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  • AEP Weighs PJM and SPP Exit Over Interconnection Delays

    AEP Weighs PJM and SPP Exit Over Interconnection Delays

    American Electric Power is publicly weighing withdrawal from two of the country’s largest wholesale power markets — PJM Interconnection and the Southwest Power Pool — citing the slow pace at which new generation gets studied, approved and connected to the grid, according to a report published by Utility Dive on 6 May 2026.

    AEP is among the largest transmission owners in PJM and a long-standing SPP member through its Oklahoma, Arkansas, Louisiana and Texas operating companies. The available source material is headline-level: it indicates AEP is examining an exit, not that the company has filed a withdrawal notice with federal regulators or set a date.

    Executive Summary

    Regional transmission organizations, or RTOs, are the independent bodies that run the high-voltage grid and wholesale power markets across most of the eastern United States. Utilities join them voluntarily, and once inside, they hand over control of transmission planning and the queue that determines when new power plants can plug in. AEP saying out loud that it may leave two of them is unusual. Utilities have migrated between RTOs before, but a large incumbent threatening to step outside organized markets entirely is a governance event, not a routine filing.

    The stated grievance is generation interconnection: the multi-year engineering and cost-allocation process every new power plant must clear before it can energize. Queues across the country have lengthened as developers filed far more projects than the grid can absorb, and as demand forecasts — driven heavily by data centers and industrial electrification — moved faster than the studies designed to serve them. For a utility trying to build or contract generation to match load growth in Ohio, Indiana, Virginia, West Virginia and Oklahoma, the queue is the bottleneck between a signed customer and a served customer.

    What matters for buyers of digital infrastructure is not whether AEP ultimately leaves. It is that a utility of this size considers the market structure itself a liability worth reopening. Data centers are sited on ten- to twenty-year horizons; the assumption that the rules governing power supply are stable for that period is now a live question in a meaningful part of the eastern grid.

    Two Markets, One Complaint — and What That Implies

    The most analytically interesting feature of the report is that AEP names both PJM and SPP. These are very different institutions. PJM coordinates a largely restructured, competitive footprint across the Mid-Atlantic and parts of the Midwest, where merchant generators compete and a capacity market pays for future reliability. SPP spans mostly vertically integrated territory in the Plains and South, where utilities still own their generation and recover costs through state rate cases. If the same utility finds the interconnection process unworkable in both, the diagnosis pointing only at PJM’s design is incomplete.

    That cuts in two directions, and both deserve equal scrutiny. It strengthens the argument that queue processing is a systemic failure of the current model rather than one operator’s mismanagement — a fair reading. It also weakens the implicit premise that leaving would solve the problem, because a utility outside an RTO still runs an interconnection process under federal rules, still needs system impact and facilities studies, and still faces the same constrained supply of turbines, transformers, high-voltage breakers and skilled labor that is throttling projects industry-wide. Neither AEP nor the RTOs have, in the material available, shown how much of the delay is queue administration versus physical supply chain. That distinction is the whole argument, and it is unresolved.

    What Leaving an RTO Actually Requires

    Exit is not a decision a utility makes alone. Withdrawal from an RTO typically requires approval from the Federal Energy Regulatory Commission, compliance with notice provisions in the RTO’s governing agreements, and in practice the acquiescence of state regulators in every state where the utility operates — states that have their own views on reliability, rates and whether their consumers benefit from a larger market. FERC has historically been attentive to whether a departure strands costs on the members left behind, and obligations for transmission projects already approved under regional plans generally do not evaporate on the way out.

    Then there is the operational bill. An RTO provides centralized dispatch, reserve sharing across a wide area, and a resource adequacy framework. A departing utility must replicate those functions or buy them, either by running its own balancing authority or joining another market. It also inherits seams — the friction at the borders between neighboring grids, where power that used to flow on a single set of rules now needs contracts, scheduling and duplicated reserves. Seams cost real money and, historically, are the argument that built RTOs in the first place. Precedent from past migrations, such as the moves of several Midwestern utilities from MISO into PJM last decade, suggests a timeline measured in years, not quarters.

    None of that makes the threat empty. A large transmission owner signalling that the exit math is being run changes the bargaining table inside RTO stakeholder processes, where votes are weighted and reform packages are negotiated among generators, load-serving entities, states and consumer advocates. Observers are entitled to ask whether this is leverage, intent, or both — and to note that leverage is a legitimate governance tool, not a scandal. The honest answer is that the available reporting does not distinguish between them.

