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Canada's Uranium Production & Nuclear Power

(November 2008)

• Canada produces about one third of the world's uranium mine output, much of it from two new mines.
• After 2011 Canadian production is expected to increase further as more new mines come into production. 
• About 16% of Canada's electricity comes from nuclear power, using indigenous technology. 18 reactors provide over 12,600 MWe of power. 
• New nuclear capacity is proposed in three provinces.

Canada generates about 616 billion kWh per year and has a high per capita use of this power - about 15,800 kWh/yr.  Nuclear power in 2006 contributed about 15.6% of this power, compared with 58% from hydro, 16% from coal and 6% from gas.

Uranium mining and exploration

Uranium exploration in Canada began in earnest in 1942 and accelerated in 1947, resulting in significant discoveries both near Elliott Lake, Ontario and in northern Saskatchewan. By 1959, 23 mines with 19 treatment plants were in operation in five districts and uranium exports of C$ 330 million exceeded the value for every other mineral. 

A new burst of exploration in the 1970s resulted in major discoveries in northern Saskatchewan's Athabasca Basin.  Rabbit Lake, Cluff Lake and Key Lake mines started up in 1975, 1980 and 1983 respectively.  Cameco Corporation was formed by merger in 1988.

Canada has developed its own line of nuclear power reactors, starting from research in 1944 and with the first CANDU power reactor coming on line in 1962.  Nuclear power provides about 16% of the country's electricity - and about 50% in Ontario.  Hydro provides about 60% nationally.  Canadian electricity use is over 17,000 kWh per person, one of the highest levels in the world.

Nuclear energy contributes some $5 billion per year to the Canadian economy and provides 20,000 direct jobs (2000 in mining and uranium processing) and many more indirect jobs.  The total nuclear electricity generated has a value of about C$ 3.7 billion per year and helps Canada minimise emissions from electric power generation.

Total exports of Canadian nuclear goods and services was some C$ 1.2 billion in 2001.  Almost $500 million of this was uranium, but $350 million for reactor fuel, radioisotopes and heavy water emphasise the value-added component and the market for products capable of being produced in such countries.  Reactor hardware, notably CANDU reactors, adds to this when sales are made.

About C$ 6-billion was invested 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. A study by the Canadian Energy Research Institute found that the nuclear industry contributes about $6 billion annually to Canada's GDP, while government R&D investment in it is about $130 million.

Canada became the 18th member of the Global Nuclear Energy Partnership (GNEP) in November 2007. 

Uranium resources

Canada is the world's largest producer of uranium. In 2004 production at 13,676 tonnes of uranium oxide concentrate (11,597 tonnes U) was about 30% of total world production. Its value was about C$ 800 million.

Canada's known uranium resources (Reasonably Assured Resources plus Inferred Resources to US$ 130/kgU) are 524,000 tonnes of U₃O₈ (444,000 tU, 9% of world total), compared with Australia's reserves of 2.5 times that.

Some $539 million was spent on U exploration in Canada 1986-97 (over twice as much as Australia's $226 million) and this led to a sharp increase in recoverable resources to 507,000 tonnes U₃O₈ (measured, indicated & inferred resources). Despite depletion from mining, this remains much the same. Of the total at 1/1/04, 297,000 tonnes (252,000 tU) was "measured", possibly equivalent to "proven reserves" in some of the company data quoted on p3 below.

Exploration expenditure in 2004 was C$ 44 million, mostly at established projects. However, the C$26 million of this on grassroots exploration in Saskatchewan - double the 2003 level - represented a major proportion of world uranium exploration.

Canada and Australia are the main countries able to expand production strongly as required to meet increases in world uranium demand.

Uranium Production

Canada has almost completed a transition from second-generation uranium mines (started 1975-83) to new high-grade ones, all in northern Saskatchewan. A brief history of Canadian uranium mining is appended.

Cameco operates the McArthur River mine - the world's largest uranium mine, which started production at the end of 1999. Its ore is milled at Key Lake, which once contributed 15% of world uranium production but is now mined out. Its other former mainstay is Rabbit Lake, which still has some reserves at Eagle Point, where mining resumed in mid 2002 after a three-year break. Production is expected progressively to diminish from 2007.

Areva Resources, (formerly Cogema Resources), operates the McClean Lake mine, which started production in mid 1999. Its Cluff Lake mine has now closed, and is being decommissioned. Areva has ISO 14001 environmental certification on all its mines worldwide.

Canadian Uranium Mine Production 

Canadian Uranium Mine Production 

* from WNA Market Report

The Saskatchewan government actively encourages and supports uranium mining in the Province where it is found to be environmentally acceptable. This reversed a previous policy of the New Democratic Party in the early 1990s to phase out uranium mining. The Government recognised that the jobs brought to the provincial economy by uranium mining were too important to be eliminated by doctrinaire considerations and that the environmental impact of mining could be minimised. Both McClean Lake and McArthur River mines now have ISO 14001 environmental certification.

In 1991 a Joint federal-Saskatchewan Panel was formed to study the health, safety, environment and socio-economic impact particularly of the four proposed uranium mining developments. It held public hearings on three proposals in 1996: Cigar Lake, McArthur River and Midwest.

The McClean Lake mine commenced operation in mid 1999. It was producing about 2500 t/yr U₃O₈ (2120 tU) from 2.4% ore but has been relicensed for 3640 t/yr. It has new plant and other infrastructure and uses the first mined-out pit for tailings disposal (the ore having been stockpiled). Production in 2006 was well down due to lower grades. Expansion of the mill to prepare for Cigar Lake ore will be complete in 2007. McClean Lake involves three open pits and later will become an underground mine. It is owned by Areva Resources (70%, also operator), in joint venture with Denison Energy (22.5%) and OURD (7.5%).

