Allen Crowley, vice-president of regulation and market studies with Calgary-based EDC Associates Ltd., which offers consulting services and produces a well-regarded annual report on the province’s electricity system, says recent forecasts by the Alberta Electric System Operator (AESO), which manages the province’s power system, are overly pessimistic about the system’s ability to shift to a greener footprint.

“I don’t see the sense of urgency they [AESO] have created,” he said, commenting on the agency’s forecast, released last spring. “We have a lot of time to adjust.”

The AESO forecast provides different scenarios, including a reference case, a high growth case, a low growth case and an “alternative policy” case. The varying scenarios are essentially in response to different levels of economic growth, with the high growth case based on more oilsands and other growth than now seems likely.

The reference case outlook visualizes the need for 23,424 megawatts (MW) of power by 2030, which is about double the peak demand last year.

With the New Democratic government mandating that coal-fired power, now responsible for about 6,299 MW of electricity, needs to be eliminated by 2030, while 30 per cent of the province’s electricity will need to come from wind power and other renewables, there is a perception that power generators need to move quickly to ramp up their output of renewables and gas-fired power.

The AESO recommended that the electricity market design be changed from the “energy-only” design to a “capacity market.”

In any energy-only market, generators receive virtually all their revenues from the hourly sale of energy. If they don’t run in a given hour, they don’t get paid.

In a capacity market, Crowley explained, generators are also paid for capacity sitting idle and ready to serve, even if it isn’t needed in a given hour. The AESO is predicting that generators will not make enough money in an energy-only market and, therefore, won’t be incented to build enough new generators to meet reliability standards.

However, Crowley said the recession that has hung over the province’s economy for the last two years, along with a burst of new gas-fired power built to meet rapid growth that didn’t arrive — such as the 860 MW Shepard Energy Centre in east Calgary, as well as new cogeneration plants built by oilsands producers — means there will be enough electricity to meet demand for years.

“Our maximum load last year was 11,500 MW,” he said, adding that the system has an ability to provide more than 17,000 MW of electricity. “You need to have a cushion, but now we have more than we need.”

In fact, Crowley, who has been studying Alberta’s power system for decades, said just small additions to the power fleet would mean there’s enough electricity to meet demand for the next five to 10 years.

Under almost any scenario EDC has outlined in its reports, he said there is no need for there to be a sense of urgency, even if successive governments also require coal-fired power to be gone by 2030.

However, Crowley is not minimizing the impact of the shift away from coal and to renewables.

This year’s EDC analysis, to be released in about two weeks (it costs $5,300 to purchase the extensive analysis), will focus on how Alberta’s unique deregulated, private sector-dominated electricity market will be challenged by the shift to a capacity market.

In North America, only Texas has a similar energy-only market, although the state’s government has not mandated a shift to a given percentage of renewables. Most other jurisdictions in North America have opted for a more complicated capacity market.

The consulting firm concludes that Alberta’s “energy-only” market design, where AESO and other agencies act as referees, while free market generators participate, will be challenged by the new renewables mandate, but will still encourage enough new generation, at least for the next decade and probably indefinitely.

EDC says the three main goals of Alberta’s power system; reliability/safety, an efficient market based on fair and open competition, and, finally, a minimal cost of regulation and incentives for efficiency, faces upheaval.

That’s because the Alberta government has injected a fourth goal of achieving a power system with a low-carbon footprint.

“This admirable objective raises a question as to whether Alberta’s current ‘energy-only’ market design will continue to incent enough new investment to ensure long-term reliability or [to] contain price volatility within an acceptable range…,” EDC writes in a summary of a chapter in its upcoming 300-page report dealing with challenges power generators will face.

The report will provide several scenarios under this “bifurcated market design.”

Although there are many capacity markets in the U.S. and Europe, there is no precedent for moving from an energy-only market to a capacity market. 

