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Informe especial

Highlights Few issues in the global oil and gas markets are as closely followed as the development of the U.S. shales. In this Special Report, we examine the extent to which the growth of oil and gas production in the shales will be constrained by capital discipline in the U.S. – something unheard of in years past. For the E&P companies large and small comprising this sector, success will depend on their ability to manage investors’ expectations for competitive returns – not their ability to grow production simply for the sake of growing production. We see early signs these companies – majors and independents alike – are behaving like capital-constrained firms that must provide a return greater than their cost of capital to attract and retain the funding necessary to ensure their growth and survival (Chart of the Week). Feature Since the 2014-15 global oil-price collapse, U.S. shale production has been driving non-OPEC liquid fuels production growth, expanding by an annual average ~ 1.13mm b/d vs. 0.61mm b/d for the other non-OPEC producers.1 We expect U.S. shale to remain the main vehicle of production growth over the next 2 years (Chart 2, panel 1). Our latest expectations for global supply – demand balances remain positive for the U.S. shale-oil producers. We have U.S. lower 48 production expanding by 1.3mm b/d in 2019, and 0.9mm b/d in 2020, led by shale production. This is slightly above the EIA and OPEC forecasts (Chart 2, panel 2). We have consistently exceeded the EIA’s and IEA’s production estimates for U.S. onshore production since August 2016 (Chart 3). This is not to say we believe the E&Ps will once again recklessly expand production in excess of the ability of their free cash flow (FCF) to support. In the past, we have tended to fade the independent E&Ps’ declarations of capital-discipline – e.g. in 2017 – 2018. We’ve staunchly maintained higher oil prices would compel the E&Ps to grow production beyond the ability of their FCF to support it. Nonetheless, this time could be different. Chart 2U.S. Shales Vs. Non-OPEC Production In point of fact, we now believe the independent E&P model is transitioning to a mature business model – i.e., these companies will, over time, look more like firms in other industries that seek to maximize shareholder value in order to retain their access to capital to grow and invest (Charst 4A &  4B). If the sector evolves in this direction, we could witness a sea change in the development of the U.S. shales, which leads to lower production growth. Chart 4AMajors Sensitive To Shareholder Concerns ... Chart 4B... As Are Independent E&Ps In this 2-part Special Report, we review our forecasting methodology for U.S. shale production, assess whether capital discipline demands by investors will affect current production forecasts, and explore ongoing logistical constraints in the Permian Basin and the U.S. Gulf Coast. E&Ps Transitioning To A Mature Business Model Historically, the U.S. E&P model prioritized sharp production growth above all else, making these companies highly dependent on external capital to finance that growth. In fact, since 2011, public E&Ps outspent their operating cash flow by ~ 40% on average, using a mix of debt, asset sales and equity financing (Chart 5).2 Efficiency gains allowed producers to be almost as profitable in 2018, with oil prices hovering around $65/bbl, as they were in 2014 with prices above $100/bbl. Since 2016, equity financing and asset sales have supported most of the over-spending. The equity financing window appears to have closed in 2018, as a large part of the equity issuance of smaller E&Ps was forced on them by banks to reduce leverage following their semi-annual credit re-determinations. Still, most E&Ps stock prices have remained depressed during the 32% surge in WTI prices in 1Q19 (Chart 6, panel 1). Investors remain skeptical about the E&P model, and are demanding proof this sector is moving toward a business model that can withstand the oil-price volatility that is endemic to these markets. This has – and will continue to – limited E&Ps’ ability to easily source funding from Wall Street via equity and debt financing. In fact, investors are demanding a higher premium to hold high-yield energy debt (Chart 6, panel 2), in the wake of the recent exceptional volatility oil markets have experienced. Chart 6Equities, Oil Prices Disconnected Ideally, the independent E&P cohort’s behavior would move closer to that of the Majors – i.e. spend less on capex than is generated via operating cash flow (OCF), using this margin to support dividends, and return of capital to shareholders via share buybacks. We expect most U.S. E&Ps to meet investors’ expectations, and to register positive FCF growth this year.3 Efficiency gains allowed producers to be almost as profitable in 2018, with oil prices hovering around $65/bbl, as they were in 2014 with prices above $100/bbl (Chart 7). Chart 7Efficiency Gains Drive EBIT E&P 2019 Production And Spending Guidance The last time BCA examined E&Ps’ finances – and their ability to sustain profitable growth – was in April 2018. At that time, we identified a sharp divergence in production vs. capex intentions. We argued then that these numbers were incompatible, and that E&Ps’ capital expenditures would have to increase above guidance to sustain the large production increases these firms were projecting. Actual 2018 numbers confirmed our thesis: E&P capex grew by ~ 16% y/y. Nonetheless, despite outspending their 2018 guidance, these producers needed only a limited amount of external capital. Most of the additional capex was financed from higher-than-expected operational cash flow, due mostly to higher WTI prices, cost reductions and productivity gains. Output per well slipped, all the same, while rig turnover increased, resulting in higher overall production (Chart 8). Our updated analysis for 2019 shows our group of producers is guiding toward ~ 14% y/y increase in production, and ~ 17% y/y decrease in capex. Again, these expectations are inconsistent, in our estimation. We calculate E&Ps’ production guidance is in line with our 15% y/y shale production growth forecasts. Achieving this growth will require flat to higher capex. Chart 8Well Output Down; Rig Turnover Up We estimate the exploration and development cost of adding a new barrel of oil-equivalent production in 2018 was around $32,100 for our group of 41 E&P companies (ex-property purchase and other expenses)(Chart 9). Assuming ~ 5-10% cost-inflation  and an estimate of property purchase for 2019, the ~ 1.7mm b/d of new production expected from our group – including the replacement of legacy production declines (more on this below) – would cost > $60 billion. This is above the companies’ current guidance. Achieving this would require further efficiency gains from technology improvement and geology high-grading – i.e., producers would have to focus their drilling activity on their best geologies to increase production per well, while reducing overall activity/expenditure in second-tier regions. We doubt this can happen. Our concerns about new wells’ productivity are increasing. The spacing of new wells appears to interfere with nearby older wells’ output, decreasing the overall pressure and productivity for both the newer and older wells. This often is referred to as the “parent-child” problem. The jury is still out re whether the industry has reached a tipping point in terms of well proximity that lies at the heart of this problem. However, reverting to wider spacing between wells would effectively reduce available drilling acreage in E&Ps’ tier-1 locations. Based on the most recent U.S. EIA Drilling Productivity Report (DPR) data, we cannot entirely substantiate these concerns – it is too early to detect a tipping point in the data (Chart 10). Nonetheless, we believe efficiency gains will be limited from here on, as the inventory of tier-1 wells has been decreasing in the past few year, and lateral and proppant growth slows. Importantly, this means the accelerating decline rates of U.S. production, as the share of new oil production coming from shale increases, will require more drilling and capex as new wells risk being less productive. Even in the prolific Permian Basin, new production per new well appears to have peaked in 2018. Moreover, there are growing risks of logistical bottlenecks in U.S. Gulf Coast exporting facilities that could further limit growth, a subject we will address in next week’s report. Chart 10Tipping Point For Productivity? Increasing Decline Rates Require More Capex With tight-oil production as a share of total production increasing, overall production decline rates are increasing – i.e. the downhole pressure which pushes the oil out of the well against the force of gravity dissipates much faster in shale oil wells.4 This is an underappreciated aspect of E&P production forecasts. In our view, attaining the production levels E&Ps currently are guiding toward, while accounting for massive production decline rates, will require capex to surprise to the upside and grow y/y.  