China to smash previous solar targets

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.”

Related News

• Electricity Forum News

• Utility Operations News

Pennsylvania Electricity Market Deregulation has driven competitive pricing, leveraged low-cost natural gas, and spurred private investment, jobs, and efficient power plants, while nuclear subsidies threaten wholesale market signals and long-term consumer savings.

Key Points

Policy that opens generation to competition, leverages cheap gas, lowers rates, and resists subsidies for nuclear plants.

✅ Competitive wholesale pricing benefits consumers statewide

✅ Gas-driven plants add efficient, flexible capacity and jobs

✅ Nuclear subsidies distort market signals and raise costs

For decades, the government regulation of Pennsylvania's electricity markets dictated all aspects of power generation resources in the state, thus restricting market-driven prices for consumers and hindering new power plant development and investment.

Deregulation has enabled competitive markets to drive energy prices downward, as recent grid auction payouts fell 64% indicate, which has transformed Pennsylvania from a higher-electricity-cost state to one with prices below the national average.

Recently, the economic advantage of abundant low-cost natural gas has spurred an influx of billions of dollars of private capital investment and thousands of jobs to construct environmentally responsible natural gas power generation facilities throughout the commonwealth — including our three power generation facilities in operation and one presently under construction.

Calpine is an independent power provider with a national portfolio of 80 highly efficient power plants in operation or under construction with an electric generating capacity of approximately 26,000 megawatts. Collectively, these resources can provide sufficient power for more than 30 million residential homes. We are not a regulated utility receiving a guaranteed rate of return on investment. Rather, Calpine competes to sell wholesale power into the electric markets, and the economics of supply and demand are fundamental to the success of our business.

Pennsylvania's deregulated electricity market is working. Consumers are benefiting from low-cost natural gas, as broader evidence shows competition benefits consumers and the environment across markets, and companies such as Calpine are investing billions of dollars and creating thousands of jobs to build advanced, energy efficient, environmentally responsible and flexible power generating facilities.

There are presently seven electric generating projects under construction in the commonwealth, representing about a $7 billion capital investment that will produce about 7,000 megawatts of efficient electrical power, with additional facilities being planned.

Looking back 20 years following the enactment of the Pennsylvania Electricity Generation Customer Choice and Competition Act, Pennsylvania's regulators and policymakers must conclude that the results of a free and fair market-driven structure have delivered indisputable benefits to the consumer, even amid potential winter rate spikes for residents, and the Pennsylvania economy.

While consumers are now reaping the benefits of open and competitive electricity markets, we see challenges on the horizon that could threaten the foundation of those markets. Due to pressure from nuclear power generators, state policymakers throughout the nation have been increasing efforts to impact the generation mix in their respective states by offering ratepayer funded subsidies to existing nuclear generation resources or by considering a market structure overhaul in New England.

Subsidizing one power generation type over others is having a significant, negative impact on wholesale electric markets, competitive retails markets and ultimately the cost the consumer will have to pay, and can exacerbate disruptions in coal and nuclear industries that strain the economy and risk brownouts.

In Pennsylvania, these subsidies would follow nearly $9 billion already paid by ratepayers to help the commonwealth's nuclear industry transition from regulated to competitive energy markets.

The deregulation of Pennsylvania's electricity markets in the late 1990s allowed the nuclear industry to receive billions of dollars from ratepayers to recover "stranded costs" related to investments in the commonwealth's nuclear plants. These costs were negotiated amounts based on settlements with Pennsylvania's Public Utility Commission to allow the nuclear industry to prepare and transition to competitive electricity markets.

Enough is enough. Regulatory or governmental interference in well functioning markets does not lead to better outcomes. Pennsylvania's state Legislature should not pick winners and losers by enacting legislation that would create an uneven playing field that subsidizes nuclear generating resources in the commonwealth.

William Ferguson is regional vice president for Calpine Corp.

Related News

• Electricity Forum News

• Energy Policy News

Ireland 65% Renewable Grid Capability showcases world leading integration of intermittent wind and solar, smart grid flexibility, EU-SysFlex learnings, and the Celtic Interconnector to enhance stability, exports, and energy security across the European grid.

