What Are You Actually Comparing?

How PJM, MISO and ERCOT Are Approaching Large-Load Growth—and What Executives Should Understand Before Comparing Progress

Large-load growth is forcing three major power regions to confront extraordinary new demands on their systems.

That does not mean they are confronting the same problem in the same way.

Consider three mechanisms that can all appear in a discussion about regional progress.

PJM Interconnection’s proposed Reliability Backstop Procurement would procure capacity to address a resource-adequacy need.

The Midcontinent Independent System Operator’s Expedited Resource Addition Study provides an accelerated generator-interconnection study pathway for qualifying resource additions.

The Electric Reliability Council of Texas’s Batch Zero is a coordinated transmission study and allocation process for large loads.

All three matter.

But they are not three versions of the same solution. One is principally about procuring capacity. Another advances the study of generation that may help serve new demand. The third addresses how limited transmission capability is studied and allocated among a very large population of proposed projects.

That difference matters before anyone asks which region is moving faster—or whether one region has found the better answer.

It matters even more because these approaches are still evolving.

On June 18, the Federal Energy Regulatory Commission opened separate Federal Power Act Section 206 proceedings for each of the six regional grid operators under its jurisdiction, directing them to justify or reform tariff provisions governing large-load integration. FERC issued separate, tailored proceedings rather than one common regional model.

PJM and MISO are part of that process. Their approaches are also moving through regional stakeholder and regulatory proceedings in which individual mechanisms remain subject to review, modification and implementation.

ERCOT is different. It is proceeding through Texas institutions rather than the FERC Section 206 process.

So this is not a comparison of three finished systems.

It is a comparison of three evolving approaches—and of what progress inside each one actually represents.

PJM: What Problem Is the Region Trying to Address?

PJM becomes easier to understand once the individual problems are separated.

The proposed Reliability Backstop Procurement addresses resource adequacy. It would procure capacity where an identified adequacy need exists.

PJM’s proposed Interim Resource Adequacy Service and Large Load Registry address another issue: how unsupported new load should enter future capacity calculations and how that load could be reduced during a capacity emergency.

A separate initiative addresses the ride-through behavior of computational loads following certain grid disturbances.

Those issues are connected.

They are not interchangeable.

One asks whether enough dependable capacity will be available.

Another asks how new demand should be reflected when that capacity has not yet been secured.

Another asks what happens when the system is short.

And another asks how certain large loads should behave when a disturbance occurs.

That is the first useful PJM insight:

“Large-load solution” is too broad a description of what PJM is developing.

The mechanisms also produce different kinds of evidence.

A procurement requirement is not a capacity award.

An award would not itself be a constructed generating resource.

And a constructed resource would still require the transmission, fuel, testing and operating arrangements necessary to perform when needed.

Likewise, assigning a customer a particular treatment during a capacity emergency does not establish that the customer has been physically connected and can be served.

PJM’s proposed emergency architecture illustrates another important boundary. The regional design would rely on states, Transmission Owners, utilities and Electric Distributors to translate a regional requirement into customer-level action. The materials reviewed do not establish one uniform PJM-to-customer instrument governing customer selection, notification, metering, performance verification, remedies, default and compensation.

That list is consequential because those functions are not interchangeable. Allocating a regional requirement is different from establishing how an individual customer is identified, contacted, measured and held accountable for performance.

That does not mean those downstream arrangements cannot be established through state, utility or project-specific mechanisms.

It means the regional mechanism does not answer every question.

For an executive, PJM provides important insight into how a capacity-market region is approaching resource adequacy while very large new loads are entering the system.

It does not, standing alone, create one regional pathway that studies the customer, secures the supply, builds the infrastructure, connects the load and delivers power.

That is not necessarily a defect.

It is the boundary of what the mechanism is intended to address.

MISO: When the Approach Is a Portfolio, Not a Single Process

MISO exposes a different challenge.

Its approach is distributed across multiple pathways. Existing transmission-planning and generator-interconnection processes coexist with developing large-load study pathways, service alternatives, operating requirements and resource-adequacy work.

The result is better understood as a portfolio of mechanisms rather than one MISO large-load process.

That distinction becomes particularly important when speed enters the discussion.

MISO has described an objective of approval within 120 days using multiple pathways, including completion of studies and generator-interconnection agreements.

That can easily be heard as a 120-day path to power.

The evidence supports something narrower.

The 120-day objective is pathway-dependent. Study or agreement completion is not construction, energization, commercial operation or proof that sufficient supply will be available.

