Nuclear: Revival and Reassessment
After years of decline, nuclear power is creeping back onto the strategic agenda on both sides of the Atlantic. In Europe, high fuel prices and geopolitical turmoil have prompted several governments to rethink nuclear policy. In May 2025, Belgium scrapped a two-decade-old phase-out law, opening the door to building new reactors as part of its climate strategy. “We have three objectives, security of supply, a controlled price and low-carbon energy. And nuclear power meets all three criteria,” Belgium’s energy minister said, explaining the U-turn. Even Germany – which shut down its last three reactors in April 2023 – has seen an ideological shift. By early 2025, Berlin’s new government indicated it would stop blocking efforts to treat nuclear on par with renewables in EU policy. Meanwhile, Italy’s administration set 2030 as a target to bring nuclear energy back, reversing a ban in place since the 1980s. Coal-dependent Poland is pressing ahead with its first-ever nuclear station (due ~2033), and Sweden passed a law funding new reactors amid a pro-nuclear turn in 2023. Across Europe, what was once taboo is now framed as a pragmatic move for energy security and emissions cuts. As one energy scholar noted, “anything we can do to make ourselves more independent of gas, we have to do. Nuclear power is one way”.
North America is likewise witnessing a cautious nuclear renaissance. In the United States, 2023 saw the first newly constructed reactors in over 30 years begin operation. Georgia’s Vogtle plant Unit 3 entered commercial service in July 2023, followed by Unit 4 in April 2024. This long-delayed project added over 2.2 GW of capacity and made Vogtle the largest clean power station in the country. “Units 3 and 4 are the first newly constructed nuclear units built in the United States in more than three decades,” Southern Company noted, calling nuclear energy “irreplaceable” in the drive to net-zero. The Biden administration has touted nuclear’s role in a carbon-free grid by 2035, providing federal loan guarantees that helped Vogtle across the finish line. Attention is also turning to advanced reactors: regulators approved the design of small modular reactors (SMRs) and companies like NuScale and TerraPower are pursuing deployments later this decade. Canada, for its part, is doubling down on nuclear to meet growth and climate goals. In 2023 Ontario announced plans for up to 4,800 MW of new large reactors at the Bruce site – the country’s biggest nuclear expansion in decades. Ontario’s power utility also began site preparation for a first 300 MW SMR at Darlington, aiming for operation before 2030. These investments reflect a strategic bet that modern nuclear can supply reliable, carbon-free baseload power for 60–80 years. Still, cost and time remain formidable: as one European expert cautioned, building new reactors “is much more complicated” and takes around ten years – while renewables are rolling out far faster. Governments and industry are grappling with that trade-off, extending the life of existing reactors even as they lay groundwork for the next generation.
Offshore Wind: From North Sea to New Shores
Blustery seas are becoming prime real estate for renewable energy. Europe’s offshore wind industry, already world-leading, entered an ambitious new phase in 2023. In April that year, nine North Sea countries inked the Ostend declaration setting a combined 120 GW offshore wind target by 2030 – a huge leap from ~30 GW today. The goal, which rises to 300 GW by 2050, is to make the North Sea the “Green Power Plant of Europe”. The UK alone committed to build 50 GW of offshore wind by 2030 (including 5 GW floating turbines), while the Netherlands, Germany, and others scaled up their contributions. This international coordination also spurred new grid links: a planned LionLink undersea cable between Britain and the Netherlands will enable sharing of 1.8 GW of wind power, with the UK targeting at least 18 GW of interconnectors by 2030. “Today’s deal at the North Sea Summit has the UK centre stage. It sends a strong message to Putin that his control over European energy markets is well and truly over,” declared Britain’s energy secretary Grant Shapps as Europe pivots to “home-grown” offshore resources. On the project level, developers are delivering ever-bigger wind farms.
Off England’s coast, the giant Dogger Bank project (3.6 GW across three phases) began producing its first power in October 2023. Touted as the world’s largest offshore wind farm, Dogger Bank’s initial turbines are already feeding British homes, with full operations due by 2025. Such mega-projects, alongside innovations like floating turbines for deep waters, underscore Europe’s commitment to offshore wind as a cornerstone of its energy transition.
