Oil & Gas Exploration & Production

Highlights Portfolio Strategy Recession odds continue to tick higher, according to the NY Fed’s probability of recession model, at a time when global growth is waning, U.S. profit growth is contracting and the non-financial ex-tech corporate balance sheet is degrading rapidly. On a cyclical 3-12 month time horizon we remain cautious on the broad equity market. This is U.S. Equity Strategy’s view, which stands in contrast to the more sanguine equity BCA House View. The souring macro backdrop coupled with a firming industry demand outlook signal that more gains are in store for hypermarket stocks. The global growth slowdown, declining real bond yields, missing inflation, rising policy uncertainty and a favorable relative demand backdrop suggest that there is an exploitable tactical trading opportunity in a long global gold miners/short S&P oil & gas E&P pair trade. Recent Changes Upgrade the S&P hypermarkets index to overweight, today. Initiate a long global gold miners/short S&P oil & gas exploration & production (E&P) pair trade, today Table 1 Feature Obsession with the Fed easing continues to trump all else, with the SPX piercing through the 3,000 mark to fresh all-time highs last week. However, it is unrealistic for the Fed to do all the heavy lifting for the equity market as we have argued recently (see Chart 3 from June 24),1 at a time when profit cracks are spreading rapidly. This should be cause for some trepidation. Since the Christmas Eve lows essentially all of the 26% return in equities is explained by valuation expansion. The forward P/E has recovered from 13.5 to nearly 17.2 (Chart 1). There is limited scope for further expansion as four interest rate cuts in the coming 12 months are already priced in lofty valuations. Now profits will have to do the heavy lifting. But on the eve of earnings season, more than half of the S&P 500 GICS1 sectors are forecast to have contracted profits last quarter, and three sectors could not lift revenue versus year ago comps, according to I/B/E/S data. Looking further out, there is a plethora of indicators that we highlighted last week that suggest that a profit recession is looming.2 Our sense is that once the euphoria around the looming Fed easing cycle settles, there will be a massive clash between perception and reality (Chart 2) that will likely propagate as a surge in volatility. Chart 1Multiple Expansion Explains All Of The SPX’s Return Chart 2Unsustainable Divergence This addiction to low rates has come at a great cost to the non-financial corporate sector. As a reminder, this segment of the economy is where the excesses are in the current cycle as we have been highlighting in recent research.3 Using stock market related data for the non-financial ex-tech universe, net debt has increased by 70% to $4.2tn over the past five years, but cash flow has only grown 18% to $1.7tn. As a result, net debt-to-EBITDA has spiked from 1.7 to 2.5, an all-time high (Chart 3). While stocks are at all-time highs (top panel, Chart 3), the debt-saddled non-financials ex-tech universe will likely exert substantial downward pressure to these equities in the coming months (Chart 4). Chart 3Balance Sheet Degrading Chart 4Something’s Got To Give Moving on to the labor market, we recently noticed an interesting behavior between the unemployment rate and wage inflation since the early-1990s recession: a repulsive magnet-type property exists where like magnetic poles repel each other (middle panel, Chart 5). In other words, every time the falling unemployment rate has kissed off accelerating wage growth, a steep reversal ensued at the onset of recession during the previous three cycles. A repeat may be already taking place, as average hourly earnings (AHE) growth has been stuck in the mud since peaking in December 2018. Importantly, the AHE impulse is quickly losing steam and every time the Fed embarks on an aggressive easing cycle it typically marks the end of wage inflation (bottom panel, Chart 5). Chart 5Beware Of Repulsion Chart 6Waiting For Growth Meanwhile, BCA’s global manufacturing PMI diffusion index has cratered to below 40% (middle panel, Chart 6). Neither the G7 nor the EM aggregate PMIs are above the boom/bust line (top panel, Chart 6). Our breakdown of the Leading Economic Indicators into G7 and EM14 also signals that global growth is hard to come by, albeit EMs are showing some early signs of a trough (bottom panel, Chart 6). As the early-May announced increase in Chinese tariffs begin to take a toll, we doubt global growth can have a sustainable recovery for the rest of 2019, despite Chinese credit growth picking up. Now, even Japan and Korea are fighting it out and are erecting barriers to trade, dealing a further blow to these economically hyper-sensitive export-oriented economies. Netting it all out, the odds of recession by mid-2020 continue to tick higher according to the NY Fed’s model (NY Fed’s probability of recession shown inverted, top panel, Chart 5) at a time when global growth is waning, U.S. profit growth is contracting and the non-financial ex-tech corporate balance sheet is degrading rapidly. On a cyclical 3-12 month time horizon we remain cautious on the broad equity market. This is U.S. Equity Strategy’s view, which stands in contrast to the more sanguine equity BCA House View. This week we are upgrading a consumer staples subgroup to overweight and initiating an intra-commodity market neutral trade. Time To Buy The Hype The tide is shifting and we are upgrading the S&P hypermarkets index to an above benchmark allocation. While valuations are stretched, trading at a 50% premium to the overall market on a 12-month forward P/E basis (not shown), our thesis is that these Big Box retailers will grow into their pricey valuations in the coming months.  