- June 19, 2016
- Posted by: Art Berman
- Category: The Petroleum Truth Report
The break-even price for Permian basin tight oil plays is about $61 per barrel (Table 1). That puts Permian plays among the lowest cost significant supply sources in the world. Although that is good news for U.S. tight oil plays, there is a dark side to the story.
Just because tight oil is low-cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
The disturbing truth is that the real cost of oil production has doubled since the 1990s. That is very bad news for the global economy. Those who believe that technology is always the answer need to think about that.
Through that lens, Permian basin tight oil plays are the best of a bad, expensive lot.
Not Shale Plays and Not New
The tight oil plays in the Permian basin are not shale plays. Spraberry and Bone Spring reservoirs are mostly sandstones and Wolfcamp reservoirs are mostly limestones.
Nor are they new plays. All have produced oil and gas for decades from vertically drilled wells. Reservoirs are commonly laterally discontinuous and, therefore, had poor well performance. Horizontal drilling and hydraulic fracturing have largely addressed those issues at drilling and completion costs of $6-7 million per well.
Permian Basin Overview
The Permian basin is among the most mature producing areas in the world. It has produced more than 31.5 billion barrels of oil and 112 trillion cubic feet of gas since 1921. Current production is approximately 1.9 million barrels of oil (mmbo) and 6.6 billion cubic feet of gas (bcfg) per day.
The Permian basin is located in west Texas and southeastern New Mexico (Figure 1). It is sub-divided into the Midland basin on the east and the Delaware basin on the west, separated by the Central Basin platform.
The first commercial discovery in the Permian basin was made in 1921 at the Westbrook Field (Figure 1). It was followed in 1926 with the 2 billion barrel (bbo) Yates Field (San Andres & Grayburg reservoirs), the 2.1 bbo Wasson Field (Glorieta and Leonard reservoirs) in 1936, and the 1.5 bbo Slaughter Field (Abo and Clear Fork reservoirs) also in 1936. Reservoirs were chiefly high-quality limestones although the Wasson and Slaughter fields also produced from mixed sandstones and limestones that are equivalent to reservoirs in today’s Bone Springs tight oil play.
The Spraberry Field (1949) was the first discovery whose primary reservoir was among the present tight oil plays (Figure 2). Its ultimate production before horizontal drilling was estimated at 932 mmbo. The field had low recovery efficiency of 8-10% and was only marginally commercial prior to the recent phase of tight oil drilling.
Tight Oil Plays
I evaluated the three main tight oil plays. The Trend Area-Spraberry play is located mostly in the Midland basin while the Wolfcamp and Bone Spring plays are located mainly in the Delaware basin (Figures 1 and 2).
The Wolfcamp play has produced the most oil and gas—205 million barrels of oil equivalent (mmBOE)*—and has the largest number of producing wells, followed by the Trend Area-Spraberry and Bone Spring plays (Table 2). All of the plays produce considerable associated gas and only the Trend Area-Spraberry is technically an oil play. The Wolfcamp and Bone Spring are classified as gas-condensate plays based on liquid yield.
The Bone Spring play is the most commercially attractive of the tight oil plays with an estimated $49 per barrel of oil equivalent (BOE) break-even price for the top 5 operators. The Spraberry play has a break-even price of $55 per BOE for the top 5 operators but considerably higher well density and, therefore, lower long-term potential. Results from the Wolfcamp play are mixed with an average break-even price of $75 per BOE for the top 5 operators but $61 per BOE excluding one operator with poorer well performance.
Trend Area-Spraberry Play
I evaluated the 5 key operators in the Trend Area-Spraberry play with the greatest cumulative production and number of producing wells: Pioneer (PXD), Laredo (LPI), Diamondback (FANG), Apache (APA) and Energen (EGN) (Table 3).
I did standard rate vs. time decline-curve analysis for those operators. The matches with production history were generally good as shown in the examples in Figure 3.
Much of the gas production in the Permian basin is irregular because of periodic flaring so matching gas production history was sometimes difficult. Oil reporting in Texas is by lease rather than by well so there are periodic upward excursions of oil production as new wells on the same lease come on line. For these reasons, I feel that the decline-curve analysis results are probably optimistic.
