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Highlights Both the massive inventory accumulation and robust underlying consumption have been driving Chinese crude imports in recent years. Chinese crude oil import growth will decelerate in 2021 due to a slower pace in the country’s oil inventory accumulation. The country’s underlying crude oil consumption growth will remain robust this year, which will support a still positive growth in Chinese crude oil imports this year. Strong Chinese crude oil imports are positive to global oil prices this year. Feature The gap between China’s total crude oil supply and its domestic crude oil consumption has been widening in recent years, due to a massive buildup in Chinese crude oil inventory (Chart 1A and 1B). In fact, China’s crude oil inventories have quadrupled in the past five years, exceeding two billion barrels as of November 2020 and are equal to about 70% of OECD total inventory (Chart 2). Chart 1AA Massive Buildup In Chinese Crude Oil Inventory Chart 1BChina: Total Crude Oil Supply Growth Has Exceeded Its Domestic Consumption Growth In addition, China’s crude oil import growth has been outpacing domestic oil consumption growth, while domestic production remains stagnant (Chart 3). Chart 2Crude Oil Inventories In China Have Quadrupled In The Past Five Years Chart 3China: Crude Oil Import Growth Has Been Stronger Than Its Domestic Consumption Growth Will China maintain its strong crude oil import growth this year? How will the interplay between domestic consumption and imports evolve in 2021? We expect China’s crude oil consumption growth to remain solid in 2021, growing at an annual rate of about 6-7% and up from the 4.5% growth rate reached in 2020. However, China’s crude oil imports are likely to increase by 4-6% in 2021 from the previous year, slower than the 7.2% growth seen in 2020. The moderation in Chinese oil imports in 2021 will mainly be due to a slower pace of crude oil inventory buildup. Understanding The Surge In Crude Oil Inventory Chart 4China's Crude Oil Inventory Buildup: One Major Driver Behind Its Strong Imports Since 2016 The massive buildup in domestic crude oil inventory has been one major driving force behind the strong growth in China's crude oil imports since 2016 (Chart 4). As oil prices continue to rebound, and given China’s existing large oil inventories, we think the pace of inventory accumulation in China will slow in 2021. Therefore, growth in Chinese oil imports this year will likely moderate. China’s crude oil imports currently account for about 75% of the country’s total crude oil supply. Since China’s domestic crude oil production has been stagnant in the last decade, the fluctuations in Chinese crude oil imports are largely driven by the change in the country’s total demand, which includes both domestic consumption and changes in inventories. China’s crude oil import growth has significantly outpaced domestic consumption growth in the past five years, leading to a buildup in inventory. China’s crude oil inventory includes Commercial Petroleum Reserves (CPR), which are held by refiners and traders; and Strategic Petroleum Reserves (SPR), which are held by the government. Our Chinese crude oil inventory proxy1 was constructed based on the crude oil flow diagram shown in Chart 5.  Chart 5How Did We Derive Our Chinese Crude Oil Inventory Proxy? Our research has suggested that since 2016, most of the buildup has occurred in CPR. This is due to the following: The government in 2015 required refiners to keep their inventory level at no less than their 15-days requirement for operation use. Chinese refinery capacity had been expanded at a compound annual growth rate (CAGR) of 2.8% during 2016-2019. These existing and new refineries have been building their inventories to meet government regulations in the past several years.  In addition, the government started to allow independent refineries to import crude oil by setting a quota in mid-2015, and the import quotas have been increased every year. In 2020, the quota reached 184.6 million tons, equaling to about 3,700 kbpd, nearly five times the quota in 2015. The total increase in imports of these independent refiners over the past five years was about 2,950 kbpd, accounting for 70% of the increase in the country’s total crude oil imports during the same period. Chart 6China: Rising Run Rates For Its Independent Refineries Independent refiners import crude oil for both refinery purposes and to meet the new inventory requirement. Over the last several years, the increased amount of quota has improved Chinese independent refiners’ profitability and refinery capacity run rate, as the import quota allows these private sector refiners to save operating costs by cutting out the “middleman” and by actively managing their own feedstocks. For example, Shandong has the largest number of independent refineries among all provinces. Chart 6 shows that the run rate of the region’s independent refineries has surged since 2016, from about 40% in that year to 75% this year. In addition, since 2016, the fluctuations in their run rates have become much more closely correlated with global oil prices.   Commercial crude oil users have much larger physical reserve space than the SPR. Notably, they tend to sharply increase their imports when crude oil prices are low.  In addition, inventory accumulation often occurs when credit/financing is available with low costs and refiners expect higher prices ahead. Meanwhile, our research shows the SPR development has been slowing considerably in recent years, resulting in little inventory buildup in SPR. The last time the National Bureau of Statistics (NBS) reported the SPR data was December 29, 2017. It showed the SPR was about 37.73 million tons by mid-2017, not far from the country’s target of 40 million tons for the first two phases2 of SPR. This suggests that the country was at least close to finishing its second phase of the SPR in 2017. Since then, there has been little information about the third phase of the SPR progress. We have only been able to find two pieces of news on that subject, and both suggest the construction of the third phase of SPR has been stagnant, and the planning of two sites only started in 2019. As the average construction time for projects in the second phase of SPR was about four years, we do not think these sites were completed in 2020. The NBS data shows that even during the period of mid-2015 and mid-2017, the SPR had only increased by 234 kbpd, about 117 kbpd per year. In comparison, the Chinese total crude oil inventory increased by 600-700 kbpd per year in 2016 and 2017. Clearly, SPR only accounted for a small share of the Chinese total crude oil inventory. Looking forward, we expect a much slower pace of crude oil inventory buildup in China in 2021. Our forecast is based on the following factors: Current Chinese crude oil inventories (CPR and SPR combined) are already in the upper range when comparing the OECD countries (Chart 7). Although the IEA data shows that Japan and Korea have oil stocks of 200 days and 193 days of their respective crude oil net imports, Chinese oil inventories are currently equivalent to 195 days of crude oil net imports and much higher than the 90 days the IEA requires OECD countries to hold. With Brent oil prices having risen by a lot from the April 2020 trough and elevated domestic crude oil inventories, both government and commercial users will likely slow their purchases of overseas oil for inventory accumulation. In comparison, Chinese crude oil inventory accumulation growth slowed sharply in 2018 when Brent oil prices rose by 95% from their trough in mid-2017 (Chart 8), A significant portion of Chinese oil inventory buildup was accumulated over the past five years. At 1,170 kbpd, the largest annual accumulation was in 2020, higher than the 700-900 kbpd fill per year during 2017-2019. Chart 7China's Crude Oil Inventory: No Longer Low Chart 8China: Rising Oil Prices Will Likely Slow Down Its Pace Of Crude Oil Inventory Accumulation We do not expect the fast inventory accumulation of 2020 to repeat in 2021. Instead, a mean-reversal in the inventory accumulation pace will likely occur. Table 1Our Estimates Of The Scale Of Chinese Crude Oil Inventory In 2021 Our baseline estimate based on China’s 2021 import quota and refinery capacity3 is that Chinese crude oil inventory will increase to 207-210 days of Chinese crude oil imports by this year-end, up from 192 days at last year-end (Table 1). With already-elevated crude oil inventory, the pace of the inventory accumulation in China will be slower than last year. Bottom Line: After a massive buildup over recent years, the pace of inventory accumulation in China will slow in 2021 and probably onwards as well. As a result, Chinese oil import growth will converge with the pace of domestic consumption growth. China’s Robust Crude Oil Consumption Growth In 2021 Chart 9China: Resilient Domestic Crude Oil Consumption Growth In 2020 Despite the pandemic outbreak, last year’s underlying consumption of crude oil in China was resilient at a year-on-year growth of 4.5%, even though the rate was smaller than the average growth of 6-7% in 2018-2019 (Chart 9).  