Although the Alberta NDP government’s Climate Leadership Plan is terrible news for coal-fired power producers, who now face extinction, and bad news for consumers, who will have to pay a new carbon tax and higher utility bills, natural gas producers could emerge as the big winners. Developers of renewable energy could also fare pretty well.
Ben Brunnen, manager of fiscal and economic policy for the Canadian Association of Petroleum Producers (CAPP), says CAPP forecasts that by 2030, Alberta’s electricity sector’s demand for natural gas will have grown by 1.5 bcf/d.
Brunnen assumes most of that gas would come from Alberta-based producers, who have seen their production drop from about 14 bcf/d in 2006 to below 10 bcf/d this past year, as shale gas production in the U.S. led to a significant decline in gas exports from Canada.
“We see gas demand in Alberta’s power sector growing by 1.5 bcf/d by 2030, once they retire all the coal-fired power [the target of the plan] and generate 30 per cent of Alberta’s power from renewables,” says Brunnen.
CAPP has estimated that, at today’s gas prices, that could generate $140 million in new royalties for the province, higher than what the province receives from coal production.
Last November, when the climate plan was released, CAPP gave it its tacit approval, saying it would “further enhance the reputation of our sector and improve our province’s environmental credibility as we seek to expand market access nationally and internationally.”
The plan allows oilsands production to grow by at least 50 per cent, especially if producers implement new technologies. But CAPP also went out of its way to highlight the opportunities for gas producers.
“Natural gas is the cleanest-burning fossil fuel,” the association said in a press release. “Used in power generation, it emits about half the carbon dioxide compared to coal and could virtually eliminate emissions of smog-causing pollutants.”
Brunnen says the opportunity created for natural gas producers “is the most positive part of the plan.”
Bill Gwozd, Calgary-based senior vice-president of HSB Solomon Associates, one of the leading consultants to the oil and gas industry, agrees the climate plan does look bright for gas producers, who have faced years of lower exports and low gas prices.
“We see natural gas demand for power production in Canada growing by about one bcf/d between now and 2022,” he says. He also suggests that pace of growth could continue through 2030.
In early November, Solomon produced a comprehensive study forecasting Canadian and U.S. gas demand for the next 34 years. The report, entitled North American Natural Gas Forecast to 2050, paints an optimistic picture for gas producers going forward.
Canadian gas production in 2015 varied between 14.32 bcf/d and 15.3 bcf/d, with an average of 10 bcf/d coming from Alberta, between 3.9 bcf/d and 4.3 bcf/d from B.C., and the rest from Saskatchewan and offshore Nova Scotia. That’s down about 30 per cent in the last 10 years, a period that saw prices drop by 50 per cent or more.
But Gwozd says the price weakness that has plagued Canadian gas producers for the past few years could change dramatically as gas demand for power grows in both Canada and the United States.
“Natural gas [generation] comprises about 28 per cent of the North American power market now,” he says. “We see that growing to 29 per cent, but that percentage will be of a growing market. Now we’re burning 28 bcf/d to produce power, and we see that growing to 42 bcf/d by 2050, which will be up 50 per cent.”
Solomon sees several drivers for western Canadian gas producers and says they could be producing 25 bcf/d by 2050.
But the consultancy is less optimistic about prospects for LNG export projects on Canada’s west coast. Once projecting a potential for 15 bcf/d or more of demand, Solomon now says LNG on the west coast will account for about eight bcf/d of demand by the next decade.
Another source of demand will be the oilsands, assuming oil prices recover and new or expanded projects are built. Solomon believes gas demand in the oilsands could grow from about two bcf/d now to four bcf/d in the next decade or so.
Although Canada is a relatively small player in the gas-fired power market in North America, gas demand for power production will experience a meaningful boost.
North American demand for natural gas to generate electricity, Gwozd says, is projected to increase to 32 bcf/d by 2022 from current levels around 25 bcf/d. Meanwhile, coal used in the power sector will drop by about 0.6 per cent per year in that period, declining from 33 per cent of power generation down to 19 per cent.
Solomon projects renewables, such as wind and solar, will grow their share of the market significantly, from about seven per cent now to as much as 25 per cent by 2050, while nuclear, hydro and other sources will provide the balance of the generation.
Alberta’s Climate Leadership Panel, chaired by University of Alberta economist Andrew Leach, also sees renewables taking a stronger role in the province’s electricity mix.
“The panel recommends an integrated electricity policy package, which will phase out coal-fired power in Alberta by 2030 and replace at least [50–75 per cent] of retired coal generation with renewable power, increasing the overall share of renewables to 30 per cent while retaining Alberta’s competitive electricity market structure,” the panel’s report says.