The average Trend Area-Spraberry well EUR (estimated ultimate recovery) for the 5 operators is approximately 265,000 BOE using an economic value-based conversion of natural gas-to-barrels of oil equivalent of 15-to-1 (Table 4). The break-even oil price for that average EUR is approximately $55 per BOE. Laredo has the best average well performance with a break-even oil price of about $43 per BOE and Apache has the poorest well performance and highest break-even price of almost $92 per BOE.
Economic assumptions are shown in Table 5.
Wolfcamp Play
The top 5 producers in the Wolfcamp play are Cimarex (XEC), Anadarko (APC), EOG, Devon (DVN) and EP (EPE) (Table 6).
Examples of decline-curve analysis for this play are shown in Figure 4.
The average Wolfcamp well EUR for the 5 operators is approximately 228,000 BOE (Table 7). The break-even oil price for that average EUR is approximately $75 per BOE. That is because of poor well performance by Devon and EP whose break-even oil prices are more than $100 per BOE.
By eliminating EP from the calculations, the average EUR for the play is approximately 303,000 BOE and the associated break-even price is about $61 per BOE.
Anadarko has the best average well performance with a break-even oil price of about $45 per BOE and EP has the poorest well performance and highest break-even price of almost $177 per BOE.
Economic assumptions are shown above in Table 4.
Bone Spring Play
The top 5 producers in the Bone Spring play are Cabot (COG), Devon (DVN), Cimarex (XEC), Energen (EGN) and Mewbourne (Table 8).
Examples of decline-curve analysis for this play are shown in Figure 5.
The average Bone Spring well EUR for the 5 operators is approximately 294,000 BOE (Table 9). The break-even oil price for that average EUR is approximately $49 per BOE.
Cimarex has the best average well performance with a break-even oil price of about $42 per BOE and Mewbourne has the poorest well performance and highest break-even price of almost $78 per BOE.
Economic assumptions are shown above in Table 4.
Commercial Play Areas
I made EUR maps for the 3 Permian basin tight oil plays using all wells with 12 months of production. I then used the average play EUR to determine commercial cutoffs for $45 and $60 per BOE oil prices using the economic assumptions in Table 4.
Using the calculated EUR-cutoffs for the two oil-price cases, 26% of Permian tight oil place well break even at $45 per BOE, and 40% break even at $60 per BOE price (Table 10).
Current well density was calculated by measuring the mapped area of the $60 commercial area and dividing by the number of producing wells within those polygons. The Wolfcamp has the lowest well density of 1,269 acres per well and, therefore, the most development potential (Table 11). The Bone Spring also has considerable infill potential with 725 acres per well.
The Trend Area-Spraberry has additional development potential but a comparatively lower current well density of 281 acres per well because there are more than 6,000 vertical producing wells within the $60 commercial area defined by horizontal well EUR. These vertical wells have produced 203 MMBOE to date, approximately equal to the 206 MMBOE for all horizontal wells both inside and outside of the commercial area.
Operators routinely stress the large number of potential infill locations in their investor presentations and press releases based on very close well spacing of, for example, 40 acres per well. Although well density is important for determining play life, I doubt that well spacing of much less than 100 acres per well is economically attractive because of potential interference between wells that are drilled horizontally and hydraulically fractured.
Investors should understand that more wells is not better. Superior economics result from drilling the fewest number of wells necessary to optimize production.
Operators also stress the potential for additional potential reservoirs within the same play reservoir. That is undoubtedly true but those are not yet discovered and are, therefore, resources and not reserves of any category based on the SPE Petroleum Resources Management System. If they are so attractive, why haven’t they been drilled and produced already?
Love In The Time of Cholera
Tight oil and shale gas plays emerged at a time of worry and angst about impending resource scarcity and the decline of America as an world energy power. For some, these plays renewed faith in the ingenuity and technology that made America great. Now, there are even widespread delusions about becoming energy-independent and using new-found resources for global political and economic advantage.
