The following entities updated their queue data this period: PJM, MISO, SPP, CAISO, ISO-NE, Idaho Power, PacifiCorp, Puget Sound Energy, Portland General Electric, NV Energy, BPA, Public Service Co. of Colorado, PNM, Tri-State, NorthWestern Energy, Southern Company, Duke Energy Carolinas, Dominion Energy South Carolina.

Additions: 16.61 GW (71 projects)

• MISO: 11.7 GW across 39 requests. 34 are DPP-2026 application-window requests (11.3 GW) without a fuel type. MISO also posted five surplus interconnection requests (400 MW).

• Non-CAISO West: 4.2 GW across 25 requests. About 3.4 GW of that is 12 Idaho Power affected system study records (”AFS”). These are projects already in PacifiCorp’s and Avista’s queues that Idaho Power is studying for impacts on its system, not new requests seeking to interconnect in Idaho Power.

• Southeast: 360 MW; SPP: 327 MW (two surplus requests, including a 252 MW battery in Cottle County, TX).

• By resource type (for requests that currently report a fuel type, excluding Idaho Power’s affected system records): solar+battery 715 MW, battery 400 MW and gas 320 MW. About 11.6 GW, nearly all of it MISO’s DPP-2026 requests, does not yet report a fuel type.

Withdrawals: 30.30 GW (164 projects)

• PJM: 21.4 GW across 127 projects. Cycle 1 accounts for 15.3 GW (51 projects) and Transition Cycle (TC) 2 for 6.05 GW (75 projects).

• Non-CAISO West: 6.3 GW across 18 projects. Idaho Power accounts for 2.3 GW, including two projects with executed IAs (1 GW solar+battery in Wyoming, 800 MW wind+battery in Idaho). Puget Sound Energy lost 1.8 GW and PSCo 1.4 GW.

• Southeast: 2.0 GW, led by a 711 MW Duke Energy Carolinas gas request and 11 Dominion Energy South Carolina projects (1.1 GW).

• SPP: 397 MW; CAISO: 120 MW; MISO: 100 MW.

• By resource type: gas 8.6 GW, battery 8.4 GW, solar 6.8 GW, solar+battery 3.2 GW.

Other Activity:

• GIAs: 56 projects, 14.6 GW.

• Newly operational: 7 projects, 739 MW.

In the News

• FERC delays PJM’s reliability backstop auction by five months. On September 29, FERC accepted PJM’s Reliability Backstop Procurement, a one-time auction for new capacity, but suspended it until February 28, 2027, while it reviews cost allocation, transmission owner exit rules, and load-serving entity collateral requirements. PJM did not open bidding on September 30 as planned and has not set a new date.

• Texas pauses state permits for data centers. As we covered in the last issue, on September 21, Gov. Abbott directed the Texas Commission on Environmental Quality (TCEQ) to stop issuing permits for data center projects until state audits of their effects on the grid, ratepayers, and water supplies are complete. The order appears to reach self-powered sites with on-site gas generation as well, which an August directive on grid interconnection had left untouched.

On the Docket

• PJM’s Interim Resource Adequacy Service (IRAS) and Large Load Registry. PJM is proposing that new loads of 50 MW or more that come online after June 1, 2027 would be curtailed before existing demand response unless they bring their own new capacity. That capacity must be new and offered into the capacity auction as a price taker for ten years. PJM asked FERC to act by Oct 12. (Docket ER26-3515-000)

• MISO’s Interconnection Reliability Requirements for Large Loads. MISO filed in late August to require new large loads to meet voltage ride-through and ramping standards, so that data centers and other large loads don’t trip offline or swing abruptly during grid disturbances. Loads that begin service by December 4, 2026 would be largely exempt. In comments filed September 18 through 24, Google backed MISO’s proposed “grandfathering” approach. The Data Center Coalition and Entergy argued that late-stage projects could miss the cutoff, while state regulators and consumer advocates questioned the usefulness of basing exemptions on development status. (Docket No. ER26-3650-000)

Activity Map

The big story this period is PJM’s Cycle 1 and TC2 withdrawals. Three areas in PJM account for most of the 21.4 GW of withdrawn project capacity:

• Northern Illinois: About 5 GW across 28 requests withdrew in the ComEd zone. These withdrawals split evenly between Cycle 1 battery and solar+battery requests and older Transition Cycle 2 solar projects.

• Virginia/Chesapeake region. Virginia had the most withdrawn capacity of any state within PJM, about 6.2 GW across 36 requests. Withdrawals also extend into Maryland and Delaware, where the largest exit is a 1.5 GW Cycle 1 gas request in Sussex County.

• Ohio and Indiana: This area of PJM’s footprint had fewer exits, but they were much larger, including the two largest withdrawals in PJM this period: Cycle 1 gas requests of 1.75 GW in Marshall County, Indiana, and 1.2 GW in Hancock County, Ohio.

In Southern Virginia, two 650 MW gas requests in Pittsylvania County and a 520 MW request in neighboring Henry County, all from the same developer, withdrew this period. Outside of PJM, we saw a second set of withdrawals in South Carolina, composed of mostly older transition cluster records from Dominion Energy South Carolina, along with a 711 MW Duke Energy Carolinas gas request in Spartanburg County that entered the queue in March 2026.

At first glance, the Pacific Northwest and southern Idaho look like the hub of additions to the queue this period. Most of those projects, however, are affected system study records filed with Idaho Power for projects already in the PacifiCorp and Avista queues, not new requests. Elsewhere in the non-CAISO west, Tri-State added a 715 MW solar+battery request in Hidalgo County, NM and a 50 MW geothermal request in Socorro County. Withdrawals across the region are scattered: Puget Sound Energy requests in Whatcom and Skagit counties, about 1.3 GW in central and south-central Montana, a 1 GW solar+battery project in southwest Wyoming and an 800 MW wind+battery project in south-central Idaho (both had signed interconnection agreements), and roughly 1 GW in eastern Colorado.

Signed interconnection agreements cluster in Oklahoma and Kansas this period, where six SPP gas projects from its expedited resource adequacy process signed this IAs this period. MISO’s roughly 12 GW of new requests are mostly missing from the map as we work to attach coordinates to DPP-2026 records. The main exception is a 1.4 GW Duke Energy Indiana request in Vermillion County, along the Illinois border.

Queue Activity

This period saw the most withdrawals since mid-August. About 30 GW left the queues and about 17 GW entered, for a net decline of nearly 14 GW. The two prior periods each saw only between 5 and 6 GW of withdrawals. As is typical for our bi-weekly updates, a few data releases drive the totals: PJM accounts for about 21 GW of withdrawals, and MISO for about 12 GW of new requests.

The headline added capacity figure of 16.61 GW overstates new entries this period. As noted above, about 3.4 GW of total new entries comes from 12 Idaho Power records that are affected system studies for projects already in the PacifiCorp and Avista queues. Excluding those, about 13 GW entered, mostly from MISO’s DPP-2026 application window which added 34 requests totaling about 11 GW. Outside MISO, genuinely new capacity was limited, led by a 715 MW Tri-State solar+battery request in New Mexico and a 252 MW battery in Texas seeking energy-only service (ERIS) through SPP’s surplus interconnection process. Like last period, the MISO DPP-2026 requests do not yet include a fuel type, so the technology mix is not quite as informative this period.

PJM’s withdrawals come from two separate cycles/processes. Fifty-one Cycle 1 requests totaling about 15 GW withdrew between September 22 and 25, just ahead of PJM’s penalty-free withdrawal deadline before Phase 1 began on September 28. Another 75 TC2 projects totaling about 6 GW withdrew on September 30, after PJM’s second decision point. We have network upgrade cost estimates for these projects as part of GridTracker, which we examine in the regional breakdown section below.

Gas accounted for the largest share of withdrawals this period at about 8.6 GW, with roughly 7 GW coming from PJM, including 7 Cycle 1 requests of greater than 500 MW in capacity. Outside PJM, about 9 GW withdrew. That total includes roughly 3 GW of projects with executed interconnection agreements, led by a 1 GW solar+battery project in Wyoming and an 800 MW wind+battery project in Idaho Power service territory.

Executed GIAs total about 15 GW, but roughly half of this total reflects status updates rather than new agreements. All 16 NV Energy agreements, about 6 GW, moved from suspended back to IA executed status, and several older BPA records reappeared. About 7 GW across 32 projects reflects agreements signed this period. SPP accounts for about 5 GW of that, including six gas projects from its Expedited Resource Adequacy Study (ERAS) process.

Queue Snapshot — Current State

Active capacity stands at 1.96 TW across 8,850 projects, down about 20 GW and roughly 140 projects from our last edition. The national queue is back below the 2 TW mark it crossed after PJM’s Cycle 1 release. Five technologies still make up about 91% of active capacity: battery at about 468 GW, solar at 434 GW, gas at 402 GW, solar+battery hybrids at 288 GW and wind at 195 GW.

Gas recorded the largest decline of any technology, about 17 GW over the past two weeks, mostly from PJM’s Cycle 1 withdrawals. This is the first meaningful drop in queued gas capacity we have tracked in recent months, and it widened the gap between solar and gas back to about 32 GW from roughly 23 GW. Gas remains up about 78% year over year, down from about 117% in our last edition.

Regional Breakdown by ISO/RTO

PJM had the largest net change this period, losing about 21 GW with no new requests. As noted above, these withdrawals come from (1) Cycle 1, PJM’s first cluster under its reformed interconnection process, and (2) TC2, the last of the transitional cycles PJM created to clear its legacy queue backlog.

About 15 GW across 51 Cycle 1 requests withdrew between September 22 and 25, in the days before Phase 1 studies began on September 28. Gas makes up the largest share of Cycle 1 withdrawals at about 7 GW across seven requests, followed by about 7 GW of battery and battery hybrid requests. PJM reports that 96 of the 715 projects accepted into the cycle withdrew before Phase 1, leaving 617 projects and about 169 GW in study. Since the Phase 1 study process is just getting underway for Cycle 1, we do not yet have cost estimates for these projects.

The TC2 cohort are mostly projects that originally entered the queue in 2020 and 2021. Seventy-five TC2 projects totaling about 6 GW withdrew by September 30, about three months after PJM posted their Phase II study results and asked developers to post a readiness deposit tied to their share of network upgrade costs. Unlike Cycle 1, these projects have cost estimates, which suggest that cost was a significant factor in withdrawal decisions.

Of the roughly 270 TC2 projects with Phase II results, those that withdrew make up about 28% of projects and 20% of capacity, but about 44% of allocated network upgrade costs, roughly $2.3 billion. Their median allocation was about $356/kW, compared with about $102/kW for projects still in study and essentially zero for the 12 projects that have already signed agreements. Of the 65 projects allocated more than $300/kW, 37 withdrew. Solar accounts for about two-thirds of the withdrawn capacity, and solar+battery projects carried the highest costs at about $750/kW.

Looking at zones within PJM, we see the same pattern. ComEd TC2 projects that withdrew averaged about $455/kW, about three times the roughly $160/kW for ComEd projects still under study. Some of the highest allocations belonged to small projects in western Pennsylvania and southern Virginia, where a 34 MW solar+battery project faced roughly $1,900/kW in upgrade costs. The projects that remain may see their allocations change in Phase III, as PJM restudies the cluster without the recently withdrawn projects.

TC2 has now lost about two-thirds of its capacity across three waves of withdrawals, two of which came shortly after PJM released cost estimates.

The non-CAISO West posted a net decline of about 2 GW. Its withdrawals include two projects that had signed interconnection agreements: a 1 GW solar+battery project in Wyoming and an 800 MW wind+battery project in Idaho. Puget Sound Energy withdrew six requests totaling about 1.8 GW, including a 700 MW hybrid project in Montana and two 188 MW gas requests in northwest Washington. The Southeast declined by about 1.6 GW, led by a 711 MW Duke Energy Carolinas gas request that withdrew about six months after entering the queue. SPP and CAISO saw only small changes this period, and ERCOT, NYISO and ISO-NE recorded no activity.

Notable Projects

It’s worth digging into the interconnection agreements signed this period. Most of the GIAs signed this period are for projects that were studied via expedited or limited-purpose paths rather than standard cluster studies.

The largest group comes from SPP’s ERAS process. Six ERAS gas projects totaling about 4 GW signed agreements this period: two Oklahoma Gas and Electric units at its Horseshoe Lake substation in Oklahoma City, two Evergy units in south-central Kansas, and two AEP units in Oklahoma. All six entered the queue in September and October 2025, roughly a year before signing an IA. Their allocated network upgrade costs average about $25/kW. Across the full SPP ERAS cohort, 11 projects have now signed agreements and the remaining 25 moved to pending agreement status on October 2. The process still ran later than planned, since SPP had expected to issue ERAS agreements by the end of March. The six projects that signed this period list proposed in-service dates between 2029 and 2030.

SPP also executed agreements for five surplus interconnection batteries totaling about 750 MW. The largest is a 400 MW battery in Henry County, Missouri. Most of these requests reached signed agreements within about 13 to 18 months of entering the queue. By comparison, a 215 MW wind project from SPP’s 2022 cluster, which also signed this period, took more than three and a half years and was allocated about $150/kW in upgrades.

In PJM, eight of the 12 TC2 projects that signed agreements this period are small gas additions at existing plants selected through the Reliability Resource Initiative, PJM’s one-time process for fast-tracking projects that could address near-term reliability needs. They include units at Dominion’s Remington and Possum Point stations in Virginia and at the Lordstown and South Field plants in Ohio. Together they total about 330 MW, and most were allocated no network upgrade costs.

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The following entities updated their queue data this period: NYISO, MISO, PJM, SPP, ERCOT, CAISO, ISO-NE, PacifiCorp, Portland General Electric, Black Hills Colorado Electric, Southern Company, Duke Energy Progress, LG&E and KU, and Tampa Electric.

Additions: 9.45 GW (44 projects)

• NYISO: 5.1 GW across 25 requests, all from their 2026 cluster (C26).

• MISO: 3.7 GW across 14 requests. Twelve of these are early DPP-2026 requests that do not yet disclose fuel type (DPP-2026 application cycle closes on January 15, 2027)

• West (non-CAISO): Two PacifiCorp gas requests totaling 585 MW.

• Southeast: 89 MW; SPP: 41 MW.

• By technology: battery 2.8 GW, gas 1.3 GW, wind 1.1 GW, solar 540 MW and solar+battery 130 MW.

• The average size of newly added projects this period is about 215 MW.

Withdrawals: 5.99 GW (33 projects)

• West (non-CAISO): 2.3 GW across 10 projects.

• PJM: 2.1 GW across eight projects, including a 1.3 GW gas request from Cycle 1.

• SPP: 605 MW; MISO: 598 MW; Southeast: 369 MW; NYISO: 20 MW.

• By technology: gas 1.6 GW, wind 1.4 GW, solar 940 MW, a 750 MW solar+wind+battery hybrid, battery 740 MW, and solar+battery 570 MW.

• Average project size: about 180 MW.

Other Activity:

• 21 projects executed GIAs this period totaling 2.3 GW. Twelve of these are from Southern Company (1.3 GW), including six nuclear uprate requests at Plants Hatch and Vogtle.

• 27 projects (3.6 GW) show up as newly operational. Roughly 2.0 GW of that reached commercial operation in August or September. The rest reflects delayed status updates from ISOs/utilities dropping in our data.

Policy Watch

In the News

PJM opens its 6 GW reliability backstop auction on Sep 30. PJM’s 2028/2029 capacity auction earlier this summer fell 6,831 MW short of the reliability requirement. The bid window for its Reliability Backstop Procurement will open on September 30th and run through October 21st, with results due by December 2nd.

The House passed the Ratepayer Protection Act (H.R. 9340) 417–3 on Sep 16. The bill requires states to consider standards so that loads over 100 MW pay the full incremental cost of grid infrastructure. The path for this bill to become law before the midterms is unclear, and the Senate is not expected to act before the midterm elections.

Virginia continues to grapple with data centers. On September 14th, Dominion and NextEra revised their $67B merger commitments in response to concerns from stakeholders, and doubled the duration of $10 bill credits for residential customers from two to four years. The Virginia State Corporation Commission (SCC) also mandated three in-person hearings across Dominion’s Virginia service area that will offer residents the opportunity to weigh in on the proposed merger. Separately, in late August, Microsoft filed a notice of appeal to preserve its challenge to the SCC’s July 31st order requiring data centers to pay upfront for direct-connect transmission.

On the Docket

MISO’s “zero injection” interconnection proposal draws broad support. MISO filed a Zero Injection Generator Interconnection Agreement (ZGIA) framework on Aug 18. It creates a 90-day study path for generators that serve large or co-located loads at the same substation and voltage. The proposal places limits on eligible projects: interconnection service cannot exceed the associated load’s peak demand, projects cannot require network upgrades beyond the substation (other than protection equipment), and each study cycle accepts only the first ten requests. This is MISO’s first filing responding to FERC’s large-load show cause order. (Docket No: ER26-3552-000)

Xcel Energy’s Southwestern Public Service Company (SPS) seeks approval for 570 MW of batteries using surplus interconnection rights. SPS is seeking Texas PUC approval of six battery storage purchase agreements with NextEra. The 570 MW of projects are co-located with existing NextEra renewable plants. Xcel/SPS want to use surplus interconnection rights to avoid SPP’s lengthy study process and high network upgrade costs. The Office of Public Utility Counsel (OPUC) in Texas, and others, want a large-load tariff that would require new loads of 50 MW or more to build, buy or bring their own generation. Initial briefs were filed on September 16th and 17th. (Docket No: PUCT 59034; SOAH 473-26-15924)

Good Reads

There is so much quality research coming out related to interconnection, large loads, and all things energy/the grid. Here is a non-exhaustive list of everything I’ve been reading (or, at the very least, bookmarking and planning to read).

• Luminary Strategies (Arushi Sharma Frank) released a detailed explainer of ERCOT’s Provisional Controllable Load Resource (PCLR) construct, which enables large loads to energize ahead of the transmission upgrades it would otherwise wait on. Rather than treating a data center as a fully firm obligation, the framework splits it into a firm planning floor and a larger dispatchable range that clears through nodal SCED, which makes batteries, onsite generation, and workload flexibility a way to buy speed to power.

• The Grid 2.0 Task Force published RFC #1, a draft protocol specification that would let large loads, batteries, and renewable assets voluntarily broadcast tiered flexibility requests each minute and receive proportional grid access in return, with the aim of unifying the one-off flexible connection structures now emerging separately in ERCOT, PJM, and SPP.

• A recent GridLab report on how California could use flexible demand, especially EV charging and discharging on the utility’s signal, to hold down rates while keeping the grid reliable.

• Berkeley Lab (LBL) and Brattle Group’s annual survey of large-load tariffs, discussing which terms utilities are converging on for data centers and other large customers.

• A study from Tyler Norris and researchers at Duke and LBL about whether energy-only interconnection service (ERIS) actually delivers a cheaper or faster path to the grid.

• An analysis by Piq Energy, using Base Power’s distributed battery fleet, testing whether coordinated dispatch of small batteries can free up enough room on the grid to connect a large new load without curtailment.

• An MIT CEEPR working paper measuring how much data center growth has raised retail electricity rates, and which customers and which kinds of utilities have absorbed the increase.

Activity Map

New York accounts for most of the new queue activity this period, with two main clusters of additions in the region:

• Battery storage requests along the Hudson Valley, in Ulster, Dutchess and Orange counties, totaling about 1.2 GW. Nearly all of these requests are four-hour battery storage systems.

• A pair of 380 MW wind requests in Franklin and Clinton counties, near the Canadian border.

Smaller storage projects on Long Island (Queens and Suffolk County) round out the activity in the state. MISO’s 3.7 GW of new requests this period is underrepresented on the map, because most of its DPP-2026 entries do not yet include a county or coordinates.

Withdrawals are scattered this period, with only one clear concentration in central Oregon, where five PGE requests totaling 1.75 GW withdrew from the Mountain View 500 kV substation in Jefferson County. Two smaller PacifiCorp also withdrew, in Lake and Umatilla counties bringing total withdrawn capacity in the region to about 2 GW. The largest exit from the queues this period is a 1.3 GW gas request from PJM in Columbiana County, Ohio.

Projects reaching commercial operation and signing GIAs cluster in Georgia, Alabama and Oklahoma. In Georgia and Alabama, Southern Company accounts for three newly operational projects (about 1.5 GW of battery and gas) and 12 executed GIAs (about 1.3 GW, led by battery storage and nuclear uprates). In Oklahoma, several of the projects newly marked operational in our data share a single SPP substation. More on that below.

Queue Activity

This was the second consecutive quiet period for the queues. About 9.5 GW entered the queues and just under 6 GW withdrew, for a net capacity increase of roughly 3.5 GW. The period from Aug 8th - 21st saw 23 GW of new requests and 56 GW of withdrawals, while the Aug 22nd - Sep 4th period landed closer to 10 GW and 5 GW of new additions and withdrawals, respectively.

Two queue data updates account for nearly all of this period’s new requests:

• NYISO posted 25 requests from its 2026 cluster, totaling 5.1 GW.

• MISO posted 14 requests totaling 3.7 GW, most of them early entrants into its DPP-2026 cycle.

The technology mix this period is not quite as informative as usual. MISO has not yet disclosed fuel types for requests in the DPP-2026 application window, so about 3.6 GW of this period’s additions carry no technology label and are currently labeled as “Other,” though we expect MISO to update their underlying data as they process additional DPP-2026 requests. Among requests with a disclosed fuel type, battery storage led the way at 2.8 GW, with gas at 1.3 GW, down sharply from the 8.4 GW of new capacity added between Aug 8th and Aug 21st. The queues also added 1.1 GW of wind. With MISO’s fuel types still unknown, we would not read the gas decline as a shift in recent trends in gas requests.

