Ensuring Adequate Generation Capacity

Utilities Policy 11 (2003) 95–102www.socscinet.com/bam/jup

Ensuring adequate generation capacity

R. Turvey∗,1

London Business School, Regent’s Park, London NW1 4SA, UK

Received 1 August 2002; accepted 16 January 2003

Abstract

This article examines whether the market mechanism for electricity as it now exists in England and Wales is likely to ensuresufficient generating capacity to avoid power cuts. The main issues raised are whether market prices will ensure that existinggeneration plants are retained in serviceable condition as long as necessary, whether the level of capacity deemed desirable couldand should be secured by public action and whether and how the extent of demand response to current prices could be increased. 2003 Elsevier Science Ltd. All rights reserved.

Keywords: Electricity prices; Generating capacity; Demand response; Incentives; Power shortage

1. Introduction

There is currently a surplus of generating capacity inGreat Britain. In coming years, however, nuclear powerplants will be permanently shut down, some older coaland oil plants will be irreversibly closed and emissionlimitations will probably become tighter. It is thereforeconceivable that demand growth and limited construc-tion of new generating plant could result in a futurecapacity shortage and power cuts.

The electricity regulator, The Office of Gas and Elec-tricity Markets, has mounted a sturdy defence of theability of markets and the inefficiency of central plan-ning to avoid the eventuality of future capacity shortage(Office of Gas and Electricity Markets, 2001). We acceptthat marketscould achieve this; our purpose is to discusswhether the actual electricity markets we now have inBritain would do so. Our discussion falls into two parts:the provision of generating capacity and demand respon-siveness.

A joint Department of Trade and Industry/The Officeof Gas and Electricity Markets Joint Energy Security ofSupply Working Group, which will produce twice-yearly

∗ Tel.: +44-207262-5050; fax:+44-207724-78752.E-mail address: [email protected] (R. Turvey).

1 Visiting Professor in Regulation, London School of Economica;Associate Director, The Regulation Initiative, London BusinessSchool.

0957-1787/03/$ - see front matter 2003 Elsevier Science Ltd. All rights reserved.doi:10.1016/S0957-1787(03)00021-3

reports, has now been charged with assessing risks toBritain’s future electricity (and gas) supplies. Its tasksinclude monitoring the availability of supplies of elec-tricity and fuels used for electricity generation, theadequacy of generating capacity and the adequacy of theUK’s electricity infrastructure. It is also to identify rel-evant policy issues and to assess whether appropriatemarket-based mechanisms will bring forward timelyinvestment. Certainly, issues, such as the security of gassupplies, market power and achieving the target level ofrenewable generation are important, but they are not thesubject of this paper and so are not considered.2

2. Generating capacity

2.1. Incentives to provide capacity

How much capacity investment will be undertakenand disinvestment postponed depends on expectations ofrevenue in relation to costs.

To estimate the future revenue either from a new gen-erating plant or from continuing to run an existing plant,it is necessary to estimate (i) for how many hours, andin which hours, it will run, making allowance for out-

2 For examples of similar discussions in other countries see SvenskaKraftnat (2002) and Morey (2001).

96 R. Turvey / Utilities Policy 11 (2003) 95–102

ages, and (ii) the prices which will be obtainable in thosehours, whether from spot sales or forward contracts.These two variables are of course interdependent, sincebase loads fetch lower prices than peak loads.

Where old generating plants are concerned, onlyshort-term revenue forecasts are required. Such plantswill be retained in use for each forthcoming month oryear for which their owners expect that the revenue fromtheir output will exceed their operating costs. If not, theywill be mothballed rather than permanently closed if thepresent worth of such expectations for a few years henceoutweighs the cost of keeping them mothballed to startwith or if it is expected that, by postponing decision,better information about possible future revenue willbecome available.3

Decisions about new generating plants are different.Except for occasional open-cycle gas turbine plants, theyare very rarely built to operate in peak periods only.Embodying more recent technology, they are usuallymore efficient than older thermal plants and initiallymeet base or intermediate load. As time passes, thermalplants will gradually be displaced in the merit order bymore modern plants. Their plant load factors will fall,so that they become peaking plant. A generator will thusbuild a new plant if it expects that, over the new plant’sexpected lifetime:

the present worth of the revenue from its addition tohis total output plus any cost saving resulting fromits displacement of output of its existing lower-meritplant is likely to exceed the present worth (calculatedat their cost of capital) of the estimated costs of con-structing and operating it by an amount sufficient tooutweigh the uncertainty involved.

