Chevron chosen for Narragansett wind project

Manitoba-Minnesota Transmission Project faces NEB certificate review, with public hearings, Indigenous consultation, and cross-border approval weighing permit vs certificate timelines, potential land expropriation, and Hydro's 2020 in-service date for the 308-MW intertie.

Key Points

A cross-border hydro line linking Manitoba and Minnesota, now under NEB review through a permit or certificate process.

✅ NEB recommends certificate with public hearings and cabinet approval

✅ Stakeholders cite land, health, and economic impacts along route

✅ Hydro targets May-June 2020 in-service despite review

A recommendation from the National Energy Board could push back the construction start date of a $453-million hydroelectric transmission line from Manitoba to Minnesota.

In a letter to federal Natural Resources Minister Jim Carr, the regulatory agency recommends using a "certificate" approval process, which could take more time than the simpler "permit" process Manitoba Hydro favours.

The certificate process involves public hearings, reflecting First Nations intervention seen in other power-line debates, to weigh the merits of the project, which would then go to the federal cabinet for approval.

The NEB says this process would allow for more procedural flexibility and "address Aboriginal concerns that may arise in the circumstances of this process."

The Manitoba-Minnesota Transmission Project would provide the final link in a chain that brings hydroelectricity from generating stations in northern Manitoba, through the Bipole III transmission line and, like the New England Clean Power Link project, across the U.S. border as part of a 308-megawatt deal with the Green Bay-based Wisconsin Public Service.

When Hydro filed its application in December 2016, it had expected to have approval by the end of August 2017 and to begin construction on the line in mid-December, in order to have the line in operation by May or June 2020.  

Groups representing stakeholders along the proposed route of the transmission line had mixed reactions to the energy board's recommendation.

A lawyer representing a coalition of more than 120 landowners in the Rural Municipality of Taché and around La Broquerie, Man., welcomed the opportunity to have a more "fulsome" discussion about the project.

"I think it's a positive step. As people become more familiar with the project, the deficiencies with it become more obvious," said Kevin Toyne, who represents the Southeast Stakeholders Coalition.

Toyne said some coalition members are worried that Hydro will forcibly expropriate land in order to build the line, while others are worried about potential economic and health impacts of having the line so close to their homes. They have proposed moving the line farther east.

When the Clean Environment Commission — an arm's-length provincial government agency — held public hearings on the proposed route earlier this year, the coalition brought their concerns forward, echoing Site C opposition voiced by northerners, but Toyne says both the commission and Hydro ignored them.

Hydro still aiming for 2020 in-service date

The Manitoba Métis Federation also participated in those public hearings. MMF president David Chartrand worries about the impact a possible delay, as seen with the Site C work halt tied to treaty rights, could have on revenue from sales of hydroelectric power to the U.S.

"I know that a lot of money, billions have been invested on this line. And if the connection line is not done, then of course this will be sitting here, not gaining any revenue, which will affect every Métis in this province, given our Hydro bill's going to go up," Chartrand said.The NEB letter to Minister Carr requests that he "determine this matter in an expedited manner."

Manitoba Hydro spokesperson Bruce Owen said in an email that the Crown corporation will participate in whatever process, permit or certificate, the NEB takes.

"Manitoba Hydro does not have any information at this point in time that would change the estimated in-service date (May-June 2020) for the Manitoba-Minnesota Transmission Project," he said.

The federal government "is currently reviewing the NEB's recommendation to designate the project as subject to a certificate, which would result in public hearings," said Alexandre Deslongchamps, a spokesperson for Carr.

"Under the National Energy Board Act, an international power line requires either the approval by the NEB through a permit or approval by the Government of Canada by a certificate. Both must be issued by the NEB," he wrote in an email to CBC News.

By law, the certificate process is not to take longer than 15 months.

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Canada Oil Recession Outlook analyzes the Russia-Saudi price war, OPEC discord, COVID-19 demand shock, WTI and WCS collapse, Alberta oilsands exposure, U.S. shale stress, and GDP risks from blockades and fiscal responses.

