The UK Electricity Supply Industry ESI

The State-Owned Central Electricity Generating Board

Before 1990, the entire UK ESI was in the state sector and was centrally planned and operated by the Central Electricity Generating Board (CEGB). The remit of the CEGB was to provide a secure supply of electricity to its consumers. All generating plant, transmission lines, distribution lines, substations and metering were owned and operated by the CEGB as a monopoly. During the days of the CEGB, electricity was supplied to consumers through the Regional Electricity Companies, which were also responsible for the operation of the distribution network in their area (132 kV and below).

Although this system had worked well for many years, it was a monopoly and severely restricted opportunities for small scale privately-owned generation. During privatization, which was intended to promote competition and drive down costs, the CEGB was broken up into various sectors and sold off to the private sector and new market mechanisms were brought into being.

The Electricity Pool

In 1990, the Pooling and Settlement Agreement (PSA) was introduced and the ESI privatized. The generators were split up between two privatized companies, National Power and Powergen, but nuclear power stations remained under state control. The Regional Electricity Companies (RECs) were individually privatized and given sole licences to supply electricity in their areas, while still retaining responsibility for the distribution network in their areas. The RECs jointly owned the National Grid Company (NGC), which was responsible for the operation of the transmission network (275 and 400 kV) and the pumped-storage facilities in Wales. The NGC also served as the network operator responsible for the scheduling and dispatch of the generation plant.

The Operation of the Pool and Pool Rules

Instead of generation plant being scheduled centrally in an optimum economic dispatch mode reflecting efficiency, operating cost and flexibility, generators now 'bid' into a pool, offering to generate a given output at a given price for the day ahead. The NGC would examine the bids, put them in order of increasing cost and then from this list select the generation plants it would need to meet the demand in a given half-hour period, allowing for transmission constraints and reserve. The most expensive plant required in each halfi hour period would set the soicalled system marginal price (SMP) for that halfihour. To this price would be added a capacity credit in order to ensure that sufficient capacity over and above maximum demand would always be available for reasons of security of supply. This price was called the pool purchase price (PPP) and was paid to all generators selected within the halfihour regardless of whether they had bid less. This pool system is known as a uniform auction.

Inflexible plant such as nuclear would commonly bid in at a very low price or even zero to ensure being selected. Note that they would still be paid the PPP even if they had bid zero. Combined cycle gas turbines (CCGTs) with fixed gas contracts would also bid low to ensure being scheduled. The next lowest prices would be operated by the coal fired generators, which were more flexible but with higher operating costs. Finally, open cycle gas turbines and pump storage would bid higher due to higher operating costs and greater flexibility. It can be seen that in general the order of the bids would be in line with the old merit order system but now prices were meant to be driven down due to the competitive bidding nature of the pool.

Figure 7.13 shows a comparison of the average daily half-hourly demand and the PPP for November 1999. It can be seen that the trend in prices throughout the day broadly follows the demand trend during the day. The peaks in prices reflect the more expensive plants that

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Figure 7.13 NGC average daily half-hourly demand and pool purchase price for November 1999

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Figure 7.13 NGC average daily half-hourly demand and pool purchase price for November 1999

need to be chosen by the NGC to meet the peaks in demand. The PPP was then 'uplifted' slightly to cover the difference in the total cost incurred by the NGC in balancing generation and demand and what was paid out to generators through the PPP. This uplifted price was known as the pool selling price (PSP). The PSP is then charged through to suppliers for the amount of electricity supplied to their customers.

All generation and demand is metered. Large generators and consumers are metered every half-hour. Small consumers are metered monthly, quarterly or six-monthly. All meter readings are processed and made available to the system operator (SO), who works out who should be paid, what amount and who owes what amount. Additionally, charges are made for the use of the transmission and distribution networks. The process of allocating the costs and payments is known as settlement.

