We saw some key producer Q2 disclosures and analyst comments that should ultimately lead to a pull back on some (not all) of the key inputs to any Permian Basin oil forecast model and these models bringing forward the time when the Permian reaches peak/plateau oil. The Permian oil growth has been the disrupter to global oil markets and no one doubts there will be strong Permian oil growth in 2019 and 2020. Looking to mid/long term, markets generally expect solid US oil growth (driven by the Permian) to continue for several years. But we expect the implications of this week’s Permian insights will lead to a review and pull back to some (not all) of the inputs to their model forecasts. These input questions will inevitably be the #1 focus issue for oil markets/capital providers for H2/19 and 2020 as they try to figure out if the implications mean (i) Saudi Arabia is directionally right (see our July 3, 2019 blog) that Permian oil will reach peak oil supply years earlier than most expect and (ii) Exxon is right (see our June 20, 2019 blog) with their implied 7% decline rate in overall global oil supply. The insights this week reminded us that tight oil plays, like the Delaware, can produce extremely high water/oil ratios from day 1 (ie. brings bigger economic risk to non-sweet spot wells), parent/child well variances are still being understood, increasing strong production rates in sweet spots are being offset to a fair amount by lower non sweet spot wells, some parts of the Permian could be moving to wider spacing (ie. less future development locations) and inventory of Permian DUCs is likely far less than expected. There is no question Permian oil growth is strong in 2019 and 2020, that isn’t in doubt, but it also isn’t the question that needs to be examined. The number one question for oil markets will be if the Permian will have several years of solid growth as currently expected or will it reach peak/plateau years sooner than expected. Hopefully for industry its only a year or two and then that would be a non event. After this week’s disclosures, its hard to see Permian Basin modellers not pulling back on some of their inputs, the question will be if it makes any significant change to when the Permian reaches peak/plateau oil. But even any bring forward to something like Saudi’s longer view of 3 to 4 years will have a major impact on oil markets and outlook. This will be the question to watch in H2/19 and 2020. Sounds like a positive to post 2020 oil. And a positive to tone and sentiment to oil if markets see the potential for a pull back in Permian Basin oil growth inputs.
Expect Permian Basin oil growth modellers to pull back on some of their key model inputs for post 2020 Permian oil growth. Permian oil growth has been the global oil story and disrupter for the past few years. It has surprised to the upside and we don’t believe anyone doubts that the Permian will have strong oil growth in 2019 and 2020. There are many positives to the Permian including the strong endorsement (evidenced by capital allocation) of supermajors like Exxon and Chevron, who see their ability to have several years of Permian oil growth on their assets. We don’t have a Permian Basin oil model, but any Permian model will be based on the same key assumptions or inputs such as decline rates, capital and drilling levels, DUCs inventory, average well rates, oil/water/gas ratios, well spacings, etc. And we can see more questions emerging on some of these key inputs to any mid to long term Permian oil model that, at least for now, should cause these Permian modellers to look at pulling back on some of these key inputs in their models for post 2020 Permian oil growth. For example, later we note the Kayrros analysis that Permian DUCs are potentially >25% less than believed. Unless someone has better data or doesn’t believe Kayrros, this will be a tweak to a Permian Basin forecast model. And if these modellers pull back on some of their model inputs, it will point to Permian reaching peak/plateau sooner than was expected at the beginning of the year. And then the debate will be how much sooner?
