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Crunch time
US shale drillers keep their powder dry for now, but it remains unclear how they’ll respond in 2022 as the declines in drilled but uncompleted wells (DUCs) and inventories come to bear, says Johannes Van Der Tuin
INCREASING GLOBAL oil demand has started to revive US hydrocarbon production, but any recovery is nascent at best and – as with other areas of the global economy – the pandemic accelerated trends within the US shale patch that had already been at work prior to 2020. As the latest round of US earnings calls highlighted, management teams and investors remain focussed squarely on free cash flow. ‘Capital stewardship’ had already become the watchwords for US exploration and production (E&P) executives before COVID-19 and remains so today. Additionally, environmental, social and governance (ESG) pressures continue to ramp-up from investors and are likely to stick around for the foreseeable future, particularly given the change of administrations in Washington. As a result, after the last year and a half of market tumult, management teams are understandably gun shy about forward-looking capital expenditures and aggressively raising production, instead preferring to live off their dwindling drilled but uncomplicated wells (DUC) inventories, pay down debt, and focussing on returning cash to shareholders. Given the current rate of completions, however, the test will come as we move into 2022, when corporates are likely to have exhausted their inventory of DUCs. Management teams will then need to decide whether to increase capex proactively or wait to see if lower production results in higher oil prices and more organic cashflow – some of which could then be reinvested into the basins.
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A NASCENT RECOVERY
US Energy Information Agency (EIA) data show that crude and condensate
production have yet to really turn the corner in every major US shale oil basin except for the Permian. Liquid hydrocarbon supply remains more or less depressed in the Niobrara and Williston, but West Texas oil output is already back up to around 4.8 million bpd according to the latest US government projections. Even in the Midland region though, rig activity remains sedate and growth is being driven more by completions, with the number of active fracking crews above 120 for the first time since the start of the pandemic. Perhaps unsurprisingly given their track record of overproduction, private companies in the Permian are the only E&P segment that has been raising its Permian rig count substantially, with now over 200 active rigs in basin. The side effect has been lower aggregate average well productivity, given that privates tend to have weaker type curves, bringing down overall basin performance – a trend that is likely to continue over the short-term. Management teams for the publicly traded international oil companies
(IOCs) and independent E&Ps are still a bit more cautious on the need to raise their rig counts and capex, relative to their private peers. Travis Stice, the CEO of Permian producer Diamondback Energy, articulated this sentiment during the company’s Q2 earnings call, saying: ‘As we look at supply and demand fundamentals, oil supply is still purposefully being withheld from the market and we continue to believe that there’s not a call on US shale production growth.’
A POTENTIALLY TIGHT 2022
With a conservative spending mindset firmly in the driver’s seat at many publicly traded E&P companies, instead of drilling new wells, executives prefer to rely on their existing, but rapidly dwindling, surplus Permian DUC inventories – loosely defined as the number of DUCs above and beyond the average working level required for smooth ongoing operations. That strategy can work through the balance of this year, but at the current rate of completions, it threatens inventory exhaustion in the first half of 2022 unless new capital is deployed or well productivity improves dramatically. Spending additional capital, however, will likely require higher oil prices. CEOs have made commitments to increase investor returns and will be loath to proactively raise capex in lieu of higher organic cash flows, which would risk the wrath of shareholders. Some companies have even gone so far as making explicit reinvestment commitments, such as the Permian behemoth Pioneer Natural Resources, which promises to only spend 50% - 60% of cash flow on new production in 2022 as of early August strip prices. Overall, publicly traded US independent E&P capex guidance through the end of the year hovers at around US$35 billion (€29.6 billion), only slightly above 2020 levels, with little likelihood of any increases unless market circumstances change materially over the next few months. Of course, if the recovery in global oil demand stalls due to a COVID variant, such as Delta, or OPEC increases production above current commitments, oil prices may stay relatively muted, reducing the need for additional US shale capex this year and next – per the fears of E&P management teams, many of which feel they were burned by OPEC in 2020. Alternatively, though, the bull case of rising oil prices and an increasing ‘call on US shale’, could spur companies to raise spending reactively, resulting in higher rig counts and ultimately rising US production, but this is only likely to occur after DUC inventories become depleted – likely in 2022. In the meantime, publicly traded oil companies would prefer to nurse their balance sheets, paying down debt and returning cash to shareholders via dividends, special dividends and share buybacks. And with billions of dollars in callable debt likely to be paid down through the end of the year in order to reduce leverage, executives have more than enough uses for their cash, other than ploughing it back into production.
SHIFTING CORPORATE INCENTIVES
Undergirding the change in tune from executive teams, and lowering the likelihood of a short-term return to exuberant US shale liquids growth given current market circumstances, has been a structural shift of incentives over the last couple of years. Even prior to the collapse in early 2020, the investor base in oil and gas had shrunk. Years of capital destruction and poor returns in the shale space had alienated many generalist asset managers, as reflected in the roughly 70% decline in total net-returns of the S&P Oil & Gas Exploration & Production Select Industry Index since mid-2014. As a direct result, investors continue to agitate for consolidation within the US upstream – a process that was accelerated last year due to financial pressure but is likely unfinished. Most notably, this included mergers between high quality names (read: Parsley and Pioneer) as well as the acquisition of corporates with excellent acreage positions (such as Concho Resources). This has reduced the number of operators and, potentially, animal spirits. Shareholders hope it will also result in better capital management, higher returns and – implicitly – higher oil prices. ESG mandates have also added to investor pressures. Large asset managers such as BlackRock are increasingly laying down the gauntlet on behalf of their customers, pushing corporates to reduce scope 1 and 2 emissions. A process that will require greater internal compliance and controls within the E&P business, this generally favours companies with scale and tends to encourage consolidation. Firms that cannot make the adjustment will, and are, facing a higher cost of capital, which again threatens to erode their competitiveness. Simultaneously, the change in US administration last January will likely result in a further shift in the regulatory environment – particularly focused on methane emissions and greenhouse gas (GHG) disclosures – increasing investor scrutiny and compliance costs further. A heavier regulatory burden for the E&P sector would potentially be more easily borne by large companies, erecting higher barriers to capital for subscale drillers overtime.
IMPLICATIONS FOR FLOWS AND STORAGE
The bottom line is that the structure of the US shale market is changing, potentially raising the weighted average of breakeven prices, and reducing the risk of overproduction that we saw in the earlier stages of the development of US shale. As a result, aggregate US onshore lower-48 oil production is likely to incrementally increase by only around 400 – 500 kb/d in the second half of 2021. The biggest driver will be the Permian, which should constitute roughly 70% of all production growth and might in fact reach new highs by the end of Q4 2021 or in Q1 2022. Growth will be hard to sustain at the current rate through 2022, though, if rig activity doesn’t pick-up towards the end of this year. Otherwise, the exhaustion of the DUC inventory will weigh down US shale production next year, causing it to underperform a possible further 800,000–1 million bpd year over year increase by December 2022. Regardless, the dramatic pipeline buildout prior to 2020 means that the current Permian takeaway capacity of roughly 8 million bpd should be more than ample over the next year, even if inbasin production reaches well above 5 million bpd in 2022. The futures curve is also likely to stay backwardated into next summer, with local demand, refinery runs and exports continuing to outstrip production growth, obviating most over-supply risks for US storage capacity for the next 12 months.
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This article was written by Johannes Van Der Tuin, an independent consultant and freelance energy writer based in New York City, US.