Key Points

An outlook on how the oil price war and COVID-19 demand shock could tip Canada into recession and strain producers.

✅ WTI and WCS prices plunge on OPEC-Russia discord

✅ Alberta oilsands face break-even pressure near 30 USD WTI

✅ RBC flags global recession; GDP hit from blockades, virus

A war between Russia and Saudi Arabia for market share for oil may have been triggered by the COVID-19 pandemic in China, but the oil price crash contagion that it will spread could have impacts that last longer than the virus.

The prospects for Canada are not good.

Plunging oil prices, reduced economic activity from virus containment, and the fallout from weeks of railway blockades over the Coastal GasLink pipeline all add up to “a one-two-three punch that I think is almost inevitably going to put Canada in a position where its growth has to be negative,” said Dan McTeague, a former Liberal MP and current president of Canadians for Affordable Energy. The situation “certainly has the makings” of a recession, said Ken Peacock, chief economist for the Business Council of British Columbia.

“At a minimum, it’s going to be very disruptive and we’re going to have maybe one negative quarter,” Peacock said. “Whether there’s a second one, where it gets labeled a recession, is a different question. But it’s going to generate some turmoil and challenges over the next two quarters – there’s no doubt about that.”

RBC Economics on March 13 announced it now predicts a global recession and cut its growth projections for Canada's economy in 2020 by half a per cent.

Oil price futures plunged 30% last week, dragging stock markets and currencies, including the Canadian dollar, down with them, even as a deep freeze strained U.S. energy systems. That drop came on top of a 17% decline in February, due to falling demand for oil due to the virus.

The latest price plunge – the worst since the 1991 Gulf War – was the result of Russia and the Organization of Petroleum Exporting Countries (OPEC), led by Saudi Arabia, failing to agree on oil production cuts.

The COVID-19 outbreak in China – the world’s second-largest oil consumer – had resulted in a dramatic drop in oil demand in that country, and a sudden glut of oil, with the U.S. energy crisis affecting electricity, gas and EV markets.

OPEC has historically been able to moderate global oil prices by controlling output. But when Russia refused to co-operate with OPEC and agree to production cuts, Saudi Arabia’s state-owned company, Aramco, announced it plans to boost its oil output from 9.7 million barrels per day (bpd) to 12.3 million bpd in April.

In response to that announcement, West Texas Intermediate (WTI) prices dropped 18% to below US$34 per barrel while the Canadian Crude Index fell 24% to US$21. Western Canadian Select dropped 39% to US$15.73.

The effect on Alberta oilsands producers was severe and immediate. Cenovus Energy Inc. (TSX:CVE) saw roughly $2 billion in market cap erased on March 9, when its stock dropped by 52%, which came on top of a 12% drop March 6.

The company responded the very next day by announcing it would cut spending by 32% in 2020, suspend its oil-by-rail program and defer expansion projects.

MEG Energy Corp. (TSX:MEG), which suffered a 56% share price drop on March 9, also announced a 20% reduction in its 2020 capital spending plan.

Peter Tertzakian, chief economist for ARC Energy Research Institute, wrote last week that Russia’s plan is to try to hurt U.S. shale oil producers, who have more than doubled U.S. oil production over the past decade.

Anas Alhajji, a global oil analyst, expects that plan could work. Even before the oil price shock, he had predicted the great shale boom in the U.S. was coming to an end.

“Shale production will decline, and the myth of ‘explosive growth’ will end,” he told Business in Vancouver. “The impact is global and Canadian producers might suffer even more if the oil that Saudi Arabia sends to the U.S. is medium and heavy. This might last longer than what people think.”

The question for Alberta is how Canadian producers can continue to operate through a period of cheap oil. Alberta producers do not compete on the global market. They serve a niche market of U.S. heavy oil refiners, and Biden-era policy is seen as potentially more favourable for Canada’s energy sector than alternatives.

