Less Than 2 Percent of Permian Basin Is Commercial at $30 Oil

Less than 2 percent of Permian basin tight oil wells are commercial at $30 per barrel oil prices.

Sorry about that. I know that many believe that U.S. shale and tight oil plays are commercial even at current low oil prices but data on the Permian basin and Bakken plays simply does not support that belief.

To make matters worse, Pioneer and EOG have made outrageous claims about Permian basin reserves in their 3rd quarter 2015 earnings reports that no sensible person should believe. Statements like these simply add to the mistaken idea that tight oil plays get a pass on the laws of physics and economics and that somehow the USA is going to beat Saudi Arabia as the low-cost “swing producer” of the world. I wish that were true but trust me–based on data, that’s not going to happen.

The Permian basin is one of the oldest producing areas in the United States. It has been thoroughly drilled and is in a hyper-mature phase of development. The Spraberry, Wolfcamp and Bone Springs plays that Pioneer and EOG are pursuing (Figure 1) are really secondary recovery projects in which horizontal drilling and hydraulic fracturing have replaced water and CO2 injection methods used in the past. Few new reserves should be expected. Most of the claims that these companies make are really about higher recovery efficiency of existing reserves.

None of these plays are remotely commercial at present oil prices. In the most-likely per-well reserve case, these plays require break-even oil prices in the range of at least $50-$75 per barrel, and current wellhead prices in the basin are less than $30 per barrel.

Bone Spring-Wolfcamp Location Map 13 Dec 2015
Figure 1. Horizontal Wolfcamp-Spraberry & Leonard-Bone Spring play location map, Permian basin.
Source:  Drilling Info & Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Reality Check:  The Claims vs. Proven Reserves for the Permian Basin

Pioneer claims more than 10 billion barrels for its Spraberry-Wolfcamp position, and EOG claims 2.35 billion barrels for its Bone Spring and Wolfcamp plays.

Let’s put that in context.

Total proven crude oil and condensate reserves for the United States as of the November 2015 EIA report are 39.9 billion barrels. So, these two companies claim that they have reserves or resources of more than one-quarter of all U.S. reserves in 3 plays in the Permian basin. According to the same EIA report, the Permian basin has less than three-quarters of a billion (722 million) barrels of proven tight oil reserves.


Pioneer’s claim is by far the more preposterous of the two but it wasn’t very long ago (May 2014) that EOG CEO Bill Thomas told investors that his company wasn’t really all that into the Permian basin. Pioneer CEO Scott Sheffield has been making statements for a few years about the Spraberry that ought to give his company’s General Counsel heart seizures.

“The Spraberry Wolfcamp could possibly become the largest oil and gas discovery in the world.”

It is incredible that analysts have not challenged Sheffield’s claim over the last two years that the Spraberry is second only to the Ghawar Field (Saudi Arabia) as the world’s largest oil field.

What exactly do analysts analyze, anyway?

It’s Not A Lie If We Tell You It Is A Lie

Companies like EOG and Pioneer get away with making misleading claims by carefully choosing their words and by explaining that what they just said was technically untrue.

Investor beware.

A reserve is a volume of oil or gas that is commercially producible at a specific current price. EOG describes a billion barrels of new Permian reserves as “net potential reserves.”  This is something that is not a reserve today but that may become a reserve at some future price high enough to make it commercial. It could be $100 per barrel or it could be $1000 per barrel. In other words, these are at best possible reserves that have nothing to do with being commercial at current prices.

Pioneer describes its 10 billion barrels in the Permian Spraberry/Wolfcamp as “net recoverable resource potential.”  A resource is an estimated volume of oil or gas in “known and yet-to-be discovered accumulations (SPE)”. A net recoverable resource, therefore, means that there are 10 billion barrels that are known and have the potential to become discovered but are not discovered today. That means absolutely nothing.

If all  of this sounds somewhat misleading and deceptive, that’s because it is. At the end of both press releases are extensive disclaimers stating that their use of terms like reserves and resources are outside of SEC guidelines, and should not be taken seriously.

“Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include “potential” reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines.”

The trouble is that many investors lack the technical knowledge of the oil and gas business to realize that they are being told is largely fantasy.

