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74-658: Its business plan was to build one or more twin-reactor ACR-1000 nuclear plants in partnership with Atomic Energy of Canada Limited to supply electrical energy to the rapidly growing demand of the Alberta electrical grid, influenced by announced new facilities for oil extraction from the Athabasca Oil Sands , oil upgrading facilities near Edmonton , and associated population and economic growth across Alberta. Energy Alberta initially proposed to build their first plant at either Whitecourt (several hundred kilometres southwest of

148-523: A small modular reactor (SMR) at Darlington Nuclear Generating Station. It is expected to be operational by 2028 at the earliest. OPG will work with GE Hitachi Nuclear Canada to build the SMR. On December 2, 2022, Ontario Power Generation officially broke ground on the new build Darlington SMR (Darlington B) project. The first unit to be constructed is a GE BWRX-300 unit, expected to produce power by late 2029. Low and intermediate level waste from Darlington

222-485: A different site still within 30 km of Peace River. As of October, 2007, the company had not announced the names of any oil sands companies interested in using its energy, or investors willing to provide the estimated $ 6.2 billion ($ 8.7 billion today) for construction of the first plant. Present oil sands extraction plants use natural gas to supply heat to make hot water or steam used in the separation of oil and sand. Using nuclear power instead of burning gas would prevent

296-438: A four-year building schedule, during a period of high interest rates , the budget continued to balloon. An additional $ 3.3 billion can be attributed to the interest during these delays. An additional $ 1.2 billion had to be added to the bill as Hydro changed their accounting procedures and moved several items, including training the operators, from operational costs to capital. Design changes due to changing safety requirements after

370-449: A half years of operation, Unit 2 achieved a lifetime load factor of only 29.9% while Unit 1, between July 1992 and the end of June 1993, achieved a load factor of 56.8%. The changes, especially the new power shafts, also added another $ 600 million to the final bill. The Peterson government fell in 1990, resulting in Rae's NDP taking the province in the midst of a recession . The Darlington plant

444-477: A large number of new reactors would have to be built. Land at the Darlington Provincial Park was identified as a potential site in the late 1960s, and Hydro purchased the plot in 1971 as an "energy centre". The first official plans to develop the site for nuclear were approved in 1973, apparently at the personal direction of Conservative Ontario premier Bill Davis without discussion by cabinet. At

518-500: A long prompt neutron lifetime; small reactivity holdup; two fast, independent, safety shutdown systems; and an emergency core cooling system. The fuel bundle is a variant of the 43-element CANFLEX design (CANFLEX-ACR). The use of LEU fuel with a neutron absorbing centre element allows the reduction of coolant void reactivity coefficient to a nominally small, negative value. It also results in higher burnup operation than traditional CANDU designs. The ACR-1000 design currently calls for

592-424: A much smaller BWRX-300 small modular reactor on the B site, which are ongoing as of 2023 . Darlington was part of a large nuclear buildout planned by Ontario Hydro based on their predictions of almost linear growth in power demand at 7% per year essentially forever. Based on this predicted growth, the company stated that nuclear would account for 60 to 70% of the province's supply by 1990, and for that to occur,

666-466: A period of historically high interest rates. In 1989, Hydro filed its latest 25-year Demand Supply Plan, Providing the Balance of Power , calling for another 10 reactors and 32 fossil plants. In 1993, this plan was withdrawn, after Darlington entered service and the province now had a surplus of generation and was forced to sell at very low and sometimes negative prices. This, combined with the enormous debt

740-555: A plan to use their two CANDU-6 reactors in a recycling scheme under the name Advanced Fuel CANDU Reactor (AFCR). However, these plans did not proceed. SNC and CNNC subsequently announced collaboration on a Heavy Water Reactor, also based on legacy CANDU technology, and unrelated to the Advanced Heavy Water Reactor being developed in India. Darlington Nuclear Generating Station Darlington Nuclear Generating Station

