Can Alberta govt kick-start petroleum value-added processing?

Alberta can take advantage of market niches to add value to its oil – economist Michael Moore

Over the decades, many 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 Michael C. Moore says the job-creating upgraders slash refineries demanded by unions and NDP supporters during the 2015 provincial election are yesterday’s game.

But two petrochemical plant announcements in February and a University of Calgary study on the economic benefits of partial upgrading of bitumen may point toward a new value-added strategy for Alberta.

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 the tough job of wringing more value from gooey bitumen.

“I mean, it’s like listening to [American President Donald] Trump. There’s no strategy, no vision going forward and where you want to be in ten years,” he 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 will soon be forthcoming. The Alberta government struck its expert panel, called the Energy Diversification Advisory Committee, in October. The committee’s mandate is to explore options for energy diversification such as partial upgrading, refining, petrochemicals and chemicals manufacturing.

Notley has hinted that she could use oil and gas royalties to “incent” technological innovation.

New or significantly more efficient processes will be needed to overcome Alberta’s inherent disadvantages, says Moore, but 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 committee will have to consider how to overcome two barriers.

One, the NDP’s own climate policies, which seek to limit greenhouse gas emissions (currently 36 per cent of the Canadian total) to 50 Mt CO2 equivalent below “business as usual” by 2020. Upgraders, like the Husky operation in Lloydminster, heat crude oil to about 500C, then cool it to 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.

Two, while oil is far from dead, 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,” says Moore.

“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 is only nearing completion in 2017 because of significant financial involvement from the Alberta government dating back to PC Premier Ed Stelmach, Alberta has seen the last of upgraders and refinery projects, 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 said in an interview.

“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.”

Last time the North American industry went on a building binge, bell bottoms and lava lamps were all the rage. Companies built refineries close to markets, near ports that facilitated importing crude oil and exporting finished product like diesel fuel, kerosene, a range of aromatics, asphaltines depending on the season, even paraffin wax at the bottom of the value-added chain. Then significant infrastructure (think pipelines and storage) was 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 American investors has created clusters of refining and processing – like the Texas Gulf Coast, where much of the American 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.

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 barrel a day plant to be built for about $3 billion, chump change compared to a refinery.

And the benefits for industry, the Alberta economy, the provincial government are considerable: a $10 to $15 per barrel increase in the value of a barrel of bitumen; no need for diluent (which comprises 30% of dilbit), which increases the capacity of existing pipelines; 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 approximately 60 per cent of Alberta’s 2.3 million barrels a day 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.

Anxious to get started before the diversification committee reported, Notley launched the Petrochemical Diversification Program in Feb. 2016 and 10 months later two projects were announced.

Pembina Pipeline Corp.’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 35,000 b/d of propane to produce up to 800,000 tonnes a year of polypropylene, which is used to make automobile plastics, medical supplies, home appliances, etc.

Inter Pipeline’s plant will also manufacture propane into propylene and receive up to C$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 value-added processing of Alberta crude oil, especially oil sands bitumen. 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 in a few months when the Notley government releases it economic diversification strategy.