Will rising oil prices lead to a renewed shale boom?

Will shale’s return on investment be higher and faster with a rising oil price or does it lose its competitive advantage above $60? Jonathan Green, upstream oil and gas business analyst, provides some provocative food for thought on shale as we approach the end of 2017.

Hydrocarbons are effectively an infinite resource. It just depends on how much you are prepared to spend to exploit them. Many shale players are stating that they can profitably produce at US$40/bbl and that they are well positioned to ramp up production massively as the price of WTI moves beyond US$60/bbl. However, shale’s resilience has to a large extent relied on the willingness of the capital markets to fund persisting cash-flow deficits in E&P companies.

The Funding Challenge

Since Q2 2016, WTI has been well above $40/barrel. But in this period, most of the integrated oil companies have only just returned a profit and that thanks to their downstream business. Indeed, ConocoPhillips showed an average quarterly loss across the corporation of $900 million over the 18-month period, with no indication of the performance of its shale assets. Chevron, on the other hand, confirmed a loss of US$26 million on its US upstream activities, with its overall global upstream segment showing a profit due to its international operations.

Since the shale oil boom began almost a decade ago, far more money has been invested than has been returned as investors rewarded companies for production and reserve gains rather than profitability and return on investment. Rystad suggests that in only one quarter since 2014 did the US shale industry report even a meagre positive cash flow and that was in Q3 2016 when capex investment was at its lowest since Q1 2014. Bloomberg estimates that the cashflow deficit from the main US shale basins has exceeded US$15 billion every year since 2014. This implies eye-watering levels of corporate debt have accumulated in the shale basins and very high levels of shareholder expectation. The industry is now confronting the massive maturing debt burdens by renegotiating and pushing repayment into an optimistic future requiring substantially higher oil prices.

Recent trends in the market suggest the finance model is changing. Funding of shale oil through private and public equity and public debt jumped to $100 billion in 2016, of which US$30 billion was raised via public equity. Bloomberg forecast a drop by about one-third in public equity financing in 2017. Declarations made by shale players when announcing Q3 2107 results recognise this shift in financing behaviour. The mantra of growth in reserves and production at all costs has been replaced by a focus on cash flow, profits, debt reduction and, significantly, on return to shareholders.

The Productivity Challenge

The continued gains in shale profitability appear to be waning and production costs may be rising. The EIA’s drilling productivity report shows that for much of 2017 most of the main oil shale fields have seen a stagnation or even decline in productivity per rig, whilst service costs have been rising. Concerns have also been voiced that advanced technology is improving the initial production rates but reducing the ultimate recoverable reserves.

The expectation that the current oil price increase is likely to trigger another shale boom may therefore be misguided. There are three factors in particular to consider: the resulting upward pressure on services costs; and the likelihood that rigs brought back into service will be less efficient; and that operations will expand outside of the basin sweet spots currently being exploited. On this last point, a recent MIT study also challenges the EIA’s shale oil production growth estimates, suggesting compounding annual forecasting errors of 10% due to the move out of the basin sweet spots.

There is a further aggravation for the shale oil business in the Permian Basin: operators are finding it difficult to get to market the significant volumes of natural gas associated with shale oil production. Pipelines from the Permian Basin are full: as a result, the Wall Street Journal suggests, wells may be shut in and drilling plans postponed pending the construction of new pipelines to the Gulf of Mexico and planned gas-fired power plants in Mexico.

Competition from traditional reserves

Continued investment in shale oil since 2014 has largely been driven by the perceived rapid return on investment. Underpinning this perception is the quick turnaround from drilling to production during a period of low long-term oil prices. Now that fears of US$30/bbl have calmed and prices are expected to settle at double that figure (and possibly rise higher in the near-term), focus is returning to traditional reserves.

McKinsey believes that over 75% of future new production will come from the world’s deep-water basins. Rystad reports that nearly all current unsanctioned deep-water development projects have break-even prices below $60/bbl and most are below US$55/bbl. It is looking increasingly plausible that finance will be redeployed from shale wells that deplete by more than 65% within two years towards the deep water where up-front capital-intensive projects have subsequent long-term low opex/bbl and sustained high output. The current low cost of offshore services and equipment will accelerate this move. This trend would appear to be confirmed by Exxon’s recent record bids for blocks in Brazil’s deep water and Shell’s report in late November that its pre-FID average forward looking breakeven price is below $30 per barrel for deep-water projects and that the cost of a deep water project has come down on average by around 45% since 2014

In summary, shale oil producers face three challenges. First, meeting their debt obligations; second, a decline in productivity per rig; third, competition from a revitalised deep-water sector that can now operate at much lower oil prices. A higher oil price may ease the pressure on their debts, but it will also increase the competition for both capital and markets from traditional reserves. So, it may avoid a bust, but it is unlikely to lead to a boom.

 Jonathan Green is an international upstream oil and gas business analyst and presenter. He is a senior associate of IMAP Systems, an Australian portfolio management consultancy, and of Warren Business Consulting, a UK executive training company. He previously headed the IHS A&D and Strategy Practices in London and was a member of their corporate thought leadership team. Since 2009, he was manager of business and competitive intelligence for Addax Petroleum, a Sinopec company based in Geneva, Switzerland.


jgreen@warrenbusinessconsulting.com   Tel: +41 79 755 17 60

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