814-494: A primary case study for the anti-nuclear movement in Canada, and was one of the main reasons Ontario Hydro was broken up in 1999 and its debts paid off by special billings. After initial operations and shakeout, it is often among the most reliable plants in the world in terms of capacity factor . As of 2023 , the plant is undergoing a mid-life upgrade, with two units completed and the second two expected to complete in 2026. Room for

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888-613: A record previous held by Pickering Unit 7 at 894 days for 22 years until it was broken in 2016 by Heysham 2 in the UK. As of September 28, 2020, Unit 1 was at 976 days. 2021: On Thursday, February 4 at sometime after 11PM Darlington Unit 1 finally went down for maintenance after 1,106 continuous days of generation, setting the world nuclear operation record and world thermal plant generation record. In 2009, more than 200,000 litres of water containing trace amounts of tritium and hydrazine spilled into Lake Ontario after workers accidentally filled

962-411: A second four-reactor unit had been in place since the original site selection, with a large area to the east of the current plant set aside for what was known as Darlington B. In 2006, Ontario Power Generation began the process of applying to build a two-unit plant on the B site. This project was cancelled in 2013 when the estimated cost was far beyond initial projections. In 2020 plans started to install

1036-530: A second source for NASA . Rods containing Np-237 would be fabricated by Pacific Northwest National Laboratory (PNNL) in Washington State and shipped to OPG's Darlington Nuclear Generating Station where they would be irradiated with neutrons inside the reactor's core to produce Pu-238. The graph represents the annual electricity generation at the site in GWh. As of the end of 2023, the total lifetime output of

1110-438: A triple-channel logic circuit. When any 2 of the 3 circuit paths are activated (due to sensing the need for emergency reactor trip), each of these valves are opened and Gd(NO 3 ) 3 solution is injected through the nozzles to mix with the heavy-water moderator liquid in the reactor vessel (calandria). The result is that the reactor heat output is reduced by 90% within 2 seconds. Reserve water system (RWS): The RWS consists of

1184-458: A variety of safety systems, most of which are evolutionary derivatives of the systems utilized on the CANDU 6 reactor design. Each ACR requires both SDS1 & SDS2 to be online and fully operational before they will operate at any power level. Safety Shutdown System 1 (SDS1): SDS1 is designed to rapidly and automatically terminate reactor operation. Neutron-absorbing rods (control rods that shut down

1258-434: A water tank located at a high elevation within the reactor building. This provides water for use in cooling an ACR that has suffered a loss of coolant accident (LOCA). The RWS can also provide emergency water (via gravity-feed) to the steam generators, moderator system, shield cooling system or the heat transport system of any ACR. Emergency power supply system (EPS): The EPS system is designed to provide each ACR unit with

1332-552: Is a Canadian nuclear power station located on the north shore of Lake Ontario in Clarington, Ontario . It is a large nuclear facility comprising four CANDU nuclear reactors with a total output of 3,512 MWe when all units are online, providing about 20 percent of Ontario's electricity needs, enough to serve a city of two million people. The reactor design is significantly more powerful than those used in previous CANDU sites at Pickering and Bruce , making its 4-unit plant

1406-545: Is generated by coal plants, nuclear facility emissions are compared with the much higher radioactive emissions of coal-fired plants . In March 2008, the Energy Alberta Corporation was purchased by Bruce Power . Bruce Power announced in December 2011 that it will not go ahead with the nuclear power plant proposed for Peace River. Advanced CANDU reactor The Advanced CANDU reactor ( ACR ), or ACR-1000 ,

1480-488: Is inserted into the calandria, and the reactor heat output is reduced by 90% within 2 seconds. Safety Shutdown System 2 (SDS2): SDS2 is also designed to rapidly and automatically terminate reactor operation. Gadolinium nitrate (Gd(NO 3 ) 3 ) solution, a neutron-absorbing liquid that shuts down the nuclear chain reaction, is stored inside channels that feed into horizontal nozzle assemblies. Each nozzle has an electronically controlled valve, all of which are controlled via

1554-656: Is stored at the Western Waste Management Facility (WWMF) at the Bruce nuclear site near Kincardine, Ontario . OPG has proposed the construction and operation of a deep geologic repository for the long-term storage of this low and intermediate level waste on lands adjacent to WWMF. On May 6, 2015 the Joint Review Panel issued the Environmental Assessment (EA) Report recommending the approval of