Across the Atlantic, the United States is finally setting sail on offshore wind, though not without headwinds. In early 2024, Vineyard Wind 1 – America’s first utility-scale offshore array – delivered power to the Massachusetts grid, a milestone “momentous event” nearly a decade in the making. The project’s first 5 MW turbine came online January 2, 2024, with all 62 turbines (806 MW) on track by year-end to supply ~400,000 New England homes. “As the nation’s first utility-scale offshore wind farm this is a fairly momentous event,” said an executive of co-developer Avangrid, highlighting the long struggle to launch a new industry. Vineyard Wind’s success offers lessons for the dozens of U.S. projects in earlier stages – on logistics, permitting, and grid integration. Federal policy has been supportive: the Biden Administration set a bold goal of 30 GW offshore wind by 2030 and, in 2023, held lease auctions from the Atlantic to the Pacific. Yet rising costs have put several marquee projects in jeopardy. High inflation, interest rates, and supply snags drove some developers to cancel power contracts or write down investments, warning that original price bids are no longer viable. In late 2023, Ørsted – the world’s leading offshore wind firm – stunned the market by halting its 2.2 GW Ocean Wind projects in New Jersey, citing potential impairments over $5 billion amid a “shortage of vessels” and surging costs. The CEO of Ørsted called for a “reset” of offshore wind pricing to reflect economic reality. Similarly, oil majors BP and Equinor wrote off over $800 million on planned New York wind farms after state regulators refused contract price increases, saying ratepayers shouldn’t bear the inflation burden. In total, at least ten East Coast wind projects sought to renegotiate deals in 2023, and several were shelved, casting doubt on the 2030 deployment target.
Industry experts note that developers are regrouping rather than exiting – some states began adjusting auction rules to index contracts to costs, aiming to keep investors on board. Even so, the delays threaten to derail President Biden’s plan to install 30 GW by 2030. The U.S. experience underscores both the promise of vast offshore wind resources and the importance of aligning policy with market conditions. As projects like Vineyard Wind and its follow-on (the 132 MW South Fork Wind in New York, due in 2024) come online, pressure is mounting to resolve bottlenecks – from a lack of specialized installation vessels to lengthy permitting. Without faster reforms, analysts warn “it will be impossible to build new renewable infrastructure in the time needed” to meet climate goals. In short, offshore wind in the U.S. is at once a newborn industry with political backing and a sector learning hard lessons about cost discipline.
Solar Power Scales Up
Solar energy has been shining at record levels in the past two years, with rapid deployment across Europe and North America. The European Union, spurred by high gas prices and pro-renewable policies, saw an unprecedented solar boom in 2023. Developers connected roughly 62.8 GW of new solar capacity across the EU that year – a 53% jump from 2022 installations. This one-year surge lifted Europe’s cumulative solar fleet to 338 GW by the end of 2024, a fourfold increase from a decade prior. Countries like Germany, Spain, Poland and the Netherlands led the charge with massive additions in utility-scale and rooftop photovoltaics. The feverish pace did moderate in 2024, when EU solar growth slowed to about 4% (65.5 GW added) amid fading post-crisis incentives. Nonetheless, Europe remains on track to hit steep 2030 targets – which require sustained installs of ~70 GW per year. Industry leaders have urged action to maintain momentum. “Slowing solar deployment means slowing the continent’s goals on energy security, competitiveness, and climate,” warned Walburga Hemetsberger, CEO of SolarPower Europe, noting that policy bottlenecks must be addressed. Indeed, after the frenzy of 2022–23 (driven by emergency energy measures and plummeting PV costs), Europe is focusing on grid upgrades and permitting reforms to support the next wave of solar. Investment in EU solar dipped in 2024 for the first time in a decade, from €63 billion to €55 billion, as grid constraints and political uncertainties loomed. Still, technology costs continue to fall, and solar’s share of the power mix keeps rising to new highs on sunny days – Spain, for example, hit a record 56% renewable electricity in 2024 with solar farms contributing strongly. With the EU raising its 2030 renewable target (to 42.5% of energy), utility-scale solar is set to remain a linchpin of Europe’s decarbonization plans.