Tight oil was a story of bittersweet success because the plays were commercial only at very high oil prices. When prices dropped in 2014, many expected that these plays would collapse. Instead, producers have taken advantage of the lowest oil-field service prices in decades and the plays have emerged as low-cost leaders among important suppliers of the world’s crude oil.
Low oil-field service costs won’t last and neither will the low break-even prices shown in this post. Still, tight oil plays and two of the Permian basin plays in particular, will break-even at lower prices that almost all OPEC producers once fiscal costs are included (Figure 9). The cost to balance a fiscal budget is the equivalent of corporate overhead for a country whose principal source of income is oil.
But just because tight oil is low cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
Since 2009, oil has never been more expensive. The average price in real May 2016 dollars is $83 per barrel, the highest in history (Figure 10). This average includes the year of low oil prices in 2009 after The Financial Crisis and the two years since the mid-2014 oil-price collapse.
Even during the period of the oil shocks from 1974 to 1986, real oil prices were far less averaging $68 per barrel. Today’s price of $48 per barrel remains higher than the average real price of $45 since 1950.
Those who believe that Peak Oil is a failed observation do not understand that it was never about running out of oil. Peak Oil was always about running out of cheap oil. That is an indisputable fact.
The Bone Spring and Trend Area-Spraberry plays of the Permian basin are cheaper than any major world source of oil except Kuwait. They are the best of a bad lot.
Gabriel García Márquez’s masterpiece Love In The Time of Cólera is a story of forbidden love. Cholera is, of course, a disease that comes from infected water supplies and can result in prostration from the loss of fluids (Cólera more commonly means anger or rage in Spanish).
Like a disease, the high cost of energy and debt, its corollary, have drained the life from our global economy over the last several decades. The economic benefits anticipated from lower oil prices after the price collapse did not materialize because prices never stayed low enough for long enough.
The period of high oil prices from 1974 to 1986 created great economic distress for most of the world including the United States. Those who want to make America great again recall the economic prosperity of 1987 to 1999 (Reagan-Bush-Clinton years) when real oil prices averaged only $33 per barrel.
The economic problems that lead up to the 2008 Financial Collapse included high oil prices from 2000 through 2008. The massive new debt incurred to remedy that crisis along with even higher oil prices have thwarted a recovery.
Since the 2014 price collapse, monthly oil prices were less than $33 per barrel for only two months in January and February of this year.
Many talk hopefully about renewed drilling now that oil prices are near $50 per barrel. I doubt that prices will stay at $50 but will, instead, follow the 2015-2016 pattern of cyclicity. Prices should trend higher but I don’t expect a major shift to new drilling or a return to the peak production rates of 2014 and early 2015. The industry is wounded and will not heal for many years if ever.
Tight oil may have bought us a few years of abundance but the resulting over-supply, debt and prolonged period of prices below the cost of production have exacted a terrible cost. Under-investment, a damaged service sector, weak oil company balance sheets and a decimated work force practically ensure cripplingly higher prices a few years in the future.
The calamity of our time of cholera is that we cannot escape ever-higher costs of oil production.
__________________________________________
*I use a 15 mcf per barrel equivalent conversion based on the price of natural gas and crude oil. The conversion based on energy content is approximately 6:1 and is used by most producers to calculate BOE EUR. The EUR reported by producers are, therefore, higher than those shown in this study especially for plays and wells with high gas-oil ratios.
If so, why is investments so high in shale ?
Yoananda,
Yield.
When you can’t get a decent yield on any reasonable investments because of low interest rates, you turn to less reasonable choices that involve risk.
Since when did following the crowd lead to a good outcome?
Thanks for your question,
Art
This is a great analysis, Art. I have just come back from the SPE Forum on Unconventional Reservoirs in San Antonio. Times are tough, but there are several fabulously creative engineers and scientists, who surely cope well.
Thank you, Tad
Tad,
Thanks for you input.
Human ingenuity is a marvelous thing that is often left out of many projections. The cost of the technology that ingenious people employ is also left out in most of their encouraging stories.
The more successful we are at maintaining our astronomical level of energy consumption–never mind the fuel source–the worse the outcome for the quality of life on earth for all its inhabitants. But you know that!
