Nuclear Power in Canada
(Updated January 2016)
- About 15% of Canada's electricity comes from nuclear power, with 19 reactors mostly in Ontario providing 13.5 GWe of power capacity.
- Canada had plans to expand its nuclear capacity over the next decade by building two more new reactors, but these have been deferred.
- For many years Canada has been a leader in nuclear research and technology, exporting reactor systems developed in Canada as well as a high proportion of the world supply of radioisotopes used in medical diagnosis and cancer therapy.
Canada generated some 652 billion kWh in 2013, of which 102.8 billion kWh (15.8%) was from nuclear power, compared with 391.5 billion kWh (60%) from hydro, 63 billion kWh from coal and 67 billion kWh from gas. Annual electricity use is about 15,000 kWh per person, one of the highest levels in the world. Net exports in 2013 were 52 billion kWh, to the USA. Total generating capacity in 2012 was 134 GWe, more than half of this being hydro.
According to a study by the Canadian Energy Research Institute,1 Canada’s nuclear reactors contribute C$6.6 billion per year to GDP, create C$1.5 billion in government revenue and generate some $1.2 billion in exports. The nuclear power industry employs 21,000 directly, 10,000 indirectly as contractors and is responsible for another 40,000 jobs indirectly.
About C$13.26 billion (in 2005 dollars) was invested by the government in Canada's nuclear program over 1952-2006 through AECL. This investment has generated more than C$160 billion in GDP benefits to Canada from power production, research and development, Candu exports, uranium, medical radioisotopes and professional services, according to AECL.
Canada has developed its own line of nuclear power reactors, starting from research in 1944 when an engineering design team was brought together in Montreal, Quebec, to develop a heavy water moderated nuclear reactor. The National Research Experimental Reactor (NRX) began operation in 1947 at Chalk River, Ontario, where today the Chalk River Laboratories are the locus of much of Canada's nuclear research and development. The government established Atomic Energy of Canada Ltd (AECL) as a crown corporation in 1952 with a mandate to research and develop peaceful uses of nuclear energy. The National Research Universal (NRU) reactor was built at Chalk River in 1957. Today, NRU produces 40% of the world supply of molybdenum-99, the source of technetium-99 widely used for medical diagnosis, and cobalt-60 for cancer treatment. It is due to be shut down in March 2018, after a remarkable service life.
AECL, in cooperation with Canadian industry, began developing the first Candu (Canada deuterium uranium) reactor in the late 1950s. Candu reactors use heavy water (deuterium oxide) as a moderator and coolant, and are fueled using natural uranium (as opposed to enriched uranium). The advantages of the Candu reactor are savings in fuel cost, because the uranium does not have to go through the enrichment process, and reduced reactor downtime from refueling and maintenance. These savings are partially offset by the cost of producing heavy water. A small (22 MWe) Candu prototype went into operation in 1962 at Rolphton, Ontario, 30 km upstream from the Chalk River facilities. A larger prototype – 200 MWe – began generating power at Douglas Point, Ontario, in 1967. It was the design basis of the first Indian PHWR power reactors, Rawatbhata 1&2.
The first commercial Candu reactors began operations in Pickering, Ontario, in 1971. Sixteen of Canada's 18 commercial reactors are located in Ontario (the others are in Quebec and New Brunswick). In 2008, 53% of Ontario's electricity production came from nuclear power. The Darlington plant which came on line 1990-93 experienced a major cost overrun in construction largely due to political interference.
The technology and design of Candu reactors have evolved through several generations, with the newest reactors the Enhanced Candu 6 (EC6, based on Qinshan in China). The next-generation Advanced Candu Reactor (ACR-1000) was not fully developed.
Today, there are 31 Candu power reactors in seven countries, as well as 13 'Candu derivative' reactors in India, with more being built. Export sales of 12 Candu units have been made to South Korea (4), Romania (2), India (2), Pakistan (1), Argentina (1) and China (2), along with the engineering expertise to build and operate them. Three of the Canadian units are undergoing major refurbishment.
In mid-2011 AECL sold its reactor division to SNC-Lavalin's Candu Energy subsidiary for C$ 15 million, with the Canadian government retaining intellectual property rights for the CANDU reactors, in the hope of future royalties from new build and life extension projects "while reducing taxpayers' exposure to nuclear commercial risks". Candu Energy will pursue new business opportunities in connection with existing CANDU reactors worldwide and new build opportunities with EC6 models and the third-generation ACR-1000 design (since shelved). The government would contribute $75 million towards completing the EC6 development program. Candu Energy would complete the refurbishment projects at Bruce, Point Lepreau, and Wolsong through subcontract service agreements with the Canadian government. About 1200 employees transferred to Candu Energy.
As well as their use for electricity, Candu power reactors produce almost all the world's supply of the cobalt-60 radioisotope for medical and sterilization use.
Canada's nuclear operating power reactorsa
||Planned close, or licnce to
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
||Ontario Power Generation
|Point Lepreau 1* b
||New Brunswick Power
|Total operating (19)
To meet current and future electricity needs, provincial governments and power companies have made the decision to extend the operating life of a number of reactors by refurbishing them. Refurbishing Candu units consists of such steps as replacing fuel channels and steam generators and upgrading ancillary systems to current standards. While refurbishing usually takes less time and is less costly than building a new plant, there have been several cost overruns that in some cases have made it almost as expensive as new construction.
From 1995-98, the four Bruce A units and the four Pickering A units were laid up by the former Ontario Hydro. This followed a review commissioned by Ontario Power Generation which was critical of the company's management and recommended a phased approach to improvement which involved the closure of seven reactors (one was already shut down) pending refurbishment and a focus on the other 12 then operating (Bruce B, Pickering B and Darlington). Of these eight Pickering A and Bruce A reactors four have been refurbished and returned to service, two are undergoing that now, and two (at Pickering) were considered uneconomic to refurbish so will not be restarted.
The Pickering A – Bruce A saga is a cautionary tale (and classic industry case study) regarding what is now called knowledge management (KM). By the mid-1990s there was a divergence between drawings and modifications which had progressively been made, and also the company had not shared operating experience with the designer. Maintenance standards fell and costs rose. A detailed audit 1997-98 showed that the design basis was not being maintained and that 4000 additional staff would be required to correct the situation at all Ontario Hydro plants, so the two A plants (8 units) were shut down so that staff could focus on the 12 units not needing so much attention. From 2003, six of the eight A units were returned to service with design basis corrected, having been shut down for several years – a significant loss of asset base for the owners.