Analysis of Pioneer’s Spraberry-Wolfcamp and EOG’s Bone Spring and Wolfcamp Plays

I evaluated Pioneer’s and EOG’s plays in the Permian basin using the lowest drilling and completion costs that Pioneer (PXD) and EOG show in recent investor presentations and made the economic assumptions shown in the table below.

Table 1. Permian basin economic assumptions for Pioneer (PXD) Spraberry-Wolfcamp, EOG Wolfcamp and EOG Bone Spring plays.
Source:  Company reports and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

I used standard rate vs. time decline-curve analysis methods to forecast reserves for wells grouped by play and operator, and by year of first production. The matches of decline-curve forecasts and production histories were generally good providing reasonable confidence in resulting estimated ultimate recoveries (EUR). The forecasts are probably optimistic because of the effect of multi-well lease reporting in Texas that has the effect of flattening some of the production history matches. The decline trends were consistently hyperbolic with b-exponents generally in the 0.5-1.0 range. Representative examples of the decline-curve analyses are shown in Figure 2.

Figure 2. Examples of decline-curve analysis for Pioneer Spraberry, EOG Wolfcamp and EOG Bone Springs vintaged production groups.
Source:  Drilling Info & Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Resulting EUR forecasts are shown in Table 2 by year of first production and weighted average (WTD AVG) for all years evaluated.


Table 2. Summary table of reserve forecasts for Pioneer Spraberry, EOG Bone Spring and EOG Wolfcamp plays.
Source:  Drilling Info & Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Table 2 shows a probabilistic range of EUR values for each play based on the method of converting natural gas to barrels of oil equivalent (BOE): a P90 Low-EUR Case, a P10 High EUR Case, and a P50 Most-Likely EUR Case.

The P50 Most-Likely case uses a 12 Mcf-to-1 BOE (12:1) conversion formula, the historical ratio before the collapse in natural gas prices from over-production of shale gas wells. The P10 High EUR Case uses a 6:1 BOE conversion formula based on the energy content of gas vs. oil in British Thermal Units (BTU). The P90 Low-EUR Case uses a 19:1 BOE conversion based on value by dividing the 2015 average price of WTI crude oil ($50.46 per barrel) by the average 2015 price of Henry Hub natural gas ($2.69 per MMBTU).

Pioneer’s Spraberry-Wolfcamp play has the lowest EUR with a P50 weighted average of almost 151,000 BOE and an associated break-even price of $99.07 per BOE.

EOG’s Bone Spring play has the highest most-likely EUR of the plays evaluated with a P50 weighted average of about 291,000 BOE and an associated break-even price of $51.04 per BOE.

The EUR of EOG’s Wolfcamp play is intermediate between the Bone Spring and Spraberry. The P50 weighted average EUR for the Wolfcamp is approximately 244,000 BOE with an associated break-even price  of $72.94 per BOE.

“Monster” Wells

There are many “monster” wells in the Permian basin plays. This does not change the fact that average wells for top operators in the best parts of the plays are not commercial at current prices–even using the latest technology at the lowest cost and highest efficiency.

Pioneer states that its average Spraberry well is “continuing to deliver an average EUR of 1 MMBOE from all Wolfcamp B and Wolfcamp A interval wells drilled in the northern Spraberry/Wolfcamp since 2013.”   Pioneer has drilled many impressive “monster” wells mostly in 2015 one of which will probably reach an EUR 1.25 million barrels of oil (Figure 3). But for 2015, the 123 wells that I evaluated have a per-well average P50 EUR of 164,000 BOE (also Figure 3) and that is nowhere close to being commercial.

PXD UNIV 17H & PXD 2015 DCA 15 DEC 2015
Figure 3. Decline-curve analysis of Pioneer University 178B-17H well (1.2 mmbo & 2.4 bcfg EUR) and Pioneer 2015 production group average (146 kbo & 221 mmcfg EUR).
Source:  Drilling Info & Labyrinth Consulting Services, Inc.
(Click image to enlarge)

This leaves me scratching my head and wondering exactly which average Pioneer Spraberry wells are delivering an average EUR of 1 MMBOE? I can only conclude that this represents some cherry-picked subset of Pioneer’s wells and is, therefore, a misleading statement at best.

