Energy

Highlights Portfolio Strategy As growth becomes scarce, investors flock to sectors that are slated to outgrow the broad market and shy away from the ones that are forecast to trail the SPX’s growth rate. This week we rank sectors and subsectors by EPS growth in our universe of coverage, and identify sweet and trouble spots. Fired up crack spreads, firming refining industry operating metrics, reaccelerating exports along with washed out technicals and compelling valuations, all signal that the time is ripe to buy into refining weakness. The cable industry’s demand headwinds are reflected in depressed relative valuations at a time when industry pricing power is trying to stage a comeback and a drifting lower greenback may also provide positive profit offsets. Stick with a benchmark allocation. Recent Changes Boost the S&P Oil & Gas Refining & Marketing index to overweight all the way from underweight today, locking in relative profits of 21%. Table 1 Feature Equities broke out last week and surpassed the upper band of their recent trading range, despite economic data releases that continued to surprise to the downside. Two weeks ago, we cautioned investors not to put cash to work as a tactical indigestion period loomed, with the SPX facing stiff resistance near the 2,800 level. In addition, we posited that most of the good news related to the U.S./China trade spat front was reflected in the S&P 500’s V-shaped recovery (top panel, Chart 1). In relative terms, the bottom panel of Chart 1 confirms that the easy money has already been made on the assumption of a positive resolution to the U.S./China trade dispute. Chart 1Trade Deal Priced In Going forward, the earnings juggernaut will have to remain in place in order for stocks to vault to fresh all-time highs, likely in the back half of the year. The Trump administration’s massive fiscal stimulus artificially fueled profit growth last year both by lowering the corporate tax rate and by encouraging overseas cash repatriation. The latter boosted share buybacks to an all-time record. Despite 24% EPS growth and $1tn in equity retirement, the SPX ended 2018 6% lower. Why? It became clear that EPS growth was headed lower. In order to gauge trend EPS growth we opt to use EBITDA, a cash flow proxy measure that strips out the direct impact of last year’s fiscal easing. Chart 2 clearly shows that trend growth took a step down following the positive base effects of the GFC-induced collapse and averaged close to 5%/annum from 2012 to 2014. Subsequently, the late-2015/early-2016 manufacturing recession sunk EBITDA into contraction, but the euphoria surrounding the newly elected President pushed trend EBITDA growth to near 10%/annum for two full years in 2017 and 2018. Chart 2Return To 5% Growth? Since the late-2018 peak, 12-month forward EBITDA growth continues to drift lower and is now hovering just shy of 3%. Our sense is that 5% organic profit growth is consistent with nominal GDP printing 4%-4.5% at this stage of the business cycle, signaling that a return to the 2012-2014 growth backdrop is likely later in the year. As a reminder, positive profit growth in calendar 2019 remains one of the three pillars underpinning stocks that we have highlighted since the beginning of this year. Stocks have come full circle recovering all of last December’s losses, but in order to make fresh all-time highs, profits will have to deliver. We deem that an earnings validation phase is transpiring and there are early signs that profit growth will trough sometime in the first half of the year. Not only has EBITDA breadth put in a bottom (Chart 2), but also economically hypersensitive indicators suggest that forward EBITDA growth will soon tick higher. Namely, the ISM manufacturing new orders component has perked up on a year-over-year basis. The trough in lumber futures momentum corroborates this message, as does the tick higher in the U.S. boom/bust indicator (Chart 3). Chart 3Growth Green-shoots Given the current macro backdrop and awaiting the profit validation, when growth becomes scarce investors flock to sectors that are outgrowing the broad market and shy away from ones that trail the SPX’s growth rate. Typically, in recessionary times that would equate to investors bidding up defensive sectors that command stable cash flow businesses and avoiding highly cyclical industries. But, BCA does not expect a recession in the coming year. Thus, in order to identify high growth sectors that should outperform during the current soft patch and growth laggards that should underperform, we compiled a table with the GICS1 sectors and all the subsectors we cover. First, we rank the GICS1 sectors and then within each sector we rank the subsectors, both times by absolute 12-month forward EPS growth using I/B/E/S/ data (see second columns, Table 2). We aim to reproduce this table once a quarter. Table 2Identifying S&P 500 Sector EPS Growth Leaders And Laggards The third columns in Table 2 show the sector growth rate relative to the SPX. The final columns in Table 2 highlight the trend in relative growth. In more detail, they compare the current relative growth rate to that of three months ago: a positive sign indicates an upgrade in analysts’ relative estimates and a negative sign a downgrade in analysts’ relative estimates. Industrials and financials (we are overweight both) are leading the pack outpacing the broad market by 410bps and 350bps, respectively, and enjoy a rising profit trend. On the flip side, energy (overweight) and real estate (underweight) trail the broad market by 490bps and 1480bps, respectively, and showcase a deteriorating EPS trend. With regard to energy, we first identified that analysts are really punishing this sector in the January 22 Weekly Report and the sector’s 2019 EPS contribution was and remains negative.1 Our overweight call will be offside if oil prices suffer a new setback, but our Commodity & Energy strategy service remains bullish on oil, implying relative EPS outperformance in 2019. Year-to-date, energy has bested the SPX by 170bps. This week, we make an energy sector subsurface tweak, and also update a communication services subgroup. Light My Fire Last summer we took refiners down to a below benchmark allocation as all of the good news was perfectly reflected in soaring relative share prices (top panel, Chart 4), at a time when cracks were forming. Now we are compelled to book gains of 21% and boost exposure all the way to overweight. Chart 4Crack Spreads Are On Fire Today, refiners paint a near exact opposite picture compared with last July. Relative share prices are no longer rising by 50%/annum. Instead, momentum has collapsed and is now contracting (middle panel, Chart 4). Sell-side analyst exuberance has turned into outright pessimism: refiners’ profits are expected to trail the broad market in the coming year. By comparison, last summer they were penciled in to beat the market by 30 percentage points (bottom panel, Chart 4). Granted M&A activity had also added fuel to the fire, but now all the hot air has come out of the refining industry, and then some. Refiners’ riches move in tandem with crack spreads. When refining margins widen, profits excel and vice versa. Now that refining margins are in a slingshot recovery, refining ills will turn into fortunes (bottom panel, Chart 4). Importantly, wide Brent-WTI spreads underpin crack spreads. Moreover, the crude oil versus refined product inventory backdrop currently reinforces a widening in refining margins. In absolute terms, gasoline stockpiles are being worked off (gasoline inventories shown inverted, bottom panel, Chart 5) and grinding higher demand for refined petroleum products (top panel, Chart 5) will further tighten the industry’s inventory outlook. Chart 5Healthy Supply/Demand Backdrop One way domestic refiners are taking advantage of the still wide Brent-WTI differential is via the export markets. Net refined products exports are running at over 3mn barrels/day (bottom panel, Chart 6), and the softening greenback since November will further boost profits with a slight lag as U.S. refining exports will grab an even larger slice of the global pie (U.S. dollar shown inverted and advanced, middle panel, Chart 6). Chart 6U.S. Dollar Softness Is A Boon To Refining Profits