Data Centers and the US Grid

The pathway for adding data centers to the U.S. transmission system became clearer when the Federal Energy Regulatory Commission on June 18, 2026, found that major grid operators’ rules for large load interconnections appeared to be inadequate.

“We take historic action to push our country’s electric markets and economy into the future — a future of fair cost allocation, unprecedented transparency for the American ratepayer, respect for states’ rights, efficient markets and speed to power,” FERC Chairman Laura Swett said in a concurring statement with the six orders the agency issued.

In its “show cause” orders, FERC detailed five issues it wants regional transmission organizations and independent system operators to address in their large load interconnection rules:

• efficient transmission service application and study processes, including the consideration of alternative transmission technologies;
• prevention cost shifts and transparency into transmission costs;
• co-location and behind-the-meter generation;
• new transmission services for flexible large loads; and,
• a study process for generating facilities that serve “electrically proximate” large loads and co-located loads.

FERC’s decision was driven by a massive wave of data center development that started about two years ago, after years of generally flat electric demand growth in the United States. The development has sparked a race for data center developers to get power to their facilities as quickly as possible and created political backlash over rising electricity bills.

In October, the U.S. Department of Energy directed FERC to establish rules for enabling data center interconnection to the transmission system. FERC’s response to the DOE’s “advanced notice of proposed rulemaking” drew more than 3,500 pages of comments and was completed in roughly eight months.

“FERC's action is far more substantively ambitious than the ANOPR, and it enables region-specific investigation pathways that should be more effective than a uniform rulemaking,” Devin Hartman, a senior fellow at the R Street Institute, said in an email to Utility Dive.

Ultimately, new interconnection rules could provide greater cost clarity for electric utilities, according to Morningstar DBRS.

“For regulated utilities, the key benefit is a clear framework for determining the need for large-load-related infrastructure, who pays for it, and how long the large-load customer must remain financially responsible for the investment and to an extent mitigate customer affordability concerns," Zujian Li, Morningstar DBRS’ vice president of energy and natural resources ratings, said Monday.

For data center developers, FERC’s orders indicate that the agency is “committed to prioritizing projects that can prove they are real, financeable, operationally flexible, and capable of integrating with the grid without imposing unjustified costs on other customers,” Jane Rueger, Perkins Coie data center co-chair, said in an email to Utility Dive.

FERC’s orders were issued to: the California Independent System Operator; ISO New England; the Midcontinent Independent System Operator; New York Independent System Operator; the PJM Interconnection; and, the Southwest Power Pool.

Here are six takeaways from FERC’s landmark decision.

FERC opts for regional approach

FERC directed the RTOs and ISOs to develop their own data center interconnection rules that can best meet their specific needs.

“The era of one national standard for data center interconnection is over before it began,” Mona Dajani, a partner and the co-chair of Cooley's infrastructure, energy and real estate practice, said in an email to Utility Dive. “What replaces it is six regional answers to the same question, decided on six different timelines.”

As a result, data center developers face new diligence needs for near-term deals, according to Dajani.

“A term sheet signed against today’s PJM tariff carries different risk than one signed against today’s MISO or CAISO tariff, because each region’s show cause filing will land on its own schedule with its own substantive answer on cost allocation, co-location, and flexible load service,” she said.

FERC was smart to avoid a “one-size-fits-all approach,” according to Gretchen Kershaw, COO and vice president of strategy at Grid Strategies, a transmission-focused consulting firm.

“FERC did an admirable job of explaining the nuances of each region in the orders,” Kershaw said in an email to Utility Dive.

However, Kershaw said she would like FERC to take some action outside of RTOs as well. “The framework of vertically integrated utilities and bundled retail sales is distinct, but there is no part of the country where there is less transparency than in these regions,” she said.

Hartman echoed those comments. “I wish FERC had included non-RTO areas, which typically suffer from the worst transmission and interconnection practices,” he said.

About a third of Americans live outside of RTOs, former FERC Commissioner Allison Clements noted in an email. “By punting on the tougher jurisdictional questions, FERC has left these customers without the cost and transparency protections that will be made available to families in RTO regions," said Clements, a partner with digital infrastructure advisory firm ASG and principal of 804 Advisory.

FERC encouraged transmission owners outside of RTOs — such as much of the West and Southeast  — to propose data center interconnection rules.

FERC ‘stays in its lane’

With its orders, FERC appears to have avoided conflicts over federal and state jurisdiction, a major concern that arose when the DOE ordered the agency to develop large load interconnection rules.

“We recognize that states will continue to regulate: (1) the specific terms of retail sales to large load; (2) which entities may make retail sales within their borders, including which entities are legally permitted to provide electricity to retail large load customers; and (3) any siting decisions and construction associated with the large load project,” FERC said in its PJM order. “Nothing in this order is intended to intrude upon state authority over retail service to large loads.”

FERC did a “great job” staying in its jurisdictional ambit, according to Kershaw.

“As a long-time FERC lawyer, I think FERC has more jurisdiction than it has asserted, but I recognize that fast and durable action is easier when litigation risks are reduced — and that is no more true than when sticking to existing jurisdictional lanes,” Kershaw said.

Protecting ratepayers from cost-shifts

In its orders, FERC said it was concerned that there appears to be a lack of transparency in how RTOs and ISOs determine how network upgrades are assigned and paid for. Also, grid operators appear to lack pro forma cost recovery agreements for network upgrades that can be required to safely interconnect new loads to the grid. Those agreements can help ensure that large load customers bear the risk and pay for their transmission service, including the cost of network upgrades, FERC said.

FERC, for example, directed PJM to explain whether its tariff remains just and reasonable without providing “robust, accurate, and systematic” and easily searchable data on its website on network upgrade costs.