In the United States, the solar industry is likewise in the midst of an historic growth spurt, turbocharged by favorable policy. The first full year under the Inflation Reduction Act (2023) proved “record-shattering” for U.S. solar deployment. According to the Solar Energy Industries Association (SEIA), 32.4 GW of solar capacity were installed nationwide in 2023, a 51% leap over 2022 and the first time annual additions surpassed 30 GW. Solar accounted for 53% of all new U.S. generation capacity that year – an unprecedented dominance for a renewable source. SEIA’s CEO Abigail Ross Hopper credited the Inflation Reduction Act’s incentives for “supercharging solar deployment” and catalyzing a domestic manufacturing revivalu. Indeed, panel factories are springing up: U.S. module production capacity nearly doubled in 2023 (from 8.5 GW to 16.1 GW/year) as firms respond to Made-in-America tax credits. The solar pipeline remains robust – though 2023’s torrid growth benefited partly from delayed projects from 2022 (when trade and supply hurdles hit). Going forward, analysts expect high but steadier expansion. The Energy Information Administration projects another record year in 2024 with 36 GW of utility-scale solar additions (almost double 2023’s figure). By 2025, U.S. solar capacity is on track to roughly double from pre-IRA levels, potentially reaching 180 GW or more. One notable trend is the geographic spread: while sunbelt states like Texas, California and Florida lead in new farms, projects are now blooming in the Midwest and Northeast as costs drop. Massive desert installations are underway (Nevada’s 690 MW Gemini project, paired with batteries, will be the nation’s largest once online). Yet the U.S. solar boom faces growing pains familiar in Europe – namely, lengthy interconnection queues and insufficient transmission. SEIA warns that grid bottlenecks have become the main constraint on long-term growth. Even so, the outlook for solar is sunny: the technology has achieved an 80-year first in America by outpacing all rivals in new capacity, and continued cost declines plus policy support make it central to utility strategies. Utilities and power producers are increasingly replacing coal plants with solar farms (often coupled with batteries) to meet clean energy mandates.
In Canada, solar is a smaller but rising part of the mix, especially in provinces like Alberta where ample sun and open land have led to a spike in utility-scale projects. Canadian developers added a few gigawatts of solar in 2023–24, and the federal government’s 2023 clean investment tax credits are set to further boost photovoltaics, aiming to mirror the IRA’s impact north of the border.
Grid-Scale Storage: Batteries Balance the System
As wind and solar capacity soars, investment in energy storage has taken off to keep grids balanced and resilient. Across Europe and North America, big batteries and other storage technologies are being rolled out at unprecedented scale, fundamentally reshaping grid strategy. Europe’s battery storage market in particular is booming. The continent added approximately 17.2 GWh of new battery storage in 2023 – a 94% increase over the previous year. This rapid growth, the third year in a row of roughly doubling, brought Europe’s total deployed battery capacity to around 36 GWh by end-2023. Once niche pilot projects, large-scale batteries are now critical grid assets helping stabilize voltage and time-shift renewable energy.
Germany, Italy and the UK have led utility-scale installations, connecting systems of 100 MW+ that can respond in milliseconds to fluctuations. Meanwhile, thousands of smaller batteries in homes and businesses – especially in solar-heavy countries like Germany – have created a sizable behind-the-meter resource. Analysts note that Europe’s battery boom is enabled by supportive policy and falling costs. By 2024, average system costs for big battery projects had fallen ~28%, and new EU rules ended “double taxation” and other regulatory barriers for storage. Many EU countries launched capacity auctions specifically for storage or integrated batteries into renewables tenders, ensuring revenue streams for investors. The result is a rapidly maturing market – one where batteries are not just backups but key enablers of a renewables-based system.
