Natural Resource Market Commentary 3 rd Quarter 2017

Transcription

1 Natural Resource Market Commentary 3 rd Quarter 2017 Introduction Brace for another steep and sudden drop in Oil Prices Commodities Column, Barrons, August 14, 2017 BHP chairman say $20 billion investments in shale was a mistake. Reuters, June 29, 2017 A Commodity Superpower Asks What if India Turns Out Like China? Bloomberg News, October 5, 2017 We have so much to discuss in this letter that it s hard to know where to start. Global oil inventories continue to draw rapidly and we have now reached the point where further drawdowns will put severe upward pressure on prices. Oil production from the US shales has slowed significantly in the last six months, taking the energy analytic community by complete surprise, and evidence continues to emerge suggesting India is now entering its period of accelerated commodity consumption (a subject we discussed at length in our last letter). Each makes for a great story and, we will cover these topics in depth. But first, it is imperative to discuss the inventory situation today and its historical impact on oil prices. We are being presented with the buying opportunity of a lifetime and we want you to clearly understand the reasons why. Despite continued rampant bearishness, global oil demand continues to significantly exceed supply and global inventories are now drawing at record rates. Back in January, our models told us the energy analytic community was significantly underestimating demand. We wrote, the world oil markets will end up severely under-supplied by over 600,000 b/d during At the time, few in the energy analytic community agreed with anything we wrote. However, a funny has happened as 2017 has progressed. After a brief build in January and February, oil and product inventories (both here in the US and globally) have in fact drawn down by 500,000 b/d since March very much in line with what we predicted. As Chart 1 vividly shows, we are now drawing down global inventories at the fastest rate ever experienced. Readers of our letters will be familiar with the drivers of this rapid drawdown: global oil demand is surging, while non-opec oil supply (both here in the US and abroad) is disappointing (subjects we have extensively discussed in previous letters). 110 Wall Street New York, NY 10005

2 60,000 Chart 1: US Core Petroleum Inventories Since Jan 1 40,000 20, bbl -20,000-40,000-60,000-80, , Week Year Average Source: Energy Information Agency. But now another important point has emerged in our oil bull market journey that must be highlighted. As demonstrated by the energy analyst Mike Bodell on Chart 2, the inventories have now drawn down to critical points where further inventory reductions will result in severe upward price pressure. As you can easily see from our modeling, we have marked where inventories will stand by both year end and by the first quarter of If our inventory extrapolation is correct and inventories reach these levels (and they should our modeling has been correct over the past nine months), then prices have historically surpassed $100 per barrel. 2

3 Chart 2: US Core Petroleum Comparative Inventory vs. Oil Price $ $ $ Mar (est): 4 m b above Dec 31(est): 40 m b above Today: 88 m b above Jan : 178 mm b above WTI Oil Price ($/bbl) $ $80.00 $60.00 $40.00 $20.00 $ , , , , , ,000 US Core Petroleum Comprative Inventory (000 bbl) Source: Energy Information Agency, Mike Bodell, Goehring & Rozencwajg Associates models. In our January letter, we went into great detail about our belief that OPEC, relying on faulty International Energy Agency (IEA) data, was repeating the same mistake it made back in For those who don t remember what happened in 2006, OPEC cut production into an oil market that had quietly slipped into deficit and thereby over-tightened global oil markets. A price spike to $150 per barrel in the summer of 2008 was the result. Although inventories started at a much higher level this year compared to 2006, inventory draws since the 2016 OPEC production cuts have been nearly four times larger than what we experienced back in 2007 and Our models tell us that global inventories will continue to draw and we run the risk of a huge upward move in prices starting right now. The same roadmap that told us we were repeating the 2006 OPEC production cut mistake, is telling us now that we are travelling down the exact same road. Please read the Oil Section of this letter where we were will discuss all the supply and demand issues that are unfolding right now in today s global oil markets. The second important issue cropping up since our last letter has been the abrupt slowdown in production growth from the US oil shales. Most oil analysts at the start of 2017 believed US crude production would grow by approximately one million barrels per day between January 1st and December 31st. That level of growth would imply full-year 2017 oil production of 9.3 million barrels per day or 450,000 b/d above 2016 levels. Factoring in NGL growth of ~200,000 b/d would leave 3