FERC directed RTOs and ISOs to have “cost recovery agreements” to help make sure that large loads pay their share of the costs incurred to serve them, FERC Commissioner David Rosner noted in a concurring statement.

“We target speculative projects by establishing escalating readiness requirements for distinct phases of the study process to deter duplicative or speculative requests for transmission service,” Rosner said.

Options coming for flexible loads

“Load flexibility can avoid inefficient and costly transmission system build-out,” FERC said. “In addition, transmission services that reflect that flexible large loads are willing and able to limit their withdrawals from the transmission system under certain conditions could help timely interconnect flexible large loads.”

FERC’s orders reflect a growing recognition that data centers can be more flexible than traditional loads, Robert Montejo, a data center partner at the Duane Morris law firm. “The ability to curtail or operate flexibly could become one of the most valuable tools for getting new projects connected faster,” he said in an email.

FERC’s orders preliminarily find that the agency should extend the transmission services developed in PJM’s co-location proceeding — interim network integration transmission service, firm contract demand and non-firm contract demand — to new types of load and new regions, FERC Commissioner Judy Chang said in a concurring statement.

“While these services have the potential to facilitate more efficient use and build out of the transmission system, they also contemplate running the system ‘tighter’ than we have done in the past, potentially with more loads on the system served by co-located or behind-the-meter generation, and potentially more use of batteries, load control systems, and backup resources to manage demand during system peaks or other stressed conditions,” Chang said.

FERC calls for ATT evaluations

In its orders, FERC called on grid operators to consider alternative transmission technologies — such as advanced power flow control devices, synchronous condensers, advanced conductors and dynamic line ratings — when conducting transmission service request studies for data centers and other large loads.

If a grid operator decides traditional network upgrades are needed, they should clearly show why ATTs are infeasible or would not lower costs or offer a faster timeline for interconnecting a large load, according to FERC.

“The goal is to respect transmission providers’ engineering judgments while protecting against upgrade costs when ATTs could solve transmission needs faster and with a lower bill,” FERC Commissioner Lindsay See said in a concurring statement. 

ATTs can “unlock every megawatt of existing capacity from our current transmission system,” FERC Commissioner David LaCerte said. “We have the technology. We should use it now to enable faster interconnection of large loads, lower costs to customers, and help prevent cost shifting.”

Reform timeline could be challenging

FERC gave the RTOs and ISOs 60 days to respond to their show cause orders. However, within 45 days, they can request 90-days extensions to be added to the initial 45 days.

That timeline may result in “relatively cursory reports, not detailed reform proposals,” Hartman said in a social media post. “Regional stakeholders have to rapidly diagnose deficiencies and identify reforms for issues that often take multiple years to develop remedies.”

The timeline is “really aggressive” and there may be governance barriers to meeting it, according to Kershaw.

“I expect we'll see some requests for abeyance,” she said. “I will also be watching the PJM governance technical conference carefully for how FERC is thinking about reforms that can result in expedited filings like those envisioned by the show cause orders.”

LaCerte warned that the agency expects solid responses from the RTOs and ISOs, saying the agency used “considerable restraint” through its show cause orders.

“The commission has very broad jurisdiction over transmission that we will not hesitate to utilize as necessary to ensure that we meet our objectives in all show cause proceedings,” he said in a concurring statement to the orders.

If the grid operators fail to adequately address the large-load-related concerns identified by FERC, the agency will dictate the solutions, according to LaCerte.

“I say this not as a threat, but as a statement of duty,” LaCerte said. “While you may not like our remedies — I have often said that the federal government generally does not come up with the best solutions — this is an outcome we are prepared to pursue given the gravity of the moment and our statutory obligation.”

The Federal Energy Regulatory Commission on June 5, 2026, approved the Southwest Power Pool’s proposal for providing transmission service to data centers and other large loads that agree to be curtailed during grid emergencies.

Under the “conditional high impact large load service,” or CHILLS, SPP will provide transmission service using available transmission capacity for up to seven years while large loads acquire firm service.

Currently, SPP requires transmission customers to have sufficient generating resources to serve their load. But those resources often require network upgrades that can take years to complete, the grid operator said in its proposal to FERC.

To help bring data centers and other large loads online quickly, the CHILLS framework will allow SPP to provide non-firm transmission service to large loads while the upgrades needed for firm service are being built or new generation becomes fully operational, the grid operator said.

SPP will be able to cut service to those large loads when the transmission system is constrained or under emergency conditions, according to FERC’s decision.

“We find that CHILLS is a just and reasonable and not unduly discriminatory or preferential approach to addressing the need to expeditiously interconnect and provide transmission service to new [high impact large loads,] while maintaining the reliable operation of SPP’s transmission system,” FERC said.

The conditional transmission service builds on SPP’s High Impact Large Loads and High Impact Large Load Generation Assessment study processes that FERC approved in January.

SPP is also developing a Price Adaptive Load Service framework for large loads that are willing to be curtailed.

SPP runs the grid and wholesale power markets in 17 states from northern Texas to Montana.

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By Bloom Energy

Utilities are being asked to serve electricity demand at a scale and speed the grid was not designed to handle.

Hyperscale data centers, AI infrastructure, and broader electrification are compressing timelines from years to months. Interconnection queues, on the other hand, are stretching, and large-load customers are no longer willing to wait for traditional grid buildout.

The question is no longer whether demand will materialize, but how utilities will be able to serve it.

Bridging the Gap Between Demand and Delivery

Utilities have reached a critical inflection point. Driven by the explosive demand of artificial intelligence, hyperscale data centers, and sweeping electrification, utilities are facing a historic capacity crunch to meet the needs of AI-driven compute demand.

The issue is timing.