Hedging

It can be seen from Figure 7.13 that there is a wide variation in prices during the day. The prices shown are monthly averages. It was quite possible to get price fluctuations at times of peak demand (around 5:30 pm), well over £100/MW h (€150/MWh). In certain severe weather conditions this could go over £250/MW h (€375/MW h). For a supplier with a peak 'tea-time' demand of 2 GW (2000 MW) this could mean half-hourly cost fluctuations approaching £0.25 million (€0.38 million)! Most suppliers operate to quite tight margins and charge a fixed price to their customers, so a sudden increase in pool prices over a cold period could potentially bankrupt a supplier. On the other hand, generators are paying a fixed price for their fuel and similarly a dip in prices during a prolonged warm period could also spell disaster for their cash flow. Soon after the introduction of the PSA, so-called 'Contracts for Differences' came into existence. These 'financial instruments' gave generators and suppliers the ability to fix the price of their generation or demand for a given period of time, typically a month or more, but also up to several years ahead. The contracts did this by hedging against changes in the pool prices.

Typically a supplier would forecast its demand profile by the half-hour throughout a month, taking into account changes due the seasons, changes due to expected customer losses/gains, etc. This would be the hedged volume. The supplier would present this profile to a third party broker, which could be a financial institution. This broker would then offer a fixed price for the contract, reflecting how volatile the broker expected the prices to be in the next month. The supplier would still have to pay the half-hourly PSP for demand but at the same time if the PSP went above the fixed price, the broker would pay the supplier for the difference between the PSP and fixed price multiplied by the hedged volume. On the other hand, if the PSP went below the fixed price for any half-hour, the supplier would pay the broker for the difference between the fixed price and the PSP multiplied by the hedged volume. In this way the supplier was effectively paying a fixed price for its hedged volume. Obviously, if the hedged volume were an underforecast, the supplier would be exposed for the difference between the forecast and actual demand. If the forecast were too high, then the supplier might be paying over the odds for the contract, though it could be possible to make a profit with some speculation. Generators could fix the price they were paid for a hedged volume of generation in exactly the same way.

Eventually, bespoke contracts became 'off-the-shelf' contracts with standard terms and conditions and standard contract types, for example for base load or peaking. These were known as Electricity Forward Agreements (EFAs). These could be bought and sold on power exchanges. In this way, suppliers and generators could buy and sell in a forward trading market. The importance of such contracts became apparent when the independent supplier Independent Energy lost its credit rating and could not obtain an EFA, finally becoming bankrupt due to excessively high generation prices in September 2000.

Deregulation

Immediately following privatization, consumers could still only buy their electricity from their local REC. However, in 1992, consumers with an average demand of greater than 1 MW could choose a supplier outside their local area. In 1994, the demand threshold was reduced to 100 kW. Eventually, in 1999, all consumers were able to choose their supplier.

At the same time, small independent generators and second tier suppliers entered the market, breaking the monopoly of National Power, Powergen, Nuclear Electric and the RECs (which latterly became known as Public Electricity Suppliers or PESs). This gave an opportunity for renewable energy generators and specialist renewable energy suppliers (such as unit[e] and Ecotricity) to enter the market. In addition, the PESs have been unbundled so that supply, distribution, metering and meter reading have all become separate businesses. Over time the larger suppliers like National Power and Powergen have become fragmented and taken over so that they bear little resemblance to the companies they were at privatization. In addition, the National Grid Company, still the system (and transmission line) operator, became an independent company.

The New Electricity Trading Arrangements (NETA)

The electricity pool system was felt to have played its part in the successful deregulation and opening up of the ESI. However, criticisms were made of the way in which pool prices could be manipulated by a few key generators bidding into the pool. In fact, it was considered that this 'rigging' of pool prices was keeping wholesale electricity prices artificially high. In addition, it was felt that generators and suppliers should be free to enter into bilateral agreements instead of also buying from the pool, albeit with a bilateral hedging contract sitting on top. Furthermore, it was seen as beneficial that third parties could enter the market to trade in physical electricity much as they had been doing in CFDs and EFAs. For this reason, the New Electricity Trading Arrangements (NETA) were introduced in March 2001.

Buying and Selling Electricity Under NETA

Generators and suppliers (above a certain size) are obliged to notify their position for each half-hour in terms of generation and demand for the day ahead to the National Grid as system operator. This allows the NGC to carry out its balancing of supply and demand much as before. Generators now self-dispatch rather than wait to be dispatched by the NGC, although they can alter their output when requested to do so or if they participate in the balancing market (see below). Generators still self-dispatch in a very similar order to the merit order under the CEGB regime, but this time the order of dispatch is dictated solely by price. In addition, suppliers and generators notify what contracts they have struck to the NETA central

Figure 7.14 Average daily half-hour system sell and system buy prices for March 2002

Figure 7.14 Average daily half-hour system sell and system buy prices for March 2002

systems. These contracts must be notified at least 1 hour1 ahead of actual time, known as gate closure. Instead of suppliers dealing in CFDs and EFAs to hedge an agreed volume against pool prices, they now trade in physical volumes at a fixed price. Any difference between the physical volume contracted and actual volume generated or supplied is cashed-out at prices set within the balancing market.

