Brutal could describe the earnings results for the exploration sector in the final three months of 2015, but could sharp reductions in capital expenditures (capex) have set in motion a much tighter production supply, with improved pricing sooner than later? It’s not likely before the end of this year because a confluence of factors, analysts said.
And it will take higher oil and natural gas prices, along with an even further reduction in finding and development (F&D) costs, before U.S. exploration and production (E&P) companies get rolling again.
U.S. onshore production is in decline and the resulting output response by mid-year is “already baked in,” as development plans and rigs are curtailed, said Sanford Bernstein analyst Bob Brackett. By extension, “any expectations for growth in supply in 2016 must come from an increase in capital spend that occurs before mid-year. Our view is that is unlikely…
“We often encounter the theory that $50 oil will balance the market because costs for E&Ps have fallen dramatically,” said the Bernstein senior analyst.
“The forward curve currently projects that $50 will be where prices settle by 2021.” Bernstein’s team is more optimistic and expects crude oil prices to return to $70/bbl in the next year.
“One of the pillars of our belief in a higher market price than $50 is what the sector looks like at $50 oil.” Last year was an “ideal case in point,” Brackett said, as West Texas Intermediate (WTI) crude averaged $49/bbl, and Henry Hub natural gas averaged $2.61/Mcf.
“At $50 oil, the sector produced negative net income,” he said. “Both commodities are trading well below these 2015 average prices for prompt-month delivery — April 2016 WTI is at $38 and Henry Hub is at $1.75. On the forward curve, oil doesn’t hit $50 until 2020 and Henry Hub is around $2.75 through 2019.
“And yet even with 2015’s vaunted cost reductions, $50 oil and $2.60 gas do not allow the sector to create economic value. This is a clear indication that $50 is not a sustainable price.”
Capex last year was about 64% above cash flow, but even with the outspending at $50 oil, U.S. production still flipped from growth to decline over the year.
“During the last round of earnings we found that E&Ps were guiding to a 50% cut in capex in 2016,” Brackett said. “Given we are already in decline in the U.S., production should plummet in 2016 as a result.”
However, if prices correct sooner rather than later, “frictional forces” are at play, preventing E&P companies from returning to outspending their cash flow.
“First, hedging limits cash flow and thus capex in a rising price environment — because it limits cash flow downside in a falling price environment,” Brackett said. “Second, deleveraging limits capex as excess cash flow is used to improve the balance sheet,” through buying back discounted debt or paying down revolvers.
“Fear” also should be a limiting factor in capex as management teams — and their boards — insist on capital programs that heed the downturn’s implications.
In her review of the upstream, BTU Analytics analyst Erika Coombs, said nearly every management team for E&Ps said during the 4Q2015 reports that the price downturn will be lower for longer.
“However, as producers lay out budgets and focus capital on their best value acreage, there are many indicators that these changes may not be enough to allow them to live within cash flow in 2016,” Coombs said.
BTU estimated that U.S. capex reductions this year should range from 20% to 60%. For some E&Ps, such as Anadarko Petroleum Corp., capex specific to the onshore is even cut more sharply, down an estimated 70% from 2015 (see Shale Daily, March 1).
“Although cuts have been significant, there will be more to come,” Coombs said. Producers will be attempting to keep their balance sheets “neutral,” using a $50-60 WTI price. But year to date, WTI has been no where close to that average.
In any case, she thinks the large inventory of drilled but uncompleted (DUC) wells in the onshore will limit any pricing upside.
Some E&Ps have reduced their dividends to cope, including No. 1 independent ConocoPhillips and Anadarko (see Shale Daily, Feb. 9; Feb. 4). Chesapeake Energy Corp. and Penn Virginia Corp., among others, have suspended their payouts altogether (see Shale Daily, Jan. 28; Sept. 17, 2015).
“There may be many more to follow, as this strategy frees significant capital for investment and liquidity in navigating the low price environment,” Coombs said. “While this comes at shareholders’ expense, it may be a necessary action for more producers in order to stay liquid.”
BTU is forecasting WTI prices to average $39/bbl this year, which suggests that “without funding outside capital, or taking on more debt, producers who are budgeting based on higher crude prices, depending on hedges, will have to make additional cuts to live within cash flow,” she said.