McArthur River has enormous high-grade (23%) reserves at a depth of c 600 metres.  It opened at the end of 1999.  Remote-control raise-boring methods are used for mining and the ore is trucked 80 km south to the modified Key Lake mill, where it is blended with "special waste rock" to produce 8500 t/yr of U3O8.  Mining is constrained by licensed capacity, and a planned increase to 10,000 t/yr is under review by government agencies and expected to be implemented in 2009. Tailings are deposited in a mined-out pit.  Cameco is the operator and majority owner, with Areva (30.2%) as partner.  The Key Lake mill, originally Cameco's, is 83% owned by Cameco, 17% by Areva.

Future Mines

There are further new uranium projects coming into production in the next few years in N. Saskatchewan:

Cigar Lake will be a 450 m deep underground mine in poor ground conditions, using ground freezing and high-pressure water jets for excavation of ore. High-grade ore slurry from remote mining will be trucked for toll treatment at Areva's expanded McClean Lake mill, 70 km northeast, for the first two years. The average feed grade will be 20.7% U₃O₈. Then, as production approaches full capacity, about half of the uranium solution from milling will go to Cameco's Rabbit Lake mill 70 km east. From both mills total production is expected to be 8200 t/yr U₃O₈ (7000 tU/yr) ramping up to this over three years from production start in 2011.  Proven and probable ore reserves are 176,700 tonnes U₃O₈ at over 24% average grade, and with other resources the mine is expected to have a life of 30-40 years.

Construction of the project began early in 2005. The McClean Lake mill has been modified to take the new ore, the Rabbit Lake mill will be modified by 2010. Some 1.3 million cubic metres of waste rock from Cigar Lake will be emplaced under water in the Sue C pit at McClean Lake. Tailings will remain at Mclean Lake and Rabbit Lake.

However, a major flood in October 2006 set the project back some years to about 2011 and increased the total mine cost (including mill modification) from C$ 660 to more than C$ 1 billion, with extra requirements for pumping capacity (to 2300 m³/hour) and refrigeration becoming evident.  During dewatering in August 2008 a further major inflow set back the remediation and mine development.

The full construction licence was issued in December 2004 and construction of the C$ 520 million project began early in 2005. The McClean Lake mill is being modified in 2005-06 to take the new ore. Some 1.3 million cubic metres of waste rock from Cigar Lake will be emplaced under water in the Sue C pit at McClean Lake. The joint venture is managed by Cameco which holds 50%, other parties being Areva 37%, Idemitsu 8% and TEPCO 5%.

Areva's Midwest mine mine was to be underground, utilising ground freezing and water jet boring, but is now proposed as a very large open pit, to depth of 215 metres.  The ore will be milled at McClean Lake nearby, to produce 2600 t/yr U3O8 over seven years.  Government approval received in 1998 enabled application for CNSC construction and operating licences.  A comprehensive multi-agency environmental assessment began in 2006, including new mine, 15 km haul road to McClean Lake mill, and expansion of the mill.  Approval is expected in 2009, allowing production from 2011.  In the light of this in December 2007 Areva announced a decision to proceed with the development, now costed at $435 million.    Mining will commence early in 2010 and ore removal to stockpile will be 2011-13.  The Midwest project is managed by Areva Resources Canada (holding 69.16%), with Denison Energy (25.17%) & OURD Canada (5.67%).  A further prospect, Midwest A is 3km north of the mine and is being evaluated.

The small Dawn Lake deposit is further from development. Grades up to 30% U₃O₈ at depths of 280 m have been reported nearby. Cameco has 58%, Areva 23%, and PNC 19%.

Informationon Cameco's and Areva's uranium mines and new developments is on the web.

With Cigar Lake and Midwest operating, Areva's McClean Lake mill will produce over 9,000 tonnes/yr U₃O₈ (7600 tU), while Cameco's Key Lake mill will produce 8200 t (7000 tU) and Rabbit Lake mill probably about 4000 t (3400 tU), assuming half of the Cigar Lake ore is milled there instead of at McClean Lake mill.

Exploration prospects 

Cameco's Millennium deposit (Cameco 43%) in northern Saskatchewan has indicated resources of 21,000 tonnes U3O8 at 4.5% and 4400 t of  inferred resources at 2.1% grade (NI 43-101 compliant).  A feasibility study on the project is under way.

Areva's Shea Creek project in northern Saskatchewan, 15 km south of its now closed Cluff Lake mine is the subject of intensive exploration effort, with very high grade intersections reported. A 900 metre deep shaft is being sunk to give better access to the mineralization. UEX Corporation has a 49% share in the venture, having spent some $30 million on exploration there.  Cameco holds 21.5% of UEX.

UEX also has the Hidden Bay project in eastern Athabasca basin.  The Horseshoe uranium deposit there has NI 43-101 indicated resources of 8500 tonnes U₃O₈ at a grade of 0.237%.

Further uranium exploration is concentrated in northern Saskatchewan, but there are also promising prospects in Labrador and Nunavut.

The main Labrador project centres on the Michelin deposit being drilled in a $21 million program by Aurora Energy Resources (46.8% Fronteer Development) and proposed for development from 2010. Aurora has defined measured and indicated resources of 30,000 tonnes U₃O₈ in the area with inferred resources of 16,000 tonnes.  The Michelin project includes the adjacent Jacques Lake deposit.  However, a three year moratorium on mining to April 2011 will delay this project and others on Nunavut lands in Labrador.

