US shale oil production has surged this year, underlining the short-cycle nature of the resource, but what goes up can come down. Shale oil production is much more responsive to price than the majority of conventional drilling and there are early indicators that recent output gains are already topping out.
Such has been the jump in production that the US Energy Information Administration (EIA) now predicts total US liquids supply this year of 17.83 million b/d, more than 1 million b/d higher than it forecast for 2018 a year ago, largely as a result of increased shale oil drilling.
The jump in US output, higher production from Saudi Arabia and Russia, Washington’s granting of sanctions waivers to key importers of Iranian crude and an increasingly gloomy economic outlook, have all served to take the heat out of the oil market.
The result has been the liquidation of long positions by hedge funds and traders, a drop in oil prices, and a softening of the market’s backwardated structure.
However, while US oil production may now be quicker to take advantage of high returns, that same short-cycle responsiveness also works in the opposite direction.
Coming in from the cold
Prior to the late-2000s, the oil majors at least saw the future as being offshore in ever deeper water and harsher environments. This would require big capital, long-lead times and expertise only they possessed.
The prospect of the marginal barrel taking around…
US shale oil production has surged this year, underlining the short-cycle nature of the resource, but what goes up can come down. Shale oil production is much more responsive to price than the majority of conventional drilling and there are early indicators that recent output gains are already topping out.
Such has been the jump in production that the US Energy Information Administration (EIA) now predicts total US liquids supply this year of 17.83 million b/d, more than 1 million b/d higher than it forecast for 2018 a year ago, largely as a result of increased shale oil drilling.
The jump in US output, higher production from Saudi Arabia and Russia, Washington’s granting of sanctions waivers to key importers of Iranian crude and an increasingly gloomy economic outlook, have all served to take the heat out of the oil market.
The result has been the liquidation of long positions by hedge funds and traders, a drop in oil prices, and a softening of the market’s backwardated structure.
However, while US oil production may now be quicker to take advantage of high returns, that same short-cycle responsiveness also works in the opposite direction.
Coming in from the cold
Prior to the late-2000s, the oil majors at least saw the future as being offshore in ever deeper water and harsher environments. This would require big capital, long-lead times and expertise only they possessed.
The prospect of the marginal barrel taking around five years to come into production meant a reinforcement of the long-term cyclical nature of the oil market.
Given the potential for both demand and supply-side shocks, the only stabilising factor was the holding of spare capacity, a role taken on in theory by OPEC, but in practice by Saudi Arabia, and to a lesser extent commercial and strategic reserves, fostered by the International Energy Agency and supported by the governments of countries dependent on oil imports.
Independent US drillers, however, had other ideas. Shale, or Light Tight Oil (LTO) to give it its broader title, fundamentally altered this dynamic.
LTO meant new wells could be brought into production in weeks rather than years. Non-OPEC production capacity could even be stored in the form of uncompleted wells (DUCs) to be brought on-stream when prices or company requirements warranted. The marginal barrel had come onshore, and taken up residence in the shale plays of the US.
Short versus long-cycle dynamics
This meant the oil market would be governed by a new set of supply-side responses to price. Compare, for example, LTO with US offshore production.
When the oil price headed unrelentingly south from July 2014, it took only nine months before US LTO output started to contract, shrinking by about 800,000 bpd over the ensuing 18 months. The Gulf of Mexico by contrast saw a succession of major projects -- planned and costed in higher-priced times – coming on-stream, keeping production on a rising trend throughout the low oil price period.
WTI hit a nadir of close to $30/b in February 2016 before entering a new up cycle. The LTO response was again quick, taking just nine months for output to start rising in earnest, this time from a much lower cost base as a result not just of productivity gains, but the sharp fall in input costs brought about by the decline in oil prices and contraction in demand for oil services.
Legacy decline
But as prices soften, LTO’s unique short-term cyclical dynamic again comes to the fore. It concertinas not just the supply response to price but the decline rate.
LTO wells are most productive in the first months of their lives and then see a sharp decline with a long tail of relatively low output. As drilling activity rises and production ramps up, the legacy decline of existing wells also increases with a lag of about six months. However, when prices start to fall and drilling flattens off, that legacy decline is still building, following production like a billowing rain cloud.
The US Energy Information Administration’s October Drilling Productivity Report (DPR) predicts for November a production gain from new LTO drilling of 626,000 bpd offset by a legacy decline of 528,000 bpd to give a net add to output of 98,000 bpd.
In an expansionary phase, the net gain will build each month. However, the DPR figures suggests that the net gain from the seven major shale plays it considers peaked in May-June above 140,000 b/d. New production remains high, but has been broadly flat since May, while the legacy of earlier drilling continues to rise. In short, US shale has entered a post-expansionary phase in which net gains decelerate.
Cost pressures
This is not the only process under way.
In the expansionary phase, input costs – chemicals, fracking sand, rigs etc – generally rise as slack is taken out of the oil services market. Average day rates for high specification land rigs in the US, according to oil and gas portal Daleel, bottomed out at $21,000 in first-quarter 2017, but had risen to $23,000 by first-quarter 2018. Not a huge jump, and rates have stayed flat since then, but an indication of growing cost pressures.
These pressures are offset by productivity gains, but after rising fairly consistently, productivity took a dive in 2017, dropping in November of that year to an average 589 b/d per rig from 632 b/d in November 2016, according to the EIA. The good news is that shale drillers have reversed this trend, and new well oil production per rig was up at 668 b/d for November 2018. However, this represents just a 5.7% gain over two years, compared with a doubling of productivity between November 2014 and November 2016.
So the squeeze is there – falling returns from lower oil prices on the one hand, and higher input costs for drilling and completions on the other. While there is no single breakeven cost for shale wells, some of the least rewarding prospects will start to drop off the bottom of the balance sheet. If the squeeze gets tighter, the stock of DUCs is likely to rise, and the legacy decline of the expansionary phase will eat further into new drilling, reducing the net gains.
The expansionary phase should take another 9 months or so to move from deceleration to actual contraction, if prices continue to weaken, so further output gains will be made as we move into 2019. This presents a massive dilemma for OPEC and Russia because any action to reign in supply and support prices will only serve to put the lead back in US producers’ drills.
