Peak and Off-Peak Hours for Solar: 2026 EPC Guide

Last updated August 2, 2026 (Originally published July 18, 2026)

November 1, 2025: Enedis begins implementing France’s TURPE 7 off-peak hours reform. In summer, up to 3 of the 8 daily off-peak hours can move to a midday window between 11h and 17h to better match solar production, while at least 5 consecutive off-peak hours remain overnight year-round.
June 14, 2023: India’s Electricity (Rights of Consumers) Amendment Rules, 2023 introduced Time-of-Day tariff provisions, including separate peak, solar and normal hours. Implementation depends on consumer category, metering rollout and state-level regulatory schedules.
California reference point: PG&E, SCE and SDG&E do not use one universal peak/off-peak schedule. Peak windows vary by utility, rate plan, demand class, season, legacy status and event-day programme. Under the Net Billing Tariff, export value is time-dependent, which makes rate-plan selection and storage dispatch part of the solar design problem.

Quick Answer

1. What are peak and off-peak hours?
   Peak hours are the periods when electricity is most expensive, usually because system demand is high or the grid is under stress. Off-peak hours are lower-price periods, traditionally overnight, but this is changing in high-solar markets.
2. Why do they matter for solar projects?
   Because the value of one solar kilowatt-hour depends on when it is generated, consumed, exported or stored. A system that looks strong on annual kWh can underperform financially if most of its output lands in low-value hours.
3. What is the duck curve?
   The duck curve describes the drop in net grid demand around midday when solar output is high, followed by a sharp evening ramp when solar generation falls and demand rises.
4. Did France shift off-peak hours to the evening?
   No. France’s reform shifts some summer off-peak hours to midday, between 11h and 17h, to better align consumption with solar output. At least 5 consecutive off-peak hours remain overnight.
5. Is 4 p.m. to 9 p.m. the peak window everywhere in California?
   No. It is common across several California schedules, but not universal. PG&E residential, PG&E business, SCE commercial, SDG&E residential, PG&E agricultural and SCE legacy accounts can all have different rules.
6. What should EPCs do before quoting?
   Pull the customer’s actual tariff schedule, verify demand class and legacy status, model hourly solar output against current tariff windows, and size storage against the real export and consumption value of energy.

Why This Matters for EPCs

Peak and off-peak timing is not background context. It changes inverter sizing, battery sizing, orientation, self-consumption value, demand-charge exposure and the final revenue projection shown to the client.

A proposal built on a generic assumption such as “peak equals evening” can fail in two different ways. It can undersell storage where local Time-of-Use rates make load shifting valuable. It can also oversell export revenue where the tariff pays little for midday solar generation.

This is now an EPC workflow issue, not just a tariff explainer. The right design decision depends on hourly generation, hourly consumption, local export credits, battery dispatch, customer rate plan and any plan-switch lock-in period after commissioning.

What Peak and Off-Peak Hours Mean in a Solar Proposal

A Time-of-Use tariff prices electricity differently depending on the clock, calendar and, in some cases, the day type. The same kilowatt-hour can have one value at noon, another at 6 p.m. and another overnight.

For a normal electricity customer, this affects when power should be consumed. For a solar customer, it affects four additional decisions:

• whether solar should be self-consumed or exported;
• whether storage should be included;
• when the battery should charge and discharge;
• whether the customer should move to a different post-solar rate plan.

The mistake is treating peak/off-peak hours as a generic education topic. For EPCs, the useful question is more specific:

Which hours does this exact tariff reward, and does the proposed solar-plus-storage design place energy into those hours?

The Duck Curve: Why Tariff Windows Are Moving

The duck curve became important because solar changed the shape of grid demand. When a large amount of solar generation enters the grid around midday, net demand from the grid falls. Then, as solar generation drops in the evening while homes and businesses continue using power, the grid has to ramp other generation quickly.

That is why many high-solar markets are no longer rewarding midday energy the way older tariff structures did. Midday can become lower-value because solar is abundant. Evening can become higher-value because solar has fallen and the grid still has to serve demand.

The EPC implication is simple: annual generation is not enough. A design needs to answer when the energy is valuable, not only how much energy the system produces over the year.

France: The Midday Off-Peak Reform EPCs Should Understand Precisely

France’s TURPE 7 reform is one of the clearest examples of a grid reshaping off-peak hours around solar generation.

Starting November 1, 2025, Enedis began changing off-peak schedules for HP/HC customers. The total remains 8 off-peak hours per day. In summer, from April to October, up to 3 of those 8 hours can move into a midday window between 11h and 17h. At least 5 consecutive off-peak hours remain overnight between 23h and 7h. In winter, from November to March, the structure remains focused on overnight off-peak hours.

