Transmission Use of System Charges under Future GB Power System Scenarios. Graham W. Ault, Member, IEEE, Ian M. Elders and Richard J.

Transcription

1 > Paper TPWRS < 1 Transmsson Use of System Charges under Future GB Power System Scenaros Graham W. Ault, Member, IEEE, Ian M. Elders and Rchard J. Green Abstract If transmsson charges are to reflect costs, they should be affected by the locaton of demand and generaton. Ths paper descrbes the Investment Cost Related Prcng (ICRP) methodology used to calculate transmsson charges n Great Brtan (GB), whch s based on the margnal nvestment cost of addtonal demand or generaton, usng a DC Load Flow transport model. We apply ths exstng method to calculate charges for the Supergen FutureNet scenaros for. Ths study hghlghts the senstvtes n charges for use of the transmsson system arsng from plausble demand and generaton developments. The changes n tarffs wll present fnancal challenges for system users n some areas. The objectve of the work presented s to llustrate the senstvty of the charges produced by ths methodology to changes n demand, generaton and network topology rather than compare alternatve prcng approaches. The concluson drawn s that the ICRP system prcng method may be sutable n future years but only wth some mportant ssues nvestgated and resolved. Index Terms Power system economcs, Power transmsson economcs, Power transmsson. I. INTRODUCTION T he prcng of electrcty transmsson s a controversal subject. There may be broad agreement that a good set of transmsson prcng rules should encourage effcent operaton of, and nvestment n, the electrcal system [1], but ths s not suffcent to defne a unque set of rules. In general, there are two man classes of transmsson prcng: those based around the dfferences n margnal prces of generaton separated by a set of transmsson facltes; and the others based on the actual costs of nvestng n and operatng those same transmsson facltes. The advantages and drawbacks of these two classes of prcng methodology n the key areas of economc effcency, prce sgnals to Manuscrpt receved September 30, Ths work was supported by the UK Government Engneerng and Physcal Scences Research Councl (EPSRC) as part of the SuperGen FutureNet Consortum, grant number GR/S28082/01. Rchard Green s Drector of the Insttute for Energy Research and Polcy, 90 Vncent Drve, Unversty of Brmngham, Brmngham B15 2TT, Unted Kngdom (Tel: , Fax: , e-mal r.j.green@bham.ac.uk). Ian Elders and Graham Ault are wth the Insttute for Energy and Envronment at the Unversty of Strathclyde, Glasgow, G1 1XW, Unted Kngdom (e-mal:.elders@eee.strath.ac.uk and g.ault@eee.strath.ac.uk). transmsson network users, farness, stablty and revenue reconclaton are dealt wth extensvely n the lterature (see [2] for a thorough overvew of the varous prncples, benefts and potental shortcomngs of dfferent transmsson prcng approaches). If transmsson prces equal margnal costs, then system users who take these prces as gven should act n a way that maxmzes welfare (e.g. mnmzes the total costs of meetng a fxed demand). Ths should lead to economc effcency n both operatng and nvestment decsons. The problem s that prces equal to margnal costs wll typcally only recover a small proporton of the total cost of the transmsson system [3], and so addtonal charges wll be needed. The ICRP methodology descrbed and appled n ths paper [4] falls nto the latter category of transmsson cost based methods also knows as transmsson cost allocaton (TCA). Ths class of prcng methodologes starts from the baselne prncple of allocatng the full costs of all transmsson facltes and therefore do not suffer from the revenue reconclaton problem of generaton margnal prce methods. TCA approaches n turn are subdvded nto those based on a flat rate and those based on power flows (see [5] for a bref descrpton of some methods and the key dfferences). Among the power flow based methods, there s dversty n the approaches used to allocate the use of transmsson facltes (.e. power flows) to generaton and demand users of those facltes. The proportonal sharng prncple (PSP) [6] allocates power flows to generaton and demand users based on njectons nto branches at each node n the system but are senstve to mnor changes n generatng unt market postons. Methods based on generaton shft dstrbuton factors (DF) [7] have been shown to be senstve to the choce of slack bus. More recently proposed approaches for TCA such as Equvalent Blateral Exchanges (EBE) [5,8] overcome the noted drawbacks of PSP and DF methods. The ICRP method presented n ths paper has none of these senstvtes and the relatve merts of the approach are outlned n secton II. The problem s that the choce between alternatve rules can lead to large transfers of shares of costs between users of the transmsson system, and that many of these users are well aware of ths. Once a rule has been adopted, changng t s lkely to be poltcally dffcult, and too much nstablty can dscourage nvestment. Predctng the long-term consequences of a gven prcng rule can help determne whether future changes mght be necessary.