The growth in oil consumption last year was mainly from the non-transportation sector. The output of non-transportation fuels, including fuel oil, naphtha, petroleum coke, and petroleum pitch, are mostly having impressive growth, suggesting strong consumption in sectors like chemical products, steel sector and infrastructure (Chart 10). For example, naphtha is the primary feedstock for ethylene production. Ethylene is the building block for a vast range of chemicals from plastics to antifreeze solutions and solvents. Transportation fuel consumption was weak in 2020, with the output of major transportation fuels including gasoline, diesel oil and kerosene in contraction (Chart 11). Chart 10Strong Consumption In Non-Transportation Sectors in 2020 Last Year Chart 11Transportation Fuel Consumption Was Weak In 2020 In 2021, we expect the underlying consumption growth of crude oil in China to increase to 6-7% from last year’s 4.5%. This will be in line with its growth in both 2018 and 2019 (Chart 9 on page 7). First, the consumption of transportation fuels will likely recover this year. Transportation fuels are the largest consuming sector for Chinese petroleum products. Based on British Petroleum data, gasoline, diesel and kerosene accounted for 55% of total Chinese oil consumption in 2019. We expect the transportation fuel consumption growth to be stronger (i.e., 6-7%) than its five-year compounded annual growth rate (CAGR) of 4.1% during 2015-2019. Chart 12China's Automobile Sales Correlated Well With Its Crude Oil Imports Automobile sales in China correlated well with the country’s crude oil imports (Chart 12, top panel). Despite a year-on-year contraction of 2% for the whole year of 2020, automobile sales had been strong with a double-digit growth nearly every month since May. Only 5% of these automobiles are new energy vehicles (NEV). About 80% of them are gasoline cars and 15% are diesel automobiles. Annual total car sales still account for about 9% of total existing automobiles (Chart 12, bottom panel). This means a 6-7% growth in the transportation consumption of passenger cars and commercial cars is very possible in 2021. The number of airports and airplanes are still on the uptrend in China. The CAGR of Chinese kerosene consumption rose from 10.1% during 2010-2014 to 10.6% during 2015-2019. This suggests that the kerosene consumption growth in China could reach 11% in 2021. Domestic gasoline and diesel prices are near decade lows (Chart 13). This will encourage consumption of these fuels. Second, the oil consumption growth in the industry sector will likely be larger than the 5% in the recent years (Chart 14). Based on the NBS data, the industry sector accounts for about 36% of China’s petroleum product consumption. Chart 13Low Domestic Gasoline And Diesel Prices Encourage Fuel Consumption This Year Chart 14Robust Oil Consumption Growth In The Industry Sector In 2021 Third, infrastructure spending and property market construction will slow in 2H2021 given the credit, fiscal, and regulatory tightening that has been taking place. However, construction only accounts for about 6% of Chinese petroleum product consumption.  Given all of this, achieving a 6-7% underlying consumption growth of crude oil in China this year is possible. Taking into consideration the slower pace of inventory buildup, we expect China’s crude oil imports to increase by 4-6% in 2021 over the previous year, slower than last year’s 7.2% growth. Bottom Line: The underlying consumption growth of crude oil in China is likely to increase to 6-7% in 2021 from last year’s 4.5%, providing solid support to China’s crude oil imports. What About Other Factors Affecting Chinese Crude Oil Imports? Currently, both domestic crude oil production and net exports of Chinese petroleum products exports are small contributors to the growth of Chinese crude oil imports. However, as the Chinese petroleum export sector becomes more competitive in the global market, it will likely take a bigger share of China’s crude oil imports going forward. Chart 15Net Exports Of Chinese Petroleum Products Are On The Uptrend We expect domestic crude oil output to be stagnant in 2021. The breakeven prices for most domestic oil fields are US$50-60 per barrel. Without a considerable rally in oil prices, the total domestic crude oil output is unlikely to pick up. Moreover, due to the massive crude oil inventory buildup in recent years, Chinese oil producers may constrain their output. In this scenario, a reduction in domestic crude oil output by 1-2% in 2021 from 2020 is possible. Nonetheless, this will only increase China’s oil imports by a small amount of about 40-80 kbpd. The net exports of Chinese petroleum products are on the uptrend (Chart 15). Currently net exports of Chinese petroleum products account for only about 6% of Chinese crude oil imports.  However, Chinese refineries are increasingly competitive in global gasoline and diesel markets, since most of the new refineries in the country are high technology equipped and highly efficient. In addition, last July, China started issuing export licenses to private refiners, and we expect the trend to continue. According to Bloomberg, China is set to surpass the US to become the world’s largest oil refiner in 2021. As such, in the coming years we expect rising Chinese exports of petroleum products will demand more imports of crude oil.  We expect Chinese petroleum products net exports to rise by 100-150 kbpd in 2021 15-20% growth from last year), which may increase our estimate of China’s year-on-year crude oil import growth from 4-6% to 5-7% in 2021. However, increasing Chinese petroleum product exports does not increase global final demand for oil. It cannot be viewed as a fundamentally bullish factor for oil prices. Bottom Line: Stagnant domestic crude oil output and rising net exports of Chinese petroleum products will also lead to an increase of China’s crude oil imports.  Investment Implications Chart 16China: An Increasingly Important Factor For Global Oil Demand Strong crude oil imports by China have supported global oil prices in recent years. China has become an increasingly important driving force of global oil demand. Its oil imports currently make up about 12% of global oil demand, more than doubled from a decade ago (Chart 16). The country’s crude oil imports will continue expanding this year. Even at a slower rate, the robust oil consumption and imports from China will remain a positive factor for global oil prices in 2021. Beyond 2021, however, the country’s crude oil import growth outlook is facing increasing downside risks. Demand that is due to inventory accumulation is ultimately finite and non-recurring. Moreover, more oil accumulations in 2021 on top of China’s already elevated oil inventories may weigh on Chinese oil imports beyond 2021. In the meantime, US crude oil producers may benefit from continuing strong purchases from China. In 2020, China significantly ramped up its crude oil imports from the US, as the country has pledged to boost purchases of US energy products under the phase one trade deal signed with President Trump in January 2020. Chart 17Chinese Imports Of US Crude Oil May Continue To Rise In 2021 In 2020, Chinese imports of US crude oil in volume terms were 155% higher from a year before (Chart 17, top panel). Its share of total Chinese crude oil imports also spiked from 1-2% in late 2019 to 7-8% in the past several months (Chart 17, bottom panel). In the meantime, China’s share of US crude oil export also jumped from 4.6% in 2019 to 14.7% last year. In 2021, our baseline view is that China will want to show goodwill to the newly elected Biden administration by continuing to boost its crude oil purchase from the US. This will benefit US crude oil producers. However, if China buys more from the US, it may buy less from other countries.   Ellen JingYuan He  Associate Vice President ellenj@bcaresearch.com     Footnotes 1By deducting crude oil used in refineries and in direct final consumption from the total supply, we derived the flow of inventory and the level of changes in inventory. By using the cumulative value of the flow inventory data, we were able to derive the stock of inventory. We assume the initial inventory in 2006 was zero. This assumption is reasonable as the first fill of the SPR was in 2007 and the stock of CPR was extremely low at that time as well. In addition, based on the data from the National Bureau of Statistics, we found out that the direct final consumption of crude oil without any transformation only accounted for about 1-2% of total supply. 2 In 2004, the government planned three phases of SPR construction, targeting 10-12 million tons of crude oil SPR for the first phase, 28 million tons for the second phase, and another 28 million tons for the third phase. 3The import quota for independent refiners in 2021 has been increased by 20% (about 823 kbpd), and the country’s refinery capacity will expand at about 500 kbpd per year over 2021-2025. Cyclical Investment Stance Equity Sector Recommendations

Highlights WTI futures contracts delivering into Cushing, Oklahoma, in June could trade or go off the board below $0.00/bbl next month, just as the May contracts did this month, when they changed hands at a low of -$40.32/bbl last week.  Oil storage at this critical hub is approaching its practical limit of 80% full, raising the odds of sub-zero pricing (Chart of the Week). Pricing pressures will accelerate the rate of oil-supply destruction in the US, particularly in the prolific shale-oil basins.  We are revising our estimate of US production losses upward to 1.6mm b/d this year, and to 2.3mm b/d from January 2020 to December 2021. Retail speculation – in the US via ETFs and long-only index exposure, and in China via bank wealth-management products – is compounding WTI price volatility. The CME Group, which operates the NYMEX WTI futures and options markets, will be forced to address storage constraints in Cushing, and will have to better manage retail-spec positioning: These factors increase the probability of negative pricing and exacerbate price volatility as contracts go off the board. Feature The stunning -$40.32/bbl print for May 2020 WTI futures last week marks the first time this global oil benchmark has traded below $0.00/bbl. Negative prices are nothing new to non-storable commodities. In electricity markets, for example, wholesale prices go negative to force generation offline to balance supply and demand so that markets clear.1 Negative pricing also is seen in natural gas markets. It is occurring in the Permian basin with greater frequency, due to insufficient pipeline take-away capacity for all of the associated gas being produced there as oil output in the basin soars. This leaves no alternative to producers but to either shut in oil production or flare the associated gas. Indeed, forward natgas prices at the Waha Hub in Pecos County, Texas, recently have traded below zero for prolonged periods, owing to the surge in Permian oil production (Chart 2).2 Chart of the WeekCushing Approaches Crude Storage Limit Chart 2Lack Of Storage Pushes Natgas Prices Below Zero   Markets once again were reminded WTI futures are far more than electronic blips on computer screens: They are binding legal contracts to physically deliver light-sweet West Texas Intermediate (WTI) crude oil into the Cushing, Oklahoma, pipeline and storage hub. The stunning -$40.32/bbl print for May 2020 WTI futures last week marks the first time this global oil benchmark has traded below $0.00/bbl since the 1983 introduction of the NYMEX crude oil futures (Chart 3). Markets once again were reminded WTI futures are far more than electronic blips on computer screens: They are binding legal contracts to physically deliver light-sweet West Texas Intermediate (WTI) crude oil into the Cushing, Oklahoma, pipeline and storage hub. Going off the board long requires contract holders to take delivery into a pipeline or storage facility; going off