But Duane Reid-Carlson, president of Calgary-based economic consulting firm EDC Associates, which specializes in the power sector, helped author an analysis of Alberta’s electricity sector in light of the climate plan, and believes it will be impossible for renewables to provide the amount of electricity the plan envisions. That will open the door to more gas-fired power.
In November, prior to the release of the climate plan, EDC released its annual update on developments in Alberta electricity market. EDC tried to anticipate changes that would result from the impending climate plan, but the plan went far beyond what the firm, which has been observing electricity markets since 1992 (Reid-Carlson has been doing so since 1988), had anticipated.
In particular, Reid-Carlson says the plan’s goal of eliminating all coal-fired power by 2030 amounts to a radical—and unrealistic—restructuring of the province’s electricity grid.
“You can’t replace all of your coal-fired power with renewables because wind and solar are intermittent power sources. You need something to backstop the grid.”
That’s because coal-fired power, which now provides about 6,200 megawatts (MW) of the province’s more than 16,000 MW of installed capacity is baseload power. That means it is far more reliable than renewable sources by essentially being available most of the time. Gas has the same attributes.
When Ontario shut down its coal-fired power plants, at one point responsible for about 30 per cent of its installed capacity, the government-owned utility scrambled to replace the power with renewables. It had to turn to gas-fired power while also revamping existing nuclear plants.
Power rates in that province nearly doubled as a result of the off-coal program, a course Reid-Carlson thinks is likely for Alberta.
EDC’s update, released in early January, envisions the amount of gas-fired power, now responsible for about 3,000 MW, rising by about 2,000 MW to 5,000 MW.
It sees renewables providing about 13,000 MW. Included in this would be wind, some solar and a possible increase in hydro (there is about 800 MW of hydro now and marginal solar).
In an addendum to the report, EDC concludes that wind generation is the most cost-effective way to reach the target, forecasting that the province might see wind power rise from the current 1,500 MW to 12,500 MW. That would account for 45 per cent of the power fleet’s capacity by then.
“As a fairly stable rule of thumb for the Alberta market, the capacity percentage for renewables has to be 1.5 times as large as its production percentage,” the update says. “Since wind production is intermittent and only runs [32–35 per cent] of the time, to achieve 30 per cent of production by renewables, they must comprise 45 per cent of fleet capacity. That is why renewables by 2030 would comprise over 12,500 MW at a 30 per cent of production target.”
While laudable from a climate change perspective, this radical remaking of the power market will come at a cost to Albertans.
The good news, according to the EDC analysis, is that greenhouse gas emissions would fall 44 per cent below a business-as-usual case.
The bad news is “costs for the aggressive program are very substantial…prices for electricity could rise by $10–$50/ megawatt-hour [MWh], depending on the speed and type of renewables being incented.”
Wholesale prices for electricity in Alberta have averaged $65/MWh, so power rates could almost double, and power consumers will then face similar rate increases.
But, aside from this direct impact, the EDC report argues that the provincial government will have to buck up to compensate coal power producers for retiring their units early (some are less than a decade old) and provide generous incentives for wind and other renewables producers.
EDC estimates it would cost $85/MWh to bring on wind and as much as $300/MWh to bring on a mix of wind, solar and hydro.
The report also concludes that it will cost owners of coal-fired power plants $100 billion to retire units earlier than they’d anticipated before the climate plan. The government has promised to appoint an official to discuss compensation with owners of coal-fired plants, but that has not yet happened.
Reid-Carlson says there is no way to escape the fact that power rates in Alberta will rise significantly since coal is the lowest-cost source of power.
“Power rates have to go up or people won’t change their behaviour,” he says.
How the government pays for that change is another question.
In Ontario, the government has imposed a surplus charge in addition to normal power rates. He says that’s likely the approach Alberta will take.
Reid-Carlson says he also has doubts, given the dramatic overhaul implied in the climate plan, that Alberta’s deregulated power market can continue as it is, even though the Alberta government has pledged to maintain the current model.
That’s because, by the very nature of the climate plan, free market forces are being altered.
Ultimately, he thinks there could be more gas-fired power brought on than anticipated.In particular, EDC champions cogeneration (cogen) power.
In a 2014 report entitled Full Steam Ahead, it concludes that cogen—much of which is produced at SAGD oilsands plants, which produce two-thirds of the greenhouse gas emissions of combined cycle gas plants—holds out the potential for substantial expansion.
The simultaneous production of steam and electrical energy is much more efficient than creating the two separately, achieving up to a 90 per cent efficiency, the EDC report concludes.
However, Reid-Carlson says low oil prices, which have brought new SAGD development to a virtual halt, may stand in the way of any substantial growth in cogen going forward.