On the valuation front, both the relative forward P/E and P/S have undershot their respective historical means and EPS breadth is as bad as it gets, offering investors an excellent entry point in the pure-play oil & gas refining industry (Chart 7). Chart 7Extreme Analyst Pessimism Reigns In sum, fired up crack spreads, firming refining industry operating metrics, reaccelerating exports along with washed out technicals and compelling valuations, all signal that the time is ripe to buy into refining weakness. Bottom Line: Lift the S&P oil & gas refining & marketing index to overweight all the way from a below benchmark allocation, crystalizing 21% in relative profits since last summer’s inception. The ticker symbols for the stocks in this index are: BLBG: S5OILR – PSX, MPC, VLO, HFC. Cable’s Down But Not Out Cable & satellite stocks had been in an uninterrupted run from the depths of the Great Recession until the peak in relative share prices in August 2017. Since then, cord cutting news and the proliferation of on demand streaming services have wreaked havoc on the industry and cable stocks have trailed the market by over 33% from peak to the most recent trough (top panel, Chart 8). Chart 8Cable Signals Are… This deteriorating demand backdrop more than offset the industry’s reaction function, which has been intra and inter-industry M&A. Now that the M&A dust has settled, what is next in store for the industry? We reckon that leading profit indicators are a mixed bag and we continue to recommend a benchmark allocation in this niche communications services subgroup. The top panel of Chart 8 shows that relative outlays on cable are on a slippery slope, and will continue to weigh heavily on relative share prices for the coming quarters. Nevertheless, the ISM services survey ticked higher recently and is on the cusp of making fresh recovery highs, unlike its sibling the ISM manufacturing survey. This is encouraging news for cable executives and suggests that demand for cable services may not be as moribund as the PCE release is projecting (second panel, Chart 9). Chart 9..A Mixed… While the cable demand backdrop is unclear, industry pricing power has managed to exit deflation. Cable selling prices have been positive for the better part of the past decade, but starting in late-2017 they collapsed by roughly 600bps relative to overall inflation. True, this deflationary impulse dented profit margins, but currently the industry’s selling prices – and to a much lesser extent profit margins – are in a V-shaped recovery mostly courtesy of base effects (middle & bottom panels, Chart 8). Absent a sustained hook up in cable demand, selling price inflation will prove fleeting and the recent margin expansion phase will also lose steam. Meanwhile, cable stocks and the U.S. dollar enjoy a positive correlation as most of the constituents’ earnings are derived domestically (Chart 10). The recent U.S. dollar softness will, at the margin, weigh on relative profits and thus relative share prices, especially if the Fed stays pat and refrains from raising rates for the rest of the year as the bond market currently expects. Chart 10…Bag Finally, earnings breadth continues to fall, but relative valuations are still well below the historical mean (third & bottom panels, Chart 9). Netting it all out, cable’s demand headwinds are well reflected in depressed relative valuations at a time when industry pricing power is trying to stage a comeback and a drifting lower greenback may both provide positive profit offsets. Bottom Line: Remain on the sidelines in the S&P cable & satellite index. The ticker symbols for the stocks in this index are: BLBG: S5CBST – CMCSA, CHTR, DISH.   Anastasios Avgeriou, U.S. Equity Strategist anastasios@bcaresearch.com   Footnotes 1      Please see BCA U.S. Equity Strategy Weekly Report, “Dissecting 2019 Earnings” dated January 22, 2019, available at uses.bcaresearch.com. Current Recommendations Current Trades Size And Style Views Favor value over growth Favor large over small caps

Highlights Price differentials between global light-sweet crude oil benchmarks Brent and WTI will narrow over the next three years, as U.S. light-sweet crude oil exports expand and North Sea production growth remains challenged. U.S. product exports also will expand, as investments by Gulf Coast refiners allow them to take in more of the domestic light-sweet crude output. Growing volumes of WTI being exported to Europe are being priced relative to Brent. Over time, we expect the marginal light-sweet crude barrel for the global oil market – and the benchmark of refiners’ primary cost – will be directly linked to WTI – Houston pricing. Given this expectation of increased U.S. exports, we are initiating a long WTI vs. short Brent swap position at tonight’s close in 2020. The 2020 swap settled Tuesday at $6.6/bbl; we project it will average $3.25/bbl. In the heavy-sour markets, differentials – most prominently the Brent – Dubai spread – will remain tight, owing to OPEC 2.0 production cuts, lost Venezuelan and Iranian exports, due to U.S. sanctions, and ongoing difficulties getting Canadian heavy crude to refining markets. Energy: Overweight. OPEC 2.0 likely will decide to extend production cuts to year-end in June, as opposed to May, as was expected earlier.1 This will allow the Cartel to respond to whatever the U.S. decides on May 4 re extending waivers on Iranian export sanctions, and to export losses from U.S. sanctions on Venezuela’s state oil company. Base Metals/Bulks: Neutral. Chinese Premier Li Keqiang announced tax cuts amounting to almost $300 billion (~ 2 trillion RMB), as policymakers attempt to hit a GDP growth target of 6.0 to 6.5% this year. We are getting tactically long spot copper at tonight’s close, expecting this fiscal stimulus to boost prices over $3.00/lb in the next 3 – 6 months. Feature In a little more than two years from now, Exxon will add 1mm b/d of pipeline take-away capacity to the Permian Basin. The new pipe is in addition to the 2mm b/d of takeaway capacity currently being added to the basin, which is expected to be fully operational by the end of this year. Current production in the Permian is close to 4mm b/d, so the combined incremental new pipe will provide considerable room for production growth into the 2020s. Exxon’s pipeline expansion – undertaken with Plains All American and Lotus Midstream – was announced in January, just before the company proceeded with its final investment decision (FID) to expand the capacity of its Beaumont, TX, refinery by 250k b/d to 616k b/d. The new capacity is expected to come online in 2022, and will make Beaumont the largest refinery in the U.S. The refinery expansion will take in light-sweet crude from the Permian, where Exxon plans to triple production to 600k b/d by 2025.2 These announcements are not one-offs: Permian production, and shale-oil output generally, is booming. In the Permian, oil output rose just over 800k b/d last year, according to the U.S. EIA (Chart of the Week, panel 1). Overall U.S. shale output in the Big 5 basins – Anadarko, Bakken, Eagle Ford, Niobrara and Permian – rose close to 1.5mm b/d in 2018.3 Output growth in the Permian will remain super-charged on the back of the pipeline buildout, and the capex being poured into it as the Majors and large E&P companies industrialize production there, not unlike a manufacturing process. We expect the Permian to lead the development of shale-oil production, driving total crude and liquids growth in the U.S., which last year grew by 2.2mm b/d to reach 19mm b/d by December (Chart of the Week, panel 2). Chart of the WeekBrent Physical Liquidity Continues To Fall Continued investments in state-of-the-art refinery expansions in the U.S. Gulf are expected to continue as well, given the production growth we expect for the Permian, and the pipeline expansions that will take that output to the Houston refining market. Chevron, for example, is expected to close on an acquisition from Brazilian state oil company Petrobras for the 110k b/d Pasadena Refining System, also in the Houston Ship Channel. The company will feed this unit with light-sweet crude from the Permian, which it told analysts this week it expects to grow to 600k b/d by end-2020 and 900k b/d by 2023.4 At present, the U.S. Gulf