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1628-598: The Canadian Nuclear Safety Commission announced in December 2015 the renewal of Darlington’s power reactor operating licence, for 10 years from Jan. 1, 2016, until Nov. 30, 2025, to allow for the refurbishment of the Darlington station, which began in October 2016. On October 14, 2016, OPG began Canada’s largest clean infrastructure project – the refurbishment of all four of Darlington’s reactors. According to

1702-487: The Conference Board of Canada , the $ 12.8 billion investment will generate $ 14.9 billion in economic benefits to Ontario, including thousands of construction jobs at Darlington and at some 60 Ontario companies supplying components for the work. The project is scheduled for completion by 2028 and will ensure safe plant operation through 2055. In 2006, OPG started the federal approvals process to build new nuclear units at

1776-572: The Three Mile Island accident and Chernobyl added a further $ 0.9 billion, and other unforeseen changes to construction, including site works, added another $ 1 billion. As a result, the final cost was put at $ 13.8 billion, a full $ 6.8 billion, or 86%, over the 1981 estimate. Unit 2 was the first to start construction, ahead of Unit 1, on 1 September 1981. Unit 1 followed on 1 April 1982. Construction started on Unit 3 on 1 September 1984, and Unit 4 on 1 July 1985. Construction on 1 and 2 continued with

1850-522: The alternators were found to suffer from cracking, which led to lengthy shutdowns in 1990 and 1991. This was addressed with a new shaft design installed in May 1992. The other three units had already received the original design, but for initial operations they were modified to avoid the problem while awaiting the new shafts, expected in May 1993 for Unit 1 and in March and August 1994 for Units 3 and 4. In early 1991 it

1924-669: The second-largest in Canada behind the 8-unit Bruce. It is named for the Township of Darlington, the name of the municipality in which it is located, which is now part of the amalgamated Municipality of Clarington . The plant began construction in September 1981 and planned to start initial operations in 1985. Several delays ensued, and the construction start on Units 3 and 4 was put off until 1984 and 1985. Unit 2 entered operation in 1990, followed by Unit 1 in 1992, and Units 3 and 4 in 1993. The delays and resulting cost overruns have made Darlington

1998-550: The 1970s, Hydro's future demand estimates were repeatedly attacked as unrealistic. The 1973 oil crisis and subsequent 1973–1975 recession led to greatly reduced growth rates, which reached zero in the province in 1977. As these concerns became more public, in 1975 Davis formed two independent committees, the Porter Commission and the Select Committee, both of whom concluded the predictions were far too high. Shortly after,

2072-420: The 1980s. In practice, these advantages did not work out. The high expected fuel costs never came to be; when reactor construction stalled at around 200 units worldwide, instead of the expected thousands, fuel costs remained steady as there was ample enrichment capability for the amount of fuel being used. This left CANDU in the unexpected position of selling itself primarily on the lack of need for enrichment and

2146-402: The Darlington B installation. Ultimately, AECL was the only company to place a formal bid, with a two-reactor ACR-1000 plant. The bids required that all contingencies for time and budget overruns be considered in the plans. The resulting bid was $ 26 billion for a total of 2,400 MWe, or over $ 10,800 per kilowatt. This was three times what had been expected, and called "shockingly high". As this

2220-572: The Deep Geologic Repository for Ontario’s low and intermediate level waste to the federal government. In February 2016, the Federal Minister of Environment and Climate Change delayed a decision on OPG’s DGR, causing a pause in the timeline for the environmental assessment decision to be issued. OPG has since committed to completing further DGR studies by the end of 2016. The Darlington Waste Management Facility provides dry storage for

2294-464: The amount of heavy water needed, and the cost of the primary coolant loop. Heavy water remains in the low-pressure section of the calandria, where it is essentially static and used only as a moderator. The reactivity regulating and safety devices are located within the low-pressure moderator. The ACR also incorporates characteristics of the CANDU design, including on-power refueling with the CANFLEX fuel;