Shale technology does allow for a more elastic oil supply, as it can be brought on line quickly in response to rising prices. However, the associated production declines can exceed 70% in the first year – i.e., production at a specific well (in b/d) will fall by 70% from its peak in the first year of operation – and another ~ 30% in the second year, compared to an average <10% for conventional onshore wells. This as large consequences for rig count in the U.S. Our updated decline-curve estimates show U.S. shale production will fall by ~ 37% in the next 12 months (Chart 11). This implies ~ 2mm b/d will be lost by the end of 2019. Hence, maintaining a flat level of production would require 750 rigs on average per month – given current well-per-rig and new-production-per-well rates. Accounting for the 14% y/y growth based on production guidance, this implies a total of 3.3mm b/d of new onshore U.S. production (Chart 12). In our view, attaining the production levels E&Ps currently are guiding toward, while accounting for massive production decline rates, will require capex to surprise to the upside and grow y/y. Chart 12Higher Rig Counts Needed Producers Will Remain Profitable, And Within OCF We expect U.S. E&P spending to remain within the limits of the operating cash flow. This will allow E&Ps to deliver on investors’ expectations of higher FCF and return on capital employed (ROCE). Two points support this expectation: (1) higher WTI prices, and (2) a higher inventory of Drilled-but-Uncompleted (DUCs) wells. Higher WTI prices. Our most recent oil price forecast sees WTI prices averaging $66/bbl in 2019, and $72/bbl in 2020, vs. $65/bbl in 2018.5 Most public E&Ps base their capex projection on a $50 - $55/bbl WTI price. The higher prices we expect will allow capex to increase above guidance while remaining within the limits of cash flow. Assuming no efficiency gains, this alone would increase OCF by ~ 20% compared with a $55/bbl price – depending on each company's hedging program. Including the expected 14% y/y volumes increase in 2019 adds another 14% to OCF. Hence, we believe there is room for an additional ~ $10 billion capex increase by our group of producers vs. last year solely based on our oil price and production projections. This outcome is highly contingent on our prices forecast. If prices remain in the low $50s/bbl, most producers’ cash flow will fall below the capex required to achieve current production growth forecasts. In this scenario, smaller shale producers would scramble to raise external funding to cover their expenses. As mentioned above, debt and equity financing will remain scares this year as investors demand financial discipline. This would either result in lower production growth or additional asset sales and increasing drilling partnerships. DUCs completion. Since mid-2018, Permian production has been constrained by a lack of pipeline takeaway capacity to move increasing oil production out of the basin. This put pressure on Midland, TX, prices, and incentivized additional truck and rail transportation (Chart 13, panel 1). Not unexpectedly, this led to a slowdown in completions relative to drilling activity (Chart 13, panel 2), and increased the number of DUCs. As a result, Permian producers built an inventory of excess DUCs awaiting pipeline expansions (Chart 13, panel 3). The process of drilling and completing wells produces a normal inventory of uncompleted wells, because of the time lag between the moment wells are drilled and the time they are completed. The development of multi-well pad drilling in U.S. shale basins structurally increased the time lag between drilling and completion to ~ 5 months. This implies a normal level of DUC inventory that corresponds to ~ 5 - 6 months’ worth of drilling activity. We define any DUC above our estimate of normal as an excess DUC well. It also implies that, as rig count expands, the normal level of DUCs will rise accordingly. Hence, simply looking at the absolute level of DUCs can be misleading. DUCs should be analyzed in relation to drilling. Chart 13Expect More From DUCs We estimate current excess DUCs to be ~ 1,700 in the top five shale basins, and 1,100 in the Permian alone. If completed, this represents a potential 1mm b/d and 700k b/d of additional production in top five basins and the Permian, respectively – at current well productivity. On average, completion accounts for ~ 65% of the total well costs. This implies adding new production from the 1mm b/d inventory of DUCs would require a 35% lower capital expenditure. This will support our expectation of higher E&P production while keeping expenses within OCF. In our projections, we include a monthly increase of 40k b/d of oil production from DUC completions from October 2019 to end-2020, given the 1.8mm b/d of additional pipeline capacity from the Permian to Gulf Coast that will be built before the end of the year, along with another 1.5mm b/d of new pipe that will be operational by 2021 (Chart 14). Additionally, 2mm b/d of additional takeaway capacity projected to be built from Cushing to the Gulf by 2021. This will completely