Electricity Deregulation - The UK Experience

Author(s):

John Matthews
John Matthews, Principal, ADR Ltd., Bracknell, www.adrna.com, Berkshire, RG12 1RP, England, 44/1344-303078, adr.ltd@virgin.net
Linda P. Michels, C.P.M.
Linda P. Michels, C.P.M., Associate Director, ADR North America LLC, www.adrna.com, Ann Arbor, MI 48106-0366, 734/930-5070, adrna@ic.net

84th Annual International Conference Proceedings - 1999 

Abstract. In 1999 the electricity market in the USA will begin to change as deregulation becomes effective. Non-negotiable tariffs will be replaced by negotiated contracts and, in theory, a competitive market for the sale and purchase of electricity will become established. If any buyer of electricity in the United States believes this to be true, he or she should examine the experience of the UK where electricity deregulation commenced in 1990. This paper will present the issues faced in the UK and how they were tackled or remedied.

One Supplier to Many Suppliers. In simple portfolio analysis terms, when a marketplace becomes deregulated, the supply market positioning of a commodity moves from Strategic or Critical (high market difficulty) to Leverage or Acquisition (i.e., low market difficulty - see Figure 1), depending on the size of the expenditure. The speed and the extent to which this happens is very much dependent upon the way the marketplace has been set up AND the degree of skill and the posture of electricity buyers within that marketplace.

Figure 1: Portfolio Analysis (this graphic illustration is not available in the text-only version of this paper).

From the UK experience, it is possible to define three stages of the migration from a completely fixed / regulated marketplace to one in which competition is genuinely occurring and in which buyers do have choice which they can exercise.

Phase 1 - limited deregulation /competitive advantage secured through technical analysis

Phase 2 - more extensive deregulation / genuine non-technical competition (at the margins)

Phase 3 - complete deregulation / pure price competition

This paper will describe how those phases have worked in the UK market over the last 8 years and will provide some pointers to ensure that, at every stage of the deregulation process, US buyers are in a position to make maximum use of the opportunity the market affords.

Factors Affecting the Setting Up of the Market. When the electricity market was deregulated in the UK, two factors were of overriding importance in determining how the market was set up. They were:

  1. The need to guarantee future generating capacity.
  2. The recognition that electricity does not exist in a physical place.

Let us examine these two factors in detail. In virtually every developed Western economy, the supply of electricity (keeping the lights on) is of national strategic importance. In the era of nationalized or in some way regulated market places, this has meant institutionalized over-capacity has become commonplace. This over-capacity operates at two levels:

At the micro level, an individual consumer is asked to identify the maximum demand he wishes to guarantee, which almost invariably results in demands at least 20 - 40% over their real peaking maximum demand. At the macro level within the UK, the old national power organization (Central Electricity Generating Board - CEGB) responded to these multiple consumer maximum demands by putting in place the capacity to meet them with an additional safety factor which resulted in generation capacity within the UK some 30% + higher than peaking demand (assuming all stations were available for operation at all times). This pattern is repeated in other countries. An example of this over capacity is provided by the fact that Electricite de France (EDF) consistently exports 2-3,000 megawatts per day, via an undersea interconnect, to the UK. This represents some 2 - 3% of UK nominal demand and obviously a significant proportion of French nuclear generation capacity which otherwise would be sitting idle.

The second factor is more difficult to grasp. Electricity does not exist at a physical location, i.e., you cannot as a seller, sell a "piece" of electricity to a customer and guarantee the piece of electricity you have sold is the one they receive. In this sense, the electricity market should operate like a true market (e.g., financial markets, currency markets) where one is trading in a notional, not a physical, product. This, however, has some difficulties because, unlike those other markets, distance from seller to consumer does have implications. The consumption of electricity can only be measured at the point where the supply crosses the consumers threshold. If, however, that electricity has had to be transported some distance before it crosses that threshold, then losses will have occurred during transmission and these losses are affected by the voltage at which the transmission occurs. Thus, a premium had to be devised and applied to cover these transmission losses.

Options in Setting up the Market. In essence, there are two options when setting up a deregulated electricity market. These can be characterized by reference to the

  1. UK model (key objectives - plant optimization/capacity guarantee);
  2. Nordic model (key objective - establishment of competition).

In the Nordic model, there is a real meeting of buyers and sellers in the market place. People offer contracts for packets of electricity, which can be bought by real consumers and/or brokers who then sell to genuine consumers of electricity. The marketplace decides the price at which such contracts will be struck. Individual buyers and sellers are free to make decisions on the price of the contract between them. The fundamental premise under which this market operates is that it will settle at prices sufficient to guarantee future investment to meet demand. One aspect that has changed significantly since the UK electricity market was deregulated, is that the lead times to build new generation capacity (particularly combine-cycle gas plants) is now much shorter than the lead time to build more conventional oil, nuclear or coal-fired power stations.