Transmission and distribution infrastructure takes years to plan, permit, and build. Large-load customers are operating on much shorter timelines, and that gap is widening. As a result, utilities are being pushed to find ways to serve new load requirements without waiting for full grid expansion.

Bloom Energy's newly released 2026 Utilities Insights Report shows how utilities are responding. Behind-the-meter (BTM) onsite power is becoming central to how large load demand is served, rather than sitting outside the system, as a temporary measure. Instead, utilities see it as a structural, permanent pillar of the modern energy ecosystem.

The findings point to a broader shift in how utilities and developers are approaching new load with onsite power solutions.

Key Findings

• 80% of utilities now view behind-the-meter generation as permanent infrastructure, expecting it to serve a significant share of large-load demand by 2030 and an even larger share by 2035.
• Nearly two-thirds of data center developers cite onsite power as their primary response when grid timelines slip — choosing to stay in their utility territory rather than relocate.
• The energy landscape is shifting from rigid, centralized distribution toward integrated hybrid ecosystems. Onsite generation is now a mechanism for grid optimization, not a signal of grid failure.
• New commercial models, including utility-owned BTM assets, tolling agreements, and co-development partnerships are unlocking revenue opportunities for regulated and unregulated utilities alike.

Taken together, the data reflects a change not just in preference, but in operating reality.

How Can Utilities Ease Mounting Grid Bottlenecks?

As demand accelerates, the pressure shows up first at the grid edge.

Connecting a large-load customer requiring hundreds of megawatts or gigawatts is no longer a standard operational request. Transmission and distribution (T&D) infrastructure takes years to build, and standard interconnection queues are buckling under the weight.

According to the double-blind survey of senior decision-makers at U.S. utilities [1], interconnection timelines ranked as the highest barrier, with more than half of utility leaders reporting that wait times have deteriorated. Equipment availability and community acceptance follow close behind, and both are getting worse. While regulatory cost allocation and tariff pathways show modest signs of improvement, the physical realities of grid expansion simply have not kept pace with the accelerating timelines of modern data center developers.

How Are Data Center Developers Staying Put with Onsite Power?

Against this backdrop, developer behavior is shifting.

When grid timelines slip, what do developers do? Data center operators want to remain within their chosen utility territories and are actively deploying alternative strategies. In fact, nearly two-thirds of developers surveyed cite onsite power as their primary response when grid access is delayed. Only a small fraction would consider relocating to another market. The implication for utilities is clear: onsite power generation is increasingly being used to hold load in place, not divert it elsewhere.

Why Are Utilities Turning to Onsite Power as a Permanent Long-Term Strategy?

The shift is not limited to developers. Utility perspectives are also evolving.

The most telling finding from the report is how utility perspectives have adapted. Rather than interpreting BTM power as a lost rate base or competitive threat, 80% of utilities now view onsite power as permanent infrastructure. Utilities expect behind-the-meter generation to serve a significant share of large-load demand by 2030, and an even greater share by 2035. Detailed projections for BTM demand share by 2030 and 2035, broken down by utility type and region, are available in the full report.

• 44% of utility leaders categorize distributed power as permanent baseload generation — a foundational shift in long-term energy infrastructure planning.
• 36% view distributed power as vital supplemental capacity for peak shaving and grid backup, cementing onsite generation as an integral part of grid management.
• Only 5% of utility leaders believe distributed power is unviable — a clear signal that industry consensus has shifted decisively toward hybrid energy models.

Speed to Market and Beyond: The Strategic Benefits

As adoption increases, the advantage extends beyond timing.

While faster time to power remains the most immediate driver, onsite generation yields broader operational benefits that complement the macro grid:

• Capital Expenditure Relief: A notable share of survey respondents value onsite power for its ability to reduce or defer expensive T&D upgrade costs.
• System Flexibility: Localized generation can help defend the regional grid during peak-demand constraints. Depending on the asset mix, it can support critical ancillary services like frequency regulation, voltage control, and dispatchable reactive power.
• New Commercial Models: Unregulated utility subsidiaries and investor-owned utilities (IOUs) are discovering revenue upside through direct asset ownership, tolling, or structured co-development partnerships.

"Ultimately, utilities will provide integrated front-of-the-meter and behind-the-meter power solutions as part of a single package. That's increasingly the structure behind many of the major deals being announced today."

— Senior Development Manager, Regulated IOU

Moving Toward a Hybrid Energy Future

Taken together, these shifts point in a clear direction.

The energy landscape is transitioning from rigid, centralized distribution toward integrated, hybrid ecosystems. Onsite generation is no longer an indicator of grid failure; it is a mechanism for grid optimization.

By leaning into behind-the-meter fuel cell systems and microgrids, utilities can serve large-load customers on accelerated timelines, alleviate stress on existing T&D systems, and foster regional economic growth.

Is BTM Power the Same as Going Off-Grid?

Not exactly — and the distinction is critical for utilities. BTM power refers to generation assets located on the customer’s side of the utility meter, designed to operate in parallel with the grid. Off-grid systems, by contrast, operate in complete isolation from grid infrastructure. When utilities partner with Bloom Energy to deploy BTM solutions, the goal is to complement grid supply, not replace it. Bloom’s fuel cell platforms allow large-load customers to draw reliable onsite power while maintaining full grid interconnection — giving utilities a practical path to serve new demand without waiting years for T&D buildout.

Want to explore the complete benchmark data and utility engagement strategies? The full report covers how regulated and unregulated utilities are approaching onsite power differently, and the commercial structures emerging as a result. Download the Full 2026 Utilities Insights Report To Gain Insights Now.

The addition of 58 GW of summer resource capacity has the U.S. grid in good shape heading into the summer months, but risks are growing during the shoulder seasons, the North American Electric Reliability Corp. said May 19, 2026, in its annual summer assessment.

