In a broad sense, an electricity market is a system that facilitates the exchange of electricity-related goods and services. During more than a century of evolution of the electric power industry, the economics of the electricity markets had undergone enormous changes for reasons ranging from the technological advances on supply and demand sides to politics and ideology. A restructuring of electric power industry at the turn of the 21st century involved replacing the vertically integrated and tightly regulated "traditional" electricity market with multiple competitive markets for electricity generation, transmission, distribution, and retailing. The traditional and competitive market approaches loosely correspond to two visions of industry: the deregulation was transforming electricity from a public service (like sewerage) into a tradable good (like crude oil). As of 2020s, the traditional markets are still common in some regions, including large parts of the United States and Canada.
The initial idea of a simple wholesale electricity market restructuring ("energy-only", replacing the regulated electricity price with the market-defined one) did not work out, thus the competitive wholesale electricity market structure is quite complex and typically includes (in addition to two markets for the electricity itself: wholesale – all of these use offer caps in some form – and retail):
The competitive retail electricity markets were able to maintain their simple structure.
In addition, for most major operators, there are markets for transmission rights and electricity derivatives such as electricity futures and options, which are actively traded.
The market externality of greenhouse gas emissions is sometimes dealt with by carbon pricing.
Electricity market is characterized by unique features that are absent in a typical commodity or consumption goods market. These peculiarities make the electricity market fundamentally incomplete.
Electricity is by its nature difficult to store and has to be available on demand. Consequently, unlike other products, it is not possible, under normal operating conditions, to keep it in stock, ration it or have customers queue for it, so the supply shall match the demand very closely at any time despite the continuous variations of both (so called grid balancing). Frequently, the only safety margins are the ones provided by the kinetic energy of the physically rotating machinery (synchronous generators and turbines). If there is a mismatch between supply and demand the generators absorb extra energy by speeding up or produce more power by slowing down causing the utility frequency (either 50 or 60 hertz) to increase or decrease. However, the frequency cannot deviate too much from the target: many units of the electrical equipment can be destroyed by the out-of-bounds frequency and thus will automatically disconnect from the grid to protect themselves, potentially triggering a blackout.
There are many other physical and economic constraints affecting the electricity network and the market, with some creating non-convexity:
The design of transmission network limits the amount of electricity that can be transmitted from one tighly-coupled area ("node") to another, so a generator in one node might be unable to service a load in another node (due to "transmission congestion"), potentially creating fragments of the market that have to be served with local generation ("load pockets").
After its first few years of existence, the electricity supply industry was regulated by the various levels of government. By the 1950s, a wide variety of arrangements had evolved with substantial differences between countries and even at the regional level, for example:
These diverse structures had a few unifying features: very little reliance on competitive markets, no formal wholesale markets, and customers unable to choose their suppliers.
The diversity and sheer size of the US market made the potential trade gains large enough to justify some wholesale transactions:
On the retail side, customers were charged fixed regulated prices that did not change with marginal costs, retail tariffs almost entirely relied on volumetric pricing (based on the meter readings recorded monthly), and fixed cost recovery was included into the per-kWh price.
The traditional market arrangement was designed for the state of the electric industry common pre-restructuring (and still common in some regions, including large parts of the US and Canada). Schmalensee[who?] calls this state historical (as opposed to post-restructuring emerging one). In the historical regime almost all generation sources can be considered dispatchable (available on demand, unlike the emerging variable renewable energy).
Chile had become a pioneer in deregulation in the early 1980s (the law of 1982 had codified the changes that were started in 1979). Only few years later the new market approach to electricity was formulated in the US, popularized in the influential work by Joskow and Schmalensee, "Markets for Power: An Analysis of Electrical Utility Deregulation" (1983). At the same time in the UK, Energy Act of 1983 made provisions for common carriage in the electricity networks, enabling a choice of supplier for electricity boards and very large customers (analogous to "wheeling" in the US).
A wholesale electricity market, also power exchange or PX, is a system enabling purchases, through bids to buy; sales, through offers to sell. Bids and offers use supply and demand principles to set the price. Long-term contracts are similar to power purchase agreements and generally considered private bi-lateral transactions between counterparties.
