Electricity Payouts on Biggest U.S. Grid Fall 64 Per Cent in Auction

Germany Nuclear Phase-Out drives policy amid gas supply risks, Nord Stream 1 shutdown fears, Russia dependency, and energy security planning, as Robert Habeck rejects extending reactors, favoring coal backup, storage, and EU diversification strategies.

Key Points

Ending Germany's last reactors by year end despite gas risks, prioritizing storage, coal backup, and EU diversification.

✅ Reactors' legal certification expires at year end

✅ Minimal gas savings from extending nuclear capacity

✅ Nord Stream 1 cuts amplify energy security risks

Germany’s vice-chancellor has defended the government’s commitment to ending the use of nuclear power at the end of this year, amid fears that Russia may halt natural gas supplies entirely.

Vice-Chancellor Robert Habeck, who is also the economy and climate minister and is responsible for energy, argued that keeping the few remaining reactors running would do little to address the problems caused by a possible natural gas shortfall.

“Nuclear power doesn’t help us there at all,” Habeck, said at a news conference in Vienna on Tuesday. “We have a heating problem or an industry problem, but not an electricity problem – at least not generally throughout the country.”

The main gas pipeline from Russia to Germany shut down for annual maintenance on Monday, as Berlin grew concerned that Moscow may not resume the flow of gas as scheduled.

The Nord Stream 1 pipeline, Germany’s main source of Russian gas, is scheduled to be out of action until July 21 for routine work that the operator says includes “testing of mechanical elements and automation systems”.

But German officials are suspicious of Russia’s intentions, particularly after Russia’s Gazprom last month reduced the gas flow through Nord Stream 1 by 60 percent.

Gazprom cited technical problems involving a gas turbine powering a compressor station that partner Siemens Energy sent to Canada for overhaul.

Germany’s main opposition party has called repeatedly to extend nuclear power by keeping the country’s last three nuclear reactors online after the end of December. There is some sympathy for that position in the ranks of the pro-business Free Democrats, the smallest party in Chancellor Olaf Scholz’s governing coalition.

In this year’s first quarter, nuclear energy accounted for 6 percent of Germany’s electricity generation and natural gas for 13 percent, both significantly lower than a year earlier. Germany has been getting about 35 percent of its gas from Russia.

Habeck said the legal certification for the remaining reactors expires at the end of the year and they would have to be treated thereafter as effectively new nuclear plants, complete with safety considerations and the likely “very small advantage” in terms of saving gas would not outweigh the complications.

Fuel for the reactors also would have to be procured and Scholz has said that the fuel rods are generally imported from Russia.

Opposition politicians have argued that Habeck’s environmentalist Green party, which has long strongly supported the nuclear phase-out, is opposing keeping reactors online for ideological reasons, even as some float a U-turn on the nuclear phaseout in response to the energy crisis.

Reducing dependency on Russia
Germany and the rest of Europe are scrambling to fill the gas storage in time for the northern hemisphere winter, even as Europe is losing nuclear power at a critical moment and reduce their dependence on Russian energy imports.

Prior to the Russian invasion of Ukraine, Berlin had said it considered nuclear energy dangerous and in January objected to European Union proposals that would let the technology remain part of the bloc’s plans for a climate-friendly future that includes a nuclear option for climate change pathway.

“We consider nuclear technology to be dangerous,” government spokesman Steffen Hebestreit told reporters in Berlin, noting that the question of what to do with radioactive waste that will last for thousands of generations remains unresolved.

While neighbouring France aimed to modernise existing reactors, Germany stayed on course to switch off its remaining three nuclear power plants at the end of this year and phase out coal by 2030.

Last month, Germany’s economy minister said the country would limit the use of natural gas for electricity production and make a temporary recourse to coal generation to conserve gas.

“It’s bitter but indispensable for reducing gas consumption,” Robert Habeck said.

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Africa Energy Investment must quadruple, says IEA, to deliver electricity access via grids, mini-grids, and stand-alone solar PV, wind, hydropower, natural gas, and geothermal, targeting $120 billion annually and 2.5% of GDP.

Key Points

Africa Energy Investment funds reliable, low-carbon electricity via grids, mini-grids, and renewables.