Coast refining infrastructure cannot absorb all of the light-sweet crude that will be produced in the Permian and the other major basins in coming years. The export markets – particularly the Atlantic Basin, which is home to the physical Brent market – will be absorbing more and more of U.S. light-sweet production in coming years as North Sea production stagnates relative to the U.S. shales (Chart of the Week, panel 3). Output in the U.K. North Sea was at its lowest level since 1973 in 2017, following the price collapse of 2014 – 2017 instigated by the OPEC market-share war launched in 2014. UK output was flattish last year, while Norwegian production was down slightly more than 6% in 2018, bringing it to just under 1.5mm b/d. Drilling activity is picking up this year, along with M&A activity as private equity firms step in to buy properties being sold by the U.S. Majors. As can be seen in the Chart of the Week, production is expected to begin picking up at the end of this year, but base effects from the low levels of late exaggerate the gains in percentage terms. U.S. Crude Exports Set To Soar The North Sea Brent market is arguably the most important crude oil market in the world. It is the underlying physical market for the world’s benchmark crude oil – Brent Blend – against which up to two-thirds of the world’s crude oil prices are indexed.5 Production of the five constituent streams comprising the Brent index – the Brent, Forties, Oseberg, Ekofisk and Troll crudes – has been falling year on year, and one of the streams (Forties) is regularly being exported to Asian refining markets. This has prompted the main price-reporting agencies to consider adding to the constituents of the Brent index, and changing the type of pricing it records.6 At the same time, increasing volumes of WTI light-sweet crude are making their way into the Brent North Sea physical market.7 These export volumes will increase, supported by the buildout of pipeline takeaway and deep-water harbor capacity in the U.S. Gulf, which, when done, will expand the capacity of Gulf ports to accommodate very large crude carriers (VLCCs).8 On the back of these rising exports to the European market, Argus Media, one of the price-reporting agencies, this year began publishing U.S. waterborne pricing assessments as differentials to the ICE Brent futures. According to Argus, slightly over a quarter of the 2.6mm b/d of crude exports out of the U.S. last November went to Europe to compete with North Sea grades like Brent and Forties, two of the Brent index constituents. For the week ended February 22, 2019, the four-week average of crude oil exports from the U.S. was close to 3.1mm b/d, a record for average exports. According to S&P Global Platts, “There have been 48 VLCCs booked for loading out of the USGC so far in 2019 – about five times the amount booked in the first two months of 2018 and a drastic difference to the two VLCCs that were booked during the same period in 2017.”9 Most of the growth in U.S. exports is coming from the shale-oil production boom, which is swelling the volume of light-sweet barrels in the Gulf. While increasing volumes of WTI are making their way into European wet markets, it is too early to call WTI delivered to the Houston refining market (WTI – Houston) a benchmark; it’s more of a reference price for now. All the same, the necessary and sufficient conditions are falling into place for WTI – Houston to become a global benchmark: It has consistent quality; diversity of buyers (refiners and trading companies), sellers (producers and traders), and speculators to provide hedging liquidity to physical-market participants; and, in due course, will have reliable shipping facilities, including ports capable of handling VLCCs and smaller vessels. This last condition is the critical limiting factor at present.10 We expect that, by the early 2020s, the necessary and sufficient conditions will be in place to allow WTI – Houston to become a global benchmark. By that time, we project the U.S. will be exporting in excess of 10mm b/d of crude and liquids, and refined products, with crude exports alone exceeding 5mm b/d by then. Currently, the U.S. exports slightly more than 8mm b/d of crude oil and products (Chart 2). The six largest importers of U.S. crudes are found in the Atlantic and Pacific basins (Charts 3A & 3B). Chart 2U.S. Will Expand Its Lead As Largest Crude and Products Exporter Chart 3AU.S. Exports To Atlantic ... Chart 3B... And Pacific Growing Bottom Line: We expect the Brent vs. WTI crude oil differential to narrow next year, as U.S. light-sweet crude oil exports expand and North Sea production stagnates. On the back of this, we are opening a long WTI vs. short Brent position in 2020. We expect this differential to average $3.25/bbl next year versus current market levels of $6.6/bbl. Canadian WCS Differentials Could Relapse The Western Canadian Select (WCS) differential to WTI YTD contracted to a discount of $10.50/bbl from an average discount of $26.3/bbl in 2018, as the Alberta government’s production curtailment took effect (Chart 4).11 This is allowing Alberta’s excess inventories to start declining, which was one of the primary motivations of the government’s action. Chart 4Government-mandated Production Cuts Reverse Inventory Builds in Alberta Not all the news out of Canada is good for producers, however. An unexpected delay in Enbridge’s Line 3 replacement and expansion puts future Canadian production growth in jeopardy. This will complicate the Alberta government’s plan to stabilize the sound discount to WTI, which is necessary to maintain investors’ confidence in the sector. In our previous analysis of the Canadian oil sector, we assumed the Line 3 replacement project would be completed in the fourth quarter of this year. This is now pushed back by at least 6 months, likely into 2H20.12 The replacement was expected to restore Line 3’s original takeaway capacity of 760k b/d from 390k b/d, and was a crucial input in our Canadian oil output forecasts. The reduction of the production curtailment to ~ 95k b/d in 2H19 previously announced by the Alberta government will not be sufficient to maintain the WCS transportation discount below $15/bbl (Chart 5). Thus, the government most likely will extend part of the ~ 325k b/d mandatory cuts into 2H19. A rollback of the curtailment policy to 95k b/d ahead of the Line 3 replacement would push the differential back above the crude-by-rail range – i.e., a $15-to-$22/bbl discount over the quality discount for heavy sour crude vs. the light-sweet. We expect a combination of production decreases and increased crude-by-rail transport, which will have to go to record levels, could help alleviate the negative pressure on the WCS-WTI discount (Chart 6). For instance, maintaining a 225k-barrel-per-day production curtailment from April to December 2019, combined with an increase in crude-by-rail transport to ~ 460k b/d by year-end would be enough to maintain the discount in our estimated crude-by-rail range (Chart 7).13 Heavy Crude Differentials Will Remain Tight The prolongation of Canadian crude bottlenecks will contribute to keeping heavy-sour vs. light-sweet price differentials tight. Altogether, our expectation of high compliance to the output cuts agreed by OPEC 2.0 countries, which primarily export heavy-sour crudes; larger-than-expected Venezuelan output declines in heavy-sour output; and continued takeaway capacity constraints in Canada will keep the price differentials between light-sweet and heavy-sour crudes tight. This can be seen in the Brent – Dubai spread, which at times, favors the heavy-sour crude streams (Chart 8). Chart 8Heavy-Sour Crude Differentials Tighten As Supply Contracts Bottom Line: The WCS differential vs. WTI is at risk of weakening once again, following the unexpected delay in Enbridge’s Line 3 replacement and expansion. The Alberta government will have to get more deeply involved to keep unconstrained production from hammering the differential once again.   Robert P. Ryan Chief Commodity & Energy Strategist rryan@bcaresearch.com Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com   Footnotes 1 Please see “OPEC likely to defer output policy decision until June – sources,” published by uk.reuters.com, March 4, 2019. 