The war on North American oil

Startling production growth in the US and Canada has upended the world’s oil market. Can these new producers keep going despite lower prices?

Last November, around a horseshoe table in Vienna’s Helferstorferstrasse, the oil ministers of Opec, a cartel of crude-producing countries that control about four-fifths of the world’s reserves and sell about a third of its oil, faced a fateful decision.

The mood was grim. As the men took their seats, oil prices were in freefall, threatening the finances of Opec’s members, most of which export little of value except hydrocarbons. Ordinarily, their next move would be straightforward: cut back some production to raise the global oil price.

Instead, Ali Naimi – as Saudi Arabia’s oil minister, the most powerful man at the table – persuaded his fellow ministers to hold firm and do nothing. The price would fall – fine. But this would kill off supply from areas where it is costlier to produce oil. Opec could no longer surrender chunks of the market to these upstarts, who had thrived during a period of high oil prices. Regaining that customer base – not keeping prices high – was now Saudi Arabia’s priority.

Opec fights back

From Canada’s oil sands to the giant oil-bearing shale formations of Texas and North Dakota, the news from Vienna sent a shiver down the spine of North America’s new oil producers. Market commentators said the continent’s startling production growth would now end, as sinking oil prices made the plays unprofitable. The unconventional oil revolution had taken Opec by surprise and now the group was going to stop it.

Opec wasn’t alone in being caught out by unconventional oil. Just 10 years ago, rising oil demand and the apparently inexorable decline of the US’ oilfields meant the country was importing ever greater volumes of energy. Worse still, American consumers were competing for barrels against buyers in China’s booming economy. International prices were rising steeply, feeding through to the gas pump. When Americans filled up their cars, more than half of the gasoline came from foreign crude.



High oil prices were painful; in advanced economies, almost everything we do – buy, eat, make or drive – depends on oil. So the 240% rise in the cost of the world’s most important fuel between 2000 and 2008 drained money from countries that import more oil than they produce (and swelled the coffers

In advanced economies, almost everything we
do – buy, eat, make or drive – depends on oil

of exporters like Saudi Arabia). As the world’s biggest consumer of oil, the US was shipping hundreds of billions of dollars out of its economy. People had less money to spend on everything else: in that way, high oil prices deepened the recession of 2008.

But as things got rough for Americans above ground, beneath it high oil prices were spurring a startling revival in oil production. Oil-bearing rock formations once thought too tricky and costly to drill suddenly attracted interest from small firms willing – as long as prices stayed high – to take a risk. Companies like Continental Resources hoovered up acreage in North Dakota, home to much of the Bakken formation. Landsmen traversed Texas in search of choice new chunks of land where geologists thought more of this tight oil could be found.

Supply soars, prices plummet

The shale-gas experience gave these risk-takers some confidence. By combining an older technology (hydraulic fracturing) with a newer one (horizontal drilling), a host of small companies had upended the outlook for US natural gas supply. As the techniques were rolled out across shale plays like Texas’s Barnett, the frackers found more gas than they could use. Supply soared. Gas prices plummeted. Plans to import natural gas from as far away as Qatar were scrapped as it became clear the US would have more than enough to meet its own needs.

Slumping natural gas prices in turn gave drillers more reason to target more profitable light, tight oil (so called because of the crude’s high quality and its position in trapped rocks) found in similar formations. The number of rigs in operation skyrocketed – and output soon followed.

At the beginning of 2005, North Dakota was producing about 90,000 barrels a day from just over 3,000 wells and its forgotten, windswept towns were slowly decaying. By 2015, the state had almost 12,000 wells pumping more than 1.2 million barrels a day; its economy was growing faster than any other state in the US; it had one of the country’s lowest unemployment rates, and was humming with oilfield activity, as services firms laid down the infrastructure to support it all. In Texas, output tripled in the six years to the end of 2014, reaching nearly 3.5 million barrels a day.

When oil executives talk about all this as a revolution they aren’t exaggerating (see Figure 1 and Figure 2). Expectations of declining output in the US have been replaced with forecasts that the country will become the world’s biggest oil producer this year. In the same period, new trends in energy efficiency and urbanisation – pushed along by the same high oil prices and supported by government legislation – have curbed American oil use. Its oil consumption was 20.8 million barrels a day in 2005 but last year was just 18.5 million barrels a day. The total number of miles Americans drive has flatlined. The result has been a sharp drop in the amount of oil the US imports from abroad: 6.2 million barrels a day in 2013, barely half the number for 2005 – a saving equivalent to more than Japan, the world’s third-largest oil market, consumes.