The lead-time for development of new generation inthe UK is considerable. Recent analysis indicates that ittakes up to two years to obtain consents and another yearor two to get financial close. Leaving these time-lagsaside, but taking account of their build times, theexpected lifetimes of plants whose construction com-mences this year (2003) will be the years 2013–2063 inthe case of nuclear power stations, 2010–2050 in thecase of coal-fired stations, 2006–2036 in the case of gas-fired power stations and, say, 2005–2025 for wind-powerstations.4 Since forward contracts of such durations areunlikely to be made, it is clear that decisions to invest innew plant must rest upon forecasts which are long-term.

3 Rates (local property taxes) in many cases paid in ten instalmentseach year are avoided when generation is suspended. Transmission useof system demand charges paid by generators are determined annually,so are escapable once a year.

4 Build times and lives taken from PIU (2002). Before constructioncommences, a couple of years is required to obtain consents and furthertime may then be required to secure finance.

The point that the time horizon for decisions aboutexisting plants is far shorter is too easily forgotten.While the adequacy of capacity to meet peak demand isa matter of ensuring that capacity additions less retire-ments match load growth, it is the decisions about scrap-ping, mothballing or continuing to operate old plants thatare the immediate determinants of the capacity margin.It will only be in exceptional circumstances—whereunforseen rapid load growth is combined with severeimpediments to the construction of new nuclear, coal,oil or CCGT plants—that preservation of an adequatecapacity margin will necessitate hastened construction ofnew interconnectors or recourse to building new open-cycle gas turbine plants.

The incentive to refrain from permanent plant closureswill be greater, when:

� The lower the costs incurred and the higher the costsavoided by keeping old generating units available.

� The higher the likelihood of pressure upon capacityand hence the firmer the expectation of occasionallyhigh prices.

� The greater the possibility of making forward optioncontracts to provide energy, so obtaining payment tocover the fixed costs of capacity availability.

We therefore have to investigate the following issues:

� Does the public interest require the conclusion ofoption contracts to ensure the provision of adequatepeak capacity? If so, what body operating in thatinterest would be responsible, and how should thecosts of these contracts be borne?

� Or, alternatively, does the public interest require thatsuppliers should be required to ensure provision ofadequate capacity to meet their possible peakdemands?

2.2. Adequate capacity

As a preliminary to examination of these issues, themeaning of “adequate capacity” requires discussion.This is a matter of the probability of power cuts, esti-mated by the convolution of expected probability distri-butions of demand and of capacity availability. Takingaccount of the possibility of extreme cold weather, a24% plant margin was, in former times, shown to berequired in order to avoid demand disconnections morefrequently than nine years in every hundred. A figure ofthe order of 20% is considered to be appropriate now-adays.

Similar calculations could again be made to providea more precise estimate of future required total capacity,taking due account of the increased reserve requirementsresulting from greater use of intermittent generation andinvolving a judgment of what risk of such disconnections

97R. Turvey / Utilities Policy 11 (2003) 95–102

is acceptable in the public interest. This would requirebalancing the social cost of disconnections against thecost of avoiding them, a matter which can only be donecollectively and so should presumably be done by TheOffice of Gas and Electricity Markets if it is to be doneat all.

At one time, but in the context of distribution security,The Office of Gas and Electricity Markets quoted surveydata on the financial impact on domestic, commercialand industrial consumers from interruptions according tothe duration of interruptions. The data came from twopapers by K.K. Kariuki and R. N. Allen (Kariuki andAllen, 1996a,b). After piloting, questionnaires were sentby post to random samples in each of three electricitydistribution companies of 7000 residential consumers,1700 commercial consumers and 700 industrial users.The aim was to ascertain the costs they would incur inthe event of disconnection. The overall response rates tothe enquiry were, most unfortunately, only 19, 8 and 6%.The Office of Gas and Electricity Markets neverthelessused the data, together with reported and forecast capi-talised costs (including operating costs) of measures toimprove distribution security, to estimate cost-benefitratios for each distribution company (Office of Gas andElectricity Markets, 1999). These received no sub-sequent mention, but if The Office of Gas and ElectricityMarkets were to decide upon what generation capacitywould be adequate, it would have to return to these mat-ters.5

