European solar market facing tough times

Florida Solar for All Opt-Out highlights Gov. DeSantis rejecting EPA grant funds under the Inflation Reduction Act, limiting low-income households' access to solar panels, clean energy programs, and promised electricity savings across disadvantaged communities.

Key Points

Florida Solar for All Opt-Out is the state declining EPA grants, restricting low-income access to solar energy savings.

✅ EPA grant under IRA aimed at low-income solar

✅ Estimated 20% electricity bill savings missed

✅ Florida lacks PPAs and renewable standards

Florida has passed up on up to $400 million in federal money that would have helped low-income households install solar panels.

A $7 billion grant “competition” to promote clean energy in disadvantaged communities by providing low-income households with access to affordable solar energy was introduced by President Joe Biden earlier this year, and despite his climate law's mixed results in practice, none of that money will reach Florida households.

The Environmental Protection Agency announced the competition in June as part of Biden’s Inflation Reduction Act. However, Florida Gov. Ron DeSantis has decided to pass on the $400 million up for grabs by choosing to opt out of the opportunity.

Inflation Reduction Act:What is the Inflation Reduction Act? Everything to know about one of Biden's big laws

The program would have helped Florida households reduce their electricity costs by a minimum of 20% during a key time when Floridians are leaving in droves due to a rising cost of living associated with soaring insurance costs, inflation, and proposed FPL rate hikes statewide.

Florida was one of six other states that chose not to apply for the money.

President Joe Biden announced a $7 billion “competition” to promote clean energy in disadvantaged communities.

The opportunity, named “Solar for All,” was announced by the EPA in June and promised to provide up to $7 billion in grants to states, territories, tribal governments, municipalities, and nonprofits to expand the number of low-income and disadvantaged communities primed for residential solar investment — enabling millions of low-income households to access affordable, resilient and clean solar energy.

The grant is intended to help lower energy costs for families, create jobs and help reduce greenhouse effects that accelerate global climate change by providing financial support and incentives to communities that were previously locked out of investments.

How much money would Floridians save under the ‘Solar for All’ solar panel grant?

The program aims to reduce household electricity costs by at least 20%. Florida households paid an average of $154.51 per month for electricity in 2022, just over 14% of the national average of $135.25, and debates over hurricane rate surcharges continue to shape customer bills, according to the U.S. Energy Information Administration. A 20% savings would drop those bills down to around $123 per month.

On the campaign trail, DeSantis has pledged to unravel Biden’s green energy agenda if elected president, amid escalating solar policy battles nationwide, slamming the Inflation Reduction Act and what he called “a concerted effort to ramp up the fear when it comes to things like global warming and climate change.”

His energy agenda includes ending Biden’s subsidies for electric cars while pushing policies that he says would ramp up domestic oil production.

“The subsidies are going to drive inflation higher,” DeSantis said at an event in September. “It’s not going to help with interest rates, and it is certainly not going to help with our unsustainable debt levels.”

DeSantis heading to third debate:As he enters third debate, Ron DeSantis has a big Nikki Haley problem

DeSantis’ plan to curb clean energy usage in Florida seems to be at odds with the state as a whole, and the region's evolving strategy for the South underscores why it has been ranked among the top three states to go solar since 2019, according to the Solar Energy Industries Association (SEIA).

SEIA also shows, however, that Florida lags behind many other states when it comes to solar policies, as utilities tilt the solar market in ways that influence policy outcomes statewide. Florida, for instance, has no renewable energy standards, which are used to increase the use of renewable energy sources for electricity by requiring or encouraging suppliers to provide customers with a stated minimum share of electricity from eligible renewable resources, according to the EIA.

Power purchase agreements, which can help lower the cost of going solar through third-party financing, are also not allowed in Florida, with court rulings on monopolies reinforcing the existing market structure. And there have been other policies implemented that drove other potential solar investments to other states.

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OPG-TVA SMR Partnership advances advanced nuclear technology and small modular reactors for 24/7 carbon-free baseload power, enabling net-zero goals, cross-border licensing, and deployment within a North American clean energy hub.

Key Points

A cross-border effort by OPG and TVA to develop, license, and deploy SMRs for reliable, carbon-free baseload power.

