That growth is landing on a grid the Department of Energy already says faces aging infrastructure and insufficient transmission capacity. Utilities and grid operators are racing to add capacity fast enough to keep up, on both the power plants themselves and the wires that carry what they produce.

Data centers are driving most of the new demand

US electricity consumption stayed nearly flat for two decades, then started climbing again. The Energy Information Administration now forecasts average growth of 1.7% a year from 2020 through 2026, enough that 2025 and 2026 are both projected to top the prior high set in 2024. The commercial sector, which includes data centers, is growing faster than that average, at 2.6% a year over the same stretch, alongside industrial growth from manufacturing, all drawing on the same grid you plug into every day.

A data center is a warehouse of server racks running around the clock, plus the chillers and fans needed to keep them from overheating. The building might sit somewhere you’ll never see, but the electricity to run it comes out of the same grid that powers your house, drawn from the same power plants and the same substations that serve everyone else nearby.

How much power data centers actually use

US data centers used 176 terawatt-hours of electricity in 2023, about 4.4% of total US consumption that year, according to Lawrence Berkeley National Laboratory, on the same grid that reaches your own house. The lab’s 2028 projection spans a wide range. It runs from 325 to 580 terawatt-hours. That range equals 6.7% to 12.0% of the country’s forecast electricity use that year, because so much depends on how many GPUs ship and how efficient the cooling gets.

Globally, data centers used about 415 terawatt-hours in 2024, 1.5% of the world’s electricity, with the United States accounting for 45% of that global total, according to the International Energy Agency. The IEA expects global data center electricity use to more than double to around 945 terawatt-hours by 2030.

Grid operators are already flagging the strain

NERC’s 2025 summer reliability assessment flagged MISO as being at risk of running short on reserves during high demand, and named ERCOT for evening hours when solar output fades. New England drew a warning about supply shortfalls under extreme conditions, and the Southwest Power Pool region about energy shortfalls when demand is high and wind is low. In the Southeast, utilities told NERC that peak demand rose about 2% that summer, citing economic growth and data mining loads as drivers alongside other industry.

When NERC flags this kind of risk in your region, it can mean a request to ease up on air conditioning during a hot evening, or in a serious shortfall, a rolling outage. The pressure is concentrated in specific places. NERC’s longer-range assessment has MISO projecting 18 gigawatts of data center load by 2035, while ERCOT expects 23 of its 45 gigawatts of large loads asking to connect by 2030 to be data centers.

Demand forecasts keep climbing, unevenly

Utilities themselves keep raising their own numbers. Grid Strategies, which compiles utility forecasts every year, found the national load forecast reached 166 gigawatts of growth by 2030, a six-fold jump from the flat growth utilities had forecast back in 2022. The EIA’s September 2026 outlook projects US electricity consumption of 4,135 billion kilowatt-hours in 2026 and 4,211 billion in 2027, attributing the growth to data center development and manufacturing.

Not every regional forecast has moved in the same direction, though. The EIA cut its 2026 US generation growth forecast to 1.7%, down from an earlier estimate of 3%, after large loads came online slower than expected. ERCOT’s own 2026 growth forecast dropped from 15.7% to 9.6%, because of a pause in connecting new data center projects to the Texas grid. If you get your power through ERCOT, that pause is part of why your own region’s growth forecast got cut nearly in half.

Old transmission lines are the bottleneck

The Department of Energy’s National Transmission Needs Study puts a number on what catching up requires. Under its high load growth scenario, within-region transmission capacity needs to grow 128% by 2035 compared with 2020, and capacity to move power between regions needs to grow 412%, more than fivefold. Picture the high-voltage towers and transformers strung across the country decades ago, now asked to carry loads their designers never planned for.

The need isn’t spread evenly. The same DOE study breaks this out by region. Texas would need 140% more transmission capacity by 2035, the Plains 119%, and the Midwest 112%.

Texas and the Midwest, covered above through ERCOT and MISO, are two of the same regions already citing heavy data center growth. If your state is one of those three, this is the specific bottleneck grid planners are racing hardest to fix.

