How big power will keep control

By Nick Rosen, Off Grid


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The man who runs one of the largest energy retailers in America (and Britain) has signaled the death of the traditional utility company. He is typical of a new breed of energy executive which will try to take the mantle of environmentalism to keep the profits rolling in and keep control of the industry firmly away from end users.

Sam Laidlaw is boss of Direct Energy, which sells energy to five million customers in the United States and Canada. He has revolutionized Direct Energy, bringing in a scheme where American customers can pay extra $25 a month to ensure their electricity is generated from wind power.

So far the company has power purchase agreements totaling 813MW of wind power but that will increase as it wins more customers. Laidlaw provides energy and energy-related services to residential and business customers in Texas, and the north and east of the U.S., as well as across Canada. But he has no ideological commitment to renewables, Direct Energy owns and operates approximately 3,000 natural gas wells in Alberta, while in Texas it owns three gas-fired power plants.

He aims to sell every American and Brit a “warm, well-lit home” and in a carbon-constrained world, he argues, energy companies must reinvent themselves. No longer can they thrive simply by offering consumers an “all-you-can eat buffet” of cheap gas and electricity, with scant regard for emissions. Instead, “in future, we will sell you a warm, well-lit home and take care of everything else,” said Mr. Laidlaw, a former oil company executive who was educated at Eton and Insead and joined Centrica in 2006.

The companies will continue to sell gas and electricity “but we will sell more energy-efficiency products — insulation, heat pumps, solar panels.… And we will add valuable margin and pick up more customers along the way.”

As well as owning British Gas — one of the UK’s Big Six power companies Centrica owns Direct Energy, the American retail energy business, and three other wholesale energy production and storage businesses.

“We decided three years ago that in a world of climate change, carbon dioxide cuts and increased consumer enthusiasm for lower-carbon products, we wanted to turn all of those things into a business.” For Mr. Laidlaw, the answer to the challenge of carving a viable energy business out of reduced consumption lay in the unlikely form of the company’s boiler repair division, a hidden jewel — an army of experienced engineers.

Mr. Laidlaw’s plan was to transform this band into the shock troops of a green revolution, training the engineers to conduct home “energy audits” and to install a range of other products, from solar panels to smart meters. The strategy is reaping results already. “If you look at the revenue stream between selling energy and services, there is a change under way,” Mr. Laidlaw said.

“We are starting to see some of the potential benefits from that,” Mr. Laidlaw said, adding that this was only the start. He believes that gas demand could fall by up to 15 per cent over the next five years. “You could get nearly half of those cuts simply from energy efficiency,” he said.

Far from being a threat to utility companies, energy efficiency, Mr. Laidlaw believes, represents a vast untapped business opportunity, one that could be worth up to £150 billion in the UK.

“UK energy consumption is one of the highest in Europe because of the poor quality and age of our housing stock,” he said. “So, there is a huge opportunity.”

With a market value of £13 billion, 33,000 staff and 15.7 million customers, Centrica is applying the same strategy to Direct Energy, which sells energy to five million customers in the United States and Canada. And while Centrica’s traditional businesses of producing and selling gas and power still generate the lion’s share of group profits, Mr. Laidlaw believes that services will be increasingly important. New technology will broaden the opportunity and the company is preparing to launch a home-based fuel cell that generates electricity, as well as heat.

“You will have a boiler that will also generate electricity and you can export that to the grid and get paid for it,” Mr Laidlaw said.

Yet the real key to unlocking the opportunity will be the rollout of “smart meters” in all 26 million homes in the UK, plans for which the government is expected to unveil this week. Smart meters, monitoring household energy all day, will allow for more sophisticated services, including systems that allow people to control home appliances remotely or to turn the heating on automatically when their mobile phone indicates that they are near home.

Most importantly, they will let utilities control demand by giving discounts for off-peak energy use. By encouraging people to run their dishwashers and tumble dryers at night, utilities will be able to ease overall demand, allowing Britain to get by with less electricity and fewer emissions.

