DOE published the draft 2026 National Transmission Needs Study on July 9, 2026, and opened a 60-day public-comment period. Comments are due Sept. 7, 2026.

The study is required under the Federal Power Act. It identifies high-impact transmission needs and anticipated capacity constraints across the nation’s electric grid, according to DOE’s Office of Electricity.

Demand is changing the grid outlook

DOE said the assessment reflects electricity-load growth associated with data centers, expanding domestic manufacturing, large industrial loads and broader economic growth. Those trends are increasing the importance of long-distance transmission, which moves electricity between regions and helps connect generation with areas where demand is rising.

The study could influence future transmission investment, grid planning and permitting. It is an assessment rather than a construction authorization or final federal funding decision, and the draft does not by itself approve specific projects.

DOE said several regional grid organizations have recently approved some of their largest transmission portfolios. The agency identified the Midcontinent Independent System Operator, or MISO; the Southwest Power Pool; PJM Interconnection; and ERCOT as regions involved in those major portfolios.

The regional activity provides context for the national review. Transmission projects often require long planning timelines, coordination across utilities and grid operators, and decisions about how costs and reliability benefits will be allocated. The draft study is intended to examine those needs at a national level as electricity demand expands.

Public review runs through September

DOE said it plans to hold public roundtables during the summer of 2026 as part of the review. The agency will consider the comments it receives and incorporate them into the final study as appropriate.

That means the study’s conclusions remain subject to change. The July release is a draft, not a final federal determination about the size, location or timing of future transmission construction.

For electricity customers, the practical stakes are tied to whether the grid can add capacity quickly enough to serve new large users while maintaining reliable service. The study does not guarantee higher electricity prices, blackouts or construction of any particular project. Its significance is that it gives federal policymakers a formal assessment of where transmission constraints may limit future growth.

Broader grid investment context

The study arrives as DOE is also pursuing investments in transmission technology and grid infrastructure. The department previously announced an approximately $1.9 billion SPARK funding opportunity focused on reconductoring and advanced transmission technologies. DOE said project selections were anticipated in August 2026.

Reconductoring can increase the capacity of some existing transmission corridors, while advanced technologies can improve how the system uses available infrastructure. Those efforts are separate from the draft national needs study, but they reflect the same policy challenge: expanding or upgrading the grid as power demand grows.

Recent electricity data also point to increased system pressure in some parts of the country. The U.S. Energy Information Administration reported that net U.S. electricity generation rose 3.1% year over year in May 2026. Its monthly update also identified pressure on Texas peak demand as summer heat increased.

DOE’s next formal step is to complete the public-comment period, review submissions and prepare the final study. Until that process is finished, the draft offers a framework for evaluating transmission needs rather than a final list of projects or a commitment to build them.

The Virginia State Corporation Commission issued the order Aug. 5. The action applies to regulated utility transmission arrangements in the Commonwealth and addresses the growing demands that large data centers are placing on the electric grid.

The decision comes as Virginia continues to expand its position as a major data-center hub. The industry’s growth has raised questions about who should pay for new power infrastructure, how fast utilities should build it and whether the costs of serving large projects could affect households and businesses that are not responsible for that demand.

Costs tied to individual facilities

The order requires data centers to cover transmission infrastructure tied exclusively to their facilities. That separates those dedicated project costs from broader grid expenses that may be allocated among a wider group of electricity customers.

The governor’s administration had urged regulators to prevent costs dedicated to data centers from being spread across other ratepayers. The State Corporation Commission, however, is the independent regulator that issued the order.

The decision does not establish that electricity bills will fall statewide. Its significance is in how future infrastructure costs are assigned as data-center electricity demand grows. Virginia residents and businesses could be affected by whether project developers or general ratepayers bear the costs of expanding transmission capacity for new facilities.

The exact dollar amount of infrastructure costs covered by the order and the timetable for implementation were not identified in the public announcements available about the action.

Rapid expansion across Virginia

A July 28 report by VPM News and The Associated Press cited Cleanview tracking that counted 371 operating data centers and 438 planned facilities statewide. The figures show the scale of the development pipeline, but planned facilities are not the same as completed projects and may change as projects are added, delayed or canceled.

That distinction matters for the electric grid. Operating facilities already use power, while planned facilities represent potential future demand that may require additional generation, transmission or other infrastructure. The way those costs are assigned can influence development decisions as well as the bills paid by customers who use less electricity.

Virginia’s affordability and economic agenda also identifies energy development and data-center environmental standards as continuing state priorities. The competing goals are to support economic development while limiting the burden that large industrial projects can place on public infrastructure and natural resources.