The main Nunavut prospect is Kiggavik, a large low-grade deposit in the Thelon Basin, 80 km west of Baker Lake, discovered by Urangesellshaft in the 1980s. The two parts of the project are operated by Areva Resources Canada Inc.: Sissons is held 50% by Areva in joint venture with JCU (Canada) Exploration Co. Ltd. (48%) and Daewoo Corporation (2%), and Kiggavik itself is held 99% by Areva and 1% by Daewoo.  The estimated resource comprises some 57,000 tonnes of uranium (tU) grading about 0.24%.  The indigenous Inuit organization Nunavut Tunngavic Inc supports uranium mining and exploration.  In December 2007 the three JV partners decided to proceed with a two-year feasibility study and to commence the regulatory process for a Kiggavik mine and mill complex which could start up in 2015.

Ontario's Elliot Lake area, which was the centre of Canada's uranium mining in the 1950s, producing some 120,000 tonnes of U₃O₈ tapering out to 1996, is again attracting exploration interest. Pele Mountain Resources Inc is examining the feasibility of a 375t/yr mine at Elliot Lake to access 19,000 tonnes of inferred resources at 0.33% grade.

In Quebec Azimut Exploration has committed $42 million to uranium exploration, centred on the Kativic project in the northern Nunavik region and Uracan Resources reports 9000 t U3O8 as NI 43-101 compliant inferred resource for its North Shore prospect, eastern Quebec.

In Nova Scotia exploration is proposed at Millet Brook, where a legislated moratorium applied to uranium exploration in the province since 1982 may be reviewed.

The Blizzard prospect south of Kelowna in British Columbia, revived from the 1980s has also been in the news, but in April 2008 a moratorium on uranium exploration was renewed in the province. 
Cameco spent C$ 32 million on exploration globally in 2006 and planned to spend $45 million in 2007.  This is mainly in Saskatchewan, Nunavut and Northwest Territories, Australia and Mongolia.

Late in 2007 Cameco signed an agreement with Russia's AtomRedMetZoloto (ARMZ) to create joint venture companies to explore for and mine uranium in both Russia and Canada, starting with identified deposits in northwestern Russia as well as Saskatchewan and Nunavut.

Canadian Uranium Resources 

* % U₃O₈. NB: these figures are from recent company sources (Cameco Dec 2006) and are not directly comparable with those (RAR) in the first part of the paper.
Cameco resources do not include reserves and are reported in accordance with Canadian standard NI-43-101.

Other Fuel Cycle Activities

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 worldÕs 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 1900 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.

Nuclear Power generation

In 1944, an engineering design team was brought together in Montreal, Quebec, to develop a heavy water moderated nuclear reactor. The National Research Experimental reactor (NRX) was built at Chalk River, Ontario, and started up in 1947. It provided the basis for Canada's development of the very successful CANDU series of pressurised heavy water reactors (PHWR) for power generation, and served as one of the most valuable research reactors in the world.

In 1955 Atomic Energy of Canada Ltd (AECL) with others committed to build the small (22 MWe) prototype NPD reactor at Rolphton, Ontario. It started up in 1962. A larger prototype - 200 MWe - was built at Douglas Point, Ontario and started up in 1967. It was the design basis of the first Indian PHWR power reactors, Rawatbhata 1 & 2. Then the 250 MWe Gentilly-1 prototype started up in 1971 in Quebec, but only ran for six years.

The CANDU nuclear reactor system was developed by AECL and Canadian industry. The CANDU (CANada Deuterium Uranium) is generically a pressurised heavy water reactor. The key to the success of the system is its simplicity, its use of natural uranium (as UO₂) as a fuel, and the ability to refuel without shutting down. The reactors use heavy water under pressure as a coolant, as well as using heavy water as a moderator.

The use of heavy water means that an ancillary industry is needed to produce it, corresponding to the rather more capital-intensive enrichment services required by other reactor types.

The major commercial utilisation of the CANDU system has been in Ontario, which has benefited from this electricity source since the early 1970s. In Ontario, 16 commercial nuclear reactors operate at three locations, providing 51% of the province's electricity in 2005. They, with a further four older ones now being refurbished or closed, were producing two thirds of the Province's electricity in early 1990s.

Canada's nuclear power reactors

The Darlington plant which came on line 1990-93 experienced a major cost overrun in construction largely due to political interference.

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.

Renewal, refurbishment and new build

Two previously laid-up Pickering A units have been refurbished, extending their lives to 2018 and 2022, two have been retired permanently. The Pickering 1 refurbishment over 2004-05 cost Ontario Power Generation (OPG) over US$ 1600/kW - more than double the original estimate, and the government then decided against reviving units 2 & 3 there because it would be uneconomic.  Pickering B is licenced to mid 2013, and a decision on refurbishment is pending.  This might take them to 2060.

Facing an impending power shortage, the Ontario government in October 2005 agreed with Bruce Power to refurbish its four oldest reactors - collectively known as Bruce A, each 769 MWe - rather than the longer process of building new ones to replace them.

Bruce A 1 & 2 started commercial operation in 1977. Unit 2 was shut down in 1995 due to a maintenance accident in which lead contaminated the core. Unit 1 was laid up with another six units at the end of 1997 to allow operational focus on newer plants. Both are now having their fuel channels and 16 steam generators replaced and ancillary systems upgraded to current standards, giving them a further 25-year life from 2009-10 when they restart. Units 3 & 4 will then have their fuel channels and steam generators replaced by 2012, giving them another 25 years operation. It had been planned to shut down unit 4 at the end of 2017, but with the other work running on time and within budget, plans for refurbishment of it were announced in 2007, at an extra cost of $1 billion.

UK-based AMEC is managing Bruce A work.  The whole Bruce A project was expected to cost C$ 5.25 billion - C$ 2.75 billion for units 1 & 2, $1.15 billion for unit 3 refurbishment and $1.35 billion for unit 4.  The cost (some US$ 1500/kW) approaches the cost of new plant.  Early in 2008, with $2 billion spent, it was announced that the cost of unit 1 & 2 refurbishment would be about $3 billion and in April this was increased to $3.1 to 3.4 billion.

