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December 15, 2025

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Trump Executive Order Targets Renewable Energy Tax Credits

President Donald Trump issued an executive order July 7 targeting renewable energy tax credits as strongly as possible under the One Big Beautiful Bill Act. 

The law accelerates to 2026 the phaseout of the large tax credits created by the Inflation Reduction Act of 2022 in line with Trump’s strong opposition to renewables and support for fossil fuel. He signed it at a July 4 ceremony. (See related story, Trump Signs Big Beautiful Bill into Law on Independence Day.) 

The order, “Ending Market Distorting Subsidies for Unreliable, Foreign-controlled Energy Sources,” directs Treasury Secretary Scott Bessent to determine and then take all actions needed to terminate 45Y and 48E clean energy production and tax credits for wind and solar facilities. 

The OBBBA specifies construction start dates and safe-harbor provisions for the remaining period of eligibility for these tax credits, and Trump’s order directs that these rules not be circumvented by eligibility manipulation. 

Trump also directed prompt implementation of the bill’s enhanced restrictions on foreign entities of concern. And he directed Interior Secretary Doug Burgum to look for and eliminate any codified forms of preferential treatment for wind and solar over dispatchable energy sources. 

The reasons stated in a White House fact sheet are familiar speaking points for Trump and some of his Republican allies: 

    • Wind and solar are unreliable, denigrate the natural beauty of the American landscape and displace dispatchable energy, compromising the grid.
    • Reliance on green subsidies threatens national security by making the U.S. dependent on supply chains controlled by foreign adversaries. 
    • Ending these massive taxpayer subsidies is vital to energy dominance, national security, economic growth and the fiscal health of the country. 

Trump specifies that his order be implemented consistent with applicable laws. However, there may be some room for interpretation of the energy-related provisions of the 870-page OBBBA. 

Investment analysis firm Jefferies in a note to clients earlier July 7 said the House Freedom Caucus sought a strict interpretation by the administration of the “beginning of construction” provisions during negotiations as a condition for support. It said the concern now is whether the Trump administration will attempt to “change the goal posts” for these safe harbor provisions. 

The order directs the Interior and Treasury departments to report back within 45 days on their findings and the actions they have taken or planned. 

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NYISO Management Committee Briefs: June 30, 2025

The NYISO Management Committee passed two motions at its brief June 30 meeting, unanimously recommending that the Board of Directors approve them.

The committee recommended revisions to the ISO’s Joint Operating Agreement with PJM for the upcoming activation of a phase angle regulator at a new 345-kV Dover substation for approval. The project is part of the AC Transmission Segment B public policy transmission project, which is intended to reduce congestion between the Capital District and downstate. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

The committee also passed revisions to the NYISO tariff to implement transmission owners’ right of first refusal over upgrades in the reliability and economic planning processes. (See “Committees Approve Updates to ROFR Implementation,” NYISO BIC & OC Briefs: Week of June 16, 2025.)

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DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030

The U.S. Department of Energy released a report July 7 saying that retirements and delays in new firm capacity “will lead to a surge in power outages and a growing mismatch between electricity demand and supply,” especially from growth driven by data centers. 

The Report on Evaluating U.S. Grid Reliability and Security responds to President Trump’s executive order from April, which DOE used to keep open power plants in MISO and PJM that were set to retire in May. Trump’s order directed DOE to come up with a uniform method of studying resource adequacy. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

“This report affirms what we already know: The United States cannot afford to continue down the unstable and dangerous path of energy subtraction previous leaders pursued, forcing the closure of baseload power sources like coal and natural gas,” Energy Secretary Chris Wright said in a statement. “In the coming years, America’s reindustrialization and the AI race will require a significantly larger supply of around-the-clock, reliable and uninterrupted power. 

The report argues that “absent decisive intervention,” the grid will be unable to meet projected demand for manufacturing, re-industrialization and data centers, which make adversary nations control the future development of artificial intelligence, thus jeopardizing economic and national security. 

The status quo of additional generator retirements and “less dependable replacement generation” is not consistent with winning the AI race or maintaining reliability, the report said. “Absent intervention, it is impossible for the nation’s bulk power system to meet the AI growth requirements while maintaining a reliable power grid and keeping energy costs low for our citizens.” 