“On the positive side, the industry is battle-hardened,” Tertzakian wrote. “Over the past five years, innovative companies have already learned to endure some of the lowest prices in the world.”

But he added that they need WTI prices of US$30 per barrel just to break even.

“But that’s an average break-even threshold for an industry with a wide variation in costs. That means at that level about half the companies can’t pay their bills and half are treading water.”

Just prior to the oil price plunge, the International Energy Agency (IEA) updated its 2020 forecast for global oil consumption from an 825,000 bpd increase in oil consumption to a 90,000 bpd decrease, due to the COVID-19 virus and consequent economic contraction and reduction in travel.

The IEA predicts global oil demand won’t return to “normal” until the second half of 2020. But even if demand does return to pre-virus levels, that doesn’t mean oil prices will – not if Saudi Arabia can sustain increased oil production at low prices, and evolving clean grid priorities could influence the trajectory too.

The oil plunge was greeted in Alberta with alarm. Alberta Premier Jason Kenney warned Alberta is in “uncharted territory” as consumers are urged to lock in rates and said his government might have to review its balanced budget and resort to emergency deficit spending.

While British Columbians – who pay some of the highest gasoline prices in North America – will enjoy lower gasoline prices at a time when prices are usually starting a seasonal spike, B.C.’s economy could feel knock-on effects from a recession in Alberta.

“We sell a lot of inputs, do a lot of trade with Alberta, so it’s important for B.C., Alberta’s economic health,” Peacock said, “and recent tensions over electricity purchase talks underscore that.”

Last week, the Trudeau government announced $1 billion in emergency funding to cope with the virus and waived a one-week waiting period for unemployment insurance.

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Ontario Pickering Nuclear Closure will shift supply to natural gas, raising emissions as the electricity grid manages nuclear refurbishment, IESO planning, clean power imports, and new wind, solar, and storage to support electrification.

Key Points

Ontario will close Pickering and rely on natural gas, increasing emissions while other nuclear units are refurbished.

✅ 14% of Ontario electricity supplied by Pickering now

✅ Natural gas use rises; grid emissions projected up 375%

✅ IESO warns gas phaseout by 2030 risks blackouts, costs

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall with natural gas-generated power in a move that will, as an analysis of Ontario's grid shows, hike the province’s greenhouse gas emissions substantially in the coming years.

In a report released this week, a nuclear advocacy group urged Ontario to refurbish the aging facility east of Toronto, which is set to be shuttered in phases in 2024 and 2025, prompting debate over a clean energy plan after Pickering as the closure nears. The closure of Pickering, which provides 14 per cent of the province’s annual electricity supply, comes at the same time as Ontario’s other two nuclear stations are undergoing refurbishment and operating at reduced capacity.

Canadians for Nuclear Energy, which is largely funded by power workers' unions, argued closing the 50-year-old facility will result in job losses, emissions increases, heightened reliance on imported natural gas and an electricity supply gap across Ontario.

But Palmer Lockridge, spokesperson for the provincial energy minister, said further extending Pickering’s lifespan isn’t on the table.

“As previously announced in 2020, our government is supporting Ontario Power Generation’s plan to safely extend the life of the Pickering Nuclear Generating Station through the end of 2025,” said Lockridge in an emailed response to questions.

“Going forward, we are ensuring a reliable, affordable and clean electricity system for decades to come. That’s why we put a plan in place that ensures we are prepared for the emerging energy needs following the closure of Pickering, and as a result of our government’s success in growing and electrifying the province’s economy.”

The Progressive Conservative government under Premier Doug Ford has invested heavily in electrification, sinking billions into electric vehicle and battery manufacturing and industries like steel-making to retool plants to run on electricity rather than coal, and exploring new large-scale nuclear plants to bolster baseload supply.

Natural gas now provides about seven per cent of the province’s energy, a piece of the pie that will rise significantly as nuclear energy dwindles. Emissions from Ontario’s electricity grid, which is currently one of the world’s cleanest with 94 per cent zero-emission power generation, are projected to rise a whopping 375 per cent as the province turns increasingly to natural gas generation. Those increases will effectively undo a third of the hard-won emissions reductions the province achieved by phasing out coal-fired power generation.