A Spraberry-Wolfcamp well with 1 million BOE EUR would break even at an oil price of $15 per barrel. Yet Pioneer showed $0.98 billion in negative cash flow through the 3rd quarter of 2015. If they truly had wells this good, why wouldn’t they drill all of their 2015 wells in the Spraberry and show a profit?

EOG has $1.2 billion in negative cash flow so far in 2015.

The Bigger Picture for the Spraberry and Bone Spring Plays

I cannot explain the perception that Permian basin plays are more profitable than other tight oil plays. Data suggests  the Permian basin is no better than the Bakken or Eagle Ford plays. None are commercial at current prices of around $30 per barrel and are largely non-commercial at $45 per barrel wellhead prices.

Pioneer’s performance in the Spraberry-Wolfcamp play is reasonably representative of the overall play. At $45 WTI wellhead prices, approximately 2% of wells break even at a per-well EUR of 332,000 BOE; at $30 oil prices, less than 1% of wells break even at an EUR of 499,000 BOE (Figure 4–break-even to commercial areas shown in green).

Spraberry-Wolfcamp $45 & $30 BE EUR Maps 18 Dec 2015
Figure 4. Spraberry-Wolfcamp $45 and $30 per barrel break-even EUR maps. Break-even EUR at $45 WTI wellhead oil prices is 332,000 BOE. Break-even EUR at $30 WTI wellhead oil prices is 499,000 BOE. Green areas are commercial and blue areas are non-commercial at the break-even prices and EUR values shown.
Source:  Drilling Info & Labyrinth Consulting Services, Inc.
(Click image to enlarge)

EOG’s performance in the Bone Spring play is reasonably representative of the overall play. At $45 WTI wellhead prices, approximately 10% of wells break even at a per-well EUR of 330,000 BOE; at $30 oil prices, about 2% of wells break even at an EUR of 495,000 BOE (Figure 4.)

Bone Spring $45 & $30 BE EUR Maps 18 Dec 2015
Figure 5. Bone Spring $45 and $30 per barrel break-even EUR maps. Break-even EUR at $45 WTI wellhead oil prices is 330,000 BOE. Break-even EUR at $30 WTI wellhead oil prices is 495,000 BOE. Green areas are commercial and blue areas are non-commercial at the break-even prices and EUR values shown.
Source:  Drilling Info & Labyrinth Consulting Services, Inc.
(Click image to enlarge)


Many believe that U.S. shale and tight oil plays are commercial even at current low oil prices. This belief is apparently founded on a relentless faith that technology and American ingenuity can somehow circumvent the laws of physics and economics.

Data does not support that view.

Technology as a “game-changer” in oil and gas production is a familiar refrain that rarely considers cost. It is a faith-based perspective that is seemingly supported by confirmation bias–if almost everyone agrees that technology is an oil and gas game-changer, then it must be true. Few people look beyond the great volumes of oil and gas resulting from horizontal drilling and hydraulic fracturing to ask, “How much of it makes any money?” A quick look at the cash flow and income statements of companies using this technology should produce an immediate red flag. A closer look at the actual costs and resulting economics of the plays confirms the truth that technology in the oil and gas business comes at a considerable cost and few producers actually make money. We hear a lot about break-even prices but who wants to invest in something whose only merit is that it does not lose money?

None of the Permian basin plays evaluated in this study are commercial at present oil and gas prices. Pioneer reported a realized price of $28.75 per BOE (including natural gas liquids) for the 3 months ending September 30, 2015 in its 10-Q SEC filing and the current price is undoubtedly lower. That means that wellhead prices need to be at least double for the most attractive of the three evaluated plays to break even.

Times are tough in the oil business and the many of the best E&P companies are losing money at current oil prices. I cannot understand why good companies like Pioneer and EOG feel that they must resort to hyperbole about huge new reserves when sensible investors would prefer the honest truth.



  • Eric

    Interesting analysis. I suppose the SEC writedowns are coming in the next 1-3 months? Is there a specific date when oil companies have to adjust their reserves (and thus balance sheets) based on SEC rules about current oil/strip pricing?

