We believe that two of the primary headwinds faced by midstream equities over the cyclical break in oil pricing have been meaningfully mitigated.
First, the midstream sector’s shift to self-funding should significantly lesson capital markets risks. Second, the ongoing shift in midstream producer customers to larger and/or higher quality companies lessens the threat to midstream volume consistency.
First, A Review
The cyclical break in oil prices that emerged in late 2014 both reflected and engendered significant changes in the global energy industry. Just as the incredible productivity of U.S. shale contributed to the surge in global oil inventories that sparked the late-2014 oil price collapse, the resultant low oil prices forced U.S. shale producers to rapidly improve the economics of their production.
In turn, by early 2016 some market participants began to fear that U.S. shale was so efficient that crude pricing per barrel might stay in the $30s, or lower, for the foreseeable future. Under this view, wide-spread bankruptcies were expected across the U.S. independent oil and gas sector as this new price level did not appear sufficient relative to the balance sheet leverage of many of these operators.
One result was good for energy infrastructure MLPs and companies, or midstream. Produced volumes reflected surprising stability despite the price collapse, providing steady cash flows to midstream operators, who typically employ a fee or fee-like tariff mechanism on volumes.
Source: EIA, December 2018.
The second result was bad for midstream. Investors began to fear that the impending wave of producer customer bankruptcies would ultimately decimate producer drilling plans and volumes.
As these fears metastasized, midstream equities sold off sharply. In the time since though, very few U.S. producers were forced into bankruptcy, and produced volumes continued to reflect relative stability and then growth.
However, the damage done to midstream equity values lingered and fed a destructive cycle. Investors began to worry that the poor trading of midstream equities would limit those companies’ ability to reasonably fund midstream commitments to build new infrastructure. As a result, many midstream equities sold off further, and the effect compounded.
It was an unpleasant period.
Now, A Better Outlook
As we have discussed previously, and most recently in the blog Private Equity Believes in Midstream Infrastructure, many midstream operators no longer need to issue new equity to fund their capital investment commitments. These midstream operators now retain enough cash flow, after paying distributions or dividends, to fund their equity capital commitments. Or, as discussed in the blog referenced above, have sought or plan to seek the sale of non-core assets to supplement this funding. In fact, in 2018, midstream unaffiliated common equity issuance was only $1.6 billion versus a $36.9 billion annual pace from 2011 to 2017. We believe the benefit of the sector’s new self-funding nature remains underappreciated by many investors.
Second, we note the potential benefit of another change in the U.S. oil and gas production landscape. In recent decades, domestic production of oil and gas has mostly been dominated by independent production companies. These companies are typically smaller and less diversified and, therefore, more susceptible to commodity price swings than the larger oil and gas companies of the world (ExxonMobil (NYSE: XOM), Chevron (NYSE: CVX), BP (NYSE: BP), Shell (LSE: RDSA), etc.), referred to going forward as the “Majors.” However, these Majors have taken notice of the economics offered by U.S. shale and are becoming a force in shale oil and gas production.
Source: U.S. Capital Advisors, December 2018.
ExxonMobil and Chevron both had their annual investor meetings in early March. While each company discussed their respective free cash flow growth and buyback plans, both companies made it clear they are coming for the Permian crown. Chevron announced at their meeting that it expects to be producing 900 thousand oil-equivalent barrels per day by 2023. That is an increase of over 200% from their current production in the Permian.
Not to be outdone, XOM preempted their analyst meeting with a press release stating it would be producing 1 million oil-equivalent barrels per day by 2024. XOM believes that its investment in the Permian can generate a 10% return even at $35/barrel oil. This is quite the increase in production compared to last year’s projections which were that XOM’s Permian production would reach 600,00 oil-equivalent barrels per day by 2025.
To put this in perspective IHS, a leading consulting and information firm, announced in January that it expects the Permian to produce 9.6 million oil-equivalent barrels per day in 2023.1 This means that almost 20% of the Permian’s production in 2023 will be coming from XOM and CVX.
XOM and CVX aren’t the only Majors to make a significant commitment to the Permian. Last year BP bought U.S. shale oil and gas assets from the global mining company BHP Billiton for $10.5 billion. These assets included about 500,000 producing acres in the Eagle Ford, Haynesville, and Permian Basin. BP expects to operate 5 to 10 rigs in the Permian from 2019 through 2021. Shell currently has a small presence in the Permian, but the CEO said on the company’s February 2019 earnings call that Shell is looking at how it can use its vertical integration capabilities to improve its current position in the Permian.
The Majors are also making their presence felt in basins besides the Permian.
- CVX has ~809,000 net acres in the Marcellus/Utica basin. To put that in perspective, EQT Corp. (NYSE: EQT), the largest gas producer in the United States, has 1.4 million acres in the Utica and Marcellus.
- Shell is one of the larger producers in the Northeast Marcellus2 and is spending ~$6 billion3 on a new cracker and polyethylene plant in Pennsylvania.
- BP has guided to operating 5 to 6 rigs in the Eagle Ford and 4 to 6 rigs in the Haynesville through 2021.4
Importantly, the Majors typically set and operate under long-term plans that vary much less radically with commodity price changes than do the smaller independents. The Majors are vertically integrated through downstream activities such as refining and petrochemical production, which often mitigate the impact of commodity price fluctuations. Further, most Majors today have very low leverage enabling spending consistency regardless of commodity price realizations.
Further, even U.S. independents have worked to right size spending to the new commodity price environment and to rely less on external funding. As a result, credit metrics for U.S. independents have also materially improved in recent years; net debt to EBITDA has returned to 2014 levels despite crude pricing now trading in a lower range.
Sources: Bloomberg, Capital IQ, December 2018.
- ^IHS assumes 5.4 mpd of oil, 15 bcf/d of natural gas, and 1.7 mpd of NGLs. Oil and NGL production is converted to BOE on a 1:1 basis, natural gas production converted to BOE on a 6:1 basis. https://news.ihsmarkit.com/press-release/energy/new-ihs-markit-outlook-%E2%80%93-stunning-permian-basin-oil-production-more-double-2017.
- ^Source: RDS produced 382 MMcf/d in 12/1/17 according to East Daly.
- ^Source: https://www.phillymag.com/business/2016/06/08/shell-ethane-cracker/
- ^Source: BP 2018 Investor Day Breakout Slides.
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