short requires contract holders to make delivery. Chart 3WTI June Futures Could Go Below $0.00/bbl Owing to structural flaws in the delivery mechanism for WTI futures, and what appears to be a lapse in monitoring positions in the spot-month contract as May 2020 WTI was going off the board last week, the likelihood June 2020 WTI contracts pricing below $0.00/bbl is high. These flaws must be addressed by the CME Group’s NYMEX division and federal regulators, given the WTI futures contract’s importance to the global physical market and the capital at risk. Implications Of Negative WTI Prices Storage at Cushing is, for all intents and purposes, full. Cushing accounts for ~ 15% of the total 653mm barrels of US crude oil storage, which was only at 60% of capacity in mid-April, based on the US EIA’s reckoning. However, Cushing is the delivery point of the physically settled WTI futures contracts traded on the NYMEX. With close to 80% of capacity filled – ~ 58mm barrels of the total capacity of ~ 76mm barrels – the operational limit of storage has been reached at Cushing. This is amply seen in the June-vs-July intermonth spread between futures, which, earlier this week, settled at more than $5/bbl – i.e., more than 10x the then-elevated 50 cents/bbl/month being charged to store oil in Cushing in March (Chart 4). Intermonth spreads are used as proxies for the cost of storage for physically delivered contract that actually can be stored, like oil. If physical surpluses cannot be moved out of regions where storage is full – and pipelines also are full – prices are forced lower and lower until enough production is shut in to allow storage to drain and inventories to return to normal levels. This is happening now in Oklahoma and the prolific Texas shale basins, and other shale basins in the US where horizontal rigs are being laid down and drilling crews are being laid off (Chart 5). Chart 4Intermonth-Spread Blow Out Indicates Full Cushing Storage Chart 5Texas Horizontal Rig Counts Collapse We are revising our estimate of US production losses upward for this year, and to 2.3mm b/d from January 2020 to December 2021. In our most recent modeling of US shale-oil production, we expect these pricing pressures to accelerate the rate of oil-supply destruction, particularly in the prolific shale-oil basins. In fact, we are revising our estimate of US production losses upward for this year, and to 2.3mm b/d from January 2020 to December 2021 (Chart 6). Depending on how long WTI prices stay depressed in the key producing basins, this supply destruction could be even more pronounced. The same is true of global storage: Kpler, the oil-storage tracker, last week estimated global onshore inventories were 85% full.3 Until sufficient supply destruction occurs to offset the COVID-19-induced demand destruction, inventories cannot draw. Floating storage also is surging, as the crude and product forward curves fall deeper into contango, and incentivize holding stocks on the water (Chart 7). Chart 6Lower Prices Will Push US Oil Output Lower Chart 7Floating Storage Volumes Surge Price will go low enough – negative if needs be – to clear surplus supply to rebalance markets. Storage acts as a shock absorber for physical commodities like crude oil – when there is more supply than demand, the physical surplus is moved to storage until it is needed, and vice versa when there is a physical deficit. When inventories fill in Cushing – arguably the most important crude-oil delivery hub in the world, given WTI is the most liquid crude oil futures contract in the world – it is as if there is no storage at all there. At this point, market for WTI behaves a lot like electricity, which cannot be stored (at least at utility scale), or natgas at Waha, where storage and pipeline takeaway capacity are in very short supply. In such circumstances, price will go low enough – negative if needs be – to clear surplus supply to rebalance markets. This appears to be what spooked markets last week when WTI futures for May delivery traded as low as -$40.32/bbl. Retail Specs Push WTI Volatility Higher Speculators perform a vital and necessary function in futures markets – they willingly accept risk hedgers want to shed. Natural longs – i.e., producers – do not want to sell when prices are low, which is when natural shorts want to buy. Likewise, natural shorts – i.e., consumers – don’t want to buy when prices are high, which is when natural longs want to sell. Speculators provide the liquidity that allows producers and consumers to hedge. When prices are relatively high, they can provide a bid to oil producers looking to hedge production – they may be short-term traders or have a view prices are going higher, or they may be getting out of short positions they put on earlier. When prices are low, speculators provide offers – selling futures because they are short-term traders, or have a view prices are going lower, or they are getting out of long positions. Speculators trade on information and typically never stand for delivery of futures like WTI, which means they typically are out of prompt-month contracts before they are getting ready to go off the board. At that point, only physical-market participants – producers, consumers and physical traders – are left in the market balancing their physical books. When speculators find themselves trading WTI futures as they are getting ready to go to delivery, something in their risk-management systems has gone terribly wrong. Not only do they not trade the physical oil, but they don’t know who to call to take them out of their risk. Something also has gone terribly wrong at the regulatory level: At the CME, which, as the operator of the NYMEX oil trading markets, and at the US Commodity Futures Trading Commission (CFTC) in Washington, D.C. The CME is the self-regulatory organization responsible for ensuring its rules are followed and markets trade in an orderly fashion, and, at the federal level, the CFTC exercises oversight and enforces laws and regulations. It appears Bank of China (BOC), the fourth largest bank in China and the world, has found itself holding long positions in WTI futures delivering in May on the last two days of trading last week. These contracts supported wealth-management products – known as “bao” or treasure – the state-owned bank offered its retail clients.4 Other banks in China also offer such products, but it appears BOC was the only one that did not roll out of its delivery exposure in a timely manner.5 The exposure BOC was trying to trade out of was not huge by normal standards, but after settling its open May futures at -$37.63/bbl, BOC clients apparently lost close to $1.3 billion.6 How the CME or the CFTC allowed a commercial bank with no capability to take delivery of WTI in Cushing against a long NYMEX WTI futures contract as it was going off the board is a mystery. Markets will have to wait for a detailed post-mortem to determine what exactly happened, and how. Retail Piles Into WTI Exposure The experience of BOC – and, most likely, the shock of such deeply negative WTI prices realized upon settlement of these contracts – and a change in US regulations on spot-month position limits for futures used by commodity-pool operators prompted a wholesale exodus from spot-month WTI futures – the June 2020-delivery WTI futures that deliver in Cushing – this week. As a result, the commodity-pool operator running the United States Oil Fund (USO) ETF and S&P Dow Jones, which designs and markets long-only commodity index products for investors – e.g., the S&P GSCI index – rolled their June WTI futures into July and later months in an effort to avoid holding length in the June contract out of fear these futures could trade negative.7 USO is geared to retail investors, and inflows are negatively correlated with front-month WTI futures prices – when prices tank retail investors pile into the ETF (Chart 8). This can dramatically increase the number of futures the fund has to buy to provide its product to retail investors. Chart 8Retail Piles Into WTI Futures Exposure Markets were exceptionally volatile early in the week as these fire sales were being executed. The $3.6 billion USO ETF, in particular, apparently was ordered to spread its spot-month exposure (June WTI) across the forward curve by the CME over the first three days of this week. This action was taken to keep the USO ETF from exceeding new position-limit levels in the spot-month contract, which go into effect May 1, and state no entity can have more than 25% of total open interest in the WTI spot contract.8 Markets were exceptionally volatile early in the week as these fire sales were being executed. This rolling out of June WTI exposures should reduce – but not eliminate – the selling pressure on front-month WTI futures contracts by providers of retail and institutional commodity exposure as June goes off the board next month. However, if storage at Cushing remains at tank tops, the rolling by these ETFs that source futures liquidity to hedge their exposures could again push spot prices below $0.00/bbl as the June WTI futures go off the board May 19.9 That said, it is difficult to ascertain exactly what exposure retail investors are getting now when they buy the USO ETF – its WTI futures now span contracts into next year, based on news reports. This could prompt investors to jettison positions, setting up another round of fire sales in WTI futures. Markets also will expect a post-mortem explaining how the CME and CFTC allowed this retail-focused fund could exceed position limits in spot-month WTI futures contracts so significantly at any point in time, let alone when Cushing infrastructure is so extraordinarily taxed. WTI Futures Contract Flaws Contribute To Volatility The CME has failed to find a way to ensure those holding futures that are going off the board are bona fide hedgers capable of making and taking delivery, as the BOC experience showed. The CME Group has not acquitted itself well in the termination of May 2020 futures trading. And, as researchers at the Oxford Institute for Energy Studies note, the past couple of weeks have exposed deep flaws in the WTI futures contracts’ physical-delivery mechanisms, which have been persistent.10 The lack of sufficient storage at Cushing to accommodate the volume of trading in WTI futures is not a new problem. In 2009, the Kingdom of Saudi Arabia changed its pricing benchmark for US sales to the Argus Sour Crude Index for its crudes sold into the US Gulf, because the WTI contract detached from fundamentals then owing to infrastructure constraints at Cushing. The CME has failed to find a way to ensure those holding futures that are going off the board are bona fide hedgers capable of making and taking delivery, as the BOC experience showed. In addition, the CME has shown it has no institutionalized automatic delivery procedures that kick in when Cushing storage is full – e.g., making and taking delivery, say, in the US Gulf using a WTI contract loaded for export, as the OIES researchers observe. Lastly, as of April 22, the CME is using an options-pricing model based on the original theory on random walks developed by the great Louis Bachelier in 1900, which assumes prices are normally distributed and can go below zero, vs. its previous methodology using Fischer Black’s commodity option pricing model, which assumes prices are log-normally distributed and have a lower boundary of zero.11 We’ll be exploring this in further research.   