With many E&Ps struggling to keep their businesses afloat, producers around the globe have forgone turning off the taps even when fields are losing them money.
Despite the drop in oil prices from late 2014, only about 0.1% of global oil production has been halted, amounting to about 100,000 barrels per day (bbl/d) of halted production, according to a Wood Mackenzie report published Feb. 5.
In June, the inventory of drilled but uncompleted wells in the Lower 48 was estimated to be as high as 4,000, the Energy Information Administration said. At the high end, that’s about 10% of the 40,000 wells drilled in 2014. The wells were located primarily in the Eagle Ford, Bakken and Permian Basin.
In part, companies are delaying wells because they can’t make money from their production. Wood Mackenzie’s analysis shows that of the world's 96.1 MMbbl/d production, 3.5% or 3.4 MMbbl/d is cash negative, meaning production costs are higher than the price the producer receives.
During a downturn, an operator’s first response could be to store production on the chance that the oil can be sold when the price recovers, said Robert Plummer, vice president of investment research at Wood Mackenzie, in the report.
“For others the decision to halt production is more complex and we expect that volumes are more likely to be impacted where mechanical or maintenance issues arise and operators can’t rationalize further investment at current prices,” Plummer said.
According to Wood Mackenzie, the areas with the largest volumes shut-in up to now have been Canada onshore and oil sands, conventional U.S. onshore projects and aging U.K. North Sea fields.
Even at the high point of 2015 before $30 became a reality, many U.S.-based E&Ps were struggling to hang on.
Among E&Ps that filed for bankruptcy in 2015:
- About 43% had been in business for more than 10 years;
- Roughly 12% had had revenues greater than $500 million; and
- Owed a cumulative $18 billion.
In its Capital Global Outlook released in January, Barclays reported that E&P budgets will be down again in 2016, with North American spending falling by 27%.
However, E&Ps only began to make significant capex cuts in second-quarter 2015. Since around mid-2014, companies have slashes capital expenditures, sold assets, issued equity and lowered shareholder distributions to raise or save $130 billion, Deloitte said. Two-thirds of savings have come from non-capex financial measures.
Capex cuts have since steepened along the spectrum of E&Ps. ExxonMobil (NYSE: XOM) outlined a 25% reduction in 2016 spending. Many companies have also announced further cuts relative to their 2014 budgets, including Hess Corp. (NYSE: HES) with a 40% cut, Anadarko Petroleum Corp. (NYSE: APC) with 50% and Continental Resources Inc. (NYSE: CLR) with 66%.
Even though these companies are planning on spending less, improved efficiency is expected to buttress U.S. crude supply, said Daniel P. Katzenberg, senior research analyst of E&P with Robert W. Baird & Co.
“While these cuts should help curtain the supply outlook, continued productivity gains in field level development, another round of operational expense ‘leaning,’ and additional downward pressure on services pricing continue to provide meaningful offsets that have helped the resilience of U.S. supply,” Katzenberg said in a Feb. 5 report.
One of the key ways companies have managed to remain viable has been by reducing production costs. About 95% of U.S. operators produce at costs below $15 per barrel of oil equivalent (boe), compared to 65% in the second quarter of 2014, Deloitte said.
According to Katzenberg, more pain is still needed to improve the supply/demand balance.
In the past year, the U.S. has significantly lowered production costs, which has resulted in only 190,000 bbl/d being cash negative at a Brent price of US$35, Stewart Williams, vice president of upstream research at Wood Mackenzie, said in the report.
“In fact, the biggest reductions have been from tight oil, the majority of which only becomes cash negative at Brent prices well below US$30 per barrel,” he added.
Additionally in the U.S., more than 1 MMbbl/d of oil production comes from what are called “stripper wells.” Many of these produce only a few barrels a day with operating costs varying between US$15-$40.
“We believe that once the cost of collecting the oil from these wells becomes marginal, producers may opt not to sell or temporarily shut-in the wells first. However, shut-ins are not sustainable and low prices eventually lead to well abandonments,” the report said.
Who Has Shut In, According To Wood Mackenzie
- Canada: “The most significant response has been in Canada, where the combination of heavy oil and long transportation distances result in large price differentials to international prices. So far we believe at least 30,000 bbl/d has been shut-in, predominately from legacy wells in Alberta and British Columbia, following a number of company announcements. No major oil sands project has been shut-in, but heavy oil production has been shut-in.”
- U.S.: “In the past year we have seen significant downward movement in the cost of production in the U.S., where margins have benefitted from a rapid reduction in costs and a closing of the WTI-Brent differential. High royalty rates magnify these effects, which combined have lowered the cash breakeven by US$10 or greater across almost all of the onshore U.S.”
“Operators have enjoyed significant margins over the past few years and will be reluctant to give up the option value of a well that is only losing a few hundred dollars per month. We expect volumes will be impacted where mechanical or maintenance issues arise that require further investment. Wide-scale abandonment of wells requires capital commitment in its own right and for that reason we expect shut-ins in the U.S. to be short-lived.”
- U.K.: “The U.K. North Sea saw six oil fields cease producing in 2015. Total production from the six fields in 2015 was just under 13,000 bbl/d, around 1% of total U.K. production last year.”
Wood Mackenzie’s latest study collates oil production data from more than 10,000 fields and calculates the cash operating costs. The method identifies the price at which the fields turn cash negative, and the volume of oil production associated with this price level.
Contact the author, Emily Moser, at firstname.lastname@example.org.