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2368-564: The best performing in OPG's CANDU fleet, including a top year in 2008 in which the plant achieved a combined 94.5% capacity factor . In June 2016, the World Association of Nuclear Operators (WANO) named Darlington one of the safest and top-performing nuclear stations in the world - for the third time in a row. In March 2017, Ontario Power Generation (OPG) and its venture arm, Canadian Nuclear Partners, announced plans to produce Plutonium-238 as

2442-543: The collapse of worldwide uranium prices in the late 1980s. This led Hydro to break the contracts in 1991 at another $ 717 million charge. After much debate, the decision was made to isolate the debts into a separate crown corporation , the Ontario Electricity Financial Corporation. Ontario Hydro officially ended operations on 31 March 1999. Their final financial statements listed long-term debts of $ 26.2 billion and assets totalling $ 39.6 billion, but

2516-619: The company had already spent the original $ 7 billion budget, and was now predicting another $ 4 billion would be needed to complete it. Completion of Unit 2 was now predicted to be in 1988. On 2 May 1985, the 1985 Ontario general election resulted in the ruling Conservatives receiving a minority government, but a vote of no confidence in June ended their 42-year rule and brought David Peterson 's Liberals to power with support by Bob Rae 's NDP . Peterson had previously voiced his support for an immediate stop to Darlington. In contrast, Rae relied on

2590-498: The company had taken on to finance the plant, led to the decision to break up the company into several smaller ones. The project was adversely affected by declining electricity demand forecasts, mounting debt of Ontario Hydro, and the Chernobyl disaster, which necessitated safety reviews in mid-construction. Each delay incurred interest charges on debt, which ultimately accounted for 70% of the cost overruns. Inflation during 1977 to 1981

2664-401: The company. As a result of Farlinger's suggestions, Strong began the process of breaking up the company into five divisions, each with a separate area of responsibility. As part of these plans, any future nuclear expansion was ended. When Mike Harris ' Conservatives regained power in 1995, Harris appointed Farlinger as CEO of Hydro and the plans were amended to sell off the various divisions once

2738-449: The construction start to 1981, with the first reactor coming online in 1985 and then the other three after that, one every 12 months. This pushed the budget up only slightly to $ 3.9 billion in construction and another $ 1 billion for heavy water . A more detailed budget, this time accounting for inflation during the expected construction period through 1988 put the final figure at $ 7.4 billion, equivalent to $ 30 in 2023. The time-frame

2812-460: The continuing construction of Darlington Units 1 and 2, but suggested a wait-and-see period before allowing completion of Units 3 and 4. It was during this period that the labour force at the site reached its peak of 7,000, making it the largest construction program in North America at that time. Cabinet approved the continued construction in 1987, before the next election. Now seven years into

2886-616: The cost of nuclear electricity is about 7 cents per kilowatt-hour when privately financed or more than $ 17 per gigajoule compared with $ 6 per gigajoule for natural gas. Rising costs for gas and carbon taxes could change that picture. Some environmental groups oppose nuclear power in Alberta. A Pembina Institute opinion argues that renewable sources of energy be used instead and mentions many problems associated with nuclear power including risk of devastating accident, radioactive waste, leaks, heat pollution, cost overruns and unreliable performance. See Nuclear Power . Since most electricity in Alberta

2960-479: The emission of large quantities of carbon dioxide. The direct use of heat from nuclear reactors has been found cost effective in an energy analysis. However, nuclear reactors have a lifetime of 50 years or more and cannot be moved so there is a problem supplying the heat where it is needed as nearby deposits are depleted. Energy Alberta appears to have no plans for using the heat directly; they plan to produce electricity which can easily be delivered anywhere. However,

3034-507: The expansions at Pickering and Bruce that were now about to come online. At the time, Hydro calculated the budget to have risen to $ 10.9 billion. The pause ended in early 1985, but not all of the original staff were assigned back to the project, and new staff had to be hired and trained. Additionally, during the pause a number of issues in the design were found, this being the first plant of the ~900 MW size to be built, introducing further delay in getting construction started again. At this time,