2 > Paper TPWRS < 2 In ths paper, we apply the transmsson prcng methodology currently used by Natonal Grd the transmsson system operator n Great Brtan (GB) to four scenaros for the electrcty ndustry n GB n, and assess the resultng transmsson charges. The scenaros [9] have been developed as part of the SuperGen Future Network Technologes ( FutureNet ) research consortum s actvtes to show possble evolutons of the power sector (and country) over the next ffteen years, as ntermedate stages n the development of scenaros for the year 2050 [10]. Natonal Grd s current methodology, known as Investment Cost-Related Prcng (ICRP) sets annual transmsson charges for generaton capacty and for consumer demand, based on system condtons at the tme of peak demand. The charges are based on the cost of buldng the network to meet the ncremental flows stemmng from addtonal generaton (or demand) at each locaton. The transmsson owners remanng revenue requrements are effectvely collected va unform charges on generaton and on demand, the approach often known as postage stamp prcng. Other transmsson chargng methodologes nclude nodal congeston prcng, when users must pay for ther ncremental mpact on congested lnks at all tmes of the year, and locatonal charges for losses, whch have so far been consdered but never ntroduced n Great Brtan. These charges can capture the short-run margnal cost of transmsson, whereas ICRP attempts to reflect ts long-run margnal cost. Our motvatons for ths work are to llustrate a chargng method that may not be well known nternatonally, and to explore the senstvty of charges to plausble system developments. Generaton developers need reassurance that ther charges wll not alter to the extent that projects become uneconomc n response to future developments. We wll show that most transmsson charges are not senstve to dfferences between the scenaros we consder, whch should provde some reassurance gven the breadth of possble generaton and demand outcomes that the scenaros cover. Fnally, the specfc predctons n the paper provde nformaton for GB polcy-makers on the future evoluton of transmsson charges. In secton II, we outlne the ICRP system, and our methodology for calculatng transmsson revenues n. Secton III descrbes the key features of the FutureNet scenaros. Secton IV apples the ICRP rule to the four scenaros, and Secton V dscusses the results. Secton VI concludes. Our am s to llustrate how senstve the charges produced by ths methodology are to changes n system condtons, rather than to compare alternatve prcng methodologes. II. GB USE OF SYSTEM CHARGING METHODOLOGY: INVESTMENT COST RELATED PRICING (ICRP) As already stated, the ICRP methodology ams to collect the full, regulated, cost of the transmsson system from ts users, wth regonal dfferentals that are based on the dfferences between the long-run margnal cost of provdng transmsson to users n dfferent areas. The ICRP methodology was developed for ntroducton by Natonal Grd n 1993 and subsequently updated n 2004 to nclude a full DC load flow model of the hgh voltage transmsson system. A full descrpton of the methodology s gven n [4]. Ths paper explores the applcaton of ths prcng mechansm and ts senstvtes to future generaton, demand and network developments. The scope of the prcng mechansm covers all the lnes defned as transmsson : 132 kv n Scotland, and 275 kv and 400 kv throughout Great Brtan. The grd s modeled at the system peak, usng the weather-adjusted Average Cold Spell demands, and scalng generaton capacty so that t exactly matches demand. For each node n turn, the model calculates the ncremental flows on each lne n the system that would arse from a 1 MW ncrease n generaton or n demand, offset by a reducton at the swng bus (Thorpe Marsh n Yorkshre). As dscussed below, the choce of swng bus wll not affect the fnal tarff. These flows are added up across the country, havng been converted nto equvalent MW-km, scalng up the length of lnes that are at voltages below 400 kv, or are underground, to reflect ther hgher cost per unt of capacty. Denotng the ncremental flow from an ncrease n generaton at node as f, we have: f = φ lr (1) k k k k where φ k s the power transfer dstrbuton factor from the DC load flow equatons that gves the ncremental flow on lne k from a 1 MW ncrease n generaton at node, l k s the length of lne k, and r k gves the relatve cost of dfferent types of lnes. It equals 1.0 for a 400 kv overhead lne, s slghtly hgher for 275 kv and 132 kv lnes, and far hgher for underground cables. To obtan a tarff, the fgures n MW-km per MW of ncremental demand have to be converted to fgures n /kw of capacty. Ths s done by multplyng them by the annualzed cost of transmsson capacty per MW-km. Natonal Grd starts wth the estmated drect annual cost of a MW of capacty on a 400 kv lne, whch t calls the expanson constant, equal to per MW-km n 2006/7. Transmsson companes n Great Brtan have to buld ther systems to an N-2 securty standard, however, and f flows rose by 1 GW, then addng only 1 GW of capacty would probably breach ths rule. Natonal Grd reflects ths electrcal realty by scalng up ts expanson constant by the locatonal securty factor, currently The practcal mpact of ths choce s to rase the prce dfferentals between nodes, compared to a system wthout ths securty factor. We would thus have a basc tarff τ gven by: τ = f = φ l r φ c (2) l k k where c k s defned as the annual cost of lne k. Lnes that Natonal Grd deems to have sgnfcant spare capacty are k k k k