Major projects illustrate the trend: in 2022 Britain installed a 98 MW two-hour battery (using Tesla Megapacks) at the North Sea wind hub of Dogger Bank to help firm its huge offshore turbines. In 2024, Italy and Spain began procurement of multi-hundred-MW storage plants as they confront solar “duck curve” effects. Still, Europe will need far more storage. The European electricity lobby Eurelectric said in 2025 that “more energy storage [is] needed to maintain grid stability” as renewables grow. Pumped hydro storage – the continent’s traditional reservoir of flexible power – is also seeing renewed interest, with expansions in the Alps and Iberia under study. All told, Europe is forecast to install an additional 20–30 GWh of batteries annually in the coming years, putting it on a path to well over 100 GWh by 2030.
The United States has likewise entered the battery big leagues. In 2023 the U.S. commissioned around 6.4 GW of new large-scale battery capacity (mostly 4-hour lithium-ion systems), a 70% jump from the previous year. This brought total installed battery power to ~15.5 GW by end-2023, concentrated in high-solar states like California and Texas. Driven by the same needs – smoothing solar output and replacing gas peakers – developers plan to nearly double U.S. battery capacity in 2024 alone, with 14.3 GW slated for installation. The Inflation Reduction Act has supercharged this sector by providing, for the first time, an investment tax credit specifically for stand-alone storage. Previously, batteries only got federal support if paired with solar now developers are free to deploy storage wherever the grid needs it. The response has been dramatic: Texas and California each have multi-gigawatt pipelines underway. In Texas’s ERCOT grid, big batteries are being built at wind and solar sites and even old fossil plant locations to provide fast frequency response and hedge against price spikes. California, a pioneer with its 2019–2022 storage procurements, this year approved another $6 billion of new lines and storage to integrate 40 GW of new renewables.
Notably, the U.S. is combining solar and batteries at scale – the forthcoming Gemini plant in Nevada will marry 690 MW of PV with 380 MW of storage to deliver evening power. Similar “solar+storage” hybrids have become the default for many new projects in the desert Southwest. By providing peak power after sundown, these batteries are already helping prevent blackouts during heatwaves that strain the grid at dusk. The U.S. storage boom also includes emerging technologies: several long-duration pilot projects (like 8-hour iron-air batteries and compressed air storage) broke ground in 2023, backed by Department of Energy demo grants. And at the distribution level, utilities are installing community battery banks and even exploring vehicle-to-grid solutions, albeit in early stages. Canada is following suit, especially in Ontario where nuclear refurbishments and rising demand have created capacity gaps. In 2023–24 Ontario’s grid operator procured nearly 2.9 GW of new battery storage – the largest such procurement in Canadian history. Winning projects ranged up to 400 MW each and will deliver at least 4 hours of backup supply, with completion by 2027. The province’s energy minister noted the average cost of storage came in below that of new gas turbines, cementing batteries as “the most affordable new capacity resource… period” according to industry groups. This mirrors a broader strategic shift: storage is no longer seen as a high-cost add-on, but as a central tool for grid reliability and renewable integration. While challenges remain – supply chain constraints for battery materials and the need for advanced grid management – the momentum is unmistakable. Major utilities and power producers are now planning storage at scale in resource plans, marking a critical evolution in the power sector’s approach to flexibility.