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3108-419: The facility was 764,192 GWh. The Darlington station incurred massive cost overruns during its construction. The initial cost estimate for the station was $ 3.9 billion CAD in the late 1970s, which increased to $ 7.4 billion in 1981 when construction was started. A year-long period of public hearings and study by an Ontario government all-party committee finished in 1986 with the decision to proceed with

3182-471: The government concluded the fair value of the assets was far below the claimed price. Their valuations calculated a resulting $ 19.5 billion of stranded debt, which was then paid off as a separate Debt Retirement Charge on customer bills from 2003 until 31 March 2018. In April 1999 Ontario Hydro was split into 5 component Crown corporations with Ontario Power Generation (OPG) taking over all electrical generating stations. The Darlington reactors have been among

3256-416: The heavy water cooling loop with one containing conventional light water, reducing costs. The name refers to its design power in the 1,000 MWe class, with the baseline around 1,200 MWe. The ACR-1000 was introduced as a lower-priced option compared to a larger version of the baseline CANDU which was being designed, the CANDU 9. ACR was slightly larger but less expensive to build and run. The downside

3330-445: The latter known as a "calandria", which it was believed would lower construction costs compared to designs that used highly pressurized cores. In contrast to typical light-water designs, CANDU did not require a single large pressure vessel, which was among the more complex parts of other designs. This design also allowed it to be refuelled while it was running, improving the capacity factor , a key metric in overall performance. However,

3404-420: The nuclear chain reaction ) are stored inside isolated channels located directly above the reactor vessel (calandria) and are controlled via a triple-channel logic circuit. When any 2 of the 3 circuit paths are activated (due to sensing the need for emergency reactor trip), the direct current-controlled clutches that keep each control-rod in the storage position are de-energized. The result is that each control-rod

3478-531: The oil sands) or Peace River (on the western part of the oil sands). Peace River local councils welcomed the project, and a site 30 km west of Peace River on Lac Cardinal was chosen in August, 2007 and an application to the Canadian Nuclear Safety Commission was filed. In 2007 Energy Alberta was acquired by Bruce Power of Ontario. In March 2009, Bruce decided to relocate the site to Whitemud,

3552-410: The pauses noted above, but 3 and 4 were significantly scaled back. Unit 2 entered commercial service on 9 October 1990, and Unit 1 on 14 November 1992. The final two units were much closer to competition by this point, with Unit 3 entering service on 14 February 1993, and Unit 4 shortly after on 14 June. Almost immediately on entering service, the power shafts on Unit 2 connecting the steam turbines to

3626-448: The possibility that this presented a lower nuclear proliferation risk. ACR addresses the high capital costs of the CANDU design primarily by using low-enrichment uranium (LEU) fuel. This allows the reactor core to be built much more compactly, roughly half that of a CANDU of the same power. Additionally, it replaces the heavy water coolant in the high-pressure section of the calandria with conventional "light" water. This greatly reduces

3700-477: The post-1992 demand seemed uncertain and no new reactors were scheduled. The company turned its attention to grid improvements. Construction began on schedule, with the "first pour" in June 1981. In 1982, the construction starts for Units 3 and 4 were pushed back several years to 1985. In 1983, suffering from overcommitment and understaffing, Hydro management ordered the project be delayed. The engineering staff on Darlington were assigned to other projects, including

3774-417: The project, which had then risen to $ 7 billion in actual and committed costs. The final cost was $ 14.4 billion CAD, almost double the initial construction budget, even adjusted for inflation. Hydro was not allowed to charge for the cost of construction until the plant was actually delivering power to customers. As such, all of the cost overruns in the project until 1990 had to be taken on as debt, during

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3848-468: The province of New Brunswick accepted a proposal for a feasibility study for an ACR-1000 at Point Lepreau . This led to a formal bid by Team Candu, consisting of AECL, GE Canada , Hitachi Canada, Babcock & Wilcox Canada and SNC-Lavalin Nuclear, which proposed using a 1085 MWe ACR-1000. Nothing further came of this bid. It was later replaced by a mid-2010 bid by Areva, a bid that also lapsed. AECL