3 > Paper TPWRS < 3 assgned a value of c k that s reduced by 25%. It s hghly unlkely that ths basc tarff would recover the correct amount of revenue for the transmsson companes, however, and t s adjusted to do so. Ofgem, the GB power sector regulator, has decreed that generators should collectvely pay 27% of the companes revenue requrements, and consumers 73%. Natonal Grd therefore rases (or reduces) all the ntal tarffs by a unform amount that wll allow t to meet ths requrement. Denotng the revenue to be recovered from generators by R G, and the generaton at node by g, we have a scaled tarff equal to: 1 t = φkck + RG g φkck k g k We can use equaton (3) to show that the choce of swng bus s rrelevant to these transport tarffs. Gven the propertes of the DC Load Flow model, f we choose an alternatve swng bus, s, we have a new set of power transfer dstrbuton factors φ k, where φ k = φ k φ sk. That s, the ncremental flows from any node to the new swng bus are gven by the ncremental flows from that node to the old swng bus, plus the flow from the old swng bus to the new one, or (equvalently) less the flow from the new swng bus to the old one. Gven ths relatonshp, we can calculate the scaled tarff resultng from the new swng bus, t, as: (3) absolute level of prces pad by customers n dfferent geographcal locatons whle not affectng the relatve dfferences n prces between the zones. The relatve prce dfferentals between zones are affected by the power flows (a functon of generaton and demand magntude and geographcal dsposton) and also by the annualzed cost of transmsson capacty per MW-km and the securty factor as descrbed above. These latter two factors are set by the transmsson system operator but an assessment of ther mpact s beyond ths paper. The most mportant extra step n Natonal Grd s tarff calculatons s that whle the ncremental flows are calculated for each node on the system, transmsson charges are set for 14 demand zones (the areas of the fourteen GB dstrbuton network operators) and a potentally varable number of generaton zones (currently 21). The generaton zones are chosen by groupng nodes wth smlar ncremental flows that are electrcally and geographcally close together. These zones are shown n Fg. 1. The ntal transport tarff for demand n a zone uses the load-weghted average of the ncremental flows from each node, converted from MW-km to /kw when they are multpled by the expanson constant and the locatonal securty factor. Smlarly, the ntal transport tarff for generaton s calculated from the capacty-weghted average of the ncremental flows at the generaton nodes. The correctons to get the desred revenue recovery are then made to these averaged tarffs. 1 t = φ kck + RG g φ kck k g k 1 = ( φk φsk ) ck + RG g ( φk φsk ) ck k g k 1 = φkck + RG g φkck t k g = k The choce of swng bus s thus rrelevant for the fnal scaled tarff. In practce, the calculatons used by Natonal Grd nvolve some addtonal stages, but they do not affect ths result. We verfed ths result by runnng scenaros wth the swng bus set at a dfferent locaton, and found that the prces are completely nvarant to the choce. Whle the choce of a slack bus has been shown not to affect the dfferentals n prces between dfferent areas, there wll normally be one bus wth a zero prce for generaton, and one (normally dfferent) wth a zero prce for demand. The choce of the proporton of revenues to be rased from generaton and demand customers (73:27 respectvely, as noted above) does affect the locaton of these mpled slack buses. Alterng the 73:27 splt wll alter the locatons wthn the system that return a zero charge from the methodology. In addton, t should be noted that the generaton to demand revenue splt affects the Fg. 1: Demand (left) and generaton (rght) zones n 2006 In a fnal stage, any negatve demand tarff s rased to zero. The Transmsson Use of System charges are appled to consumpton n three peak half-hours, and can dwarf the energy prce n those half-hours. Natonal Grd argues that t would be napproprate to gve users the ncentve to ncrease peak consumpton that a negatve transmsson charge mght mply, and so elmnates any negatve charges. The practcal mpact of ths rule s actually low we only obtaned a