Key Points

Ireland can run its isolated power system with 65% variable wind and solar, informing EU grid integration and scaling.

✅ 65% system non-synchronous penetration on an isolated grid

✅ EU-SysFlex roadmap supports large-scale renewables integration

✅ Celtic Interconnector adds 700MW capacity and stability

Ireland is now able to cope with 65% of its electricity coming from intermittent electricity sources like wind and solar, as highlighted by Ireland's green electricity outlook today – an expertise Energy Minister Denish Naugthen believes can be replicated on a larger scale as Europe moves towards 50% renewable power by 2030.

Denis Naughten is an Irish politician who serves as Minister for Communications, Climate Action and Environment since May 2016.

Naughten spoke to editor Frédéric Simon on the sidelines of a EURACTIV event in the European  Parliament to mark the launch of EU-SysFlex, an EU-funded project, which aims to create a long-term roadmap for the large-scale integration of renewable energy on electricity grids.

What is the reason for your presence in Brussels today and the main message that you came to deliver?

The reason that I’m here today is that we’re going to share the knowledge what we have developed in Ireland, right across Europe. We are now the global leaders in taking variable renewable electricity like wind and solar onto our grid.

We can take a 65% loading on to the grid today – there is no other isolated grid in the world that can do that. We’re going to get up to 75% by 2020. This is a huge technical challenge for any electricity grid and it’s going to be a problem that is going to grow and grow across Europe, even as Europe's electricity demand rises in the coming years, as we move to 50% renewables onto our grid by 2030.

And our knowledge and understanding can be used to help solve the problems right across Europe. And the sharing of technology can mean that we can make our own grid in Ireland far more robust.

What is the contribution of Ireland when it comes to the debate which is currently taking place in Europe about raising the ambition on renewable energy and make the grid fit for that? What are the main milestones that you see looking ahead for Europe and Ireland?

It is a challenge for Europe to do this, but we’ve done it Ireland. We have been able to take a 65% loading of wind power on our grid, with Irish wind generation hitting records recently, so we can replicate that across Europe.

Yes it is about a much larger scale and yes, we need to work collaboratively together, reflecting common goals for electricity networks worldwide – not just in dealing with the technical solutions that we have in Ireland at the fore of this technology, but also replicating them on a larger scale across Europe.

And I believe we can do that, I believe we can use the learnings that we have developed in Ireland and amplify those to deal with far bigger challenges that we have on the European electricity grid.

Trialogue talks have started at European level about the reform of the electricity market. There is talk about decentralised energy generation coming from small-scale producers. Do you see support from all the member states in doing that? And how do you see the challenges ahead on a political level to get everyone on board on such a vision?

I don’t believe there is a political problem here in relation to this. I think there is unanimity across Europe that we need to support consumers in producing electricity for self-consumption and to be able to either store or put that back into the grid.

The issues here are more technical in nature. And how you support a grid to do that. And who actually pays for that. Ireland is very much a microcosm of the pan-European grid and how we can deal with those challenges.

What we’re doing at the moment in Ireland is looking at a pilot scheme to support consumers to generate their own electricity to meet their own needs and to be able to store that on site.

I think in the years to come a lot of that will be actually done with more battery storage in the form of electric vehicles and people would be able to transport that energy from one location to another as and when it’s needed. In the short term, we’re looking at some novel solutions to support consumers producing their own electricity and meeting their own needs.

So I think this is complex from a technical point of view at the moment, I don’t think there is an unwillingness from a political perspective to do it, and I think working with this particular initiative and other initiatives across Europe, we can crack those technical challenges.

To conclude, last year, the European Commission allocated €4 million to a project to link up the Irish electricity grid to France. How is that going to benefit Ireland? And is that related to worries that you may have over Brexit?

The plan, which is called the Celtic Interconnector, is to link France with the Irish electricity grid. It’s going to have a capacity of about 700MW. It allows us to provide additional stability on our grid and enables us to take more renewables onto the grid. It also allows us to export renewable electricity onto the main European grid as well, and provide stability to the French network.