The watchdog’s report flagged four areas at risk of energy shortfalls or local constraints during extreme heat conditions this year, down from six in 2025.

The pace of electricity demand growth continues to rise, and NERC officials highlighted difficulties in demand forecasting due to data center interconnection issues and evolving operational data. Summer peak demand this year will be about 865 GW, according to the assessment, up from about 842 GW in 2023.

A “large influx” of bulk power system resources over the past year “has outpaced demand and is boosting reserves,” according to the report. Resources available to meet peak demand this summer jumped by over 58 GW over last year, including 16 GW of solar, 15 GW of storage and 7 GW of gas capacity.

Another 19 GW of capacity additions include other types of resources and changes to generator availability, including the completion of nuclear outages and maintenance plans. NERC said 16 of its 23 assessment areas have increased available capacity ahead of summer.

“Overall, this is a positive story,” NERC analyst Suzanne Edwards said in a call with reporters to discuss the assessment. 

The Midcontinent Independent System Operator and Electric Reliability Council of Texas markets both saw “a robust jump” in year-over-year anticipated resources, of 7% and 12%, respectively, allowing each to shed the “elevated” risk assessment from the previous summer’s assessment, Edwards said.

NERC’s report flagged parts of New England, the Northwest, SaskPower’s territory in Canada and a local area in West Texas as facing elevated risks in extreme heat.

In NPCC-New England, firm import commitments have declined since last year “resulting in lower operating reserves and increased reliance on non-firm supplies from neighboring systems to meet high demand,” NERC said. In WECC-Northwest, persistent drought conditions, rising demand and a decline in resource capacity “could increase vulnerability during more extreme summer conditions.”

In the SaskPower area, a higher demand forecast reduced operating reserves. And while ERCOT was broadly removed from the “elevated risk” designation, a small area in the western portion of the state “remains at risk for load disruption when solar and wind output is low and transmission constraints limit the flow of imports.”

West Texas “has a bit of everything, with respect to our big reliability topics of the day,” Edwards said. “There is definitely large load growth, and that's complicating the load forecast when the rate of completion is not super stable.”

Data center growth has muddled the demand picture in Texas, and ERCOT in April preached caution on its own projections. The grid operator estimated summer peak load to range between 90,500 MW and 98,000 MW, significantly cutting the 112,000 MW peak it forecast in a previous report that included large-load demand estimates from utilities at the direction of state lawmakers.

The Texas Interconnection is “widely at a normal risk level” this summer due the jump in anticipated resources as well as a 4.5% decline in projected net internal demand, NERC said. The lower demand forecast is the result of “updated load modeling that reflects the observed behavior of load during peak periods and more demand response from large computational loads.”

“On a regional basis we have seen some downward revisions in the demand associated with large load interconnection rates in certain areas,” Edwards said. Large loads, including data centers, have “been difficult to time, with respect to the speed at which they connect to the grid. Slower than expected interconnection rates have spurred these adjustments to the near-term load forecast,” she said.

“The trend is also visible in [the PJM Interconnection], with lesser growth expected. It's not quite as stark as a full on decline in demand, but lesser growth,” Edwards said.

In January, PJM trimmed its load growth forecast through 2032 on stricter data center vetting and the economic outlook in its operating footprint.

NERC warned that sudden load reduction events or disconnections are a growing concern with data centers and “pose operational challenges for the upcoming summer.” Earlier this month, NERC issued a Level 3 alert and mandatory actions, following instances of data centers unexpectedly dropping load or oscillating demand rapidly, creating reliability concerns.

Other reliability risks NERC is watching this summer include wind droughts. The bulk power system grew its wind capacity 3% year on year, NERC said.

“The impact of wind ramp events — particularly down ramp — must be anticipated and planned for such that appropriate resources are ready to replace the energy lost during these conditions,” the summer assessment said. “It is not uncommon for areas to experience several thousands of megawatts of wind energy coming off-line during these events.”

Increasing grid complexity, rising demand and shifting temperatures are also driving up reliability risks in the spring and fall, seasons typically thought to be safer from reliability challenges, officials said. The overlap of early summer heat and spring maintenance outages can lower operating reserves, the assessment noted.

“There is trending higher risk in shoulder periods than in ... the summer peak conditions, and I think that's a really reflection of how we're using electricity [and] the types of resources that are being provided to us,” said John Moura, NERC director of reliability assessments and performance analysis.

As large-load customers increasingly look to power their operations with new clean firm technologies like advanced geothermal and small modular nuclear reactors, clean energy tariffs, as well as bilateral customer-utility arrangements, are helping to commercialize and de-risk the deployment of these technologies, the Corporate Energy Buyers Association said in a May 21, 2026, report.

“The goal is to try and get some of these technologies closer to commercialization, and then we'd see costs shift down, like we did with solar and wind,” lead report author Priya Barua, CEBA's senior director of utility partnerships and innovation, told Utility Dive. “I think we're in that phase with that next wave of technologies.”

Clean energy tariffs “allow large customers to identify, fund, and support specific clean or clean firm resources,” the report said, “within existing regulatory frameworks, pairing customer-driven investment with strong ratepayer protections.”

Hyperscalers are spending aggressively on the AI race, including the construction of data centers and the energy needed to power them. The five largest hyperscalers — Google, Meta, Amazon, Oracle and Microsoft — are expected to cross $1 trillion in capital expenditures this year, according to venture capital and private equity firm Bessemer Venture Partners, and $8 trillion total between 2025 and 2031.

Those five companies also “represented 49% of all corporate clean energy [power purchase agreements] globally in 2025,” the CEBA report said, “with a growing share of investments in nuclear, hydropower, and geothermal.”