2 Please see “Permian Majors Expand Downstream Processing,” published by Morningstar Commodities Research, February 11, 2019. 3 These data were sourced from the EIA’s Drilling Productivity Report for February 2019. 4 See fn 2 above. See also “Chevron, Exxon take turns wooing investors with shale boasts,” published by reuters.com March 5, 2019. 5 This estimate comes from ICE Brent Crude Oil, published by The Intercontinental Exchange (ICE), which runs the Brent futures market. 6 Please see “Viewpoint: North Sea benchmark changes looming” which was published by Argus Media on December 27, 2018. 7 Please see “US waterborne crude trade shifts toward Brent basis” published by Argus Media on February 15, 2019. 8 See, e.g., Carlyle Group’s recently announced involvement in such a venture. Carlyle expects its deep-water buildout to be done in late 2020. 9 Please see “In the LOOP: Record US crude exports boost VLCC tanker demand, rates,” published by S&P Global Platts on March 5, 2019. 10 Please see Liz Bossley’s article “There Can (Not) Be Only One,” beginning on p. 15 of the May 2018 issue of the Oxford Energy Forum – Oil Benchmarks – Issue 113, for a discussion of different oil-price benchmarks. 11 We discuss Canada’s take-away dilemma in our November 29, 2018, publication entitled “The Third Man At OPEC 2.0’s Meeting.” It is available at ces.bcaresearch.com. 12 Please see “Enbridge’s Line 3 pipeline replacement likely won’t be in service until second half of 2020,” published by The Globe and Mail on March 3, 2019. 13 The government intends to increase the production ceiling by 100k b/d by April 2019, this makes the mandatory cuts at 225k b/d from 325k b/d in January 2019. https://www.alberta.ca/protecting-value-resources.asp Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Commodity Prices and Plays Reference Table Trades Closed in Summary of Trades Closed in

Highlights The global shipping-fuels market will tighten as UN-mandated fuel standards kick in next year. This will keep ship fuels, known as bunkers, and other distillate prices – e.g., diesel and jet fuel – elevated relative to other refined products like gasoline. In turn, this will boost demand for lighter, sweeter crudes – particularly Brent and similar grades – that allow refiners to raise distillate yields, as they scramble to meet higher demand for low-sulfur ship-fuel next year. After pipeline expansions in the Permian Basin come on line later this year, WTI exports should provide the marginal light-sweet barrel refiners will need to raise distillate output next year. Light-sweet exports from the U.S. will find a ready home in the Atlantic Basin and Asia, as demand for shipping fuels – along with other distillates– rises. Still, the ramp in WTI exports from the U.S. will be hampered by a lack of deep-water ports that can accommodate very large crude carriers (VLCCs) used to ship crude oil globally. As a result, we expect the light-sweet crude market ex-U.S. to tighten. Given this expectation, we are extending our long July 2019 Brent vs. short July 2020 Brent recommendation – up 240.2% since inception January 3 – to long 2H19 Brent vs. short 2H20 Brent. Highlights Energy: Overweight. In line with our expectation, OPEC is showing no sign of agreeing to raise production less than two months after initiating output cuts to drain inventories. Separately, Muhammadu Buhari was re-elected for a second four-year term as Nigeria’s president. The main opposition party rejected the results, following record-low voter turnout, after elections were unexpectedly delayed by one week, according to the BBC. Base Metals/Bulks: Neutral. The prompt March copper contract on the CME’s COMEX is attempting to fill a gap just above $2.95/lb, which opened in July 2018 as U.S. – China trade tensions rose. Positive signals from Sino – U.S. trade talks are supporting prices. Precious Metals: Neutral. Palladium traded to a record high of $1,536.50/oz Monday, pushing it more than $200/oz over gold. Platinum prices also rallied, as South African miners were notified by labor unions of intended strikes next week. Russia’s leading producer, Norilsk Nickel, which accounts for 40% of global palladium production, expects an 800k-ounce physical deficit in 2019, according to Reuters. Ags/Softs: Underweight. U.S. President Donald Trump said he would delay increasing U.S. tariffs on Chinese imports. Trump also said he expects to meet China’s President Xi Jinping to conclude the trade deal they’ve been negotiating if both sides continue to make progress. Feature Maritime shipping represents ~ 80% of international trade, and is responsible for roughly 90% of the total sulfur emissions from the transportation sector. In 2008, the UN’s International Maritime Organization (IMO) adopted a new regulation to reduce the cap for sulfur content of ships’ fuel oil – known as bunker fuel – to 3.5% from 4.5% in 2012, and to 0.5% from 3.5% in 2020 (Chart 1).1 Chart of the WeekReducing Marine Sulfur Pollution Requires Higher-Priced Low-Sulfur Fuels Around 50% of the cost of shipping is fuel costs. This amounts to more than 4mm b/d of bunker fuel (~ 3.5mm b/d of High-Sulfur Fuel Oil, or HSFO, and ~ 0.8mm b/d of marine gasoil, known as MGO). Hence, the IMO 2020 regs threaten demand of ~ 3.5mm b/d of HSFO. As the January 1, 2020, IMO deadline approaches, uncertainty surrounding the new regs remains elevated. On the demand side, shippers have the option to install abatement technology (i.e., scrubbers); burn IMO 2020-compliant fuels like MGO; use liquefied natural gas (LNG) as a fuel on ships; or do nothing, i.e., not comply with the regulation. Refiners on the supply side have to adjust via a combination of increasing MGO and Low-Sulfur Fuel Oil (LSFO) production; modifying their crude slates, which will favor lighter, sweeter crudes like Brent and WTI; building additional refining capacity; or running their units harder – i.e., increase refinery utilization rates – to produce more fuel. Demand for bunkers is the only part of the HSFO market that is growing. IMO 2020 removes the all-important shipping consumer of residual fuel oil, which will have a major impact on simple refineries, and will force a dramatic reconfiguration of the shipping and refining industries. To date, shippers and refiners have been slow to implement required changes as market participants have an incentive to move last.2 We agree with a recent McKinsey analysis, which notes the simplest solution for shippers is to switch to MGO.3 We also could see an uptick in demand for LSFO with sulfur content below the 0.5% limit for blending purposes. This would push demand for the lower-sulfur fuels and prices up. It also would pressure HSFO prices lower over the short term, to the point where this fuel can compete in the utility sector as a fuel, or in the refining sector as a charging stock for complex refiners. The IEA expects MGO consumption to rise from 0.8mm b/d to 1.7mm b/d in 2020.4 Complex Refiners, Light-Sweet Crude Producers Benefit Moving to LSFO and MGO shifts the burden of IMO 2020 to the refining market. According to the IEA, around 80% of the sulfur content in crude is removed from the final product. Once IMO 2020 is implemented, this will rise to 90%. In the lead-up to the IMO 2020 deadline, refiners are adjusting their crude slates to minimize residual fuel and maximize distillate output. As a result, demand for light-sweet crudes like Brent and WTI – the crude being produced in ever-rising quantities in the U.S. shales – will increase. At the same time, heavier crudes exported by Venezuela and GCC states will see demand fall, which means the spread between these crudes will favor the lighter, sweeter barrel, all else equal.5 Simple refineries incapable of cracking the complex heavy-sour crudes favored by U.S. Gulf Coast refiners will either have to upgrade, close, or use low-sulfur crude as a charging-stock input. According to McKinsey, the switch to marine gasoil will lead to an increase of 1.5mm b/d of distillate demand. This represents ~ 2.2 to 2.7mm b/d of increased demand for light-sweet oil. The IEA estimates diesel prices could rise by 20 – 30%, as a result.6 This increased demand for low-sulfur bunkers – MGO in particular –will keep prices for distillates generally well supported over the next year