Refineries? Where’s The Value In That?

Bitumen upgrading in Alberta sounds like a good investment for the province. But an economic question mark hangs over the whole theory of "value added"

March 06, 2017

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The North West Redwater Sturgeon refinery’s value to Alberta has been alternately questioned and vindicated by recent reports
Photograph Paul Swanson

For decades Alberta premiers have tried to develop value-added processing of the province’s abundant hydrocarbon reserves. Now, it’s Rachel Notley’s turn. The NDP Premier has tasked a committee with drafting an energy diversification strategy, with a report expected this spring.
Economist Michal Moore says the job-creating upgraders and refineries demanded by unions and NDP supporters during the 2015 provincial election are yesterday’s game. But two new petrochemical plant projects and a University of Calgary study on the economic benefits of partial upgrading of bitumen indicate a new value-added strategy for Alberta.

“I look at the market for energy and I see that it’s changing quite a bit, reflecting the fact that it’s going to be an electric world out there. It’ll take 40 years to get there, maybe longer, but the transition’s already occurring. So, the last thing you want to do is chase something that’s diminishing.”
Michal Moore, senior fellow at the University of Calgary

Moore is a senior fellow at the School of Public Policy for the University of Calgary. He worries that, thus far, the Notley government is missing the big picture when it comes to wringing more value from gooey bitumen. “I mean, it’s like listening to [U.S. President Donald] Trump. There’s no strategy, no vision going forward and where you want to be in 10 years,” Moore says. “I don’t know how they’ll attract capital and I don’t know what the end product is likely going to be. I don’t know where they’re headed.”

The strategy is forthcoming. The Alberta government struck its expert panel, called the Energy Diversification Advisory Council, in October. Its mandate is to explore options for energy diversification, including partial upgrading and refining. Notley has hinted that she could use oil and gas royalties to “incent” technological innovation. Moore agrees that new or significantly more efficient processes are needed to overcome Alberta’s inherent disadvantages, and he thinks provincial entrepreneurs are up to the challenge. “I think that the advances over the next five years or so are probably going to be with new chemical plants and new chemical techniques. And it’s going to likely transform the way we think about hydrocarbons,” he said. “I put a lot of faith in Alberta entrepreneurs and I think if they face a clear set of rules, they’ll deliver.”

When writing its report, the diversification council will have to consider how to overcome two barriers. One is the NDP’s own climate policies, which seek to limit greenhouse gas emissions without a carbon capture program for refineries and upgraders. (Alberta accounts for 36 percent of Canada’s total GHG emissions.) Upgraders, like the Husky operation in Lloydminster, heat crude oil to about 500C, then cool it to below 70C for transportation via pipeline to a refinery, where it is heated once again. “With a standalone upgrader and a remote refinery, the GHG emissions are going in the wrong direction,” says Bruce Peachey, a professor of petroleum engineering at the University of Alberta.


Former Alberta Premier Peter Lougheed oversaw a boom in refinery and petrochemical plant construction in the 1970s

The second obstacle, according to Moore, is that while the age of oil is far from over, the North American market for oil is relatively flat. “I look at the market for energy and I see that it’s changing quite a bit, reflecting the fact that it’s going to be an electric world out there. It’ll take 40 years to get there, maybe longer, but the transition’s already occurring,” he says. “So, the last thing you want to do is chase something that’s diminishing.”

Aside from the 80,000 b/d Phase 1 of the Sturgeon Refinery, which will start up later this year and received financial support from the Progressive Conservative government of Premier Ed Stelmach, Alberta has seen the last of its new upgraders and refineries, according to Moore. “I certainly don’t disagree that if there was a way to upgrade raw bitumen in Alberta, it would be a tremendous advantage, for both the government and employment,” he says. “But, you can’t push a string. If the market isn’t going to support it, or if those markets have changed, if there’s not enough capital to underpin it, you can’t wish away the real world.”

The last time the North American refining industry went on a building binge, bell bottoms and lava lamps were all the rage. Companies built refineries close to markets and near ports that facilitated importing crude oil and exporting refined products. Significant infrastructure, including pipelines and storage, were built to support those investments. “Once you invest that capital, it’s not going to move around,” says Moore. “That’s why the last big refinery for gasoline developed in the late-70s, because the market has been relatively flat for those types of products. So, you tend to fix and repair your own but no one wants to build a new one.”

