Everyone knows the story by now.
Alberta’s government is set on retiring all the province’s coal-fired power plants and increasing renewable energy to up to 30 per cent of total generation by 2030 as part of its efforts to cut carbon emissions.
Other jurisdictions around the world are on the same path, and some are far ahead of Alberta in expanding renewable generation. However, they did it at a great cost and struggled through a steep learning curve. There are lessons Alberta could learn from these experiences to avoid making the same mistakes.
Flexible power the key behind Denmark’s successes
Denmark’s green energy transition began after the 1973 oil crisis. When the oil embargo started, Danes used Middle Eastern oil for 92 per cent of their energy needs—from power generation to heating.
Shortly after the oil crisis, the country built its first wind turbine and set multiple renewable goals and initiatives. Now it’s the world’s wind trailblazer. In 2015, Denmark generated 42 per cent of its electricity with wind, according to data from Energinet.dk, the country’s transmission system operator (TSO).
Denmark aims to obtain 50 per cent of its electricity from wind by 2020, to generate all of its electricity from renewables by 2035 and, ultimately, to be fully fossil-fuel-free by 2050.
Copenhagen-based consultant Ea Energy Analyses identifies three main challenges for integrating wind energy into the grid—ensuring wind power remains valuable when it is very windy, guaranteeing sufficient capacity when there is no wind and balancing wind power production.
In Denmark, flexibility has been the answer to all these challenges. It is present at all levels of the Danish grid, allowing it to reap the benefits from airstreams and to be stable when there is barely a breeze.
While the variability of wind energy can’t be controlled, it can be predicted. Weather forecasting allows the Danish grid to integrate large amounts of wind energy without compromising its reliability.
“In Denmark, the day-ahead predictions are now accurate to about more or less five per cent of installed capacity, and on shorter-time horizons are even better,” explains Bo Hesselbæk, head of electrical systems analysis in the wind department of DONG Energy, Denmark’s largest energy company.
Usually, wind can be counted on for 20 per cent of the electricity Danes consume. However, wind can swing instantly from generating over 140 per cent of electricity demand to nothing at all. In Denmark, wind predictions and the grid balance are done one day in advance. However, traders can alter their plans until one hour before the operating time.
Eric Martinot, a professor of economics at the Beijing Institute of Technology, says weather forecasts are used everywhere there is high load of renewables, from Germany to Ontario to California. However, Denmark has taken wind prediction one step further.
During the day, the TSO compares minute-by-minute the actual output of renewables against the prediction made the day before.
“The error of actual versus predicted is then used to forecast the output of renewables in the coming hours ahead of real time,” says Martinot.
Precise weather forecasts allow thermal power plants to react according to the amount of wind and sunlight available—by increasing or reducing electricity generation or shutting off if needed.
Breaking the limits of engineering
A second way the Danes are managing the variability of wind power is through turning their thermal power plants—originally designed for baseload operation—into some of the most flexible power plants in Europe.
Most coal plants are designed to operate at a minimum load of 70 per cent capacity. The average Danish coal plant can operate with a minimum load of ten per cent, says Ea Energy. This indicates Danish coal plants can ramp up by four per cent of its capacity per minute, allowing them to generate electricity rapidly as the wind slows down. In comparison, an average German coal plant can ramp up by 1.5 per cent of its capacity per minute.
These technical capabilities are the result of 20 years of improvements. Danish power companies carefully reduced the minimum load in their plants until the first mechanical limitations appeared. Engineers analyzed the problems they found until an adequate solution was created. Then minimum load was further reduced until limitations appeared again, and the process was repeated until they arrived at the real technical limits on the power plants.
This flexibility not only provides reliability when the wind slows down, but also prevents owners of coal and gas plants from losing money. Denmark, like Alberta and Germany, has an energy-only market: generators are paid only for the electricity they generate, and prices are set between offer and demand.
If thermal plants kept operating at full throttle when the wind or sun surged, the oversupply would bring electricity rates near zero or even into the negatives. So when a wind stream is predicted, a concert of gas and coal plants adjust their generation and shut down if required.
Wind forecasts have decreased the need for must-run capacity from six power plants down to three and sometimes only one, according to Energinet.dk.
Also to help balance the grid, Denmark sells electricity to Germany, Norway and Sweden during times of high wind generation and imports electricity from them when the wind won’t blow, explains Ea Energy. It adds that Norwegian and Swedish hydropower have turned into energy storage for surplus Danish wind energy. Multiple analysts believe Alberta’s wind and B.C.’s hydro could work in a similar way as these countries.