In the absence of any collective decision about thelevel of generation security, it is left to market forces todetermine capacity implicitly, which is the present situ-ation. This does not provide a zero risk of blackouts, theplant margin achieved, and hence that risk, depends upongenerators’ decentralised decisions resting upon theircomparisons of expected and uncertain prospects ofprice spikes with the projected costs of postponing per-manent plant closures or building new peaking plant (theprice elasticity of demand is relevant too, but this topicis not considered until the second part of this paper).

Some of the generators have expressed unease con-cerning the present situation. Innogy asserted that “Apotential weakness of the NETA design is the removalof any form of capacity credit and there is the potentialto compromise system security unless peaking andreserve capacity is adequately remunerated” (PIUEnergy Policy Review, 2001a) Similarly, TXU arguedthat The abolition of capacity payments under NETAhas increased the pressure in this area by increasing thevulnerability of existing low utilisation plant, making itharder for such plant to cover its fixed costs. We have

5 Under the Pool, but not under NETA, fixing a capacity price ofVOLL × LOLP (which turned out to be too unstable) rather thandetermining the desirable magnitude of capacity was posssible.

discussed above some adjustments to rates and use ofsystem charges which could go some way toward ame-liorating this problem, but even so the system willdepend on generators being able to charge apparentlyhigh prices during occasional periods of shortfall. To theextent that the ability to charge such high prices is (oris perceived to be) subject to regulatory pressure, onecan expect the necessary investment to be less attractive(PIU Energy Policy Review, 2001b).

If and when suppliers foresee that peak demand maypress upon aggregate capacity, they will expect more fre-quent price spikes and may consequently be prepared tosign more long-term contracts But the question iswhether the extent of such contracting will suffice tosecure sufficient capacity to avoid unacceptable powercuts in those few hours of future years when they will bethreatened by bitter weather conditions and/or significantforced outages. Uncertainty about future price spikeswill deter such contracting. There is a danger that therole of price spikes in paying for the provision of reservecapacity will not be recognised and that they will beviewed as resulting from the exercise of market power,leading for a demand for the imposition of price caps.Yet the acceptability of possible occasional price spikesis a necessary condition if a market mechanism alone isto provide adequate capacity. Fears that it would not besufficient have led to the two proposals now discussedfor assuring adequacy.

3. Option contracts

The Balancing Mechanism does not allow the systemoperator, the National Grid Company to ensure the com-mitment of generating units, since there is no separateremuneration of startup and no-load costs in that Mech-anism. In addition to procuring frequency response ser-vices, the National Grid therefore undertakes pre-Gateactions in the form of ancillary services contracts,locational trades, BMU transactions and warming con-tract call offs in order to help deal with constraints andpossible aggregate generation shortfalls.6 Options allowit to call for output increases and decreases at pricesagreed in the contracts. The National Grid has alsodeclared that it is interested in making energy relatedcontracts with demand side providers. The costs to TheNational Grid of all these actions form part of the rev-

6 For example, on one occasion National Grid issued five noticesof insufficient margins and the short term markets displayed alarm inconsequence of the removal of several plants from the system over-night. The National Grid responded by purchasing energy through preGate Closure Balancing Transactions. Prices of up to £425/MWh werealso paid to plant such as Grain and Littlebrook through the BalancingMechanism, leading to high day ahead prices, which at one pointreached £320/MWh.


enue that it is allowed to cover from participants andwhich they are incentivised to minimise.