The macro landscape is aligned perfectly with these defensive retailers. Consumer confidence has been falling all year long and now cracks are spreading to the labor market (confidence shown inverted, top panel, Chart 7). ADP small business payrolls declined for the second month in a row. Similarly, the NFIB survey shows that small business hiring plans are cooling (hiring plans shown inverted, middle panel, Chart 7). As a reminder, 2/3 of all new hiring typically occurs in the small and medium enterprise space. In the residential real estate market, the drop in interest rates that is now in its eighth month has yet to be felt, and house price inflation has ground to a halt. Historically, Costco membership growth has been inversely correlated with house prices (house price inflation shown inverted, bottom panel, Chart 7). Chart 7Deteriorating Macro Backdrop … Chart 8…Is A Boon To Hypermarkets… Chart 8 shows three additional macro variables that signal brighter times ahead for the relative share price ratio. The drubbing in the 10-year U.S. treasury yield reflects a souring macro backdrop, melting inflation and a steep fall in U.S. economic data surprises. The ISM manufacturing index that continues to decelerate and is now closing in on the boom/bust line corroborates the bond market’s grim message. Tack on the Fed’s expected four cuts in the coming 12 months, and factors are falling into place for a durable rally in relative share prices. This disinflationary backdrop along with the Fed’s looming easing interest rate cycle have put a solid bid under gold prices. Hypermarket equities and bullion traditionally move in lockstep, and the current message is to expect more gains in the former (top panel, Chart 9). On the trade front specifically, these Big Box retailers do source consumer goods from China, but up to now these imports have been nearly immune to the U.S./China trade dispute as prices have been deflating (import prices shown inverted, bottom panel, Chart 9). However, this does pose a risk going forward and we will be closely monitoring it for two reasons: First, because downward pressures may intensify on the greenback and second, President Trump may impose additional tariffs, both of which are negative for industry pricing power. Chart 9Profit Margins… Chart 10…Will Likely Expand Meanwhile, industry demand is on the rise and will likely offset the potential trade and U.S. dollar induced margin pressures. Hypermarket retail sales are climbing at a healthy clip outpacing overall retail sales (bottom panel, Chart 10). Already non-discretionary retail sales are outshining discretionary ones, which is a precursor to recession at a time when overall consumer outlays have sunk below 1% (real PCE growth shown inverted, top panel, Chart 10). The implication is that hypermarkets will continue to garner a larger slice of consumer outlays as the going gets tough. In sum, the souring macro backdrop coupled with a firming industry demand outlook signal that more gains are in store for hypermarket stocks. Bottom Line: Boost the S&P hypermarkets index to overweight. The ticker symbols for the stocks in this index are: BLBG – S5HYPC – WMT, COST. Initiate A Long Global Gold Miners/Short S&P Oil & Gas E&P Pair Trade One way to benefit from the global growth soft-patch and looming global liquidity injection is to go long global gold miners/short S&P oil & gas E&P stocks on a tactical three-to-six month basis. While this market neutral and intra-commodity pair trade has already enjoyed an impressive run, there is more upside owing to a favorable macro backdrop. The key determinant of this share price ratio is the relative move in the underlying commodities that serve as pricing power proxies (top panel, Chart 11). Given the massive currency debasement potential that has gripped Central Banks the world over, such a flush liquidity backdrop will boost the allure of the shiny metal more so than crude oil. Global manufacturing PMIs are foreshadowing recession and our diffusion index has plummeted to the lowest level since 2011 (diffusion shown inverted, middle panel, Chart 11). In the U.S. specifically there is a growth-to-liquidity handoff and the ISM manufacturing survey’s new order versus prices paid subcomponents confirms that global gold miners have the upper hand compared with E&P equities (bottom panel, Chart 11). Chart 11Global Soft-Patch… Chart 12…Disinflation… As a result of this growth scare that can easily morph into recession especially if the U.S./China trade war continues into next year, inflation is nowhere to be found. Unit labor costs are slumping (top panel, Chart 12), the NY Fed’s Underlying Inflation Gauge has rolled over decisively (not shown),4 and the GDP deflator is slipping (middle panel, Chart 12).      