The report estimates an additional 104 GW are set for retirement by 2030, which is planned to be replaced by 209 GW, though only 22 GW of that is from “baseload sources.” Retirements and load growth combined could lead to 100 times greater risk in power outages by the end of the decade, the report said. 

“Antiquated approaches to evaluating resource adequacy do not sufficiently account for the realities of planning and operating modern power grids,” the report said. “At a minimum, modern methods of evaluating resource adequacy need to incorporate frequency, magnitude and duration of power outages; move beyond exclusively analyzing peak load time periods; and develop integrated models to enable proper analysis of increasing reliance on neighboring grids.” 

The report said it used a model based on NERC’s Interregional Transfer Capability Study, which uses time-correlated generation and outages based on historical data. It looked at a range of projections for data center demand by 2030 from major projects and picked a midpoint of 50 GW, allocating it regionally based on a forecast from Standard & Poor’s. 

The report includes several models, including one with the 104 GW of retirements that are in line with NERC and Energy Information Administration projections, another without power plant closures and a scenario with replacement capacity. 

The only regions that did not fail to meet reliability thresholds in the power plant retirement category were ISO-NE and NYISO, which are not expected to see additional data center growth. But every other region saw higher risks of outages in the closed power plant case. Even if all the power plants were to stay open, the report still found shortfalls in PJM, SPP and the Southeastern Electric Reliability Council. 

The report found that at least 23 GW of new “perfect capacity” is needed to meet future demand, especially in ERCOT and PJM (particularly in Virginia and Maryland). 

The report calculates unserved energy (USE) for different regions of the country based on its forecast supply and demand and found troublingly high levels of the metric in some regions for 2030. 

“It should be noted that USE is not an indication that reliability coordinators would allow this level of load growth to jeopardize the reliability of the system,” the report said. “Rather, it represents the unrealizable AI and data center load growth under the given assumptions for generator build outs by 2030, generator retirements by 2030, reserve requirements and potential load growth. These numbers are used as indicators to determine where it may be beneficial to encourage increased generation and transmission capacity to meet an expected need.” 

The report does not use common probabilistic measurements of resource, such as expected unserved energy (EUE) or loss of load expectation (LOLE), instead using deterministic equivalents. 

The report was released midafternoon July 7, so most people had limited time to review it. Advanced Energy United Managing Director Caitlin Marquis said it appears to exaggerate the risk of blackouts and undervalues the reliability contributions of wind, solar and battery storage. 

“We are working quickly to dig into the numbers to unpack how DOE reached its conclusions, but it’s troubling that the report was not subject to public input and scrutiny, especially since the executive order that mandated it calls for it to be used to identify power plants that should be retained for reliability,” Marquis said in a statement. “If the analysis is overly pessimistic about advanced energy technologies and the future of the grid, consumers will end up paying too much for resources we no longer need.” 

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NYISO Proposes ICAP Changes for New Entry Ahead of CHPE

NYISO on July 2 released its proposed changes to certain capacity market parameters to accommodate the Champlain Hudson Power Express transmission project, as well as facilitate the new entry of resources.

The changes, presented to the Installed Capacity Working Group, would see NYISO developing two sets of market parameters for capability years where “triggering resources” did not enter the market by May, the first month of the ISO’s capability year.

This would mean that NYISO would use an alternative set of market parameters as the foundation of the market until the resource begins participating. The ISO would run two installed reserve margin (IRM) studies: one assuming the new resource (in this case CHPE) is in service, and one assuming it is not. This would create two sets of transmission security limit (TSL) floors, locational capacity requirements, capacity accreditation factors, system translation factors, unforced capacity demand curve parameters and load-serving entity minimum capacity requirements.

CHPE is a 1,250-MW HVDC line that will run between Quebec and New York City and is expected to go into service in 2026 — but the exact date is unknown. NYISO is keeping an eye on its progress, but it is worried it will be mistimed with the beginning of the capability year. Most of the ICAP market is predicated on annual inputs, with limited seasonality. CHPE’s entry would have major implications for the reliability parameters in the New York City zone.

While NYISO does not anticipate CHPE to shift the IRM, it does anticipate the TSL floor to increase by about 4%, which would impact “downstream” parameters.