Similar option contracts could be concluded on amuch longer term basis than these operating reserve con-tracts if either The National Grid as System Operator orThe Office of Gas and Electricity Markets were givenan explicit responsibility for ensuring the degree of con-tinuity of supply judged to be in the public interest. Theywould then have to decide and pay in advance for theprovision of capacity that would only be called to runin extreme peak situations. This is what has been donein Sweden, where, as a short-term measure for the threewinters ending with 2002–2003 Svenska Kraftnat nego-tiated with the owners of mothballed plants to securereserve capacity. The fixed costs of this reserve were tobe met by the state reducing its required distributionfrom Svenska Kraftnat, which it owns.7 In Finland,responsibility for adequacy of capacity lies with thestate, agreements with generators being made for theprovision of “slow” reserve capacity, the cost beingrecovered alongside the electricity tax. In Norway, Stat-nett is responsible for ensuring that there is sufficientcapacity. Contracts for reserves are made for 1, 3 and12 months ahead, providing offers which are bid into thebalancing market. The cost is recovered as part of thetransmission use of system charges. In Denmark, the sys-tem operators are responsible for ensuring adequatecapacity and negotiate contracts with generators forminimum levels of capacity to cover “slow” reserve aswell as fast reserves and frequency reserves, in one casethe contract being for four years. The costs are recoveredas part of the transmission use of system charges(Svenska Kraftnat, 2002 (Appendix 5)).

A solution of a similar kind—call options purchasedthrough competitive bidding, with a high strike price(and stiff penalties for failure to deliver)—has been pro-posed by Vasquez et al. (2001).8 This would constitutea mixture of a market and a planning solution. Therewould be competition among actual or potential gener-ators for such contracts, but the National Grid as systemoperator or The Office of Gas and Electricity Marketswould have to determine their total volume on the basisof load forecasts, estimates of future available capacityand outage rates and a public interest notion of whatrisks were acceptable. The time horizon of the forecastsand the duration of the contracts could be much shorterfor postponing the permanent closure of old plants thanthey would have to be were construction of some newpeaking units deemed necessary in order to secureadequate capacity. The resulting costs should be met bysuppliers and, to obtain appropriate customer incentive

7 Elmarknaden 2002, Statens Energimyndighet.8 Cited in de Vries and Havkvoort, 2002.

effects, should be spread over energy taken duringpotential peak hours, not “smeared” over all energy.

4. Capacity requirements

Alternatively, capacity requirements related to theirnotified maximum demands could be imposed upon sup-pliers. Their licences would then have to require themto possess capacity (of their own and/or under contractswith generators for its provision) exceeding their fore-cast maximum demands by a certain percentage. TheOffice of Gas and Electricity Markets would have toapprove or make the maximum demand forecasts andlay down the required percentage of reserve capacity asthe percentage it judged to be justified in the public inter-est.

The result of these capacity requirements would bedevelopment of a secondary market in capacity rights.Most of these rights would mirror ownership or wouldbe embodied in suppliers’ contracts with generators. Theexcess of a supplier’s required capacity over forecastmaximum demand not covered by its owned capacityand contracted generation would take the form of oneor more options negotiated with generators with excessesof their capacity over their contracted outputs.

That some sort of capacity requirements system isfeasible is suggested by the existence of one in the casesof PJM and the New England and New York Inde-pendent System Operators (though their governance issuch that its enforceability may be in doubt). The mainfeatures of the latter are as follows:

� Installed Capacity Requirements are imposed on sup-pliers based on their annual peak loads

� Monthly Installed Capacity auctions accommodateloadshifting and latest generator performance

� Supply can be via bilateral transaction, self supply,or auction

� Monthly deficiency charges are applied to suppliers,if requirements are not met

� Full credit is given for interruptible loads and inter-mittent generators

� 75% Bilateral Transactions, 25% New York Inde-pendent System Operator Auctions.

The Federal Energy Regulatory Commission has nowproposed a Standard Market Design to reform the whole-sale power generation, trading, and transmission marketsin the US. To address the problem of capacity adequacythe proposals include the imposition of a ResourceAdequacy Requirement. This would supplant the currentinstalled capacity requirements in New England, NewYork and PJM. Each regional grid would have to assessthe current and future generation needs of the region andeach “ load serving entity” (for instance, a utility or


marketer) would have to be able to show that it hadobtained generation and interruptible load sufficient toserve all of its load over a planning horizon of the next3–5 years, plus 12%. This would be monitored by eachregional grid provider and enforced either through pen-alty prices or by curtailing defaulting load servingentity’s loads during emergencies. This kind of enforce-ment has been criticised as being too short-term, as notproviding long-term assurance of adequate generationcapacity and because it is not always feasible to curtailindividual load serving entities when there is retail com-petition.

Many details would need to be worked out to developa capacity requirements system in Britain.

