Alberta power grid operator prepares to accept green energy bids

Leningrad II VVER-1200 Reactor Vessel assembly completed in Sosnovy Bor, with Rosenergoatom preparing for first criticality, hydraulic tests, and physical startup checks of neutron physics, control systems, and passive heat removal safety.

Key Points

Core vessel for Leningrad II Unit 1, completed, sealed, and prepared for hydraulic tests ahead of first criticality.

✅ Hydraulic tests to verify circuit integrity and equipment density

✅ Physical tests to refine neutron-physics of initial fuel loading

✅ Passive heat removal system testing completed; fuel loading began

Rosenergoatom has completed the assembly of the reactor vessel for unit 1 of the Leningrad Phase II nuclear power plant, which is in Sosnovy Bor in western Russia, even as it develops power lines to reactivate the Zaporizhzhia plant in a separate project. The nuclear power plant operator subsidiary of state nuclear corporation Rosatom said yesterday the VVER-1200 is now being prepared for first criticality this month.

Alexander Belyaev, chief engineer of Leningrad NPP, said in the company statement, noting industry-wide nuclear project milestones this year: "The reactor is fully assembled, sealed and ready for hydraulic tests of the first and second circuits, during which we will once again check the equipment of the reactor installation, and finally confirm its density. After that, it will be possible to start the reactor at the minimum controlled power level."

Belyaev said this preparatory phase "envisages a whole series of physical tests that will make it possible to refine the neutron-physical characteristics of the first fuel loading of the nuclear reactor, as well as prove the reliability of the entire control and safety system (in line with the US NRC's final safety evaluation for the NuScale SMR) of the reactor installation".

The existing Leningrad plant site has four operating RMBK-1000 units, while Leningrad II will have four VVER-1200 units, as projects like the Georgia nuclear expansion continue to take shape globally. Testing of the passive heat removal system of unit 1 of Leningrad II was completed in late August and fuel loading began in December, while a new U.S. reactor startup underscored the broader resurgence.

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Labrador Hydro Open Access could enable non-discriminatory electricity transmission through Quebec, unlocking wheeling rights for Muskrat Falls and Gull Island, boosting green energy exports to Ontario and U.S. markets under interprovincial trade rules.

Key Points

Applying open, non-discriminatory transmission rules so Labrador power can wheel through Quebec to U.S. markets.

✅ Aligns with U.S. open access and non-discrimination standards

✅ Enables wheeling rights for Muskrat Falls and Gull Island

✅ Expands export routes to Ontario and Northeast U.S. grids

There's growing optimism that hydroelectric power from Labrador may soon be flowing through Quebec and into other markets in Canada and the United States as demand grows.

That was one of the revelations in a new interprovincial free trade agreement that was unveiled Friday.

If such an agreement on electricity transmission were reached, it would open the door to huge markets for Labrador hydroelectric power, including excess power from the controversial Muskrat Falls Project, and possibly end a bitter stalemate that has long soured relations between the two neighbouring provinces. 

"The best-case scenario is we move electricity through Quebec and into markets. It could be Ontario among others. It could be the U.S. It could be anywhere," Ball said Friday.

Rules based on principle of open access

The new trade deal sets out specific rules around the transmission of electricity across provincial borders, and are based on open access and non-discrimination rules in the United States.

The Muskrat Falls transmission network will bypass Quebec in moving power to the North American market, but at a considerable cost, though a ratepayer agreement aims to shield consumers. (Jacques Boissinot/Canadian Press)

Those rules allow Quebec to freely export electricity from the Upper Churchill and other power sources into the U.S., and Dwight Ball says this province wants the same rules to apply to power from the Muskrat Falls project, and potential projects such as Gull Island.

As part of the trade talks, Ottawa and other provinces asked that Newfoundland and Labrador and Quebec engage in talks about electricity transmission, including what are known as wheeling rights, and related rate mitigation talks are ongoing. Ball said that will happen.

"I'm not here to pre-judge what the outcome will be. All I'm saying is if there's an opportunity to bring benefit to our province we want to be at that table," said Ball.

"Right now we're seeing support from other provinces. We're seeing support from the federal government. We believe in using the resources that we have to support a national policy on green energy.  And if that leads us into a development in Labrador, so be it. That would be a good thing for our economy. But we have to get at that table first."