Ontario creating expensive jobs rather than cheap electricity
Many Albertans are worried that integrating more renewable energy in the grid will create rocketing power rates like Ontario. But Alberta is taking a different path than its eastern cousin.
Ontario entered into the renewable energy world in 2003 when it announced its coal plant phase out. Then the province launched a competitive procurement process to commission renewable energy projects. Nic Rivers, Canada Research Chair in climate and energy policy at the University of Ottawa, says the tenders “proved to be quite successful” and funded 1.5 gigawatts of renewable capacity.
In 2009, then premier Dalton McGuinty introduced the province’s Green Energy Act, looking to build a “green economy.” One of the act’s main goals was to create wind and solar industries in Ontario, and with them, 50,000 renewable energy jobs.
To achieve this, the Liberals discontinued the competitive procurement process and implemented a Feed-in Tariff (FIT) program, which was accessible only for projects that complied with high local content requirements. In addition, the program didn’t have a project size cap and gave higher support to certain technologies over others, mirroring the German FIT.
Local content requirements were introduced at a low rate and eventually were increased to 50 per cent for wind and 60 per cent for solar.
“This was a political decision rather than a good policy choice,” Rivers says.
Calculations by Ontario’s auditor general show the previous competitive procurement brought onshore wind contracts at 9.5 cents/kilowatt-hour—a very competitive rate compared to natural gas prices at the time. Fast forward a little bit and the FIT funded onshore wind projects at a rate of 13.5 cents/kilowatt-hour. Even worse, Ontario offered premium rates around 40 cents/kilowatt-hour for solar projects.
The FIT funded over six gigawatts of renewable energy at a cost estimated by Ontario’s auditor general of $2 billion per year on surcharges to electric consumers.
The Ontario FIT had two attributes that increased costs, explains Rivers. It did not subject firms to competition, but instead provide a fixed premium payment, and it provided much higher tariffs for some types of energy than for others.
Rivers says providing different tariffs to certain technologies over others was a mistake as all renewables create the same product—electricity.
“By procuring renewable power at the lowest cost, rather than promoting particular technologies like solar, a significant portion of the costs of the FIT could have been avoided,” Rivers concludes.
In 2012, the World Trade Organization ruled the local content requirements clause to be illegal, and the Liberals had to scrap the FIT program. Later, Ontario brought back a competitive procurement process. But new factors such as community support, local energy needs and participation by aboriginal communities were added.
The results have been positive. In March, Ontario procured large wind farm contracts with rates ranging from 6.45 cents to 10.55 cents per kilowatt-hour.
On the goal of creating a green economy, Rivers says it is hard to defend any job creation arguments.
“We don’t know how many jobs might have been destroyed by higher electricity rates.” Also, the renewable jobs created came at a heavy price. The price tag is $179,000/year for each job created, as calculated by the C.D. Howe Institute.
Ontario’s general auditor estimates in a report that consumers could end up paying $9.2 billion more for renewable energy over the 20-year contracts issued under the FIT with guaranteed prices set at double the U.S. market price for wind and 3.5 times the going rates for solar last year.
“With wind and solar prices around the world beginning to decline around 2008, a competitive process would have meant much lower costs,” the auditor general says in the report.
Ontario’s electricity prices have increased from $50/megawatt-hour in 2006 to a range of $90–$100/megawatt-hour this year. However, only a portion of this increase can be blamed on renewables, says Rivers. He adds that that incentives to green energy add about $7–$10 of the bill.
“There was a big deficit in the electricity infrastructure for a long time,” says Rivers, attributing much of the cost to poor planning, non-competitive gas-fired power plant contracts, extensive required nuclear refurbishment, overpriced hydropower plants and the rebuilding of the aging transmission system.
In 2015, renewables generated 45 gigawatt-hours—30 per cent of Ontario’s electricity, or 12 per cent if hydro is excluded. Today, the total installed capacity for renewables is 13 gigawatts, with wind and solar capacity at four gigawatts.
The province’s goal is to have 20 gigawatts of renewable capacity installed by 2025. However, a report from the Ontario Society of Professional Engineers (OSPE) argues that integrating more wind and solar into Ontario’s grid will be difficult and costly.