    The Data Center Angle Is Real but Frequently Misstated

    Two clarifications matter here. First, the process AEP is reportedly complaining about is generation interconnection — plugging power plants in — which is a separate queue from large load interconnection, the process a hyperscale campus goes through to plug demand in. Developers care about both, because a load request is only as good as the supply behind it, but they are governed by different rules and different disputes.

    Second, the geography deserves precision. Northern Virginia’s Data Center Alley sits in Dominion Energy’s service territory, not AEP’s, so an AEP withdrawal would not remove Loudoun County from PJM. What it would do is shrink the footprint across which PJM plans transmission, shares reserves and allocates costs — and a smaller pool changes the arithmetic for everyone still inside, including the utilities serving the Alley. AEP’s own data center exposure is concentrated elsewhere: central Ohio, which has attracted substantial hyperscale and semiconductor investment, plus growing interest across Appalachian Power’s Virginia and West Virginia footprint and Indiana Michigan Power’s territory.

    For site selection, the practical effect is a new diligence line item. A campus reaching commercial operation in 2030 or later, in AEP territory, may be energized under a market structure, capacity obligation and cost-allocation regime different from the one modelled at underwriting. That is not a reason to avoid the region; central Ohio’s fundamentals — land, fiber, water, workforce, existing anchor tenants — are unchanged. It is a reason to price structural risk explicitly rather than assume it away.

    Winners, Losers and the Claims That Remain Unproven

    If AEP stayed and secured faster queue treatment, the winners would be its own generation plans and the customers waiting on them, and the loser would be the principle that all developers queue on equal terms — a principle merchant generators and independent power producers defend precisely because it protects them from incumbent preference. If AEP left, it would gain control over the sequencing of its own build-out and lose the reserve-sharing and market-depth benefits of a wide area. Consumers could plausibly land on either side depending on whether seams costs exceed the value of faster capacity additions. Anyone claiming certainty about that outcome, in either direction, is ahead of the evidence.

    The RTOs have a defensible record to point to. Both operate under FERC Order 2023, which replaced serial, project-by-project studies with cluster analysis and first-ready, first-served rules, and PJM has stood up expedited pathways for shovel-ready projects. It is reasonable for PJM and SPP to argue that reforms adopted only recently have not had time to show results. It is equally reasonable for a utility facing near-term load commitments to say that a reform which pays off in 2029 does not help a customer energizing in 2027. Both claims can be true; neither is proven by assertion.

    The fair-minded conclusion is narrow. This is a credible signal of strain in RTO governance from a participant with standing to know, reported at a level of detail too thin to adjudicate. It should raise the priority of queue reform on every regulator’s docket. It should not, on this evidence, be read as a verdict that PJM or SPP have failed, nor as a commitment by AEP to go anywhere.

    Background

    American Electric Power is one of the largest electric utility holding companies in the United States, headquartered in Columbus, Ohio, operating regulated utilities across a footprint that stretches from Michigan and Ohio through Appalachia into Oklahoma, Arkansas, Louisiana and Texas. That geography is unusual: it straddles three separate wholesale market structures — PJM in the east, SPP in the west, and ERCOT in Texas — which gives the company direct comparative experience of how different market designs handle new generation.

    PJM and SPP both emerged from the federal push in the late 1990s and 2000s to separate grid operation from utility ownership and create competitive wholesale markets. The bargain was that utilities would cede control of transmission planning and dispatch in exchange for a larger, more efficient pool. That bargain has come under strain since 2023 as electricity demand began growing again after two decades of flat consumption, driven substantially by data centers, and as interconnection queues filled with more projects than could be studied or built. The result is a widening gap between how quickly load can be signed and how quickly supply can be connected — the gap at the centre of AEP’s reported complaint.

    Source: AEP eyes exit from PJM, SPP over slow generation interconnection — Utility Dive, 6 May 2026, reporting that American Electric Power is weighing withdrawal from two major wholesale markets over interconnection delays.

  • Gas Leads PJM’s Reopened Interconnection Queue at 106 GW

    Gas Leads PJM’s Reopened Interconnection Queue at 106 GW

    PJM Interconnection, the grid operator serving the largest electricity market in the United States, has reopened its interconnection queue — the formal waiting line new power plants must join before they can connect to the grid — and gas-fired generation leads the intake at 106 gigawatts (GW), according to an April 30, 2026 report by Utility Dive. The queue had been closed to new entrants for years while PJM worked through a massive backlog under reformed study rules.

    Executive Summary

    The reopening of PJM’s queue is one of the most consequential grid events of the decade for the data-center industry. PJM’s territory — spanning 13 states and the District of Columbia, including the Northern Virginia corridor that hosts the world’s densest concentration of data centers — has been the epicenter of the load-growth crunch. For years, developers of new generation could not even get in line, while demand forecasts climbed relentlessly on the back of AI and cloud expansion.