Bruce Power will be 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 c/kWh average Ontario spot price in 2005, and 4.5 c/kWh floor price for Bruce B - units 5-8). If the capital expenditure is over or under the $4.25 billion (apart from unit 4 refurbishment), the difference will be shared between the government and the investors.

One of the partners in Bruce Power - Cameco, holding 31.6% - said that while it strongly applauded the project it did not meet Cameco's investment criteria, so it receives a $200 million payout of its interest in Bruce A. The other partners will set up Bruce A Limited Partnership (BALP) to sublease Bruce A from Bruce Power and to pay for the project.

A decision on refurbishing Pickering B (2064 MWe) will be made in 2008 and the work done over 2013-16.  Decisions on Bruce B (3260 MWe net, to be undertaken about 2014) and Darlington (3524 MWe) will be made thereafter.

Single unit CANDU-6 reactors also operate in New Brunswick and Quebec.

In mid 2005 a decision was taken to refurbish New Brunswick's 635 MWe Point Lepreau reactor which provides one quarter of the province's power.  The cost of C$ 1.4 billion includes replacement power.  It will be the first CANDU-6 type to undergo full refurbishment, from March 2008 to be completed in September 2009, extending its life to 2034 and providing a 25 MWe uprate. 

Hydro Quebec decided in August 2008 to refurbish the 638 MWe Gentilly-2 as an alternative to closing it about 2011.  Most Quebec electricity is hydro, from the north of the province.  Gentilly, close to the load centre, has particular importance for grid stability and it also provides energy security regardless of seasonal rainfall.  The $1.9 billion investment includes construction of a radioactive waste management facility.  The work will be undertaken 2011-12.

Planned and proposed Canadian Nuclear Power Reactors

The Ontario proposals are taken as amounting to 4000 MWe total and the first two of these units plus New Brunswick are listed as 'planned' in WNA Reactor table.  A further four in Ontario plus two in Alberta are "proposed".

New Build in Ontario:

In August 2006 Bruce Power applied for a licence to prepare its site for construction of up to four new reactors. It had been studying the feasibility of this on its 9.3 sq km site for more than two years. The Canadian Nuclear Safety Commission accepted the company's project description for 4000 MWe at the end of January 2007. In order to expedite its environmental assessment it recommended to the federal Environment Minister that the project go straight to a public review panel rather than first negotiating an eight-month process to determine if such a panel is necessary. Bruce Power submitted its environmental impact statement to the government in September 2008, showing that up to four new reactors would have no significant environmental effect. New plants are envisaged as coming on line from 2014 after four years construction (though OPA assumes 2018). Six different reactor types are under consideration, with a decision to be made in 2008.

In September 2006 OPG followed suit and applied for a licence to prepare its Darlington site for construction of up to four new nuclear power units. The Canadian Nuclear Safety Commission (CNSC) will review the applications and decide what level of environmental assessment is required. If the licences are granted, environmental studies taking up to three years will follow, along with assessment of possible reactor designs other than CANDU.

In March 2008 Ontario's minister of energy invited four companies to submit proposals to build two new nuclear reactors at Darlington or Bruce or both: AREVA, AECL and Westinghouse. GE Hitachi Nuclear Energy was also invited but withdrew.  However, it remains a member of the Team Candu consortium (see below) supporting the AECL bid.  The bids will be assessed by Infrastructure Ontario and include representatives from the Energy and Finance ministries, Bruce Power and Ontario Power Generation. A total of 2000 to 3500 MWe is envisaged.

In June 2008 The Ontario government selected Darlington as the site for two large new nuclear reactors operated by OPG to come on line in 2018. A decision will be made early in 2009 among the three reactor vendors invited to tender - AECL, Westinghouse and Areva on the basis of lifetime cost of power, schedule, and investment in Ontario.  The government affirmed the importance of privately-run Bruce Power and the need for it to contribute 6300 MWe of nuclear capacity either through refurbishment or new build.  A decision on refurbishing Bruce B (3260 MWe) is pending, as is an alternative proposal to build four new reactors there as Bruce C.

See later section on Ontario Energy Policy.

New Build in New Brunswick:  

In 2007 the New Brunswick provincial government decided to undertake a feasibility study of building a second reactor at the Point Lepreau site, and since then proposals have been made for a third, primarily with a view to exporting power to US New England states.  The feasibility study is evaluating a 1085 MWe ACR-1000 unit with a life of 60 years.  It is being undertaken by the Team Candu consortium of AECL, GE-Hitachi Nuclear, Hitachi Canada, Babcock & Wilcox and SNC-Lavalin Nuclear.  A parallel viability study commissioned from MZ Consulting by the provincial government shows that a second nuclear power reactor at Point Lepreau would be viable under likely conditions, including major power export to northeastern USA. 

If approved, it would be the first Canadian ACR-1000 plant built.  Team Candu was set up in 2006 to offer fixed-price plants on a turnkey basis.  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.

New Build in Alberta and Saskatchewan:

The current Alberta proposal by Bruce Power Alberta is for up to 4000 MWe of nuclear capacity at Peace River, 500 km northwesst of Edmonton, costing up to $10 billion.  The main discussion has centred upon building 2200 MWe with twin ACR-1000 reactors primarily for electricity rather than steam production (see later section on Alberta Tar Sands).  Energy Alberta Corp. earlier applied to the Canadian Nuclear Safety Commission for a site licence for a C$ 6.2 billion 2200 MWe plant but this is now 4000 MWe with technology choice open and aiming for 2017 start-up. 