“Consumers will not have the agonies of estimated bills and we won’t need to build as many power stations,” Mr. Laidlaw said.

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Coronavirus impacts dismantling of Germany's Philippsburg nuclear plant

Philippsburg Demolition Delay: EnBW postpones controlled cooling-tower blasts amid the coronavirus pandemic, affecting decommissioning timelines in Baden-Wurttemberg and grid expansion for a transformer station to route renewable power and secure supply in southern Germany.

 

Key Points

EnBW's COVID-19 delay of Philippsburg cooling-tower blasts, affecting decommissioning and grid plans.

✅ Controlled detonation shifted to mid-May at earliest

✅ Demolition links to transformer station for north-south grid

✅ Supports security of supply in southern Germany

 

German energy company EnBW said the coronavirus outbreak has impacted plans to dismantle its Philippsburg nuclear power plant in Baden-Wurttemberg, southwest Germany, amid plans to phase out coal and nuclear nationally.

The controlled detonation of Phillipsburg's cooling towers will now take place in mid-May at the earliest, subject to coordination as Germany debates whether to reconsider its nuclear phaseout in light of supply needs.

However, EnBW said the exact demolition date depends on many factors - including the further development in the coronavirus pandemic and ongoing climate policy debates about energy choices.

Philippsburg 2, a 1402MWe pressurised water reactor unit permanently shut down on 31 December 2019, as part of Germany's broader effort to shut down its remaining reactors over time.

At the end of 2019, the Ministry of the Environment gave basic approval for decommissioning and dismantling of unit 2 of the Philippsburg nuclear power plant, inluding explosive demolition of the colling towers. Since then EnBW has worked intensively on getting all the necessary formal steps on the way and performing technical and logistical preparatory work, even as discussions about a potential nuclear resurgence continue nationwide.

“The demolition of the cooling towers is directly related to future security of supply in southern Germany. We therefore feel obliged to drive this project forward," said Jörg Michels head of the EnBW nuclear power division.

The timely removal of the cooling towers is important as the area currently occupied by nuclear plant components is needed for a transformer station for long-distance power lines, an issue underscored during the energy crisis when Germany temporarily extended nuclear power to bolster supply. These will transport electricity from renewable sources in the north to industrial centres in the south.

As of early 2020, there six nuclear reactors in operation in Germany, even as the country turned its back on nuclear in subsequent years. According to research institute Fraunhofer ISE, nuclear power provided about 14% of Germany's net electricity in 2019, less than half of the figure for 2000.

 

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Bruce Power awards $914 million in manufacturing contracts

Bruce Power Major Component Replacement secures Ontario-made nuclear components via $914M contracts, supporting refurbishment, clean energy, low-cost electricity, and advanced manufacturing, extending reactor life to 2064 while boosting jobs, supply chain growth, and economy.

 

Key Points

A refurbishment program investing $914M in advanced manufacturing to extend reactors and deliver low-cost, clean power.

✅ $914M Ontario-made components for steam generators, tubes, fittings

✅ Extends reactor life to 2064; clean, low-cost electricity for Ontario

✅ Supports 22,000 jobs annually; boosts supply chain and economy

 

Today, Bruce Power signed $914 million in advanced manufacturing contracts for its Major Component Replacement, which gets underway in 2020, as the reactor refurbishment begins across the site and will allow the site to provide low-cost, carbon-free electricity to Ontario through 2064.

The Major Component Replacement (MCR) Project agreements include:

  • $642 million to BWXT Canada Inc. for the manufacturing of 32 steam generators to be produced at BWXT’s Cambridge facility.
  • $144 million to Laker Energy Products for end fittings, liners and flow elements, which will be manufactured at its Oakville location.
  • $62 million to Cameco Fuel Manufacturing, in Cobourg, for calandria tubes and annulus spacers for all six MCRs.
  • $66 million for Nu-Tech Precision Metals, in Arnprior, for the production of zirconium alloy pressure tubes for Units 6 and 3.