Full refurbishment of the later model Candu 6 units such as Point Lepreau includes replacement of all calandria tubes, steam generators and instrument and control systems. (This first project has gone over time and budget, but the second, at Wolsong 1 in Korea, benefited from the experience and the reactor is now back on line. The third was to be Gentilly 2, then Embalse in Argentina.)
The four Pickering A reactors were laid up in 1997. Pickering A1 and A4 have both been refurbished in recent years, extending their life expectancy to 2022 and 2018, respectively. The Pickering 1 refurbishment in 2004-05 cost its operator Ontario Power Generation (OPG) over US$1600/kWe, more than double the original estimate, which led the government to retire units 2&3 rather than refurbish them.
In February 2010, OPG decided against full refurbishment, but would spend C$ 200 million on a fuel channel life management project to keep them going for another ten years before finally closing and decommissioning them in 2020. CNSC renewed the single operating licence of all six reactors for five years in August 2013, subject to a whole-site probabilistic safety assessment focused on the B units 5-8. The design limit for these units is normally 210,000 equivalent full-power hours. In August 2014 CNSC extended the limit for unit 6 to 247,000 hours – by four years to about 2019. This will be the first Canadian reactor to clear the 210,000 hour limit.
In November 2015 a study was released assessing the potential of running the six units (3100 MWe) for a further four years from 2020 to 2024. In January 2016 the government approved OPG's plan for this, with two shutting down in 2022 and four in 2024. OPG is preparing a licence application accordingly.
Bruce Power was formed in 2001 as a Canadian company and it leases the Bruce site from Ontario Power Generation. It is the licensee for the plant. Over 90% of Bruce employees hold equity in the company.
Units 3 and 4 of Bruce A had been laid up early in 1998, and were returned to service in January 2004 and October 2003, respectively as an early priority of Bruce Power.
Facing an impending power shortage, the provincial government's Ontario Power Authority in October 2005 agreed with Bruce Power to refurbish its oldest Bruce A reactors, each with 769 MWe capacity (see Appendix 1: Ontario Energy Policy). Unit 2 had been laid up in 1995 due to a maintenance accident in which lead contaminated the core. Unit 1 was laid up along with the four Pickering A units at the end of 1997, to allow operational focus on newer plants. Their operational lifetimes were extended by 25 years. Refurbishment of units 1&2 followed units 3&4 being returned to service by 2004 and was completed in 2012.
About eight years after returning to service, unit 3 had a C$300 million upgrade over November 2011 to May 2012 to extend its operating lifetime by ten years, and unit 4 had a similar life-extending upgrade in 2012. Replacement of low-pressure turbines was completed following the reactor refurbishments, at a cost of over $200 million per unit.
UK-based AMEC managed Bruce A work. The whole project was expected to cost C$5.25 billion, with C$2.75 billion for units 1&2, C$1.15 billion for unit 3 and $1.35 billion for unit 4. Early in 2008, with C$2 billion spent, it was announced that the cost of unit 1&2 refurbishment would be about C$3 billion, which late in 2010 was increased to C$4.8 billion. The installation of new calandria tubes was completed in November 2010. In July 2012 unit 1 was authorized to restart, and it was grid-connected in September. Unit 2 started up in March 2012 and came back on line in October, after sorting out a generator problem. They returned to commercial operation by October and November 2012 respectively.
Bruce Power is paid for all electricity from Bruce A on the basis of a 6.3 cents/kWh current reference price capped for 25 years (cf 6.765 ¢/kWh average Ontario spot price in 2005, and 4.5 ¢/kWh floor price for Bruce B – units 5-8). The difference between the actual capital expenditure and $4.25 billion (apart from unit 4 refurbishment) is shared between the government and the investors. One of the partners in Bruce Power, Cameco (31.6%), said before commencement that while it strongly applauded the project it did not meet Cameco's investment criteria, so it received a $200 million payout of its interest in Bruce A. The other partners set up Bruce A Limited Partnership (BALP) to sublease Bruce A from Bruce Power and to pay for the project.
Decisions on the four Bruce B reactors were pending, though in July 2009 Bruce Power announced that it would focus on refurbishing these rather than building new plants at Bruce, the expected cost being about half that of new plants. Early in 2010 the company completed work to uprate the four units from 90% to 93% of original design capacity by modifying the fuel loading. From 2001 to 2015 Bruce Power spent about C$10 billion on the whole plant.
Effective at the end of December 2013, Cameco sold its 31.6% interest in Bruce Power LP (effectively Bruce B) to Borealis Infrastructure, one of its partners, for C$ 450 million. Borealis is a division of the Ontario Municipal Employees Retirement System (OMERS), doubling its share to 63.2%. TransCanada Corporation, the Power Workers' Union and the Society of Energy Professionals are other equity holders, and TransCanada is acquiring some of OMERS’ holding so that each have 48.5%.
Following the Ontario 2013 Long-Term Energy Plan, in December 2015 Bruce Power and the Independent Electricity System Operator (IESO)* agreed on long-term sales of 6300 MWe from Bruce, enabling a major refurbishment programme to extend operating lives of units 3-8 by up to 35 years. From 2016 Bruce Power will receive C$65.73/MWh for all output, adjusted according to consumer price index. The six reactor refurbishments are expected to cost C$8 billion (in 2014 C$) from 2020 to 2033 and include steam generator and calandria tube replacement. In addition, C$5 billion will be spent on other life-extension or ‘asset management’ work from 2016 to 2053, $2.3 billion of these sums before 2020.
* incorporating Ontario Power Authority
The refurbishment schedule is:
Unit 6: January 2020 for 48 months.
Unit 3: January 2022 for 54 months.
Unit 4: January 2025 for 36 months.
Unit 5: July 2026 for 36 months.
Unit 7: July 2028 for 36 months.
Unit 8: July 2030 for 36 months.
Bruce Power has contracted with BWXT Canada to design and manufacture 32 replacement steam generators for the Bruce B plant, for C$ 400-500 million.