� Available capacity would have to be defined in somesuch terms as maximum output given x hours noticeassuming no outages (these being one of the contin-gencies for which the plant margin provides). Inter-ruptible demand should be treated as one kind ofcapacity.

� Maximum demands could be determined ex ante,being forecast annual maximum demands for theaverage cold spell conditions assumed in determiningthe required plant margin. They would have to bedetermined separately for each supplier (not, as wouldbe easier, as an aggregate for each distribution net-work operator). For each non-half-hourly meteredconsumer, their Profile applied to their EstimatedAnnual Consumptions could be used. How forecastsof the maximum demands of half-hourly metered con-sumers could be made and audited would constitutea major problem. The capacity requirements wouldhave to be annual, rather than applying only duringpotential peak periods, since otherwise supplierswould seek to acquire or lose customers after orbefore those periods.

� Ascertaining and recording changes in the capacityrequirement imposed upon each supplier followingthe acquisition or loss of consumers would add to thetasks of the existing data collection system.

� Some penalty for default would have to be imposedby The Office of Gas and Electricity Markets. Its levelwould obviously act as a ceiling to capacity optioncontract prices, so it should be set high enough toreflect the whole annual costs of peak capacity.

� Alternatively, and more simply, maximum demands,weather-corrected for average cold spell conditions,would be ascertained ex post for each supplier. Sup-pliers would then be charged by The Office of Gasand Electricity Markets for any shortfall below theirshare of required available capacity, this charge againacting as a ceiling to capacity option contract prices.

� Large consumers whose loads display below-averagetemperature sensitivity would claim that their loadsmerited a below-average capacity margin.

5. Demand

It is generally accepted that the greater the responseof consumers to energy prices, the less will be pricevolatility (and the smaller will be the market power ofgenerators). In the present context of system securitywhat is at issue is not consumer responses to high energyor demand charges at regular times of potential peakknown well in advance, responses which will raise loadfactors. Tariffs which elicit such responses require amechanism for switching meter registers to record con-sumption at different prices. Time-switched EconomySeven meters (and systems in other countries with radioor ripple controlled water heaters) do this, but only atpre-established times.

The issue here is the different one of very short-termand real-time demand responses to situations of a highloss of load probability. If, in future, the capacity marginbecomes lower than at present, such situations may arisedue to the conjunction of generation outages and fiercecold weather at times of high load The greater are short-term and real-time demand responses to such contin-gencies, the better, for three reasons. One is that the riskof power cuts is diminished. The second is that thereduced volatility of prices will reduce uncertainty aboutthe profitability of postponing plant retirements andbuilding new plants. The third is that generators’ marketpower is lessened.

6. Demand side participation

The amount of demand side response in the BalancingMechanism is disappointing and is less than it used to beunder the Pool. Currently, non-generator suppliers couldcontract for interruption with generators if they madematching sets of contracts for interruptible supply withtheir half-hourly-metered customers. However, suchlarge-scale aggregation by suppliers of the half-hourlymetered demand of customers has scarcely occurred,though this may change if wholesale prices rise. Individ-ual large industrial consumers which can either cut theirconsumption at short notice or start up their own gener-ation can provide an important sort of demand responsein the form of interruptible contracts, and some half-hourly customers compete in the provision of balancingservices to the National Grid, although demand side par-ticipation in the Balancing Mechanism has been mini-mal. Selling into the Balancing Mechanism is complexand therefore costly.

A Demand-Side Working Group was set up in Nov-ember 2001 to review the range of options available todemand-side participants, and has identified obstacles to


their participation in NETA and recommended measuresto remove them.9

7. Triad avoidance

The National Grid’s use of system demand chargesfor half-hourly metered demand are charged to its cus-tomers with respect to their actual demands at times ofthe Triad. This is the average demand over the half hourof System Peak Demand and the two half hours of nexthighest demand which are separated from the SystemPeak Demand and from each other by at least 10 cleardays, between November to February inclusive. Thecharge varies between £1/KW in the Northern zone and£15/KW in the South West. Some large consumers seekto limit their consumption at anticipated triad times; oneestimate is that at least 500 MW of load are thus shifted.Some large users, such as steel and chemical works, havereduced demand to avoid these demand charges. Sincethe Triad periods cannot be accurately forecast, theyreduce their demands in all of the 25–30 half hours whenhigh system demand is expected. The result used to beto reduce the system peak by up to 2 GW. With changesin the energy market, the amount of load managementnotified to the National Grid, roughly matched by theamount of unnotified load management, has fallen fromaround 800 MW in 1998/99 to around 400 MW in2001/02. The point made here is simply that scope fordemand elasticity has been demonstrated in respect ofhalf-hourly metered consumers.