Green Hydrogen: The Next Frontier
Once dismissed as perpetually a decade away, green hydrogen has in 2023–2025 moved into concrete development plans as Europe and North America seek to decarbonize hard-to-electrify sectors. The European Union is leading the charge in hydrogen investment and policy. Faced with the need to replace natural gas and store renewable energy seasonally, the EU set a target to produce 10 million tonnes of renewable (“green”) hydrogen annually by 2030 (and import another 10 million tonnes) – a goal established under its 2022 REPowerEU plan. To spur progress, Brussels created a European Hydrogen Bank in 2023, a novel funding mechanism to subsidize early green hydrogen projects. The first EU-wide auction under this program, launched late 2023, drew 130+ bids from electrolyzer projects across 17 countries – oversubscribed by a factor of 15 for the €800 million on offer. In early 2024, the EU awarded €720 million to seven winning projects, which together pledged to produce 1.58 million tonnes of green H₂ over 10 years. While modest relative to the 2030 ambitions, this pilot provided a price signal (winning bids were around €4–5 per kg of hydrogen) and will bring several hundred megawatts of electrolyzers into operation mid-decade. Individual European countries are also heavily supporting hydrogen. Germany, for instance, approved billions in 2023 for domestic H₂ infrastructure and launched its own tenders for electrolysis capacity. France and the Netherlands are investing in gigawatt-scale projects linked to offshore wind farms, aiming to create “hydrogen valleys” where green hydrogen feeds local industry and heavy transport. Even countries without a history of hydrogen are joining: Portugal and Spain, blessed with cheap solar, plan to export green ammonia (a hydrogen carrier) to Northern Europe, and a new hydrogen pipeline (H2Med) is on the drawing board to connect the Iberian Peninsula to France by 2030. A pan-European hydrogen pipeline network – the European Hydrogen Backbone – is gradually taking shape as gas TSOs repurpose old pipelines and plan new ones to carry H₂ across borders. In parallel, EU regulators in 2023 finalized long-awaited rules defining “renewable hydrogen” (additionality and time-matching requirements for the power used in electrolysis), providing clarity that unlocks investment. All these steps reflect a strategic view that hydrogen will be vital for decarbonizing sectors like steel, chemicals, long-haul transport, and balancing the grid in winter. As Europe’s energy chief Kadri Simson put it, green hydrogen is moving “from plans to projects” as the EU strives to maintain its lead in what could be a trillion-euro market.
In North America, hydrogen is also a strategic focus, albeit with a different approach emphasizing regional hubs and diverse production methods. The United States in 2023 launched a $7 billion program to kick-start “clean hydrogen hubs” across the country. In October 2023, the Biden administration selected seven regional hydrogen hubs spanning 16 states to receive this funding. These hubs – clusters of producers, infrastructure, and end-users – aim to collectively output over 3 million metric tons of clean H₂ per year by 2030, roughly one-third of the U.S. target for that date. They also promise to leverage more than $40 billion in private investment alongside the federal grants. The chosen hubs reflect a mix of technologies and regions: for example, a Mid-Atlantic hub (Pennsylvania-led) will make hydrogen from renewable and nuclear-powered electrolysis to supply industries, while an Appalachian hub (West Virginia) will produce “blue” hydrogen from natural gas with carbon capture, tapping the area’s gas reserves. California’s hub focuses on electrolytic hydrogen for heavy-duty transport, and a Gulf Coast hub in Texas will use both natural gas and renewables to create a hydrogen supply chain for refining and petrochemicals. By backing multiple pathways (green, blue, and even nuclear H₂), the U.S. hopes to drive down costs and demonstrate end-use cases in trucking, fertilizer production, and power generation. Crucially, the Inflation Reduction Act’s separate hydrogen production tax credit – up to $3 per kg for green hydrogen – has drawn significant private plans. Numerous projects were announced in 2023 to build electrolyzer factories (by companies like Plug Power, Nel and Siemens) in the U.S., aiming to capitalize on expected demand. Some solar and wind developers are now adding electrolyzers to produce hydrogen when power prices are low, potentially providing grid services. For instance, in Texas, a project is underway to use excess wind power at night to generate hydrogen for fuel cell trucks. Canada too is eyeing the hydrogen opportunity. A 2023 federal progress report tallied some 80 hydrogen projects announced across Canada, representing over $100 billion in potential investment. Canada’s strategy leans on its ample hydropower (for green H₂) and natural gas (for blue H₂ with CO₂ storage in Alberta’s geology). The country signed a high-profile deal with Germany in late 2022 to begin exporting green hydrogen/ammonia from Atlantic Canada by mid-decade, and by 2025 the first such project (in Newfoundland) is expected to start production. Provinces like Alberta and Quebec have each launched hydrogen roadmaps and pilot programs – Alberta is testing hydrogen blending into gas-fired power plants, while Quebec is building electrolyzers to make hydrogen for local industry using surplus hydroelectricity. One eye-catching venture is a proposed transatlantic shipment of hydrogen: an Newfoundland project plans to convert wind power to ammonia and ship it to German customers, illustrating the global linkages forming.