 

Bruce Power’s Life-Extension Program, which started in January 2016 with Asset Management Program investments and includes the MCRs on Units 3-8, remains on time and on budget.”

#google#

By signing these contracts today, we have secured ‘Made in Ontario‘ solutions for the components we will need to successfully complete our MCR Projects, extending the life of our site to 2064,” said Mike Rencheck, Bruce Power’s President and CEO.

“Today’s announcements represent a $914 million investment in Ontario’s highly skilled workforce, which will create untold economic opportunities for the communities in which they operate for many years to come.”We look forward to growing our already excellent relationships with these supplier partners and unions as we work toward our common goal, supported by an operating record, of continuing to keep Canada’s largest infrastructure project on time and on budget."

By extending the life of Bruce Power’s reactors to 2064, the company will create and sustain 22,000 jobs annually, both directly and indirectly, across Ontario, while investing $4 billion a year into the province’s economy, underscoring the economic benefits of nuclear development across Canada.

At the same time, Bruce Power will produce 30 per cent of Ontario’s electricity at 30 per cent less than the average cost to generate residential power, while also producing zero carbon emissions, aligning with Pickering NGS life extensions across the province.The Hon. Glenn Thibeault, Minister of Energy, said today’s announcement is good news for the people of Ontario.”

Bruce Power’s Life-Extension Program makes sense for Ontario, and the announcements made today will create good jobs and benefit our economy for decades to come,” Minister Thibeault said.

“Moving forward with the refurbishment project is part of our government’s plan to support care and opportunity, while producing affordable, reliable and clean energy for the people of Ontario.”Kim Rudd, Parliamentary Secretary to the Minister of Natural Resources and MP for Northumberland-Peterborough South, offered her support and congratulations.”

Related planning includes Bruce C project exploration funding that supports long-term nuclear options in Ontario.

Canada’s nuclear industry, including its advanced manufacturing capability, is respected internationally,” Rudd said. “Bruce Power’s announcement today related to the advanced manufacturing of key components throughout Ontario as part of its Life-Extension Program will allow these suppliers to have a secure base to not only meet Canada’s needs, but export internationally.”

 

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Three Mile Island at center of energy debate: Let struggling nuclear plants close or save them

Three Mile Island Nuclear Debate spotlights subsidies, carbon pricing, wholesale power markets, grid reliability, and zero-emissions goals as Pennsylvania weighs keeping Exelon's reactor open amid natural gas competition and flat electricity demand.

 

Key Points

Debate over subsidies, carbon pricing, and grid reliability shaping Three Mile Island's zero-emissions future.

✅ Zero emissions credits vs market integrity

✅ Carbon pricing to value clean baseload power

✅ Closure risks jobs, tax revenue, and reliability

 

Three Mile Island is at the center of a new conversation about the future of nuclear energy in the United States nearly 40 years after a partial meltdown at the Central Pennsylvania plant sparked a national debate about the safety of nuclear power.

The site is slated to close in just two years, a closure plan Exelon has signaled, unless Pennsylvania or a regional power transmission operator delivers some form of financial relief, says Exelon, the Chicago-based power company that operates the plant.

That has drawn the Keystone State into a growing debate: whether to let struggling nuclear plants shut down if they cannot compete in the regional wholesale markets where energy is bought and sold, or adopt measures to keep them in the business of generating power without greenhouse gas emissions.

""The old compromise — that in order to have a reliable, affordable electric system you had to deal with a significant amount of air pollution — is a compromise our new customers today don't want to hear about.""
-Joseph Dominguez, Exelon executive vice president
Nuclear power plants produce about two-thirds of the country's zero-emissions electricity, a role many view as essential to net-zero emissions goals for the grid.

The debate is playing out as some regions consider putting a price on planet-warming carbon emissions produced by some power generators, which would raise their costs and make nuclear plants like Three Mile Island more viable, and developments such as Europe's nuclear losses highlight broader energy security concerns.