These investments include a PPA between Microsoft and Constellation Energy, which is driving the restart of Three Mile Island Unit 1, and a 115-MW PPA between Google and advanced geothermal startup Fervo Energy under a Clean Transition Tariff that Google and NV Energy proposed and got approved by the Public Utilities Commission of Nevada.

“In a lot of the partnerships that have been established around some of these technologies, it's really the tech companies that are taking on a lot of the risk,” Barua said. “And so, in addition to essentially safeguarding non-participating customers from a cost perspective, that risk is being taken on, and there's a lot built into these tariffs to really protect the rest of the ratepayers from those risks.”

Small modular reactors are increasingly drawing investments from hyperscalers looking to power future data center operations, thanks in part to their smaller footprint when compared to a traditional nuclear facility, though no SMRs are operating yet in the U.S.

The report identifies three characteristics which the authors associate with “durable” clean energy tariff designs: the allocation of “associated costs exclusively to participating customers”; the embedding of capacity value into rate structures; and “long-term revenue certainty necessary for capital-intensive, clean firm resources.”

The report authors also noted that large load tariffs and clean energy tariffs “are increasingly linked.”

“New state-mandated, large load tariffs establish minimum demand charges, collateral requirements, and long contract terms to protect ratepayers,” the report said. “Clean energy tariffs often build on these foundations, giving customers a pathway to pair load growth with new capacity, improving system economics rather than exacerbating them.”

Barua said she thinks large load customers are “looking at a broader suite of clean firm technologies than they were five years ago, just because of where we are right now, and the recognized need for more capacity. So I do think that as a result we're seeing a lot of innovative partnerships between customers and utilities.”

She pointed to Minnesota, where Google and Xcel Energy utilized the state's Clean Energy Accelerator Charge, a specialized green energy tariff, to bring online a portfolio of resources that includes solar, wind and 300 MW of long duration energy storage, “the biggest long duration energy storage system that that we've seen.”

“Again, that is a new technology, and in that arrangement, Google is taking on some of the risks of bringing that technology onto the system,” Barua said. “But we will see system benefits from it.”

Several North American grid assessment areas will see sharp changes in demand response availability this summer, compared with 2025, according to the most recent assessment from the North American Electric Reliability Corp.

The U.S. regions with the most significant changes include the Southeastern Electric Reliability Corp. Central region (+172.3% from 2025), the Electric Reliability Council of Texas (+54.9%), the Southwest Power Pool (+25.8%) and New England (-13.3%).

Demand management is getting more attention from utilities looking to find near-term solutions to add capacity to the grid, due in large part to increasing demand from data centers and large industrial loads. NERC expects peak demand across the North American bulk power system to increase by 224 GW, or 24%, over the next 10 years.

The reasons for the shifts vary by region, NERC said in its assessment. For example, ERCOT’s positive change is due to updated load modeling that better reflects the responsive behavior of “large computation loads” — data centers — during peak periods, it said. 

The positive change in the SERC Central region, much of which is served by the Tennessee Valley Authority, is due to new demand-side management programs and industrial load enrollments, NERC said.

In ERCOT, NERC said it reduced its 2026 summer forecast for total internal demand by 1.9 GW, or 2.3%, due to updated modeling of large computational load behaviors. It dropped its forecast for net internal demand by 3.7 GW, or 4.6%, “because more data centers can be curtailed by grid operators when needed to prevent grid emergencies,” it said.

Texas law requires loads of 75 MW or more that interconnect from 2026 onwards to accept mandatory curtailment during firm load shed events. Texas has a separate, competitively procured reliability service open to large loads on a voluntary basis as well.

ERCOT is one of the few assessment areas where NERC expects net internal demand to fall this year, however. Nineteen of NERC’s 23 assessment areas are set for higher net internal demand, with the exceptions being winter-peaking Québec and WECC’s Rocky Mountain and Mexico regions, NERC said.

In some other NERC assessment areas that saw sharp shifts in demand response availability, the category represents a negligible share of total internal demand. For example, NERC expects Southwest and Northwest regions of the Western Electricity Coordinating Council to shift by +82.9% and -93.3%, respectively. But official demand response capacity represents less than 1% of projected 2026 internal demand in WECC-Southwest and is virtually nonexistent (just 2 MW) in WECC-Northwest.

Meanwhile, demand response availability was little changed in the PJM Interconnection (-0.4%, to 7,864 MW) and Midcontinent Independent System Operator (+1.1%, to 9,100 MW), according to NERC’s assessment.

NERC has previously identified PJM and MISO as facing particularly high risk of capacity shortfalls over the next few years. The reliability nonprofit downgraded its threat assessment for MISO last year after pushback from the grid operator’s independent market monitor, however.

David Patton, president of Potomac Economics, said at a Federal Energy Regulatory Commission technical conference in May 2025 that NERC’s forecast did not properly account for behind-the-meter generation and demand response capacity in MISO, among other factors. Its projection missed more than 8 GW of potential capacity, Patton said.

NERC blamed “mismatched data” in a MISO submission for the mix-up.

NERC still sees high reliability risks in PJM, MISO, ERCOT, WECC-Northwest and WECC-Basin, according to an updated long-term reliability assessment released in January. Its three risk categories are “normal,” “elevated” and “high.”

That forecast blamed planned generator retirements outpacing additions and projected load growth in MISO and PJM. Beginning May 2025, the Trump administration issued and renewed emergency orders requiring several coal- and oil-fired generators in both regions to run beyond their scheduled retirement dates, citing near-term resource adequacy risks. 