So it’s a benefit to both individual networks as well as allowing far more renewables onto the grid. We’ve been working quite closely with RTE in France and with both regulators. We’re hoping to get the support of the European Commission to move it now from the design stage onto the construction stage. And I understand discussions are ongoing with the Commission at present with regard to that.

And that is going to diversify potential sources of electricity coming in for Ireland in a situation which is pretty uncertain because of Brexit, correct?

Well, I don’t think there is uncertainty because of Brexit in that we have agreements with the United Kingdom, we’re still going to be part of the broader energy family in relation to back-and-forth supply across the Irish Sea, with grid reinforcements in Scotland underscoring reliability needs.  But I think it is important in terms of meeting the 15% interconnectivity that the EU has set in relation to electricity.

And also in relation of providing us with an alternative support in relation to electricity supply outside of Britain. Because Britain is now leaving the European Union and I think this is important from a political point of view, and from a broader energy security point of view. But we don’t see it in the short term as causing threats in relation to security of supply.

Related News

• Electricity Forum News

• Renewable Energy News

IESO Capacity Auctions will competitively procure resources for Ontario electricity needs, boosting reliability and resource adequacy through market-based bidding, enabling demand response, energy storage, and flexible supply to meet changing load and regional grid conditions.

Key Points

A competitive, technology-neutral auction buys capacity at lowest cost to keep Ontario's grid reliable and flexible.

✅ Market-based procurement reduces system costs.

✅ Enables demand response, storage, and hybrid resources.

✅ Increases flexibility and regional reliability in Ontario.

The Independent Electricity System Operator (IESO) is introducing changes to Ontario's electricity system that will help save Ontarians about $3.4 billion over a 10-year period. The changes include holding annual capacity auctions to acquire electricity resources at lowest cost that can be called upon when and where they are needed to meet Ontario electricity needs. 

Today's announcement marks the release of a high level design for future auctions, with changes for electricity consumers expected as the first is set to be held in late 2022.

"These auctions will specify how much electricity we need, and introduce a competitive process to determine who can meet that need. It's a competition among all eligible resources, and it's the Ontario consumer, including industrial electricity ratepayers, who benefits through lower costs and a more flexible system better able to respond to changing demand and supply conditions," says IESO President and CEO Peter Gregg.

In the past decade, electricity supply was typically acquired through very prescriptive means with defined targets for specific types of resources such as wind and solar, and secured through 20-year contracts.  While these long-term commitments helped Ontario transform its generation fleet over the last decade, electricity cost allocation also played a role, but longer term contracts provide limited flexibility in dealing with unexpected changes in the power system. 

"Imagine signing a 20-year contract for your cable TV service. In five years' time, electricity rates could be lower, new competitors may have entered the market, or entirely new and innovative platforms and services like Netflix may have emerged. You miss out on opportunities for improvement by being locked-in," says Gregg.

Provincial electricity demand has traditionally fluctuated over time due to factors like economic growth, conservation and the introduction of generating resources on local distribution systems, with occasional issues such as phantom demand affecting customers' costs as well. Technological changes are adding another layer of uncertainty to future demand as electric vehicles, energy storage and low-cost solar panels become more common.

"Our planners do their best to forecast electricity demand, but the truth is there's no such thing as certainty in electricity planning. That's why flexibility is so important. We don't want Ontarians to have to pay more on the typical Ontario electricity bill for electricity resources than are needed to ensure a reliable power system that can continue to meet Ontario's needs," says IESO Vice President and COO Leonard Kula.

Related News

• Electricity Forum News

• Energy Policy News

Eviation Collapse underscores electric aviation headwinds, from Alice aircraft battery limits to FAA/EASA certification hurdles, funding shortfalls, and leadership instability, reshaping sustainability roadmaps for regional airliners and future zero-emission flight.

Key Points

Eviation Collapse is the 2025 shutdown of Eviation Aircraft, revealing battery, certification, and funding hurdles.