This matters because the reform is sometimes described incorrectly as an evening shift. It is not. It is a midday shift in summer, designed to encourage consumption when solar output is high.

For EPCs, France is useful because it shows where tariff design is going. A market with more solar does not always solve the duck curve by making evening exports more valuable. It may instead make midday consumption cheaper, encouraging customers to run flexible loads when solar is abundant.

EPC takeaway: In France-style structures, the storage question is not only “how much solar can we move into the evening?” It is also “which loads can be moved into the new midday off-peak window?”

California: Why Generic Peak-Hour Tables Break Solar Quotes

California is the strongest example of why EPCs should not design from a generic peak/off-peak table.

PG&E, SCE and SDG&E all use Time-of-Use structures, but their windows vary by customer class, demand threshold, season, event-day programme and legacy status. A California solar proposal that says “peak is 4–9 p.m.” without checking the actual tariff may be directionally useful but operationally incomplete.

PG&E Residential

PG&E’s default residential E-TOU-C plan uses a 4 p.m. to 9 p.m. peak window every day of the week. PG&E also offers another residential option with a narrower 5 p.m. to 8 p.m. weekday peak window.

This means two residential customers in the same utility territory can have different peak windows. The post-solar rate plan is therefore not just a billing choice. It changes the economics of self-consumption, storage and any load-shifting recommendation.

PG&E also limits how frequently customers can switch Time-of-Use plans. If the wrong plan is selected around commissioning, the customer may be locked into that choice for a year.

PG&E Business

PG&E business Time-of-Use plans commonly set peak at 4 p.m. to 9 p.m. every day, including weekends. That is materially different from SCE commercial schedules, where on-peak periods are often limited to summer weekdays and exclude holidays.

Some PG&E business plans also carry demand charges. These are based on the highest short interval of power demand during the billing period, often a 15-minute peak. PG&E indicates that plans with demand charges can have lower per-kWh energy charges than comparable plans without demand charges.

For EPCs, this creates a trade-off. A customer with a flat load profile may benefit from a lower energy rate even with a demand charge. A customer with sharp peaks may need storage or load control to avoid demand-charge exposure.

PG&E Agricultural

Some PG&E agricultural schedules have a 5 p.m. to 8 p.m. peak period that applies across all 365 days of the year, including weekends and holidays. PG&E also offers agricultural flex options that can shift off-peak days to fixed weekday pairs for operations that can concentrate pumping or processing loads.

This matters because agricultural solar design often depends heavily on load timing. A pump, cold-storage load or processing schedule can change whether solar-only, solar-plus-storage or tariff switching is the better proposal.

PG&E Business EV

PG&E’s business EV rate structure is especially important because it includes a super off-peak period from 9 a.m. to 2 p.m. every day, year-round. PG&E describes this kind of period as supporting energy use when solar is most plentiful.

For workplace charging, fleet charging and commercial EV infrastructure, this can completely change the design logic. Instead of sizing only around evening discharge, the project may be designed to absorb solar during the lowest-cost daytime charging window.

SCE Commercial

SCE commercial schedules are shaped by demand thresholds.

TOU-GS-1 generally applies to small business customers whose demand does not regularly exceed 20 kW. TOU-GS-2 applies above 20 kW and below 200 kW. TOU-GS-3 covers higher registered demand bands, such as 200 kW to 500 kW.

Across these commercial schedules, on-peak periods are commonly 4 p.m. to 9 p.m. in summer on weekdays, with holidays excluded. That differs from PG&E business schedules that can apply the peak window every day.

SCE also has legacy or discontinued Time-of-Use periods for certain existing accounts, where on-peak hours may still run from noon to 6 p.m. These are not generally open to new customers, but an existing account on one of these schedules is a different design problem. In that case, the peak window sits directly on top of solar production rather than after it.

SDG&E Residential

SDG&E’s residential peak period is commonly 4 p.m. to 9 p.m. The utility also enforces commitment periods for many pricing plans, meaning a customer who recently switched plans may not be able to change again immediately.

SDG&E also offers event-day pricing structures where called events can make the 4 p.m. to 9 p.m. period much more expensive on specific days.

For EPCs, this means the standard bill-savings model is not enough. The proposal should identify the customer’s current plan, eligible alternatives, event-day exposure and any 12-month restriction before recommending storage or rate switching.

The Net Billing Tariff: Export Value Is Not One Number

California’s Net Billing Tariff changed the export side of the solar proposal.

Under older net metering structures, exported solar was often close to a retail offset. Under the Net Billing Tariff, export credits are tied to avoided-cost values that vary by month, hour and day type. A commonly referenced structure contains 576 export value points in a year, reflecting 12 months, 24 hours and weekday versus weekend or holiday periods.