4 total US crude and NGL production growth at ~650,000 b/d. As recently as July, the IEA echoed these views, calling for total US 2017 production (i.e., oil and NGL s) to grow by 610,000 b/d compared to Many analysts felt these estimates would ultimately be revised higher. Even with substantial OPEC production cuts, the energy analytic community has vigorously argued that because of strong US shale oil growth, global oil markets would remain in long-term structural surplus. We have long argued that even with strong production growth from the US shales, the oil markets would remain undersupplied by as much as one million barrels per day as 2017 progressed, given the OPEC production cuts and our non-consensus estimates for strong global demand growth. However, data has now emerged suggesting that US crude production growth is rapidly slowing. We first noticed this trend in the beginning of June and we made a brief reference to it in our 2nd Q letter released July 21st when we wrote: now recent data indicates the US shales have slowed their growth dramatically, which confirms our models. Between September 2016 and February 2017, US crude production grew by 100,000 barrels per day per month, but since then US production has ground to a near standstill. Between February and July, US production has only grown by 33,000 barrels per day per month a slowdown of 67%. Moreover, preliminary weekly data for August and September (adjusted for the impact of Hurricanes Harvey and Irma) suggest that production growth has slowed even more. Part of this slowdown is the result of the Gulf of Mexico which went from adding 50,000 b/d per month between September and February to being largely flat between February and July. However, onshore production growth has slowed by nearly 45% over that time as well (from 54,000 b/d per month to 30,000 b/d per month). The slowdown in US onshore production growth is even more puzzling given the huge increase in drilling that took place over that time. The Baker Hughes oil rig count is up 130% since bottoming in May of last year. In spite of a surging rig-count, onshore production growth is now showing signs of significant deceleration. Although it is still early in the production history of the shales, it now appears the growth in US shale production may not be nearly as robust as originally expected. If our observations and analysis are correct, then the oil market will be even more under-supplied that we expected in the 4th Q of the year and incredibly undersupplied into The ramifications are going to be huge. In the oil section of this letter we will try to answer the question of why US oil-shale production is now slowing. As of today, we have seen little in the way of analysis that attempts to explain what 4

5 is quickly becoming the most pressing issue facing global non-opec oil supply. We believe there are two main explanations. First, based upon our field-by-field analysis, we believe that many of the US shale fields (particularly the Eagle Ford and Bakken) are showing early signs of exhaustion. Most of the top-tier acreage in the plays have been developed and, as producers are forced to move into the second- and third-tier drilling inventory, production growth will be harder to come by. Second, we believe that last year s production data benefitted from a one-time surge due to the development of a large number of drilled-but-uncompleted wells (DUCs). These wells were brought on in the second half of last year and boosted production. Analysts then extrapolated this level of production growth into 2017 without realizing that it was a one-time surge in production. The unexpected slowdown in US shale production is clearly shown in E&P company s 2nd Q reported results. We constructed an index of 67 publicly traded US companies. While not all of these companies production is exclusively in the US, the majority of it is. In aggregate, these companies produced 4.0 mm b/d in the first quarter. If we assume that 85% of the total production is US based, then our survey represents approximately 40% of US crude oil production. Incredibly, nearly 70% of these 67 companies missed their consensus estimate for 2nd Q oil production. In total, the group was expected to grow by 150,000 b/d sequentially but instead only grew by 56,000 b/d 62% below expectations. Moreover, 12% missed production estimates by over 10%. Furthermore, we have seen several companies lower their full-year 2017 production guidance. We believe that more reductions are coming. Of the companies that we track, 14% have reduced their 2017 production guidance. In aggregate, these companies had guided to 67,000 b/d of oil production growth at the start of the year and have since reduced this figure by 40% to 42,000 b/d today. Our analysis tells us these reductions are only the beginning. In a very interesting development, another 20% of our survey have left their production guidance unchanged, but have increased their capital spending guidance by 10%. In other words, they will need to spend more than expected to reach the same level of production growth they had anticipated only a few months ago. Since most drilling and completion costs were likely locked in when guidance was set earlier this year, these revisions suggest that many companies are not seeing the drilling productivity they had originally expected. We believe we will continue to see additional production guidance reduction from many of these companies. These two incremental data points (2nd Q production estimates coming up short and full-year production guidance being lowered) suggests to us that most analysts (and indeed many companies) did not expect the current slow-down in oil production growth. This raises a very interesting question- -and one that we will try to address in the oil section of this letter: Are the shales as big and robust as generally believed, or are we over-estimating the ultimate recovered reserves of the shales and thereby their peak production rates? This is a very difficult question to answer; however in this letter, we will analyze the various shale basins in the United States using a reserve estimation technique called Hubbert Linearization 5

6 Using Hubbert Linearization (a technique used to estimate the inputs used in a Hubbert Curve), our models tell us the energy analytic community is over-estimating ultimate recoverable reserves of the US shale oil plays by a factor of nearly 50%. This study has profound implications. First, it suggests that future production from the shale oil plays in the US could be much smaller than most people believe. Second, it could explain why shale production has already started to disappoint over the last six months. Last, it suggests that we are unlikely to repeat the level of production growth we have experienced over the last five years. In fact, according to our Hubbert Linearization, total US oil production may only grow at a fraction of the level we have seen over the last several years. This last point is particularly important because most analysts believe that US shale production will surge as soon as oil prices advance above $50 per barrel. Our analysis leads us to believe this is a very unlikely outcome. The US shale oil plays are the only remaining source of material non-opec supply growth in analysts models -- conventional oil discoveries are at an all-time low. If we are ultimately unable to grow shale production, then global oil supply is at risk of falling far short of strong demand growth going forward. Please read the oil section for a full description of our analysis. It s all original research, and the investment implications, both short term, and long term, are huge. Since we wrote in our last letter that India s growth in commodity consumption is on the verge of substantial acceleration, numerous data points have emerged confirming our theory. Many analysts believe, because of structural and cultural problems, India would never be able replicate China s growth over the last 25 years, that India would never be China. We have never believed this, although our models told that India s period of accelerated commodity demand (the S-Curve tipping point) was still a number of years away. However, our models are now beginning to tell us India is today where China was back in the early part of last decade, and that going forward India will surprise materially to the upside in terms of demand, just like China starting doing 17 years ago. It s important to note the surprises have already started. For example, in a series of recent revisions, the IEA has made huge upward revisions in India s oil demand for the last several years revisions that almost no India or oil analysts have commented on. The oil section of this letter will discuss the size and importance of these revisions. Given the supply constraints we have just talked about in global oil markets, as well as continuing strength from other sources of non-oecd demand and pervasive market bearishness, we believe we are on the verge of a once-in-a-career inflection point in global oil markets. Market Commentary Commodity prices and natural resource stocks rebounded in the 3 rd Q. Much stronger than expected growth from China and continued economic strength from the rest of the emerging markets forced short covering and raised some interest from the investment community. Continued weakness in the US dollar also helped commodity prices. As measured by the DXY index, the dollar fell 5% in 6

