Much of the oil world is closely watching the comeback of U.S. shale, a major factor impacting prices in the coming months. OPEC has succeeded in boosting prices with its production cuts, but rising U.S. shale output is right now undermining the bullish case for oil, as evidenced by the sell-off this week.
Besides the U.S., two other non-OPEC producers, Brazil and Canada, are expected to add to significant amounts to global supply this year and next.
But the U.S. is not the only supplier adding significant production volumes in 2017, further making the bearish case for oil. Two other non-OPEC producers, Brazil and Canada, are expected to add to global supply this year and next. In its latest medium-term outlook, the IEA projects U.S. shale will add between 1.4 million barrels per day (mbd) in new supply by 2022, depending on oil prices. While those figures garner a lot of attention, overlooked is the fact that Canada and Brazil are expected to add a combined 2 mbd over the same timeframe.
Canada suffered economic setbacks in the first half of 2016 from the horrific wildfires that swept through Fort McMurray, the jumping-off point for much of Canada’s large-scale oil sands projects. But the fires were a temporary hindrance, with relatively swift restoration toward the latter half of the year.
Between 2017 and 2022, Canada’s oil sands will add 900,000 b/d, bumping the country’s total output up to 5.3 mbd.
Moving forward, Canada will make a large contribution to oil supply growth from a series of oil sands projects set to come online. Between 2017 and 2022, Canada’s oil sands will add 900,000 b/d, bumping the country’s total output up to 5.3 mbd.
A good portion of that production growth is poised to come in the next two years from projects that were already underway before the collapse of oil prices in 2014. ConocoPhillips just completed an expansion at its Surmont project, and Cenovus Energy and Canadian Natural Resources are growing output at existing facilities this year. In 2018, Suncor Energy will add 160,000 b/d from its Fort Hills project. In all, the IEA sees Canada adding 150,000 b/d this year and another 170,000 b/d in 2018.
That pace of growth slows considerable after 2020, however, dipping to 100,000 b/d of additional output per year.
Crucially, after years of impasse, the industry could finally see new pipeline capacity, opening up Alberta for more exports. The Canadian federal government gave the greenlight to Kinder Morgan’s Trans Mountain expansion in late 2016, which will add nearly 600,000 b/d of takeaway capacity, moving Alberta oil to the Pacific Coast. Enbridge also received approval for its Line 3 replacement, which runs from Alberta to Wisconsin in the U.S. and will almost double the pipeline’s capacity to 760,000 b/d. Moreover, the election of Donald Trump to the U.S. Presidency led to the revival of the Keystone XL pipeline. It is not at all clear, however, that there is an economic case for all three pipelines, but the industry is suddenly dealing with a surplus of takeaway capacity after years of bottlenecks.
The Canadian industry is suddenly dealing with a surplus of takeaway capacity after years of bottlenecks.
With new pipelines in the works and some cost reductions achieved over the past three years during market downturn–plus the recent stabilization of oil prices in the $50s per barrel–a few oil companies are breathing new life into projects canceled over the past three years. Canadian Natural Resources announced in November 2016 that it would move forward with its Kirby North oil sands facility, the first oil sands project to be revived since the collapse of prices in 2014. Cenovus Energy will spend up to $1.4 billion this year, a 24 percent increase over 2016 levels, while also giving the go-ahead for the expansion of its Christina Lake Project.
Despite the list of projects, these are small figures compared to what the industry had planned before the oil price meltdown in 2014. According to Greenpeace, an estimated 42 major oil sands projects have been delayed or canceled since 2014, accounting for billions of dollars of deferred investment.
Even if oil prices move higher than current levels, the prospects of Canada’s oil sands are uncertain. Although oil sands producers have reduced lifting costs by around 35 percent over the past few years, new greenfield projects are still some of the most expensive forms of oil production in the world, with breakeven prices–$85 to $95 per barrel for a new oil sands mine and $55 to $65 for a new steam-assisted gravity drainage (SAGD) project–far above the prevailing market price expected for the near- to medium-term. ExxonMobil and ConocoPhillips recently took more than 4 billion barrels of oil off of their books, concluding that the projects are unviable in today’s market. Royal Dutch Shell also said it would back away from Alberta’s oil sands. All three oil majors are pouring more money into comparatively low-risk shale drilling.
“How many of these long or medium cycle projects can you stack up in your portfolio? You have to be really careful.”