Solar and battery projects are exposed here too. Transmission bottlenecks are one reason a grid can only absorb so much wind and solar before reliability questions come up, regardless of how cheap the panels get.

The strain already shows up in your electricity bill

PJM, which runs the grid for a large stretch of the mid-Atlantic and Midwest, holds an annual auction that pays power plants to be available for future years. Its 2028/2029 auction cleared at $325 per megawatt-day, a bit below the prior year’s price cap of $333.44 per megawatt-day but still the third straight auction to hit the FERC-approved ceiling.

If you live in PJM’s territory, those capacity payments flow into the delivery charges on your electric bill, years before the power itself gets delivered. The high, capped price is itself a signal that the region doesn’t have enough spare generation bidding into the auction to push the price down on its own.

Reconductoring old towers is the fastest fix on the table

The Department of Energy launched its Speed to Power initiative on September 18, 2025, aiming to shorten the years it typically takes to permit and build large transmission and generation projects. One piece of it, called SPARK, put up about $1.9 billion for reconductoring and other upgrades to existing transmission lines, with a concept paper deadline of April 2, 2026 for the first round of applicants.

Reconductoring existing towers with higher-capacity cable adds capacity without waiting years for new rights of way, using the same towers already standing over highways and backyards across the country. On the supply side, the EIA expects solar generation to grow 92% in ERCOT and 63% in PJM between 2024 and 2026, adding supply on a timeline utilities control directly.

One option skips the wait entirely. Smart meters and demand response programs already pay you to cut usage during the same peak hours that strain the grid, whether or not your region’s transmission upgrades get picked for DOE funding.

How much banks lend to fossil fuel companies

Banking on Climate Chaos is now in its 17th edition. The report’s authors include Rainforest Action Network and BankTrack, and its co-authors include Oil Change International and Sierra Club. Together they count $8.7 trillion in bank financing since the Paris Agreement was signed a decade ago. Twelve banks, which the report’s authors label the “Dirty Dozen,” provide close to 40% of that financing, even though roughly 2,000 banks worldwide do some fossil fuel lending.

JPMorgan Chase was the largest single fossil fuel financier in 2025, at $58 billion, up 12.6% from 2024. Bank of America and Japan’s Mitsubishi UFJ Financial Group tied for second, at $47 billion each, with MUFG’s total up 21% from 2024. If your paycheck or mortgage runs through a US bank, you have more of a stake in this than you did a few years ago. Banks in the US supplied 32% of all global bank fossil fuel financing in 2025, up from 28% in 2021.

Financing aimed at expanding fossil fuel production grew even faster than the overall total. Money for companies actively expanding oil, gas or coal climbed 27% to $508 billion in 2025. Financing for new coal mines alone surged 77% to $84 billion in 2025. Coal power plant expansion financing rose 40% to $81 billion over the same year, even as coal’s place in the US power mix keeps shrinking.

How that financing works

A bank can lend to a fossil fuel company directly, through a corporate loan or a revolving credit line it draws on to cover drilling, pipelines or day-to-day costs. A bank can also underwrite the company’s bonds and shares, meaning it arranges the sale to investors and collects a fee instead of holding the debt itself.

You already know how the revolving line works if you carry a balance on a credit card. The company draws down what it needs for a delivery of drill pipe or a month of payroll, then pays interest on that draw until it settles the balance.

The report adds up both kinds of deal for the banks it tracks, whether the money funds a company’s general operations or one specific project like a pipeline or an LNG export terminal. That’s why a single bank’s yearly total can mix a loan that keeps an existing refinery running with underwriting for a brand-new gas terminal.

What climate campaigns want banks to do

Groups behind the report want banks to end fossil fuel expansion financing entirely. “Voluntary commitments aren’t working,” said David Tong of Oil Change International, one of the report’s co-authors, who wants governments to force change through binding rules instead of bank pledges. If you’re trying to sort real lending cuts from bank messaging, Lucie Pinson of Reclaim Finance, another co-author, pointed to BNP Paribas and Crédit Agricole as banks whose restrictions on financing new oil and gas fields have translated into real cuts in lending.

