There are just too many parameters to say exactly what the refiners and the producers should do generally. – Dr. Fogwill
New marine fuel regulations are likely to hit the oil sands hard beginning Jan. 1, 2020, when bunker fuel’s sulphur content must drop from 3.5 per cent to 0.5 per cent. One executive thinks it will cost Alberta producers as much as $5 a barrel at a time when they are already suffering a steep discount to world prices because Canadian pipelines are full.
Economist Allan Fogwill, head of the Canadian Energy Research Institute, which recently published An Economic Assessment of the International Maritime Organization Sulphur Regulations on Markets for Canadian Crude Oil, says there is a great deal of uncertainty around how the new rules will be implemented and the effect it will have on crude oil producers.
“The shipping industry can make many types of adjustments, including installing scrubbers, fuel blending, replacing bunker fuel with LNG (liquified natural gas) or methanol,” he said in an interview.
“They could also not comply with the new regulations because the host countries are responsible for enforcement, not the IMO. How strictly will the host countries enforce those rules?”
The CERI study estimates that between three million and four million b/d of heavy crude oil (82% of it produced in the Americas, i.e. Canada, Mexico, Venezuela) will be affected. The Calgary-based organization thinks that heavy crude prices will be volatile for a short period, meaning refineries are unlikely to pay for costly equipment upgrades.
“Markets are expected to rebalance in a couple of years, and this discourages significant capital investments in complex refining units, which have payback periods of at least two decades,” according to the study.
“Also, there seems to be enough room to process more crudes to meet the expected increases in demand for distillates for marine fuel use…”
Harbir Chhina is the VP of technology for Cenovus Energy, one of Alberta’s largest oil sands producers. He agrees with Fogwill that the impact on prices will be short-lived.
“The worst-case scenario, we felt, was that it would have an impact of about $5/b on differentials for a couple of years,” he said in an interview.
“We’re assuming that it will have a negative impact and we want to make sure that our projects survive, which is why we are reacting with things like shipping more crude oil by rail and being integrated with the downstream.”
Cenovus owns two refineries in the United States, which Chhina thinks will help the company negate some of the effect of the IMO.
Fogwill agrees: “There’re just too many parameters to say exactly what the refiners and the producers should do, but the one thing our study does suggest is that additional refining can add value to heavy crude.”
The biggest concentration of heavy crude refining is at the US Gulf Coast, where giant complexes process 1.65 million b/d, according to the US Energy Information Administration.
The CERI study suggests the new sulphur regulations will likely boost USGC refining margins and, in turn, moderate lower prices for Alberta producers.
“Complex refineries that can handle the heavier crude and create desirable refined products, in certain situations they will actually see an increase in margins as opposed to a decrease in margins, which would suggest that the potential increase in margin could get transferred back to producers,” said Fogwill.
Traditional suppliers like Venezuela (political and economic crisis has curtailed production from 3 million b/d in 2011 to 1 million b/d in 2018) and Mexico (long-term decline due to maturing fields) are giving up market share in this key region, but with Canadian pipeline projects delayed, producers like Cenovus have no choice but to rely upon more costly rail shipments.
Duncan Kenyon, managing director of the fossil fuels program of the Pembina Institute, thinks there is a good chance the higher differentials may stay in place for longer. He doesn’t buy the argument there is enough refining capacity to meet the IMO requirements.
“Even if refiners decides this is a significant market they don’t want to lose and they have to find a way to meet the new criteria, there’s no public dollars, no tax incentives to improve their heavy oil processing so they could take more bitumen like there was in the early 2000s under the George W. Bush administration,” he said in an interview.
But Alberta may have an additional advantage its competitors don’t, says Fogwill.
Earlier this year, the Alberta government committed $1 billion to speed up commercialization of partial upgrading technologies. Instead of upgrading Alberta’s bitumen (which is the consistency of peanut butter) to full synthetic crude, partial upgraders raise the quality to medium or heavy crude that doesn’t require diluting with 30 per cent light hydrocarbons in order to flow in a pipeline.
“If you’re able to partially refine the bitumen, you can reduce the sulphur content and that only adds to the business case for domestic refining in Alberta,” he said.
How will Alberta fare under the stricter IMO standards?
Optimists like Chhina hope for a few years of turblence and wider differentials that could be offset by rising global oil prices.
Pessimists like Kenyon believe the marine fuel issue could be a real shock for the Alberta oil industry, which is already reeling from the controversy over the Trans Mountain Expansion pipeline and impending new climate policies from both the federal and provincial governments.
Fogwill thinks there are far too many unknowns to predict the impact. From his point of view, the possible consequences range along a continuum from catastrophic at one end to slightly higher prices at the other.
So, that’s where Alberta stands, about to affected by a new global regulations but with no idea as to how or by how much. Buckle up.
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