Parts of the yield curve first inverted in early-December and the 10-year/fed funds rate slope is still inverted, signaling that gold miners will continue to outperform oil producers (yield curve shown on inverted scale, bottom panel, Chart 13). The near 100bps dive in real interest rates since late-December ties everything together and is a boon to bullion (and gold producers) that yields nothing (TIPS yield shown inverted, top panel, Chart 13). Meanwhile, bond volatility has spiked of late and the bottom panel of Chart 14 shows that historically the MOVE index has been joined at the hip with relative share prices. Chart 13…Melting Real Yields And… Chart 14…The Spike In Bond Vol, All Favor Gold Miners Over Oil Producers On the relative demand front, we peer over to China to take a pulse of the marginal moves in these commodity markets. China (and Russia) has been aggressively shifting their currency reserves into gold, and bullion holdings are rising both in volume terms and as a percentage of total FX reserves. In marked contrast, oil demand is feeble and Chinese apparent diesel consumption that is closely correlated with infrastructure and manufacturing activity has tumbled. Taken together, the message is to expect additional gain in relative share prices (middle & bottom panels, Chart 15). Adding it all up, the global growth slowdown, declining real bond yields, missing inflation, rising policy uncertainty and a favorable relative demand backdrop suggest that there is an exploitable tactical trading opportunity in a long global gold miners/short S&P oil & gas E&P pair trade. Bottom Line: Initiate a tactical long global gold miners/short S&P oil & gas E&P pair trade on a three-to-six month time horizon with a stop at the -10% mark. The ticker symbols for the stocks in these indexes are: GDX:US and BLBG – S5OILP – COP, EOG, APC, PXD, CXO, FANG, HES, DVN, MRO, NBL, COG, APA, XEC, respectively. Chart 15Upbeat Relative Demand Backdrop   Anastasios Avgeriou, U.S. Equity Strategist anastasios@bcaresearch.com   Footnotes 1      Please see BCA U.S. Equity Strategy Weekly Report, “Cracks Forming” dated June 24, 2019, available at uses.bcaresearch.com. 2      Please see BCA U.S. Equity Strategy Weekly Report, “Beware Profit Recession” dated July 8, 2019, available at uses.bcaresearch.com. 3      Please see BCA U.S. Equity Strategy Weekly Report, “A Recession Thought Experiment” dated June 10, 2019, available at uses.bcaresearch.com. 4      https://www.newyorkfed.org/research/policy/underlying-inflation-gauge   Current Recommendations Size And Style Views Favor value over growth Favor large over small caps

Special Report

Highlights The U.S. oil market has always been dynamic, but, over the past couple of years, profound changes have been occurring at increasingly rapid rates. In Part 1 of this two-part Special Report, we presented our forecasts for U.S. independent E&P companies’ crude oil production.1 We concluded that U.S. producers would increase production by 15% and 10% yoy this year and next, roughly in line with guidance. We argued that this could be done with flat/higher capex this year, and that current guidance for more than a 10% yoy decrease in capex would not allow for the estimated production increase. This week, we publish Part 2 of our Special Report and look at some of the larger changes occurring in the U.S., and assess the big factors we believe could significantly impact the evolution of oil production: The Majors’ increasing presence in the Permian Basin; Rising U.S. Gulf of Mexico (GOM) production; and Bottlenecks at U.S. Gulf Coast export facilities. Feature The world’s largest privately held energy companies – the "Majors" – have committed to the U.S. in a big way – mostly in the Permian Basin in Texas – directing their formidable technology, scale, and, most importantly, strong balance sheets to expanding U.S. production. Guidance from supermajors2 indicates capital expenditures increased by 11.6% in 2018, and will increase by 17.3% in 2019 (Chart of the Week). U.S.-directed capex for the group has been in a steep upward trend since 2016. In 2018, Chevron, Exxon and BP increased their U.S upstream capex by ~ 50% y/y. Additionally, Exxon’s and Chevron’s U.S. upstream capex represented 30% and 36% of each company’s total capex vs. an average 22% and 23%, respectively, over the past 5 years. This is not exclusively related to tight-oil developments in the major shale basins. Nonetheless, it corroborates comments from these companies re the expansion of their activity in the U.S. tight oil market.3 The major oil companies are expected to invest more than $10 billion in the Permian this year, according to IHS Markit.4 The supermajors could add close to 1mm b/d by 2021 and ~ 2mm b/d of production from U.S. shales alone by 2024, most of it in the Permian and at the lower end of the shale production cost curve. Adding this to the guidance from the E&Ps highlighted in Part 1 of our Special Report motivates our positive U.S. crude production outlook. We expect U.S. onshore production will increase by close to 1.3mm b/d in 2019, and ~ 1mm b/d in 2020. Longer term, the presence of these major integrated oil companies in the U.S. shale patch will reduce production’s price-elasticity. This is because, for some of these companies with all-in sustaining costs close to $40/bbl, tight-oil production out of the Permian will become baseload production, which higher-cost producers will be forced to adjust to going forward.5 These major oil producers focus mainly on the medium- to long-term, on sustainable and stable production, and dividend growth versus short-term production in response to higher – and often transient – prices. The latter production strategy – i.e., ramping production as prices rise – can only be sustained by outspending cash flow (Chart 2). Chart 2E&Ps Have Outspent Their Cash flow Since 2011 Moreover, large integrated oil companies can sustain extended periods of low prices from their shale projects, because their focus is on being the lowest-cost producers wherever they operate. This is the strongest risk-management policy an oil producer can pursue, because it minimizes revenue and profit exposure to low and volatile prices. In addition, these firms develop a presence in midstream and downstream operations to diversify revenues, which reduces direct exposure to E&P activity, thus benefiting balance sheets and income statements. Our updated full-cycle