The Independent Electricity System Operator (IESO), which manages Ontario’s grid, studied whether the province could phase out natural gas generation by 2030 and concluded that “would result in blackouts and hinder electrification” and increase average residential electricity costs by $100 per month.

The Ontario Clean Air Alliance, however, obtained draft documents from the electricity operator that showed it had studied, but not released publicly, other scenarios that involved phasing out natural gas without energy shortfalls, price hikes or increases in emissions.

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall facing Ontario with natural gas-generated power in a move that will hike the province’s greenhouse gas emissions.

One model suggested increasing carbon taxes and imports of clean energy from other provinces could keep blackouts, costs and emissions at bay, while another involved increasing energy efficiency, wind generation and storage.

“By banning gas-fired electricity exports to the U.S., importing all the Quebec water power we can with the existing transmission lines and investing in energy efficiency and wind and solar and storage — do all those things and you can phase out gas-fired power and lower our bills,” said Jack Gibbons, chair of the Ontario Clean Air Alliance.

The IESO has argued in response that the study of those scenarios was not complete and did not include many of the challenges associated with phasing out natural gas plants.

Ontario Energy Minister Todd Smith asked the IESO to develop “an achievable pathway to zero-emissions in the electricity sector and evaluate a moratorium on new-build natural gas generation stations,” said his spokesperson. That report, an early look at halting gas power, is expected in November.

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West and Central Africa Electricity Access hinges on utility reform, renewable energy, off-grid solar, mini-grids, battery storage, and regional grid integration, lowering costs, curbing energy poverty, and advancing SDG7 with sustainable, reliable power solutions.

Key Points

Expanding reliable power via renewables, grid trade, and off-grid systems to cut energy poverty and unlock inclusive growth.

✅ Utility reform lowers costs and improves service reliability

✅ Regional grid integration enables clean, least-cost power trade

✅ Off-grid solar and mini-grids electrify remote communities

As commodity prices soar and leaders around the world worry about energy shortages and prices of gasoline at the pump, millions of people in Africa still lack access to electricity.  One-half of the people on the continent cannot turn on a fan when temperatures go up, can’t keep food cool, or simply turn the lights on. This energy access crisis must be addressed urgently.

In West and Central Africa, only three countries are on track to give every one of their people access to electricity by 2030. At this slow pace, 263 million people in the region will be left without electricity in ten years.  West Africa has one of the lowest rates of electricity access in the world; only about 42% of the total population, and 8% of rural residents, have access to electricity.

These numbers, some far too big, others far too small, have grave consequences. Electricity is an important step toward enhancing people’s opportunities and choices. Access is key to boosting economic activity and contributes to improving human capital, which, in turn, is an investment in a country’s potential.  

Without electricity, children can’t do their schoolwork at night. Businesspeople can’t get information on markets or trade with each other. Worse, as the COVID-19 pandemic has shown so starkly, limited access to energy constrains hospital and emergency services, further endangering patients and spoiling precious medicine.  

What will it take to power West and Central Africa?  
As the African continent recovers from COVID-19 impacts, now is the critical time to accelerate progress towards universal energy access to drive the region’s economic transformation, promote socio-economic inclusion, and unlock human capital growth. Without reliable access to electricity, the holes in a country’s social fabric can grow bigger, those without access growing disenchanted with inequality.  

Tackling the Africa region’s energy access crisis requires four bold approaches. 

First, this involves making utilities financially viable. Many power providers in the region are cash-strapped, operate dilapidated and aging generation fleet and infrastructure. Therefore, they can’t deliver reliable and affordable electricity to their customers, let alone deliver electricity to those that currently must rely on inadequate alternatives to electricity. Overall, fewer than half of the utilities in Sub-Saharan Africa recover their operating costs, resulting in GDP losses as high as four percent in some countries.