✅ Requires about $120B per year, or 2.5% of GDP

✅ Mix: grids, mini-grids, stand-alone solar PV and wind

✅ Targets reliability, economic growth, and electricity access

African countries will need to quadruple their rate of investment in their power sectors for the next two decades to bring reliable electricity to all Africans, as outlined in the IEA’s path to universal access analysis, an International Energy Agency (IEA) study published on Friday said.

If African countries continue on their policy trajectories, 530 million Africans will still lack electricity in 2030, the IEA report said. It said bringing reliable electricity to all Africans would require annual investment of around $120 billion and a global push for clean, affordable power to mobilize solutions.

“We’re talking about 2.5% of GDP that should go into the power sector,” Laura Cozzi, the IEA’s Chief Energy Modeller, told journalists ahead of the report’s launch. “India’s done it over the past 20 years. China has done it, with solar PV growth outpacing any other fuel, too. So it’s something that is doable.”

Taking advantage of technological advances and optimizing natural resources, as highlighted in a renewables roadmap, could help Africa’s economy grow four-fold by 2040 while requiring just 50% more energy, the agency said.

Africa’s population is currently growing at more than twice the global average rate. By 2040, it will be home to more than 2 billion people. Its cities are forecast to expand by 580 million people, a historically unprecedented pace of urbanization.

While that growth will lead to economic expansion, it will pile pressure on power sectors that have already failed to keep up with demand, with the sub-Saharan electricity challenge intensifying across the region. Nearly half of Africans - around 600 million people - do not have access to electricity. Last year, Africa accounted for nearly 70% of the global population lacking power, a proportion that has almost doubled since 2000, the IEA found.

Some 80% of companies in sub-Saharan Africa suffered frequent power disruptions in 2018, leading to financial losses that curbed economic growth.

The IEA recommended changing how power is distributed, with mini-grids and stand-alone systems like household solar playing a larger role in complementing traditional grids as targeted efforts to accelerate access funding gain momentum.

According to IEA Executive Director Fatih Birol, with the right government policies and energy strategies, Africa has an opportunity to pursue a less carbon-intensive development path than other regions.

“To achieve this, it has to take advantage of the huge potential that solar, wind, hydropower, natural gas and energy efficiency offer,” he said.

Despite possessing the world’s greatest solar potential, Africa boasts just 5 gigawatts of solar photovoltaics (PV), or less than 1% of global installed capacity, a slow green transition that underscores the scale of the challenge, the report stated.

To meet demand, African nations should add nearly 15 gigawatts of PV each year through 2040. Wind power should also expand rapidly, particularly in Ethiopia, Kenya, Senegal and South Africa. And Kenya should develop its geothermal resources.

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Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

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Alberta Electricity Market Reforms aim to boost grid reliability and efficiency through a day-ahead market, transmission policy changes, clearer pricing signals, AESO oversight, and smarter siting near existing infrastructure to lower consumer costs.

Key Points

Policies add a day-ahead market and transmission fees to modernize the grid and improve reliability.

✅ Day-ahead market for clearer pricing and scheduling

✅ Up-front, non-refundable transmission payments by generators

✅ AESO to draft new rules by end of 2025

The Alberta government is implementing significant electricity policy changes to its electricity market to enhance system reliability and efficiency. These reforms aim to modernize the grid, accommodate growing energy demands, and align with best practices observed in other jurisdictions.

Proposed Market Reforms

The government has outlined several key initiatives:

• Day-Ahead Market Implementation: Introducing a day-ahead market is intended to provide clearer pricing signals and improve the scheduling of electricity generation. This approach allows market participants to plan and commit to energy production in advance, enhancing grid stability.

• Transmission Policy Revisions: The government proposes reforms to transmission policies, including the introduction of up-front and non-refundable transmission payments from new power generators. These payments would vary based on the proximity of new generators to existing transmission lines with available capacity. As part of a broader market overhaul, this strategy encourages the development of power plants in areas where existing infrastructure can be utilized, potentially reducing costs for consumers and businesses.

Government's Objectives

Minister of Affordability and Utilities, Nathan Neudorf, emphasized that these changes are necessary to meet growing energy demands and modernize Alberta’s electricity system. The government's goal is to create a more reliable and efficient electrical system that benefits both consumers and the broader economy.