All the best,
Art
Very interesting analysis, and I agree with several of the larger conclusions – e.g., EURs are much lower than “idealized” type curves put out by public producers and breakevens are substantially higher than stated levels. However, your EUR estimates are somewhat lower than mine, and I wanted to get some additional input on how you selected the wells in your study and the period of the EUR (e.g., are these 20-year EURs or life of well? Are these all wells over all times or just over a fixed period? How do you know Trend Area wells are only Spraberry, since, until recently, Trend Area captured all of Spraberry and Wolfcamp?). As you know, there are majo shortcomings in how TX reports its production on a lease, rather than well, basis. Obviously, DI has an algorithm that is supposed to be able to untangle the aggregate into per well flows; however, I have found many substantial errors and so do not trust them fully. What would your analysis look like if you used only single well leases so you knew the monthly production truly represented the results of the well?
Brad,
I use an economic limit of 50 and 2000 mcf per month so there is not a fixed 20 year vs. life of well cutoff. Also, I impose an 8% terminal decline rate. Those two factors probably account for much of the difference between your results and mine.
You are absolutely correct about the reporting–it is a confusing maze and part of the reason that my estimates have varied over time. It is also why I use the term “Trend Area-Spraberry”–I really don’t know what reservoirs are contributing although I believe that Spraberry is the main one.
I also have found DI’s Texas allocation algorithm to have serious problems.
Thanks for your comments and questions,
Art
Interesting analysis. So you have changed your mind about Permian (https://www.artberman.com/less-than-2-percent-of-permian-basin-is-commercial-at-30-oil/), I think EURs you were estimating there before were about half the ones in this article?
Also, what do you think about this data:
http://www.eia.gov/todayinenergy/detail.cfm?id=24932#tab_1
Makes average Permian look way worse than Bakken/EF (and it’s not hz-vertical bug, since almost all wells drilled in 2015 in Permian were hz).
D,
Yes. More information and experience usually gives a different answer. Most of that is more and more recent data but some is learning curve for sure.
I don’t understand your point about Permian initial rates in the EIA link that you sent. In June 2015, about 25% of Permian rigs were drilling vertical well.
All the best,
Art
Interesting article, Art.
Just a few questions:
1. It seems like your D&C costs for the plays are too high in the current environment, by about $1-2M, particularly for the Southern Midland Basin Wolfcamp, where I’ve heard much lower numbers than you use. I wonder if anyone is actually drilling and completing anything in West Texas right now at a $7M price as you suggest.
2. The many old vertical wells in the Spraberry (Trend Area) generally produce from basin-floor fan sands in the Spraberry itself; the horizontal plays have focused on the underlying Wolfcamp B and C and the Spraberry shale (incorrectly assigned to Spraberry (Trend Area) for field rule spacing convenience and other non geological reasons), so I doubt the existing vertical wells significantly mess with the development potential for much of the Midland Basin stuff; people appear to be going around it since it’s producing from different reservoirs than they are going sideways in. Any thoughts?
3. How do your 200-400 MBO type curves square with the 800-1000+ MBO contoured areas on your map that seem to be attracting the buzz? Are you taking the average for your analysis? Do you think the press releases claiming 1000+ MBO EURs are legit? Are they based on more recent results that your analysis hasn’t captured yet, or are they more likely fluff designed to pump up various peoples’ stock prices?
Bryan,
Thank you for your insights especially into the vertical segregation of production in the Trend Area-Spraberry.
The 1 mmboe claims are hard to believe. There are a few wells in that range but I see nothing in the publicly available production data that supports those claims as a trend for any operator for any vintage of wells.
How many wells in the U.S. have ever produced 1 mmboe? How many in the world? I don’t know but it’s way beyond normal.
My guess is that 1 mmboe claim includes all of the stacked potential that hasn’t been tested.
People just want to believe no matter how improbable it seems.
All the best,
Art
“I use a 15 cubic feet per barrel equivalent conversion”
I would bet that you use 15 mcf per barrel.
Clueless,
Thanks for catching that error. The conversion is 15 mmcfg/boe.