NYISO is also proposing that notice requirements for new capacity resources be changed so they must achieve commercial operation prior to notifying the ISO that they intend to participate in the market. The ISO must receive the notification by the first business day of the month before the month the resource wants to qualify for participation. This would only apply to resources whose entry would change contingencies evaluating the transfer capability into a zone.

Stakeholders questioned the rigidity of the timing NYISO laid out, saying that it could possibly create a situation where the market parameters were acting under the assumption that a new resource was not participating when it was.

“If commercial operations start during the middle of June, that means that the resource wouldn’t be able to provide capacity until September,” one stakeholder said. “I’m having trouble understanding why you think this is an improvement.”

There was also some back and forth with Zach Smith, senior manager of capacity and resource integration for NYISO, about why changing the ICAP market parameters could not be moved more swiftly. Smith said that he would look into whether it was possible to increase the flexibility of the proposal.

Another stakeholder asked NYISO to make the forecasted commercial operation dates of resources like CHPE available to the market so they could plan for the shift in market parameters.

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IESO to Expand Synchrophasor Data Requirements to Storage

IESO proposes to update its synchrophasor data requirements to include storage resources as part of its effort to expand the use of phasor measurement units (PMUs) in Ontario. 

Storage units rated at least 20 MVA, including aggregations, would be required to provide their voltage and current phasor measurements and frequency for all three phases. The same requirement would apply to units that are associated with or have the potential to impact a NERC interconnection reliability operating limit, regardless of size. 

The data required would be the same as those provided by generators and transmission owners, but the ISO also proposes doubling the reporting rate — 60 samples per second — for all resources. Storage units also would need to provide phasor measurements for each phase sequence, unlike generation and transmission, which must provide data for only the positive sequence. 

The number of PMUs grew exponentially in North America after the 2003 Northeast blackout. The American Recovery and Reinvestment Act of 2009 (the so-called “stimulus package”) provided $4.5 billion for grid operators to deploy smart grid technologies, including PMUs. Utilities and RTOs installed more than 1,000 production-grade PMUs over the following five years. 

But Ontario has lagged behind the U.S. The IESO proposal is part of a larger initiative to increase PMU usage throughout the province to more than 200. The requirements for generation and transmission went into effect at the end of 2024. 

“This project will enable us to finally begin closing the gap between what our neighbors have been doing for some years before us and also adopt some new applications for our control room folks,” Dame Jankuloski, IESO’s lead power system engineer, said during a webinar June 26 to present the proposal. 

Feedback on the proposal is due July 10, with the goal of Technical Panel approval by the end of the year and PMU registration beginning in early 2026. 

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Behind-the-meter Solar Shines in ISO-NE Capacity Deficiency Event

Amid the rapid growth of behind-the-meter (BTM) solar in New England, a capacity deficiency event demonstrated the significant benefits of solar resources, along with their limits in displacing fossil resources during peak load periods.

On June 24, extreme heat and humidity caused ISO-NE peak demand to surpass 26,000 MW at about 7 p.m., marking the region’s highest peak load since summer 2013. (See Extreme Heat Triggers Capacity Deficiency in New England.)

Without the contributions of BTM solar, ISO-NE estimates the peak would have reached over 28,400 MW at about 3:40 p.m. The 2,400-MW reduction in the region’s peak provided significant cost and reliability benefits to the grid. According to an analysis by the Acadia Center, “BTM solar avoided as much as roughly $19.4 million in costs on this single day by suppressing the overall price of wholesale electricity.”

In recent years, New England has seen annual additions of about 700 MW of BTM solar capacity, largely driven by state policy in Massachusetts and Connecticut. This has helped prevent load growth, pushed peaks later in the day and contributed to a growing duck curve and evening ramping requirements in the region. (See Growth of BTM Solar Drives Record-low Demand in ISO-NE.)

While BTM solar made a significant contribution to lowering the peak load, fossil resources continue to dominate the generation mix during the peak hour. ISO-NE estimates that carbon-emitting generation “provided about 74% of total energy consumed in the region during the peak” on June 24, including over 12,000 MW of natural gas generation, over 3,000 MW of oil generation and about 300 MW of coal generation.