Improving the performance of national utilities and greening their power generation mix is a prerequisite to lowering the costs of supply, thus expanding electricity access to those currently unelectrified, usually lower-income and often remote households. 

In that effort — and this a critical second point — West and Central African countries need to look beyond their borders and further integrate their national utilities and grids to other systems in the region. The region has an abundance of affordable clean energy sources — hydropower in Guinea, Mali, and Cote d’Ivoire; high solar irradiation in the Sahel — but the regional energy market is fragmented. 

Without efficient regional trade, many countries are highly dependent on one or two energy resources and heavily reliant on inefficient, polluting generation sources, requiring fuel imports linked to volatile international oil prices.

The vision of an integrated regional power market in countries of the Economic Community of West African States (ECOWAS) is coming a step closer to reality thanks to an ambitious program of cross-border interconnection projects. If countries take full advantage of this grid, the share of the region’s electricity consumption traded across borders would more than double from 8 percent today to about 17 percent by 2030. Overall, regional power trade could lower the lifecycle cost of West Africa’s power generation system by about 10 percent and provide greener energy by 2030. 

Third, electrification efforts need to be open to private sector investments and innovations, such as renewables like solar energy and battery storage, which have made a tremendous impact in enabling access for millions of poor and underserved households.  Specifically, off-grid solar systems and mini-grids have become a proven reliable way to provide affordable modern electricity services, powering homes in rural communities, healthcare facilities, and schools.

Burkina Faso, which enjoys one of the best solar radiation conditions in the region, is a successful example of leveraging the transformative impact of solar energy and battery storage. With support from the World Bank, the country is deploying solar energy to power its national grid, as well as mini-grids and individual household systems. Solar power with battery storage is competitive in Burkina Faso compared to other technologies and its government was successful in attracting private sector investments to support this technology.

Last, achieving universal electricity access will involve significant commitment from political leaders, especially developing policies and regulations that can attract high-quality investments.  

A significant step in that direction was achieved at the World Bank’s 2020 Annual Meetings with a commitment to set up the Powering Transformation Platform in each African country. Through the platform, each government will set their country-specific vision, goals and metrics, track progress, and explore and exchange innovative ideas and emerging best practices according to their own national energy needs and plans. 

This platform will bring together the elements needed to bring electricity to all in West and Central Africa and help attract new financing.

Over the last 3 years, the World Bank has doubled its investments to increase electricity access rates in Central and West Africa.  We have committed more than $7.8 billion to support 40 electricity access programs, of which more than half directly support new electricity connections. These operations are expected to provide access to 16 million people. The aim is to increase electricity access rates in West and Central Africa from 50 percent today to 64 percent by 2026.

However, World Bank’s financing alone is not enough. Our estimates show that nearly $20 billion are required for universal electrification across Sub-Saharan Africa, aligning with calls to quadruple power investment to meet demand, with about $10 billion annually needed for West and Central Africa. 

Closing the funding gap will require mobilizing traditional and new partners, especially the private sector, which is willing to invest if enabling conditions are in place, as well as philanthropic capital, that can fill in the space in areas not yet commercially attractive. The World Bank is ready to play a catalytical role in leveraging new investments. 

This is vital as less than a decade remains to reach the 2030 SDG7 goal of ensuring electricity for all through affordable, reliable, and modern energy services. As headlines worldwide focus on soaring energy prices in the developed world, we cannot lose sight of the vast populations in Africa that still cannot access basic energy services. This is the true global energy crisis.  

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Ontario electricity emissions forecast highlights rising grid CO2 as nuclear refurbishments and the Pickering closure drive more natural gas, limited renewables, and delayed Quebec hydro imports, pending advances in storage and transmission upgrades.

Key Points

A projection that Ontario's grid CO2 will rise as nuclear units refurbish or retire, increasing natural gas use.