Street protests have targeted this financing directly. On September 20, 2025, a coalition led by 350.org and Women’s March held nationwide “Make Billionaires Pay” marches in cities across the US. The largest march, in New York City, was timed to the United Nations General Assembly meeting that same week, and demands included a shift away from fossil fuels alongside higher taxes on extreme wealth.

Why the Net-Zero Banking Alliance collapsed

The Net-Zero Banking Alliance started in 2021, when former Bank of Canada governor Mark Carney set it up as a UN-sponsored group pushing banks toward net-zero emissions by 2050. It grew from 43 founding banks to more than 120 members across 40 countries.

Then, starting in December 2024, big banks began leaving. Six US banks, including Goldman Sachs, Wells Fargo, Bank of America, Citigroup, Morgan Stanley and JPMorgan Chase, departed between late December and early January, before Donald Trump’s second-term inauguration on January 20, 2025. Canada’s six largest banks left by the end of that month.

The UK’s HSBC and Barclays left NZBA in July 2025, and Switzerland’s UBS followed in August. Around the same time, Republican-led states led by Texas sued BlackRock, Vanguard and State Street, arguing the asset managers had used climate goals to violate antitrust law by cutting coal production and driving up the power prices you and other customers pay.

In April 2025, NZBA dropped the requirement that members align their financing with limiting warming to 1.5 degrees Celsius, calling the update “version 3” of its guidance. Dutch bank Triodos left over the change, saying the new rules “fall short of the needed urgency.”

NZBA members then voted on October 3, 2025, to immediately cease operations and shift to a guidance-only framework instead of staying a formal membership group. Jeanne Martin of the investor-advocacy group ShareAction called the vote “bitterly disappointing”, while an NZBA spokesperson said its climate target-setting guidance would stay public for banks to use on their own. NZBA was the second UN-aligned net-zero industry group to shut down in 2025, after the Net Zero Asset Managers initiative suspended its work when BlackRock left it in January.

How individual banks have responded

Some banks pulled back their own climate rules once NZBA fell apart. JPMorgan Chase and Goldman Sachs dropped their coal and Arctic drilling exclusions entirely, replacing them with case-by-case reviews instead of blanket bans. Of the 15 North American banks the Banking on Climate Chaos report tracks, 12 now have no meaningful fossil fuel financing commitments left.

Not every bank moved the same direction in 2025. The table below shows how six banks’ fossil fuel financing changed from 2024 to 2025, based on the same report.

Source: Banking on Climate Chaos 2026, Rainforest Action Network et al.

If you bank with UBS, BNP Paribas or La Caixa, your money moved the other way. Those three banks cut fossil fuel financing by 28% to 36% in 2025.

Apart from fossil fuel lending, Citi has committed $647.2 billion toward its $1 trillion sustainable finance goal since 2020, including $91.3 billion in 2025. Citi CEO Jane Fraser said in the bank’s 2026 sustainability report that clients now treat business resilience as “a competitive necessity.” That goal funds a mix of environmental and social projects and sits apart from the bank’s fossil fuel lending, which the report tracks on its own.

COP30 kept climate finance voluntary too

COP30, held in Belém, Brazil, in November 2025, produced a similar split between voluntary and binding rules. Countries agreed to work toward tripling adaptation finance and raising climate finance toward $300 billion a year by 2035, a goal first set at COP29 in Baku, but a push for a binding fossil fuel phase-out plan ended up as a voluntary “roadmap” sitting outside the formal UN process instead.

This financing data follows the same shape. Big banks left the Net-Zero Banking Alliance instead of keeping a shared climate commitment, and negotiators at Belém picked a voluntary roadmap over binding fossil fuel rules. If you want to see whether that pattern holds, how UN climate conferences work walks through what past summits delivered against their own pledges.