The region’s reliance on fossil generation to keep the grid running was not without challenges — outages of large fossil units appear to have played a major role in triggering the deficiency event. Natural gas generation declined by about 1,000 MW immediately prior to ISO-NE’s declaration of a capacity deficiency, and the RTO estimates there were about 2,550 MW of generator outages and reductions at the time of the declaration.

The performance of BTM solar, coupled with fossil unit outages, has drawn attention from solar advocates. At a Massachusetts legislative hearing on June 25, several representatives of solar companies pointed to the benefits of solar during the deficiency when arguing against a proposal from Gov. Maura Healey (D) to reduce net metering compensation for new large solar facilities. (See Mass. Gov. Healey Introduces Energy Affordability Bill.)

“Solar … is the reason we didn’t have backouts and we didn’t have even higher prices and even higher emissions over the last few days,” said Jessica Robertson of New Leaf Energy.

However, incremental standalone solar capacity likely will have diminishing effects on peak loads in the coming years, as BTM solar has pushed peak periods into the evening, when solar production declines rapidly. ISO-NE’s 2025 Capacity, Energy, Loads and Transmission report estimates that increasing BTM solar will reduce the region’s gross summer peak by only an additional 144 MW by 2034.

In the wake of the capacity deficiency event, clean energy advocates made the case that increased energy storage capacity would have provided significant benefits during the peak.

“Had we had even more behind-the-meter solar paired with storage online, we could have potentially completely avoided that absurd price spike later in the evening,” said Kyle Murray of the Acadia Center at the June 25 hearing.

The Acadia Center wrote in its analysis of the event that there is “clear evidence that additional BTM battery energy storage would have been able to further reduce the overall cost to consumers by increasing flexibility and shifting the solar production later in the day, dampening the early evening peak prices.”

Consulting firm Power Advisory estimated that 1,000 MW of battery storage capacity could have reduced real-time LMPs by an average of over $100/MWh during the event, saving up to $17/kW. The firm also estimated that offshore wind would have reduced LMPs by $47/MWh, assuming a capacity factor of nearly 50% based on prevailing wind speeds.

While battery storage is in its infancy in the region, it is poised to grow quickly in the coming years, which would help to balance the production profile of storage. About 1,800 MW of energy storage cleared in ISO-NE’s capacity auction for the 2027/28 capacity commitment period, including 700 MW of new storage. Storage resources also account for 45% of the active projects in ISO-NE’s interconnection queue, totaling 18.4 GW in capacity.

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Texas Supreme Court Dismisses Bulk of Winter Storm Uri Claims

The Texas Supreme Court has ruled against residents and businesses who sued utilities after the deadly February 2021 winter storm known as Uri, saying they did not adequately prove the companies were intentionally negligent in causing widespread power blackouts.

In a June 27 order, the high court ruled the plaintiffs did not provide enough evidence to show Oncor, CenterPoint Energy and AEP Texas were “purposely negligent” or caused a nuisance when they were ordered to cut power as ERCOT struggled to meet overwhelming demand following Winter Storm Uri (24-0424).

Writing for the court’s unanimous decision, Justice Debra Lehrmann dismissed the claims of intentional nuisance, saying the plaintiffs did not allege sufficient facts to survive a motion to dismiss. She held that the plaintiffs, “as a matter of law, cannot allege” that the utilities “created” or “maintained” a nuisance.

“The alleged ‘nuisance’ here is prolonged freezing temperatures during Winter Storm Uri,” Lehrmann wrote. “The allegations do not suggest that the utilities created or exacerbated the cold temperatures or affirmatively maintained them. Rather, the plaintiffs complain that the utilities failed to adequately respond to and mitigate the harm caused by those temperatures. That is not a basis for an intentional-nuisance claim.”

Lehrmann also held that the plaintiffs’ arguments “do not sufficiently allege gross negligence.” However, she wrote they should “have an opportunity to replead the gross-negligence claims.”

The court ordered the Harris County multidistrict litigation (MDL) court to dismiss the intentional-nuisance claims with prejudice and to provide the plaintiffs an opportunity to replead their gross-negligence claims in an amended petition.

Thousands of customers filed hundreds of lawsuits against electricity companies in the wake of Uri’s outages, which lasted up to 80 hours for some Texans. The cases, alleging negligence, gross negligence, nuisance and other claims, were consolidated into an MDL proceeding.

