In economic terms, electricity (both power and energy) is a commodity capable of being bought, sold, and traded. An electricity market is a system enabling purchases, through bids to buy; sales, through offers to sell; and short-term trades, generally in the form of financial or obligation swaps. Bids and offers use supply and demand principles to set the price. Long-term trades are contracts similar to power purchase agreements and generally considered private bi-lateral transactions between counterparties.
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. The commodities within an electric market generally consist of two types: power and energy. Power is the metered net electrical transfer rate at any given moment and is measured in megawatts (MW). Energy is electricity that flows through a metered point for a given period and is measured in megawatt-hours (MWh).
Markets for energy-related commodities trade net generation output for a number of intervals usually in increments of 5, 15 and 60 minutes. 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.
In addition, for most major operators, there are markets for transmission congestion and electricity derivatives such as electricity futures and options, which are actively traded. These markets developed as a result of the restructuring of electric power systems around the world. This process has often gone on in parallel with the restructuring of natural gas markets.
One early introduction of energy market concepts and privatization to electric power systems took place in Chile in the early 1980s, in parallel with other market-oriented reforms associated with the Chicago Boys. The Chilean model was generally perceived as successful in bringing rationality and transparency to power pricing. Argentina improved on the Chilean model by imposing strict limits on market concentration and by improving the structure of payments to units held in reserve to assure system reliability. One of the principal purposes of the introduction of market concepts in Argentina was to privatize existing generation assets (which had fallen into disrepair under the government-owned monopoly, resulting in frequent service interruptions) and to attract capital needed for rehabilitation of those assets and for system expansion. The World Bank was active in introducing a variety of hybrid markets in other Latin American nations, including Peru, Brazil, and Colombia, during the 1990s, with limited success.
A quantum leap in electricity pricing theory occurred in 1988 when four professors at MIT and Boston University (Fred C. Schweppe, Michael C. Caramanis, Richard D. Tabors, and Roger E. Bohn) published a book entitled, "Spot Pricing of Electricity." It presented the concept that prices at each location on a transmission system should reflect the marginal cost of serving one additional unit of demand at that location. It then proposed quantifying these prices by solving a systemwide cost minimization problem while complying with all of the system's operational constraints, such as generator capacity limits, locational loads, line flow limits, etc. using linear programming software. The locational marginal prices then emerged as the shadow prices for relaxing the load limit at each location.
A key event for electricity markets occurred in 1990 when the UK government under Margaret Thatcher privatised the UK electricity supply industry. The process followed by the British was then used as a model (or at least a catalyst) for the restructuring of several other Commonwealth countries, notably the National Electricity Markets of Australia and New Zealand and the Alberta Electricity Market in Canada.
In the United States the traditional vertically integrated electric utility model with a transmission system designed to serve its own customers worked extremely well for decades. As dependence on a reliable supply of electricity grew and electricity was transported over increasingly greater distances, wide area synchronous grid interconnections developed. Transactions were relatively few and generally scheduled well in advance.
However, in the last decade of the 20th century, some US policy makers and academics asserted that the electric power industry would ultimately experience deregulation and independent system operators (ISOs) and regional transmission organizations (RTOs) were established. They were conceived as the way to handle the vastly increased number of transactions that take place in a competitive environment. About a dozen states decided to deregulate but some pulled back following the California electricity crisis of 2000 and 2001.
In different deregulation processes the institutions and market designs were often very different but many of the underlying concepts were the same. These are: separate the potentially competitive functions of generation and retail from the natural monopoly functions of transmission and distribution; and establish a wholesale electricity market and a retail electricity market. The role of the wholesale market is to allow trading between generators, retailers and other financial intermediaries both for short-term delivery of electricity (see spot price) and for future delivery periods (see forward price).
Some states exempt non investor-owned utilities from some aspects of deregulation such as customer choice of supplier. For example, some of the New England states exempt municipal lighting plants from several aspects of deregulation and these municipal utilities do not have to allow customers to purchase from competitive suppliers. Municipal utilities in these states can also opt to function as vertically-integrated utilities and operate generation assets both inside and outside of their service area to supply their utility customers as well as sell output to the market.
Nature of the marketEdit
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. Furthermore, demand and supply vary continuously.