While Crowley said the deregulated, private sector-dominated market should be able to exist under the new green power mandate with a capacity market, there will be a need for continued regulatory tinkering, as witnessed by continued changes in other capacity markets in the U.S. northeast and elsewhere.

“It’s 10 per cent of the way back to a regulated market,” he said.

It transfers some of the risk of overbuilding back to the consumer and away from the generators themselves, he said.

While the goal of the CLP might be to see far more renewables brought into the system, Crowley said natural gas-fired power will be the big winner.

In fact, many of the generators who will need to phase out coal, are looking at converting their plants to gas-fired electricity.

While AESO saw wind power, in a province where wind power already provides about 1,500 MW of power, growing to as much as 5,663 MW by 2030, Crowley said that is “nameplate capacity.”

In fact, wind power only regularly provides about 35 per cent of the maximum electricity it is designed to generate.  When the wind is not blowing at full speed, the generator is not producing at full capacity, unlike a gas-fired unit which can produce its full capacity whenever called upon.

All forms of natural gas-generated power now are responsible for about 7,216 MW of electricity in the province. The biggest contribution comes from cogeneration plants, mostly in the oilsands. In fact, the oilsands is the largest single user of gas in the province, at above two bcf per day.

Those cogeneration facilities are designed for dual-purpose, to very efficiently produce both electricity and use of the steam. The steam, mostly used to coax bitumen out of the ground, is produced as a by-product, without using any more gas, by capturing what was otherwise waste heat  from the electricity generator.  Those plants now generate 4,504 MW. Much of the electricity generated is used on site, but any excess is sold to the Alberta power grid.

AESO says that will grow to 5,550 by 2030. That will lead to some growth in natural gas consumption.

But the shift to natural gas generated power in other power plants, chiefly highly-efficient combined cycle plants, will be significant.

Combined-cycle plants are only responsible for about 1,716 MW now, but AESO says that will grow to 8,541 MW by 2030.

In addition, it forecasts simple-cycle gas-fired plants will be producing 2,307 MW by 2030, up from 996 MW now.

EDC, in a study it released in 2014, entitled Full Steam Ahead, concluded that there is the potential for cogeneration in Alberta to grow far beyond its current capacity.

In its report, EDC says one of the largest forces leading to the need for more cogen is the shift to SAGD technology in the oilsands, which the firm calls “the perfect environment” for the technology.

“With cogen, natural gas is burned directly at the blades of a gas combustion turbine, which spins a generator to make electricity,” the consultants explained. “The extremely hot exhaust gasses are passed through a heat recovery steam generator (HRSG), which extracts the waste heat to boil steam. The steam is then put to work in its host’s process, replacing steam otherwise produced by a traditional stand-alone steam boiler.”

They went on to explain that the simultaneous creation of electrical energy and steam energy is much more efficient than creating the two separately, achieving up to 90 per cent efficiency.

Crowley also believes there is far more potential for the development of hydropower in Alberta than the 750 MW that now exists. Some existing power producers in the province are studying that potential, which would involve building more hydro projects in northern Alberta.

He said he believes the new power shift to move to more renewables could be costly, with some estimates it will require government incentive payments of $30-$40 billion to bring about the required generation.

If government policy allows for the addition of more cogeneration to the grid, it would be less challenging to attract that investment, since oilsands producers would have a reliable market for their excess power.

“Cogen is the ideal solution,” he said.

EDC isn’t alone in having reached that conclusion. Studies released recently by researchers at the University of Calgary, led by David Layzell, director of the Canadian Energy Systems Analysis Research Initiative (CESAR), said large scale cogeneration could lead to the earlier retirement of coal-fired plants, while achieving additional greenhouse gas emission reductions.

Crowley said the existing surplus of electricity in Alberta gives the New Democratic government ample time to come up with well-considered, logical solutions that will both reduce emissions from the province’s power sector and provide enough electricity far into the future.  These solutions should include consideration of more cogeneration and less dramatic changes to the electricity market.