The storm’s freezing temperatures knocked more than 34 GW of generation offline, bringing the Texas Interconnection within minutes of total collapse. The ensuing outages caused billions of dollars in damages, bankrupted electric companies and killed hundreds of Texans.

The 14th Court of Appeals dismissed the negligence and strict-liability nuisance claims but allowed the gross negligence and intentional nuisance claims to proceed. The Texas Supreme Court heard arguments on appeal in February. (See Texas Supremes Hear Arguments in Last Uri Case.)

Oncor spokesperson Roxana Rubio said the company was pleased with the ruling in that it barred plaintiffs from pursuing six of the seven original causes of action alleged against it. She said the utility is confident the case will “ultimately be fully dismissed should the plaintiffs attempt to pursue an allegation of gross negligence under the strict limitations of this ruling.”

“We continue to maintain that every action Oncor took during Winter Storm Uri was for the purpose of successfully preventing the collapse of the Texas grid,” Rubio said in an email. “We recognize this does not lessen the anguish experienced by our customers and by Texans across the state during that time.”

CenterPoint said it takes seriously “the privilege it has of providing safe and reliable electric service to its customers and communities.” It said it implemented ERCOT’s load-shed orders and “acted quickly to save the electric grid when demand exceeded supply.”

“CenterPoint is confident that plaintiffs will be unable to support any claim for gross negligence,” the utility said in a statement. “If plaintiffs replead, CenterPoint will continue to vigorously defend against plaintiffs’ remaining claim in the trial and appellate courts.”

AEP Texas declined to comment.

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CESA Report Examines State Approaches to Meet Rising Power Demand

The Clean Energy States Alliance released a report July 2 highlighting how states are tackling the rise in electricity demand, which varies based on factors such as the scale of demand growth they face and their geography.

About 80% of national data center load in 2023 was in 15 states, but the growth is concentrated in Virginia, with the largest collection of data centers in the world that account for a quarter of statewide electricity consumption. Other states expecting to see significant demand growth from data centers in the coming years are Georgia, Texas, Pennsylvania, Indiana, Ohio and the Carolinas.

Demand from manufacturing is expected to rise in the Midwest (both PJM and MISO), Southeast and West, while electrification is going to drive demand growth in California, New York and New England.

“A big challenge facing states is uncertainty around load forecast projections,” the report said. “The future of artificial intelligence and cryptomining, changes in state policy around electrification and clean energy, and the impact of federal policies on domestic industry and manufacturing all contribute to uncertainty. Additionally, big data centers often scout multiple potential locations for potential development, thereby making it unclear to state regulators and utility planners if and where a particular data center will ultimately be built.”

Most states, especially those with strong climate goals, continue to expand renewable energy, efficiency and demand response, but those facing near-term growth are backing new natural gas capacity and delaying the retirements of older fossil plants. Many states are exploring nuclear generation, with utilities including it in their long-term plans.

Concerns about rising costs from higher demand have led legislatures, regulators and utilities to develop large-load tariffs, promote data center efficiency and limit cost shifts among different customer classes.

The different drivers of load growth have their own demand profiles, which affects how they impact the grid and how state regulators and others need to address them.

Data centers generally are less flexible than most demand, but tech firms can shift computing demand around to different locations, and cryptomining facilities are price sensitive. But their usage is unpredictable, leading to forecasting challenges.

Industrial load tends to be higher during the workday, but process heat electrification and industrial-scale storage could help some facilities become more flexible.

Electrification load will tend to peak in the morning before people go to work and then again in the late afternoon/evening. In northern climates, such as New York and New England, electrification will shift the grid to having its overall peak in the winter.

“Transportation electrification’s load shape will also vary to some degree,” the report said. “Residential or commercial overnight charging will peak at night, while public fast EV chargers will likely peak during the day.”

An analysis from RMI estimates that to meet the growing demand, about 94 GW of new natural gas capacity is being planned to come online by 2035, 34 GW more than had been planned at the end of 2023. Renewables also are expected to grow, but the utility sector now plans to build 40 GW more natural gas than wind and solar by 2035, when just a couple years ago the planned new capacity for both was even.