A Mitsubishi-led consortium walked away from 1.7 GW of projects it had already won, telling investors in August 2025 that the numbers no longer worked. The government has spent the months since rewriting its own auction rules and opening a much larger stretch of ocean to the floating turbines it’s counting on to close the gap.

How much offshore wind Japan has now

Japan’s offshore fleet is still mostly a short list of fixed-bottom wind farms bolted to the seabed near port cities. The newest and largest is Ishikari Bay New Port, which added 99.9 MW in January 2024. Before that came Akita Port’s 54.6 MW in January 2023 and Noshiro Port’s 84.0 MW in December 2022.

Picture your own town’s harbor with a turbine bolted into the seabed. That’s already true at Akita Port and Noshiro Port, both running commercial wind farms.

Two much smaller floating turbines have been running even longer, a 2 MW unit off Sakiyama since April 2016 and a 3 MW unit at Hibiki since May 2019, both demonstration projects instead of commercial wind farms. Add every fixed and floating site together and Japan had 253.4 MW running nationwide at the end of 2024.

Japan’s list of operating wind farms

Source: Japan Wind Power Association, data through the end of 2024, plus offshoreWIND.biz on the Goto wind farm’s January 2026 start.

Why floating turbines matter here

A steel and concrete cylinder floats upright offshore Fukue Island, held in place by mooring lines instead of a foundation driven into the seabed. That’s Toda Corporation’s Goto wind farm, which reached commercial operation on January 5, 2026 with eight Hitachi turbines totaling 16.8 MW. The site sits in water 120 to 135 meters deep. It’s also 7 to 11 kilometers offshore, too deep and too far out for the fixed-bottom foundations used at Noshiro Port and Akita Port.

If deep water rules out a fixed foundation on your own project, this design is already running commercially at Goto.

The consortium calls its steel-topped, concrete-bottomed hull a hybrid spar and says it’s the first commercial use of the technology anywhere. Getting there took longer than planned. A defect found in the floating structure during construction pushed the start date back from January 2024 to January 2026, a change METI approved on September 22, 2023. The wind farm will sell power at 36 yen per kWh through December 2043.

How the government’s auctions work

Japan opened its coastal waters to wind developers when the Sea Area Utilization Act took effect in April 2019. As written, the law’s promotion zones covered only Japan’s territorial and inland waters. Regulators had already flagged four zones for fast-tracking by July 2019, the Akita and Chiba sites that later became Round 1, plus Goto in the south.

Under the feed-in tariff auction that followed, developers bid low prices to win a site, then get paid that fixed rate for years. In Japan’s first auction round, a Mitsubishi-led consortium won all three Akita and Chiba sites in December 2021, bidding 11.99 to 16.49 yen per kWh, well under the 29 yen ceiling the government had set. Those low bids left the projects almost no room to absorb what came next.

The mechanism behind Japan’s auctions works a lot like a fixed-rate deal on your own utility bill, a price locked in for years no matter what fuel costs or the yen does later.

What went wrong for Mitsubishi

Mitsubishi Corporation said in its August 27, 2025 announcement that it would not proceed with any of the three sites, citing tight supply chains, inflation, exchange rates and rising interest rates since its 2021 win. By the time the company pulled out, costs had more than doubled and total investment passed 1 trillion yen. If you own Mitsubishi Corporation shares, that reversal already hit the numbers you’d see in its filings, a 52.2 billion yen impairment, on top of as much as 20 billion yen in penalty payments for abandoning sites it had already secured.

The inflation behind that reversal shows up across Japan’s construction sector. Average offshore wind construction costs there rose 20% between fiscal 2020 and fiscal 2024, compared with an 8.5% rise in consumer prices over the same years. The yen has made imported equipment costlier too, falling 109.78 in 2021 to 151.50 in 2024 per dollar, a 38% drop. On top of that, Japan has no domestic manufacturer of large offshore wind turbines, so every project leans on imports exposed to that weaker yen.