There is a proposal to replace triad demand by eachuser’s average MW demand taken between 16:00 and19:00, Monday to Friday between November and Febru-ary, excluding Bank holidays (National Grid Company,2002). It is admitted that this would remove an incentivefrom those consumers who currently load manage avoidthe current Triad periods, thus diminishing some demandresponse over the highest peak periods. It is hoped, how-ever, that the use of a defined time period for the chargesmight “ incentivise other half-hourly metered demandusers, who do not currently load manage to avoid theTriad periods, to load manage over the peak periods” .

The peak demands of non half-hourly metered con-sumers are not measured but only estimated by the useof profiles. The National Grid’s Use of System demandcharges charges for non half-hourly metered demand aretherefore based on the estimated kWh taken over theperiod 16:00 to 19:00 for such customers, taking everyday over the Financial Year and not just the winter toavoid discouraging suppliers from taking on new cus-tomers just prior to the winter season.

9 The review of the first year of NETA - A review document, vol.2, July 2002. Appendix 12 Demand side issues.

8. Real-time pricing

Interruptible contracts, which involve the impositionof load reductions on customers up to agreed amountswhen called for in exchange for a reduced demandcharges, are one way of organising a demand response.A much more flexible approach is to provide customerswith tariff incentives to restrain their demands at timesof pressure.10 Large consumers whose supply contractsare with generators can react to day-ahead prices bymodifying their consumption patterns and engaging intransactions in the prompt markets. (Water companieswho paid Pool prices used to do this, time-shifting theirpumping operations.) Suppliers of half-hourly-meteredconsumers could, under appropriate tariff arrangements,notify them of price increases when prices rise on theexchanges, motivating some of them to reduce theirloads, their response depending on the cost and incon-venience of reductions in the circumstances of the day.This would yield their suppliers a gain—in reducedexpensive power exchange purchases or lower imbal-ance charges at high System Buy prices—which theywould pass on to those of their customers for whom thefinancial impact of their load reductions would be out-weighed by the savings in their bills.

No information appears to be available concerning theextent of such arrangements, which is a pity. But it isclear that if there were less spare generating capacitythan at present, so that more and larger price spikes inthe exchanges could be expected, competition betweensuppliers would lead them to offer tariffs with real-timeand day-ahead arrangements. When greater demandresponsiveness becomes needed, therefore, it will beforthcoming—so long as the prompt markets are reason-ably liquid.

Real-time and day-ahead tariffs would thus work withhalf-hourly metering. But they do not require it; theirminimum requirement is only for separate recording ofconsumption for each of different tariff periods and amethod of changing the timing of these periods andinforming consumers of the changes. Meters are nowavailable which are equipped with display units and inte-gral modems capable of two-way communication usingfixed lines, mobile phone facilities or power lines. Theycan indicate the unit price being charged or to be chargedin the immediate future, they can store readings for per-iodic remote reading and they can record consumptiondata according to set time intervals which, along withthe prices, can be remotely updated at any time. The data

10 An email from a Norwegian friend reported that the temperaturewas �25 °C—even his dog stayed indoors—and since no new capacityhad been added during the last eight years, prices to end-user wereabout 90 øre/KWh, plus transmission and distribution charges andtaxes.


collected can be stored in non-volatile memory, all dataand settings being protected against power failure.

Electricite de France’s TEMPO tariff is an impressiveexample of such a system. It uses smart meters withprices that vary according to current circumstances aswell as by time of day and year. On a display unit thatcan be plugged into any socket, is shown a colour indi-cator for the day, days being distinguished according toprice (blue for low, white for medium and red for high),together with an indication of whether the hour is cur-rently one of eight off-peak hours or not; each eveningthe “colour” of the following day is indicated, usuallylinked to the weather. An (optional) beep will inform theconsumer if the following day will be a red day. Cus-tomers can adjust their consumption either manually orby selecting a programme for automatic connection anddisconnection of separate water and space-heating cir-cuits. Components of household consumption that couldbe adjusted include electric storage heaters, the hot watertank, washing machines, tumble dryers, dishwashersand refrigeration.

