Curtailment risk · Glossary

Curtailment risk refers to the risk that an operational power generation plant has to temporarily reduce the feed-in that would be possible under the prevailing conditions. In the narrower sense, it concerns grid-related interventions and connection-side restrictions. In broader economic usage, market-driven shutdowns are also included. For a robust assessment, these causes must be kept separate: they differ with regard to responsibility, forecasting and financial treatment.

Curtailment is the actual event; curtailment risk describes the uncertainty about the frequency, duration, extent and consequences of such events. It affects wind and photovoltaic plants in particular, but is not limited to these technologies. The decisive point is the distinction between physical and economic impact: a quantity of electricity that is not fed in does not necessarily mean an equally large loss of revenue. Statutory or contractual compensation can fully or partially offset the economic burden.

Power, lost energy and revenue loss

What is curtailed is first of all power, measured for example in kilowatts or megawatts. The resulting quantity of energy follows from the power difference over time. A simplified example: a wind turbine could feed in 5 megawatts continuously for two hours but may only deliver 2 megawatts. The difference is 3 megawatts; over two hours this results in 6 megawatt-hours of energy not fed in. This presupposes that, without the limitation, 5 megawatts would actually have been possible throughout the entire period.

With changing wind or irradiation, this difference must be determined for the respective time intervals and then added up. The hypothetical generation without intervention cannot be read directly from the feed-in meter. It must be determined on the basis of suitable operational, weather and reference data. The lost energy determined in this way is therefore not simply the rated power multiplied by the shutdown duration. Technical unavailability and other limitations acting at the same time must be taken into account.

A curtailment share also needs a clear reference basis. If, for example, 400 megawatt-hours out of an otherwise possible 10,000 megawatt-hours are not fed in, the share is 4 percent of the possible energy. Relative to the remaining 9,600 megawatt-hours, by contrast, the percentage would be higher. Annual figures of different projects are only comparable if the reference basis, observation period and causes covered are consistent.

The revenue loss cannot be derived from this using an arbitrary annual average price. In the example, 6 megawatt-hours at an assumed revenue of 80 euros per megawatt-hour would initially mean 480 euros of lost gross revenue. This is a calculation assumption, not a statement about current prices or compensation claims. For the actual economic loss, the affected time intervals, the marketing and support rules, any compensation, and additional or avoided expenses are what matter.

Distinction from other yield risks

Curtailment risk must be separated from resource and weather risk. Lack of wind and low solar irradiation already reduce possible generation. Curtailment, by contrast, presupposes that higher generation or feed-in would be possible without the limitation in question. A wind assessment or a solar yield forecast therefore does not yet fully answer how much electricity can actually reach the grid at the intended site.

Technical failures also belong in a category of their own. A defective inverter or a gearbox failure reduces plant availability. An operational plant whose feed-in is limited on instruction, by contrast, has not technically failed for that reason alone. Shutdowns required by permits, for example for species protection or noise protection, must also be reported separately. This separation prevents double counting and helps in reviewing maintenance guarantees, insurance and compensation claims.

Finally, not every missing payment is a curtailment. A plant can feed in and nevertheless have lower market revenues or no entitlement to support for certain periods. Conversely, it can be physically curtailed and be largely protected economically through compensation mechanisms. Feed-in, marketing, balancing and remuneration are interconnected but not equivalent.

Why the grid can limit feed-in

A grid congestion means that the current feed-in and consumption situation is incompatible with the permissible operating limits of a grid area. In redispatch, generation is changed so that critical lines are relieved: suitable plants reduce their feed-in while others increase it. A congestion is therefore not to be equated with a nationwide electricity surplus. Congestion management also includes further instruments; not every intervention is legally treated like regular redispatch.

The spatial effect can be illustrated by a region with high wind production and limited line connections. Even if electricity is needed elsewhere, the additional feed-in can overload the connection between the two regions. What matters is not the commercial supply contracts but the actual electrical power flows. In addition to the capacity of lines, transformers, voltage limits and requirements for secure operation in the event of equipment outages can have a limiting effect.

With photovoltaics, pronounced midday peaks can meet low local demand. In that case, for example, the reverse feed from a distribution grid into the higher-level grid layer is decisive. With wind, high feed-in can occur simultaneously over longer periods and larger regions. The curtailment profiles of the two technologies therefore differ. Installed capacity alone explains neither the frequency nor the energy volume of possible limitations.