    That 106 GW of gas-fired capacity leads the new intake is the headline signal: developers are betting that dispatchable, fuel-based generation is what the market will pay for. For context, 106 GW of proposed gas alone approaches the scale of PJM’s entire historical peak load — a striking statement of intent, even acknowledging that interconnection requests are proposals, not power plants, and that historically only a fraction of queued projects reach commercial operation.

    The Queue Reopens Into a Seller’s Market

    An interconnection queue is the study pipeline through which a grid operator evaluates whether a proposed generator can connect safely and what network upgrades it must fund. PJM froze new entries while it transitioned from a first-come, first-served process — which had become clogged with speculative projects — to a clustered, first-ready, first-served model. The reopening is therefore a pressure release: years of pent-up development interest arriving all at once.

    The market these projects are entering is unusually favorable to generators. PJM’s recent capacity auctions have cleared at elevated prices, reflecting tightening reserve margins as older coal and gas plants retire faster than replacements arrive and as data-center load grows. High capacity prices are precisely the signal designed to attract new steel in the ground — and 106 GW of gas proposals suggests the signal is being heard.

    Why Gas Leads — Economics, Not Ideology

    Gas-fired turbines dominate this intake for practical reasons. They are dispatchable — able to run on demand rather than when the weather cooperates — which is what capacity markets and 24/7 data-center loads reward most. They site on relatively small footprints near existing gas pipelines and transmission. And developers can point to a revenue stack (capacity payments, energy sales, and potentially direct contracts with large loads) that pencils today.

    But the gas wave faces its own bottlenecks. Turbine manufacturers are reporting multi-year order backlogs industry-wide, EPC (engineering, procurement, and construction) labor is scarce, and gas pipeline expansion in parts of PJM’s eastern footprint has historically faced permitting resistance. Proposing 106 GW is easy; procuring turbines, pipe, and crews for even a fifth of it is the hard part. The queue position is now arguably the cheapest asset in the whole development chain.

    What This Means for Data-Center Developers

    For hyperscalers and colocation operators stuck in multi-year utility interconnection waits, a generation-heavy queue is cautiously good news: more supply eventually means faster load interconnection and less severe capacity-price escalation. It also strengthens the case for co-location deals, in which a data center sites directly alongside a new plant and contracts for its output — a structure regulators in PJM have been actively wrestling with.

    The timing mismatch remains the industry’s core problem. Data centers can be built in 18–24 months; a new combined-cycle gas plant typically takes four or more years from queue entry through studies, permitting, and construction. Even under PJM’s reformed process, the bulk of this 106 GW cannot plausibly serve load until late this decade. Buyers planning capacity for 2027–2028 should not count on this queue cycle to bail them out.

    The Decarbonization Tension Nobody Should Ignore

    A gas-led buildout sits uneasily beside the carbon-neutrality pledges of the very customers driving the demand. Most major cloud providers maintain public net-zero or carbon-free-energy targets, and a decade of gas additions in PJM would make those targets harder to reconcile with grid reality — unless paired with offsets, carbon capture, or an eventual nuclear and storage wave. The honest framing is that the market is prioritizing reliability and speed-to-power first and emissions second. Whether that ordering persists will depend on state policy in PJM’s footprint, federal rules, and how loudly corporate energy buyers push back through their procurement.

    Background

    PJM Interconnection grew out of a 1927 power pool among Pennsylvania and New Jersey utilities and today operates the largest wholesale electricity market in the United States. Its territory contains Northern Virginia’s “Data Center Alley,” which by itself consumes more data-center power than most countries. Over the past several years PJM became the poster child for the interconnection bottleneck: thousands of proposed projects — predominantly renewables in earlier cycles — languished in multi-year study backlogs, prompting a federally approved overhaul of its queue process and a temporary halt to new applications.

    The reopening lands amid record demand forecasts, plant retirements, and capacity prices that have drawn political scrutiny across PJM’s member states. The resource mix of this new intake — and how much of it survives to construction — will shape the region’s reliability, emissions trajectory, and data-center growth capacity into the 2030s.

    Source: At 106 GW, gas-fired generation leads PJM’s newly reopened interconnection queue — Utility Dive report, April 30, 2026, on the resource mix entering PJM’s reformed interconnection process.

  • PJM’s First Reformed Queue Cycle Draws 811 Projects and 220 GW

    PJM’s First Reformed Queue Cycle Draws 811 Projects and 220 GW

    PJM Interconnection, the grid operator for the largest wholesale electricity market in the United States, has closed the application window for the first cycle of its reformed interconnection queue with 811 project applications totaling roughly 220 gigawatts (GW) of proposed capacity, according to an April 30, 2026 report in POWER Magazine. The interconnection queue is the formal process through which new power plants, storage facilities, and other resources apply to connect to the high-voltage grid.