Gas accounts for the largest share of withdrawals at 1.6 GW, but a single 1.3 GW PJM request accounts for most of that total. Renewables and storage made up roughly three-quarters of withdrawn capacity, consistent with the pattern we have tracked all year.

More notable is how far along some of the existing projects were. About 830 MW of withdrawn capacity had executed interconnection agreements including five PJM solar projects that entered the queue between 2018 and 2020, and two MISO wind projects that signed GIAs in 2021 and 2022.

Looking at the projects that came online this period, we see 3.6 GW reaching commercial operation, but only about 2.0 GW did so during August or September. The rest of the capacity that changed COD status this period comes from utility/ISO data updates, including about 1.0 GW of SPP projects that have online dates between May 2025 and April 2026 and 590 MW of plants in Black Hills Colorado Electric built between 2011 and 2020.

Queue Snapshot — Current State

Active capacity stands at 1.98 TW across 8,993 projects, essentially flat over the last 6 weeks. The national queue remains just below the 2 TW mark it crossed briefly after PJM’s Cycle 1 release.

The composition of the queue barely moved this period. Five technologies still make up roughly 92% of active capacity: battery at about 477 GW, solar at 442 GW, gas at 419 GW, solar+battery hybrids at 288 GW and wind at 196 GW. The queues added about 10 GW of battery capacity over the past month and about 5 GW of gas, while solar was flat and both hybrids and wind edged down.

The gap between solar and gas continued to narrow, from 27.5 GW in our August 8th - 21st edition to about 23 GW now. Over the past month, gas has gained capacity while solar has held roughly steady. Battery storage is now slightly positive year-over-year at +0.5% after sitting at -3.9% as of August 21, driven by the new requests in New York.

Other year-over-year changes are consistent with recent queue trends. Thermal and firm resources continue to add capacity compared to 2025, with nuclear up about 250% to 33 GW, coal up roughly 130% to 7.5 GW, gas up about 117%, and geothermal up about 104% to 9.7 GW. Renewables continue their decline, with offshore wind down 63%, solar plus battery down 19%, solar down 13% and wind down 12%.

Regional Breakdown by ISO/RTO

Now let’s dig into recent changes by ISO and utility. NYISO posted the largest net gain this period, roughly 5 GW, bringing its active queue to about 36 GW. All 25 new requests are from its 2026 cluster. The fuel mix of these new requests skews heavily toward storage, and includes about 2.8 GW of battery requests, most of them four-hour systems ranging from 100 to 300 MW, along with two 380 MW North Country wind requests and a 199 MW wind project in Wyoming County, as well as about 530 MW of solar. The lone gas request in NYISO’s 2026 cluster is a 641 MW project located in Pennsylvania.

MISO added 3 GW of net capacity this period Its DPP-2026 cycle now includes 160 active requests totaling about 56 GW across its subregions. This period’s 14 requests are an incremental addition to that cycle, led by a 1 GW Ameren Missouri request. MISO’s three withdrawals were all older projects from the 2017 to 2020 study cycles, two of which had already signed GIAs.

PJM recorded no new requests and 2.1 GW of withdrawals composed of three Cycle 1 projects that entered in April and exited in September, including a 1.3 GW Ohio gas request, as well as five older solar projects that withdrew after executing GIAs. PJM’s reformed Cycle 1 has now recorded roughly 100 withdrawals totaling about 22 GW since its July data release. However, the bulk of the withdrawals (18 GW, 91 projects) withdrew before PJM publicly released data for the Cycle 1 cluster.

The non-CAISO West posted a net decline of 1.7 GW, driven by five Portland General Electric requests that withdrew at the Mountain View 500 kV substation POI in Jefferson County, OR. PacifiCorp’s two new gas requests (400 MW in Idaho and 185 MW in Utah) partially offset the region’s decline this period.

Both SPP and the Southeast posted small net declines of about 560 MW and 280 MW, respectively. The Southeast total includes five small gas requests, 17 to 19 MW each, that LG&E and KU withdrew at its Trimble County switching station. ERCOT was quiet again this period, and posted no additions or withdrawals. The non-ISO West remains the largest queue by active capacity, about 7 GW ahead of ERCOT.

Notable Projects

Existing power plants and interconnection rights continue to be a viable, and faster, path for new capacity seeking interconnection. In our Aug 8th - 21st issue, we highlighted Homer City and Merom, where developers are utilizing retired coal sites’ interconnection rights for new projects. This period, we are seeing similar developments with incremental and surplus capacity requests, and uprates at existing plants.

Six of Southern Company’s executed GIAs this period are incremental requests at Georgia Power’s Plant Hatch and Plant Vogtle, totaling about 255 MW. The requests add capacity on top of the plants’ existing interconnection service. They line up with the extended power uprates Georgia Power is pursuing at Vogtle Units 1 and 2 and Hatch Units 1 and 2, which were approved in its 2025 IRP. The company filed its latest semiannual status report on those uprates with the Georgia PSC on Sep 11 (Docket 56002). PacifiCorp also executed a surplus interconnection agreement for a 122 MW battery in southern Utah this period.

Looking at SPP’s Woodring 345 kV substation in Garfield County, Oklahoma, we can see some evidence of the shorter interconnection timelines with projects using surplus interconnection service, or capacity additions at sites with existing and excess interconnection rights.

• A 250 MW solar project and a 52 MW battery at Woodring substation each took about eight years from queue entry to commercial operation.

• A 200 MW battery at the same substation, requested under surplus interconnection service in 2024, reached COD in about a year and a half.

• A 72 MW solar project requested under SPP’s replacement process at Southwestern Public Service’s Cunningham station reached operation in under three years.

The largest withdrawal this period is a 1.3 GW gas request in Columbiana County, Ohio. It entered PJM’s Cycle 1 in April under the name West Field Energy Center LLC and withdrew on Sep 17th. While not the first withdrawal from PJM’s Cycle, it is the first large gas project to exit the cluster. Elsewhere in PJM, two Dominion-zone battery requests (300 MW and 90 MW) from Cycle 1 also withdrew in the same week as the Ohio gas plant. The queue filings do not explain the reasons for the withdrawals, but we will continue to watch whether PJM withdrawals ramp up as Cycle 1 moves through its first study phase.

Want to go deeper? GridTracker users get access to:

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While generator interconnection queues stayed relatively static for the past couple of weeks, policies governing large loads moved dramatically. This edition will focus largely on the most crucial policy updates that moved across regulators’ desks.

Quick queue stats:

• New entries: 10 new projects, totaling 1.17 GW

• Withdrawals: 11 projects, totaling 2.11 GW

• GIAs signed: 11 projects, totaling 1.67 GW

Policy Watch

Regulators have been moving fast to define how large loads will be managed in their respective territories, and the strategies are highly varied between jurisdictions.

What is a large load, anyways?

Regulators’ definitions vary widely. Here are just a few examples:

So SPP’s and Georgia’s definitions differ by a factor of ten. FirstEnergy in Ohio has asked to apply its data center tariff to any data center of any size at all.

A 40 MW facility could simultaneously be a regulated data center under AEP Ohio’s tariff, an ordinary commercial customer in Georgia, Texas and Oklahoma, and, if you interconnect at 69 kV or below anywhere in SPP, already a High Impact Large Load at the federal level.

One caution before you use these numbers to plan anything: a threshold marks the point above which a regime definitely catches you. But falling below it does not make you safe from the “large load” treatment. PJM has reserved the ability to spread backstop costs across all load in a zone when the local utility declines to assign them, so a 40 MW facility in Ohio may end up paying for capacity it was never originally classified as needing.

Texas: the load queue is frozen, but the rulebook is finally coming into focus

Governor Abbott sent a letter on August 3 directing the PUCT and ERCOT to run a “comprehensive verification and audit” of every data center in the interconnection queue before any more advance. ERCOT missed its August 7 classification deadline and the Batch Zero study slipped. It did get one critical piece out the door, though. On September 3, it told developers which projects it treats as already cleared and which still have to go through the study. Those calls are provisional and projects can still move between the two categories. The study itself is waiting on Abbott’s audit.

ERCOT can afford to be choosy, even hard-nosed. The queue holds more than 1,800 projects representing over 474 GW, roughly 90% of it data centers, against a grid whose record peak sits under 90 GW. Significant attrition is unavoidable, so from ERCOT’s perspective, it may as well happen on their terms.

The same day ERCOT was sorting projects, PUCT staff filed the recommended adoption order for new 16 TAC Sec. 25.194, the rule implementing SB 6. It’s 280 pages, and it finally puts a clear price on withdrawal.

A large load posts $50,000 per MW to get into the study. It gets 20% back at energization, and the rest in 20% increments as it hits the milestones for paying its minimum billing demand. Withdraw after ERCOT has handed you transmission capacity, though, and you forfeit: 20% if you were studied load, and 50% if you were base load that had studies and permits and stopped there.

Keep in mind that staff recommended the rule, and the signature block is still blank.

Order Adopting New 16 TAC 25.194: GridTracker subscribers can view the filing here

Ohio: the hyperscalers showed up in person

Reply comments closed August 25 in FirstEnergy’s data center tariff case, and the filers include Google and Amazon Data Services directly.

The fight is over the definition of a data center, so let’s start with what FirstEnergy proposed. The PUCO ordered the company in May to file “an application for tariff approval creating a separate class for data centers to assure that future costs are properly allocated to data centers.” FirstEnergy’s June filing defines that class by what a customer does: a centralized facility used primarily or exclusively for electronic information services. Notably, no megawatt floor appears anywhere in that definition. A 15 MW back-office data center for a bank lands in the same class as a gigawatt AI campus, and a 500 MW steel mill is excluded entirely from the same responsibilities that those data centers incur. The tariff also catches mixed sites, so a factory with enough servers on the premises can find its entire electric service billed under Schedule DCT unless it pays to meter the two loads separately.

Google wants Ohio to key the tariff to load size at the federal 50 MW line instead. That swaps the criteria: large manufacturers come in, data centers under 50 MW drop out, and the eventual PJM backstop bill gets divided across every big load in the zone rather than landing on data centers alone.

Google’s stated reasoning is cost allocation. PJM plans to hand each zone a bill for the backstop capacity it is procuring and leave the state to decide which customers pay it. If Ohio’s tariff covers a different group than PJM’s 50 MW definition does, the utility has no mechanism to charge that 500 MW steel mill for costs PJM says it caused, and the unassigned share spreads across every customer in the zone, residential included.

Ohio’s manufacturers arrive at the same definitional point from the other direction, arguing that singling out an industry is discriminatory under state law. PUCO Staff and the Consumers’ Counsel want the opposite, a tariff aimed squarely at data centers at 25 MW and above. Amazon leaned on the White House ratepayer pledge it signed and asked for cost-causal treatment with enforceable commitments.

Three days later AEP Ohio issued revised Schedule DCT sheets. Above 25 MW there, you take a four-year maximum ramp with capacity floors of 50/65/80/90 percent, an 85% billing demand floor after that, a $20,000 monthly charge at transmission voltage, and 180 days’ notice plus the full cost of a procurement if you want to return to standard service.

GridTracker subscribers can see Google’s reply comments here

Georgia: OpenAI’s 3.2 GW cleared, and the residential commitment doubled

Georgia Power has now run seven large load contracts through the review process the Commission set up in 2025. The customers are confidential, since each contract and its supporting documents are filed as trade secret in their entirety, but the sizes are public. In order of approval: 180 MW, 800 MW and 901 MW cleared in October 2025, 1,400 MW in December, 523 MW in March, and another 1,400 MW in April. Those six come to roughly 5.2 GW.

The seventh is 3,210 MW by itself.

That one is OpenAI’s, for a campus in Effingham County. Georgia Power filed it for Staff review on July 15. On August 12, Sierra Club, the Southern Alliance for Clean Energy and NRDC wrote to the Commission asking Staff to object and urging rejection unless the contract carried protections strong enough to keep existing ratepayers off the hook for what they called “this extraordinarily large new load.” It was deemed approved two weeks later, on August 26.

However, the approval came with a price. Georgia Power had already committed to filing its 2028 rate case in a way that puts at least $8.50 a month of downward pressure on a typical residential bill through 2029 to 2031. The same joint statement that cleared the OpenAI contract raised that floor to $15.00, conditional on enough contracts materializing to fill the certified capacity.

Georgia also defined the failure case. If a data center terminates early, Georgia Power will absorb the resulting revenue deficiency rather than seek it from customers below 100 MW. Whatever survives termination payments and mitigation goes to the Commission, which may assign it to other large load customers.

Seven contracts in, the residential commitment has nearly doubled. And the most recent contract is now worth nearly two thirds of the first six combined, which is a stark signal of how quickly the leverage is moving on both sides of the table.

GA Sources (Links require GridTracker access)

The story:

• Joint Statement of Commission Staff and Georgia Power, August 26, 2026. Carries the seventh contract’s approval, the $8.50 to $15.00 increase, the Non-Large Load definition, and the early-termination provisions

• Joint Letter on Data Center Load Growth and Ratepayer Protections, August 12, 2026. Sierra Club, SACE and NRDC name the OpenAI contract, put the load at 3.2 GW, and urge rejection

• Notice of Filing, seventh large load contract, July 15, 2026. The 3.2 GW OpenAI contract filing, trade secret in its entirety

• Large Load Incremental Revenue Filing, August 27, 2026. Sets the minimum revenue estimate the $15.00 floor depends on

The seven executed contracts, in order of approval:

• 180 MW, approved October 9, 2025

• 800 MW, approved October 16, 2025

• 901 MW, approved October 23, 2025

• 1,400 MW, approved December 26, 2025

• 523 MW, approved March 30, 2026

• 1,400 MW, approved April 20, 2026

• 3,210 MW, approved August 26, 2026

If you don’t have GridTracker access, we still love you: all filings can be found in Georgia PSC Docket No. 44280.

Oklahoma: a judge blessed bring-your-own-generation

An Administrative Law Judge recommended on August 21 that the Corporation Commission adopt a large load tariff negotiated by Google, the Commission’s own Public Utility Division, and the Petroleum Alliance of Oklahoma. The Attorney General signed it, but later withdrew.

The tariff’s self-supply option lets a customer above 75 MW build its own generation, serve its own load, and keep Public Service Company of Oklahoma (PSO) as its retail supplier of record. That route requires no collateral, and the contract runs ten years, the shortest term allowed by statute. Taking PSO’s generation instead would require posting collateral worth 48 months of non-fuel minimum bills and signing a fifteen-year contract. The Administrative Law Judges (ALJ) found the arrangement smells like wheeling while stopping just shy of it, since PSO remains the retail supplier.

Exceptions were filed September 1, and the Commission has scheduled an en banc hearing for October 1.

One provision in HB 2992 deserves more attention than it has gotten. A large load customer that buys rural land outside a municipality has 60 days to notify the Commission, the county, and every abutting landowner by certified mail. Missing that deadline costs $1,500 per day, per violation.

Developers will probably read that penalty as a potential line item rather than a deterrent. The letters themselves cost almost money to send, but the real cost is anonymity, and anonymity during land assembly is worth far more than the fine, because the moment the neighbors know a deep-pocketed buyer is assembling next door, every nearby landowner’s price will go up. At roughly $547,500 a year, a developer putting together a multi-gigawatt campus may view the penalty as a rounding error.

Two things could change that math. First, the statute never defines a “violation.” So if each un-notified neighbor counts separately, then the annual figure multiplies. Second, it reaches only entities that purchase land, and doesn’t say anything about options and leases, which developers routinely use to tie up parcels instead of outright parcel purchases.

ALJ report, PUD 2025-000075

Utah: large loads can leave the utility’s generation service and keep its transmission

Reply comments landed September 4 in Utah’s rulemaking on its Large-Scale Electric Service Act, and the framework differs markedly from those discussed above.

Utah’s law, in effect since May 2025, lets a customer expecting to reach 100 MW within five years buy its power from someone other than the utility. The customer signs a large load contract with a large-scale generation provider, which is a non-utility that registers with the Commission, and takes service one of two ways.

Option 1: A connected generation system plugs into Rocky Mountain Power’s transmission and runs independently of the utility’s own fleet.

Option 2: A closed private generation system sits physically disconnected from the grid and feeds the customer directly.

Once that large load contract is in place, the statute says Rocky Mountain Power, “has no duty to serve a large load customer except as explicitly provided in a large load contract,” owes it no backup power beyond what the contract spells out, and can refuse to buy any power a connected system sends back. In the connected case, the load customer still uses the utility’s transmission. It just stops being the utility’s job to keep them supplied.

So the rulemaking is a negotiation over the terms of that exit. How long does the utility get to verify that a private system is genuinely isolated from the grid? Rocky Mountain Power wants seven business days, counted from the moment it holds complete documentation rather than from the customer’s first request.

Who pays for the transmission that already exists? Rocky Mountain Power proposed a peak demand charge pulled from its FERC-approved rates, which sidesteps running a fresh cost study inside the Act’s 60-day window for filing a contract. A third question is whether any of this reaches the distribution system, and Rocky Mountain Power says the statute grants no open access there, only service under an agreement with the company.

Everywhere else on this list, regulators are writing rules for getting large loads connected and served: what they post up front, and what they commit to over time. Utah’s law heads the other way. It lets a registered non-utility take over supplying the customer, leaving Rocky Mountain Power as the transmission provider with no obligation beyond whatever that individual large load contract spells out. The money question in it is how much of Rocky Mountain Power’s embedded transmission revenue requirement a customer still owes after it leaves the utility’s generation service, and how much shifts to the customers who stay.

Rocky Mountain Power’s reply comments

Why all of this is happening at once

Every jurisdiction here is grappling with the same load growth, and their solutions differ because each market is unique.

FERC ordered all six RTOs and ISOs on June 18 to justify or reform how their tariffs handle large loads. That reaches two states on this list. Ohio sits in PJM and Oklahoma sits in SPP, so both will eventually have a federal wholesale definition to reconcile against. ERCOT sits outside FERC’s jurisdiction over transmission rates and wholesale sales, so the FERC orders don’t apply there. Texas had already established its own framework in SB 6. Georgia and Rocky Mountain Power’s territory in Utah have no RTO and no federal large-load docket at all, so a state contract review process and a state statute will need to define their entire framework.

Of all the states discussed in this post, the one with the nearest deadline is Ohio. PJM’s capacity auction for 2028-2029 came up short, and PJM is running a one-time backstop procurement to fill the gap, with commitments running as long as 15 years. The offer window is targeted to open September 30, pending FERC’s acceptance of the filing.

When it clears, PJM assigns the cost to each utility zone and leaves the states to decide how it gets distributed to retail customers. That is the question Ohio has been arguing about all summer, and every state in the PJM footprint will need to grapple with their portion of the costs.

Activity Map

Queue Activity

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The following entities updated their queue data this period: NYISO, SPP, MISO, PJM, CAISO, ISO-NE, Arizona Public Service, Bonneville Power Administration, Duke Energy Progress, Idaho Power, Jacksonville Electric Authority, LADWP, PacifiCorp, Santee Cooper, SMUD, Tampa Electric, Tennessee Valley Authority, Tri-State Generation and Transmission.

Additions: 23.4 GW (82 projects)

• Southeast: 7.9 GW, the largest of any market. Tennessee Valley Authority (TVA) accounts for 6.9 GW across 9 requests.

• West (non-ISO): 5.6 GW.

• MISO: 4.4 GW, including five Expedited Resource Addition Study (ERAS) requests.

• NYISO: 4.4 GW.

• SPP: 1.0 GW.

• By technology: gas 8.4 GW (36%), battery 4.4 GW (19%), and coal 3.3 GW (14%), with the remaining queue additions composed of mainly solar hybrids, wind, and standalone solar.

• Gas and coal together were 50% of all new entries. Storage in some form was 30%.

• Average project size: 286 MW.

Withdrawals: 55.5 GW (179 projects)

• The non-ISO West accounts for roughly 85% (46.9 GW, 119 projects) of everything withdrawn.

• Bonneville Power Administration (BPA) alone saw 24.7 GW of withdrawals across 58 projects.

• LADWP: 14.8 GW across 27 projects.

• Southeast: 4.8 GW across 34 projects.

• SPP: 2.0 GW across 10, mainly from the DISIS-2024-001 cluster.

• By technology: solar plus battery 18.72 GW, battery 16.53 GW, other hybrid configurations 6.26 GW, gas 5.91 GW, solar 4.07 GW, biofuel 1.44 GW, wind 1.07 GW, pumped storage 600 MW, compressed air 500 MW, hydrogen 346 MW.

• By technology: storage configurations led withdrawals at 41.5 GW (75%). Gas (5.9 GW) and standalone solar (4.0 GW) make up the remainder.

• Average project size 310 MW.

Other Activity:

• 31 projects executed GIAs totaling 5.6 GW.

• 21 projects (4.1 GW) reached commercial operation, with gas (2.4 GW) accounting for 58% of capacity coming online in the data.

In the News & On the Docket

• All six grid operators answered FERC’s large load show cause orders on August 17. FERC issued the orders on June 18 and directed each RTO and ISO to demonstrate that its tariff appropriately handles the interconnection of large and co-located loads. CAISO circulated a large load straw proposal on August 12 that proposes defining a large load as “a new commercial or industrial customer, located at a single site behind one or more points of interconnection, and that has a peak load of 50 MW or greater, interconnects to the transmission system at a voltage level of greater than 69 kV, and is not part of a colocation arrangement.” The proposal also outlines two flexible interconnection service options, with a full FERC filing expected in November.

