Big solar plant planned for northwest China

By Reuters


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Two Chinese companies announced plans to build a solar power plant in northwestern China that could one day be the largest photovoltaic solar project in the world.

The news helped spur a rally in shares of solar power companies that was also underpinned by higher oil prices and a strong rise the broader market.

China Technology Development Group Corp and privately held Qinghai New Energy Group will begin building a 30 megawatt solar power station in China's Qaidam Basin this year with an initial investment of $150 million, they said in a joint statement.

The project, which will combine thin-film and traditional silicon-based technologies that turn the sun's rays into electricity, ultimately will produce 1 gigawatt of power, the companies said, without giving a timeframe.

According to Raymond James analyst Pavel Molchanov, the largest photovoltaic solar project announced to date is the 550 MW deal between closely held thin-film company OptiSolar and California utility PG&E Corp.

"The initial phase of the project is... itself one of the largest solar farms ever announced in China," Molchanov wrote in a client note, adding that the Chinese government is beginning to offer more incentives for solar power projects.

"While PV demand has been historically driven by a small number of key countries, the demand profile should become more geographically diverse over time," Molchanov added.

The news was a welcome reprieve for investors in solar power companies, which have been hard hit by a lack of funding for new projects, a drop in prices on solar panels as supplies have jumped and a dramatic drop in oil prices that has tempered investor appetite for renewable energy.

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The Need for Electricity During the COVID-19 Pandemic

US utilities COVID-19 resilience shows electric utilities maintaining demand stability, reaffirming earnings guidance, and accessing the bond market for low-cost financing, as Dominion, NextEra, and Con Edison manage recession risks.

 

Key Points

It is the sector's capacity to sustain demand, financing access, and guidance despite pandemic recession pressures.

✅ Bond market access locks in low-cost, long-term debt

✅ Stable residential load offsets industrial weakness

✅ Guidance largely reaffirmed by major utilities

 

Dominion Energy (D) expects "incremental residential load" gains, consistent with COVID-19 electricity demand patterns, as a result of COVID-19 fallout. Southern Company CEO Tom Fanning says his company is "nowhere near" a need to review earnings guidance because of a potential recession, in a region where efficiency and demand response can help level electricity demand for years.

Sempra Energy (SRE) has reaffirmed earnings per share guidance for 2020 and 2021, as well timing for the sale of assets in Chile and Peru, and peers such as Duke Energy's renewables plan have reaffirmed capital investments to deliver cleaner energy and economic growth. And Xcel Energy (XEL) says it still "hasn’t seen material impact on its business."

Several electric utilities have demonstrated ability to tap the bond market, in line with utility sector trends in recent years, to lock in low-cost financing, as America moves toward broader electrification, despite ongoing turmoil. Their ranks include Dominion Energy, renewable energy leader NextEra Energy (NEE) and Consolidated Edison (ED), which last week sold $1 billion of 30-year bonds at a coupon rate of just 3.95 percent.

It’s still early days for US COVID-19 fallout. And most electric companies have yet to issue guidance. That’s understandable, since so much is still unknown about the virus and the damage it will ultimately do to human health and the global economy. But so far, the US power industry is showing typical resilience in tough times, as it coordinates closely with federal partners to maintain reliability.

Will it last? We won’t know for certain until there’s a lot more data. NextEra is usually first to report its Q1 earnings reports and detailed guidance. But that’s not expected until April 23. And companies may delay financials further, should the virus and efforts to control it impede collection and analysis of data, and as they address electricity shut-off risks affecting customers.

 

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Hydro once made up around half of Alberta's power capacity. Why does Alberta have so little now?

Alberta Hydropower Potential highlights renewable energy, dams, reservoirs, grid flexibility, contrasting wind and solar growth with limited investment, regulatory hurdles, river basin resources, and decarbonization pathways across Athabasca, Peace, and Slave River systems.

 

Key Points

It is the technical capacity for new hydro in Alberta's river basins to support a more reliable, lower carbon grid.

✅ 42,000 GWh per year developable hydro identified in studies.

✅ Major potential in Athabasca, Peace, and Slave River basins.

✅ Barriers include high capital costs, market design, water rights.

 

When you think about renewable energy sources on the Prairies, your mind may go to the wind farms in southern Alberta, or even the Travers Solar Project, southeast of Calgary.

