Sixty minutes each year, spread across four 15-minute intervals in June, July, August, and September, can dictate a substantial share of a large Texas business's electricity delivery cost for the following 12 months. That's 4CP Texas commercial electricity billing at its most consequential: the Four Coincident Peak methodology that ERCOT uses to allocate transmission costs across the state, and the reason large industrial and commercial facilities in Texas care intensely about which afternoon this summer their meter is running hard.
This guide covers what 4CP is, how it actually works, which businesses are directly exposed, how the mechanism shows up on your bill, and what a defensible curtailment strategy looks like. It also flags an important 2026 regulatory development: the PUCT is actively evaluating whether to replace the four-peak methodology with a broader 12CP approach, which means content written as though 4CP will remain the framework forever needs a caveat.
What is 4CP in Texas ERCOT?
4CP stands for "Four Coincident Peak." It's the transmission cost allocation methodology ERCOT uses to distribute the annual cost of the wholesale transmission system across the loads that use it.
The mechanics are specific:
- Four intervals per year: ERCOT identifies the single highest 15-minute system-wide demand interval in each of the four summer months: June, July, August, and September.
- One interval per month, not four in aggregate: The June peak is one interval. The July peak is another. August is a third. September is a fourth. Together these are the four coincident peaks used in the calculation.
- 15 minutes, not one hour: The measurement unit is a 15-minute interval, not an hour. Content that refers to 4CP as "four hours" or "the four peak hours" is using a shorthand that oversimplifies the actual settlement methodology.
- Coincident, meaning system-wide: The peak is when total ERCOT system demand hits its monthly maximum, not when any individual customer's load hits its own maximum. Your facility's demand at that specific 15-minute interval, not your own peak, is what gets measured.
- Settled after the fact: ERCOT determines the official 4CP intervals from settlement data after each month closes. You cannot know with certainty during the month which interval will end up being the peak; you can only forecast the probability.
ERCOT publishes the 4CP calculations for each Distribution Service Provider (DSP) on its official website at ercot.com. The calculations use final settlement data and are updated as each summer month closes.
Why 4CP exists
The Texas transmission grid is expensive to build and maintain, and its capacity has to be sized to handle the highest load conditions of the year. The rational way to allocate the annual cost of that capacity is to charge it to the customers who use it during the moments when the grid is most stressed. In ERCOT, that's summer weekday afternoons, when air conditioning load is highest, industrial production is running, and the grid comes closest to its capacity limits.
By measuring each customer's contribution to those specific stress points and allocating transmission costs accordingly, 4CP creates a direct economic incentive for large loads to reduce their demand during exactly the times the grid needs relief.
4CP vs. monthly demand charges vs. NCP: the important distinction
This is where a lot of published commercial energy content gets confused. There are at least three separate "demand" concepts that appear in Texas commercial electricity, and they follow different rules.
Monthly NCP demand
Your non-coincident peak (NCP) demand is the highest 15-minute average demand recorded at your specific meter during a billing month, regardless of when that peak occurred relative to the ERCOT system. If your facility's highest load occurred at 10:00 AM on a Wednesday when the ERCOT system was at a moderate load, that's still your NCP peak for the month.
Monthly TDSP demand charges are typically calculated against NCP or a ratcheted variant of NCP. This is the biggest single line on most demand-metered commercial bills, and it's driven entirely by your own load pattern.
4CP demand
Your 4CP demand is your facility's demand during the four specific 15-minute intervals when the ERCOT system as a whole hit its monthly peaks. Averaged across all four months, this figure determines how ERCOT-level transmission costs get allocated to your account for the following year.
4CP demand and NCP demand are not the same number. Your facility could have hit its NCP peak at 10:00 AM (perhaps a manufacturing shift starting), while the ERCOT system peak occurred at 5:00 PM (when air conditioning across the state was maxed out and you were still running normally). Both intervals count for different purposes.
The billing chain
Here's how these interact on a commercial bill:
- Every month, your TDSP calculates your NCP demand and bills your distribution demand charge against it (with possible ratchet adjustments based on your prior 11 months of peaks).
- Once per year, ERCOT determines the four coincident peaks and calculates 4CP demand for each DSP based on that DSP's aggregate load during those intervals.
