Labrador power flowing through Quebec

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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Zambia Mining Electricity Tariff Agreement signals a shift to a 9.33 cents/kWh flat rate for mining companies, as Zesco and the ERB steer power pricing talks, with backdating, copper output, and tariffs in focus.

Key Points

A policy to set a 9.33 cents/kWh flat rate for mines, with Zesco backdating terms still under negotiation.

✅ 9.33 cents/kWh flat tariff accepted by most mining houses

✅ Talks involve Zesco, ERB, First Quantum, Glencore, Vale, Vedanta

✅ Backdating to January remains under negotiation

Zambia is close to reaching an agreement with mining companies over its plans to increase electricity prices, in line with recent increases in Hong Kong seen elsewhere, Finance Minister Felix Mutati reports.

The government last month proposed introducing a flat tariff of 9.30 U.S. cents/kilowatt hour (kWh) backdated to January for mining companies, instead of individually negotiated rates that have averaged 6 U.S. cents/kWh, a structure echoing Manitoba's planned 2.5% yearly hikes over three years, but mining companies opposed the plan.

A team headed by the minister of energy was due to hold talks with mining companies this week, including First Quantum Minerals,.

"We have concluded with all the mining houses except for one. They have accepted our proposal to actually pay 9.33 cents/kwh," Mutati told Reuters in a move comparable to BC Hydro's 3.75% rate plan over two years.

However, an agreement has not yet been reached on backdating the higher tariffs to January as proposed by power firm Zesco Ltd, a point comparable to issues outlined in Nunavut's electricity price hike analysis, he said.

"It is part of the negotiations but ideally that is what the government is considering," Mutati said.

Other mining companies operating in Zambia, Africa's No. 2 copper producer, include Glencore of Switzerland, Brazil's Vale and London-listed Vedanta Resources .

Last week Zambia's Energy Regulation Board (ERB) approved a 75 percent increase in the price of electricity for retail customers, whereas utilities such as BC Hydro's $2 per month proposal in Canada have pursued more gradual adjustments. (Reporting by Chris Mfula; Editing by James Macharia and Susan Fenton)

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NB Power Hydrogen-from-Seawater Project explores clean energy R&D with Joi Scientific, targeting zero-emission electricity for Belledune using Bay of Chaleur seawater, hydrogen production, and possible carbon credits within Canada's climate plan.

Key Points

An NB Power R&D initiative with Joi Scientific to produce hydrogen from seawater for zero-emission power at Belledune.

✅ Targets coal phase-out by 2030 at Belledune

✅ Evaluates costs, efficiency, and carbon credits

✅ Seawater-to-hydrogen tech via proprietary R&D

NB Power is betting $7 million on a promising but untested new way to generate electricity without emitting greenhouse gases: turning seawater from the Bay of Chaleur into energy, a marine approach similar to Nova Scotia's Bay of Fundy tidal tests in recent years.

CEO Gaëtan Thomas talked last month about converting the Belledune generating station to hydrogen power by 2030, after coal is phased out, though some argue planning should be led by an independent planning body to ensure long-term oversight.

But the public utility is tight-lipped so far o

"Unfortunately, it is too early in the process to be discussing details of this research and development project," said NB Power spokesperson Marie-Andrée Bolduc.

Joi Scientific's vice-president of marketing, Vicky Harris, said in an email statement that the company is "involved in multiple research projects, in many different sectors, but, as I am sure you would understand, we are not sharing details of our proprietary research and development work at this time."

On its website, the company calls hydrogen "the universe's most abundant element and the world's cleanest source of energy."

In its collaboration with Florida-based Joi Scientific, a start-up headquartered at the Kennedy Space Centre.

What to do with Belledune?

The federal government has set 2030 as the deadline for provinces to phase out coal-powered electricity under its national climate plan, and NB Power has pursued deals to import Quebec power as part of its transition.

NB Power says other options for Belledune include burning natural gas or biomass, and small nuclear reactors have been discussed provincially as well. But those options would still generate some carbon dioxide emissions.

Green Party Leader David Coon said last month that it was "news to me" that hydrogen power could be generated affordably enough to use in a power plant.