3922-506: The recently formed Ministry of Energy and the public Energy Probe foundation both released reports stating that the company's predictions for power use in 2000 were some 12 gigawatts too high, about three four-reactor plants worth. In 1980, the Porter Commission delivered its final report, which stated the growth rate would be closer to 4% and suggested Hydro should abandon its plans for further nuclear plants and should instead develop smaller plants and implement demand management . This advice

3996-453: The report, the federal government approved the Environmental Assessment. In October 2013, the Ontario government declared that the Darlington new build project would not be a part of Ontario's long term energy plan, citing the high capital cost estimates and energy surplus in the province at the time of the announcement. In November 2020, Ontario Power Generation (OPG) announced plans to build

4070-440: The required electrical power needed to perform all safety functions under both operating & accident conditions. It contains seismically qualified, redundant standby generators, batteries and distribution switchgear. Cooling water system (CWS): The CWS provides all necessary light water (H 2 O) required to perform all safety system-related functions under both operating & accident conditions. All safety-related portions of

4144-540: The site of its Darlington Nuclear Station. The project proposal involved the construction and operation of up to four nuclear units, with capacity of up to 4,800 MW. A request for proposals (RFP) process for design and construction resulted in bids from Areva NP , Westinghouse , and Atomic Energy of Canada Limited (AECL). In June 2009, the Government of Ontario put the RFP process on hold, citing unexpectedly high bids, and

4218-458: The split was complete. By this time, Hydro had $ 34 billion in debt, almost half of that due to Darlington and a significant portion of the rest from construction and expansions on Pickering and Bruce. Additional charges were due to cost overruns on the boilers at these plants, which ran to $ 850 million. More was added due to the take-or-pay contracts with Rio Algom and Denison Mines for supply of uranium that were set at market rates prior to

4292-565: The support of the Hydro worker's union, CUPE Local 1000, who strongly supported the project. As part of the inter-party deal, Peterson promised to not stop construction while a new commission considered the issue. The Select Committee was reformed and produced a new report in 1986. By this time the Chernobyl disaster had cast a further pall over the field, and Hydro had further reduced its predictions to 30 GW in 2000. The committee provisionally accepted

4366-727: The system are seismically qualified and contain redundant divisions. The ACR has a planned lifetime capacity factor of greater than 93%. This is achieved by a three-year planned outage frequency, with a 21-day planned outage duration and 1.5% per year forced outage. Quadrant separation allows flexibility for on-line maintenance and outage management. A high degree of safety system testing automation also reduces cost. Bruce Power considered ACR in 2007 for deployment in Western Canada, both for power generation, or for steam generation to be used in processing oil sands . In 2011, Bruce Power decided not to move forward with this project. In 2008,

4440-400: The time, the construction cost of the four-unit plant was estimated at $ 4.5 billion (equivalent to $ 30 billion in 2023), and construction would start in 1979. Public hearings began in 1974 and the general plans were finalized in 1976. The official go-ahead from the government was given on 18 April 1977, and the first contracts for construction let on 8 June 1978. Through the rest of

4514-535: The uncertainty surrounding the future of the only compliant bidder (AECL). In August 2011, the three-member Joint Review Panel (mandated by the Ontario Ministry of the Environment and the Canadian Nuclear Safety Commission ) released a report finding that the Darlington new build project would not result in any significant adverse environmental impacts (after taking into account mitigation measures). Following

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4588-404: The use of natural uranium also meant the core was much less dense compared to other designs, and much larger overall. It was expected this additional cost would be offset by lower capital costs on other items, as well as lower operational costs. The key trade-off was the cost of the fuel, in an era when enriched uranium fuel was limited and expensive and its price was expected to rise considerably by

4662-423: The used fuel from Darlington, after an initial period in a water-filled storage bay. The facility was opened in 2007, reportedly on schedule and on budget. The Nuclear Waste Management Organization is seeking a site in Canada for a permanent repository for used fuel from all of Canada's nuclear reactors. 2020: On Tuesday, September 15 Darlington Unit 1 broke the world record for continuous generation at 963 days,