States that allow nuclear facilities to close need to think carefully because once a reactor is powered down, there's no turning back, said Jake Smeltz, chief of staff for Pennsylvania State Sen. Ryan Aument, who chairs the state's Nuclear Energy Caucus.

"If we wave goodbye to a nuclear station, it's a permanent goodbye because we don't mothball them. We decommission them," he told CNBC.

Three Mile Island's closure would eliminate more than 800 megawatts of electricity output. That's roughly 10 percent of Pennsylvania's zero-emissions energy generation, by Exelon's calculation. Replacing that with fossil fuel-fired power would be like putting roughly 10 million cars on the road, it estimates.

A closure would also shed about 650 well-paying jobs, putting the just transition challenge in focus for local workers and communities, tied to about $60 million in wages per year. Dauphin County and Londonderry Township, a rural area on the Susquehanna River where the plant is based, stand to lose $1 million in annual tax revenue that funds schools and municipalities. The 1,000 to 1,500 workers who pack local hotels, stores and restaurants every two years for plant maintenance would stop visiting.

Pennsylvanians and lawmakers must now decide whether these considerations warrant throwing Exelon a lifeline. It's a tough sell in the nation's second-largest natural gas-producing state, which already generates more energy than it uses. And time is running out to reach a short-term solution.

"What's meaningful to us is something where we could see the results before we turn in the keys, and we turn in the keys the third quarter of '19," said Joseph Dominguez, Exelon's executive vice president for governmental and regulatory affairs and public policy.

The end of the nuclear age?

The problem for Three Mile Island is the same one facing many of the nation's 60 nuclear plants: They are too expensive to operate.

Financial pressure on these facilities is mounting as power demand remains stagnant due to improved energy efficiency, prices remain low for natural gas-fired generation and costs continue to fall for wind and solar power.

Three Mile Island is something of a special case: The 1979 incident left only one of its two reactors operational, but it still employs about as many people as a plant with two reactors, making it less efficient. In the last three regional auctions, when power generators lock in buyers for their future energy generation, no one bought power from Three Mile Island.

But even dual-reactor plants are facing existential threats. FirstEnergy Corp's Beaver Valley will sell or close its nuclear plant near the Pennsylvania-Ohio border next year as it exits the competitive power-generation business, and facilities like Ohio's Davis-Besse illustrate what's at stake for the region.

Five nuclear power plants have shuttered across the country since 2013. Another six have plans to shut down, and four of those would close well ahead of schedule. An analysis by energy research firm Bloomberg New Energy Finance found that more than half the nation's nuclear plants are facing some form of financial stress.

Today's regional energy markets, engineered to produce energy at the lowest cost to consumers, do not take into account that nuclear power generates so much zero-emission electricity. But Dominguez, the Exelon vice president, said that's out of step with a world increasingly concerned about climate change.

"What we see is increasingly our customers are interested in getting electricity from zero air pollution sources," Dominguez said. "The old compromise — that in order to have a reliable, affordable electric system you had to deal with a significant amount of air pollution — is a compromise our new customers today don't want to hear about."

Strange bedfellows

Faced with the prospect of nuclear plant closures, Chicago and New York have both allowed nuclear reactors to qualify for subsidies called zero emissions credits. Exelon lobbied for the credits, which will benefit some of its nuclear plants in those states.

Even though the plants produce nuclear waste, some environmental groups like the Natural Resources Defense Council supported these plans. That's because they were part of broader packages that promote wind and solar power, and the credits for nuclear are not open-ended. They essentially provide a bridge that keeps zero-emissions power from nuclear reactors on the grid as renewable energy becomes more viable.

Lawmakers in Pennsylvania, Ohio and Connecticut are currently exploring similar options. Jake Smeltz, chief of staff to state Sen. Aument, said legislation could surface in Pennsylvania as soon as this fall. The challenge is to get people to consider the attributes of the sources of their electricity beyond just cost, according to Smeltz.