The Peace River site was selected because of expressed community support, but the company pointed out it was just the start of a long approval process.  Most of the power would be supplied to the grid, but off-peak it would be used for hydrogen production (for oil refining).  In November 2007 Bruce Power took over the Energy Alberta initiative, and will proceed with a full environmental study for the project (eventually envisaged as two twin-unit plants).  Bruce Power is 31.6% owned by Cameco.  Another Bruce partner, TransCanada, had expressed interest in building nuclear power capacity in Alberta.

Areva has also offered its EPR technology for a nuclear power plant, to be at Whitecourt, 180 km NW of Edmonton, which was earlier considered by Energy Alberta.

In neighbouring Sakatchewan, Bruce Power has announced a joint feasibility study with SaskPower to build two nuclear power reactors.  A report on the proposal and wider energy options for the province is due by the end of 2008.  A likely site is Lake Diefenbaker, less than 100km from the Alberta border and a very long way from Peace River.  SaskPower currently operates 3065 MWe of plant, more than half of it coal-fired, and part of any 2000 MWe nuclear increment might be exported to southern Alberta. SaskPower has previously investigated the prospect of nuclear power and in 2007 suggested that a 360 to 750 MWe reactor size would be feasible with Alberta, or larger if including Manitoba.

New Canadian reactor designs

The reactors at Darlington, Ontario provide the base design for the CANDU-9 design of around 900 MWe. It supplements the proven CANDU-6 of about 700 MWe, which has been an export success. The CANDU-9 has flexible fuel requirements ranging from natural uranium through slightly-enriched uranium, recovered uranium from reprocessing spent PWR fuel, mixed oxide (U & Pu) fuel, direct use of spent PWR fuel, to thorium. However, the design has been shelved.

Some of the innovation of this, along with experience in building recent Korean and Chinese units, was then put back into the Enhanced CANDU-6 (EC-6) - built as twin units - with power increase to 750 MWe and flexible fuel options, plus 4.5 year construction and 60-year plant life (with mid-life pressure tube replacement).

The Advanced CANDU Reactor (ACR) is a more innovative concept, also being developed from the CANDU-6. 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 will run on low-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. Units will be assembled from prefabricated modules, eventually cutting construction time to three years. A design review of the ACR-1000 by the CNSC is pending.

The initial design was a 700 MWe ACR-700, but the 1200 MWe ACR-1000 is now the focus of attention. The modular construction means that AECL anticipates having major components built in US shipyards, using a high degree of standardisation of components. The ACR is designed to be built in pairs, and construction time is estimated at 44 months for the first unit reducing to 36 months for the fifth and subsequent ones.

In 2006 AECL teamed up with four other nuclear technology and engineering companies to offer new nuclear power plants in Ontario, and later: New Brunswick.  Team CANDU comprises AECL with Babcock & Wilcox Canada, General Electric Canada, Hitachi Canada and SNC-Lavalin Nuclear.  It will offer fixed-price nuclear power plants on a turnkey basis.  Initially these will be the well-proven 700 MWe CANDU 6 units, but later the new third-generation 1200 MWe ACR-1000 will be an option, with the first being proposed for New Brunswick.

Beyond the ACR designs AECL has the CANDU-X on the drawing board - a supercritical reactor and step forward from the ACR. It is expected to be available about 2020.

Ontario energy policy

A major energy review by the Ontario Power Authority (OPA) reported in December 2005 that the province needed to spend C$ 83 billion on refurbishing its electricity supply over the next twenty years, and expand the contribution of nuclear power so that its share remained 50%. Nuclear was acknowledged as having less environmental impact than gas and operated at lower cost. Public opinion polls showed significant support for nuclear power, with 72% in favour of refurbishing old plants and 52% supporting new build.

In June 2006 the Ontario government confirmed that new nuclear capacity will be an important part of its plan to tackle looming electricity shortages. It directed the Ontario Power Authority to proceed with its plan to overhaul the province's generating capacity, ensuring reliability of supply with stable prices. This required maintaining nuclear capacity of 14,000 MWe. Some C$ 40 billion was expected to be spent on nuclear plant, including probably two new reactors, among 24,000 MWe of new and replacement capacity overall.

It told Ontario Power Generation (OPG) to begin feasibility studies on refurbishing its Pickering and Darlington nuclear plants and to commence environmental studies on refurbishing Pickering B units 5-8 and constructing new nuclear units which need not be Canadian designs. However, they would need to be supplied on fixed-price, turn-key contracts. Major investment in renewables and energy conservations is part of the plan. The government fast-tracked the C$ 83 billion plan, and exempted it from the need for full deliberation under the province's Environmental Assessment Act, which would be likely to take five years. However, individual proposals will be subject to federal environmental review, a 2-year process. (The Darlington plant had a massive cost overrun due to politically-imposed construction delays, and electricity consumers are still paying that off.)

The response of Bruce Power and OPG is described above, under Renewal and Refurbishment.

In August 2007, after extensive public consultation, the Ontario Power Authority released a C$ 60 billion plan to meet power demand to 2027. In line with the 2006 government announcement, it involves bringing on 14,000 MWe of new or refurbished nuclear plant costing $26.5 billion. Two scenarios for nuclear power relate to either refurbishing Pickering B over 2013-16 or not doing so, requiring 1400 or 3400 MWe of new build respectively. Gas-fired power will increase from 22 to 28% of total at a cost of $3.6 billion. Energy conservation costing $10 billion is a new feature of the plan and aims to reduce demand by 6300 MWe. A doubling of renewable energy capacity - adding 10,771 MWe hydro, 4685 MWe wind - will cost $15 billion. CO2 emissions will drop by 60% and electricity costs rise by 15-20%. Present Ontario generating capacity - much of it old - is about 30 GWe and projected 2027 need is for extra 8 GWe (or 1.7 GWe with conservation measures). Base-load provision rises from 138 TWh today to 170 TWh, from 16 and 20 GWe of base-load plant respectively.