4 > Paper TPWRS < 4 negatve demand tarff, before applyng the rule, for one zone n one scenaro. Generators n favorable locatons do face negatve capacty charges, whch amount to a payment for the support that they provde to the grd. Ths payment s only receved for the output actually suppled at the tmes of the system peak. Ths gves a strong ncentve to be avalable at those tmes (when almost all avalable generators would be runnng, n any case), but s not counter-ntutve n the same way as payng consumers to rase ther demand. The dfferent treatment of demand may owe as much to poltcs as to economcs, but we reterate that ts practcal mpact s small. The ICRP methodology should be seen as a way of decdng how the costs of the transmsson system are shared among users. It does not attempt to send short-run prce sgnals for effcent operaton, but to collect revenues n a manner that produces regonal dfferentals that are algned wth dfferences between the long-run margnal costs of provdng transmsson for users n dfferent parts of the nterconnected system. All the charges for usng the transmsson system are collected by Natonal Grd, and there are no blateral arrangements for pont-to-pont transmsson between generators and loads. The methodology does contan some smplfcatons, made n the name of greater transparency (and ths paper could only be wrtten because Natonal Grd makes ts model freely avalable), but the calculated prce dfferentals reflect cost dfferentals, and the methodology performs well aganst ts objectves. Natonal Grd s frst ICRP tarffs gnored the actual power flows (now calculated usng a DC Load Flow algorthm) effectvely sendng power along the shortest route n (adjusted) MW-km. Ths resulted n much lower prce dfferentals and hence produced a rather nferor result (from the pont of vew of reflectng costs). Snce even these lower prce dfferentals were greater than users had been facng before the ICRP system was ntroduced, ther low level may have been poltcally useful to Natonal Grd. III. GB SCENARIOS Four scenaros for the GB power system n the year were developed under the SuperGen FutureNet collaboratve research ntatve. Full detals of the scenaros are found n [9]. The scenaros address many of the key ssues affectng the power system n GB and worldwde. Some of the key ssues the scenaros deal wth nclude: Growth and development of renewable generaton Demand growth n a post-ndustral and servce orented economy Implementaton of advanced demand sde and effcency measures Retrement and replacement of the conventonal generaton fleet Declne then possble growth n nuclear generaton Dfferent combnatons of these ssues and trends (and many other drvng forces n the power sector) are collated nto four plausble scenaros for that have the followng ttles and summares: Contnung Prosperty (CP): Ths scenaro envsons a future n whch buoyant economc growth s supported by strong research and development nvestment n electrcty network and generaton technology. These factors result n an electrcty ndustry of ncreasng techncal sophstcaton, n whch long-term growth n demand for energy servces s addressed through a combnaton of contnung nvestment n network nfrastructure and strong promoton of load management measures such as energy effcency and demand-sde partcpaton. Envronmental Awakenng (EA): Ths scenaro consders a future n whch the mpact on the envronment of the electrcty ndustry, ncludng generaton, networks and end use, s a matter of ncreasngly mportant and popular concern. Ths awareness has ts foundaton n the heghtened publc awareness of clmate change and the envronment evdent currently. Supportve Regulaton (SR): Ths scenaro descrbes a future n whch the government and regulatory authortes exert a gradually ncreasng nfluence over the development of the electrcty ndustry. Ths development s brought about by ncreasng publc concern over ssues such as energy securty and strategc plannng ssues assocated wth power generaton and network nfrastructure. Economc Concern (EC): Ths scenaro envsages a future n whch the economy enters a perod of moderate declne, perhaps as a result of sgnfcant fuel prce ncreases or because of unfavorable condtons n the wder global economy. As a result, the avalablty of fnance for nvestment n the electrcty network and for research nto generaton and network technologes s restrcted. Concern over the economy tends to replace envronmental ssues n the publc conscousness; therefore pressure to acheve targets on emssons and thus deployment of renewables tends to reduce n ths scenaro. The scenaros were developed wth reference to other energy and power sector scenaro actvtes (detals of the assocated work can be found n [9] and [10]) and are ntended to provde plausble future condtons under whch the power sector wll exst. They have found wde use n the sector n GB. The four scenaros produce dfferent drvers for electrcty demand, generaton and power networks. The generaton mx and demand n each of the scenaros are detaled n Table I:

5 > Paper TPWRS < 5 TABLE I GENERATION TECHNOLOGY CAPACITY MIX AND SYSTEM PEAK DEMAND FOR EACH GB SCENARIO Generaton capacty per scenaro Generaton technology (GW) CP EA SR EC Wnd generaton Marne generaton Bomass Hydro Mcro-generaton Nuclear Large gas-fred unts Coal Total Generaton Capacty GB Peak Demand n scenaro GB Peak Demand n The ICRP zonal transmsson prcng approach leads to senstvtes n prces arsng from the geographcal dsposton of demand and generaton. Analyss of these four scenaros, wth the demand and generaton changes theren, wll llumnate theses prcng senstvtes to dfferent generaton and demand outcomes. The followng secton descrbes a seres of studes usng the Natonal Grd ICRP prcng model adapted to reflect the changes n generaton, demand and transmsson network under each of the scenaros. Ths allows exploraton of the effects of the dfferent scenaros and addtonal senstvty cases. IV. APPLICATION OF CHARGING METHODOLOGY TO SCENARIOS To calculate the ICRP tarffs for the scenaros, we therefore needed the ncremental flows n MW-km for each zone, and the overall level of transmsson revenues that the three transmsson owners would be allowed to receve. Transmsson revenues were calculated by rollng forward the prce control calculatons that Ofgem makes for the three GB transmsson companes. For a fve-year perod, the regulator predcts the companes cash spendng (operatng costs, nvestment n the network, and tax payments) and the change n the value of ther transmsson assets (nvestment less deprecaton). A company s allowed revenue s equal to ts cash spendng over the perod, less the change n the net present value of ts assets. If a company s nvestng heavly, whle deprecaton s low, the value of ts assets wll rse. Ths offsets the nvestment spendng when the transmsson revenues for the current perod are beng decded, ensurng that transmsson users pay for the assets over many years, and not all at once. We assumed that the companes controllable operatng costs would grow at 1% a year, and that ther non-controllable operatng costs would be constant n real terms. We assumed that the base level of captal expendture would rse by 3% a year for each company, and added the cost of any addtonal network nvestments that we ncluded n our scenaros. We assumed that tax payments would fall by 10% a year, gven the companes rsng nvestment levels (under the UK tax system, hgh nvestment allows companes to reduce ther tax payments). All of these trends are n lne wth those shown n Ofgem s ntal calculatons for the 2007/8 2011/12 transmsson prce control [11]. We assumed that the revenue requred over a fve-year perod would be recovered evenly across the fve years. Our chosen year,, s towards the mddle of a prce control perod, whch reduces the mpact of ths assumpton on the prces n that year. The prce control calculatons nclude revenues that wll not be recovered through the ICRP charges, such as charges for connectng to the network. We assumed that the revenue to be recovered from ICRP charges would be a constant proporton of the revenue requred from the prce control calculatons throughout the perod. Ths gave us a predcted revenue requrement, from ICRP charges, of 1175 mllon, n 2004/5 prces, on whch the transmsson prces n ths paper are based. Ths revenue s recovered from all users of the transmsson system n Great Brtan, and passed on to the three transmsson owners n lne wth ther regulated revenue requrements. A. Modfcatons to ICRP for year Our startng ponts for the applcaton of the chargng methodology to the scenaros descrbed above were the current versons of Natonal Grd s publcly avalable transmsson chargng model, and of ther Seven Year Statement (SYS) document [12]. The SYS descrbes the changes to the Brtsh transmsson network proposed for each year to 2012, and lsts new generaton developments that have entered nto contracts to connect to the transmsson system over that perod. Snce the Brtsh regulatory regme does not requre generators to provde long-term advance notce of permanent or temporary closure of power statons, the SYS does not lst such changes. The 2006 chargng model was modfed by updatng the transmsson network transport model to reflect planned changes to 2012, and addng new generators contracted to connect up to that date. The model was then projected forward to by retrng exstng gas turbne and steam (.e. coal, ol, gas and nuclear) plant based on a nomnal 40-year lfetme. No further modfcatons to the network topology were made other than those planned to 2012 n the SYS. Ths resulted n a baselne model onto whch the demand and generaton developments outlned n each scenaro could be appled. B. Modelng of scenaros Each of the scenaros descrbed above calls for a partcular capacty of the generaton technology types as lsted n Table I. In each case ths capacty wll be made up of a mxture of large, transmsson connected developments, whch are subject to the transmsson chargng regme, and smaller developments