relieve the transportation constraint and allow the > 900k b/d of additional production we expect by December 2020 to be moved toward export facilities. Beyond 2020, our group of E&P companies could be forced to raise external financing, as a large portion of their long-term debt will need to be paid off, or re-financed (Chart 15). This alone could capture more than 50% of E&Ps’ FCF, leaving little room to expand production within cash flow from operations. Permian Natgas Bottlenecks Remain A Risk To Oil Production Growth The exceptional growth in Permian tight oil production was mirrored by a glut in the volume of associated gas output (Chart 16, panel 1). While oil-takeaway investment has proceeded apace to get those molecules out of the Basin, supporting infrastructure development failed to produce the necessary natural-gas pipeline-takeaway capacity. This pushed gas supply above local demand and pipeline capacity, forcing natgas prices at Waha Hub lower – at times, to less than zero (e.g., in April and May 2019) (Chart 16, panel 2). In other words, producers are willing to pay midstream companies to move their gas out of the Permian. Delays in pipeline completion in Mexico led to an under-utilization of the current capacity from the Waha Hub to the Mexican border via the Trans-Pecos, Comanche Trail and Roadrunner pipelines (Chart 17). Chart 16Associated Gas Production Soars The completion of the Fermaca pipelines carrying gas toward central Mexico; and gas pipelines from the Permian to the U.S. Gulf Coast are expected to start coming on line in 2H19, which ultimately will bring an additional 9.8 Bcf/d of takeaway capacity to this market by 4Q20. This lack of capacity forced oil producers either to flare their additional gas or to reduce oil production – thereby reducing associated gas production. Most producers chose the former. As a result, flaring in the Permian reached ~ 610 MMcf/d in 4Q18 and a record high of 661 MMcf/d in 1Q19.6 By comparison, total residential natgas consumption in the entire state of Texas averaged 544 MMcf/d over the 2010 – 17 period, according to the U.S. EIA.7 When accounting for flaring and low Mexican pipelines utilization, we expect a marked supply-surplus until the end of the year, which will keep downward pressure on Waha prices (Chart 17, panel 2-3). Over the next 12 months, additional natgas pipeline takeaway will allow more gas to be shipped out of the Permian Basin: The completion of the Fermaca pipelines carrying gas toward central Mexico; and gas pipelines from the Permian to the U.S. Gulf Coast are expected to start coming on line in 2H19, which ultimately will bring an additional 9.8 Bcf/d of takeaway capacity to this market by 4Q20. This will provide the required feedstock for the ongoing Gulf Coast LNG buildout centered around Corpus Christi, TX. We expect > 5 Bcf/d of export capacity will be completed by end-2021. Nonetheless, the resumption of tight-oil production in the Permian in 2H19 is expected to build before the natgas system takeaway capacity comes on line. This will once again pressure natgas prices, and could stymie the growth in oil production in the Permian at the margin, given this would require additional flaring. How these issues are resolved partly depends on the Texas Rail Road Commission’s (RRC), which will have to rule on exemptions from the state’s Rule 32. Operators in Texas are allowed to flare gas while drilling, and for up to 10 days after completion. After this, each well’s owner must apply for a 45-day flare permit, and prove it is necessary for it to flare gas at specific wells. Texas RRC staff can issue these permits for a maximum of 180 days, beyond which an extension has to be approved via a Commission Final Order.8 Despite this strict process, YTD, none of the more than 20 requests for exception to Rule 32 in the main Permian Districts (7C, 08 and 8A) have been rejected.9 In general, the lack of existing pipeline capacity has been treated as a reasonable cause to grant exceptions to Rule 32. As long as the RRC allows these exceptions, oil production growth in the Permian will be primarily restrained by oil-pipeline takeaway constraints in the Basin, and export constraints in the Gulf. Nonetheless, these abnormal levels of flaring and venting are already gaining exposure in the media. The public opinion could switch rapidly and environmental protests could emerge, demanding the RRC enforces Rule 32 to E&P companies. This remains a risk to monitor. Bottom Line: The growth in U.S. shale-oil production could be slowing as E&P companies exercise greater capital discipline, and productivity gains begin to level off. It is still early days on the capital-discipline front – we have been here before – but we believe E&Ps are behaving in a manner consistent with that of other capital-constrained companies, and are prioritizing shareholder interests over their desire to increase production. The next big step in this evolution will be demonstrating to investors that lower-risk plays like the Permian Basin can provide the long-term returns necessary to sustain E&Ps access to capital. This will be critical as decline curves steepen in the Permian Basin and the other big U.S. shale plays.   Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com  Robert P. Ryan, Chief Commodity & Energy Strategist rryan@bcaresearch.com   Footnotes 1      U.S. shale production denotes the sum of Anadarko, Bakken, Eagle Ford, Permian and Niobrara crude oil production. In this analysis, non-OPEC liquid fuels production excludes Russia, as it jointly leads the producer coalition we’ve dubbed OPEC 2.0, which was formed at the end of 2016 to manage global oil production and drain the unintended inventory accumulation resulting from OPEC’s 2014 – 16 market-share war. 2      Our analysis is based on a group of 41 public U.S. E&P companies. As a group, these companies represent ~3.3mm b/d of production (or around 38% of U.S. onshore production). 3      Not all E&Ps will perform similarly. Well-capitalized shale producers are on track to reach positive FCF by year-end. However, smaller companies with weak fundamentals will continue to face increasing default risk as external funds from Wall Street dry up. Indeed, a management premium – well-run vs. poorly run firms – almost surely will be a defining feature of the E&P market. 4      This downhole pressure is crucial for oil production. In general, wells are not abandoned when oil is completely depleted, but when pressure reaches levels so low that almost no oil is naturally pushed up the wellbore. Pass this point, artificial lifts or re-pressurization methods are needed to continue extraction from this well, requiring additional capex. 5      Please see BCA Research’s Commodity & Energy Strategy Weekly Report titled “Oil Market Volatility Reflects Recession Fears,” dated June 6, 2019, available at ces.bcaresearch.com. 6       Please see Permian "Natural Gas Flaring And Venting Reaching All-Time High," published by rystadenergy.com, June 4, 2019. 7      Based on EIA data, https://www.eia.gov/dnav/ng/NG_CONS_SUM_DCU_STX_A.htm. 8      Please see Texas Railroad Commission's flaring regulation, https://www.rrc.state.tx.us/about-us/resource-center/faqs/oil-gas-faqs/faq-flaring-regulation/. 9      Based on Texas Railroad Commission data, https://www.rrc.state.tx.us/hearings/dockets/oil-gas-proposals-for-decision-and-orders/index-for-332/.

We are compelled to put the S&P tech sector on our downgrade watch list as President Trump’s hawkish trade talk and actions since May 5 warn that tech revenues (60% export exposure) and profits will likely remain under intense downward pressure. Our tech EPS model is also flashing red on the back of sinking capex and an appreciating U.S. dollar (bottom panel). We will be downgrading the tech sector to underweight via the S&P software index, the tech sector’s largest industry group on a market cap basis. A downgrade to neutral in the S&P software index would push our S&P tech sector weight to a below benchmark allocation. Thus, we are initiating a stop near the 10% relative return mark on the S&P software high-conviction overweight call since the December 3, 2018 inception. We also lift the stop to 27% from 17% relative return on the cyclical overweight we have on the S&P software index since the November 27, 2017 inception. Bottom Line: We are compelled to put the tech sector on our downgrade watch list. We will execute the S&P tech sector downgrade to underweight when the S&P software index’s stops are triggered. This would push the S&P software index to neutral from currently overweight.

As we highlighted in our most recent Weekly Report, the risk/reward tradeoff remains squarely to the downside and we are turning cyclically (3-12 month horizon) cautious on the prospects of the broad equity market. The Presidential cycle, UBER’s IPO, the S&P 500 hitting all-time highs following the initial December 2018 yield curve inversion, and two additional yield curve inversions signal that this time is no different and a recession is likely upon us in the coming 18 months. Using the NY Fed’s yield curve-derived recession probability forecast is revealing. This recession gauge has been an excellent leading indicator of S&P 500 momentum since the S&L crisis induced recession and its current message corroborates U.S. Equity Strategy’s cautious cyclical equity market view (recession gauge shown inverted, see chart). For additional details, please refer to the most recent Weekly Report.

