Electricity tariff structures and time of use

The value of a kilowatt-hour generated by a PV system depends entirely on when it is generated and what tariff structure it displaces or is sold into. Under a flat-rate tariff this is a trivial multiplication; under time-of-use or dynamic pricing, the same physical kilowatt-hour can be worth two or three times as much or as little depending on the hour of the day, and getting this wrong is one of the most common ways a solar financial projection diverges from reality. This article sets out the main tariff structures a European household or business is likely to encounter, how each interacts with a typical PV generation profile, and how to model the resulting value correctly.

By the end you should be able to take a half-hourly or hourly generation profile and a tariff schedule and compute a realistic blended value per kilowatt-hour, rather than applying a single average price across the whole year.

Flat, time-of-use, and dynamic tariffs

A flat tariff charges (and, for export, credits) the same rate per kilowatt-hour regardless of when the energy is used or exported. It is the simplest to model and the easiest for consumers to understand, but it is increasingly being phased out or supplemented by time-varying alternatives as grid operators seek to encourage demand to follow supply.

A time-of-use (ToU) tariff divides the day into fixed bands — typically peak, shoulder and off-peak — each with a different rate, usually set seasonally or with a fixed weekday/weekend pattern known well in advance. ToU tariffs are relevant to solar economics because PV generation is concentrated in the middle of the day, a period that on many ToU schedules falls into a shoulder or even off-peak band precisely because that is when supply, including solar supply at grid scale, is abundant and wholesale prices are typically lower.

A dynamic or wholesale-indexed tariff passes through the actual day-ahead or intraday wholesale electricity price, sometimes with a fixed markup, updated daily or even hourly. These tariffs increasingly show negative or near-zero prices during periods of high renewable output across the wider grid — meaning a household's own solar export at midday can coincide with a period when the wholesale export value is at its lowest point of the day, sometimes near zero, because every other PV system in the region is exporting at the same time.

Why this matters more for export than for self-consumption

For self-consumed generation, the relevant tariff is the retail import rate the household would otherwise pay, and under most residential ToU schedules the difference between bands, while real, is a second-order effect on solar value compared with the simple fact that self-consumption avoids the highest retail rate available at that time of use. For exported generation, the effect is first-order: many European markets have seen a growing gap between daytime and evening/night wholesale prices as solar penetration rises, a pattern often described as the "duck curve" effect at a regional level. An export tariff indexed to wholesale price captures this directly, and a flat feed-in style export rate does not reflect it at all — which can work in the owner's favour if the flat export rate is set above the true midday wholesale value, or against them if it understates evening peak value that battery storage could otherwise capture.

Worked example

A household has a 5 kWp array generating a rough seasonal profile with, on an average day in the relevant billing period, 60 percent of daily output occurring in a midday band (typically 10:00-16:00) and the remainder split across morning and afternoon shoulder periods. Self-consumption share is 40 percent of total generation.

Under Tariff Plan A (flat): import rate €0.30/kWh, export rate €0.09/kWh, applied uniformly. For a day generating 20 kWh, 8 kWh is self-consumed (worth 8 × €0.30 = €2.40) and 12 kWh is exported (worth 12 × €0.09 = €1.08), for a daily value of €3.48.

Under Tariff Plan B (time-of-use): import rate is €0.35/kWh peak (17:00-21:00), €0.28/kWh shoulder, €0.20/kWh off-peak (23:00-07:00); export rate is indexed and averages €0.04/kWh during the midday band specifically (reflecting regional oversupply) and €0.11/kWh during shoulder export periods. Assume the household's self-consumption of 8 kWh occurs mostly during shoulder hours when tariffs are €0.28/kWh (worth 8 × €0.28 = €2.24), and that of the 12 kWh exported, 9 kWh falls in the midday band at €0.04/kWh (€0.36) and 3 kWh in shoulder export at €0.11/kWh (€0.33), for a total export value of €0.69 and a daily value of €2.93.