or so at the expense of HSFO. S&P Global Platts reported this week the first physical trade for U.S. Gulf Coast 0.5% MGO was done in its official trading window at $67.70/bbl, a $3.75/bbl premium to HSFO.7 IMO 2020 will keep distillates the star performers for refiners. Distillate crack spreads – most visible in the ultra-low-sulfur diesel (ULSD) cracks employing the CME’s NY Harbor ULSD futures vs. WTI and Brent – recently were trading $16/bbl over gasoline cracks using the Exchange’s RBOB futures (Charts 2A and 2B). We expect these cracks to remain wide, to incentivize more distillate-production capacity. Chart 2ABrent Diesel And Gasoline Cracks Likely Trade > $14/bbl Wide Chart 2BBrent Diesel Cracks Will Remain Elevated Following IMO 2020 Prices for other distillates also will be supported by IMO 2020 – e.g., jet fuel – over the coming year, given the high correlation of products within this cut of the barrel. These distillate prices also are highly correlated with Brent and WTI prices, as can be seen in Chart 3, and in Tables 1 and 2. These high correlations likely will persist as IMO 2020 is implemented, and hedgers seek out liquid markets in which to shed their price risk.8 Chart 3Global Distillate Prices Will Be Supported by IMO 2020Table 1Distillate Fuels’ Correlations Remain High Around The WorldTable 2Percent Changes In Distillates Also Are Highly Correlated Baker & O’Brien, an energy consultancy based in Dallas, Texas, expects a number of factors – ranging from non-compliance with IMO 2020; increased use of scrubbers to capture sulfur-oxide emissions; blending to make IMO 2020-compliant marine fuel; upgrades by refiners and changes in their crude slates – will lead to lower prices once the market adjusts to the new regs.9 We do not disagree, but the timing on this likely hinges on how quickly U.S. light-sweet crude oil exports ramp up. Investment Implications WTI exports – actually LTO exports from U.S. shales – will provide the marginal light-sweet barrel refiners will need to raise distillate output next year. As a result, LTO exports from the U.S. will find a ready home in the Atlantic Basin and Asia, as demand for low-sulfur shipping fuels increases. However, this will not happen overnight. At present WTI exports from the U.S. are hampered by a lack of deep-water ports that can accommodate the VLCCs used to ship crude oil. The 2mm b/d of expanded pipeline capacity out of the Permian by the end of this year will move the U.S. crude-oil bottleneck from the Permian to the U.S. Gulf.10 So, as refiners prepare this year for the IMO 2020 regs effective January 1, 2020, the light-sweet crude market ex-U.S. – particularly Brent– will tighten. This already is visible in the backwardation we were expecting at the beginning of this year, when we recommended getting long July 2019 Brent vs. short July 2020 Brent, which is up 240.2% since inception on January 3. Given our expectation for a tighter light-sweet crude market ex-U.S., we are liquidating our existing Brent 2019 long position vs. a short position in July 2020 at tonight’s close, and replacing it with a long 2H19 Brent vs. a short 2H20 Brent position.11 Bottom Line: The implementation of IMO 2020 will tighten marine fuels markets globally, as refiners increase their demand for light-sweet crude oil and shippers most likely increase their demand for MGO and lower-sulfur fuels generally.     Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com   Footnotes 1      The regulation is part of Annex VI to the International Convention for the Prevention of Pollution from Ships (MARPOL). Following the adoption of the regulation in 2008, a provision was kept in order to review the compliant fuel availability and possibly push the implementation to 2025. In October 2016, the IMO’s Marine Environment Protection Committee confirmed the final implementation date (January 1, 2020) following a positive assessment of the availability for shippers of compliant fuels. Any amendment to MARPOL needs to be circulated for a minimum of six months, and can only be implemented 16 months after adoption, therefore, no legal amendment to the current January 2020 date are possible. Please see https://www.iea.org/etp/tracking2017/internationalshipping/ 2      The slow response by refiners can be explained by: (1) the fact that a switch to LSFO or MGO prior to the actual deadline would lead to a financial loss due to the current high price of LSFO and MGO vs. HSFO; (2) abatement technology requires large upfront investments (i.e. capital cost of new processing units, storage tanks, loss of revenue from laying ships in dry dock while they are retrofitted, and a permanent loss of deck space and loading capacity to the new equipment); and (3) the unpredictability of fuel prices and the endogenous relationship between other shippers and the behavior of prices. In other words, trying to get out in front of the official implementation of IMO 2020 leads to unnecessary financial burdens and to competitive disadvantage. Please see Halff, Antoine, Lara Younes, Tim Boersma (2019), “The Likely Implications of the new IMO standards on the shipping industry.”  Energy Policy, 126: 277 - 286. 3      Please see “IMO 2020 and the outlook for marine fuels,” published by McKinsey & Company, September 2018.  S&P Global Platts reaches a similar conclusion in a report entitled “Turning tides, the future of fuel oil after IMO 2020,” which was released this month.  Platts notes, “The IMO’s lower sulphur cap is set to take away the bulk of marine fuel oil demand from the start of next year.  Most ship owners and operators will switch to burning new low-sulfur bunker blends, translating into an almost overnight shift of 3 million b/d of demand.” 4      The IEA expects 30% of the current HSFO bunker demand will switch to marine gasoil (MGO), 30% of the HSFO bunker demand will switch to the new ultra low 0.5% sulphur fuel (ULSFO), and 40% of HSFO bunker demand will remain.)  In the IEA’s modeling, this could push prices up by as much as 30%.  Please see “Oil 2018: Analysis and forecasts to 2023” published by the IEA. It is available at iea.org 5      Please see “IMO 2020 and the Brent – Dubai Spread,” published by The Oxford Institute For Energy Studies in September 2018.  Of course, reducing the export of heavy-sour crudes, as has been done by the Gulf Arab members of OPEC will keep the Brent – Dubai spread tighter than pure economics would dictate. 6      Please see sources in footnotes 3 and 4. 7      This trade was done in the Platts Market on Close assessment.  Please see “USGC Marine Fuel 0.5% has first physical trade in Platts MOC process,” published by S&P Global Platts February 26, 2019. 8      These are short-term correlations, which use daily data from 2017 to now. We present correlations in levels and in percent-changes, given these are cointegrated variables. Please see section 3.3 of “Correlation, regression, and cointegration of nonstationary economic time series,” by Soren Johansen, published November 6, 2007, by the Center for Research in Econometric Analysis of Time Series at the University of Aarhus. 9      Please see “The Thunder Rolls – IMO 2020 And The Need For Increased Global Oil Refinery Runs (Part 3)” published by Baker & O’Brien, December 11, 2018. 10     An additional 1mm b/d of new takeaway is scheduled for 1H21, following a final investment decision from an Exxon-led group that will move Permian Basin LTO to the U.S. Gulf.  This came one day after Exxon FID’d a 250k b/d buildout of its Beaumont refinery in Houston, which will increase capacity by more than 65%, Natural Gas Intelligence reported January 30. 11     Please see EIA’s This Week in Petroleum report titled “Upcoming changes in marine fuel sulfur limits will affect crude oil and petroleum product markets,” published January 16, 2019. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Commodity Prices and Plays Reference Table   Trades Closed in Summary of Closed Trades