Since 1 October 2021, the former German rules on feed-in management have been transferred into the redispatch system. This also covers renewable generation, combined heat and power and electricity storage. Risk assessment must therefore distinguish between the general technical concept of curtailment and the statutory procedure that is applicable in each case.

Germany: scope of plants and financial compensation

For Germany, according to the legal status reviewed here as of 11 November 2026: Section 13a EnWG covers generation and storage plants with a rated capacity of 100 kilowatts or more, as well as, irrespective of this, plants that a grid operator can remotely control at any time. Section 14 applies the rules, with particularities, to distribution system operators. For measures under Section 13a, appropriate financial compensation is provided for, which, taking balancing compensation into account, is intended to leave the operator economically neutral. For the reduction of renewable generation, the law names lost income and additional expenses. However, this does not result in a blanket entitlement to reimbursement for every technical, market-driven or contractual limitation.

For a specific project, several questions must therefore be examined separately: On what legal basis did the intervention take place? Who is entitled to claim? Which revenue components are affected? How are benefits already received taken into account? What evidence is required? The remark that curtailment is compensated does not replace this examination. In particular, earlier compensation rules of feed-in management must not be transferred to present-day cases without verification.

The amount of a claim that exists in principle and the timing of its payment are different risks. Even if compensation largely eliminates the economic burden, delayed settlement, disputed reference quantities or missing operating data can tie up liquidity. For financing, therefore, not only the expected annual revenue is relevant, but also when money actually flows in and what effort is required for evidence and processing.

Balancing compensation and direct marketing

Balancing compensation is intended to prevent a redispatch measure from burdening the affected balancing group as if the missing feed-in were an ordinary forecast deviation. In this regard, the Federal Network Agency issued determination BK6-23-241 on 7 May 2026. For distribution grids, a special statutory rule applies until the end of 2031: targeted compensation by the grid operator takes place only in accordance with a corresponding determination. Where it is not carried out, special rules on reimbursement of expenses apply in addition. A project should therefore not assume a settlement process that is identical everywhere.

In direct marketing, the technical interventions must be brought together with feed-in forecasts, trading positions and balancing group management. The contract should clarify who processes notifications, reconciles lost quantities and asserts claims. Equally important is who is economically entitled to replacement or compensation payments and how they are passed on. Balancing compensation is not automatically an additional cash payment of the same amount to the plant operator.

Contract analysis must therefore avoid double remuneration as well as uncovered gaps. If, for example, one party receives a balancing replacement quantity and another receives financial compensation, the payment and delivery flows must fit together. A mere clause under which the direct marketer bears or passes on all consequences of curtailment can lead to disputes without a precise definition of the cases covered.

Flexible grid connections and fixed feed-in limits

Curtailment risk can already be embedded in the connection concept. A limited connection capacity can be acceptable for a project if it enables an earlier connection or another technically and economically viable solution. However, this implies neither an automatic cost advantage nor a commitment to unrestricted feed-in outside individual congestion hours. What matters are the rights and limitations actually assured.

Section 8a EEG enables flexible grid connection agreements for EEG plants in Germany. A maximum active power feed-in can be agreed, including with different limits per time window. In particular, the level of the limitation, any time windows, duration, technical implementation and liability must be regulated. For jointly used connection points, additional agreements are required. The provision thus does not establish a general commitment to treat every feed-in remaining below the installed plant capacity as curtailment subject to compensation.

For investors, it is particularly important to distinguish between a capacity limit agreed from the outset and an additional intervention in the feed-in possible within that limit. An example: a solar park has more module capacity than it may feed in at the connection point. Exceeding the agreed connection capacity would not be permissible even without later redispatch. A yield model must therefore not at the same time treat this difference as a grid measure eligible for compensation.

A fixed limit can be modelled comparatively clearly if the generation profile is known. With variable restrictions, the risk additionally depends on when and how much the limit may be changed. For contract review, notice periods, metering point, data access, permissible duration, possible annual quotas and the end of temporary restrictions are important questions. An annual quota is not an automatically existing statutory safeguard.

Negative prices and economic shutdown

Grid-related curtailment and negative electricity prices can occur at the same time but have different causes. A local line can be overloaded at a positive exchange price. Conversely, a plant may technically be allowed to feed in at a negative price. Economic shutdown means that operators or marketers forgo production because the expected revenues, including support, do not cover the relevant costs and disadvantages.