Electricity and water pressures

The transmission-cost decision comes alongside concerns about the industry’s effect on water supplies. A separate study of eastern Virginia found that groundwater declines are likely because of population growth and industrial use, and it called for tighter regulation of data-center water use.

The study recommended stronger authority over industrial withdrawal permits and review of alternative water sources. Those recommendations address a different resource from the SCC’s transmission order, but together they show the range of infrastructure and environmental issues associated with data-center expansion.

For Virginia, the immediate regulatory question is how dedicated electricity infrastructure will be paid for. The broader policy question is how the state will manage a fast-growing industry whose demands reach across the electric grid, water systems and affordability debates.

The draft 2026 National Transmission Needs Study, issued by DOE’s Office of Electricity, examines high-impact transmission needs along with current and anticipated constraints and congestion across the national electric-transmission system. The study is required under the Federal Power Act.

DOE is seeking input from states, Tribal Nations, communities and regional reliability entities before it finalizes the assessment. The department also planned in-person roundtables during summer 2026 to give those groups an additional opportunity to participate.

Why the review matters

Transmission lines move electricity between power plants, communities and regional grids. The review comes as the electricity system faces new and expanding demands from data centers, manufacturing and broader electrification, according to DOE’s description of the study.

That demand is developing alongside a large pipeline of new generation. The U.S. Energy Information Administration reported that developers planned 86 gigawatts of new utility-scale generating capacity for 2026, a record-high amount in the agency’s March 1 outlook. Transmission planning will need to account for how and where that generation connects to the grid.

The draft study does not itself approve specific transmission projects. It also does not authorize construction or guarantee federal financing for any project identified in the assessment. DOE’s review is a planning and information-gathering step, rather than a final national transmission plan.

A broader federal focus on large electricity loads

The DOE review follows a separate Federal Energy Regulatory Commission action focused on how regional grid operators handle large-load customers. On June 18, FERC issued show-cause orders to six regional grid operators concerning tariff treatment for those customers.

FERC gave the operators 60 days to justify their existing tariffs or propose changes. Tariffs set the terms under which customers receive transmission and other grid services, making the proceedings relevant to how unusually large electricity users connect to the system and pay for service.

Together, the federal actions point to two related planning questions: where transmission capacity is constrained and how grid rules should account for customers whose electricity needs may be unusually large. The DOE study addresses national transmission needs rather than the system of one utility or one state.

What happens next

The public now has 60 days to comment on the draft study. The approved notice does not provide the exact Federal Register publication date or a specific calendar date for the close of the comment period, so the deadline should be confirmed through DOE’s formal notice.

After the comment period and planned summer roundtables, DOE is expected to use the submitted information as it finalizes its assessment. The department’s next assessment could help inform future federal and regional transmission planning, but the source material does not establish that every identified need will receive federal approval or financing.

For states, Tribal Nations, communities and reliability organizations, the immediate consequence is an opportunity to put local capacity concerns, anticipated demand and other transmission issues into a formal national review. For electricity users, the study signals that federal planners are evaluating how the grid should adapt to changing demand and new generation, but it does not by itself promise lower electricity prices or prevent outages.

The draft 2026 National Transmission Needs Study says additional transmission is needed for data-center load, manufacturing, industrial electrification, new generation interconnection, new load interconnection and congestion relief. DOE opened a 60-day public-comment period, with comments due Sept. 7, 2026.

The document is an assessment of transmission needs, not a final federal transmission plan. It does not order specific projects, authorize construction or provide funding. Its findings are intended to inform regional and interregional planning as grid operators respond to changing patterns of electricity demand and generation.

Demand is rising in several parts of the grid

DOE’s study covers the U.S. transmission system and identifies needs across MISO, the Southwest Power Pool, PJM Interconnection, ERCOT, NYISO, NorthernGrid, WestConnect and ISO-New England.

The report identifies NYISO, NorthernGrid South and MISO as areas with high potential for within-region transmission that could reduce congestion costs. Congestion is concentrated in roughly 5% of hours, according to the study, but those periods can create significant challenges for moving electricity through constrained parts of the system.

The draft also says interregional links can improve reliability and resilience while increasing the grid’s ability to meet demand growth. Those links can connect separate regional systems, although the study itself does not approve any particular project.

DOE says MISO, SPP, PJM and ERCOT have recently approved some of their largest transmission portfolios. MISO approved its largest-ever U.S. transmission portfolio in 2024, according to the department.

Large-load connections are already a federal focus

The study follows a separate Federal Energy Regulatory Commission action announced June 18. FERC ordered all six regional grid operators to justify or reform tariffs governing interconnections for large users, including data centers, manufacturing facilities and other energy-intensive customers.