Industry Reactions

The proposed reforms have elicited mixed reactions from industry stakeholders amid profound sector change across Alberta:

• Renewable Energy Sector Concerns: The Canadian Renewable Energy Association (CanREA) has expressed concerns about the potential for punitive market and transmission changes, and some retailers have similarly urged caution. They advocate for policies that support the integration of renewable energy sources and ensure fair treatment within the market.

• Regulatory Oversight: The Alberta Electric System Operator (AESO) is tasked with preparing restructured energy market rules by the end of 2025. This timeline reflects the government's commitment to a thorough and consultative approach to market reform.

Implications for Consumers

The Alberta government's proposed market changes aim to enhance the reliability and efficiency of the electricity system by considering measures such as a Rate of Last Resort to provide additional stability. By encouraging the development of power plants in areas with existing infrastructure, the reforms seek to reduce costs for consumers and businesses. However, the success of these initiatives will depend on careful implementation and ongoing engagement with all stakeholders to balance the diverse interests involved.

Alberta's proposed electricity market reforms represent a significant step toward modernizing the province's energy infrastructure. By introducing a day-ahead market and revising transmission policies, the government aims to create a more reliable and efficient electrical system and promote market competition more effectively. While these changes have generated diverse reactions, they underscore the government's commitment to addressing the evolving energy needs of Alberta's residents and businesses.

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Toyota and Honda Moving e delivers hydrogen backup power via a fuel cell bus, portable batteries, and power exporters for disaster relief, emergency electricity, and grid outage support near charging stations and microgrids.

Key Points

A hydrogen mobile power system using a fuel cell bus and batteries to supply emergency electricity during disasters.

✅ Fuel cell bus outputs up to 18 kW, 454 kWh capacity

✅ Portable batteries and power exporter deliver site power

✅ Supports disaster relief near hydrogen charging stations

Without the uninterrupted supply of power and electricity, modern economies would be unable to function. A blackout can impact everything from transport to health care, communication, and even water supplies, as seen in a near-blackout in Japan that strained the grid. It is one of the key security concerns for every government on earth, a point underscored by Fatih Birol on electricity options during the pandemic, and the growth in the market for backup power reflects that fact. In 2018, the global Backup Power market was $14.9 billion and is expected to reach $22 billion by the end of 2025, growing at a CAGR of 5.0 percent between 2019 and 2025.

It is against this backdrop that Toyota and Honda have come up with a new and innovative solution to providing electricity during disasters. The two transport giants have launched a mobile power generation system that consists of a fuel cell bus that can carry a large amount of hydrogen, aligned with Japan's hydrogen energy system efforts underway, portable external power output devices, and portable batteries to disaster zones. The system, which is called ‘Moving e’ includes Toyota’s charging station fuel cell bus, Honda’s power exporter 9000 portable external power output device, two types of Honda’s portable batteries, and a Honda Mobile Power Pack Charge & Supply Concept charger/discharger for MPP. 

In simple terms, the bus would drive to a disaster zone, and while other approaches such as gravity energy storage are advancing, the portable batteries and power output devices would be used to extract electricity from the fuel cell bus and provide it wherever it is needed. The bus itself can generate 454kWh and has a maximum output of 18kW. That is more than enough energy to supply electricity for large indoor areas such as an evacuation area. The bus is also fitted with space for people to nap or rest during a disaster.

The two companies plan to test the effectiveness of the Moving e at multiple municipalities and businesses. These locations will have to be within 100km of a hydrogen station that is capable of refueling the bus. If the bus has to drive 200km, then its electricity supply to the disaster zone would drop from 490kwh to 240kWh. While there aren’t currently enough hydrogen stations to make this a realistic scenario for all disaster zones, especially as countries push for hydrogen-ready power plants in Germany and related infrastructure, hydrogen is growing increasingly competitive with gasoline and diesel.

While gas generators are still considered more reliable and generally cheaper than backup batteries for home use, cleaner backup power is growing increasingly popular, and novel storage like power-to-gas in Europe is also advancing across grids. This latest development by Toyota and Honda is another step forward for the battery and fuel cell industry, with initiatives like PEM hydrogen R&D in China accelerating progress, – especially considering the meteoric rise of hydrogen energy in recent years.
 