"Are the plants worth essentially saving? That's a social choice. Do they provide us with something that has benefits beyond the electrons they make? That's the debate that's been happening in other states, and those states say yes," he said.

Subsidies face opposition from anti-nuclear energy groups like Three Mile Island Alert, as well as natural gas trade groups and power producers who compete against Exelon by operating coal and natural gas plants.

"Where we disagree is to have an out-of-market subsidy for one specific company, for a technology that is now proven and mature in our view, at the expense of consumers and the integrity of competitive markets," NRG Energy Mauricio Gutierrez told analysts during a conference call this month.

Smeltz notes that power producers like NRG would fill in the void left by nuclear plants as they continue to shut down.

"The question that I think folks need to answer is are these programs a bailout or is the opposition to the program a payout? Because at the end of the day someone is going to make money. The question is who and how much?" Smeltz said.

Changing the market

Another critic is PJM Interconnection, the regional transmission organization that operates the grid for 13 states, including Pennsylvania, and Washington, D.C.

The subsidies distort price formation and inject uncertainty into the markets, says Stu Bresler, senior vice president in charge of operations and markets at PJM.

The danger PJM sees is that each new subsidy creates a precedent for government intervention. The uncertainty makes it harder for investors to determine what sort of power generation is a sound investment in the region, Bresler explained. Those investors could simply decide to put their capital to work in other energy markets where the regulatory outlook is more stable, ultimately leading to underinvestment in places where government intervenes, he added.

Three Mile Island nuclear power plant, Londonderry Township, Pennsylvania
PJM believes longer-term, regional approaches are more appropriate. It has produced research that outlines how coal plants and nuclear energy, which provide the type of stable energy that is still necessary for reliable power supply, could play a larger role in setting prices. It is also preparing to release a report on how to put a price on carbon emissions in all or parts of the regional grid.

"If carbon emissions are the concern and that is the public policy issue with which policymakers are concerned, the simple be-all answer from a market perspective is putting a price on carbon," Bresler said.

Three Mile Island could be viable if natural gas prices rose from below $3 per million British thermal units to about $5 per mmBtu and if a "reasonable" price were applied to carbon, according to Exelon's Dominguez. He is encouraged by the fact that conversations around new pricing models and carbon pricing are gaining traction.

"The great part about this is everybody understands we have a major problem. We're losing some of the lowest-cost, cleanest and most reliable resources in America," Dominguez said.

 

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Climate change poses high credit risks for nuclear power plants: Moody's

Nuclear Plant Climate Risks span flood risk, heat stress, and water scarcity, threatening operations, safety systems, and steam generation; resilience depends on mitigation investments, cooling-water management, and adaptive maintenance strategies.

 

Key Points

Climate-driven threats to nuclear plants: floods, heat, and water stress requiring resilience and mitigation.

✅ Flooding threats to safety and cooling systems

✅ Heat stress reduces thermal efficiency and output

✅ Water scarcity risks limit cooling capacity

 

 

Climate change can affect every aspect of nuclear plant operations like fuel handling, power and steam generation and the need for resilient power systems planning, maintenance, safety systems and waste processing, the credit rating agency said.

However, the ultimate credit impact will depend upon the ability of plant operators to invest in carbon-free electricity and other mitigating measures to manage these risks, it added.
Close proximity to large water bodies increase the risk of damage to plant equipment that helps ensure safe operation, the agency said in a note.

Moody’s noted that about 37 gigawatts (GW) of U.S. nuclear capacity is expected to have elevated exposure to flood risk and 48 GW elevated exposure to combined rising heat, extreme heat costs and water stress caused by climate change.

Parts of the Midwest and southern Florida face the highest levels of heat stress, while the Rocky Mountain region and California face the greatest reduction in the availability of future water supply, illustrating the need for adapting power generation to drought strategies, it said.

