Several Milestones Reached at Nuclear Power Projects Around the World

Noncarbon Electricity Investment Strategy helps utilities hedge policy uncertainty, carbon tax risks, and emissions limits by scaling wind, solar, and CCS, avoiding stranded assets while balancing costs, reliability, and climate policy over decades.

Key Points

A strategy for utilities to invest 20-30 percent of capacity in low carbon sources to hedge emissions and carbon risks.

✅ Hedges future carbon tax and emissions limits

✅ Targets 20-30 percent of new generation from clean sources

✅ Reduces stranded asset risk and builds renewables capacity

When utility executives make decisions about building new power plants, a lot rides on their choices. Depending on their size and type, new generating facilities cost hundreds of millions or even billions of dollars. They typically will run for 40 or more years — 10 U.S. presidential terms. Much can change during that time.

Today one of the biggest dilemmas that regulators and electricity industry planners face is predicting how strict future limits on greenhouse gas emissions will be. Future policies will affect the profitability of today’s investments. For example, if the United States adopts a carbon tax 10 years from now, it could make power plants that burn fossil fuels less profitable, or even insolvent.

These investment choices also affect consumers. In South Carolina, utilities were allowed to charge their customers higher rates to cover construction costs for two new nuclear reactors, which have now been abandoned because of construction delays and weak electricity demand. Looking forward, if utilities are reliant on coal plants instead of solar and wind, it will be much harder and more expensive for them to meet future emissions targets, even as New Zealand's electrification push accelerates abroad. They will pass the costs of complying with these targets on to customers in the form of higher electricity prices.

With so much uncertainty about future policy, how much should we be investing in noncarbon electricity generation in the next decade? In a recent study, we proposed optimal near-term electricity investment strategies to hedge against risks and manage inherent uncertainties about the future.

We found that for a broad range of assumptions, 20 to 30 percent of new generation in the coming decade should be from noncarbon sources such as wind and solar energy across markets. For most U.S. electricity providers, this strategy would mean increasing their investments in noncarbon power sources, regardless of the current administration’s position on climate change.

Many noncarbon electricity sources — including wind, solar, nuclear power and coal or natural gas with carbon capture and storage — are more expensive than conventional coal and natural gas plants. Even wind power, which is often mentioned as competitive, is actually more costly when accounting for costs such as backup generation and energy storage to ensure that power is available when wind output is low.

Over the past decade, federal tax incentives and state policies designed to promote clean electricity sources spurred many utilities to invest in noncarbon sources. Now the Trump administration is shifting federal policy back toward promoting fossil fuels. But it can still make economic sense for power companies to invest in more expensive noncarbon technologies if we consider the potential impact of future policies.

How much should companies invest to hedge against the possibility of future greenhouse gas limits? On one hand, if they invest too much in noncarbon generation and the federal government adopts only weak climate policies throughout the investment period, utilities will overspend on expensive energy sources.

On the other hand, if they invest too little in noncarbon generation and future administrations adopt stringent emissions targets, utilities will have to replace high-carbon energy sources with cleaner substitutes, which could be extremely costly.

Economic modeling with uncertainty

We conducted a quantitative analysis to determine how to balance these two concerns and find an optimal investment strategy given uncertainty about future emissions limits. This is a core choice that power companies have to make when they decide what kinds of plants to build.

First we developed a computational model that represents the sectors of the U.S. economy, including electric power. Then we embedded it within a computer program that evaluates decisions in the electric power sector under policy uncertainty.

The model explores different electric power investment decisions under a wide range of future emissions limits with different probabilities of being implemented. For each decision/policy combination, it computes and compares economy-wide costs over two investment periods extending from 2015 to 2030.

We looked at costs across the economy because emissions policies impose costs on consumers and producers as well as power companies. For example, they may lead to higher electricity, fuel or product prices. By seeking to minimize economy-wide costs, our model identifies the investment decision that produces the greatest overall benefits to society.

