It should be a big focus week on US shale oil growth potential with the convergence of global oil leaders, including OPEC, in Houston for CERAWeek. US shale surprising to the upside in 2017 was the supply shock to oil markets and forced OPEC to continue cuts in 2018. The key question for oil markets is how long can the US players keep getting bigger and better wells as the cause and effect formula is that bigger and better wells leads to stronger than expected oil production. The IEA just issued its Oil 2018 (5 yr forecast for oil) estimates US oil supply is +2.7 mmb/d and oil/NGLs +3.7 mmb/d from 2017 thru 2023, but the IEA forecast includes US oil growth essentially stopping after 2021. We expect that global oil markets are going to leave Houston with a view that US oil growth will continue to be very strong at least in 2018 and 2019 with a clear impression that US shale oil wells will be bigger and better in 2018. The key assumption for lower YoY US oil growth post 2020 is that wells don’t get keep getting bigger and better. It is why we believe there may be a more important, question that is being overlooked by everyone and likely to not get headlines this week – can EOR be successful in more than the Eagle Ford shale oil? Because if so, this can be a game changer for US shale and set up a view that the US can keep growing post 2020 and not that it stops growing as soon as the wells don’t keep getting bigger and better every year.
All eyes on US shale oil this week with CERAWeek in Houston and the takeaway is likely US shale wells will be bigger and better in 2018 and there is upside to 2019 oil growth. The current major energy agency views are that US will have very strong oil growth in 2018 and lower oil growth in 2019. We think one of the takeaways from CERAWeek will be that there is likely upside to US 2019 oil growth. The EIA’s Short Term Energy Outlook estimates US oil growth of +1.26 mmb/d YoY in 2018, but only +0.59 mmb/d YoY in 2019, and today’s IEA outlook estimates US oil growth of +1.28 mmb/d YoY in 2018 and +0.81 mmb/d YoY in 2019. CERAWeek starts today in Houston and this means all of the major global oil players, including from OPEC, will be converging in Houston. It may officially be CERAWeek, but it will akin the US shale sector holding an investor day for all of the global oil leaders and watchers at a range of offsite meetings and presentations. We expect that the theme of this US shale investor day to be that the US shale oil story is still getting bigger and better wells in 2018, continuing the same trend as in 2017. The game changer for oil in 2017 was the ability for US shale oil to grow at faster rates even with oil ~$50. It forced OPEC/Russia to extend the cuts into 2018 and is now forcing them to continue the cuts (at some level) into 2019. US oil production has surprised to upside, driven by technology being applied in increasingly better and more effective ways – primarily from a series of completion improvements, bigger fracks, more proppant per well, and especially longer lateral well length. Each of these completion advancements has helped on a step by step basis to increase well rates and recovery. The below table shows the EIA has consistently increased its forecast for US oil production in almost every month for the past year.
EIA Estimated US Crude Oil Production By Forecast Month
The major micro data points will be US shale oil wells keep getting bigger and better. Our weekly Energy Tidbits memos [LINK] have noted how Q4 earnings calls that the US shale players are essentially all calling for bigger and better wells in 2018 vs 2017. They may not see the same YoY service cost decreases, but expect the YoY bigger and better wells to drive strong oil growth in 2018 vs 2017. The stronger and stronger Permian oil wells are well known and are being seen across the board. But not getting as much attention is that industry is getting better and better wells in other plays like the Bakken and Eagle Ford. Marathon Oil’s recent Q4 call highlighted its view for even stronger drilling in 2018. Below are Marathon Oil’s Q4 call slides on its Bakken and Eagle Ford wells that show 2017 wells were significantly higher than 2016.
Marathon Oil Bakken Wells (Above) and Eagle Ford Wells (Below)
Source: Marathon Oil
The post 2020 oil forecasts assume marginal oil US oil growth and US no longer getting bigger and better wells. The IEA’s new oil forecast is an excellent example of the worry that US oil growth will be stopping soon ie. once they stop drilling sweet spots and stop getting bigger and better wells each year. Despite the headlines on the IEA’s forecast of strong US oil growth, the IEA only has marginal US oil growth after 2020, which implies US per well results not getting bigger and better in 2018 or 2019 at the latest. The IEA estimates YoY US oil growth of 1.28 mmb/d in 2018, 0.81mmb/d in 2019, 0.41 mmb/d in 2020, 0.21 mmb/d in 2021, 0.09mmb/d in 2022 and a decline of 0.05 mmb/d in 2023. This is the cause and effect – bigger and better wells lead to growth, hence a stopping of that cause means that US oil growth will be less than expected. And the assumption that US shale oil wells can’t keep getting bigger and better for the next couple years is likely a key assumption for OPEC/Russia in their cuts. A key part of this assumption is that shale players are only drilling sweet spots and it is inevitable to drill more marginal wells outside the sweet spot. Its hard to disagree with the basic thesis but we remind that the density and stacking of wells means that the sweet spots have materially more wells than conventional wisdom and technology developments like micro proppants are increasing well rates and recovery. However, there will be a point when wells don’t keep getting better and, right now, it is primary reason for forecasts that US oil production turns to declines sometime post 2020. When will US shale wells stop getting bigger and better performance YoY, will it be in 2019 or 2020 or 2021? It isn’t a new question and there will be support for the IEA’s view of only marginal US oil growth post 2020 based on comments from well known Centennial CEO Mark Papa. In the Q4 call Q&A, he replied “I think that we’ve now reached a point where we’re getting our laterals in zone like 96% of the lateral we just were supposed to be generating and we’re now up to between 2,500 and 3,000 pounds of proppant per foot, and we’re 100% slick water. So, I think that we’ve done a lot over the last year to get our frac technology and our completion technology to state-of-the-art. And that is showing in our relative well results that we’ve got several slides in our presentation compared to other companies. But I’m just not convinced that over the next two or three years, you’re going to see a continued improvements of 10% or 15% per year per year per year in per well productivity or per foot productivity because I’m not sure where we go next with frac technology or completion technology to get such improvements”. As an aside, Papa’s reply reinforces why we say the best sector insights come from the Q&A and not mgmt’s prepared remarks.