Deal comes into effect in July

The new, open access rules will come into force if either of the two provinces sign off on them within 36 months of the trade deal coming into effect on July 1.

It's nearly a certainty that the Ball government will endorse such a framework, since the province has long argued for permission to use excess transmission line capacity in Quebec to send Labrador power to other markets.

"You could argue that the U.S. rules would apply right now, but we all know that's not happening in the way we'd like to see it happen," said Ball. "So we're going to get at the table and see if we can get that access more streamlined." 

As part of the trade deal, both Newfoundland and Labrador and Quebec will maintain their monopolies over power production and the right to sell it, which means Labrador power can only be transmitted through Quebec.

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Grid Inertia and Stability underpin synchronous generation, frequency control, and voltage resilience, with virtual inertia, fast governor response, and hydro ramping mitigating oscillations when gas turbines or large generators trip or interconnectors fail.

Key Points

Grid inertia and stability show how synchronous assets resist frequency swings and damp oscillations in AC grids.

✅ Synchronous machines and loads collectively stiffen system frequency.

✅ Fast governor, hydro ramps, and virtual inertia arrest deviations.

✅ Excess inertia is costly; smart controls can replace part of it.

The discussion on inertia and synchronous generation is rather confused. Inertia is necessary because it provides stability to the grid. “Strength” and “stiffness” are terms that are used to show that lots of rotating inertia is “good’ or even essential to a stable grid. Because it was free it is often assumed that the system needs as much generator inertia as it always had, though some argue for keeping electricity options open to manage reliability during transition.

But inertia is just one way to supply stability and it can be argued that beyond more than a certain minimum level, generator inertia is an expensive and anachronistic way of providing stability.

Stability is required to protect timing circuits, minimise mechanical loads on motors and generators caused by changing speed, prevent overheating of inductive loads like AC motors and most of all to prevent voltage/frequency oscillations after fast changes in load or generation e.g. from a loss of a connection or generator or even start-up of all the hot water services at 10PM.

Inertia is one simple way of providing stability because the rotating mass of the generators absorbs or disburses energy by small changes in speed.

While the inertia of turbines is large, it is only useful as a store of energy if you can use it.  Most of the energy stored in a rotating turbo-generator is unavailable because the energy is 1/2Jω2 where ω is the angular velocity and J the rotary inertia. As the angular velocity is only supposed to vary by 0.15Hz in 50Hz you can only use 0.6% (49.85/50)2 of the inertia in the system to stabilise the load. Even if a 1Hz short term deviation is allowed it is still only 4% of the system inertia.

The key to stability is not so much the inertia itself but the synchronous nature of an AC system which locks all the turbines and loads together at the same frequency, thus inertia is not just that of one generator but all the synchronous generators, the capacitance of the transmission and distribution network and even all the AC motors and loads on the load side. These later contributors are still there, even if some of the generation is no longer synchronous, and recent low-carbon electricity lessons emphasize system-level coordination.

The downside of inertia is that once it is given up it must be replaced. So, if system frequency falls by 1Hz, to recover the frequency a large fraction of the output response from the remaining generators is used just to spin all the generators and loads back up to speed rather than just supply lost power to the grid. In the best case, it will prolong the frequency disturbance. In worst case the extended frequency deviation will trigger protection circuits and more widespread faults.

In a conventional system inertia provides the first 0.1-10 seconds of load disturbance response and it was free. A steam plant is quite good for the next 3-6 seconds after a disturbance because there is a quantity of steam in the steam chest which can be released quickly.

If the lost generation stays off line steam is then limited because it has slow ramping after that first steam dump. Hydro comes up after 20-150 seconds but has excellent stability and very fast ramps, especially in pumped storage hydro configurations where response is rapid. The combination of inertia of water in the penstock and rotary inertia of the generator gives very stable ramping and for large scale power changes, hydro seems to offer the best combination of ramp rate and stability.

Gas turbines respond quite well after 8-30 seconds, then ramp quickly if they don’t stall or oscillate which they are prone to do at low loads. It is clear that “the straw that broke the camel’s back” in the SA blackout was the failure of gas turbine generators at the Quarantine station to respond properly to rapidly increasing demand, a contrast to California shutdowns that raised questions about grid management practices.

However, even if inertia is seen as desirable at the plant level, gas turbine plants have no more inertia per MW than wind and many of them are operated slaved to the largest generator(s) because it is simpler and more efficient, and recent moves like new Ontario gas plants aim to boost capacity.