    I think CLR is going to take another hit, even with shares already low. Debt is way too high compared to claimed reserves, which will be written down. In any case, I seem to remember you saying you were long EOG, do you think EOG and PXD (which I believe are considered to have the best leverage ratios among the major pure-frack companies) are also going to take major hits?

    Hope you can keep us informed about the current SEC overhang.

    • Arthur Berman


      Thanks for your comments and question.

      There are two types of write-downs coming at year-end that we will see in the first quarter 2015 10-Q (February-March time-frame) filings for public companies in the U.S.

      The first is what is called a ceiling test impairment. For companies that use the full-cost accounting method, this is a comparison of the net present value at a 10% discount (NPV10) of reserves with the 2015 SEC price for oil and gas, the average of prices on the first day of each month of 2015. If the discounted cost to develop those reserves is above that price, the value of the reserves must be written down to that price.

      The ceiling test impairment is a non-cash item for the present quarter because the cash was spent in a previous period and, therefore, companies explain in their filings and in earning statements that it really doesn’t matter although it does because it reduces the asset value of the company. Companies have been taking these charges every quarter of the year so far with little attention from investors so I do not foresee the 4th quarter impairments causing much more concern.

      The second and more interesting write-down will be the removal of booked proven-undeveloped reserves (PUD) under that 5-year rule of the 2009 SEC reserve rule changes (effective January 2010). This provision allowed companies to book PUDs based on proximity alone to proven producing wells without having to show map- and lowest-known water level-based evidence as in the past. This was a huge gift to the shale players and they used it fully with some companies’ PUDs making up 65% of total booked reserves. The provision of the rule change, however, stipulates that a development plan must be submitted within 5 years of booking or the reserves must be removed.

      Companies like Chesapeake have already stated in the 3rd quarter 10-Q that their reserve inventory will fall by 45% because of this rule. It remains to be seen if investors pay more attention to these write-downs than they ordinarily pay to ceiling test impairments.

      I think that these “write-downs” will have more effect this year on gas rather than oil reserves because tight oil production was not fully developed for many companies in 2010 but we will see about that when the filings are available–and I will certainly keep readers of this blog informed!

      All the best,


  • David Ryan

    Hi Art, Sheffield recently said that in 2025 the Permian
    will still be growing , while all the other tight oil plays
    would have peaked? Do you buy this or is he just talking his book
    again? I think Pioneer is only in the Permian. Any insight into
    when the Permian peaks? It seems to be the best of the shale plays
    or at least the lowest costs? Thank you sir?

    • Arthur Berman


      Pioneer’s main production is from the Permian basin (35%), Eagle Ford Shale (25%) and Raton basin coal-bed methane (11%). David Hughes’ forecast indicates Permian peak production in around 2021. EIA forecasts a peak for U.S. tight oil in 2020 although their view is really more of a peak plateau from 2020-2025.

      This data argues that Sheffield’s statements about Permian production growth after 2025 is questionable.

      On a discounted capital cost per barrel EUR-basis for break-even at $30 oil price, the Bakken is best at $10.38/barrel, the Eagle Ford is almost as good at $10.48/barrel and the Permian is lowest with $13/barrel.

      Current horizontal rig count for the Permian is 175 vs. 73 for Eagle Ford and 56 for Bakken. Go figure.

      Thanks for your questions that made me do some calculations!


  • Paul


    Thanks for interesting post (again).

    I’ve been waiting all year for large writedowns from the shale plays (especially following on from Einhorns presentation), but if there has been any, they don’t seem to have been as large as expected. Have I missed some? or do you think that it’s going to hit Q1 next year.

    Also – has now been 1 year since oil price crashed. Will we start to see more impact of hedges ending and companies now being exposed to lower prices?

    • Arthur Berman


      Please see my reply to Eric below on write-downs.

      Pioneer has taken $210 million in ceiling test impairments through the 3rd quarter of 2015. These generally don’t get a lot of notice from investors because they are a “non-cash item” in the current quarter. They are significant, however, because they represent cash spent in some quarter and reduce the company’s net asset value, equity, etc.

      Patience is required before seeing tangible evidence of lower production from lower oil prices and hedges are part of that practice. Hedges vary greatly from company to company so it’s impossible to make general statements. My friend Asjylyn Loder at Bloomberg writes about hedges regularly. Follow the link to find all of her articles.