Robert P. Ryan Chief Commodity & Energy Strategist rryan@bcaresearch.com     Commodities Round-Up Energy: Overweight Exports from OPEC countries increased by more than 2mm b/d in April – led by Saudi Arabia and UAE – according to Petro-Logistics – a seaborne oil trade analytics company. This is flooding global markets while global demand is expected to drop to its lowest level since 2Q03 this month. Separately, we are revising up our Canadian oil sands shut-in estimates to ~ 800k b/d in 2Q20 from ~ 500k b/d, as US demand for Canadian oil will be hit more severely than we previously anticipated and local storage is filling rapidly. Rystad Energy now expects Canadian capex to fall 41% y/y in 2020. This will have a lasting impact on the industry’s production capacity. Base Metals: Neutral The LMEX rose 3% since the start of April – led by nickel and copper prices moving up by ~ 6%. Base metals – chiefly aluminum and copper – are poised to rebound in 2Q20 if China’s economy continues to improve and is not hit by a second wave of COVID-19 infections. According to BCA’s China Investment Strategy, the country’s fiscal response is now expected to reach 10% of its GDP this year. This will support further upside in base metals prices (Chart 9). Precious Metals: Neutral Despite the record fiscal and monetary stimulus deployed globally, consumer and market-based inflation expectations remain low, as markets focus on the deflationary effects of the COVID-19 shock and the uncertainty about the speed of the recovery (Chart 10). The low realized inflation post-GFC stimulus could influence investors’ expectations down. We see inflation risks as materially higher which will warrant larger protection in a diversified portfolio over the coming year. Inflation expectations will normalize later this year and next, boosting inflation hedges. Nominal bonds’ protection will remain expensive as rates in major DM countries are expected to stay low for a prolonged period. Chart 9 Chart 10       Footnotes 1     Please see Bajwa, Maheen and Joseph Cavicchi, “Growing Evidence of Increased Frequency of Negative Electricity Prices in U.S. Wholesale Electricity Markets.” IAEE Energy Forum, 4th Quarter 2017. 2     Please see U.S. Gas Prices Turn Negative at Texas Waha Hub published by the Pipeline & Gas Journal March 3, 2020. The article notes, “The first swing to negative spot prices in almost seven months occurred due to pipeline constraints and as mild weather cut heating demand. Prices in the forward market have been trading below zero for weeks on expectations there will not be enough pipelines to transport record amounts of gas from the region’s shale oil fields. That gas that comes from oil wells, called associated gas in the industry, helped propel U.S. gas output to record highs, driving prices to their lowest in years as production outpaces demand for the fuel. Analysts expect gas prices in 2020 to fall to their lowest since 1999.” 3    Please see Oil prices sink as world runs low on storage capacity amid frail demand published by reuters.com April 28, 2020. The IEA estimates total onshore storage globally at close to 7 billion barrels, according to the Center for Strategic & International Studies in Washington, D.C. Please see The Oil Inventory Challenge published by the CSIS April 20, 2020, which notes the US has ~ 1.3 billion barrels of storage, while China has an estimated 1.5 billion barrels. Of that ~ 7 billion barrels of nameplate capacity, ~ 80%, or ~ 5.6 billion barrels, represents the operational limit. 4    Please see The world's 100 largest banks published by S&P Global Market Intelligence April 5, 2019. 5    Please see China's ICBC closes commodity-linked products to new investment published by reuters.com April 27, 2020. 6    Please see Bank of China says main investors to settle crude oil product at -$37 published by reuters.com on April 22, 2020. 7     Please see Futures contract moves endangering WTI prices again published by worldoil.com April 28, 2020. 8    Please see USO ETF pushes oil futures exposure out to June 2021 published by etfstrategy.com April 27, 2020. Earlier this month, the USO ETF has accounted for close to 30% of June WTI futures. Please see Biggest Oil ETF Shakes Up Structure published by etf.com April 17, 2020. 9    The USO ETF is not the only fund sourcing futures liquidity to provide retail exposure to WTI, but it is by far the largest. Please see Oil ETF roils already volatile crude markets published April 27, 2020, by investmentnews.com. 10   Please see Oil Benchmarks Under Stress published by OIES April 28, 2020. 11    Please see Davis, Mark, and Alison Etheridge. Louis Bachelier's Theory of Speculation: The Origins of Modern Finance. Princeton University Press, 2006; and Black, Fischer, “The Pricing of Commodity Contracts,” Journal of Financial Economics, Vol. 3, (1976), pp. 167-79, reprinted with permission in Interrelations Among Futures, Option, and Futures Option Markets (1992), the Board of Trade of the City of Chicago publisher.     Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Trade Recommendation Performance In 2020 Q1 Commodity Prices and Plays Reference Table Trades Closed In 2020 Summary of Closed Trades

Highlights The May-June WTI spread settled earlier in the week at a $7.29/bbl contango, the widest level since February 2009 during the GFC. This reflects an extraordinarily tight storage market in the US Gulf and Midcontinent. WTI for May delivery breached $20/bbl Wednesday, touching a 18-year low (Chart of the Week). Output cuts starting in May agreed by OPEC 2.0 over the weekend will remove 6.1mm b/d on average for May-December vs. 1Q20 levels. Additional losses outside OPEC 2.0 will reduce global supply 4.5mm b/d y/y. We raised our estimate of COVID-19-induced demand destruction in 2Q20 to 14.6mm b/d from 12.1mm b/d. We expect demand to fall ~ 8mm b/d in 2020 vs. our previous estimate of 4mm b/d, as global fiscal and monetary stimulus revives growth in 2H20. We expect 2021 demand to rise 7.7mm b/d, averaging 100.6mm b/d. In our updated forecast, Brent is expected to average $39/bbl – slightly above our earlier $35/bbl estimate – as incremental supply losses offset lower demand. Our Brent forecast for 2021 remains ~ $65/bbl. WTI will trade $2-$4/bbl lower. Feature   April is the cruellest month … - T.S. Eliot, The Waste Land1 Global oil logistical capacity will be tested in extremis this month, as cargoes laden with oil arrive in ports that have no need for ready supply and few storage options to hold the crude until its needed. This is filling traditional global storage, inland pipelines and ships, which, as typically occurs in extremis, are used as floating storage (Chart 2). Chart of the WeekCrude Oil In Extremis Chart 2Floating Storage Volumes Soar As Terminals and Pipelines Fill The most extreme testing of global logistics likely will occur in this cruel month, to borrow once again from the laureate, as markets are forced to absorb the production surge from OPEC 2.0 – mostly from KSA and its allies. Repeated excursions to and through $10/bbl in physical markets, as already have been registered in Canada and US shale basins, can be expected this month (Chart 3). Indeed, we expect price pressures to reduce US oil ouput – mostly in the shales – by 1.5mm b/d or more.2 Beginning in May, OPEC 2.0 will begin cutting production, with its putative leaders – KSA and Russia – accounting for 1.3mm b/d and 2.1mm b/d, respectively, of the coalition’s total pledged cuts of 7.6mm b/d vs. 1Q20 production levels. (Based on OPEC 2.0’s October 1, 2018, reference level – except for KSA and Russia, both of which are cutting from a nominal 11mm b/d level – the cuts amount to 9.7mm b/d for May-June, and 7.7mm b/d for 2H20).3 Chart 3Cash Markets Pressing /bbl While the official OPEC communique notes the coalition also will implement a 6mm b/d cut from January 2021 to April 2022, we doubt this will be necessary. The coalition meets again in June, and KSA’s Energy Minister, Prince Abdulaziz bin Salman, said the Kingdom is prepared to increase its cuts if needed.4 Based on historical experience, we expect KSA to over-deliver on cuts, and for Russia to gradually meet its pledged volumes. We are haircutting other states’ production cuts based on historical observation, and are projecting cuts of ~ 75% for 2020 and 70% for 2021 compliance (Table 1). Additional losses outside OPEC 2.0 will reduce global supply 4.5mm b/d y/y on average. Table 1BCA Global Oil Supply - Demand Balances (MMb/d, Base Case Balances) Lowering Our Demand Forecast The COVID-19 pandemic, which, owing to the global lockdowns, has literally shut the majority of the world’s economies down, and produced a global GDP contraction far greater than the recession the Global Financial Crisis (GFC) produced in 2008. Our estimate of COVID-19-induced demand destruction in 2Q20 is now 14.6mm b/d, up from 12.1mm b/d. For all of 2020, we expect demand to fall 7.9mm b/d in our base case vs. our previous estimate of 4mm b/d. These estimates are highly conditional on the trajectory of the containment of the COVID-19 pandemic, which, owing to the global lockdowns, has literally shut the majority of the world’s economies down, and produced a global real GDP contraction far greater than the recession the Global Financial Crisis (GFC) produced in 2008 (Chart 4). Nonetheless, we believe the massive global fiscal and monetary stimulus now being deployed will restore growth beginning in 2H20 and carrying through to expect 2021 demand to rise 7.7mm b/d, and to average 100.6mm b/d (Chart 5). Chart 4COVID-19 Real GDP Hits Dwarf 2009 GFC Recession Chart 5Massive Stimulus Will Revive Demand We assume OPEC 2.0 will be required to raise production in 2021 to keep prices