More investments in clean generation make economic sense

We found that for a broad range of assumptions, the optimal investment strategy for the coming decade is for 20 to 30 percent of new generation to be from noncarbon sources. Our model identified this as the best level because it best positions the United States to meet a wide range of possible future policies at a low cost to the economy.

From 2005-2015, we calculated that about 19 percent of the new generation that came online was from noncarbon sources. Our findings indicate that power companies should put a larger share of their money into noncarbon investments in the coming decade.

While increasing noncarbon investments from a 19 percent share to a 20 to 30 percent share of new generation may seem like a modest change, it actually requires a considerable increase in noncarbon investment dollars. This is especially true since power companies will need to replace dozens of aging coal-fired power plants that are expected to be retired.

In general, society will bear greater costs if power companies underinvest in noncarbon technologies than if they overinvest. If utilities build too much noncarbon generation but end up not needing it to meet emissions limits, they can and will still use it fully. Sunshine and wind are free, so generators can produce electricity from these sources with low operating costs.

In contrast, if the United States adopts strict emissions limits within a decade or two, they could prevent carbon-intensive generation built today from being used. Those plants would become “stranded assets” — investments that are obsolete far earlier than expected, and are a drain on the economy.

Investing early in noncarbon technologies has another benefit: It helps develop the capacity and infrastructure needed to quickly expand noncarbon generation. This would allow energy companies to comply with future emissions policies at lower costs.

Seeing beyond one president

The Trump administration is working to roll back Obama-era climate policies such as the Clean Power Plan, and to implement policies that favor fossil generation. But these initiatives should alter the optimal strategy that we have proposed for power companies only if corporate leaders expect Trump’s policies to persist over the 40 years or more that these new generating plants can be expected to run.

Energy executives would need to be extremely confident that, despite investor pressure from shareholders, the United States will adopt only weak climate policies, or none at all, into future decades in order to see cutting investments in noncarbon generation as an optimal near-term strategy. Instead, they may well expect that the United States will eventually rejoin worldwide efforts to slow the pace of climate change and adopt strict emissions limits.

In that case, they should allocate their investments so that at least 20 to 30 percent of new generation over the next decade comes from noncarbon sources. Sustaining and increasing noncarbon investments in the coming decade is not just good for the environment — it’s also a smart business strategy that is good for the economy.

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Germany Energy Demand Decline reflects economic stagnation, IEA forecasts, and the Energiewende, as industrial output slips and efficiency gains, renewables growth, and cost-cutting reduce fossil fuel use while reshaping sustainability and energy security.

Key Points

A projected 7% drop in German energy use driven by industrial slowdown, efficiency gains, and renewables expansion.

✅ IEA projects up to 7% demand drop in the next year

✅ Industrial slowdown and efficiency programs cut consumption

✅ Energiewende shifts mix to wind, solar, and less fossil fuel

Germany is on the verge of experiencing a significant decline in energy demand, with forecasts suggesting that usage could hit a record low as the country grapples with economic stagnation. This shift highlights not only the immediate impacts of sluggish economic growth but also broader trends in energy consumption, Europe's electricity markets, sustainability, and the transition to renewable resources.

Recent data indicate that Germany's economy is facing substantial challenges, including high inflation and reduced industrial output. As companies struggle to maintain profitability amid nearly doubled power prices and rising costs, many have begun to cut back on energy consumption. This retrenchment is particularly pronounced in energy-intensive sectors such as manufacturing and chemical production, which are crucial to Germany's export-driven economy.

The International Energy Agency (IEA) has projected that German energy demand could decline by as much as 7% in the coming year, a stark contrast to the trends seen in previous decades. This decline is primarily driven by a combination of factors, including reduced industrial activity, increased energy efficiency measures, and a shift toward alternative energy sources, as well as mounting pressures on local utilities to stay solvent. The current economic landscape has led businesses to prioritize cost-cutting measures, including energy efficiency initiatives aimed at reducing consumption.