7 July and August before rebounding in September. For the quarter, the dollar slipped over 2.7%. Leading the commodity rebound were the base metals. Copper, aluminum, and nickel were up approximately 10% during the quarter. Zinc, reflecting continued supply constraints, was the strongest base metal up over 15%. For the year, the base metals have been among the best performing commodities. For example, copper, aluminum, and zinc have appreciated between 20% and 25%. Copper remains our favorite investment in the base metals. Last year we wrote extensively about copper and the impact the electric vehicle would have on global copper demand. At the time we wrote that letter, few understood how much copper is required to build out and generate electricity from renewable sources. Today, this fact is becoming more widely recognized. In a widely read interview given at the end of September, the Chief Commercial Office of BHP called copper the metal of the future. He argued that the biggest impact from the growth of electric cars will be on copper. As we have outlined many times in these letters, copper demand in the next 10 years is going to surge, resulting in much higher copper prices. Copper equites rose strongly during the quarter (up 20%), but we believe the copper bull market is just starting. The copper bull market will play out over many years. Copper remains our favorite investment metal. Global coal markets also performed well during the quarter, driven by continued economic strength in China and a rebound in steel production. Metallurgical coal prices rose a strong 30% during the quarter and global thermal prices rose almost 25%. We find the sector particularly attractive for two reasons. Since most of the industry slid into bankruptcy over the last five years, US coal equities are now very cheap. The US Department of Energy is proposing new rules allowing utilities, including coal plants, to cover certain costs related to base-load capacity. The purpose of the rule is to maintain a certain level of base-load capacity to back up an electrical grid made increasing unstable by renewables. This would potentially slow the retirement of existing coal plants. As long as gas prices remain depressed, we do not see a bull market developing in coal. However, we believe the super-depressed valuations of the stocks make these equities potentially rewarding investments. Oil prices rebounded in the 3 rd Q. WTI rose 12% and Brent prices rose almost 20%. Although large amounts of US oil data was distorted by impacts of Hurricane Harvey, which knocked out almost 25% of the US s refining capacity at the end of August, certain strong trends continue. Global oil demand is surging (a subject that we have discussed at length over the last year) and it now looks like production from the US shales is slowing. Both US and global inventories are now drawing at approximately 500,000 b/d a figure very much in line with what our models told us back in January. As discussed in the introduction of this letter, we believe that we are now at the point in the relationship between inventories and price where further inventory drawdowns, something our modelling tells us to expect, will put significant upward pressure on prices. 7

8 We remain extremely bullish on oil prices and believe that prices in the triple digits remain a distinct possibility at some point in the first half of Investors remain bearish. The energy weighting in the Standard & Poor s stock index is near all -time lows and oil prices have bottomed and are now heading higher. Energy names have been poor performers this year (for example the S&P Exploration and Production and the S&P Oil Services Indices are down 17% and 25% for the year), but we believe investors today are being presented with a buying opportunity of an lifetime. We offer our detailed analysis of today s oil market the Oil Section of this letter. Elsewhere in the market, precious metals and related stocks were lackluster. Gold was up 3%, while gold stocks were up less than 1% during the quarter; silver was flat; and platinum was down slightly. Palladium was the standout rising almost 12%. Back in April of 2016, we discussed at length the historical relationship between gold and oil going all the way to the 1850s. We pointed out that whenever an ounce of gold was priced at 30 times the price of an oil barrel, then oil and oil-related investments represented excellent value. This ratio almost hit 30 back at the end of June and in September it hit 29. Although we like gold here, the historical relative cheapness of oil to gold makes us favor the former over the latter. And finally regarding agriculture, we remain neutral on the group. Good growing conditions here in the US have again produced another huge crop, and grain prices were weak during the third quarter. Wheat prices fell 13% and corn fell 4%. Because of continued strong demand from China, soybean prices actually bucked the bearish trend and rose 3% during the quarter. Given the potential for a huge 2017 harvest, with the world again facing extremely large ending grain inventories, we remain neutral on the grains and have cut back on our agriculture related investments. Global Oil Markets As we discussed in our introduction, there is so much to discuss this quarter we almost don t know where to start. After a weak start to the year, oil prices were strong during the third quarter with WTI advancing by 12% and Brent advancing by 20%. From their 2017 lows made in June, oil prices have advanced by between 25-30%, putting them back in bull-market territory for the first time this year. Oil-related securities were weak to start the quarter, before rallying back sharply in September. Between the end of June and the end of August, many securities were down between 5-20%, before rallying back a comparable amount in September. Given how much ground we have to cover this quarter, we have decided to break down our commentary into four main categories: 8