Most of the conversation around renewable energy in the province is dominated by advancements in solar and wind power, amid Alberta's renewable energy surge that continues to attract attention. 

But what about Canada's main source of electricity — hydro power?

More than half of Canada's electricity is generated from hydro sources, with 632.2 terawatt-hours produced as of 2019. That makes it the fourth largest installed capacity of hydropower in the world. 

But in Alberta, it's a different story. 

Currently, hydro power contributes between three and five per cent of Alberta's energy mix, while fossil fuels make up about 89 per cent.

According to Canada's Energy Future report from the Canada Energy Regulator, by 2050 it will make up two per cent of the province's electricity generation shares.

So why is it that a province so rich in mountains and rivers has so little hydro power?


Hydro's history in Alberta
Hydro power didn't always make up such a small sliver of Alberta's electricity generation. Hydro installations began in the early 20th century as the province's population exploded. 

Grant Berg looks after engineering for hydro for TransAlta, Alberta's largest producer of hydro power with 17 facilities across the province.

"Our first plant was Horseshoe, which started in 1911 that we formed as Calgary Power," he said. 

"It was really in response to the City of Calgary growing and having some power needs."

Berg said in 1913, TransAlta's second installation, the Kananaskis Plant, started as Calgary continued to grow.

A historical photo of a hydro-electric dam in Kananaskis Alta. taken in 1914.
Hydro power plant in Kananaskis as seen in 1914. (Glenbow Archives)
Some bigger installations were built in the 1920s, including Ghost reservoir, but by mid-century population growth increased.

"Quite a large build out really, I think in response to the growth in Alberta following the war. So through the 1950s really quite a large build out of hydro from there."

By the 1950s, around half of the province's installed capacity was hydro power.

"Definitely Calgary power was all hydro until the 1950s," said Berg. 


Hydro potential in the province 
Despite the current low numbers in hydroelectricity, Alberta does have potential. 

According to a 2010 study, there is approximately 42,000 gigawatt-hours per year of remaining developable hydroelectric energy potential at identified sites. 

An average home in Alberta uses around 7,200 kilowatt-hours of electricity per year, meaning that the hydro potential could power 5.8 million homes each year. 

"This volume of energy could be sufficient to serve a significant amount of Alberta's load and therefore play a meaningful role in the decarbonization of the province's electric system," the Alberta Electric System Operator said in its 2022 Pathways to Net-Zero Emissions report.

Much of that potential lies in northern Alberta, in the Athabasca, Peace and Slave River basins.

The AESO report says that despite the large resource potential, Alberta's energy-only market framework has attracted limited investment in hydroelectric generation. 

Hydro power was once a big deal in Alberta, but investment in the industry has been in decline since the 1950s. Climate change reporter Christy Climenhaga explains why.
So why does Alberta leave out such a large resource potential on the path to net zero?

The government of Alberta responded to that question in a statement. 

"Hydro facilities, particularly large scale ones involving dams, are associated with high costs and logistical demands," said the Ministry of Affordability and Utilities. 

"Downstream water rights for other uses, such as irrigation, further complicate the development of hydro projects."

The ministry went on to say that wind and solar projects have increased far more rapidly because they can be developed at relatively lower cost and shorter timelines, and with fewer logistical demands.

"Sources from wind power and solar are increasingly more competitive," said Jean-Denis Charlebois, chief economist with the Canadian Energy Regulator. 


Hydro on the path to net zero
Hydro power is incredibly important to Canada's grid, and will remain so, despite growth in wind and solar power across the province.

Charlebois said that across Canada, the energy make-up will depend on the province. 

"Canadian provinces will generate electricity in very different ways from coast to coast. The major drivers are essentially geography," he said. 

Charlebois says that in British Columbia, Manitoba, Quebec and Newfoundland and Labrador, hydropower generation will continue to make up the majority of the grid.

"In Alberta and Saskatchewan, we see a fair bit of potential for wind and solar expansion in the region, which is not necessarily the case on Canada's coastlines," he said.

And although hydro is renewable, it does bring its adverse effects to the environment — land use changes, changes in flow patterns, fish populations and ecosystems, which will have to be continually monitored. 