from accelerating too fast. While our demand expectations are slightly weaker, in our modeling we see supply being curtailed sufficiently to produce a physical deficit beginning in 3Q20 (Chart 6). Our supply-demand trajectory projects a peak in OECD storage of 3.7 billion barrels in May, after which inventories fall sharply (Chart 7). Indeed, we assume OPEC 2.0 will be required to raise production in 2021 to keep prices from accelerating too fast. Chart 6Oil Supply-Demand Balances Point To Physical Deficit By 4Q20 Chart 7Inventories Spike, Then Draw Sharply Two-Way Price Risk Our forecast assumes the COVID-19 pandemic is contained and that fiscal and monetary stimulus re-energizes global growth. In our updated forecast, we see Brent averaging $39/bbl this year – slightly above our earlier $35/bbl estimate – as incremental supply losses offset lower demand. Next year, our expectation remains ~ $65/bbl. WTI will trade $2-$4/bbl lower (Chart 8). As noted above, our forecast assumes the COVID-19 pandemic is contained and that fiscal and monetary stimulus re-energizes global growth. However, as the pandemic spreads deeper into less-developed EM economies without robust public-health infrastructures, or social security systems providing a basic income in the event of job loss due to recessions the risk of widespread infection rises significantly.5 Chart 8Stronger Price Recovery Expected No amount of fiscal or monetary stimulus will allow an economy to weather such a storm. This is a clear and present danger to the global recovery and to a recovery in commodities generally, oil in particular. Investment Implications Our expectation for prices is reflected in Chart 8, premised, again, on COVID-19 being contained and fiscal and monetary stimulus reviving global growth. We are retaining our long exposure to the market, expecting the supply and demand policies set in motion will be effective. However, there is no way of accurately assessing the likelihood of an uncontained pandemic hitting EM markets, and, from there, re-entering other markets that presumably have dealt with the coronavirus.   Robert P. Ryan Chief Commodity & Energy Strategist rryan@bcaresearch.com Hugo Bélanger Associate Editor Commodity & Energy Strategy HugoB@bcaresearch.com Fernando Crupi Research Associate Commodity & Energy Strategy FernandoC@bcaresearch.com   Commodities Round-Up Energy: Overweight Global oil inventories will be filled rapidly in 2Q20 as major economies remain in lockdowns. High-cost Canadian oil sand producers will be severely hit as their output is landlocked, distant from key demand centers, and facing storage and pipeline infrastructure constraints. More than 500k b/d of production will be shut-in in April and May as crude-by-rail collapses, local and US refinery runs are reduced, and Alberta’s limited inventory moves closer to its maximum capacity – estimated at ~ 90mm bbls (Chart 9). Separately, a €20/MT stop to our EUA futures recommendation was triggered on April 14, 2020, leaving us with a 14.2% gain. Base Metals: Neutral China’s iron ore imports fell to 85.9mm MT in March, a decline 0.6% y/y, after growing 1.5% in January and February. This came as steel mills arranged maintenance or slowed production to deal with record-high inventories after the COVID-19 pandemic curtailed construction and industrial activities. However, in the long run the outlook for iron ore and steel appears to be improving. Mysteel data for China indicates utilization rates at blast furnaces have been rising for four weeks and are now at ~ 79%. Chinese Steel exports also picked up in March, up 2.4% from a year earlier, but are now facing new anti-dumping duties on stainless steel in the EU. Precious Metals: Neutral Gold continues to trade above $1700/oz – reaching its highest level since October 2012 – supported by easing fiscal and monetary policy in the US and fear of a prolonged economic slowdown. A lower US dollar – the DXY index fell back below 100 last week – and depressed real rates supported gold’s move higher (Chart 10). Dollar debasement risks and negative real rates increase gold’s attractiveness as a safe asset. Ags/Softs:  Underweight China’s March soybean imports came in at 4.28mm MT y/y, the lowest level since February 2015. Rains in Brazil delayed that country’s exports to China. The fall also reflects a 6% contraction in soymeal (i.e., the “crush”) consumed by livestock – as the African Swine Fever slashed China’s pig herd by more than 40% and shortages forced operations to grind to a halt. Similarly, meat suppliers in the US and Canada are closing plants temporarily due to COVID-19 cases among employees. As a result, Chicago soybean futures traded 0.8% lower on Tuesday. Chart 9Limited Storage Capacity In Alberta Chart 10Lower US Rates And Dollar Support Gold   Footnotes 1     The Waste Land, by T.S. Eliot, originally was published in 1922 in The Criterion, which was founded and edited by Eliot. 2     The Texas Railroad Commission held day-long hearings April 14 to consider returning to its historic roll as an oil-production regulator on Tuesday.  As we went to press no ruling on the petition to revive pro-rationing was delivered.  The Oklahoma Corporation Commission will hold similar hearings next month.  Please see Texas and Oklahoma weigh production quotas for oil published by washingtonpost.com April 13, 2020. 3    Please see The 10th (Extraordinary) OPEC and non-OPEC Ministerial Meeting concludes, posted by OPEC April 12, 2020. 4    Please see Saudi energy minister leaves door open for more cuts in June, published by worldoil.com April 13, 2020. 5    Please see National governments have gone big. The IMF and World Bank need to do the same. This op-ed by Gordon Brown and Larry Summers, published by washingtonpost.com April 14, 2020, lays out some of the issues that elevate downside risk to a COVID-19 recovery.   Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Trade Recommendation Performance In 2019 Q4 Commodity Prices and Plays Reference Table   Trades Closed in 2020 Summary of Closed Trades

La diferencia de precio a la que el crudo pesado y ácido canadiense cotiza frente al referente norteamericano WTI se verá empujada a -$20/bbl hasta 1T20, ya que las limitaciones de transporte siguen ralentizando la salida del barril marginal desde Alberta. El aumento de la demanda de combustibles destilados de bajo azufre a medida que las normas mundiales de combustible marítimo se endurecen bajo las regulaciones IMO 2020 el próximo año también contribuirá a debilitar los precios del crudo canadiense. Durante los próximos tres a cinco años, la política interna determinará si la industria petrolera canadiense podrá atraer la inversión necesaria para crecer. Y eso dependerá de cómo se resuelva la incertidumbre en torno a la expansión de oleoductos. Permitir que la capacidad de los oleoductos se expanda para que más crudo pueda enviarse al sur podría conducir a un repunte significativo en las valoraciones de capital de los productores canadienses. Los costos de equilibrio de la industria ahora están a ambos lados de $50/bbl para crudo pesado entregado en Cushing, OK. A medida que la producción de crudo ligero y dulce en las lutitas de EE. UU. aumenta, la demanda por el crudo relativamente escaso y más pesado probablemente se recupere, redundando en beneficio de los productores canadienses. Aspectos destacados Energía: Sobreponderar. Las operaciones en la instalación de procesamiento de crudo Abqaiq y en el yacimiento petrolero Khurais de Saudi Aramco se restablecieron en gran medida a finales de septiembre, en línea con la orientación de la dirección. La capacidad en el Reino es de 11.3mm b/d, mientras que la producción funciona en 9.9mm b/d. Abqaiq y Khurais fueron atacados por drones y misiles de crucero, una operación que EE. UU. y Arabia Saudita creen fue orquestada por Irán. El domingo, el príncipe heredero Mohammad bin Salman, hablando en 60 Minutes de CBS News, estuvo de acuerdo con la caracterización del secretario de Estado estadounidense Mike Pompeo del ataque como un acto de guerra por parte de Irán, y advirtió: “Si el mundo no toma una acción fuerte y firme para disuadir a Irán, veremos más escaladas que amenazarán intereses mundiales. Los suministros de petróleo se verán interrumpidos y los precios del petróleo subirán a números inimaginablemente altos que no hemos visto en nuestras vidas.” En la entrevista con Norah O’Donnell, añadió una declaración de que el Reino prefiere “una solución política y pacífica” para resolver sus problemas con Irán. El príncipe heredero, con un tono conciliador, dijo que el presidente Donald Trump y el Reino buscan la paz, pero que “los iraníes no quieren sentarse en la mesa.”1 Metales básicos: Neutral. La producción de acero de China aumentó 9.3% interanual en agosto a 87.3k MT, según la World Steel Association (WSA). Esto representó el 56% de la producción global, según datos de la WSA. La producción china alcanzó un récord de 89.1k MT en mayo. Metales preciosos: Neutral. Los precios de los metales preciosos colapsaron cuando el amplio USD ponderado por el comercio se disparó a principios de esta semana. Los precios del platino cayeron 5.5% desde el cierre del viernes hasta el martes, mientras que el oro y la plata bajaron 1.3% y 2%, respectivamente. Agrícolas/Productos blandos: Infraponderar. Los precios del maíz y la soja se dispararon a principios de la semana tras un informe alcista del USDA sobre existencias. El maíz de diciembre subió 5.7%, mientras que la soja subió 4.1%. Artículo principal La demanda de crudo pesado canadiense está funcionando con fuerza en Asia, como se ve en el aumento de las exportaciones a través del Golfo de EE. UU. durante el periodo de mayo a mediados de septiembre. Según el análisis de ClipperData, se enviaron 16mm de barriles de crudo canadiense en ese periodo, más del doble del volumen total enviado a Asia en 2018.2 La demanda canadiense se está viendo impulsada por el colapso de la industria petrolera de Venezuela, que ha eliminado alrededor de 1.5mm b/d de crudo pesado del mercado desde 2016. Si bien las exportaciones canadienses a los mercados asiáticos están en auge, este aumento de la demanda insinúa una oportunidad aún mayor si se expande la capacidad de oleoductos de norte a sur. Las exportaciones acumuladas de crudo canadiense a EE. UU. en lo que va del año suben ~ 2.5% interanual a un promedio de 3.5mm b/d, según la EIA de EE. UU. Este crecimiento está limitado por la capacidad de exportación que se expande lentamente.3 Restricciones de salida del petróleo canadiense De 2010 a 2017, la producción de petróleo del oeste