The exact implementation should always be checked against the utility and customer tariff, but the practical lesson is clear: one average export price is not enough for a serious proposal.

An EPC quoting a solar-plus-storage project needs to model:

• hourly solar production;
• hourly customer consumption;
• hourly export value;
• battery charge and discharge timing;
• whether exported energy is less valuable than self-consumed energy;
• the customer’s post-solar rate plan.

The same hardware can produce different savings under different rate plans. In one Aurora Solar case study, changing the post-solar rate plan produced more than $42,000 in additional lifetime savings on the same installed system. The point is not that every project will see that exact gain. The point is that tariff choice can be a design variable, not an afterthought.

Storage Sizing: The Battery Does Not Always Discharge for the Whole Peak Window

A battery should not be sized only against the published peak window. It should be dispatched against the actual value of each hour inside that window.

A simple example explains the difference. If exported solar at midday is worth 4 cents per kWh but the same energy can offset 60 cents per kWh during an evening peak hour, storage captures the spread. But even inside a peak period, every hour may not have the same value. A battery may be better off holding charge through the first hour of peak pricing and discharging later if the tariff value rises within the window.

For EPCs, this changes the battery sales conversation. The question is not only “Does the customer have evening peak pricing?” It is:
Which hours should the battery actually discharge into, and what is the value difference between those hours and the hours when the battery charges?

Orientation and Load Shifting: Why West-Facing or East-West Can Matter

Peak/off-peak timing can also affect array orientation.

South-facing arrays often maximize annual generation in the northern hemisphere. But under some Time-of-Use tariffs, a west-facing system can shift more generation toward late afternoon and early evening. It may produce less total energy, but some of that energy can land closer to the expensive window.

East-west layouts can also matter where the goal is a flatter production curve or higher rooftop capacity. But orientation should not be treated as a universal rule. It has to be tested against the tariff, the load profile and the actual roof geometry.

The strongest design workflow is to model orientation, storage and tariff together. A west-facing layout without storage may not beat a south-facing layout with storage. An east-west layout may add capacity but export more low-value energy. A south-facing layout may win on annual kWh but lose on timing value.

EPC takeaway: Orientation is not only a solar-geometry decision. In Time-of-Use markets, it is also a tariff-value decision.

India: Time-of-Day Tariffs Follow the Same Solar-Hour Logic

India’s Electricity (Rights of Consumers) Amendment Rules, 2023 introduced Time-of-Day tariff provisions with separate treatment for solar hours, peak hours and normal hours. The policy direction is similar to France and California: electricity pricing should increasingly reflect when power is abundant and when the grid is under stress.

The important caution is implementation. India’s rollout depends on consumer category, smart-meter availability, state commission rules and local tariff orders. EPCs should not assume one national peak/off-peak window across India.

For Indian EPCs, the proposal-level action is straightforward: check the state tariff order, identify whether the customer falls under a Time-of-Day category, and model solar-plus-storage economics against the local schedule actually applicable to that consumer.

Key Timelines and Windows EPCs Should Track

France

• November 1, 2025: Enedis starts implementing off-peak hour reform.
• 2025 to 2027: gradual rollout across affected HP/HC customers.
• Summer structure: up to 3 of 8 off-peak hours can move to 11h-17h.
• Year-round protection: at least 5 consecutive off-peak hours remain overnight.

California

• December 15, 2022: CPUC votes to finalize the Net Billing Tariff.
• April 13, 2023: last day for new NEM 2.0 interconnection applications.
• 4 p.m. to 9 p.m.: common peak window across many PG&E, SCE and SDG&E schedules, but not universal.
• 5 p.m. to 8 p.m.: PG&E narrower residential option and some agricultural schedules.
• Noon to 6 p.m.: still relevant for some SCE legacy discontinued Time-of-Use periods.
• 9 a.m. to 2 p.m.: PG&E business EV super off-peak window.

India

• June 14, 2023: Ministry of Power notifies the Electricity (Rights of Consumers) Amendment Rules, 2023.
• Implementation should be checked by state, consumer category and meter status.

What EPCs Should Do Before the Next Quote Goes Out

• Pull the customer’s actual tariff schedule. Do not rely on a generic peak/off-peak table.
• Check customer class and demand threshold. For SCE and many commercial schedules, demand size changes the applicable tariff.
• Check legacy or transition status. Existing solar customers may still be billed under older peak windows or delayed-transition rules.
• Model hourly production against hourly tariff value. Annual kWh alone is not enough.
• Size storage against the most valuable discharge hours. Do not assume the battery should discharge evenly across the whole printed peak window.
• Model demand charges separately. A lower energy charge can be offset by a single demand spike.
• Check post-solar rate-plan options before commissioning. A wrong plan selection can be locked in for 12 months or more.
• Document tariff assumptions in the proposal. The client should see the exact tariff schedule used in the ROI model.
• Recheck tariff assumptions before final design. Tariff structures are changing quickly in high-solar markets.