There is therefore a physical requirement for a controlling agency, the transmission system operator, to coordinate the dispatch of generating units to meet the expected demand of the system across the transmission grid. If there is a mismatch between supply and demand the generators speed up or slow down causing the system frequency (either 50 or 60 hertz) to increase or decrease. If the frequency falls outside a predetermined range the system operator will act to add or remove either generation or load.
The proportion of electricity lost in transmission and the level of congestion on any particular branch of the network will influence the economic dispatch of the generation units.
Markets may extend beyond national boundaries.
Wholesale electricity marketEdit
This article's factual accuracy may be compromised due to out-of-date information. (March 2017)
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.
Bid-based, security-constrained, economic dispatch with nodal pricesEdit
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 PJM Interconnection, ERCOT, New York, and New England markets in the USA, New Zealand, and in Singapore.
In practice, the LMP algorithm described above is run, incorporating a security-constrained, least-cost dispatch calculation (see below) 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.
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".
Since the introduction of the market, New Zealand has experienced shortages in 2001 and 2003, high prices all through 2005 and even higher prices and the risk of a severe shortage in 2006 (as of April 2006). These problems arose because New Zealand is at risk from drought due to its high proportion of electricity generated from hydro.
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.
Wholesale electricity marketsEdit
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- Argentina - see Electricity sector in Argentina
- Australia - see Electricity sector in Australia
- 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)
- 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)
- India - see Indian Energy Exchange and Power Exchange India Limited (PXIL)
- 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
- Portugal - OMI-Polo Español, S.A. (OMIE), OMIP, Sociedad Rectora del Mercado de Productos Derivados, S.A. (MEFF), and European Energy Exchange AG (EEX)
- Scandinavia - see Nord Pool Spot
- Slovakia - Power Exchange Central Europe (PXE)
- Spain - OMI-Polo Español, S.A. (OMIE), OMIP, Sociedad Rectora del Mercado de Productos Derivados, S.A. (MEFF), and EEX
- Russian Federation - Trade System Administrator (ATS)
- Singapore - Energy Market Authority of Singapore (EMA) and Energy Market Company (EMC)
- Turkey - Turkish Electricity Market
- United Kingdom - see APX-ENDEX and Elexon
- USA - summarized by the Federal Energy Regulatory Commission (FERC).
- California - California ISO
- ERCOT Market
- Midwest - Midcontinent Independent System Operator, Inc (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
Retail electricity marketEdit
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:
- Credit control
- Customer management via an efficient call centre
- Distribution use-of-system contract
- Reconciliation agreement
- "Pool" or "spot market" purchase agreement
- Hedge contracts - contracts for differences to manage "spot price" risk
The two main areas of weakness have been risk management and billing. In the USA 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 (see Manifesto on The California Electricity Crisis). 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 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).
Electricity market experienceEdit
In the main, experience in the introduction of wholesale and retail competition has been mixed. 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 FERC hearings on the NEPOOL market structure. Several mechanisms that are intended to incent 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"). There is substantial doubt as to whether any of these mechanisms will in fact incent new investment, given the regulatory risk and chronic instability of the market rules in US systems, and there are substantial concerns that the result will instead be to increase revenues to incumbent generators, and costs to consumers, in the constrained areas.
This section needs expansion. You can help by adding to it. (May 2018)
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:
- "CMU (Capacity Market Unit) – this is the Generating Unit(s) or DSR Capacity that is being prequalified and will ultimately provide Capacity should they secure a Capacity Agreement".
- "A Generating CMU is a generating unit that provides electricity, is capable of being controlled independently from any other generating unit outside the CMU, is measured by 1 or more half hourly meters and has a connection capacity greater than 2MW".
- "A DSR CMU is a commitment by a person to provide an amount of capacity by a method of Demand Side Response by either reducing the DSR customers import of electricity, as measured by one or more half hourly meters, exporting electricity generated by one or more permitted on site generating units or varying demand for active power in response to changing system frequency".
- Availability based tariff
- Competition law
- Cost of electricity by source
- Distributed generation
- Electric utility
- Electricity generation
- Electricity liberalization
- Electricity tariff
- Electricity transmission
- Energy demand management
- Future energy development
- Independent system operator
- Load profile
- National Grid (UK)
- Negawatt Power
- NERC Tag
- North American Electric Reliability Corporation
- Open Energy Modelling Initiative
- Power quality
- Power purchase agreement
- Voltage drop
- Criteria for economically efficient electricity wholesale markets - Criteria for economically efficient wholesale markets
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- List of Power and Energy exchanges worldwide