de Canadá creció un impresionante 6.5% anual, llevando la infraestructura de oleoductos y almacenamiento a una utilización máxima (Gráfico de la semana). El desarrollo de la infraestructura de apoyo no produjo la capacidad de salida requerida, encerrando la producción de betún dentro de la Cuenca Sedimentaria del Oeste de Canadá (WCSB). En consecuencia, los inventarios de crudo de Alberta crecieron por encima de niveles normales y el descuento del Western Canadian Select (WCS) respecto a Cushing WTI se disparó, alcanzando -$50/bbl en 3T18. Si bien esto incentivó los envíos de crudo por ferrocarril (CBR), los precios recibidos por los productores albertense cayeron por debajo de $20/bbl, un nivel significativamente inferior a los niveles de equilibrio necesarios para sostener la inversión. Gráfico de la semana El aumento de la producción de crudo pesado ... La producción de crudo pesado se dispara ... La producción de crudo pesado se dispara ... Ante múltiples retrasos en los desarrollos de oleoductos, la entonces primera ministra Rachel Notley anunció en diciembre que el gobierno provincial impondría restricciones obligatorias de producción de petróleo de ~ 325k b/d a partir de enero de 2019. Además, su gobierno aseguró contratos para arrendar 4,400 vagones de ferrocarril – ~ 120k b/d para mediados de 2020 – con Canadian National (CN) y Canadian Pacific (CP) para mover crudo fuera de la WCSB. La intervención del gobierno de Alberta distorsionó rápidamente el mecanismo de precios del mercado. Inicialmente, la reducción de producción ordenada por el gobierno tuvo el impacto deseado. El componente de transporte del descuento WCS-WTI comenzó a reducirse, y los inventarios de crudo de Alberta empezaron a disminuir (Gráfico 2). Gráfico 2 ... Pero la infraestructura se retrasa ... Pero la infraestructura se queda rezagada ... Pero la infraestructura se queda rezagada Sin embargo, la intervención del gobierno de Alberta distorsionó rápidamente el mecanismo de precios del mercado. Para ser rentable, mover petróleo por ferrocarril requiere un descuento WCS-WTI que se sitúe en algún punto entre -$12/bbl y -$22/bbl además de un descuento por calidad, y posiblemente más alto cuando se necesitan inversiones adicionales en trenes y tripulaciones (Gráfico 3). En enero de 2019, el descuento de transporte sobrepasó su equilibrio – estrechándose a -$2.90/bbl por debajo del componente de calidad – lo que debilitó los volúmenes de crudo por ferrocarril y condujo a una acumulación de inventarios. Gráfico 3 La política del gobierno provincial distorsiona la dinámica de precios del crudo pesado Probablemente se amplíen los diferenciales del crudo canadiense Probablemente se amplíen los diferenciales del crudo canadiense El gran acto de equilibrio Para abordar estos desequilibrios, el gobierno provincial comenzó a flexibilizar gradualmente las restricciones de producción (Gráfico 4). Pero esto es un trabajo en progreso: en última instancia, su objetivo es encontrar el equilibrio correcto entre los niveles de producción y el diferencial WCS-WTI – es decir, el incentivo de precio necesario para que el mercado mueva más crudo por ferrocarril (CBR). Los siguientes proyectos siguen avanzando por parte de los desarrolladores. Sin embargo, no se espera capacidad de salida adicional significativa antes de 2S20 (Gráfico 5): Gráfico 4 La política sigue siendo un trabajo en progreso Probablemente se amplíen los diferenciales del crudo canadiense Probablemente se amplíen los diferenciales del crudo canadiense Gráfico 5 Los mercados intentan corregir el déficit de salida Diferenciales del crudo canadiense probablemente se amplíen Diferenciales del crudo canadiense probablemente se amplíen Reemplazo de la Línea 3 de Enbridge. Este oleoducto forma parte del sistema Enbridge Mainline. Este proyecto restaurará la capacidad original del oleoducto Línea 3 existente a 760k b/d desde 390k b/d. El reemplazo va desde Hardisty, AB, hasta Superior, WI en EE. UU. Desde su anuncio inicial en 2014, el proyecto ha enfrentado múltiples vientos en contra, más recientemente, un retraso en los permisos del Estado de Minnesota respecto al impacto de un posible derrame cerca del Lago Superior. La compañía sigue esperando que el proyecto se complete en 2S20. Las porciones canadienses y de Wisconsin ya están completadas. Keystone XL de TC Energy. Este es el mayor de los proyectos propuestos. Aumentará la capacidad de exportación canadiense a EE. UU. en 830k b/d. El proyecto fue propuesto por primera vez en 2008, y correrá de Hardisty, AB a Steele City, NE. Recientemente, la Corte Suprema de Nebraska aprobó la ruta de Keystone XL, levantando uno de los últimos retos legales pendientes – y probablemente el más importante – que enfrentaba la construcción del oleoducto. Esto es un desarrollo positivo para los productores canadienses de petróleo. No obstante, el proyecto aún enfrenta una demanda federal en Montana presentada por grupos ambientalistas que bloquea el nuevo permiso del presidente Trump, el cual dio luz verde al proyecto. Se programó una vista para el 9 de octubre; esto es una victoria crucial para TC Energy.4 Tomar una Decisión Final de Inversión (DFI) antes de fin de año hace posible una finalización para finales de 2022. Expansión federalmente propiedad de Trans Mountain. La solicitud inicial se presentó en 2013 y se proyecta que agregará 590k b/d de capacidad desde Edmonton, AB, hasta Burnaby, B.C. El oleoducto fue comprado por $4.5 mil millones el año pasado por el gobierno federal. A principios de este mes, un juez del Tribunal Federal de Apelaciones rechazó seis de los 12 desafíos legales a la expansión, desestimando reclamaciones centradas en cuestiones medioambientales. La construcción continuará; el gobierno espera que la expansión esté operativa a mediados de 2022. Expansión de capacidad en oleoductos existentes. Esperamos que se produzcan algunos aumentos marginales de capacidad en oleoductos existentes entre 3T19 y 3T20. Enbridge comunicó que podría añadir hasta 450k b/d sin construir nuevos oleoductos para 2022. En este momento, creemos que ~150k b/d se añadirán gradualmente antes de finales del próximo año. Además, Enbridge mencionó que podría aumentar la capacidad en su línea Express en ~60k b/d antes de finales de 2020. Por último, Plains Midstream Canada anunció capacidad adicional en su línea Rangeland en ambas direcciones, Norte y Sur.5 Esto ayudará a los productores canadienses que esperan el reemplazo de la Línea 3 en 2S20. Los retrasos en poner en línea nueva capacidad de salida obligaron al nuevo gobierno provincial Conservador dirigido por Jason Kenney, que llegó al poder en abril de 2019, a extender el programa de recortes hasta diciembre de 2020. Esperamos que este acto de equilibrio continúe durante los próximos 12 meses.6 Perspectiva a corto y medio plazo Esperamos que las necesidades de CBR superen 450k b/d para equilibrar el mercado En nuestro informe del 7 de marzo de 2019, argumentamos que el componente de transporte del diferencial WCS-WTI necesitaba aumentar en ~ $10/bbl para apoyar volúmenes incrementales de crudo por ferrocarril. De marzo a julio, el descuento de transporte aumentó solo $4.80/bbl hasta ~$12/bbl – el límite inferior de nuestro rango estimado de precio ferroviario – y se derrumbó poco después. Esto no logró catalizar volúmenes ferroviarios suficientes para despejar el exceso del mercado. Las estimaciones preliminares de los volúmenes de CBR basadas en datos de CN y CP muestran que se mantuvieron en gran medida planos en agosto y septiembre (Gráfico 6). Gráfico 6 Los envíos por ferrocarril se estancan Envíos de crudo por ferrocarril se estancan Envíos de crudo por ferrocarril se estancan A medida que el gobierno continúa relajar los recortes de producción – alcanzando 100k b/d en octubre – seguimos creyendo que el descuento de transporte necesita subir desde los niveles actuales. Los movimientos recientes en el descuento, promediando $10.3/bbl desde principios de mes, respaldan nuestra visión, y esperamos que esto continúe hasta que alcance ~$15/bbl. Esperamos que las necesidades de CBR superen 450k b/d para equilibrar el mercado hasta que el reemplazo de la Línea 3 se complete, en algún momento de 2S20 (Gráfico 7). También esperamos que el descuento por calidad del crudo WCS comience a aumentar a medida que se acerque IMO 2020. En lo que va del año, el descuento por calidad se ha mantenido relativamente estrecho, debido a la escasez global de oferta de crudo pesado y ácido (Gráfico 8).7 A partir de enero de 2020, la demanda de crudo pesado se moderará a medida que los transportistas se adapten a la nueva regulación de combustible marítimo, compensando parte del efecto de la oferta limitada. Proyectamos que esto añadirá $5/bbl al diferencial WCS-WTI. Gráfico 7 Se requiere capacidad adicional de CBR Se requiere capacidad CBR adicional Se requiere capacidad CBR adicional Gráfico 8 El mercado de crudo pesado sigue apretado El mercado del crudo pesado sigue ajustado. El mercado del crudo pesado sigue ajustado. Combinados, el descuento por calidad y el de transporte deberían empujar el diferencial WCS-WTI hacia -$20/bbl durante los próximos 6 meses, lo que, creemos, perjudicará los flujos de caja de los productores canadienses. Esperamos que la oferta de la WCSB se mantenga plana interanual en 2019. El próximo año, se espera que la producción crezca 4%, y en 2021 otro 1.2% interanual. Perspectiva de producción a largo plazo La inversión en el sector petrolero canadiense nunca se recuperó verdaderamente del colapso de los precios del petróleo de 2014, a pesar del repunte de los precios del crudo (Gráfico 9). El gasto de capital total de Canadá excluyendo petróleo y gas ha estado aumentando desde 2016, reduciendo la participación del gasto de capital en extracción de petróleo y gas al 14% desde el 27% en 2014 (Gráfico 10). Esto se refleja en nuestra previsión de producción a más largo plazo: Esperamos que la producción de la WCSB promedie 5.1mm b/d en 2022 frente a 5.3mm b/d que pronostica la Canadian Association of Petroleum Producers (CAPP). El conjunto finito de fondos disponibles para el sector petrolero y gasífero canadiense compite con el desarrollo de las lutitas en EE. UU. Un entorno regulatorio y fiscal favorable, ciclos de inversión más cortos y retornos iniciales más rápidos atraen la mayor parte de los fondos asignados al desarrollo de petróleo y gas hacia EE. UU. en detrimento de Canadá (Gráfico 11).8 Más recientemente, la divergencia en los flujos de inversión se centra en el acceso al mercado Gráfico 9 La inversión en petróleo canadiense se queda atrás Diferenciales del crudo