Highlights Fed: A Fed rate cut in June or July is not a done deal, but is looking increasingly likely purely from a risk management perspective, as it would both calm financial markets and potentially boost the inflation expectations component of Treasury yields. ECB: Easier monetary policy is required in Europe, and Mario Draghi hinted that rate cuts or even more QE are viable policy options. Depressed European bond yields (excluding Italy) suggest that this outcome is already fully priced. Maintain only a neutral allocation to core European government bonds. Feature Chart of the WeekA Lot Of "Negativity" In Bond Yields The Great Global Bond Rally of 2019 has caught many by surprise – including, we admit with some humility, us. Not only has the pace of the decline in yields been impressive, but the outright yield levels seen in many markets are startlingly low. The 10-year German bund reach an all-time low of -0.25% last week, while sub-1% 10-year bond yields can be seen in “risky Peripherals” like Spain and Portugal. The ferocity of the global bond move has left 54% of all developed market government bonds trading with negative yields; the highest such percentage since July 2016 after the U.K. Brexit vote unnerved investors (Chart of the Week). There are parallels to today purely from a political risk perspective, given the trade tensions between the U.S. and China (and potentially any other country that the Trump Administration has issues with). Another comparison can be made versus three years ago when looking at more fundamental drivers of low global yields that require a response from policymakers – namely, slowing growth and sluggish inflation. Our Central Bank Monitors are now sending a clear message that easier monetary policy is needed in all the major developed economies (Chart 2). Given soft market-based inflation expectations, this suggests that policymakers must not only talk dovish, but act dovish, to defend the lower bound of price stability. Chart 2Pressure To Ease GLOBAL Monetary Policy We’re seeing that in places like Australia and New Zealand, where policymakers have already cut rates. We can also see that in the euro area, where the ECB has introduced a new funding program to support bank lending (TLTRO3) and is now even contemplating restarting quantitative easing (QE). The Fed is next in line, with numerous Fed officials hinting that some easing of monetary policy could be on the horizon. Much easier monetary policy is already largely discounted in the current depressed level of global bond yields, though. While there are still risks to the growth outlook from trade uncertainty, we do not foresee a U.S./global recession on the immediate horizon. That means the risk/reward balance now favors some pickup in global bond yields, warranting a below-benchmark medium-term stance on duration exposure. Why “Insurance” Fed Cuts Are Likely Chart 3A Strong Dollar Is Disinflationary Last week, the Federal Reserve held a research conference to discuss its monetary policy framework. Among the topics discussed were potential changes to the way the Fed manages its inflation target, including tolerating faster inflation after a period of below-target inflation. The goal of such “make-up” strategies would be to ensure that periods of low inflation do not get embedded into inflation expectations and bond yields. The problem with such strategies, however, is they are less likely to work if low interest rates and low inflation are a global phenomenon. The coordinated nature of the global bond rally has left the Fed facing a combination of rapidly falling Treasury yields alongside a strong U.S. dollar. With interest rate differentials continuing to favor the greenback, the currency is exerting downward pressure on commodity prices and, more generally, global inflation (Chart 3). Of course, the dollar does not only trade off interest rate differentials, but also global growth expectations, so some of the dollar rally seen this year reflects slowing non-U.S. economies and capital outflows from non-U.S. financial markets. What is clear, however, is that a strong dollar, and all it represents in terms of global growth, is disinflationary. Numerous Fed officials, including Fed Chairman Jay Powell, gave hints last week that they were open to considering interest rate cuts in response to signs of weakening U.S. growth and heightened trade uncertainty. With 5-year/5-year forward inflation expectations in the TIPS market now at 1.9% – still well below the 2.3-2.4% levels consistent with the Fed’s 2% target on the PCE deflator – the Fed has the cover to deliver one or two “insurance” rate cuts in the next few FOMC meetings. This would be consistent with their risk management framework. Our Central Bank Monitors are now sending a clear message that easier monetary policy is needed in all the major developed economies. Given soft market-based inflation expectations, this suggests that policymakers must not only talk dovish, but act dovish, to defend the lower bound of price stability.  