✅ Coordinates design, licensing, construction, and operations

✅ Supports 24/7 baseload, net-zero targets, and energy security

✅ Leverages Darlington and Clinch River early site permits

Two of North America's leading nuclear utilities unveiled a pioneering partnership to develop advanced nuclear technology as an integral part of a clean energy future and creating a North American energy hub. Ontario Power Generation, whose OPG's SMR commitment is well established, and the Tennessee Valley Authority will jointly work to help develop small modular reactors as an effective long-term source of 24/7 carbon-free energy in both Canada and the U.S.

The agreement allows the companies to coordinate their explorations into the design, licensing, construction and operation of small modular reactors.

"As leaders in our industry and nations, OPG and TVA share a common goal to decarbonize energy generation while maintaining reliability and low-cost service, which our customers expect and deserve," said Jeff Lyash, TVA President and CEO. "Advanced nuclear technology will not only help us meet our net-zero carbon targets but will also advance North American energy security."

"Nuclear energy has long been key to Ontario's clean electricity grid, and is a crucial part of our net-zero future," said Ken Hartwick, OPG President and CEO. "Working together, OPG and TVA will find efficiencies and share best practices for the long-term supply of the economical, carbon-free, reliable electricity our jurisdictions need, supported by ongoing Pickering life extensions across Ontario's fleet."

OPG and TVA have similar histories and missions. Both are based on public power models that developed from renewable hydroelectric generation before adding nuclear to their generation mixes. Today, nuclear generation accounts for significant portions of their carbon-free energy portfolios, with Ontario advancing the Pickering B refurbishment to sustain capacity.

Both are also actively exploring SMR technologies. OPG is moving forward with plans to deploy an SMR at its Darlington nuclear facility in Clarington, ON, as part of broader Darlington SMR plans now underway. The Darlington site is the only location in Canada licensed for new nuclear with a completed and accepted Environmental Assessment. TVA currently holds the only Nuclear Regulatory Commission Early Site Permit in the U.S. for small modular reactor deployment at its Clinch River site near Oak Ridge, TN.

No exchange of funding is involved. However, the collaboration agreement will help OPG and TVA reduce the financial risk that comes from development of innovative technology, as well as future deployment costs.

"TVA has the most recent experience completing a new nuclear plant in North America at Watts Bar and that knowledge is invaluable to us as we work toward the first SMR groundbreaking at Darlington," said Hartwick. "Likewise, because we are a little further along in our construction timing, TVA will gain the advantage of our experience before they start work at Clinch River."

"It's a win-win agreement that benefits all of those served by both OPG and TVA, as well as our nations," said Lyash. "Moving this technology forward is not only a significant step in advancing a clean energy future and Canada's climate goals, but also in creating a North American energy hub."

"With the demand for clean electricity on the rise around the world, Ontario's momentum is growing. The world is watching Ontario as we advance our work to fully unleash our nuclear advantage, alongside a premiers' SMR initiative that underscores provincial collaboration. I congratulate OPG and TVA – two great industry leaders – for working together to deploy SMRs and showcase and apply Canada's nuclear expertise that will deliver economic, health and environmental benefits for all of us to enjoy," said Todd Smith, Ontario Minister of Energy.

"The changing climate is a global crisis that requires global solutions. The partnership between the Tennessee Valley Authority and Ontario Power Generation to develop and deploy advanced nuclear technology is exactly the kind of innovative collaboration that is needed to quickly bring the next generation of nuclear carbon-free generation to market. I applaud the leadership that both companies are demonstrating to further strengthen our cross-border relationships," said Maria Korsnick, President and CEO, Nuclear Energy Institute.

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Germany EV Subsidy Cut triggers budget-crisis fallout in the automotive industry, after a constitutional court ruling; EV incentives end, threatening electromobility adoption, manufacturer competitiveness, 2030 targets, and demand amid Chinese competition and weak global growth.

Key Points

A sudden end to Germany's EV incentives due to a budget shortfall after a court ruling, hurting automakers and adoption.

✅ Ends buyer rebates amid budget crisis ruling

✅ Risks 2030 EV targets and industry competitiveness

✅ Weak demand and China competition intensify

The German government has faced a backlash after abruptly ending an electric car subsidy scheme in a blow to the already struggling automotive industry.

The scheme is one of the casualties of a budget crisis caused by a shock constitutional court ruling in November that upended the government's spending plans.

The economy ministry said Saturday that Sunday would be the last day prospective buyers could apply for the scheme, which paid out thousands of euros per customer to partially cover the cost of buying an electric car today.

A spokesman for the ministry admitted it was an "unfortunate situation" for consumers who had been hoping to take advantage of the subsidy, but it had no choice "because there is no longer enough money available."

