Electricity News in March 2021
Shanghai Electric Signs Agreement to Launch PEM Hydrogen Production Technology R&D Center, Empowering Green Hydrogen Development in China
Shanghai Electric PEM Hydrogen R&D Center advances green hydrogen via PEM electrolysis, modular megawatt electrolyzers, zero carbon production, and full-chain industrial applications, accelerating decarbonization, clean energy integration, and hydrogen economy scale-up across China.
Key Points
A joint R&D hub advancing PEM electrolysis, modular megawatt systems, and green hydrogen industrialization.
✅ Megawatt modular PEM electrolyzer design and system integration
✅ Zero-carbon hydrogen targeting mobility, chemicals, and power
✅ Full-chain collaboration from R&D to EPC and demonstration projects
Shanghai Electric has reached an agreement with the Dalian Institute of Chemical Physics of the Chinese Academy of Sciences (the "Dalian Institute") to inaugurate the Proton Exchange Membrane (PEM) Hydrogen Production Technology R&D Center on March 4. The two parties signed a project cooperation agreement on Megawatt Modular and High-Efficiency PEM Hydrogen Production Equipment and System Development, marking an important step forward for Shanghai Electric in the field of hydrogen energy.
As one of China's largest energy equipment manufacturers, Shanghai Electric is at the forefront in the development of green hydrogen as part of China's clean energy drive. During this year's Two Sessions, the 14th Five-Year Plan was actively discussed, in which green hydrogen features prominently, and Shell's 2060 electricity forecast underscores the scale of electrification. With strong government support and widespread industry interest, 2021 is emerging as Year Zero for the hydrogen energy industry.
Currently, Shanghai Electric and the Dalian Institute have reached a preliminary agreement on the industrial development path for new energy power generation and electrolyzed water hydrogen production. As part of the cooperation, both will also continue to enhance the transformational potential of PEM electrolyzed water hydrogen production, accelerate the development of competitive PEM electrolyzed hydrogen products, and promote industrial applications and scenarios, drawing on projects like Japan's large H2 energy system to inform deployment. Moreover, they will continue to carry out in-depth cooperation across the entire hydrogen energy industry chain to accelerate overall industrialization.
Hydrogen energy boasts the biggest potential of all the current forms of clean energy, and the key to its development lies in its production. At present, hydrogen production primarily stems from fossil fuels, industrial by-product hydrogen recovery and purification, and production by water electrolysis. These processes result in significant carbon emissions. The rapid development of PEM water electrolysis equipment worldwide in recent years has enabled current technologies to achieve zero carbon emissions, effectively realizing green, clean hydrogen. This breakthrough will be instrumental in helping China achieve its carbon peak and carbon-neutrality goals.
The market potential for hydrogen production from electrolyzed water is therefore massive. Forecasts indicate that, by 2050, hydrogen energy will account for approximately 10% of China's energy market, with demand reaching 60 million tons and annual output value exceeding RMB 10 trillion. The Hydrogen: Tracking Energy Integration report released by the International Energy Agency in June 2020 notes that the number of global electrolysis hydrogen production projects and installed capacity have both increased significantly, with output skyrocketing from 1 MW in 2010 to more than 25 MW in 2019. Much of the excitement comes from hydrogen's potential to join the ranks of natural gas as an energy resource that plays a pivotal role in international trade, as seen in Germany's call for hydrogen-ready power plants shaping future power systems, with the possibility of even replacing it one day. In PwC's 2020 The Dawn of Green Hydrogen report, the advisory predicts that experimental hydrogen will reach 530 million tons by mid-century.
Shanghai Electric set its focus on hydrogen energy years ago, given its major potential for growth as one of the new energy technologies of the future and, in particular, its ability to power new energy vehicles. In 2016, the Central Research Institute of Shanghai Electric began to invest in R&D for key fuel cell systems and stack technologies. In 2020, Shanghai Electric's independently-developed fuel cell engine, which boasts a power capacity of 66 kW and can start in cold temperature environments of as low as -30°C, passed the inspection test of the National Motor Vehicle Product Quality Inspection Center. It adopts Shanghai Electric's proprietary hydrogen circulation system, which delivers strong power and impressive endurance, with the potential to replace gasoline and diesel engines in commercial vehicles.
As the technology matures, hydrogen has entered a stage of accelerated industrialization, with international moves such as Egypt's hydrogen MoU with Eni signaling broader momentum. Shanghai Electric is leveraging the opportunities to propel its development and the green energy transformation. As part of these efforts, Shanghai Electric established a Hydrogen Energy Division in 2020 to further accelerate the development and bring about a new era of green, clean energy.
As one of the largest energy equipment manufacturing companies in China, Shanghai Electric, with its capability for project development, marketing, investment and financing and engineering, procurement and construction (EPC), continues to accelerate the development and innovation of new energy. The Company has a synergistic foundation and resource advantages across the industrial chain from upstream power generation, including China's nuclear energy development efforts, to downstream chemical metallurgy. The combined elements will accelerate the pace of Shanghai Electric's entry into the field of hydrogen production.
Currently, Shanghai Electric has deployed a number of leading green hydrogen integrated energy industry demonstration projects in Ningdong Base, one of China's four modern coal chemical industry demonstration zones. Among them, the Ningdong Energy Base "source-grid-load-storage-hydrogen" project integrates renewable energy generation, energy storage, hydrogen production from electrolysis, and the entire industrial chain of green chemical/metallurgy, where applications like green steel production in Germany illustrate heavy-industry decarbonization.
In December 2020, Shanghai Electric inked a cooperation agreement to develop a "source-grid-load-storage-hydrogen" energy project in Otog Front Banner, Inner Mongolia. Equipped with large-scale electrochemical energy storage and technologies such as compressed air energy storage options, the project will build a massive new energy power generation base and help the region to achieve efficient cold, heat, electricity, steam and hydrogen energy supply.
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Mercury in $3 billion takeover bid for Tilt Renewables
Mercury Energy Tilt Renewables acquisition signals a trans-Tasman energy push as PowAR and Mercury split assets via a scheme of arrangement, offering $7.80 per share and a $2.96b valuation across Australia and New Zealand.
Key Points
A PowAR-Mercury deal to buy Tilt Renewables, splitting Australian and New Zealand assets via a court-approved scheme.
✅ $7.80 per share, valuing Tilt at $2.96b
✅ PowAR takes AU assets; Mercury gets NZ business
✅ Infratil and Mercury to vote for the scheme
Mercury Energy and an Australian partner appear to have won the race to buy Tilt Renewables, an Australasian wind farm developer which was spun out of TrustPower, bidding almost $3 billion, amid wider utility consolidation such as the Peterborough Distribution sale to Hydro One.
Yesterday Tilt Renewables announced that it had entered a scheme implementation agreement under which it was proposed that PowAR would acquire its Australian business and Mercury would acquire the New Zealand business, mirroring cross-border approvals where U.S. antitrust clearance shaped Hydro One's bid for Avista.
Conducted through a scheme of arrangement, Tilt shareholders will be offered $7.80 a share, valuing Tilt at $2.96b.
Yesterday morning shares in Tilt opened about 18 per cent up at $7.65, though regulatory outcomes can swing valuations as seen when Hydro One-Avista reconsideration of a U.S. order came into play.
In early December Infratil, which owns around two thirds of Tilt's shares, announced it was undertaking a review of its investment after receiving approaches, with investor sentiment sensitive to governance shifts as when Hydro One shares fell after leadership changes in Ontario.
According to a report in the Australian Financial Review, the transtasman bid beat out other parties including ASX-listed APA Group, Canadian pension fund CDPQ and Australian fund manager Infrastructure Capital Group, as Canadian investors like Ontario Teachers' Plan pursue similar infrastructure deals.
“This compelling acquisition proposal is a result of Tilt Renewables’ constant focus on delivering long-term value for shareholders and the board is pleased that, with these new owners, the transition to renewables in Australia and New Zealand will continue to accelerate,” Tilt’s chairman Bruce Harker said.
Comparable community-led clean energy partnerships, such as initiatives with British Columbia First Nations highlighted in clean-energy generation, underscore the broader momentum.
Just prior to the announcement, Tilt shares had been trading for less than $4. Such repricing reflects how utilities can face perceived uncertainties, as one investor argued too many unknowns at the time.
