Ontario to Rely on Battery Storage to Meet Rising Energy Demand

Offshore wind power accelerates low-carbon electrification, leveraging floating turbines, high capacity factors, HVDC transmission, and hydrogen production to decarbonize grids, cut CO2, and deliver competitive, reliable renewable energy near demand centers.

Key Points

Offshore wind power uses offshore turbines to deliver low-carbon electricity with high capacity factors and falling costs.

✅ Sea-based wind farms with 40-50% capacity factors

✅ Floating turbines unlock deep-water, far-shore resources

✅ Enables hydrogen production and strengthens grid reliability

The need for affordable low-carbon technologies is greater than ever

Global energy-related CO2 emissions reached a historic high in 2018, driven by an increase in coal use in the power sector. Despite impressive gains for renewables, fossil fuels still account for nearly two-thirds of electricity generation, the same share as 20 years ago. There are signs of a shift, with increasing pledges to decarbonise economies and tackle air pollution, and with World Bank support helping developing countries scale wind, but action needs to accelerate to meet sustainable energy goals. As electrification of the global energy system continues, the need for clean and affordable low-carbon technologies to produce this electricity is more pressing than ever. This World Energy Outlook special report offers a deep dive on a technology that today has a total capacity of 23 GW (80% of it in Europe) and accounts for only 0.3% of global electricity generation, but has the potential to become a mainstay of the world's power supply. The report provides the most comprehensive analysis to date of the global outlook for offshore wind, its contributions to electricity systems and its role in clean energy transitions.

The offshore wind market has been gaining momentum

The global offshore wind market grew nearly 30% per year between 2010 and 2018, benefitting from rapid technology improvements. Over the next five years, about 150 new offshore wind projects are scheduled to be completed around the world, pointing to an increasing role for offshore wind in power supplies. Europe has fostered the technology's development, led by the UK offshore wind sector alongside Germany and Denmark. The United Kingdom and Germany currently have the largest offshore wind capacity in operation, while Denmark produced 15% of its electricity from offshore wind in 2018. China added more capacity than any other country in 2018.

The untapped potential of offshore wind is vast

The best offshore wind sites could supply more than the total amount of electricity consumed worldwide today. And that would involve tapping only the sites close to shores. The IEA initiated a new geospatial analysis for this report to assess offshore wind technical potential country by country. The analysis was based on the latest global weather data on wind speed and quality while factoring in the newest turbine designs. Offshore wind's technical potential is 36 000 TWh per year for installations in water less than 60 metres deep and within 60 km from shore. Global electricity demand is currently 23 000 TWh. Moving further from shore and into deeper waters, floating turbines could unlock enough potential to meet the world's total electricity demand 11 times over in 2040. Our new geospatial analysis indicates that offshore wind alone could meet several times electricity demand in a number of countries, including in Europe, the United States and Japan. The industry is adapting various floating foundation technologies that have already been proven in the oil and gas sector. The first projects are under development and look to prove the feasibility and cost-effectiveness of floating offshore wind technologies.

Offshore wind's attributes are very promising for power systems

New offshore wind projects have capacity factors of 40-50%, as larger turbines and other technology improvements are helping to make the most of available wind resources. At these levels, offshore wind matches the capacity factors of gas- and coal-fired power plants in some regions – though offshore wind is not available at all times. Its capacity factors exceed those of onshore wind and are about double those of solar PV. Offshore wind output varies according to the strength of the wind, but its hourly variability is lower than that of solar PV. Offshore wind typically fluctuates within a narrower band, up to 20% from hour to hour, than solar PV, which varies up to 40%.

Offshore wind's high capacity factors and lower variability make its system value comparable to baseload technologies, placing it in a category of its own – a variable baseload technology. Offshore wind can generate electricity during all hours of the day and tends to produce more electricity in winter months in Europe, the United States and China, as well as during the monsoon season in India. These characteristics mean that offshore wind's system value is generally higher than that of its onshore counterpart and more stable over time than that of solar PV. Offshore wind also contributes to electricity security, with its high availability and seasonality patterns it is able to make a stronger contribution to system needs than other variable renewables. In doing so, offshore wind contributes to reducing CO2 and air pollutant emissions while also lowering the need for investment in dispatchable power plants. Offshore wind also has the advantage of avoiding many land use and social acceptance issues that other variable renewables are facing.