This has made the supply / demand "feedback" loop within the market place much more sensitive and made significant over capacity even more "redundant". This Nordic model of the market where individual customers and sellers set prices is fundamentally different from that operating in the UK. The electricity market within the UK is commonly referred to as the "electricity pool". Each day a price for electricity consumed in every half hour period is set. This is known as the pool price. However, the pool price is not developed from a series of competing offers to sell matched with competing offers to buy. Each generator offers each of his power station's output for every half hour period at a nominated price. The authority controlling the pool then works out which is the station that will be generating at the point of threshold demand. The price offered by this threshold station is then "enjoyed" by all stations that are requested to generate. This price is known as the "System Marginal Price". In effect organizations like Nuclear Electric and Electricite de France with high fixed costs consistently bid at prices well below the System Marginal Price, sometimes offering electricity for "free" because they know that whatever they bid they will enjoy the System Marginal Price. Their key objective is to ensure their stations remain generating. This very different marketplace was devised to guarantee that all generators would consistently receive the highest selling price for electricity thereby resulting in prices which would ensure continued future generation capacity.

Components of the UK Electricity Price. The price on the pool for each half hour period or System Marginal Price, is, however, only the first step in a pricing formula which finally results in a selling price to consumers. These steps can be summarized as follows:

  Pool price
= +
System Marginal Price(SMP)
  Capacity charges
(VOLL/LOLP)
= Charge
+
Pool purchase price Energy
Price at which Contracts for Difference (CFD) are set Uplift
(determined by grid) =
+
Delivery losses
+
Use of system charges
(TUOS/DUOS)
+
Management fee
+
Taxes (Fossil Fuel Levy + VAT)
Pool selling price
= Price to Customer  

Onto the System Marginal Price, capacity charges are added. These are referred to as VOLL (value of lost load) and LOLP (loss of load probability). In essence these are applied whenever forecast demand approaches available capacity for any half hour period. Available capacity is obviously influenced by factors such as outage of stations for maintenance, etc. These charges are designed to be punitive to those organizations purchasing electricity when demand is approaching available capacity and often will increase the system marginal price by a factor of 10. Once the capacity charges (VOLL and LOLP) have been added, there comes an uplift which is determined by the National Grid Company. The National Grid Company is the organization that controls the pool and the high voltage transmission system for the distribution of electricity. The uplift is set by regulation and covers such issues as the costs of maintaining standby generation capacity. Once the uplift has been added, what is achieved is the Pool Selling Price. This is the price at which anyone (initially with over 1Mw of demand subsequently reduced to 100Kw of demand) could theoretically enter the market place and purchase electricity. In reality, all but a very small number of very high demand users, like ICI (a chemicals company consuming approximately 2% of UK national demand), contracted to buy electricity from distribution companies (RECs) who bought electricity from the pool via Contracts For Difference (CFDs) struck with the generators. In essence a Contract For Difference is a hedging mechanism whereby a fixed price is agreed between the REC and the generator, whenever the pool price deviates from this fixed price money is transferred either from the generator to the distributor or vice versa.

From the Contracts For Difference price, the RECs then add a further set of charges, the first of which cover the delivery losses. As stated earlier, the transmission of electricity over distance results in losses. The lower the voltage at which transmission occurs the higher the percentage of loss. Therefore the charge for delivery losses can be ameliorated by agreeing to take supply at higher and higher voltages and placing the step-down transformers required within your own premises. Fundamentally, this is what a number of large customers did in the early stages of deregulation of the UK market. They may have previously been supplied at 16KVa and opted to increase the supply voltage to 32KVa or more by building transformers on their site and receiving electricity at the higher voltage. This often resulted in savings of £50 - 100,000 per year for large users which very rapidly paid back the cost of the equipment required on their premises.

The next charges added are the Use of System charges. These break into 2 elements, the TUOS (Transmission Use of System Charge) and the DUOS (Distribution Use of System charge). The only difference between them being the voltage involved. The Transmission charges refer to the high voltage national grid for transporting electricity over distance and the Distribution system charges relate to the lower voltage distribution network within regional electricity company (REC) area. These charges are set by regulation, although it subsequently became clear that different RECs had different prices for their DUOS charges. It also emerged that over 90% of the RECs profits were being generated from these DUOS charges. The final two elements added to the price, again set by regulation, are a management fee and taxes. Of the latter, one tax (the fossil levy) was specifically introduced to support the continued generation of electricity via alternative means. This in theory was meant to include wind, solar, wave energy, etc., but in effect it was a subsidy to the UK nuclear generation industry (which in the early stages was not privatized) and has since been removed (in 1997) when the nuclear industry was finally removed from public ownership.

It is clear from the above very brief summary of the elements within the UK electricity price, that this is not a simple commodity market, like a currency market, nor even the Nordic model electricity market. It contains regulation at many different levels and provides the opportunity for both generators and distributors to hide behind technicality and regulation to avoid competition; there is no clear link between buyers and sellers in this market place.