But if the key large generator(s) are for some reason isolated from the grid, the gas turbines will sag under the increased load and they will have limited mechanism or perhaps, if they are already at full load, even capacity, to respond. So, within fractions of a second their frequency will start to fall just as quickly as a group of wind turbines.

Even if governor response is fast, maximum stable ramp rates are around 5-10% per minute usually starting at less than that (they tend to have S shaped response curves) Gas turbines have another weakness which means that their inertia is of less value to the grid.

If frequency falls the compressors slow down reducing compression ratio and thus power so even more so more of the governor response is needed just to compensate for reduced air flow.

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SaskPower Geothermal Power aims to deliver renewable baseload energy in Saskatchewan, complementing wind and solar. With DEEP's 5 MW pilot near Estevan tapping aquifers, it supports grid reliability alongside LED streetlights and flare gas.

Key Points

SaskPower Geothermal Power is a baseload plan using DEEP's aquifers to deliver zero-emission power in Saskatchewan.

✅ 5 MW DEEP pilot near Estevan targets hot sedimentary aquifers

✅ Provides 24/7 renewable baseload, complementing wind and solar

✅ Higher upfront costs and timelines challenge rapid deployment

It would be a first for Saskatchewan and Canada.

SaskPower‘s efforts to double renewable electricity by 2030 could potentially include geothermal power stations.

 Regina and Saskatoon areas were selected to provide a range of settings to test the new LED streetlights SaskPower is piloting. SaskPower pilot project converting streetlights to LED

 The second project in SaskPower’s flare gas power generation program is contributing 750 kilowatts of electricity to Saskatchewan’s power grid. SaskPower turning waste flare gas into electricity

 SaskPower reporting power outages in some regions as high winds sweep across Saskatchewan. SaskPower launches homeowner energy efficiency assessment tool

“If projections hold true, we’re going to need to find over 2,000 megawatts of renewable power,” Kirsten Marcia, president and CEO of Deep Earth Energy Production (DEEP), said.

“Geothermal is not the only solution here, but we hope to have a very significant place at the table.”

With a power purchase agreement with SaskPower signed in May, and ongoing initiatives such as purchasing power from Flying Dust First Nation to diversify supply, DEEP hopes to build a five megawatt, zero emission power plant near Estevan, where subterranean water is the warmest in Saskatchewan.

Typically, geothermal operations use the water for heat, as in Manitoba's geothermal homes initiative where thousands of residences would be converted; however DEEP’s plant will pass water through an exchanger to create steam, which will drive a turbine and generate energy.

“You think of our potash resources, our oil and gas resources, and at the very bottom of those sedimentary units is thick, 150 metre deep aquifer,” Marcia said. “We could drill it here in Saskatoon, but it’s too shallow to be hot enough, and the same aquifer continues to deepen as we go towards the United States, it’s about 3.4 kilometers in depth, so that’s what gives it the heat.”

But is investment in geothermal power generation worth it for the province? Experts say they’re cautiously optimistic, but initial costs may drive away potential interest, which is why SaskPower is also planning to buy more electricity from Manitoba Hydro as a complementary measure.

“The payback period is going to be much longer,” said Grant Ferguson, an associate professor of geological engineering at the University of Saskatchewan. “So we’re going to run into problems with risk and financing and these sorts of things that might not be in play with something like a wind or solar project.”

Time is also a factor.

Each unit is expected to generate between five and 10 megawatts of power; multiple unites would be required to generate the amount of power needed in Saskatchewan. Nearly a decade of work has gone into DEEP’s first station.

“If we’re looking towards 2030 and we’re taking 10 years for one, then it’s going to take a while to pull all this off,” Ferguson said.

“Maybe if it's on the space of two or three years then we can build these things up.”

The benefit geothermal electricity has over solar and wind generated power? Electricity is consistently being generated, even during record power demand events in Saskatchewan.

“Ideally, this becomes a baseload power supply,” Marcia said, “so unlike wind and solar, which provide an intermittent power supply, geothermal is the only renewable that provides power 24 hours a day, seven days a week.”

DEEP’s first plant is expected to be built in two years. It’s expected the aquifer will be able to support a capacity of roughly 200 megawatts.

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Ohio gas-fired generation accelerates as combined-cycle plants join PJM Interconnection, challenging FirstEnergy's Davis-Besse baseload in Lucas County with 869-955 MW capacity and lower costs than nuclear, this summer and a new 2020 project.