Political economy – i.e., the interplay between critical nation states’ policies and markets – often trumps straightforward supply-demand analysis in oil. This is because policy decisions affect production and consumption, along with global trade. These decisions, in turn, determine constraints states – central and tangential – confront in pursuit of their interests. Presently, U.S. policies toward Venezuela and Iran dominate oil supply considerations, while Sino – U.S. trade tensions and their effect on EM consumption dominate the demand side. In this month’s balances assessment, we revised some of our supply-side assumptions to include the high probability U.S. waivers on Iranian export sanctions will have to be extended until Venezuela stabilizes. OPEC 2.0 appears to be flexible -- positioning for either an extension of waivers, or sanctions. This keeps our baseline oil-supply assumptions fairly steady this year as the coalition adjusts to changes in Venezuela’s output. Adjustments could be volatile, however. On the demand side, we continue to expect growth of 1.49mm b/d this year and 1.57mm b/d in 2020. Steadier production and unchanged demand assumptions lower our price forecasts slightly to $75/bbl and $80/bbl this year and next for Brent, with WTI trading $7.0/bbl and $3.25/bbl below those levels, respectively (Chart of the Week). Chart of the WeekExpect OPEC 2.0 To Smooth Venezuelan Production Losses In 2019 Highlights Energy: Overweight. Nigeria’s elections, scheduled for this past weekend, were unexpectedly postponed until Saturday. Political leaders urged Nigerians to “refrain from civil disorder and remain peaceful, patriotic and united to ensure that no force or conspiracy derail our democratic development.”1 Nigeria produces ~ 1.7mm b/d of oil. Base Metals/Bulks: Neutral. Estimated LMEX, CME, SHFE and bonded Chinese warehouse copper inventories are down 29.8% y/y, which will continue to be supportive of prices. Precious Metals: Neutral. Palladium is trading ~ $111/oz over gold, as concerns over supply deficits persist. The last time this occurred was on November, 2002. Ags/Softs: Underweight. Chinese buyers are believed to have cancelled as much as 1.25mm bushels of soybean purchases last week, according to feedandgrain.com. Feature The analytical framework informing global political economy provides a useful augmentation to our standard supply-demand analysis, particularly now, when U.S. policy continues to play a pivotal role in the evolution of oil fundamentals. In particular, we believe the near-term evolution of oil prices hinges on how events in Venezuela play out, following the imposition of U.S. trade and financial sanctions directed against the state-owned PDVSA oil company and the Maduro regime. The evolution of the U.S.’s PDVSA sanctions will directly determine whether waivers on Iranian export sanctions granted by the Trump administration in November are extended when they expire in May.2 These tightly linked evolutions, in turn, will drive OPEC 2.0 production policy, and whether its production-cutting agreement is extended beyond its June 2019 termination. As we discussed recently, we see OPEC 2.0 building its flexibility to adjust quickly to either an extension of the waivers on Iranian sanctions, or to accommodate the termination of these sanctions at the end of May. Given the state of the market, which we discuss below, we believe waivers on Iranian export sanctions almost surely will be extended when they expire in May. Global Oil Markets Are Tightening Our supply assumptions are driven by our assessment that global spare capacity of just over 2.5mm b/d could accommodate the loss of Venezuelan oil exports with little difficulty (in a matter of months), aside from a further tightening at the margin in the heavy-sour crude oil market (Chart of the Week and Table 1). In fact, the loss of up to 1mm b/d or more of Iranian exports – versus the ~ 800k b/d we now expect if waivers are extended until December – could also be accommodated by OPEC 2.0’s spare capacity, given the rebuilding of this potential output on the back of OPEC production cuts, which have the effect of increasing spare capacity (Chart 2).3 Table 1BCA Global Oil Supply – Demand Balances (MMb/d) (Base Case Balances) However, should this combination of events be realized, an unplanned outage similar to the one that removed ~ 1mm b/d of Canadian production due to wildfires in the summer of 2016, with Venezuela production falling toward 650k b/d and Iranian exports even partially constrained, could move the oil market perilously close to the limits of global spare capacity, which now stands just over 2.5mm b/d, based on the EIA’s reckoning. This would increase the risk of dramatically higher prices, simply because the flex in the system would approach zero. Iranian Waivers Hinge On Venezuela The manner in which U.S. sanctions against PDVSA and the Maduro regime evolve – in particular, whether regime change is affected – will determine whether waivers on the oil-export sanctions the U.S. re-imposed on Iran last November are extended beyond their end-May terminal point. In turn, this will affect OPEC 2.0’s production policies, particularly after its production-cutting agreement expires in June. In our current model of OPEC 2.0 production, we now expect its 2019 production to continue to decline in 1H19, to drain the overhang resulting from the ramp-up member states undertook in preparation for U.S. sanctions against Iran. This policy was substantially reversed with the last-minute granting of waivers to eight importing countries by the Trump administration prior to sanctions kicking in in November. This led to a sharp sell-off in crude oil prices in 4Q18, as market participants re-calibrated the supply side of global balances. In 2H19, our base case assumes OPEC 2.0’s production rises by ~ 900mm b/d (December vs. July 2019 level), to smooth out the loss of Venezuelan output as it falls to 650k b/d by the end of this year from just under 1.1mm b/d now. The goal of this policy is to quickly drain global inventories to levels comfortably below the five-year average (in 1H19), and then to keep Brent prices in the $75/bbl to $80/bbl range over 2H19 – end-2020 (Chart 3). We expect core OPEC 2.0 countries, led by KSA, core GCC states and Russia production to rise by more than 500k b/d in 2H19 (vs. 1H19 levels), to maintain inventories at desired levels and prices in the $75/bbl to $80/bbl range. Chart 3Core OPEC And Non-OPEC Output Will Rise To Offset Venezuelan Losses To this end, we assume core OPEC 2.0’s production rises in 2020 to 33.52mm b/d from 32.98mm b/d in 2019, led by a ~ 200k b/d increase from KSA – which takes its output to ~ 10.4mm b/d from ~ 10.2mm b/d in 2019. We expect Russian production to rise to 11.7mm b/d from ~ 11.5mm b/d in 2019. Additional output hikes come from core OPEC and other non-OPEC producers (Chart 4, Table 1). Chart 4OPEC 2.0's Goal: Quickly Reduce Inventories In 1H19 We do not try to forecast how the sanctions against PDVSA and the Maduro government play out – i.e., whether the incumbent government survives, or whether a peaceful or violent regime change occurs. If Venezuela were to descend into civil war, or were to experience a violent revolution, the outcome would be unpredictable and the rebuilding of that economy – regardless of who emerges to take control of the state – would require years. Likewise, if President Maduro and the military leaders supporting him were to quietly decamp, it still would require years to rebuild that country’s oil industry and economy.4 We view the odds of a confrontation between the U.S. and Venezuela’s benefactors/creditors as extremely low. We believe the U.S. would revive the Roosevelt Corollary to the Monroe Doctrine, and that Russia and China most likely would concede Venezuela is within the U.S.’s sphere of influence, as neither intend to project the force and maintain the supply lines such a confrontation would require.5 Because the resolution of the political uncertainty in Venezuela is unsure and the outcome unknowable – particularly when unplanned outages represent such a non-trivial risk to global supply at the margin – we strongly believe waivers granted on U.S. sanctions against Iranian oil exports will be extended at least by 90 to 180 days when they expire at the end of May. As we discuss above, global spare capacity is insufficient to cover the loss of Venezuelan and Iranian output, and still have the flexibility required to meet a large unplanned outage over the course of this year or next. For this reason, Iranian sanctions will not be