- August 18, 2015
- Posted by: Art Berman
- Category: The Petroleum Truth Report
E&P companies have added 30 horizontal rigs in the Permian basin since the end of June. Most analysts didn’t notice (Figure1).
Figure 1. Tight oil horizontal rig counts since January 1, 2015.
Source: Baker Hughes & Labyrinth Consulting Services, Inc.
(click image to enlarge)
Rig counts in most active plays are stabilizing after falling more than 50% since November but companies are adding rigs in the Permian like there’s a boom going on. Last week the total U.S. rig count was unchanged but 7 new horizontal rigs were added in the Permian. In fact, rigs were added in each of the last 7 weeks there.
There have been a lot of silly pronouncements since oil prices collapsed about how rig counts don’t matter anymore. Pad drilling and extraterrestrial advances in rig efficiency have made rig counts a meaningless measure. Also, the backlog of deferred completions allow companies to add production without adding new rigs. So we are told.
But rig counts matter because they show where capital is going. When a rig contract is signed, major cash follows and usually, for a long period of time.
When capital in the oil business is scarce, a counter-flow of 30 new rigs into one play says a great deal about how company executives view that play. 30 new rigs in the Permian basin means more than $200 million in capital expenditures if all the rigs are released after drilling just one well and no further spending occurs as a result of the drilling.
Since rig counts began falling in November 2014, there have always been more rigs in the Permian than in any other tight oil or shale gas play (Figure 2).
Figure 2. Tight oil and shale gas rig counts as of August 14,2015. Source: Baker Hughes & Labyrinth Consulting Services, Inc.
(click image to enlarge)
More rigs have also been released in that play than in any other. Still, there are more than twice as many rigs drilling in the Permian as there are in the Eagle Ford Shale, and almost three times as many as there are in the Bakken play.
Rig count is how company executives vote on the plays.
We may hear great things about the potential of the Utica Shale but it’s in the lower third for rigs and, therefore, capital. Studies proclaim that the Barnett and Fayetteville core areas are commercial at current gas prices but almost no one wants to put rigs there and spend money. Even the mighty Marcellus is a distant fourth in rig count behind the Permian, Eagle Ford and Bakken.
There is a reason and it is profit or the perception of profit and rig count is how we know the score.
For plays like the Eagle Ford and the Bakken, the best leases were taken long ago. If you don’t have a position, the only way to get one is to buy or join someone else at a premium (e.g., Devon and Encana in the Eagle Ford).
But the Permian is different. It is an old producing basin whose glory days were decades ago until tight oil technology came along. As a result, the land situation is complex and fragmented and there is usually a way to get in on a lease or a play with a good landman and enough money.
There are multiple pay horizons in the Permian whereas, in the Eagle Ford and Bakken there is basically only one pay zone. In a comprehensive study done in 2000, Shirley Dutton of the Bureau of Economic Geology identified 32 different oil plays from 1,339 significant reservoirs in the Permian basin and each reservoir with cumulative production greater than 1 million barrels of oil.
The Bakken and Eagle Ford are dominated by a dozen or so substantial public companies but in the Permian, there are hundreds of operators, many of whom are small and privately held, and some that are without access to the major capital required to be a shale player. To put it bluntly, the Permian is a great place for tight oil have-nots to find a home. Deals can be made in the Permian.
How Good Is the Permian Basin Anyway?
EOG Resources and Pioneer Natural Resources have strong positions in the Permian basin, Eagle Ford Shale and other shale plays. Their CEOs have very different views on how good the Permian basin is.
EOG CEO Bill Thomas spoke in May 2014 at the Sanford C. Bernstein Strategic Decisions Conference about the Permian basin:
“…the Permian is a great place to drill wells… But it’s not the play quality, the rock quality and the technical aspects of the play are not nearly as strong as Eagle Ford or the Bakken. And it will not be able to maintain this dramatic growth rate that we have had historically in the country. And it will not be able to replace an Eagle Ford or a Bakken.”
Pioneer CEO Scott Sheffield spoke about the Permian basin in August 2013 at the Unconventional Resources Technology Conference (URTeC) in Denver:
“The Spraberry Wolfcamp could possibly become the largest oil and gas discovery in the world.”
So, How good is the Permian, anyway?