Feeling the pain

The international ramifications of this explosion of American supply are profound – and that’s where Opec comes in. Some of its members have been especially hard hit. Angola and Nigeria used to ship about 1.6 million barrels a day of oil to the east coast of the US. But their oil is similar to the light, tight oil being produced from the US’ shale fields, so the market for African crude has dried up. Even Canadian refiners that used to take African oil can now buy it from the Bakken instead. (US laws allow for crude-oil exports to countries with which it has a free-trade agreement, which include Canada.) The Atlantic Basin, once a thorough

The Atlantic Basin is now awash with cheap
Nigerian and Angolan cargoes seeking a home fare

for tankers shipping West African crude to North America, is now awash with cheap Nigerian and Angolan cargoes seeking a home. China is one reliable destination, but even that country is not increasing oil consumption at the rate it was.

Saudi Arabia’s oil is heavier and doesn’t directly compete with the US’ light oil producers. But its sales to the US – alongside China, one of the two pillars of Saudi export policy – have also fallen, partly because of growth in the other great North American winner from the high oil prices of recent years: Canada. Recovering its share of the US market is now among Riyadh’s priorities; that’s a measure of the stunning success of North America’s oil industry, which hasn’t just revived the American economy but is shaking up older trading patterns across the world too.




Unstoppable momentum

Figuring out how to convert a clump of this energy-rich organic substance into oil that can be refined into something useful, like gasoline – and doing it at scale and economically – has been the work of decades. But it only really took off when rising oil prices made the projects profitable. In 2005, Canada was squeezing less than 1 million barrels a day from the oil sands. Now output is about 2.3 million, with forecasts of almost 5 million by 2030. The rise of Alberta’s unconventional oil sector – the province is home to large tight-oil reserves, too – is what prompted Canada’s prime minister Stephen Harper to proclaim his country as an “emerging energy superpower”.

Exports from the oil sands all flow to the US, Canada’s sole oil market. That’s become a problem for Canada, because, as its production rises, the pipelines that ship the oil – and the refineries kitted out to handle its heavy grade, mainly in the US Midwest – are maxing out. For that reason, barrels of oil sands-grade oil trade at a big discount to other grades of crude, hurting oil sands producers’ margins and Canada’s oil income.

The solution is to find new markets: the US Gulf coast has lots of big refineries with spare capacity that could handle Canadian oil; and China, India and even European refiners used to taking similarly heavy oil from producers like Iran would also like to import oil from Alberta. Several projects to ship oil to Canada’s west and east coast, or to expand the existing network, are under way. The most ambitious, the Keystone XL project to pipe oil to Texas, has become a political hot potato in the US. In the meantime, North America’s railway operators have stepped in, rapidly building new cars to ship this oil.

The path to self-sufficiency

Whether it has arrived by pipeline or train, Canada’s oil has been just as significant for the US. The 3 million barrels a day America receives from Canada now account for nearly half of its oil imports; these days, it gets just 3.2 million barrels a day from other countries. If the conservation trend continues and North American supply growth persists, the continent could soon be self-sufficient.

That’s why Opec wants oil prices to fall. Left unchecked, the burst of new supply from North America threatens to close off the world’s biggest market to Opec’s exporters – and then some. Moves are afoot in US Congress to allow the US to export crude oil beyond Canada, which will eventually start selling its own oil to Asia as well. That should mark another step change for North America’s producers, allowing their unconventional oil to reach more dynamic markets, spurring even more growth in output.


A tale of two unconventional business models

Will cheaper oil prices kill off North American unconventional oil supply growth? It’s unlikely to be that simple.

Tight oil and the oil sands operate according to fundamentally different business models, each with different vulnerabilities to falling oil prices – but with some built-in resilience, too.

Tight oil

Start with tight oil. The production profile of a typical tight oil well, in the Bakken for example, sees output soar in the first couple of years and then plummet. So if a company wants to keep output steady – and the cash flowing in – it needs to keep drilling, repeating the process across the oilfield. By industry standards, a single tight oil well comes cheap: it might cost $8 million or so, compared with, say, $100 million for a deep-water well. When oil prices are strong, the driller has every incentive quickly to drill that next well. Tight oil wells might only produce a hundred barrels a day at peak output, too. So thousands of new wells each year are needed to reach the kind of output numbers seen in Texas and North Dakota.


Not all tight oil wells, or plays, are equal though. Some wells need an oil price of over $80 a barrel to be drilled profitably, while others might need just $30 a barrel. By March 2015, the $80-a-barrel-wells were already being mothballed. The number of rigs in operation had fallen steeply in just a few months, reflecting the plummeting oil price. But, in turn, this had another effect. To keep earning money, the drillers returned to areas they knew would yield most oil for the least outlay – a phenomenon that in the first half of 2015 explains why this so-called high-cost oil output kept rising even while some rigs were shut down and oil prices kept falling. Meanwhile, as rigs went off line, the pool of available oilfield workers swelled and the rates charged by services firms came down.

