How Electricity Markets Set Prices: Merit Order, Demand and Capacity
Electricity supply and demand must be coordinated continuously while the transmission network remains within physical limits. The cheapest plant or an average generation cost therefore cannot determine every wholesale price at every time and location. A day-ahead market schedules the next operating day from forecasts; a real-time market corrects demand, outage and variable-generation differences. In many organised markets, constrained economic dispatch selects resources and the marginal increment helps set the energy price, while transmission loss and congestion create location differences. This guide separates that short-run price from capacity payments, capacity factor, retail bills and long-run investment return.
Who this guide is for: Readers who want to distinguish wholesale power prices, LMP, gas-fired generation economics, renewable output, capacity factor and retail electricity cost
Key points to understand first
- A wholesale energy price belongs to a delivery interval and location; it is separate from capacity, ancillary services, network charges, policy cost, tax and the final retail bill.
- Merit order dispatches available offers economically subject to constraints. Marginal pay-as-clear designs are widespread, but detailed rules, caps and payment mechanisms vary.
- In an LMP design, energy, marginal transmission losses and congestion create the nodal price, so a line outage or load location can split prices under one generation mix.
- Heat rate measures fuel energy per electrical output and capacity factor measures actual generation relative to a maximum; neither directly equals availability, profit or reliability.
Several market horizons adjust the same delivery day
- Day-ahead Commitment and schedule are formed before delivery
- Intraday Demand, wind, solar and outage forecasts are updated
- Real-time Actual injections, withdrawals and constraints are balanced
Electricity has separate prices for time, location and service
A wholesale electricity energy price represents the value of an incremental MWh at a defined delivery location and interval. Forward, day-ahead, intraday and real-time markets differ by decision horizon. Energy, capacity, reserves and frequency response provide different services. A retail bill can add networks, metering, supplier costs, policy charges and tax, so a wholesale spot spike cannot be passed one-for-one into a household tariff without examining the contract and regulation.
Electricity cannot generally be placed unchanged in a tank for long-duration storage. Generation, storage discharge, imports and demand response must cover load and system losses. Batteries and pumped storage can shift time, but each has energy capacity, power, efficiency, state-of-charge and network limits. A low-cost schedule that violates balance, reserve or security requirements cannot operate, which makes power pricing a flexibility and network problem as well as a fuel-cost problem.
Merit order meets demand with the least-cost feasible set of offers
A simplified merit order ranks available generation, storage and demand-response offers from lower to higher incremental cost and accepts them until demand and reserve needs are satisfied. In a marginal pay-as-clear design, the last required increment can set a common energy price for cleared resources under the rules. That outcome does not assert that every plant has the same lifetime cost. Short-run dispatch and recovery of investment cost are separate questions.
Actual dispatch can include minimum output, start-up cost, minimum run time, ramp rate, reserve capability, emissions, fuel availability, transmission and security constraints. Wind and solar may offer at a low price because fuel cost is near zero, but forecast error, curtailment, network and balancing costs remain. Nuclear and thermal units can also have technical limits that prevent costless switching from one interval to the next.
| Layer | Representative input | Path to price | Common misreading |
|---|---|---|---|
| Incremental energy | Fuel, heat rate, carbon and variable O&M | Offer foundation | It may omit fixed cost |
| Unit commitment | Start, minimum run and ramp | Feasible combination | Plants cannot freely switch every interval |
| System security | Reserve, inertia and voltage | Extra service and constraint | Energy alone does not provide reliability |
| Network | Line limit, loss and outage | Location difference and redispatch | A national average cannot explain a node |
| Market rules | Caps, floors, uplift and settlement | Payment and signal | No universal global design |
Identify the marginal feasible resource for that interval instead of assuming the fuel with the highest general cost always sets price.
Transmission loss and congestion separate location prices
FERC explains that LMP in organised wholesale markets reflects the cost to produce the next unit of energy, electricity lost across the network and transmission congestion. If a line cannot carry more low-cost generation into a load area, the operator may need a more expensive resource on the constrained side, separating nodal prices. A line outage, temperature-dependent rating, generator outage or changing load pattern can therefore change the congestion component even with an unchanged fuel quote.
The day-ahead market creates financially binding schedules from forecast load and resource availability. The real-time market settles deviations caused by actual demand, renewable output, outages and flows. Their price difference can reflect forecast error, risk preference, liquidity, constraint updates and scarcity. A high real-time price does not prove that day-ahead was simply wrong; reconcile the forecast and actual quantities and the network state.
LMP = marginal energy component + marginal loss component + congestion componentDay-ahead deviation = actual metered quantity − day-ahead scheduleTwo-settlement value = day-ahead schedule × DA price + deviation × RT priceSign, loss treatment, uplift, virtual bidding and settlement interval vary by market. This is a conceptual bridge, not an invoice calculation.Heat rate converts gas and carbon into cost per MWh
Heat rate measures the fuel energy used by a generator to produce a net kilowatthour of electricity, often in Btu per kWh. A lower heat rate means less fuel for the same output. The EIA expresses percentage efficiency as 3,412 Btu per kWh divided by heat rate. Actual plant heat rate changes with load, ambient conditions, degradation, starts and auxiliary use, so a nameplate number should not be applied mechanically to every dispatch interval.