Mercury is already Tilt’s second largest shareholder, at just under 20 per cent. Both Infratil and Mercury have agreed to vote in favour of the scheme. The deal values Tilt’s New Zealand business at $770m, however the value of Mercury’s existing shareholding is around $585m, meaning the company will increase debt by around $185m.
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GE to create 300 new jobs at French offshore wind blade factory
LM Wind Power Cherbourg Recruitment 2021 targets 300 new hires for offshore wind manufacturing, wind turbine blade production, Haliade-X components, and operations in France, with Center of Excellence training and second 107-meter blade mold expansion.
Key Points
A hiring drive to add 300 staff for offshore wind blade manufacturing in Cherbourg, with Center of Excellence training.
✅ 300 hires to scale offshore wind blade production
✅ 6-week Center of Excellence training for all recruits
✅ Second 107-meter blade mold boosts capacity
GE Renewable Energy plans to recruit 300 employees in 2021 at its LM Wind Power wind turbine blade factory in Cherbourg, France / Opened almost three years ago in April 2018, the factory today counts more than 450 employees / Every new hire will go through an intensive training program at the factory's ‘Center of Excellence' to learn wind turbine blade manufacturing processes / Site has produced the first offshore wind turbine blade longer than 100 meters, 107-meters long / Second 107-meter blade manufacturing mold is being installed at the plant today
GE Renewable Energy announced today its plan to recruit 300 employees at its LM Wind Power wind turbine blade manufacturing site in Cherbourg, France, in 2021. Every new hire will go through an intensive training program at the factory's ‘Center of Excellence' to learn wind turbine blade manufacturing processes supporting offshore wind energy growth in Europe. The expanded production workforce will allow LM Wind Power to meet the growing industry demand for offshore wind equipment, including emerging offshore green hydrogen applications across the sector.
The factory currently has more than 450 employees, with 34 percent being women. The facility became the first wind turbine blade manufacturing site in France when it was opened almost three years ago in April 2018, while Spanish wind factories faced temporary closures due to COVID-19 restrictions.
The facility has produced the first offshore wind turbine blade longer than 100 meters, a 107-meters long blade that will be used in GE’s Haliade-X offshore wind turbine. A second 107-meter blade manufacturing mold is currently being installed at the plant to support growing project pipelines like those planned off Massachusetts' South Coast in the U.S.
Florence Martinez Flores, the site’s Human Resources Director, said: "The arrival of the second mold within the factory marks an increased activity for LM Wind Power in Cherbourg, and we are happy to welcome a large wave of new employees, allowing us to participate in social development and create more jobs in the surrounding community, but also to bring new skills to the region."
Recent investments such as EDF Irish offshore wind stake news underscore the broader market momentum.
The Cherbourg team is mostly looking to expand its production workforce, with positions that are open to all profiles and backgrounds. Every new employee will be trained to manufacture wind turbine blades through LM Wind Power's ‘Center of Excellence' training program – a six-week theoretical and practical training course, which will develop the skills and technical expertise required to produce high-quality wind turbine blades and support wind turbine operations and maintenance across the industry. The site will also be looking for production supervisors, quality controllers and maintenance technicians.
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German steel powerhouse turns to 'green' hydrogen produced using huge wind turbines
Green Hydrogen for Steelmaking enables decarbonization in Germany by powering electrolyzers with wind turbines at Salzgitter. Partners Vestas, Avacon, and Linde support renewable hydrogen for iron ore reduction, cutting CO2 in heavy industry.
Key Points
Hydrogen from renewable-powered electrolysis replacing coal in iron ore reduction, cutting CO2 emissions from steelmaking
✅ 30 MW Vestas wind farm powers 2x1.25 MW electrolyzers.
✅ Salzgitter, Avacon, Linde link sectors to replace fossil fuels.
✅ Targets CO2 cuts in iron ore reduction and steel smelting.
A major green hydrogen facility in Germany has started operations, with those behind the project hoping it will help to decarbonize the energy-intensive steel industry in the years ahead.
The "WindH2" project involves German steel giant Salzgitter, E.ON subsidiary Avacon and Linde, a firm specializing in engineering and industrial gases, and aligns with calls for hydrogen-ready power plants in Germany today.
Hydrogen can be produced in a number of ways. One method includes using electrolysis, with an electric current splitting water into oxygen and hydrogen, and advances in PEM hydrogen technology continue to improve efficiency worldwide.
If the electricity used in the process comes from a renewable source such as wind or solar, as underscored by recent German renewables gains, then it's termed "green" or "renewable" hydrogen.
The development in Germany is centered around seven new wind turbines operated by Avacon and two 1.25 megawatt (MW) electrolyzer units installed by Salzgitter Flachstahl, which is part of the wider Salzgitter Group. The facilities were presented to the public this week.
The turbines, from Vestas, have a hub height of 169 meters and a combined capacity of 30 MW. All are located on premises of the Salzgitter Group, with three situated on the site of a steel mill in the city of Salzgitter, Lower Saxony, northwest Germany, where grid expansion woes can affect project timelines.
The hydrogen produced using renewables will be utilized in processes connected to the smelting of iron ore. Total costs for the project come to roughly 50 million euros (around $59.67 million), with the building of the electrolyzers subsidized by state-owned KfW, while a national net-zero roadmap could reduce electricity costs over time.
"Green gases have the wherewithal to become 'staple foodstuff' for the transition to alternative energies and make a considerable contribution to decarbonizing industry, mobility and heat," E.ON's CEO, Johannes Teyssen, said in a statement issued Thursday.
"The jointly realized project symbolizes a milestone on the path to virtually CO2 free production and demonstrates that fossil fuels can be replaced by intelligent cross-sector linking," he added.
According to the International Energy Agency, the iron and steel sector is responsible for 2.6 gigatonnes of direct carbon dioxide emissions each year, a figure that, in 2019, was greater than the direct emissions from sectors such as cement and chemicals.
It adds that the steel sector is "the largest industrial consumer of coal, which provides around 75% of its energy demand."
The project in Germany is not unique in focusing on the role green hydrogen could play in steel manufacturing.
Across Europe, projects are also exploring natural gas pipe storage to balance intermittent renewables and enable sector coupling.
H2 Green Steel, a Swedish firm backed by investors including Spotify founder Daniel Ek, plans to build a steel production facility in the north of the country that will be powered by what it describes as "the world's largest green hydrogen plant."
In an announcement last month the company said steel production would start in 2024 and be based in Sweden's Norrbotten region.
Other energy-intensive industries are also looking into the potential of green hydrogen, and examples such as Schott's green power shift show parallel decarbonization. A subsidiary of multinational building materials firm HeidelbergCement has, for example, worked with researchers from Swansea University to install and operate a green hydrogen demonstration unit at a site in the U.K.
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More Polar Vortex 2021 Fallout (and Texas Two-Step): Monitor For ERCOT Identifies Improper Payments For Ancillary Services
ERCOT Ancillary Services Clawback and VOLL Pricing summarize PUCT and IMM actions on load shed, real-time pricing adders, clawbacks, and settlement corrections after the 2021 winter storm in the Texas power grid market.
Key Points
Policies addressing clawbacks for unprovided AS and correcting VOLL-based price adders after load shed ended in ERCOT.
✅ PUCT ordered clawbacks for ancillary services not delivered.
✅ IMM urged price correction after firm load shed ceased.
✅ ERCOT's VOLL adder raised costs by $16B during 32 hours.
Potomac Economics, the Independent Market Monitor (IMM) for the Electric Reliability Council of Texas (ERCOT), filed a report with the Public Utility Commission of Texas (PUCT) that certain payments were made by ERCOT for Ancillary Services (AS) that were not provided, even as ERCOT later issued a winter reliability RFP to procure capacity during subsequent seasons.
According to the IMM (emphasis added):
There were a number of instances during the operating days outlined above in which AS was not provided in real time because of forced outages or derations. For market participants that are not able to meet their AS responsibility, typically the ERCOT operator marks the short amount in the software. This causes the AS responsibility to be effectively removed and the day-ahead AS payment to be clawed back in settlement. However, the ERCOT operators did not complete this task during the winter event, echoing issues like the Ontario IESO phantom demand that cost customers millions, and therefore the "failure to provide" settlements were not invoked in real time.