The 2007 plan involves closing but not decommissioning 6434 MWe of coal-fired capacity (maintaining it as emergency back-up) by 2014. Due to revised forecasts of energy demand, with summer peak loads now 3000 MWe higher, the government had delayed indefinitely the shutdown of two coal-fired power plants at Lambton and Nanticoke. These were originally - in 2003 - pledged to close in 2007, but this was extended to 2009, and now is 2014. The plants, of 1975 and 3920 MWe respectively, comprise one fifth of the province's 30 GWe capacity.

Early in 2008 communities surrounding the Nanticoke coal-fired power station 250 km northwest of Toronto strongly urged the provincial government to consider the area for a new nuclear power plant.  It has the advantage of established transmission infrastructure.  In November 2008 Bruce Power announced that it planned to build two new nuclear reactors at Nanticoke, total 2200 to 3300 MWe, using Canadian, Westinghouse or Areva reactors.  This met with a cool reception from the provincial government on the grounds that its policy for expanded nuclear power did not include new sites.  An environmental assessment is expected to take three years, and the plant might come on line in 2018.

Alberta Tar Sands prospects

From about 2003 various proposals have been made to use nuclear power to produce steam for extraction of oil from Alberta's northern oilsand (tar sand) deposits and electricity also for the major infrastructure involved. At present a lot of natural gas is used - up to 30 cubic metres per barrel of oil. With projections of three million barrels per day by 2016, a great deal of gas is used and the cost exposure is increasing dramatically. In fact, Canadian natural gas is inadequate to supply the anticipated expansion in oil sands output and its use has major CO2 implications which are creating public concern - about 20% of the energy in the oil is required to produce it and about 80kg of CO2 per barrel is released.

Mining is either conventional open cut strip mining or in situ extraction using steam, eg steam-assisted gravity drainage.

The gas is used as an energy source to make steam to liquefy the bitumen, enabling its separation, and to generate electricity for mining and treatment. It is also a raw material for hydrogen to break down the long-chain hydrocarbons to yield synthetic crude oil (about 5 kg is used per barrel). Hydrogen production is by steam reforming of the natural gas. Nuclear power could make steam and electricity and use some of the electricity for high-temperature electrolysis for hydrogen production. (Heavy water and oxygen could be a valuable by-products of electrolysis.)  The steam supply needs to be semi portable as tar sand extraction proceeds, so relatively small reactors which could be moved every decade or so may be needed.

The Canadian Energy Research Institute predicts an increase in gross bitumen production from 1.2 million barrels per day in 2006 to 3.8 million by 2020, with supply costs (natural gas, materials, labour, plus 10% return on investment) averaging C$ 7.5 billion per year.

One proposal from Energy Alberta Corp. suggested that a single CANDU 6 reactor configured to produce 75% steam and 25% electricity would replace 6 million cubic metres per day of natural gas and support production of 175-200,000 barrels per day of oil. It would also save the emission of 3.3 million tonnes of CO2 per year.

In this region there are leases held by a Shell subsidiary Sure Northern Energy Ltd over limestone containing an estimated 60 billion barrels of heavy bitumen which may recovered using a lot of heat. Shell paid $571 million in 2006 to acquire these oil shale leases, but early development is not expected.

One problem related to the provision of steam for mining is that a nuclear plant is a long-life fixture, and mining of oilsands proceeds across the landscape, giving rise to very long steam transmission lines and consequent loss of efficiency.

In March 2007 the House of Commons Standing Committee on Natural Resources recommended that no decision should be taken on the use of nuclear energy for Canada's oil sands until the "repercussions of this process are fully known and understood". Their report estimated that a reactor of some 600 MW capacity could supply a processing plant producing 60,000 barrels of synthetic crude oil per day. Hence almost 20 such reactors would be needed to meet the production growth planned to 2015, when Canadian output from oil sands is forecast to reach three million barrels per day. Smaller reactors, with capacities of some 100 MW, could be more suitable for individual projects, given the limitations of supplying steam over more than 25 km.

In March 2008 the US Department of Energy's Idaho National Laboratory (INL) and the Alberta Research Council agreed to jointly study the potential applications of nuclear power for extracting and treating Alberta's tar sands which seem set to become an increasingly important source of oil for the USA.   The study will also look at conventional electricity generation.  INL is focused on advanced, next-generation nuclear power systems for both electricity and hydrogen production - since 1949 some 52 different reactors have been designed and tested there.  INL is well qualified in R&D on small semi-portable reactors.

Research & Development

The government established Atomic Energy of Canada Ltd (AECL) in 1952 and has funded its R&D programs since then. AECL also receives commercial revenues from its ventures.

The Chalk River Laboratories in Ontario were set up by the government in the 1940s and have been the locus of much successful R&D under AECL.  The 42 MW National Research Experimental (NRX) reactor of was built there in 1947, followed by the 135 MW National Research Universal (NRU) reactor a decade later.  Four other research reactors followed, with two 10 MW MAPLE units aborted in 2008.  The operating licence for NRU runs to October 2011 and in the light of a series of upgrades may have it renewed well past that.  AECL says it will work closely with CNSC and MDS Nordion on the requirements for continued medical isotope production beyond 2011.

Six other research reactors were built and continue to operate on university campuses. Five of these are SLOWPOKE-2 units, low-energy pool-type reactors designed by AECL with passive cooling and safety systems.