✅ Nuclear refurbs and Pickering shutdown cut zero-carbon baseload

✅ Gas plants fill capacity gaps, boosting GHG emissions

✅ Quebec hydro imports face cost, transmission, and timing limits

Ontario's energy grid is among the cleanest in North America — but the province’s nuclear plans mean that some of our progress will be reversed over the next decade.

What was once Canada’s largest single source of greenhouse-gas emissions is now a solar-power plant. The Nanticoke Generating Station, a coal-fired power plant in Haldimand County, was decommissioned in stages from 2010 to 2013 — and even before the last remaining structures were demolished earlier this year, Ontario Power Generation had replaced its nearly 4,000 megawatts with a 44-megawatt solar project in partnership with the Six Nations of the Grand River Development Corporation and the Mississaugas of the Credit First Nation.

But neither wind nor solar has done much to replace coal in Ontario’s hydro sector, a sign of how slowly Ontario is embracing clean power in practice across the province. At Nanticoke, the solar panels make up less than 2 per cent of the capacity that once flowed out to southern Ontario over high-voltage transmission lines. In cleaning up its electricity system, the province relied primarily on nuclear power — but the need to extend the nuclear system’s lifespan will end up making our electricity dirtier again.

“We’ve made some pretty great strides since 2005 with the fuel mix,” says Terry Young, vice-president of corporate communications at the Independent Electricity System Operator, the provincial agency whose job it is to balance supply and demand in Ontario’s electricity sector. “There have been big changes since 2005, but, yes, we will see an increase because of the closure of Pickering and the refurbs coming.”

“The refurbs” is industry-speak for the major rebuilds of both the Darlington and Bruce nuclear-power stations. The two are both in the early stages of major overhauls intended to extend their operating lives into the 2060s: in the coming years, they’ll be taken offline and rebuilt. (The Pickering nuclear plant will not be refurbished and will shut down in 2024.)

The catch is that, as the province loses its nuclear capacity in increments, Ontario will be short of electricity in the coming years and the IESO will need to find capacity elsewhere to make sure the lights stay on. And that could mean burning a lot more natural gas — and creating more greenhouse-gas emissions.

According to the IESO’s planning assumptions, electricity will be responsible for 11 megatonnes of greenhouse-gas emissions annually by 2035 (last year, it was three megatonnes). That’s the “reference case” scenario: if conservation and efficiency policies shave off some electricity demand, we could get it down to something like nine megatonnes. But if demand is higher than expected, it could be as high as 13 megatonnes — more than quadruple Ontario’s 2018 emissions.

Even in the worst-case scenario, the province’s emissions from electricity would still be less than half of what they were in 2005, before the province began phasing out its coal generation. But it’s still a reversal of a trend that both Liberals and Progressive Conservatives have boasted about — the Liberals to justify their energy policies, the PCs to justify their hostility to a federal carbon tax.

Young emphasized that technology can change and that the IESO’s planning assumptions are just that: projections based on the information available today. A revolution in electricity storage could make it possible to store the province’s cleaner power sources overnight for use during the day, but that’s still only in the realm of speculation — and the natural-gas infrastructure exists in the real world, today.

Ontario Power Generation — the Crown corporation that operates many of the province’s power plants, including Pickering and Darlington — recently bought four gas plants, two of them outright (two it already owned in part). All were nearly complete or already operational, so the purchase itself won’t change the province’s emissions prospects. Rather, OPG is simply looking to maintain its share of the electricity market after the Pickering shutdown.

“It will allow us to maintain our scale, with the upcoming end of Pickering’s commercial operations, so that we can continue our role as the driver of Ontario’s lower carbon future,” Neal Kelly, OPG’s director of media, issues, and management, told TVO.org via email. “Further, there is a growing need for flexible gas fired generation to support intermittent wind and solar generation.”

The shift to more gas-fired generation has been coming for a while, and critics say that Ontario has missed an opportunity to replace the lost Pickering capacity with something cleaner. MPP Mike Schreiner, leader of the Green party, has argued for years that Ontario should have pursued an agreement with Quebec to import clean hydroelectricity.