- The DSP allocates ERCOT-billed transmission costs among its customer classes, and for customer classes on rate schedules that use 4CP as a billing determinant, the individual customer's 4CP demand feeds into the following year's Transmission Cost Recovery Factor (TCRF) charges on their bill.
Not every Texas commercial customer is exposed to 4CP directly. It depends on which rate schedule your account is on.
Who has direct 4CP exposure?
4CP directly affects transmission-related charges for larger commercial and industrial customers on rate schedules that use 4CP as a billing determinant. The specifics vary by TDSP and rate class, but the general pattern:
Typically directly exposed:
- Accounts with interval data recorder (IDR) or advanced metering (AMS) meters
- Accounts on primary service or transmission service schedules
- Large secondary service accounts, often those above roughly 700 kW peak demand, though the threshold is tariff-dependent and can be lower
Typically not directly exposed:
- Residential and small commercial customers, whose transmission costs are recovered volumetrically or through fixed allocations
- Smaller commercial accounts below the demand threshold
- Accounts on rate schedules that use NCP demand (rather than 4CP) as the transmission billing determinant
If you're not sure whether your account is directly exposed to 4CP, look at your bill. If a TCRF line item appears with a billing determinant tied to a "4CP" or "coincident peak" figure, you're exposed. If the TCRF is billed against kWh or against your NCP demand, your transmission cost is not directly tied to the four summer peaks.
Larger commercial and industrial businesses (manufacturing plants, data centers, cold storage operations, large industrial facilities, crypto mining operations, big-box retail) are the most common directly-exposed accounts. Small offices, restaurants, and retail stores generally are not.
How 4CP flows onto your electricity bill
The financial chain from ERCOT to your invoice runs through the Transmission Cost Recovery Factor (TCRF) rider on your TDSP tariff.
The allocation chain
- ERCOT calculates its total wholesale transmission revenue requirement for the year: the aggregate cost of the entire transmission system that needs to be recovered from load.
- ERCOT allocates that cost across DSPs based on each DSP's 4CP demand (the sum of its customers' demand during the four coincident peak intervals).
- Each DSP allocates its share across customer classes through its PUCT-approved rate case allocations.
- For customer classes on 4CP-based rate schedules, the DSP calculates each individual customer's contribution based on that customer's 4CP demand, and bills the TCRF accordingly for the following 12 months.
The Public Utility Commission of Texas governs this chain under Substantive Rule 16 TAC §25.192 (Transmission Service Rates) and 16 TAC §25.193 (Distribution Service Provider Transmission Cost Recovery Factors), among other rules.
The illustrative rate
ERCOT's April 2026 strategic materials referenced a 2025 rate of approximately $68.55/kW-year as the figure used to recover the ERCOT system annual transmission revenue requirement. This is an ERCOT-level allocation rate applied to DSP-aggregated 4CP demand. It is not the exact TCRF line that appears on a specific customer's bill; each DSP applies its own allocation to the customer classes on 4CP-based schedules, and the individual customer's TCRF rate reflects that allocation.
Directionally, however, if a large customer contributes an average of 1 MW of demand across the four coincident peaks in 2025, that customer's exposure to the ERCOT-level transmission cost for the following year could be in the range of $68,550 for that year, before any DSP-level allocations or adjustments. This is why avoiding load during those four specific intervals matters so much for large commercial and industrial customers.
For a full breakdown of how TDSP delivery charges work, including TCRF and the other riders that carry transmission and distribution costs to your bill, our overview of TDSP delivery charges across Oncor, CenterPoint, AEP Texas, and TNMP walks through each component.
Historical ERCOT 4CP timeline (2022 to 2025)
The table below shows the settled 4CP intervals for each year from 2022 through 2025, compiled from ERCOT's published 4CP calculations. These are historical dates, not predictions. Past peak patterns do not tell you when this year's peaks will occur. What they do show is the general shape: weekday afternoons, almost always between roughly 3:00 PM and 6:00 PM Central Time, during hot summer months.
- 2022: June 23 at approximately 4:00 PM; July 20 at approximately 4:00 PM; August 2 at approximately 4:00 PM; September 20 at approximately 4:00 PM.
- 2023: June 27 at approximately 5:00 PM; July 31 at approximately 4:00 PM; August 10 at approximately 5:00 PM; September 8 at approximately 4:00 PM.