At the IHS CERAWeek Conference in Houston, ConocoPhillips’ CEO Ryan Lance emphasized that while oil sands projects can produce for decades, unlike shale wells, they are also more expensive and have longer payback periods. “So how many of these long or medium cycle projects can you stack up in your portfolio? You have to be really careful,” Lance said. On Thursday, RoyalDutch Shell announced it was selling most of its assets in the oil sands.
Canada’s export problem
About three-quarters of Canada’s oil is exported, mostly to the United States. The shortage of pipeline capacity has forced some crude onto rails, but the higher costs of rail transport makes Canadian oil much less competitive. Moving heavy Canadian oil to the U.S. Gulf Coast costs $15 to $20 per barrel by rail compared to the $7 to $10 per barrel by pipeline. As a result, the benchmark price for Western Canada Select (WCS) trades at a sharp discount to WTI and even Mexico’s heavy Maya blend.
Canada’s oil sands are far from dead, but the uptick in output this year and next are the fruits of investments made years ago.
Looking forward, the growth in oil demand will come from Asia, not the United States. That puts extra emphasis on Kinder Morgan’s Trans Mountain Expansion, a project that would allow for the export of an additional 590,000 b/d to Asian customers. But the pipeline will not come online until 2019 at the earliest. Even then, growth in exports could be capped at the upper limit of that pipeline capacity.
Canada’s oil sands are far from dead, but the uptick in output this year and next are the fruits of investments made years ago, not from a resurgence in interest in high-cost oil sands.
The pre-salt comeback
Brazil is the other key non-OPEC country that will add to global supplies this year and for the foreseeable future. The IEA expects Brazil to add 230,000 b/d in 2017, and 1.1 mbd of new production by 2022. The highly indebted Petrobras is giving way to a new set of private companies, which could help jumpstart growth in Brazil’s oil sector.
The highly indebted Petrobras is giving way to a new set of private companies, which could help jumpstart growth in Brazil’s oil sector.
The massive discoveries of a handful of oil fields off of Brazil’s coast a decade ago sparked a surge of interest in offshore Brazil. Petrobras discovered 5 to 8 billion barrels in a single oil field in 2007, following that up with even larger discoveries in 2010. Ambitions soared–Petrobras predicted it would double its output by 2020 to nearly 5 mbd.
But delays, cost overruns, and local content rules led to a rapid increase in debt for Brazil’s state-owned oil company. Most importantly, the enormous corruption and bribery scandal that has rocked Brazil’s political establishment for the past several years dragged Petrobras into protracted legal proceedings, credit downgrades, and even more debt. Petrobras repeatedly downgraded its production assumptions as it ran out of steam.
Up until last year, Petrobras was required by law to take a 30 percent operating stake in any pre-salt drilling projects, but because the company can no longer realize its once lofty ambitions, the law was scrapped and the pre-salt was opened up to international companies.
More investment should follow. Petrobras could still add 700,000 b/d over the next five years, taking production just shy of 3 mbd–far below than what the company once thought it would produce by then, but still a sizable contribution to global supplies. Moreover, Petrobras has shortened the time required to build an offshore oil to just 54 days, down sharply from 152 days in 2010. Pre-salt wells are also much more productive than previously thought, the IEA reports.
Like Canada, Brazil is set to add new production in the next few years from projects planned long ago.
However, like Canada, Brazil is set to add new production in the next few years from projects planned long ago. The massive Lula field–the original field that started the pre-salt craze–could top 1 mbd of output in 2018 after originally coming online seven years earlier. An array of other offshore outlays–new projects and expansions of existing ones–will add output in the coming years.
On the other hand, unlike Canada, Brazil has much higher growth potential. The liberalization of the energy sector could attract billions of dollars in new investment. Royal Dutch Shell’s $50 billion purchase of BG Group was in part made with an eye on Brazil’s offshore sector. Shell says it will spend $10 billion on Brazilian projects over the next five years, which will help the company boost production to 800,000 b/d by 2020, up from 300,000 b/d today.
Shell says it will spend $10 billion on Brazilian projects over the next five years.
After only tendering one new pre-salt exploration block over the past seven years, Brazil’s government expects to hold three auctions in 2017 alone. “More frequent licensing rounds, with reduced [Petrobras] participation, as well as expanded partnerships and divestments by Petrobras, will open up increased opportunities for [international oil company] investment,” the IEA wrote in its report. Producing in Brazil’s pre-salt is still expensive, but not prohibitively so. While Canada’s oil struggles to find ways to the international market, Brazil’s offshore oil fields won’t likely have the same problem.