6 > Paper TPWRS < 6 embedded wthn local dstrbuton networks, whch we assume do not pay transmsson charges, and whch effectvely reduce the demand suppled by the transmsson system. The proporton of large and small generaton s assgned for each generaton type wthn an ndvdual scenaro. Furthermore, large generators n each scenaro wll be a mxture of new capacty bult between 2012 and and exstng capacty, some of whch may be lfe extended beyond the ntally-assumed 40-year lfespan. For each scenaro and type of generaton, an assessment s made of the wllngness of stakeholders to nvest n new plant for economc or envronmental benefts n preference to extendng the lves of old power statons. Resultng plant lfetmes vared between 40 and 45 years. However, we assumed that hydro-electrc statons, some of whch are already over 50 years old, would be lfe-extended ndefntely. Generatng unts were generally retred n chronologcal order of ther commssonng date, but as complete power statons rather than ndvdual unts, snce owners would be unlkely to wsh to ncur the overhead costs of a complete power staton to support a sngle unt for the last one or two years of ts notonal lfe. New gas-turbne and coal statons were located at the stes of closed plants n the model; n each scenaro the requred volume of new coal generaton was concentrated nto two or three large statons at sutable locatons for access to local or mported coal supples. Addtonal gas turbne capacty was then dstrbuted among the remander of avalable stes n proporton to the capacty of the retred plant. New nuclear generators, where requred by a scenaro, were placed at exstng nuclear stes. The level of demand at each node n was modeled by unformly scalng the 2006 demand by the factor requred n each scenaro. The level of embedded generaton wthn each dstrbuton network operator s (DNO) area vares accordng to the scenaros and the capacty s unformly dstrbuted across the demand-carryng nodes wthn each DNO area. The full rated capacty of the embedded generaton s subtracted from the demand at each node. In some cases, ths results n net export from the dstrbuton system nto the transmsson system, whch s also (although to a lesser extent) a feature of the model publshed by Natonal Grd. The result of ths process s a model approxmatng the lkely dstrbuton of generatng capacty and demand n under each of the scenaros, whch we go on to use to calculate the level of charges payable by electrcty generators and retalers for use of the transmsson system. V. RESULTS A. Generaton Table II, Fg. 4 and Fg. 5 show our predcted generaton use of system charges, for the 21 generaton zones currently n use. Usng today s zones allows us to make a clearer comparson wth the present-day charges, but t s possble that the generaton zones mght change over ths perod. Natonal Grd groups nodes wth smlar charges nto generaton zones, and as power flows change, new groupngs mght become approprate [13]. We dscuss the mplcatons of ths below. TABLE II GENERATION TRANSMISSION USE OF SYSTEM TARIFFS FOR BASE CASES AND SCENARIOS ( /KW/YEAR) Generaton Zone 2006 Base CP EA SR EC Fg. 2 shows how the generaton tarffs vary across the country. In general, the current pattern of generaton charges n whch the tarffs decreases from north to south (generally leftto-rght n the fgure 2) s mantaned. Tarffs rse n zones whch see an ncrease n ther net exports of electrcty (generally speakng). Ths mostly affects northern zones (e.g. zones 3 and 6 are substantally hgher for the cases than the 2006 case), but an ncrease n renewable generaton n South Wales and the South West leads to an ncrease n these tarffs as well (zones 19 and 21). Snce the total revenue requrement s hardly changed from 2006, other zones experence offsettng reductons n ther tarffs. In general the charges change by a modest amount n most zones (as shown by the closeness of data ponts on the graphs) but the more sgnfcant generaton tarff changes are n the order of 5-10 /kw at whch level the economcs of generaton n those zones could be materally affected. Where the data ponts for the scenaros overly the 2006 tarff lne there s effectvely good stablty n transmsson use of system prces. Fg. 3 shows some of the generaton tarffs n a form whch allows for easer comparson between years and scenaros. There s a partcularly sharp ncrease n the tarff n zone 3 between 2006 and. Ths s a zone wth few network nodes whch s remote from the man transmsson system, and whch sees a sgnfcant ncrease n renewable generaton n all of the scenaros. As a result, the zone becomes a net exporter rather than mporter of electrcty; further generaton n ths