- 2024: June 30 at approximately 5:00 PM; July 1 at approximately 5:00 PM; August 20 at approximately 5:00 PM; September 19 at approximately 4:00 PM.
- 2025: June 19 at 5:00 PM; July 30 at 5:00 PM; August 18 at 5:00 PM; September 4 at 5:30 PM.
- 2026: Provisional data available for June and July; August and September to be determined once ERCOT settles the data.
Times shown are approximate. Each interval is a 15-minute window; the timestamp represents the interval's start time. Verify official settled intervals directly at ercot.com under the Four Coincident Peak Calculations page. Provisional 2026 dates are not final until ERCOT settles the data.
What the historical timeline actually tells you
Three things worth noting from this pattern:
1. Peaks occur on weekdays
Across 2022 to 2025, all settled 4CP intervals I've reviewed occurred Monday through Friday, though a weekend peak is possible in an extreme weather event.
2. Peaks occur in the late afternoon
All settled 4CP intervals occurred between roughly 4:00 PM and 6:00 PM Central Time. As solar penetration on the ERCOT grid grows, the gross system peak and the net-load peak (system load minus solar generation) are increasingly diverging, with the net-load peak often shifting later into the evening. The 4CP methodology uses the gross system peak, which continues to occur in the traditional afternoon window.
3. Peaks are not evenly distributed within each month
June peaks have occurred as early as the 19th and as late as the 30th. September peaks have occurred as early as the 4th and as late as the 20th. There is no reliable "third week of the month" rule.
Why you can't know the exact interval in advance
ERCOT determines the official 4CP intervals from final settled data after each month closes. During the month itself, market participants and their consultants forecast the probability that a specific interval will end up being the monthly peak based on weather forecasts, load projections, and grid conditions. Forecasts are probabilistic, not deterministic. A forecast that says "high 4CP risk between 4:00 PM and 6:00 PM tomorrow" does not guarantee that the peak will occur; it just says the conditional probability is elevated.
Sophisticated 4CP management operations use day-ahead and same-day forecasting to trigger load reduction on high-probability days. Less sophisticated approaches use a blanket "reduce load every hot summer afternoon" rule, which is more expensive to operate but simpler.
Worked example: 5 MW manufacturing facility
To make the arithmetic concrete, consider a Texas manufacturing facility with a typical peak demand of 5 MW (5,000 kW) that is directly exposed to 4CP under its applicable rate schedule.
Baseline scenario
The facility runs at close to full production during the summer, and its meter records the following demand at each of the four ERCOT system peak intervals:
- June: 4.9 MW facility demand at the ERCOT peak interval
- July: 5.0 MW
- August: 5.1 MW
- September: 4.8 MW
- Average across the four intervals: 4.95 MW
The facility's 4CP demand for the year is 4.95 MW.
Applying the illustrative $68.55/kW-year ERCOT allocation rate:
Illustrative annual transmission exposure = 4,950 kW × $68.55 = $339,323
This is illustrative and pre-DSP-allocation. The actual TCRF line on the facility's bill reflects the DSP's rate case allocation and rider mechanics, and the arithmetic on the actual bill will differ. But the order of magnitude tells the story: for a 5 MW manufacturer, transmission cost exposure runs into six figures annually.
Curtailment scenario
Suppose the facility invests in a 4CP management program: forecasting subscription, automated load-shed protocols, and pre-cooling capacity. It successfully reduces its load to 4.0 MW at each of the four coincident peak intervals (a 1 MW reduction from baseline).
- June: 4.0 MW facility demand at the ERCOT peak interval
- July: 4.0 MW
- August: 4.0 MW
- September: 4.0 MW
- Average across the four intervals: 4.0 MW
Illustrative curtailment scenario exposure = 4,000 kW × $68.55 = $274,200
Annual savings: approximately $65,000, before accounting for the operational cost of curtailment (lost production, labor, equipment cycling).
The economic question
The manufacturer must weigh the $65,000 in avoided transmission cost against the operational cost of achieving the reduction. If pre-cooling and load shifting cost roughly $15,000 per year, the net benefit is $50,000. If production curtailment costs $80,000 per year in lost margin, the net is negative and the strategy shouldn't be implemented.
This is the calculation most competitor content skips. Generic advice to "reduce load during 4CP" is not free. It requires quantifying both sides and choosing the strategy with the best net economics.