The horizontal plays in the Permian basin are not shale plays. They are purely conventional sandstone reservoirs that were discovered decades ago and are now being exploited using horizontal drilling and hydraulic fracturing.
The recent rig additions in the Permian basin are directed chiefly at the Trend Area and Bone Spring plays (Figure 3).
Figure 3. Permian basin recent rig additions by play for the 6 weeks ending August 14, 2015.
Source: Drilling Info., Baker Hughes & Labyrinth Consulting Services, Inc.
(click image to enlarge)
The Trend Area is located in the eastern Midland sub-basin of the greater Permian basin, and the Bone Spring play is located in the western Delaware sub-basin (Figure 4).
Figure 4. Permian basin location map showing Delaware and Midland sub-basins and the locations of the Trend Area and Bone Spring plays. Source: Drilling Info, Murchison Oil & Gas, Inc. and Labyrinth Consulting Services, Inc.
(click image to enlarge)
I studied the Bone Spring and Trend Area plays by evaluating well performance for the major operators in each play. I used standard decline-curve analysis to determine estimated ultimate recovery (EUR) by operator for wells with first production in 2012, 2013 and 2014.
My analysis suggests that Bill Thomas has the more accurate assessment of the Permian basin based on reserves and economics for these two leading plays. In other words, it’s not as good as the Eagle Ford or Bakken but it’s a pretty good place to have a position for when oil prices are higher.
The average well EUR for the major operators in the Bone Spring play is 236,000 barrels of oil equivalent (boe) and, in the Trend Area, 158,000 boe. Costs are comparable to the Eagle Ford Shale and there, the break-even EUR is 350,000 boe at $70/barrel WTI oil price (full-cost economics but not including land). The difference is that, in the Eagle Ford, there are significant areas with EUR greater than 350,000 boe. Fewer than 1% of Bone Spring wells and no Trend Area wells meet this criterion.
Bone Spring Evaluation
In the Bone Spring play, I evaluated wells by Concho, Devon, Cimarex, EOG, Mewbourne and Yates. Results are summarized in Table 1.
Table 1. Bone Spring EUR (estimated ultimate recovery) summary table showing oil, gas and barrels
of oil equivalent (boe) and weighted (WTD) averages based on the number of producing wells with
first production in 2012, 2013 and 2014. A price conversion of 16.67:1 (using $50 oil and $3 gas) was used to
convert mmBtu/mcf gas to barrels of oil equivalent. BS=Bone Springs.
Source: Labyrinth Consulting Services, Inc. with production data from Drilling Info.
(click image to enlarge)
Concho had the best average well performance followed closely by EOG, and Mewbourne had the worst. Overall, well performance based on weighted average EUR varied 30% above and 34% below the mean by the highest and lowest performing company.
Average well performance improved about 22% in 2014 compared to 2012 and, for Concho, Devon EOG and Yates, average well performance improved by about 37%.
The decline-curve trend matches were generally excellent for the Bone Springs (Figure 5) providing a high level of confidence in the EUR values shown in Table 1.
Figure 5. Examples of Bone Spring decline-curve analysis showing group decline for Concho (COG) wells
with first production in 2012 and for Cimarex wells with first production in 2013.
Source: Labyrinth Consulting Services, Inc. with production data from Drilling Info.
(click image to enlarge)
Trend Area Evaluation
In the Trend Area play, I evaluated wells by Apache, Energen, Encana, Laredo, and Pioneer. Horizontal drilling in the Trend Area does not have as much history as in the Bone Springs so only 2013 and 2014 data were available to evaluate and, for some operators, there was only 2014 data. Results are summarized in Table 2.
Table 2. Trend Area EUR (estimated ultimate recovery) summary table showing oil, gas and barrels
of oil equivalent (boe) and weighted (WTD) averages based on the number of producing wells with
first production in 2013 and 2014. A price conversion of 16.67 (using $50 oil and $3 gas) was used to
convert mmBtu/mcf gas to barrels of oil equivalent . Trend=Trend Area.
Source: Labyrinth Consulting Services, Inc. with production data from Drilling Info.
(click image to enlarge)
Encana had the best average well performance and Pioneer had the worst. Overall, well performance based on weighted average EUR varied between 49% above and 27% below the mean by the highest and lowest performing company.