In the context of these developments, Germany’s energy transition—known as the "Energiewende"—is becoming increasingly significant. The country has made substantial investments in renewable energy sources such as wind, solar, and biomass in recent years. As energy efficiency improves and the share of renewables in the energy mix rises, traditional fossil fuel consumption has begun to wane. This transition is seen as both a response to climate change and a strategy for energy independence, particularly in light of geopolitical tensions and Europe's wake-up call to ditch fossil fuels across the continent.

However, the current stagnation presents a paradox for the German energy sector. While lower energy demand may ease some pressures on supply and prices, it also raises concerns about the long-term viability of investments in renewable energy infrastructure, even as debates continue over electricity subsidies for industry to support competitiveness. The economic slowdown has the potential to derail progress made in reducing carbon emissions and achieving energy targets, particularly if it leads to decreased investment in green technologies.

Another layer to this issue is the potential impact on employment within the energy sector. As energy demand decreases, there may be a ripple effect on jobs tied to traditional energy production and even in renewable energy sectors if investment slows. Policymakers are now tasked with balancing the immediate need for economic recovery, illustrated by the 200 billion-euro energy price shield, with the longer-term goal of achieving sustainability and energy security.

The effects of the stagnation are also being felt in the residential sector. As households face increased living costs and rising heating and electricity costs, many are becoming more conscious of their energy consumption. Initiatives to improve home energy efficiency, such as better insulation and energy-efficient appliances, are gaining traction among consumers looking to reduce their utility bills. This shift toward energy conservation aligns with broader national goals of reducing overall energy consumption and carbon emissions.

Despite the challenges, there is a silver lining. The current situation offers an opportunity for Germany to reassess its energy strategies and invest in technologies that promote sustainability while also addressing economic concerns. This could include increasing support for research and development in green technologies, enhancing energy efficiency programs, and incentivizing businesses to adopt cleaner energy practices.

Furthermore, Germany’s experience may serve as a case study for other nations grappling with similar issues. As economies around the world face the dual pressures of recovery and sustainability, the lessons learned from Germany’s current energy landscape could inform strategies for balancing these often conflicting priorities.

In conclusion, Germany is poised to witness a historic decline in energy demand as economic stagnation takes hold. While this trend poses challenges for the energy sector and economic growth, it also highlights the importance of sustainability and energy efficiency in shaping the future. As the nation navigates this complex landscape, the focus will need to be on fostering innovation and investment that aligns with both immediate economic needs and long-term environmental goals. The path forward will require a careful balancing act, but with the right strategies, Germany can emerge as a leader in sustainable energy practices even in challenging times.

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US Electricity Sales Decline amid population growth and GDP gains, as DOE links reduced per capita consumption to energy efficiency, warmer winters, appliances, and bulbs, while hotter summers and rising AC demand may offset savings.

Key Points

US electricity sales fell 3% since 2010 despite population and GDP growth, driven by efficiency gains and warmer winters.

✅ DOE links drops to efficiency and warmer winters

✅ Per capita residential use fell about 7% since 2010

✅ Rising AC demand may offset winter heating savings

Since 2010, the United States has grown by 17 million people, and the gross domestic product (GDP) has increased by $3.6 trillion. Yet in that same time span, electricity sales in the United States actually declined by 3%, according to data released by the U.S. Department of Energy (DOE), even as electricity prices rose at a 41-year pace nationwide.

The U.S. decline in electricity sales is remarkable given that the U.S. population increased by 5.8% in that same time span. This means that per capita electricity use fell even more than that; indeed, the Department of Energy pegs residential electricity sales per capita as having declined by 7%, even as inflation-adjusted residential bills rose 5% in 2022 nationwide.

There are likely multiple reasons for this decline in electricity sales. Department of Energy analysts suggest that, at least in part, it is due to increased adoption of energy-efficient appliances and bulbs, like compact fluorescents. Indeed, the DOE notes that there is a correlation between consumer spending on “energy efficiency” and a reduction in per capita electricity sales, while utilities invest more in delivery infrastructure to modernize the grid.

Yet the DOE also notes that states with a greater increase in warm weather days had a corresponding decrease in electricity sales, as milder weather can reduce power demand across years. In southern states, the effect was most dramatic: for instance, from 2010 to 2016, Florida had a 56% decrease in cold weather days that would require heating and as a result, saw a 9% decrease in per capita electricity sales.