A wholesale electricity market exists when competing generators offer their electricity output to retailers. The retailers then re-price the electricity and take it to market. While wholesale pricing used to be the exclusive domain of large retail suppliers, increasingly markets like New England are beginning to open up to end-users. Large end-users seeking to cut out unnecessary overhead in their energy costs are beginning to recognize the advantages inherent in such a purchasing move. Consumers buying electricity directly from generators is a relatively recent phenomenon.
Buying wholesale electricity is not without its drawbacks (market uncertainty, membership costs, set up fees, collateral investment, and organization costs, as electricity would need to be bought on a daily basis), however, the larger the end user's electrical load, the greater the benefit and incentive to make the switch.
For an economically efficient electricity wholesale market to flourish it is essential that a number of criteria are met, namely the existence of a coordinated spot market that has "bid-based, security-constrained, economic dispatch with nodal prices". These criteria have been largely adopted in the US, Australia, New Zealand and Singapore.
Markets for power-related commodities required and managed by (and paid for by) market operators to ensure reliability, are considered ancillary services and include such names as spinning reserve, non-spinning reserve, operating reserves, responsive reserve, regulation up, regulation down, and installed capacity.
Wholesale transactions (bids and offers) in electricity are typically cleared and settled by the market operator or a special-purpose independent entity charged exclusively with that function. Market operators do not clear trades but often require knowledge of the trade in order to maintain generation and load balance.
Markets for electricity trade net generation output for a number of intervals usually in increments of 5, 15 and 60 minutes. Depending on the market design, the market operator can either:
The clearing can use two arrangements:
Generally, it is assumed that with MPS, in the absence of collusion, the producers will bid close to their short run marginal cost to avoid the risk of missing out altogether. MPS is also more transparent, as the new bidder already knows the market price and can estimate the profitability with his marginal cost, in order to do well with the PAB, the bidder needs information about other bids, too. Due to higher risks of the PAB, it gives an extra advantage to the large players that are better equipped to estimate the market and take the risk (for example, by gambling with a high bid for some of their units). Still, the high electricity prices trigger the calls in politics to switch to PAB in order for consumers not to overpay producer with lower costs, with counterargument being that doing so will simply incentivize the lower-cost producers to bid higher.
To handle all the constraints while keeping the system in balance, a central agency, the transmission system operator (TSO), is required to coordinate the unit commitment and economic dispatch. If the frequency falls outside a predetermined range the system operator will act to add or remove either generation or load.
Unlike the real-time decisions that are necessarily centralized, the electricity market itself can be centralized or decentralized. In the centralized market the TSO decides which plant should run and how much is it supposed to produce way before the delivery (during the "spot market" phase, or day-ahead operation). In a decentralized market the producer only commits to the delivery of electricity, but the means to do that are left to the producer itself (for example, it can enter the agreement with another producer to provide the actual energy). Centralized markets make it easier to accommodate non-convexities, while the decentralized allow intra-day trading to correct the possibly suboptimal decisions made day-ahead, for example, accommodating improved weather forecasts for renewables. Due to the difference in the grid construction (US had weaker transmission networks), the design of wholesale markets in the US and Europe had diverged, even though initially the US was followed the European (decentralized) example.
To accommodate the transmission network constraints centralized markets typically use locational marginal pricing (LMP) where each node has its own local market price (thus another name for the practice, nodal pricing). Political considerations sometimes make it unpalatable to force consumers in the same territory, but connected to different nodes, to pay different prices for electricity, so a modified generator nodal pricing (GNP) model is used: the generators are still being paid the nodal prices, while the load serving entities are charging the end users prices that are averaged over the territory. Many decentralized markets do not use the LMP and have a price established over a geographic area ("zone", thus the name zonal pricing) or a "region" (regional pricing, the term is used primarily for very large zones of the National Electricity Market of Australia, where five regions cover the continent).