Bruce Power will continue to provide approximately one-third of its output (2,400 MW) as flexible generation, allowing the province to permanently balance system needs in its post-coal environment. This is a feature that only the Bruce Power units can provide, and has been used frequently by the IESO since 2009.
These are Canada's newest Candu reactors and in November 2015 were licensed to 2025. Following detailed studies, OPG decided on full refurbishment starting about 2016 and consequent 30-year life extension. Detailed planning for this will include an environmental assessment, an integrated safety review and an integrated improvement plan that will define the scope, cost and schedule of the refurbishment project. The work will involve replacing fuel channels and upgrading ancillary systems to current standards as well as overhauling the turbine generators. In November 2015 OPG announced approval of a C$12.8 billion refurbishment project to 2026, about half the cost of replacing them, and 9% less than originally projected. The Ontario government approved the project in January 2016.
OPG plans to shut the reactors sequentially for 3.5 years each for refurbishment from 2016: unit 2 then, unit 1 in 2018, unit 3 in 2020 and unit 4 in 2021, so that no more than two are out of action at the same time. OPG awarded a C$ 600 million contract to a joint venture of SNC-Lavalin Nuclear and Aecon Construction for the project's planning phase, and in January 2016 a C$ 2.75 billion contract to them for re-tubing. CNSC has given environmental approval for the refurbishment, which will enable the units to continue operating for a further 25-30 years, although this would be subject to separate licensing approvals.
(The Darlington site was selected by the Ontario government as the location for the province's next nuclear generating facility, of up to 4800 MWe, but this plan is not proceeding beyond site studies and site preparation licensing. It is proposed to refurbish four Darlington and four Bruce B reactors instead.)
Point Lepreau 1
In mid-2005, the decision was made to refurbish New Brunswick Power's 635 MWe Point Lepreau reactor, which provides one quarter of the province's power. It was the first Candu-6 type in commercial operation and was the first Candu-6 reactor to undergo full refurbishment, including replacement of all calandria tubes as well as steam generators. The project is expected to extend the life of the reactor to 2034 or beyond, and provide a 25 MWe uprate. Work began in April 2008 and was originally estimated to be completed in September 2009 at a cost of C$1.4 billion including replacement power. However, the project ran some C$ 2 billion over budget and three times over schedule (54 instead of 18 months). In 2010 AECL decided to remove and reinstall all 380 calandria tubes in the reactor core because of problems with the seals obtained for initial installation during the project.
CNSC authorized fuel loading in March 2012, restart in July, and grid connection in October 2012, but it continued to operate at low capacity for some time. It was at full capacity late in 2013. The provincial government is aiming to recover the overrun cost from the federal government. Two new low-pressure turbine rotors will be installed at a future outage, replacing those damaged in transit in 2008.
There was a proposal to sell the unit for C$ 1.4 billion to Hydro Quebec, to be finalized after the reactor was back on line, but this was cancelled in March 2010c.
Hydro Quebec decided in August 2008 to similarly refurbish the 638 MWe Gentilly 2 as an alternative to closing it in 2012, thereby extending its operating life to about 2040. Most Quebec electricity is hydro, from the north of the province. Gentilly, close to the load centre, had particular importance for grid stability and it also provided energy security regardless of seasonal rainfall. The C$1.9 billion investment would have included construction of a radioactive waste management facility. It was planned to commence work in 2011, but in the light of considerable delays with the Point Lepreau rebuild, the work was deferred to 2012-13. In February 2009, GE Energy was awarded a contract worth more than $120 million to refurbish the turbine island. In 2011the plant operating licence was extended to 2016. However, in September 2012 the new provincial government decided to close the plant at the end of 2012 instead of refurbishing.
New reactor plans and proposals
There have been proposals to build several nuclear reactors to go into operation in the next decade, but these have been deferred or have lapsed. Two reactors are planned in Ontario, one was proposed in New Brunswick and one (or possibly four smaller reactors) were proposed in Alberta. Total capacity of the new reactors would have amounted to as much as 9 GWe.
Planned (2 Darlington) and proposed Canadian nuclear power reactorsd
||Darlington 5&6, Ontario
||2 x 750 or 1200
||EC6 or AP1000
|New Brunswick Power
|1 x 1100 approx
||Atmea1 or Kerena
|Bruce Power Alberta
||Peace River, Alberta
||ACR-1000, AP1000, EPR
In June 2006, the Ontario government implemented a 20-year energy plan, which envisaged maintaining existing nuclear generation capacity at 14,000 MWe (see Appendix 1: Ontario Energy Policy). Then the 2010 revision of the energy plan3 envisaged 12,000 MWe of nuclear capacity by 2030 out of a total installed capacity of around 41,000 MWe (2010 total capacity: 35,000 MWe). This level of nuclear capacity would account for 50% of Ontario's electricity supply. The 2010 energy plan projected $33 billion capital expenditure on new and refurbished nuclear capacity to 2030, the latter involving refurbishment of ten older reactors (4 at Darlington, 6 at Bruce). The plan called for an update in 2013, which in the light of reduced power demand deferred the new construction at Darlington due to reduced demand forecasts. The update also scaled back refurbishment plans for Bruce A and Darlington, and said that Pickering might be closed earlier than 2020. However, nuclear power was central in the Ontario plan to phase out all coal-fired generation in 2014, and is expected to contribute 42% of electricity in 2025. In 2014 it contributed 62% of the province’s power.
In August 2006, Bruce Power applied for a licence to prepare its 9.3 km2 Bruce site for construction of up to four new reactors as Bruce C. The Canadian Nuclear Safety Commission (CNSC) accepted the company's project description for 4,000 MWe in January 2007. Bruce Power submitted an environmental impact statement in September 2008, showing that up to four new reactors at Bruce C would have no significant environmental effect. The new units were envisaged as coming on line beginning in 2015. Six different reactor types were under consideration. However, in July 2009, the company announced that it would withdraw its site licence application and suspend its environmental assessment for Bruce C, and focus on refurbishment of Bruce A and B (a major task – see above).
In September 2006, Ontario Power Generation (OPG) applied for a licence to prepare its Darlington site for construction of up to four new nuclear power units. An updated application and the environmental impact statement were submitted in September 2009. An independent review panel appointed by the Environment Department and CNSC in 2009 concluded in August 2011 that the construction of up to four new reactors was unlikely to cause adverse environmental effects, and in May 2012 the environmental assessment was approved. A licence to prepare site was issued by CNSC in August 2012. This was revoked by a federal court in May 2014 due to concerns about nuclear waste, hazardous emissions and accidents, but CNSC is appealing the decision on the grounds that these are matters for the construction and operating licences. To keep the construction option open, OPG and the government will seek to maintain the licence.
