Economic Dispatch · Glossary

Economic dispatch refers to the cost-optimised allocation of electricity generation among available power plants, storage facilities and controllable assets. The aim is to meet a given electricity demand at a specific point in time. It is not about which power plants should be built. It is about which existing assets are used, and to what extent, in ongoing operation. The term therefore describes an operational decision in the power system: Which megawatts are deployed, in what order, at what cost and under which technical constraints?

A frequently cited statutory definition comes from the United States. Section 1234 of the Energy Policy Act of 2005 describes economic dispatch, in essence, as the operation of generation facilities to supply consumers reliably and at the lowest cost while respecting the operational limits of generation and transmission facilities. This definition formally applies only under US law. However, it summarises well what the term also means in Europe: minimising costs without giving up reliability and technical limits.

The central quantity in economic dispatch is power, usually in megawatts. The dispatch determines how much electrical power each asset provides in a market and operating interval. In European day-ahead market coupling (SDAC), this has been the quarter-hour since the delivery day of 1 October 2025; before that it was the hour. Over time, this yields the amount of energy generated in megawatt-hours or kilowatt-hours. This distinction matters. A power plant with low variable costs must not only be able to generate cheaply, but also be available at the right time. Economic dispatch is therefore a deployment decision for a specific point in time and not an annual balance.

Basic principle and simplified example

In greatly simplified terms, power plants are sorted by their variable costs. Assets with low short-term generation costs run first, while more expensive assets cover the additional demand. This sorting is closely linked to the merit order. For conventional power plants, variable costs consist mainly of fuel costs, CO₂ costs and variable operating and maintenance costs, with further levies added in some cases. Wind and solar power have very low short-term marginal costs because no fuel is consumed. For storage, it is not only the direct operating costs that count. What also matters is the value the stored energy would have at a later time, the so-called opportunity value.

A purely fictitious numerical example: Plant A can supply 400 MW at 5 euros per MWh, plant B 300 MW at 60 euros per MWh and plant C 500 MW at 110 euros per MWh. With a demand of 900 MW, A and B run at full output and C supplies the remaining 200 MW. The last megawatt-hour dispatched then costs 110 euros. In a marginal-price market, this plant would set the price. Behind this lies a mathematical optimisation problem: without limits and with continuously rising cost curves, the assets are deployed so that their additional costs per megawatt-hour are equal. Exceptions are assets that are running at full capacity or not running at all. In practice, technical and grid-related limits shift this result.

Economic dispatch must not be confused with power plant planning. Power plant planning concerns investments, locations, capacity needs and long-term security of supply. Economic dispatch works with the existing fleet of assets. The term marginal costs is also narrower. Marginal costs are the costs of one additional unit generated. Economic dispatch describes the resulting order of deployment under technical and organisational conditions. Likewise, economic dispatch is not the same as the electricity price. A market price can arise from the order of deployment. However, it reflects only the costs and scarcities that the market rules actually take into account.

Distinction from merit order, unit commitment and redispatch

The merit order is a sorting logic, whereas economic dispatch is the concrete deployment decision. The difference becomes important as soon as technical limits come into play. Power plants cannot ramp up and down arbitrarily fast. Many thermal plants have minimum loads, start-up times and start-up costs. Gas turbines and many gas engines generally respond faster than large coal or nuclear power plant units. For combined-cycle gas plants, flexibility depends strongly on design and operating state. Hydropower plants are tied to inflows, reservoir levels and ecological requirements. Battery storage responds very quickly, but is limited by energy content, state of charge and ageing through charge cycles.

One step earlier lies unit commitment. This determines which power plant units are switched on and kept ready in the first place. A unit with a start-up time of several hours cannot be deployed in the same way as a battery or a gas turbine. Unit commitment therefore concerns the operational readiness and availability of individual units. Economic dispatch then allocates output among the running units. In many practical models, both decisions are optimised jointly. Conceptually, however, they remain distinguishable.

Economic dispatch differs from redispatch in its view of the grid. A dispatch in the market may appear cost-optimal for a bidding zone but cannot be fully transmitted physically. If electricity is generated cheaply in the north and consumed in the south, lines can become overloaded. Grid operators then curtail assets upstream of the bottleneck and ramp up others downstream of it. In Germany, this is governed by § 13a EnWG. Operators of generation and storage facilities with a rated capacity of 100 kW or more, as well as of facilities that can be remotely controlled at any time, must adjust their active or reactive power at the request of the transmission system operator or tolerate such adjustment. In return they receive balancing-related and financial compensation. Redispatch corrects the planned deployment so that the grid can be operated safely. Costs usually rise as a result, because it is no longer only the price of generation that counts, but also its location.

In centrally managed markets, such as those of many US grid operators, grid limits are built directly into the optimisation. This is called security-constrained economic dispatch (SCED). It means a dispatch that observes all normal grid limits and can also cope with the failure of an important grid element (n-1 criterion). In the European zonal logic, by contrast, this grid check is largely handled downstream through redispatch.

Why the term matters in the electricity market

Economic dispatch shows that electricity supply means constant coordination. Installed capacity alone says little about which assets actually generate electricity. A power plant may exist and still hardly run because of high fuel costs. A photovoltaic system generates very cheaply, but only when the sun shines. A storage facility can only deliver power if it has previously absorbed energy. In power plant dispatch, technical availability, costs, demand and market rules come together.