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American-Made Solar Prize Round 3 accelerates DOE-backed solar innovation, empowering entrepreneurs and domestic manufacturing with photovoltaics and grid integration support via National Laboratories, incubators, and investors to validate products, secure funding, and deploy backup power.

Key Points

A DOE challenge fast-tracking solar innovation to market readiness, boosting US manufacturing and grid integration.

✅ $50,000 awards to 20 teams for prototype validation

✅ Access to National Labs, incubators, investors, and mentors

✅ Focus on PV advances and grid integration solutions

The U.S. Department of Energy (DOE) announced the 20 competitors who have been invited to advance to the next phase of the American-Made Solar Prize Round 3, a competition designed to incentivize the nation’s entrepreneurs to strengthen American leadership in solar energy innovation and domestic manufacturing, a key front in the clean energy race today.

The American-Made Solar Prize is designed to help more American entrepreneurs thrive in the competitive global energy market. Each round of the prize brings new technologies to pre-commercial readiness in less than a year, ensuring new ideas enter the marketplace. As part of the competition, teams will have access to a network of DOE National Laboratories, technology incubators and accelerators, and related DOE efforts like next-generation building upgrades, venture capital firms, angel investors, and industry. This American-Made Network will help these competitors raise private funding, validate early-stage products, or test technologies in the field.

Each team will receive a $50,000 cash prize and become eligible to compete in the next phase of the competition. Through a rigorous evaluation process, teams were chosen based on the novelty of their ideas and how their solutions address a critical need of the solar industry. The teams were selected from 120 submissions and represent 11 states. These projects will tackle challenges related to new solar applications, like farming, as well as show how solar can be used to provide backup power when the grid goes down, aided by increasingly affordable batteries now reaching scale. Nine teams will advance solar photovoltaic technologies, and 11 will address challenges related to how solar integrates with the grid. The projects are as follows:

Photovoltaics:

• Durable Antireflective and Self-Cleaning Glass (Pittsburgh, PA)
• Pursuit Solar - More Power, Less Hassle (Denver, NC)
• PV WaRD (San Diego, CA)
• Remotely Deployed Solar Arrays (Charlottesville, VA)
• Robotics Changing the Landscape for Solar Farms (San Antonio, TX)
• TrackerSled (Chicago, IL)
• Transparent Polymer Barrier Films for PV (Bristol, PA)
• Solar for Snow (Duluth, MN)
• SolarWall Power Tower (Buffalo, NY)

Systems Integration:

• Affordable Local Solar Storage via Utility Virtual Power Plants (Parker, TX)
• Allbrand Solar Monitor (Detroit, MI)
• Beyond Monitoring – Next Gen Software and Hardware (Atlanta, GA)
• Democratizing Solar with Artificial Intelligence Energy Management (Houston, TX)
• Embedded, Multi-Function Maximum Power Point Tracker for Smart Modules (Las Vegas, NV)
• Evergrid: Keep Solar Flowing When the Grid Is Down (Livermore, CA)
• Inverter Health Scan (San Jose, CA)
• JuiceBox: Integrated Solar Electricity for Americans Transitioning out of Homelessness and Recovering from Natural Disasters (Claremont, CA)
• Low-Cost Parallel-Connected DC Power Optimizer (Blacksburg, VA)
• Powerfly: A Plug-and-Play Solar Monitoring Device (Berkeley, CA)
• Simple-Assembly Storage Kit (San Antonio, TX)

Read the descriptions of the projects to see how they contribute to efforts to improve solar and wind power worldwide.

Over the next six months, these teams will fast-track their efforts to identify, develop, and test disruptive solutions amid record solar and storage growth projected nationwide. During a national demonstration day at Solar Power International in September 2020, a panel of judges will select two final winners who will receive a $500,000 prize. Learn more at the American-Made Solar Prize webpage.

The American-Made Challenges incentivize the nation's entrepreneurs to strengthen American leadership in energy innovation and domestic manufacturing. These new challenges seek to lower the barriers U.S.-based innovators face in reaching manufacturing scale by accelerating the cycles of learning from years to weeks while helping to create partnerships that connect entrepreneurs to the private sector and the network of DOE’s National Laboratories across the nation, alongside recent wind energy awards that complement solar innovation.

Go here to learn how this work aligns with a tenfold solar expansion being discussed nationally.

https://www.energy.gov/eere/solar/solar-energy-technologies-office

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