In March 2008, Ontario's Minister of Energy invited companies to submit proposals to build two new nuclear reactors at Darlington or Bruce, or both. In June 2008, the Ontario government selected Darlington as the site for the two new nuclear reactors, to be operated by OPG and to come on line in 2018e. Three submissions were received by the February 2009 deadline – from Areva (US EPR), Westinghouse (AP1000) and AECL (ACR-1000). However, in June 2009, the provincial government announced that the procurement process was being stalled pending resolution of the future of AECLf. This brought the Canadian EC6 reactor into contention as the most likely design for Darlington 5 & 6. In June 2012 OPG signed agreements with Westinghouse and SNC-Lavalin/Candu Energy Inc. to prepare detailed construction plans, schedules and cost estimates for two potential nuclear reactors – EC6 and AP1000 types respectively – at Darlington. These were received in June 2013, but further decisions were put on hold when the Ontario government deferred plans for construction in November 2013. OPG paid the two companies up to C$ 26 million for the estimates.
In October 2008, Bruce Power announced it would conduct an environmental assessment for two new nuclear units in the Haldimand-Norfolk region of southern Ontario. The region is home to OPG's 4,096 MWe Nanticoke Generating Station, the largest coal-fired power plant in North America. The Nanticoke plant had been scheduled for closure under the provincial government's plan to phase out coal power, but after several delays, the planned closure date is now in 2014. Although both the Haldimand and Norfolk councils supported the Bruce Power proposal, as well as 80% of residents, according to an Ipsos-Reid poll, the Ontario government did not support it. In July 2009, Bruce Power withdrew its site licence application and suspended its environmental assessment.4
Following the financial crisis of 2007-08, Ontario’s power demand decreased by about 25 TWh annually, mainly due to industry cutbacks, and it has remained flat since. In 2014 the Nanticoke coal-fired power station closed, leaving Ontario’s electricity supply almost entirely from hydro and nuclear.
In 2007, the New Brunswick provincial government requested a feasibility study on building a second reactor at the Point Lepreau site. The 2008 study was conducted by the Team Candu consortium of AECL, GE Canada, Hitachi Canada, Babcock & Wilcox Canada and SNC-Lavalin Nuclear. (Team Candu was set up in 2006 to offer fixed price plants on a turnkey basis, and originally the 1085 MWe ACR-1000 was the intended technology, which would have been the first ACR-1000 plant in Canada.) In mid-2010, Areva signed a letter of intent with the government regarding it financing and building a merchant plant using Atmea (1100 MWe PWR) or Kerena (formerly the SWR-1000, a 1250 MWe BWR) technology. While government-owned NB Power would be licensee and operator, the plant would most likely be privately owned and financed rather than publicly financed from government debt. About half of the output would be likely to go to the northeastern USA. There is over 1300 MW interconnection to New England, and in 2007 it imported 12 TWh from New Brunswick. However, the proposal has lapsed.
Proposals have also been made for a third reactor in New Brunswick, mainly for the purpose of exporting power to New England.
Much of the interest in building nuclear reactors in Alberta centers on the extraction of oil from the province's extensive oilsands (tar sands) deposits. The current extraction process relies on energy from natural gas, which is costly and poses the additional problem of carbon emissions. Nuclear power is considered an economically attractive, low emission alternative for producing the steam and electricity the oil extraction process requires. (See Appendix 2: Alberta Tar Sands)
In 2005, Energy Alberta was established to build a nuclear plant in northern Alberta. In August 2007, Energy Alberta filed an application for a site preparation licence for one or two twin-unit ACR-1000 plants at a site in Peace River5. Soon after, the company agreed to be acquired by Bruce Power, which in March 2008 filed a new application for a licence to prepare site for up to 4000 MWe at the same site, Lac Cardinal.6 The main discussion centred upon building twin ACR-1000 reactors primarily for electricity rather than steam production. Most of the power would be supplied to the grid, but off-peak it could be used for hydrogen production (for oil refining).
In late 2008, Bruce Power identified a second site, Whitemud, and decided to withdraw the licence to prepare site application for Lac Cardinal while the company determined which of the two sites was the most viable7. Both sites are located about 30 km from the town of Peace River, 500 km northwest of Edmonton. In March 2009, Bruce Power announced that the Whitemud site had been selected and that an environmental assessment was expected to be launched in 20108. The project, known as the Peace Region Nuclear Power Plant Project, would involve the construction of up to four reactors to provide between 3200 and 4400 MWe of capacity. The designs under consideration were the EPR (two units), AP1000 (four units), and the ACR-1000 (two twin-units).
Alberta's nuclear consultation process in 2009 confirmed that nuclear technology could play a role in the province's future energy mix – the Government said nuclear power will be given the same consideration as all other energy options. In response, in late 2009, Bruce Power stated: "Any decision to proceed further will require us to take another look at the commercial case given the changing market conditions we have seen over the last 18 months."9 In December 2011 it shelved the project, ending a positive four-year engagement with the local people.
At the end of November 2008, a joint feasibility study by Bruce Power and SaskPower concluded that nuclear power could contribute at least 1,000 MWe capacity to Saskatchewan’s generation mix by 2020. The study identified a region spanning from Lloydminster, including the Battlefords and Prince Albert – generally referred to as the 'Prince Albert economic sub-region' – as the most viable host for a nuclear facility. The study also noted that growth in electricity demand in northeastern Alberta could provide a possible export market for Saskatchewan.10 SaskPower currently operates 3065 MWe of capacity, more than half of it coal-fired. The company has previously investigated the prospect of nuclear power and in 2007 suggested that a 360-750 MWe reactor size would be feasible if Alberta is included, or larger if it also included Manitoba.