Permitting adds years developers in other markets don’t lose. A fixed-bottom project in Japan can take 6 to 8 years to build, versus 2 in the EU, which caps its own permitting timeline. If you’re financing the project, you feel that gap directly, years of carrying costs before a single turbine turns.

The rule changes underway

Auction rules changed too. Starting with Round 4, new rules from January 2025 let developers pass up to 40% of cost inflation through to the electricity price between winning a site and starting construction. The same reform doubled the bid bond, from 13,000 to 24,000 yen per kilowatt, meant to discourage the kind of aggressive bidding that sank Mitsubishi’s sites.

A second round of measures in November 2025 added 20 years of guaranteed capacity revenue for zero-premium projects from Rounds 2 and 3, through a separate power auction, on top of allowing developers to swap in a new turbine supplier if theirs backs out.

Turbine makers outside Japan are the ones who gain from that swap-in rule. If a developer’s original supplier drops out mid-project, this is the rule that lets your factory step in instead.

Regulators also went after the map itself. On March 7, 2025, the Cabinet approved a bill letting developers build in Japan’s exclusive economic zone as well as its territorial waters, and parliament passed it in June 2025. That water tends to run deeper, which is exactly the depth floating designs like Goto’s are built for.

Whether Round 4 avoids Round 1’s mistake

The government postponed Round 4, originally planned for October 14, 2025, to work out why the Round 1 developer walked away before opening a new round to the same risks. Officials are also weighing whether to reauction Mitsubishi’s three abandoned sites under the new rules. If that’s your market, that reauction decision is the one to plan around.

Floating wind’s record in Japan includes NEDO’s 7 MW demonstration turbine off Fukushima, which went up in July 2015 and was towed away for dismantling in May 2020 instead of joining the operating fleet.

Not every project is waiting on that outcome. The Round 3 winners off Aomori and Yamagata are both targeting commercial operation in June 2030 using Siemens turbines, and Tohoku Electric’s Aomori site is moving ahead too. Whether Japan reaches its 10 GW target for 2030 depends on whether the rewritten auctions produce bids that survive construction, unlike the ones Round 1 cleared only on paper.

For more on the technology behind these projects, see how offshore wind power works generally, and how wind power growth compares across countries.

If you get a bill from BGE, you’re already feeling it. The delivery rate alone is up 30% since 2020, and Exelon CEO Calvin Butler wants state lawmakers to let his company build new power plants of its own to bring supply costs down.

The supply side is what’s pushing bills up

Butler says about 80% of recent bill increases in Exelon’s territory came from power supply costs. Delivery charges, the part a utility controls directly, climbed too, though by less. BGE’s distribution rate is up 30% since 2020 and has run at about twice the rate of inflation since 2010, according to Maryland’s Office of People’s Counsel.

Regulators are also letting utilities earn more on that delivery business. Pepco’s October 2025 Maryland rate filing requested a 10.50% return on equity, the regulated profit a utility earns on its wires investment. For a Pepco customer, that 10.50% return is money built into your delivery bill before the company builds a single power plant. Butler argues that same guaranteed, regulated return is what makes utility-built power plants cheap to finance compared with a merchant generator borrowing at market rates.

Data centers and new demand are straining the system

The supply side is under pressure because demand is climbing. The Energy Information Administration expects US electricity use to keep rising through 2027, the strongest four-year growth stretch since 2000. Data centers are the biggest reason EIA cites. They used 176 terawatt-hours of electricity in 2023, or 4.4% of all US electricity, and the Department of Energy’s Lawrence Berkeley National Laboratory projects that share could reach 12% by 2028.

In 2025, PJM’s own summer forecast put peak demand at over 154,000 megawatts, against roughly 179,200 megawatts of available capacity. For the first time in PJM’s own assessment, supply could fall short of reserves in an extreme scenario reaching an all-time peak above 166,000 megawatts. If PJM hits that 166,000-megawatt scenario, the reserve margin that’s supposed to keep your lights on during a heat wave gets thin.