The same physical generation is worth €3.48/day under the flat tariff and €2.93/day under this particular time-of-use and indexed export structure — a reduction of about 16 percent, entirely due to when the energy arrives relative to when it has value, not any physical difference in the system. This is exactly the kind of adjustment a payback or NPV model should make explicitly using an hourly or half-hourly profile rather than an annual average rate; see the payback calculator and self-consumption calculator for tools that let you test different self-consumption shares against a chosen tariff structure.

Implications for system design and storage

Because midday export value is compressing in many markets as solar penetration rises, the economic argument for maximising self-consumption — through load shifting, battery storage, or sizing the array to household daytime demand rather than to maximise total annual kWh — strengthens correspondingly. A battery that shifts midday surplus into the evening peak band can capture the spread between a near-zero midday export rate and a €0.30+ peak import rate, a value proposition that barely exists under a flat tariff where the spread is small or absent. This should be modelled explicitly with an hourly price and generation series rather than assumed from general principles, since the actual spread varies significantly by market and by year.

What goes wrong in practice

The single most common modelling error is applying an annual average import and export rate to a self-consumption/export split calculated from annual totals, which discards all of the timing information that determines whether a time-of-use or dynamic tariff is favourable or unfavourable to a given generation profile. A second error is projecting today's flat feed-in-style export rate forward for 20-25 years without considering that many markets are moving toward time-varying or wholesale-indexed export pricing, which could materially change the export side of the model over the system's life. A third is ignoring seasonal variation in tariff bands — some ToU schedules vary peak and off-peak hours or rates between summer and winter, and a model built on a single day's tariff schedule misses this. A fourth, particularly relevant to dynamic tariffs, is treating the wholesale price series as static rather than recognising that it responds to solar penetration itself: as more systems export at midday, the midday price tends to fall further, a feedback effect that argues for conservatism when projecting future midday export value from a growing regional PV fleet.

Standards and references

There is no dedicated IEC or EN standard specifically governing tariff structure; retail and wholesale electricity pricing arrangements are set by national regulatory frameworks and are outside PV equipment standards. The relevant technical link is IEC 61850-based smart metering and communication standards that make granular time-of-use and dynamic billing possible at scale, referenced in the JRC's smart metering policy work.

Frequently asked questions

Why is my export payment so much lower than my import rate?

This reflects both the retail markup embedded in the import price (covering network charges, taxes, and supplier margin, none of which apply to a wholesale export) and, on time-varying or wholesale-indexed export tariffs, the fact that midday solar export commonly coincides with regional oversupply, when wholesale prices are at their lowest. The gap tends to widen as regional solar penetration increases.

Should I choose a flat or time-of-use tariff if I have solar?

It depends on your self-consumption profile and the specific band structure and rates on offer. If your household load is concentrated in the evening peak and the ToU peak rate is high, self-consumption during that peak (potentially aided by a battery) can be more valuable than a flat rate. Model both options against your actual or estimated hourly profile rather than choosing on the basis of the headline rate alone.

Does a dynamic tariff make solar less attractive?

Not necessarily overall, but it typically reduces the value of midday export specifically while potentially increasing the value of self-consumption avoided during high-price periods, and it can significantly increase the value proposition of adding battery storage to shift generation into higher-priced hours.

How many hourly data points do I need to model this properly?

A full year of hourly (or half-hourly) generation and tariff data captures seasonal variation in both solar output and tariff bands, and is the standard used in professional PV financial modelling. A single representative day is useful for illustration but should not be the sole basis for a purchase decision.

Will time-of-use tariffs become universal?

Many European markets are moving toward smart-meter-enabled time-of-use and dynamic tariffs as standard or default options, driven by network operators seeking to manage demand and by increasing renewable penetration, but flat tariffs remain widely available in most markets at the time of writing and the pace of change varies by country.

Does time-of-use pricing affect payback period calculations?

Yes, materially, if the self-consumption and export shares are large relative to total generation. A payback calculation using a single blended annual rate can overstate or understate the true payback period by a meaningful margin compared with one that applies band-specific rates to an hourly generation profile.