"You want to be able to manage downstream effects; make sure that you're doing all the proper things for the environment," said Ryan Braden, director of mining and hydro at TransAlta.

Braden said hydro power still has a part to play in Alberta, even with its smaller contributions to the future grid. 

"It's one of those things that, you know, the wind doesn't blow or the sun doesn't shine, this is here. The way we manage it, we can really support that supply and demand," he said.

 

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COVID-19 pandemic zaps electricity usage in Ontario as people stay home

Ontario Electricity Demand 2020 shows a rare decline amid COVID-19, with higher residential peak load, lower commercial usage, hot-weather air conditioning, nuclear baseload constraints, and smart meter data shaping grid operations and forecasting.

 

Key Points

It refers to 2020 power use in Ontario: overall demand fell, while residential peaks rose and commercial loads dropped.

✅ Peak load shifted to homes; commercial usage declined.

✅ Hot summers raised peaks; overall annual demand still fell.

✅ Smart meters aid forecasting; grid must balance nuclear baseload.

 

Demand for electricity in Ontario last year fell to levels rarely seen in decades amid shifts in usage patterns caused by pandemic measures, with Ottawa’s electricity consumption dropping notably, new data show.

The decline came despite a hot summer that had people rushing to crank up the air conditioning at home, the province’s power management agency said, even as the government offered electricity relief to families and small businesses.

“We do have this very interesting shift in who’s using the energy,” said Chuck Farmer, senior director of power system planning with the Independent Electricity System Operator.

“Residential users are using more electricity at home than we thought they would and the commercial consumers are using less.”

The onset of the pandemic last March prompted stay-home orders, businesses to close, and a shuttering of live sports, entertainment and dining out. Social distancing and ongoing restrictions, even as the first wave ebbed and some measures eased, nevertheless persisted and kept many people home as summer took hold and morphed into winter, while the province prepared to extend disconnect moratoriums for residential customers.

System operator data show peak electricity demand rose during a hot summer spell to 24,446 megawatts _ the highest since 2013. Overall, however, Ontario electricity demand last year was the second lowest since 1988, the operator said.

In all, Ontario used 132.2 terawatt-hours of power in 2020, a decline of 2.9 per cent from 2019.

With more people at home during the lockdown, winter residential peak demand has climbed 13 per cent above pre-pandemic levels, even as Hydro One made no cut in peak rates for self-isolating customers, while summer peak usage was up 19 per cent.

“The peaks are getting higher than we would normally expect them to be and this was caused by residential customers _ they’re home when you wouldn’t expect them to be home,” Farmer said.

Matching supply and demand _ a key task of the system operator _ is critical to meeting peak usage and ensuring a stable grid, and the operator has contingency plans with some key staff locked down at work sites to maintain operations during COVID-19, because electricity cannot be stored easily. It is also difficult to quickly raise or lower the output from nuclear-powered generators, which account for the bulk of electricity in the province, as demand fluctuates.

READ MORE: Ontario government extends off-peak electricity rates to Feb. 22

Life patterns have long impacted overall usage. For example, demand used to typically climb around 10 p.m. each night as people tuned into national television newscasts. Livestreaming has flattened that bump, while more energy-efficient lighting led to a drop in provincial demand over the holiday season.

The pandemic has now prompted further intra-day shifts in usage. Fewer people are getting up in the morning and powering up at home before powering down and rushing off to work or school. The summer saw more use of air conditioners earlier than normal after-work patterns.

Weather has always been a key driver of demand for power, accounting for example for the record 27,005 megawatts of usage set on a brutally hot Aug. 1, 2006. Similarly, a mild winter and summer led to an overall power usage drop in 2017.

Still, the profound social changes prompted by the COVID-19 pandemic _ and whether some will be permanent _ have complicated demand forecasting.

“Work patterns used to be much more predictable,” the agency said. “The pandemic has now added another element of variability for electricity demand forecasting.”

Some employees sent home to work have returned to their offices and other workplaces, and many others are likely do so once the pandemic recedes. However, some larger companies have indicated that working from home will be long term.

“Companies like Facebook and Shopify have already stated their intention to make work from home a more permanent arrangement,” the operator said. “This is something our near-term forecasters would take into account when preparing for daily operation of the grid.”