Offshore wind is on track to be a competitive source of electricity

Offshore wind is set to be competitive with fossil fuels within the next decade, as well as with other renewables including solar PV. The cost of offshore wind is declining and is set to fall further. Financing costs account for 35% to 50% of overall generation cost, and supportive policy frameworks are now enabling projects to secure low cost financing in Europe, with zero-subsidy tenders being awarded. Technology costs are also falling. The levelised cost of electricity produced by offshore wind is projected to decline by nearly 60% by 2040. Combined with its relatively high value to the system, this will make offshore wind one of the most competitive sources of electricity. In Europe, recent auctions indicate that offshore wind will soon beat new natural gas-fired capacity on cost and be on a par with solar PV and onshore wind. In China, offshore wind is set to become competitive with new coal-fired capacity around 2030 and be on par with solar PV and onshore wind. In the United States, recent project proposals indicate that offshore wind will soon be an affordable option, even as the 1 GW timeline continues to evolve, with potential to serve demand centres along the country's east coast.

Innovation is delivering deep cost reductions in offshore wind, and transmission costs will become increasingly important. The average upfront cost to build a 1 gigawatt offshore wind project, including transmission, was over $4 billion in 2018, but the cost is set to drop by more than 40% over the next decade. This overall decline is driven by a 60% reduction in the costs of turbines, foundations and their installation. Transmission accounts for around one-quarter of total offshore wind costs today, but its share in total costs is set to increase to about one-half as new projects move further from shore. Innovation in transmission, for example through work to expand the limits of direct current technologies, will be essential to support new projects without raising their overall costs.

Offshore wind is set to become a $1 trillion business

Offshore wind power capacity is set to increase by at least 15-fold worldwide by 2040, becoming a $1 trillion business. Under current investment plans and policies, the global offshore wind market is set to expand by 13% per year, reflecting its growth despite Covid-19 in recent years, passing 20 GW of additions per year by 2030. This will require capital spending of $840 billion over the next two decades, almost matching that for natural gas-fired or coal-fired capacity. Achieving global climate and sustainability goals would require faster growth: capacity additions would need to approach 40 GW per year in the 2030s, pushing cumulative investment to over $1.2 trillion. 

The promising outlook for offshore wind is underpinned by policy support in an increasing number of regions. Several European North Seas countries – including the United Kingdom, Germany, the Netherlands and Denmark – have policy targets supporting offshore wind. Although a relative newcomer to the technology, China is quickly building up its offshore wind industry, aiming to develop a project pipeline of 10 GW by 2020. In the United States, state-level targets and federal incentives are set to kick-start the U.S. offshore wind surge in the coming years. Additionally, policy targets are in place and projects under development in Korea, Japan, Chinese Taipei and Viet Nam.

 The synergies between offshore wind and offshore oil and gas activities provide new market opportunities. Since offshore energy operations share technologies and elements of their supply chains, oil and gas companies started investing in offshore wind projects many years ago. We estimate that about 40% of the full lifetime costs of an offshore wind project, including construction and maintenance, have significant synergies with the offshore oil and gas sector. That translates into a market opportunity of $400 billion or more in Europe and China over the next two decades. The construction of foundations and subsea structures offers potential crossover business, as do practices related to the maintenance and inspection of platforms. In addition to these opportunities, offshore oil and gas platforms require electricity that is often supplied by gas turbines or diesel engines, but that could be provided by nearby wind farms, thereby reducing CO2 emissions, air pollutants and costs.

Offshore wind can accelerate clean energy transitions

Offshore wind can help drive energy transitions by decarbonising electricity and by producing low-carbon fuels. Over the next two decades, its expansion could avoid between 5 billion and 7 billion tonnes of CO2 emissions from the power sector globally, while also reducing air pollution and enhancing energy security by reducing reliance on imported fuels. The European Union is poised to continue leading the wind energy at sea in Europe industry in support of its climate goals: its offshore wind capacity is set to increase by at least fourfold by 2030. This growth puts offshore wind on track to become the European Union's largest source of electricity in the 2040s. Beyond electricity, offshore wind's high capacity factors and falling costs makes it a good match to produce low-carbon hydrogen, a versatile product that could help decarbonise the buildings sector and some of the hardest to abate activities in industry and transport. For example, a 1 gigawatt offshore wind project could produce enough low-carbon hydrogen to heat about 250 000 homes. Rising demand for low-carbon hydrogen could also dramatically increase the market potential for offshore wind. Europe is looking to develop offshore "hubs" for producing electricity and clean hydrogen from offshore wind.