9 The turn in oil prices is now upon us as inventories continue to normalize relative to average levels. The disappointment in US shale output has removed a major bearish argument in the global oil markets. Are we overestimating the ultimate recoverable reserves in US shales, and what does that mean for production? India is now confirming our models. This will have a huge impact on global oil demand in the coming decade. Global Inventories and the Coming Turn in Oil Prices Readers of our letters will recall that, starting in January 2017, we made the very contrarian prediction that oil inventories would normalize over the course of Underestimated global demand combined with disappointments in non-opec supply would leave global oil markets undersupplied by upwards of 600,000 b/d. As a result, the large inventory overhang brought about by OPEC s decision to dismantle production quotas in 2014 would be largely worked off by the first quarter of We cannot overstate how contrarian this call was at the time. Most (if not all) analysts were convinced that rising production from Libya, Nigeria, Iran, and Iraq combined with the inevitable resurgence of the US shale plays would leave global inventories at record high levels for the foreseeable future. Since we first wrote in January, inventories have not remained at record levels (the bear s argument), but instead have drawn sharply just as our models predicted. In fact, since the end of February, US core petroleum inventories have drawn by nearly 500,000 b/d relative to long-term averages, while total OECD inventories (a proxy for global inventories) have drawn by 700,000 b/d relative to long-term averages. The total overhang relative to average levels has now repaired itself by 40-50% in only six months and our models continue to tell us inventory drawdowns will persist into While our fundamentals models have been very accurate, in retrospect we underestimated the emergence and strength of bearish psychology that gripped global oil markets in the last six months. Once inventories began to draw, we thought investors would recognize the substantial deficit imbedded in global oil markets and that oil prices and oil-related investments would move higher. Instead, investors remained focused on the absolute level of global inventories which started the year at near-record levels, as opposed to the rate of their decline. 9

10 However, our models tell us the days of investor complacency are quickly coming to an end. Energy analyst Mike Bodell has long followed the relationship between comparative inventory levels (i.e. the level of inventories relative to the long-term average) and the price of crude. The results have profound implications for today s oil market. As we mentioned in our introduction, US core comparative inventories stood at ~200 mm bbl above long-term averages at the beginning of As the year has progressed, US core petroleum inventories have worked off nearly 40% of their overhang and now stand at ~88 million barrels. According to our models (which have accurately predicted the inventory draws to date), US core petroleum inventories should hit 20 million barrels by February 2018, at which point historically oil prices begin to move sharply higher. In fact, since 2007 when US core petroleum inventories have been within 20 million barrels of normal, the oil price has averaged $92, and has exceeded $75 per barrel 80% percent of the time. These trends are not limited to the US. On a global level, total OECD comparative inventories will reach 20 million barrels by the 2 nd Q of next year, which also suggests much higher prices. Our research focuses on fundamental developments taking place in both supply and demand and we aim to be among the very first in identifying new trends. As a result, we are sometimes early in calling for a market bottom. That s why we construct a roadmap populated by mile-markers that we must pass in our journey. If we are travelling in the right direction and keep passing our data points, eventually the commodity price will reflect the true fundamentals in a market. In the interim however, it can be frustrating. That is precisely what has happened with oil markets this year. Our research has told us we have been on the right track, but investor sentiment has been slow to turn positive. We are very quickly approaching a level in comparative inventories where investors will no longer be able to ignore the positive fundamentals. The turning point is very near and the investment implications are profound. The Disappointment in US Shale Production The undisputed consensus view among all energy analysts is that shale production will accelerate sharply once prices exceed $50 per barrel, putting an effective cap on global crude prices. It is also widely believed that shale drilling productivity will continue to improve at double-digit rates. As a result, the break-even price required to earn economic returns on new drilling will also continue to move lower. However, as we mentioned in the introduction to this letter, US oil production, instead of accelerating, has now begun to slow materially. Total US oil production growth over the last five-months (ending July) has slowed by 70% compared with the previous five-month period. While offshore production has ground to a near standstill, even onshore production growth has slowed by nearly 45% over those two periods. This has occurred despite a sharp increase in the US oil rig count, which is up 130% from the recent-cycle lows made in May Why has this happened, and will the unexpected slowdown in oil shale production continue? 10