In the beginning of 2020s there was no clear preference for any of the two market designs, for example, the North American markets went through centralization, while the European ones moved in the opposite direction: 
|Day-ahead market||Nodal pricing|
|Texas (ERCOT)||Centralized (since 2010)||Yes (GNP)|
|Midwest ISO (MISO)||Centralized||Yes|
|ISO New England||Centralized||Yes (GNP)|
|Nord Pool||Decentralized||No (zonal)|
|Great Britain||Decentralized (since 2001)||No|
|Ireland||Decentralized (since 2018)||No (zonal)|
|NEM, Australia||Decentralized||No (regional)|
A transmission system operator in a centralized electricity market obtains the cost information (usually three components: start-up costs, no-load costs, marginal production costs) for each unit of generation ("unit-based bidding") and makes all the decisions in the day-ahead and real-time (system redispatch) markets. This approach allows the operator to take into consideration the details of the configuration of the transmission system. The centralized market normally uses the LMP, and the dispatch goal is minimizing the total cost in each node[clarification needed] (which in a large network count in hundreds or even thousands). The centralized markets use some procedures resembling the vertically integrated electric utilities of the era before the deregulation, so the centralized markets are also called integrated electricity markets.
Due to the centralized and detailed nature of the day-ahead dispatch, it stays feasible and cost-efficient at the time of delivery, unless some unexpected adverse events occur. Early decisions help to efficiently schedule the plants with the long ramp-up times.
The drawbacks of the centralized design with LMP are:
Price of a unit of electricity with LMP is based on the marginal cost, so the start-up and no-load costs are not included. Centralized markets therefore typically pay a compensation for these costs to the producer (so called make-whole or uplift payments), financed in some way by the market participants (and, ultimately, the consumers).
Inflexibility of the centralized market manifests itself in two ways:
Market clearing algorithms are complex (some are NP-complete) and have to be executed in limited time (5–60 minutes). The results are thus not necessarily optimal, are hard to replicate independently, and require the market participants to trust the operator (due to the complexity sometimes a decision by the algorithm to accept or reject the bid appears entirely arbitrary to the bidder).
If the transmission system operator owns the actual transmission network, it would be incentivized to profit by increasing the congestion rents. Thus in the US the operator typically does not own any capacity and is frequently called an independent system operator (ISO).
The higher degree of centralization of the market involves the direct cost calculations by the market operator (producers no longer submit bids). Despite the obvious problem with generation companies incentivized to inflate their costs (this can be hidden through transactions with affiliated companies), this cost-based electricity market arrangement eliminates the market power of the providers and is used in situation when an abuse of market power is possible (e. g., Chile with its preponderance of hydro power, in the US when the local market power is sufficiently high, some European markets[which?]). A less-obvious issue is the tendency of market participants under these conditions to concentrate on investments in the peaker plants to the detriment of the baseload power. One of the advantages of the cost-based market is the relatively low cost to set it up. The cost-based approach is popular in Latin America: in addition to Chile, it is used in Bolivia, Peru, Brazil, and countries in Central America.
A system operator performs an audit of parameters of each generator unit (including heat rate, minimum load, ramping speed, etc.) and estimates the direct marginal costs of its operation. Based on this information, an hour-by-hour dispatch schedule is put in place to minimize the total direct cost. In the process, the hourly shadow prices are obtained for each node that might be used to settle the market sales.
Decentralized markets allow the generation companies to choose their own way to provide energy for their day-ahead bid (that specifies price and location). The provider can use any unit at its disposal (so called "portfolio-based bidding") or even pay another company to deliver the energy. The market still has the central operator that exclusively controls the system in real-time, but with significantly diminished powers to intervene ahead of delivery (frequently just the ability to schedule the transmission network for day-ahead operation). This arrangement makes operator's ownership of the transmission capacity less of an issue, and European countries, with the exception of UK, permit it (following the independent transmission system operator or ITSO model).
While some operators in Europe are involved in structuring the day-ahead and intra-day markets, the other ones are not. For example, the UK market after the New Electricity Trading Arrangements in UK and the market in New Zealand let the markets sort out all the frictions before real-time. This reliance on financial instruments leads to the additional names for the decentralized markets: exchange-based, unbundled, bilateral.