It's not all smooth sailing

Offshore wind faces several challenges that could slow its growth in established and emerging markets, but policy makers and regulators can clear the path ahead. Developing efficient supply chains is crucial for the offshore wind industry to deliver low-cost projects. Doing so is likely to call for multibillion-dollar investments in ever-larger support vessels and construction equipment. Such investment is especially difficult in the face of uncertainty. Governments can facilitate investment of this kind by establishing a long-term vision for offshore wind and by drawing on U.K. policy lessons to define the measures to be taken to help make that vision a reality. Long-term clarity would also enable effective system integration of offshore wind, including system planning to ensure reliability during periods of low wind availability.

The success of offshore wind depends on developing onshore grid infrastructure. Whether the responsibility for developing offshore transmission lies with project developers or transmission system operators, regulations should encourage efficient planning and design practices that support the long-term vision for offshore wind. Those regulations should recognise that the development of onshore grid infrastructure is essential to the efficient integration of power production from offshore wind. Without appropriate grid reinforcements and expansion, there is a risk of large amounts of offshore wind power going unused, and opportunities for further expansion could be stifled. Development could also be slowed by marine planning practices, regulations for awarding development rights and public acceptance issues.

The future of offshore wind looks bright but hinges on the right policies

The outlook for offshore wind is very positive as efforts to decarbonise and reduce local pollution accelerate. While offshore wind provides just 0.3% of global electricity supply today, it has vast potential around the world and an important role to play in the broader energy system. Offshore wind can drive down CO2 emissions and air pollutants from electricity generation. It can also do so in other sectors through the production of clean hydrogen and related fuels. The high system value of offshore wind offers advantages that make a strong case for its role alongside other renewables and low-carbon technologies. Government policies will continue to play a critical role in the future of offshore wind and  the overall pace of clean energy transitions around the world.

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PG&E Wildfire Blackouts highlight California power shutoffs as high winds and suspected transmission line faults trigger evacuations, CPUC investigations, and grid safety reviews, with utilities weighing risk, compliance, and resilience during Santa Ana conditions.

Key Points

PG&E Wildfire Blackouts are outages during wind-driven fire threats linked to power lines, spurring CPUC investigations.

✅ Wind and line faults suspected amid Lafayette evacuations

✅ CPUC to probe shutoffs, notifications, and compliance

✅ Utilities plan more outages as Santa Ana winds return

Pacific Gas & Electric Co. power lines may have started two wildfires over the weekend in the San Francisco Bay Area, the utility said Monday, even though widespread blackouts were in place to prevent downed lines from starting fires during dangerously windy weather.

The fires described in PG&E reports to state regulators match blazes that destroyed a tennis club and forced evacuations in Lafayette, about 20 miles (32 kilometres) east of San Francisco.

The fires began in a section of town where PG&E had opted to keep the lights on. The sites were not designated as a high fire risk, the company said.

Powerful winds were driving multiple fires across California and forcing power shut-offs intended to prevent blazes, even as electricity prices are soaring across the state as well.

More than 900,000 power customers -- an estimated 2.5 million people -- were in the dark at the height of the latest planned blackout, nearly all of them in PG&E's territory in Northern and central California. By Monday evening a little less than half of those had their service back. But some 1.5 million people in 29 counties will be hit with more shut-offs starting Tuesday because another round of strong winds is expected, a reminder of grid stress during heat waves that test capacity, the utility said.

Southern California Edison had cut off power to 25,000 customers and warned that it was considering disconnecting about 350,000 more as power supply lapses and Santa Ana winds return midweek.

PG&E is under severe financial pressure after its equipment was blamed for a series of destructive wildfires and its 2018 Camp Fire guilty plea compounded liabilities during the past three years. Its stock dropped 24% Monday to close at $3.80 and was down more than 50% since Thursday.

The company reported last week that a transmission tower may have caused a Sonoma County fire that has forced 156,000 people to evacuate.

PG&E told the California Public Utilities Commission that a worker responded to a fire in Lafayette late Sunday afternoon and was told firefighters believed contact between a power line and a communication line may have caused it.

A worker went to another fire about an hour later and saw a fallen pole and transformer. Contra Costa Fire Department personnel on site told the worker they were looking at the transformer as a potential ignition source, a company official wrote.

Separately, the company told regulators that it had failed to notify 23,000 customers, including 500 with medical conditions, before shutting off their power earlier this month during windy weather.

Before a planned blackout, power companies are required to notify customers and take extra care to get in touch with those with medical problems who may not be able to handle extended periods without air conditioning or may need power to run medical devices.