11 Our models tell us that the recent deceleration in US onshore production growth is the result of two separate but equally important dynamics. First, the slowdown in shale production growth is the result of a simple fact: the inventory of top-tier wells in both the Bakken and the Eagle Ford has now largely been drilled. As producers have moved to develop their second- and third-tier acreage, the initial production rates have suffered. While these effects have been somewhat mitigated by larger and more complex completion designs, we believe these efforts can only forestall, and not prevent, the effects of top-tier prospect exhaustion now being faced in two of the three largest shale basins in the US. This view has notably been echoed by several oil executives whom we believe to be among the best in the industry. According to one of these executives, one who had first mover advantage in both Bakken and Eagle Ford plays, 80% of the Bakken s, and 70% of Eagle Ford s tierone acreage has now been drilled. This same shale pioneer also stressed that when drilling tier-two acreage, we are underestimating the drop in drilling productivity that occurs. When drilling tier-two acreage, he told us, two drilling rigs are needed to replicate the production of just one rig when drilling tier-one prospects. This is a concept few energy analysts understand. We will be paying particular attention to the comments made by executives during the upcoming 3 rd Q earnings conference calls and will report our findings in the next quarterly letter. While the Permian Basin and emerging SCOOP/Stack play in Oklahoma still have a large inventory of tier-one wells left to drill, we believe that they will only partially offset the declining productivity of wells in the Eagle Ford and Bakken basins. As a result, the average US shale well may have already peaked in terms of productivity. The slowing of drilling productivity partially explains the slowing of US onshore production growth. The second factor affecting US onshore production growth revolves around the inventory of drilled-but-uncompleted wells (DUCs). Shale oil wells undergo extensive fracture stimulation in which massive amounts of proppant (usually sand) are injected into the well bore under tremendous pressure. This process (known as hydrological fracture stimulation or fracking) allows the trapped oil to flow from the otherwise impermeable shale rock formation. Oftentimes, the fracture stimulation can cost as much (or more) than the actual cost to drill the well itself. Since energy companies often enter into fixed drilling contracts ahead of time, when the oil price plummeted in 2015 many were forced to continue some level of drilling activity while postponing the well s completions in order to reduce their overall capital spending. Also, many companies were forced to continue drilling in 2015 to prevent acreage lease commitments from lapsing. In 2014, the number of wells drilled approximately equaled the number of wells completed. However, in 2015, only 90% of drilled wells were completed, meaning that a significant inventory of drilled-but-uncompleted wells had built up over the course of In 2016, this dynamic began to reverse itself and for the year as a whole the US drilled 6,992 shale wells but completed nearly 8,000 11

12 wells. Instead of completing 90% of the wells drilled, the US shale industry in 2016 completed nearly 115% of the wells drilled. We believe that the liquidation of DUC inventory that occurred in 2016 artificially inflated the apparent dramatic increases in drilling productivity that were reported last year. Simply looking at the rig count and new oil production, it seems drilling productivity surged by 60% in from 530 b/d of new production per rig per month in 2015 to 850 b/d in Using these elevated productivity figures, most analysts expected monthly production gains to average 80,000 b/d per month assuming a ~50% base decline rate and a 650 oil rig count. Instead, if you adjust for the extra DUCs brought online last year, it becomes clear last year s boost in drilling productivity was temporary and would likely decline by as much 30% as 2017 progressed. And this is exactly what happened. Drilling productivity since February has averaged 29.2% lower than the September 2016 February 2017 period. Last year s boost in drilling productivity now appears to have been driven mainly by DUC liquidation, and as a result was onetime in nature. Now that the DUC inventory has largely normalized, we expect the primary driver of drilling productivity (i.e., declining inventory of high-quality drilling prospects) to come to the fore once again. Using today s rig count, and adjusting downward drilling actual productivity (uninflated by 2016 s DUC liquidation), our models tell us to expects monthly onshore production gain of approximately 30,000 b /d per month. This is in line with actual production growth over the last five months, but down over 50% from the expected 80,000 b /d per month gains expected by most energy analysts. We should point out that a new bearish argument has emerged recently, regarding the DUCs. Over the last several months, the DUC inventory in the US has actually started to grow again. Several analysts have written that the liquidation of these DUCs will cause production to surge into 2018 just as it did in While it is true that the DUCs have started to rise again, we think there is a fundamental difference between the current period of DUC accumulation and what we saw in 2015/2016: the direction of the rig count. When a rig count is sharply rising on a year-over-basis (as it is today), it is normal for DUC inventories to grow, as there is a normal delay between the drilling of a well and its completion. In other words, in a rising rig count environment, there is a certain level of steady-state DUC inventories that is considered normal. Our analysis suggests that is what is happening today in reaction to the rising rig count. When the DUC inventory built in 2015 however, it occurred as the rig count plummeted by 80%. The increase in DUC inventory over that time was a deliberate choice to hold off completing wells, and was not considered steady-state DUC behavior. The difference is very important. DUCs that are deliberately held uncompleted can be brought online very quickly at the operators discretion, whereas DUCs that accumulate due to the normal backlog of completion activity tend to come online in a more slow and orderly manner. 12