Aggregated data from better smart meters, which show power usage throughout the day, is one method of improving forecasting accuracy, the operator said.

 

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Manchin Calls For Stronger U.S. Canada Energy And Mineral Partnership

U.S.-Canada Energy and Minerals Partnership strengthens energy security, critical minerals supply chains, and climate objectives with clean oil and gas, EV batteries, methane reductions, cross-border grid reliability, and allied trade, countering Russia and China dependencies.

 

Key Points

A North American alliance to secure energy, refine critical minerals, cut emissions, and fortify supply chains.

✅ Integrates oil, gas, and electricity trade for reliability

✅ Builds EV battery and critical minerals processing capacity

✅ Reduces methane, diversifies away from Russia and China

 

Today, U.S. Senator Joe Manchin (D-WV), Chairman of the Senate Energy and Natural Resources Committee, delivered the following remarks during a full committee hearing to examine ways to strengthen the energy and mineral partnership between the U.S. and Canada to address energy security and climate objectives.

The hearing also featured testimony from the Honorable Jason Kenney (Premier, Alberta, Canada), the Honorable Nathalie Camden (Associate Deputy Minister of Mines, Ministry of Energy and Natural Resource, Québec, Canada), the Honorable Jonathan Wilkinson (Minister, Natural Resources Canada) and Mr. Francis Bradley (President and CEO, Electricity Canada). Click here to read their testimony.

Chairman Manchin’s remarks can be viewed as prepared here or read below:

Today we’re welcoming our friends from the North, from Canada, to continue this committee’s very important conversation about how we pursue two critical goals – ensuring energy security and addressing climate change.

These two goals aren’t mutually exclusive, and it’s imperative that we address both.

We all agree that Putin has used Russia’s oil and gas resources as a weapon to inflict terrible pain on the Ukrainian people and on Europe.

And other energy-rich autocracies are taking note. We’d be fools to think Xi Jinping won’t consider using a similar playbook, leveraging China’s control over global critical minerals supply chains.

But Putin’s aggression is bringing the free world closer together, setting the stage for a new alliance around energy, minerals, and climate.
Building this alliance should start here in North America. And that’s why I’m excited to hear today about how we can strengthen the energy and minerals partnership between the U.S. and Canada.

I recently had the privilege of being hosted in Alberta by Premier Kenney, where I spent two days getting a better understanding of our energy, minerals, and manufacturing partnership through meetings with representatives from Alberta, Saskatchewan, the Northwest Territories, the federal government, and tribal and industry partners.

Canadians and Americans share a deep history and are natural partners, sharing the longest land border on the planet.

Our people fought side-by-side in two world wars. In fact, some of the uranium used by the Manhattan Project and broader nuclear innovation was mined in Canada’s Northwest Territories and refined in Ontario.

We have cultivated a strong manufacturing partnership, particularly in the automotive industry, with Canada today being our biggest export market for vehicles. Cars assembled in Canada contain, on average, more than 50% of U.S. value and parts.

Today we also trade over 58 terawatt hours of electricity, including green power from Canada across the border, 2.4 billion barrels of petroleum products, and 3.6 trillion cubic feet of natural gas each year.

In fact, energy alone represents $120 billion of the annual trade between our countries. Across all sectors the U.S. and Canada trade more than $2 billion per day.
There is no better symbol of our energy relationship than our interconnected power grid and evolving clean grids that are seamless and integral for the reliable and affordable electricity citizens and industries in both our countries depend on.

And we’re here for each other during times of need. Electricity workers from both the U.S. and Canada regularly cross the border after extreme weather events to help get the power back on.

Canada has ramped up oil exports to the U.S. to offset Russian crude after members of our committee led legislation to cut off the energy purchases fueling Putin’s war machine.

Canada is also a leading supplier of uranium and critical minerals to the U.S., including those used in advanced batteries—such as cobalt, graphite, and nickel.
The U.S-Canada energy partnership is strong, but also not without its challenges, including tariff threats that affect projects on both sides. I’ve not been shy in expressing my frustration that the Biden administration cancelled the Keystone XL pipeline.

In light of Putin’s war in Ukraine and the global energy price surge, I think a lot of us wish that project had moved forward.