• ERCOT Batch Zero. The Public Utility Commission of Texas discussed Governor Abbott’s directive to verify and audit all data centers advancing through ERCOT’s large load interconnection process. ERCOT has paused Batch Zero classification and study activity until that verification is complete, and it will not authorize data centers or other large loads to energize in the meantime. ERCOT is implementing the directive through two workstreams:

  • Batch Zero eligibility check, where ERCOT will ask developers with loads of 75 MW and above to produce documentation certifying their projects met the entry criteria.

  • ERCOT will also collect and report information from computational loads of 25 MW and above on grid and water usage, onsite generation, public financial assistance, ownership, and community impacts.

Activity Map

The majority of the queue activity this period comes in the form of withdrawals, concentrated in the Pacific Northwest and Southern California. BPA’s withdrawals (24.7 GW across 58 projects) in Oregon and Washington are all Transition Cluster projects added between September 2021 and November 2023. The California withdrawals are from LADWP and center in Los Angeles County (12 projects, 7.8 GW) and Kern County (7 projects, 2.0 GW), with an additional 2.3 GW across six projects on the Nevada side of its footprint in Clark County. Nearly all the withdrawn LADWP capacity is solar and storage. Solar+battery hybrids account for 8.8 GW (13 projects) and another 3.1 GW of standalone battery capacity withdrew. Elsewhere in the non-ISO West, 1.6 GW of gas withdrew from Arizona Public Service’s queue.

New queue requests are more evenly distributed this period. Colorado added 3.6 GW of new capacity via 21 Tri-State Generation and Transmission requests, part of a 28-request, 5.2 GW update that also extends into New Mexico and Wyoming. The bulk of other newly added capacity is spread across the Midwest, mid-South and Southeast. NYISO also added two requests in Homer City, PA totaling 4.4 GW, which we discuss in more detail below.

Projects recently executing GIA agreements cluster in Alabama, Georgia, and the Carolinas courtesy of Southern Company and Duke Energy progress. Southern Company accounts for 15 of the 31 agreements executed this period, twelve in Alabama and three in Georgia, totaling 1.5 GW. Duke Energy Progress accounts for four more totaling 1.7 GW across North and South Carolina. ERCOT, which usually updates its queue data regularly, is notably absent this period with no new additions or withdrawals.

Queue Activity

Last period, we saw a huge influx of new queue capacity, mainly coming from the first cycle of PJM’s newly reformed interconnection process. Over the last two weeks, new requests fell by 90% to just over 23 GW while withdrawals are up more than tenfold to 55.5 GW, resulting in a net reduction of 32.1 GW. While the capacity entering the queues over the past two weeks seems relatively small, especially compared to last period, it is within the normal range for a two-week period over the last 12 months, and is a function of the uneven cadence of ISO and utility queue data updates. On the other hand, the 55.5 GW of withdrawals this period is the second largest two-week total we’ve seen so far in 2026.

What is entering and exiting the queues continues to follow the pattern we have tracked all year. Gas represented over a third of newly added capacity, at 8.4 GW, while renewables and storage accounted for roughly 89% of withdrawn capacity this period. Storage in some form appears in 75.8% of withdrawn capacity, and solar paired with battery accounted for 18.7 GW of withdrawals, the highest of any technology. Standalone solar requests, by contrast, totaled 490.5 MW, the smallest figure we have recorded in recent periods. Gas and other firm resources are continuing to claim a larger share of the queue.

Queue Snapshot — Current State

Active capacity stands at 1.98 TW across 9,018 projects, down from 2.01 TW across 9,068 projects last period. We flagged the 2 TW threshold last edition as a largely arbitrary but useful gut check on the size of the national queue and noted that PJM’s Cycle 1 additions had pushed the queue back above it for the first time in a while. This period, withdrawals pushed total active capacity back below 2 TW.

Five technologies still account for 91.4% of the queue, essentially unchanged from last edition: battery at 467.1 GW, solar at 441.6 GW, gas at 414.1 GW, solar+battery hybrids at 289.4 GW, and wind at 197.2 GW. The gap between solar and gas narrowed again, to 27.5 GW from roughly 33 GW last period. Gas added 1.85 GW net this period while solar shed 3.73 GW. If gas overtakes solar within 2026, it looks likelier to happen because renewables are withdrawing at a higher clip than gas capacity is being added.

Year-over-year, thermal resources continue to see the largest percentage gains. Gas is up 109%, with PJM accounting for roughly a quarter of the national gas queue at 109.1 GW, almost all of it from their recent Cycle 1 queue update. Nuclear is up over 200% to 32.5 GW, and PJM holds about 60% of that. Coal is up 120% to just over 7 GW. Renewables continue to move in the other direction, with solar down 17%, solar+battery down 19%, wind down 14%, and offshore wind down 63%. Battery is the most resilient technology in the queues, only down 3.9% and remains the single largest technology in the queue. Storage in some form now accounts for roughly 762 GW, or 38.5% of active capacity, down from roughly 786 GW last period.

Regional Breakdown by ISO/RTO

The non-ISO West shed 41.3 GW net, taking its active queue from 483.9 GW to 444.0 GW and dropping 87 projects in two weeks. With this decline in active capacity, ERCOT is closing in on becoming the largest queue in the country in terms of active capacity (just 3.7 GW behind the non-ISO West).

In the non-ISO west, BPA’s active queue fell from 71.6 GW across 245 projects last period to 47.0 GW across 189, a 34.3% reduction in capacity in two weeks. All 58 withdrawals are recorded as Transition Cluster projects. In LADWP, only three of its 27 withdrawals this period include withdrawal dates between August 8th and 21st. The remaining 24 range from February 25th through June 26th, which suggests this is a larger queue data update from LADWP as opposed to a set of recent withdrawal decisions. Fifteen of the projects that exited LADWP’s queue queue were recorded as withdrawn at the interconnection customer’s request and 12 were withdrawn by the transmission provider. Transmission provider-initiated withdrawals usually indicate a project didn’t meet queue process milestones or requirements rather than a business decision by the developers.

The Southeast added more new capacity than any other market at 7.9 GW, though it also shed more than any market outside the West, resulting in a net gain of 3.1 GW. TVA drove both sides, with nine new requests totaling 6.9 GW against six withdrawals totaling 1.5 GW. Three of the additions came through TVA’s Expedited Resource Addition Study (ERAS) process, and two of those are coal: the 2,529 MW Cumberland plant and the 780 MW at Kingston plant. Both appear to be continuations of existing plants rather than new construction, since the TVA board voted back in February to keep Kingston and Cumberland running past their scheduled retirement dates. The other six requests are new projects, including 1.5 GW of gas across two requests at the Bellefonte nuclear site in Alabama.

MISO posted a net increase of 3.8 GW stemming from five ERAS requests. All five cite incremental commercial load they intend to serve in the region. SPP posted a net reduction of 967 MW this period, with nine of its ten withdrawals coming from the DISIS-2024-001 cluster. The SPP DISIS-2024-001 cluster has now shed 63.2% of its capacity before reaching Phase 2 of the study process.

NYISO added 4.4 GW of new capacity this period from two new requests for the Homer City redevelopment project in Pennsylvania. Based on the queue data for these two projects, they appear to be affected system interconnection requests for which NYISO will study reliability impacts and allocate the cost of any resulting upgrades, but will not assess deliverability or confer interconnection service. The same redevelopment also has two queue requests in PJM’s Cycle 1 cluster totaling 2.5 GW, which makes the NYISO pair look like the New York side of a single Pennsylvania interconnection. The retired Homer City coal plant was directly connected to both the PJM and NYISO transmission systems, which is why requests appear in both queues, and we will dig into the relationship between the two sets of filings before treating the capacity as either duplicated or additive.

Notable Projects

Existing interconnection rights at decommissioned coal plants are becoming valuable assets. Homer City is a clear example, a retired Pennsylvania coal station now being redeveloped to deliver up to 4.4 GW to AI and high-performance computing data centers. In MISO, the Merom project in MISO, where two requests from different developers, a 642 MW gas plant and a 500 MW battery, are both at an Indiana coal plant, and highlight how existing interconnection rights are proving to be a viable pathway for circumventing queue delays and upgrade costs.

The two largest projects reaching commercial operation this period were gas plants that entered the queue in 2020 and 2021, and represent more than half of all new operational capacity. The largest non-thermal project to come online is a 680 MW battery in Riverside County that entered the CAISO queue in April 2019 and reached operation in June 2025, a 6.2. The queue is shedding storage and renewable capacity faster than it is adding anything, while the capacity converting into steel in the ground is firm and was requested years ago.

Every withdrawal at or above 1 GW this period is a battery or battery hybrid in the non-ISO West. Five of those are 1.3 GW BPA requests that entered the queue on the same day in November 2023. Two of the projects requested service at the La Pine 230 kV substation and withdrew together. BPA does not publish developer names in its queue data, so we cannot confirm common ownership, but identical capacity at a shared point of interconnection with a shared queue date is consistent with a developer submitting multiple requests for different configurations of one project rather than distinct developments.

The two largest projects reaching commercial operation this period were gas plants that entered the queue in 2020 and 2021, and represent more than half of all new operational capacity added this period. The largest non-thermal project to come online is a 680 MW battery in Riverside County that entered the CAISO queue in April 2019 and reached operation in June 2025 (a 6.2 year queue duration). This appears to be more evidence that the queue is shedding renewable and battery storage capacity while what is being added to the queues and coming online is gas.

In terms of time to reach an agreement or interconnection, Duke Energy Progress executed an agreement on a 1,455 MW gas project in Person County, North Carolina, roughly 2.17 years after it entered the queue, which is one of the shortest durations from request to GIA we’ve observed all year and far quicker than the multi-year timelines we typically see.

Want to go deeper? GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

• Exportable datasets (export the full list of newly operational, withdrawn, GIA-signed, and added projects)

• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

• Exclusive in-depth industry reports

• … and much more!

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The following entities updated their queue data this period: PJM, ERCOT, Tucson Electric Power, Public Service Company of New Mexico, SPP, MISO, Southern Company, Black Hills Colorado Electric, Avista, CAISO, and Dominion South Carolina.

Additions: 223.05 GW (775 projects)

• PJM: 206.10 GW across 715 active requests, or 92.4% of everything added nationally this period. All of the PJM new entries are from their first cycle under their post-FERC Order 2023 reformed interconnection process.

• ERCOT: 8.34 GW.

• Non-CAISO West: 7.29 GW.

• SPP: 1.15 GW; MISO: 100 MW; Southeast: 74.9 MW.

• By technology, gas led the way at roughly 107 GW nationally, followed by battery at 65 GW, nuclear at 18 GW, and solar at 17 GW.

Withdrawals: 4.36 GW (24 projects)

• National withdrawals down 73.7% relative to the previous two-week period.

• West: 1.99 GW across 10 Public Service Company of New Mexico projects.

• ERCOT: 1.96 GW across 10 projects.

• CAISO: 250 MW, a single project and a reprieve from the substantial Cluster 15 queue attrition observed over the last month.

• Storage in some form appeared in 83.6% of withdrawn queue capacity.

Other Activity:

• 17 projects executed GIAs totaling 3.12 GW, down 10.4% from the previous period. Median wait from queue entry to executed agreement was 2.55 years, down from 3.4 years last period.

• 19 projects reached commercial operation totaling 2.30 GW, up 9.9%. Median wait from queue entry to COD was 4.68 years for these projects.

In the News

• Texas Governor Greg Abbott ordered the PUCT and ERCOT to audit every data center seeking to connect to the grid on August 3rd, halting approvals until those reviews are complete. Developers will have to disclose the tax incentives they receive, their power and water use, cooling operations, and facility ownership. If any project fails to comply with the audit, they will be denied interconnection.

• RWE reached a $1.22 billion settlement with the Department of the Interior on August 6th, relinquishing its offshore wind leases in New York, California, and Louisiana. The capital is being redeployed into gas and LNG, including a $900 million stake in the Louisiana LNG project. The reallocation from renewables to gas tracks what we have observed in the queue over the last year.

Activity Map

At GridTracker, we have been waiting for PJM’s release of interconnection queue data for the first cycle of its reformed process since PJM announced it in late April. The requests cover the entirety of the PJM footprint, spanning twelve states.

Virginia has the highest project count in the cohort at 184 active requests totaling 37.33 GW. Dominion’s zone accounts for 155 of those requests and 29.73 GW, or 84% by count and 80% by capacity. That concentration is expected given load growth in the region, likely driven in part by the ongoing data center buildout. Pennsylvania leads on capacity at 40.34 GW across 83 requests, followed by Ohio at 38.94 GW across 103. Indiana carries 25.38 GW across only 50 requests, an average of 508 MW per request, the largest average project size of any state in the PJM cohort.

Outside PJM, activity was comparatively light this period. ERCOT saw its usual mix of entries, withdrawals, and newly operational projects, adding 8.34 GW while withdrawing 1.96 GW, and accounting for 16 of the 19 projects that reached commercial operation this period. In the Southwest, Public Service Company of New Mexico posted a small update of 10 withdrawals totaling 1.99 GW alongside three executed GIAs totaling 900 MW. Tucson Electric Power added 6.94 GW across 17 requests, 16 in Arizona and one in New Mexico, all filed between January and March of this year.

Queue Activity

Data from PJM’s first reformed queue cycle means that new entries this period outpace anything we’ve seen so far this year, just over 223 GW of new queue additions between July 25th and Aug 6th, compared to a previous high of roughly 60 GW back in the first half of June. Withdrawals fell 73.7% to 4.36 GW compared to last period, yielding a net addition to the queues of 218.69 GW.

Gas led new additions at 103 GW, more than the next three technologies combined. Battery followed at 65 GW, then nuclear at 18 GW and solar at 17 GW. Wind and hybrid configurations trail well behind. In terms of withdrawals, the composition is unchanged from prior periods. Battery led at 2 GW across 13 projects, followed by solar+battery at 970 MW across 5, solar at 432 MW, wind+battery at 300 MW, and wind at 282 MW.

17 projects (3.12 GW) executed a GIA this period. ERCOT accounted for 9 of these projects (1.49 GW). For those nine GIA-executed ERCOT projects, the median duration from queue entry to GIA execution of 2.55 years. It is the shortest queue entry to IA execution duration we have observed in recent periods, though ERCOT has historically moved projects to executed agreements faster than other jurisdictions.

ERCOT also accounted for 16 of the 19 projects that came online over the last two weeks (2.06 GW of the 2.30 GW total). New operational capacity was split roughly evenly between standalone batteries at 1,188 MW across 11 projects and solar at 1,104 MW across 7, with a single 9.9 MW gas project making up the balance.

Queue Snapshot — Current State

The 2 TW threshold for active queue capacity is largely arbitrary, though it has been a useful gut check for the size of the queue over the last couple of years as process reforms have taken effect across ISOs and utilities. With PJM’s first reformed cycle (C01) now reflected in the data, we are back to over that threshold at 2.01 TW of active queue capacity across 9,068 projects, up from 1.79 TW across 8,335 projects last period.

Gas now stands at 412 GW, up 108.1% year over year and up 107 GW from last period alone. PJM accounts for 109 GW of that total, or roughly a quarter of the national gas queue, and almost all of the active PJM gas capacity is from the C01 cluster. Nuclear tells a similar story in a smaller frame. It stands at 32.26 GW, up 269.0% year over year, the largest percentage increase of any technology we track. PJM accounts for 19.29 GW of that, roughly 60% of the national nuclear queue, and about three quarters of the year over year increase arrived in this period.

The renewable side of the queue continues to move the other way. Solar is down 16.1% to 445.37 GW, solar+battery hybrids are down 16.1% to 300.26 GW, wind is down 13.4% to 198.55 GW, and offshore wind is down 62.9% to 6.86 GW. Battery is close to flat at 479.08 GW, down 1.4% year over year, and is now the single largest technology in the queue.

The overall composition of the queue remains largely unchanged. Five technologies account for roughly 91% of the 2.01 TW total: battery at 479.08 GW, solar at 445.37 GW, gas at 412.31 GW, solar+battery at 300.26 GW, and wind at 198.55 GW. Storage in some form accounts for roughly 786 GW, or about 39% of everything in the queue.

The ordering of the major resource types represented in the queue is starting to change. Last period solar led at 432 GW with gas at 306 GW, a gap of roughly 126 GW. Battery has since passed solar, and gas now sits 33 GW behind it. If gas continues to enter the queue at anything close to its recent rate, it will account for the largest share of capacity in the national interconnection queue within the year.

Regional Breakdown by ISO/RTO

Outside of PJM, this was one of the quieter periods we have tracked in recent months. Net of withdrawals, ERCOT added 6.38 GW, the non-ISO West added 5.30 GW, SPP added 1.15 GW, and MISO and the Southeast were effectively flat at plus 53.8 MW and minus 25.1 MW respectively. After shedding roughly 11.6 GW of Cluster 15 capacity across the two prior editions, CAISO recorded only a single 250 MW withdrawal this period.

PJM’s active queue went from 76.36 GW to 282.46 GW with the addition of the C01 requests, an increase of 270%, and surpassed the Southeast, SPP, and CAISO in terms of total active capacity. PJM now trails only the non-ISO West at 484 GW, ERCOT at 440 GW, and MISO at 358 GW. The C01 cluster alone accounts for 73% of PJM’s active queue by capacity, against 45 GW still held in the legacy TC1 and TC2 transition clusters and 31 GW in the pre-transition serial queue.

As published, C01 contains 816 requests totaling 226 GW, of which 715 requests and 206 GW remain active.

The composition of C01 is close to an inversion of PJM’s last transition cluster. Of the 31 GW still active in TC2, solar accounts for 38.4%, gas for 26.3% including hybrid configurations, battery for 22.0%, solar+battery for 6.6%, nuclear for 4.8%, and wind for 1.6%. Solar went from the largest technology in the prior cluster to the fourth largest in this one, and its share fell by a factor of six. Gas roughly doubled its share. Nuclear went from a small percentage of the previous transitional cluster to the third largest technology in the cohort.

The capacity of new PJM queue requests is also far larger. Gas requests in C01 average 675 MW and nuclear requests average 710 MW (includes uprates), against a cohort-wide average of 288 MW and average request sizes of 109 MW for solar and 107 MW for wind. There are 42 requests of 1 GW or larger in PJMS C01, which carry nearly a third of the cohort’s capacity on their own.

Geographically, the cohort concentrates in two transmission owners. AEP accounts for 152 requests and 60.04 GW, and Dominion has 177 requests and 35.93 GW. In total, AEP and Dominion represent 46.6% of the cohort’s requested capacity. ComEd follows at 107 requests and 22.27 GW, then ATSI at 18.07 GW and Alleghany Power at 17.13 GW. Gas requests in PJM C01 are also geographically concentrated. Pennsylvania and Ohio hold 61.87 GW of the 99.95 GW of gas in the cycle (61.9%) with West Virginia, Indiana, and Virginia holding roughly 8.5 to 9.5 GW each.

It is always important to remember that the majority of queue requests ultimately do not get built, and even those that do reach commercial operation historically take years to come online. In PJM C01, proposed commercial operation dates cluster in 2030 and 2031, which together account for 376 requests and 122.95 GW, or 59.7% of the cohort. Near-term proposed CODs are comparatively less common: 3.68 GW proposes 2026, 1.30 GW proposes 2027, 10.85 GW proposes 2028, and 24.09 GW proposes 2029.

As discussed in the previous GridTracker Insights edition, PJM’s 2028/29 capacity auction cleared at the $325/MW-day cap for a third consecutive year and fell 6,831 MW short of the reliability requirement while clearing just 525 MW of new generation and uprates. Even if every 2028 request in C01 were built on schedule, which will not happen, it would arrive after the delivery year the auction has already priced.

Of the initial 816 requests published in this first reformed PJM queue cycle, 101 (19.44 GW) already withdrew by the time PJM published their data. That is 12.4% of requests and 8.6% of capacity gone before receiving initial study results. Batteries led pre-publication exits at 7.68 GW across 39 requests, followed by gas at 4.88 GW across 10 and solar at 2.63 GW across 19. Looking at PJM’s previous transition clusters as a benchmark, TC2 has lost 369 requests and 48.73 GW to withdrawal against the 278 requests and 31.12 GW still active, an attrition rate of over 60% by capacity. Applying that rate to C01 puts the surviving cohort around 80 GW, compared to the 206 GW that entered. That is still a substantial amount of new capacity seeking interconnection in PJM, but it is substantially less than the current headline GW figure for PJM C01.

Notable Projects

The PJM C01 records show what entities filed which requests. The largest nuclear filings belong to AEP and its associated entities. Indiana Michigan Power Co. filed five requests of 2,300 MW each, three in Spencer County at Rockport-Jefferson 765 kV and two in Sullivan County at Sullivan 765 kV, staged one year apart from 2033 to 2035. Appalachian Power filed a sixth in Campbell County, Virginia. That is 13.8 GW, or 78% of all nuclear capacity requested in C01. These are more likely different phases of two nuclear plants rather than five separate nuclear power plants.

There are also 13 requests totaling 1.37 GW that are uprates at existing nuclear plants, ranging from 5.7 MW to 382 MW. Six from Constellation and four from Vistra. Six of the thirteen proposed in-service dates of 2028 or earlier. None of AEP’s six nuclear requests propose anything before 2033.