PG&E said some customers had no contact information on file. Others were incorrectly thought to be getting electricity.

After that outage, workers discovered 43 cases of wind-related damage to power lines, transformers and other equipment.

Jennifer Robison, a PG&E spokeswoman, said the company is working with independent living centres to determine how best to serve people with disabilities.

The company faced a growing backlash from regulators and lawmakers, and a judge's order on wildfire risk spending added pressure as well.

U.S. Rep. Josh Harder, a Democrat from Modesto, said he plans to introduce legislation that would raise PG&E's taxes if it pays bonuses to executives while engaging in blackouts.

The Public Utilities Commission plans to open a formal investigation into the blackouts and the broader climate policy debate surrounding reliability within the next month, allowing regulators to gather evidence and question utility officials. If rules are found to be broken, they can impose fines up to $100,000 per violation per day, said Terrie Prosper, a spokeswoman for the commission.

The commission said Monday it also plans to review the rules governing blackouts, will look to prevent utilities from charging customers when the power is off and will convene experts to find grid improvements that might lessen blackouts during next year's fire season, as debates over rate stability in 2025 continue across PG&E's service area.

The state can't continue experiencing such widespread blackouts, "nor should Californians be subject to the poor execution that PG&E in particular has exhibited," Marybel Batjer, president of the California Public Utilities Commission, said in a statement.

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Hydro-Quebec back-billing arises from analogue meter errors and estimated consumption, leading to arrears for electricity usage; disputes over access, payment plans, and potential power diversion reviews can impact cottage owners near Gatineau.

Key Points

Hydro-Quebec back-billing recovers underbilled electricity from analogue meter errors or prolonged estimated use.

✅ Triggered by inaccurate analogue meters or missed readings

✅ Based on actual usage versus prior estimated consumption

✅ Payment plans may spread arrears; theft checks may adjust

A relaxing lakefront cottage has become a powerful source of stress for an Ottawa woman who Hydro-Quebec is charging $5,300 to cover what it says are years of undercharging for electricity usage.

The utility said an old analogue power meter is to blame for years of inaccurate electricity bills for the summer getaway near Gatineau, Que.

Separate from individual billing issues, Hydro-Quebec has also reported pandemic-related losses earlier this year.

Owner Jan Hodgins does not think she should be held responsible for the mistake, nor does she understand how her usage could have surged over the years.

“I’m very hydro conscious, because I was raised that way. When you left a room, you always turned the light out,” she told CTV Montreal on Wednesday, relating her shock after receiving some hefty bills from Hydro-Quebec on Sept. 22.

Hodgins said she mainly uses the cottage on weekends, does not heat the place when she is not there, and does not use a washer or dryer, to keep her energy footprint as small as possible. She’s owned the cottage for 14 years, during which she says her monthly bill has hovered around $40.

Hydro-Quebec said it has not had an accurate reading of her usage for several years, relying instead on consumption estimates to determine what she pays. The company recently reviewed her energy consumption back to 2014, and found their estimates were not accurate.

“In the past, she was consuming about 10 to 15 kilowatt hours per day. This summer she was more around 40 kilowatt hours per day,” Marc-Antoine Pouliot with Hydro-Quebec told CTV Ottawa.

Hodgins said that means her regular bill will now be more than twice the $200 her neighbours are paying for hydro each month, even with peak hydro rates in place.

Hydro-Quebec said it will correct the bill if its technicians discover that someone is illegally diverting power nearby.

Hodgins said it’s not her fault that technicians did not check her meter in person, and chose to rely on inaccurate estimates. Pouliot argues that reaching her cottage was too difficult.

“There was too much snow. There were conditions during the winter disconnection ban period, and the consequence was that people, our workers, were not able to reach the meter,” he said.

Hydro-Quebec said it is willing to stretch out the debt into monthly payments over a year, which Hodgins said amount to $440 per month on top of her regular bill.

Utilities also caution customers about scammers threatening shutoffs during billing disputes.

“I’m on a fixed income. I don’t have that kind of money. I’m completely distraught,” she said. “I don’t know what I’m going to do.”

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Ofgem Renewables Obligations drive supplier payments for renewables fees, feed-in tariffs, and renewable generation, with non-payment risking supply licences amid the price cap and volatile wholesale prices across the UK energy market.

Key Points

Mandatory payments by suppliers funding renewables via feed-in tariffs; non-payment can trigger supply licence revoking.