      You can investigate hedges and write-downs by downloading a company’s 10-Q filing from their website as a PDF and searching for “impairment,” “hedge,” “swap” and “derivative.” For Pioneer, look for derivatives and you will find the hedge type and price, volume of oil or gas hedged, and the term.

      All the best,


  • Heinrich Leopold


    In my view it is the bond market, who judges about the economics of a business concept over the long term. As the bond market is currently revolting against shale oil and gas investments, it will regulate additional investments until prices go up again.

    • Arthur Berman


      I hope that you are correct but that has not been the history of E&P investment. The banks should have slashed the borrowing limits of these companies in October but gave them a pass.

      Investors would like to find a better place to put their money but cannot get the yield elsewhere so they return to E&P junk bonds. Maybe this time it will be different.

      All the best,


  • […] Table 2. Key operator weighted-average estimated ultimate recoveries (EUR) in barrels of oil equivalent and break-even oil prices. Drilling and completion (D&C) costs used in the economic calculations are shown. Economics also include an 8% discount. Details may be found at the following links: Bakken, Eagle Ford and Permian. […]

  • […] Table 2. Key operator weighted-average estimated ultimate recoveries (EUR) in barrels of oil equivalent and break-even oil prices. Drilling and completion (D&C) costs used in the economic calculations are shown. Economics also include an 8% discount. Details may be found at the following links: Bakken, Eagle Ford and Permian. […]

  • […] Table 2. Key operator weighted-average estimated ultimate recoveries (EUR) in barrels of oil equivalent and break-even oil prices. Drilling and completion (D&C) costs used in the economic calculations are shown. Economics also include an 8% discount. Details may be found at the following links: Bakken, Eagle Ford and Permian. […]

  • For ten years I have watched Berman’s comments and seen the criticism from the drillers. He is right. It is nuts. After running dozens of declines in both central Oklahoma and the Fayetteville in Arkansas, I’ve seen EURs improve as laterals are increased, but overall, when doing several wells in a given unit, there seems to be some wells that “surrender” reserves to another well. They suddenly decline after a new well is drilled. If each well is being judged on the basis of the first or best well the issue is whether that is a real proxy for all the wells that can be drilled.

    Secondly, it happened in Guy, Arkansas, and now in Central OK….earthquakes. Those quakes clearly have a geological reason, but the trigger is also clear. Injection wells. And while a well making 400 bpd looks good, what is the cost of disposal when it makes 2400 bpd of water? And how do you inject at higher rates in the face of earthquakes…another very damaging quake happened a few days ago. People will sue and should.

    The high lifting costs are something the Saudi’s won’t face. And the pundits who think the industry is simply waiting in the wings for $60 oil and the rigs will pop back up like dandelions are mistaken. The drillers are hurt bad, their help is leaving town for jobs elsewhere. Like the song sayd, this ain’t no technological freeway. It’s the road to hell.

    • Arthur Berman


      As a professional mineral ownership appraiser, your opinion means a lot to me. I am not happy to be right about the marginal commercial value of shale gas and tight oil plays in the U.S. to date but, outside of small parts of core areas, it is difficult to be optimistic. The core counties of the Marcellus Play in Pennsylvania are an exception but there, the operators have over-produced themselves into an impossible price environment–wellhead gas prices today are well below $1 per mcf.

      Water production is almost never mentioned and is only found occasionally in the 10-Q filings by producers although it must be somehow buried in other operational costs. The earthquake problem is not going away. I met a seismologist who was my host at a recent talk that I gave at the Dallas Geological Society and he confirmed what I thought to be true namely, water injection along existing fault planes lubricates the faults and allows slippage that produces earthquakes. Water disposal is hardly a new problem in the oil and gas business so it seems reasonable that siting injection wells away from known or probable faults would make sense although it would add cost.

      I show a figure from Schlumberger in a post from April that describes that for approximately equal daily volumes of oil, U.S. operators drilled 297 million feet of hole compared to 3 million feet for Saudi Arabia and 83 million feet for Russia. I believe that slide says all that you need to understand the true commercial reality of tight oil production in the United States.

      All the best,


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