In the PJM C01 cycle, we are seeing some evidence of redevelopment at retired coal plants to take advantage of existing interconnection rights and capacity. The largest gas request in C01 is 2,500 MW in Beaver County, Pennsylvania at Bruce Mansfield 345 kV, filed by Shippingport Power Station, LLC for November 2028. Bruce Mansfield was a 2,741 MW coal station that retired in 2019. Three more gas requests sit on adjacent points of interconnection, bringing roughly 5.9 GW to that one node. The same is happening at Homer City, an 1,884 MW coal station in Indiana County, Pennsylvania that retired in 2023, where two gas projects (1,736 MW and 780 MW) both requested service at the retired plant’s 345 kV and 230 kV interconnections.

Cortex Sycamore, LLC, the largest filer in C01 with 25 requests, submitted 10 nearly-identical gas requests at exactly 976 MW in pairs across five different points of interconnection in Ohio and Indiana. Dominion filed both of its 1,694 MW gas requests along the Cunningham-Elmont line and both of its 1,530 MW gas requests at Mount Storm-Valley.

It is always interesting to check how long projects actually take to move through the interconnection process and come online as we see newly operational projects in the data. The 19 projects that reached commercial operation this period waited a median of 4.68 years. On the high-end of the distribution, a 72.5 MW solar project in Mayes County, OK reached commercial operation on August 3rd after entering the SPP queue in May 2017, a queue duration of 9.2 years.

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• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

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The following entities updated their queue data this period: BPA, PacifiCorp, LADWP, NV Energy, Tucson Electric, Salt River Project, APS, CAISO, SPP, MISO, Duke, and Georgia Transmission.

Additions: 7.96 GW (72 projects)

• MISO: 3.40 GW across 8 projects, driven by Entergy Arkansas, Entergy Texas, and Duke Energy Indiana.

• SPP: 2.35 GW across 40 projects. Highest project count of any market, lowest average project size (roughly 59 MW).

• Southeast: 1.39 GW across 18 projects, mostly Duke surplus interconnection requests and new Georgia Transmission solar+storage entries.

• Battery led new entries at 3.26 GW, followed by “Other” at 1.66 GW, gas at 1.29 GW, solar+battery at 810 MW, standalone solar at 573 MW, and wind at 367 MW.

• Surplus interconnection requests accounted for 17 of the 72 projects added and 1.76 GW, roughly 22% of added capacity.

Withdrawals: 16.54 GW (67 projects)

• Non-ISO West: 11.60 GW, the largest single-market withdrawal figure of the year so far.

• CAISO: 4.16 GW, a continuation of the Cluster 15 exits.

• Solar+battery hybrids led at roughly 8.3 GW, followed by standalone batteries at 4.0 GW, wind at 2.0 GW, gas at 1.5 GW, and solar at 1.1 GW. Storage in some form was represented in more than three quarters of withdrawn capacity.

On the Docket

Texas PUCT

Crusoe/Goodnight Co-location, Final Order (Docket No. 59220)

The PUCT signed a final order on July 24 approving the net metering arrangement for Crusoe Two, a second 260 MW data center behind the Goodnight Wind POI, and imposed the same six conditions from Docket 58881. Crusoe and Ensign’s main objection related to the curtailment requirement, which would apply to both loads and shed 525.5 MW of demand to protect a wind facility that generates at most 265.5 MW. The Commission rejected the argument, reasoning that because both loads net against the same generator behind a single point of interconnection, curtailing only one would not achieve the objective of keeping the wind facility’s capacity available to the grid during emergencies.

Notably, the order also retains a provision that requires the data center to curtail upon ERCOT instruction while barring it from being compensated for doing so, since the load cannot be offered into any ERCOT or utility demand response program.

(Note: Deep-dive on this facility’s permitting and interconnection history available for free here)

Large Load Customer Tariffs Rulemaking (Project No. 58000)

Earlier this month, the Commission issued a set of proposed rules implementing Senate Bill 6, which would be the first codified standards for how large loads connect and pay in ERCOT. At the center of the rules is a 20-year minimum take obligation. A large load customer would owe 240 consecutive monthly payments based on the greater of its contracted peak demand or its actual demand, and billing would start once transmission capacity is made available whether or not the site has energized. The proposal also ends cost socialization for new agreements, barring utilities from recovering large-load interconnection costs through general transmission rates.

The open question is whether Texas creates a separate rate class for what the proposal calls “large computational load,” meaning a site where at least half of demand comes from computing equipment. The Commission asked parties for legal support on whether it can lawfully draw that distinction. Comments are due August 11.

the cleanest test yet of who absorbs the asset when the anchor customer’s obligation ends.

Virginia

Governor’s Energy Office Asks for Large-Load Cluster Studies (Case No. PUR-2026-00056)

Virginia’s Chief Energy Officer intervened on July 9 in Dominion’s transmission rate case. The Governor’s Office wants the SCC to “transition from sequential interconnection studies to a proactive Cluster Study Approach for large-load connection requests,” describing it as “a direct application of the same logic of FERC Order No. 2023 that requires cluster studies for new generation interconnections.” It also asks the Commission to require Dominion to apply a rigorous “but for” test, meaning that any network or substation upgrade the utility would not have built absent a specific large load would be charged directly to that customer rather than spread across all ratepayers.

For context on this docket, Dominion’s investment in transmission assets grew 56.2% between 2020 and 2025, from roughly $10 billion to $15 billion, and nearly two thirds of that growth came from its largest commercial and industrial customers (e.g., data centers). Google’s testimony in this case estimates Dominion would need roughly 233 substations to interconnect the 70 GW currently in its large-load queue.

In the News

• PJM’s 2028/29 capacity auction cleared at the $325/MW-day price cap for the third consecutive year, procuring 138,318 MW but falling 6,831 MW short of the reliability requirement. Three years of maximum prices produced almost no new supply, with just 525 MW of new generation and uprates clearing, down from 774 MW a year earlier. The auction procures for delivery in 2028, and between interconnection timelines, network upgrade costs, and equipment lead times, very little can move from the queue to commercial operation on that timeline. PJM’s market monitor separately attributed $6.3 billion of the $16.4 billion in auction charges to data centers and proposed a separate capacity auction for that load.

• MISO will develop a dedicated expedited study process for large loads and their dedicated generation, run separately from the generator interconnection queue, alongside a non-firm transmission service option. Announced on July 20th, it is one of the first responses to FERC’s show cause orders to all six RTOs and ISOs.

• New York imposed a statewide moratorium on new hyperscale data centers on July 14th, pausing discretionary state environmental permits for up to a year while they develop standards for data center development. Permits already deemed complete may proceed. The order follows an open “Energize NY” proceeding examining whether data centers should pay more for grid upgrades or supply their own power.

Activity Map

The West (the Desert Southwest and Pacific Northwest in particular) account for the bulk of activity this period, but it’s mostly capacity leaving the queue. Nevada and Utah recorded the largest exits in the West, where NV Energy cleared roughly 3.6 GW of battery and gas requests and a Los Angeles Department of Water and Power portfolio of more than 3 GW withdrew from Intermountain Power Agency’s queue (Utah). Western Arizona and California saw a further 4.16 GW of withdrawals, all of it CAISO, led by a 2.0 GW battery project in La Paz County.

There was a fair amount of newly operational activity in the Columbia River Corridor, with ten projects totaling 1.38 GW, roughly two thirds of the 2.09 GW that moved to operational status. Nearly all of it sits in Bonneville Power Administration territory across Morrow, Gilliam, Umatilla, Wasco, and Deschutes counties in Oregon and Yakima and Clark counties in Washington.

New entries came from a different set of markets. MISO led with 3.40 GW, concentrated in Entergy Arkansas, Entergy Texas, and Duke Energy Indiana, followed by 2.35 GW spread across 40, mostly small, SPP requests and 1.39 GW in the Southeast, largely Duke Energy Florida surplus additions and Georgia Transmission.

Queue Activity

Additions fell by more than half compared to last edition, dropping 56.6% to 7.96 GW while withdrawals rose 17.4% to 16.54 GW, a net reduction of 8.58 GW and the lowest two-week entry figure since the period ending February 20th. Storage dominated both queue entries and exits this period. Hybrid solar+battery projects accounted for roughly 8.3 GW of withdrawals and standalone batteries another 4.0 GW, so more than three quarters of everything that left the queue included storage. On the entry side, surplus interconnection requests accounted for 17 of the 72 new requests (1.76 GW), roughly a fifth of added capacity, including eight Duke Energy Florida battery projects and four SPP requests. PacifiCorp also executed four surplus agreements in Utah. This may be a sign that developers are looking for ways around lengthy cluster studies and the network upgrade costs that come with them by adding storage at points where interconnection service has already been secured.

A total of 3.48 GW executed GIAs across 18 projects this period, most of it in the West and most of it storage, with only about 720 MW of standalone solar in the mix. That cohort waited a median of 3.4 years between queue entry and executing a GIA. Of the 19 projects reported as newly operational (2.09 GW), only two list a commercial operation date between July 11 and July 24. The rest appear to be a Bonneville Power Administration records refresh, covering projects with proposed completion dates as far back as 2012.

Queue Snapshot — Current State

The active queue stands at 1.79 TW across 8,335 projects, down roughly 10 GW from the prior period but essentially flat on the year. What we are starting to see now is less a continuation of the contraction that followed FERC Order 2023 and the related ISO and utility queue reforms, and more a recomposition of what’s in the queue. Gas is up 54.4% year over year at 305.64 GW, and renewables continue to move the other way, with solar down 20.2%, wind down 21.8%, and battery down 15.0%.

The queue remains highly concentrated. Five technologies make up roughly 91% of the 1.79 TW total: solar at 432 GW, battery at 418 GW, gas at 306 GW, solar+battery hybrids at 292 GW, and wind at 189 GW. Storage in some form accounts for roughly 717 GW, about 40% of everything in the queue.

Regional Breakdown by ISO/RTO

The West recorded a net decline of 10.77 GW, the largest single-market drop that we’ve tracked so far this year. Nearly all of it came from NV Energy, LADWP, Tucson Electric, and Salt River Project refreshing their queues within a two-day span. At the other end of the table, ERCOT, PJM, and ISO-NE registered no activity in either direction, which is notable given ERCOT accounted for roughly 80% of new entries in the last edition.

CAISO shed an additional 4.16 GW this period, extending the Cluster 15 attrition tracked earlier this month. Combined with the 7.44 GW flagged two weeks ago, that puts cumulative exits from the cohort at roughly 11.6 GW across two periods. CAISO’s active queue has fallen from roughly 190 GW last August to about 105 GW today, the steepest sustained decline of any market. Elsewhere activity was quieter, with MISO up 2.95 GW, SPP up 2.35 GW, and the Southeast up 1.32 GW.

Notable Projects

GridTracker’s queue data includes free-text comment fields that accompany new interconnection requests. Developers and utilities often state the purpose of a request there, providing an early signal of what is driving new capacity. Increasingly, we are seeing comments reference large loads and data centers.

In Indiana, Crosley Energy Storage, a 400 MW battery project in Pike County on a Duke Energy Indiana 345 kV line, states that it will meet “the load needs identified by Decennial Group for their 2028 projected hyperscaler data center load.” Sycamore BESS, a 400 MW battery in Vermillion County, describes itself as serving “an incremental large load located in Clark County, Indiana.” NIPSCO added a 150 MW surplus battery request in Newton County. Together, that is just under 1 GW of storage capacity entering the queue in two weeks, most of it tied to an identified load rather than proposed as a merchant asset.

There are similar dynamics at play in eastern Arkansas, where Entergy Arkansas filed DOUBLEC Energy Center 3 (750 MW combined cycle) and DOUBLEC Energy Center 4 (250 MW simple cycle) at the same West Memphis to Keo interconnection in Crittenden County, both stating that they exist to serve long term resource adequacy for new large loads in MISO’s LRZ8.

Want to go deeper? GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

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• Custom dashboards with real-time alerts and data export

• Exclusive in-depth industry reports

• … and much more!

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State PUC dockets don’t always get a lot of coverage, but they’re where some of the most consequential decisions on large-load interconnection, data center cost allocation, and co-location arrangements are being made right now. Luckily, GridTracker’s Model Context Protocol (MCP) connection allows us to search and surface relevant filings across state PUC dockets and FERC directly. So in addition to providing bi-weekly updates on generator interconnection queues, starting this edition we’ll be covering the proceedings we think are worth watching.

Texas PUCT

Crusoe/Goodnight Wind Co-location, Round Two (Docket No. 59220)

We mentioned this case in a previous newsletter (and it received some news coverage earlier this year as well). The Crusoe/Goodnight Wind co-location (Docket No. 58881) was effectively Texas’s first real test of SB6’s new co-location framework. It involved a 260 MW AI data center (developed by Crusoe, operated by Ensign), located behind a 265.5 MW wind farm in Armstrong County, sharing a single ERCOT POI. The PUCT approved this net metering arrangement with six conditions, the most contentious being a 30-minute mandatory curtailment requirement during grid emergencies.

The July 9th proposed order under Docket No. 59220 adds a second 260 MW data center at the same POI and settlement meter. ERCOT studied it and found no transmission security issues, and PUCT staff recommends approval under the same six conditions. The application also discloses that a second Goodnight Wind facility (260 MW) is planned at the same POI by May 2027, which would put two wind facilities and two data centers stacked behind a single interconnection point and shared meter. Crusoe and Ensign still object to certain aspects of the conditions, but they’re back for a second data center at the same site under the same requirements, which suggests the model is working even with the curtailment strings attached.

BTM Co-location and REC Accounting (Docket No. 59963)

MARA Holdings, who acquired Great Plains Wind, a 114 MW SPP wind farm in Gruver, Texas, is amending its Renewable Energy Credit (REC) Generator Certification to account for a co-located data center served as BTM load. Because the data center consumes generation before it reaches the POI meter, the existing REC certification no longer reflects the facility’s total renewable output, so MARA is amending it to allow self-reporting of total generation as the sum of what the meter sees plus what the BTM data center consumed.

This is a fairly minor REC accounting question, but it points to something that will come up in every renewable plus data center co-location arrangement: how to attribute and certify renewable generation when it is being consumed before it ever hits a meter.

Hyperscalers/Big Tech

Amazon Briefs for a Fast-Track Large-Load Queue in Virginia (Case No. PUR-2026-00011)

Virginia SCC is weighing whether to create a fast-track interconnection queue for large loads willing to self-fund infrastructure or commit to grid flexibility. Amazon filed its response on June 30th, arguing there are no legal impediments and asking the Commission to create a contractual framework for large loads to self-fund or self-build qualifying infrastructure in exchange for queue priority.

The brief points to Maryland’s recently enacted tiered interconnection priority legislation (Md. H.B. 1532), which gives large-load customers who commit to demand response and incremental resource investments top priority in load studies, as a working model. The SCC hasn’t ruled yet, but the filing is a signal that hyperscalers are willing to put money on the table and commit to flexibility if it means moving faster through the queue.

Microsoft Testifies on “Bring Your Own Power” in the APS Rate Case (Case No. E-01345A-25-0105)

This Arizona Public Service (APS) general rate case has drawn out some of the most direct testimony yet on how utilities should treat large data center customers. In the July 8th hearing, Microsoft’s expert witness was cross-examined on a “bring your own power” proposal Microsoft advanced as an alternative to APS building out additional capacity to serve data center load. Microsoft operates in APS’s territory as an Extra High Load Factor customer running near 100% capacity factor and testified that it is willing to pay its own interconnection costs and that those costs are not passed on to residential ratepayers. Western Resource Advocates pushed back, arguing that data center load growth is driving up electricity rates and delaying coal plant retirements. No order yet, but the record being built here on self-supply feasibility and the real resource planning costs of data center load is worth tracking.

In the News

• PUCT, facing 438 GW of large-load requests (nearly 90% from data centers), approved rules for ERCOT to begin processing those requests in batches of 75 MW or larger on June 18th. The first cohort, called Batch Zero, will be studied together rather than project-by-project. The approach mirrors the cluster study model long used for generator interconnection. This is one of the more consequential structural changes to ERCOT’s large load interconnection process yet.

Queue Activity, June 27 - July 10, 2026

Additions: 17.57 GW (37 projects)

• ERCOT: 14.05 GW, almost entirely gas, led by a cluster of large plants in central and east Texas.

• MISO: 3.10 GW (7 projects), driven by gas and storage requests in Indiana and Louisiana.

• Gas dominated new entries (~13 GW), followed by solar (~3.2 GW) and battery (~2.8 GW).

Withdrawals: 14.09 GW (54 projects)

• CAISO: 7.44 GW of mostly Cluster 15 battery project exits.

• ERCOT: 3.36 GW (16 projects), led by a 1.25 GW gas project withdrawal.

• More than half of withdrawals were battery capacity (~7.5 GW), followed by hybrid solar+battery (~2 GW) and standalone solar (~1.7 GW).

Newly Operational: 2.08 GW (15 projects)

• A very active period for projects reaching COD, up roughly 697% from the prior two weeks and concentrated in ERCOT (solar and battery).

Activity Map

CAISO and ERCOT were both busy this period. ERCOT comprised the bulk of new entries (~14 GW of gas), GIA signings (solar, wind, and battery across central and east Texas), and projects coming online, while CAISO saw over 7 GW of Cluster 15 battery projects withdraw, concentrated in the Central Valley and the LA/San Bernardino area. MISO added roughly 3.1 GW of gas and storage in southern Indiana and Arkansas, offset by a single 1.54 GW Entergy Louisiana withdrawal. Elsewhere activity was comparatively light. A 300 MW battery project came online in Utah, a 250 MW gas project signed a GIA in northern Colorado, and scattered withdrawals registered in Oregon, New Mexico, and Georgia.

Queue Activity

Queue additions, withdrawals, and newly operational capacity were all sharply up from the prior two-week window. 17.57 GW of new capacity entered the queue across 37 projects, while 14.09 GW withdrew across 54 projects, a net addition of about 3.5 GW.

The entry side is almost entirely ERCOT, which accounted for 14.05 GW (roughly 80% of new entries, virtually all from gas) of new capacity entering the queues across the country. We are starting to see developer and project information in the queue data point explicitly to data center load both in ERCOT and, increasingly, in MISO. MISO added 3.1 GW across seven projects, some of which cited serving large commercial loads in their comments to the ISO.

CAISO saw 7.44 GW withdrawn this period, driven by Cluster 15 battery projects that had been in queue since the 2025 cluster cycle window. ERCOT had 3.36 GW in withdrawals, led by a single large gas project that had reached the facility study phase. 2.08 GW (15 projects) came online, up nearly sevenfold from the prior window. 2.85 GW across 18 projects signed GIAs, down about 41% from last period and were also ERCOT-heavy.

Queue Snapshot — Current State

The active queue stands at 1.80 TW across 8,341 projects, essentially flat from last period. The YoY composition shift towards gas and away from renewables continues. Gas is up 48%, nuclear 81.3%, and geothermal is up 171.1%. Against those gains, batteries are down 17.1%, solar down 19.9%, and wind and offshore wind are down 21.1% and 62.9%, respectively.

Regional Breakdown by ISO/RTO

On net, queues added +3.48 GW, with ERCOT as the sole major positive contributor at +10.69 GW. MISO added +1.56 GW on net; SPP edged up +270 MW. Every other market contracted: Southeast -445 MW, PJM -175 MW, ISO-NE -170 MW, the non-CAISO West -813 MW, and CAISO -7.44 GW.

Of CAISO’s 7.44 GW in withdrawals, roughly 67% (~5.0 GW) were standalone batteries, another 26% (~2.0 GW) were solar+battery hybrid projects, and the remaining ~6% (450 MW) was a single standalone solar project. Per CAISO’s published Cluster 15 (C15) Queue Report, project withdrawals for C15 started back in April 2025 and continued through earlier this month. C15 is one of the first clusters to move through CAISO’s reformed queue process. We be monitoring whether the projects that remain in C15 advance through study milestones and reach commercial operation at higher rates than projects from prior CAISO clusters.

Notable Projects

ERCOT’s most recent queue data update confirms what has been widely covered in the energy space: lots of gas is being built in Texas, much of it to serve data center demand. The five largest projects added this period are all ERCOT gas plants. Developer/entity names like “Bullock Data Center, LLC” and “Liberty Data Center I, LLC” make the data center connection explicit in the queue record. Additions in MISO are telling a similar story, though on a smaller scale. Entergy Louisiana (Bayou Point Natural Gas, 750 MW), Duke Energy Indiana (Maple Creek Energy, 641.8 MW and Trotman Energy Center, 400 MW), and Entergy Arkansas (two projects, 400 MW each) all cited serving large commercial loads in the comments accompanying their queue requests.

The COD activity this period is worth quickly flagging. 2.08 GW came online, the most active two-week window of the year so far, and a reminder that a meaningful amount of capacity is actually crossing the finish line. The breakdown was roughly 44% solar, 33% battery, and 23% solar+battery hybrid, and 12 of the 15 projects that came online are in ERCOT.

Want to go deeper? GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

• Exportable datasets (export the full list of newly operational, withdrawn, GIA-signed, and added projects)

• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

• Exclusive in-depth industry reports

• … and much more!

  Learn More about GridTracker

While much of the industry’s focus has been on growing crisis risk from massive demand growth driven by data centers, there are much-needed signs of improvement on the generation side. Timelines (to both withdrawal and commercial operations) are finally trending back down, and we finally have a healthy and growing pipeline of GIA-signed power plants.

