Shale oil drillers bring out the knife
Cost cutting, not production growth, is now the sector’s obsession
A new reality has taken hold in the US shale patch. Lower oil prices have forced producers to quickly pivot from the growth-at-any-cost mode that turned the US into the world’s largest oil producer to a relentless focus on efficiency and cost cutting.
They have been more successful than most expected. Costs have fallen sharply over the past six months – by as much as 30% in some areas. At the same time, producers are squeezing about a third more oil out of every well they drill compared to the start of the year as they mobilise the best crews and equipment to drill on the best acreage.
While shale has proven resilient through the downturn, the sharp fall in spending and the number of rigs at work is finally catching up with shale producers. The Energy Information Administration (EIA) expects shale output to fall for the third month in a row in June – by around 90,000 b/d –as declines from existing wells outpace the rate at which new wells are being drilled.
In the Bakken, where oil production has risen from around 200,000 b/d in 2009 to more than 1.2mn b/d by early 2015, output is expected to have falled by 29,000 b/d in June. The fall in the rig count in the Bakken has been precipitous – there were 77 active rigs in the shale play in June, down from 185 a year earlier. That has made it impossible for drillers to keep up with the decline from existing wells, which is running at around 80,000 b/d. The North Dakota Department of Mineral Resources says around 110 to 120 new well completions would be needed to sustain output.
Production is also dropping in the prolific Eagle Ford shale in Texas, another stalwart of the tight oil boom. The EIA says it expects output to fall from a high of 1.71mn b/d in March to 1.59mn b/d by July, even as producers get twice as much oil from new wells – 741 b/d – than they did in December 2012.
The Permian Basin is the only major shale play that has managed to sustain production growth through the downturn, though just barely. Output is plateauing at around 2mn b/d, according to the EIA, up from around 1.4mn at the start of 2014. The Permian, a longtime powerhouse conventional basin but a relative unconventional newcomer, is still seeing rapidly improving well performance as producers improve their understanding of the shale, adapting tight oil techniques to the play. Unlike other shale plays that have struggled with logistical bottlenecks, the Permian also benefits from ample existing infrastructure.
More oil for less
Although production has started declining, shale executives have turned notably more positive in recent weeks as oil prices have stabilised and recovered to around $60/b. The new economics of US shale – lower costs and higher productivity – have convinced many that a return to growth is possible at a much lower oil price.
EOG says it could return to double-digit growth with WTI at $65/b. The company says that cost-cutting and increased productivity in the Eagle Ford means its returns at the wellhead – excluding transport – are better at today’s oil price than they were in 2012 at $95/b. It hopes to cut its Bakken completed well costs by 20% from $9.3mn in 2014 to $7.4mn this year. It takes the company just 10 days to drill a Bakken well now, compared with 23 in 2012.
Whiting Petroleum is another major shale player eyeing a return to growth. The company says it could start to add rigs again if WTI rose to $70/b, though as costs continue to fall that threshold could come down further. Whiting says it can now get a 54% rate of return on a strong Bakken well at $60/b.
Pioneer Natural Resource’s chief executive Scott Sheffield says his company now plans to start adding rigs at a rate of two a month in the Permian Basin from July as long as oil prices stay stable. “We felt margins had improved enough,” he said recently. Analysts at Raymond James reckon cash margins for Permian drillers will average $15 per barrel of oil equivalent (boe) at $60/b as costs continue to fall, enough to sustain activity. “Permian activity has bottomed and should improve in the second half of 2015. The bottom line is that we are still in the very early stages of horizontal oil development in a very prolific oil reservoir,” the analysts said.
The economics of the other two major shale plays – the Bakken and Eagle Ford – have also improved thanks to lower costs and better well completions. Both the Bakken and Eagle Ford are near the bottom of the cost curve among shale plays. Deutsche Bank reckons that the breakeven for an average well in each falls from around $55/b (at late-2014 costs) to around $50/b with a 10% fall in costs and around $40/b with a 25% decline in costs. Another $10-15/b, though, could be needed to cover corporate costs.
All this suggests a quick return to growth for shale is possible even with a relatively small rise in the oil price. It took the industry about six months to scale back in response to lower prices and it’s reasonable to assume a similar time frame for ramping up output. So if the industry starts to add rigs again later this year, output growth should resume in the latter half of 2016.
The risk is that – fearful of missing out on the oil price recovery – producers flood the market with new shale barrels, prompting another sharp fall in the oil price. Things could get volatile.