The moral is that warm winters save on electricity. But if global temperatures continue to rise, and summers become hotter, too, this decrease in winter heating spending may be offset by the increased need to run air conditioning in the summer, and given how electricity and natural gas prices interact, overall energy costs could shift. Indeed, it takes far more energy to cool a room than it does to heat it, for reasons related to the basic laws of thermodynamics. 

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GMP Tesla Powerwall Program replaces utility meters with smart battery storage, enabling virtual power plant services, demand response, and resilient homes, integrating solar readiness, EV charging support, and smart grid controls across Vermont households.

Key Points

Green Mountain Power uses Tesla Powerwalls as smart meters, creating a VPP for demand response and home backup.

✅ $30 monthly for 10 years or $3,000 upfront for two units

✅ Utility controls batteries for peak shaving and demand response

✅ Enables backup power, solar readiness, and EV charging support

There are more than 100 million single-family homes in the United States of America. If each of these homes were to have two 13.5 kWh Tesla Powerwalls, that would total 2.7 Terawatt-hours worth of electricity stored. Prior research has suggested that this volume of energy storage could get us halfway to the 5.4 TWh of storage needed to let the nation get 80% of its electricity from solar and wind, as states like California increasingly turn to grid batteries to support the transition.

Vermont utility Green Mountain Power (GMP) seeks to remove standard electric utility metering hardware and replace it with the equipment inside of a Tesla Powerwall, as part of a broader digital grid evolution underway. Mary Powell, President and CEO of Green Mountain Power, says, “We have a vision of a battery system in every single home” and they’ve got a patent pending software solution to make it happen.

The Resilient Home program will install two standard Tesla Powerwalls each in 250 homes in GMP’s service area. The homeowner will pay either $30 a month for ten years ($3,600), or $3,000 up front. At the end of the ten year period, payments end, but the unit can stay in the home for an additional five years – or as long as it has a usable life.

A single Powerwall costs approximately $6,800, making this a major discount.

GMP notes that the home must have reliable internet access to allow GMP and Tesla to communicate with the Powerwall. GMP will control the functions of the Powerwall, effectively operating a virtual power plant across participating homes, expanding the scope of programs like those that saved the state’s ratepayers more than $500,000 during peak demand events last year. The utility specifically notes that customers agree to share stored energy with GMP on several peak demand days each year.

The hardware can be designed to interact with current backup generators during power outages, or emerging fuel cell solutions that maintain battery charge longer during extended outages, however, the units will not charge from the generator. As noted the utility will be making use of the hardware during normal operating times, however, during a power outage the private home owner will be able to use the electricity to back up both their house and top off their car.

The utility told pv magazine USA that the Powerwalls are standard from the factory, with GMP’s patent pending software solution being the special sauce (has a hint of recent UL certifications). GMP said the program will also get home owners “adoption ready” for solar power, including microgrid energy storage markets, and other smart devices.

Sonnen’s ecoLinx is already directly interacting with a home’s electrical panel (literally throwing wifi enabled circuit breakers). Now with Tesla Powerwalls being used to replace utility meters, we see one further layer of integration that will lead to design changes that will drive residential solar toward $1/W. Electric utilities are also experimenting with controlling module level electronics and smart solar inverters in 100% residential penetration situations. And of course, considering that California is requiring solar – and probably storage in the future – in all new homes, we should expect to see further experimentation in this model. Off grid solar inverter manufacturers already include electric panels with their offerings.

If we add in the electric car, and have vehicle-to-grid abilities, we start to see a very strong amount of electricity generation and energy storage, helping to keep the lights on during grid stress, potentially happening in more than 100 million residential power plants. Resilient homes indeed.

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Smart solar inverters anchor DER communications and control, meeting IEEE 1547 and California Rule 21 for volt/VAR, reactive power, and ride-through, expanding hosting capacity and enabling grid services via secure real-time telemetry and commands.