FERC said faster interconnection must be accompanied by consumer protections and clear cost allocation. The commission’s action reflects a central issue raised by rapid load growth: connecting new facilities can require changes to the grid, and regulators must determine how those costs and risks are assigned.

The Associated Press reported that the FERC vote had national implications for energy-hungry artificial-intelligence data centers and raised questions about effects on ratepayers. The DOE study similarly treats data-center demand, industrial expansion and electrification as transmission-planning issues rather than isolated facility decisions.

What happens next

DOE is accepting public comments through Sept. 7, 2026. The department also plans summer 2026 roundtables with communities, tribes, states and regional reliability entities before preparing a final study.

Those steps could add feedback from the people and institutions affected by proposed transmission development, but the packet does not identify a final list of projects, a construction schedule or projected changes to consumer bills.

For now, the draft establishes the federal government’s assessment of where transmission expansion may be needed as electricity demand changes. Any specific projects, funding decisions, tariff changes or consumer-cost effects would require later actions outside the study itself.

The draft 2026 National Transmission Needs Study examines the United States electric-transmission system and was released with a 60-day public-comment period. The Energy Department said comments are due September 7, 2026.

The study is not a final federal determination. It identifies needs and provides information for planning, infrastructure investment and reliability decisions, but it does not itself authorize construction or guarantee funding for specific transmission projects.

What the draft identifies

The Energy Department’s Office of Electricity said the study addresses high-impact transmission needs, capacity constraints and congestion affecting national planning. The assessment covers multiple regional transmission organizations and independent system operators, including the Midcontinent Independent System Operator, Southwest Power Pool, PJM Interconnection and ERCOT.

Those systems manage or coordinate electricity transmission across broad areas of the country. Their inclusion reflects the national scope of the draft, rather than a decision approving one project or one regional plan.

The department identified several forces behind expected future transmission needs. Data centers are increasing electricity demand in some areas, while domestic manufacturing and other large industrial loads are also adding pressure. The study additionally points to economic growth as a driver of future grid requirements.

Transmission lines move electricity between generators and the communities and businesses that use it. When available transmission capacity is limited or congestion develops, moving power across regions can become more difficult. The draft’s findings are intended to help inform decisions about how the system should be planned as demand changes.

Why reliability is part of the question

The draft arrives as federal officials are also tracking broader reliability conditions. A May 29, 2026, assessment from the Federal Energy Regulatory Commission provided national context on reliability, generation retirements and summer grid conditions.

FERC’s assessment said generators planned to retire 8.1 gigawatts between summer 2025 and summer 2026. That figure is separate from the Energy Department’s draft transmission study: it describes planned generation retirements in FERC’s reliability assessment, not approved transmission construction or a forecast of immediate outages.

Together, the two federal documents provide context for why transmission planning is receiving attention. The DOE draft focuses on constraints and future needs, while the FERC assessment addresses reliability conditions, generation retirements and the summer outlook. Neither document, on its own, guarantees a particular project or establishes that consumers’ electricity rates will rise.

Regional plans cited by DOE

The Energy Department said MISO, SPP, PJM and ERCOT are among the major regional systems that have approved or pursued large transmission portfolios. DOE also said MISO approved its largest-ever U.S. transmission portfolio in 2024.

Those examples show that some regional planning activity is already underway, but they do not convert the draft national study into construction approval. The study’s role is to identify national transmission needs and help inform future planning and investment decisions.

For households and businesses, the practical significance is forward-looking. Decisions made through transmission planning can affect the reliability of electricity service, where new generation and large electricity users can connect, and how infrastructure investment is evaluated. The draft does not specify that it will directly increase electricity rates or guarantee new transmission projects.

What happens next

The public-comment period runs for 60 days, with comments due September 7, 2026. The Energy Department plans to review the submitted comments before issuing a final study.

Until that review is complete, the document remains a draft. Its findings may shape future discussions about transmission planning, grid reliability and investment as data centers, manufacturing facilities and other large users seek more electricity, but the next formal step is the comment process rather than immediate construction.

NERC must submit both the proposed reliability standards and related changes to its Rules of Procedure by December 31, 2026. The action, taken in FERC Docket RD26-7-000, addresses reliability risks associated with rapidly growing large electricity users, including artificial-intelligence and cryptocurrency data centers.

Why computational loads raise a reliability issue

The concern is not only how much electricity these facilities consume. Large computational loads can also change their demand very quickly. A facility may reduce or shift power use within seconds, creating a sudden imbalance that grid operators must manage through generation, transmission and voltage or frequency controls.