    The cycle is the first to run entirely under PJM’s overhauled “first-ready, first-served” cluster study rules, replacing the serial, first-come-first-served process that had produced multiyear backlogs.

    Executive Summary

    The headline numbers are striking on their own terms: 811 projects and about 220 GW of proposed capacity entered a single study cycle — a volume on the same order as the entire existing generating fleet serving PJM’s 13-state-plus-D.C. footprint. That developers are willing to post the deposits and demonstrate the site control the reformed process demands, at that scale, is a concrete market signal rather than a speculative one.

    The timing matters. PJM has spent recent years warning of tightening supply as older plants retire while demand — led by AI and data center load growth concentrated in places like Northern Virginia — climbs after decades of flat consumption. A deep pipeline of proposed generation is the necessary first step toward closing that gap.

    The essential caveat is that a queue application is not a power plant. Historically, only a fraction of projects that enter U.S. interconnection queues ever reach commercial operation, and the reformed process is designed to study projects faster, not to guarantee they get financed and built. The 220 GW figure measures developer appetite and process throughput — not committed steel in the ground.

    A 220-GW Referendum on Electricity Demand

    For most of the 2010s, U.S. electricity demand was essentially flat, and grid planning was an exercise in managing retirements and replacement. The 220 GW that flowed into PJM’s first reformed cycle reflects a different era: hyperscale data centers, AI training and inference clusters, electrified transport, and reshored manufacturing have turned load growth from a rounding error into the central planning problem in the nation’s largest power market.

    Because the reformed process requires real financial commitments and demonstrated site control up front, this cycle’s volume is a cleaner demand signal than the old queue ever provided. Under the prior serial process, speculative placeholder projects could sit in line for years at little cost, inflating queue totals. A 220-GW cycle under stricter entry rules suggests developers see durable, creditworthy demand — much of it from data center operators willing to sign long-term commitments — rather than a bubble of free options.

    What Queue Reform Fixed — and What It Cannot

    PJM’s old process studied projects one at a time in the order they arrived, so a single stalled or withdrawn project could force costly restudies of everyone behind it. The reformed approach, approved by federal regulators as part of a broader national shift toward cluster studies, batches projects into cycles, studies them together, and allocates shared network-upgrade costs across the group. Projects that are not ready — lacking land rights or deposits — are filtered out early instead of clogging the line.

    What reform cannot do is build anything. Study speed is only one bottleneck among several: transformer and switchgear lead times remain long, skilled-labor markets are tight, local permitting is contested, and network upgrade costs identified in cluster studies can still kill marginal projects. The queue’s completion rate — nationally, often cited at roughly one in five projects historically — is the number that ultimately matters, and this announcement tells us nothing about it yet.

    Winners, Losers, and the Shape of the Pipeline

    The reformed rules structurally favor well-capitalized developers who can post deposits, secure land early, and absorb study-phase risk — utilities, large independent power producers, and infrastructure-fund-backed platforms. Smaller and more speculative developers, who thrived under the low-cost old queue, face a higher bar. That consolidation cuts both ways: it should raise the fraction of queued projects that actually get built, but it also concentrates the development pipeline in fewer hands.

    For large power buyers — data center operators above all — a deep, better-qualified queue is medium-term good news, since it is the raw material for future supply. But the near-term picture is unchanged: projects entering study now are years from commercial operation, so tight capacity conditions and elevated prices in PJM are likely to persist until this pipeline starts delivering. The gap between when demand arrives and when supply can physically connect remains the defining tension in the market.

    Background

    PJM traces its roots to 1927, when utilities in Pennsylvania and New Jersey first pooled their generation, and it has grown into the largest wholesale power market in North America. In the early 2020s its interconnection queue became a symbol of national gridlock: thousands of projects languished in a serial study process while wait times stretched toward half a decade, prompting a federally approved overhaul that paused new entries while PJM worked through the backlog and transitioned to clustered, readiness-based study cycles.

    The reform arrives just as PJM’s supply-demand balance has tightened. Plant retirements, sharply rising data center load, and record-setting capacity market results have made the pace of new generation buildout the market’s defining question — which is why the volume of this first reformed cycle is being read as a bellwether well beyond PJM’s borders.

    Source: PJM’s First Reformed Queue Cycle Draws 811 Projects, 220 GW — POWER Magazine report on the close of the first study cycle under PJM’s reformed interconnection process, April 30, 2026.