Informe especial
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.