NERC’s large-load work identifies rapidly expanding computational facilities as a growing operational issue and points to customer-initiated load reductions and oscillations that can occur on very short time scales.

A separate July 22 event in the PJM Interconnection region illustrated why sudden load changes are receiving attention. Reuters reported that more than 3 gigawatts of data-center demand abruptly went offline after a transmission-line outage in northern Virginia. PJM reported a change in grid frequency but said the event did not affect reliability. The event occurred after FERC’s July 16 action and was not identified as the reason for that order.

What FERC ordered

FERC directed NERC to develop and file new or modified reliability standards addressing risks tied to integrating computational loads into the Bulk-Power System. The commission also directed NERC to propose revisions to its Rules of Procedure, including criteria for determining which computational-load entities should be included in the applicable registry.

That registry question matters because the July action does not automatically make every data center a NERC-registered entity. The criteria still have to be developed, filed and reviewed.

FERC’s public meeting page says its summaries are general synopses and are not substitutes for the individual Commission orders. FERC’s July 16 action notice separately confirms that the commission acted on the computational-load item under Docket RD26-7-000.

What does not change immediately

The July 16 action is a directive to develop and file standards. It is not a final nationwide operating rule that immediately imposes a complete new compliance regime on all AI data centers.

After NERC files its proposals, FERC will review them. The commission could approve, reject or require changes to the filings before any new standards take effect.

Why utilities and customers should watch

Future standards could affect how large computational facilities connect to the grid, what operating information they provide, how they coordinate with utilities and how they respond during reliability events.

Utilities and regional grid operators may need to account for both sustained demand growth and fast changes in demand when planning transmission, generation and system controls. Data-center developers could face additional technical studies, communications requirements or operating obligations if later proposals are approved.

Cost allocation is another issue to watch. The July action itself does not create an immediate nationwide increase in household electric bills. Later standards, interconnection decisions, transmission planning and rate proceedings could raise questions about which costs are assigned to large new customers and which are shared more broadly, but those outcomes remain unresolved.

What happens next

NERC’s first major deadline is December 31, 2026, for the proposed reliability standards and Rules of Procedure revisions. NERC’s broader large-load work also identifies a March 2027 milestone for an additional action plan. FERC review and possible revisions would follow.

For now, the practical takeaway is narrower: federal regulators are moving computational loads into the formal reliability discussion, but the detailed rules governing AI-era data centers have not yet been finalized.

Sources

• FERC July 2026 Commission Meeting Summary
• NERC Large Loads Action Plan
• Associated Press report on AI data-center grid connections
• Reuters report on the July 22 PJM disturbance

The process, called Batch Zero, replaces the previous project-by-project approach with a combined study of eligible requests. ERCOT will examine the batch’s reliability effects, available transmission capacity and potential transmission upgrades before classifying applicants.

The change comes as ERCOT tracks more than 438,000 megawatts of large-load requests. Nearly 89% of that figure is associated with data centers, according to ERCOT. The figure represents requests being tracked—not approved demand, committed generation or projects certain to be built.

What changed in Texas

Under Batch Zero, qualifying facilities of 75 megawatts or more can be evaluated together rather than moving through separate reviews. ERCOT says the grouped approach is intended to give planners a systemwide view of large-load growth and the reliability and transmission work that may be needed.

The process supersedes ERCOT’s legacy large-load interconnection procedure. ERCOT says the older procedure is no longer in effect and will be removed from its website on September 9, 2026.

Applicants faced staged submission deadlines. Several applicant forms, attestations and eligibility materials were due to the interconnecting distribution or transmission provider by July 10, 2026. The providers then had to submit the required Batch Zero materials to ERCOT by the end of July 24. ERCOT’s implementation page lists both dates and the responsibilities attached to them.

In a July 23 market notice, ERCOT said applicants that substantially met an eligibility criterion but could not satisfy a specific element could request a good-cause exception with supporting documentation. The notice did not create a broad waiver: certain study and qualification requirements were excluded from the exception process, and an applicant could be reclassified if ERCOT or the Public Utility Commission of Texas ultimately rejected the request.

Reliability options for large users

Batch Zero includes several pathways intended to address the strain that large projects could place on the grid. One involves onsite generation that supplies some or all of a facility’s electricity and reduces its reliance on the broader system.

Another covers withdrawal-limited private-use networks, which can combine large loads with associated generation under defined conditions. A separate pathway involves provisional controllable load resources. In practical terms, a qualifying user may agree to reduce or curtail electricity use when local transmission constraints require it.

