A
wholesale electricity market, also
power exchange or
PX, (or
energy exchange especially if they also trade gas) 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.
Market clearing 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 may or may not clear trades, but often require knowledge of the trade 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. Two types of auction can be used to determine which producers are dispatched: •
Double auction: the operator aggregates both the supply bids for each interval (forming a
supply curve) and demand bids (
demand curve). The clearing price is defined by the intersection of the supply and demand curves for each time interval. One example of this is the
Nord Pool. • Single
reverse auction: the operator aggregates only the supply bids, and dispatches the cheapest combination of options. To determine payments, the clearing can use one of two arrangements: •
pay-as-bid (PAB) where each successful bidder is paid the price stated in their bid. This arrangement is not common, but notable cases include the UK and the Nord Pool's intra-day market. •
pay-as-clear: also known as
uniform pricing, or
marginal pricing system (MPS). All participants are paid the price of the highest successful bid (
clearing price). This system is commonly used by the electricity markets. In PAB, strategic bidding can lead producers to bid much higher than their true cost, because they will be dispatched as long as their bid is below the
clearing price. In the absence of
collusion, it is expected that MPS incentivizes producers to 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, 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). However, MPS results in producers being paid more than their bidding prices by design, leading to calls to replace it with PAB despite the incentive for strategic bidding.
Centralized and decentralized markets 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:
Centralized market 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 (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: • politically, it proved hard to justify higher electricity pricing for customers in some locations. In the US the solution was found in the form of GNP; • simplified bidding does not allow to properly capture the cost structure of a more complicated plants, like a
combined cycle gas turbine or a
hydropower cascade; • generation companies have an incentive to overstate their start-up costs (to capture more make-whole payments, see below); • absence of the intra-day market makes integration of the renewables harder; • the integrated markets are very computation-intensive, this complexity makes them opaque to traders and hard to scale; • the unchecked power of the transmission system operator makes it harder for the regulator to handle. 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: • once set at the day-ahead market, the contract usually cannot be changed (some markets allow for an hour-ahead correction), so unexpected adverse events have to be accommodated in the real-time and thus in suboptimal way, hurting producers with long ramp-up times, complex cost structures, wind power generation; • new technology (
energy storage,
demand response) with new cost structures require time and effort to accommodate.
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).
Cost-based market 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 hydropower, in the US when the local
market power is sufficiently high, some European markets). 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 market 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.
Bid-based, security-constrained, economic dispatch with nodal prices 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". 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).
Risk management 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,
virtual bidding,
financial transmission rights,
call options and
put options are traded in sophisticated electricity markets. In general they are designed to transfer financial risks between participants.
Price capping and cross subsidy 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.
Wholesale electricity markets •
Argentina – see
Electricity sector in Argentina • Australia – see
Electricity sector in Australia •
Wholesale Electricity Market (WA) –
Australian Energy Market Operator (AEMO) •
National Electricity Market (East Coast) – AEMO •
Austria – see
EPEX SPOT and EXAA Energy Exchange •
Belgium – see
APX Group • Brazil – see
Electricity sector in Brazil • Canada – see
Electricity sector in Canada • Chile – see
Electricity sector in Chile •
Colombia – see
Electricity sector in Colombia •
Czech Republic – Czech electricity and gas market operator and Power Exchange Central Europe (PXE) •
Croatia – Croatian Power Exchange (CROPEX) • France – see
Electricity sector in France and
EPEX SPOT • Germany – see
Electricity sector in Germany, European Energy Exchange AG (EEX) and
EPEX SPOT •
Hungary – Hungarian Power Exchange HUPX and Power Exchange Central Europe (PXE) • Ireland – Single Electricity Market Operator (SEMO) • Italy – GME • Japan – see
Electricity sector in Japan and
Japan Electric Power Exchange (JEPX) •
Korea –
Korea Power Exchange (KPX) • Mexico – Centro Nacional de Control de Energía (CENACE) •
Netherlands – see
APX-ENDEX • New Zealand – see
Electricity sector in New Zealand and
New Zealand Electricity Market •
Philippines – Philippine Wholesale Electricity Spot Market •
Poland – Polish Power Exchange (POLPX) •
Portugal – OMI-Polo Español, S.A. (OMIE), OMIP, Sociedad Rectora del Mercado de Productos Derivados, S.A. (MEFF), and European Energy Exchange AG (EEX) •
Russian Federation – Trade System Administrator (ATS) • Singapore – Energy Market Authority of Singapore (EMA) and Energy Market Company (EMC) •
Turkey – see
Electricity sector in Turkey, Turkish Electricity Market • United Kingdom – see
APX-ENDEX and Elexon • United States – summarized by the Federal Energy Regulatory Commission (FERC). •
California Independent System Operator • ERCOT Market in Texas •
Midwest –
Midcontinent Independent System Operator (MISO Energy) • New England market • New York –
New York Independent System Operator (NYISO) •
PJM Interconnection for all or parts of
Delaware,
Illinois,
Indiana,
Kentucky,
Maryland,
Michigan,
New Jersey,
North Carolina,
Ohio,
Pennsylvania,
Tennessee,
Virginia,
West Virginia, and the
District of Columbia. •
Southwest – Southwest Power Pool, Inc •
Vietnam – Vietnam wholesale electricity market (VWEM). Operated by EVN
Electric power exchanges An
electric power exchange is a
commodities exchange dealing with
electric power: •
Indian Energy Exchange •
APX Group •
Energy Exchange Austria •
European Energy Exchange •
European Power Exchange •
HUPX Hungarian Power Exchange •
Nord Pool AS •
Powernext International trading 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.
Possible future changes 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. == Retail electricity market ==