Removing the operator intervention step and automating the "failure to provide" settlement was contemplated in NPRR947: Clarification to Ancillary Service Supply Responsibility Definition and Improvements to Determining and Charging for Ancillary Service Failed Quantities; however, the NPRR was withdrawn in August 2020 amid ongoing market reform discussions because of the system cost, some complexities related to AS trades, and the implementation of real-time co-optimization.
Invoking the "failure to provide" settlement for all AS that market participants failed to provide during the operating days outlined above will produce market outcomes and settlements consistent with underlying market principles. In this case, the principle is that market participants should not be paid for services that they do not provide, even as a separate ruling found power plants exempt from providing electricity in emergencies under Texas law, underscoring the distinction between obligations and settlements. Whether ERCOT marked the short amount in real-time or not should not affect the settlement of these ancillary services.
On March 3, 2021, the PUCT ordered (a related press release is here) that:
ERCOT shall claw back all payments for ancillary service that were made to an entity that did not provide its required ancillary service during real time on ERCOT operating days starting February 14, 2021 and ending on February 19,2021.
On March 4, 2021, the IMM filed another report and recommended that:
the [PUCT] direct ERCOT to correct the real-time prices from 0:00 February 18,2021, to 09:00 February 19, 2021, to remove the inappropriate pricing intervention that occurred during that time period.
The IMM approvingly noted the PUCT's February 15, 2021 order, which mandated that real-time energy prices reflect firm load shed by setting prices at the value of lost load (VOLL).1
According to the IMM (emphasis added):
This is essential in an energy-only market, like ERCOT's, where the Texas power grid faces recurring crisis risks, because it provides efficient economic signals to increase the electric generation needed to restore the load and service it reliably over the long term.
Conversely, it is equally important that prices not reflect VOLL when the system is not in shortage and load is being served, and experiences in capacity markets show auction payouts can fall sharply under different conditions. The Commission recognized this principle in its Order, expressly stating it is only ERCOT's out-of-market shedding firm load that is required to be reflected in prices. Unfortunately, ERCOT exceeded the mandate of the Commission by continuing to set process at VOLL long after it ceased the firm load shed.
ERCOT recalled the last of the firm load shed instructions at 23:55 on February 17, 2021. Therefore, in order to comply with the Commission Order, the pricing intervention that raised prices to VOLL should have ended immediately at that time. However, ERCOT continued to hold prices at VOLL by inflating the Real-Time On-Line Reliability Deployment Price Adder for an additional 32 hours through the morning of February 19. This decision resulted in $16 billion in additional costs to ERCOT's market, prompting legislative bailout proposals in Austin, of which roughly $1.5 billion was uplifted to load-serving entities to provide make-whole payments to generators for energy that was not needed or produced.
However, at its March 5, 2021, open meeting (related discussion begins around minute 20), although the PUCT acknowledged the "good points" raised by the IMM, the PUCT was not willing to retrospectively adjust its real-time pricing for this period out of concerns that some related transactions (ICE futures and others) may have already settled and for unintended consequences of such retroactive adjustments.
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Westinghouse AP1000 Nuclear Plant Breaks A First Refueling Outage Record
AP1000 Refueling Outage Record showcases Westinghouse nuclear power excellence as Sanmen Unit 2 completes its first reactor refueling in 28.14 days, highlighting safety, reliability, outage optimization, and economic efficiency in China.
Key Points
It is the 28.14-day initial refueling at Sanmen Unit 2, a global benchmark achieved with Westinghouse AP1000 technology.
✅ 28.14-day first refueling at Sanmen Unit 2 sets global benchmark
✅ AP1000 design simplifies systems, improves safety and reliability
✅ Outage optimization by Westinghouse and CNNC accelerates schedules
Westinghouse Electric Company China operations today announced that Sanmen Unit 2, one of the world's first AP1000® nuclear power plants, has set a new refueling outage record in the global nuclear power industry, completing its initial outage in 28.14 days.
"Our innovative AP1000 technology allows for simplified systems and significantly reduces the amount of equipment, while improving the safety, reliability and economic efficiency of this nuclear power plant, reflecting global nuclear milestones reached recently," said Gavin Liu, president of the Westinghouse Asia Operating Plant Services Business. "We are delighted to see the first refueling outage for Sanmen Unit 2 was completed in less than 30 days. This is a great achievement for Sanmen Nuclear Power Company and further demonstrates the outstanding performance of AP1000 design."
All four units of the AP1000 nuclear power plants in China have completed their first refueling outages in the past 18 months, aligning with China's nuclear energy development momentum across the sector. The duration of each subsequent outage has fallen significantly - from 46.66 days on the first outage to 28.14 days on Sanmen Unit 2.
"During the first AP1000 refueling outage at the Sanmen site in December 2019, a Westinghouse team of experts worked side-by-side with the Sanmen outage team to partner on outage optimization, and immediately set a new standard for a first-of-a-kind outage, while major refurbishments like the Bruce refurbishment moved forward elsewhere," said Miao Yamin, chairman of CNNC Sanmen Nuclear Power Company Limited. "Lessons learned were openly exchanged between our teams on each subsequent outage, which has built to this impressive achievement."
Westinghouse provided urgent technical support on critical issues during the outage, as international programs such as Barakah Unit 1 achieved key milestones, to help ensure that work was carried out on schedule with no impact to critical path.
In addition to the four AP1000 units in China, two units are under construction at the Vogtle expansion near Waynesboro, Georgia, USA.
Separately, in the United States, a new reactor startup underscored renewed momentum in nuclear generation this year.
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Whooping cranes steer clear of wind turbines when selecting stopover sites
Whooping crane migration near wind turbines shows strong avoidance of stopover habitat within 5 km, reshaping Great Plains siting decisions, reducing collision risk, and altering routes across croplands, grasslands, and wetlands.
Key Points
It examines cranes avoiding stopovers within 5 km of turbines, reshaping habitat use and routing across the Great Plains.
✅ Cranes 20x likelier to rest >5 km from turbines.
✅ About 5% of high-quality stopover habitat is impacted.
✅ Findings guide wind farm siting across Great Plains wetlands.
As gatherings to observe whooping cranes join the ranks of online-only events this year, a new study offers insight into how the endangered bird is faring on a landscape increasingly dotted with wind turbines across regions. The paper, published this week in Ecological Applications, reports that whooping cranes migrating through the U.S. Great Plains avoid “rest stop” sites that are within 5 km of wind-energy infrastructure.
Avoidance of wind turbines can decrease collision mortality for birds, but can also make it more difficult and time-consuming for migrating flocks to find safe and suitable rest and refueling locations. The study’s insights into migratory behavior could improve future siting decisions as wind energy infrastructure continues to expand, despite pandemic-related investment risks for developers.
“In the past, federal agencies had thought of impacts related to wind energy primarily associated with collision risks,” said Aaron Pearse, the paper’s first author and a research wildlife biologist for the U.S. Geological Survey’s Northern Prairie Wildlife Research Center in Jamestown, N.D. “I think this research changes that paradigm to a greater focus on potential impacts to important migration habitats.”
Some policymakers have also rejected false health claims about wind turbines and cancer in public debate, underscoring the need for evidence-based decisions.
The study tracked whooping cranes migrating across the Great Plains, a region that encompasses a mosaic of croplands, grasslands and wetlands. The region has seen a rapid proliferation of wind energy infrastructure in recent years: in 2010, there were 2,215 wind towers within the whooping crane migration corridor that the study focused on; by 2016, when the study ended, there were 7,622 wind towers within the same area.
Pearse and his colleagues found that whooping cranes migrating across the study area in 2010 and 2016 were 20 times more likely to select “rest stop” locations at least 5 km away from wind turbines than those closer to turbines, a pattern with implications for developers as solar incentive changes reshape wind market dynamics according to industry analyses.
The authors estimated that 5% of high-quality stopover habitat in the study area was affected by presence of wind towers. Siting wind infrastructure outside of whooping cranes’ migration corridor would reduce the risk of further habitat loss not only for whooping cranes, but also for millions of other birds that use the same land for breeding, migration, and wintering habitat, and real-world siting controversies, such as an Alberta wind farm cancellation, illustrate how local factors shape outcomes for wildlife.