Industries most exposed to 4CP
Not every large business has the same 4CP exposure or the same flexibility to manage it.
Manufacturing
Texas manufacturing plants typically have the strongest combination of high demand and load flexibility. Motors, compressors, ovens, and process equipment create peaks that can often be shifted or reduced during specific windows. Multi-shift operations can defer certain processes to overnight or weekend hours. Batch processes can be timed around expected 4CP windows. Our overview of manufacturing electricity procurement in Texas covers demand management strategies alongside contract structure and 4CP planning.
Data centers and 24/7 operations
Continuous-operation facilities like data centers, telecom hubs, and hosting providers face a harder 4CP problem: they have high load factors (typically 80% or above) but limited ability to curtail. Their peaks come from cooling loads that must run whenever server load runs, which is always. For these facilities, 4CP strategy focuses on precision cooling optimization during identified peak-risk intervals, battery-based peak shaving, and negotiating REP contracts that don't stack additional supply-side demand charges on top of the TDSP transmission pass-through.
Cold storage and warehousing
Cold storage operations have consistent base loads (refrigeration must run continuously) with predictable demand spikes when compressors cycle. Precise cycling sequencing during high-probability 4CP intervals, combined with pre-cooling to lower setpoints in the hours before a forecasted peak, can reduce coincident demand without compromising product integrity. Our warehouse and cold storage electricity procurement guide for Texas businesses covers 4CP exposure, refrigeration cycling, and the contract terms that protect against transmission-driven cost variability.
Crypto mining
Cryptocurrency mining operations have become substantial ERCOT loads, and they are among the most flexible large loads on the grid. Because mining revenue depends on continuous operation but can absorb short curtailment windows without permanent damage, mining operators have led in aggressive 4CP participation. Publicly-traded mining companies routinely disclose 4CP curtailment as a material cost management strategy in their financial filings.
Oil and gas
Large industrial loads in oil and gas production, particularly in the Permian Basin, can include pumping and compression that have some scheduling flexibility. Whether 4CP curtailment is economical depends on the production-level economics at the specific site.
Big-box retail and large commercial
Chain retailers, big-box stores, and large hospitality operations sit somewhere in the middle. They have HVAC and lighting loads that can be trimmed during 4CP windows without shutting down operations, but their revenue depends on customer experience during those exact peak hours. Aggressive curtailment can hurt sales. Modest, well-managed setpoint adjustments and lighting reduction can help without measurable customer impact.
Predicting a 4CP event: forecast vs. official settlement
This is the single most important operational point, and where a lot of businesses trip up.
You cannot know the 4CP interval in advance
The official 4CP interval is determined by ERCOT after the month closes, based on settlement data. During the month, businesses and their consultants work with:
- Day-ahead weather forecasts
- Day-ahead ERCOT load projections
- Same-day grid conditions
- Historical patterns
None of these tell you with certainty which interval will end up as the monthly peak. They tell you probabilities.
The forecasting industry
Several third-party 4CP forecasting services exist, provided by REPs, consultants, and independent firms. They typically provide:
- Multi-day-ahead risk assessments (probability of 4CP occurring in the next 3 to 7 days)
- Day-ahead alerts (specific hour-by-hour risk for tomorrow)
- Same-day intraday alerts (real-time updates as grid conditions evolve)
- Post-event confirmation (which intervals actually settled as the monthly peak)
A subscription to a decent 4CP forecasting service is a small line item compared to the potential transmission cost exposure for a large customer.
The false-positive cost
The cost of over-responding to 4CP forecasts is real. Every day the facility curtails load unnecessarily, there is a real operational cost: lost production, disrupted schedules, equipment cycling wear, labor overhead. A forecasting service that has too many false positives costs its customers more than a service with a lower alert rate.
Well-designed 4CP curtailment programs use tiered response protocols:
- Low-probability days: No action.
- Moderate-probability days: Advisory alert to operations, prepare load-shed protocols.
- High-probability days: Activate voluntary curtailment (setpoint adjustments, non-critical load reduction).
- Very-high-probability windows: Full curtailment protocol (mandatory load reduction, if authorized).
How to reduce 4CP exposure in Texas
The interventions below are ordered from lowest operational cost to highest.