These arrangements may affect how a project is studied or classified, but they do not guarantee service, prevent outages or eliminate future grid costs.

What happens next

ERCOT expects to notify Batch Zero applicants of their classifications in August 2026. Those classifications will be an important implementation step, but they should not be read as final interconnection approvals or guarantees that every request will be constructed.

The larger transmission picture will take longer. ERCOT expects to publish a final transmission plan for the full batch in fall 2027. That plan is expected to identify the upgrades that may be needed for projects that continue through the process, but the batch’s final size and transmission requirements were not settled as of August 5, 2026.

For Texas residents and businesses, the central question is not only whether large data centers can obtain power. It is also who pays for the transmission and reliability work needed to serve them, and whether existing customers are protected from costs linked to projects that may change or never materialize.

A national issue with a Texas test case

Texas is pursuing its own approach as federal regulators press other regional grid operators to address the same growth in electricity demand. On June 18, 2026, the Federal Energy Regulatory Commission directed six regional operators and their transmission owners to either justify their existing tariffs or file changes addressing large-load issues.

FERC’s orders identify five areas for review: faster transmission-service studies, protection against cost shifting, rules for co-located generation and behind-the-meter resources, services for flexible large loads, and studies of generation serving electrically proximate large users. The orders also required informational reports on serving existing and new large loads within 30 days, while tariff justifications or revisions were due within 60 days.

That federal action provides national context, but Texas’ Batch Zero process remains governed by ERCOT and the Public Utility Commission of Texas. The next major checkpoint is the August classification process. After that, readers should watch ERCOT and PUCT filings for reliability findings, transmission plans, cost-allocation decisions and evidence showing which proposed projects have a viable path to construction.

Sources

• ERCOT Large Load Integration: Batch Zero Interconnection Study Process
• FERC large-load integration orders

DOE released the draft 2026 National Transmission Needs Study on July 9, 2026, under the Federal Power Act. The agency is accepting public comments through September 7, 2026.

The study is not a national construction plan. It does not approve specific transmission lines, select projects or replace regional transmission-planning processes. Instead, it identifies current and anticipated national needs that could guide later investment and planning decisions.

What DOE found

The draft examines transmission needs linked to data centers, expanding domestic manufacturing, other large industrial users, electrification, new generation interconnections, new load interconnections and congestion relief.

DOE says most transmission congestion is concentrated in about 5% of hours, particularly during periods involving high net load, cold weather, significant intermittent generation or large differences between day-ahead and real-time market prices. The agency also identifies potential value from both additional within-region transmission and stronger interregional connections.

Those findings come as utilities and regulators consider how quickly electricity demand may grow and where new generation and large customers will connect. A July 17 report by Utility Dive, citing a Bank of America analyst forecast, said projected data-center growth could outpace planned utility capacity additions through 2030. That forecast is an independent market analysis, not a federal projection.

The study does not decide who pays

A central unresolved question is how to allocate the cost of grid upgrades. A transmission project may provide broader regional benefits, while a large new customer may require network improvements that would not otherwise be needed.

Policymakers and regulators are weighing whether those costs should fall primarily on the customer creating the need, be shared among a wider group of ratepayers or be assigned through another formula. The DOE study itself does not set household electricity rates or determine which customers will pay for future upgrades.

Those decisions generally emerge through regional planning processes, utility proceedings, federal and state regulatory actions, permitting decisions and rate cases. As a result, the study could influence later policy without directly changing a household’s bill.

FERC is examining large-load interconnections

The Federal Energy Regulatory Commission is separately examining how large electricity users connect to the interstate transmission system in docket RM26-4. FERC generally defines the large-load category in this proceeding as demand above 20 megawatts, including data centers and manufacturing facilities.

The docket is an advance notice of proposed rulemaking, an early-stage process in which FERC gathers input before deciding whether to propose specific regulatory changes. The commission is considering issues such as interconnection-study timelines, flexible or curtailable loads, reliability standards and whether large customers should pay the full cost of grid upgrades associated with their connections.

FERC also acted on June 18, 2026, when it directed six regional grid operators to justify or revise tariffs covering large-load interconnection. The orders address transmission-study processes, cost transparency, prevention of cost shifting, co-location and behind-the-meter generation, flexible large-load services and reliability reviews. The regional operators were given 60 days to defend or revise their tariffs and 30 days to submit reports on how they would ensure adequate generation for existing and new large loads.

What happens next

DOE is seeking comments from states, Tribal Nations, local communities, industry, regional reliability entities and the general public until September 7, 2026. The agency said it will review the submissions and incorporate them into the final study as appropriate.

