Summary
- Exelon classifies approximately 11GW as high-probability load: about 9GW at ComEd and about 2GW across its Mid-Atlantic utilities.
- Projects in that category are in advanced design or supported by FERC-approved Transmission Security Agreements; about 40% has TSAs backed by roughly $1 billion of collateral.
- A separate future pipeline of approximately 25GW—about 17GW at ComEd and 8GW in the Mid-Atlantic—remains in current or future cluster studies.
- Neither category is operating capacity: Exelon does not disclose customer identities, individual sites, final connection dates, power prices or a complete network-upgrade bill.
- The company’s $41.7 billion 2026–2029 capital plan and $12 billion to $17 billion of additional transmission opportunity must remain separate from requested or screened load.
- The next useful evidence will be a bridge from queue stage to permits, funded upgrades, energisation, metered demand and revenue.
The scarce resource is not an application; it is a believable path to power
A data-centre developer can request more electricity years before it has a completed building, a final computing plan or a firm date for needing the power. Utilities must nevertheless study how those requests affect substations, transmission lines and generation adequacy. A queue measured only in gigawatts can therefore mix serious projects with options, duplicates and demand that will disappear when costs become clear.
Exelon’s second-quarter presentation offers a more useful hierarchy. Approximately 11GW sits in a high-probability category, divided between roughly 9GW at ComEd and 2GW in the Mid-Atlantic. The company says those projects are either in advanced design phases or supported by FERC-approved Transmission Security Agreements. About 40% has such agreements backed by approximately $1 billion of collateral.
That is meaningful evidence because it makes delay or withdrawal expensive for the customer. A request expresses interest; collateral commits capital to the consequences of network planning. A security agreement can protect a transmission owner from some costs if a project fails to proceed. It can also give engineers and regulators a firmer basis for deciding which upgrades deserve scarce attention.
The evidence is still intermediate. Collateral does not supply electricity, construct a line or prove that a customer will consume its full requested load. It improves the quality of the queue by placing a cost behind part of it. The distinction matters precisely because 11GW is extraordinarily large relative to ordinary utility growth.
Forty per cent is stronger evidence—and a warning about the other sixty
Exelon’s 40% disclosure implies that only part of the high-probability group has the cited TSA-and-collateral protection. The rest can still qualify because it is in advanced design, but the presentation does not provide a project-level ladder showing which contractual, engineering and permitting milestones each request has passed.
This is why the $1 billion should not be described as project finance, revenue or payment for electricity. It is financial security attached to transmission arrangements. Its analytical value lies in loss allocation: a customer that walks away may bear costs that would otherwise fall on the utility or its wider customer base.
The aggregate also conceals concentration. Ten customers providing equal collateral would create a different risk profile from one customer supporting most of the amount. A portfolio of campuses with staggered service dates would be easier to absorb than several projects seeking simultaneous energisation at one constrained node. Exelon does not identify customers, sites, security by project or expected connection dates.
Readers should therefore treat “high probability” as a screening label rather than a forecast with a known error rate. The company could improve it by reporting movements each quarter: additions, withdrawals, projects receiving TSAs, projects entering construction and projects reaching commercial service. Without that bridge, the category is more credible than a raw inquiry list but cannot be calibrated against delivery.
The 25GW pipeline belongs on a different line
Exelon separately shows approximately 25GW of future pipeline, consisting of about 17GW at ComEd and 8GW in the Mid-Atlantic. These projects are in current or future cluster studies that the company expects to conclude during 2026 and 2027.
Cluster studies examine groups of requests against a common network rather than pretending that each can be assessed in isolation. The method can reveal whether several projects depend on the same transformer, substation or transmission corridor. It can also allocate upgrade responsibilities more coherently when one project’s connection changes the costs faced by another.
The study stage is designed to discover constraints, not to certify that all proposed demand can be served. Results can raise a project’s cost, alter its schedule or require new generation and transmission. Customers may reduce their requests or leave after seeing the price. Regulatory approvals and local permits can introduce further delays.
Adding 25GW to 11GW and calling the resulting 36GW contracted would erase the purpose of Exelon’s segmentation. The first group carries stronger evidence; the second is undergoing the process that determines what evidence and infrastructure will be required. Even within the 11GW, the available protection is not uniform.
The more responsible use of the numbers is as a funnel. Twenty-five gigawatts supplies the wider opportunity set. Eleven gigawatts is Exelon’s screened subset. Roughly 40% of that subset carries the disclosed TSA-and-collateral feature. The eventual connected load will be determined by attrition, construction and customer operations, not arithmetic.