Withdrawals

Withdrawals were significant. In January, 31 GW exited (11.9 GW from MISO DPP-2025, plus a long tail of utility queues in the West and Southeast). Then in April and May: 144 GW across 807 projects, driven by more MISO DPP 2025 withdrawals, PJM cleaning out their legacy serial queue, and SPP's DISIS 2024 Phase 1 decision point. Withdrawals aren’t universally bad, though. Early withdrawals followed by lower attrition at later study stages is a sign of well-executed policy.

Most of that May wave was administrative. PJM accounted for 43.1 GW of it, and every one of those 353 projects came from the RTO’s legacy serial queue: positions with queue ID prefixes like AH2, AI1, AI2, and AJ1, filed back in 2022 and 2023 under the old first-come, first-served process. PJM required all of them to reapply as new projects for Cycle 1, the first cluster of its reformed process, before the application window closed on April 27. Whatever did not transition was withdrawn. The purge shows up in our data as a bulk status flip between the April and May snapshots.

The other May driver was organic. SPP’s DISIS-2024-001 study cluster reached its Phase 1 decision point, and 126 projects totaling 28.5 GW dropped once they saw their study results. Our March report on that cluster projected heavy attrition at exactly this milestone. Even with the PJM purge included, the half-year total of 245 GW runs well behind 2025, when 283 GW exited in the first six months and another 450 GW followed in the second half.

Technology Shifts

Six months is typically a short window for the technology mix to meaningfully move. But gas is continuing its unprecedented expansion. Active gas capacity climbed from 247 GW to 305 GW, a 23% jump since the end of 2025 and a whopping 66% since the end of 2024. Solar slipped 4.7% to 682 GW. Offshore wind, already cut nearly in half last year, fell another 58% and now totals 6.9 GW nationwide.

The Long Wait: Queue Timelines

Projects that reached commercial operation in the first half waited a median of 4.8 years from queue entry, down from 5.5 years for projects completing in 2025.

Withdrawal timelines are an earlier leading indicator of queue efficiency, and they keep improving. Projects that withdrew in the first half had spent a median of 21 months in the queue, down from 35 months for 2025's withdrawals and 40 months in 2024. Studies are flagging non-viable projects earlier, and developers are cutting their losses sooner. That was the design intent of FERC Order 2023. It appears to be working.

Where the Activity is Happening

The non-CAISO West and ERCOT markets led the way in new additions. Looking at the map also provides a crystal-clear view of the technology trends, as well. Those orange dots are gas projects, appearing at an increasing rate. And while gas projects grow in abundance, they also tend to be the most resilient, completing at much higher rates than solar, storage, and wind projects.

GridTracker subscribers get the full report (also available as standalone purchase here)

The full report includes:

• 44 charts and maps, breaking out data by power market, technology, and more

• 6 fully-exportable datasets:

  • Starting projects (Everything active in the queue Jan 1 2026)

  • Added projects (Entered the queue during H1 2026)

  • GIA-signed projects (Executed GIAs during H1 2026)

  • Operational Projects (Reached commercial operations during H1 2026)

  • Withdrawn Projects (Withdrew during H1 2026)

  • Ending Projects (What was active in the queue at the end of H1 2026)

Get The Full Report

Additions: 10.96 GW (56 projects)

• Non-CAISO West: 5.8 GW (20 projects), driven by Western Area Power Administration (WAPA) requests across Arizona, Nevada, and California.

• MISO: 2.5 GW (6 projects), almost entirely a single unclassified tech type 2.2 GW Ameren Missouri request.

• Southeast: 2.5 GW (29 projects), from Duke Energy Carolinas’ latest cluster.

• By technology, gas led new requests (3.0 GW, 17 projects), followed by battery storage (2.4 GW).

Withdrawals: 4.85 GW (26 projects)

• Withdrawals were spread across the West, MISO, and the Southeast.

• West: 1.7 GW (5 projects), led by a 600 MW Idaho Power gas request.

• MISO: 1.3 GW (9 projects).

• Southeast: 0.9 GW (8 projects), split between Southern Company and Florida Power & Light.

• CAISO: 0.4 GW (1 project), a single wind withdrawal.

In the News

• FERC issues orders on large load interconnection. On June 18, FERC issued “Show Cause” orders to the six FERC-jurisdictional grid operators, requiring them to either demonstrate that their existing large load tariffs adequately serve large loads or revise them to address the issues the Commission identified. Each operator and its transmission owners have 60 days to respond, and within 30 days must file an informational report on how they will ensure adequate generation to serve existing and new large loads. The orders highlight five reform areas: more efficient transmission study and application processes; cost-shifting protections and cost transparency; accommodation of co-location and behind-the-meter generation; new transmission services for flexible large loads; and a process to study generation serving co-located and electrically proximate loads. The fifth reform area is one we will be watching as proposals come in, since study tracks for generation serving co-located load could create separate queue clusters/pathways to monitor and analyze.

• Virginia weighs making large loads pay up front for the transmission they trigger. In a Dominion transmission rate case, Virginia State Corporation Commission staff filed testimony on June 16 recommending that the cost of transmission lines and upgrades built to serve a single high-load customer be assigned directly to that customer rather than spread across the rate base. Staff would do this by modifying Dominion’s line-extension policy to recover those facilities through Contribution-in-Aid-of-Construction, meaning the triggering customer pays up front. The recommendation builds on the Commission’s 2025 biennial order, which directed Dominion to develop alternative ways to allocate transmission costs. As the largest data-center market in the country, whatever Virginia codifies may become a reference point beyond PJM.

• Amazon and Vistra take Texas co-location to a nuclear plant (Deep dive at the bottom of this issue). Comanche Peak Power Company and Amazon are seeking PUCT approval for a net metering arrangement that would place up to 1,200 MW of behind-the-meter data center load at the existing 2,400 MW Comanche Peak nuclear plant in Somervell County, under the same SB6 framework as the Crusoe-Goodnight case we covered last issue. The data center would install its own backup generation, sized to cover its full load and kept off the transmission grid, so that during an emergency the load runs on backup. The applicants go further, committing to making all of Comanche Peak’s capacity available to Security Constrained Economic Dispatch within 30 minutes of an ERCOT instruction. It is a notable contrast with co-location cases elsewhere, where data center developers have resisted curtailment, and could be a sign of hyperscalers making efforts to trade grid-friendly terms for a faster path online. More on this below.

• Gas turbine shortage tests PJM’s fast-track rules. Advanced Power Services, developer of the Chestnut Run gas project in Ohio, has asked FERC for a waiver to swap in lower-output turbines after manufacturing backlogs pushed its in-service date out by at least two years. The swap would trim the plant’s maximum output but let it hold close to its original online date. The catch is that PJM’s Reliability Resource Initiative, the shovel-ready fast track, bars changes to a project’s size or Capacity Interconnection Rights, so the substitution needs a waiver. PJM protested on June 18, arguing the request fails FERC’s waiver criteria and would hand Advanced Power an unfair edge over developers complying with the tariff, and noted the company could instead use the Expedited Interconnection Track FERC approved on June 9.

Worth a Read

• Coverage of, and commentary on, FERC’s large load interconnection order:

  • Jackson Ewing (Duke Univ.) in Latitude Media.

  • Ric O’Connell from GridLab.

• The case for auctioning interconnection and flexible large-load service from Chris Gillet.

• An updated review of ISO/RTO generator interconnection processes from GridStrategies and Brattle Group.

• The long-awaited 2026 edition of LBL’s Queued Up report is finally here! GridTracker was happy to serve as data providers in a fruitful partnership for this project.

Activity Map

The main action this period is in the non-CAISO West and Southeast. New queue requests came in from the Southwest (WAPA), the Mountain/Pacific Northwest (Idaho Power, BPA, PacifiCorp, Black Hills Power), and a new cluster from Duke Energy Carolinas. Withdrawals were scattered, showing up across the Mountain West, the Upper Midwest in MISO, and the Southeast. There was also substantial GIA activity in SPP.

Queue Activity

This was a relatively quiet period for the queues, with additions, withdrawals, and newly operational activity all down from the prior period. The two-week totals come to just under 11 GW of new entries against 4.9 GW of withdrawals, a net addition of about 6 GW.

New entries were led by Duke Energy Carolinas, which added 28 projects totaling 2.5 GW across North and South Carolina, mostly battery storage (about 1.4 GW) and gas (roughly 0.7 GW). A WAPA Desert Southwest cluster of about 3.3 GW across eight projects in Arizona, Nevada, and California accounts for most of the West’s activity (a mix of gas, battery, and solar+storage). The single largest request is a 2.2 GW project from Ameren Missouri in MISO, which entered the queue seeking network resource service and sits in its application window. It has not yet been assigned a resource type in the MISO queue data, so it accounts for much of the “Other” capacity this period.

Withdrawals were broadly distributed, the largest being a 600 MW Idaho Power gas request and a 500 MW solar+storage project in SPP. Only four projects reached commercial operation this period, all small Florida and Georgia solar projects in the Southeast.

The standout metric this period is GIAs signed, up about 119%to 4.6 GW. Most of that is a cluster of Nebraska public-power gas units, from NPPD and OPPD, reaching interconnection agreements in SPP.

Queue Snapshot - Current State

The active queue stands at 1.80 TW across 8,366 projects, and is still overwhelmingly solar and battery by volume. Firm resources continue to gain share even after a relatively quiet couple of weeks for the queues, with gas up about 51 percent, nuclear up 81 percent, and geothermal up over 170 percent year-over-year, while battery, solar, and wind are each down by double digits. As we have noted before, the outsized swing in "Other" (up roughly 349 percent) is mostly unclassified new entries like this period's Ameren (MISO) request that have not yet been assigned a technology, so it overstates how much genuinely uncategorized capacity is entering the queue.

On net, the queue grew by about 6.1 GW this period.The non-CAISO West leads at +4.1 GW on the WAPA cluster, followed by the Southeast at +1.6 GW on Duke's Carolinas additions and MISO at +1.2 GW. Only two markets contracted, both marginally: CAISO at -400 MW on a single wind withdrawal and SPP at -422 MW. PJM, which dominated last period's withdrawals as it cleared its legacy serial queue, is quiet this time, with the reformed cluster process queue data still pending release.

Amazon vs Crusoe: A Test of Two Distinct ERCOT Co-location Strategies

We’ve recently covered two contrasting data center architectures for co-location in ERCOT.

On one hand, we have Crusoe: they are proposing to co-locate two large data center facilities, Crusoe One (265.5 MW) and Crusoe Two (260 MW), behind a single existing wind farm (the 265.5 MW GOODNIT1), with a second wind farm (GOODNIT2, expected commercial operation May 2027) planned to be added behind the same point of interconnection later.

Under ERCOT’s proposal, both Crusoe facilities would need to fully curtail (525.5 MW of firm AI load combined) in exchange for taking a 265.5 MW intermittent wind generator into the net metering arrangement. That’s a 2:1 ratio between curtailed firm load and removed intermittent generation.

It’s important to note the Crusoe facilities are co-located with intermittent wind power. This means these facilities cannot remain fully behind-the-meter. They regularly need to draw power from the ERCOT grid when wind output is below the facility’s demand. Secondly, based on testimony in this PUCT filing, they do not appear to have full backup generation readily deployable. We are inferring this from the harm argument in that testimony, where Crusoe’s expert argued the following about a 30-minute shutdown window:

“Abrupt, unplanned curtailment carries serious operational risks: cascading hardware failures across server clusters, corruption or loss of active computational work that cannot be recovered, data storage integrity failures, and thermal events caused by the sudden loss of coordinated cooling infrastructure. These are not hypothetical concerns - they are documented in this record.”

— Bojorquez Testimony, PUCT Docket 59220, Item 21, June 3, 2026

That does not paint a picture of a facility which has full, rapidly available backup generation on-site.

We contrast this against Amazon’s Comanche Peak filing (PUCT Docket 59399), widely reported as “Project Spectrum.” This is a recent proposal to co-locate a data center of up to 1.2 GW behind an existing 2.4 GW nuclear plant (Comanche Peak). This facility is planned to be fully behind the meter, with the load not expected to ever be served by grid power (per Amazon’s application in the docket). Also crucially, Amazon explicitly plans to establish sufficient backup generation on-site, sized “equal to or exceeding” the load’s expected demand, to power the entirety of their facility. For this reason, Amazon is preemptively offering the 30-minute mechanism directly in their application, rather than waiting to negotiate around ERCOT’s proposed conditions. However, their architecture grants them a convenient luxury which Crusoe seemingly does not share: they structure the guarantee as a return of Comanche Peak’s full capacity back to the grid, and not a shutdown of their facility. In the case of such an event, Amazon plans to simply switch to their fleet of on-site backup generators. Based on the testimony filed by Crusoe’s expert and referenced above, it appears that Crusoe does not expect to have this same capability.

It’s worth noting that under ERCOT’s proposed conditions, the backup gen must be sized to serve the full facility load, and not just enough to offset what the co-located generator was contributing behind the meter. So a developer co-locating a 1 GW facility with a 50 MW generator would need to build roughly 1 GW of backup, not 50 MW, if they want to remain operational through a grid emergency. The sizing requirement scales with the data center, and not with the co-located generator.

And here we see the pattern that’s likely to emerge in ERCOT for future co-located projects: full backup power is likely to become an absolute necessity under the SB 6 framework. For facilities like Amazon’s with extremely high availability SLAs, full backup power was probably always a baseline requirement. So this precedent seems unlikely to dissuade those projects. The precedent from Docket 58881 (Crusoe One) and Docket 58872 (Freestone) already points in this direction. Docket 59220 (Crusoe Two) will determine whether that precedent solidifies or whether the Commission narrows the scope in response to Ensign’s proportionality argument.

Want to go deeper? GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

• Exportable datasets (export the full list of newly operational, withdrawn, GIA-signed, and added projects)

• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

• Exclusive in-depth industry reports

• … and much more!

  Learn More about GridTracker

Withdrawals: 53.4 GW (384 projects)

• Roughly 80% of all withdrawn capacity in this period is from PJM clearing out legacy, serial queue requests. Setting those aside, other withdrawals this period total 9.5 GW, and are concentrated in MISO and CAISO.

• PJM: 42.9 GW (354 projects)

• MISO: 3.0 GW (4 projects)

• CAISO: 2.7 GW (10 projects)

• Arizona Public Service: 2.0 GW (1 project)

• Less than 1 GW of withdrawals in both ERCOT and the Southeast (Southern Company)

Additions: 44.5 GW (97 projects)

• Arizona Public Service: 28.2 GW (58 projects)

• ERCOT: 12.1 GW (26 projects)

• Southeast: 2.0 GW (3 projects), all Duke Energy (Carolinas and Progress).

• Outside the APS block, gas led the new requests (8.8 GW, 12 projects), ahead of storage (4.7 GW), a shift from the composition of new additions last period (solar+storage led the way last period).

In the News

• America’s largest wind farm is now spinning. Pattern Energy brought its 3.65 GW SunZia project in New Mexico online, making it the largest wind farm in the country. A single 3.65 GW resource reaching operation is one of the larger commercial-operation milestones we expect to track all year, and a sign that some long-stalled western megaprojects are finally reaching the grid.

• Big tech keeps building around the grid. Google and Intersect Power are developing the Meitner Energy Center in Texas, pairing a data center with more than a gigawatt of co-located wind, solar, storage, and on-site gas. It is their first project since Alphabet’s $4.75 billion acquisition of Intersect, and the co-located supply is meant to serve the data center’s load while limiting new demand on the local grid.

• PJM opens a fast lane for shovel-ready generation. FERC has approved PJM’s expedited interconnection track, which will fast-track up to 10 projects a year for resources of at least 250 MW that can reach operation within three years. The carve-out runs through the end of 2027 and targets PJM’s resource adequacy needs as data center demand outpaces supply, with the first projects possibly named in October.

• SPP gives large loads a conditional on-ramp. FERC approved SPP’s Conditional High-impact Large Load Service, letting large new loads such as data centers connect on a non-firm, interruptible basis until they secure firm resources or the needed network upgrades are finished. SPP says the structure gives developers more certainty on timing and cost. Alongside PJM’s fast lane, it shows RTOs improvising ways to absorb large loads in the near-term.

• A Texas test case is setting the rules for co-located data centers. Crusoe, an AI data center developer, and the Goodnight wind farm asked regulators back in October to approve a net-metering deal that puts the data center behind the wind farm’s existing grid connection. ERCOT found no reliability problems but recommended approval only with strict curtailment terms, including a 30-minute shutdown during grid emergencies. The developer is contesting, and as one of the first contested cases under Senate Bill 6’s co-location policy, whatever the commission adopts will establish the template in ERCOT moving forward. It remains in contested hearings as of mid-June, with no ruling yet.

Activity Map

PJM accounts for the bulk of this period’s withdrawals, but based on our review of the data, covered in more detail below, we believe this is largely PJM clearing out older, stranded serial requests rather than active queue projects truly withdrawing. Outside of PJM, Arizona Public Service is driving new requests, while ERCOT shows a mix of new entries, withdrawals, newly operational projects, and newly signed GIAs.

Queue Activity

The two main figures this period, 44.5 GW (97 projects) of new entries and 52.4 GW (384 projects) of withdrawals, are each the product of a single-entity data event rather than a shift in the market.

Of the 52.4 GW of withdrawals, about 42.9 GW across 354 projects is PJM. Looking at the data, our assessment is that these withdrawals are clerical rather than formal withdrawals during this period. These are requests from PJM’s final serial queue intake windows, filed between 2021 and 2023 and nearly all still at the first study phase. We read this batch of withdrawals as PJM formally closing out its legacy serial queue as it moves to the cluster process, not as active projects leaving. The one exception worth noting is the Pilesgrove Solar project in New Jersey (149 MW), which is the only project in the group that progressed beyond the feasibility study phase and actually withdrew after executing an interconnection agreement.

That also means the technology split of this period’s withdrawals is an artifact of the cleanup rather than a signal about any resource. For example, 9.5 GW of offshore wind that withdrew in PJM this period comes from six serial requests being removed from the queue. We will be monitoring and reporting on the data from PJM’s Cycle 1 of the reformed process and will also cross-check the set of withdrawn PJM projects from this period against the new data once it drops.

Non-PJM withdrawals total roughly 7 GW this period, and are concentrated in MISO and CAISO. MISO lost roughly 3 GW, led by NIPSCO’s 1.1 GW Malden gas plant and a 1.5 GW CLECO request that withdrew prior to initiating the study phase. CAISO’s 2.7 GW of withdrawals across ten projects are all from the same April 2021 cluster, and withdrew during the System Impact Study stage, likely after receiving their study results and being required to commit additional deposits. A 2.0 GW APS request also dropped, though it dates to 2017 and carries no withdrawal date, so we suspect this is also the product of the utility doing some queue housekeeping.

New entries this period are inflated by a single source. APS accounts for 28.2 GW of the 44.5 GW across 58 projects. These requests have been accepted into APS’s queue but sit in deficiency review, meaning the submissions still need corrections, so their resource types and study details are not yet published. We expect that information to fill-in over the coming weeks and will analyze the batch properly once it does. The conventional new-entry activity is in ERCOT, which added 12.1 GW across 26 projects, and the Southeast, where Duke Energy added 2 GW. Among the new requests with populated resource type data, gas led at roughly 8.8 GW, ahead of storage at 4.7 GW.

Queue Snapshot - Current State

The active queue stands at 1.79 TW across 8,330 projects. Part of the decrease this period is the PJM cleanup working its way out of the active totals, and not an indication of developers losing interest in the region.

The more durable story is in the mix. Firm and dispatchable resources continue to gain ground, though the queue is still overwhelmingly solar and battery by volume. One caveat on the “Other” category, which is up three-fold to about 75 GW. Much of that growth is simply unclassified new entries like the APS batch that have not yet been assigned a technology, so it overstates how much genuinely uncategorized capacity is entering the queues.

Notable Projects

The largest projects this period are gas. There are gigawatt-scale gas plants entering the ERCOT queue, and the largest newly operational plant is gas as well. The largest withdrawals, as discussed above, are PJM cleaning up its queue rather than real cancellations.

At GridTracker, we are also tracking the data center buildout (existing data centers, permitting, and construction). Using this data, we find that the largest gas plants entering the queue are landing near existing or planned/proposed data center facilities. The Giant Arc I (1.3 GW) gas plant in Pecos County, TX is registered to an entity called Powering Knowledge, LLC (an opaque entity, but likely a shell company owned by a large energy or data center developer), and is located in the middle of a growing West Texas compute corridor. Within roughly 30 miles sit CoreWeave’s 250 MW site and Poolside AI’s 2 GW Project Horizon (currently under construction), with much larger proposed campuses from Microsoft (about 2.6 GW) and Pacifico Energy (the 7.65 GW GW Ranch) nearby. The same pattern appears to the north, where the two >1 GW Thunder Bird gas units in Jack County sit on the western edge of the Dallas-Fort Worth data center build-out. Though we cannot see the offtakers behind any of these projects, it looks like the firm capacity entering ERCOT’s queue is clustering near data center facilities.

At GridTracker, we are also tracking the data center buildout (existing data centers, permitting, and construction). Using this data, we find that the largest gas plants entering the queue are landing near existing or planned/proposed data center facilities.

The Giant Arc I (1.3 GW) gas plant in Pecos County, TX is registered to an entity called Powering Knowledge, LLC (an opaque entity, but likely a shell company owned by a large energy or data center developer), and is located in the middle of a growing West Texas compute corridor. Within roughly 30 miles sit CoreWeave's 250 MW site and Poolside AI's 2 GW Project Horizon (currently under construction), with much larger proposed campuses from Microsoft (about 2.6 GW) and Pacifico Energy (the 7.65 GW GW Ranch) nearby. The same pattern appears to the north, where the two >1 GW Thunder Bird gas units in Jack County sit on the western edge of the Dallas-Fort Worth data center build-out. Though we cannot see the offtakers behind any of these projects, it looks like the firm capacity entering ERCOT’s queue is clustering near data center facilities.

GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

• Exportable datasets (export the full list of newly operational, withdrawn, GIA-signed, and added projects)

• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

• … and much more!

  Learn More About GridTracker

Withdrawals: 38.2 GW (167 projects)

• Mostly SPP’s DISIS-2024-001 projects (122 projects, 28.1 GW), which exited the queue after receiving their Phase 1 interconnection cost estimates

• Bonneville Power Administration (BPA): 4.4 GW (15 projects) of withdrawals

• ~1.6 GW (2 projects) from Tucson Electric Power in Arizona

• ~1.3 GW (5 projects) withdrawn from CAISO

Additions: 20.3 GW (72 projects)

• Public Service Company of Colorado (PSCo): 13.3 GW (46 projects)

• MISO: 3.9 GW (14 projects)

• Southeast: 2.0 GW (10 projects). Solar+storage hybrids led additions (7.6 GW, 23 projects)

In the News

• Even NERC can’t make sense of data center load growth: NERC released its 2026 Summer Reliability Assessment last month. The report found that the grid added 58 GW of summer resource capacity, predicted a summer peak demand of 865 GW, and noted difficulty forecasting large-load and data-center interconnections, with their near-term load forecasts revised downward in several regions as those loads come online more slowly than expected.

• Rate payers in PJM may already be feeling pain from data centers. PJM’s market monitor reported wholesale power averaged $136.53/MWh in the first three months of 2026, up from $77.78 a year earlier. This roughly 76% jump is a symptom of rising demand from data centers and other customers in the region.

• Coal gets another boost. On June 4, DOE announced $850 million in funding to support the coal sector, including up to $425 million in Defense Production Act funds to modernize more than a dozen existing facilities alongside a separate $350 million tranche backing four projects, among them two new plants in Anchorage, Alaska (1.25 GW) and Mt. Storm, West Virginia (1.6 GW). These would be the first new U.S. coal plants to come online since 2013.

• The 5% safe harbor is back, for now. A federal court vacated IRS Notice 2025-42, restoring the safe harbor as a way for wind and solar to projects greater than 1.5 MW to establish beginning of construction under the 45Y and 48E credits, less than a month before the July 4 deadline. The court found that the Treasury never adequately explained the change and unfairly singled out wind and solar, though the ruling could still be appealed.

Worth a Read

• CAISO published its revised 2025-2026 Transmission Plan last month.

• Interested in nuclear? This deep dive on Diablo Canyon economics from UCSB is well worth a read.

Where’s the Activity?

Three queue activities stand out, each covered in more detail below: SPP's DISIS-2024-001 cluster withdrawals in the central US, BPA's withdrawals in the Pacific Northwest, and PSCo's new requests in eastern Colorado.

Activity at a Glance

Withdrawals are the story this period: 38.2 GW exited the queues (up 737.5%) while new entries slowed to 20.3 GW (down 45.1%). Both dynamics are mostly a matter of major cluster updates being published. Beyond the headline flows, GIA signings ticked up (21 projects, 4.8 GW, +15.3%), while the newly operational and suspended tallies are too small to read much into.

Regional Breakdown

Net of new entries and withdrawals, most markets experienced only modest changes to their queues: the West added 7.2 GW from the PSCo entries, MISO and the Southeast posted smaller net gains (+3.5 GW and +1.2 GW, respectively), and CAISO and PJM saw minor net declines (−1.3 GW and −0.2 GW). SPP experienced a net −28.3 GW swing that accounts for essentially all of the period’s contraction.

GridTracker subscribers will have seen our March report on the Phase 1 study results for SPP’s DISIS-2024-001 cluster. As we saw in that report, DISIS-2024-001 is the largest interconnection cluster in SPP history, with more than 250 projects and 66.5 GW seeking interconnection. The Phase 1 study process allocated $30.2 billion in network upgrade costs, with a median project cost of $408/kW. In that report we flagged that many of these projects sat in the path of newly planned 765 kV transmission lines and had been assigned massive upgrade costs to help fund them, and that heavy attrition was likely. After Phase 1 results were posted, they had 15 business days to advance into the next study phase or withdraw. SPP has now updated its queue to reflect those decisions.

The post-Phase 1 decisions played out as we predicted. Attrition was substantial and clearly driven by costs. Nearly half the cluster’s projects (122, totaling 28.1 GW) withdrew. As we predicted in our March report, the withdrawn projects were largely those which faced the highest upgrade costs. Withdrawn projects had a median allocated cost of $655/kW versus $244/kW for those that stayed. 72% of the withdrawn cohort had allocated costs above the $408/kW median identified in our Phase 1 analysis, compared to just 26% of those that remained. Of the cluster’s $30.2 billion in allocated costs, roughly $19.3 billion, about two-thirds, was allocated to projects that have now exited.

Those costs are overwhelmingly shared network upgrade costs rather than POI costs. 91% of the withdrawn projects’ allocated costs were for network upgrades and only 9% for POI facilities. The largest of those network costs trace to a single 765 kV corridor: the Minco, Phantom, and Woodward EHV ties into Crawfish Draw are the biggest line items in the withdrawn cohort, each allocated between $600 and $700 million across roughly 30 of the withdrawn projects. The Southeast study region shed the most capacity (42 projects, 10 GW) but at a moderate $431/kW median, while the Southwest and Central study regions carried the highest median upgrade costs among the withdrawn ($980/kW and $923/kW, respectively) and the two largest total cost burdens ($6.9 billion and $6.1 billion).

The DISIS-2024-001 cluster was almost entirely composed of projects seeking full-deliverability: 241 of 251 active projects requested NRIS service, requiring study for full network deliverability. Within the set of NRIS projects, the projects that withdrew faced a $655/kW median against $262/kW for those that stayed. However we cut the data, the result is the same: upgrade costs are what separated the projects that withdrew from the ones that stayed in the queue.

Outside SPP, two regional stories played out. BPA posted 4.4 GW of withdrawals across 15 projects in Washington and Oregon, all of it renewables and storage. Storage and storage hybrids made up the bulk, led by a single 1 GW battery exit, with wind accounting for most of the rest. PSCo’s new requests cut the other way: 13.3 GW of additions across 46 projects, overwhelmingly solar and storage. Solar+battery hybrids led at 5.3 GW, with standalone solar and battery close behind (about 2.4 GW each) and wind adding another 1.8 GW.

Notable Projects/Trends

A few individual projects worth flagging. Counter to the broader pattern we've observed recently, where renewables and storage made up the bulk of withdrawn capacity, the single largest project to withdraw was a 1.3 GW gas plant in SPP (Oklahoma Gas and Electric). In terms of additions, the standout is the Double C Energy Center, a roughly 1.25 GW Entergy Arkansas development in Crittenden County, AR, that includes an 826 MW solar+battery facility and a 421 MW battery facility. The development is located near Google's $4 billion West Memphis data center, announced in October 2025 and powered by Entergy. It interconnects directly into the West Memphis 500 kV line. It's an early, concrete example of hyperscaler energy procurement showing up in the generator interconnection queue. That’s something we expect to see more of, and will continue to track, as data center buildouts accelerate. On the operational side, little came online. The largest was a 200 MW solar project in MISO (Michigan), alongside four smaller storage and solar+storage projects in CAISO from Southern California Edison.

GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

• Exportable datasets (export the full list of newly operational, withdrawn, GIA-signed, and added projects)

• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

• … and much more!

Learn More About GridTracker

A Quick Introduction

Welcome to the first issue of our newsletter, authored in partnership with . Nick spent two years at Lawrence Berkeley National Lab’s Energy Markets and Policy Group, where he contributed to Queued Up, the annual report widely treated as the standard reference on U.S. interconnection queues. We worked closely with Nick during his time at LBNL, and there’s nobody we’d rather have helping us unpack the queue data every two weeks. This newsletter delivers biweekly insights into the most relevant updates that affect the U.S. grid and the projects planning to interconnect to it. We’ll surface relevant news, regulatory insights, and of course, in-depth intel on what is changing in the interconnection queues across the country.

Executive Summary

The past 2 weeks have seen exceptional activity in the queues. 157 new projects totaling 36.92 GW entered the queues against 4.56 GW of withdrawals, largely driven by 25 GW of additions from Southern Company’s 2026 cluster window. The broader renewable versus firm/thermal bifurcation of the queues continues: gas led additions this period (roughly 20 GW added, +50% YoY), while renewable and battery storage queue capacity continues to contract. Regional trends and totals will be impacted by the 811 recently announced new projects (220 GW) from the first cycle of PJM’s reformed interconnection process.

In the News

• PJM capacity market overhaul. PJM released a whitepaper last week, Powering Reliability Through Market Design, proposing three frameworks for reforming its capacity market amid skyrocketing demand.

  • The options outlined are:

    • Stabilize the existing capacity market

    • Differentiate grid reliability by customer type or geography

    • Transition to an energy and ancillary services market with contracting requirements to guard consumers against energy price volatility.

  • FERC approved PJM’s extension of the existing capacity auction price cap and floor for two more years on April 28th.

• FERC action on large load interconnection is looming. Last month, FERC announced that they will act by June on DOE’s October 2025 ANOPR (Docket RM26-4-000). The ANOPR directs FERC to issue a set of reforms standardizing the interconnection process for data centers and other large loads.

• NextEra & Dominion mega-merger announced. NextEra Energy announced on May 18th it has agreed to acquire Dominion Energy in a $67 billion deal, creating the largest regulated utility business in the U.S. Particularly timely given Virginia’s April 2026 legislation requiring Dominion to procure 16 GW of short-duration storage and 4 GW of long-duration storage by 2045.

• Hot rocks and hot stocks. Geothermal continues to have its moment. Fervo Energy raised $1.89 billion in its IPO this past week. Amazon recently announced a PPA for 100 MW of geothermal from Zanskar in Nevada.

Worth a Read

• Substack commentary on PJM’s recent capacity market whitepaper from Lynee Kiesling and Elizabeth K. Whitney.

• For those of you tuned in to the ongoing discussions surrounding the rate impacts of large loads, Brattle Group and ESIG released a great primer on the topic.

Where’s the Activity?

New queue entries during this period are clustered most heavily in the Southeast, ERCOT, and the Pacific Northwest (Avista). We also see a smattering of queue additions across the non-CAISO West (PacifiCorp/Idaho Power) and the Midwest/Plains.

The Southeast led all regions in new capacity additions at just under 26 GW, driven almost entirely by new gas projects in Southern Company’s service territory following the April 3rd close of Southern Company’s 2026 cluster request window. ERCOT added another 6.5 GW of capacity over the past two weeks, with three of the five largest new requests sited in Texas.

Withdrawals were modest and broadly scattered during this period. No single region or utility drove meaningful attrition, and at 4.56 GW, this period’s withdrawal volume was roughly 60% lower than the prior two-week period.

More than 700 GW of capacity exited U.S. queues in 2025 as FERC Order 2023 and other ISO- and utility-specific reforms cleared out a backlog of projects unlikely to ever be built. The relative lull in withdrawals over the last two weeks may not be indicative of a slowing of withdrawal rates in 2026. Two major ISO clusters could drive significant withdrawals this year. SPP has yet to publish updates to its DISIS 2024 cluster data since its Phase 1 results in March, and PJM’s first reformed cluster window (811 projects, 220 GW) only closed on April 27th, with no early-stage withdrawals yet reflected in the PJM data.

Newly operational projects appeared across the country, with battery projects coming online in CAISO and ERCOT, solar in SPP and the Southeast, as well as gas and oil in ERCOT and the Southwest. We also see roughly 4 GW (19 projects) with newly signed GIAs in the queue data over the past two-week period, a 142% increase compared to the prior two-week period. Most of these newly signed GIAs are clustered in the central U.S. (ERCOT and SPP) and mainly for solar and battery storage projects.

Activity at a Glance

The first two weeks of May have been a relatively active period for U.S. interconnection queues. 157 new projects totaling 36.92 GW entered the queues, a 250% jump from the prior two-week period. Only early April (50 GW added) saw more new queue capacity over the past six months.

After years of surging requests from renewables (mainly solar and storage) we are now seeing gas rebound and continue to drive additions to the queue, accounting for more than half of all new capacity this period (~20 GW). Batteries (~10 GW) were the second largest contributor to the increase in queue capacity over the last two weeks.

Withdrawals were comparatively muted at 4.56 GW across 26 projects. The tech mix of withdrawals largely tracks the composition of the active queue. Battery storage and solar represent the largest shares of both currently active queue and recently withdrawn capacity. Six projects (864 MW total) suspended their queue request during this period.

Other parts of the queue ecosystem were active as well. 28 projects totaling 3.78 GW were reported as newly operational (up over 800% vs. the prior two-week period), and 21 projects (4.17 GW) appeared with newly signed GIAs (up 142%). Two-week snapshots of these metrics depend on utility and ISO data publication cadence, but the simultaneous uptick is a positive signal for project progression in 2026.

Queue Snapshot

Overall U.S. queue capacity is continuing its multi-year contraction into early 2026. Active queue capacity now stands at 1.83 TW across 8,769 projects, down more than 200 GW from the end of 2025 (2.061 TW) and marking the second consecutive year of contraction following the 20–40% annual growth that defined 2019 to 2023. Two opposing YoY trends define the current state of the queues: the continued contraction of renewables and storage, and the rapid expansion of firm resources (mainly gas).

Every major renewable and storage category is down YoY. Solar fell 24% (now 446 GW), solar plus battery hybrids dropped 21% (305 GW), wind shed 22% (198 GW), and offshore wind contracted by 13% (16 GW). Storage, which had seen substantial growth through 2023, has also entered the contraction phase with active battery capacity down 14% YoY (437 GW).

On the firm side of the queue, the trend is flipped. Gas is up 50% YoY at 273 GW, consistent with the surge that dominated 2025 additions and continues to lead recent activity. Nuclear capacity in the queue is up 75% to 14 GW, likely reflecting expectations around data center load. Geothermal is up 114% (nearly 4 GW), and even diesel (+282%) and coal (+5%) are growing.

Regionally, the queue remains heavily concentrated in three markets: the non-CAISO West (~430 GW), ERCOT (~420 GW), and MISO (~350 GW). Together these three represent the bulk of total queued capacity. The Southeast (~160 GW), SPP (~170 GW), CAISO (~120 GW), and PJM (~120 GW) trail behind, though PJM’s recent cluster window (220 GW of new requests) will reshape regional totals once those projects are reflected in the queue data.

Regional Breakdown

The Southeast region added more new capacity over the last two weeks than every other market combined. 25.88 GW of new entries against just 470 MW of withdrawals yields +25.41 GW net for the region, driven almost entirely by gas projects in Southern Company service territory. ERCOT added another +6.02 GW net (6.50 GW in, 487 MW out), continuing the steady growth trajectory that has defined its queue since 2023. The West contributed +2.77 GW net. In the absence of new cluster window data (still no project-level details on PJM’s Cycle 1), all other markets saw net withdrawals, led by MISO at -1.23 GW. The remaining markets each saw less than 200 MW of net withdrawals.

The West has contracted from ~480 GW since last June, while ERCOT has held roughly steady. MISO, one of the busiest markets in 2025, has shed roughly 75 GW over the same window, working through the aftermath of its DPP 2022 and DPP 2023 cluster cycles. CAISO, PJM, Southeast, and SPP all hover in the 120–175 GW range while NYISO is down from ~45 GW to ~25 GW over the past year.

PJM’s recent reformed-process cluster window will reshape these rankings significantly. Once those 220 GW (811 projects) are reflected in queue data, PJM will jump from ~120 GW to roughly ~340 GW, putting it in line with MISO. We should start to see the new PJM requests reflected in the data in the coming weeks.

Notable Projects/Trends

The largest new requests in this period reinforce the broader trend we have seen in queues over the last year or so. Gas is continuing to dominate additions, and over the last two weeks the largest prospective gas projects are coming from the Southeast and ERCOT.

Four of the five largest new requests are natural gas. Two are from Southern Company (1.50 GW and 785 MW) and ERCOT also added two projects greater than 1 GW. The volume of large gas projects in these regions is another sign of the firm capacity build out that has been gathering momentum throughout 2025 and 2026, likely driven by rising data center load growth and lower interconnection costs.

The Biggest Movers

Multiple new mega-projects entered the queues during this period. If you’re interested in following projects like these with real-time change alerts and deeper asset-level insights, reach out to us to learn more about GridTracker.

GridTracker users get access to:

• Project-level insights (see the project-level changes that occur in real-time)

• Exportable datasets (export the full list of newly operational, withdrawn, GIA-signed, and added projects)

• Interactive graphs and visualizations

• Custom dashboards with real-time alerts and data export

• … and much more!

Learn More About GridTracker

Top takeaways from the LBNL report

This report confirms and extends the trends that we flagged in our 2025 retrospective analysis published in February 2026: queues contracted across the country by a meaningful margin overall in 2025. However, the distribution of these withdrawals reflects a stark difference between technologies. Renewables shrank across the board, while gas capacity grew dramatically in the major markets.

Q3 and Q4 of 2025 saw the most dramatic withdrawal volumes, likely due (at least in part) to the tax implications of the OBBBA, but also due to very large clusters in MISO and SPP entering critical decision point windows.

How to access the LBNL data

1. Go to https://emp.lbl.gov/queues

2. Navigate to the bottom, and click the Data File link (note: the PDF report is still last year’s PDF report, reflecting changes through EOY 2024)

   

Want real-time queue data?

Reach out if you are interested in real-time intelligence about projects being planned, developed, operated, and cancelled for grid interconnection.

In addition to a real-time version of the LBNL dataset, GridTracker users can:

• See much deeper information about projects by accessing related regulatory filings, press releases, and other crucial resources relevant to projects connecting to the grid

• Track data center builds across the country based on permits and official records, and not just press releases

• See detailed developer profiles including owned projects, track record, and contact information of folks actively working on each company’s portfolio

API access is also available for those who need a more automated data integration.

If you’d like to learn more, you can book a call here:

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The Phase 1 results reveal a total of $30.2 billion in allocated network upgrade costs across the cluster, with a median cost assignment of $375/kW. Developers in this cluster now have 15 business days to determine whether to proceed in the queue or withdraw their request. Based on historical SPP withdrawal patterns, substantial attrition is likely.

DISIS 2024 Cycle Overview

The cluster’s unprecedented size is partly by design. The application window was extended by roughly five months following SPP’s FERC waiver request. The extension, combined with strong developer interest, produced a cluster more than twice the size of any prior cycle, and the pre-Phase 1 withdrawal rate had already exceeded 30% before a single cost assignment was posted.

Gas comprises the largest share of total active capacity at 17.7 GW across 33 projects. Solar (62 projects, 13.9 GW) and battery storage (74 projects, 13.9 GW) are nearly identical in total capacity. Solar + battery hybrids comprise 43 projects and 10.3 GW. Wind, historically a major resource type in SPP, accounts for just 32 projects and 9 GW, its smallest share of any recent DISIS cluster.

Phase 1 Cost Results

… Continue reading on Interconnection.fyi

Load forecasts exploded thanks to an era-defining AI infrastructure boom.

Renewables were suddenly forced to grapple with the upending of incentives which were often foundational for their financial viability.

Supply chain woes compounded.

And sweeping queue reform was enacted swiftly in many regions.

The net impact of all of this: an unprecedented volume of withdrawals from interconnection queues, especially among renewable projects. But not all technologies were as battered as solar and wind. Gas projects swarmed the queues, with total gas capacity growing nearly 40%, while all other major technologies experienced a relentless culling.

… you can continue reading the free report on the interconnection.fyi blog

Or, purchase the full report to understand:

• Full regional and technology breakdowns for withdrawals, additions, new CODs

• See which ISOs drove each wave, cluster-by-cluster detail, and the impact of the ERAS fast-track program.

• Full report also includes fully exportable project-level data:

  • 2025 Starting Projects dataset (12,453 rows)

  • 2025 Ending Projects dataset (10,027 rows)

  • Projects added during 2025 (2,140 rows)

  • Projects which became operational in 2025 (408 rows)

  • Projects which signed GIAs in 2025 (2,722 rows)

  • Projects which withdrew in 2025 (4,061 rows)

  • 46 charts with per-power-market and per-technology breakdowns + printable PDF (no watermarks)

👉 Buy the full report here

The queue data tells you a project exists. But it doesn’t tell you who’s actually making decisions on it, what permits have been filed, or what FERC, state, or county proceedings might affect its timeline. That context lives across hundreds of scattered sources, and tracking it manually doesn’t scale.

So we built something to solve that.

Introducing GridTracker

GridTracker gives you real-time visibility into every generation project in every transmission interconnection queue across the continental US and Canada. But more importantly, it connects each project to the broader context that determines whether it will actually get built.

See the documents that matter

Immediately pull up relevant permits, press releases, FERC filings, and state PUC/PSC dockets in one click. No more hunting across multiple databases, and no more wrestling clunky government websites with incomplete and cumbersome search portals.

Find the actual decision-makers

This isn't a "who works at Company X" list from LinkedIn. We track who's attending relevant meetings and signing the paperwork. These are the people who are actually moving the projects forward.