canadiense probablemente se amplíen Diferenciales del crudo canadiense probablemente se amplíen Gráfico 10 El sector de petróleo y gas de Canadá pierde peso Probablemente se amplíen los diferenciales del crudo canadiense Probablemente se amplíen los diferenciales del crudo canadiense Gráfico 11 EE. UU. percibido como alternativa de inversión favorable Diferenciales del crudo canadiense probablemente se amplíen Diferenciales del crudo canadiense probablemente se amplíen Las empresas extranjeras están abandonando el sector petrolero canadiense, desinvirtiendo más de $30 mil millones desde 2017.9 La intervención del gobierno para limitar la producción llevó a las empresas a posponer nuevos proyectos en Alberta. El conteo de plataformas en Canadá sigue siendo débil y no muestra señales de recuperarse (Gráfico 12).10 No obstante, el sector debería ofrecer una oportunidad para los inversores en los próximos años. Una vez que se resuelva la incertidumbre en torno a la finalización de los oleoductos, creemos que podría producirse un repunte significativo en el rendimiento de las acciones de los productores canadienses (Gráfico 13). La mejora tecnológica ha reducido los costos de equilibrio de las arenas petrolíferas a algún punto entre $45/bbl-$55/bbl para petróleo entregado en Cushing.11 Además, las bajas tasas de declinación del suministro de las arenas petrolíferas lo convierten en una fuente de suministro más estable y predecible en comparación con la producción de lutitas. Gráfico 12 Las reducciones de capex reducen el conteo de plataformas Reducciones del CAPEX reducen el número de plataformas Reducciones del CAPEX reducen el número de plataformas Gráfico 13 Los precios de las acciones energéticas podrían recuperarse Los precios de las acciones del sector energético podrían recuperarse Los precios de las acciones del sector energético podrían recuperarse La próxima nueva capacidad de oleoducto que permitirá entregar más crudo pesado canadiense a las complejas refinerías de la Costa del Golfo de EE. UU. revivirá el sentimiento hacia los proyectos de arenas petrolíferas canadienses. Canadá está posicionado de manera juiciosa para ser el claro ganador en la guerra por cuota de mercado librada por los países productores de crudo pesado para asegurar capacidad en las refinerías del Golfo de EE. UU. El crudo canadiense ya domina las importaciones de PADD 2, y ha ido aumentando su participación en las importaciones de PADD 3 (Gráfico 14). La escasez mencionada de crudo pesado presenta una excelente oportunidad para que Canadá capture espacio adicional en las refinerías de PADD 3. El colapso de Venezuela y los recientes ataques a infraestructura petrolera crítica en el Reino de Arabia Saudita (KSA) resaltan el atractivo del crudo pesado canadiense para las refinerías de EE. UU. Gráfico 14 Fuerte demanda estadounidense por el petróleo de Canadá Probablemente se amplíen los diferenciales del crudo canadiense Probablemente se amplíen los diferenciales del crudo canadiense Impacto de las próximas elecciones federales canadienses Canadá se está preparando para unas elecciones federales el 21 de octubre. El consenso sostiene que el Partido Liberal del primer ministro Justin Trudeau permanecerá en el poder con un gobierno minoritario, o posiblemente en coalición con el Nuevo Partido Democrático (NDP) de izquierda y/o el Partido Verde. Nuestros estrategas geopolíticos creen que las probabilidades de que Trudeau mantenga una mayoría de partido único son mucho más altas que el consenso (que ronda el 25%), dado que se presenta con el respaldo de una economía bastante fuerte, un acuerdo comercial renegociado con Estados Unidos y un entorno sociopolítico estable (Gráfico 15). Gráfico 15 El riesgo político canadiense está contenido y debería mantenerse así El riesgo político canadiense está atenuado y debería permanecer así. El riesgo político canadiense está atenuado y debería permanecer así. Aunque la popularidad de Trudeau ha disminuido, su índice de aprobación todavía lo sitúa en el rango superior de los primeros ministros canadienses y no enfrenta un rival carismático. Tiene una base firme en ambos bastiones tradicionales del poder político, Ontario y Quebec, y las proyecciones de escaños muestran a los liberales liderando en ambas provincias. Los partidos pequeños no están en buenas cifras en las encuestas; el NDP está rindiendo mal en Quebec y es poco probable que le quite muchos votos a los liberales. Todavía podrían haber sorpresas, pero es indicativo que los liberales permanezcan al frente a pesar de los escándalos y controversias de último minuto que los amenazan. Las elecciones canadienses deberían producir un resultado de statu quo que no cambie las perspectivas del sector energético. Para el sector energético, el resultado más positivo es una mayoría conservadora; de lo contrario, una mayoría liberal renovada es el statu quo y por tanto el resultado menos negativo. Trudeau es criticado por los conservadores y en Alberta por comprometer los intereses energéticos de Canadá, aunque su apoyo al oleoducto Trans Mountain lo pone en desacuerdo con los partidos de izquierda. El peor escenario para el sector energético sería si Trudeau se viera obligado a depender de estos partidos en el parlamento – y esto es una posibilidad real aunque no nuestro caso base. Conclusión: Las elecciones canadienses deberían producir un resultado de statu quo que no cambie las perspectivas del sector energético – sin embargo, conllevan un riesgo no trivial de forzar a los liberales a integrarse en una coalición con partidos de izquierda cuyas posturas son negativas para el mercado del sector energético. Si se evita este resultado, espere que el mercado celebre a corto plazo, aunque los efectos a largo plazo de un segundo mandato de Trudeau no son positivos en el frente energético.   Hugo Bélanger, Analista Senior Estrategia de Commodities y Energía HugoB@bcaresearch.com     Notas a pie de página 1      Véase Mohammad bin Salman niega haber ordenado el asesinato de Khashoggi, pero dice que asume la responsabilidad, que se emitió el domingo 29 de septiembre de 2019 en CBS News. En un desarrollo relacionado la semana pasada, Arabia Saudita anunció un alto el fuego limitado con el Movimiento Houthi respaldado por Irán en Yemen, con el que ha estado en guerra desde 2015; véase Saudi Arabia agrees to limited ceasefire in Yemen, publicado por Arabian Business el 28 de septiembre de 2019. 2      Véase Las exportaciones de petróleo pesado de Canadá a Asia desde EE. UU. se disparan: datos, comerciantes publicado el 27 de septiembre de 2019 por reuters.com. 3      La expansión del oleoducto de 100k b/d de Enbridge Inc. programada para estar operativa en diciembre aumentará marginalmente los envíos canadienses hacia el sur. Enbridge es el operador dominante de oleoductos en el oeste de Canadá. Está intentando que los transportistas firmen contratos a largo plazo – frente a los contratos mensuales existentes – durante su actual temporada de subastas para el espacio en oleoducto. Su regulador “tiene preocupaciones respecto a la equidad del proceso de temporada abierta de Enbridge y la percepción de abuso del poder de mercado de Enbridge.” Véase El regulador canadiense ordena a Enbridge detener el plan de reforma del oleoducto debido a la 'percepción de abuso' publicado por reuters.com el 27 de septiembre de 2019. 4      Véase La corte confirma la ruta alternativa del oleoducto Keystone XL a través de Nebraska, publicado el 23 de agosto de 2019 por reuters.com. 5      Véase “Canadian Oil Sands Supply Costs and Developments Projects (2019-2039),” publicado por el Canadian Energy Research Institute (CERI), julio de 2019. 6      El nuevo gobierno hizo cambios pequeños adicionales a la política previa. Por ejemplo, dará a los productores un aviso de 2 meses sobre cualquier cambio en los límites, aumentó el límite base a 20k b/d desde 10k b/d y permite al ministro de Energía usar discreción para fijar los límites de producción tras fusiones y adquisiciones. Véase la sección límite de producción de petróleo del sitio web del gobierno de Alberta. 7           Como se discutió en nuestro informe de marzo de 2019, nuestra expectativa de alta adhesión a los recortes de producción acordados por los países de OPEC 2.0, que principalmente exportan crudos pesados y ácidos; mayores de lo esperado descensos en la producción venezolana de crudo pesado; y sanciones sobre los volúmenes de exportación de petróleo iraní limitan la oferta de crudo pesado disponible para los consumidores. 8              En junio de 2019, el gobierno canadiense aprobó el Proyecto de Ley C-69, llamado “La modernización de la Junta Nacional de Energía y la Agencia Canadiense de Evaluación Ambiental.” Esta ley cambia el proceso federal de evaluación ambiental. Los críticos argumentaron que esto repelería a los inversores energéticos y limitaría la aprobación de proyectos de oleoductos. Adicionalmente, el Senado canadiense aprobó el Proyecto de Ley C-48 – que pretende prohibir grandes petroleros en las aguas al norte de la costa de B.C. Esta ley dificulta que Alberta envíe su petróleo vía instalaciones de exportación del norte de B.C. Las empresas ahora están probando el envío de betún semisólido en lugar de en forma líquida para evitar cumplir con la nueva legislación. Véase El crudo de las arenas petrolíferas navega desde B.C., eludiendo la prohibición federal, publicado por el Edmonton Journal el 26 de septiembre de 2019. 9           Véase La diáspora de $30 mil millones: Las empresas petroleras extranjeras siguen abandonando el sector energético de Canadá publicado por el Financial Post el 22 de agosto de 2019. 10             El conteo de plataformas no captura completamente la producción de petróleo canadiense. La producción de betún a partir de minería representa ~30% de la producción total. Sin embargo, creemos que el conteo de plataformas sigue siendo un buen proxy del capex en el sector. 11             Véase “Canadian Oil Sands Supply Costs and Developments Projects (2019-2039),” publicado por el Canadian Energy Research Institute (CERI), julio de 2019. Visiones y temas de inversión Recomendaciones Recomendaciones estratégicas Operaciones tácticas RENDIMIENTO DE RECOMENDACIONES DE OPERACIONES EN 2019 3T Es probable que se amplíen los diferenciales del crudo canadiense Es probable que se amplíen los diferenciales del crudo canadiense Tabla de referencia de precios de commodities y jugadas Operaciones cerradas en 2019 Resumen de operaciones cerradas Diferenciales del crudo canadiense probablemente se amplíen. Diferenciales del crudo canadiense probablemente se amplíen.