7 > Paper TPWRS < 7 zone would thus ncrease rather than reduce flow through the long connecton to the man grd, resultng n a large ncrease n the tarff between 2006 and. greatest varaton n charges between scenaros reflectng dfferent demand trajectores for dfferent scenaros. /kw-year Generaton Tarff ( /kw/year) BASE CP EA SR EC Generaton Tarff Zone BASE CP EA SR EC Fg. 3 : Generaton Transmsson Use of System Tarffs for selected zones - base cases and scenaros ( /kw/year) Fg. 2 : Generaton Transmsson Use of System Tarffs for each zone and scenaro There s also a sgnfcant rse n the tarff n zone 7 (Central Hghlands) whch results from the combnaton of ncreased renewable generaton and the ntroducton of an underwater cable across the Clyde estuary, lnkng ths htherto remote zone more closely to the man ctes of central Scotland. Much of the renewable output flows through these cables, whch have a hgh cost per unt of capacty. The ICRP model scales up the length of the cables by a factor of more than 20 when calculatng the MW-km of nvestment requred (after power flows are computed), resultng n ncreased generaton charges n ths zone. It s also notable that the sgnfcant negatve tarffs n the south-west (zones 20 and 21) are reduced n nearly all of the scenaros as new renewable generaton becomes avalable n these areas. However, the tarffs n these zones reman negatve; sgnalng to potental developers that new generaton n these areas would be benefcal n reducng overall network flow. Power flows nto zone 16 (Central London) rse, wth ncreasng demand but lttle or no local generaton, and the generaton tarff becomes the most negatve n the country. Whle ths mght normally provde an ncentve to locate n the area, the dffculty of ganng local plannng permsson s lkely to restrct ths. We note, however, that ths zone sees the B. Demand Table III, Fg. 4 and Fg. 5 show our predcted demand use of system charges, for the areas of the 14 dstrbuton network operators. TABLE III DEMAND TRANSMISSION USE OF SYSTEM TARIFFS FOR BASE CASES AND SCENARIOS ( /KW/YEAR) Demand Zone 2006 Base CP EA SR EC

8 > Paper TPWRS < /kw-year Demand Tarff ( /kw/year) BASE CP EA SR EC Demand Tarff Zone Fg. 4 : Demand Transmsson Use of System Tarffs for each zone and scenaro Fg. 4 shows how the demand tarffs vary across the country. It can be seen that the general pattern n whch demand tarffs ncrease from north to south contnues. Tarffs are generally hgher n than today, except n zones 10 and 14 (South Wales and South-west England). The effect over most of the country results from the dsplacement of coalfred generators n north and central England by renewable sources, partcularly n Scotland. As a result, electrcty s beng transported further to meet demand n England. The degree to whch charges ncrease depends on the extent to whch renewables are exploted. For example, n zone 6 north Wales and the cty of Lverpool renewable generaton ncreases strongly, leadng to greater self-suffcency and reduced mport of electrcty (although that whch s mported travels further). In zones 10 and 14, the ncrease n renewable generaton s suffcent to overturn the effect of ncreased transport dstance and leads to a reducton n demand charges. Ths s the corollary to the ncrease n generaton charges n these areas (generaton zones 19-21) seen above. Fg. 5 shows the demand charges for selected zones n a format whch allows clearer comparsons between scenaros. Whle some zones see only modest dfferences between scenaros, the amount of varaton s greater than for the generaton charges BASE CP EA SR EC Fg. 5 : Demand Transmsson Use of System Tarffs for selected zones - base cases and scenaros ( /kw/year). The greatest varaton s n the north of Scotland (zone 1), where the demand tarff, presently 0.5/kW-year, vares between 11.1/kW-year (n scenaro SR) and zero (n scenaro EA). Were t not for the need to avod a negatve demand tarff, ths latter value would have been even lower. It s notable that ths zone has a relatvely low level of demand at present, whch s further dluted n the scenaros by the connecton of small-scale renewable generaton embedded wthn the dstrbuton network (for whch there are sgnfcant opportuntes n northern Scotland). As the nstalled capacty of embedded generaton approaches and ultmately exceeds the total demand n ths zone, large varatons are experenced n the load-weghtngs used to average the nodal tarffs and produce a zonal tarff. Modfcatons to the tarff calculaton method are lkely to be requred to elmnate ths effect before embedded generaton reaches such a sgnfcant level, n order to provde clarty n the lkely future level of charges experenced by users of the transmsson system. It s arguable also that snce some of ths embedded generaton wll be makng use of the transmsson system to transport power to other nearby nodes n the same zone, t should therefore contrbute to the fundng of the transmsson network through the use of system chargng mechansm. Further research nto how these ssues could be farly resolved appears to be requred.