For households and communities, the main issues to watch are whether the final study identifies different national needs, how regional planners respond to new demand, how quickly transmission projects move through permitting and whether regulators require large electricity users to bear the costs of upgrades they cause.

The draft begins a policy process; it does not authorize construction, set rates or resolve the cost-allocation debate. The consequential decisions will come through final agency actions, regional transmission plans, FERC tariff filings, permitting proceedings and utility rate cases.

Sources

• DOE’s 2026 Draft National Transmission Needs Study
• FERC Docket RM26-4
• Utility Dive: AI Data Center Growth and Utility Planning

Order No. 202-26-37 took effect July 26 under Section 202(c) of the Federal Power Act after a request from SPP. It directed SPP to dispatch specified generation units as needed to maintain reliability and authorized the operator to call on qualifying backup generation as a last resort before or during an Energy Emergency Alert Level 3.

The order covered SPP’s broader system footprint, which includes all or parts of 17 states. That footprint is different from the smaller East and West balancing-authority areas used in SPP’s operating notices. Conditions in one balancing area therefore did not mean every state or customer in the wider SPP system faced the same level of risk.

What the order authorized

The order created temporary emergency authority, not a permanent change to electricity-market rules. It allowed SPP to direct specified generation units and, if necessary, qualifying backup resources to support reliability during the most serious emergency conditions.

The authorization did not automatically require every listed generator or backup unit to operate. Independent energy reporting said no generation had been dispatched under the order as of July 27, while SPP and stakeholders assessed which resources could provide additional energy if conditions worsened.

That distinction remains important after expiration. The order itself does not show that backup generators were used, that every authorized resource operated, or that the authority prevented an outage.

What happened operationally

SPP’s public records show that reliability conditions varied over time and across its balancing areas. The West BAA reached Energy Emergency Alert Level 3 on July 20, before the July 26 DOE order took effect. SPP then moved through lower alert levels and said no controlled service interruptions were directed during that event.

SPP defines EEA3 as the highest of its three energy-emergency levels. At that stage, operating reserves are below required minimums, assistance through the reserve-sharing group has begun and the operator foresees or has implemented interruption of firm customer load. An EEA3 is not the same as a regionwide blackout.

The West BAA later remained under a Conservative Operations Advisory because of possible higher-than-expected loads, forced outages, hot temperatures and lower-than-forecast wind and solar output. SPP said the advisory represented stable operating conditions and did not require the public to conserve electricity. On August 3, SPP announced that the advisory would end at midnight on August 4 because conditions had improved.

Earlier reporting from S&P Global said SPP peak demand reached 56.553 gigawatts at 4:50 p.m. on July 27. That figure could have set a new peak, but SPP had not immediately confirmed the record when the report was published. The episode nonetheless showed how rising cooling demand, generator outages and uncertain wind output can tighten operating margins.

What expiration changes

After 11:59 p.m. CDT on August 3, the temporary federal authority in Order No. 202-26-37 was no longer in effect. The Department of Energy’s 2026 order list identifies the order’s expiration date and does not list a later SPP extension or replacement order.

The end of the order does not mean the wider reliability issue has disappeared. It means SPP no longer has that specific temporary federal authorization unless DOE issues another order.

For households and businesses, the practical issue is whether another heat spike leads local utilities or grid operators to issue conservation requests, emergency alerts or controlled-outage warnings. SPP’s regional notices do not determine whether an individual home or business will lose service, so customers should follow their local utility’s instructions.

Why the episode matters beyond SPP

The North American Electric Reliability Corporation’s 2026 Summer Reliability Assessment identified a broader set of pressures: accelerated demand, rapid growth in large loads, periods of low wind output and heat occurring alongside generator maintenance outages. NERC also said load growth had increased by more than 11 gigawatts from its 2025 summer assessment, even as new solar, battery and natural-gas resources strengthened readiness.

NERC’s assessment does not attribute the specific SPP emergency order to climate change. It does show why heat, demand forecasts, generator availability and variable renewable output are central to summer grid planning across the country.

The next signals to watch are any new DOE order, SPP alert or advisory, outage information and follow-up from the Federal Energy Regulatory Commission or NERC. The August 3 expiration ended one temporary federal tool; it did not eliminate the challenge of matching rising electricity demand with dependable supply during hot weather.

Sources

• DOE Order No. 202-26-37
• SPP Current Grid Conditions
• 2026 Summer Reliability Assessment
• S&P Global report on the DOE order

Emergency Order No. 202-26-37 took effect at 12:22 p.m. CDT on July 26 and is scheduled to expire at 11:59 p.m. CDT on August 3, unless the Energy Department renews it. It applies to SPP’s East and West balancing authority areas within the organization’s 17-state operating footprint.