“To me, it’s a cost-effective solution, and it’s a zero-emissions solution,” Schreiner says. “Regardless of your position on sources of electricity, I think everyone could agree that waterpower from Quebec is going to be less expensive.”

Quebec is eager to sell Ontario its surplus hydro power, but not everyone agrees that importing power would be cheaper. A study published by the Ontario Chamber of Commerce (and commissioned by Ontario Power Generation) calls the claim a “myth” and states that upgrading electric-transmission wires between Ontario and Quebec would cost $1.2 billion and take 10 years, while some estimates suggest fully greening Ontario's grid would cost far more overall.

With Quebec imports seemingly a non-starter and major changes to Ontario’s nuclear fleet already underway, there’s only one path left for this province’s greenhouse-gas emissions: upwards.

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Great Britain electricity generation spans renewables and baseload: wind, solar, nuclear, gas, and biomass, supported by National Grid interconnectors, embedded energy estimates, and BMRS data for dynamic imports and exports across Europe.

Key Points

A diverse, weather-driven mix of renewables, gas, nuclear, and imports coordinated by National Grid.

✅ Baseload from nuclear and biomass; intermittent wind and solar

✅ Interconnectors trade zero carbon imports via subsea cables

✅ Data from BMRS and ESO covers embedded energy estimates

Great Britain has one of the most diverse ranges of electricity generation in Europe, with everything from windfarms off the coast of Scotland to a nuclear power station in Suffolk tasked with keeping the lights on. The increasing reliance on renewable energy sources, as part of the country’s green ambitions, also means there can be rapid shifts in the main source of electricity generation. On windy days, most electricity generation comes from record wind generation across onshore and offshore windfarms. When conditions are cold and still, gas-fired power stations known as peaking plants are called into action.

The electricity system in Great Britain relies on a combination of “baseload” power – from stable generators such as nuclear and biomass plants – and “intermittent” sources, such as wind and solar farms that need the right weather conditions to feed energy into the grid. National Grid also imports energy from overseas, through subsea cables known as interconnectors that link to France, Belgium, Norway and the Netherlands. They allow companies to trade excess power, such as renewable energy created by the sun, wind and water, between different countries. By 2030 it is hoped that 90% of the energy imported by interconnectors will be from zero carbon energy sources, though low-carbon electricity generation stalled in 2019 for the UK.

The technology behind Great Britain’s power generation has evolved significantly over the last century, and at times wind has been the main source of electricity. The first integrated national grid in the world was formed in 1935 linking seven regions of the UK. In the aftermath of industrialisation, coal provided the vast majority of power, before oil began to play an increasingly important part in the 1950s. In 1956, the world’s first commercial nuclear reactor, Calder Hall 1 at Windscale (later Sellafield), was opened by Queen Elizabeth II. Coal use fell significantly in the 1990s while the use of combined cycle gas turbines grew, and in 2016 wind generated more electricity than coal for the first time. Now a combination of gas, wind, nuclear and biomass provide the bulk of Great Britain’s energy, with smaller sources such as solar and hydroelectric power also used. From October 2024, coal will no longer be used to generate electricity, following coal-free power records set in recent years.

Energy generation data is fetched from the Balancing Mechanism Reporting Service public feed, provided by Elexon – which runs the wholesale energy market – and is updated every five minutes, covering periods when wind led the power mix as well.

Elexon’s data does not include embedded energy, which is unmetered and therefore invisible to Great Britain’s National Grid. Embedded energy comprises all solar energy and wind energy generated from non-metered turbines. To account for these figures we use embedded energy estimates from the National Grid electricity system operator, which are published every 30 minutes.

Import figures refer to the net flow of electricity from the interconnectors with Europe and with Northern Ireland. A positive value represents import into the GB transmission system, while a negative value represents an export.

Hydro figures combine renewable run-of-the-river hydropower and pumped storage.

Biomass figures include Elexon’s “other” category, which comprises coal-to-biomass conversions and biomass combined heat and power plants.

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