The Expedited Resource Addition Study illustrates the distinction.

It can accelerate interconnection studies for qualifying generation additions. That may move an important supply-side dependency forward.

But the study does not procure the generation. It does not construct it. It does not fuel it. And it does not establish that the resource will be operating when the associated demand arrives.

MISO is also developing other pathways that address different parts of the problem.

Firm Service Step-Up is intended to allow a large-load customer to receive a reduced amount of firm transmission service before all infrastructure needed for its full requested demand is complete.

By September, MISO was referring to its developing interim non-firm concept as Flexible Large-Load Interim Transmission Service, or FLITS. The concept would allow qualifying large loads to use interim non-firm transmission service while required network upgrades are being completed. MISO separately introduced a proposed Contract Demand service with potentially longer-term implications.

The distinction was still being worked through.

Stakeholder feedback raised questions about how those service options should interact with resource adequacy, cost responsibility, curtailment priority, metering, operational controls and existing firm service. The MISO Transmission Owners supported continued development of interim FLITS for the November show-cause response while saying the proposed permanent Contract Demand product raised broader unresolved questions and should not move forward on the same timetable. Other stakeholders likewise sought clearer treatment of the different service paths and their operational and commercial consequences.

That matters because an executive may hear “MISO is developing flexible service” and assume it describes one settled product.

It does not.

The mechanisms address different questions, and the stakeholder process shows that important parts of their interaction remain under development.

The developing service concepts also have to interact with forecasting, resource adequacy, reserves, telemetry, curtailment, commercial treatment and existing transmission rules. The materials reviewed through September 18 leave those cross-process relationships unresolved.

The breadth matters. A service design can look workable in isolation and still leave questions about how the same load is forecast, represented for capacity purposes, observed operationally, curtailed when required and treated commercially.

For an executive, the MISO insight is therefore not simply that multiple solutions are under development.

It is that progress has to remain attached to the pathway that produced it.

A faster study can be meaningful.

A staged firm-service pathway can be meaningful.

An interim non-firm service option can be meaningful.

But progress inside one pathway should not quietly inherit the meaning of another.

ERCOT: When the Queue Becomes Part of the Problem

ERCOT confronts another version of the challenge.

The official mid-2026 inventory reviewed for this analysis identified more than 438,000 MW of proposed large-load demand, nearly 90 percent associated with data centers.

That number immediately communicates scale.

It does not communicate probability.

The inventory is not a forecast that 438,000 MW will ultimately connect and operate.

At that scale, the queue itself becomes part of the problem.

The system cannot treat every proposed project as though it represents an equally mature claim on future transmission capability. It also has to determine which projects have progressed far enough to warrant scarce planning attention and transmission capacity.

Batch Zero reflects that problem.

It places eligible large loads into a coordinated study and transmission-allocation process followed by additional commitment and refinement stages. Projects remain subject to interconnection agreements, protection requirements, construction and operating obligations.

Batch Zero does not procure generation or capacity.

ERCOT’s approach also makes project maturity unusually visible. The reviewed mechanism considers governmental approvals, financial responsibility, security for system upgrades, funding of direct interconnection facilities, property interests and post-study commitments.

The accumulation matters because project maturity is not demonstrated by any one of those elements. A project can be financially credible and still lack an approval. It can control a site and still lack required infrastructure. It can advance through a study and still face commitments that determine whether it proceeds.

Among the mechanisms reviewed, Batch Zero therefore provides the most explicit unified regional project-maturity screen.

But design specificity is not demonstrated performance.

The evidence through September 18 does not establish that the screen will eliminate speculative requests, improve project-conversion rates, reduce costs, accelerate delivery or improve reliability. Those conclusions require evidence from what happens next: commitments, withdrawals, construction, energization and sustained operation.

Batch Zero also sits inside a broader Texas framework established through Senate Bill 6, PUCT implementation and ERCOT operating and planning processes. That framework addresses not only transmission allocation but also project verification, financial commitment, curtailment capability and other requirements affecting how large loads advance.

Texas had already added another layer as of September 18.

On August 3, Governor Greg Abbott directed the Public Utility Commission of Texas and ERCOT to conduct a comprehensive verification and audit of data centers advancing through ERCOT’s interconnection process, with completion of that audit required before those projects move forward.

Then came an important subsequent development.

