[NGW Magazine] Editorial: Price shocks
The steepening gradient of oil prices is lifting oil companies out of their latest trough: having spent the last few years cutting costs and investments and planning for $50/barrel under their “lower for longer” scenario, many of the majors are breaking even at just $30/b as construction and contractors costs plummet.
So far, companies have continued their cost discipline, focusing on the profitability of each barrel rather than growing output for its own sake. So after big profits in the first quarter, more can be expected in the second.
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The market has been comfortably above $70/b for some months, as the US president, Donald Trump, was expected to make good on his campaign promise long before he did so. When he did walk away from the Iran agreement – leaving the other signatories in the lurch – prices rose a little further to just below $80/b, on the assumption that Iran’s oil exports will fall somewhat.
Some analysts now talk of Brent crude trading at $100/b next year, with uncertainties on the downside coming from the extension of the Opec-Russia production cuts beyond March 2019; and on the upside, the effect of US sanctions on Iranian crude and what happens to failing Venezuelan output.
So the International Energy Agency can take some comfort from its forecasts of doom: unless producers now decide that growth for its own sake is the way forward at a time of high prices, a squeeze on supply could force prices up once more within a few years, as it has warned. Declining output and rising demand already combine to create the need for another 4mn barrels/day each year, it says.
A lack of transport capacity in the US means that shale producers cannot simply ramp up output: instead the US benchmark WTI will trade at a larger discount.
The focus on profitability also suggest that the wave of acquisitions is likely to continue: not only are buyers and sellers more closely aligned than for some time on where the oil price is, but the question of materiality looms large for the majors, where management time for maturing plays is scarce and capital is needed more nowadays for better dividends or debt repayment.
Assuming that the global crude supply and demand picture remains as is, or worsens, the news for gas is as ever good and bad, depending on where in the world you are.
With North American crude and condensate producers anxious to capitalise on high prices, gas will have a negative economic value if it obstructs output. So it will become even cheaper in some parts, moving into negative territory again.
This makes it more attractive as an alternative vehicle fuel: Total’s deal to buy into Clean Energy is intended to exploit this arbitrage, for the heavy trucking industry that now uses other liquid fuels. Similarly, LNG bunkering in the US will benefit, the feedstock becoming cheaper while the price of the competing fuel drifts northwards.
Depressed local gas prices are also more attractive for liquefaction plant operators on either of Canada’s coasts. In the US it has been the terminal operators that are holding open seasons to finance pipelines to collect gas from the giant shale basins for liquefaction for their customers. In Canada, these plants do not exist yet, so it is more theoretical; but the possibility is there, given low to negative gas prices in the Alberta region and plenty of gas in the Montney but with a long way to go to reach either coast.
Higher gas prices also make it more attractive for resource holders seeking to build their economies. On the one hand, it can displace imports of diesel and improve balances of payments. On the other, export projects that looked difficult before, can now look attractive for financiers, also improving the resource holder’s prospects of big revenues. Without the impetus, the gas could stay in the ground.
Consuming countries by contrast will have to grit their teeth and abide by their plans to cut coal come what may; or plead circumstances beyond their control as LNG rises in price in a short or overpriced market and revert to their old practices.
Pleading partnership status and the special long-term relationship that binds buyer and seller together in a joyless marriage for 20 years will no longer cut any ice on either side – which was even then a doubtful proposition. LNG marketers with access to equity production will be able to undercut those relying on imports to meet customers’ needs. This will help the Prelude LNG project earn back faster as commissioning draws near with, so far, no sign of an oil price – or gas demand – collapse.
In contrast, the low unit cost Fortuna FLNG venture continues to struggle to pin down financing, with operator Ophir Energy now warned by the host government to take a FID by end-2018, or else. Even lower risk US export ventures have had similar travails with project financing of late, all of which could constrict the pipeline of future LNG supply in 2022 and beyond.
Small wonder that China, South Korea and Japan have at least started talks on co-operating in LNG purchasing, taking the Jera model, which merely united two utilities from one country, to a much higher level; and, if followed through, having serious implications for many terminal-specific long-term contracts. Commercial lawyers will be watching with interest how this plays out.