13 Based on our updated drilling models, we expect that US crude production will now grow by only 600,000 b/d from January 1st to December 31 - a far cry from the +1 mm b/d that most analysts expected only a few months ago. The IEA has revised down its estimates for 2017 US production growth by 200,000 b/d since July, however it is still expecting huge growth of 1.2 m b/d from the US in Quite frankly, this cannot happen without either a huge surge in drilling productivity (highly unlikely) and/or a dramatic increase in the rig count. And remember, the US is by far the largest source of expected non-opec production growth next year. The next largest source of growth, Brazil, is only expected to be one-fifth that of the US. The rest of non-opec, excluding the US and Brazil, is expected to be up only 170,000 b/d in 2018 in total. If the present US oil rig count holds (presently at 743), we project US shale growth to be only between 400,000 to 500,000 b/d in For shale oil production to accelerate from here, dramatic increases will be needed in the rig count, which would require much higher oil prices. Given our present calculation of drilling productivity, we calculate the US oil rig count would have to surge to over 1,000 if shale oil production were to grow at 1 mm b/d year-over-year rates. Given today s oil prices, and given that the US rig count has now actually declined over the last six weeks, we believe this to be impossible. A Discussion of Shale Oil Reserves The recent unexpected slow-down in shale production growth has raised very interesting questions that few people are asking: what if the shales simply are not as big and productive as originally thought? As we mentioned above, we think a major source of the slow-down in shale production growth is due to companies having fully developed their inventory of tier-one wells. In other words, most of the shale basins are already exhibiting the first signs of exhaustion, a subject we touched on in the introduction of this letter. This claim stands in sharp contrast to the consensus opinion which believes that marginally higher oil prices will bring about a surge of new production that for all practicable purposes will be unlimited. We decided to turn to Hubbert Linearization to help shed some light on the subject and what we found was very surprising. As we discussed in the 3 rd Q letter of 2016 and in the introduction, King Hubbert did a huge amount of work on natural resource exploitation and depletion and built a series of models that tried to estimate a field s peak production and ultimate recoverable reserves. His model was essentially a logistic growth function in which basin-level production grows at an exponential rate before plateauing and eventually declining. A field reaches peak production at the point where roughly 50% of its ultimate recoverable reserves have been produced. A Hubbert Linearization is simply a plot of cumulative production vs. the ratio of current production to cumulative production. Hubbert noticed that after an initial noisy period, this trend settled into a very predictable straight line which could then be used to estimate a field s recoverable reserves and its ultimate peak production. 13

14 Hubbert s analysis gained a huge amount of prominence after he used it to predict that US oil production would peak in 1970 at 9.5 million barrels per day and ultimately recover 200 billion barrels. While Hubbert failed to predict the rise of shale production some 50 years later, if you look only at conventional oil production in the US, his prediction was very accurate. Daily Production / Cumulative Production Chart 3: US Lower 48 Conventional (assuming 200 bn bbl recoverable reserves) Cumulative Production (bn bbl) Production (000 bbl / d) 12,000 10,000 8,000 6,000 4,000 2, Source: Energy Information Agency & Goehring & Rozencwajg Associates Model. Despite the accuracy of Hubbert s many predictions, his methodology has remained controversial. Nevertheless, oil field production trends first identified by Hubbert in the 1950s have expressed themselves repeatedly around the world and include such high profile fields and producing regions as Prudhoe Bay, Mexico s Cantarell field, Samatlor field in Russia and the North Sea. Although controversial (we realize one of Hubbert s biggest drawbacks is that it fails to capture everincreasing field recovery assumptions), we decided to apply the same analysis on several of the shale gas and shale oil fields to see if we could shed some light on the recent slow- down in production growth. We believe what we found has huge and serious potential implications to the energy complex going forward. We started our analysis with the shale gas fields because they have the longest production histories and the most data. Although it elicits no comments from analysts, many of the oldest producing shale gas fields are today tracing out almost perfect Hubbert curves. We believe that two important observations should be mentioned regarding the shape of these curves. First, the Hubbert Curve shape of these production curves goes against conventional wisdom suggesting that current production rates from these shale gas fields can be held at high rates almost indefinitely. Second and even more remarkable, these Hubbert Curves are suggesting we are grossly overestimating recoverable reserves from these fields. This is critically important because if the shale oil reserves 14

15 are also being overstated by a similar magnitude, it will be impossible for these shales to materially grow their production a growth expected by almost all energy analysts. We performed a Hubbert Linearization on several of the oldest natural gas shales including the Barnett, the Fayetteville and the Haynesville. A Hubbert analysis assumes that a field is produced in an unconstrained fashion, and so the Marcellus (with its infrastructure bottlenecks) was less revealing. We first noticed that a Hubbert Linearization fits the actual historical production data from the fields very well with r-squared values of between 0.89 and 0.99 for the Barnett, Fayetteville and Haynesville. We also noticed that the implied total recoverable reserves from those fields were each approximately 35% to 40% lower than the EIA s most recent estimates. For example, our Hubbert Linearization indicates that Fayetteville will recover 9 tcf of gas (versus 14 tcf estimated by the EIA), the Barnett will recover 19 tcf (versus 33 tcf estimated by the EIA), and the Haynesville will 16 tcf (versus 25 tcf estimated by the EIA). In the chart below, you can see the Hubbert Linearization for the Fayetteville. The chart on the left is the Hubbert Linearization that indicates what recoverable reserves will be (i.e., where the line intersects the X-axis at 9 tcf). The chart on the right is a fitted Hubert Curve that assumes 9 tcf of recoverable reserves. As you can see, the curve fits very well. If we had assumed the Fayetteville s total recoverable reserves would total 14 tcf (as per the EIA data), then production, as predicted by Hubbert Curve analysis, should have peaked at 4.4 bcf/d in Instead, production in the Fayetteville peaked at less than 3 bcf in 2013 and has declined sharply since then. Chart 4: Fayetteville Shale (assuming 9.1 tcf recoverable reserves) Daily Production / Cumulative Production Cumulative Production (tcf) Production (bcf/d) /1/2006 1/1/2008 6/1/ /1/2010 4/1/2012 9/1/2013 2/1/2015 7/1/ /1/2017 5/1/ /1/2020 3/1/2022 8/1/2023 1/1/2025 Source: Energy Information Agency & Goehring & Rozencwajg Associates Model. Below is the Hubbert Linearization for the Barnett Field, the oldest of the shale gas plays. The chart on the left indicates that the Barnett will ultimately recover 19 tcf of gas. The chart of the right is a fitted Hubbert Curve that assumes 19 tcf are in fact ultimately recovered. Once again, the 15

