Investors have grown wary of U.S. shale after years of disappointing returns, and they have pressed shale companies to rein in reckless drilling practices. But with money still pouring into the shale sector, there’s no sign yet that Wall Street is withholding investment in the industry.
Shale executives have gone to great lengths in recent months to reassure investors that they are pursuing a more conservative strategy, foregoing aggressive drilling plans to prioritize profits. Despite what could be a seismic shift in the shale sector, Big Finance continues to shower shale companies with money.
According to a series of interviews conducted by Reuters with industry experts, there is no shortage of capital interested in shale drilling. “If you’ve got the rocks, you can get the money,” Buddy Clark, co-chairman of the energy practice group at law firm Haynes Boone, told Reuters.
Private equity is taking on a larger role in the shale industry as traditional banks pare back lending. Since 2014, investors have funneled $200 billion to private equity firms that have a focus on energy, according to the WSJ, citing data from Preqin.
Armed with cash and hungry for yield, private equity firms have injected $20.26 billion into energy deals so far this year, more than 36 percent higher than in 2016, Reuters says. The latest example of that trend came from Warburg Pincus LLC, which just a few days ago announced a $780 million investment into ATX Energy Partners. ATX will use the money to purchase assets from larger oil producers, but notably, ATX is a new venture without any drilling assets to date.
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The commitment from Warburg Pincus is, in part, a bet on ATX’s chief executive, with whom Warburg has worked on other shale ventures. But that the private equity firm is willing to put up more than three quarters of a billion dollars despite ATX not having oil producing assets is a sign of how bullish private equity firms are on the shale industry generally. ATX doesn’t even have a clear picture of how it will use the cash.
Reuters reports that new financial instruments are popping up, servicing the needs of shale drillers and filling the void that traditional lending has left. “The upstream industry has been really creative in how it pursues financing of late,” Charlie Leykum, founder of private equity firm CSL Capital Management LLC, told Reuters. These instruments include Drillcos, which give investors more control over cash flow until certain returns are met.
Meanwhile, the bond market is also not turning its back on the shale industry, despite the growing warnings from major investors that a strategy shift is needed. Energy companies have raised an estimated $60 billion in new debt this year, up 28 percent from the total in 2016, according to the FT, citing data from Dealogic. It’s the largest total since the market downturn began more than three years ago.
Analysts attribute the renewed interest in shale from the bond market to the rebound in oil prices. “It is the resurgence in the commodity, that’s the bottom line,” Tom Stolberg, a portfolio manager with Loomis Sayles, told the FT. “The commodity trending better has brought out a slew of new issuance. The fringier [companies], lower rated, more stressed balance sheets, it benefits them a whole lot more because it gets them over the hump of not making it at $50 or $45 oil.”
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Whiting Petroleum just secured $750 million in new debt and Continental Resources raised more than $1 billion this month from a fresh round of bond issuance.
Aiding the shale industry in their quest for capital is the fact that they have locked in a large portion of their 2018 production with hedges, which gives peace of mind to lenders. More than one million barrels per day of shale output is secured by hedges in the first half of 2018, according to Bloomberg Gadfly.
What does all of this mean? It means that capital probably won’t be the limiting factor for the growth of U.S. shale, at least for the next year or so. Wall Street is still enamored with the shale story, despite years of questionable returns.
By Nick Cunningham of Oilprice.com
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“Buyers are wary of grades such as Eagle Ford and can’t take much more of it.”
Previous article on the topic:
US tight oil: Too light, too sweet
International buyers’ appetite may start to wane in 2018
Refiners like known crude grades and predictable crude qualities. While integrated majors familiar with US crudes are now moving light tight oil within their international systems, it has proved difficult to market many grades of US oils to refiners less familiar with them.
In fact, according to EIA figures the run up in US crude exports this year has been concentrated in sales to two countries: Canada, which has long familiarity with its neighbour's crude, and China. Chinese imports by crude stream aren't public, so it is difficult to detect whether it is buying established US crude grades, or very high API gravity shale oil. But recent reports indicate that India has acquired a mixed cargo of 1m barrels each of WTI and Southern Green Canyon, which are respectively 40°API and 28°API. The weighted average API gravity of Japan's crude imports from the US is only about 36.9°, according to Petroleum Association of Japan data.
If exports are concentrated in medium US crude grades rather than very light tight oil grades, where is the tight oil going? There is a technical limit to the US refining system's ability to absorb these crudes, so considerable volumes may ending up in American storage farms. Analysts say there's a net export of medium—and heavier—API gravity crude from US inventory and that the gravity of US inventories is becoming progressively lighter. Meanwhile, US crude oil storage usage is running at around 70% utilisation, leaving limited space for further tank fill. Notably, Cushing storage volumes have risen while refinery storage volumes have fallen, which points to slack market interest in light sweet shale oils.
All this suggests that there is currently a limit to the market's ability to absorb further volumes of very light US tight oil—a trend that won't disappear in 2018. In the medium term, refining systems, not least in the US, will undoubtedly adapt to welcome these crudes in large volumes. But for the time being the market is glutted. Expect a narrowing of the sweet-sour crude differential and a persistent WTI discount to Brent.