Common Mistakes to Avoid

• Assuming off-peak always means nighttime. France’s reform proves that off-peak can include midday solar hours.
• Describing France’s reform as an evening shift. It is a summer midday shift, not an evening shift.
• Assuming 4 p.m. to 9 p.m. applies to every California customer. It is common, but utility, class, season and legacy status matter.
• Using one average export value under the Net Billing Tariff. Export value is time-dependent, and a single blended number can hide important design differences.
• Ignoring demand charges. Commercial bills can be shaped by one short demand spike, not only energy consumption.
• Treating the post-solar rate plan as admin work. The selected plan can materially change project economics.
• Forgetting legacy schedules. Some existing accounts may still be on older peak windows.
• Sizing the battery against the window, not the hourly values inside the window. The best discharge hour may not be the first peak hour.
• Applying one country’s tariff logic to another. France, California and India follow similar solar-hour logic, but the mechanics are different.

How This Fits Into a Reslink Workflow

A proposal’s revenue projection is only as good as the tariff assumptions behind it. If the design model assumes one generic peak/off-peak structure while the customer’s actual tariff has seasonal, hourly or event-day variation, the ROI can be wrong before the project is even installed.

Reslink’s proposal workflow connects solar design, tariff modelling, storage sizing and revenue assumptions in one project record. That helps EPCs move from generic peak-hour claims to site-specific proposals that show when the system generates, when the client consumes, when storage charges, when storage discharges and what each hour is worth.

See how Reslink keeps tariff assumptions tied to the project design itself → Book a demo

Frequently Asked Questions

Q1. Are peak and off-peak hours the same everywhere?

No. Peak and off-peak windows vary by utility, country, state, consumer category, season, demand size and tariff plan. A generic online table is useful for education but not enough for an EPC proposal.

Q2. Why did solar make peak-hour timing more complicated?

Solar creates high midday generation and lower net grid demand during the day, followed by a sharper evening ramp when solar output drops. Tariffs increasingly reflect this by discounting solar-rich hours and pricing evening ramp hours higher.

Q3. Did France move off-peak hours to the evening

No. France moved some summer off-peak hours to midday, specifically between 11h and 17h, to better align consumption with solar production. At least 5 consecutive off-peak hours remain overnight.

Q4. Is 4 p.m. to 9 p.m. always the California peak window?

No. It is common across several California schedules, but PG&E, SCE and SDG&E all have exceptions. Customer class, demand threshold, season, legacy status and rate plan must be checked.

Q5. Why does Net Billing Tariff change solar design

Because export value varies by time. A kWh exported at midday may be much less valuable than a kWh consumed or discharged during an evening peak. That changes the case for batteries, orientation and post-solar rate selection.

Q6. Should a battery discharge for the full peak period?

Not always. The battery should discharge into the hours with the highest value after considering the customer’s load, tariff, export credit and battery limits. The printed peak window is only the boundary.

Q7. Does west-facing solar make sense under Time-of-Use tariffs?

Sometimes. West-facing systems can shift generation later into the day, closer to evening peak windows, but they may produce less total energy. Whether that trade-off works depends on the tariff, load profile and available roof geometry.

Q8. How should EPCs model peak/off-peak hours in proposals?

Use hourly solar production, hourly consumption, the customer’s current tariff schedule, expected export values, storage dispatch logic and any demand charges. The assumptions should be documented in the proposal.

Q9. Is India following the same trend?

Directionally yes. India’s 2023 Time-of-Day tariff framework introduces solar, peak and normal hours, but implementation depends on state-level tariff orders, consumer category and smart-meter rollout.

Sources

Official and regulatory sources

• Service-Public.gouv.fr — Change in off-peak hours as of November 1, 2025
• Enedis — Reform of off-peak hours to support transition-related electricity uses
• Press Information Bureau, Government of India — Electricity Rights of Consumers Amendment Rules, 2023 and ToD tariffs
• CPUC Resolution E-3179
• U.S. Energy Information Administration — Wholesale and retail electricity rate context

Utility and tariff sources

• PG&E — Time-of-use rate plans
• SCE — Summary of Available Residential and Nonresidential Rate Options
• SDG&E — Residential pricing plans

Research and trade sources

• The Brattle Group — A Survey of Residential Time-of-Use Rates
• American Public Power Association — Moving Ahead with Time-of-Use Rates
• Solar Power World — CPUC finalizes California Net Billing Tariff
• Aurora Solar — How Time-of-Use Rates Work
• Aurora Solar — Better Solar Designs Under TOU Rates
• Constellation — Peak vs. Off-Peak Electricity Hours