Clean energy groups, environmental organizations, ratepayer advocates and even some owners of affected plants have pushed back, saying they are not needed for resource adequacy and saddle utility customers with unnecessary costs. An ongoing lawsuit pitting the environmental nonprofit Earthjustice and three Midwestern states against the U.S. Department of Energy will likely reach the U.S. Supreme Court, industry analysts say.

In some parts of the United States, grid operators’ own assessments show behind-the-meter energy assets reducing net load during the afternoon windows when daily summer power demand has historically peaked. 

For example, ISO New England’s 2026 summer outlook expects behind-the-meter solar to reduce demand by more than 1,700 MW during the peak hour of demand on days with normal weather conditions. The region now has more than 8,000 MW of behind-the-meter solar, which is enough to push the demand peak later into the evening, ISO-NE says.

Over the next 10 years, ISO-NE expects behind-the-meter solar to play a much larger role in midday net load reduction — up to 6.5 GW by the winter of 2038, according to a forecast released earlier this month. But limited solar irradiation means behind-the-meter solar and batteries will do less to mitigate the region’s early-morning or early-evening seasonal peaks as electrified buildings and vehicles flip it from summer to winter peaking, the grid operator said.

The U.S. Energy Information Administration projects that data centers will “increasingly skew more energy intensive” and that electricity consumed by them will increase across all commercial building stock, with their servers growing to make up an estimated 22% to 33% of commercial building electricity use by 2050, according to an April 2026 report.

In its 2026 Annual Energy Outlook, EIA modeled various scenarios to explore how much data centers might drive demand in the medium and long term. In its high electricity demand scenario, the agency assumed “growth in the installed stock of AI servers follows an exponential trend through 2050” and didn’t make any assumptions about increases in computational efficiency beyond historical trends. 

“These assumptions lead data center server energy use alone to grow to 818 billion kilowatt hours in 2050 in the High Electricity Demand case,” EIA said. “Server electricity consumption in 2050 is more than 16 times that in 2020.”

In its counterfactual base case, EIA models how “U.S. and world energy markets would operate through 2050 under laws and regulations in force as of December 2025,” but said that this “should not be regarded as the most likely of the cases.”

EIA projects that electricity consumption in the U.S. will continue to grow through 2050 at an annual rate of 0.9% to 1.6%, “with data center server energy use a major factor,” after the previous five years saw a 2.1% average annual demand increase, which followed 15 years of nearly flat demand.

“Energy use in commercial buildings, home to data center activity, grows more rapidly than in the residential or industrial sectors in all modeled cases,” the report said. In a Tuesday release, EIA noted that “across all cases, servers alone accounted for an estimated 7% of commercial sector electricity consumption in 2025.”

In both EIA’s high electricity demand scenario and its counterfactual base case, the commercial sector’s electricity intensity — measured in kilowatt hours of electricity consumed per square foot — eventually exceeds the 2003 historical high of 14.9 kWh per square foot for the first time in either 2031 or 2032, depending on the scenario.

In its counterfactual base case, EIA projects that “after 2040, servers will become increasingly efficient, resulting in a 10% reduction in average annual operational power draw every three years, above and beyond historical efficiency trends. However, continued growth in server installations drives overall consumption growth.”

State policymakers are increasingly looking to large load tariffs as a way to shield ratepayers from the surge in interconnection requests from artificial intelligence data centers, with 77 such tariffs pending or in place across 36 states, according to the Smart Electric Power Alliance, which recently updated its Database of Emerging Large Load Tariffs. 

In 2025, state regulators approved 29 large load tariffs, compared to 14 between 2018 and 2024, SEPA said. The database, which is jointly maintained with the North Carolina Clean Energy Technology Center, has added 12 entries and 3 additional states since its last update in November 2025

Experts say it’s too soon to know whether the tariffs are working as intended, and broader reforms to utility planning and power markets are likely needed. “We’ve seen the tariffs that set the initial agreements and the kind of frameworks, and they have these really important safeguards, but in a lot of states, we haven’t yet gotten to that process of cost allocation, which is complicated,” Louisa Eberle, a senior associate with the nonprofit Regulatory Assistance Project, told Utility Dive. “There are several reasons why rates might still go up for other customers if cost allocation isn’t done effectively.”

The growth of large load tariffs comes amid rising retail power costs that are increasing pressure on elected officials, regulators, utilities and tech companies to justify an estimated trillion-dollar grid buildout to meet demand growth projections from data centers and, to a lesser extent, manufacturing and electrification.

“I think the properties of that growth at a regional level are what drives the increased look at how we could build upon the longtime commercial and industrial tariff structures and principles to shore up guardrails for this new growth era that we’re in,” Ann Collier, SEPA’s director of grid strategy, said in an interview. “The growth is coming at a much faster pace than we have seen in decades, and it’s much denser.”

In particular, the definition of “large load” has evolved as the size of projects have grown. A few years ago, utilities defined “large loads” using a threshold of five, 10 or 25 MW, Collier said, but more recently-approved tariffs are defining large loads at 50 MW and above.

Other common features of these tariffs include asking loads to pay more of the upfront costs for engineering studies or power delivery infrastructure, minimum contract terms, minimum load guarantees, defined load ramp schedules, exit fees and financial security in case a project falls through. Some have also introduced incentives, such as reduced load guarantees or faster interconnection, for customers that bring their own capacity or agree to flex their power demand during times of grid stress.

Collier said while utilities are still originating many of their own large load proposals, she’s noticed that states are taking a more active role in regulating large loads, either through regulatory bodies or legislation. Oregon, Minnesota, Indiana, Texas and Virginia are among the states that have passed laws governing how large load customers are treated by utilities. State regulators in Pennsylvania are developing a model large load tariff that could be applied to all utilities there. 

Collier said “time will tell” if the tariffs and other rules for large loads are effective, and the needs of each territory are different. But some early evidence appears to show that the tariffs can weed out speculative requests from the large load pipeline. 