But to be clear, I’m not holding this hearing to re-litigate the past. We are here to advance a stronger and cleaner U.S.-Canada energy partnership for the future.
Our allies and trading partners in Europe are begging for North American oil and gas to offset their reliance on Russia.

There is no reason whatsoever we shouldn’t be able to fill that void, and do it cleaner than the alternatives.

That’s because American oil and gas is cleaner than what is produced in Russia – and certainly in Iran and Venezuela. We can do better, and learn from our Canadian neighbors.

On average, Canada produces oil with 37% lower methane emissions than the U.S., and the Canadian federal government has set even more aggressive methane reduction targets.

That’s what I mean by climate and security not being mutually exclusive – replacing Russian product has the added benefit of reducing the emissions profile of the energy Europe needs today.

According to the International Energy Agency, stationary and electric vehicle batteries will account for about half of the mineral demand growth from clean energy technologies over the next twenty years.

Unfortunately, China controls 80% of the world’s battery material processing, 60% of the world’s cathode production, 80% of the world’s anode production, and 75% of the world’s lithium ion battery cell production. They’ve cornered the market.

I also strongly believe we need to be taking national energy security into account as we invest in climate solutions.

It makes no sense whatsoever for us to so heavily invest in electric vehicles as a climate solution when that means increasing our reliance on China, because right now we’re not simultaneously increasing our mining, processing, and recycling capacity at the same rate in the United States.

The Canadians are ahead of us on critical minerals refining and processing, and we have much to learn from them about how they’re able to responsibly permit these activities in timelines that blow ours out of the water.

I’m sure our Canadian friends are happy to export minerals to us, but let me be clear, the United States also needs to contribute our part to a North American minerals alliance.

So I’m interested in discussing how we can create an integrated network for raw minerals to move across our borders for processing and manufacturing in both of our countries, and how B.C. critical minerals decisions may affect that.

I believe there is much we can collaborate on with Canada to create a powerful North American critical minerals supply chain instead of increasing China’s geopolitical leverage.

During this time when the U.S., Canada, and our allies and friends are threatened both by dictators weaponizing energy and by intense politicization over climate issues, we must work together to chart a responsible path forward that will ensure security and unlock prosperity for our nations.

We are the superpower of the world, and blessed with abundant energy and minerals resources. We cannot just sit back and let other countries fill the void and find ourselves in a more dire situation in the years ahead.

We must be leaning into the responsible production of all the energy sources we’re going to need, and strengthening strategic partnerships – building a North American Energy Alliance.

 

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Share of coal in UK's electricity system falls to record lows

UK Coal Phase-Out marks record-low coal generation as the UK grid shifts to renewable power, wind farms, and a net zero trajectory, slashing carbon emissions and supporting cleaner EV charging across the electricity system.

 

Key Points

UK Coal Phase-Out ends coal-fired electricity nationwide, powered by renewables and net zero policy to cut grid carbon.

✅ Coal's Q2 share fell to 0.7%, a record low

✅ Renewables up 12% with Beatrice wind farm

✅ EV charging grows cleaner as grid decarbonizes

 

The share of coal in the UK’s electricity system has fallen to record lows in recent months, alongside a coal-free power record, according to government data.

The figures show electricity generated by the UK’s most polluting power plants made up an average of 0.7% of the total in the second quarter of this year, a shift underway since wind first outpaced coal in 2016 across the UK. The amount of coal used to power the electricity grid fell by almost two-thirds compared with the same months last year.

A government spokesperson said coal-generated energy “will soon be a distant memory” as the UK moves towards becoming a net zero emissions economy, despite signs that low-carbon generation stalled in 2019 in some analyses.

“This new record low is a result of our world-leading low-carbon energy industry, which provided more than half of our energy last year and continues to go from strength to strength as we aim to end our contribution to climate change entirely by 2050,” the spokesperson said.

The UK electricity market is on track to end coal power after 142 years by the government’s target date of 2025.

This year three major energy companies have announced plans to close coal-fired power plants in the UK, which would leave only four remaining after the coming winter, ahead of the last coal power station going offline nationwide.

RWE said this month it would close the Aberthaw B power station in south Wales, its last UK coal plant, after the winter. SSE will close the Fiddler’s Ferry plant near Warrington, Cheshire, in March 2020, and EDF Energy will shutter the Cottam coal plant in September.