Nuclear plants seeking to extend their operations by 20, or even 40 years, beyond their existing 40-year licenses in support of sustaining U.S. nuclear power and decarbonization face this climate hazard and may require capital investment adjustments, Moody’s said, as companies such as Duke Energy climate report respond to investor pressure for climate transparency.

“Some of these investments will help prepare for the increasing severity and frequency of extreme weather events, highlighting that the US electric grid is not designed for climate impacts today.”

 

 

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European gas prices fall to pre-Ukraine war level

European Gas Prices hit pre-invasion lows as LNG inflows, EU storage gains, and softer oil markets ease the energy crisis, while recession risks, windfall taxes, and ExxonMobil's challenge shape demand and policy.

 

Key Points

European gas prices reflect supply, LNG inflows, storage, and policy, shaping energy costs for households and industry.

✅ Month-ahead hit €76.78/MWh, rebounding to €85.50/MWh.

✅ EU storage 83.2% filled; autumn peak exceeded 95%.

✅ Demand tempered by recession risks; LNG inflows offset Russian cuts.

 

European gas prices have dipped to a level last seen before Russia launched its invasion of Ukraine in February, after warmer weather across the continent eased concerns over shortages and as coal demand dropped across Europe during winter.

The month-ahead European gas future contract dropped as low as €76.78 per megawatt hour on Wednesday, the lowest level in 10 months, amid EU talks on gas price cap strategies that could shape markets, before closing higher at €83.70, according to Refinitiv, a data company.

The invasion roiled global energy markets, serving as a wake-up call to ditch fossil fuels for policymakers, and forced European countries, including industrial powerhouse Germany, to look for alternative suppliers to those funding the Kremlin. Europe had continued to rely on Russian gas even after its 2014 annexation of Crimea and support for separatists in eastern Ukraine.

On Tuesday 83.2% of EU gas storage was filled, data from industry body Gas Infrastructure Europe showed. The EU in May set a target of filling 80% of its gas storage capacity by the start of November to prepare for winter, and weighed emergency electricity measures to curb prices as needed. It hit that target in August, and by mid-November it had peaked at more than 95%.

Gas prices bounced further off the 10-month low on Thursday to reach €85.50 per megawatt hour.

Europe has several months of domestic heating demand ahead, and some industry bosses believe energy shortages could also be a problem next winter, with a worst energy nightmare still possible if supplies tighten. However, traders have also had to weigh the effects of recessions expected in several big European economies, which could dent energy demand.

UK gas prices have also dropped back from their highs earlier this year, and forecasts suggest UK energy bills to drop in April. The day-ahead gas price closed at 155p per therm on Wednesday, compared with 200p/therm at the start of 2022, and more than 500p/therm in August.

Europe’s response to the prospect of gas shortages also included campaigns to reduce energy use – a strategy belatedly adopted by the UK – and windfall taxes on energy companies to help raise revenues for governments, many of which have started expensive subsidies to cushion the impact of high energy prices for households and consumers. Energy companies have enjoyed huge profits at the expense of businesses and households this year, as EU inflation accelerated, but costs remained much the same.

However, the US oil company ExxonMobil on Wednesday launched a legal challenge against EU plans for a windfall tax on oil companies, according to filings by its German and Dutch subsidiaries at the European general court in Luxembourg. ExxonMobil argued that the windfall tax would be “counter-productive” because it said it would result in lower investment in fossil fuel extraction, and that the EU did not have the legal jurisdiction to impose it.

ExxonMobil’s move has prompted anger among European politicians. A message posted on the Twitter account of Paolo Gentiloni, the EU’s commissioner for the economy, on Thursday stated: “Fairness and solidarity, even for corporate giants. #Exxon.”

Oil prices are significantly lower than they were before the start of Russia’s invasion, and only marginally above where they were at the start of 2022. Brent crude oil futures traded at $100 a barrel on 28 February, but were at $81.84 on Thursday.