On September 21, Abbott directed the Texas Commission on Environmental Quality to halt permits sought by data centers until ERCOT completes its audit. The directive also stated that state agencies should not proceed with related regulatory approvals until the required information is obtained.

That later action does not change what Batch Zero was designed to do.

It changes the current environment in which projects are attempting to move through it.

For an executive, the ERCOT insight is therefore broader than transmission allocation.

When the queue becomes extraordinarily large, project maturity, verification, financial commitment and the ability to advance through multiple grid and state processes become part of the pathway toward service.

Filtering demand, however, is still not the same thing as supplying it.

Same Unit. Different Evidence.

Once the regional mechanisms are separated by function, another comparison problem becomes visible.

Every number may be expressed in megawatts.

That does not mean every megawatt number represents the same thing.

Across the evidence reviewed, megawatts appear at different stages: requests, studies, contracts, procurement processes, prospective transmission allocations, approvals, construction, energization, developed capacity and actual operation.

That list should not be collapsed into a generic category such as “project progress.” Each stage represents different evidence.

ERCOT’s queue tells us something important about the extraordinary scale of proposed demand.

It does not tell us how much of that demand will eventually operate.

A PJM procurement requirement can tell us something important about a capacity need.

It does not establish that the necessary resources have already been selected, constructed and placed into dependable operation.

A MISO study or executed agreement can establish that a project has crossed an important procedural threshold.

It does not establish commercial service.

All three numbers can be correct.

The comparison can still be wrong.

The problem arises when the common unit—MW—causes the reader to lose the lifecycle stage represented by the number.

For an executive, that can distort far more than a chart. It can change perceptions of market opportunity, infrastructure requirements, capital exposure, project timing and the credibility of projected demand.

What the Three Regions Reveal Together

Placed side by side, PJM, MISO and ERCOT reveal something more useful than which region appears to have the most developed large-load program.

They expose different dimensions of the problem.

PJM makes the resource-adequacy problem particularly visible: how sufficient dependable capacity is secured and how unsupported demand is treated when it is not.

MISO makes the coordination problem particularly visible: how planning, generator interconnection, service firmness, operating requirements and resource adequacy can proceed through different pathways but ultimately have to work together.

ERCOT makes the maturity and allocation problem particularly visible: what happens when proposed demand becomes so large that the system must distinguish among projects competing for limited transmission capability.

Those are not simply competing answers to one narrowly defined question.

They are different parts of a much larger infrastructure and reliability challenge.

That is why asking which region is “ahead” can produce the wrong discussion.

Even procedural maturity is not a performance measure.

In the materials reviewed through September 18, PJM’s principal backstop-procurement and interim resource-adequacy mechanisms remained pending. MISO combined existing pathways with proposed and developing ones. ERCOT had moved much of Batch Zero into approval and partial implementation while retaining specifically deferred provisions.

Those differences are real.

They do not establish that ERCOT will deliver power faster, that PJM is behind, that MISO is slower, or that one architecture will ultimately produce lower costs, greater reliability or better project conversion.

The more useful question is what kind of progress each mechanism represents.

From Regional Mechanism to Executive Decision

For me, the practical discipline begins with the objective.

What problem are you trying to solve?

If the objective is dependable service to a new 1,000-MW facility by a specified date, a completed study may answer one part of that problem.

A capacity procurement may answer another.

A transmission allocation, financial commitment, operating condition or flexible-service arrangement may answer others.

Each can be important.

None should be allowed to prove more than it actually proves.

A useful sequence is:

Objective → Mechanism → Evidence → Remaining Gap → Next Proof Point

Start with the objective.

Determine which part of that objective the mechanism addresses.

Identify what the available evidence establishes.

Then determine what remains unresolved and what evidence would justify the next conclusion.

This is where operating experience matters.

Once an organization has selected or approved a solution, it can become easy to treat the existence of that solution as evidence that the original problem has been solved.

Those are not the same thing.

A better discipline is to ask:

What did this solve for the objective I actually care about, and what still has to be demonstrated?

Financial commitment provides a useful example.

Collateral, security, minimum-demand provisions and other financial instruments can test commitment and allocate specified financial consequences.

They cannot create generation, transmission infrastructure, fuel supply, equipment, permits, construction progress or operating performance.

Those are distinct dependencies, which is why reducing the thought to “financial commitment does not equal readiness” would lose something important. The question is which part of readiness the financial instrument establishes—and which parts remain outside it.

That does not make financial security unimportant.

It tells you what problem it addresses.