In March 2009, the major Uranium Development Partnership report from a widely representative government-appointed panel recommended that Saskatchewan should move towards building nuclear power capacity.11 The report recommended maintaining a focus on uranium mining and exploration, since the province provides all of Canada's current uranium production. It specifically discouraged value adding in conversion and fuel fabrication, but said that up to 3,000 MWe of nuclear power capacity would be appropriate for the province, with major net economic benefit. Overall the panel said that its recommendations could increase the province's gross domestic product by an estimated C$50 billion and create 6,500 construction jobs and 5,500 long-term jobs. It also suggested working with Alberta to consider "a common power-generation solution for the two provinces by pooling their power needs." Subsidiary recommendations included building a research reactor and pursuing medical isotope production in partnership with the federal government, and getting involved with laser enrichment technology (Saskatoon-based Cameco has 24% of the main developer already).
A public consultation on the report then resulted the government supporting most of the recommendations but saying that it would not support Bruce Power's proposal or any immediate "addition of 1000 MWe as proposed from a single nuclear reactor", but SaskPower should keep the option open for the long term.12 However, the Energy and Resources Minister noted that "the large scale of the proposed nuclear power investment requires a regional approach involving, ideally, all three prairie-provinces for successful implementation," which is in line with the UDP recommendation.
New reactor designs
Since its inception in the late 1950s, the Candu reactor design has gone through several generations of evolution to improve fuel efficiency and flexibility, meet more stringent safety requirements and reduce costs and construction time.
Innovation has continued on the current Candu 6 design. Although it was later shelved, features from the Candu 9 design (about 900 MWe) have been incorporated into recent Candu 6 reactors. The Candu 9 design has flexible fuel requirements ranging from natural uranium through slightly-enriched uranium, recovered uranium from reprocessing spent PWR fuel, mixed uranium and plutonium oxide (MOX) fuel, direct use of spent PWR fuel, to thorium. The innovations in Candu 9, along with experience in building recent Korean and Chinese units, has gone into the Enhanced Candu-6 (EC6) – built as twin units – with a capacity increase to 750 MWe and flexible fuel options, plus 4.5-year construction and 60-year plant life (with mid-life pressure tube replacement). It is presented as a third-generation design.
The Enhanced Candu-6 (EC6) has now completed CNSC pre-licensing review. Initial design approval was granted in March 2010. The second phase of certification, intended to identify in greater detail any potential barriers to licensing the design, ran to 2012, and the third and final phase was completed in June 2013. This to a large extent clears the way for it to be built in Canada should a construction licence application be submitted, and will help its acceptance internationally, notably in Argentina, Romania and China.
The EC6 has been proposed by Candu Energy as a means of burning surplus plutonium in the UK. Up to four EC6 reactors could burn MOX fuel with about 2% plutonium (CANMOX).
The Advanced Candu Reactor (ACR) represents a further evolution in design. While retaining the low-pressure heavy water moderator, it incorporates some features of the pressurised water reactor. Adopting light water cooling and a more compact core reduces capital cost. It would run on slightly enriched uranium (about 1.5% U-235) with high burn-up, extending the fuel life by about three times and reducing high-level waste volumes accordingly. Attention became focused on the 1200 MWe ACR-1000. The modular construction means that major components can be built in US shipyards, using a high degree of standardisation of components. The ACR was designed to be built in pairs, with construction time estimated at 44 months for the first unit and 36 months for the fifth and subsequent units. The Canadian Nuclear Safety Commission (CNSC) gave pre-project design approval to the ACR-1000 in 2009, saying that it met the overall regulatory requirements and the expectations for new nuclear power plants in Canada and that there were no fundamental barriers to licensing it. However, the design has been shelved.
Beyond the ACR designs, AECL was also developing the Candu-X, a supercritical reactor that is a step forward from the ACR. It was expected to be available about 2020 but has been shelved.
The CNSC has also completed the second phase of preliminary design review of the Westinghouse AP1000, but Areva's EPR was put on hold by the vendor after its bid for Darlington was rejected in mid-2009. In February 2011 Areva and Mitsubishi Heavy Industries applied to CNSC for pre-licensing design review of their Atmea1 reactor, and the first phase has been completed. The Atmea1 has design certification in France and equivalent status in Argentina. Babcock & Wilcox's mPower small modular reactor is also undergoing the pre-licensing review process, with the first phase due to be completed late 2013.
Uranium mining in Canada is covered in the information page on Uranium Production in Canada.
Cameco's refinery at Blind River, Ontario takes uranium oxide concentrate (U3O8) from mines in Canada and abroad and refines it to UO3, an intermediate product.
The UO3 is trucked to Port Hope, Ontario where Cameco has about one quarter of the Western world's uranium hexafluoride (UF6) conversion capacity – 12,400 tU per year – and provides the only commercial supply of fuel-grade natural (unenriched) uranium dioxide (UO2). The uranium hexafluoride is enriched outside Canada for use in light water reactors, while natural UO2 is used to fabricate fuel bundles for Candu reactors in Canada and abroad. About 80% of the UO3 from Blind River is converted to UF6, while the remainder is refined to UO2.
Two fuel fabrication plants in Ontario process some 1,900 tonnes of uranium per year to UO2 fuel pellets, mainly for domestic Candu reactors. Between 15 and 20% of Canada's uranium production is consumed domestically.
Used fuel, waste storage and disposal
Canada's Nuclear Waste Management Organization (NWMO) was set up under the 2002 Nuclear Fuel Waste Act by the nuclear utilities operating in conjunction with AECL. Its mandate is to explore options for storage and disposal, to then make proposals to the government and to implement what is decided. NWMO, working with AECL, is also required to maintain trust funds for used fuel management and probable disposal. Less than 1500 tonnes of used fuel per year from Candu reactors is involved.
Used fuel, high-level waste
Used fuel bundles are stored in cooling ponds at each nuclear power plant for 5 to 10 years until they cool somewhat. They are then placed in large dry concrete and steel containers, thick enough to shield the radiation effectively. Until a permanent disposal repository for used nuclear fuel is built, nuclear power plant operators safely store this fuel under licence at their plant sites in these containers. There are three main types of dry storage units:
- Concrete canisters or silos, each holding 325 to 600 fuel bundles, vertical and above ground, at Point Lepreau.
- Modular air-cooled storage (MACSTOR) units, each holding 12,000 fuel bundles, above ground at Gentilly.
- Cylindrical containers made of reinforced concrete with steel shells inside and outside, holding 384 fuel bundles. They weigh 60 tonnes empty, 70 t full, are portable and filled with helium. Designed by OPG and used for Pickering, Bruce and Darlington.