All the best,
Art
As expected companies with the highest EUR per well have the lowest “break-even” numbers. But why the difference between companies? Is it because some companies are simply drilling in the better locations. Maybe the got there 1st? Different fracking methods? spacing?
Tim,
It’s mostly about location: some geographies are better than others. But there are differences in drilling and completion methods that are difficult to know about unless you are a working-interest or royalty owner. For example, a friend who is a WIO in another shale play told me about a company that uses significantly less proppant per lateral-foot in their fracks and gets poorer well performance.
Thanks for your question,
Art
It strikes me that as the decline in rigs available eventually levels the playing field, service companies will have better pricing power. Which means that current B-E price is a moving target that will be skating right along as oil prices firm, meaning the oil companies will be hard pressed to increase margins
Terrel,
I agree with you and that is why I stated twice that the D&C costs used in the break-even economics were set when oil prices were $30 per barrel and will increase if prices stay where they are or move higher. Operators talk about efficiency gains but the biggest gain is just oil-field service costs.
Thanks for you comment,
Art
High scientific level post, which is a good point to start a wide discussion, but to my amazement it did not happen. You write, that operators have not broke the “shale code”.
If there was this boisterous “code” it had been broken in 1960s at the first Bakken shale field- the Antelope where the developers understood that they deal with a naturally fractured reservoir and have placed the vertical development wells in the fractured zone. Most of shales are naturally fractured reservoirs which could be not economically developed with carpet drilling, practically without geological foundation.
Simon,
Thanks for your comment. I would expect a wider discussion also but do not find it here or on Forbes that has very broad exposure. When OilPro picks up my posts, there is wider discussion but among mostly oil industry professionals.
It may be that those who disagree with my views/data prefer their beliefs and choose not to engage. That’s a guess and may be very wrong.
All the best,
Art
very detailed objective study!!
I wish to raise an issue though — water production curve in Permian.
I used Enno’s website to calculate the production curves for oil only,
http://seekingalpha.com/instablog/35805355-nuassembly/4889413-production-decline-shale-oil-gas-wells-different-basins
and found Permian has quite fast decline rate, and even though slower than EF, it is much faster than Bakken.
E.g. If you use Enno’s website, Diamondback’s Spraberry wells EUR BO could hardly ever reach over 150K on average.
I believe the reason for the fast drop out in Permian is due to water production, which could effectively raise the bar of terminal boepd production in Permian wells. This bar will vary with WTI prices though, but it will hurt Permian’s EUR. I actually measured the water cut indicator in the produced oil in Permian, not enough number of samples yet, but they obviously pointed to obvious water cut, even though not serious as Miss Lime.
Sheng Wu,
Many thanks for the link to Enno’s website. I am aware that water production in the Permian is a significant cost that is not included in my economics. The reason is that Texas and New Mexico (indeed most states) do not require operators to report water production so the data are suspect at best. Few operators show water disposal costs as a separate item from lease operating expenses in their 10-Q filings (e.g., Laredo has a 10-Q footnote explaining that water disposal is included in LOE and those expenses do not seem anomalous to me).
I believe that you are probably correct about water production as a limiting factor in EUR but without data, there is little that I can do. There are enough skeptics of my work without resorting to water production data that is not operator- and area-specific.
All the best,
Art
nice to hear your feedback!
I believe the cost of water disposal might even be hidden from 10Q, because if the well already producing 1,000 barrel of water continuously each day, the cost to take it will be over $2k, if the oil produced is under 30 barrels at $50 WTI, then it means this well has to be shut down — no more cost to show up in 10Q, but the EUR is stopped short of promise.
I work Arkansas and Oklahoma as a mineral appraiser – mainly for estates – and use a fellow geologist in Ft. Smith to run decline analysis. 10 years ago we did early stage declines in the Fayetteville estimating EURs that were far lower than that touted by Chesapeake and others. As a dry basin, the Fayetteville declines are gas only and thus are less complex than the oil/gas mix of other basins. Today some of those early wells have produced almost double that of our early projections. Even so they are still far lower values than that touted. The wells are producing, many producing modest amounts of water, and since drilling in Arkansas has been reduced to zero rigs since the first of the year, I figure no one is breaking even. The newer wells have higher EURs but the lateral is double the length. So these older wells which are not far above the break even point, may produce a lot more gas, but do so over the next 20 years or more so long as not overwhelmed by water costs. That long tail of production, which you do the DCF back to present value, is basically zero. Who wants to wait 30 years for an income? So even if the original EUR estimates are proven “right”, if half the production comes from beyond year 10, why would you invest?