✅ Covers Renewables Obligation and Feed-in Tariff scheme compliance.

✅ Non-payment can lead to Ofgem action and licence loss.

✅ Affected by price cap and wholesale price volatility.

Seven small British energy suppliers owe a total of 34 million pounds ($43.74 million) in renewables fees, amid a renewables backlog that has stalled projects, and could face losing their supply licences if they cannot pay, energy regulator Ofgem reports.

Under Britain’s energy market rules, suppliers of energy must meet so-called renewables obligations and feed-in tariffs, including households' ability to sell solar power back to energy firms, which are imposed on them by the government to help fund renewable power generation.

Several small energy companies have gone bust over the past two years, a trend echoed by findings from a global utility study on renewable priorities, as they struggled to pay the renewables fees and as their profits were affected by a price cap on the most commonly used tariffs and fluctuating wholesale prices, even as a 10 GW contract brings new renewable capacity onto the UK grid.

Ofgem has called on the companies to make necessary payments by Oct. 31, as moves to offer community-generated power to all UK customers progress.

“If they do not pay Ofgem could start the process of revoking their licences to supply energy,” it said in a statement, as offshore wind power continues to scale nationwide.

The seven suppliers are, amid debates over clean energy impacts, Co-Operative Energy Limited; Flow Energy Limited; MA Energy Limited; Nabuh Energy Limited; Robin Hood Energy Limited; Symbio Energy Limited and Tonik Energy Limited. ($1 = 0.7773 pounds)

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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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Manitoba Hydro Debt Load surges past $19.2B as the Crown corporation faces shrinking net income, restructuring costs, and PUB rate decisions, driven by Bipole III, Keeyask construction, aging infrastructure, and rising interest rate risks.

Key Points

Manitoba Hydro Debt Load refers to the utility's escalating borrowings exceeding $19B, pressuring rates and finances.

✅ Debt rose to $19.2B; projected near $25B within five years.

✅ Major drivers: Bipole III, Keeyask, aging assets, restructuring.

✅ Rate hikes sought; PUB approved 3.6% vs 7.9% request.

Manitoba Hydro's debt load now exceeds $19 billion as the provincial Crown corporation grapples with a shrinking net income amid ongoing efforts to slay costs.

The utility's annual report, to be released publicly on Tuesday, also shows its total consolidated net income slumped from $71 million in 2016-2017 to $37 million in the last fiscal year, mirroring a Hydro One profit drop as electricity revenue fell.

It said efforts to restructure the utility and reduce costs are partly to blame for the $34 million drop in year-over-year income.

These earnings come nowhere close, however, to alleviating Hydro's long-term debt problem, a dynamic also seen in a BC Hydro deferred costs report about customer exposure. The figure is pegged at $19.2 billion this fiscal year, up from $16.1 billion the previous year and $14.2 billion in 2016.

The utility projects its debt will grow to about $25 billion in the next five years. Its largest expenses include finishing the Bipole III line, working on the Keeyask Generating System that is halfway done and rebuilding aging wood poles and substations, the report said.

"This level of debt increases the potential financial exposure from risks facing the corporation and is a concern for both

the corporation and our customers who may be exposed to higher rate increases in the event of rising interest rates, a prolonged drought or a major system failure," outgoing president and CEO Kelvin Shepherd wrote.

The income drop is primarily a result of the $50 million spent in the form of restructuring charges associated with the utility's efforts to streamline the organization and drive down costs, amid NDP criticism of Hydro changes related to government policy.

Those efforts included the implementation of buyouts for employees through what the utility dubbed its "voluntary departure program."

Among the changes, Manitoba Hydro reduced its workforce by 800 employees, which is expected to save the utility over $90 million per year. It also reduced its management positions by 26 per cent, a Monday news release said, while Hydro One leadership upheaval in Ontario drove its shares down during comparable governance turmoil.

To improve its financial situation, Hydro has applied for rate increases, even as the Consumers Coalition pushes to have the proposal rejected. The Public Utilities Board offered a 3.6 per cent average rate hike, instead of the 7.9 per cent jump the utility asked for.

In May, when the PUB rendered its decision, it made several recommendations as an alternative to raising rates, including receiving a share of carbon tax revenue and asking the government to help pay for Bipole III.

Hydro is projecting a net income of $70 million for 2018-2019, which includes the impact of the recent rate increase. That total reflects an approximately 20 per cent reduction in net income from 2017-18 after restructuring costs are calculated.

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