Key Points

Smart solar inverters use IEEE 1547, volt/VAR and reactive power to stabilize circuits and integrate DER safely.

✅ Meet IEEE 1547, Rule 21 ride-through and volt/VAR functions

✅ Support reactive power to manage voltage and hosting capacity

✅ Enable utility communications, telemetry, and grid services

Advanced solar inverters could be one of the biggest distributed energy resource communications and control points out there someday. With California now requiring at least early-stage “smart” capabilities from all new solar projects — and a standards road map for next-stage efforts like real-time communications and active controls — this future now has a template.

There are still a lot of unanswered questions about how smart inverters will be used.

That was the consensus at Intersolar this week, where experts discussed the latest developments on the U.S. smart solar inverter front. After years of pilot projects, multi-stakeholder technical working groups, and slow and steady standards development, solar smart inverters are finally starting to hit the market en masse — even if it’s not yet clear just what will be done with them once they’re installed.

“From the technical perspective, the standards are firm,” Roger Salas, distribution engineering manager for Southern California Edison, said. In September of last year, his utility started requiring that all new solar installations come with “Phase 1" advanced inverter functionality, as defined under the state’s Rule 21.

Later this month, it’s going to start requiring “reactive power priority” for these inverters, and in February 2019, it’s going to start requiring that inverters support the communications capabilities described in “Phase 2,” as well as some more advanced “Phase 3” capabilities.

Increasing hosting capacity: A win-win for solar and utilities

Each of these phases aligns with a different value proposition for smart inverters. The first phase is largely preventative, aimed at solving the kinds of problems that have forced costly upgrades to how inverters operate in solar-heavy Germany and Hawaii.

The key standard in question in the U.S. is IEEE 1547, which sets the rules for what grid-connected DERs must do to stay safe, such as trip offline when the grid goes down, or avoid overloading local transformers or circuits.

The old version of the standard, however, had a lot of restrictive rules on tripping off during relatively common voltage excursions, which could cause real problems on circuits with a lot of solar dropping off all at once.

Phase 1 implementation of IEEE 1547 is all about removing these barriers, Salas said. “They need to be stable, they need to be connected, they need to be able to support the grid.”

This should increase hosting capacity on circuits that would have otherwise been constrained by these unwelcome behaviors, he said.

Reactive power: Where utility and solar imperatives collide

The old versions of IEEE 1547 also didn’t provide rules for how inverters could use one of their more flexible capabilities: the ability to inject or absorb reactive power to mitigate voltage fluctuations, including those that may be caused by the PV itself. The new version opens up this capability, which could allow for an active application of reactive power to further increase hosting capacity, as well as solve other grid edge challenges for utilities.

But where utilities see opportunity, the solar industry sees a threat. Every unit of reactive power comes at the cost of a reduction in the real power output of solar inverters — and almost every solar installation out there is paid based on the real power it produces.

“If you’re tasked to do things that rob your energy sales, that will reduce compensation,” noted Ric O'Connell, executive director of the Oakland, Calif.-based GridLab. “And a lot of systems have third-party owners — the Sunruns, the Teslas — with growing Powerwall fleets — that have contracts, performance guarantees, and they want to get those financed. It’s harder to do that if there’s uncertainty in the future with curtailment."

“That’s the bottleneck right now,” said Daniel Munoz-Alvarez, a GTM Research grid edge analyst. “As we develop markets on the retail end for ...volt/VAR control to be compensated on the grid edge and that is compensated back to the customer, then the customer will be more willing to allow the utility to control their smart inverters or to allow some automation.”

But first, he said, “We need some agreed-upon functions.”

The future: Communications, controls and DER integration

The next stage of smart inverter functionality is establishing communications with the utility. After that, utilities will be able use them to monitor key DER data, or issue disconnect and reconnect commands in emergencies, as well as actively orchestrate other utility devices and systems through emerging virtual power plant strategies across their service areas.

This last area is where Salas sees the greatest opportunity to putting mass-market smart solar inverters to use. “If you want to maximize the DERs and what they can do, the need information from the grid. And DERs provide operational and capability information to the utility.”

