fantasy world that you describe implies that shale plays are exempt from the fundamentals of profit and loss.

      Good luck living in that reality.

  • Nony

    Art: I’ll stop posting. If I backslide and post anyway, please delete.

  • Tony Chan

    Hi Art,

    Pioneer and EOG represent some of the better run share companies. Your analysis seems to indicate they will need USD45-50/bbl just to maintain production. Given that contractors have probably given as much as they can, operating costs are not likely to reduce further. If the present cash bleed continues, how much longer can they go on before production starts falling in a big way?

    • Arthur Berman


      Your question is, of course, what everyone wants to know and no one can answer.

      The EIA September STEO was published yesterday and shows U.S. crude oil production is down 510,000 bopd since April. In February, I developed a model based on incorrect EIA spud-to-production data that said ~600,000 bopd (535,000-665,000 range) decline by June. So, the magnitude was right but the timing was a few months off. My colleague Euan Mearns has recently forecast a decline of 830,000 bopd by the end of 2015.

      The problem exemplified by Continental Resources in my latest post is that some companies in more dire straits than EOG or Pioneer will do whatever they can to continue to over-produce for cash flow to meet debt service.

      So, the answer to your question is that the decline is underway but unless capital flow stops, it will be an uneven process with some months up in an overall downward trend. The bad guys here are the capital providers not the oil producers who are caught in a struggle to survive after being encouraged to leverage up by the capital providers (mostly investment bankers).

      All the best,


  • Tony Chan

    Hi Art,

    I want to thank you for all the work you have done on this website. I have learned a great deal reading here. Just a few points

    – Core Labs is calling for 500k bpd decline for LTO by end 2015 with a V shaped recovery thereafter (2Q Eranings Call). Do you think they are right?
    -The IEA August report out today seems a little more price supportive than they have been in a while. What puzzles me is the “call on OPEC” for 2016 which would imply that for the market to balance OPEC will have to produce at present elevated levels. Can they actually do this? I am hearing rumors that Ghawar is being pumped with CO2 which does not suggest record production going forwars?
    -Who is more credible, Igor Sechin who suggests that Rosneft can keep up current production in 2016 OR the Lukoil guys who are hinting at a 500-800K bpd fall in 2016?

    Once again many thanks

    • Arthur Berman


      Thanks for your comments. Demshur’s statements about production declines all make sense but a V-shaped recovery is speculative and assumes that all of the factors he describes are perfectly synchronized. Things seldom happen this way.

      Doubts about Saudi production sustainability have been around for at least a decade and I understand the concerns there. At the same time, they are long-term thinkers and quite conservative. I don’t see a lot of upside in taking sides on this debate except to say that both sides are plausible and that no one wins by betting.

      It is hard to decipher truth from posturing in Russia these days. I think it is pretty clear that the economy is in bad shape and that budgets for Rosneft, Gazprom, Lukoil, etc. are thin. I don’t have the data to say whether Rosneft can or can’t maintain production in 2016.

      All the best,


  • […] oil at a loss because of their largely junk bond financing and debt. The Texas shale drlllers are forced to sell below cost to bring in enough oil revenue to avoid bankruptcy, as we are seeing […]

  • Simon Hodges

    Dear Art

    An excellent article as usual.

    I wouldn’t worry too much about your earlier predictions not materializing. Many of us were thinking along similar lines but what none of us anticipated was the sheer scale of central bank intervention and QE that was going to take place globally from 2012 onward. ZIRP and trillions in QE has enabled many of these companies to raise and borrow money whilst making losses year in and year out.

    It is mal-investment writ as large as you can get and has led directly to global over-supplies of all sorts of things and ironically deflation when central bankers were supposedly aiming at creating inflation.

    There is a tendency of many commentators on the oil business to focus exclusively on the oil industry as a black box, when it really needs to be considered within the broader scheme of markets in general and how central bankers have manipulated them. The meaningful development of shale industry pretty much runs concurrently with the post-financial crisis era, ZIRP and QE and needs to be situated and understood within that context. This explains why a lot of our anticipations have not panned out as expected.



    • Arthur Berman


      Thanks for your comments. I have never done price predictions, so it surprises me that some people interpret earlier comments to be wrong about price. What I said was that production levels were not likely to continue growing–that was wrong for the reasons that you have so lucidly described. I did make general observations about what this meant for prices but I have never done a price forecast in my life for oil and gas!