Dominion Energy plans to build 5.9 GW of new gas by the end of the 2030s; Duke Energy has been approved to add 3.6 GW; and Southern Co.’s Georgia Power won approval for another 1.4 GW of gas this decade. Lawmakers in Maryland passed legislation to fast track a new gas plant, and those in Texas identified 17 gas-fired projects for state-backed loans.

About 9,100 MW of older capacity is expected to see its life extended because of demand growth, which includes two coal plants in West Virginia benefiting from new transmission planned to serve data centers in Virginia.

“Even New York, a state deeply committed to climate action, delayed the retirement of gas peaker plants in late 2023 due to reliability concerns and growing demand,” the report said.

The federal government also has started to issue orders keeping coal plants open, which was anticipated by some in the industry: Duke Energy said it would revisit its plans to retire its coal plants just days after President Donald Trump won the 2024 election.

Using fossil plants to deal with the higher load clashes with climate policies in some states, such as Virginia and North Carolina, the report noted.

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FERC Again Rejects SDG&E Bid for RTO Adder

FERC has denied San Diego Gas & Electric’s challenge of a commission order rejecting the utility’s request for an RTO adder to its transmission rates based on its participation in CAISO, saying SDG&E is ineligible for the adder under California law. 

FERC found that SDG&E failed to show its participation in CAISO is voluntary, a condition for receiving the RTO adder, stating a 2022 California law requires electric utilities to join and remain members of CAISO, allowing them to leave only with the California Public Utility Commission’s approval (ER25-270). 

Investor-owned utilities Pacific Gas and Electric and Southern California Edison joined SDG&E in challenging FERC’s order. 

“We continue to find that SDG&E’s participation in CAISO is not voluntary,” FERC’s July 2 order stated. “Section 362(c) of the California Public Utilities Code provides that, ‘[c]onsistent with Section 851 and the [CPUC’s] regulation of transfers of operational control of electric facilities, an electric corporation subject to [the transfer order] … shall participate in [CAISO].’ California IOUs do not dispute that SDG&E is subject to the transfer order. Therefore, the plain meaning of section 362(c) requires SDG&E to participate in CAISO.” 

In a separate but related order, FERC also affirmed a previous decision that SDG&E must refund adders with an effective date of June 1, 2019. 

The decisions stem from a broader FERC order issued in December 2024 in which the commission partly accepted SDG&E’s proposed formula rate and recovery of costs associated with transmission facilities. But FERC also rejected the utility’s request for an adder and affirmed that decision July 2. 

SDG&E proposed a base return on equity of 11.75% and an adder of 50 basis points for participating in CAISO — for a total ROE of 12.25%.  

RTO adders are provided through federal ratemaking as a way for FERC to incentivize utilities to join RTOs or ISOs. However, to be eligible for the adder, utilities must show that participation in an RTO or ISO is voluntary and not mandated by state law. 

Disputes around whether to allow California investor-owned utilities to recover an incentive for participating in the ISO have been ongoing. (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.) 

In a 2020 case involving PG&E, FERC rejected CPUC’s argument that PG&E was ineligible for the RTO adder because participation in CAISO was mandatory. FERC ruled that, based on California law, the utility’s participation in the ISO was voluntary and that it could decide unilaterally to leave. (See FERC Rejects RTO Incentive Adder Rehearing.) 

But in September 2022, California amended its public utilities code to mandate participation in CAISO, with the ability to leave only with CPUC approval. Following this, FERC in December 2023 issued a decision holding that PG&E no longer was eligible for the RTO adder. 

In the underlying case involving SDG&E, the San Diego-based utility told the commission it believed FERC wrongly ruled against PG&E in 2023 and had appealed the decision to the U.S. Court of Appeals for the Ninth Circuit. 

According to the FERC July 2 order, the IOUs argue the CPUC code contains ambiguous language that allows them to leave CAISO, making their participation voluntary. 

But FERC disagreed, instead finding “Contrary to California IOUs’ view, Section 362(c) mandates participation and does not address withdrawal at all.” 

“While California IOUs argue that passages in the formula rate order and PG&E adder order suggest otherwise, the commission clarified in the PG&E adder rehearing order that Section 362(c) does not provide for withdrawal subject to CPUC approval,” the order stated. “To the extent the formula rate order leaves any ambiguity, we clarify that Section 362(c) does not provide for withdrawal.” 

