Upstream oil and gas producers in the US are trapped in a dilemma they might have previously thought would be desirable: abundant production at low cost.
For decades, higher production from oil companies was what the market wanted and rewarded. If producers had to borrow and overspend to do it, the attitude was “c’est la vie”. But in the last couple of years, it has become clear that what is desired, often voiced and certainly rewarded, is slower production growth and reined-in spending.
Capital discipline has been the watchword among upstream producers and Wall Street alike for at least 18 months. That could help brake production growth this year, along with small decreases in well productivity and efforts to return more capital to shareholders.
Increases in US unconventional production from shale, particularly shale oil, are the product of years of innovation. In particular, during the industry downturn between 2015-2017, E&P companies hacked away at their costs and forced down their breakeven prices. The industry has more than doubled production since 2011, and the fastest growth has been in the last couple of years.
According to US Energy Information Administration data, domestic oil production breached the 12 million b/d mark in March, and nearly 2 million b/d of that was added last year alone. S&P Global Platts Analytics forecasts year-end production at 12.78 million b/d and end-2020 production at 13.48 million b/d.
Long-time energy economist Phil Verleger, in a report in January cited EIA projections of 800,000 b/d additional production from December 2018 to December 2019, adding that the International Energy Agency figures on 780,000 b/d of added production in the same time span and OPEC, 1.7 million b/d.
“The level of activity last year will be difficult to maintain without oversupplying the market,” Credit Suisse analyst Jim Wicklund observed in a recent investor note.
But operators can’t help it: the efficiencies achieved in recent years have made it easier to produce more oil from every well. They’re not going away anytime soon, so something else will have to slow down their progress.
When crude prices dropped from over $100/b in mid-2014 to about half that level at the end of the year, operators learned the meaning of efficiency the hard way. Suddenly each barrel they produced was bringing in 50% of the money it had done just months earlier, so they had to make each drilling and production dollar they spent work harder.
From necessity to invention
Through diligent operational streamlining, they squeezed every last drop of value out of each stage of the E&P chain.
They eventually brought their breakeven price – the cost of producing a barrel of oil to get a 10% return – down to levels that would have seemed miraculously low a few years before. These days, oil breakevens for the best operators in the most prolific plays are not too much more than the cost of an extra-large pizza with the works, plus a magnum of Coca-Cola and tip for delivery.
The continuous technological wizardry of well drilling and completion improvements allowed the industry to produce far more oil and gas in far less time at ever-lower costs – and at extremely economic return rates which often yielded 100% or more. But it also brought the supply genie ahead of the demand curve faster than expected.
Producers exploiting US plays from Texas to North Dakota, from Pennsylvania to Wyoming, have pulled gargantuan volumes of shale oil and gas out of the earth in the last 15 years. Gas was the initial commodity to be produced unconventionally – meaning horizontally – starting in the early 2000s. So successful were producers at coaxing large gas volumes out of shale wells that eventually the domestic market was facing a glut that pushed gas prices to low levels within a few years. Prices have continued to stagnate.
Pre-shale, a decent initial flow rate for a conventional gas well was about 1,000 Mcf/d. Now many shale wells yield initial rates of 20,000 Mcf/d and double that rate is not unheard of. Those numbers have kept gas storage bins full and gas exports to markets around the world humming.
Increases in crude well outputs are also robust even if not as dramatic. Conventional oil wells of the past might have yielded 500 b/d, while early shale oil wells saw typical initial outputs of 1,000 b/d. That has frequently doubled and sometimes tripled, while in rare cases 5,000 b/d or 6,000 b/d have been eked out of wells. Even so, total oil production growth over the last eight years as the shale oil revolution blossomed has been phenomenal. In January 2011, US oil production was just below 5.5 million b/d. By January 2015, just as the recent industry downturn had begun, domestic oil production stood at 9.3 million b/d. That increase was largely achieved at prices of $90/b-$100/b.
Production peaked in April of that year at 9.6 million b/d, but fell back because operators cut back activity and capex during the downturn. The 50 largest E&P companies slashed their 2015 capital budgets collectively more than 40% year on year, and another 25% or so for 2016, according to research from EY (formerly Ernst & Young). By that time, oil prices had fallen to levels around $30/b just as operators were releasing their annual budgets at the start of that year.
But then, oil prices stabilized around $50/b for several months, and heading into 2017, E&P operators were more sanguine. The constancy of prices lent confidence to the sector and the operational improvements forced by low crude prices had put them in good stead to produce oil for less than before. Capital budgets rose that year about 32% to a total $114.5 billion – still far below the $198 billion spent in 2014. But spending didn’t need to return to former levels, as E&P operators found they could still grow production at $50/b.
Even at capex levels 65% to 70% lower, during the downturn, US production from January 2015 to January 2017 dropped only about 6%, to 8.8 million b/d. And given the efficiency improvements achieved during that time, it didn’t take long for US production to climb back up.
From November 2016 to November 2017, at an average price of $50/b, US oil production grew by 1.2 million to 10 million b/d. And from November 2017 to November 2018, at an average price of $64.83/b, production grew just under 1.8 million b/d, hitting 11.9 million b/d.
In the low oil-price environment of 2015-17, operators drastically reduced the number of days needed to drill wells. They became more precise in placing drill bits within an oil formation to land in a reservoir’s sweetest spot. And they continually streamlined and perfected their recipes for completing wells at increasingly lower costs.
Continually evolving well completion designs have allowed operators to bring down the cost of a well by about a third or more. At the start of 2014, the Permian Midland –the eastern and part of that giant West Texas basin– had an average oil breakeven cost of about $44/b; currently it is around $30/b, according to S&P Global Platts Analytics data.
Prices point to slowing growth
What to do about the US supply glut, then? It is likely that a combination of technical production limits, investor demands and the simple factor of oil price will start to redress the imbalance this year. Lower crude prices should put a brake on production growth this year by some order of magnitude. E&P company capital budgets for 2019 are coming in flat or lower on average, and some operators that late last year guided this year’s spending at higher levels, have revised them down.
Also, operators are being encouraged by market forces to spend money in other ways than growing production. E&P companies that return more cash to shareholders are being rewarded, since in some cases dividends were reduced or eliminated during the downturn. Companies that are more disciplined and keep spending at the level of cash flows – which was uncommon in years past when operators typically outspent their income – have also been rewarded with higher share price. Access to credit is also a likely consideration in times of volatile oil prices, as a more restrained approach to spending may help when companies are looking to the capital markets for funding.
In any case, premium acreage – the so-called “Tier 1” areas – is starting to decline for many companies, although some claim that continued efficiencies and cost control can turn many drilling locales to premium status that were not originally deemed that way.
Well productivity also appears to be reaching a plateau, many operators say. In a recent report on basin trends in Q4, Evercore ISI analyst Stephen Richardson said more corporate level efficiencies are expected in 2019, although finding the optimum spacing between wells remains an ongoing challenge.
Richardson’s examination “reveals the pace of incremental [well] performance gains have tapered across basins,” he said, adding: “The market needs producers to exhibit restraint in 2019 plans.”
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