Apache’s average well performance improved about 14% in 2014 compared to 2013, and Pioneer’s wells improved 6%. Laredo’s average well performance decreased by 27%.
The decline-curve trend matches were generally fair for the Trend Area, as shown in Figure 6, providing only a moderate level of confidence in the EUR values shown in Table 2.
Figure 6 Examples of Trend Area decline-curve analysis showing group decline for Laredo wells
with first production in 2012 and for Apache wells with first production in 2013.
Source: Labyrinth Consulting Services, Inc. with production data from Drilling Info.
(click image to enlarge)
“The best places to find oil are in places where it’s already been found.”
Simmons & Company International recently published average well EUR for the Bone Spring play as 676 boe. If you believe that number, there is no mystery about why companies are adding rigs in the Permian. Let’s assume for now that I am closer to the truth than Simmons (they don’t explain the source of that EUR).
Neither the Bone Springs nor the Trend Area are commercial unless oil prices return to $100 per barrel using full-cost economics. Even using phony shale half-cycle economics, prices have to be much higher than anyone’s forecast for the next several years.
Here are the players who have contracted rigs in the last few months:
Figure 7. Latest Permian basin rig contracts. Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)
Most of the companies are relatively small independents whose sole business is the Permian basin. Many don’t have access to enough capital to compete in the real shale plays. Or maybe they were never really sold on shale, and are more comfortable with a good old-fashioned sandstone reservoir. But, if you’re selling a prospect that has horizontal drilling and hydraulic fracturing, it sounds enough like a shale play to attract some capital.
Of the larger independents, Oxy, Concho and Apache are Permian-focused companies. The others–Pioneer, Devon, EOG and XTO–are companies with relatively strong balance sheets and diverse unconventional portfolios that are able to bet on the future.
The Permian basin probably has the lowest risk of all the tight oil plays because its reservoirs are purely conventional and there are multiple stacked pay intervals all charged with oil because the basin’s petroleum system is among the best in the world.
The Permian basin has been a large-scale enhanced oil recovery (EOR) project since I began my career in the oil business almost 40 years ago. The basin is blessed with more than 1000 high quality reservoirs and cursed because most of them have limited lateral continuity. For all the oil that’s been found, there is an undrained reservoir volume a stone’s throw from wherever you are. Horizontal drilling may be the holy grail to unlock those tens of billions of barrels that are stranded in real reservoir rock and not in a source rock like shale.
Perhaps that is Scott Sheffield’s vision for the Permian basin.
If you’ve bet your company on unconventional plays and the plays are not economic today, there are really only two choices: go out of business or double down on the opportunities you have and hope that higher prices will save you. The Permian, where the reservoir is not shale, may end up being the best tight oil play out there for the long term.
Art,
Thanks as always for another excellent post! I always enjoy reading your work.
You didn’t mention one of the common rationales for the “rig counts don’t matter any more” argument, i.e. the assertion that there is now such a wide gap between the most modern/efficient/productive rigs and the old clunkers that are still in service but not nearly as efficient as the newest rigs.
I’ve heard that argument from quite a few analysts, but I don’t know enough about it to gauge how real this gap in productivity is between the best and worst rigs in service really is. Art, would you care to share any insight on how credible this agrument is?
A a fund manager, I couldn’t agree more with your sentiment that what really matters here is how much capital (measured in dollars) is being committed to new projects. It seems to me that the BH rig count has always been an imperfect measure of capital commitment and now it’s getting even more imperfect. Maybe you should invent a better mousetrap – the Art Berman Capital Commitment Index or somesuch, that measures not the number of rigs but rather the amount of capital commitment they truly represent. It sounds like you have access to enough data to model CAPEX commitments, which would be far more interesting to us financial types than how many rotary drilling rigs are in operation.
All the best,
Erik
Hi Art,
Excellent post. I agree with you here in mostly all aspects. The economics of the Permian (especially Midland Basin) never looked particularly attractive to me.
Bone springs appears to have some decent sweet spots which may generate return. Two Georges field that straddles Reeves/Ward? This play is analogous to Spraberry in Midland correct?