Terrel,
Thanks as always for your field-oriented perspective.
We re-evaluated the Fayetteville Shale recently and found SWN’s weighted-average well EUR to be 2.2 Bcf based on 2011-2015 well performance. Southwestern Energy claims an average of more than 3 Bcf. If we had included pre-2011 data, our average EUR would have been lower.
So, how do we understand the disparity? SWN is probably using a lower abandonment threshold that prolongs the tail of production but adds no net present value.
We think that it takes 2.5 Bcf to break even at $5 gas prices so you are correct that SWN is losing money at current prices.
You are completely right about the investment aspect of shale plays–why would anyone invest in something that only breaks even in a decade or so? The truth is that people don’t want to understand that. They prefer to believe the propaganda so they can feel good about things. I get a lot of comments on Forbes from people who think that my data and views are ridiculous because they don’t match what they prefer to be true.
All the best,
Art
Great analysis of the Permian. Someone may have already asked this question since I am three or four weeks behind, but I suspect you confused Concho with Cabot. Cabot only has 33 wells in the Permian Basin and many of those are inactive. Concho on the other hand is huge and not mentioned. Read you often and find your work informative. Thanks Mike
[…] and income taxes! Break-even price for Pioneer’s average Trend Area-Spraberry well is about $52 per BOE. I’m sure the Saudis are scared to death about that. Related: Oil Prices Fall Below $40 As OPEC […]
[…] and income taxes! Break-even price for Pioneer’s average Trend Area-Spraberry well is about $52 per BOE. I’m sure the Saudis are scared to death about that. Related: Oil Prices Fall Below $40 As OPEC […]
Art,
Thanks for all the good information and analysis. It is always hard to find a truly objective viewpoint.
However, I would disagree to a minor extent over these not being shale plays. The term ‘tight oil’ is a better description as you use later in the article. The Wolfcamp has obvious source rock characteristics – average TOC (total organic carbon) value through the entire thick interval with some maturity loss is 2.05% with a standard deviation of 0.88 on cuttings (which tend to give lower TOC values). At low thermal maturity these rocks show petroleum generation potentials of 230 boe/acre-ft, again on restored cuttings; these values are likely 400-500 boe/acre-ft if measured on core. Thus, the Wolfcamp has huge petroleum generation at higher thermal maturities as depicted by the higher GOR or CGR values. The fact that the Wolfcamp has good reservoir lithofacies, albeit it ‘tight’, really makes this more of a shale hybrid play, which I define as ‘an organic-rich source rock with juxtaposed non-source lithofacies that requires high energy stimulation to flow petroleum’ (petroleum being both oil and gas). Of course, the Wolfcamp’s overall thickness means a very significant petroleum resource for unconventional as well as conventional production as exhibited over the last 100 years. The Spraberry is similar although not such a potent source.
Otherwise, thank you for the solid information!
Best wishes,
Dan Jarvie
I wrote a comparison of water handling in production cost between Midland PXD and STACK NFX.
http://seekingalpha.com/instablog/35805355-nuassembly/4914375-comparing-cost-water-midland-stack
I think PXD is hiding the real cost. Don’t you hear that Permian is also having more earthquakes now?
[…] the real world, an average Wolfcamp well costs $7 million to drill and complete (Table 1 from my June 2016 post on the Permian basin plays). Average operating costs are about $12 per barrel. Severance taxes are […]
This is an excellent article by a very intelligent person. I have been a wildcattet and oil and gas consultant for over 40 years. My remaining years will be spent on world class conventional oil fields in the Nevada portion of the Eastern Great Basin. Great article.
Thank you, Charles.
All the best,
Art