AECL designed the multipurpose MAPLE pool-type research reactor and the first two 10 MW units were undergoing commissioning at Chalk River.  One unit went critical in 2000, the second in 2003, but in 2008 AECL, after spending $680 million on them,  "concluded that it is no longer feasible to complete the commissioning and start-up of the reactors."  The problem is that unexpectedly they have a positive power coefficient of reactivity, hence no negative feedback enhancing safety as in most reactors.  They would have been the world's first reactors dedicated exclusively to medical isotope production, though MDS Nordion, which originally ordered them, had opted out of the contract due to excessive delays in commissioning.  MAPLE reactors can have a thermal power of 5 to 40 MW.  South Korea (KAERI) has built a 30 MW version of it - Hanaro, which started up in 1995 and is operating successfully.  MAPLE had been short-listed for Australia's 20 MW replacement research reactor in 1999.

AECL planned eventually to replace NRU reactor with the Canadian Neutron Facility (CNF), a 40 MW unit intended to meet the needs of fundamental research on industrial and biological materials as well as to support R&D on existing CANDU reactors, the ACR and other future CANDU design concepts.  Because of its dual-purpose function, AECL aimed to participate with the National Research Council in seeking Federal Government funding for design and construction of the 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.

AECL has undertaken all the developmental work on the Candu reactor types. It is now developing the third-generation Advanced Candu Reactor (described above) and also has the lead role internationally in developing the Generation IV Super-Critical Water-Cooled Reactor (SCWR).

Radioactive wastes & Decommissioning

Canada's Nuclear Waste Management Organisation (NWMO) was set up under the 2002 Nuclear Fuel Waste Act by the three nuclear utilities, who operate 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.

For high-level wastes NWMO published three conceptual designs for the technical options specified in the Act, based on proven technologies. NWMO with AECL is also required to maintain trust funds for spent fuel management and probable disposal. Less than 3000 tonnes of spent fuel per year from Candu reactors is involved.

Reactor Site Extended Storage (at 7 sites) is found to be feasible, requiring only some further dry storage facilities to be built. Centralised Extended Storage is similar to systems operating in 12 countries already, but longer term. Dry storage is also preferred in this case, with two options on the surface and two below ground level. A deep geological repository is the third possibility, allowing later retrieval if required. It is most closely aligned with international consensus and has already been the subject of environmental review in Canada.

It involves burying nuclear waste 500 to 1000 metres deep in the stable rock of the Canadian Shield. This will be below the water table and with the containers packed in bentonite clay. This concept was the subject of detailed scrutiny by the federal Environment Assessment Panel over three years in the 1990s, involving public hearings. The waste may consist of spent fuel bundles or the solidified high-level waste from reprocessing them, sealed in copper or titanium containers.

A further public discussion phase in 2004 led to recommendations in 2005 that the country's used nuclear fuel be placed in a deep geological repository, retrievably, but not until there has been a further 18 years of public discussion to identify a site. The deep repository is in line with all other national plans and is essentially where the federal review had got to early in 1998.

Early in 2007 NWMO said 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 search for a site was expected to begin in 2009. In mid 2007 the government confirmed its decision to adopt the retrievable deep geological disposal option and to proceed with site selection.

For low and intermediate-level wastes, the utilities and AECL remain responsible. These are stored above ground, and a longer-term facility for Ontario is envisaged to be in operation about 2017.

Following a strong positive response to polling of local residents, Ontario Power Generation (OPG) in 2005 proceeded with plans to construct a deep geological repository for its low- and intermediate-level wastes near the Bruce nuclear power plant. The repository will be 660 metres beneath its Western Waste Management Facility, which it has operated since 1974. Environmental assessment and licensing is expected to take 6-8 years, culminating in a review panel in 2010 and a construction licence in 2012. Capacity will be 160,000 cubic metres and it is expected to be open for about 40 years. Meanwhile the surface facility is being developed to accommodate materials arising from refurbishment of OPG and Bruce reactors.

In June 2006 the Canadian government has announced a 5-year, C$ 520 million program to clean up legacy wastes from R&D on nuclear power and medical isotopes and early military activities to 1950s. It covers clean-up of AECL contaminated lands, radioactive wastes and decommissioning old infrastructure which the government is responsible for. A large amount of low-level legacy waste from historic radium and uranium refinery operations at Port Hope, Ontario will be permanently emplaced in an above-ground repository. All waste and decommissioning liabilities for nuclear power utilities remain the responsibility of those bodies and are not included.

Three Candu reactors have been shut down and are being decommissioned: Gentilly-1, Douglas Point and NPD at Rolphton - all owned by AECL. They were shut down in 1977, 1984 and 1987 respectively and are expected to be demolished in about 30 years.

Regulation and safety

The Canadian federal nuclear regulatory and licensing agency is the Canadian Nuclear Safety Commission (CNSC). It is responsible for regulating domestic nuclear facilities and is also charged with administering the country's safeguards agreement. It was set up in 2000 under the new Nuclear Safety & Control Act and its 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.

In December 2007 the CNSC declined to allow a restart of Canada's 50-year old NRU research reactor, operated by AECL, which supplies much of the world's medical radioisotopes.  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 authorizing the restart.  Nevertheless, 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 remaining upgrade was completed early in February 2008.

Non-proliferation

Canada's uranium is sold strictly for electrical power generation only, and international safeguards are in place to ensure this. Other equipment and services are for peaceful uses only. The CNSC assists the 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 IAEA. Canada is also a member of the Nuclear Suppliers' Group.

Sources:
Natural Resources Canada, Canada's Uranium Industry, October 2004.
Cameco Annual Reports, media releases , Areva Resources web site
OECD NEA & IAEA 2003, Uranium: Resources, Production & Demand.
Uranium in Saskatchewan, 2002.
Canada Energy Research Unit, 2003, Economic impact of the nuclear industry in Canada.
NWMO 2004, Conceptual designs overview
IAEA 2003, Country Nuclear Power Profiles
Canadian Nuclear Association
Ontario Minister of Energy 13/6/06 + backgrounders.
Bruce Power 2007, New Build Project Description

Appendix:

Brief history of uranium mining in Canada

Early Uranium Mining

In Canada, uranium ores first came to public attention in the early 1930s when the Eldorado Gold Mining Company began operations at Port Radium, Northwest Territories, to recover radium. A refinery to produce radium was built the following year at Port Hope, Ontario, some 5000 km away.