For high-level wastes long-term, in 2005 NWMO published three conceptual designs for the technical options specified in the Nuclear Fuel Waste Act, based on proven technologies. The first, reactor site extended storage (at seven sites), was found to be feasible, requiring only some further dry storage facilities to be built. The second, centralised extended storage, is similar to systems already operating in 12 countries, but is longer term. A deep geological repository is the third possibility, allowing later retrieval if required. It is most closely aligned with international consensus and had already been the subject of detailed scrutiny by the federal Environment Assessment Panel over three years in the 1990s, involving public hearings. This option, known as adaptive phased management (APM), was the one recommended by NWMO and chosen by the government in June 2007. NWMO is now responsible for implementing it.
A deep geological repository involves burying nuclear waste 500 to 1000 metres deep in the stable rock of the Canadian Shield, the large formation that extends northward across central and eastern Canada. The waste would be placed below the water table in containers packed in bentonite clay. The waste may consist of used fuel bundles or solidified high-level waste from reprocessing, sealed in copper or titanium containers.
Early in 2007, NWMO stated that a final repository would probably be in Ontario, Quebec, New Brunswick or Saskatchewan, and host localities would need to volunteer for the role. The organisation designed a siting process and commenced technical and socio-economic assessment of potential candidate sites late in 2012.13 It expected within five years to narrow down 21 possibilities put forward by communities interested in hosting the repository to one or two. Of the 21, 15 are on the Canadian shield, 6 are sedimentary. The timeline will be determined by potential host communities, but NWMO expects to have a repository operating by 2035. At the end of 2013 four of the eight communities which had completed preliminary assessments moved on to more detailed studies by NWMO. These were Creighton in Saskatchewan, and Hornepayne, Ignace and Schreiber in Ontario, but Creighton and Schreiber were dropped due to geological complexity. At the end of 2014 NWMO announced that the focus had narrowed to two communities: the municipality of South Bruce, and the township of Huron-Kinloss in Bruce County, Ontario.
At the end of 2012 there was about 46,000 tonnes of used fuel in storage at reactor sites, and this was increasing at almost 1500 tonnes per year. NWMO said a repository would need about one square kilometre on the surface and about four times that underground. It estimated that the total cost of repository and transport system would be C$ 16-24 billion.
Canadian nuclear power plant operators make extensive use of dry cask storage – the Western Waste Management Facility provides dry fuel storage for the Bruce reactors. The Pickering Waste Management Facility provides dry fuel storage for the Pickering reactors. The Darlington Waste Management Facility provides dry fuel storage for the Darlington reactors.
Low- and intermediate-level waste
The nuclear utilities and AECL remain responsible for low- and intermediate-level wastes, which are currently stored above ground.
Following a strong positive response to polling of local residents, Ontario Power Generation (OPG) in 2005 proceeded with plans to construct a deep geologic repository for 200,000 cubic metres of its low- and intermediate-level wastes from three plants. The repository will be located 680 metres beneath OPG's Western Waste Management Facility on the Bruce site, which it has operated since 1974. In April 2011 OPG submitted its 12,500-page environmental assessment to CNSC. A federally-appointed review panel considered this and released a 457-page report approving it in May 2015. A final ministerial decision is expected in September. Financing for the repository project is provided from the decommissioning fund established under the Ontario Nuclear Funds Agreement.
OPG is the owner and licensee of the repository; however, NWMO was contracted to manage development of it from the beginning of 2009.
The Western Waste Management Facility stores all the low- and intermediate-level nuclear waste from the operation of OPG's 20 nuclear reactors, including those leased to Bruce Power.
In June 2006 the Canadian government announced a five-year, C$520 million programme to clean up legacy wastes from R&D on nuclear power and medical isotopes and military activities in the 1940s and early 1950s. The programme covered clean-up of AECL's contaminated lands, radioactive wastes and decommissioning old infrastructure which the government is responsible for. A large amount of low-level legacy waste from former radium and uranium refinery operations at Port Hope, Ontario, will be permanently emplaced in an above-ground repository.
In mid-2012, AECL began a comprehensive review of its nuclear liabilities through the Nuclear Legacy Liabilities Program (NLLP). The review is intended to reflect best practices in nuclear decommissioning and waste management of Canada's nuclear legacy, mainly comprising AECL's Chalk River Laboratories. The last such review was completed in 2005. In March 2013 AECL advised the government that its estimated liabilities for nuclear decommissioning and waste management had increased by two-thirds to C$6 billion. The main reason for the increased liabilities estimate was "an increase in the indirect costs attributed to the decommissioning and waste management over the period of up to 70 years of the program." The Chalk River Laboratories in Ontario account for about 70% of the liabilities, with 20% attributable to Whiteshell Laboratories and 10% to three decommissioned prototype reactors. The NLLP is a program to manage Canada's nuclear legacy liabilities at AECL sites that is funded through Natural Resources Canada (NRCan). It is based on a 70-year timeline, which started in 2006. Over time, activities will increasingly focus on designing, building and operating facilities for the safe and cost-effective management of waste.
Four power reactors have been shut down and are being decommissioned: the first three area Gentilly 1, Douglas Point and Rolphton NPD – all owned by AECL. They were shut down in 1977, 1984 and 1987 respectively and are expected to be demolished in about 30 years. Gentilly 1 was a steam-generating heavy water reactor with vertical pressure tubes, light water coolant and heavy water moderation. It was not successful, and had only about 180 full-power days in six years operation. The other two were prototype Candu designs.
The fourth unit is Gentilly 2, a more modern Candu 6 type, which was shut down at the end of 2012, after 30 years operation. It is being defueled and the heavy water will be treated over 18 months to mid 2014. The main part of the reactor will then be closed up and left for 40 years to allow radioactivity to decay before demolition. Decommissioning cost is put at C$ 1.8 billion over 50 years.
Research and development
Canada is a longtime leader in nuclear energy research and development. The Chalk River Laboratories in Ontario were set up by the government in the 1940s and have been the locus of much the world's successful R&D into the peaceful uses of nuclear energy. The 42 MWth National Research Experimental (NRX) reactor was built there in 1947, followed in 1957 by the 135 MWth National Research Universal (NRU) reactor, a world leader in the development and production of nuclear medical isotopes (see below). NRX was shut down in 1993.