Oxy, Cimarex, Concho and BHP are drilling the Wolfcamp (Phantom). The fairway looks relatively slim, basically traversing Reeves/Ward/Loving county line. Economics appear on par with Bakken/EF here. Perhaps exceedingly so. Interesting to see how much new rig activity is targeting this interval.
Hi Eric,
I’m enjoy reading your thoughtful comments on Art’s blog. Maybe there could be an index comprised of month to month drill bits sold in a basin. To my thinking, it’s the amount of footage drilled and good rock vs. bad rock the rather than “rig efficiency” that really matters.
Incidentally, one of my favorite you tube videos is titled ” Extraordinary Popular Delusions And The Madness of Crowds”.
Thanks for the kind words, John.
Art, to expand my question, what in your opinion is the most meaningful way to measure how much dumb money is still pouring into the shale patch mal-investment? While I agree that rig count still “matters”, it’s clearly an imprecise measure.
John’s idea about measuring drill bit sales seems very interesting, but I fear that drill bits SOLD does not necessarily equal drill bits CONSUMED because it would be entirely understandable for shale operators to stock up on consumables now because they know their funding sources will dry up soon.
BTW, my suggestion was entirely serious: Everyone on wall street watches the rig count because it’s all we’ve got. Art, you’re clearly smart enough to invent a better mousetrap for this need. One that takes into account the “fracklog” of incomplete wells, the differences between rig efficiencies, etc. I hope you will! What we really care about is how much “supply creation” is really occurring. Rig count offers a very poor approximation. I think you could design a much better model and sell the data just like API sells their inventory data.
Erik
How many wells in Bakken and Eagle Ford have been drilled, but not completed and how long will it take until all these wells are producing?
Matt,
There is no way to estimate the uncompleted wells in the Eagle Ford but the latest Directors Cut release from the North Dakota Department of Mineral Resources says:
“At the end of June there were an estimated 848 wells waiting on completion services, 60
less than at the end of May. The current rig count plus NC well inventory is sufficient to
maintain 1.2 million barrels of oil per day for 24 months.”
There were 185 well completions in June which was an increase of 51 from May. If only existing uncompleted wells were completed at the quarterly average rate of 140/month, it would take 6 months to work through the backlog. You can do your own guesstimate of how long it will take with a rig count of 73 but it will be at least a year but we need to see how many of this backlog is completed to meet the 1-year deadline for completion to receive a ND tax benefit (part of the reason for the increase in June completions).
All the best,
Art
Art,
I love your thoughtful, balanced, and data rich columns. It would seem that the EUR’s you have calculated show that at these oil prices, capital has been betrayed.
My question concerns the GOR in your plots. I’ve come across charts by Enno Peters that show the Bakken GOR really spiked beginning about the time that oil’s price slide began and is now up by 30%.
You charts show a very flat relationship over time. The question is, does a spiking GOR indicate that wells are being opened up (to produce more oil revenue for strapped companies?) and what does that indicate about the future prospects for those wells? Is EUR/well integrity being damaged by this practice or do we not know enough about shale wells to tell?
Hello Art,
Please help me out here. I am having some difficulty understanding how your mcf gas to BOE conversion works. For instance, in Table 1, the average Bone Springs well produces 700,735 mcfg but this only adds 11,679 BOE (205,158 – 193,479). How does this equate to a 16.67 to 1 ratio?
Thanks for your help.
Gary
Gary,
Thanks for the question. If you look in the captions below the tables, I explain that it is a value conversion using $50 oil and $3 gas (16.67 mmBtu/mcf per barrel equivalent). It is a fairly common way to express a market relationship based on price rather than energy (Btu) equivalents. The 5.7 conversion has never reflected anything close to the price relationship in my career.
All the best,
Art
Don’t you mean 16.67 mcf per barrel? That would make a huge difference in your BOE calculation.
Gary,
Thanks for the question. If you look in the captions below the table, I explain that it is a value conversion using $50 oil and $3 gas (16.67 barrels per mcf). It is a fairly common way to express a market relationship based on value rather than energy (Btu) equivalents. The 5.7 conversion has never reflected anything close to the price relationship in my career.
All the best,
Art
Gary,
Yes, my first sentence was correct but I transposed the numbers in the second.I have made the corrections in the post. The difference is not huge, it’s about 14%. Important to correct.
Many thanks.
