Grid 2026-07-29

ERCOT 4CP Is Being Rewritten: What If Your Best Flexibility Strategy Stops Paying Off?

Texas is reconsidering ERCOT's 4CP transmission-cost model, with a published proposal pointing to 12 monthly peaks and minimum billing demand. Here's what the three possible outcomes could mean for large-load costs, operations, and flexibility strategy.

ERCOT 4CP Is Being Rewritten: What If Your Best Flexibility Strategy Stops Paying Off?

What the next transmission-cost model could mean for large-load costs, operations, and flexibility

TL;DR

Texas is reconsidering ERCOT's current 4CP transmission-cost model. The PUCT must amend its rules by December 31, 2026.

The published proposal points to 12 monthly 30-minute peaks and minimum billing demand for qualifying large loads, but 12CP is not the only possible final outcome.

The final model could broadly take three forms: 12CP largely as proposed; 12CP with a different minimum-demand structure; or a broader redesign that changes which peaks matter, potentially including peak net load.

For customers, the key question is shifting from "How do we avoid four peaks?" to "Which costs can we still influence, and when is flexibility worth using?"

Where the reform stands today

Under ERCOT's current 4CP methodology, transmission-cost allocation is based on four 15-minute system peaks: one each in June, July, August, and September.

That structure has created a familiar operating strategy for many large loads: forecast likely summer peaks, reduce demand during candidate intervals, and manage future transmission exposure. ERCOT explains the current methodology in its 4CP Calculation Overview.

Texas is now reconsidering that model.

The PUCT published a proposal in the July 24, 2026 Texas Register that would replace four summer peaks with one 30-minute coincident peak in every month. It would also introduce minimum-billing-demand requirements and new tariff provisions for qualifying large loads.

But the proposal is not the final rule.

Stakeholder comments, revisions, and final commission decisions could still change the design. Under Senate Bill 6, the PUCT must amend its rules by December 31, 2026. That is a rulemaking deadline, not necessarily the date when customers begin being billed under a new methodology.

For individual customers, the impact will not be determined by the label "12CP" alone. The ultimate result will also depend on utility tariffs, retail contracts, customer classifications, contracted capacity, and implementation timing.

Why Texas is reconsidering 4CP

The review is trying to address two related issues.

First, policymakers are questioning whether customers that rely on substantial transmission capacity throughout the year should be able to avoid a large share of those costs through a few well-timed summer curtailments.

Texas Senate Bill 6 directed the PUCT to reconsider 4CP and assess whether transmission-investment costs are being assigned appropriately. It also asked the commission to examine seasonal peaks, different measurement periods, peak-energy approaches, and the portion of transmission costs that should be nonbypassable.

Second, the periods that drive 4CP do not always match the periods when ERCOT most needs demand reduction.

An April 2026 ERCOT and Charles River Associates assessment found that 4CP creates significant summer load response, but that response does not consistently align with ERCOT's highest net-load periods, including evening and non-summer conditions.

The policy debate is therefore not simply about replacing four peaks with twelve. It is about finding a better balance between:

Three ways the final outcome could take shape

These are editorial scenarios, not three equally active official proposals. The published 12CP proposal is the current regulatory starting point, but the final rule could still evolve.

#### Scenario 1: 12CP is adopted largely as proposed

Under this scenario, ERCOT would use twelve monthly 30-minute peaks, and covered large-load customers would be subject to a minimum billing demand.

The published proposal currently sets that minimum at the greatest of:

The proposed minimum would apply for the first 20 years after billing begins. Billing could also begin when transmission capacity is made available, even if the customer has not yet fully energised or used that capacity.

What it could mean commercially

This could create a clearer floor beneath a customer's transmission exposure.

Customers may still manage part of their costs through monthly peak response, but successful curtailment may no longer reduce billing demand below the applicable minimum.

That does not automatically mean every customer will pay more. The outcome would depend on contracted capacity, actual site demand, monthly-peak performance, tariff structure, and the customer's current approach to managing 4CP.

What it could mean operationally

Peak management could become a year-round activity.

Because the actual monthly peak is confirmed after the fact, customers may evaluate or respond to several candidate intervals before knowing which one ultimately counted. The practical number of operating decisions could therefore be greater than twelve.

The 30-minute measurement could also place more emphasis on sustaining a response than the current 15-minute structure.

What it could mean for flexibility

The question would move beyond simply catching the peak.

Customers would need to understand how much cost a response can still influence—and whether that value exceeds the operational cost of responding.

#### Scenario 2: 12CP remains, but the cost floor changes

The PUCT has specifically requested feedback on alternatives to the proposed minimum billing demand.

Those alternatives could include a minimum that:

The commission is also asking whether qualifying large computational loads, including data centers and cryptocurrency mining facilities, should receive separate rate treatment. That is an open question for stakeholder comment, not a final policy decision.