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Renewables Are Ready to Deliver a Renewable World - Time for Action for 100% Renewable Energy Globally
100% Renewable Energy Transition unites solar, wind, hydropower, geothermal, and bioenergy with storage, smart grids, and sector coupling, delivering decarbonization, energy security, and lower LCOE amid post-Fukushima policy shifts and climate resilience goals.
Key Points
It is a pathway using all renewables plus storage and grids to fully decarbonize power, heat, transport, and industry.
✅ Integrates solar, wind, hydro, geothermal, and bioenergy
✅ Uses storage, smart grids, and sector coupling for reliability
✅ Requires enabling policies, finance, and rapid deployment
Renewable energy organizations representing different spheres of the renewable energy community have gathered on the occasion of the tenth anniversary of the Great East Japan Earthquake and Fukushima nuclear accident to emphasize that renewable energies are not only available in abundance, with global renewable power on course to shatter more records, but ready to deliver a renewable world.
The combination of all renewable technologies, be it bioenergy, geothermal energy, hydropower, ocean energy, solar energy or wind power, in particular in combination with storage options, can satisfy all energy needs of mankind, be it for power, heating/cooling, transportation, or industrial processes.
Renewables have seen tremendous growth rates and cost reduction over the past two decades, but there are still many barriers that need to be addressed for a faster renewable energy deployment to eventually achieve global 100% renewable energy, as outlined in an on the road to 100% renewables initiative that charts the path. It is up to political decision-makers to create the legislative and regulatory conditions so that the renewable energy community can act as fast as needed.
Such rapid switch towards renewables is not only a must in light of nuclear risks and the growing threats of climate change, but also the necessary response to the current pandemic situation. And it will allow those hundreds of millions of humans in unserved areas to get for the first time ever access to modern energy services, as noted by a new IRENA report that details how renewables can decarbonise the energy sector and improve lives.
Speakers from the renewable energy community presented today in a joint webinar that a renewable future is a realistic vision, representing:
Energy Watch Group, Global100RE Platform, Global100RE Strategy Group, International Geothermal Association, ISEP Japan, REN Alliance, World Bioenergy Association, World Wind Energy Association.
Dr. Tetsunari Iida, Director of the Institute for Sustainable Energy Policies ISEP Japan:
Ten years ago, on 11 March 2021, the Great East Japan Earthquake and Fukushima Daiichi Nuclear Power Plant accident occurred. It is a "coincidence of global history" that it now coincides with the starting point of the 100% renewable energy initiative that is accelerating around the world.
The world has changed dramatically since 311. Germany, Italy, Switzerland, Taiwan, South Korea, China and many other countries were all shocked by 311 and shifted their focus from nuclear power to renewable energy, and in the U.S. clean energy industries are setting sights on market majority to accelerate this trend. The next ten years will be the decade in which this perception will rapidly become the "new reality". 311 was the "starting point" for a structural energy shift in world history.
Hans-Josef Fell, former MP, President of the Energy Watch Group and co-initiator of the Global100RE Strategy Group:
The disasters of Fukushima and Chernobyl are urging the entire world to quickly end the use of atomic energy, and many call for a fossil fuel lockdown to catalyze a climate revolution alongside the transition. Contrary to what is often claimed, nuclear energy cannot make a contribution to climate protection, but only creates immense problems with toxic radioactivity emissions, nuclear waste, atomic bomb material and the dangers of a nuclear catastrophe. In contrast, 100% renewable energies until 2030 can help achieve climate protection and a simultaneous nuclear phase-out, according to a recently published statement by a world-leading group of energy researchers from the USA, EU and Australia.
Their research suggests that a 100% renewable energy supply, including storage systems, can provide full energy security for all of mankind by 2030 and will even be cheaper than the existing nuclear and fossil energy supply, and with over 30% of global electricity already from renewables, momentum is strong. The only requirement for implementation is the right decisions taken by decision makers both in governments and industry. All technical and economic prerequisites for a disruptive conversion of the global energy supply to 100% renewable energies are already in place.
Hon. Peter Rae AO, President of WWEA and Honorary Chairman of the REN Alliance:
40 years ago, the idea of developing nuclear power appealed to me as a non-polluting method of generating electricity. So I studied it. How to deal with waste and how to ensure it would not create a danger to life. Along came Chernobyl and other accidents. Storage of waste was leaving dangerous hiding places while some waste was alleged to be dumped at sea. I became more and more concerned. There were demonstrations that the existing methods were dangerous and required very strict construction and operational tolerances - up went the cost. Long delays and huge cost increases. I had visited nuclear power stations and talked to expert proponents in UK, France, US, Taiwan and Australia, and debates such as New Zealand's electricity future reflect similar concerns. The more I did the more certain I became that it was not the way to go. Then Fukushima put the dangers and cost beyond doubt.
Let's get on with the rollover to renewables.
Dr. Marit Brommer, Executive Director of the International Geothermal Association IGA:
The IGA is proud to work with all renewable energy associations to continuously provide a unified voice to a cleaner energy future. The Geothermal sector is proven to be a partner of choice for many locations in the world serving baseload power and clean heat to customers. We are particularly interested in the increased attention system integration gets, which underpins the importance of all renewables coming together at events such as the webinar organised by the WWEA.
Christian Rakos, President of the World Bioenergy Association:
The IPCC has emphasized the important role of sustainable bioenergy for climate protection. Recent advances in technology allow us to use feedstock from forestry, wood processing and agricultural production in an efficient and clean way. Today, bioenergy already contributes 12 - 13% to global final energy demand. Importantly, contribution from bioenergy is more than 5 times as much as nuclear energy worldwide. Together with other renewable energy technologies such as solar, wind, geothermal and hydropower, bioenergy can increase the contribution in a substantial way to meet the energy demands of all end use sectors and meet the international energy and climate goals.
Stefan Gsanger, Secretary General of the World Wind Energy Association and Co-chair of the Global100RE Platform:
The switch to a renewable energy future requires new political and economic thinking: from centralised structures with few large actors towards decentralised, participatory models with millions of communities and citizens playing an active role, not only as consumers but also as producers of energy. To make this new paradigm the predominant energy paradigm is the true challenge of the energy transformation which we as the world community are facing. If we manage this shift well and on time, billions of people across the globe, in industrialised and developing countries alike, will benefit and will face a bright future.
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Biden's interior dept. acts quickly on Vineyard Wind
Vineyard Wind I advances as BOEM issues a final environmental impact statement for the 800 MW offshore wind farm south of Martha's Vineyard, delivering clean energy, jobs, and carbon reductions to Massachusetts toward net-zero.
Key Points
An 800 MW offshore wind project near Martha's Vineyard supplying clean power to Massachusetts.
✅ 800 MW capacity; power for 400,000+ homes and businesses
✅ BOEM final EIS; record of decision pending within 30+ days
✅ 1.68M metric tons CO2 avoided annually; jobs and lower rates
Federal environmental officials have completed their review of the Vineyard Wind I offshore wind farm, moving the project that is expected to deliver clean renewable energy to Massachusetts by the end of 2023 closer to becoming a reality.
The U.S. Department of the Interior said Monday morning that its Bureau of Ocean Energy Management completed the analysis it resumed about a month ago, published the project's final environmental impact statement, and said it will officially publish notice of the impact statement in the Federal Register later this week.
"More than three years of federal review and public comment is nearing its conclusion and 2021 is poised to be a momentous year for our project and the broader offshore wind industry," Vineyard Wind CEO Lars Pedersen said. "Offshore wind is a historic opportunity to build a new industry that will lead to the creation of thousands of jobs, reduce electricity rates for consumers and contribute significantly to limiting the impacts of climate change. We look forward to reaching the final step in the federal permitting process and being able to launch an industry that has such tremendous potential for economic development in communities up and down the Eastern seaboard."
The 800-megawatt wind farm planned for 15 miles south of Martha's Vineyard was the first offshore wind project selected by Massachusetts utility companies with input from the Baker administration to fulfill part of a 2016 clean energy law. It is projected to generate cleaner electricity for more than 400,000 homes and businesses in Massachusetts, produce at least 3,600 jobs, reduce costs for Massachusetts ratepayers by an estimated $1.4 billion, and eliminate 1.68 million metric tons of carbon dioxide emissions annually.