Key Points

Ohio gas-fired generation is new combined-cycle capacity for PJM, adding 955 MW and competing with nuclear baseload.

✅ 955 MW Lucas County plant approved by Ohio Power Siting Board

✅ 869 MW Oregon Clean Energy Center entered service this summer

✅ PJM says reliability unaffected without FirstEnergy nuclear

Nuclear generators already struggling in Ohio will face even more competition from almost 900 MW of gas-fired generation that came online this summer, amid concerns over a growing supply gap in some regions, and another 950 MW plant now in the works.

Both plants will connect to the PJM Integration market, according to the Toledo Blade, and will generate more power than FirstEnergy's nearby Davis-Besse nuclear plant overall.

The Clean Energy Future–Oregon project will cost an estimated $900 million to construct, and is expected to begin operation in 2020. The project was initially approved more than four years ago.

Nuclear plants in Ohio have pressed for subsidies to remain in operation, as their emissions-free power is being pushed off the grid by cheaper natural gas, reflecting a broader debate over the future of struggling nuclear plants across the U.S. In May, FirstEnergy CEO Chuck Jones told the Ohio Senate Public Utilities Committee that its Davis-Besse and Perry nuclear plants are unlikely to successfully compete with low cost gas-fired generation in the wholesale power market.

Proponents of supporting baseload generation like coal and nuclear have pointed to their contributions to the reliability and resiliency of the power system, and some jurisdictions are considering new large-scale nuclear to meet those goals. But FirstEnergy's Ohio nuclear plants are not necessary for system reliability, according to Craig Glazer, vice president of federal government policy at PJM Interconnection and the former chairman of the Public Utilities Commission of Ohio.

The Ohio Power Siting Board last week authorized Clean Energy Future-Oregon LLC to construct a 955 MW gas-fired, combined-cycle power plant in Lucas County.

The plant will be located on a 30-acre parcel of land in Oregon, Ohio, and will interconnect to the regional electric transmission grid via nearby 138 and 345 kV transmission lines.

The project is being developed by CME Energy, which this summer also brought online the Oregon Clean Energy Center, an 869 MW gas-fired power plant at a nearby location, while governments elsewhere weigh new gas plants to boost electricity production.

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Summerside Plant Asbestos Removal enables a heating system upgrade to electric furnaces with heat storage bricks, maximizing wind energy use and lowering peak loads; contractor tenders closed, work starts May 1.

Key Points

A city effort to remove asbestos so an electric furnace heating upgrade with wind energy heat storage can proceed.

✅ Four electric furnaces with heat storage bricks

✅ Maximizes wind energy, lowers peak load and diesel use

✅ Work starts May 1; about three weeks; no service disruptions

The City of Summerside is in the process of removing hazardous asbestos at the Summerside Electric Power Plant building in order to clear the way for replacement of the heating system.

The city is hiring a contractor to do the work and tenders for the project closed Thursday afternoon. 

The heating system is being replaced with four new electric furnaces, which are Heat for Less Now products. The products help maximize wind energy by using bricks to store heat created from wind energy for use during peak demand times, similar to using more electricity for heat initiatives advocated in the N.W.T.

"This program's working so well we wanted to continue with that in the power plant," said Rob Steele, electrical operations supervisor with the City of Summerside. 

Time to replace system

The new system will heat the whole building, as other utilities evaluate options like geothermal power plants to meet targets. 

"Having more of these units with heat storage already placed in them can lower the peak load of Summerside which therefore will help keep our diesel engines from running, aligning with power grid operation changes being considered in Nova Scotia," said Steele. 

Steele said the existing system is beyond life its expectancy and maintenance is getting costly so it's time to replace it, amid calls to reduce biomass electricity in generation portfolios. 

"And unfortunately in 1960 and 1963 asbestos was used on the elbow sections of the piping insulation and of course that must be removed for us to proceed," said Steele.  

Steele said the city doesn't know how much the project will cost yet as the tenders just closed Thursday afternoon. He said the city plans to announce the cost along with the successful bidder who will do the asbestos removal April 6. 

The city said there won't be any interruption of power or services during the upgrades, even as major facilities like the Bruce nuclear reactor undergo refurbishment elsewhere. Work is expected to start May 1 and take about three weeks to finish. 

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