Oil prices dropped by 1.7% on Thursday. Prices had risen from 12-month lows in early December as traders hoped for increased demand from China after it relaxed its coronavirus restrictions. However, Covid-19 infection numbers are thought to have surged in the country, prompting the US to require travellers from China to show a negative test for the disease and tempering expectations for a rapid increase in oil demand.

 

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Africa's Electricity Unlikely To Go Green This Decade

Africa 2030 Energy Mix Forecast finds electricity generation doubling, with fossil fuels dominant, non-hydro renewables under 10%, hydro vulnerable to droughts, and machine-learning analysis of planned power plants shaping climate and investment decisions.

 

Key Points

An analysis predicting Africa's 2030 power mix, with fossil fuels dominant, limited renewables growth, and hydro risks.

✅ ML model assesses 2,500 planned plants' commissioning odds

✅ Fossil fuels ~66% of generation; non-hydro RE <10% by 2030

✅ Policy shifts and finance reallocation to scale solar and wind

 

New research today from the University of Oxford predicts that total electricity generation across the African continent will double by 2030, with fossil fuels continuing to dominate the energy mix posing potential risk to global climate change commitments.

The study, published in Nature Energy, uses a state-of-the art machine-learning technique to analyse the pipeline of more than 2,500 currently-planned power plants and their chances of being successfully commissioned. It shows the share of non-hydro renewables in African electricity generation is likely to remain below 10% in 2030, although this varies by region.

'Africa's electricity demand is set to increase significantly as the continent strives to industrialise and improve the wellbeing of its people, which offers an opportunity to power this economic development and expand universal electricity access through renewables' says Galina Alova, study lead author and researcher at the Oxford Smith School of Enterprise and the Environment.

'There is a prominent narrative in the energy planning community that the continent will be able to take advantage of its vast renewable energy resources and rapidly decreasing clean technology prices to leapfrog to renewables by 2030 but our analysis shows that overall it is not currently positioned to do so.'

The study predicts that in 2030, fossil fuels will account for two-thirds of all generated electricity across Africa. While an additional 18% of generation is set to come from hydro-energy projects across Africa. These have their own challenges, such as being vulnerable to an increasing number of droughts caused by climate change.

The research also highlights regional differences in the pace of the transition to renewables across Sub-Saharan Africa, with southern Africa leading the way. South Africa alone is forecast to add almost 40% of Africa's total predicted new solar capacity by 2030.

'Namibia is committed to generate 70% of its electricity needs from renewable sources, including all the major alternative sources such as hydropower, wind and solar generation, by 2030, as specified in the National Energy Policy and in Intended Nationally Determined Contributions under Paris Climate Change Accord,' says Calle Schlettwein, Namibia Minister of Water (former Minister of Finance and Minister of Industrialisation). 'We welcome this study and believe that it will support the refinement of strategies for increasing generation capacity from renewable sources in Africa and facilitate both successful and more effective public and private sector investments in the renewable energy sector.'

Minister Schlettwein adds: 'The more data-driven and advanced analytics-based research is available for understanding the risks associated with power generation projects, the better. Some of the risks that could be useful to explore in the future are the uncertainties in hydrological conditions and wind regimes linked to climate change, and economic downturns such as that caused by the COVID-19 pandemic.'

The study further suggests that a decisive move towards renewable energy in Africa would require a significant shock to the current system. This includes large-scale cancellation of fossil fuel plants currently being planned. In addition, the study identifies ways in which planned renewable energy projects can be designed to improve their success chances for example, smaller size, fitting ownership structure, and availability of development finance for projects.

'The development community and African decision makers need to act quickly if the continent wants to avoid being locked into a carbon-intense energy future' says Philipp Trotter, study author and researcher at the Smith School. 'Immediate re-directions of development finance from fossil fuels to renewables are an important lever to increase experience with solar and wind energy projects across the continent in the short term, creating critical learning curve effects.'

 

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