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Google Data Center Electricity Consumption Up 27% in 2024

Google is reporting another sharp annual jump in electricity consumption at its data centers but says greenhouse gas emissions were lower in 2024 than 2023 by some measures. 

The company in its 2025 Environmental Report said it bought 32.11 million MWh worldwide in 2024 — 0.83% as much as the total electricity consumption in the 50 states in 2023 and 499% more than Vermont, the state that used the least electricity. 

Electricity use by data centers, particularly with the advent of energy-intensive artificial intelligence, is the focus of much debate and consternation among grid operators and policymakers. Some maintain the dire predictions are overblown, others say the demand is real, and there is a looming crisis on which the nation’s future rides. 

Google is a giant — its soaring power consumption may or may not be a bellwether of the tech sector as a whole. But its purchased electricity use in 2024 was 27% higher than in 2023 and 112% higher than in 2020. 

For perspective, fellow tech giant Microsoft reported 29.83 million MWh consumed in its fiscal 2024 — 26% more than in fiscal 2023 and 177% more than in fiscal 2020.  

Both companies reported small additional amounts of energy purchased in the form of fuel, heat, steam and chilled water, or generated by on-site renewables. 

A potentially huge environmental footprint accompanies all those gigawatt hours and all those data computations. 

In the annual report issued June 27, Google frames its power consumption within efforts to reduce that footprint and increase sustainability. 

“In 2024, we made our largest-ever procurement of clean energy, adding 8 GW to our portfolio, more than we’ve ever done in a single year,” Google Chief Sustainability Officer Kate Brandt said in announcing the Environmental Report.

Google nearly doubled its on-site renewable electricity from 10,700 MWh in 2023 to 20,500 MWh in 2024, for example. More than two dozen clean power projects contracted over the previous five years came online in 2024, raising Google’s carbon-free energy use from 64% in 2023 to 66% in 2024, even as total energy use soared. 

More broadly, Google said, energy-intensive AI data crunching is saving electricity beyond the data centers, through company products such as fuel-efficient routing, solar API, traffic signal management and machine learning-enabled thermostats. 

Google says those five products alone enabled an estimated 2024 emissions reduction of 26 million metric tons. The company’s goal is to reduce clients’ carbon-equivalent emissions by 1 gigaton per year by 2030. 

Google also has made headlines with its partnerships in advanced nuclear and geothermal development. 

An entire school of climate activism is dedicated to calling out corporate greenwashing, and five days after Google issued its 120-page report, Kairos Fellowship issued a 53-page report criticizing its emissions reporting as misleading and its conclusions as wrongly self-congratulatory. 

In the tenth annual report, Google acknowledges the gray areas within some decarbonization metrics. 

It set out in 2012 to match its global energy use with renewable energy purchases; it reached 100% in 2017 and every year since, but a 100% match is not what it considers carbon-free. 

“Even if a company buys clean energy in bulk and applies it to match its total usage over the course of the year, its real-time energy mix likely includes electricity generated from fossil fuels,” the authors write. 

Google continues to pursue its 24/7 carbon-free energy goal — a real-time match of electricity used with clean energy generated locally on the same grid in the same hour. On that measure, it claimed 66% success in 2024. 

In the final tally, Google reported its Scope 1 emissions and certain Scope 2 emissions were lower in 2024 than 2023, while Scope 3 emissions were higher. Combined, they are 6.3% higher, but Google does not include in that equation another type of Scope 2 emissions that showed the biggest year-over-year increase of all.  

Carbon intensity per unit of revenue, per full-time employee equivalent and per megawatt hour of energy consumed all were significantly reduced year over year. 

The hurdles Google sees to further progress are the same ones that face everyone else: interconnection delays, regulatory bottlenecks, logistical and economic constraints, limited local supply, permitting challenges and regional variations. 

The company reached only 12% carbon-free energy in the Asia-Pacific region in 2024, for example, compared with 70% in the U.S., 5% in the Middle East/Africa and 92% in Latin America. 

Google is pursuing multiple strategies for further progress but acknowledges the scale of the task, saying, “The path ahead is anything but simple.”