The system price in the day-ahead market is, in principle, determined by matching offers from generators to bids from consumers at each node to develop a classic supply and demand equilibrium price, usually on an hourly interval, and is calculated separately for subregions in which the system operator's load flow model indicates that constraints will bind transmission imports.
The theoretical prices of electricity at each node on the network is a calculated "shadow price", in which it is assumed that one additional kilowatt-hour is demanded at the node in question, and the hypothetical incremental cost to the system that would result from the optimized redispatch of available units establishes the hypothetical production cost of the hypothetical kilowatt-hour. This is known as locational marginal pricing (LMP) or nodal pricing and is used in some deregulated markets, most notably in the Midcontinent Independent System Operator (MISO), PJM Interconnection, ERCOT, New York, and ISO New England markets in the United States, New Zealand, and in Singapore.
In practice, the LMP algorithm described above is run, incorporating a security-constrained (defined below), least-cost dispatch calculation with supply based on the generators that submitted offers in the day-ahead market, and demand based on bids from load-serving entities draining supplies at the nodes in question.
Due to various non-convexities present in wholesale electricity markets, in the form of economies of scale, start-up and/or shut-down costs, avoidable costs, indivisibilities, minimum supply requirements, etc., some suppliers may incur losses under LMP, e.g., because they may fail to recover their fixed cost through commodity payments only. To address this problem, various pricing schemes that lift the price above marginal cost and/or provide side-payments (uplifts) have been proposed. Liberopoulos and Andrianesis (2016) review and compare several of these schemes on the price, uplifts, and profits that each scheme generates.
While in theory the LMP concepts are useful and not evidently subject to manipulation, in practice system operators have substantial discretion over LMP results through the ability to classify units as running in "out-of-merit dispatch", which are thereby excluded from the LMP calculation. In most systems, units that are dispatched to provide reactive power to support transmission grids are declared to be "out-of-merit" (even though these are typically the same units that are located in constrained areas and would otherwise result in scarcity signals). System operators also normally bring units online to hold as "spinning-reserve" to protect against sudden outages or unexpectedly rapid ramps in demand, and declare them "out-of-merit". The result is often a substantial reduction in clearing price at a time when increasing demand would otherwise result in escalating prices.
Researchers have noted that a variety of factors, including energy price caps set well below the putative scarcity value of energy, the effect of "out-of-merit" dispatch, the use of techniques such as voltage reductions during scarcity periods with no corresponding scarcity price signal, etc., results in a missing money problem. The consequence is that prices paid to suppliers in the "market" are substantially below the levels required to stimulate new entry. The markets have therefore been useful in bringing efficiencies to short-term system operations and dispatch, but have been a failure in what was advertised as a principal benefit: stimulating suitable new investment where it is needed, when it is needed.
In LMP markets, where constraints exist on a transmission network, there is a need for more expensive generation to be dispatched on the downstream side of the constraint. Prices on either side of the constraint separate giving rise to congestion pricing and constraint rentals.
A constraint can be caused when a particular branch of a network reaches its thermal limit or when a potential overload will occur due to a contingent event (e.g., failure of a generator or transformer or a line outage) on another part of the network. The latter is referred to as a security constraint. Transmission systems are operated to allow for continuity of supply even if a contingent event, like the loss of a line, were to occur. This is known as a security constrained system.
In most systems the algorithm used is a "DC" model rather than an "AC" model, so constraints and redispatch resulting from thermal limits are identified/predicted, but constraints and redispatch resulting from reactive power deficiencies are not. Some systems take marginal losses into account. The prices in the real-time market are determined by the LMP algorithm described above, balancing supply from available units. This process is carried out for each 5-minute, half-hour or hour (depending on the market) interval at each node on the transmission grid. The hypothetical redispatch calculation that determines the LMP must respect security constraints and the redispatch calculation must leave sufficient margin to maintain system stability in the event of an unplanned outage anywhere on the system. This results in a spot market with "bid-based, security-constrained, economic dispatch with nodal prices".