Unfortunately, full retail competition requires the useof profiling to estimate the consumption half hour byhalf hour of non-half-hourly-metered consumers. Profi-ling completely prevents the introduction of such real-time tariffs for them.11 This point is more recognised inAustralia than in Britain for, as the Australian Compe-tition Commission put it:

The Commission is not convinced that the full bene-fits of competition will be delivered in the longer termwithout a move towards interval metering. The Com-mission considers that … only interval metering, notprofiling, will provide the potential for signals toencourage demand side responsiveness and innov-ative retail tariffs, thereby leading to more genuineretail competition (ACC, 2001).12

The costs which suppliers incur in respect of all pro-filed consumers, i.e. all non-half-hourly metered con-sumers, depend upon those consumers’ annual consump-tions and attributed profiles and so are whollyindependent of the consumers’ actual load shapes. Thus,to take an example, a supplier wishing to introduce asubscribed demand tariff for small consumers (whichwould use existing metering but require installation of acircuit-breaker) could only do so if profiles had beenestablished for such consumers. Such profiles could beestimated by load research studies of a sample of suchconsumers only if they already existed!

Curiously, a recent report on smart metering,13

11 For further discussion of these matters see Turvey and Cory(1997, p. 291).

12 Cited in Essential Services Commission (2002).13 Smart Metering Working Group Report para. 3.5.

although it mentions EdF’s TEMPO tariff, recognisesthis major disadvantage of profiling only implicitly, say-ing that “Smart meters, if allied with half-hourly meter-ing in the domestic market, could also offer energy sup-pliers better ability to manage consumer demand.” .

Supply competition has its advantages, but its exten-sion beyond half-hourly metered consumers has ruledout practically all tariff innovation other than dual-fuelarrangements, and these do nothing to introduce anydemand elasticity into the behaviour of the bulk of con-sumers. The extension of the settlement system to coverprofiled consumers was extremely costly; the moneycould alternatively have been spent in lowering the half-hourly metering threshold below 100 KW. If distributionand supply to non-half hourly metered consumers hadremained in the same hands, the companies would haveborne the costs of all the energy they distributed andsold net of the half-hourly recorded consumption of cus-tomers in their territory supplied by other suppliers,grossed up for distribution losses. They would then havebeen able to weigh up the changes in cost against thechanges in revenues that would result from innovatorytariffs which exploited the possibilities opened up bytechnological developments in metering and communi-cation.

All that can be done so long as profiling continues,however, will be to extend half-hourly metering and thusthe possibility of real-time pricing, to smaller consumersthan at present. This may become mutually advantageousto some such consumers and to their suppliers withreductions in the cost of half-hourly metering and theintroduction of two-way communication. The use of rec-ording meters, polled every night by using a modem andexisting phone lines, and transmission of price warningsignals would be required. It might then be possible toreduce the almost £600 per annum on average whichsuppliers now have to pay for the metering services foreach half-hourly meter point. This cost, made up ofmeter operation, data collection and data aggregationservices14 is at present a considerable deterrent to theextension of half-hourly metering, so measures to reduceit would be very desirable.

9. Concluding remarks

I put forward no conclusions: this is a discussionpaper. I have shown that the following issues are veryimportant ones which need to be examined:

� Whether the prices agreed in long-term bilateral con-tracts and in the forward markets will suffice to pro-

14 See Appendix B of the DTI’s Smart Metering Working Group,2001.


vide appropriate incentives for existing generationplants to be retained in serviceable condition as longas necessary to ensure adequate capacity.

� Whether, as a default measure, provision of the levelof capacity deemed desirable in the public interestcould and should be secured either by centrally con-cluded capacity availability option contracts withselected generators or by imposing capacity reserverequirements upon all suppliers. Whether meeting thecosts of option contracts or a resultant market for sec-ondary capacity rights, in both cases the result wouldbe a market expression of the value of capacity.

� Whether the extent of demand response to currentprices could be increased by extending half-hourlymetering or escaping the constraints on intelligentmetering imposed by profiling.

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Documents

Ensuring Adequate Generation Capacity