Recommendations for Action. In Phase 1 of the deregulation of the marketplace, most benefits will accrue from a detailed technical understanding of how the price is built and what technical issues and regulation underpin the costs. This usually involves the need to work multifunctionally with manufacturing engineers and/or specialist utility engineers who have this expertise. Savings over and above the general market downward drift come from issues such as:

  1. Increasing voltage at which the organization is supplied.
  2. Consolidating metering so that all organizations within a common site perimeter are metered on one meter, creating a common maximum demand and an ability to enter into the competitive marketplace (i.e. initially 1Mw of demand).
  3. Load factor management at the consumer's premises.

This latter in particular is important with regard to TUOS charges. These charges are calculated on the peaking maximum demand of the customer for 3 half hour periods throughout the year. These "Triads", as they are known, are declared when available capacity and demand are in close balance, usually late in the afternoon on cold, foggy, November or December Thursday evenings! Whatever your demand is during those half hour periods will determine the level of your TUOS charge. Many RECs, therefore, set up Triad warning systems whereby consumers were offered some degree of forecasting of which half hour periods were likely to be declared a Triad and thus could make attempts to minimize their demand during them, thus cutting the level of their TUOS charges.

Clearly negotiation of such esoteric charging issues is not something that can be best left to purchasing alone. It requires multifunctional teams comprising of engineers and often finance staff who can assist in the development of capital requests to cover the cost of the additional equipment that may be requested to cut costs.

In the second phase of the UK's deregulation, customers with over 100Kw of demand became eligible to buy in the competitive market place. The initial focus on technical avenues to secure additional value became less marked. In essence the RECs, who up to that point had only a small part of their marketplace vulnerable to competition from either other RECs or generators, now faced a much more significant threat. This appeared to concentrate their minds and it became possible to negotiate in areas such as the DUOS charge by comparing and contrasting different distributor's charges. Volume leverage (something that is common in virtually every supply market) also finally became a useful tool. Previously, volume had appeared to offer either no or sometimes adverse benefits when attempting to negotiate. From 1994 on, the ability to aggregate volume and offer large chunks of demand became ever more powerful a tool as the RECs recognized that if they failed to compete they risked losing large sectors of what was formerly their captive market.

It is interesting to note some of the anomalies that resulted from the way the "Demand" was defined. For example, a major city such as Birmingham could not claim that its demand for electricity to power street lighting was a unitary demand and, therefore, capable of being included in the competitive market place, because the metering was done at many individual points. So while it was clear that a major metropolitan area would necessarily be well in excess of 1Mw of demand for street lighting, this demand was excluded initially from the competitive marketplace.

Finally, the UK is just entering phase 3 of the cycle described in this paper. The market will continue to be regulated (it will always be regulated), however, from October / December 1998 it will be completely open. Anyone, irrespective of the size of their demand, down to and including individual households, will be able to buy their electricity from wherever they wish. This creates what many people find to be a very "weird" situation. For example, a householder in the south of England could decide to switch supply from his original supplier and buy electricity from a supplier located in Scotland 700 miles away. That supplier may not have generation capacity and indeed the electricity that they will supply will still be delivered using the lines of the householder's original supplier. Many people find this difficult to grasp but it lies at the heart of the fundamental premise that electricity does not exist in a place, and is in essence a theoretical construct. Because householders and less sophisticated buyers find difficulty in getting their minds around this "weirdness", the distributors are having to come up with prices which are as easy to understand as the Comex price for aluminum or the Yen/$ exchange rate (i.e., traditional commodity prices). Thus, the marketplace is starting to compete on a price basis alone in order that the least sophisticated buyers can operate in the market. This will clearly spill over into the relationships between the RECs and generators and their more sophisticated industrial consumers as they force those generators and RECs to equally compete on price alone for their business.

We believe, therefore, that over the coming two or three years the UK electricity market will become a genuine commodity market place, albeit large users will continue to gain additional benefits by sophisticated use of the regulations and / or the technical issues around supply.

Conclusions. Depending on how US deregulation is handled state by state, buyers will need to adopt different stances. If the Nordic model is adopted, then buyers can use their traditional skills, probably with relatively little involvement from their engineering colleagues to manage the expenditure for additional value. If, however, the US follows the UK model, then it will be absolutely essential that buyers form strong multifunctional teams with engineers and finance staff to extract maximum value from the newly competitive market places during the early first and second phases of the deregulation. Buyers who fail to do so will find the marketplace totally unresponsive to their normal purchasing overtures and will potentially create competitive disadvantage for their organizations.

During the writing of this article a "White Paper" (government proposal for legislation) was brought before Parliament which proposed three key amendments to the electricity market in the UK:

i) modifications to the workings of the pool ii) a moratorium on the building of new CCG (combined cycle gas) plants iii) requirements that force the two key generators (PowerGen and National Power) to divest themselves of significant proportions of their coal-fired generation capacity.

Note: Coal accounts for 40-45% of UK generation capacity (70% in 1990), with nuclear and gas contributing 20-25% and 15% respectively.

These measures are designed to create a more competitive market place, one that is not "rigged" against coal stations with high fixed costs and high (compared to nuclear) fuel costs. While the detailed implications of these proposals are not yet known, it is likely that they will create a more "Nordic" market for electricity in the UK and ultimately result in a further 10-12% drop in the price of electricity to the consumer.


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