Ontario’s hydroelectric plants have limited storage, and inflexible nuclear plants can’t ramp up or cycle down to match the variability of solar and wind energy, explains OSPE. By installing more wind and solar, more carbon-free electricity from nuclear and hydro will be displaced. The Independent Electricity System Operator forecasts that wasted carbon-free electricity in Ontario will be about 11 terawatt-hours in 2016, enough to power over one million homes for a year.
Renewable integration in the province has become politically motivated rather than economically driven.
“The Ontario government is under pressure to increase the capacity of wind and solar generation because of public support for these technologies,” says OSPE.
The Alberta government announced they will adopt a procurement process, which will keep the price of renewables down, says Rivers. He explains that based on what has been made public so far, Alberta will stay away from policies similar to Ontario’s suspended FIT program.
The potential of variable renewable energy in Alberta
Alberta has the pieces to adopt a flexible electrical system with high loads of variable solar and wind energy. To achieve this, the province might not require extensive new grid or backup capacity investment, despite what many critics argue.
The province could adopt a flexible strategy, like Denmark, as it has high-quality solar and wind resources plus plentiful cheap natural gas, says Sara Hastings-Simon, director of the Pembina Institute’s clean economy program.
“It can be cost-competitive to have a power system with renewable and peaking fossil plants that balance the grid,” says Hastings-Simon. She adds that Alberta wouldn’t require heavy investment in backup capacity as the province already has capacity in place to back up its power coal plants.
Allen Crowley, vice-president of regulatory with EDC Associates, a Calgary-based energy and electricity consultant firm, says gas-fired plants in Alberta are flexible enough to ramp up and cope with wind energy variability. Using a flexible system is possible, but it has its drawbacks.
“It is not perfect to have gas plants swinging back and forward, but it is not impossible,” Crowley says, adding that the current electrical infrastructure can easily accommodate 20 per cent variable generation.
However, higher levels would create problems.
Albertans would have to learn to appreciate the economics behind a flexible system. There would be times when the wind or the sun wouldn’t be enough to fufill everyone’s needs and times when wind would be the only source needed, so gas plants would have to run at low prices or shut down during high wind generation,
“Then when there is a wind shortfall, gas guys would charge more to compensate for those hours when they don’t run at all,” says Crowley.
Albertans would see more price swings with cheap rates in the mornings and high price spikes in the afternoon.
“People would be calling MLAs for those hours asking why prices are so high,” says Crowley, adding that people in Denmark might not make a fuss about changing electricity rates but Alberta might be a different story.
Alberta could reliably integrate 4,000 megawatts of wind energy capacity without any additions to the electrical system, concludes a wind integration study done by the Alberta Electric System Operator in 2012. The system operator notes that more variable generation could be added in Alberta if the province had more flexible natural gas generation or storage options.
Bahman Daryanian, director of smart power and power economics at GE Energy, led the recently published three-year-long pan-Canadian wind integration study funded by the Canadian Wind Energy Association.
The study looks at four scenarios for wind generation in Alberta by 2025. These range from four per cent to 50 per cent of total generated electricity in Alberta.
The study showed positive results of the potential of integrating high shares of wind energy in the province. Daryanian says Alberta’s high-quality wind resource has an average capacity factor of 38 per cent.
He adds that generating 50 per cent of Alberta’s electricity from wind is attainable. Under this high-penetration scenario, wind generation in Alberta would grow from 3.8 terawatt-hours today to over 57 terawatts-hours by 2025. To achieve this feat, the province would have to bump its installed wind capacity from 1.4 gigawatts to 17.7 gigawatts.
Daryanian says the study found that Alberta’s current thermal power plants could provide all the backup needed to balance wind variability in the high-penetration scenario. However, the province would need to increase its regulation reserve requirements to ensure grid stability.
After using extensive wind forecasting models, the study found that the required reserve levels would have to be increased from 1.5 to 2.4 per cent of installed wind capacity.
“In our highest wind penetration case considered, the amount of additional regulated reserve requirement is about 428 megawatts,” says Daryanian.
However, additional investments on transmission lines would be required to avoid congestions by 2025.
“It is important to note that some level of transmission reinforcements would be needed anyway in the future simply because of future load and supply growth,” Daryanian says, adding that this investment would be necessary even if the supply doesn’t happen to be wind generation.
Like in Denmark, Alberta would require more exporting transmission capacity in the high-penetration scenario. However, the required amount and investment level would be much less than imagined. Total new transmission investment would have to be $290 million to increase transmission capacity to and from Alberta, B.C. and Montana to 2,235 megawatts from 1,500 megawatts capacity in place today.
Like this? Check out the latest issue of Oilweek.