Offshore wind power, informed by the U.S. offshore wind outlook, is expected to become an increasingly significant part of Massachusetts' energy mix. The governor and Legislature agree on a goal of net-zero carbon emissions by 2050, but getting there is projected to require having about 25 gigawatts of offshore wind power. That means Massachusetts will need to hit a pace in the 2030s where it has about 1 GW of new offshore wind power on the grid coming online each year.
"I think that's why today's announcement is so historic, because it does represent that culmination of work to understand how to permit and build a cost-effective and environmentally-responsible wind farm that can deliver clean energy to Massachusetts ratepayers, but also just how to do this from start to finish," said Energy and Environmental Affairs Secretary Kathleen Theoharides. "As we move towards our goal of probably [25 GW] of offshore wind by 2050 to hit our net-zero target, this does give us confidence that we have a much clearer path in terms of permitting."
She added, "There's a huge pipeline, so getting this project out really should open the door to the many additional projects up and down the East Coast, such as Long Island proposals, that will come after it."
According to the American Wind Energy Association, there are expected to be 14 offshore projects totaling 9,112 MW of capacity in operation by 2026.
Susannah Hatch, the clean energy coalition director for the Environmental League of Massachusetts and a leader of the broad-based New England for Offshore Wind Regional group, called offshore wind farms like Vineyard Wind "the linchpin of our decarbonization efforts in New England." She said the Biden administration's quick action on Vineyard Wind is a positive sign for the burgeoning sector.
"Moving swiftly on responsibly developed offshore wind is critical to our efforts to mitigate climate change, and offshore wind also provides an enormous opportunity to grow the economy, create thousands of jobs, and drive equitable economic benefits through increased minority economic participation in New England," Hatch said.
With the final environmental impact statement published, Vineyard Wind still must secure a record of decision from BOEM, which processes wind lease requests, an air permit from the Environmental Protection Agency and sign-offs from the U.S. Army Corps of Engineers and the National Marine Fisheries Service to officially clear the way for the project that is on track to be the nation's first utility-scale offshore wind farm. BOEM must wait at least 30 days from the publication of the final environmental impact statement to issue a record of decision.
Project officials have said they expect the final impact statement and then a record of decision "sometime in the first half of 2021." That would allow the project to hit its financial close milestone in the second half of this year, begin on-shore work quickly thereafter, start offshore construction in 2022, begin installing turbines in 2023 and begin exporting power to the grid, marking Vineyard Wind first power, by late 2023, Pedersen said in January.
"Offshore energy development provides an opportunity for us to work with Tribal nations, communities, and other ocean users to ensure all decisions are transparent and utilize the best available science," BOEM Director Amanda Lefton said.
The commercial fishing industry has been among the most vocal opponents of aspects of the Vineyard Wind project and the Responsible Offshore Development Alliance (RODA) has repeatedly urged the new administration to ensure the voices of the industry are heard throughout the licensing and permitting process.
In comments submitted earlier this month in response to a BOEM review of an offshore wind project that is expected to deliver power to New York, including the recent New York offshore wind approval, RODA said the present is "a time of significant confusion and change in the U.S. approach to offshore wind energy (OSW) planning" and detailed mitigation measures it wants to see incorporated into all projects.
"To be clear, none of these requests are new -- nor hardly radical. They have simply been ignored again, and again, and again in a political push/pull between multinational energy companies and the U.S. government, leaving world-famous seafood, and the communities founded around its harvest, off the table," the group said in a press release last week. Some of RODA's suggestions were analyzed as part of BOEM's Vineyard Wind review.
Vineyard Wind has certainly taken a circuitous path to get to this point. The timeline for the project was upended in August 2019 when the Trump administration decided to conduct a much broader assessment of potential offshore wind projects up and down the East Coast, which delayed the project by almost a year.
When the Trump administration delayed its action on a final environmental impact statement last year, Vineyard Wind on Dec. 1 announced that it was pulling its project out of the federal review pipeline in order to complete an internal study on whether the decision to use a certain type of turbine would warrant changes to construction and operations plan. The Trump administration declared the federal review of the project "terminated."
Within two weeks of President Joe Biden being inaugurated, Vineyard Wind said its review determined no changes were necessary and the company resubmitted its plans for review. BOEM agreed to pick up where the Trump administration had left off despite the agency previously declaring its review terminated.
"It would appear that fishing communities are the only ones screaming into a void while public resources are sold to the highest bidder, as BOEM has reversed its decision to terminate a project after receiving a single letter from Vineyard Wind," RODA said.
The final environmental impact statement that BOEM published Monday showed that the federal regulators believe the Vineyard Wind I development as proposed will have "moderate" impacts on commercial fisheries and for-hire recreational fishing outfits, and that the project combined with other factors not related to wind energy development will have "major" impacts on commercial and recreational fishing ventures.
Vineyard Wind pointed Monday to the fishery mitigation agreements it has entered into with Massachusetts and Rhode Island, a fishery science collaboration with the University of Massachusetts Dartmouth's School of Marine Science and Technology, and an agreement with leading environmental organizations around the protection of the endangered right whale.
Responding to concerns about safe navigation among RODA and others in the fishing sector, Vineyard Wind and the four other developers holding leases for offshore wind sites off New England agreed to orient their turbines in fixed east-to-west rows and north-to-south columns spaced one nautical mile apart. Last year, the U.S. Coast Guard concluded that the grid layout was the best way to maintain maritime safety and ease of navigation in the offshore wind development areas south of Martha's Vineyard and Nantucket.
Since a 2016 clean energy law kicked off the state's foray into the offshore wind world, Massachusetts utilities have contracted for a total of about 1,600 MW between two projects, Vineyard Wind I and Mayflower Wind.
A joint venture of Shell and Ocean Winds North America, Mayflower Wind was picked unanimously in 2019 by utility executives to build and operate a wind farm approximately 26 nautical miles south of Martha's Vineyard and 20 nautical miles south of Nantucket, with South Coast construction activity expected as the project progresses. The 804-megawatt project is expected to be operational by December 2025.
Massachusetts and its utilities are expected to go out to bid for up to another 1,600 MW of offshore wind generation capacity later this year using authorization granted by the Legislature in 2018.
The climate policy bill that Gov. Charlie Baker returned to the Legislature with amendments more than a month ago would require that the executive branch direct Massachusetts utilities to buy an additional 2,400 MW of offshore wind power.
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CALIFORNIA: Why your electricity prices are soaring
California Electricity Prices are surging across PG&E, SCE, and SDG&E territories, driven by fixed grid costs, wildfire mitigation, CARE subsidies, and Net Energy Metering, burdening low-income renters and increasing statewide utility debt, CPUC reports show.
Key Points
High rates driven by fixed grid costs and policies, burdening low-income customers across PG&E, SCE, and SDG&E.
✅ Fixed costs: transmission, distribution, wildfire mitigation
✅ Solar NEM shifts grid costs onto remaining ratepayers
✅ CPUC, CARE, LIHEAP aim to relieve rising utility debt
California's electricity prices are among the highest in the country, new research says, and those costs are falling disproportionately on a customer base that's already struggling to pay their bills.
PG&E customers pay about 80 percent more per kilowatt-hour than the national average, according to a study by the energy institute at UC Berkeley's Haas Business School with the nonprofit think tank Next 10. The study analyzed the rates of the state's three largest investor-owned utilities and found that Southern California Edison charged 45 percent more than the national average, while San Diego Gas & Electric charged double. Even low-income residents enrolled in the California Alternate Rates for Energy program paid more than the average American.
"California's retail prices are out of line with utilities across the country," said UC Berkeley assistant professor and study co-author Meredith Fowlie, citing Hawaii and some New England states among the outliers with even higher rates. "And they're increasing, as regulators face calls for action across the state."
So why are prices so high?
One reason is that California's size and geography inflate the "fixed" costs of operating its electric system, even as the state considers revamping electricity rates to clean the grid in parallel, which include maintenance, generation, transmission, and distribution as well as public programs like CARE and wildfire mitigation, according to the study. Those costs don't change based on how much electricity residents consume, yet between 66 and 77 percent of Californians' electricity bills are used to offset the costs of those programs, the study found.