Even worse news for Alberta is that all that capital spent 40 years ago by U.S. investors has created clusters of refining and processing—like the Texas Gulf Coast, where much of the U.S. heavy oil refineries are located—that are very hard to compete against. The existing players have long-term business relationships with their customers in a slowly declining market—not ideal conditions for a new Alberta competitor. “Once a competitor captures a market, it’s very hard to wrest it away,” says Moore.

But if refining and full upgrading are not on the table, partial upgrading could be. School of Public Policy researchers believe there is a market niche for medium to heavy crude oil that is partially upgraded from bitumen.

New technology allows a 100,000 b/d plant to be built for about $3 billion—chump change compared to a refinery. And the benefits for industry, the Alberta economy and the provincial government are considerable: a $10 to $15 per barrel increase in the value of bitumen; no need for diluent (which comprises 30 percent of dilbit), which would increase the amount of bitumen pipelines can carry; and an annual boost to Alberta’s GDP of $505 million with plenty of jobs and an extra $60 million a year in provincial tax revenues.

With about 60 percent of Alberta’s 2.3 million b/d of oil sands production not upgraded, and another 800,000 b/d of new production coming online in the next five years, partial upgrading is a pretty safe bet to be included in the new diversification strategy.

The same can be said for petrochemicals. As soon as the oil and gas royalties review panel recommended it, Notley launched the Petrochemical Diversification Program in February 2016 and 10 months later two projects were offered financial support.

Pembina Pipeline’s joint venture with Kuwait’s Petrochemical Industries Company was approved to receive up to $300 million in royalty credits to build an Edmonton-area facility that will use 22,000 b/d of propane to produce up to 550,000 tons a year of polypropylene plastic pellets for shipping to other markets. Inter Pipeline’s complex will also manufacture polypropylene and receive up to $200 million in royalty credits. About 1,400 direct and indirect full-time jobs will be created when the plants open in 2021.

The future looks bright for the value-added processing of Alberta’s hydrocarbons, including oil sands bitumen and NGLs. Between partial upgrading, petrochemicals, and opportunities provided by new technologies, the provincial industry seems poised to wring more profit from a difficult feedstock. That said, as executives consistently point out, the devil is always in the details, some of which will become clear this spring when the Notley government releases its economic diversification strategy.

More posts by Markham Hislop

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Comments

One Response to “Refineries? Where’s The Value In That?”


  1. Diana Daunheimer says:

    “One is the NDP’s own climate policies, which seek to limit greenhouse gas emissions without a carbon capture program for refineries and upgraders.”

    As per Bill 25 legislation, upgrading emissions, post 2015, are exempt.

    “Oil sands greenhouse gas emissions limit
    2(1) Subject to subsection

    (2), the greenhouse gas emissions limit
    for all oil sands sites combined is 100 megatonnes in any year.

    (2) In determining the greenhouse gas emissions for all oil sands
    sites combined in a year for the purposes of subsection (1), the
    following greenhouse gas emissions are excluded:

    (a) cogeneration emissions attributable to the electric energy
    portion of the total energy generated or produced by
    cogeneration, as determined in accordance with the
    regulations;

    (b) upgrading emissions
    (i) attributable to upgraders that complete their first year
    of commercial operation after December 31, 2015, or
    (ii) attributable to the increased capacity resulting from
    the expansion, after December 31, 2015, of
    upgraders that completed their first year of
    commercial operation on or before December 31,
    2015,
    as determined in accordance with the regulations, to a
    combined maximum of 10 megatonnes in any year;

    (c) greenhouse gas emissions from any prescribed
    experimental scheme or any experimental scheme within a
    prescribed class of experimental scheme;

    (d) greenhouse gas emissions from any prescribed primary
    production or any primary production within a prescribed
    class of primary production;

    (e) greenhouse gas emissions from any prescribed enhanced
    recovery or any enhanced recovery within a prescribed
    class of enhanced recovery.”

    http://www.assembly.ab.ca/ISYS/LADDAR_files/docs/bills/bill/legislature_29/session_2/20160308_bill-025.pdf