AEP Ohio cut its large load forecast by more than 50%, from 30 GW to 13 GW, after regulators approved a new large load tariff last year, though manufacturers in the state say data center demand is still inflated.

“AEP has designed its large‑load tariffs, both those already approved and those pending across our jurisdictions, to ensure that large‑load customers pay their fair share of the costs to serve them,” Scott Blake, a spokesperson for AEP, said in a statement to Utility Dive.

“Our approach is focused on protecting existing customers from bearing the costs of grid upgrades or infrastructure improvements needed to accommodate these large new loads,” he added. “Each of our state jurisdictions has unique regulatory frameworks, but across all of them, our priority is ensuring fairness, transparency, cost causation, and long‑term system reliability as demand from large‑load customers continues to grow.”

Eberle said utilities should prepare for more scrutiny of their requests as regulators contend with a growing affordability crisis. 

“In some of these cases, the utilities are really asking regulators to approve things that, you know, they’re big resource commitments,” she said. “If a utility can also come in and say, ‘We’ve looked at grid enhancing technologies; we’ve looked at energy efficiency; we’ve looked at demand response; we’ve looked at all of these measures that can make this cost effective, and we’ve included them,’ I think that can go a long way.”

The Public Utility Commission of Texas on Thursday approved rules for the state’s grid operator to process large load interconnection requests, including data centers. The first set of projects to navigate the new process is called “Batch Zero.”

The Electric Reliability Council of Texas says it is tracking more than 438 GW of large-load requests, and nearly 90% are from data centers.

The PUCT’s decision mirrors a national conversation around data center load growth and how to interconnect projects to the electric grid. The Federal Energy Regulatory Commission on Thursday concluded most grid operators’ rules for large load interconnections are insufficient to the moment, and directed them to develop their own data center interconnection rules based on regional needs.

Under the Texas framework, ERCOT will look at batches of projects that are 75 MW or larger in a single study to “assess the full picture of future electricity demand at once,” the grid operator said.

Officials said the process will protect grid reliability and support economic growth while eliminating a project-by-project evaluation that had become “lengthy and repetitive” as large loads rushed to interconnect.

"Texas is experiencing an energy transformation unlike anything we have seen before," ERCOT President and CEO Pablo Vegas said in a statement. "This new process represents a fundamental shift in how ERCOT manages the significant growth of large load interconnection, providing a structured, transparent path forward.”

Texas data center announcements continue to mount. On Monday, Microsoft said it planned to build a 2-GW data center in Pecos, Texas, with the company funding all of the energy infrastructure.

Batch Zero applicants will be informed of their inclusion in the initial study in August, and ERCOT said a final transmission plan covering the batch is expected to be published in the fall of 2027. Applications for Batch 1 are expected to open in the summer of 2027.

“While not all interconnection requests result in built projects, ERCOT data shows the majority expect to be operational by 2030,” the grid operator said.

The grid operator also said the principles established through the Batch Zero framework will be the basis for an “ongoing, comprehensive transmission planning process” to be developed in partnership with stakeholders later this year.

The framework includes provisions for large loads to develop their own generation on-site. The process also creates a path to interconnect large load customers who agree to let ERCOT curtail their power use in response to local constraints.

“Facilities that are truly islanded with no grid connection would generally fall outside ERCOT's interconnection process, though they may still be subject to registration requirements with the PUCT,” the grid operator said.

Projects eligible for Batch Zero inclusion will meet a “maturity criteria” based on having completed certain steps, Jeff Billo, ERCOT vice president of interconnection and grid analysis, told commissioners before their vote. And the grid operator expects to allow projects to meet those qualifications through an attestation by an affiliate.

Texas energy expert Arushi Sharma Frank called ERCOT’s Batch Zero approach “the first market design that is ready-to-ship for large loads that actually solves reliability risk, transmission affordability, and siting loads to benefit all ratepayers, simultaneously.”

Sharma Frank, principal at Luminary Strategies, also noted FERC’s Thursday decision and said the federal regulator “punted the market design decision to dozens of individual utility operators” because of the need to take a regional approach.

“It is unavoidable. It is not red tape,” she wrote. “The physics of a grid determine what solutions work — ERCOT is lucky that its regulator directly governs physics-based solutions.”

FirstEnergy on June 5, 2026, urged the Federal Energy Regulatory Commission to require data centers to pay for transmission upgrades needed to bring them online instead of spreading those costs across existing customers as is current practice.

The proposal is based on a cost allocation method that has been used for natural gas pipelines for more than 25 years, according to FirstEnergy. It could be adopted without requiring legislation or “novel regulatory authority,” the Akron, Ohio-based utility company said.

The proposal faced pushback at FERC from Maven Solutions, a consulting firm specializing in AI infrastructure governance and other issues. “FirstEnergy’s framework guarantees the transmission owner’s cost recovery, collateralizes the transmission owner’s investment, and shifts all demand-forecast, utilization, and cancellation risk from the utility to the customer,” Jayne Algermissen, Maven Solutions founder and technical program manager, said in the filing.

FirstEnergy made its proposal as part of FERC’s consideration of possible rules for interconnecting data centers and other large loads to the transmission system. Cost allocation is one of the issues FERC is expected to tackle in that decision, which could be voted on at its June 18, 2026, open meeting.

With data center development facing public opposition across the United States, Amazon, Google, Meta, Microsoft, OpenAI, Oracle and xAI in March signed the White House “Ratepayer Protection Pledge,” saying they would pay for the power-related infrastructure needed to bring electricity to their facilities.

However, existing transmission rules won’t allow that to happen, according to FirstEnergy. Currently, the costs of building transmission infrastructure for data centers are spread across the zone where the infrastructure is built, the utility company noted.