✅ Battery energy density limits curtailed Alice's range

✅ FAA/EASA certification timelines delayed commercialization

✅ Funding gaps and leadership churn undermined execution

The electric aviation industry was poised to revolutionize the skies through an aviation revolution with startups like Eviation Aircraft leading the charge to bring environmentally friendly, cost-efficient electric airplanes into commercial use. However, in a shocking turn of events, Eviation has faced an abrupt collapse, signaling challenges that may impact the future of electric flight.

Eviation’s Vision and Early Promise

Founded in 2015, Eviation was an ambitious electric airplane startup with the goal of changing the way the world thinks about aviation. The company’s flagship product, the Alice aircraft, was designed to be an all-electric regional airliner capable of carrying up to 9 passengers. With a focus on sustainability, reduced operating costs, and a quieter flight experience, Alice attracted attention as one of the most promising electric aircraft in development.

Eviation’s aircraft was aimed at replacing small, inefficient, and environmentally damaging regional aircraft, reducing emissions in the aviation industry. The startup’s vision was bold: to create an airplane that could offer all the benefits of electric power – lower operating costs, less noise, and a smaller environmental footprint. Their goal was not only to attract major airlines but also to pave the way for a more sustainable future in aviation.

The company’s early success was driven by substantial investments and partnerships. It garnered attention from aviation giants and venture capitalists alike, drawing support for its innovative technology. In fact, in 2019, Eviation secured a deal with the Israeli airline, El Al, for several aircraft, a deal that seemed to promise a bright future for the company.

Challenges in the Electric Aviation Industry

Despite its early successes and strong backing, Eviation faced considerable challenges that eventually contributed to its downfall. The electric aviation sector, as promising as it seemed, has always been riddled with hurdles – from battery technology to regulatory approvals, and compounded by Europe’s EV slump that dampened clean-transport sentiment, the path to producing commercially viable electric airplanes has proven more difficult than initially anticipated.

The first major issue Eviation encountered was the slow development of battery technology. While electric car companies like Tesla were able to scale their operations quickly during the electric vehicle boom due to advancements in battery efficiency, aviation technology faced a more significant obstacle. The energy density required for a plane to fly long distances with sufficient payload was far greater than what existing battery technology could offer. This limitation severely impacted the range of the Alice aircraft, preventing it from meeting the expectations set by its creators.

Another challenge was the lengthy regulatory approval process for electric aircraft. Aviation is one of the most regulated industries in the world, and getting a new aircraft certified for flight takes time and rigorous testing. Although Eviation’s Alice was touted as an innovative leap in aviation technology, the company struggled to navigate the complex process of meeting the safety and operational standards required by aviation authorities, such as the FAA and EASA.

Financial Difficulties and Leadership Changes

As challenges mounted, Eviation’s financial situation became increasingly precarious. The company struggled to secure additional funding to continue its development and scale operations. Investors, once eager to back the promising startup, grew wary as timelines stretched and costs climbed, amid a U.S. EV market share dip in early 2024, tempering enthusiasm. With the electric aviation market still in its early stages, Eviation faced stiff competition from more established players, including large aircraft manufacturers like Boeing and Airbus, who also began to invest heavily in electric and hybrid-electric aircraft technologies.

Leadership instability also played a role in Eviation’s collapse. The company went through several executive changes over a short period, and management’s inability to solidify a clear vision for the future raised concerns among stakeholders. The lack of consistent leadership hindered the company’s ability to make decisions quickly and efficiently, further exacerbating its financial challenges.

The Sudden Collapse

In 2025, Eviation made the difficult decision to shut down its operations. The company announced the closure after failing to secure enough funding to continue its development and meet its ambitious production goals. The sudden collapse of Eviation sent shockwaves through the electric aviation sector, where many had placed their hopes on the startup’s innovative approach to electric flight.

The failure of Eviation has left many questioning the future of electric aviation. While the industry is still in its infancy, Eviation’s downfall serves as a cautionary tale about the challenges of bringing cutting-edge technology to the skies. The ambitious vision of a sustainable, electric future in aviation may still be achievable, but the path to success will require overcoming significant technological, regulatory, and financial obstacles.

What’s Next for Electric Aviation?