If the Fed fails to ratify markets’ dovish expectations at next week’s policy meeting, risk assets will likely sell off – perhaps violently, as occurred last December. That would deliver the kind of tightening in financial conditions that would force the Fed turn more dovish and eventually cut rates anyway. Alternatively, if the Fed actually cuts rates next week or in July and both the economy and inflation eventually recover, and risk assets surge higher, then the Fed can always take back those cuts with tighter policy later (especially if trade uncertainty diminishes with some sort of U.S.-China trade deal at the G20 meeting later this month). Such a strategy could even help Fed credibility by boosting inflation expectations back to levels more consistent with the Fed’s inflation target, which would also help put upward pressure on Treasury yields. Our Fed Monitor is now signaling the need for easier U.S. monetary policy, but that is already discounted in the 75bps of rate cuts (over the next twelve months) priced at the front-end of the yield curve, and in the current low level of Treasury yields (Chart 4). The Treasury rally also looks overdone when looking at other measures, such as the low level of mean-reverting U.S. data surprises, overbought price momentum and extended long duration positioning (Chart 5). Chart 4Treasuries Fully Priced For Fed Easing   Net-net, the medium-term risk/reward balance favors moderate below-benchmark duration positioning for Treasury investors, and underweight tilts for the U.S. in global government bond portfolios. More tactically, the amount of Fed rate cuts now discounted seems excessive with only the U.S. manufacturing sector cooling while the rest of the economy remains on firm footing. For that reason, we are already taking profits on one leg of our fed funds futures calendar spread trade initiated last week. The Treasury rally also looks overdone when looking at other measures, such as the low level of mean-reverting U.S. data surprises, overbought price momentum and extended long duration positioning  Chart 5The Treasury Rally Looks Stretched Chart 6Fed Funds Futures Trade: Exit Long Aug 2019, Stay Short Feb 2020 We recommended buying the August 2019 fed funds futures contract to hedge the risk that the Fed tries to get ahead of market sentiment by cutting rates in June or July. That contract would have returned a positive return in a scenario where the Fed delivered one 25 basis point rate cut in either June or July, and a negative return in a scenario where rates are unchanged. In only one week, that contract’s risk/reward profile has shifted dramatically. The contract is now priced for a loss in both the “one rate cut” and “no rate cut” scenarios. We therefore exit our long position in the August 2019 fed funds futures contract for a gain of +5bps. The second leg of our proposed trade was to short the February 2020 fed funds futures contract. This remains an excellent bet. As of last Friday, a short position in the February 2020 contract will earn a positive return as long as three or fewer rate cuts occur between now and next February (Chart 6). We are keeping this position on as a pure rates trade to play for the Fed delivering less than the market expects. Bottom Line: A Fed rate cut in June or July is not a done deal, but is looking increasingly likely purely from a risk management perspective, as it would both calm financial markets and potentially boost the inflation expectations component of Treasury yields. Are European Bond Yields Discounting More ECB QE? While we see little absolute value in U.S. Treasuries, there may not be much near-term upside in yields without an improvement in European economic growth. Simply put, Europe remains an anchor weighing on global bond yields. While we see little absolute value in U.S. Treasuries, there may not be much near-term upside in yields without an improvement in European economic growth. Simply put, Europe remains an anchor weighing on global bond yields. Our country diffusion indicators for the euro area – measuring the share of countries within the region that are seeing faster GDP growth, rising leading economic indicators and quickening headline inflation rates – all show that the current downturn is broad-based (Chart 7). Dating back to the introduction of the single currency zone in the late 1990s, there have been three periods where the country diffusion indicators were as weak as they are now. All three times lead to multiple interest rate cuts by the