What’s next?

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[mk_dropcaps style=”simple-style”]W[/mk_dropcaps]HEN THE NDP swept to power in Alberta and Rachel Notley became premier in May 2015, the response from the energy sector was swift. The win came at the crest of an oil-price swoon not seen since 2008, giving Notley’s threats of tax hikes and a royalty rejig the feeling of salt in a wound. So when the new government stood by its campaign promises to raise corporate taxes, double carbon fees for industrial emitters, and overhaul the province’s oil and gas royalty system, some energy companies threatened to move jobs and investment out of the province.

[/vc_column_text][/vc_column][vc_column width=”2/3″][mk_image src=”https://energy-exchange.net/wp-content/uploads/2016/01/08721412.jpg” image_width=”800″ image_height=”500″ crop=”true” lightbox=”false” frame_style=”simple” target=”_self” desc=”THE CANADIAN PRESS / JEFF MCINTOSH” caption_location=”outside-image” align=”right” margin_bottom=”10″][/vc_column][/vc_row][vc_row][vc_column width=”1/1″][vc_column_text disable_pattern=”true” align=”left” margin_bottom=”0″]But the pushback, it seems, was more than premature. The tax and fee changes the government plans to introduce are designed to situate Alberta closer to the middle of the pack among other provinces. And any changes to oil and gas royalties won’t take effect until after 2016, when global commodity prices are expected to stabilize.

“This isn’t a royalty increase, it’s a royalty review,” says Dave Mowat, chair of the province’s review panel. The review may actually have been overdue. The last review was in 2008, and it was only 10 years ago that 90 per cent of Alberta’s royalties came from natural gas with the rest from oil. By 2014, those ­ figures had reversed. “We want to make sure that whatever adjustments are possible in the royalty system will support Alberta in terms of the next 10 years,” says Mowat.[/vc_column_text][/vc_column][/vc_row][vc_row][vc_column width=”1/1″][mk_blockquote style=”line-style” font_family=”none” text_size=”22″ align=”left”]

Alberta Premier Rachel Notley faces a range of energy challenges.

[/mk_blockquote][/vc_column][/vc_row][vc_row][vc_column width=”1/1″][vc_column_text disable_pattern=”true” align=”left” margin_bottom=”0″]The province’s plans for coal are likewise long term. Notley announced in November that her government would phase out the use of coal fired power in the next 15 years. That’s a big shift for a province that burns more coal to generate electricity than the rest of Canada combined. That looming electricity supply gap will have to be met, likely with new natural-gas-­ red plants and renewables, such as solar and wind, which remain very much in the early phase in Alberta.

Still, the major issue for Alberta’s energy sector is getting, in Premier Notley’s words, at least one new “drama-free” oil pipeline to tidewater built, a goal to which her government is committed. But in the absence of a binding national energy plan, it falls chiefly on the provinces to strike their own interprovincial deals. To that end, the government will rely on its record on the environment to bring other provinces, such as British Columbia and Quebec, on side.

“The way to get social licence or export licence or transboundary licence in the case of interprovincial pipelines is to get oilsands greenhouse-gas emissions at parity with conventional crude,” says Chris McDermott, a cap-and-trade proponent who from 1998 to 2006 served as a Canadian negotiator on the Kyoto Protocol. “Then they can say that the oilsands is no more greenhouse-gas intensive than anything else.” And the most ef­ficient way to do that, McDermott says, is through carbon trading.

In November, the government announced a new hybrid system with an economy-wide carbon price ($20 per tonne of carbon-dioxide emissions in 2017 rising to $30 in 2018) and a 100-megatonne cap on emissions from the oilsands (which currently emit 70 megatonnes annually). Flexibility mechanisms such as offsets are expected to be available for some emitters, but the cap-and-trade system will initially be contained to Alberta. In the future, however, the province could consider linking to other carbon markets. A 2013 Citi Research report found that to offset the emissions from oilsands crude enough to bring them on par with emissions from an average barrel of U.S. crude would cost just US$0.89 per barrel on California’s carbon market. That’s the same market that Ontario and Quebec have signed on with. Given that, if a future carbon-trading Alberta was buying up a large part of Ontario’s and Quebec’s carbon credits, it might allow Alberta’s oil producers to cast off long-standing interprovincial trade restrictions and earn world-market prices for their oil, while offsetting their carbon emissions, investing in clean energy and supporting industry in other provinces — not bad for about a buck a barrel. Of course, no system is perfectly fair and carbon pricing is no exception.

“The government has been hamstrung in the past by policies that focus on a relatively small group of industries of visible and heavy pollutants — and the assumption is that if you focus on those you can get the problem solved,” says Michal Moore, director of energy and environment at the University of Calgary’s School of Public Policy. “But a lot of the problem is diesel vehicles and automobiles.”

With the recent new measures, clearly Alberta is looking to new approaches to its climate challenges.[/vc_column_text][/vc_column][/vc_row][vc_row][vc_column width=”1/1″][vc_column_text disable_pattern=”true” align=”left” margin_bottom=”0″]

– Todd Coyne

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Read more stories from the Winter 2016 issue of Energy Exchange magazine