1. Load shifting to off-peak hours
Loads that don't require summer weekday afternoon operation can often be moved to overnight or weekend hours. Battery charging (for material handling equipment or EV fleets), some water heating, non-critical refrigeration cycling, and batch production processes are candidates. This has no operational cost if the loads are truly flexible.
2. HVAC pre-cooling
Buildings can be pre-cooled to a lower setpoint in the morning hours (when outside temperatures are lower and grid load is moderate), then coasted through the peak window with a warmer setpoint. This shifts HVAC demand out of the 4CP window without compromising interior comfort during business hours.
3. Automated setpoint adjustment during peak windows
Building management systems can be programmed to raise thermostat setpoints by 2 to 3 degrees during forecasted 4CP hours (typically 3:00 PM to 6:00 PM in summer), reducing compressor draw during exactly the intervals that matter.
4. Battery-based peak shaving
Commercial battery storage systems can be dispatched to discharge during high-probability 4CP intervals, offsetting a portion of site demand. Battery economics have improved substantially, and for large facilities with high, predictable 4CP exposure, payback periods can be 4 to 6 years depending on installed cost and demand charge structure.
5. Onsite generation dispatch
Facilities with permitted backup generators may be able to dispatch them during 4CP intervals under specific conditions (subject to environmental permits and grid interconnection rules). Fuel and maintenance costs must be weighed against avoided transmission cost.
6. Process load curtailment
For manufacturers with flexibility, direct production curtailment during high-probability 4CP intervals can produce the largest single-interval demand reduction. This is also the highest operational cost intervention: lost production time, disrupted schedules, and equipment cycling all impose real costs.
7. Demand response program participation
Distinct from voluntary curtailment, formal demand response programs pay participants for verified load reduction during specific dispatch events. Several REPs and third-party program operators offer commercial demand response in Texas. Payments are typically for participation in grid emergencies, not for 4CP-specific curtailment, so the two strategies can stack.
4CP self-curtailment vs. demand response: not the same thing
Many articles blur these two concepts. They shouldn't.
4CP self-curtailment is voluntary. The customer decides when to reduce load based on their own forecast of 4CP probability. The customer is not paid for the reduction. The financial benefit is entirely in the avoided transmission cost the following year. If the customer over-curtails on days that don't turn out to be 4CP intervals, they've spent operational cost with no benefit.
Demand response is contractual. The customer enrolls in a specific program (typically administered by their REP or an independent aggregator), agrees to reduce load when the program dispatches an event, and gets paid for verified reduction. Programs vary; some pay for capacity (an annual payment for standing available), others pay for energy (a per-event payment for actual reduction), and many combine both. The customer's role is to respond to dispatch signals, not to forecast when to act.
The two strategies can coexist on the same site. A facility can voluntarily curtail during forecasted 4CP intervals and separately enroll in an emergency demand response program that dispatches during grid emergencies. Payments from the demand response program help offset the cost of maintaining curtailment capability, and the 4CP savings compound on top.
Curtailment economics: when it's worth it
The question isn't "should we curtail during 4CP?" It's "does the avoided transmission cost exceed the operational cost of curtailment?"
The calculation:
Net benefit = (4CP demand reduction in kW) × (applicable transmission rate) − (operational cost of curtailment)
Where operational cost includes:
- Lost production margin (if production is curtailed)
- Labor cost for load-shed operations
- Equipment cycling wear (motors starting and stopping)
- HVAC comfort compromise (if any)
- Product integrity risk (for temperature-sensitive operations)
- Fuel and maintenance (if generators dispatch)
For a facility with genuinely flexible load and low operational cost of curtailment (a data center that can shift non-critical workloads, or a manufacturer with a slow production week), the math often works well. For a facility with rigid operations and high curtailment cost, it may not.
Running this calculation before committing to a curtailment strategy is essential. A generic "always curtail during summer afternoons" policy can cost more than it saves.
The 2026 regulatory watch: is 4CP being replaced?
An important development for anyone making multi-year procurement or capital investment decisions based on 4CP:
The PUCT is actively evaluating whether to replace the four-peak methodology under PUCT Project 58484, following requirements in Texas Senate Bill 6 (SB6) enacted in 2025. Proposed rulemaking has explored a 12CP methodology that would use 12 monthly coincident peaks (one per month) measured over 30-minute intervals, rather than four 15-minute intervals in the summer months only.