These are legitimate expenses, Fowlie said. However, because lower-income residents use only moderately less electricity than higher income households, they end up with a disproportionate share of the burden, according to the study. And while the bills of older, wealthier Californians continue to decrease as they adopt cost-efficient alternatives like the state's Net Energy Metering solar program and the resulting solar power cost shift dynamic, costs will keep rising for a shrinking customer base composed mostly of low- and middle-income renters who still use electricity as their main energy source.
"When households adopt solar, they're not paying their fair share," Fowlie said. While solar users generate power that decreases their bills, they still rely on the state's electric grid for much of their power consumption - without paying for its fixed costs like others do.
"As this continues it's going to make electricity even more unaffordable," said F. Noel Perry, founder of Next 10, which funds nonpartisan research on the economy and environment.
PG&E this month raised its electricity rates 3.7 percent, amounting to a $5.01 a month increase for the average residential customer, who now pays $138.85 a month for electricity. It was the second increase this year, as regulators consider major changes to electric bills statewide, said Mark Toney, executive director of The Utility Reform Network, who noted that higher rates are particularly difficult for those who have lost their jobs in the pandemic. The California Public Utilities Commission last year approved a PG&E plan for more incremental increases through Dec. 31, 2022.
PG&E spokesperson Kristi Jourdan said in an email statement that the company was committed to keeping prices as low as possible as the state weighs income-based flat-fee utility bills proposals, and that although some programs are meant to be subsidized through rates, "in other cases, given that some customers have greater access to energy alternatives, the remaining customers - often those with limited means - are left paying unintended subsidies."
The costs quickly became overwhelming for Fretea Sylver, who rents a small house in Castro Valley and lost much of her work as the owner of a small woodwork business early in the pandemic. "They're little tiny changes but they accumulate. You turn around and you're like wait a second, why is my bill $20 more?," Sylver said. "And you have to pay it, no matter what."
Many more are unable to pay. Between February and December of last year, Californians accumulated more than $650 million in late payments from their utility providers, according to an analysis by the CPUC. In 2019, utility debt fell $71,646,869 from the prior year.
Sylver, who was on unemployment for 10 months last year, accumulated over $600 in unpaid PG&E bills. "We sort of went into a bit of debt, having to use credit cards and loans to sustain what we had to pay for. We're trying to catch up," Sylver said. The family received some help from the federal Low-Income Home Energy Assistance Program, which provides up to $1,000 to those who are late on their utility bills.
The study identified improvements to make California's power grid more equitable, such as income-based fixed electricity charges for the grid's cost that are based on income. Republican state senators this week called on the state to use federal relief money to forgive the billions Californians owe in utility debt, even as some lawmakers move to overturn income-based utility charges amid ongoing debate. Californians are currently protected by a statewide moratorium on disconnection for nonpayment of electricity bills through June 30. The CPUC this month began taking public input on the issue of how to grant some relief to those who have fallen behind on their utility bills.
This article is part of the California Divide, a collaboration among newsrooms examining income inequality and economic survival in California.
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Major investments by Canada and Quebec in electric vehicle battery assembly
Lion Electric Battery Plant Quebec secures near $100M public investment for an automated battery-pack assembly in Saint-Jérôme, fueling EV manufacturing, R&D, local supply chains, and heavy-duty zero-emission vehicle competitiveness and jobs.
Key Points
Automated battery-pack plant in Saint-Jérôme boosting EV manufacturing and strengthening Quebec's supply chain.
✅ $100M joint federal-provincial investment announced
✅ 135 jobs in 2023; 150 more long-term positions
✅ R&D hub to enhance heavy-duty EV battery performance
Canadian Prime Minister of Canada, Justin Trudeau, and the Premier of Quebec, François Legault, have announced an equal investment totalling nearly $100 million to Lion Electric, as a B.C. battery plant announcement has done in another province, for the establishment of a highly automated battery-pack assembly plant in Saint–Jérôme, in the Laurentians. This project, valued at nearly $185 million, will create 135 jobs when construction of the plant is completed in 2023. It is also expected that 150 additional jobs will be created over the longer term.
For the announcement, Mr. Trudeau and Mr. Legault were accompanied by the Minister of Innovation, Science and Industry, François-Philippe Champagne, by Quebec's Minister of Economy and Innovation, Pierre Fitzgibbon, and by Marc Bédard, President and Founder of Lion Electric.
The battery packs assembled at the new plant will be used in Lion Electric vehicles. This strategic investment will allow the company to improve its cost structure, and better control the design and shape of its batteries, making it more competitive in the heavy-duty electric vehicle market, as EV assembly deals put Canada in the race. Ultimately, the company will be able to increase the volume of its vehicle production. Lion Electric will be the first Canadian manufacturer of medium and heavy-duty vehicles to have state-of-the-art, automated battery-pack manufacturing facilities.
The company will also establish a research and development innovation centre within its manufacturing plant, which will allow it to test and refine products for future use, including batteries for emergency vehicles such as ambulances. The company will test innovations from research and development, including energy storage capacity and battery performance. The results will make these products more competitive in the North American market, where a Niagara Region battery plant signals growing demand.
The company said it expects to employ 135 people at the plant when it is operational by 2023. It also plans to invest in a research and development facility that could create a number of spinoff jobs.
"When we talk about an economic recovery that's good for workers, for families and for the environment, this is exactly the kind of project we mean," Trudeau said at a news conference in Montreal.
Trudeau toured Lion Electric's factory in Saint-Jérôme, Que., last March, just before the pandemic. (Ryan Remiorz/The Canadian Press)
It was the prime minister's first trip to Montreal in more than a year. He said one of the reasons he decided to attend the announcement was to illustrate the importance of the green economy and how Canada can capitalize on the U.S. EV pivot for future job growth.
The project also aligns with the Legault government's desire to create a supply chain within Quebec that is able to feed the electric vehicle industry, where Canada-U.S. collaboration could accelerate progress.
At Monday's announcement, Economy Minister Pierre Fitzgibbon spoke at length about the province's deposits of lithium and nickel — key components in electric vehicle batteries — as well as its supply of low-emission hydroelectricity.
"If we play our cards right, we could become world leaders in this market of the future," Fitzgibbon said.
Currently, many of those strategic minerals found in Quebec are exported to Asia where they are turned into battery cells, and then imported back to Quebec by companies like Lion, said Mickaël Dollé, a chemistry professor at the Université de Montréal.
By opening a battery assembly plant in Quebec, Lion could help stimulate more cell-makers, such as the Northvolt project near Montreal, to set up shop in the province. Further localizing the supply chain, Dollé said, means better value and a greener product.
But other countries have the same goal in mind, he said, and the window for the province to establish itself as an important player in the emerging electric vehicle battery industry is closing quickly, as major Ford Oakville deal commitments accelerate competition.
"The decision has to be taken now, or in the coming months, but if we wait too long we may miss our main goal which is to get our own supply chain in Canada," Dollé said.
What's in a name?
Monday's announcement was closely watched in Quebec for what it foretold about the political future as well as the economic one.
By coming to Montreal and touring a vaccination clinic before making the funding announcement, Trudeau fed speculation in the province that he is preparing to call an election soon.
Intrigue also surrounded the informal meeting Trudeau had with Legault on Monday. The Quebec premier and members of his government have repeatedly expressed frustration with Trudeau during the pandemic.
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Why Canada should invest in "macrogrids" for greener, more reliable electricity
Canadian electricity transmission enables grid resilience, long-distance power trade, and decarbonization by integrating renewables, hydroelectric storage, and HVDC links, providing backup during extreme weather and lowering costs to reach net-zero, clean energy targets.
Key Points
An interprovincial high-voltage grid that shares clean power to deliver reliable, low-cost decarbonization.
✅ Enables resilience by sharing power across weather zones
✅ Integrates renewables with hydro storage via HVDC links
✅ Lowers decarbonization costs through interprovincial trade
As the recent disaster in Texas showed, climate change requires electricity utilities to prepare for extreme events. This “global weirding” is leaving Canadian electricity grids increasingly exposed to harsh weather that leads to more intense storms, higher wind speeds, heatwaves and droughts that can threaten the performance of electricity systems.