Both Europe and North America recognize that widespread hydrogen use is not without challenges. Costs remain significantly higher than incumbent fuels, infrastructure is nascent, and questions persist about the most efficient use of H₂ (where direct electrification isn’t feasible). Nonetheless, strategic policy bets are being placed now to ensure hydrogen has a foothold by the late 2020s. As the White House stated, advancing clean hydrogen is “essential to… a strong clean energy economy” for hard-to-decarbonize sectors. Early investments – whether Europe’s hydrogen bank auctions or America’s regional hubs – are intended to scale up electrolyzer manufacturing, drive down the cost per kilogram, and solve distribution logistics. By mid-2025, the momentum is unmistakable: hydrogen has moved from theory to practice, with governments, heavy industry, and energy firms all positioning for a future where H₂ complements electricity in the clean energy puzzle.
Grid Infrastructure and Integration: Wiring a New Era
All of these developments – surges in renewable generation, the revival of nuclear, and the promise of new energy carriers – ultimately hinge on one often-overlooked element: the power grid. From early 2023 to mid-2025, a clear consensus emerged that Europe and North America must invest massively in transmission and distribution infrastructure to support the evolving energy landscape. The challenge is formidable. Much of Europe’s electric grid dates to the mid-20th century half of EU high-voltage lines are over 40 years old. These aging networks were not designed for today’s distributed renewables or the rising demand from electrified transport and heating. The need for modernization became starkly apparent in April 2025, when Spain and Portugal suffered their worst blackout in decades. While investigation into the cause was ongoing, it served as “a wake-up call” on grid vulnerabilities. “It showed that the need to modernise and reinforce Europe’s electricity grid is urgent and unavoidable,” said Kristina Ruby, secretary-general of Eurelectric, the European power industry group. Her warning is backed by sobering analysis: global investment in renewables has nearly doubled since 2010, but investment in grids has stagnated around $300 billion per year. According to the International Energy Agency, grid spending needs to double to over $600 billion per year by 2030 to handle the clean energy buildout. For Europe specifically, the European Commission estimates a whopping $2 trillion (roughly €1.8 trillion) in grid investment will be required by 2050. Already, annual grid spending is rising – EU utilities invested about €80 billion in 2022, up from €50–70 bn in prior years – but this may need to reach €100 billion or more consistently.
A key focus is strengthening interconnections between countries and regions. Robust cross-border links can provide critical backup and smooth out renewable variability. The EU has set a target for each member state to have interconnections equal to at least 15% of its domestic generation capacity by 2030 (up from a 10% target earlier). Progress is underway: for example, Spain – long an “energy island” – is doubling its grid ties to France via a new Bay of Biscay submarine cable, which will help integrate Spain’s surging wind and solar output. Several new interconnectors are being built in Northern Europe too, linking offshore wind hubs. The Viking Link between Denmark and Britain (1.4 GW) is nearing completion, and ground was broken on NeuConnect, a 725-km cable directly linking Germany and the UK, slated to carry 1.4 GW by late decade. In the North Sea, plans for hybrid “energy islands” and meshed offshore grids took shape in 2023, aiming to allow giant wind farms to send power to multiple countries efficiently. Europe is also beefing up internal transmission: Germany, for instance, is constructing high-voltage DC “autobahns” from its windy north to industrial south (the SuedLink and SuedOstLink, each well over 500 km, finally started construction after years of permitting delay). Italy is upgrading north-south lines to transmit solar from the south and hydro from the Alps. And in Eastern Europe, the Baltics are synchronizing their grid with the rest of the EU and building new links (like the Harmony Link to Poland) to replace dependence on Russia’s grid.
