Asbestos removal underway at Summerside power plant as upgrades proceed

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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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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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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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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Three Mile Island closure highlights Exelon's nuclear plant losses as cheap natural gas, grid auctions, and renewable energy credits undercut profitability in Pennsylvania, prompting bailout debates over subsidies, reliability, carbon emissions, and local jobs.

Key Points

The Three Mile Island closure is Exelon's plan to shut the plant after gas losses, failed grid bids, and no state aid.

✅ Cheap natural gas undercuts nuclear profitability

✅ Plant missed capacity market awards in grid auctions

✅ Exelon seeks subsidies; Pennsylvania debates costs

Cheap natural gas could do what the worst commercial nuclear power accident in U.S. history could not: put Three Mile Island out of business.

Three Mile Island’s owner, Exelon Corp., announced Tuesday that the plant, now at the center of an energy debate over whether to let struggling nuclear plants close or save them, will close in 2019 unless the state of Pennsylvania comes to its financial rescue.

Nuclear power plants around the U.S. have been struggling in recent years, even as nuclear generation costs hit a ten-year low, to compete with generating stations that burn plentiful and inexpensive natural gas to produce electricity.

The Chicago-based energy company’s announcement came after what it called more than five years of losses at the single-reactor plant and Three Mile Island’s recent failure to be selected as a guaranteed supplier of power to the regional electric grid.

Exelon wants Pennsylvania to give nuclear power the kind of preferential treatment and premium payments that are extended to renewable forms of energy, such as wind and solar. It has not said how much it wants.

Pennsylvania Gov. Tom Wolf has made no commitment to a bailout. In a statement Tuesday, Wolf said he is concerned about layoffs at Three Mile Island and open to discussions about the future of nuclear power in the state. Exelon employs 675 people at the plant, whose license does not expire until 2034.

Nuclear bailouts have won approval in Illinois and New York, but the potential for higher utility bills in Pennsylvania is generating resistance from rival energy companies, manufacturers and consumer advocates.

The control room seen at the Three Mile Island nuclear power plant. The site has struggled to compete in an electricity market booming with inexpensive gas.

David Hughes, president of the Pittsburgh-based consumer group Citizen Power, said the notion that nuclear power is clean energy, as the industry argues, is laughable.

“It’s a myth, and they’re trying any way they can to get more money out of ratepayers,” he said.

In addition to contending that nuclear power can help fight climate change and enable net-zero emissions better than gas or coal, Exelon and other energy companies have argued that their plants are big employers and sources of tax revenue.

“Like New York and Illinois before it, the commonwealth has an opportunity to take a leadership role by implementing a policy solution to preserve its nuclear energy facilities and the clean, reliable energy and good-paying jobs they provide,” Chris Crane, Exelon president and CEO, said in a statement.

Around the U.S., nuclear plants have been hammered by the natural gas boom.

In December, Illinois approved $235 million a year for Exelon to prop up nuclear plants in the Quad Cities and Clinton, six months after the company threatened to shut them down.

FirstEnergy Corp. has said it could decide next year to sell or close its three nuclear plants — Davis-Besse and Perry in Ohio and Beaver Valley in Pennsylvania. PSEG of New Jersey, which owns all or parts of four nuclear plants, has said it won’t operate ones that are long-term money losers.

In this undated file photo, a Pennsylvania state police officer and plant security guards stand outside the closed front gate at Three Mile Island after the plant was shut down following a partial meltdown on March 28, 1979.  (PAUL VATHIS/AP)  

Built during a golden age for nuclear power, Three Mile Island’s Unit 1 went online in 1974 and Unit 2 in 1978, coughing steam into the air above its sliver of land in the Susquehanna River, about 10 miles from Harrisburg.

In March 1979, equipment failure and operator errors led to a partial core meltdown of Unit 2, leading to several days of fear and prompting 144,000 people to flee their homes amid conflicting or ill-informed information from utility and government officials.

Scientists worried at one point that a hydrogen bubble forming inside the reactor would explode with catastrophic consequences.

Experts have come to no firm conclusion about the health effects or the amount of radiation released, though government scientists have said the maximum individual dosage was not enough to cause health problems.

Regardless, the accident badly undermined support for nuclear power. No nuclear plant that was proposed after the accident has been successfully completed and put into operation in the U.S.

The damaged reactor has been mothballed, but the other reactor is still in use. Exelon says the operating costs for just the one unit are high, further straining Three Mile Island’s financial health.

Pennsylvania is the nation’s No. 2 nuclear power state, after Illinois.

Closing Three Mile Island would have little or no effect on electricity bills, analysts say. But the power may be replaced by electricity generated by carbon-emitting fuels such as coal or gas.

Because of the flood of natural gas on the market, a lot of it from the Northeast’s Marcellus Shale formation, dozens of new gas-fired plants are coming online or planned. At the same times, states are putting more emphasis on renewable energy and efficiency.

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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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