Stakeholder positions vary. Some argue that expanding to 12CP would better reflect year-round grid stress conditions (particularly winter peaks, which have grown in relative importance since Winter Storm Uri in February 2021). Others argue that 4CP provides a stronger incentive for summer demand management, which is when the grid is most stressed. The PUCT is working through this in 2026 with a target of completing rule amendments by the end of the year per SB6 requirements.
What this means practically:
- For the 2026 summer season, 4CP remains the operative methodology. Continue managing your summer peak exposure accordingly.
- For 2027 and beyond, verify current tariff rules before making multi-year commitments. If the PUCT adopts 12CP or an alternative methodology, your transmission cost exposure could shift substantially.
- Multi-year contracts and capital investments in 4CP-specific infrastructure (dedicated forecasting subscriptions, battery peak-shaving systems sized specifically for four summer intervals) should include a review clause for changes in the regulatory framework.
Electric Decisions tracks the PUCT rulemaking directly and updates procurement recommendations for clients whose transmission cost exposure could shift under any change to the methodology.
Frequently asked questions
What is 4CP in Texas ERCOT?
4CP stands for Four Coincident Peak. It's the ERCOT transmission cost allocation methodology based on customer demand during the four highest 15-minute intervals of the ERCOT system, one per month across June, July, August, and September. For customers on rate schedules that use 4CP as a billing determinant, the average of those four demand values can drive substantial transmission-related charges over the following 12 months.
When are the 4CP peak periods?
ERCOT identifies one 15-minute peak interval in each of June, July, August, and September. Historical peaks between 2022 and 2025 have occurred on weekday afternoons, almost always between roughly 4:00 PM and 6:00 PM Central Time. The exact interval is determined by ERCOT after each month closes based on settlement data; there is no advance calendar of specific peak dates.
How does 4CP affect my Texas business electricity bill?
For customers directly exposed to 4CP, the demand recorded at your facility during the four coincident peak intervals affects the Transmission Cost Recovery Factor (TCRF) charges on your bill for the following 12 months. A 1 MW average 4CP demand exposure could translate into tens of thousands of dollars of annual transmission cost. Customers not directly exposed to 4CP (small commercial accounts, most residential) pay transmission costs through volumetric or fixed allocations that are not directly tied to those four intervals.
How to reduce 4CP exposure in Texas?
The core strategy is load reduction during forecasted 4CP intervals: HVAC pre-cooling and setpoint adjustment during peak windows, shifting flexible loads to off-peak hours, dispatching battery storage during high-probability intervals, curtailing non-critical processes, and (for eligible facilities) enrolling in formal demand response programs. Each intervention has its own operational cost that must be weighed against the avoided transmission cost.
Can you predict a 4CP event in advance?
No, not with certainty. ERCOT determines official 4CP intervals from settlement data after each month closes. During the month, third-party forecasting services can provide probability estimates based on weather forecasts, load projections, and grid conditions, but these are probabilistic rather than deterministic.
What is the difference between 4CP and monthly demand charges?
Monthly demand charges are typically based on your facility's non-coincident peak (NCP): the highest 15-minute average demand at your specific meter during a billing month, regardless of when it occurred. 4CP is based on your demand during the four specific 15-minute intervals when the entire ERCOT system hit its monthly peaks. They can be very different numbers, and they flow through different lines on your bill (NCP through the distribution demand charge, 4CP through the TCRF rider).
Does every Texas commercial customer pay 4CP charges?
No. 4CP directly affects only customers on rate schedules that use 4CP as a billing determinant, typically larger commercial and industrial accounts on interval-metered rate classes. Residential and small commercial customers pay transmission-related costs through volumetric or fixed allocations that are not directly tied to the four coincident peaks.
What is TCRF?
TCRF stands for Transmission Cost Recovery Factor. It's a rider on Texas TDSP tariffs that recovers changes in wholesale transmission costs (including ERCOT 4CP-related allocations) between rate cases. Depending on the customer's rate schedule, TCRF can be billed against kWh, NCP kW, or 4CP kW. It's the primary mechanism by which 4CP-related costs reach a customer's bill.
Does 4CP depend on electricity prices?