The 60 MWt WR-1 research reactor was built by GE at Whiteshell Laboratories and started up in 1965. The original purpose of the unit was as a test reactor for a proposed organic-cooled CANDU power reactor. When that program ceased in 1972 it was used for other R&D until shut down in 1985. The reactor had vertical fuel channels cooled by organic liquid (an oil), moderation was by heavy water in a calandria vessel, and control was by varying the level of moderator. The organic coolant meant low operating pressure and very low corrosion rates for metallic fuel, with 425ºC outlet temperature.
In 1952, the federal government established Atomic Energy of Canada Ltd (AECL) with the responsibility for managing Canada's national nuclear R&D programme, including NRU. AECL has undertaken all the developmental work on the Candu reactor types. It later consisted of two divisions: the Nuclear Laboratories, and the CANDU Reactor Division, which in 2011 was sold to Candu Energy Inc. Candu Energy has taken over development of the third-generation Advanced Candu Reactor (ACR) but the Generation IV supercritical water-cooled reactor (SCWR – see page on Generation IV Nuclear Reactors) project remained with AECL. In 2012-13 AECL was reorganized so that R&D became contractor-operated under Canadian Nuclear Laboratories (CNL), centred at Chalk River, Ontario.
Five other research reactors were built and continue to operate on university campuses. Four of these are SLOWPOKE-2 units, low-energy pool-type reactors designed by AECL with passive cooling and safety systems. The other is MNR at McMaster University, a 3 MWt pool-type reactor. (Five other Slowpoke units are decommissioned.)
Two 10 MWth MAPLE (Multipurpose Applied Physics Lattice Experiment) reactors at Chalk River Laboratories were to replace most of the radioisotope production at the ageing NRU reactor. Intended to be the world's first reactors dedicated exclusively to medical isotope production, the reactors could have supplied the entire global demand for molybdenum-99, iodine-131, iodine-125 and xenon-133. The reactors were originally scheduled to start up in 2000. One unit went critical in 2000, the second in 2003, but commissioning encountered major technical problems and in May 2008 AECL decided to cancel the project after spending $680 million on them. 14, g In August 2013 AECL and Nordion settled on damages from the MAPLE cancellation.
The delay and eventual cancellation of the MAPLE reactors has led to the extended operation of the NRU research reactor. In December 2007, the Canadian Nuclear Safety Commission (CNSC) declined to allow the restart of NRU. A five-year licence renewal in mid 2006 had specified certain back-up modifications, which AECL had not fully implemented. Parliament then intervened and passed a bill authorising the restart. The government later made it clear that it was dissatisfied with both parties to the dispute, and the Chairman of AECL then resigned. The head of CNSC was relieved of her role soon afterwards, creating widespread concern about political interference in regulatory function. The modifications were completed early in February 2008.15
In May 2009, NRU was shut down again due to leakage of heavy water through corrosion. Repairing this was a major undertaking costing some $70 million, and the reactor did not come back on line until August 2010. Since it produces about 40% of the world's Mo-99 (for Tc-99m) this had a significant impact on supply of radioisotopes. AECL now hopes to run it until March 2018, and in 2011 it was relicensed until 2016, and in in 2015 further licence extension is pending. CNL says that it is assessing the business case for a new neutron source and is planning for a ‘neutron gap’. It plans to take full advantage of the remaining three years of NRU operations to maximize benefit from the reactor, and will continue operating the Canadian Neutron Beam Centre (CNBC) based on NRU.
While the MAPLE reactors were intended to take over medical isotope production from NRU, the neutron scattering research and Candu materials testing activities of NRU were to be replaced by the Canadian Neutron Facility (CNF). A few years ago, AECL saw the CNF as essential to both Candu R&D and materials science research, but little has been heard of it since about 2003.
In mid-2009 the Saskatchewan government proposed to the federal government that it should build a new 20 MWt research reactor – the Canadian Neutron Source – at the University of Saskatchewan. This would cost some C$ 500-750 million depending on how it was equipped, and the federal government was asked for 75% of this, plus 60% of operating costs. It would be optimized for Mo-99 production, mainly for export, to take over from NRU and produce 74 six-day TBq of Mo-99 per week (about one-sixth of global demand). The design is based on Australia’s Opal reactor, built by Invap of Argentina. To minimize cost it would exclude R&D on fuel for power generation. There is already a Slowpoke-II research reactor on the campus, operated by the Saskatchewan Research Council, and a synchrotron.
CNL’s Zero Energy Deuterium (ZED-2) reactor is a versatile tank type, heavy water moderated low-power research reactor that achieved first criticality in 1960. It is used for performing reactor physics measurements and fuel studies.
The government has an Isotope Technology Acceleration Program (ITAP) to promote R&D on non-reactor based isotope production, particularly through the Medical Isotope Program (MIP). However, a key finding of the Natural Resources Canada Expert Panel on Medical Isotope Production was that reactors represent the best primary option for producing Mo-99. Canada Light Source Inc (CLS) in Saskatoon is using a linear accelerator to bombard Mo-100 targets with X-rays, and has produced some Mo-99 for the MIP.
The Canadian Nuclear Safety Commission (CNSC) is responsible for regulating and enforcing strict safety standards at domestic nuclear facilities and charged with administering the country's safeguards agreement. It was set up in 2000 under the new Nuclear Safety & Control Act and subsequent regulations as successor to the Atomic Energy Control Board, which had served since 1946. The CNSC reports to parliament through the Minister of Natural Resources.
Canada's uranium is sold strictly for electrical power generation only, and international safeguards are in place to ensure this. Nuclear equipment and services are also for peaceful uses only. The CNSC assists the International Atomic Energy Agency (IAEA) by allowing access to Canadian nuclear facilities and arranging for the installation of safeguards equipment at the sites. It reports regularly to the IAEA on nuclear materials held in Canada. The CNSC also manages a program for research and development in support of IAEA safeguards, the Canadian Safeguards Support Programme.
Canada is a party to the Nuclear Non-Proliferation Treaty (NPT) as a non-nuclear weapons state. Its safeguards agreement under the NPT came into force in 1972 and the Additional Protocol in relation to this came into force in 2000. A bilateral safeguards agreement is required with each customer nation as a precondition of trade, placing additional requirements on them beyond those of the NPT and the IAEA. These are in place with long-standing customer countries and early in 2012 an agreement was signed with China. Canada is also a member of the Nuclear Suppliers Group.