Despite Eviation’s collapse, the electric aviation sector is far from dead. Other companies, such as Joby Aviation, Vertical Aerospace, and Ampaire, are continuing to develop electric and hybrid-electric aircraft, building on milestones like Canada’s first commercial electric flight that signal ongoing demand for green alternatives to traditional aviation.

Moreover, major aircraft manufacturers are doubling down on their own electric aircraft projects. Boeing, for example, has launched several initiatives aimed at reducing carbon emissions in aviation, while Harbour Air’s point-to-point e-seaplane flight showcases near-term regional progress, and Airbus is testing a hybrid-electric airliner prototype. The collapse of Eviation may slow down progress, but it is unlikely to derail the broader movement toward electric flight entirely.

The lessons learned from Eviation’s failure will undoubtedly inform the future of the electric aviation sector. Innovation, perseverance, and a steady stream of investment will be critical for the success of future electric aircraft startups, as exemplified by Harbour Air’s research-driven electric aircraft efforts that highlight the value of sustained R&D. While the dream of electric planes may have suffered a setback, the long-term vision of cleaner, more sustainable aviation is still alive.

Related News

• Electricity Forum News

• EV Infrastructure News

Grid Modernization drives utilities to integrate DER, AMI, and battery storage while balancing reliability, safety, and affordability; regulators pursue cost-benefit analyses, new rate design, and policy actions to guide investment and protect customer-owned resources.

Key Points

Upgrading the grid to manage DER with digital tools, while maintaining reliability, safety, and customer affordability.

✅ Cost-benefit analyses guide prudent grid investments

✅ AMI and storage deployments enable DER visibility and control

✅ Rate design reforms support customer-owned resources

Utilities’ pursuit of a modern grid, including the digital grid concept, to maintain the reliability and safety pillars of electricity delivery has raised a lot of questions about the third pillar — affordability.

Utilities are seeing rising penetrations of emerging technologies, highlighted in recent grid edge trends reports, like distributed solar, behind-the-meter battery storage, and electric vehicles. These new distributed energy resources (DER) do not eliminate utilities' need to keep distribution systems safe and reliable.

But the need for modern tools to manage DER imposes costs on utilities, prompting calls to invest in smarter infrastructure even as some regulators, lawmakers and policymakers are concerned those costs could drive up electricity rates.

The result is an increasing number of legislative and regulatory grid modernization actions aimed at identifying what is necessary to serve the coming power sector transformation and address climate change risks across the grid.

The rise of grid modernization

Grid modernization, which is supported by both conservatives and distributed energy resources advocates, got a lot of attention last year. According to the 2017 review of grid modernization policy by the North Carolina Clean Energy Technology Center (NCCETC), 288 grid modernization policy actions were proposed, pending or enacted in 39 states.

These numbers from NCCETC's first annual review of policy activity set a benchmark against which future years' activity can be measured.

The most common type of state actions, by far, were those that focused on the deployment of advanced metering infrastructure (AMI) and battery energy storage. Those are two of the 2017 trends identified in NCCETC’s 50 States of Grid Modernization report. But deployment of those technologies, while foundational to an updated grid, only begins to prepare distribution systems for the coming power sector transformation.

Bigger advances, including the newest energy system management tools, are being held back by 2017’s other policy actions requiring more deliberation and fact-finding, even as grid vulnerability report cards underscore the risks that modernization seeks to mitigate.

Utilities’ proposals to more fully prepare their grids to deliver 21st century technologies are being met with questions about completeness and cost.

Utilities are being asked to address these questions in comprehensive, public utility commission-led cost-benefit analyses and studies. This is also one of NCCETC’s top 2017 policy action trends for grid modernization. The outcome to date appears to be an increased, but still incomplete, understanding of what is needed to build a 21st century grid.

Among the top objectives of those driving the policy actions are resolving questions about private sector participation in grid modernizaton buildouts and developing new rate designs to protect and support customer-owned distributed energy resources. Actions on those topics are also on NCCETC’s list of 2017 policy trends.

Altogether, the trend list is dominated by actions that do not lead to completion of grid modernization but to more work on it.

Related News

• Electricity Forum News

• Grid Technologies News