What it could mean commercially

The minimum-demand formula could matter as much as the move to twelve monthly peaks.

A minimum tied closely to contracted capacity would create a different cost profile from one that gradually adjusts toward demonstrated operating demand.

Two customers with similar monthly peak performance could therefore experience different outcomes because of their contracted capacity, ramp schedule, historical demand, tariff, or customer classification.

What it could mean operationally

Customers may need to model several versions of a 12CP structure rather than treating the current proposal as settled.

A site still ramping toward its contracted load could be affected differently from a mature facility operating close to full capacity.

What it could mean for flexibility

The final minimum will help determine how much transmission exposure remains genuinely manageable.

A higher or more persistent minimum could reduce the value of incremental peak curtailment. A declining or weighted minimum could preserve more of the incentive to manage demand.

#### Scenario 3: The methodology moves beyond peak demand

The final rule could evolve beyond simply changing how many peaks are counted. A more substantial redesign could also change which type of peak matters.

Today's 4CP methodology, and the current 12CP proposal, focus on gross system demand: when customers across ERCOT are using the most electricity.

A future approach could place greater weight on peak net load: the amount of demand remaining after available wind and solar generation are taken into account.

That distinction matters because the highest-demand interval is not always the tightest period for the grid. A hot afternoon may produce the highest total demand while solar generation remains strong, while a more challenging period could occur later as solar output falls and demand remains elevated.

Peak net load is not part of the current published 12CP proposal. However, it is a relevant broader scenario because ERCOT has observed that 4CP-driven response does not consistently align with its highest net-load periods.

SB6 also gives the PUCT scope to consider alternatives such as seasonal peaks, different interval lengths, peak-energy approaches, and nonbypassable cost components.

What it could mean commercially

A net-load-based methodology could shift the intervals that matter most for transmission-cost management.

Customers that have built strategies around hot summer afternoons might instead need to focus on evening ramps, winter conditions, or periods when renewable output is lower relative to demand.

That could change the expected value of curtailment, batteries, on-site generation, and workload shifting—even if the customer's total flexibility remains unchanged.

What it could mean operationally

Forecasting would need to consider more than total electricity demand.

Customers might also need to account for renewable generation, the timing of wind and solar declines, seasonal load patterns, the duration of tighter conditions, and whether flexibility remains available later in the day.

For data centers and miners, this could change when workloads are moved, equipment is curtailed, or stored energy is deployed.

What it could mean for flexibility

The focus could shift from responding when the system is using the most electricity to responding when the grid has the greatest remaining demand to serve.

That could better align customer response with actual grid conditions, but it would also make flexibility decisions more complex.

The central question would become:

> "Is our flexibility available at the moments that matter under the final methodology, not just the moments that mattered under 4CP?"

What all three scenarios mean commercially

Current 4CP strategies may need to be revalued—not abandoned

Flexibility is unlikely to become irrelevant. But the value of each response may change.

Customers will increasingly need to understand:

For a Bitcoin miner, that cost may include foregone mining margin, equipment cycling, and recovery behaviour.

For a data center, it may include battery use, deferred compute, workload movement, cooling constraints, reduced capacity, or SLA risk.

The cost floor may matter more than the number of peaks

Much of the public conversation is focused on moving from four peaks to twelve.

For many large loads, however, the more consequential issue could be how much transmission exposure remains after successful peak management.

The customer question may shift from:

"How much transmission cost can we avoid?"

to:

"What contribution may become part of maintaining our grid capacity, and what portion can we still influence?"

Tariffs and contracts will remain critical

A wholesale methodology will not create the same outcome for every large load.

The final customer impact may depend on its utility, retail provider, contract, tariff, contracted capacity, historical demand, interconnection agreement, and whether the site falls within the final large-load provisions.

That is why it is too early to conclude that every large load will pay more, or that any future model will eliminate the value of peak management.

What should large loads be asking now?

A detailed implementation plan should wait until the final rule and tariff process are clearer.

For now, customers can begin with three questions:

1. How much of our current energy strategy depends specifically on 4CP?

2. How would different minimum-demand or peak methodologies interact with our contracted capacity and operating profile?

3. What flexibility is technically available, and what portion remains economically worthwhile under different outcomes?

LōD's perspective

ERCOT's review should not be viewed simply as four peaks becoming twelve—or as twelve mandatory shutdowns.

It points toward a more continuous operating question:

What can flex, when is it worth flexing, and how can the response be executed without compromising the business?

Whatever final model emerges, flexibility will continue to matter. But its value will increasingly depend on connecting grid conditions, energy economics, and operational constraints—and understanding when a response creates more value than it costs.

How could ERCOT transmission reform affect your current strategy? Explore an early scenario assessment with LōD →

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