breakeven price for our group of independent E&P companies – arguably the marginal light-tight-oil producer – suggests shale production’s average breakeven (excluding land acquisition costs) is around $50.10/bbl.6 Chart 3 illustrates the impact of this new wave of low cost supply – coming from the supermajors’ focus on Permian production – on our estimated full cycle cost breakeven. Assuming a constant breakeven for independent E&P companies, this could significantly lower the average breakeven cost for shale production by 2021. These operating features brought to the shales by the supermajors have important implications for how we model U.S. onshore production. In our current methodology, we estimate the rig count elasticity with respect to variation in oil prices based on the historical relationship between realized prices, the forward curve (its level and slope), and rig counts. Subsequently, we use these rig count estimates – along with our own estimates of production decline rates and productivity per rig by basin – as an input to forecast oil production.7 Rig count is a core input to our U.S. production estimates. It is a straightforward metric entirely driven by the E&Ps’ willingness to increase capex. Thus, the ongoing capital discipline evident in the E&Ps and the Majors, combined with rising production from the supermajors, could affect our estimated rig count elasticity.8 This in turn, would increase the uncertainty of forecasts obtained from models estimated on historical data over the short run, as we – and the market – become accustomed to a less-elastic production profile in the U.S. shales. Over the short term, this will not have a material effect to our 2019 production estimates. As shown in Part 1 of this report, our modeling based on historical rig count price-elasticity is in line with E&P’s production guidance. If we are right that the current capital discipline theme will remain a top priority for independent U.S. E&P companies in the future, this will gradually affect our forecasting methodology starting next year. U.S. Gulf Production Since 3Q18, our modeling of U.S oil production has focused mainly on onshore production ex GOM. We’ve relied largely on the U.S. EIA‘s estimates of GOM production, given that our own assessment did not differ materially from the EIA’s during that period. Going forward, we believe GOM production could surprise to the upside and surpass the EIA’s estimates in the short term. The EIA recently revised down its GOM forecasts for 2020 (Chart 4). Since the 2014 global oil prices collapse, producers in the Gulf have been increasingly leveraging existing infrastructure with short-cycle field developments using subsea tie-backs to boost production at reduced costs. Previously omitted locations – i.e. smaller fields not profitable enough to support the massive investment required for their own infrastructure – can now be tied in to existing infrastructure using subsea flowlines connected to existing platforms that have surplus production-carrying capacity. GOM producers’ business model is evolving to prosper in volatile oil price environments and sustained lower oil prices. The shorter cycle time and lower capex requirements for subsea tie-backs allow for more flexible production at costs that come close to Permian shale plays. Flowlines can reach wells more than 25 miles away from the main platform; this could be extended to reach 30 miles by 2020, allowing for more field to be profitably developed.9 Chart 4EIA GOM Production Forecasts Are Too Low The theme of subsea tie-backs and low-risk development will remain in place going forward, according to IHS Markit.10 Producers are favoring these projects to limit their exposure to oil price fluctuations. BP and Shell signaled they are expanding development at existing GOM fields.11 However, production at most sites will most probably start towards the end of next year, or slightly after our end-2020 forecast horizon. Chart 5Medium Term, Large Scale Investments Are Needed In the medium term, the risk of stagnating GOM production remains elevated due to a lack of large investments and decline rates at newer fields (2014-2017) (Chart 5). Furthermore, as the majors and large E&Ps continue to focus on increasing their free cash flow, the aggressive shift toward onshore-shale projects risks starving the development of large fields in the GOM of much-needed capex. Future expansions in the Permian and GOM could increasingly be competing for funding by major oil companies. In fact, recent cost-reduction measures could allow for the development of greenfield projects at competitive costs. The recent completion of Shell’s giant Appomattox field – one quarter earlier at a cost 40% lower than initially expected – came in with a breakeven cost between $40-50/bbl, something that could signal a bright future for this type of development.12 U.S. Gulf Export Capacity Buildout Combining our production forecasts for independent E&Ps, majors and GOM projections, we expect total U.S. crude oil production to increase by 1.43mm b/d to 12.38mm b/d in 2019 and 1.16mm b/d to 13.55mm b/d in 2020. However, much of the new shale production, which will represent the bulk of the output growth in the U.S., will have to be sold in export markets, given U.S. refiners still run mostly medium and heavy crude oil slates. This is a problem, taking into account the speed at which Gulf Coast export facilities can be expanded. We believe current export facilities will reach full capacity sometime next year (Chart 6). We will be exploring this topic in greater depth next month. Over the short-term, this implies production bottlenecks likely will move from the