ECB. Chart 7A Broad-Based Slowing Of European Growth & Inflation Our ECB Monitor is also calling for easier monetary policy in the euro area (Chart 8), driven by weakness in both the growth and inflation components. Chart 8Our ECB Monitor Says 'Ease', Bund Yields Agree With the ECB policy rate already negative, however, the central bank is reluctant to push rates even lower and starve euro area banks of badly needed net interest margin. Chart 9TLTRO3 Will Help Italian & Spanish Banks The Most   At last week’s policy meeting, the ECB Governing Council committed to leaving rates unchanged through the first half of 2020. ECB President Mario Draghi noted in his press conference that forward guidance has “become the major monetary policy tool we have now”, suggesting that actual changes in interest rates will be more difficult to implement. Draghi also noted that the new TLTRO3 program was intended only as a “backstop” to sustain current levels of bank lending as the old TLTRO programs begin to roll off, not as a fresh source of stimulus. This was almost certainly aimed at the banks of Italy and Spain – countries that took up nearly 60% of the last TLTRO program that is now starting to roll off and where credit growth is contracting (Chart 9). The ECB worries that the weaker parts of the European banking system are becoming too reliant on cheap central bank funding, making it more difficult to end the liquidity program in the future without causing a credit crunch.   German bunds have already priced in some sort of ECB easing (rate cuts or fresh bond buying). Our estimate of the term premium on the 10-year German bund yield is already deeply negative, which reflects both a risk aversion bid for safety and, potentially, some market expectation of incremental ECB QE. Chart 10Market Discounting Fresh ECB Bond Buying? So if the ECB is reluctant to cut rates or subsidize more lending, what monetary ammunition is left? Draghi did hint last week that the topic of restarting the Asset Purchase Program (APP) came up in the ECB meeting as an option if the economic and inflation backdrop deteriorated further, or global trade uncertainty intensified. The ECB is facing a situation similar to when the APP was first announced in 2014. Inflation expectations, as measured by the 5-year/5-year forward euro CPI swap rate, are now down to 1.2% (Chart 10). It was a similar plunge in inflation expectations that wore down ECB hawks’ reticence to deploy quantitative easing back in 2014. German bunds have already priced in some sort of ECB easing (rate cuts or fresh bond buying). Our estimate of the term premium on the 10-year German bund yield is already deeply negative, which reflects both a risk aversion bid for safety and, potentially, some market expectation of incremental ECB QE. The latter interpretation would also explain the low level of bond yields seen in Peripheral Europe (excluding Italy, dealing with a deficit battle with the European Commission), as investors stretch for yield in anticipation of supportive future ECB policy. We see little investment value in euro area bonds at such low levels, given how much bad news on growth and inflation, and the potential monetary easing in response, is already discounted. Similar to U.S. Treasuries, the risk/reward balance favors a modest below-benchmark structural duration stance. The upside in European yields is still far more limited than for U.S. Treasury yields, given the much more fragile state of European growth and inflation expectations. Treasuries are thus more overpriced than bunds. Bottom Line: Easier monetary policy is required in Europe, and Mario Draghi hinted that rate cuts or even more QE are viable policy options. Depressed European bond yields (excluding Italy) suggest that this outcome is already fully priced. Maintain only a neutral allocation to core European government bonds.   Robert Robis, CFA, Chief Fixed Income Strategist rrobis@bcaresearch.com Recommendations Duration Regional Allocation Spread Product Tactical Trades Yields & Returns Global Bond Yields Historical Returns

Yesterday we were stopped out on our long S&P managed health care/short S&P semis market neutral pair trade initiated on May 13, 2019 for a gain of 10%. Our thesis remains intact that a lot of negative news has been priced into HMOs on the back of the threat of the “Medicare For All” bill passage, while a lot of euphoria has been baked in the cake for semis despite their current down cycle. However, portfolio risk management is forcing our hand and given our ongoing de-risking, we are obeying our trailing stop loss for a gain of 10% in a very short time span. Bottom Line: Book gains of 10% in the long S&P managed health care/short S&P semis pair trade since inception and move to the sidelines for now.