The Federal Energy Regulatory Commission voted unanimously to issue a notice of proposed rulemaking that would roughly double the cost thresholds for its blanket natural gas certificate program and expand the categories of pipeline projects eligible for streamlined review. The commission also received its 2026 Summer Energy Market and Electric Reliability Assessment, which flagged record capacity additions nationwide but warned that drought conditions could idle up to 4,500 megawatts of hydropower along the Colorado River system by August. All consent and discussion agenda items were approved on 5-0 votes.
Blanket Certificate Overhaul: Cost Caps, Compressor Stations, and Rate Protections
Item C-1 (Docket No. RM25-12-001) proposes the first major revision to FERC’s blanket certificate program since 2006. The NOPR would raise the automatic authorization cost limit from $14.5 million to $30 million and the prior notice cost limit from $41.1 million to $86 million. The annual cost limit for underground storage reservoir facilities would increase from $7.9 million to $17 million.
The rulemaking would replace the GDP Price Deflator with the Handy-Whitman Index for annual cost cap adjustments, a change intended to better track actual pipeline construction costs. Commission staff noted that the median cost per inch-mile of pipeline construction rose more than 250% between 2006 and 2024, while the existing index had attributed only a 50% increase over the same period.
The NOPR also proposes to remove cost limits entirely for in-fence-line expansions of existing compressor stations under prior notice procedures, harmonize the treatment of receipt and delivery points by removing cost caps for receipt points under automatic authorization, allow abandonment of facilities based on the actual cost of abandonment rather than replacement cost, and extend the in-service deadline from one year to two.
On ratepayer protections, the proposal would permit natural gas companies to charge incremental rates for prior notice projects—ensuring that only customers who benefit from a project bear its costs—and would require applicants to disclose the purpose and beneficiaries of blanket certificate projects. Applicants for prior notice mainline expansions would be required to demonstrate that existing customers benefit from the project.
Chairman Swett called the action a historic step toward accelerating natural gas infrastructure development, noting that FERC staff has reviewed nearly 6,000 pipeline applications and projects since the last major blanket program update. Commissioner Rosner said the reforms minimize impacts to landowners, communities, and the environment by making it easier to retool existing brownfield infrastructure rather than driving greenfield development. Commissioner See called the NOPR a model for streamlining efforts across other areas of the agency and expressed particular interest in the comment process around rate treatment for shippers and pipelines. Commissioner LaCerte said the rulemaking delivers on the president’s agenda to expedite project permitting and highlighted the provision for uncapped compression projects under prior notice.
The commission concurrently approved Item C-2 (Docket No. CP25-208-002), extending the temporary waiver of blanket program cost limits for an additional year, from May 31, 2027 to May 31, 2028, to provide industry certainty during the rulemaking process.
Summer Assessment: Record Capacity Additions, Rising Demand, and Drought Risk
Staff from FERC’s Office of Technical Reporting and Economics and Office of Electric Reliability, joined by the North American Electric Reliability Corporation, presented the 2026 Summer Energy Market and Electric Reliability Assessment. The grid is expected to add approximately 75 gigawatts of generation capacity this summer while retiring about 8 gigawatts—the largest year-over-year increase in new capacity in over a decade, with the rate of retirements slowing by more than 50% since last summer. Roughly 80% of new additions are solar, wind, and battery storage, concentrated in ERCOT, the Western Electricity Coordinating Council area, and MISO. Nearly 8,700 miles of new or upgraded transmission lines have been added since last summer.
NERC forecasts overall U.S. net internal electric demand to increase 1.3% to 790 gigawatts this summer, driven by data centers, electrification, and industrial activity. All NERC assessment areas are expected to have adequate resources under normal conditions, but three areas—NPCC New England, far west ERCOT, and the WEC Northwest—face elevated risk under extreme conditions including high peak load, generator outages, and wide-area extreme weather.
Colorado River Hydropower at Risk
The assessment’s most significant warning involves the Colorado River Basin. Lake Powell is projected to experience its lowest water inflow since Glen Canyon Dam began operations in 1964. Under the Bureau of Reclamation’s most probable forecast, the reservoir may fall to the minimum power pool level this summer, at which point hydropower generation at the dam’s one gigawatt of capacity would no longer be feasible. Without successful emergency actions, downstream facilities including the 2,000-megawatt Hoover Dam would also experience constrained operations, putting up to 4,500 megawatts of total Colorado River hydropower capacity at risk by August 2026.