The electricity sector must adapt to this changing climate while also playing a central role in mitigating climate change. Greenhouse gas emissions can be reduced a number of ways, but the electricity sector is expected to play a central role in decarbonization, including powering a net-zero grid by 2050 across Canada. Zero-emissions electricity can be used to electrify transportation, heating and industry and help achieve emissions reduction in these sectors.
Enhancing long-distance transmission is viewed as a cost-effective way to enable a clean and reliable power grid, and to lower the cost of meeting our climate targets. Now is the time to strengthen transmission links in Canada, with concepts like a western Canadian electricity grid gaining traction.
Insurance for climate extremes
An early lesson from the Texas power outages is that extreme conditions can lead to failures across all forms of power supply. The state lost the capacity to generate electricity from natural gas, coal, nuclear and wind simultaneously. But it also lacked cross-border transmission to other electricity systems that could have bolstered supply.
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Long-distance transmission offers the opportunity to escape the correlative clutch of extreme weather, by accessing energy and spare capacity in areas not beset by the same weather patterns. For example, while Texas was in its deep freeze, relatively balmy conditions in California meant there was a surplus of electricity generation capability in that region — but no means to get it to Texas. Building new transmission lines and connections across broader regions, including projects like a hydropower line to New York that expand access, can act as an insurance policy, providing a back-up for regions hit by the crippling effects of climate change.
A transmission tower crumpled under the weight of ice.
The 1998 Quebec ice storm left 3.5 million Quebecers and a million Ontarians, as well as thousands in in New Brunswick, without power. CP Photo/Robert Galbraith
Transmission is also vulnerable to climate disruptions, such as crippling ice storms that leave wires temporarily inoperable. This may mean using stronger poles when building transmission, or burying major high-voltage transmission links, or deploying superconducting cables to reduce losses.
In any event, more transmission links between regions can improve resilience by co-ordinating supply across larger regions. Well-connected grids that are larger than the areas disrupted by weather systems can be more resilient to climate extremes.
Lowering the cost of clean power
Adding more transmission can also play a role in mitigating climate change. Numerous studies have found that building a larger transmission grid allows for greater shares of renewables onto the grid, ultimately lowering the overall cost of electricity.
In a recent study, two of us looked at the role transmission could play in lowering greenhouse gas emissions in Canada’s electricity sector. We found the cost of reducing greenhouse gas emissions is lower when new or enhanced transmission links can be built between provinces.
Average cost increase to electricity in Canada at different levels of decarbonization, with new transmission (black) and without new transmission (red). New transmission lowers the cost of reducing greenhouse gas emissions. (Authors), Author provided
Much of the value of transmission in these scenarios comes from linking high-quality wind and solar resources with flexible zero-emission generation that can produce electricity on demand. In Canada, our system is dominated by hydroelectricity, but most of this hydro capacity is located in five provinces: British Columbia, Manitoba, Ontario, Québec and Newfoundland and Labrador.
In the west, Alberta and Saskatchewan are great locations for building low-cost wind and solar farms. Enhanced interprovincial transmission would allow Alberta and Saskatchewan to build more variable wind and solar, with the assurance that they could receive backup power from B.C. and Manitoba when the wind isn’t blowing and the sun isn’t shining.
When wind and solar are plentiful, the flow of low cost energy can reverse to allow B.C. and Manitoba the opportunity to better manage their hydro reservoir levels. Provinces can only benefit from trading with each other if we have the infrastructure to make that trade possible.
A recent working paper examined the role that new transmission links could play in decarbonizing the B.C. and Alberta electricity systems. We again found that enabling greater electricity trade between B.C. and Alberta can reduce the cost of deep cuts to greenhouse gas emissions by billions of dollars a year. Although we focused on the value of the Site C project, in the context of B.C.'s clean energy shift, the analysis showed that new transmission would offer benefits of much greater value than a single hydroelectric project.
The value of enabling new transmission links between Alberta and B.C. as greenhouse gas emissions reductions are pursued. (Authors), Author provided
Getting transmission built
With the benefits that enhanced electricity transmission links can provide, one might think new projects would be a slam dunk. But there are barriers to getting projects built.
First, electricity grids in Canada are managed at the provincial level, most often by Crown corporations. Decisions by the Crowns are influenced not simply by economics, but also by political considerations. If a transmission project enables greater imports of electricity to Saskatchewan from Manitoba, it raises a flag about lost economic development opportunity within Saskatchewan. Successful transmission agreements need to ensure a two-way flow of benefits.
Second, transmission can be expensive. On this front, the Canadian government could open up the purse strings to fund new transmission links between provinces. It has already shown a willingness to do so.
Lastly, transmission lines are long linear projects, not unlike pipelines. Siting transmission lines can be contentious, even when they are delivering zero-emissions electricity. Using infrastructure corridors, such as existing railway right of ways or the proposed Canadian Northern Corridor, could help better facilitate co-operation between regions and reduce the risks of siting transmission lines.
If Canada can address these barriers to transmission, we should find ourselves in an advantageous position, where we are more resilient to climate extremes and have achieved a lower-cost, zero-emissions electricity grid.
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Canada, Germany to work together on clean energy
Clean Energy Transition spans hydrogen strategies, offshore wind and undersea cables, decarbonization pledges, and net-zero targets, including green vs blue hydrogen, carbon capture, sustainable aviation fuel, forest conservation, and wetland protection in Canadian policy.
Key Points
A shift to low-carbon systems via hydrogen, renewables, net-zero policies, carbon capture, and conservation.
✅ Hydrogen pathways: green vs blue with carbon capture
✅ Grid expansion: offshore wind and undersea cables in Japan
✅ Policy and corporate moves: net-zero, SAF, forests, wetlands
The Canadian federal government is set to sign a new agreement with Germany to strategize on a “clean-energy transition,” with clean hydrogen in Canada expected to be a key player the Globe and Mail reports.
“Germany is probably the world’s most interesting market for hydrogen right now, and Canada is potentially a very big power in its production,” Sabine Sparwasser, Germany’s ambassador to Canada, said in an interview.
However, some friction is expected as Natural Resources Minister Seamus O’Regan has been endorsing “blue” hydrogen, while Germany has been more interested in “green” hydrogen. The former hydrogen is produced from natural gas or other fossil fuels, while simultaneously “using carbon-capture technology to minimize emissions from the process.” In contrast, “green” hydrogen, is manufactured from non-fossil fuel sources, and cleaning up Canada's electricity is critical to meeting climate pledges.
“How the focus on blue hydrogen will be aligned with Canada’s goal of reaching climate neutrality by 2050 is not spelled out in detail,” says an executive summary of the report by the Berlin-based think tank and consultancy Adelphi. “As a result, the strategy seems to be more of a vision for the future of those provinces with large fossil fuel resources.”
According to an IEA report Canada will need more electricity to hit net-zero, underscoring the strategy questions.
Internationally
Japan is in talks to develop undersea cables that would bring offshore wind energy to Tokyo and the Kansai region, as the country hopes to more than quadrable its wind capacity from 10 gigawatts in 2030 to 45 gigawatts in 2040. The construction of the cables would cost about US$9.2 billion.
In Western Canada, bridging the electricity gap between Alberta and B.C. makes similar climate sense, proponents argue.
Approximately 80 per cent of that offshore power is expected to be built in Hokkaido, Tohoku, and Kyushu regions. The project is part of the country’s pledge to achieve decarbonization by 2050, according to BNN Bloomberg.
Meanwhile, Russia is falling behind in the world’s transition to clean energy.
“What’s the alternative? Russia can’t be an exporter of clean energy, that path isn’t open for us,” says Konstantin Simonov, director of the National Energy Security Fund, a Moscow consultancy whose clients include major oil and gas companies. “We can’t just swap fossil fuel production for clean energy production, because we don’t have any technology of our own.” Ultimately, natural gas will always be cheaper than renewable energy in Russia, Simonov added. This story also from BNN Bloomberg.
Finally, New Zealand’s Tilt Renewables Ltd., an electricity company, has announced it would be acquired by Powering Australian Renewables (PowAR) for NZ$2.94 billion (US$2.10 billion). PowAR is Australia’s largest owner of wind and solar energy, and the deal will give the energy giant access to Tilt’s 20 wind farms. Reuters has the story.