But there is an overlooked very important linked question for 2018 – is the “cause and effect” formula changing? We think it is and will help US oil growth post 2020. Maybe we are off the mark, but we are a little surprised by the lack of focus or interest in looking to see if the cause and effect formula is changing, or if the assumptions to the formula are changing. We think we could be seeing a change in the key base assumption – decline rates. The bigger and better wells are needed for growth theory is based on the assumption that base shale decline rates are high and not changing in a material way. We aren’t suggesting the high decline rates inherent in shale wells are changing, but we are seeing the indications that decline rates can be dramatically reduced and not just by restricting the flow rates If so, it means that the amount of new production needed to be added to replace declines is less, and therefore growth may not have to rely on bigger and better wells each year.
How is this done? EOR using engineered gases is working in the Eagle Ford for EOG. What is now clear is that there were successful EOR using engineered gases tests by EOG in the Eagle Ford. Last summer, we gave our non-technical description that these scientifically engineered gases (SEGs as Core Labs calls them) interact chemically with the shale oil to increase the percentage of shale oil that is moveable thru the opened fracks. EOG’s Q4 call slides noted that the testing period (56 wells on EOR) is over and EOG is in the implementation period of increasing the number of wells that it converts to EOR. EOG held its Q4 call last week and highlighted that its Eagle Ford is their best return wells, better than the Permian and very high ATROR. EOG noted the ATROR at WTI $50 and HH $3 was 143% for the Eagle Ford vs 115% for the Permian. The overlooked part of EOG’s Q4 disclosure was that they are ‘implementing enhanced oil recovery program” in the Eagle Ford, “converting 90 wells to EOR in 2018 vs 56 in 2017” and the EOR results in “incremental reserves 30%-70%”. EOG’s Eagle Ford typical well has EUR of 580 mboe before royalty and 450 mboe after royalty. This means that EOR can add 174 to 406 mboe before royalty and add 135 to 315 mboe after royalty. This is a huge lift to recoverable reserves.
EOG only expects the Eagle Ford EOR to be >30% ATROR, but we still see it as game changing. EOG did not provide any detailed production curve or economics for its EOR in the Eagle Ford, but noted that the EOR generates incremental reserves of 30%-70% gives the EOR an ATROR of >30%, which is way less than the ATROR of the Eagle Ford wells of 143%. It is nothing to get excited about based on ATROR, but EOG also disclosed the EOR has a PVI of >2. EOG did not provide updated PVI for its Eagle Ford 143% ATROR typical well, but in looking at its H2/17 presentations, the PVI for these big Eagle Ford wells is likely around 1.4x. PVI is “Net present value divided by capital investment”. This correlation of ATROR and PVI for EOR vs regular wells is what we would expect to see. A shale well has big initial production, recovers its capital quickly, but with big declines the ultimate NPV is only a modest multiple of the capital invested. Whereas an EOR conversion’s big change to the production is that it flattens out the decline curve for a long period, so it recovers so much more oil that the NPV of the EOR is >2 times the capital investment. Its too bad they don’t provide the changed production curve but the big lift in incremental reserves supports a significant reduction in decline rates for several years. The more that EOG can flatten the decline in more wells, the less produced production EOG has to replace each year to stay flat and therefore to grow. It is why this is a game changer and if EOR is working like EOG is suggesting and can work in other shales, US will not need bigger and better wells each year to keep growing. The assumption for the cause and effect formula will be changed.
This is not a new development, Core Labs identified a year ago how EOR in shale with engineered gases was a major trend shaping tomorrow’s oil field. In Core Labs Q1/17 call, mgmt. highlighted four major trends that were reshaping tomorrow’s oil field. CLB’s first trend was enhanced oil recovery (EOR) from shale/tight oil reservoirs. The EOR themes are primarily focused on using scientifically engineered gas (SEG) absorption techniques, gas cycling and the “laws of physical and thermodynamics”. Our June 30, 2017 blog “New” Technology Is Working And/Or Increasing In Application To Increase Oil Recovery From Shale/Tight Oil” [LINK] noted CLB’s sell side presentation that week and how it was expecting the first EOR in shale field tests later in 2017. Its now clear it was EOG and it worked.
EOR won’t get much attention this week, but it will be a key factor to supporting US oil growth post 2020. We believe shale players will want to add as much EOR as they can as it makes a more sustainable shale growth model, which is one of the key sector themes – value over volume. Successful EOR with economics to EOG’s EOR model can be layered in given the strong short term cash flows of non EOR shale wells. EOR cannot change the decline rate overnight but over time can materially reduce decline rates. Absent a change in the cause and effect formula decline rate assumption, US oil growth will likely decline as being projected ie. a lagged impact once industry stops drilling bigger and better wells each year. But with EOR layered in over time, it means that decline rates will be reduced, less produced reserves to replace each year, and therefore shale wells don’t have to get bigger and better each year for US oil to grow. Also if EOR works and can be layered in, it will provide visibility to a longer time horizon for investing capital in the US oil and gas sector.