Permian Basin to the Gulf Coast. U.S. refineries cannot absorb these large volumes of new light sweet oil in such a short period. Hence, the bulk of additional production will have to be exported to foreign buyers. Additionally, Permian production is becoming lighter as the supply of West Texas Light (WTL) increases – recently reaching more than 10% of the basin’s total production.13 Gulf Coast refiners’ crude slate has become lighter and sweeter as shale-oil production has expanded in the U.S (Chart 7). However, this trend cannot continue without large investments in new capacity, especially with the rising domestic supply of ultra-light WTL-type crude. Chart 6U.S. Crude Exports Are Trending Higher Chart 7Gulf Coast Refiners Crude Slate Has Become Lighter In fact, since 2007, the abundant domestic light-sweet supply has mainly been absorbed through (1) the blending of lighter crude with heavier imported crude, (2) the rising utilization rate of atmospheric distillation units, and (3) declining light oil imports, which have fallen from more than 1.6mm b/d in 2009 to 0.36mm b/d – and close to zero at PADD 3 (Gulf Coast) – as of April 2019. These strategies are at or close to their limits (Chart 8). On the other hand, imports of the heavy crude U.S. refiners continue to need remained constant, reflecting refiners’ stable demand for these grades. Chart 8Domestic Absorption Of Light Crude Is Close To Maximum Chart 9Crude Price Spreads Starting To Signal Export Constraints Historically, logistical imbalances have been resolved quickly in the U.S. shale sector. The price mechanism incentivizes investment where it’s needed the most, and we believe this is already happening in the U.S. Gulf with planned deep-water harbor expansions (Chart 9). In the medium-term – i.e., over the next 2 – 5 years – these export-capacity issues will be fixed. In fact, there already are plenty of projects proposed to alleviate the bottlenecks. We estimate up to 12mm b/d of export capacity increase have been proposed so far. This would be a massive overbuild of Gulf export facilities. We estimate ~ 500k b/d of additional export capacity will be needed by end-2020, which implies only one offshore or a few onshore projects would have to be built. By 2023, the U.S. would need new capacity to reach around 5mm b/d (Chart 10).14 Nonetheless, the buildout of U.S. Gulf coast hydrocarbon-export infrastructure could be a bumpy ride. Risks remain, as these large projects require complicated permitting and massive funding which can drastically increase construction time. The LLS-Brent spread will probably be volatile in 2020 until the first project receives its Final Investment Decision, and markets are able to assess the timeline these new investments are on. Given the number of projects in the pipeline, however, export capacity could significantly expand by end-2020 or 2021. This evolution will be most visible in the different price spreads we follow, which offer a market-based assessment of these developments. First, we track the WTI- and Midland- LLS prices to grasp the evolution of Cushing and Permian pipeline debottlenecks toward the Gulf Coast – i.e. the domestic constraints. Second, we use the LLS-Brent spread as a gauge for the Gulf Coast export buildout – i.e. the external constraints (Chart 11). Bottom Line: Independent U.S. E&Ps will manage to increase production in line with current guidance while remaining profitable. This will be supported by completion of excess DUCs and rising WTI prices. Moreover, the emergence of the supermajors in the Permian and other prolific shale regions will contribute to increasing total U.S. onshore production in line with our current forecasts. Our base case suggests the U.S. Gulf Coast export capacity buildout will allow the excess production to reach foreign buyers. Nonetheless, risks remain re potential delays in these massive projects. The LLS-Brent spread could be volatile this year and next   Chart 11Tracking Domestic And External Constraints With Crude Price Spreads Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com Robert P. Ryan, Chief Commodity & Energy Strategist rryan@bcaresearch.com   Footnotes 1      Please see BCA Research’s Commodity And Energy Strategy Special Report titled “Shale-Oil E&Ps Turning A Corner?” published June 13, 2019. It is available at ces.bcaresearch.com. 2      Supermajors include XOM, CVX, RDS/Shell, BP AND TOTAL. 3      Please See ExxonMobil to increase, accelerate Permian output to 1 million barrels per day by 2024 published March 5, 2019 by exxonmobil.com. Please see Chevron eyes 900,000 b/d from Permian by yearend 2023 published March 6, 2019 by ogj.com. 4      Please see The ‘Monster’ Texas Oil Field That Made the U.S. a Star in the World Market published February 3, 2019 by nytimes.com. 5      For instance, Exxon communicated it could sustain double-digit returns in the Permian with prices falling to $35/bbl. Please see ExxonMobil to increase, accelerate Permian output to 1 million barrels per day by 2024 published March 5, 2019 by exxonmobil.com. 6              Our analysis is based on a sample of selected public independent U.S. E&P companies. As a group, these companies represent ~3.0mm b/d of production (or close to 35% of U.S. onshore production). Our full cycle cost breakeven represents oil price that provides a ~10%+ return on the incremental capital plus the cost of overhead and the capital cost of the drilling right acquisition. 7              Our production estimate is equal to [rig count X estimate of new production per rigs] – [estimate of decline rates X legacy production]. 