A surging differential for Western Canada’s benchmark heavy crude has traders and analysts wondering if predictions that tighter sulfur requirements for marine fuel next year will devalue the country’s oil assets are overblown.
“Nobody is talking about IMO 2020 anymore,” one trading director at an investment bank in Calgary said.
Market participants say a lot has changed since early forecasts suggested the International Maritime Organization’s rule limiting fuels to 0.5% sulfur from the current 3.5% would significantly devalue the Western Canadian Select blend due to its high sulfur content.
“It’s hard to completely write it off,” Matt Murphy, an analyst at investment bank Tudor, Pickering, Holt, said of IMO 2020’s impact to WCS. “But the medium and heavy sour market is so different than it was. The risk is much lower.”
The collapse in Venezuelan exports, US sanctions on Iran and surging Canadian exports to the US are among the factors that have buoyed the grade this year.
The differential of WCS to the front-month NYMEX light sweet crude futures contract ballooned to minus $51.50/b on October 11. But in December, Alberta’s government said it would cap production, which eventually tightened the differential to minus $6.95/b on January 11. This year, the differential has bounced around mostly in a range of minus $9 to minus $13/b, and grew slightly to minus $14.75/b last week when the NYMEX front month rolled into September.
WCS is one of the world’s heavier crudes, with an API gravity of about 21.6 and 3.62% sulfur content, according to an average of recent assays. That compares with a sulfur content of about 0.57% for the North Sea’s Forties, and about 0.41% for WTI at Cushing. Venezuela’s Merey is about 2.53% sulfur, and Boscan is around 5.38% sulfur.
A sinking ship?
Some early reports on IMO 2020 said the new standard would significantly devalue WCS.
A Canadian Energy Research Institute report released in July 2018 estimated the WCS differential could weaken to as much as a $33/b discount to WTI between 2020-2025, assuming a historical WTI-WCS differential of $13/b. The CERI report estimated as much as 574,000 b/d of oil sands production might not break even with IMO standards.
That report came before the Alberta government announced its mandatory production curtailment in December, saying the measure was needed because the province was producing 190,000 b/d of raw crude oil and bitumen more than could be shipped by pipelines and rail.
S&P Global Platts Analytics sees WCS weakening to the minus $20/b to minus $25/b range as IMO 2020 approaches and the Alberta production cap eases.
“There’s no reason we would be seeing an impact right now, but that doesn’t mean one isn’t coming,” said Jenna Delaney, an analyst with S&P Global Platts Analytics in Houston. “The impacts won’t be seen for at least a few more months, when purchasing decisions actually need to start shifting ahead of the regulation.”
Traders have also reported WCS financial trades for the fourth quarter are ranging from about WTI CMA minus $18.75/b to minus $20.50/b.
Still, some market players say Alberta is unlikely to allow WCS to weaken dramatically, and the government has said it might extend its production cap.
Alberta initially set a production limit of 3.56 million b/d in January, and has gradually increased it to 3.74 million b/d in August. While the provincial government initially set a target to end the curtailments altogether in December, Alberta Premier Jason Kenney has said they might continue into 2020.
At the same time Canada has limited production, the US in January imposed sanctions on PDVSA, Venezuela’s state-owned oil company, effectively banning US imports of Venezuelan crude.
US imports of Venezuelan crude fell to zero for the first time in the week ending March 15, according US Energy Information Administration data going back to 2010. US refiners have imported no Venezuelan crude for eight straight weeks and for 13 out of the last 18 weeks, according to the EIA.
Iran’s oil exports slumped to under 500,000 b/d in June, the lowest in modern history, also as a result of US sanctions. Shipments of Iranian oil fell to 448,633 b/d in June from 901,134 b/d in May, data from S&P Global Platts trade flow software cFlow showed.
US imports of Canadian crude averaged 3.95 million b/d in the week that ended July 5, the second-highest weekly average ever, according to the EIA, before falling to 3.54 million b/d in the week that ended July 12. US imports of Canadian crude posted a record of over 4.06 million b/d in the week that ended January 18.
“We made a ton of money being long Canadian crude,” one trader in Calgary said. “We think the tightness will continue.”
Pipelines to boost takeaway capacity
Crude traders in Canada say another reason for optimism is more than 250,000 b/d of pipeline export capacity maybe soon come online.
Pipeline operator Enbridge is planning to add a further 135,000 b/d of capacity out of Western Canada this year and early next, spokeswoman Tracie Kenyon said.
“We are always looking at ways to optimize our network to get Canadian crude oil to market,” she said.
Enhancements on the mainline systems starting in the third and fourth quarter of this year will add an additional 85,000 b/d of capacity, and drag-reducing agents will add 50,000 b/d of capacity on the Express pipeline from Alberta in the first quarter of 2020, she said.
In June, TC Energy launched an open season for 50,000 b/d of potential incremental capacity on the Keystone system expected to come online as early as August or September. Spokesman Terry Cunha said the open season will not close until later this month, and it will take a few weeks for the company to finalize arrangements.
Separately, Plains All American Pipeline last week launched an open season to gauge demand for an expansion of its Western Corridor pipeline system to move more oil from Canada, Montana and Wyoming toward refining and export markets on the Texas Gulf Coast.
The pipeline company aims to boost capacity by 70,000 b/d and start service in the second quarter of 2021, it said in a notice.
Longer term, Platts Analytics expects Enbridge’s 370,000 b/d Line 3 expansion to begin moving crude to the US Midwest in mid-2021, and TC Energy’s 830,000 b/d Keystone XL and/or the Canadian government’s 590,000 b/d Trans Mountain expansion to be completed by late 2022.
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