Saudi’s Al Falih believes Permian plateau is “in a year or two years or four years”. On July 3, we posted our blog “A Big Plus To Post 2020 Oil If Saudi Is Even Directionally Right That Permian Plateau Is “In A Year Or Two Years Or Four Years” [LINK]. We happened to catch a CNBC Worldwide Exchange interview early that morning (3:45am MT), Saudi energy minister Al Falih said “There will be a plateau for these unconventional resources in the US, the Permian being one of them. is it in a year, or two years or four years, I don’t know but certainly its not indefinitely.” We aren’t aware of anyone calling for Permian plateau (peak oil) in a year or two and even not likely 4. Maybe people didn’t see these comments at 3:45am MT or maybe most assumed it was just musings from al Falih. But we thought it was more than musings because Saudi Arabia is taking a different tactic this time than their normal strategy to get market share. Normally, they would increase oil production, crash oil prices, ruin growth prospects for other oil basins. They want solid oil prices, an increasing oil market share, and strong oil outlook for the mid/long term valuation of Saudi Aramco massive oil reserves for the IPO. But this time, al Falih’s comments suggest they believe that, they can regain market share, by letting US shale play out. If Saudi Arabia is even directionally right in Permian reaching plateau (peak oil), it means that Permian and US oil is going to hit peak oil probably at least a few years earlier than expected. This will be very bullish to oil post 2020. Unfortunately, it may not be possible to fully determine if Saudi Arabia is directionally right in 2019 with the increased Permian takeaway in H2/19. But we expect to this call, or at least the confirming nor discounting views to this call, play out over the next 18 months. There is no certainty that Saudi Arabia will be right and it may just be an educated gamble, but it is something that should be at least considered as the thesis of an earlier than expected plateau in US oil seems to fit to the recent Exxon presentation that implies a ~7% decline rate in overall global oil supply. If these two views are right, it’s a big plus to post 2020 oil prices. Its not just oil prices, there are multiple implications to differentials, Gulf Coast takeaway, pipeline utilizations, Cdn light oil opportunities, etc. At a minimum, this view should at least give people a reason to at least consider the potential for better post 2020 oil prices. We believe that this question will be the primary question for oil markets over the next 18 months. Let’s not forget that Permian oil growth is primary driver for total US oil growth, so any earlier reaching of Permian peak/plateau will directly mean that US oil, in total, also reaches peak/plateau earlier than expected.
Saudi’s US peak oil supply view also fits to the Exxon mid/long term view of global oil supply and demand. Perhaps the key reason why al Falih’s comments stood out for us was because it followed a late June Exxon sellside presentation that included their long term oil supply/demand views. We thought al Falih’s comments on an earlier than expected peak oil supply for the Permian (and the US) fits into the big picture challenge for oil supply in the Exxon outlook. Our June 20, 2019 blog “Exxon’s Math Calls For Overall Global Oil Decline Rate of ~7%, A Very Bullish Argument For Post 2020 Oil Prices” [LINK] said “We believe Exxon presented a very bullish argument for oil prices beyond 2020 and that it has been overlooked because most readers only flip thru a slide deck and don’t listen to or read transcripts of management’s spoken words. Exxon’s spoken words highlighted one of the forgotten (and perhaps most important) oil supply/demand concerns for post 2020 – the mid term challenge to replace increasing rate of overall global oil declines. And what is eye opening is Exxon’s estimated overall global oil decline rate, which is way higher than any we can ever remember seeing. Its impossible to tell from the small oil supply/demand graph in the slide deck, but Exxon’s spoken words says long term oil demand is 0.7% per year and then “When you factor in depletion rates, the need for new oil grows at close to 8% per year and new gas at close to 6% per year.” Exxon may not specifically say what the global decline rate is, but their math is that the world needs new oil supply to grow annually at close to 8% to meet the 0.7% annual increase in oil demand and offset declines ie. an overall global decline rate of approx. 7%. This is an overall global oil decline rate for OPEC and non-OPEC. This compares to BP’s estimate of overall global oil decline rate of 4.5% and we expect most are probably assuming something around 5%, certainly not above 6%. No one should be surprised by the increased decline rate given that high decline US shale and tight oil have increased by ~2.5 mmb/d in the last ~2 years. But an implied ~7% overall global oil decline rate is way higher than expectations. There is a big difference between needing to offset oil declines of ~7 mmb/d vs declines of ~4.5 mmb/d ie. an additional 2.5 mmb/d of new oil supply every year. Even if the implied difference was to 6%, it would still be an additional 1.5 mmb/d of new oil supply and that would also be very bullish for post 2020 oil. We recognize that the 2019/2020 oil supply demand story is the need for OPEC+ to keep cuts thru 2020, but Exxon’s math implying ~7% overall global oil decline rate sets up a very bullish view for oil post 2020. We believe the reality to replace oil declines post 2020 is overlooked.”.