Grid security cannot solve the generation question
Transmission Security Agreements address network investment. They do not by themselves answer where the energy and capacity needed by new campuses will come from. A data centre requires continuous supply, while a request of several hundred megawatts can change a local system’s peak, reserve and reliability needs.
Exelon’s utilities operate transmission and distribution networks; regional market and planning institutions coordinate the wider system. Large Load Adjustments submitted in 2025 have been approved by PJM, according to the presentation. Approval is a planning step. It does not specify a data centre’s final energy mix, generation contract or emissions profile, and it should not be confused with physical delivery.
New demand can be served through a combination of existing generation, new plants, imports, storage, demand flexibility and network expansion. Each route has a different construction schedule and risk. A substation completed before adequate upstream supply exists cannot deliver the requested load reliably. New generation without the required transmission cannot reach the site.
This interdependence is why connection dates matter more than an aggregate queue. A yearly schedule showing secured generation, transmission milestones and expected energisation would expose whether the components are aligned. Exelon does not provide that site-level schedule in the filed materials.
The capital plan does not expand automatically with every request
Exelon affirmed a $41.7 billion capital plan for 2026 through 2029 and expected rate-base growth of 7.9%. It also identified $12 billion to $17 billion of transmission opportunity outside the plan. The company says more than $1 billion of transmission investment is associated with committed high-density load projects.
These figures occupy different accounting and decision stages. The four-year plan represents intended company investment under current assumptions. The additional transmission opportunity is not yet embedded in that plan. Customer load is a demand measure, not capital expenditure. Collateral is security, not Exelon’s investment. Combining any of them would create a total with no coherent meaning.
The distinction also determines who bears risk. A security agreement can make a customer responsible for particular network costs if it withdraws. Approved utility investment can enter rate base and be recovered under regulatory rules. Opportunity outside the plan may never be sanctioned or may arrive on a different schedule. Customers, shareholders and ordinary electricity users can therefore face different exposures even when the same campus triggers the discussion.
Exelon says committed high-density projects are associated with more than $1 billion of transmission investment, but it does not offer a complete customer-by-customer cost bridge. To evaluate protection for other users, readers need project costs, security coverage, take-or-pay provisions, withdrawal treatment and the share ultimately recovered through general rates.
A large load can protect households only if the protections survive stress
Utilities often argue that a very large new customer can spread fixed network costs across more electricity sales. That can be true when the customer connects on time, operates for years and pays charges that reflect the infrastructure built for it. The inverse is also true: a cancelled campus can leave equipment that ordinary customers did not need.
Collateral reduces that stranded-asset risk, but the relevant denominator is not the headline amount. It is the cost covered under enforceable terms compared with all upgrades undertaken for each project. The duration of protection matters as well. A customer can reach service and later consume less than forecast, seek contract changes or suffer financial distress.
Policy should therefore follow the entire life of the load. Pre-construction security protects the study and build phase. Minimum-bill or take-or-pay provisions can protect utilisation revenue after connection. Credit requirements protect against default. Exit charges can address an early departure. None of those mechanisms is fully visible in Exelon’s aggregate presentation.
The absence of detail does not prove weak protection. It means the public evidence supports a narrower conclusion: part of Exelon’s screened queue has formal transmission security and substantial collateral. Claims about household benefit, cost neutrality or the ultimate rate effect require regulatory documents and realised billing data.
The next dashboard should measure conversion, not aspiration
Exelon has improved the debate by refusing to present every inquiry as equivalent. The next step is to show whether the stronger categories actually predict delivery. A quarterly conversion table could begin with total requests, then identify cluster-study completion, advanced design, TSA execution, collateral, construction start, energisation and metered load.
Megawatts should be accompanied by customer counts and concentration bands. A large aggregate supported by one counterparty has a different resilience from a diverse portfolio. Expected service years would reveal whether the 11GW arrives gradually or creates a single construction and generation bottleneck.
Financial reporting should connect each stage to network spending. Readers need committed customer-funded work, utility capital already in the approved plan, investment still outside it, and the security available if projects withdraw. Once campuses connect, the record should show peak demand, average use, minimum payments and realised revenue rather than nameplate requests.
The final test is operational. An energised connection may draw far below its reserved capacity, and a busy data centre can still impose costs not recovered by its tariff. Delivery, consumption and cost allocation are separate outcomes.
Exelon’s 11GW category is therefore valuable as a better numerator, not as a completed infrastructure forecast. The $1 billion of collateral gives part of that numerator financial weight. The 25GW pipeline supplies context about possible demand still being tested. Between those stages and power at the meter lies the work that matters: studies, generation, permits, funded construction and customers that remain after the price of connection is known.