Inverter makers have already been forced by California to enable the latest IEEE 1547 capabilities into their existing controls systems — but they are clearly embracing the role that their devices can play on the grid as well. Microinverter maker Enphase leveraged its work in Hawaii into a grid services business, seeking to provide data to utilities where they already had a significant number of installations. While Enphase has since scaled back dramatically, its main rival SolarEdge has taken up the same challenge, launching its own grid services arm earlier this summer.

Inverters have been technically capable of doing most of these things for a long time. But utilities and regulators have been waiting for the completion of IEEE 1547 to move forward decisively. Patrick Dalton, senior engineer for Xcel Energy, said his company’s utilities in Colorado and Minnesota are still several years away from mandating advanced inverter capabilities and are waiting for California’s energy transition example in order to choose a path forward.

In the meantime, it’s possible that Xcel's front-of-meter volt/VAR optimization investments in Colorado, including grid edge devices from startup Varentec, could solve many of the issues that have been addressed by smart inverter efforts in Hawaii and California, he noted.

The broader landscape for rolling out smart inverters for solar installations hasn’t changed much, with Hawaii and California still out ahead of the pack, while territories such as Puerto Rico microgrid rules evolve to support resilience. Arizona is the next most important state, with a high penetration of distributed solar, a contentious policy climate surrounding its proper treatment in future years, and a big smart inverter pilot from utility Arizona Public Service to inform stakeholders.

All told, eight separate smart inverter pilots are underway across eight states at present, according to GTM Research: Pacific Gas & Electric and San Diego Gas & Electric in California; APS and Salt River Project in Arizona; Hawaiian Electric in Hawaii; Duke Energy in North Carolina; Con Edison in New York; and a three-state pilot funded by the Department of Energy’s SunShot program and led by the Electric Power Research Institute.

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Russian cyberattacks on U.S. power grid exposed DHS warnings: Dragonfly/Energetic Bear breached control rooms, ICS networks, and could trigger blackouts via switch manipulation, phishing, and malware, threatening critical infrastructure and utility operations nationwide.

Key Points

State-backed breaches of utility ICS and control rooms enabled potential switch manipulation and blackouts.

✅ DHS: Dragonfly/Energetic Bear breached utility networks

✅ Access reached control rooms and ICS for switch control

✅ Ongoing campaign via phishing, malware, lateral movement

Russian hackers for a state-sponsored organization invaded hundreds of control rooms of U.S. electric utilities that could have led to blackouts, a new report says.

The group, known as Dragonfly or Energetic Bear, infiltrated networks of U.S. utilities as part of an effort that is likely ongoing, Department of Homeland Security officials told the Wall Street Journal.

Jonathan Home, chief of industrial-control-system analysis for DHS, said the hackers “got to the point where they could have thrown switches” and upset power flows.

Although the agency did not disclose which companies were impacted, the officials at a briefing Monday said that there were “hundreds of victims” including breaches at power plants across the U.S., and that some companies may not be aware that hackers infiltrated their networks yet.

According to experts, Russia has been preparing for such attacks for some time now, prompting a renewed focus on protecting the grid among utilities and policymakers.

“They’ve been intruding into our networks and are positioning themselves for a limited or widespread attack,” said former Deputy Assistant Defense Secretary Michael Carpenter, now senior director at the Penn Biden Center at the University of Pennsylvania, per the Wall Street Journal. “They are waging a covert war on the West.”

Earlier this year, the Trump administration claimed Russia had staged a power grid hacking campaign against the U.S. energy grid and other U.S. infrastructure.

The report comes after President Trump told reporters last week during a joint press conference in Helsinki alongside Russian President Vladimir Putin that he had no reason not to believe the Russian leader's assurances to him that the Kremlin was not to blame for interference in the election.

Trump later admitted that he misspoke when he said he didn’t “see any reason why” Russia would have meddled in the 2016 election, and said he believes the U.S. intelligence community assessment that found that the Russian government did interfere in the electoral process.

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