Build precise watchlists and get notified

Define exactly the segments you care about. For example: "solar projects in ERCOT and SPP with planned CODs between May and October 2027, connecting at 69kV." (Side note: There are currently 13 projects matching those criteria, totaling 1.2 GW. The largest is Double A Solar in Goliad County, TX, owned by Birch Creek). You can track segments like this and get notified whenever something changes or a new project matches.

GridTracker is built on interconnection.fyi's real-time dataset, the same data trusted by organizations like Lawrence Berkeley National Lab for their Queued Up report. We've layered on a deeply curated collection of additional sources to give you the full picture.

Want to see it?

Visit the GridTracker homepage for more details, or schedule a demo to explore whether a subscription makes sense for your team.

We have some significant updates coming to GridTracker in the next few months. And keep an eye out for our retrospective report on what happened in the queues in 2025!

Special Note: Interested in tracking project in the interconnection queues in real-time? Join the waiting list for early access to GridTracker here. It’s the easiest way to get access to all of interconnection.fyi’s data.

We saw the following updates to U.S. transmission grid interconnection projects. For access to our live dataset, contact our sales team here.

ARIDA 2 SOLAR FARM — 700MW battery + solar 🔋☀️ project in Clark, NV (CAISO). Proposed completion changed from December 29, 2027 to May 30, 2029

Deedsville 345 kV Substation — 292MW solar ☀️ project in Miami County, IN (MISO). Proposed completion changed from July 31, 2023 to July 31, 2026

Substation 1363; 161kV Substation — 255MW gas 🔥 project in Sarpy County, NE (SPP). Proposed completion changed from July 31, 2024 to June 16, 2025

Macomb to Ipava 138kV line — 200MW wind 💨 project in Mcdonough County, IL (MISO). Proposed completion changed from September 14, 2023 to September 14, 2026

Shockey 138kV — 200MW wind 💨 project in Logan County, IL (MISO). Proposed completion changed from October 30, 2023 to August 14, 2026

Ray Place Road - Washington #3 115 kV Line — 150MW solar ☀️ project in Taliaferro County, GA (Southern Company). Proposed completion changed from January 31, 2029 to January 16, 2028

Achord Road - Eastman Primary 230 kV Line — 150MW solar ☀️ project in Dodge County, GA (Southern Company). Proposed completion changed from August 14, 2028 to January 16, 2028

Hutsonville - Neoga 138 kV — 149MW solar ☀️ project in Cumberland County, IL (MISO). Proposed completion changed from July 31, 2023 to May 31, 2027

Bureau County 138 kV — 147MW wind 💨 project in Bureau County, IL (MISO). Proposed completion changed from July 31, 2022 to July 31, 2025

KENOWA - NELSON ROAD 345.0kV — 132MW solar ☀️ project in Montcalm County, MI (MISO). Proposed completion changed from October 31, 2023 to January 8, 2026

San Jose Rail Splitter 138KV (G515) — 100MW wind 💨 project in Tazewell County, IL (MISO). Proposed completion changed from August 31, 2024 to May 31, 2027

Eureka - Vestaburg 138kV Transmission Line (J1379 POI) — 100MW battery + solar 🔋☀️ project in Montcalm County, MI (MISO). Proposed completion changed from August 31, 2024 to June 6, 2027

Emery substation — 100MW battery 🔋 project in Emery, UT (PacifiCorp). Proposed completion changed from December 30, 2026 to June 29, 2027

ALTA VISTA SUNTOWER GENERATING STATION — 66MW battery + solar 🔋☀️ project in Los Angeles, CA (CAISO). Proposed completion changed from April 14, 2025 to December 10, 2027

Henry Solar — 20MW solar ☀️ project in Crawford County, PA (PJM). Proposed completion changed from July 30, 2027 to December 30, 2026

Hinkle substation — 10MW wind 💨 project in Umatilla, OR (PacifiCorp). Proposed completion changed from December 17, 2020 to December 29, 2016

Hinkle substation — 10MW wind 💨 project in Umatilla, OR (PacifiCorp). Proposed completion changed from December 17, 2020 to December 29, 2016

Hinkle substation — 10MW wind 💨 project in Umatilla, OR (PacifiCorp). Proposed completion changed from December 17, 2020 to December 29, 2016

Alturas-Mile Hi transmission line — 1MW solar ☀️ project in Lake, OR (PacifiCorp). Proposed completion changed from May 26, 2019 to November 30, 2017

ARIDA 2 SOLAR FARM — 700MW battery + solar 🔋☀️ project in Clark, NV (CAISO). Proposed completion changed from December 29, 2027 to May 30, 2029

Deedsville 345 kV Substation — 292MW solar ☀️ project in Miami County, IN (MISO). Proposed completion changed from July 31, 2023 to July 31, 2026

115kV Strandahl sub — 255MW wind 💨 project in Williams County, ND (SPP). Proposed completion changed from October 29, 2026 to May 30, 2028

Substation 1363; 161kV Substation — 255MW gas 🔥 project in Sarpy County, NE (SPP). Proposed completion changed from July 31, 2024 to June 16, 2025

Hickory Level - Yellow Dirt 230 kV Line — 250MW battery 🔋 project in Douglas County, GA (Southern Company). Proposed completion changed from April 14, 2029 to April 16, 2028

Goose Pond Road Substation 230 kV Bus, East Watkinsville - Goose Pond Road 230 kV Line — 250MW battery 🔋 project in Oglethorpe County, GA (Southern Company). Proposed completion changed from April 14, 2029 to April 16, 2028

Macomb to Ipava 138kV line — 200MW wind 💨 project in Mcdonough County, IL (MISO). Proposed completion changed from September 14, 2023 to September 14, 2026

Shockey 138kV — 200MW wind 💨 project in Logan County, IL (MISO). Proposed completion changed from October 30, 2023 to August 14, 2026

Eastman Primary - Hatch 230 kV Line — 199MW solar ☀️ project in Laurens County, GA (Southern Company). Proposed completion changed from April 14, 2029 to April 16, 2028

Ray Place Road - Washington #3 115 kV Line — 150MW solar ☀️ project in Taliaferro County, GA (Southern Company). Proposed completion changed from January 31, 2029 to January 16, 2028

Achord Road - Eastman Primary 230 kV Line — 150MW solar ☀️ project in Dodge County, GA (Southern Company). Proposed completion changed from August 14, 2028 to January 16, 2028

Hutsonville - Neoga 138 kV — 149MW solar ☀️ project in Cumberland County, IL (MISO). Proposed completion changed from July 31, 2023 to May 31, 2027

Bureau County 138 kV — 147MW wind 💨 project in Bureau County, IL (MISO). Proposed completion changed from July 31, 2022 to July 31, 2025

KENOWA - NELSON ROAD 345.0kV — 132MW solar ☀️ project in Montcalm County, MI (MISO). Proposed completion changed from October 31, 2023 to January 8, 2026

San Jose Rail Splitter 138KV (G515) — 100MW wind 💨 project in Tazewell County, IL (MISO). Proposed completion changed from August 31, 2024 to May 31, 2027

Eureka - Vestaburg 138kV Transmission Line (J1379 POI) — 100MW battery + solar 🔋☀️ project in Montcalm County, MI (MISO). Proposed completion changed from August 31, 2024 to June 6, 2027

Emery substation — 100MW battery 🔋 project in Emery, UT (PacifiCorp). Proposed completion changed from December 30, 2026 to June 29, 2027

Eastman Primary - Hatch 230 kV Line — 100MW battery 🔋 project in Laurens County, GA (Southern Company). Proposed completion changed from April 14, 2029 to April 16, 2028

ALTA VISTA SUNTOWER GENERATING STATION — 66MW battery + solar 🔋☀️ project in Los Angeles, CA (CAISO). Proposed completion changed from April 14, 2025 to December 10, 2027

Henry Solar — 20MW solar ☀️ project in Crawford County, PA (PJM). Proposed completion changed from July 30, 2027 to December 30, 2026

Hinkle substation — 10MW wind 💨 project in Umatilla, OR (PacifiCorp). Proposed completion changed from December 17, 2020 to December 29, 2016

Hinkle substation — 10MW wind 💨 project in Umatilla, OR (PacifiCorp). Proposed completion changed from December 17, 2020 to December 29, 2016

Hinkle substation — 10MW wind 💨 project in Umatilla, OR (PacifiCorp). Proposed completion changed from December 17, 2020 to December 29, 2016

Alturas-Mile Hi transmission line — 1MW solar ☀️ project in Lake, OR (PacifiCorp). Proposed completion changed from May 26, 2019 to November 30, 2017

Regional Capacity Changes (2023 → 2024)

The interconnection.fyi team went digging through our historical dataset to see how active queue volumes have shifted year-over-year — and for the first time in recent memory, they're shrinking.

The chart below compares 2023 vs. 2024 cumulative active capacity by fuel type and planning region, comparing snapshots taken at the end of each year. It reflects only projects that remained active at the end of each year, excluding anything withdrawn, completed, or otherwise removed from the queue. Green bars indicate an increase from 2023 to 2024; red bars represent a decrease.

That sea of red? It's not what we're used to seeing.

For years, active queue volumes grew at a breakneck pace — fueled by a surge of solar, wind, and storage projects. But in 2024, that trend reversed. Offshore wind fell by over 50%, solar dropped nearly 12%, and hybrid storage declined by nearly 20%.

So what changed?

Most signs point to queue reform. Over the past 18 months, ISOs like PJM, MISO, and CAISO implemented new rules requiring higher deposits, stricter site control, and milestone-based study processes. On top of that, FERC Order 2023 — while not yet fully implemented — means that these changes are here to stay. The one major exception? ERCOT, which isn't subject to FERC rules and continues to operate under its own policies.

One notable exception to the contraction trend was MISO, which saw a significant increase in queued capacity across nearly every fuel type. At first glance, this might seem to contradict the broader story — but it likely reflects a timing artifact, not a structural break.

MISO's queue was largely frozen in 2023 as it transitioned to a new interconnection process. When it reopened in early 2024, a wave of new applications entered — potentially representing deferred demand from developers waiting on clarity around the new rules. In this light, MISO's growth doesn't undermine the queue reform hypothesis — it just reflects how differently that transition played out across regions.

It's too early to tell if this is a lasting correction or a temporary reset — but 2024 marks a clear turning point in the evolution of interconnection queues.

While some of the recent decline in active queue capacity might be attributed to fewer new applications, that's not the whole story. In fact, 2024 saw a massive spike in project withdrawals. Among projects with reported withdrawal dates (which is only about half of all withdrawn projects), plus withdrawals from CAISO cluster 15[1], 296 GW of capacity was withdrawn from the queues last year — more than double the amount withdrawn in 2023, and by far the largest annual total in the dataset.

The number of individual projects withdrawn also surged, jumping 96% year-over-year. This points to a broader structural shift: queue reform processes are not just filtering future applicants — they're forcing existing projects out. The bottleneck isn't closing at the entrance; it's clearing out the middle.

Queue Timelines (2023 → 2024)

How long does it take to get through the queue?

To answer that, we analyzed the time between a project's interconnection request and its eventual commercial operation date (COD). For each power market, we calculated the median and interquartile range (25th to 75th percentile) of queue-to-COD durations for projects that reached COD in a given year.

These charts reveal that typical development timelines remain stubbornly long — often 3 to 5 years — with wide variability depending on the market. Some regions like PJM and the Southeast show relatively consistent durations, while others like SPP display more volatility and longer median timelines. Nationally, there's no clear evidence yet that queue reform efforts have meaningfully shortened the path to COD.

Note: ERCOT and NYISO are excluded from this analysis due to insufficient historical data for meaningful timeline comparisons. Including ERCOT would likely decrease the median timeline.

Note: These figures likely undercount the total number of projects reaching COD each year, as we can only include projects that report their actual commercial operation dates in interconnection queue data.

Withdrawal Timelines (2023 → 2024)

What about the projects that didn't make it?

To better understand the other side of queue attrition, we looked at how long withdrawn projects had been sitting in the queue before exiting. For each power market, we measured the time between a project's interconnection request and its withdrawal, and calculated the median and interquartile range for projects withdrawn in a given year.

The picture that emerges is just as striking. In 2024, many withdrawn projects had been in the queue for 4 to 5 years — a meaningful amount of time for developers to invest before walking away. In markets like CAISO, the median project sat in the queue for over 5.4 years before withdrawing. PJM, Southeast, and MISO show slightly shorter timelines, but still hover around the 3–4 year mark.

Importantly, this analysis includes only the roughly 50% of withdrawn projects that report a withdrawal date. While incomplete, we believe the trend is representative; these aren't just speculative applications disappearing overnight. In many cases, they're projects that stuck it out for several years before ultimately exiting, likely due to delays, reform-driven barriers, or shifting market conditions.

There’s more! Check out the rest of this analysis on our website here.

Special Note: Looking to buy or sell a project in the interconnection queue? We’re actively connecting developers with vetted, transaction-ready buyers and sellers at key decision points. Fill out this short form to get matched with serious players already in the market.

We saw the following updates to U.S. transmission grid interconnection projects. For access to our live dataset, contact our sales team here.

Caledonia — 889MW gas 🔥 project in Lamar County, AL (Southern Company). IA date changed from September 4, 2013 to July 16, 2020

McCall Road - West McIntosh 500 kV Line — 722MW gas 🔥 project in Effingham County, GA (Southern Company). Proposed completion changed from August 31, 2029 to November 30, 2031

Casitas 66/16 (D) — 500MW solar ☀️ project in Ventura, CA (CAISO). Proposed completion changed from December 30, 2025 to November 14, 2026

Chickahominy Solar 1 and 2 — 320MW solar ☀️ project in Charles City County, VA (PJM). Proposed completion changed from December 30, 2025 to December 30, 2024

North Dublin - Wadley Primary 230 kV Line — 225MW solar ☀️ project in Laurens County, GA (Southern Company). Proposed completion changed from February 28, 2027 to May 31, 2028

Laurel East - South Jones 230 kV Line — 200MW solar ☀️ project in Jones County, MS (Southern Company). Proposed completion changed from July 31, 2027 to October 5, 2028

Rocky Creek - Wadley Primary 230 kV Line — 200MW solar ☀️ project in Jefferson County, GA (Southern Company). Proposed completion changed from June 14, 2027 to May 31, 2028

Douglas - Kettle Creek Primary 230 kV Line — 200MW battery + solar 🔋☀️ project in Coffee County, GA (Southern Company). Proposed completion changed from April 30, 2026 to September 30, 2027

North Americus - Palmyra 230 kV Line — 200MW battery + solar 🔋☀️ project in Lee County, GA (Southern Company). Proposed completion changed from June 30, 2026 to May 31, 2027

North Tifton - Stump Creek 230 kV Line — 200MW battery + solar 🔋☀️ project in Irwin County, GA (Southern Company). Proposed completion changed from December 3, 2026 to June 5, 2028

McConnell - Pegamore 230 kV Line — 200MW battery 🔋 project in Paulding County, GA (Southern Company). Proposed completion changed from March 31, 2027 to March 31, 2030

Hillsdale North — 185MW solar ☀️ project in Vermillion County, IN (MISO). Proposed completion changed from June 19, 2025 to October 5, 2026

Bassett Creek - Greene County 230 kV Line — 175MW battery + solar 🔋☀️ project in Marengo County, AL (Southern Company). Proposed completion changed from March 31, 2027 to November 30, 2028

Scooter Substation 230 kV BUS — 160MW battery + solar 🔋☀️ project in Mitchell County, GA (Southern Company). Proposed completion changed from April 30, 2026 to April 30, 2027

DeGrasse 138kV Substation — 155MW solar ☀️ project in Woods County, OK (SPP). Proposed completion changed from December 30, 2027 to December 30, 2028

Ramsey East 138kV bus — 150MW solar ☀️ project in Fayette County, IL (MISO). Proposed completion changed from August 4, 2024 to April 29, 2027

Skillman Substation 161kV — 150MW solar ☀️ project in Hancock County, KY (MISO). Proposed completion changed from August 31, 2023 to August 31, 2026

Worthington Substation 138kV — 150MW solar ☀️ project in Greene County, IN (MISO). Proposed completion changed from August 31, 2023 to August 31, 2026

Morrison Ditch 138kV — 150MW solar ☀️ project in Newton County, IN (MISO). Proposed completion changed from September 30, 2023 to September 30, 2026

San Jose Rail 138kV — 150MW solar ☀️ project in Tazewell County, IL (MISO). Proposed completion changed from September 14, 2023 to September 14, 2026

Sandersville #1 - Wadley Primary 230 kV LIne — 127MW solar ☀️ project in Jefferson County, GA (Southern Company). Proposed completion changed from May 30, 2027 to May 31, 2028

Bonaire Primary - Eastman Primary 115 kV Line — 120MW solar ☀️ project in Dodge County, GA (Southern Company). Proposed completion changed from August 14, 2022 to January 30, 2027

Ridgeway Solar — 120MW solar ☀️ project in Mckean County, PA (PJM). Proposed completion changed from January 29, 2026 to June 29, 2025

Dodson Creek Solar — 117MW solar ☀️ project in Ross County, OH (PJM). Proposed completion changed from July 29, 2024 to May 29, 2025

Shaddock Creek - Vidalia 115 kV Line — 110MW battery + solar 🔋☀️ project in Treutlen County, GA (Southern Company). Proposed completion changed from August 14, 2026 to February 14, 2027

North Tifton - Pitts 230 kV Line — 110MW battery + solar 🔋☀️ project in Turner County, GA (Southern Company). Proposed completion changed from August 14, 2026 to February 14, 2027

Auburn North to Chatham Main 138kV — 100MW solar ☀️ project in Sangamon County, IL (MISO). Proposed completion changed from August 30, 2023 to August 30, 2026

Newton - Forest Industrial 115 kV Line — 100MW solar ☀️ project in Newton County, MS (Southern Company). Proposed completion changed from March 31, 2027 to March 31, 2029

Anniston (APC) - Hammond 230 kV Line — 100MW solar ☀️ project in Floyd County, GA (Southern Company). Proposed completion changed from August 14, 2026 to December 3, 2028

North Fort Dodge 115kV Substation — 100MW solar ☀️ project in Ford County, KS (SPP). Proposed completion changed from December 14, 2027 to December 14, 2028

Moonstone Substation 138kV — 100MW battery + solar 🔋☀️ project in Blaine, ID (Idaho Power Company). IA date added April 29, 2025

Moonstone Substation 138kV — 100MW battery + solar 🔋☀️ project in Blaine, ID (Idaho Power Company). IA date added April 29, 2025

Thistle 345kV substation — 95MW battery 🔋 project in Barber County, KS (SPP). Proposed completion changed from December 30, 2027 to November 30, 2028

Hawthorn Solar — 83MW solar ☀️ project in Delaware County, IN (PJM). Proposed completion changed from December 30, 2027 to December 30, 2028

Tonnece Substation 69kV — 80MW solar ☀️ project in Benton County, AR (SPP). Proposed completion changed from December 30, 2025 to July 10, 2027

Cane Creek Solar — 78MW solar ☀️ project in Clarke County, MS (Southern Company). IA date added November 18, 2021

MoonShot Solar — 78MW solar ☀️ project in Hancock, MS (Southern Company). IA date added November 18, 2021

Rocky Forge Wind — 78MW wind 💨 project in Botetourt County, VA (PJM). Proposed completion changed from December 30, 2025 to December 30, 2026

GPC Mossy Branch Battery Storage Station, Mossy Branch Substation 115 kV Bus — 65MW battery 🔋 project in Talbot County, GA (Southern Company). IA date added March 9, 2021

MULQUEENEY RANCH WIND 2 — 60MW wind 💨 project in Alameda, CA (CAISO). Proposed completion changed from November 29, 2024 to May 31, 2026

Shell - McCracken County 69.0kV — 60MW solar ☀️ project in Mccracken County, KY (MISO). Proposed completion changed from October 30, 2022 to October 30, 2025

Mark Center Solar Project — 60MW solar ☀️ project in Defiance County, OH (PJM). Proposed completion changed from December 30, 2025 to September 29, 2026

Fort Stewart CU 115 kV Bus — 43MW battery + solar 🔋☀️ project in Liberty County, GA (Southern Company). Proposed completion changed from February 8, 2026 to February 11, 2027

South Fairchild Tap 115kV — 40MW solar ☀️ project in Spokane, WA (Avista Utilities). Proposed completion changed from June 29, 2027 to June 29, 2028

MCLB Solar — 31MW solar ☀️ project in Dougherty County, GA (Southern Company). IA date changed from August 31, 2016 to November 10, 2016

Gavin Unit No. 1 — 18MW coal 🏭 project in Gallia County, OH (PJM). Proposed completion changed from June 8, 2024 to May 30, 2025

Saticoy 66/16 (D) — 4MW battery 🔋 project in Ventura, CA (CAISO). Proposed completion changed from December 30, 2025 to November 14, 2026

LASSEN LODGE HYDROELECTRIC 2 — 0MW hydro 💧 project in Tehama, CA (CAISO). Proposed completion changed from October 15, 2024 to October 14, 2027

Sunrise Wind — 880MW offshore wind 🌊️ project in Suffolk County, NY (NYISO). Proposed completion changed from February 28, 2026 to June 30, 2027

EUISMOD — 600MW battery + solar 🔋☀️ project in Kern, CA (CAISO). Proposed completion changed from February 25, 2033 to May 31, 2028

Glen Falls Facility — 550MW gas 🔥 project in Harrison County, WV (PJM). Proposed completion changed from March 30, 2028 to January 30, 2029

P2789 Red Willow Solar Battery — 325MW battery + solar 🔋☀️ project in Flagstaff County, AB (AESO). Proposed completion changed from January 31, 2027 to August 30, 2028