In Canada
Air Canada has unveiled plans to fight climate change. Specifically, the airlines giant has committed to reducing greenhouse gases (GHG) by 20 per cent from flights by 2030, investing $50 million in sustainable aviation fuel (SAF), and ensuring net-zero emissions by 2050.
In other news, B.C. is facing mounting pressure to abstain from logging “old growth forests” while the government transitions to more sustainable forestry policies. A report titled A New Future for Old Forests called on the provincial government to act within six months to protect such forests in April 2020.
The province's Site C mega dam is billions over budget but will go ahead, the premier said, highlighting the energy sector's complexity.
Last September, the province announced, “it would temporarily defer old growth harvesting in close to 353,000 hectares in nine different areas.” The B.C. government will hold consultations with First Nations and other forestry stakeholders “to determine the next areas where harvesting may be deferred,” according to Forests Minister Katrine Conroy. The Canadian Press has more.
Separately, LNG powered with electricity could be a boon for B.C.'s independent power producers, analysts say.
Finally, Pickering Developments Inc. has come forward saying it will not “alter or remove the wetland” that was meant to house an Amazon facility, according to CBC News.
The announcement comes after CBC News’s previously reported that the Toronto and Region Conservation Authority (TRCA) was pressured to issue a construction permit to Pickering Developments Inc. by Doug Ford’s provincial government. However, on March 12, an official with Amazon Canada told CBC News that the company no longer wished to build a warehouse on the site.
“In light of a recent announcement that a new fulfilment centre will no longer be located on this property, this voluntary undertaking ensures that no work, legally authorized by that permit, will occur,” Pickering Development Inc. said in a statement provided to CBC Toronto.
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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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Site C mega dam billions over budget but will go ahead: B.C. premier
Site C Dam Update outlines hydroelectric budget overruns, geotechnical risks, COVID-19 construction delays, BC Hydro timelines, cancellation costs, and First Nations treaty rights concerns affecting renewable energy, ratepayers, and Peace Valley impacts.
Key Points
Overview of Site C costs, delays, geotechnical risks, and concerns shaping BC Hydro hydroelectric plans.
✅ Cost to cancel estimated at least $10B
✅ Final budget now about $16B; completion pushed to 2025
✅ COVID-19 and geotechnical risks drove delays and redesigns
The cost to cancel a massive B.C. energy development project would be at least $10 billion, provincial officials revealed in an update on the future of Site C.
Thus the project will go ahead, Premier John Horgan and Energy Minister Bruce Ralston announced Friday, but with an increased budget and timeline.
Horgan and Ralston spoke at a news conference in Victoria about the findings of a status report into the hydroelectric dam project in northeastern B.C.
Peter Milburn, former deputy finance minister, finished the report earlier this year, but the findings were not initially made public.
$10B more than initial estimate
On Friday, it was announced that the project's final price tag has once again ballooned by billions of dollars.
Site C was initially estimated to cost $6 billion, and the first approved budget, back in 2014, was $8.775 billion. The budget increased to $10.8 billion in 2018.
But the latest update suggests it will cost about $16 billion in total.
And, in addition to a higher budget, the date of completion has been pushed back to 2025 – a year later than the initial target.
Among the reasons for the revisions, according to the province, is the impact of COVID-19. While officials did not get into details, there have been multiple cases of the disease publicly reported at Site C work camps.
Additionally, fewer workers were permitted on site to allow for physical distancing, and construction was scaled back.
Also cited as a cause for the increased cost were "unforeseeable" geotechnical issues at the site, which required installation of an enhanced drainage system.
Speaking to reporters Friday, the premier deflected blame.
“Managing the contract the BC Liberals signed has been difficult because it transfers the vast majority of the geotechnical risk back to BC Hydro,” said Horgan.
Former Premier Christy Clark vowed to get the project to a point of no return, and in 2017 the NDP decided to continue with the project because of the cost of cancelling it.
The Liberals now say the clean energy project should continue, but deny they shoulder any of the blame.
“Someone has to take ownership – and it's got to be government in power,” said MLA Tom Shypitka, BC Liberal critic for energy.
There are also several reviews underway, including how to change contractor schedules to reflect delays and potential cost impacts from COVID-19, and how to keep the work environment safe during the pandemic.
A total of 17 recommendations were made in Milburn's report, all of which have been accepted by BC Hydro and the province.
Among these recommendations is a restructured project assurance board with a focus on skill-specific membership and autonomy from BC Hydro.
Cost of cancelling the project
The report looked into whether it would be better to scrap the project altogether, but the cost of cancelling it at this point would be at least $10 billion, Horgan and Ralston said.
That cost does not include replacing lost energy and capacity that Site C's electricity would have provided, according to the province.
A study conducted in 2019 suggested B.C. will need to double its electricity production by 2055, especially as drought conditions are forcing BC Hydro to adapt power generation.
The NDP government says the cost to ratepayers of cancelling the project would be $216 a year for 10 years. Going forward will still have a cost, but instead, that payment will be split over more than 70 years, the estimated lifetime of Site C, meaning BC Hydro customers will pay about $36 more a year once the site goes live, the NDP says, even as cryptocurrency mining raises questions about electricity use.
“We will not put jobs at risk; we will not shock people's hydro bills,” said Horgan.
"Our government has taken this situation very seriously, and with the advice of independent experts guiding us, I am confident in the path forward for Site C," Ralston said.
"B.C. needs more renewable energy to bridge the electricity gap with Alberta and electrify our economy, transition away from fossil fuels and meet our climate targets."
The minister said the site is currently employing about 4,500 people.
Arguments against Site C
While there are benefits to the project, there has also been vocal opposition.
In a statement released following the announcement that the project would go ahead, the Union of B.C. Indian Chiefs suggested the decision violated the premier's commitment to a UN declaration.
"The Site C dam has never had the free, prior and informed consent of all impacted First Nations, and proceeding with the project is a clear infringement of the treaty rights of the West Moberly First Nation," the UBCIC's secretary treasurer said.
Kukpi7 Judy Wilson said the UN's Committee on the Elimination of Racial Discrimination has called for a suspension of the project until it has the consent of Indigenous peoples.
"B.C. did not even attempt to engage First Nations about the safety risks associated with the stability of the dam in the recent reviews," she said.
"It is unfathomable that such clear human rights violations are somehow OK by this government."
Chief Roland Wilson of the West Moberly First Nation said he was disappointed the province didn’t consult his and other communities prior to making this announcement. In an interview with CTV News, he said he was offered an opportunity to join a call this morning.
“We signed a treaty in 1814,” he said. “Our treaty rights are being trampled on.”
Wilson said his nation has ongoing concerns about safety issues and the plans to flood the Peace Valley. West Moberly is in a bitter court battle with the province.
At the BC Legislature, Green Party Leader Sonia Furstenau slammed the government’s decision.
“It is an astonishingly terrible business case in any circumstances, but considering that we lose the agricultural land, the biodiversity, the traditional treaty lands of Treaty 8, this is particularly catastrophic,” she told reporters.
She went on to accuse the NDP government of keeping bad news from the public. She alleged the NDP knew of serious problems before last fall’s unscheduled election, but chose not to release information.
Prior to the decision former BC Hydro president and a former federal fisheries minister are among those who added their voices to calls to halt work on the dam.
They were among 18 Canadians who wrote an open letter to the province calling for an independent team of experts to explore geotechnical problems at the site.
In the letter, signed in September, the group that also included Grand Chief Stewart Phillip of the UBCIC wrote that going ahead would be a "costly and potentially catastrophic mistake."
According to Friday's update, independent experts have confirmed the site is safe, though improvements have been recommended to enhance oversight and risk management.
Earlier in the project, a B.C. First Nation claimed it was a $1-billion treaty violation, though an agreement was reached in 2020 after the province promised to improve land management and restore traditional place names in areas of cultural significance.
The Prophet River First Nation will also receive payments while the site is operating, and some Crown land will be transferred to the nation as part of the agreement.
Additionally, residents of a tiny community not far from the site is suing the province over two slow-moving landslides they claim caused property values to plummet.
Nearly three dozen residents of Old Fort are behind the allegations of negligence and breach of their charter right to security of person. The claim is tied to two landslides, in 2018 and 2020, that the group alleges were caused by ground destabilization from construction related to Site C.
One of the landslides damaged the only road into the community, leaving residents under evacuation for a month.