Oil Supply/Demand (moebd)
RJ notes Delaware Basin “initial WORs of 4 or even 6-to1 are viewed as normal” On Monday, we tweeted [LINK] on an excellent Raymond James comment “Energy Stat: What is the Outlook for U.S. Produced Oilfield Water and What Will It Mean for Investors?” RJ notes that “U.S. will be producing a whopping 54 million barrels per day of dirty produced water by 2025 under our outlook for oil production” that will have to be disposed or recycled, and how this could be a “$20B annual market for water recycling, disposal and treatment”. But the RJ comment is much more. When we stepped thru their thesis and data, we thought they were laying out pieces of the puzzle that could support the Saudi Permian view. (i) These high initial water cuts make it more difficult for non-sweet spot or lower rate oil wells to be economic, or at least justify offsetting development. It means that higher water cuts make more wells marginally economic and a lesser number of well locations that will ultimately be developed in the Delaware, an important basin for Permian and US oil growth. (ii) RJ reminds that the big potential Delaware isn’t a shale but a conventional zone that has been unlocked by fracking horizontal wells and one that produces high water cuts from day 1. RJ said “New wells in the Delaware Basin are coming online with water-oil-ratios as high as 10-to-1, a level of water production typically exhibited in a decades-old conventional well. Across the basin, initial WORs of 4 or even 6-to-1 are viewed as “normal.” “WOR” is water oil ratio, so WOR of 4 to 1 means that for every one barrel of oil being initially produced, the well is also producing 4 barrels of water. (iii) Handling huge volumes of salt water mean the differences in returns will be hugely different between good wells (sweet spots) and marginal wells (non-sweet spots). Dealing with very large volumes of water mean will push the economic cutoff of wells to high oil volume levels. RJ also highlights the need for wells to be hooked into water infrastructure as trucking costs can eat away returns and the Delaware Basin has one of the most advanced water infrastructure networks. RJ notes “In the Delaware basin, where water may outnumber oil 6:1, this will be vital. With trucking costing $2-3/bbl of water, trucked SWD volumes could increase operating costs by $12-18/bbl of oil, which would be a massive blow to profitability.” And with the US trucking and driver shortage, trucking costs aren’t likely to go down in the foreseeable future. We don’t have our own Delaware Basin well type curves, but its clear from the RJ analysis that there will be an earlier (in terms of oil rates) economic cutoff than expected by the huge amount of water that has to be moved from a well. (iv) High initial water cuts and high water handling costs in the Delaware should inevitably lead to fewer development locations than originally expected. Don’t forget that water cuts increase over time. Its not that conventional oil zones can’t produce with water cuts over 95%, rather its that the math of moving high volumes of water at an increasing cost per barrel of oil produced tend to lead to an earlier economic cutoff. It also means that high initial water cut plays need a higher initial oil rate to justify development.
Conoco’s Austin Chalk results are a good example of how high initial water cut means high initial oil rates are needed to justify development. Our above concern on how marginal wells (high initial water cuts and not high enough initial oil rates) will eliminate future development locations was illustrated in the Conoco Q2 call on Tues and their Austin Chalk results. The Austin Chalk is another tight conventional zone, like how RJ describes the Delaware. In the Q2 call, Conoco notes its Austin Chalk Louisiana well results to date are disappointing given the high water cuts. Later in the Q&A, they describe it similarly to our discussion above. If you have high water cuts and only marginal oil rates, the play become uneconomic to develop ie. a lot of development locations in the area are now gone. The Austin Chalk is not a pure shale play and has been around for decades. It a tight conventional oil zone that was unlocked with multi stage frack. And is a conventional zone that normally produces water from the get go. In the Q&A, mgmt. “Executive Vice President and Chief Operating Officer. Yeah, it will be a few years before we get to the rig count that will ultimately take the plateau. Yeah. And on the Austin Chalk. Yeah. We’ve tested the three of the four wells that we had to test the Austin Chalk play there and it’s just that as we brought those wells on the petroleum system isn’t working as effectively as we hope but that with the Chalk hasn’t dewatered to the extent that this required to get high enough production rates, I mean, unconventional wells produced a high water cuts and other pleased. I mean the Delaware Basin for example. So that by itself is not disqualifier [ph] for here the water-cut that we’ve seen has been — it’s been a bit over 90%. The oil rates have been about 100 barrels a day. It’s just unlikely to be enough to justify development in that part of the play. Now there are targets in the Wilcox, and there are targets in the Tuscaloosa Marine Shale. So the acreage is not condemned but that the primary target in the Austin Chalk doesn’t look encouraging just now”.