Under Section 51 EEG, the applicable value generally falls to zero for periods with a negative spot market price. However, the provision contains exceptions; in addition, transitional law must be observed. Its specific application therefore depends, among other things, on plant class, size, commissioning and, where applicable, metering equipment. The loss of a support component is not an instruction from a grid operator and does not in itself give rise to redispatch compensation.

For a revenue model, grid-related interventions, connection-side limitations and economic shutdowns should form separate categories. If several causes coincide in the same time interval, the same quantity of energy must not be deducted several times as a loss. Likewise, it would be wrong to attribute the full support and market value to every megawatt-hour not fed in, although these revenues would not have arisen at all in the hour concerned without the intervention.

Significance for project finance and power supply contracts

Wind and solar projects require high initial investments. Their financing depends substantially on the cash surpluses available over many years. A small volume deduction can therefore be significant if the calculation leaves little room or if delivery obligations trigger replacement procurement. Conversely, a high physical curtailment share is not automatically equivalent to an equally high economic loss, provided reliable compensation claims exist.

In yield assessment, losses must be broken down transparently: for example technical unavailability, electrical losses, mutual shading or wake effects, permit-related shutdowns and grid-related limitation. The respective reference states must fit together. Restrictions already taken into account in the assessment report must not be deducted again as a lump sum in the financial model. Conversely, a report on the natural resource must not be understood as proof of unrestricted grid usability.

P50 and P90 do not denote fixed safety deductions. P50 is the median of an assumed yield distribution: under the model assumptions, the value is reached or exceeded with a probability of 50 percent. P90 denotes a value with a 90 percent probability of exceedance. The observation period and the uncertainties covered must be stated explicitly. A P90 yield is neither a guarantee nor necessarily already adjusted for future curtailment.

In a Power Purchase Agreement, it is decisive whether the quantity actually generated, a fixed volume or a specific delivery profile is owed. In the first case, the delivery quantity can fall in the event of curtailment. With fixed obligations, by contrast, replacement procurement costs can arise unless the contract provides a corresponding exception. Provisions on grid events, force majeure, deemed delivery quantities and compensation payments must therefore be read together.

A grid event is not necessarily force majeure. Likewise, statutory financial compensation does not automatically replace every contractual burden vis-à-vis an electricity buyer. For project assessment, it must be checked whether the definitions in the grid connection, marketing, supply and credit agreements fit together. Different terms for the same event can otherwise lead to unforeseen liability or financing gaps.

Why historical averages are not sufficient

Past curtailments are an important starting point, but not a reliable extrapolation for the entire operating life. They reflect the grid conditions, generation plants, consumption patterns, weather situations and operating rules of that time. Additional generation can increase the burden; new lines, transformers or local consumers can reduce it. Delayed grid expansion and temporary equipment outages also belong in possible future scenarios.

A nationwide average says little about an individual connection point. Two wind farms with similar weather conditions can be affected to different degrees because their feed-in acts differently on the critical grid area. Conversely, a neighbouring site does not necessarily have the same risk. Voltage level, switching states, transformer connection and upstream congestion can be more important than mere geographical distance.

For a robust forecast, several developments should be combined: secured and possible grid measures, connections already committed, additional wind and solar build-out, changes in demand, and new storage and flexible consumers. A mere list of planned projects is not enough. What matters is their timing of availability, mode of operation and grid-technical effect. An announced expansion should not be treated like a line already in operation.

Temporal correlation is also important. Windy years can bring both high potential generation and stronger congestion at the same time. Solar generation from many plants can occur in the same midday hours. A constant percentage deduction reproduces such relationships only roughly. For large or tightly calculated projects, a time-resolved analysis that examines volumes and revenues together may therefore be necessary.

Flexibility, storage and plant design

Flexibility can reduce curtailment if it is available at a suitable location and operated appropriately. Additional consumption on the generation side of a congestion can provide relief; consumption on the other side does not necessarily help that congestion. The same applies to storage. A device is not grid-serving merely because it can in principle charge, discharge or shift its consumption.

A battery storage unit behind the same connection point can absorb feed-in peaks and release energy later. However, this only works to the extent that charging power, free storage capacity, connection concept and control are compatible. In the case of a prolonged wind surplus, a small storage unit can quickly be full. When discharging later, it must not aggravate the congestion again. Storage losses, ageing, investment costs and the applicable marketing and support conditions therefore belong in the calculation.

