By Sharryn Dotson, Online Editor
Power generation capacity in Canada is on the rise thanks to government and other incentive programs, such as Ontario’s feed-in tariff program. The increase in generation helped the country reach a renewable energy goal of 4,000 MW of new installed capacity in 2010, a year ahead of schedule.
|The Nanticoke coal-fired power plant also had 1,000 MW of coal generation shut down in 2011. Courtesy: Ontario Power Generation|
While some provinces are reaching generation and environmental goals by closing down coal-fired generation and replacing it with natural gas and nuclear, others are embracing hydroelectric and nuclear generation to help boost capacity.
|As part of Ontario’s goal of ending coal-fired generation, 1,000 MW of generating capacity was closed at the Lambton coal-fired power plant in 2011. Courtesy: Ontario Power Generation|
Perhaps the most ambitious plan comes from the provincial government in Quebec, which on May 9 proposed a 25-year, C$80 billion ($83.9 billion) initiative to develop 3,500 MW of renewable energy as well as mineral resources in the northern part of the province.
Coal is a major resource in Manitoba and the northern areas of Ontario but not for too much longer in Ontario.
In June 2005, Ontario Premier Dalton McGuinty’s government proposed a plan to replace coal-fired generation with lesser emitting sources. The 1,400 MW Lakeview coal-fired power plant was closed the same year as a result of the plan.
In 2006, the government decided to shut down all coal-fired power plants in 2014 to keep the power system stable through its Long-Term Energy plan instead of closure goals that would have caused power grid instability in Ontario.
Coal-fired power plants that have been shut down include 1,000 MW each at the Lambton and Nanticoke plants in 2011. The Atikokan plant will be converted to biomass in 2013 and Thunder Bay will be converted to natural gas and possibly biomass by either 2013 or 2014.
So far, 70 percent of the province’s coal-fired generation has been closed, said JoAnne Butler, vice president of electricity resources with the Ontario Power Authority.
The coal-fired generation and resulting emissions have both dropped, said Amir Shalaby, vice president of power systems planning with OPA.
TransAlta, a major operator of wind in Canada, said in February 2011 it was interested in buying renewable power and other generating assets in Canada and the U.S. The company is phasing out coal-fired power units in Washington State and at the Sundance coal-fired power plant in Alberta, and has added 189 MW of new wind and a hydropower plant in British Columbia in 2010.
In the province of Saskatchewan, SaskPower is planning to rebuild Unit No. 3 of the Boundary Dam coal-fired power plant into a US$1.26 billion carbon capture and storage demonstration with enhanced oil field recovery. The 110 MW unit is expected to be completed by 2014.
In Alberta, a new report from the Brattle Group says simultaneous retirements of coal-fired power plants plus the end of several power purchase agreements in 2020 could have a negative impact on the province’s electricity market.
“Based on the scale and timing of PPA expirations and environmental mandates, these challenges are projected to increase the rate of generation retirements in Alberta by 50 percent over the next two decades,” said Brattle principal Johannes Pfeifenberger, a co-author of the study.
With an increase in demand expected over the next 20 years, the report said new generation will need to double to 740 MW per year.
Natural gas generation will be used mostly for peaking units in Ontario, the “dance partner” to nuclear and wind generation, said OPA’s Butler. OPA currently manages 7,935 MW of natural gas supply capacity.
Plants under contract range in size from 500 MW to more than 2,000 MW, Shalaby said. There are also two natural gas-fired power plants currently under construction, the 280 MW Greenfield South project in Mississauga and the 393 MW York Energy Centre in the Northern York Region.
Shalaby said natural gas will also be used in place of transmission in some areas.
“We will use gas to prop up reliability in regional areas that would otherwise need transmission,” Shalaby said. “It’s a reliability and sustainability move as well as a cost-saving move.”
In other areas, gas will help with the intermittency problems of wind and solar, Shalaby said. There is no set amount of natural gas that needs to be installed since it will mostly be used as a peaking source.
In Alberta, the 800 MW Shepard natural gas-fired power plant is under construction. The plant uses two 240 MW Mitsubishi M501G1 natural gas-fired turbine generators and one 320 MW steam turbine. The project is scheduled for completion in August 2015. Enmax Shepard Inc., a unit of Enmax Energy Corp. and the plant’s owners, awarded a contract to KBV, a joint venture between Kiewit Energy Canada Corp. and Black & Veatch Canada Co., to complete the plant.