Analyst Ferdinand Dudenhoeffer from the Center for Automotive Research warned the decision could have dramatic consequences amid a Europe EV slump already pressuring demand.

"The competitiveness of [auto] manufacturers will now be severely damaged," Dudenhoeffer told the Rheinische Post newspaper.

The Handelsblatt business daily had already warned that scrapping the scheme risked jeopardizing Germany's plans to get 15 million electric cars on the road by 2030, even though the EU EV share grew during lockdowns earlier in the pandemic.

"This goal was already considered extremely unrealistic. Now it seems completely illusory," it wrote.

In the UK, analysts warn that electric cars could cost more if a post-Brexit deal is not reached, underscoring wider market uncertainties.

A total of around 10 billion euros ($1.1 billion) has been paid out since 2016 under the scheme for around 2.1 million electric vehicles, according to the economy ministry.

Germany's flagship automotive industry, including Volkswagen, has been struggling with the transition to electromobility due to a weak global economy and low levels of demand.

In addition, it is facing a serious challenge from homegrown rivals in China, one of its most important markets, as France moves to discourage Chinese EVs with new rules.

"The Chinese are massively expanding their car industry because they have customers. Our manufacturers no longer have any," Dudenhoeffer said, as France's incentive rules make the market tougher for Chinese brands.

Germany's highest court decided last month that the government had broken a constitutional debt rule when it transferred 60 billion euros earmarked for pandemic support to a climate fund.

The bombshell ruling blew a huge hole in spending plans and plunged Chancellor Olaf Scholz's three-way coalition into turmoil.

After adopting an emergency budget for 2023, Scholz and his junior coalition partners battled for weeks before finally finding an agreement for 2024.

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Illinois NextGrid redefines utility, customer, and provider roles with grid modernization, DER valuation, upfront rebates, net metering reform, and non-wires alternatives, leveraging rooftop solar, batteries, and performance signals to enhance reliability and efficiency.

Key Points

Illinois NextGrid is an ICC roadmap to value DER and modernize the grid with rebates and non-wires solutions.

✅ Upfront Value-of-DER rebates reward location, time, and performance.

✅ Locational DER reduce peak demand and defer wires and substations.

✅ Encourages non-wires alternatives and data-driven utility planning.

How does the electric utility fit in to a rapidly-evolving energy system? That’s what the Illinois Commerce Commission is trying to determine with its new effort, "NextGrid". Together, we’re rethinking the roles of the utility, the customer, and energy solution providers in a 21st-century digital grid landscape.

In some ways, NextGrid will follow in the footsteps of New York’s innovative Reforming the Energy Vision process, a multi-year effort to re-examine how electric utilities and customers interact. A new approach is essential to accelerating the adoption of clean energy technologies and building a smarter electricity infrastructure in the state.

Like REV, NextGrid is gaining national attention for stakeholder-driven processes to reveal new ways to value distributed energy resources (DER), like rooftop solar and batteries. New York and Illinois’ efforts also seek alternatives, such as virtual power plants, to simply building more and more wires, poles, and power plants to meet the energy needs of tomorrow.

Yet, Illinois is may go a few steps beyond New York, creating a comprehensive framework for utilities to measure how DER are making the grid smarter and more efficient. Here is what we know will happen so far.

On Wednesday, April 5, at the second annual Grid Modernization Forum in Chicago, I’ll be discussing why these provisions could change the future of our energy system, including insights on grid modernization affordability for stakeholders.

Value of distributed energy

The Illinois Commerce Commission’s NextGrid plans grew out of the recently-passed future energy jobs act, a landmark piece of climate and energy policy that was widely heralded as a bipartisan oddity in the age of Trump. The Future Energy Jobs Act will provide significant new investments in renewables and energy efficiency over the next 13 years, redefine the role and value of rooftop solar and batteries on the grid, and lead to significant greenhouse gas emission reductions.

NextGrid will likely start laying the groundwork for valuing distributed energy resources (DER) as envisioned by the Future Energy Jobs Act, which introduces the concept of a new rebate. Illinois currently has a net metering policy, which lets people with solar panels sell their unused solar energy back to the grid to offset their electric bill. Yet the net metering policy had an arbitrary “cap,” or a certain level after which homes and businesses adding solar panels would no longer be able to benefit from net metering.