4736-465: Was 46 percent, according to Canada's Consumer Price index. In addition interest rates were running at 20 percent. Improper choice of equipment and a six-month labour stoppage of electrical workers also yielded some of these costs and delays. Discussion of who is to blame for the costs and subsequent debts associated with Darlington often arise during provincial election campaigns, and are often mentioned in anti-nuclear literature. After public hearings,

4810-429: Was a proposed Generation III+ nuclear reactor design, developed by Atomic Energy of Canada Limited (AECL). It combined features of the existing CANDU pressurised heavy water reactors (PHWR) with features of light-water cooled pressurized water reactors (PWR). From CANDU, it took the heavy water moderator, which gave the design an improved neutron economy that allowed it to burn a variety of fuels. It replaced

4884-427: Was believed that this design would result in lower overall operating costs due to its ability to use natural uranium for fuel, eliminating the need for enrichment. At the time, it was believed there would be hundreds and perhaps thousands of nuclear reactors in operation by the 1980s, and in that case the cost of enrichment would become considerable. Further, the design used both pressurized and unpressurized sections,

4958-501: Was canceled in 2009 when the price was estimated to be three times what the government was budgeting. With no other sales prospects, in 2011 the AECL reactor design division was sold to SNC-Lavalin to provide services to the existing CANDU fleet. Development of the ACR ended. The original CANDU design used heavy water as both the neutron moderator and the coolant for the primary cooling loop. It

5032-435: Was deferred and advanced several times over the next few years. In 1981, Hydro finally responded to the concerns about overbuilding with a new prediction of 38 gigawatts demand in 2000, a full 52 gigawatts less than their predictions made in 1978. A 1984 report puts the future growth at 3% at least until 1992, which, along with high interest rates of the era, led the company to cancel any future buildout for this period. Even

5106-447: Was found that vibrations in the fuel assemblies in Unit 2 was causing them to become damaged. This was ultimately traced to a problem in the pumping system that injected a 150 Hz pressure fluctuation. Changing the impellers to increase the rate to 210 Hz solved the problem. As a result of these issues, the initial availability, or capacity factor was low. During its first three and

5180-510: Was marketing the ACR-1000 as part of the UK's Generic Design Process but pulled out in April 2008. CEO Hugh MacDiarmid is quoted as stating, "We believe very strongly that our best course of action to ensure the ACR-1000 is successful in the global market place is to focus first and foremost on establishing it here at home." The ACR-1000 was submitted as part of Ontario's request for proposal (RFP) for

5254-505: Was pointedly ignored. The ongoing expansion plan was paid for by debt financing primarily through the sale of commercial bonds . Given the public scrutiny and generally negative reports, in 1976 Energy Minister Darcy McKeough told Hydro to slow down its demands and spread out the budget or the province would not guarantee the company's bonds. Darlington was one of several major programs for that time frame, including major expansions at Pickering and Bruce . Hydro responded by pushing back

5328-415: Was still under construction, and still as politically radioactive as it had been through the 1980s. Rae made the decision to complete the plant, but to ensure that these sorts of overruns did not occur again, he appointed Maurice Strong , former CEO of Petro-Canada , to become CEO of Hydro and shake up the company. Strong asked Bill Farlinger, a laissez-faire market-economy advocate, to suggest ways to reform

5402-519: Was that it did not have the flexibility of fuels that the original CANDU design offered, and would no longer run on pure unenriched uranium. This was a small price to pay given the low cost of enrichment services and fuel in general. AECL bid the ACR-1000 on several proposals around the world but won no contests. The last serious proposal was for a two-reactor expansion of the Darlington Nuclear Generating Station , but this project

5476-576: Was the only bid, the Ministry of Energy and Infrastructure decided to cancel the expansion project in 2009. In 2011, with no sales prospects remaining, the Canadian government sold AECL's reactor division to SNC-Lavalin . In 2014, SNC announced a partnership with the China National Nuclear Corporation (CNNC) to support sales and construction of the existing CANDU designs. Among these was

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