Also in Alberta, the city of Medicine Hat broke ground on a solar energy steam generation system that will be integrated with an existing natural gas-fired power plant. Design on the $8.94 million is expected to begin in September 2011 and operating by August 2012. The demonstration plant uses concentrating solar thermal technology and will power the cities of Medicine Hat, Redcliff, Dunmore, Veinerville and outlying nearby rural areas. The Climate Change Emissions Management Corp. and the city of Medicine Hat each invested one-third of project costs.
Renewables and Transmission
Canada’s main energy source is hydroelectric, but wind, solar and biomass are growing in use. Geothermal is not considered a renewable energy source under the FIT program because experience with geothermal projects for electricity production is limited in the province. Therefore, OPA does not have any geothermal developments under contract. In British Columbia and Quebec, hydro generation meets about 90 percent of electricity demand
All six nuclear units at the Pickering Generating Station will be decommissioned by 2033. Courtesy: Ontario Power Generation
In 2010, Canada installed 690 MW of wind energy, according to a report from the Global Wind Energy Council. The installed capacity is valued at US$1.7 billion in new investments. As of March 2011, Canada’s total installed wind capacity was 4,285 MW, made up of 2,570 wind turbines at 131 wind farms.
The Canadian government also runs the ecoENERGY for Renewable Power Program, which was created in 2007. The 2010 federal budget, however, failed to include money for a production tax that supported wind energy, much to the “disappointment” of Robert Hornung, president of Canada Wind Energy Association (CanWEA).
“While we remain committed to working with the federal government to find ways to attract new investment in the world’s most rapidly growing source of electricity, we are shocked and disappointed that it has chosen not to extend a cost-effective program that facilitated record levels of investment and job creation in Canada’s wind energy sector,” Hornung said in a statement.
In May 2005, the feed-in tariff (FIT) program was designed to make financing and implementation of renewable projects easier for developments 10 kW and larger in Ontario. To date, the program has executed 1,200 large-scale contracts, representing about 2,600 MW of capacity, mostly from wind and ground-mount solar, Ontario Power Authority’s JoAnne Butler said.
Ontario’s Long-Term Energy plan calls for 10,700 MW of renewable energy in the province by 2018.
“Hydro is nearly there, and wind and solar we can see doubling as of today,” OPA’s Amir Shalaby said.
With the increase in renewable energy demand comes a need for more transmission. The biggest project in place is a transmission expansion from Bruce in northern Ontario, where it is wind-rich, to the town of Milton just west of Toronto, where demand is increasing, Shalaby said.
“That would free up load capacity and other transmissions that are smaller,” he said.
Plans also call for new and upgraded transmission lines to Pickle Lake, just north of Thunder Bay in northern Ontario, and new and upgraded lines west of London, Ontario.
Butler said the 2,600 MW of new renewable energy generation already in place is just the start.
“We are looking at some transmission expansion and that will enable more renewables,” Butler said.
A US$3.36 billion investment from the FIT program helped 40 large-scale solar, wind and hydro projects get off the ground. The projects were 35 solar projects totaling 357 MW, four wind projects with a total of 615 MW and one 500 kW water project.
The FIT program is set for a two-year review coming up in October.
“I think we’ll be constantly renewing the program and it will be tweaked,” Butler said.
“It was never meant to be a boom and bust program,” but was meant to be a long-term sustainable program to bring more green energy into the system. “There are a lot of rooftops out there,” Butler said.
Ontario also has a microFIT program for projects up to 10 kW in size, such as rooftop solar arrays and small-scale systems for businesses. OPA has executed 4,500 of those projects, representing 3,800 MW of generation capacity.
Along with renewable energy power plants, the FIT program helps to finance manufacturing jobs as well. One such project is a proposed solar wafer manufacturing facility owned by MEMC Electronics in Toronto. It will have an initial production capacity of 50 MW annually that can be ramped up to 200 MW per year.
OPA awarded 31 MW of solar photovoltaic projects to SunEdison in February 2011 as part of the Renewable Energy Standard Offer Program, which is aimed at smaller solar installations.
Butler said MEMC is not the only company looking to do business in Ontario.
“The government said there are 30 companies that have expressed an interest in coming in to set up the facilities, so the policy of bringing in the jobs is a government policy.”
The province is also looking into biomass and geothermal, but those types of developments are less abundant and more difficult to get in the ground.