8              In Part 1, we discussed the likelihood independent E&P companies will deliver on investors’ demand for fiscal discipline. In our view, this will contribute, at the margin, to lowering the supply price-elasticity of U.S. shale development. In periods of high oil prices, these companies will increase production within the limit of their growing cash flow (i.e. without raising external financing via debt or equity). This implies production will have less upside as prices increase or remain elevated. On the other hand, in periods of declining or low prices, the healthy balance sheets of fiscally disciplined companies keeps the external financing window open in case of reduced cash flow. Moreover, the larger the share of companies that manage to improve their balance sheets, the lower the number of bankruptcies when prices decline. This limits the production decline. Hence, on average, production will grow at more steady pace than in the past, decreasing its price-elasticity. 9              Please see “Take a Look at Me Now – Gulf of Mexico Crude Output Is Approaching 2 MMb/d,” published May 7, 2019 by RBN Energy. 10     Please see Subsea tie-backs de-risk Deepwater Gulf of Mexico published June 4, 2019 by ihsmarkit.com. 11     BP plans to increase its production in the GoM by ~400k boe/d through expansion using existing facilities at its Atlantis, Thunder Horse and Na Kika fields. Please see BP plans for significant growth in deepwater Gulf of Mexico published January 8, 2019 by bp.com. Shell signaled it would leverage its new Appomattox infrastructure to tie-back adjacent fields -- e.g. production from Vicksburg and Fort Sumter. Shell's upstream director mentioned “Appomattox creates a core long-term hub for Shell in the Norphlet through which we can tie back several already discovered fields as well as future discoveries.” Please see Appomattox field comes on stream in GOM published May 23, 2019 by ogj.com. 12     Please see Shell starts production at giant Appomattox field in Gulf of Mexico published May 23, 2019 by reuters.com. 13     Please see As Permian oil production turns lighter, price outlook darkens published June 6, 2019 by reuters.com. West Texas Light (WTL) is a newly available crude grade from the Permian basin with an API of 44.1 to 49.9 and maximum sulfur of 0.4% vs. an API of ~ 40 for WTI. Most of the growth in WTL production comes for the Delaware basin within the Permian. The API is a measure of the density of a petroleum liquid. The higher the API, the lighter the crude is. This will determine the complexity of refining a certain crude input into finished products. 14     Please see BCA Research’s Commodity and Energy Strategy Weekly Report titled “Oil Price Diffs: Global Convergence,” published March 7, 2019. It is available at ces.bcaresearch.com.

Special Report

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/.

Overweight The S&P oil & gas exploration & production (E&P) index received a much needed boost last week when the blockbuster acquisition of Anadarko by Chevron (at a 37% premium to the stock’s previous close) was announced, triggering a wave of M&A premia being added to stocks in the index. This valuation lift looks reasonably well deserved in our opinion, considering the degree to which the integrated oil majors are moving in to shale gas plays with a focus on the Permian basin. A narrowing of junk bond spreads is confirming the resurgent optimism in the sector (second panel). Our investment thesis is based on our sister publication, BCA’s Commodity & Energy Strategy, and their bullish WTI view, which is the fundamental growth driver in the sector (WTI shown advanced six months, bottom panel). We continue to expect a recovering energy price to drive a reversal of the recent moderation in oil & gas production, delivering a double dose of growth and margin improvement, goosing sector earnings and share prices. Bottom Line: We reiterate our overweight recommendation on the S&P oil & gas E&P index and our high-conviction overweight recommendation on the broader S&P energy index that we added this week.1 The ticker symbols for the stocks in this index are: BLBG: S5OILP - COP, EOG, APC, PXD, CXO, HES, FANG, DVN, MRO, APA, NBL, COG, XEC.   1 Please see BCA U.S. Equity Strategy Weekly Report, “ Show Me The Profits” dated April 15, 2019, available at uses.bcaresearch.com.

  Overweight For the better part of this decade, the rise and fall of WTI has been the fundamental driver of the fortunes of the S&P oil & gas exploration & production (E&P) index, as it should be. However, starting in 2017, WTI began a pronounced recovery that was not matched by the relative performance of E&P stocks; this divergence has grown excessive (top panel). Such a divergence would be logical if domestic production had not matched the recovery in oil prices though, as shown in the second panel, this is not the case. Forward earnings projections too have been moving upward at a pace broadly similar to the underlying commodity, which we think marks conservatism on the part of sell-side analysts who are still stinging from being caught offside in 2014. Typically, we would expect increasing fixed cost absorption to drive multiplicative returns to profit growth as the price of oil increases. Nevertheless, forward earnings have been rising much faster than share prices, meaning valuations have collapsed to the normal range before the 2014 oil price decline (bottom panel). We reiterate our overweight recommendation on the S&P oil & gas E&P index and our high-conviction overweight recommendation on the broader S&P energy index. The ticker symbols for the stocks in this index are: BLBG: S5OILP - COP, EOG, APC, PXD, DVN, CXO, MRO, APA, HES, NBL, EQT, COG, XEC and NFX.  

