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Electricity market

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An electricity market is a system for effecting the purchase and sale of electricity using supply and demand to set the price. Wholesale transactions in electricity are typically cleared and settled by the grid operator or a special-purpose independent entity charged exclusively with that function. Markets for certain related commodities required by (and paid for by) various grid operators to ensure reliability, such as spinning reserve, operating reserves, and installed capacity, are also typically managed by the grid operator. In addition, for most major grids there are markets for electricity derivatives, such as electricity futures and options, which are actively traded. These markets developed as a result of the deregulation of electric power systems around the world. This process has often gone on in parallel with the deregulation of natural gas markets.

Early history

The earliest introduction of market concepts and privatization to electric power systems took place in Chile in the late 1970s, 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, but it contemplated the continuing dominance of several large incumbents and suffered from the attendant structural problems. 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 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 deregulation of several other Commonwealth countries, notably Australia and New Zealand, and regional markets such as Alberta. However, in many of these other instances the market deregulation occurred without the widespread privatisation that characterised the UK example.

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 contestable 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).

Wholesale electricity market

Typical daily consumption of electrical power in Germany

A wholesale electricity market exists when competing generators offer their electricity output to retailers.

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. 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.

In addition, the laws of physics determine how electricity flows through an electricity network. Hence the extent 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.

For an economically efficient electricity wholesale market to flourish it is essential that a number of criteria are met. Professor William Hogan of Harvard University has identified these. Central to his criteria is a coordinated spot market that has "bid-based, security-constrained, economic dispatch with nodal prices". Other academics such as Professors Shmuel Oren and Pablo Spiller of the University of California, Berkeley have proposed other criteria. Variants of Professor Hogan's model have largely been adopted in the US, Australia and New Zealand.

Bid-based, security-constrained, economic dispatch with nodal prices

The theoretical price 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, New York and New England markets in the USA and in New Zealand. However, many established markets do not employ nodal pricing, examples being the UK, Powernext and Nord Pool (Scandinavia and Finland). 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. Hogan and others have noted that a variety of factors, including energy price caps set well below the putative scarcity value of energy, the impact 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.

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 NZ is at risk from drought.

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.

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. 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 derinig supplies at the nodes in question. 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 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".


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 have an impact on 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, 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 markets

Retail electricity market

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:

Meter reading
Meter rental
Billing
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 Californian 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.

Electricity market experience

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 one 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 incent 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 currently (May 2006) under FERC review is call 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.

See also

Further reading

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