“Forest harvesting practices are more complicated, they take longer and they tend to come in smaller chunks,” Shalaby said.
On May 9, the government of Quebec unveiled a plan to turn 1.2 million sq km of land into a major area of mining and renewable energy. The proposal, known as Plan Nord, involves a region north of the 49th parallel that is twice the size of France and covers more than 70 per cent of the province’s territory.
“It is one of the world’s last virgin territories,” said Quebec’s Premier Jean Charest, who announced the initiative.
The area contains deposits of nickel, cobalt, platinum, zinc, iron ore and rare earth minerals. The plan includes 11 new mining projects, development of 3,500 MW of renewable energy resources (mainly hydroelectric projects, but also some wind), sustainable forestry and a huge infrastructure program.
Plans also call for new roads, airports and even a deep sea port on James Bay to built to get the raw materials to world markets.
There are currently 18 operating nuclear reactors in three provinces—New Brunswick, Ontario and Quebec—that provide around 12,000 MWe of capacity, or 15 percent of the country’s total electricity generation.
In Ontario, half of the electricity is generated from nuclear. There are currently 14,000 MW of nuclear capacity in Ontario and by 2020 that number will be down to 10,000 MW, Shalaby said. Included in that generation are several refurbishment projects at Ontario Power Generation’s Darlington and Pickering stations and Bruce Power’s Bruce station.
The six units at the Pickering station are scheduled to be shut down by 2033 and replaced by natural gas. The Ontario government is looking to add 2,000 MW more capacity at the 3,524 MW Darlington station, where refurbishing of four reactors at the site is under way.
Refurbishing unit A1 at Pickering cost Ontario Power Generation, the plant’s owner, more than $1,600/kW, more than double the original estimate. Therefore, the government retired units A2 and A3 instead of refurbishing them. The two reactors in Pickering B are licensed until 2013. OPG will spend about $300 million to keep them operating for 10 more years before they are closed and decommissioned as well. The remaining units will be closed and decommissioned when the licenses expire in 2018 and 2022.
Bruce Power has already refurbished units 3 and 4 at the Bruce Generating Station and is working to return units 1 and 2 to service in 2011 through a complete rebuild of the reactors and upgrades of major components. The rebuild is expected to increase the life span for 25 years. So far, the units are over budget with an estimated cost of $4.8 billion. The original cost estimate in 2005 was $2.75 billion.
“If we are to remain at 50 percent like the Ontario Power Authority has said, then we will need to replace the Pickering units with other nuclear units,” said Organization of Candu Industries President Dr. Neil Alexander. This is where the additional 2,000 MW at the Darlington power plant come in to play.
Canada’s nuclear fleet is based on the Canada Deuterium Uranium (Candu) nuclear reactor. It can use recovered uranium and uses heavy water for both the coolant and the moderator, and uses natural uranium fuel and pressure tubes instead of single pressure vessels.
However, the calandria tubes are causing problems at the 635 MW Point Lepreau nuclear power plant in New Brunswick. A refurbishment project there is years behind schedule because of a problem with the seals on the calandria tubes. Previously, New Brunswick threatened to sue the federal government to cover cost overruns of approximately US$387 million to buy replacement power.
Atomic Energy Canada Limited (AECL), the maker of the Candu reactor, told New Brunswick Power in October 2010 that its workers had to remove and replace the 380 tubes because of problems with loose-fitting seals. The refurbishment project was expected to be done in 2009 and is now scheduled for completion in 2012.
“Although the calandria tube installation work sequence will take longer to complete than previously planned, it is essential that these activities achieve the required quality standard to provide safe and reliable operation for the next 25 to 30 years.” said Gaëtan Thomas, NB Power president and CEO, in a statement from both NB Power and AECL.
Quebec is also home to one nuclear reactor, the 675 MW Gentilly 2 nuclear generating station operated by Hydro-Quebec. In 2008, Hydro-Quebec decided to refurbish the plant to extend its operating life to 2035. That project was also delayed from 2011 until 2012 to benefit from lessons learned at Point Lepreau and a nuclear power plant in Korea.
While the refurbishment projects are continuing, the Canadian Nuclear Safety Commission established an operational task force to investigate the technical and regulatory implications of the nuclear disaster in Japan in relation to nuclear power plants in Canada.
The task force will recommend short- and long-term measures to address any significant gaps at the power plants and whether any design modifications are necessary. It will also determine if any changes need to be made to programs and policies for existing Candu and new nuclear power plants.
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