In the United States, the grid challenge is equally pressing. Ambitious clean energy goals have exposed the bottleneck of an inadequate transmission network, especially to carry wind and solar from remote regions to cities. A Department of Energy study in 2023 warned that the U.S. may need 20,000 new gigawatt-miles of transmission by 2035 – a 57% expansion of the current system – to meet its renewable targets. Yet building long-distance lines in America is notoriously slow and contentious, often taking a decade or more. Despite this, some major projects achieved milestones over the past two years. In the western states, two of the nation’s largest transmission lines, stalled for years, finally moved forward: the TransWest Express, a 732-mile 3 GW HVDC line from Wyoming to Nevada (carrying wind power to California markets), began construction in late 2023. And SunZia, a 550-mile line to bring 3 GW of New Mexico wind to Arizona, secured its final federal approvals in 2023 after 15 years of development wrangling. These “mega-lines” will unlock gigawatts of stranded renewable potential. Likewise in the Midwest, projects like Grain Belt Express (a planned 800 mile HVDC from Kansas to Indiana) made permitting gains, and in the Northeast, the long-delayed Champlain Hudson power link from Quebec to New York City moved into construction, promising to deliver 1 GW of Canadian hydropower by 2026.
Federal regulators and lawmakers are pushing reforms to accelerate such projects – for instance, FERC issued Order 2023 to streamline generation interconnection processes, and debates continue in Congress about granting federal siting authority for interstate lines. The 2021 Infrastructure Law injected funding as well: it created a $2.5 billion Transmission Facilitation Program and provided grants for grid resiliency and “Smart Grid” investments. By mid-2025, DOE had begun allocating these funds to upgrade key bottlenecks, often in partnership with grid operators. In one example, the U.S. West’s grid operator (CAISO) approved a $7 billion suite of new lines in 2023 to bolster connections with other states and support 40 GW of planned renewables.
Upgrading distribution networks is just as vital, if less high-profile. As millions of electric cars, heat pumps, and rooftop solar panels connect to local grids, utilities are investing heavily to improve reliability and flexibility at the low-voltage level. Europe has nearly completed its smart meter rollout (over 70% of EU households have a smart meter), enabling better demand management. EU distribution operators are deploying automation and digital sensors to handle bi-directional power flows from solar roofs and batteries. A report for the European electricity association in 2023 noted that investments in Europe’s distribution grids must double by 2050 to about €67 billion per year. In the near term, the focus is on integrating the wave of electric vehicle chargers – for instance, France and the UK introduced incentives for smart charging that lets EVs draw power when grid load is low, reducing strain. Some European cities are also experimenting with local energy storage and microgrids to enhance resilience. In North America, extreme weather has underscored the need for distribution resilience. Utilities in California, after devastating wildfires, are hardening their networks by insulating lines and even undergrounding hundreds of miles of wires in high-risk areas. PG&E alone started a program to bury 10,000 miles of distribution lines over several years. On the East Coast, storms like 2023’s hurricanes prompted grid operators to invest in stronger poles, flood protection for substations, and sectionalizing equipment that can isolate outages. Both the U.S. and Canada are also rolling out more advanced metering: as of 2023, over 65% of U.S. electricity customers had smart meters, a figure rising annually (Ontario and Quebec in Canada are near 100% metered). This data helps utilities identify outages faster and implement time-of-use tariffs that encourage off-peak consumption. Another notable trend is the growth of virtual power plants – aggregating rooftop solar, home batteries, and EVs to act as a coordinated resource. Pilot programs in California, Vermont and Toronto have shown these aggregations can shave peak demand and provide grid services, hinting at a future where the distribution edge supports the broader network.
Ultimately, the massive build-out of cleaner generation must be matched by a rewiring of the grid. Policymakers acknowledge this. The European Commission in October 2023 released an Action Plan to accelerate grid deployment, streamlining permitting and boosting financing for priority power lines. In the U.S., the Biden administration’s climate agenda increasingly emphasizes infrastructure: “Without significant reforms to speed up permitting, it will be impossible to build new renewable energy infrastructure in time,” warned a Brookings Institution expert in early 2024. Even the best-laid clean energy plans, it turns out, are only as good as the wires that tie them together. The period from 2023 to mid-2025 made that clearer than ever, through blackouts that exposed weaknesses and success stories where strong grids enabled record renewable usage. The coming years will see a concerted transatlantic effort to upgrade, expand, and modernize electricity networks – a foundational but complex task akin to reconstructing the highways of the power system. These investments, costly as they are, underpin every other element of the energy transition. As Europe’s recent scare in Spain showed, a 21st-century grid is no longer optional if the lights are to stay on in a zero-carbon world.