In liberalised electricity markets such as in the EU, usually no central body orders the dispatch in full. Market participants sell and buy electricity and draw up schedules. Together with the management of balancing groups, the day-ahead market and intraday trading lead to a planned deployment. This is guided by prices, expectations and technical limits. The European day-ahead market coupling also allocates transmission capacity between bidding zones using a common algorithm. In models, however, people still often speak of economic dispatch, because the market rules are meant to achieve a cost-based order of deployment at least approximately. Deviations arise mainly from the fact that the market area, grid operation, balancing group responsibility and balancing energy are organised separately.

The term is also important for assessing renewable energy. When wind and sun are available, they often displace power plants with higher short-term costs. In many hours this lowers the exchange price and reduces the operating hours of conventional power plants. However, this does not make the other power plants superfluous. When there is little wind and sun or demand is high, controllable assets, storage, load shifting or imports must cover the residual load. Economic dispatch shows which assets are needed in which hour, and not just which technology supplies a lot of energy on an annual average.

Typical misinterpretations

Simple ranking: Economic dispatch is often understood as a mere list from cheap to expensive. This list explains part of the market but leaves out technical limits. Because of high start-up costs, it may be worthwhile not to start a power plant for a short period of operation despite low variable costs. Because of minimum loads, assets sometimes keep running even though the price is temporarily low. Ramp rates limit how quickly generation can adapt to demand or fluctuating feed-in. Reserve requirements tie up capacity that then cannot be offered in full on the energy market.
Low marginal costs equal low total costs: Economic dispatch considers only short-term operating costs. Investments, grid expansion, provision of firm capacity, ancillary services, connection costs and hedging against rare scarcities lie largely outside this optimisation. An asset with low marginal costs can have high investment costs. An asset with high marginal costs can be very valuable for a few hours a year if it covers bottlenecks or peak loads. The short-term order of deployment therefore does not replace an analysis of system costs.
Forgetting the location of generation: Within a uniform bidding zone, the market behaves as if every kilowatt-hour fed in could reach every consumer without a bottleneck. Physically, however, electricity distributes itself according to the electrical properties of the grid. In the case of grid bottlenecks, a purely market-based dispatch is not the same as a grid-compatible power plant deployment. This becomes particularly clear when a lot of renewable electricity is generated far from consumption centres. The same applies when power plants at grid-supportive locations rarely run for economic reasons.
Negative prices explained wrongly: Negative electricity prices do not mean that electricity is worthless. They arise when the market can hardly absorb additional feed-in in an interval. Suppliers are then willing to pay for offtake or want to avoid revenue losses elsewhere. Technical minimum loads, support rules, heat extraction, balancing group positions and limited flexibility contribute to this. Economic dispatch helps in analysing such situations, but only together with the respective market rules and technical constraints.

Connection with flexibility and security of supply

The more electricity is generated in a weather-dependent way, the less a pure fuel cost comparison counts and the more the ability to adapt over time counts. Flexibility becomes an operating characteristic in its own right. Assets, storage and consumers differ not only in costs. They also differ in response speed, availability, duration of provision and restrictions arising from their processes. A heat pump, an electrolyser, a battery storage system or an industrial process can influence the dispatch if consumption is shifted to hours with low prices. The demand side thus also becomes part of deployment optimisation.

Economic dispatch does not guarantee security of supply, but it makes it concrete in real-time operation. The dispatch can only use resources that exist, are available and are controllable. If there is a long-term lack of firm capacity, storage, grid capacity or flexible demand, short-term optimisation cannot make up for it. It can only manage the shortage as efficiently as possible. This marks an important limit of the term: economic dispatch explains the operation of the existing system, but not whether it is sufficiently equipped.

Institutionally, several actors are involved. Market participants optimise according to prices and the limits of their own assets. Transmission system operators ensure frequency, grid stability and congestion management. Regulatory authorities set rules for grid access, balancing energy, redispatch costs and market design. Political decisions influence fuel costs, CO₂ prices, support schemes, capacity instruments and grid expansion. The actual power plant deployment arises from this interplay and not from a technical calculation rule alone.

Economic dispatch is thus a precise term for the short-term organisation of electricity generation and controllable consumption under cost and operating conditions. It shows why the same demand can be met in very different ways depending on weather, fuel prices, grid situation, storage levels and market rules. The term is meaningful, however, only if it is clear which costs are included and which technical limits apply. It must also be clear whether a dispatch based on market results, a grid-related dispatch or a system-wide dispatch is meant.

Sources

The Value of Economic Dispatch: A Report to Congress Pursuant to Section 1234 of the Energy Policy Act of 2005 — U.S. Department of Energy; 2005-11-07. Section 1 und Section 2 (What is Economic Dispatch?), Verweis auf EPAct 2005 Sec. 1234(b)
Energy Policy Act of 2005, P.L. 109-58: Electricity Provisions (RL33248) — Congressional Research Service (über EveryCRSReport.com); unbekannt. Abschnitte zu Sec. 1234 und Subtitle J – Economic Dispatch (Sec. 1298)
15 Minute MTU Implemented in SDAC — Nord Pool (für die SDAC-Projektparteien); 2025-10-01. Meldung und Abschnitt About SDAC
Gesetz über die Elektrizitäts- und Gasversorgung (Energiewirtschaftsgesetz – EnWG) — Bundesministerium der Justiz / juris; unbekannt. § 13a (Erzeugungsanpassung und ihr bilanzieller und finanzieller Ausgleich), Abs. 1; Absatz (2a) mit Verweis auf § 13a Abs. 1

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Edited by eCMS on 11.11.2026 19:42