No. 4CP is driven by system load, not by wholesale electricity prices. A day with moderate electricity prices but high grid demand can still be a 4CP day. A day with high electricity prices but moderate demand generally is not. The mechanics of 4CP are about grid capacity utilization, not about market price signals.
What time of day do 4CP peaks usually occur?
Historically, ERCOT 4CP peaks between 2022 and 2025 have occurred between roughly 4:00 PM and 6:00 PM Central Time on weekdays. As solar generation on the ERCOT grid grows, net-load peaks (system demand minus solar) increasingly occur later in the evening, though the gross system peak (which 4CP measures) continues to occur in the traditional afternoon window.
Is ERCOT replacing 4CP with 12CP?
The PUCT is actively evaluating a potential change from the current four-peak methodology to a 12-peak (12CP) approach under Project 58484 and Senate Bill 6 requirements. Proposed rulemaking has explored using 12 monthly coincident peaks measured over 30-minute intervals rather than four 15-minute summer intervals. As of mid-2026, 4CP remains the operative methodology. Verify current tariff rules directly with the PUCT (puct.texas.gov) or your energy consultant before making multi-year decisions based on either framework.
What is the difference between 4CP and demand response?
4CP self-curtailment is voluntary and unpaid: the customer reduces load during forecasted 4CP intervals to lower their own transmission cost exposure the following year. Demand response is contractual and paid: the customer enrolls in a program, agrees to reduce load when the program dispatches an event, and receives payment for verified reduction. The two strategies can coexist on the same site.
How do I find my 4CP demand from my interval data?
Look up the settled 4CP intervals on ERCOT's website (ercot.com) for the applicable summer. Pull your 15-minute interval data from Smart Meter Texas (smartmetertexas.com) for those specific intervals. Your demand at each of the four intervals, averaged, is your 4CP demand for that year.
Can batteries reduce 4CP exposure?
Yes, if sized appropriately for the site's demand profile and the expected duration of 4CP intervals. Because 4CP is measured over 15-minute intervals, batteries need to be sized to sustain the required kW reduction across that window. Battery economics for 4CP-specific applications depend on site demand, applicable transmission rates, installed battery cost, and battery useful life. Payback analysis is site-specific.
Do smaller businesses need to worry about 4CP?
Generally no, if the account is below the demand-metered rate threshold or on a rate schedule that doesn't use 4CP as a billing determinant. Small commercial, residential, and moderately-sized commercial accounts typically pay transmission-related costs through volumetric or fixed allocations that are not directly tied to the four peaks. Verify against your specific tariff and rate schedule before assuming exposure or lack of exposure.
Where to go from here
If you want to move from generic "reduce load in summer" advice to a real 4CP strategy:
- Confirm your exposure. Look at your bill's TCRF line and identify the billing determinant. If it's tied to 4CP kW, your account is directly exposed. If it's billed on kWh or NCP kW, your exposure is indirect. Our Texas commercial electricity bill audit guide covers where these components appear on the bill.
- Pull your historical 4CP demand. Cross-reference your 15-minute interval data from Smart Meter Texas against the settled 4CP intervals published on ercot.com. This tells you your actual historical 4CP exposure and where the curtailment opportunity is.
- Quantify the economics. Calculate the potential annual savings from a specific curtailment target (say, 20% reduction) and the operational cost of achieving it. Only proceed with strategies where the net is positive.
- Subscribe to a 4CP forecasting service. For large exposed accounts, this is table stakes. Multiple REPs and independent firms offer forecasts with varying alert rates and accuracy.
- Watch the regulatory environment. PUCT Project 58484 could shift the methodology from 4CP to 12CP over the next 12 to 24 months. Multi-year infrastructure and contract decisions should account for the possibility.
Electric Decisions works with Texas commercial buyers on procurement contracts that properly address 4CP pass-throughs, including transparent TCRF handling, protection against methodology changes, and clear disclosure of how 4CP-related costs flow through the REP contract. Our commercial electricity comparison for Texas businesses benchmarks REP offers on total delivered cost including transmission pass-throughs, and our 5-step energy procurement process documents each stage of a defensible procurement RFP for large commercial and industrial buyers.
For sector-specific 4CP planning, see our overviews for Texas manufacturing electricity procurement, warehouse and cold storage electricity in Texas, and the energy strategy by industry hub for other verticals.