From Canada to Australia, energy groups’ cuts are laid bare
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Almost 30 years ago, Saudi Arabia triggered a slide in oil prices by making an aggressive bid for market share, and western energy companies were forced to make sweeping cuts in capital spending in response.
Now the industry is being obliged to take similar action after Opec, the oil producers’ cartel led by Saudi Arabia, flexed its muscles in November by deciding to keep output steady in the face of rising supply from higher-cost rivals. The move prompted a collapse in the value of crude.
Analysis of planned oil and gas projects by Rystad Energy, the Norwegian energy consultancy, shows that more than $100bn of capital spending – a huge sum – has been slowed, delayed or ditched by energy companies desperate to cut costs in the face of dwindling returns. This is affecting 26 major projects worldwide.
Morgan Stanley analysts, who have scrutinised 121 energy companies’ capital spending guidance for 2015, say these groups are planning to invest $129bn, or 25 per cent less than they did last year.
This retrenchment extends far beyond the falling rig counts in America’s shale-producing heartlands. In Canada, tens of billions of dollars of spending on extracting oil from bitumen-rich tar sands has been shelved since the start of the year – and thousands of jobs lost – as producers have delayed the highest cost projects first. But spending has also been pushed back in Australia, Norway, Iraq, Angola, Ecuador, China and the Falklands.
The effects of these cuts will be far-reaching. By postponing final decisions on whether to proceed with certain projects, oil producers hope to shore up their cash flow, protect dividends and benefit from lower development costs later.
The act of waiting itself will send suppliers’ charges – rates levied by oilfield services groups for labour and equipment such as drilling rigs – lower, pulling down the “break even” price for new projects. So, not only should giants such as Royal Dutch Shell, Chevron and BP protect their dividends, they should also reap substantial gains from cost deflation and, in time, a recovery in oil prices.
“If we are correct in our assessment, the industry is set up for a confluence of trends that is rare by historical standards: rising prices and falling costs,” says Martijn Rats, analyst at Morgan Stanley.
This prognosis owes much to the breathtaking speed at which companies have acted since crude tumbled from last summer’s $115 peak.
Discerning this is an inexact science – some operators trumpet their cost-cutting credentials, while others bury the information in annual reports.
Rystad has sought to identify projects slowed by the falling oil price from those delayed by bureaucratic holdups or political wrangling.
While Shell is continuing to spend through the downturn, it ditched plans in February to build an oil sands mine in northern Alberta – the 200,000 barrels a day Pierre River project. It has delayed the start-up of another oil sands project, Carmon Creek, by a couple of years. And, in Australia, it has scrapped the $20bn-plus Arrow liquefied natural gas project.
BP has deferred a final investment decision on the second phase of the company’s deepwater Mad Dog development in the Gulf of Mexico, aiming to reduce its projected spending of $14bn. Statoil has put off a decision on its giant Johan Castberg field, in the Norwegian Arctic, to 2016.
In Kazakhstan, a senior executive at Chevron’s joint venture Tengizchevroil was quoted by Reuters last month as saying that it had slowed expansion plans and cut projected spending this year in response to lower oil prices. A Chevron spokeswoman referred the Financial Times to its latest annual report, which said that a final decision on expansion should be made this year.
The consequences for the market will be felt, although not immediately. Per Magnus Nysveen, head of analysis at Rystad, says: “We are seeing very steep spending cuts by everyone now, but we don’t expect visible production declines before next year.”
In fact, the nature of the spending cuts – or deferrals – means it could take several years for their effects to filter through. Canada, Australia and Norway account for nearly three quarters of the total delayed capital spending that Rystad has identified.
This is no coincidence. Oil sands, LNG projects and the Arctic require hefty, upfront capital investment and the payback from such projects comes much later. So, it makes sense to wait, renegotiate contracts with suppliers and capture the benefits of cost deflation.
As such, while many of the 26 projects identified by Rystad could still go ahead, the output will come later than expected – some 500,000 b/d of anticipated production will be available in 2022, rather than 2020.
Factor in reduced spending on US shale, and total upstream investment in countries outside Opec is now expected to fall by about 22 per cent this year compared to 2014. From its 2014 peak to 2016, Rystad estimates non-Opec spending will slide by $200bn.
All this is good news for Saudi Arabia, whose production costs are much lower than for non-Opec countries. Indeed, with global demand still healthy, Rystad estimates the producers’ cartel could gain 2m b/d of market share in five years as a result of the spending cuts elsewhere. Riyadh could win its battle for dominance in the end.
Additional reporting by Guy Chazan