US oil rig counts rose for the7th straight week (up 7 to 609) to the highest level since October 2015.
With production surging back above 9mm b/d - the highest in a year - the trend in the rig count implies considerably more production to come...
And it's all in the Permian...
And with rig counts rising (in the Permian), production shows no signs of slowing, as OilPrice.com's Nick Cunningham notes, ExxonMobil’s new CEO Darren Woods announced a dramatic shift towards shale drilling this week, a new strategy that will prioritize drilling thousands of smaller wells while reducing spending on the massive projects that the oil major has long been accustomed to pursuing.
Mr. Woods gave a presentation to investors on March 1, selling his vision after recently taking over from Rex Tillerson, who left to become U.S. Secretary of State. Exxon will now ramp up spending on shale drilling, after watching dozens of smaller companies profit from the surge in production in Texas, North Dakota and elsewhere over the past decade.
Exxon will dedicate a quarter of its 2017 spending budget on shale, putting $5.5 billion into the effort. “More than one quarter of the planned spending this year will be made in high-value, short-cycle opportunities, including in the Permian and Bakken basins,” Exxon wrote in a March 1 statement. The oil major says that it has 5,500 wells in its queue for drilling in the Permian and the Bakken shales, each with a return of 10 percent or more at $40 per barrel.
Exxon was able to build up this inventory of shale wells with the $6.6 billion it spent in January to double its Permian acreage.
The shift towards shale should pay off over time, with a portfolio of thousands of tiny shale wells making up a growing share of the oil major’s production portfolio. By 2025, Exxon says that its production from the Permian and the Bakken could amount to 750,000 barrels per day, or about a fifth of its total output.
Credit Suisse is optimistic about Exxon’s fortunes, arguing that free cash flow should improve. “[I]f [ExxonMobil] can hold onto the cost savings from 2016, deliver Permian growth and maintain capex control in the legacy assets, then the unlevered fcf yield could rise toward 6.5 percent in the $60′s Brent,” Credit Suisse analyst Edward Westlake wrote ahead of the latest presentation.
Still, other oil companies offer more attractive prospects to investors than Exxon these days. Reuters notes that only five of the 25 Wall Street analysts that follow Exxon recommend a “buy” rating, while 17 of them have awarded the “buy” rating to Chevron. "Darren Woods did an effective job in laying out the story, but he was hamstrung by his predecessor's mistakes and the market's increasingly skeptical sentiment on the stock," said Pavel Molchanov, a Raymond James analyst.
To be sure, the last few years have not been kind to any energy company, but Exxon has had a rough go by any standard. The breakdown in relations between Russia and the West over Crimea in 2014 led to Russian sanctions, forcing Exxon to pull out of its Russian ventures. As a result, Exxon watched more than $1 billion it spent on drilling in Russia go down the drain, not to mention the untold billions that could have come from producing in the Russian Arctic.
Exxon also saw its total debt quadruple since the end of 2012, rising to well over $40 billion by the end of last year. Rising debt, and a steadfast refusal to ever touch its dividend led S&P to downgrade Exxon’s credit rating last year. Exxon held the AAA credit rating since 1949. Microsoft and Johnson & Johnson are the only other companies to still hold onto that top rating.
The oil major also failed to fully replace the oil that it produced over the past two years. The reserve-replacement ratio is a key metric for Wall Street analysts trying to gauge the future prospects of oil companies. If the reserve-replacement ratio falls under 100 perce nt, it means that the volume of oil under a company’s control shrank, which would dampen future profitability. Exxon reported a reserve-replacement ratio of just 65 percent in 2016 and 67 percent in 2015. Before 2015, Exxon had gone more than two decades with a greater than 100 percent ratio.
The struggle to find and book new reserves can be partly attributed to lower oil prices, which make high-cost reserves unprofitable. Exxon recently removed 3.3 billion barrels of Canadian oil sands from its books because the oil is not profitable to produce at today’s prices, for example. But it also highlights the growing difficulty that the oil majors are having at making major new discoveries. Low oil prices are forcing cutbacks in exploration budgets, which is making new discoveries more difficult. In the last two years, the global oil industry logged the lowest volume of new discoveries in seven decades. On top of that, it is also the case that there are simply fewer and fewer major oil fields left to discover.
That brings us back to shale. Exxon’s new play on shale has multiple benefits. Shale drilling is relatively low-risk, requiring low upfront costs while providing quick returns. Even through production starts to fizzle after only a few years, the company can make a return and recycle cash. In today’s low price environment, companies no longer want to tie up cash in long-term projects. Moreover, with megaprojects now viewed as a much greater risk than they were a decade ago, the oil majors and their shareholders want much more exposure to short-cycle shale drilling.
After decades of priding itself on being a pioneer of complex engineering and producing where others could not, Exxon will now be going where everyone else is going: into the shale patch.