Highlights We expect the high level of compliance with the OPEC - non-OPEC production agreement engineered by the Kingdom of Saudi Arabia (KSA) and Russia will endure, leading to significant reductions in global oil inventories this year and next. All else equal, this should backwardate WTI and Brent forward curves later this year. However, recent developments in the North American pipeline market - i.e., U.S. President Donald Trump's orders to revive development of the Keystone XL (KXL) and completion of the Dakota Access (DAPL) pipelines - could send as much as 1mm barrels/day (bbl/d) of crude south from Canada and the Bakken, which would boost inventories at Cushing and other Midwest storage facilities later in this decade. Depending on when these pipelines are completed - likely by 2020 in the case of KXL - the WTI forward curve could return to a sustained contango.1 The expanded flows of heavy crude via KXL, and light-tight oil south via the DAPL could undo a subtle benefit arising from the backwardation induced by the KSA - Russia production pact, which we uncovered in our modeling. Energy: Overweight. At Tuesday's close, our short Dec/19 WTI vs. long Dec/19 Brent spread elected last week at $.07/bbl (WTI over) was up 700%. Our long Dec/17 WTI vs. short Dec/18 WTI front-to-back spread, entered into at -$0.11/bbl on Feb 9/17, was up 263%. Base Metals: Neutral. BHP declared force majeure at its Escondida mine, which accounts for ~ 5% of global supply, after workers voted to strike. Union leaders agreed to another round of government-mediated talks with BHP management. Precious Metals: Neutral. Fed Chair Yellen's Senate Banking Committee testimony was more hawkish than expected, which rallied the USD and muted gold's overnight strength. We continue to look to get long gold at $1,180/oz. Ags/Softs: Underweight. The USDA revised grain and soybean supply/demand estimates last week, showing markets tightening slightly, with ending stocks for the 2016/17 crop year expected to be a touch lower. We remain bearish. Feature Chart of the WeekStorage Drawdowns Should Accelerate ##br##As U.S. Oil Imports Slow Regular readers of BCA's Commodity & Energy Strategy service will not be surprised by the very high compliance levels seen in the wake of the OPEC - non-OPEC production Agreement engineered by KSA and Russia late last year.2 Because the stakes are so high for KSA and Russia - and their respective oil-producing allies - we expect compliance to remain high into June, resulting in a drawdown of global oil storage, the stated goal of the deal. We believe the pact will result in both WTI and Brent forward curves returning to backwardation, as global storage levels fall some 300mm bbl (Chart of the Week). We are positioned for this outcome by being long Dec/17 WTI vs. short Dec/18 WTI. We are expecting to see the last of the Persian Gulf export surge to the U.S. this month, as the 45- to 50-day sailing time from the Gulf to the U.S. implies the last of these vessels will be arriving this week or next. This backwardation will, in all likelihood, restrain the rate at which U.S. shale-oil producers return rigs to the market next year. Chart 2Curve Shape Can Affect Rig Counts WTI Term Structure And Rig Counts: It's Complicated Recent modeling we've completed suggests curve shape can affect rig counts in the U.S. light-tight oil fields. When we regress U.S. rig count on the WTI forward curve, we find rig counts can be expected to increase when the forwards are in contango, and to decline when the market is backwardated. A flat forward curve can be expected to keep rig counts fairly constant (Chart 2).3 Obviously, the starting point for these outcomes is critical. We simulated rig counts by assuming Monday's closing prices for March through June WTI futures, then assumed different levels for July WTI futures as a starting point for estimating rig counts to end-2018. We used $50, $55 and $60/bbl in July as our starting point. All else equal, with the July/17 WTI at ~ $55/bbl and the forward curve backwardated by 10% 18 months out, we would expect to see average rig counts fall by 4.38 rigs/month in 2018, given the three-to-four month lag between rigs actually being deployed and the price signal being sent by the futures market. A contango term structure produces the opposite result. With the July/17 WTI at ~ $55/bbl and the forward curve in a contango of 10% 18 months out, we would expect to see rig counts increase by 4.57 rigs/month in 2018. There obviously is a price threshold from which the forward curve originates in this analysis, which we believe to be between $50 and $55/bbl. Below this level, we would expect shale producers to retreat back to their core production areas, and await a price signal to increase their rig counts. Above $60/bbl, backwardation and contango matters for rig counts over the next 2 to 2.5 years. A backwardated forward curve will, all else equal, incentivize a slightly lower level of rigs being deployed than a contango. For example, a 10% contango with a $60/bbl starting point results in 5.24 rigs/month being deployed, while 10% backwardation would lead us to expect 5.02 rigs/month being deployed. Sustaining Backwardation Will Be Difficult A sustained backwardation will be threatened later in this decade by the expansion of the North American pipeline grid, following U.S. President Trump's orders to revive the Keystone XL (KXL) pipeline's development and the completion the Dakota Access Pipeline (DAPL). The KXL and DAPL buildouts, if approved, will expand U.S. midcontinent crude deliveries by 1mm bbl/d, according to Genscape's tally.4 The KXL volumes would add close to 600k bbl/d to Canadian exports, and would flow directly into Cushing, OK. Another 400k bbl/d of light-tight oil from the Bakken LTO fields will flow to the midcontinent refining market via the DAPL. "Increased flows into Cushing due to the addition of Keystone XL could lead to a bottleneck of inventories at the hub, which would put downward pressure on crude prices," Genscape notes. Work on the KXL could start this year, and be completed before 2020. The DAPL is ~ 95% complete, and should be done in 6 months or less. Genscape believes the DAPL could be built and line fill could be in place in less than three months. Indeed, "drilling under Lake Oahe in southern North Dakota for Energy Transfer Partner's Bakken-to-Patoka, IL, Dakota Access (DAPL) crude pipeline began immediately upon receiving an easement from the U.S. Army Corps of Engineers on February 8, according to a company spokesman. It is expected to take 83 days for construction and linefill... ." We will monitor these pipeline buildouts closely, given the profound implications they have for U.S. midcontinent and Gulf Coast refiners, who could once again find themselves benefiting from a widening of the Brent vs. WTI differential, and Canadian E&Ps, who can be expected to increase production into this KXL buildout. The key market to watch as these pipelines are under construction will be the WCS vs. WTI spreads (Chart 3). As pipeline capacity opens up, exports of heavy crude from Canada will increase and the WCS - WTI differential will narrow, which will benefit Canadian E&Ps (Chart 4). A return of contango following the opening of these pipelines would benefit U.S. refiners, who can be expected to increase exports. Chart 3Expanding the N. American Pipeline Network##br## Will Widen WTI Differentials Chart 4Crude Differentials Will##br## Adjust To Pipeline Buildouts Bottom Line: The backwardation of the WTI and Brent forwards should accelerate as the last of the surge in exports from the Persian Gulf arrives in the U.S. President Trump's decision to expedite KXL and the completion of the DAPL in 6 months or less will have a profound impact on crude movements and storage levels in the U.S. later in the decade. Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com 1 President Trump's decision to revive KXL was endorsed by House and Senate leaders in the U.S. last month, which greatly raises the odds it will go ahead. In addition, the DAPL received an easement from the U.S. Army Corps of Engineers to complete construction. 2 Please see issue of BCA Research's Commodity & Energy Strategy Weekly Report "Raising The Odds Of A KSA-Russia Oil-Production Cut," dated November 3, 2016, available at ces.bcaresearch.com. 3 Our previous modeling indicates Granger causality goes from WTI prices to rig counts - i.e., E&P companies drilling decisions are driven by price levels and curve shape. We believe this relationship arises from the hedging behavior of shale-oil producers, many of whom hedge their forward revenues in the futures markets over a two-year interval. 4 Please see "Keystone XL, Dakota Access Could Cause Bottlenecks at U.S. Mid-Continent Storage Hubs, Shift Crude Prices," published on Genscape's blog February 14, 2017. Genscape is a near-real-time pipeline, storage and shipping monitoring service. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Commodity Prices and Plays Reference Table Trades Closed In 2017 Summary of Trades Closed in