What the order changes

The order allows SPP to dispatch specified generating units when needed to maintain reliability. It also permits SPP to direct certain auxiliary, standby and other backup resources to operate as a last resort before or during the highest-level Energy Emergency Alert, known as EEA 3.

The covered resources may include battery storage, directly connected generation and backup equipment at large-customer sites, including some data centers. These resources are one category of potential emergency supply; the order does not mean that every backup generator will operate.

The order also excludes backup equipment serving critical facilities such as hospitals, 911 centers, water-treatment plants and emergency-response operations. SPP must identify the resources needed for reliability and report their use to the Energy Department.

Why federal officials acted

The Energy Department said it found an emergency because of rising electricity demand, hot weather, possible generation and transmission outages, potential shortages of electric energy and the possibility of lower wind and solar output during peak periods.

The order cites Southwest Power Pool advisories issued in July concerning possible high peak loads, resource outages and uncertainty around wind and other variable energy production. The order remains in effect through August 3 unless it is renewed.

Southwest Power Pool is a regional transmission organization whose footprint covers all or part of 17 states. Its responsibilities include coordinating power flows, balancing electricity supply and demand, and managing regional responses during grid emergencies.

What the order does not mean

The order is a preventive reliability measure, not a declaration that widespread blackouts are underway. It gives SPP more operating options if conditions worsen, but it does not establish that firm customer load has been interrupted across the region.

The North American Electric Reliability Corporation’s 2026 summer assessment provides broader context. NERC identified rising demand, rapid growth in large electricity loads, low-wind periods and overlapping heat and maintenance outages as potential reliability challenges, while also noting additions of solar, battery and natural-gas resources.

What consumers should watch

Customers should monitor their electric utility’s outage pages, emergency alerts and any conservation requests during the highest-demand periods. The key developments through August 3 will be whether SPP activates additional emergency resources, whether utilities ask customers to reduce usage, whether outages occur and whether the Energy Department extends or lifts the order.

The immediate issue is regional reliability during a period of heat and high demand, not a confirmed nationwide or regionwide blackout. The order also illustrates how demand growth, variable renewable output, equipment outages and large new electricity loads can increase pressure on grid operators.

Sources

• U.S. Department of Energy Emergency Order No. 202-26-37
• Southwest Power Pool Fast Facts
• NERC 2026 Summer Reliability Assessment Snapshot

The Federal Energy Regulatory Commission held a commission-led technical conference on July 23, 2026, under docket AD26-7-000. The session examined PJM’s board authority, stakeholder voting structure, state participation, transparency, document procedures and filing rights under Section 205 of the Federal Power Act.

FERC did not issue a final reform order at the conference. Instead, the meeting was part of a fact-finding and policy-development process focused on whether PJM can respond quickly enough to changing operational and market conditions.

Why PJM matters

PJM coordinates the flow of electricity and administers wholesale power markets across 13 states and Washington, D.C. The organization says its system serves about 65 million people. It does not own most of the region’s power plants or transmission lines; it operates the system on behalf of many owners and manages markets for large blocks of electricity.

That role gives PJM decisions broad consequences for utilities, power producers, large electricity users and households in its footprint. Local utilities still send bills to customers, but wholesale-market and transmission decisions can influence the costs utilities must recover.

What regulators are examining

FERC’s agenda focused on whether PJM’s governance structure encourages accountability while allowing timely action. Questions included how independently the PJM board can act, whether sector-weighted voting creates delays, and how states should participate in decisions affecting reliability and electricity markets.

The conference also examined Section 205 filing rights. Those rights determine which parties can submit certain proposed changes to FERC for review. Expanding filing rights for states or PJM could give them more direct ways to bring proposals before the commission, although any change would still need to be formally adopted.

Other options discussed included making the stakeholder process primarily advisory, strengthening the independence of PJM’s board, creating faster review procedures for urgent issues and increasing transparency around documents and decision-making.

Why data centers are part of the debate

The governance dispute comes as electricity demand from data centers and other large loads is rising quickly. That growth is occurring alongside limited new generation, transmission constraints and concerns about whether the power system can maintain reliability while accommodating new customers.

Utility Dive reported that Swett said PJM has until the end of September to reach agreement on governance and stakeholder reforms. If that does not happen, she said FERC would impose its own changes. That statement describes an intended enforcement posture, not a completed commission order.

The Associated Press has also reported on a voluntary federal pledge intended to keep data-center development costs from being shifted to households and small businesses. That pledge does not settle how grid upgrades, new generation or transmission investments will be paid for.