Further information: New Zealand electricity market
Many established markets do not employ nodal pricing, examples being the UK, EPEX SPOT (most European countries), and Nord Pool Spot (Nordic and Baltic countries).
Financial risk management is often a high priority for participants in deregulated electricity markets due to the substantial price and volume risks that the markets can exhibit. A consequence of the complexity of a wholesale electricity market can be extremely high price volatility at times of peak demand and supply shortages. The particular characteristics of this price risk are highly dependent on the physical fundamentals of the market such as the mix of types of generation plant and relationship between demand and weather patterns. Price risk can be manifest by price "spikes" which are hard to predict and price "steps" when the underlying fuel or plant position changes for long periods.
Volume risk is often used to denote the phenomenon whereby electricity market participants have uncertain volumes or quantities of consumption or production. For example, a retailer is unable to accurately predict consumer demand for any particular hour more than a few days into the future and a producer is unable to predict the precise time that they will have plant outage or shortages of fuel. A compounding factor is also the common correlation between extreme price and volume events. For example, price spikes frequently occur when some producers have plant outages or when some consumers are in a period of peak consumption. The introduction of substantial amounts of intermittent power sources such as wind energy may affect market prices.
Electricity retailers, who in aggregate buy from the wholesale market, and generators who in aggregate sell to the wholesale market, are exposed to these price and volume effects and to protect themselves from volatility, they will enter into "hedge contracts" with each other. The structure of these contracts varies by regional market due to different conventions and market structures. However, the two simplest and most common forms are simple fixed price forward contracts for physical delivery and contracts for differences where the parties agree a strike price for defined time periods. In the case of a contract for difference, if a resulting wholesale price index (as referenced in the contract) in any time period is higher than the "strike" price, the generator will refund the difference between the "strike" price and the actual price for that period. Similarly a retailer will refund the difference to the generator when the actual price is less than the "strike price". The actual price index is sometimes referred to as the "spot" or "pool" price, depending on the market.
Many other hedging arrangements, such as swing contracts,[clarification needed] virtual bidding, Financial Transmission Rights,[clarification needed] call options and put options are traded in sophisticated electricity markets. In general they are designed to transfer financial risks between participants.
Due to high gas prices because of the 2022 Russia–European Union gas dispute, in late 2022 the EU capped non-gas power prices at 180 euros per megawatt hour and the UK is considering price capping. Fossil fuels, especially gas, may be price capped higher than renewables, with revenue above the cap subsidizing some consumers, as in Turkey. Academic study of an earlier price cap in that market concluded that it reduced welfare, and another study said that an EU-wide price cap would risk "a never-ending spiral of higher import prices and higher subsidies". It has been academically argued via game theory that a cap on the price of imported Russian gas (some of which is used to generate electricity) could be beneficial, however politically this is difficult.
See also: Spot contract, List of commodities exchanges, and Regulation on Wholesale Energy Market Integrity and Transparency
An electric power exchange is a commodities exchange dealing with electric power:
Electricity itself, or products made with a lot of electricity, exported to another country may be charged a carbon tariff if the exporting country has no carbon price: for example as the UK has the UK ETS it would not be charged the EU Carbon Border Adjustment Mechanism whereas Turkey has no carbon price so might be charged.
Rather than the traditional merit order based on cost, when there is excess generation ramping down the plants which most damage health has been suggested. Due to the growth of renewables and the 2021–2022 global energy crisis some countries are considering changing their electricity markets. For example some Europeans suggest decoupling electricity prices from natural gas prices.
Main article: Electricity retailing
A retail electricity market exists when end-use customers can choose their supplier from competing electricity retailers; one term used in the United States for this type of consumer choice is 'energy choice'. A separate issue for electricity markets is whether or not consumers face real-time pricing (prices based on the variable wholesale price) or a price that is set in some other way, such as average annual costs. In many markets, consumers do not pay based on the real-time price, and hence have no incentive to reduce demand at times of high (wholesale) prices or to shift their demand to other periods. Demand response may use pricing mechanisms or technical solutions to reduce peak demand.