16 curve fits very well. If we had assumed that total recoverable reserves would total 33 tcf (as per the IEA data), then production, as predicted by a Hubbert Curve should have peaked at 9 bcf/d in As you can clearly see below, instead of peaking at 9 bcf/d, the Barnett actually peaked materially lower at 5 bcf in Chart 5: Barnett Shale (assuming 19 tcf recoverable reserves) Daily Production / Cumulative Production Cumulative Production (tcf) Production (bcf/d) /1/ /1/ /1/ /1/2005 9/1/2007 8/1/2009 7/1/2011 6/1/2013 5/1/2015 4/1/2017 3/1/2019 2/1/2021 1/1/ /1/2024 Source: Energy Information Agency & Goehring & Rozencwajg Associates Model. The reason this analysis is so important is that two of the three major shale oil basins (the Eagle Ford and the Bakken) are today tracing out well-defined Hubbert-style curves. Hubbert Linearizations for both fields (charts on the left) indicate the Bakken will recover 3.6 bn bbl of oil, while the Eagle Ford will recover 3 bn bbl. Just like with the gas shales, these figures are substantially lower than conventional estimates. For example, the EIA estimates the Bakken has approximately 7 bn bbl of recoverable reserves (2 bn bbl produced, and 5 bn bbl remaining), and the Eagle Ford has 6.5 bn bbl of recoverable reserves (2 bn bbl produced, and 4.5 bn bbl remaining to be recovered). Our Hubbert Linearization analysis indicates that we may have overestimated the recovery of oil in both fields by over 50% (even greater than what s occurring in the gas shales). On the right-hand side, we have fitted Hubbert Curves assuming 3.6 bn bbls of recoverable reserves for the Bakken, and 3 bn bbl of recoverable reserves for the Eagle Ford. As you can see both charts, using these reserve assumptions, predict with great accuracy the production peaks in both fields. 16

17 0.14 Chart 6: Bakken Shale (assuming 3.6 bn bbl recoverable reserves) 1,400 Daily Production / Cumulative Production Cumulative Production (bn bbl) Production (000 bbl/d) 1,200 1, /1/2007 7/1/2008 1/1/2010 7/1/2011 1/1/2013 7/1/2014 1/1/2016 7/1/2017 1/1/2019 7/1/2020 1/1/2022 7/1/2023 1/1/2025 Source: Energy Information Agency & Goehring & Rozencwajg Associates Model. Daily Production / Cumulative Production Chart 7: Eagle Ford Shale (assuming 3.0 bn bbl recoverable reserves) Cumulative Production (bn bbl) Source: Energy Information Agency & Goehring & Rozencwajg Associates Model. Production (000 bbl/d) 1,800 1,600 1,400 1,200 1, /1/2007 7/1/2008 1/1/2010 7/1/2011 1/1/2013 7/1/2014 1/1/2016 7/1/2017 1/1/2019 7/1/2020 1/1/2022 7/1/2023 1/1/2025 Plugging the EIA reserve figures (7.0 bn bbl) into a Hubbert curve suggests that the Bakken would have peaked at 2.5 mm b/d in late Instead, it now clearly looks like the Bakken s production peaked at a little over 1.2 mm b/d in the beginning of 2015, a full 1.3 mm b/d below (and three years before) the predicted peak given a 7 bn bbl recoverable reserve estimate. Similarly, the 17

18 Eagle Ford should have reach a production peak of 3.6 mm b/d in late 2016 using the EIA s estimated 6.5 bn bbl s of recoverable reserves. As with the Bakken, it is clear that the Eagle Ford peaked at 1.7 mm b/d in 2015, a full 900,000 b/d below (and eighteen months before) its predicted peak, given 6.5 bn bbl of recoverable reserves. Given that we now have good estimates of recoverable reserves in both fields and we know that both fields have surpassed peak production, our analysis tells us that both fields will have great difficulty in achieving any period of sustained production growth. As mentioned earlier, one of the problems with Hubbert Linearization is that recoverable reserves, with the relentless application of new technologies, almost always advance over time. As you can see from the Hubbert Linearization of both the Bakken and Eagle Ford fields, the straight line of the plot has begun shifting to the right, implying our original estimate of recoverable reserves implied is too conservative. The move right in the straight plot could originate from one or multiple sources. First, it might be caused by the DUC liquidations mentioned earlier, which has temporarily boosted both Bakken and Eagle Ford production. Second, it might be caused by continued drilling productivities in the fields. Operators in both fields are experimenting with ever-increasing lateral length, tighter well spacing, and massive increasing in sand loadings during completions, which all have the impact of increasing field production and recovery factors. However, even if we push the Hubbert Linearizations out and to the right, it is unlikely that those fields will ever reach the recoverable reserve estimates put forward by the EIA (and consensus analysts). As a result, while production may be able to hang on for longer (and perhaps even grow slightly), if the Hubbert analysis is correct, then achieving the strong levels of growth expected by many analysts will be impossible to achieve, even with improved recoveries. Although the Permian basin is at an earlier stage of its development; we should stress that production from the basin is already exhibiting Hubbert Curve characteristics. By using Hubbert Curve analytics, we can make some pretty credible projections of what ultimate production levels from the basin might be. As you can see from the chart at left below, we don t have enough production history form the Permian Basin to make an accurate recoverable reserve estimate using Hubbert Linearization. Relying instead on published recoverable oil reserve estimates from the US Geological Survey (the EIA doesn t publish an up-to date reserve estimate for the Permian Basin), we estimate that consensus recoverable reserve estimates today will coalesce around 40 bn bbl. (The US Geological Survey estimates 20 bn bbl of reserves on the Midland side of the Basin. We multiplied this by two to get an estimate for both sides.) If we start with 40 bn bbl of recoverable reserves in the Permian and we assume that the industry will ultimately overestimate these reserves by 50% (as happened for the Bakken and Eagle Ford and the various gas shale plays), then the actual recoverable reserves are closer to 20 bn bbl. If 18