Suppliers and generators typically strike contracts on different timescales. A month or more ahead of actual delivery they will strike bilateral contracts, which are straight contracts between two parties for a given volume of electricity at a given price. This accounts for 90% of the volume of wholesale electricity bought and sold. Suppliers and generators may not be able to predict their demand or output exactly months ahead, so around a day ahead they buy and sell chunks of power on a power exchange. This is much like a stock exchange for power, where 'chunks' of power are bought and sold anonymously. This can be done up to gate closure, as mentioned above. Around 5% of electricity is traded in this way. The remaining 5% is traded through the cash-out or imbalance market.

The Imbalance Market

If a supplier's actual demand in a half-hour is higher than it has contracted for ahead of gate closure, then the supplier must pay the system operator to top-up this deficit at the system buy price (SBP). If the supplier's actual demand is lower than it has contracted for it is paid the system sell price (SSP) for the spill excess. This imbalance market is therefore known generally as a top-up and spill market, The principle is identical for a generator, whereby it will need to pay the system buy price for any deficit in the contracted generation output and will be paid the system sell price for any generation excess above the contracted output. The system sell price is in general lower than the average bilateral contract price between the supplier and generator. The system buy price is in general higher than the average bilateral contract price between the supplier and generator.

Figure 7.14 shows the SSP and SBP for each half-hour average over the month March 2002. The SSP is around £10.70/MWh (€16.10/MWh) for this month, and the SBP is £23.70

1This was initially 3.5 hours ahead at NETA 'Go-Live' but was reduced to 1 hour ahead in July 2002.

(€35.60/MW h), though the SBP shows rather more variation during the day, crudely reflecting the shape of the national demand curve. The typical contract price for this month would be around £15/MWh (€23/MWh). It can be seen that there is an incentive for suppliers and generators to get their forecast as close as possible to their actual position due to these non-symmetrical prices.

The Balancing Market

The system operator, National Grid, needs to give orders to generation plant to change their output in order to match supply and demand, just as in the days of the CEGB and the pool. This is done using another market known as the balancing market. Ahead of delivery, flexible generators (and to a lesser extent flexible suppliers) can place bids to reduce power output or offers to generate extra output. In the case of a supplier it would make a bid to increase demand or an offer to reduce demand. After gate closure, the NGC examines the bids and offers and accepts those it needs to balance the system. Suppliers and generators pay their accepted bids and are paid their accepted offers. This type of market is therefore known as a bid-price auction. Simplistically, the value of the bids sets the system sell price and the value of the offers sets the system buy price, though there are other costs and adjustments that feed into these prices. The total cost of balancing the system in general is slightly less than the balance of the proceeds for the SSP and SBP. This is due to the fact that two generators may be out of balance separately and pay for this, but together their imbalances cancel out. The excess is reallocated to suppliers and generators in proportion to their total generation output or total demand as appropriate.

The British Electricity Transmission and Trading Arrangements (BETTA)

Until April 2005, the electricity wholesale market in Scotland operated differently to that in England and Wales, though there were similarities in terms of 'top-up' and 'spill' prices. After this date, the two markets were merged to give a version of NETA operating across Great Britain. At the same time, the transmission network in Scotland, which had been operated by the two Scottish generation and supply companies, became independently operated by National Grid, who consequently became responsible for the entire Great Britain transmission network. These new arrangements became known as the British Electricity Transmission and Trading Arrangements (BETTA).

Renewable Energy 101

Renewable Energy 101

Renewable energy is energy that is generated from sunlight, rain, tides, geothermal heat and wind. These sources are naturally and constantly replenished, which is why they are deemed as renewable. The usage of renewable energy sources is very important when considering the sustainability of the existing energy usage of the world. While there is currently an abundance of non-renewable energy sources, such as nuclear fuels, these energy sources are depleting. In addition to being a non-renewable supply, the non-renewable energy sources release emissions into the air, which has an adverse effect on the environment.

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