In short, lower oil prices have shut in some of the most marginally economic wells, but over time lower prices also have the effect of deflating industry costs. It’s now much cheaper to rent a rig or hire some workers, because fewer companies are competing to do so. The cost of developing temporarily abandoned wells will get lower over time too, which would send the companies straight back in. A rise in oil prices could have the same effect. And because of the replication involved in drilling tight-oil wells, the business model looks a lot more like manufacturing, and less like a big infrastructure project typical elsewhere in the oil business. This means it is easy to turn up or down the output dial.



The oil sands

The opposite is true of the oil sands. There, a big project might cost $15 billion. There’s no sudden spurt of production. A project takes years to come on stream, gradually ramping up output in phases.

Now that the oil industry knows the oil is there, drillers will keep returning to the source rocks whenever the market rewards them

Most of the money – especially for in situ projects – is spent in the first few years. So while the break-even oil price for a new project might be as high as $100 a barrel, rendering new developments uneconomic now, once a project is producing it will make money at a fraction of that oil price. Unlike tight oil, once an oil-sands project is under development, companies don’t tend to turn down the dial, either. So this year another 270,000 barrels a day is scheduled to come on line in the oil sands – whatever the oil price.

In the oil sands too, the lower oil price will curb some of the runaway inflation in project costs that has left some developments needing such a high crude price to turn a profit. The same forces are at work. Some projects have been scrapped or postponed because of falling margins, and others will be developed more slowly, so the draw on the labour pool will be less severe and other input costs will come down too. And companies are exploring new ways to cut costs further, for example by using more modularisation: commissioning parts to be built in foreign shipyards, rather than relying on local builders to do the work. Shell, a big oil sands developer, has watched how Amazon warehouses its goods and wants to track every tool and bit of kit it uses electronically, to cut time lost by workers finding the equipment they need.

That’s not to say that tight-oil and oil-sands output growth won’t slow down in a period of low oil prices. They will. The Canadian Association of Petroleum Producers says developers in the oil sands will spend $25 billion this year, down from $33 billion in 2014. That will inevitably bring revisions to long-term output forecasts. The Energy Information Administration (EIA) expects production growth from tight oil, which was 1.2 million barrels a day last year, to slow to about 550,000 this year and to about 80,000 in 2016.

It’s unlikely Opec will win this battle, though. Either it will have to keep prices low to stop another surge in North American oil supply – and damage their own economies in the process – or it will see a recovery in oil prices followed by renewed strong investment in unconventional oil. In fact, although the EIA says production growth in the US will ease off in the next two years, it won’t actually stop growing. Plummeting shale-gas prices in the US have not curbed production. Now that the oil industry knows the oil is there – and can be fracked, mined, or melted from the ground – drillers will keep returning to the source rocks whenever the market rewards them.


Political pipeline: Keystone XL

RESIDENTS of Hardisty (population 639) probably never expected to find themselves at the centre of a continent-wide political storm. But there’s a reason oil-storage tanks have appeared on the hills near the central Albertan hamlet. It is the starting point for Keystone XL (KXL), a pipeline TransCanada wants to build so bitumen from the oil sands can reach the US Gulf coast, home to several refineries able to handle such heavy crude.

Hardisty is 451 kilometres south of the oil sands. Steele City, Nebraska, the end point of KXL, is another 1,100 kilometres away from Texas’s big refineries. So the proposed pipeline is really just another piece to be added to North America’s extensive patchwork of energy infrastructure. But executives in the oil sands believe KXL is critical to the future of developments there. As production rises, existing pipeline capacity will max out. Most existing pipelines also ship Alberta’s heavy oil to refineries in the US Midwest, and they too are nearing the limit of how much bitumen they can take. Without new export capacity, the price of Canada’s crude will fall, deterring investment in future developments in the oil sands and denting the country’s hopes of becoming an “energy superpower”. Ottawa has made KXL, which would ship 830,000 barrels a day, a strategic priority.

But getting it built hasn’t been a straightforward as the Canadian oil industry assumed it would be when the idea was first proposed, in 2008. The US has not approved the project, which has become one of the most contentious issues in American politics. The pipeline’s opponents argue that development of Alberta’s massive oil reserves shouldn’t continue – for environmental reasons. Its supporters say the pipeline will create jobs and secure energy supplies for the US.

The truth is that KXL is neither as critical to the oil sands as its supporters maintain nor as potentially damaging as its opponents argue. The market has figured out how to get the oil to refineries anyway. Rail-shipping capacity has grown swiftly to carry bitumen across North America. Existing pipelines have been reconfigured to handle more oil. And Canada has other pipeline options: two projects would ship oil from Alberta to the west coast, opening up Asia as a destination for the crude; another proposal would send it to the east coast, for onward export to Europe, Asia or even down to the US Gulf. (Not all of these projects will happen.)

Securing approval for KXL would be a victory for the oil sands – but partly a symbolic one, because development will continue with or without it. And while blocking it would be a moral boost for environmentalists, it would hardly shut down Canada’s heavy-oil industry.