Exploration for uranium began in earnest in 1942, in response to a demand for military purposes. The strategic nature of such material resulted in a ban on prospecting and mining of all radioactive materials across Canada. In 1944, the federal government took over the Eldorado company and formed a new Crown corporation which later became Eldorado Nuclear Ltd. Uranium exploration was restricted to the joint efforts of Eldorado and the Geological Survey of Canada.

Postwar, uranium exploration gathered pace when the ban on private prospecting was lifted in 1947. Deposits around the Bancroft, Ontario, area were discovered by the early 1950s, and the first discovery in Ontario's Elliot Lake region was in 1953. The northern Saskatchewan uranium province was also discovered in the 1950s and Eldorado Nuclear began mining at Beaverlodge in 1953.

By 1956 thousands of radioactive occurrences had been discovered. Several proved to be viable deposits, and by 1959, 23 mines with 19 treatment plants were in operation in five districts. Of these 19, about eleven in the Elliot Lake area, including the largest plants, would come to be operated by Rio Algom Ltd and Denison Mines Ltd. Three other plants were located near Bancroft, three in northern Saskatchewan and two in Northwest Territories.

This first phase of Canadian uranium production peaked in 1959 when more than 12 000 tonnes of uranium was produced. The uranium yielded C$330 million in export revenue, more than for any other mineral export from Canada that year. However, this period marked the end of cost-plus production for export, and over the next few years the number of mines declined to four. Uranium production in the Bancroft area and at Beaverlodge, Sk, ceased in 1982 and the last of the labour-intensive, lower-grade Elliot Lake mines closed in 1996.

The level of uranium exploration waned in the 1960s but recovered during the 1970s in response to world market conditions. During the 1960s the federal government supported the domestic uranium industry by initiating a stockpiling program which ended in 1974, after some 7000 tonnes of uranium was purchased at a cost of C$100 million. Uranium exploration was revived by expectations of nuclear power growth, and as a result several new uranium deposits were discovered in northern Saskatchewan's Athabasca Basin, starting in the late 1960s.

Recent Uranium Mining

In 1968 the Rabbit Lake deposit was discovered in northern Saskatchewan, and was brought into production in 1975. In that year Cluff Lake and Key Lake were discovered on the west and south of the same Athabasca Basin, and these started up in 1980 and 1983 respectively. Exploration expenditure in the region peaked at this time, resulting in the discoveries of Midwest, McClean Lake and Cigar Lake. Then in 1988 the newly-formed Cameco Corporation discovered the massive McArthur River deposit.

In the late 1970s the Saskatchewan Mining Development Corporation, a provincial crown corporation, had taken a 20% interest in the Cluff Lake development and a 50% interest in Key Lake. In 1988 this merged with Eldorado Nuclear Ltd to form Cameco Corporation, now the world's leading uranium producer. In 1991 Cameco made its first public share issue.

Canada's uranium production in 2001 was about 12 500 tonnes, one third of world mine output, all from mines in northern Saskatchewan. Canada's uranium ore reserves are about 14% of world total.

Through the 1990s Cameco's Key Lake was the world's largest high-grade uranium mine, supplying 15% of the world's uranium mine production in 1997. Cameco is also owner and operator of Rabbit Lake, another major producer.

The other uranium mine in operation in the late 1990s was Cluff Lake, owned and operated by Cogema Resources Inc (now Areva Resources). Rio Algom's Stanleigh Mine, the last at Elliot Lake in Ontario, closed in mid 1996.

The Canadian and Saskatchewan governments have adopted a policy of supporting uranium mining where it can be demonstrated to be environmentally acceptable. In 1991 a Joint Federal-Provincial Environmental Assessment and Review Panel was formed to study the health, safety, environmental and socio-economic impacts of five proposed uranium mining developments. A Federal Panel was formed to examine a sixth proposal.

Expansions at the Cluff Lake and Rabbit Lake operations were reviewed and approved in 1993, and came into operation.

Four new uranium projects became the focus of attention in the late 1990s as reserves in the older mines became depleted. All are located in northern Saskatchewan. Of these four new mines, three use or will use a common treatment plant, at McClean Lake.

The McClean Lake mine commenced operation in mid 1999. It was producing about 2500 t/yr U₃O₈ (2120 tU) from 2.4% ore but has been relicensed for 3640 t/yr. It has new plant and other infrastructure and uses the first mined-out pit for tailings disposal (the ore having been stockpiled). Production in 2006 was well down due to lower grades. Expansion of the mill to prepare for Cigar Lake ore will be complete in 2007. McClean Lake involves four open pits and later will become an underground mine. Efforts are being made to increase production to fill the gap left by the delay in Cigar Lake production. McClean Lake is owned by Areva Resources (70%, also operator), in joint venture with Denison Energy (22.5%) and OURD (7.5%).

The McArthur River mine operated by Cameco has enormous reserves of very high-grade ore and opened its underground mine at the end of 1999. Remote-control raise boring methods are used for mining, some 600 metres underground. Ore is trucked to the Key Lake mill, 80 km south.

The high-grade Cigar Lake mine to be operated by Cameco will also be underground, utilising ground freezing and water jet boring, with remotely-operated equipment. Ore will be trucked 70-80 km for treatment at the Rabbit Lake and McClean Lake mills from about 2011.

Ore from Areva's Midwest underground mine is also likely to be milled at McClean Lake nearby.

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