Highlights Portfolio Strategy Looming inflation, the synchronized global capex upcycle and rising real Treasury yields all argue for preferring oil-related to gold-exposed equities. Recent Changes Initiate a long S&P oil & gas exploration & production / short global gold miners pair trade today. Table 1 Feature Chart 1No Contagion Yet Stocks recovered smartly from the Turkey induced pullback last week, and continue to flirt with all-time highs. While the risk of contagion remains acute, three key high-frequency financial market metrics suggest that the SPX will likely escape unscathed. The second panel of Chart 1 shows that both the Japanese yen and the Swiss franc, the two ultimate safe havens, have barely budged vis-a-vis the U.S. dollar and also the junk bond market remains extremely calm (third panel, Chart 1). We will continue to closely monitor these indicators to gauge the risk of contagion in U.S. equities. The greatest risk, however, is China's economic footing, particularly its foreign exchange policy (bottom panel, Chart 1). Any further steep devaluation in the renminbi will prove destabilizing and bring back memories of August 2015 when Chinese policy easing caused the dollar to spike and short-circuited SPX EPS growth. Relatedly, there is also a risk that China moves forward more aggressively on capital account liberalization, likely leading to a renminbi devaluation at least initially. Re-reading this Bank For International Settlements paper (starting on page 35 penned by Mitsuhiro Fukao, an ex-Director of Economic Research at the Bank of Japan) and taking a cue from Japan's experience was insightful.1 But, it remains difficult to predict what China's ultimate reaction function to Trump's trade rhetoric will be (Mathieu Savary, BCA's foreign exchange strategist, will be addressing this in one of his upcoming reports). While a tactical 5-10% pullback cannot be ruled out as the seasonally weak month of September is nearing, from a cyclical perspective our strategy would be to "buy the dip" if one were to materialize. Importantly, this bulletproof equity market that refuses to go down has two stealthy allies on its side: pension plans that are forced into equities and corporate treasurers that execute buybacks. Granted, EPS have delivered and suggest that upbeat fundamentals remain the key market support pillars. As a result, the S&P 500 is on track to register a tenth consecutive positive total return year, which is unprecedented in previous expansions. The only other time that the (reconstructed) SPX rose every year for 10 years in a row was in the late 1940s, however, two recessions occurred during that equity market run (Chart 2). While we are undoubtedly in the later stages of the bull market and the business cycle, there is a big difference between "late-cycle" and "end-of-cycle". Keep in mind that the current backdrop is unusual. A large fiscal package has hit late in the game likely extending the cycle. Thus, gauging where we are in the cycle is important. Chart 3 shows a stylized liquidity cycle and our sense is that we are in the early innings of the inflation stage. The handoff from reflation to inflation has happened and during this stage excesses take root eventually morphing, more often than not, into a mania. Chart 2Impressive Streak Continues Chart 3Liquidity Cycle From a macro perspective inflation is slated to rear its ugly head. Nominal GDP is far exceeding the 10-year Treasury yield, and this yield curve type steepening is bullish for SPX top line growth (Chart 4). As a reminder, in Q2 the GDP deflator jumped to 3.35% pushing nominal GDP growth to 7.41%. Money velocity2 is also enjoying a slingshot recovery. Nominal GDP growth is outpacing M2 money supply growth by roughly 150bps. The U.S. money multiplier (M2 over the monetary base, not shown) is also at a 5-year high. This is an inflationary backdrop (bottom panel, Chart 5) and should also boost SPX revenues and thus continue to underpin the broad equity market. Similarly, the NY Fed's Underlying Inflation Gauge (UIG) is firing on all cylinders and is a harbinger of a further pickup in core inflation in the coming months. As a result, SPX sales growth remains on a solid foundation (Chart 6). Chart 4SPX Sales Rest On Solid Foundations Chart 5A Little Bit Of Inflation... Chart 6...Is A Boon For The SPX This week we are initiating a market and asset class neutral pair trade to benefit from the inflationary backdrop. Initiate A Long Oil & Gas E&P / Short Gold Miners Pair Trade One way to benefit from this onset of the inflation stage/mania phase is to go long oil & gas exploration & production/short global gold miners. On the underlying commodity front, the handoff from reflation to inflation has historically been a boon to the oil/gold ratio (OGR). Importantly, the prices paid subcomponent of the ISM manufacturing survey has gone parabolic compared with the new order sub index, roughly doubling since the 2016 nadir. This depicts an inflationary backdrop and is signaling that the OGR will play catch up in the coming months (Chart 7). Chart 7CHART 7 Reflation To Inflation Handoff Similarly, another surging inflation indicator also suggests that the OGR has ample room to run. The GDP deflator has recently eclipsed the 3% mark and since exiting deflation following the end of the recent global manufacturing recession it is up over 370bps. Chart 8 shows that if this multi-decade positive correlation were to hold then the OGR could double from current levels. Chart 8GDP Deflator On The Rise Finally, the NY Fed's UIG is also closely correlated with OGR momentum, corroborates the other firming inflation signals and hints that more gains are in store for the OGR (bottom panel, Chart 9). Global macro tailwinds are also clearly in favor of oil at the expense of gold. BCA's global industrial production gauge of 40 DM and EM countries continues to expand at a healthy clip. Oil is a global growth barometer, whereas gold represents one of the few true safe havens in times of duress. Taken together, the implication is that a catch up phase looms for the OGR (middle panel, Chart 9). The relative commodity backdrop is the most important determinant of relative share prices as it dictates the direction