Appendix 1: Ontario Energy Policy
Appendix 2: Alberta Tar Sands
Related information pages
Uranium Production in Canada
a. The four Pickering A reactors were laid up in 1997. Pickering A4 was restarted in 2003 and Pickering A1 in 2005. There are no plans to bring Pickering A2 and A3 back into service and these two units are not listed in the Table. Bruce A2 was taken out of service in 1995, A1 followed in 1997, and Bruce A3 and A4 in 1998. Bruce A3 and A4 were restarted in 2004 and 2003, respectively. Bruce A1 and A2 were restarted in 2012. Bruce B8 achieved a 3% uprate to about 822 MWe in March 2010, the last of the Bruce B units to do so through re-ordering the fuel bundles since 2004. The Bruce A units had been done prior to 2001. [Back]
b. Point Lepreau and Gentilly 2 are Candu-6 types (700 MWe class), as are those at Cernavoda, Wolsong and Qinshan. [Back]
c. In October 2009, the Premiers of New Brunswick and Quebec signed a memorandum of understanding where Hydro-Quebec would acquire the majority of New Brunswick Power's (NB Power's) generation assets, comprising seven hydroelectric stations (895 MWe), two diesel peaking units (499 MWe), the Point Lepreau nuclear power plant (635 MWe), and transmission rights associated with these assets. Hydro-Quebec was to make two payments totalling C$3.2 billion; the first (C$1.8 billion) in March 2010, and the second (C$1.4 billion) at the time of closing of the Point Lepreau transaction, which was to be when the refurbishment was completed (then expected around January 2011). As part of the deal, NB Power would have become a subsidiary of Hydro-Quebec.
As a result of a due diligence review, Hydro-Quebec requested amendments to the contract on the grounds that the Mactaquac hydroelectric station and Point Lepreau would incur substantially higher future costs than Hydro-Quebec initially believed. Following this request, in March 2010, New Brunswick Premier Shawn Graham called off the deal. [Back]
d. The Ontario proposals are taken as amounting to 4,000 MWe in total and the first two units at Bruce, plus two units at Darlington, are listed as 'planned' in the WNA reactor table. The other units in the table are categorised as 'proposed'. [Back]
e. When the government selected Darlington for new nuclear capacity, it affirmed the importance of privately-run Bruce Power and the need for it to contribute 6300 MWe of nuclear capacity, and maintaining this level of capacity beyond the present planned operating lifetime of Bruce B. A decision on refurbishing Bruce B (3290 MWe) is pending but highly probable, now that the alternative proposal to build four new reactors there as Bruce C has been shelved. [Back]
f. AECL was the only compliant bidder in the procurement process for two new units at Darlington, although AECL's bid price was higher than the provincial government was willing to accept. In May 2009, the federal government announced that it would sell AECL, leading to uncertainty over the procurement process. This uncertainty led the Ontario government in June 2009 to suspend the procurement process until the restructuring of AECL is finalized. The environmental assessment and application for a licence to prepare site processes remain in progress. [Back]
g. South Korea (KAERI) has built a 30 MWt version of MAPLE – Hanaro – which started up in 1995 and is operating successfully. MAPLE had also been shortlisted for Australia's 20 MWt replacement research reactor in 1999. [Back]
1. Canadian Energy Research Institute, The Canadian Nuclear Industry: Contributions to the Canadian Economy, Final Report, Prepared for the Canadian Nuclear Association (June 2008) [Back]
2. Point Lepreau Generating Station Refurbishment Project Update, New Brunswick Power press release (14 October 2010) [Back]
3. Ontario’s Long-Term Energy Plan: Building Our Clean Energy Future, Ontario Ministry of Energy (2010) [Back]
4. Smitherman rejects Nanticoke nuclear plant plan, Toronto Star (31 October 2008); Nanticoke a potential nuclear site, World Nuclear News (31 October 2008) [Back]
5. Energy Alberta files Candu site application, World Nuclear News (28 August 2007) [Back]
6. Bruce Power Alberta Completes Purchase of Energy Alberta Corp., Bruce Power press release (13 March 2008); Bruce Power to prepare Alberta site, World Nuclear News (14 March 2008) [Back]
7. Withdrawal of Application for Approval to Prepare a Site for the Future Construction of a Nuclear Power Generating Facility Municipal District of Northern Lights, Alberta, letter from Bruce Power to the Canadian Nuclear Safety Commission (6 January 2009) [Back]
8. Bruce Power Alberta Narrows Focus to Whitemud Site, Bruce Power press release (23 March 2009) [Back]
9. Bruce Power Responds to Alberta Nuclear Consultation Results, Bruce Power press release (14 December 2009) [Back]
10. Saskatchewan 2020 - Clean energy. New opportunity. Report on Bruce Power’s Feasibility Study, Bruce Power (November 2008) [Back]
11. Capturing the full potential of the uranium value chain in Saskatchewan, Uranium Development Partnership (31 March 2009) [Back]
12. The Government’s Strategic Direction on Uranium Development, Government of Saskatchewan (December 2009). See also Government of Saskatchewan news release, Government Announces Strategic Direction on Uranium Development (17 December 2009) [Back]
13. Implementing Adaptive Phased Management - 2009 to 2013, Nuclear Waste Management Organization (January 2009) [Back]
14. AECL halts development of MAPLE project, World Nuclear News (19 May 2008) [Back]
15. Isotope producer is to restart amid controversy, World Nuclear News (12 December 2007); Fallout from isotope crisis hits top regulator, World Nuclear News (16 January 2008) [Back]
The Canadian Neutron Source: Strengthening Canada’s Isotope Supply and R&D Capacity, Florizone, R & Chapman, D, 2010, Physics in Canada 66,1
The Canadian Nuclear Industry and its Economic Contributions webpage on the Natural Resources Canada website (www.nrcan.gc.ca)
The Canadian Nuclear Industry: Contributions to the Canadian Economy, Canadian Energy Research Institute (June 2008)
Canadian Nuclear Association (www.cna.ca)
Darlington New Build project overview page on the nuclear section of Ontario Power Generation's website (www.opg.com/power/nuclear).