immediately re-imposed following the termination of U.S. waivers on exports from that state; importers most likely will be increasing their liftings of Iranian crude, in line with the extension of the waivers we expect over the course of 2H19 (Chart 5). Oil Demand Continues To Hold Up We continue to expect global oil demand to grow by 1.49mm b/d this year and 1.57mm b/d in 2020, led as always by strong EM demand growth, with China and India at the forefront (Table 1). DM demand growth is expected to slow this year, but put in a respectable performance, as well. EM commodity demand growth generally has been trending down at a slow and constant pace since the beginning of 2018, as we discussed last week when we presented our new Global Industrial Activity (GIA) index. The index indicates demand is not as stellar as it was during the synchronized global upturn of 2017, but that it also is not as bad as sentiment and expectations would indicate.6 Pulling It All Together On balance, we expect the combination of stronger OPEC 2.0 output, plus an 800k b/d increase in U.S. shale-oil production, which lifts total U.S. crude-oil output from 12.42mm b/d to 13.49mm b/d next year, is enough to keep Brent prices close to $80/bbl next year, vs. the $75/bbl we expect this year (Chart 6). We revised our expectation for WTI slightly, and now expect it to trade ~ $7.0/bbl under Brent this year and at a $3.75/bbl discount next year. Chart 6Balanced Oil Market Expected This Year and Next ... The OPEC 2.0 production discipline and lower U.S. shale-oil output, coupled with strong – not stellar – demand growth combine to allow OECD commercial oil inventories (crude and products) to resume drawing and to fall comfortably below OPEC 2.0’s 2010 – 2014 five-year average target (Chart 7). This will be supportive of the Brent backwardation trade we recommended on January 3, 2019 which now is up 265.5%, as of Tuesday’s close. Chart 7... And Oil Inventories Resume Falling Bottom Line: We revised our supply estimates, and now expect OPEC 2.0 to cover lost Venezuelan output arising from the imposition of U.S. sanctions on PDVSA and the continued deterioration of that state’s oil industry. Because global spare capacity cannot handle the loss of Venezuelan and Iranian oil exports at the same time and still cover a large unplanned outage, we expect the waivers on U.S. sanctions of Iranian oil exports to be extended for up to 180 days following their termination at the end of May. We expect Brent crude oil prices to average $75/bbl this year and $80/bbl next year as oil markets balance. We expect WTI to trade ~ $7.0/bbl below Brent this year, and $3.25/bbl under in 2020.   Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com Footnotes 1 Please see “Nigeria Election 2019: Appeal For Calm After Shock Delay,” published February 16, 2019, by bbc.com. 2 OPEC 2.0 is the name we coined for the producer coalition of OPEC states, led by the Kingdom of Saudi Arabia (KSA), and non-OPEC states led by Russia, which recently agreed to cut production by ~ 1.2mm b/d to drain commercial oil inventories and re-balance markets globally. OPEC 2.0’s market monitoring committee meets in April to assess the production-cutting deal it reached in November, which is set to expire in June. The full coalition meets in May to set policy going forward. This is just ahead of the expiration of U.S. waivers on Iranian oil exports. For a discussion of OPEC 2.0’s production optionality, please see “OPEC Starts Cutting Oil Output; Demand Fears Are Overdone,” published by BCA Research’s Commodity & Energy Strategy January 24, 2019.  It is available at ces.bcaresearch.com. 3 We are watching the evolution of the partial closure of the offshore Safaniya field in KSA about two weeks ago closely. With 1mm b/d capacity, this is the world’s largest offshore producing field; no updates have been provided by KSA this week. 4 Please see “What Next For Venezuela,” by Anne Kreuger published by project-syndicate.org on February 15, 2019 for a discussion. 5 We note here that Gazprombank, the Russian bank, froze PDVSA’s accounts over the weekend to avoid running afoul of U.S. sanctions against the company. Please see “Russia’s Gazprombank decided to freeze PDVSA accounts – source,” published by reuters.com February 17, 2019. See also “What Comes Next For Venezuela’s Oil Industry,” published by the Center for Strategic and International Studies February 12, 2019, which details how U.S. sanctions amount to the equivalent of a full-on embargo by forcing payment for Venezuelan oil to be deposited in accounts that cannot be accessed by the government or PDVSA. 6 We discuss our global demand outlook in last week’s Commodity & Energy Strategy Weekly Report, in an article entitled “Oil, Copper Demand Worries Are Overdone.” It is available at ces.bcaresearch.com. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Trade Recommendation Performance In 4Q18 Commodity Prices and Plays Reference Table Trades Closed in 2019 Summary of Trades Closed in

Highlights Investors like to hear non-consensus views, … : Part of our role is to help clients think about all of the potential outcomes, including ones that may not be as improbable as commonly believed. … but it seems that our Fed/rates call is starting to strike them as a little too non-consensus: Clients are having a hard time seeing the potential for inflation after ten years of errant predictions that it’s just around the corner. From our perspective, the probability of higher-rate outcomes is considerably higher than the probability of lower-rate outcomes, … : An investor with a low-duration bias has a whole lot more ways to win than an investor with a high-duration bias. … so we’re staying the course: We continue to recommend underweighting Treasuries and maintaining below-benchmark duration exposure, which aligns with our constructive take on markets and the economy. It’s too early to get defensive if a recession is at least a year away. Feature BCA clients like to hear contrarian calls, and there is little that’s more deflating from a strategist’s perspective than to be told in a meeting that his/her views are the same as everyone else’s. Except for the handful of strategists who make their living from provocative views that have almost no chance of coming to fruition, however, the calls have to be plausible. For many investors, our inflation concerns seem to be straining the bounds of plausibility. Even if BCA has only lately begun to beat the inflation drums, investors have had enough of warnings about inflation and interest-rate spikes that have repeatedly failed to come to pass. Regular readers are familiar with our contention that the sizable injection of fiscal stimulus into an economy already operating at capacity is a sure-fire recipe for inflation. They are also familiar with our view that an extremely tight labor market will necessarily give rise to robust wage gains. We have repeatedly argued that the Fed will respond to the combination of inflation pressures by hiking the fed funds rate above its equilibrium level, bringing the curtain down on the expansion and the equity bull market. With a Special Report examining the links between wage gains, consumer price inflation, and the Fed’s reaction function on the way, we’re instead devoting this week’s report to several other reasons why an investor would want to maintain below-benchmark duration in a fixed-income portfolio. Oil Prices Will Rise There is a good reason for devising core price indexes that smooth out the volatility inherent in food and energy prices. Core indexes provide a better read on the underlying inflation trend, and are a better predictor of moves in headline inflation than the headline indexes themselves. Inflation-linked Treasuries (TIPS) are tied to headline CPI, however, leaving the long-run inflation break-evens at the mercy of swings in oil prices (Chart 1). As we have previously written, our commodity strategists view the October-November swoon as a one-off event disconnected from market fundamentals that will quickly be unwound1 (Chart 2). Chart 1As Oil Goes, So Go Inflation Expectations, ... Chart 2... And Oil Prices Are Poised To Rise One need not fear that a rise in oil prices, while giving a fillip to headline inflation, would slow the