PJM answered with a one-time Reliability Resource Initiative that added more than 9,300 megawatts of new capacity to a grid already under strain, most of it online by 2030.

What PJM’s capacity auctions show

PJM’s annual capacity auction pays power plant owners years ahead of time to promise they’ll be available, and every plant in a pricing zone gets paid the same cleared price no matter what it bid. That price cleared at $269.92 per megawatt-day for the 2025/2026 delivery year across most of the footprint, then jumped to $329.17 for 2026/2027, which PJM itself calls the FERC-approved price cap.

The two auctions since then eased. They cleared at $333.44 for 2027/2028 and, most recently, $325.00 for 2028/2029, with every zone landing at that same price and none of them short enough to need a higher local rate.

New Jersey called the run-up to that first spike an 833% increase and set a $325 price ceiling and $175 floor on future auctions. It also funded a $430 million relief package that sent $100 to every one of its 3.9 million residential customers, so if you’re one of them, that check already landed. That’s a state government spending money to soften a price its own capacity market produced, part of why utilities are pointing at the market’s design itself.

The case for letting utilities build again

Exelon hasn’t owned a power plant since it spun off Constellation Energy on February 2, 2022, and Maryland’s wires-only rule for utilities traces to a 1999 restructuring law that let the state’s utilities sell off their generating stations. That split is why BGE and Pepco own the poles, substations and transmission lines that carry power to a house, but nothing that generates it, and it’s the rule Butler wants changed.

Butler’s case rests on financing. He says Exelon’s return on assets runs about 9.5%, roughly half what he says independent power plant owners earn, and argues a regulated utility can borrow more cheaply and build faster because it already owns land and interconnection rights near its wires.

If regulators say yes, the profit behind that 9.5% return comes out of the same bill you pay every month. “We have inadequate supply to meet this rising demand, and until we address that issue, all of our bills are going to continue to go up,” Butler said in April 2026.

Butler frames the scale as historic. He said in December 2025 that the industry hasn’t seen load growth “of this magnitude” in “probably the last four decades,” and utilities nationwide plan to spend $1.1 trillion on infrastructure over the next five years to keep pace. Exelon’s own results give him room to make the case. The company’s net income reached $2.8 billion in 2025, up from $2.5 billion in 2024.

The case against it

Consumer advocates read the same numbers differently. John Howat of the National Consumer Law Center says growth like this makes utilities see “dollar signs,” and that isn’t the same as the public interest. Maryland’s People’s Counsel, David Lapp, says utility ownership lets a company “grow their profits by expanding their businesses into generation so they can shift risks on the ratepayers.” New Jersey’s rate counsel, Brian Lipman, makes the same point about shifting risk from developers onto the people paying the bill.

If regulators do shift that risk onto ratepayers, it lands on the same delivery line that’s already up 30% since 2020 on a BGE bill.

Independent power producers reject Butler’s premise outright. LS Power’s Marji Philips said independent companies “were investing heavily in new plants,” disputing that the market is failing. The Electric Power Supply Association’s Todd Snitchler has warned lawmakers against “a reversal in policy and a return to the monopoly utility approach for generation,” and Advanced Energy United’s Amisha Rai argues the fix is more market competition.

Maryland chose a rebate over an ownership answer

State Sen. Kevin Harris tested the idea directly, introducing a bill in February 2026 that would have directed Maryland regulators to require at least one utility to build new generation, limited to storage, wind, solar, biofuels and hydropower. Senate President Bill Ferguson said lawmakers had “a level of skepticism” about whether it would save ratepayers money.

That bill didn’t pass. Maryland’s legislature instead passed a rate relief measure expected to cut residential bills by at least $150 a year, without authorizing any utility to own a power plant. If you’re a BGE or Pepco customer, that’s the concrete result so far: $150 a year off your bill, and no new power plant.

The ownership question itself is still unanswered. Butler has said he means to keep pressing lawmakers on it beyond Maryland, and PJM’s capacity auctions clearing above $325 a megawatt-day are the reason other state legislatures keep getting asked to take up the same fight.