Concho to “test” wider spacing in 2020 on its Delaware Basin – potential to reduce development inventory. The potential for downspacing is looked at a key factor to extend solid Permian growth for several years. But what we saw this week was an example of Concho going to “test” wider spacing in 2020 ie. would reduce the believed inventory of development locations for next few years growth. Concho is viewed as one of the top independents in the Permian. Concho Resources stock was down 22% yesterday (yes 22%) following its Q2 release, in good part from the Dominator downspacing test in the Delaware Basin (Permian) not working. In the Q2 call, mgmt. said “In the Delaware Basin, the 23-well Dominator project was designed to test logistical capabilities and well spacing that was approximately 50% tighter than our current resource assessment. While initial rates were solid, current performance data indicates that we developed the Upper Wolfcamp too densely”. Concho had noted in its Q1 call that this was a test on downspacing rather than the spacing assumed in its resource inventory. Concho abandoned this downspacing. But what didn’t seem to get too much attention was mgmt. saying they will “test” wider spacing 2020 than their normal resource (pre Dominator) spacing. In the Q&A, mgmt. said “Sure, I mean, like I could mention 2019 was the year of testing a number of different things, one of the primary variables being well spacing. So there are still projects to come on in the back half of this year that have, as I stated, modestly down-spaced tests incorporated in them. I think going forward you’d expect us to revert back to that resource spacing, which I think you can generally characterize as across in a section. And then I also would expect us, as move forward into 2020, to also test what densities less than our — that resource spacing looks like as well.” The analysts didn’t probe on this point, but Concho is going to test well spacings less than their previously announced resource spacing 8 to 10 to 12 range? They must be seeing something on their existing resource inventory well spacing to do this. So when we see this, we think this suggests there will likely less development inventory in their Delaware Basin, and a lesser development inventory would likely suggest less ultimate growth than expected.
Permian DUCs inventory is far less than believed, high rate sweet spot wells being offset to a fair degree by more lower rate non-sweet spot wells. This week, we saw some excellent comments from Kayrros in its BNN Bloomberg July 31 interview that provided more color on its July 23 blog “New Satellite Data Highlight Large Underreporting of Hydraulic Fracturing Activity”. The blog and interview provided two key insights to support the Saudi view that Permian peak oil is likely sooner than most expect. (i) Permian DUCs are much less than expected. Permian Drilled UnCompleted wells are viewed as the inventory to support or enhance oil growth over the next few years. Kayrros wrote “Using optical and synthetic aperture radar imagery tracking together with proprietary algorithms to identify rigs and frac crews, Kayrros found that in 2018 alone, more than 1,100 wells were completed in the Permian basin but not reported through state commissions or FracFocus, a public repository for information on the chemicals used during fracking. The total figure of 6,394 completed wells counted by Kayrros for 2018 represents a 21% increase on the FracFocus estimate of 5,272 wells as of June 20, 2019.” The EIA Drilling Productivity Report July 2019 estimates Permian DUCs at 4,002 at June 30, which would be >25% lower including Kayrros data. (ii) Increasing child wells or non-sweet spot wells. Its impossible to precisely determine the split of parent vs child wells or sweet spot vs non-sweet spot wells. The concern being the more of lesser wells there are, the further the play is along the maturity cycle. Core Labs held its Q2 call last week and reminded of a key reality for oil wells “Remember, the decline curve still always wins and never sleeps”. Plays become mature when the impact of good wells are more than offset by the impact of weak wells such that the volume of drilling can’t offset the preponderance of weak wells. The Permian is nowhere near that stage. But its oil productivity per rig has only grown modestly in the last two years. One of the head scratchers for the past two years is why there has been very little change in the EIA’s New Well Oil Production Per Rig for the Permian from its monthly Drilling Productivity Report. It has changed very little in the past two years despite investors seeing consistent quarterly reports noting how longer horizontals and better frack performance has led to many big oil rate wells. The head scratcher is because the EIA has been showing increasing Permian DUCs (ie. wells that aren’t adding to Permian oil production base) yet only modest increase in the EIA’s Permian production per rig. Trying to reconcile this did not make sense. The Kayrros DUCs comments explains why these data points are not consistent – the DUCs aren’t increasing rather Kayrros says “In reality when you get in the full picture of the basin 20% of those wells have gone completely unreported in the Permian basin more than a year later”, “ Well it means that completion activity is much higher than we thought.” If more wells are being completed, it means that the increasing rates of the sweet spots is being offset to a fair degree (not fully) by more lower rate non-sweet spot or child wells. We don’t have the EIA detailed formula, but that’s the only way the math can work, there has to be more non-sweet spot wells dragging down the impact of big rate Permian wells.
EIA: Permian Drilled UnCompleted Wells At June 30, 2019
EIA: Permian New-well oil production per rig
A focus on key Permian oil growth model inputs should also bring a better tone and sentiment to oil. We do believe Permian Basin modeller have to at least review some of their key inputs in light of these new insights ie. starting point for Permian DUCs. We expect input review will be the question to watch in H2/19 and 2020. The Permian Basin oil growth has been the disrupter (to the negative) to oil markets. And if markets see an increasing focus on reviewing some of the key Permian Basin input to see if there will be a pull back, it should lead to an increase tone and sentiment to oil.