The same discipline applies to a regional mechanism.

Do not dismiss progress because it does not solve everything.

But do not allow progress on one part of the problem to become proof of something the evidence has not yet established.

Identify the next proof point.

What Would Change the Answer?

The next useful evidence is not simply another announcement.

It is evidence that moves the issue from one stage to another.

PJM

The PJM decision calendar reviewed through September 18 identified a planned September 30 opening of the Reliability Backstop Procurement, followed by a bid and target-adjustment period, subject to regulatory authority.

Why does that matter?

Because the evidence would begin moving from proposed procurement design toward actual solicitation behavior.

Offers, target adjustments and eventually selections would allow executives to ask questions that cannot yet be answered from the tariff design alone: What supply actually shows up? On what terms? How much of the identified need moves toward executable commitment?

That still would not prove construction or dependable operation.

But it would be the next proof point.

MISO

For MISO, the next important evidence is different.

Firm Service Step-Up and FLITS remained under development in the materials reviewed through September 18, and the calendar reviewed through that date pointed toward the November Section 206 response as a significant near-term milestone.

The September stakeholder record reinforces why that milestone matters. The question is not merely whether MISO makes another filing. It is whether the process more clearly defines the relationship among study pathways, interim and firm service, resource adequacy, forecasting, operations, cost responsibility and customer obligations.

That would allow executives to move from knowing that MISO has a portfolio of developing mechanisms toward understanding more precisely how those mechanisms are intended to work together.

ERCOT

For ERCOT, the decisive evidence will come from conversion of the queue.

The schedule reflected in the materials reviewed through September 18 contemplated verification and classification work, followed by later capability allocation, project commitments and a final Batch Zero transmission plan.

But Texas has changed the current context through the subsequent audit and permitting actions.

That means the exact future timetable remains uncertain and should not be treated as fixed.

The evidence to watch remains clear even if timing moves:

Which projects survive verification?

Which withdraw?

Which demonstrate the required commitments?

How much transmission capability is ultimately allocated?

And how many projects move from allocation into construction, energization and sustained operation?

Those results would begin testing whether the maturity-screening architecture is actually converting an enormous queue into a more credible population of projects.

That is evidence we do not yet have.

Taken together, those milestones do more than mark the calendar. Each one changes what an executive can responsibly conclude.

And you do not need projects in all three regions for the comparison to matter.

If your exposure is principally to PJM, ERCOT’s emphasis on project maturity may cause you to ask harder questions about the commitment behind projected demand.

If your exposure is principally to ERCOT, PJM’s resource-adequacy work may sharpen the distinction between obtaining transmission access and ensuring dependable supply.

If your exposure is principally to MISO, looking across the regions may make more visible how many separate pathways must converge before procedural progress becomes actual service.

And if your portfolio spans all three, understanding those distinctions becomes even more consequential.

Whether your decisions touch one region or all three, you should know the answer to one basic question before relying on a claim of progress:

What are you actually comparing?

Because PJM, MISO and ERCOT are not simply approaching the challenge differently.

In important respects, they are addressing different parts of it.

Knowing which part has advanced is what tells you what still has to happen next.

Source Note

The core regional analysis reflects primary materials reviewed through September 18, 2026. Material subsequent developments specifically identified in the article are presented as later updates and were not used to revise the underlying September 18 research conclusions.

Selected Primary Sources

• Federal Energy Regulatory Commission — FERC Launches Aggressive Targeted Action to Speed Large Load Integration and associated Section 206 show-cause orders — June 18, 2026.

• PJM Interconnection — Reliability Backstop Procurement filing, fact sheet, participation materials, and Interim Resource Adequacy Service / Large Load Registry materials — July–September 2026.

• Midcontinent Independent System Operator — Large-load planning and stakeholder materials addressing the Expedited Resource Addition Study, Firm Service Step-Up, Flexible Large-Load Interim Transmission Service, Contract Demand, and related large-load study and operating requirements — reviewed through September 18, 2026.

• Electric Reliability Council of Texas — PGRR145 / NPRR1325, Large Load Integration, and Batch Zero implementation and process materials — 2026.

• Texas Legislature / Public Utility Commission of Texas — Senate Bill 6 and related large-load implementation materials — 2025–2026.

• Office of the Texas Governor — Governor Abbott Directs Comprehensive Data Center Audit — August 3, 2026; and Governor Abbott Directs TCEQ To Halt Data Center Permits — September 21, 2026.

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