Although Illinois is still a few years away from meeting that previous “cap,” when it does hit that level, the new policy will ensure additional DER will still be rewarded. Under the new plan, the Value-of-DER rebate will replace net metering on the distribution portion of a customer’s bill (the charge for delivering electricity from the local substation to your house) with an upfront payment, which credits the customer for the value their solar provides to the local grid over the system’s life. Net metering for the energy supply portion of the bill would remain – i.e. homes and businesses would still be able to offset a significant portion of their electric bills by selling excess energy.

What is unique about Illinois’ approach is that the rebate is an upfront payment, rather than on ongoing tariff or reduced net metering compensation, for example. By allowing customers to get paid for the value solar provides to the system at the time it is installed, in the same way new wires, poles, and transformers would, this upfront payment positions DER investments as equally or more beneficial to customers and the electric grid. This is a huge step not only for regulators, but for utilities as well, as they begin to see distributed energy as an asset to the system.

This is a huge step for utilities, as they begin to see distributed energy as an asset to the system.

The rebate would also factor-in the variables of location, time, and performance of DER in the rebate formula, allowing for a more precise calculation of the value to the grid. Peak electricity demand can stress the local grid, causing wear and tear and failure of the equipment that serve our homes and businesses. Power from DER during peak times and in certain areas can alleviate those stresses, therefore providing a greater value than during times of average demand.

In addition, factoring-in the value of performance will take into account the other functions of distributed energy that help keep the lights on. For example, batteries and advanced inverters can provide support for helping avoid voltage fluctuations that can cause outages and other costs to customers.

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BC Hydro LNG Load Forecast signals rising electricity demand from LNG Canada, Woodfibre, and Tilbury, aligning Site C dam capacity with BCUC review, hydroelectric supply, and a potential fourth project in feasibility study British Columbia.

Key Points

BC Hydro's projection of LNG-driven power demand, guiding Site C capacity, BCUC review, and grid planning.

✅ Includes LNG Canada, Woodfibre, and Tilbury load requests

✅ Aligns Site C hydroelectric output with industrial electrification

✅ Notes feasibility study for a fourth LNG project

Despite recent project cancellations, such as the Siwash Creek independent power project now in limbo, BC Hydro still expects three LNG projects — and possibly a fourth, which is undergoing a feasibility study — will need power from its controversial and expensive Site C hydroelectric dam.

In a letter sent to the British Columbia Utilities Commission (BCUC) on Oct. 3, BC Hydro’s chief regulatory officer Fred James said the provincially owned utility’s load forecast includes power demand for three proposed liquefied natural gas projects because they continue to ask the company for power.

The letter and attached report provide some detail on which of the LNG projects proposed in B.C. are more likely to be built, given recent project cancellations.

The documents are also an attempt to explain why BC Hydro continues to forecast a surge in electricity demand in the province, as seen in its first call for power in 15 years driven by electrification, even though massive LNG projects proposed by Malaysia’s state owned oil company Petronas and China’s CNOOC Nexen have been cancelled.

An explanation is needed because B.C.’s new NDP government had promised the BCUC would review the need for the $9-billion Site C dam, which was commissioned to provide power for the province’s nascent LNG industry, amid debates over alternatives like going nuclear among residents. The commission had specifically asked for an explanation of BC Hydro’s electric load forecast as it relates to LNG projects by Wednesday.

The three projects that continue to ask BC Hydro for electricity are Shell Canada Ltd.’s LNG Canada project, the Woodfibre LNG project and a future expansion of FortisBC’s Tilbury LNG storage facility.

None of those projects have officially been sanctioned but “service requests from industrial sector customers, including LNG, are generally included in our industrial load forecast,” the report noted, even as Manitoba Hydro warned about energy-intensive customers in a separate notice.

In a redacted section of the report, BC Hydro also raises the possibility of a fourth LNG project, which is exploring the need for power in B.C.

“BC Hydro is currently undertaking feasibility studies for another large LNG project, which is not currently included in its Current Load Forecast,” one section of the report notes, though the remainder of the section is redacted.

The Site C dam, which has become a source of controversy in B.C. and was an important election issue, is currently under construction and, following two new generating stations recently commissioned, is expected to be in service by 2024, a timeline which had been considered to provide LNG projects with power by the time they are operational.

BC Hydro’s letter to the BCUC refers to media and financial industry reports that indicate global LNG markets will require more supply by 2023.

“While there remains significant uncertainty, global LNG demand will continue to grow and there is opportunity for B.C. LNG,” the report notes.

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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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