      All the best,


  • […] message is all about rig productivity and drilling efficiencies. I showed in my post last week that these measures are nothing but red herrings to distract from the unavoidable truth that all […]

  • […] message is all about rig productivity and drilling efficiencies. I showed in mypost last week that these measures are nothing but red herrings to distract from the unavoidable truth that all […]

  • […] message is all about rig productivity and drilling efficiencies. I showed in my post last week that these measures are nothing but red herrings to distract from the unavoidable truth that all […]

  • Tolly

    Hi Art, very interesting articles.
    I’ve done two days of intense research on the North Dakota oil, as the state publishes a lot of well data. I also get a CAPEX of 23 per barrel just to maintain production (80 wells at 300 bowls (average IP in state) needed to offset a five per cent monthly decline, multiply by 10m CAPEX per well (it’s not much less, once all costs are included) and divide by 40mmbl monthly production.

    But you forget the cost of capital (namely interest to lenders and expected equity return) – 12000 North Dakota wells cost 120billion to drill and WACC is not zero per cent. Yes it may in theory be partially depreciated, or written off, but I get 10 to 60 dollars per barrel cost of capital depending on your assumptions.

    This is the killer as you’d need a WTI of over 100 to cover all those costs. And yes about 60 if that 120bn in ground is interest free.

    Did you come across any analysis on this issue?

    It’s a fascinating topic as so easy

    • Arthur Berman


      You are absolutely right that cost-of-capital is an issue but I generously assumed that was included in the interest expense part of operating costs–see Table 2 in the post. The point that you make, I believe, and that I agree with is that there must be an additional margin beyond interest expense to provide a net present value of at least zero. That was not included in my analysis.

      All the best,


  • […] message is all about rig productivity and drilling efficiencies. I showed in my post last week that these measures are nothing but red herrings to distract from the unavoidable truth that all […]

  • […] message is all about rig productivity and drilling efficiencies. I showed in my post last week that these measures are nothing but red herrings to distract from the unavoidable truth that all […]

  • […] message is all about rig productivity and drilling efficiencies. I showed in my post last week that these measures are nothing but red herrings to distract from the unavoidable truth that all […]

  • […] oil at a loss because of their largely junk bond financing and debt. The Texas shale drlllers are forced to sell below cost to bring in enough oil revenue to avoid bankruptcy, as we are seeing […]

  • Simon Hodges

    Hi Art

    Continental Resources published their Q3 earnings yesterday and they reported a net loss of $82.4 million. I was expecting them to announce something around a loss of $500 million. I’m not too familiar with accounting practices but if you figures are correct how did they manage to only declare such a small loss?



    • Arthur Berman


      $82.9 million was CLR’s loss for Q3 only. Their loss so far this year is $217 million. They have taken $321 million in impairments this year and that removes huge DD&A charges that help the bottom line despite the reason being a disastrous loss. So-called full-cost accounting allows lots of tricky manipulations to make bad news seem somewhat good.

      All the best,


  • mark

    Hi Art,
    Just wanted to ask about your “maintenance capes” assertions. You seem to be saying that once a well is drilled and producing, the company must continually invest $30 per barrel it produces into capital expenditures, in order to produce those barrels. Above and beyond the operating cost of producing those barrels. Maybe you could elaborate on what this $30 per barrel of capital equipment cost is going towards??

    For instance, a typical Permian well might produce 500 BOE/day. You are saying that each day, the company is spending $15,000 on plant and equipment (over and above the cost of operating the well, i.e. labor, transport, consumables, etc). To take this a step further, your are saying that on a annual basis, the company is spending $5.5MM on each well in capital expenditures in order to maintain production from that well.

    Art, what are they spending this $5.5M per well on?? Most of these wells don’t cost that much to drill in the first place.

    Or is it that these capex numbers are in fact costs for drilling new wells?

    • Arthur Berman


      Maintenance capex is what must be invested in new drilling and completion to maintain declining production. Operating costs including gathering, transportation and plant processing continue as opex per boe produced.

      All the best,


  • […] eventually led to an oil price collapse (starting in mid-2014), so that now the frackers are losing money hand over fist and have had to resort to taking on enormous amounts of debt that’s soon coming due, while oil […]

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