Curtailed electricity, moreover, is usually not available as an already generated, freely usable quantity of energy. With wind and photovoltaics, it is usually the electrical generation itself that is reduced. If this energy is instead to be used for heat or hydrogen, generation, consumers and grid connection must be designed accordingly. A few irregular congestion hours alone do not automatically justify the investment in an electrolyser or another additional plant.

Design also influences the usable energy quantity. With photovoltaics, more module capacity relative to inverter capacity can increase production outside peak hours even though power peaks are cut off. This so-called clipping is first of all a design effect and not proof of grid-related curtailment. With wind, turbine selection and park layout can change the generation profile. Hybrid projects can make better use of a shared connection, although their profiles do not complement each other at all times.

Cost allocation and electricity market design

Financial compensation does not eliminate the physical congestion. It initially changes who bears its economic consequences. From the project's perspective, this can create investment security; from the system's perspective, the consequences of the changed generation and of the processing remain relevant. In a macroeconomic assessment, compensation payments, as monetary transfers, must not be equated without scrutiny with all real additional costs or counted twice alongside them.

Location and investment signals can differ between the exchange market and the grid. A uniform price within a bidding zone does not reflect every local congestion. Connection conditions, regional incentives and the allocation of congestion costs can therefore influence which sites and plant concepts appear economically attractive. A good natural resource is important, but not the sole determinant of reliable revenues and low integration costs.

Zero curtailment is not automatically an economical planning target. It can be cheaper to limit rare generation peaks than to expand the grid and connection for every conceivable peak. Whether this holds true requires a comparison of the additional infrastructure, flexibility and loss costs. Conversely, a high curtailment share does not in itself prove poor project planning or an altogether superfluous expansion of renewable energy.

Assessment in practice

A careful review combines grid engineering, the yield model, legal basis and payment flows. It should cover at least the following points:

Connection rights: assured feed-in capacity, metering and control point, fixed or variable limitations, temporary restrictions and conditions for a later expansion.
Grid development: known local and upstream congestion, reliable expansion timelines, additional connections and relevant changes in consumption and flexibility.
Yield assumptions: temporal generation profile, cleanly separated loss categories, clear reference bases and coordinated scenarios without double deductions.
Contracts and compensation: basis of claim, allocation of replacement quantities and payments, replacement procurement obligations, evidence requirements and possible settlement delays.
Data and processes: documented instructions, setpoints, measured values, weather and availability data, and clear responsibilities for quantity reconciliation and pursuit of claims.

The result should not consist of a single percentage value alone. More informative are separate expectations for energy not fed in, remaining revenue loss, possible additional costs and liquidity needs. In addition, stress scenarios show how the project reacts to stronger limitations, delayed grid expansion or later compensation payments. This makes visible which risk exists technically and which part actually remains with the project under contracts and law.

What the term explains – and what it does not

Curtailment risk makes clear that several conditions lie between technically possible generation and economically usable feed-in: grid capacity, operational management, connection rights, marketing and compensation. However, it explains neither the coverage of demand when there is little wind and sun nor the overall need for firm capacity or long-term storage. A kilowatt-hour not generated in a surplus hour is not automatically available in a later scarcity hour.

For projects, the central question is therefore not only whether curtailment occurs. What matters is which limitations are to be expected at the specific connection point, how reliable this expectation is, and which economic consequences remain after compensation and contractual allocation. Only this combination allows a sound site assessment, financing and operating decision.

Sources

Energiewirtschaftsgesetz: §§ 13a und 14 — Bundesministerium der Justiz und für Verbraucherschutz; Bundesamt für Justiz; 2026-07-23. § 13a Abs. 1 und 2, insbesondere Ausgleichsbestandteil für erneuerbare Erzeugung; § 14 Abs. 1 bis 1b
Redispatchkosten — Bundesnetzagentur; unbekannt. Abschnitte Redispatch 2.0, Bilanzieller Ausgleich und Finanzieller Ausgleich
§ 8a EEG 2023: Flexible Netzanschlussvereinbarungen — Bundesministerium der Justiz und für Verbraucherschutz; Bundesamt für Justiz; unbekannt. Absätze 1 und 2
§ 51 EEG 2023: Verringerung des Zahlungsanspruchs bei negativen Preisen — Bundesministerium der Justiz und für Verbraucherschutz; Bundesamt für Justiz; unbekannt. Absätze 1 und 2 sowie Anwendungshinweis auf § 100 Abs. 47
Netzengpassmanagement — Bundesnetzagentur; unbekannt. Abschnitte Maßnahmen und Redispatch

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Edited by eCMS on 11.11.2026 13:58