Art
Art,
These horizontal rigs will not add a single barrel of new reserves to the PB but will accelerate depletion. It is extremely frustrating to see the wasting of economic resources and physical resources over the last several years. Flaring enormous amounts of gas throughout the PB just to accelerate oil production literally makes my blood boil.
The TX RRC NM OCD has completely ignored this issue even though it is a primary reason for its existence. Every one know why this happened……Tx and NM want tax revenue and the elected politicians carry the water for these unconventional companies and ultimately it will cost all of us.
John,
The issue of reserve addition vs. rate acceleration was on my mind as I did this evaluation but I decided to leave that for a later study as this one was getting fairly time-consuming for a blog post.
How much gas is being flared vs. the gas reported to the TX RRC? That could change the EURs.
Thanks for your comments,
Art
Just went over this again and looked up Simmons International’s transaction list:
http://www.simmonsco-intl.com/Investment-Banking/Transaction-History/
unbelievable. will this people go to jail for posting things like average Mboe in Bakken 500-600?! i don’t think so, but they definitely should.
Che,
I have no idea how analysts like Simmons determine average EUR but I know how I do it and would gladly defend the methodology as far as the publicly available production data goes.
I just published a post on the Bakken today. Although I did not include an average BOE EUR for the 7 leading operators that I evaluated, I just did the calculation and it is 414 MBOE.
All the best,
Art
A wave of articles in press about Permian
http://www.ft.com/intl/cms/s/0/653e5ec0-8c3d-11e5-a549-b89a1dfede9b.html
what do you think is the resource there realistically, if not 75bboe the pioneer is touting?
Che,
The Permian hype is evidence of increased desperation by producers to distract investors from the obvious truth that no one can make any money at current oil prices.
Please recall my August evaluation of two of the leading plays in the Permian basin. Using EOG’s best year for the Bone Spring–one of the reservoirs that they hype as having more than 500 million barrels of additional potential–I calculated 307,000 barrels of oil equivalent vs. their claim of 1 million boe per average well. The play is very gassy so the gas-to-barrels of oil equivalent makes a difference. I used a value conversion of 16:1 based on the price of oil and natural gas. If you use 6:1 as the companies do in their calculations, EOG’s best year is 567,000 barrels of oil equivalent. Could I be off by a half to two-thirds? Unlikely.
EOG is an interesting case because in their investor presentation, they claim to be making a 45% rate-of-return on the Bone Spring. Yet, they took a $4 billion impairment write-down that means they are not making the minimum 10% rate-of-return required by the SEC to avoid the write-down. They will say that the 45% ROR is on their better plays and the impairment was on their worst plays. It still points out the fact that they are telling investors one thing and the SEC another.
Reading the fine print, it is clear that EOG’s measure of ROR only includes capital expenditures. As always, we must ask when we hear things that sound too good to be true, What costs are you excluding?
Also, the write-down does wonders for ROR because they no longer have to carry the burden of all the DD&A of those lousy assets.
In their press release on 3rd quarter earnings, they say that they are hedged at almost $90 per barrel. Reading closely, we find that this applies to 10,000 bopd. Sounds good until we learn later on that this represents less than 4% of their 278.3 mbopd domestic oil and condensate production!
When they claim a billion barrels of potential new recoverable resources, we must be mindful of their language. Potential means it doesn’t exist today. Recoverable resources means it has nothing to do with economics. So it may not be real and, if real, much of it is not commercial.
Pioneer has been telling us tall tales about the Spraberry for a few years. On their website, they call it “the world’s second largest resource,” second only to Ghawar, the world’s largest oil field! Again, pay attention to the language. Same B.S. as above.
Here is a quote from Pioneer’s latest investor presentation:
“In this presentation, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil in place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit Pioneer from including in filings with the SEC.”
A colleague from the SEC came to a talk that I gave last week in Fort Worth. We talked about a meeting that I had with him and some others at the SEC a few years ago. He asked if I thought that the meeting was useful. I told him it was because now the shale companies tell you when they are lying whereas before, they just lied.
EOG and Pioneer are among the better of the U.S. E&P companies based on the quality of their positions and their financial states (I own EOG stock). If companies this good feel that they need to do what I consider misleading investors, imagine what even more desperate companies might do?
All the best,
Art