19 we then construct a Hubbert curve (in the chart at right) that assumes the Permian Basin will recover 20 bn bbl of oil, the projected production profile tracks the Permian s actual five-year unconventional production history nicely. If the shape of this curve is correct, then we can project when and at what peak Permian Basin production will occur. As you can see from the chart, we should expect the Permian to grow strongly for five years with production peaking at a little below 3.5 mm barrels (up from today s production of 2.6 mm b/d). Chart 8: Permian Basin (assuming 20.0 bn bbl recoverable reserves) ,000 Daily Production / Cumulative Production Cumulative Production (bn bbl) Production (000 bbl/d) 3,500 3,000 2,500 2,000 1,500 1, /1/2007 4/1/2009 7/1/ /1/2013 1/1/2016 4/1/2018 7/1/ /1/2022 1/1/2025 4/1/2027 7/1/ /1/2031 1/1/2034 Source: Energy Information Agency & Goehring & Rozencwajg Associates Model. Although it is still early in the Permian s unconventional life, evidence has already emerged that we are significantly overestimating the production potential of the field. For example, the oil and gas consulting firm Wood Mackenzie has already published a report suggesting that the Permian will hit a production peak of more than 5 mm b /d by A Hubbert analysis would suggest that bn bbl of recoverable reserves would be needed to reach this 5 mm b/d production peak a reserve figure almost 40% above what our analysis suggests today. We will continue to monitor the production trends from the Permian, and we will continually update our reserve analysis as the data comes in. However, as in the case of the Bakken and Eagle Ford fields, it seems we are again in the process of significantly overestimating the size and future production potential from the Permian Basin. The shale gas fields have been producing for over a decade now, and what we have learned by looking at their production profiles is striking. First, they will likely recover significantly less gas than what the EIA estimates. Second, their production profiles are following a Hubbert curve remarkably 19

20 well. Remember, if we had used the EIA estimates for the Fayetteville and the Barnett, then production should have continued to grow strongly into 2015 instead of sharply rolling over. If the ultimate recoverable reserves are similarly being overstated in the shale oil reservoirs, and they too follow a Hubbert-style curve, then it will be impossible to achieve the incremental oil production growth of 1 m b/d per year that so many analysts are currently predicting. We believe the large overestimating of recoverable reserves could explain why shale production growth is now beginning to disappoint. If this is correct, then with the exception of the Permian basin and SCOOP/Stack, the US shale oil revolution is largely behind us. Production will still be able to grow in aggregate going forward, however the huge surge in production growth we experienced over the last five years will be impossible to replicate. The Coming Rise of India In our last quarterly letter we wrote that India is now on the verge of hitting its S-Curve tipping-point, a point where commodity demand growth starts to accelerate sharply. Looking at percapita GDP, India today is very reminiscent of where China was in the period, right before demand started to accelerate sharply. In our last letter we went into great detail outlining how China in compares to India today in terms of oil demand per capita, vehicle penetration and airline miles traveled, among other things. In each case, the similarities are striking. We estimate that Indian oil consumption was 1.2 barrels per person last year, very similar to the 1.4 barrels per person consumed in China in Since then, China has surged from 1.4 m barrels per person in 2001 to 3.2 m barrels per person today, and we believe India could very well follow a similar trajectory over the coming 15 years. Were India to follow this road-map, its total oil consumption would grow by over 7 mm b/d over the next 15 years, or nearly 450,000 b/d each year. What should we expect to see if our models are correct? In the case of China, IEA s chronic underestimation of Chinese demand was the clue that China had entered into its S-Curve tipping point. Since 2003, the median upward IEA revision to Chinese oil demand has been 300,000 b/d each year. Although a touch cynical, we believed that once India entered its tipping point, we should expect to see the significant underestimate of India oil demand by the IEA as well. It would be an excellent data point indicating India has passed its S-curve tipping point. And this is exactly what has begun to happen. Over the last three months alone, the IEA has revised Indian demand estimates for higher by 220,000 b/d for each year on average and by as much as 300,000 b/d for certain quarters. These types of revisions are exactly what we started to see when China entered its S-Curve tipping point 15 year ago, and we think it s notable the IEA is now repeating the same mistake with India. It s another fascinating data point strongly indicating that India has entered its S-Curve trajectory. 20