The Bureau of Reclamation has announced emergency actions including releases from the upstream Flaming Gorge reservoir and significantly reduced water releases from Glen Canyon Dam. Staff noted that an updated forecast issued on May 18, 2026 is consistent with earlier projections and that continued monitoring is recommended.
Natural Gas Markets
Dry natural gas production is forecast to reach 109 billion cubic feet per day, rising for the sixth consecutive year. Gross LNG exports are forecast to increase 10% from last summer, reinforcing the U.S. position as the world’s largest LNG exporter. Henry Hub prices are projected to average $3.07 per MMBtu, a slight decrease from summer 2025. Eastern hub prices are expected to increase due to lower storage inventories following extended cold weather last winter, while western and mid-continent hubs are expected to decrease. Summer futures at the Waha Hub in the Permian Basin are trading at negative values due to high associated gas production and takeaway capacity constraints.
Staff said domestic natural gas prices remain relatively insulated from international LNG price volatility because most U.S. export terminals are operating at high utilization rates, leaving limited capacity to respond to higher international prices.
Transmission Congestion and Regional Risks
Staff identified far west Texas as a particular area of concern, where rapid load growth combined with low solar and wind output could overload transmission lines and create cascading thermal effects. ERCOT has implemented new interconnection reliability operating limits in the region and relies on price-responsive demand during tight periods, but permanent transmission relief is not expected until 2030. In New England, the region enters summer with only 409 megawatts of firm imports—roughly one-third of what was expected going into last summer—making it more dependent on non-firm transfers.
PJM Governance Conference and Interconnection Queue
Chairman Swett announced that FERC will convene a technical conference on July 23 to address PJM Interconnection’s governance and stakeholder processes, stating that the conference will not be an airing of grievances but will require participants to come with concrete, actionable reform proposals. Commissioner LaCerte said he has communicated directly with PJM that if stakeholder gridlock continues, independent action by the commission is a requirement, not an option.
On the consent agenda, the commission denied a complaint (Item E-1, Docket No. EL26-39-000) from Gaston Green Acres Solar, LLC and Bethel NC Hwy 11 Solar, LLC challenging PJM’s readiness deposit forfeiture structure. The developers sought penalty-free withdrawal after receiving significant network upgrade cost increases late in the interconnection process. The commission found that allowing late-stage refunds would shift costs to other viable projects and undermine queue certainty. Commissioner Rosner said he remains concerned about unpredictability in interconnection upgrade costs and pointed to SPP’s consolidated planning process as a model for reducing cost surprises.
Western Market Expansion
Multiple commissioners highlighted the launch of CAISO’s Extended Day-Ahead Market on May 1, the second new organized market to begin operating in the West this year following SPP’s RTO West launch on April 1. Commissioner Chang, who participated in a panel with the CEOs of both SPP and CAISO at the CREPC conference, said she is focused on how well the markets work together across the Western Interconnection and expressed concern that failure to apply lessons from years of market seams disputes in the East could expose the West to reliability issues and market exploitation. She called for additional reporting from both CAISO and SPP.
Gas-Electric Coordination Standards
Item G-1 (Docket No. RM96-1-044) is a final rule incorporating modifications to three NAESB Version 4.0 business practice standards designed to streamline access to publicly available gas-electric coordination data during extreme cold weather or emergency events. Commissioner Chang noted that the Interstate Natural Gas Association of America has indicated that pipelines could implement the new standards before the upcoming winter heating season and called for further industry input on force majeure and standardization of pipeline scheduling confirmation practices.
Other Notable Actions
The commission approved expansion of the Pine Prairie Energy Center storage facility in Evangeline Parish, Louisiana (Item C-5, Docket Nos. CP25-533-000, CP11-1-000, CP04-379-002). Commissioner LaCerte highlighted the need for more natural gas storage to relieve pipeline congestion, support the LNG export market, and provide system reliability during peak demand.
Commissioner LaCerte also noted progress on expedited resource addition processes at MISO and SPP following rehearing orders issued in January. SPP is advancing 13,262 megawatts of new resources concentrated in Oklahoma, Kansas, and Texas, while MISO is moving forward with 20,900 megawatts largely in Louisiana, Indiana, and Wisconsin, with most projects targeting in-service dates ahead of projected shortfalls.
Commissioner Rosner highlighted NERC’s May 1 report on wildfire mitigation, produced in response to a September 2025 commission directive. Multiple commissioners described recent site visits in California where they observed wildfire detection and mitigation technology. Commissioner Chang noted that wildfire risk has extended to the eastern United States and urged continued interagency work on the issue.
The commission also congratulated Commissioner LeCert on his Senate confirmation for a second term, approved by a 46-vote margin on May 19.