P2347 Forty Mile Granlea Solar Phase 2 — 220MW solar ☀️ project in Cypress County, AB (AESO). Proposed completion changed from June 30, 2025 to August 30, 2028

Terminal substation — 200MW battery 🔋 project in Salt Lake, UT (PacifiCorp). Proposed completion changed from June 30, 2026 to December 30, 2025

P2091 Arenosum Solar — 151MW solar ☀️ project in Special Area No 2, AB (AESO). Proposed completion changed from May 25, 2027 to May 25, 2028

Interconnecting into OG&E's Ranch Road 345kV substation by tapping a 0.1 gen tie line into the existing Frontier II gen-tie line — 151MW battery 🔋 project in Kay County, OK (SPP). Proposed completion changed from November 29, 2025 to December 30, 2027

Interconnecting into OG&E's Ranch Road 345kV substation by tapping a 0.1 gen tie line into the existing Frontier II gen-tie line — 151MW battery 🔋 project in Kay County, OK (SPP). Proposed completion changed from November 29, 2025 to December 30, 2027

Bradford Solar — 100MW solar ☀️ project in Mckean County, PA (PJM). Proposed completion changed from December 14, 2026 to December 14, 2027

Tillman Solar Park — 100MW solar ☀️ project in Allen County, IN (PJM). Proposed completion changed from December 30, 2028 to December 30, 2029

RECLAIMED WIND — 90MW battery 🔋 project in Alameda, CA (CAISO). Proposed completion changed from April 3, 2025 to November 30, 2026

SAND HILL C — 80MW wind 💨 project in Alameda, CA (CAISO). Proposed completion changed from April 27, 2025 to April 27, 2027

SCAFELL STORAGE — 50MW battery 🔋 project in San Diego, CA (CAISO). Proposed completion changed from June 19, 2033 to June 29, 2029

PROSPECT ENERGY STORAGE — 49MW battery 🔋 project in Sacramento, CA (CAISO). Proposed completion changed from March 30, 2026 to May 31, 2028

Glen Falls Facility — 45MW gas 🔥 project in Harrison County, WV (PJM). Proposed completion changed from March 30, 2028 to January 30, 2029

Sunrise Wind II — 44MW offshore wind 🌊️ project in Suffolk County, NY (NYISO). Proposed completion changed from February 28, 2026 to June 30, 2027

Glen Falls Facility — 30MW gas 🔥 project in Harrison County, WV (PJM). Proposed completion changed from March 30, 2028 to January 30, 2029

Valley Solar — 20MW solar ☀️ project in Tioga County, NY (NYISO). Proposed completion changed from October 31, 2024 to December 31, 2026

HU-Pauls — 20MW solar ☀️ project in Huntingdon County, PA (PJM). Proposed completion changed from December 30, 2025 to March 30, 2027

P2757 Sturgeon 734S DER Battery — 19MW battery 🔋 project in Greenview No 16, AB (AESO). Proposed completion changed from June 30, 2026 to June 30, 2027

ALTAMONT MIDWAY LTD — 5MW wind 💨 project in Alameda, CA (CAISO). Proposed completion changed from April 27, 2025 to April 27, 2027

P2582 Woodcroft Reliability — project in Edmonton, AB (AESO). Proposed completion changed from March 30, 2028 to December 29, 2028

P3035 Aira Battery — battery 🔋 project in Cypress County, AB (AESO). Proposed completion changed from September 24, 2026 to November 30, 2027

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We saw the following updates to U.S. transmission grid interconnection projects. For access to our live dataset, contact our sales team here.

Round Valley – Peacock 230 kV line, Mead Switchyard 230 kV — 312MW battery + wind 🔋💨 project in Yavapai, AZ (WAPA Desert Southwest Region). Proposed completion changed from November 30, 2028 to March 31, 2028

Keota 345kV Substation — 299MW battery + solar 🔋☀️ project in Weld County, CO (Tri-State Generation and Transmission Association). Proposed completion changed from May 31, 2026 to March 31, 2030

Henry Lake -Story 230kV Line — 299MW battery + solar 🔋☀️ project in Weld County, CO (Tri-State Generation and Transmission Association). Proposed completion changed from December 30, 2025 to February 26, 2029

Huckleberry 230kV Substation — 299MW battery + solar 🔋☀️ project in Pueblo County, CO (Tri-State Generation and Transmission Association). Proposed completion changed from November 30, 2026 to March 30, 2028

Keota 345kV Substation — 299MW battery + solar 🔋☀️ project in Weld County, CO (Tri-State Generation and Transmission Association). IA date changed from May 31, 2026 to March 31, 2030

Henry Lake -Story 230kV Line — 299MW battery + solar 🔋☀️ project in Weld County, CO (Tri-State Generation and Transmission Association). IA date changed from December 30, 2025 to February 26, 2029

Huckleberry 230kV Substation — 299MW battery + solar 🔋☀️ project in Pueblo County, CO (Tri-State Generation and Transmission Association). IA date added March 30, 2028

South Fork 115kV Substation — 237MW battery + solar 🔋☀️ project in Kit Carson County, CO (Tri-State Generation and Transmission Association). Proposed completion changed from December 30, 2025 to June 28, 2027

South Fork 115kV Substation — 237MW battery + solar 🔋☀️ project in Kit Carson County, CO (Tri-State Generation and Transmission Association). IA date changed from December 30, 2025 to June 28, 2027

Maid 161kV substation — 100MW battery 🔋 project in Mayes County, OK (SPP). Proposed completion changed from May 31, 2025 to November 29, 2027

Hell Creek Substation — 90MW battery + solar 🔋☀️ project in Kit Carson County, CO (Tri-State Generation and Transmission Association). Proposed completion changed from May 31, 2025 to September 30, 2028

Hell Creek Substation — 90MW battery + solar 🔋☀️ project in Kit Carson County, CO (Tri-State Generation and Transmission Association). IA date changed from May 31, 2025 to September 30, 2028

Neset 230kV Substation — 74MW battery 🔋 project in Montrail County, ND (SPP). Proposed completion changed from December 30, 2026 to December 30, 2027

Dulles Solar and BESS — 50MW battery 🔋 project in Loudoun County, VA (PJM). Proposed completion changed from October 30, 2026 to October 30, 2027

Distribution Feeder — 1MW hydro 💧 project in Twin Falls, ID (Idaho Power Company). IA date added April 21, 2025

Custer/McNeil Substations, New Substation Near Hilltop/Stadium Substations — project in Pierce County, WA (Tacoma Public Utilities). Proposed completion changed from April 30, 2026 to December 8, 2026

TEXPO — 680MW gas 🔥 project in Wilbarger, TX (ERCOT). Proposed completion changed from October 30, 2026 to October 30, 2027

Hiru Solar — 603MW solar ☀️ project in Clay, TX (ERCOT). Proposed completion changed from May 28, 2026 to March 31, 2029

Hiru Storage — 503MW battery 🔋 project in Clay, TX (ERCOT). Proposed completion changed from March 30, 2028 to March 31, 2029

Millsing BESS — 501MW battery 🔋 project in Grimes, TX (ERCOT). Proposed completion changed from June 30, 2027 to October 14, 2028

Scorpius Solar — 500MW solar ☀️ project in Milam, TX (ERCOT). Proposed completion changed from October 22, 2026 to November 15, 2028

Hollow Branch Creek Solar — 460MW solar ☀️ project in Leon, TX (ERCOT). IA date added October 21, 2024

TRIFECTA Gas — 453MW gas 🔥 project in Midland, TX (ERCOT). Proposed completion changed from December 30, 2027 to October 30, 2029

Cold Creek Solar 2 — 445MW solar ☀️ project in Schleicher, TX (ERCOT). IA date added April 22, 2025

Western Flats Solar — 410MW solar ☀️ project in Crane, TX (ERCOT). Proposed completion changed from December 30, 2026 to October 31, 2028

Caliche Mound Solar — 408MW solar ☀️ project in Deaf Smith, TX (ERCOT). Proposed completion changed from August 27, 2025 to October 9, 2026

SOUTHERN SELECT ENERGY STORAGE — 404MW battery 🔋 project in Galveston, TX (ERCOT). Proposed completion changed from January 31, 2026 to January 14, 2027

Chickahominy Solar 1 and 2 — 320MW solar ☀️ project in Charles City County, VA (PJM). Proposed completion changed from December 30, 2024 to December 30, 2025

Elio BESS — 317MW battery 🔋 project in Brazoria, TX (ERCOT). Proposed completion changed from December 1, 2026 to August 4, 2027

Red Egret BESS — 310MW battery 🔋 project in Galveston, TX (ERCOT). Proposed completion changed from December 30, 2025 to August 30, 2026

Cuchillas BESS — 306MW battery 🔋 project in Webb, TX (ERCOT). Proposed completion changed from August 31, 2027 to December 26, 2026

Grapefruit Solar — 301MW solar ☀️ project in Hidalgo, TX (ERCOT). IA date added April 9, 2025

Acker BESS — 301MW battery 🔋 project in Castro, TX (ERCOT). IA date added April 20, 2025

NIGHTHAWK STORAGE — 300MW battery 🔋 project in San Diego, CA (CAISO). Proposed completion changed from March 30, 2025 to September 30, 2025

ORIENT - NORTHBORO 345.0kV — 263MW gas 🔥 project in Adair County, IA (MISO). Proposed completion changed from August 31, 2029 to August 31, 2027

Yellow Cat Wind — 262MW wind 💨 project in Navarro, TX (ERCOT). Proposed completion changed from September 29, 2026 to March 31, 2027

Miranda Solar Project — 261MW solar ☀️ project in Mcmullen, TX (ERCOT). Proposed completion changed from August 29, 2026 to December 5, 2027

Taormina Storage — 231MW battery 🔋 project in Bexar, TX (ERCOT). IA date added April 13, 2025

Dunkel BESS — 226MW battery 🔋 project in Lubbock, TX (ERCOT). Proposed completion changed from April 2, 2026 to November 1, 2027

Anila BESS — 209MW battery 🔋 project in Wilson, TX (ERCOT). Proposed completion changed from July 1, 2026 to June 29, 2028

ALWEST BESS — 208MW battery 🔋 project in Anderson, TX (ERCOT). Proposed completion changed from May 3, 2026 to April 18, 2028

Longfellow Solar II — 207MW solar ☀️ project in Pecos, TX (ERCOT). IA date added April 14, 2025

VERTUS ENERGY STORAGE — 207MW battery 🔋 project in Galveston, TX (ERCOT). IA date changed from March 26, 2024 to January 7, 2025

Hoyte Solar — 206MW solar ☀️ project in Milam, TX (ERCOT). Proposed completion changed from March 30, 2026 to December 14, 2026

Nockenut Springs Solar 3 — 203MW solar ☀️ project in Gonzales, TX (ERCOT). Proposed completion changed from May 4, 2027 to June 4, 2029

Nockenut Springs Solar 2 — 203MW solar ☀️ project in Guadalupe, TX (ERCOT). Proposed completion changed from May 4, 2027 to June 4, 2029

Nockenut Springs Solar 1 — 203MW solar ☀️ project in Guadalupe, TX (ERCOT). Proposed completion changed from May 4, 2027 to June 4, 2029

Loma Pinta Solar — 203MW solar ☀️ project in La Salle, TX (ERCOT). Proposed completion changed from May 30, 2026 to May 30, 2027

Staccato BESS — 202MW battery 🔋 project in Fayette, TX (ERCOT). Proposed completion changed from December 30, 2025 to December 30, 2026

Carolina Storage Odessa — 202MW battery 🔋 project in Howard, TX (ERCOT). Proposed completion changed from April 19, 2027 to July 31, 2028

Carolina Storage Wichita Falls — 202MW battery 🔋 project in Wichita, TX (ERCOT). Proposed completion changed from September 21, 2027 to July 31, 2028

Texas Cotton Solar — 201MW solar ☀️ project in Brazos, TX (ERCOT). Proposed completion changed from December 30, 2026 to December 30, 2028

Nockenut Springs Solar 4 — 201MW solar ☀️ project in Gonzales, TX (ERCOT). Proposed completion changed from May 4, 2027 to June 4, 2029

Echols Creek Solar — 201MW solar ☀️ project in Lamar, TX (ERCOT). Proposed completion changed from December 30, 2026 to October 12, 2027

Moonlight Sonata BESS — 201MW battery 🔋 project in Colorado, TX (ERCOT). Proposed completion changed from November 18, 2027 to June 30, 2028

Dios BESS — 201MW battery 🔋 project in Jackson, TX (ERCOT). IA date added April 2, 2025

Sengun BESS — 200MW battery 🔋 project in Nueces, TX (ERCOT). Proposed completion changed from January 5, 2026 to March 16, 2028

Kota Battery — 200MW battery 🔋 project in Carson, TX (ERCOT). Proposed completion changed from December 30, 2026 to October 30, 2028

Anila Solar — 200MW solar ☀️ project in Wilson, TX (ERCOT). Proposed completion changed from July 1, 2026 to June 29, 2028

Red Top Solar I — 200MW solar ☀️ project in Young, TX (ERCOT). Proposed completion changed from September 29, 2027 to April 12, 2028

Blackcat Storage — 200MW battery 🔋 project in Matagorda, TX (ERCOT). Proposed completion changed from April 5, 2026 to December 30, 2027

Iron Wolf Solar — 200MW solar ☀️ project in Van Zandt, TX (ERCOT). Proposed completion changed from December 30, 2026 to December 30, 2028

Accalia Point Solar — 190MW solar ☀️ project in Cameron, TX (ERCOT). Proposed completion changed from May 30, 2027 to November 30, 2028

Harryoung Solar — 190MW solar ☀️ project in Cameron, TX (ERCOT). Proposed completion changed from May 14, 2027 to May 14, 2028

HarryoungBESS — 190MW battery 🔋 project in Cameron, TX (ERCOT). Proposed completion changed from May 14, 2027 to May 14, 2028

Leighton Solar SLF — 183MW solar ☀️ project in Limestone, TX (ERCOT). Proposed completion changed from October 16, 2026 to April 29, 2027

Longfellow Solar I — 178MW solar ☀️ project in Pecos, TX (ERCOT). IA date added April 14, 2025

Sol Marina Energy Center — 175MW solar ☀️ project in Ellis, TX (ERCOT). IA date added April 24, 2025

Cold Creek Storage 2 — 174MW battery 🔋 project in Schleicher, TX (ERCOT). IA date added April 22, 2025

Flag City Storage SLF — 169MW battery 🔋 project in Jackson, TX (ERCOT). Proposed completion changed from December 30, 2026 to December 30, 2027

Flag City Solar — 167MW solar ☀️ project in Jackson, TX (ERCOT). Proposed completion changed from December 30, 2026 to December 30, 2027

Crowned Heron BESS 2 — 154MW battery 🔋 project in Fort Bend, TX (ERCOT). Proposed completion changed from July 30, 2025 to March 30, 2026

Quarter Ranch Solar — 154MW solar ☀️ project in Zapata, TX (ERCOT). Proposed completion changed from September 29, 2026 to October 14, 2028

Whiskey BESS — 153MW battery 🔋 project in Van Zandt, TX (ERCOT). Proposed completion changed from March 14, 2026 to January 29, 2027

Leon BESS — 153MW battery 🔋 project in Houston, TX (ERCOT). Proposed completion changed from February 15, 2028 to October 9, 2028

Zorro BESS — 153MW battery 🔋 project in Van Zandt, TX (ERCOT). Proposed completion changed from August 18, 2026 to April 30, 2027

El Patrimonio Solar — 152MW solar ☀️ project in Bexar, TX (ERCOT). Proposed completion changed from September 22, 2026 to April 28, 2027

Pink Solar — 151MW solar ☀️ project in Hunt, TX (ERCOT). IA date added August 29, 2022

Driet BESS — 150MW battery 🔋 project in Colorado, TX (ERCOT). Proposed completion changed from May 31, 2026 to October 14, 2027

Iron Wolf BESS — 150MW battery 🔋 project in Van Zandt, TX (ERCOT). Proposed completion changed from March 1, 2027 to December 30, 2028

Fluvanna Max Solar — 150MW solar ☀️ project in Scurry, TX (ERCOT). Proposed completion changed from September 27, 2028 to September 13, 2029

Riverstone Solar — 149MW solar ☀️ project in Buckingham County, VA (PJM). Proposed completion changed from August 29, 2026 to October 29, 2027

La Casa Wind — 148MW wind 💨 project in Stephens, TX (ERCOT). Proposed completion changed from June 29, 2025 to March 14, 2026

Rain Lily Solar 1 — 147MW solar ☀️ project in Hood, TX (ERCOT). Proposed completion changed from October 14, 2027 to October 14, 2028

Wensowitch Solar — 146MW solar ☀️ project in Navarro, TX (ERCOT). Proposed completion changed from September 22, 2027 to March 27, 2028

Brizo BESS — 140MW battery 🔋 project in Victoria, TX (ERCOT). IA date added March 26, 2025

Demeter Storage 2 — 138MW battery 🔋 project in Caldwell, TX (ERCOT). Proposed completion changed from December 30, 2026 to May 31, 2029

Giga Texas Data Center — 133MW battery 🔋 project in Travis, TX (ERCOT). IA date added April 29, 2025

Jumping Cactus Storage — 125MW battery 🔋 project in Duval, TX (ERCOT). Proposed completion changed from September 29, 2027 to October 14, 2028

Rock Island Generating (TEF -Due Diligence) — 121MW gas 🔥 project in Colorado, TX (ERCOT). IA date added March 16, 2025

Dove Run Solar — 120MW solar ☀️ project in Duval, TX (ERCOT). Proposed completion changed from July 30, 2026 to October 14, 2027

Sun Cactus Solar — 120MW solar ☀️ project in Duval, TX (ERCOT). Proposed completion changed from August 30, 2026 to October 14, 2027

Longfellow BESS II — 105MW battery 🔋 project in Pecos, TX (ERCOT). IA date added April 14, 2025

Rain Lily Storage 1 — 105MW battery 🔋 project in Hood, TX (ERCOT). Proposed completion changed from October 14, 2027 to October 14, 2028

Carolina Storage Young County — 104MW battery 🔋 project in Young, TX (ERCOT). Proposed completion changed from September 21, 2027 to July 31, 2028

Pioneer Path Energy Storage 1 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Pioneer Path Energy Storage 2 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Pioneer Path Energy Storage 3 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Pioneer Path Energy Storage 4 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Prairie Horizon Energy Storage 1 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Prairie Horizon Energy Storage 2 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Prairie Horizon Energy Storage 3 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Prairie Horizon Energy Storage 4 — 103MW battery 🔋 project in Robertson, TX (ERCOT). Proposed completion changed from May 31, 2027 to November 30, 2027

Roost Energy Storage — 102MW battery 🔋 project in Scurry, TX (ERCOT). Proposed completion changed from September 14, 2026 to September 12, 2027

Holstein 2 Solar — 101MW solar ☀️ project in Nolan, TX (ERCOT). Proposed completion changed from April 30, 2027 to April 2, 2028

Paradiso BESS — 100MW battery 🔋 project in Atascosa, TX (ERCOT). IA date added April 17, 2025

Echols Creek Storage — 100MW battery 🔋 project in Lamar, TX (ERCOT). Proposed completion changed from December 30, 2026 to October 12, 2027

Demeter Solar — 88MW solar ☀️ project in Caldwell, TX (ERCOT). Proposed completion changed from March 27, 2026 to May 31, 2029

Hinkell BESS — 78MW battery 🔋 project in La Salle, TX (ERCOT). Proposed completion changed from April 30, 2026 to November 14, 2027

92kV P line — 70MW battery 🔋 project in Imperial County, CA (Imperial Irrigation District). Proposed completion changed from May 31, 2025 to May 31, 2028

Demeter Storage — 65MW battery 🔋 project in Caldwell, TX (ERCOT). Proposed completion changed from March 27, 2026 to May 31, 2029

Centennial Solar — 61MW solar ☀️ project in Menard, TX (ERCOT). Proposed completion changed from April 28, 2028 to April 29, 2029

Sol Marina Energy Center BESS — 57MW battery 🔋 project in Ellis, TX (ERCOT). IA date added April 24, 2025

Longfellow BESS I — 54MW battery 🔋 project in Pecos, TX (ERCOT). IA date added April 14, 2025

Bergen Generating Station — 51MW gas 🔥 project in Bergen County, NJ (PJM). Proposed completion changed from May 30, 2026 to June 29, 2027

Voyager Storage — 50MW battery 🔋 project in Wharton, TX (ERCOT). Proposed completion changed from April 7, 2026 to April 7, 2028

Fluvanna Max BESS — 50MW battery 🔋 project in Scurry, TX (ERCOT). Proposed completion changed from September 27, 2028 to September 13, 2029

Redbud-Gaylord 34.5 kV — 30MW solar ☀️ project in Frederick County, VA (PJM). Proposed completion changed from March 30, 2025 to March 30, 2026

Shands Energy Center — 15MW battery 🔋 project in Sussex County, VA (PJM). Proposed completion changed from December 30, 2024 to December 30, 2025

Damon BESS 2 — 9MW battery 🔋 project in Brazoria, TX (ERCOT). Proposed completion changed from August 11, 2025 to August 20, 2026

Gears BESS — 9MW battery 🔋 project in Harris, TX (ERCOT). Proposed completion changed from February 14, 2025 to September 4, 2025

Roadrunner Crossing BESS SLF — battery 🔋 project in Eastland, TX (ERCOT). IA date added February 17, 2025