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Shale operators struggle to balance books

With low oil prices, companies are seeking financing to help stay afloat

These are tough times for all but the biggest US unconventional energy producers. For small firms, suddenly deprived of income following the fall in oil prices, expansion plans are evaporating and financing to tide them over the slump has been hard to find, forcing some to seek buyers.

For an illustration of the rapid pace of change, which has rocked the industry’s finances, look no further than the current plight of Whiting Petroleum. A major producer in the Bakken, Whiting was seeking a buyer in mid-March, having only just completed a $3.8 billion deal to buy rival producer Kodiak Oil & Gas.

When the Kodiak acquisition was agreed, the $2bn it added to Whiting’s debt looked chunky, but investors clearly regarded it as potentially sustainable. Now the company’s estimated $11bn of total debt is a millstone round its neck. Whiting’s share price has fallen by almost two-thirds since last September, as income has declined. Revenues fell by 3% in the fourth quarter 2014, compared to a year earlier, despite a 30% rise in production. The firm made a net loss of $357m, hit by a $587m charge against oil and gas assets that it had not been able to develop due to the oil price slide.

The Denver-based company is not alone. Penn Virginia is reportedly in talks with Bank of America over the sale of its business – apparently on the advice of George Soros, whose investment fund holds around 8% of the company – following the announcement of big losses. Other shale-focused players are surviving, but profits and income are down across the sector, as stocks of unsold oil at key hubs rise.

US oil production has generally continued to rise year-on-year, on the back of the shale industry’s expansion last year, though rig data shows the scale of its recent retrenchment. By early March, the number of rigs operating in the US had fallen to 922, its lowest level since April 2011 and 43% lower than the record high of 1,609 hit as recently as October last year.

Shutdown

Besides showing the sector is under pressure, the speed of this contraction does show one advantage that shale drillers have over those in some other parts of the oil and gas sector. If financing and revenues dry up, it is relatively simple to shut up shop quickly on less profitable acreage.

Companies are focusing on their most productive plays instead and relying on greater efficiency and improved technology to boost output there. However, for those that took on large debts to acquire acreage and rivals, reduced income means there is little cash left over for new investments after debts have been serviced. 

The positive side of this is that, if market conditions improve, the industry is capable of expanding quickly again, given the speed with which new wells can be drilled and production can be ramped up. And the same will be true for lending, as financial institutions working with shale drillers largely base their lending decisions on future returns from acreage, so if oil and gas prices go up, so will the lending.

With little support from the equities investors and banks, who are withholding their cash until they see signs of an oil price bounce, some US shale firms may be looking to the giants of the industry to bail them out by taking acreage from them, or indeed buying companies outright.

The heady days of 2014, when the US accounted for almost half of global upstream oil and gas transactions by value, may seem a world away, but while overall deal values may drop, analysts say there is still scope for acquisitions, if bargain hunters decide to move in. Remarks made recently by ExxonMobil chief executive Rex Tillerson suggest prospects look rather different to the leader of a supermajor with large US unconventionals operations, than they do for a shale-focused small or mid-sized player with sizeable debts. Those firms can’t call on a large cash buffer to offset any short-term loss of planned income – or indeed ExxonMobil’s AAA credit rating, which makes it unique among the majors.

He told investors at the firm’s annual strategy meeting in New York in early March that ExxonMobil’s US shale operations would remain a core part of its plans in the short term, as a way of garnering revenues to fund mega-projects elsewhere in the world. “It might surprise some people how attractive some of these things are in this environment,” he said of US shale operations.

ExxonMobil intends to double the volume of shale oil it produces over the next three years, adding 150,000 barrels a day (b/d) by 2017. Tillerson claimed this would be possible, despite the difficult climate, because the company had been cautious in expanding its shale business since it acquired shale specialist XTO in 2010, preferring to learn more about the business and how to keep costs under control rather than rushing headlong into expansion.

Tillerson’s bullish tone has set tongues wagging over the possibility that ExxonMobil might hope to snap up unconventionals acreage on the cheap from rivals in areas where the company already has a toehold and expertise, such as the Permian, Woodford and Bakken. A slew of names, from Apache and Anadarko to Hess and Occidental have been cited as possible targets – as well as Whiting Petroleum – though there is little to back up the speculation at this stage. Whiting has reportedly contacted a number of potential buyers, including Statoil. Other big players say falling costs are helping their cause, but Tillerson’s swagger is largely missing from their prognoses on the sector.

Canada’s oil sands producers are operating in the same tough global market conditions, but are subject to a number of factors specific to their industry. Unlike shale oil and gas drilling, oil sands projects require massive upfront investment, even if they are relatively cheap to produce from once built.

So, while can it make sense for developers to complete projects that are almost finished, or continue production from existing operations, financing projects that have yet to get off the drawing board makes little sense.

Wood Mackenzie estimates that, on average, an Alberta in situ oil sands project already on stream would make a return on future operations at an oil price above $41 a barrel, while an on stream oil sands mining operations would break even at around $47/b. So it makes sense for the financial backers of both types of project to provide support to claw back some of their initial investment at current oil prices.

But if that initial investment has yet to be made, the picture looks very different. Wood Mackenzie estimates that the breakeven point for the full cycle of both types of project could easily exceed $100/b. Few developers and financial institutions will be prepared to gamble on a rise in the oil price back to that level any time soon, even if oil-sands development is a long-term endeavour.

Predictably, the result has been the shelving or delay of a number of big projects led by Statoil, Total and others and a big cut in capital expenditure across the sector. Cash flows from the oil sands are set to fall by $23bn in total over 2015 and 2016, according to Wood Mackenzie.

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