Improved efficiencies in the onshore are helping with reducing costs too — but some analysts question whether it’s enough.
Using its proprietary NASWellCube model, Rystad Energy said wellhead breakevens have fallen over the past three years in all of the main unconventional basins in North America. On average, the wellhead breakevens fell by more than 40% between 2013 and 2015. The Permian Basin has exhibited the most significant cost savings for all onshore plays.
However, BMO Capital Markets Corp. analyst Phillip Jungwirth said more efficiency gains are going to be needed to cope with the depressed pricing.
Shorter drilling cycle times, reduced service costs, improved well productivity and longer laterals have kept producers in the game, “but the group still looks structurally challenged at strip.”
A few operators have professed to have breakeven well economics at $30/bbl, including ExxonMobil Corp., which recently reported that some of its Bakken Shale and Permian wells are breakeven at that price(see Shale Daily, March 3). That’s a rare company that can manage that, according to BMO.
For most E&Ps, a $60/bbl price is required to hold production flat within cash flow, according to BMO’s analysis. In aggregate, and taking the median F&D metric using seven metrics, onshore F&D costs fell by an estimated 11% year/year in 2015 following a 4% decline in 2014.
The largest declines were in the half-cycle F&D metrics, said Jungwirth. These include proved developed producing costs, which fell 27% year/year, while future proved undeveloped, or PUD, costs declined 25%. PUD conversion costs were down 14%. All-in F&D was negatively affected by price revisions.
“Granted, half-cycle metrics are the most relevant, but 25% reductions are only consistent with service cost reductions over the past 18 months,” Jungwirth said. That means if the oilfield service providers hadn’t made better pricing deals with their customers, F&D wouldn’t be down as much as they appeared to decline.
“We also estimated the typical shale well requires a 1.62 times recycle ratio to achieve a 10% after-tax internal rate of return,” Jungwirth said. Based on the aggregate of the seven F&D calculations, BMO’s E&P coverage universe “won’t exceed this on a corporate basis until 2018” using a $61/bbl WTI and $3.00/Mcf Henry Hub on the half-cycle F&D metrics.
To reduce corporate (with general and administrative) breakevens to $50/bbl WTI, BMO analysts estimated that F&D costs would need to fall to $10/boe from $12-13/boe for 2015 PUD conversion/future F&D; to $17/boe for drillbit PDP F&D; or to $15.50/boe for depreciation, depletion and amortization to acquire, explore and develop new reserves.
While Marcellus Shale producers may have a “superior recycle ratio” under the F&D scenarios, none of the E&Ps in the region screened well relative to the current oil and natural gas price strip, Jungwirth said.
E&Ps may be counting on $50/WTI to get their onshore operations back in gear, and that possibility exists, Brackett said.
Minus an end to demand growth or an “incredibly aggressive” strategy by the Organization of the Petroleum Exporting Countries (OPEC) to reduce output, “the price of oil has to rise to balance the market in the medium run, and the medium run might be sooner than people think,” Brackett said.
The Energy Information Administration is seeing evidence of continued sluggish natural gas and oil production for the nation’s seven largest unconventional plays, according to its latest Drilling Productivity Report issued last Monday (see Shale Daily, March 7).
However, productivity from new wells is expected to remain almost flat next month, said the federal agency. On a rig-weighted average basis, April’s new-well gas production per rig in the seven plays is expected to be a combined 2.69 MMcf/d, compared to 2.70 MMcf/d in March, while new-well oil production per rig is forecast at 528 b/d, compared to 516 b/d.
Once the onshore E&Ps get back to business, look out, said Brackett. Bernstein hasn’t yet estimated how long the core of the cores within the various unconventional basins will hold up before real decline begins. Once that happens, operators are expected to move their business to the so-called Tier 1 formations to the Tier 2 and Tier 3 areas — and production from those areas could surprise to the upside as well.
“In general though, 10,000 horizontal wells a year covering 60 acres is like 0.6 million acres ”consumed,’” Brackett said. DeWitt County, TX, in the Eagle Ford Shale has about 0.6 million acres, he said.
“So the pace at which we have been consuming acres is like a ”shale county or two’ a year and eight counties have accounted for half the shale oil revolution.”
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