Prices for Canadian heavy oil are starting the year unexpectedly strong despite a surge in output, easing lingering worries that a lower price would undermine Alberta government revenues.
Last month’s frigid weather in Northern Alberta, and its short-term effect on equipment and production, has been cited for some of the recent strength in the crude market, which is registering just half the discount to benchmark light oil that it did at the start of 2013.
However, structural changes in the North American crude oil market, including expanded pipeline and refining capacity, have fuelled expectations that heavy-crude discounts will narrow to the point where they won’t have the same revenue-sapping impact on Alberta’s finances as feared a year ago.
“The other thing that is helping is additional rail … capacity in Western Canada to get crude to more distant markets,” said Judith Dwarkin, director of energy research at ITG Investment Research.
She said, however, that some of the high-profile pipelines that have been the topic of intense debate – such as Enbridge Inc.’s Northern Gateway, TransCanada Corp.’s Keystone XL or the firm’s Energy East project – would be needed by 2020 due to relentless production gains.
On Tuesday, Western Canada Select heavy blend crude for February delivery sold for $19.50 (U.S.) a barrel less than U.S. benchmark West Texas Intermediate light crude, according to Calgary-based oil broker Net Energy Inc.
That compares with price spreads of $40 or more a year ago, when supplies built up within Western Canada due to severe constraints on export pipelines. At times in early 2013, the price of Alberta’s heavy crude was less than half that of international benchmark Brent oil.
Crude prices are critical to Alberta’s finances, as it depends on energy for about one-third of its revenues. Last January, Premier Alison Redford used a television address to explain the problem of discounted oil sands-derived crude, warn of a potential $6-billion (Canadian) loss to public coffers, and pledge to redouble efforts to get the supply to lucrative new markets.
Prices strengthened as the year progressed, as output from Imperial Oil Ltd.’s new Kearl oil sands project increased at a slower rate than expected and as more oil moved to market by train, despite a string of accidents on the rails.
In his fiscal 2013-2014 budget, Alberta Finance Minister Doug Horner forecast WTI at $92.50 (U.S.) a barrel and WCS at $68.21. In first-half results, issued in November, the averages were $99.99 for WTI and $82.65 for WCS.
That spelled higher royalties for the government, and helped fuel a $1.1-billion (Canadian) operating surplus for the first six months of the fiscal year, said Chris Bourdeau, spokesman for Mr. Horner. “With the differential in the $18 to $19 [U.S.] range right now, we are cautiously optimistic that we will continue to see some relief from the bitumen bubble, but the underlying constraints on market access are still there,” Mr. Bourdeau said.
In a report on global energy, RBC Dominion Securities described its outlook for Canadian heavy crude as bullish, based on increasing demand in the key U.S. Midwest region and on the improved pipeline access to refineries in Texas. These factors appear to be lining up to support prices, even as the delay persists in regulatory approval for the $5.4-billion Keystone XL pipeline, which had initially been expected to be in operation by now. U.S. President Barack Obama has given no indication when a decision on the project might be made.
Late last year, BP PLC started up new equipment at its refinery in Whiting, Ind., which adds about 170,000 barrels a day of demand for heavy crude. In addition, by the middle of the year, Enbridge Inc. is expected to complete its Flanagan South pipeline link in Illinois, which offers more capacity to the Cushing, Okla., storage hub, and its twinning of the 450,000-barrel-a-day Seaway pipeline between Cushing and Texas refineries.
Still, production is on track to keep increasing. In 2013, Canadian raw bitumen and heavy crude output averaged 1.47 million barrels a day, a 9.7-per-cent increase from 2012 and nearly 50 per cent higher than just five years ago, according to the National Energy Board.
This year, gains will come from such new projects as Canadian Natural Resources Ltd.’s 40,000-barrel-a-day Kirby South and MEG Energy Corp.’s 35,000-barrel-a-day Christina Lake Phase 2B developments.
ITG has forecast bitumen production gains of 200,000 barrels a day each year for the next five years, Ms. Dwarkin said.
“The problem with seemingly inexorable bitumen production growth, the BP expansion and this capacity supplement by Enbridge will only take us so far into the future before differentials start getting pressured again,” she said.