The grid is running into the machinery of its own reforms. PJM needs new firm capacity. Developers need turbines. Turbine queues are backed up. Interconnection rules were tightened to stop speculative projects. Now one serious gas project says those same rules could delay more than a gigawatt of dispatchable capacity.

That is the recurring theme this week. The country needs more power and faster grid access, but every solution runs into a process built for slower load growth. Columbia’s energy policy team says low-cost tools like GETs and demand response can cut pressure before customers get hit. Texas wants a 765-kV backbone for Permian load growth, while landowners argue they were not properly notified. FERC is forcing RTOs to rewrite large-load rules. DOE is offering $17.5 billion to revive large reactor construction. Everyone agrees speed is needed. The fights are over who gets charged, who gets delayed, and who gets to say no.

PJM told FERC it opposes a waiver request from Advanced Power Services that would let the company keep its Chestnut Run gas project in PJM’s fast-track Reliability Resource Initiative review. The project, located in Carroll County, Ohio, is a roughly $2 billion gas-fired plant owned by ArcLight-backed Advanced Power. The RRI process was built for shovel-ready projects and initially drew 51 projects totaling about 11.8 GW.

Advanced Power entered the RRI process using GE Vernova’s HA.03 turbine model and said the plant could be online by May 2030. Turbine backlogs have pushed that model out by at least two years. The company now wants to use GE Vernova’s HA.02 model, which would reduce the plant’s maximum output by about 550 MW while keeping the project close to its original schedule. PJM says the requested changes violate RRI rules that barred changes to project size and Capacity Interconnection Rights. Advanced Power says denial could delay more than 1.2 GW of firm, dispatchable capacity by about two years.

GridBrief Take: PJM is defending the integrity of a fast-track process created to stop queue games, and that concern is legitimate. The problem is that turbine scarcity is now colliding with resource adequacy. A waiver should come with strict conditions, updated milestones, and no special treatment on cost allocation. PJM also needs a process that can distinguish a real supply-chain adjustment from a developer trying to rewrite its bid after seeing the market.

Columbia University’s Center on Global Energy Policy released a commentary on electricity affordability and load growth that puts data centers inside the larger rate problem. The researchers identify several cost drivers: inefficient infrastructure planning, utility incentives that reward capital spending, underused flexibility, slow permitting, storm costs, wildfire costs, and supply chain inflation. Load growth from data centers compounds those pressures.

The report highlights near-term tools that already exist. Dynamic line ratings, advanced conductors, power flow controls, and other grid-enhancing technologies can increase capacity on existing infrastructure. Demand response can reduce peak demand, especially if large loads shape usage during constrained hours. Columbia also points to structural reform: better cost allocation for data centers, faster interconnection, permitting that connects price signals to actual supply, and utility regulation that rewards system optimization rather than only capital deployment.

GridBrief Take: Before regulators approve another giant capital plan, they should force utilities to show what dynamic ratings, reconductoring, demand response, and flexible large-load service can do first.

Several hundred Central Texas property owners asked the Public Utility Commission of Texas to pause review of the proposed Bell County East to Big Hill 765-kV transmission line. The line is part of Texas’ high-voltage buildout to support projected load growth in the Permian Basin and broader ERCOT needs. Landowners say utilities failed to properly notify affected property owners after route changes.

The filing says more than 1,300 directly affected property owners were denied a chance to attend public meetings before their land was included in the project footprint. Oncor says it began public meetings in summer 2025, modified routes based on feedback, and responded to thousands of public comments. PUCT staff recommended 765-kV lines based on a 2024 ERCOT study because they can move more power over longer distances with fewer losses. Hearings were held June 8-12. A final PUCT decision is expected in September.

FERC issued show-cause orders to CAISO, ISO New England, MISO, NYISO, PJM, and SPP after finding their large-load interconnection rules may be inadequate. The orders direct grid operators to address five areas: efficient study processes, cost-shift prevention, transparency into upgrade costs, co-location and behind-the-meter generation, flexible load services, and study processes for generation serving nearby large loads.

The commission chose regional proceedings rather than one national rule. That gives each RTO room to deal with its own grid conditions, but it also creates six separate timelines and six separate answers for developers. FERC’s orders also ask grid operators to evaluate alternative transmission technologies such as dynamic line ratings, advanced conductors, power flow devices, and synchronous condensers before defaulting to traditional network upgrades. RTOs and ISOs have 60 days to respond, with a possible extension process.

The Trump administration announced up to $17.5 billion in conditional loans to help utilities and energy companies purchase long-lead components for up to 10 Westinghouse AP1000 reactors. The loans would support up to five projects, each with two 1.1-GW reactors. The goal is to begin construction by 2030 and reduce timelines by ordering parts such as reactor vessels and steam generators in bulk.

The AP1000 is the only large advanced reactor design operating commercially in the United States. Vogtle Units 3 and 4 came online in Georgia in 2023 and 2024, but the project took about 15 years and cost around $35 billion, roughly double initial estimates. The DOE plan would require Westinghouse and utility partners to commit $500 million each per project before accessing federal funds. Seven utilities have expressed interest, according to Energy Secretary Chris Wright, though DOE has not named them.

GridBrief Take: Large nuclear will not return in the United States without solving the first-project risk problem. Bulk ordering can help rebuild the supply chain, but taxpayers should not become a permanent overrun account for one favored vendor. The cleanest nuclear policy is faster licensing, standardized designs, private offtake, credible cost-sharing, and no assumption that Washington can outguess construction risk better than balance sheets can price it.

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