So far this year the UK has gone more than 3,000 hours without using coal for power, including a full week without coal earlier in the year – nearly five times more than the whole of 2017.

Meanwhile, the government’s data shows that renewable energy climbed by 12% from the second quarter of last year, boosted by the startup of the Beatrice windfarm in the Moray Firth in Scotland, and the UK leading the G20 in wind power share in recent assessments.

The cleaner power system could accelerate carbon savings from the UK’s roads, too, as more drivers opt for electric vehicles. A study by Imperial College London for the energy company Drax found that the UK’s increasingly low-carbon energy system meant electric cars were a greener option even when taking into account the carbon emissions produced by making car batteries.

Dr Iain Staffell, of Imperial College London, said: “An electric vehicle in the UK simply cannot be more polluting than its petrol or diesel equivalent – even when taking into account the upfront carbon cost of manufacturing their batteries. Any EV bought today could be emitting just a tenth of what a petrol car would in as little as five years’ time, as the electricity it uses to charge comes from an increasingly low-carbon mix.”

 

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BC Hydro rates going up 3 per cent

BC Hydro Rate Freeze Rejection details the BCUC decision enabling a 3% rate increase, citing revenue requirements, debt, and capital costs, affecting electricity bills, with NDP government proposing lifeline rates and low-income relief.

 

Key Points

It is the BCUC ruling allowing a 3% BC Hydro rate hike, citing cost recovery, debt, and capital needs.

✅ BCUC rejects freeze; 3% increase proceeds April 1, 2018

✅ Rationale: cost recovery, debt, capital expenditures

✅ Relief: lifeline rate, $600 grants, winter payment plan

 

The B.C. Utilities Commission has rejected a request by the provincial government to freeze rates at BC Hydro for the coming year, meaning a pending rate increase of three percent will come into effect as higher BC Hydro rates on April 1, 2018.

BC Hydro had asked for the three per cent increase, aligning with a rate increase proposal that would add about $2 a month, but, last year, Energy Minister Michelle Mungall directed the Crown corporation to resubmit its request in order to meet an NDP election promise.

"After years of escalating electricity costs, British Columbians deserve a break on their bills," she said at the time.

However, the utilities commission found there was "insufficient regulatory justification to approve the zero per cent rate increase."

"Even these increases do not fully recover B.C. Hydro's forecast revenue requirement, which includes items such as operating costs, new capital expenditures and carrying costs on capital expenditures," the commission wrote in a news release.

Mungall said she was disappointed by the decision.

"We were always clear we were going to the BCUC. We need to respect the role the BCUC has here for the ratepayers and for the public. I'm very disappointed obviously with their decision."

Mungall blamed the previous government for leaving BC Hydro in a financial state where a rate freeze was ultimately not possible.

Last month, Moody's Investors Service calculated BC Hydro's total debt at $22 billion and said it was one of the province's two credit challenges going forward.

"There's quite a financial mess that is a B.C. Liberal legacy after 16 years of government. We have the responsibility as a new government to clean that up."

B.C. Liberal leader Andrew Wilkinson said it was an example of the new government not living up to its campaign promises.

"British Columbians, particularly those on fixed incomes, believed the B.C. NDP when they promised a freeze on hydro bills. They planned accordingly and are now left in the lurch and face higher expenses. This is a government that stumbles into messes that cost all of us because they put rhetoric ahead of planning," he said.

 

Help on the way?

With the freeze being rejected, Mungall said the government would be going forward on other initiatives to help low-income ratepayers, as advocates' call for change after a fund surplus, including:

Legislating a "lifeline rate" program, allowing people with "demonstrated need" to apply for a lower rate for electricity.

Starting in May, providing an emergency grant of $600 for customers who have an outstanding BC Hydro bill.

Hydro's annual winter payment plan also allows people the chance to spread the payment of bills from December to February out over six months, and, with a two-year rate increase on the horizon, a new pilot program to help people paying their bills begins in July.

Mungall couldn't say whether the government would apply for rate freezes in the future.

"I don't have a crystal ball, and can't predict what might happen in two or three years from now, but we need to act swiftly now," she said.

"I appreciate the [BCUC's] rationale, I understand it, and we'll be moving forward with other alternatives for making life more affordable."

 

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