FERC should look to its own rules that allow incremental pricing for pipeline infrastructure as a model for the transmission system, FirstEnergy said.

Under FirstEnergy’s proposal, data center customers would pay two rate components under 15-year contracts, which would include collateral and other requirements. Data centers would pay their share of the existing zonal transmission rate as well as an expansion rate for the costs of network upgrades needed to interconnect their facilities to the grid, FirstEnergy said.

“Doing so would protect households from unforeseen cost shifts, provide data center developers with predictable and financeable cost structures, and preserve the conditions necessary to build the transmission infrastructure the nation urgently requires,” the company said.

A data center’s expansion-rate obligation could be reallocated annually as new customers interconnect to the same transmission facilities, reducing the cost paid by any individual participant over time, FirstEnergy said.

The proposal avoids FERC’s prohibition on so-called “and pricing” — the practice of billing a customer twice for the same transmission capacity, FirstEnergy said.

“Each customer pays its pro-rata share of the zonal transmission rate, which covers the existing system; only the data center driving the expansion pays the additional expansion rate, which covers the new facilities built to serve it,” FirstEnergy said.

FirstEnergy’s proposal nods to consumer protection concerns, but it reflects the interests of a transmission owner with about 24,000 miles of transmission lines in the Midwest and Mid-Atlantic regions, Maven Solutions said.

Further, the proposal fails to consider communities that will be affected by data centers, Maven Solutions said, noting the opposition to data centers.

“A framework that assigns transmission costs while ignoring the communities standing next to the transmission facilities will not resolve that opposition,” Maven Solution’s Algermissen said. “It will deepen it.”

Any large load cost-allocation framework should include “anti-overbuild” safeguards, according to Maven Solutions.

“Where the utility’s cost recovery is secured by collateral and long-term agreements, the incentive to oversize facilities must be checked by independent engineering review,” Algermissen said.

Also, as part of a cost-allocation framework, large loads should be required to meet the North American Electric Reliability Corp.’s emerging reliability obligations for large computational loads, according to Maven Solutions.

The North American Electric Reliability Corp. on May 4, 2026, issued a rare Level 3 alert — the watchdog’s highest level — following instances of data centers unexpectedly dropping load or oscillating demand rapidly, creating reliability concerns. The alert includes seven actions grid entities “must implement to address immediate risks posed by computational loads,” NERC said.

Transmission planners and operators, system planners and balancing authorities are among the entities that must act. The required actions address the modeling, study, operation, protection and control of computational loads, including artificial intelligence training and cryptocurrency mining.

“The grid faces unprecedented challenges from a surge in large power consumers,” NERC said in a statement. Summer peak demand across the bulk power system is expected to rise 24% in the next 10 years, with data centers accounting for most of the increase, the organization said in its most recent Long Term Reliability Assessment, published in January 2026.

In the face of rising data center loads — and instances where they unexpectedly disconnected from the grid — NERC issued a Level 2 warning last year that elicited alarming responses from grid stakeholders, the reliability watchdog said.

“Entities generally did not have sufficient processes, procedures, or methods to address emerging computational loads,” NERC said in its warning. The essential actions NERC calls for include the following:

• Transmission planners and planning coordinators should develop a detailed list of modeling data, settings, and parameters needed from computational loads and distribute this to transmission operators in their footprint. Transmission operators should reflect this information in their facility interconnection requirements.
• Transmission planners and planning coordinators should collect data from computational loads such as the expected minimum and maximum consumption in megawatts and the percentage of IT load vs. non-IT load (cooling, for instance), at various load levels.
• Planning coordinators should revise definitions that trigger a review of local area protections, stability limits and other reliability studies to account for computational loads.
• Transmission operators should establish a “commissioning process” for computational loads.
• Where possible, the commissioning process transmission operators develop should include testing facilities at full load and at no load, and, if possible, with at least a 10% change from nominal voltage.
• Transmission operators should install and utilize dynamic fault recording devices to understand computational load facility electrical performance during system disturbances.

Registered NERC entities must acknowledge receipt by May 11 and must respond by Aug. 3.

Level 3 alerts, which are rare, call for grid operators to take specific steps in response to an immediate issue. NERC last issued a Level 3 alert a year ago regarding possible grid disruptions related to inverter-based resources. Solar, wind and battery resources have been known to trip offline during grid disturbances. 

Grid instability issues caused by data centers "could become quite severe — to the the point of creating widespread blackouts," Ben Inskeep, program director for the Citizens Action Coalition, told Utility Dive in an email.

"It is critical that we have standards in place to protect all ratepayers from negative impacts to grid stability, reliability, and resiliency that are caused by data centers, especially given the rapid proliferation of these mega users across the country," Inskeep said.

NERC’s efforts to better align utility and data center operations may take longer than anticipated, Digital Power Optimization CEO and founder Andrew Webber told Utility Dive. The company builds and manages data centers.

“It will take years of coordinated effort in the drafting of new regulations, understanding limitations and opportunities related to physical equipment, understanding limitations and opportunities related to software and control systems, re-prioritizing various loads all throughout society, etc.,” Webber said in an email.

He pointed to recent comments by Laura Swett, chair of the Federal Energy Regulatory Commission, about a lack of communication between data centers and energy regulators.

“Given the absolutely critical need [for data center developers] to source power for their developments, I found it quite interesting that FERC isn’t seeing more direct engagement from the data center industry,” Webber said. “I think it exemplifies the challenges NERC is also going to face in getting genuine buy-in and wholehearted acceptance by the data center industry as it pertains to grid reliability.”

“New evaluation paradigms will need to be created and worked through in partnership with the data center industry,” he said.