Generally, electricity retail reform follows from electricity wholesale reform. However, it is possible to have a single electricity generation company and still have retail competition. If a wholesale price can be established at a node on the transmission grid and the electricity quantities at that node can be reconciled, competition for retail customers within the distribution system beyond the node is possible. In the German market, for example, large, vertically integrated utilities compete with one another for customers on a more or less open grid.
Although market structures vary, there are some common functions that an electricity retailer has to be able to perform, or enter into a contract for, in order to compete effectively. Failure or incompetence in the execution of one or more of the following has led to some dramatic financial disasters:
The two main areas of weakness have been risk management and billing. In the United States in 2001, California's flawed regulation of retail competition led to the California electricity crisis and left incumbent retailers subject to high spot prices but without the ability to hedge against these. In the UK a retailer, Independent Energy, with a large customer base went bust when it could not collect the money due from customers.
Competitive retail needs open access to distribution and transmission wires. This in turn requires that prices must be set for both these services. They must also provide appropriate returns to the owners of the wires and encourage efficient location of power plants. There are two types of fees, the access fee and the regular fee. The access fee covers the cost of having and accessing the network of wires available, or the right to use the existing transmission and distribution network. The regular fee reflects the marginal cost of transferring electricity through the existing network of wires.
New technology is available and has been piloted by the US Department of Energy that may be better suited to real-time market pricing. A potential use of event-driven SOA (service-oriented architecture) could be a virtual electricity market where home clothes dryers can bid on the price of the electricity they use in a real-time market pricing system. The real-time market price and control system could turn home electricity customers into active participants in managing the power grid and their monthly utility bills. Customers can set limits on how much they would pay for electricity to run a clothes dryer, for example, and electricity providers willing to transmit power at that price would be alerted over the grid and could sell the electricity to the dryer.
On one side, consumer devices can bid for power based on how much the owner of the device were willing to pay, set ahead of time by the consumer. On the other side, suppliers can enter bids automatically from their electricity generators, based on how much it would cost to start up and run the generators. Further, the electricity suppliers could perform real-time market analysis to determine return-on-investment for optimizing profitability or reducing end-user cost of goods. The effects of a competitive retail electricity market are mixed across states, but generally appear to lower prices in states with high participation and raise prices in states that have little customer participation.
Event-driven SOA software could allow homeowners to customize many different types of electricity devices found within their home to a desired level of comfort or economy. The event-driven software could also automatically respond to changing electricity prices, in as little as five-minute intervals. For example, to reduce the home owner's electricity usage in peak periods (when electricity is most expensive), the software could automatically lower the target temperature of the thermostat on the central heating system (in winter) or raise the target temperature of the thermostat on the central cooling system (in summer).
Comparisons between the traditional and competitive market designs experience have provide mixed results. The US experience where the deregulated utilities operate alongside the vertically integrated ones, there is some evidence of the increased efficiencies:
Schmalensee concludes that it is plausible that the restructuring resulted in lower wholesale prices, at least in the US and the UK. MacKay and Mercadal in a large-scale analysis of the US market between 1994 and 2016, while confirming Schmalensee's findings on lower costs, reached the opposite conclusion on the prices: deregulated utilities realized significantly higher prices due to higher markup of the generation facilities and double extraction of the profit margin by the two vertically separated companies.
Regarding resource adequacy, the US market at the start of restructuring had excess generating capacity, confirming the expectation that regulated prices provide an incentive for the generators to overinvest. Initial hope that the revenue stream would be sufficient to continue building up the capacity did not materialize: faced with abuse of market power, all US markets introduced wholesale price caps that in many case were much lower than the value of lost load thus creating the "missing money problem" (capping revenue at the time of relatively infrequent shortages causes the shortage of money to build the infrastructure that is only used during these shortages); the problem of over-investment was replaced by underinvestment, dragging down the grid reliability. In response, major transfer payments for capacity were instituted (in the US in 2018 the payments were getting as high as 47% of the new unit's revenue). EU markets followed the American lead in the 2010s. Schmalensee notes that while the process of determining the amount of compensation for new capacity in the US is in principle similar to the integrated resource planning of the traditional markets, the new version is less transparent and provides less certainty due to frequent rule changes (the traditional scheme guaranteed the cost recovery), so an efficiency improvement in this area is unlikely.