of relative profitability (middle panel, Chart 10). Therefore, as the OGR goes so do relative share prices. Chart 9Enticing Global Macro Backdrop Chart 10Buy Oil & Gas E&P... Beyond this enticing relative commodity complex outlook, the synchronized global capex upcycle, one of BCA's key themes for the year, is underpinning the relative share price ratio. U.S. capex in particular is outpacing GDP growth and oil & gas investment is the key driver. The V-shaped recovery in the Baker Hughes oil & gas rig count data (bottom panel, Chart 10) confirms this upbeat energy capital outlay backdrop. Moreover, capex intentions from the Dallas Fed survey point to more upside in relative share prices (bottom panel, Chart 11). Meanwhile, keep in mind that the U.S. has been at full employment for 18 months now (in other words the unemployment gap closed in February of 2017) and the economy is firing on all cylinders. Real rates have also shot the lights out recently. In fact the 5-year real Treasury yield is perched near 1%, a multi-year high. Given that gold does not yield any income, it suffers when real yields rise and vice versa (for additional details on the relationship between gold and interest rates, please refer to the early-May piece penned by our sister publication U.S. Bond Strategy titled "A Signal From Gold?").3 Similarly, relative share prices thrive when real yields advance and retreat when the TIPS yield sinks (top panel, Chart 12). Chart 11...At The Expense Of Gold Miners Chart 12Bullion TIPS Over Unsurprisingly, the Fed has been tightening monetary policy since December 2015. Nevertheless, the "Fed Spread" (2-year Treasury yield compared with the fed funds rate) is steepening and continues to point to additional gains in the share price ratio (bottom panel, Chart 12). Given that both the ECB and the BoJ have remained ultra-accommodative, a hawkish Fed has boosted the U.S. dollar. However, most commodities are priced in greenbacks, thus the currency effect is a washout and is neither closely correlated to the OGR nor to the share price ratio. Two risks to this high octane, high momentum pair trade are: an EM accident induced risk off phase and a global recession likely due to a flare up in the global trade war (policy uncertainty shown inverted, top panel, Chart 9). In either of these scenarios, investors will likely seek the refuge of bullion's perceived safety as the bond market will almost immediately start pricing in easier monetary policy with investors flocking into the ultimate safe haven asset, U.S. Treasurys. Netting it all out, an enticing macro backdrop with the onset of the inflation stage, the synchronized global capex upcycle and rising real Treasury yields all argue for preferring oil-related to gold-exposed equities. Bottom Line: Initiate a market- and currency-neutral long S&P oil & gas exploration & production/short global gold miners pair trade today. The ETF ticker symbols the S&P oil & gas exploration & production and the global gold mining index are: XOP and GDX, respectively. Anastasios Avgeriou, Vice President U.S. Equity Strategy anastasios@bcaresearch.com 1 BIS Papers No 15 "China's capital account liberalisation: international perspectives", Monetary and Economic Department, April 2003. 2 "The velocity of money is the frequency at which one unit of currency is used to purchase domestically- produced goods and services within a given time period. In other words, it is the number of times one dollar is spent to buy goods and services per unit of time. If the velocity of money is increasing, then more transactions are occurring between individuals in an economy". Source: Federal Reserve Bank of St. Louis. 3 Please see BCA U.S. Bond Strategy Weekly Report, "A Signal From Gold?" dated May 1, 2018, available at usbs.bcaresearch.com. Current Recommendations Current Trades Size And Style Views Favor value over growth Favor large over small caps

  Overweight The divergence between rising crude oil prices and the performance of exploration & production (E&P) stocks has grown remarkably wide (top panel). We continue to credit the absence of market belief in the longevity of the increase in oil prices. However, we think soaring industry capex means the view on the ground is much more positive. Planned capex has reached a level not seen since the recession, despite oil prices remaining well below the 2010-2014 highs, implying E&P companies will be a solid capex upcycle play, which remains a key BCA theme for the year (middle panel). Considering the diffusion indexes for unfilled orders and current employment in Texas, both of which set decade highs in July (bottom panel), we see little that stands in the way of the recovery. We reiterate our overweight recommendation on the S&P oil & gas E&P index and our high-conviction overweight recommendation on the broader S&P energy index. The ticker symbols for the stocks in this index are: BLBG: S5OILP - COP, EOG, APC, PXD, DVN, CXO, MRO, APA, HES, NBL, EQT, COG, XEC and NFX.    

Overweight Disbelief in the longevity of the increase in oil prices is the likely culprit weighing on exploration & production (E&P) stocks along with a bottleneck-induced steep shale oil price discount to WTI. Nevertheless, the sizable recovery in underlying commodity prices has restored some semblance of normality in the E&P space. The second panel of the chart at the side shows that shale oil production is rising at a healthy clip following a long bottoming phase on the heels of reaccelerating WTI crude oil prices. Similar to the broad energy complex that integrateds dominate, oil & gas E&P producers are a capital expenditure upcycle play, which remains a key BCA theme for the year (third panel). Rising oil prices are conducive to additional energy-related investments (bottom panel). Adding it up, there are high odds that E&P stocks will continue to outpace the broad energy complex and the SPX on the back of firming capex budgets and sustained oil inflation. Bottom Line: We lifted the S&P oil & gas E&P index to an overweight stance; please see Monday's Weekly Report for more details. The ticker symbols for the stocks in this index are: BLBG: S5OILP - COP, EOG, APC, PXD, DVN, CXO, MRO, APA, HES, NBL, EQT, COG, XEC and NFX.