economy and thereby offset inflation’s upward pressure on rates. Now that the U.S. is the world’s largest oil producer, its economy and financial markets are no longer negatively correlated with oil prices (Chart 3). It is still true that falling oil prices amount to a tax cut for American businesses and households, but they now also amount to fewer high-paying jobs in the oil patch, reduced earnings in an important domestic industry, and tighter monetary conditions as fracking bond spreads widen. Chart 3No Longer A Contrary Indicator Bottom Line: Higher oil prices will push headline inflation and inflation expectations higher, while also boosting the economy at the margin. The combination promotes higher bond yields, all else equal. The Economy’s Improved. Yields Haven’t Budged. Though we attributed the bulk of the fourth-quarter selloff to misplaced fears that the Fed was pulling the rug out from under the expansion, the economy was finding it harder and harder to produce positive surprises. By late January, however, the expectations bar had been reset low enough that new releases began surpassing it, day in and day out (until the end of last week). So far, though, the 10-year Treasury yield has stubbornly failed to reflect the improvement (Chart 4). Chart 4Surprises Turned Around, But Yields Didn't Financial conditions tightened sharply upon the sudden widening in corporate bond spreads and the sudden drop in equity prices. We viewed the seize-up as equivalent to at least a quarter-point increase in the fed funds rate and thereby found pausing to be a perfectly logical course of action for the Fed. The swiftness of the subsequent bounce in risk assets – the S&P 500 has retraced more than two-thirds of its losses and high-yield bonds have retraced close to 60% of their spread widening – has gone a long way toward undoing last quarter’s tightening. With the recovery in financial conditions, all three components of our Fed monitor now point to a need for tighter monetary conditions (Chart 5). Chart 5The Fed Can Pause, But It Can't Stop Adaptive Expectations’ Sluggish Response Investors’ inflation outlooks adhere closely to an adaptive expectations framework in which future predictions are largely a function of inflation’s recent path (Chart 6). This is not unreasonable; one could do a lot worse than pick the Patriots to reach the Super Bowl or only South American and European (ex-England) teams to win the World Cup. Adaptive expectations can fall prey to the recency bias, however, in which individuals overemphasize the most recent data points to the exclusion of older, potentially more representative data when forming their future views. From a recency-bias perspective, adaptive expectations can trap investors like the mythical frog contentedly lingering in a pot of water that’s only slowly brought to a boil. Chart 6Inflation Forecasts Take Their Cue From The Past ... We are skeptical of the notion that there will be no more inflation because there’s been no inflation since the crisis. The trend may be your friend, but not once the output gap has closed and the unemployment gap is persistently negative. Using the 10-year CPI forecast from the Philly Fed’s Survey of Professional Forecasters as an inflation-expectations proxy, one could argue that the lion’s share of the outsized gains in the pre-crisis phase of the bond bull market resulted from excessively generous inflation compensation (Chart 7, bottom panel). Chart 7... Which Is Great For Investors When Inflation Trends Lower The excessive compensation was a by-product of adaptive expectations. After the experience of the mid-seventies and early eighties (Chart 8), investors and issuers both assumed inflation would be higher than it turned out to be. Today’s bond-market participants, conditioned by ten years of soggy post-crisis readings, could well assume that inflation will be lower than it ultimately turns out to be. That may leave long-maturity bondholders with insufficient compensation, just like their early-fifties forebears. Chart 8Long Stretches Of Low Inflation May Be Bad For Future Treasury Returns Reversal Of Globalization The apex of globalization has been a key theme of our Geopolitical Strategy service since its launch. We cannot go as far as they sometimes do, arguing that globalization did more to bring inflation to heel than Paul Volcker, but it surely has been an important factor in limiting wage gains for low- and semi-skilled workers (Chart 9), and has helped to stymie retail price increases. The imposition of new tariffs have exacerbated globalization’s reversal, but it had already begun before the 2016 presidential election. The Reagan-Thatcher-Koizumi policies that were ascendant after the fall of the Berlin Wall, boosting global growth while tamping down inflation, have been in retreat in the developed world ever since the crisis. Chart 9China Syndrome Decomposing Core CPI When assessing inflation’s future direction, our U.S. Bond Strategy colleagues decompose the core CPI series into its primary components: Shelter (42% of the index); Goods (25%); Services, excluding shelter and medical care (25%); and Medical Care (8%). They then look at the drivers for each of the largest three components for an advance read on their future direction. Home price appreciation and the rental vacancy rate power their shelter costs model. With home price appreciation decelerating but still positive, and the rental vacancy rate hovering around its all-time lows, the model projects that shelter costs will remain well above 3% (Chart 10, top panel). Chart 10Core Inflation Isn't About To Melt Core goods inflation lags non-oil import prices by about a year and a half. The path of import prices suggests that core goods inflation will have a tailwind for much of the rest of the year before facing a headwind next year that will push it back to its current levels (Chart 10, second panel). Wage growth is the best predictor of core services inflation, ex-shelter and medical care (Chart 10, third panel). We expect continued upward pressure on services inflation, as labor-market slack continues to be absorbed, keeping wage growth accelerating. The Golden Rule Of Bond Investing Simplicity is a virtue in investment recommendations, models, and rationales, and our U.S. Bond Strategy colleagues’ golden rule of bond investing is elegantly simple.2 If Fed rate hikes exceed market expectations over a given time horizon, overweight duration positions will underperform over that horizon, and if Fed hikes fail to meet market expectations, overweight duration positions will outperform. Now that the money market has entirely priced out any rate-hike prospects over the next two years (Chart 11), overweight duration positions face a challenging backdrop. How will the fed funds rate surprise to the downside from here? Chart 11The Money Market Is Calling For A Rate Cut It can’t unless the Fed carries out more than one 25-basis-point cut in the next year or so. Given the underlying strength of the economy, gathering inflation pressures, and the swift unwinding of much of the tightening in financial conditions, rate cuts are a stretch. Against the current backdrop, the golden rule is a stern warning away from the longer-maturity reaches of the Treasury curve. Investment Implications We continue to stay the course with our fixed-income recommendations. If the Fed’s pause will extend the expansion for a few more months, it will extend the shelf life of our underweight Treasuries and overweight spread product recommendations, as well. As outlined above, we see many more potential catalysts for higher interest rates than we do for lower rates. We reiterate our recommendation that investors maintain below-benchmark duration across fixed-income segments. The expansion, and the bull markets in risk assets, will eventually end, but it’s too soon to position portfolios for it.   Doug Peta, Senior Vice President U.S. Investment Strategy dougp@bcaresearch.com   Footnotes 1 Please see the U.S. Investment Strategy Weekly Report, “What Does Oil’s Slide Mean?,” published November 26, 2018. Available at usis.bcaresearch.com. 2 Please see the U.S. Bond Strategy Special Report, “The Golden Rule Of Bond Investing,” published July 24, 2018. Available at usbs.bcaresearch.com.