University of New Brunswick chemical engineering professor Willy Cook says turning hydrogen into energy is simple, but it's not necessarily cost-effective because the process itself requires a lot of electricity, while Nova Scotia is pursuing more wind and solar to meet its goals.

"You can't get something for nothing," he said. "Using electricity to produce hydrogen to go back to the process to produce electricity--that in itself probably isn't economically viable."

But he said he's not familiar with Joi Scientific's technology and it's possible the company has come up with "a more efficient process."

He also said if NB Power earned carbon credits for reducing emissions, hydrogen technology might become competitive with other energy sources.

"I have faith in the NB Power engineers to come through and do that assessment properly," he said.

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Alberta Renewable Energy Auction invites bids as AESO adds wind and solar capacity, targeting 5,000 MW by 2030, with 400 MW online by 2019 to replace coal, stabilize prices, and cut greenhouse gas emissions.

Key Points

A program to procure wind and solar for Alberta’s grid, replacing coal and scaling to 5,000 MW by 2030.

✅ 400 MW online by 2019 to backfill retiring coal units

✅ Timed additions to avoid price distortion on the grid

✅ Targets 5,000 MW of renewables by 2030

The operator of Alberta's electricity grid will start taking bids at the end of this month from companies interested in generating and selling renewable energy in the province.

The provincial government wants to add 5,000 megawatts of renewable electricity, supporting new jobs across the province by 2030.

The renewables, including wind power and solar power, will replace coal-fired power plants, which will be shutting down as part of the province's strategy to lower greenhouse gas emissions.

Energy Minister Marg McCuaig-Boyd announced Friday the first competition will be for 400 megawatts, which is enough to power about 170,000 houses.

"We're known as the energy hub of Canada, and make no mistake, green energy is a big part of that," she said.

Mike Deising with the Alberta Electric System Operator (AESO) says the new green power has to be developed gradually.

The new green power must be developed gradually, says Alberta Electric System Operator’s Mike Deising. (CBC)

"We don't want to put on too much generation because what we're going to see is, if we have too much generation all at once, we're going to drive down the market price and it's going to distort the electricity market that we have," he said.

Deising says from their perspective as the grid operator, they want to make sure the addition of new capacity is timed with when they are losing capacity.

AESO wants the 400 megawatts of new green power including solar generation to go onto the grid by the end of 2019 to replace electricity from coal-fired plants that will start shutting down by late 2020.

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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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Peter Sutherland Sr. Generating Station delivers 28 MW hydroelectric, renewable energy in Ontario via an Indigenous partnership, on-budget and ahead of schedule, supplying the provincial grid near the Abitibi River at New Post Creek.

Key Points

An OPG-Indigenous hydropower plant generating 28 MW in northern Ontario, feeding the provincial grid from New Post Creek.

✅ 28 MW hydropower on Abitibi River at New Post Creek.

✅ OPG and Taykwa Tagamou Nation partnership, on-budget and ahead of schedule.

✅ $300 million project delivers jobs, skills, and long-term revenue to community.

Ontario Power Generation, which has also partnered on new nuclear technology with TVA, says a new hydroelectric plant in the northern part of the province is now online, and the First Nation it has partnered with stands to benefit.

In a written release issued Friday, OPG announced the completion of the Peter Sutherland Sr. Generating Station on New Post Creek. The project is a partnership between the provincial power company and Coral Rapids Power, an Indigenous-owned company of the Taykwa Tagamou Nation, near Cochrane.

"This project has gone well due to the relationship we've built on a foundation of respect and trust," Coral Rapids President Wayne Ross was quoted as saying in the OPG release.

"There have been many benefits for our community including good paying jobs, transferable skills and a long term revenue stream."

The generating station, which is located about 80 kilometres north of Smooth Rock Falls, near where New Post Creek meets the Abitibi River, is named after a respected elder of the Taykwa Tagamou Nation. It generates 28 megawatts of power for the provincial grid, according to OPG, complementing modernization at the Niagara Falls powerhouse upgrade as well.

The project was finished ahead of schedule and on-budget, OPG said, as other Ontario initiatives like a pumped storage project advance.

According to the announcement and recent financial results, the project cost around $300 million.

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