The introduction of the choice of supplier and variable pricing in the retail market was enthusiastically supported by larger consumers (businesses) that can employ the time of consumption-shifting techniques to benefit from the time-of-use pricing and have access to hedging against very high prices. Acceptance among residential customers in the US was minimal.
Many regional markets have achieved some success, and the ongoing trend continues to be towards deregulation and introduction of competition. However, in 2000/2001 major failures such as the California electricity crisis and the Enron debacle caused a slow down in the pace of change and in some regions an increase in market regulation and reduction in competition. However, this trend is widely regarded as a temporary one against the longer term trend towards more open and competitive markets.
Notwithstanding the favorable light in which market solutions are viewed conceptually, the "missing money" problem has to date proved intractable. If electricity prices were to move to the levels needed to incentivize new merchant (i.e., market-based) transmission and generation, the costs to consumers would be politically difficult.
The increase in annual costs to consumers in New England alone were calculated at $3 billion during the recent[when?] FERC hearings on the NEPOOL market structure. Several mechanisms that are intended to incentivize new investment where it is most needed by offering enhanced capacity payments (but only in zones where generation is projected to be short) have been proposed for NEPOOL, PJM and NYPOOL, and go under the generic heading of "locational capacity" or LICAP (the PJM version is called the "Reliability Pricing Model", or "RPM").
In a deregulated grid some sort of incentives are necessary for market participants to build and maintain generation and transmission resources that may some day be called upon to maintain the grid balance (supporting the "resource adequacy", or RA), but most of the time these resources are idled and do not produce revenue from the sale of electricity. Since "energy-only markets have the potential to result in an equilibrium point for the market that is not consistent with what users and regulators want to see", all existing wholesale electricity markets rely on offer caps in some form. These caps prevent the suppliers from fully recovering their investment into the reserve capacity through the scarcity pricing, creating a missing money problem for generators. To avoid underinvestment into the generation and transmission capacity, all markets employ some kind of RA transfers.
Typical regulator requires a retailer to purchase firm capacity for 110-120% of its annual peak power. The contracts are either bilateral (between the retailers and generator owners), or are traded on a centralized capacity market (the case, e.g., for the eastern USA grid).
See also: Coal_power_in_Turkey § Taxes,_subsidies_and_incentives
The capacity mechanism is claimed to be a mechanism for subsiding coal in Turkey, and has been criticised by some economists, as they say it encourages strategic capacity withholding.
The Capacity Market is a part of the British government's Electricity Market Reform package. According to the Department for Business, Energy and Industrial Strategy "the Capacity Market will ensure security of electricity supply by providing a payment for reliable sources of capacity, alongside their electricity revenues, to ensure they deliver energy when needed. This will encourage the investment we need to replace older power stations and provide backup for more intermittent and inflexible low carbon generation sources". 
Two Capacity Market Auctions are held each year. The T-4 auction buys capacity to be delivered in four years’ time and the T-1 auction is a top-up auction held just ahead of each delivery year. The following Capacity Market Auction results have been published:
The National Grid 'Guidance document for Capacity Market participants' provides the following definitions:
Within many electricity markets, there are specialised markets for the provision of frequency control and ancillary services (FCAS). If the electricity system has supply (generation) in excess of electricity demand, at any instant, then the frequency will increase. By contrast, if there is insufficient supply of electricity to meet demand at any time then the system frequency will fall. If it falls too far, the power system will become unstable. Frequency control markets are in addition to, and separate from, the wholesale electricity pool market. These markets serve to incentivise the provision of frequency raise services or frequency lower services. Frequency raise involves rapid provision of extra electricity generation, so that supply and demand can be more closely matched.
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