Fuel cost per MWh = heat rate in MMBtu/MWh × fuel price per MMBtuCarbon cost per MWh = emissions intensity in tCO2e/MWh × allowance price per tCO2eSimple variable margin = power price − fuel cost − carbon cost − variable O&MThis excludes start cost, minimum load, imbalance, transport basis, capacity payment, fixed O&M, depreciation, hedges and tax.A gas hub and delivered power-plant gas price differ by transport and location basis. Cross-currency analysis adds FX. Use the natural-gas price-drivers guide for physical gas and the carbon-markets guide for allowances and pass-through. The calculator below treats fuel cost and carbon plus variable O&M as already converted inputs.
Separate MW, MWh, capacity factor and availability
MW measures power at an instant, while MWh measures energy through time. Capacity factor divides actual net generation by the maximum generation obtained if the selected capacity ran continuously over the period. A 100 MW annual denominator would use 100 times 8,760 MWh in a non-leap year, but summer or winter net capacity, a capacity change and a partial period require adjustment. High capacity factor establishes that a plant generated frequently; it does not by itself establish efficiency, profit or reliability.
Availability measures whether equipment could operate. Accredited or capacity credit estimates contribution during system risk, and a capacity payment compensates performance under a specific programme. Wind and solar capacity factors reflect resource quality and curtailment; thermal plant factors reflect economics, maintenance, fuel and outages. Compare technologies across energy, flexibility, location, emissions and reliability services rather than ranking them with one utilisation statistic.
Maximum possible generation = selected capacity in MW × hours in periodCapacity factor (%) = actual net generation in MWh ÷ maximum possible generation × 100Average output in MW = actual net generation in MWh ÷ hours in periodState whether the denominator uses nameplate, net summer or net winter capacity and adjust additions or retirements within the period.The physical connection between electrification, grids and metal supply chains is explored in the copper and electrification guide. Do not infer a metal price or corporate profit directly from capacity projections; equipment design, material intensity, recycling and lead time intervene.
Decompose a power price by interval, node and cost in six steps
A reproducible power study starts with the market operator’s official interval data. Preserve market, node or zone, day-ahead or real-time, delivery start and end, time zone and daylight-saving treatment, price components, currency per MWh, and preliminary or final status. Align generation mix, load, renewable forecast, outages, flows, fuel and carbon to the same interval or a documented aggregation. A monthly average can hide the few scarcity intervals driving a result.
- Define the product
Choose energy, capacity, reserve or retail bill and do not mix their prices.
- Fix the time
Record delivery interval, DA or RT, time zone, daylight-saving and revision.
- Fix the location
Retain node, zone, interconnector, loss and congestion components.
- Build the marginal stack
List available resources, fuel, heat rate, carbon, variable O&M and technical limits.
- Test with quantities
Reconcile load, generation, storage, demand response, outages and network flows.
- Bridge to revenue
Separate energy margin, starts, imbalance, capacity, ancillary service and fixed cost.
Use Macro Research Workbench to align demand, fuel, currency and macro observations, then Financial Templates Hub to retain node maps, heat-rate assumptions, daylight-saving treatment, outages and revisions. If electricity is observed through a financial product, separately verify the reference market, contract size and settlement using the contract-specification guide.
Simple generation variable margin
Subtract heat-rate-based fuel cost and carbon plus variable O&M from a wholesale power price.
Fictional educational calculation. It excludes start and shutdown, minimum load, ramps, imbalance, transmission, capacity and ancillary revenue, fixed O&M, depreciation, hedges and tax. It does not guarantee dispatch or plant profit; a percentage cannot be calculated when power price is zero.
Frequently asked questions
What is the electricity merit order?
It is the economic selection of available generation, storage and demand response from lower to higher incremental offers subject to demand and system constraints. Starts, ramps, reserves and transmission complicate the simple stack, and payment rules vary.
Does a natural gas price increase raise power prices by the same percentage?
Not necessarily. Pass-through depends on whether gas is marginal, the heat rate and delivered gas basis, carbon, other available generation, demand and transmission congestion.
Does a high capacity factor mean a power plant is efficient?
Capacity factor measures actual generation relative to maximum possible generation over a period. Fuel efficiency is measured with heat rate and availability is a separate concept, so utilisation alone does not establish efficiency or profit.
Is the wholesale electricity price the same as a household bill?
No. A retail bill can add network, supplier, policy, metering and tax components, while fixed, variable and dynamic contracts transmit wholesale prices differently and with different timing.
Primary sources and verification links
- FERC | Understanding Energy MarketsDay-ahead and real-time markets, economic dispatch, and energy, loss and congestion in LMP
- FERC | Introductory Guide to Electricity MarketsPrimary guide to RTO and ISO energy markets and transmission congestion
- European Commission | Electricity market designEU marginal pay-as-clear pricing, integration and flexibility
- U.S. EIA | Factors affecting electricity pricesFuel, generation, transmission, distribution, weather and regulation
- U.S. EIA | Power plant efficiency and heat rateHeat rate, net generation and the 3,412 Btu/kWh efficiency relationship
- U.S. EIA | Capacity and capacity factorNameplate and net capacity, MW and MWh, and capacity factor
Edited and published by: SG Group · Editorial approach: We prioritize primary materials from the EIA, IEA, OPEC, exchanges, system operators and regulators, while separating physical quantities, delivery points, contract units and publication dates. Statistics, rules and contract specifications can change, so verify current information at the linked source and with your provider before acting.
Important notice: This article provides general education about energy markets. It is not investment advice, a product recommendation, a trading signal or a price forecast. Figures, contracts and calculations are fictional learning examples. Physical quality, delivery point, contract multiplier, expiry, margin, fees, tax, currency, regulation and trading hours vary by instrument, venue, provider, jurisdiction and date. Verify current exchange specifications, regulator and statistical-agency publications, and your provider’s terms before making a trading or business decision.