What households should watch

The practical question is not whether every electricity customer will see an immediate change. The effect will depend on the reforms ultimately adopted, future capacity-market rules, new generation, transmission investment and decisions about which customers pay for infrastructure.

FERC is expected to hold a stakeholder dispute-resolution forum in September. Readers should watch for a formal PJM reform filing, additional FERC notices and any later order that changes board authority, stakeholder voting, state participation or cost-allocation rules.

For now, the July 23 conference marked pressure for change, not a final restructuring of PJM. The broader dispute is about who has enough authority to act when demand is changing quickly—and how to preserve accountability while protecting reliability and ratepayers.

Sources

• Federal Energy Regulatory Commission conference page
• Utilitydive
• PJM Learning Center

This public visualization is built to help readers explore study results—not to function as a project approval list. (Think of it as a way to ask better questions about why certain transmission paths show up as higher or lower “value” in modeling.)

What this tool is (and what it pulls from)

LBNL describes the Stage 1 tool as an exploration of the data and results from two studies: one published in Nature Communications and another report supporting the National Transmission Needs Study. In the tool, the studies use equivalent methods, but they analyze different sets of transmission links (the maps shown in the visualization).

What “links” means in the visualization

In this tool, a “link” is tied to the transmission network elements represented in the visualization—LBNL explicitly describes the transmission links as the maps used in the analysis.

Importantly, the tool includes a specific control called “Choice of transmission links”, which switches between two sets of analyzed transmission links.

What the July 1, 2026 webinar covered

On July 1, 2026, LBNL hosted a webinar titled “Exploring 2025 patterns in transmission value across the U.S. with LBNL’s Energy Market Value Tool.” The webinar is designed to introduce the tool and demonstrate how to use it, with a focus on 2025.

LBNL says the session includes case studies that investigate geographic patterns, seasonal trends, and shifts in expected trade balances, followed by a live demo and Q&A.

What the slide deck adds for readers

The downloadable webinar slides frame the session around three objectives: explaining recent trends and patterns in transmission market value, introducing and demonstrating the visualization tool, and showing how users can explore the transmission value data analyzed in the two referenced publications.

If you want to move from “clicking a map” to understanding what the tool is doing and what questions it can help answer, the slide deck is the best companion.

What to watch next (and what not to over-claim)

Because this is a modeling-and-visualization staging resource, it’s best used as context for planning discussions—not as proof that a particular upgrade is guaranteed, funded, or imminent.

What to take seriously instead: when you see arguments about congestion, reliability, or market outcomes, look for what transmission link set is being referenced and what the underlying study results are trying to show. LBNL points readers back to the cited publications for the full methods and interpretation.

Sources

• LBNL/EMP: Energy Market Value Tool (Stage 1 – Transmission Value)

One order directs specified units to operate as needed to maintain reliability. The second gives PJM authority, working with transmission owners and electric distribution companies, to direct backup generation at large loads such as data centers as a last resort before declaring an Energy Emergency Alert 3 or during one.

Why this matters

This is not a nationwide grid rule change. It applies to PJM, the regional transmission organization that FERC says manages reliability and wholesale power markets across all or part of 13 states and the District of Columbia. For households, the immediate point is simple: operators are taking temporary steps to manage expected peak demand.

PJM asked for the action on June 27 and again on June 29, saying extreme heat and high demand could strain supply. Reuters reported PJM was projecting peak load of about 159,563 megawatts on July 1 and 162,860 megawatts on July 2. Those are projections, not final demand numbers, but they show why the operator wanted backup tools ready before the worst of the heat.

What the backup-generator order changes

The second order is aimed at large power users first. PJM’s special notice says it requested permission to use emergency backup generation so transmission owners, electric distribution companies, and load-serving entities could coordinate in advance with large loads. Ordinary household customers were not told to switch to generators.

PJM’s Markets & Operations page showed a hot-weather alert already in place through July 3, signaling that operators were in active reliability mode while temperatures stayed elevated.

What to watch next

The key question is whether the grid holds through July 3 without deeper emergency steps or outages. If extreme heat lingers, PJM could issue more alerts, and DOE could extend or repeat emergency action. For now, the federal response is temporary and specific: keep the PJM system stable long enough to ride out the heat wave.

Sources

• U.S. Department of Energy press release: Energy Secretary Secures Mid-Atlantic Grid Ahead of Period of Hot Weather
• PJM Emergency Procedures special notice (Posting 105270)
• FERC PJM overview
• Reuters report: U.S. issues emergency order for PJM Interconnection as heatwave looms
• PJM Markets & Operations hot weather alert page