9 > Paper TPWRS < 9 C. Zonng Issues Natonal Grd has recently been requred to produce forecasts of future ICRP tarffs, and has publshed ts frst two forecasts [14,15]. Ths was a lcense requrement to gve nformaton to system users on the lkely evoluton of ther charges. Natonal Grd forecasts the tarffs for fve years nto the future (whch t descrbes as long term ) and so our results are not drectly comparable. Nevertheless, some ponts of comparson can be made. In most cases, Natonal Grd s charges change smoothly over tme, and by relatvely small amounts. Where there are large changes, they are n zones whch have lttle generaton or demand our results have the same feature n the Central London generaton zone (no. 16), for example. One feature of the Natonal Grd studes s that the generaton zone boundares are sometmes changed. In ts frst long-term forecast [14], the tarffs were based on 21 zones n 2005/6 and 2006/7, but 24 zones from 2007/8 onwards. No such changes were made n the second forecast [15], but the company s consultng on a possble re-zonng exercse [13]. Ths can have two mpacts. Frst, movng nodes out of a zone can have an mpact on the tarff across the remanng nodes, snce t wll be based on the average of a smaller set of numbers (the ntal tarffs at those nodes). Second, and more mportant, the tarff at the nodes that are moved s lkely to change sgnfcantly. Ths s nevtable, snce the crteron for movng the nodes out of ther former zone s that ther ntal tarff s now too dssmlar from ther neghbors. In the context of our results, ths rases an mportant pont. In most cases, plausble changes n generaton wll have lttle mpact on the charges for a gven zone, whch s a reassurng result for developers. Movng between exstng zones, however, or nto a completely new zone, can have a large mpact on the charges faced by a generator. Such a movement s most lkely to be requred just after a new generator has been connected to the grd, and could lead to a sharp dfference between the tarff assumed n the generator s plans and the tarff t has to pay. (Ths s not an ssue for consumers, snce ther zone boundares are fxed). Whle the DCLF model s a transparent tool for settng the ntal nodal charges, Natonal Grd nevtably, and sensbly, has dscreton n how the nodes are grouped nto generaton zones. Further research on whether ths dscreton could cause unacceptable uncertanty for generaton developers seems necessary. VI. CONCLUSIONS The ICRP transmsson use of system chargng methodology (as currently used n GB) has been descrbed and appled to scenaros for the GB power system n. In general terms, the charges reman relatvely stable across the perod to and across the four scenaros. However, on close nspecton t can be seen that n several cases, there wll be large changes n tarff out to. The reasons for these changes are the gradual change n generaton and demand dsposton over the perod and across the four scenaros. However there are some sgnfcant ssues n the ICRP methodology that may lead to more unfavorable outcomes for some system users. The effect of growng dstrbuton-connected generaton n low demand areas and the necessty for ndvdual system nodes to be reallocated to zones perodcally are two such defcences n the method. The study has provded nsghts nto the scenaros themselves snce the changes n use of system prces are not just an outcome of the scenaros but also a drver of the changes n demand and generaton. These use of system tarffs must now be used to explore whether the generaton and demand developments foreseen n the scenaros are realstc wth tarffs at the levels presented n ths paper. A second strand of work s to compare the ICRP method wth alternatve ways of chargng for transmsson. The ssues n the ICRP method revealed n ths work would provde a focus for such a comparson. Chargng for transmsson servces on a nodal bass would avod large changes when a node s reassgned between zones, for example, but the nodal charges mght be more volatle than zonal fees. One partcular concern n the GB context s that hgh transmsson tarffs mght dscourage nvestment n renewable generaton n Scotland. Revertng to the earler chargng method based on dstance mnmzaton rather than full DCLF mght reduce transmsson charges n Scotland, but an alternatve would be to keep the ICRP method and fnd some other way to ensure renewable generaton receves enough support. A proper analyss of ths ssue requres a study of nvestment decsons as well as of transmsson charges, thus combnng both strands of work suggested above. REFERENCES [1] R. J. Green, Electrcty transmsson prcng an nternatonal comparson Utltes Polcy vol. 6, pp , Sep [2] D.S.Krschen, G. Strbac, Fundamentals of Power System Economcs, Chchester, UK: Wley, 2004 (especally chapter 6) [3] I.J. Perez-Arraga, F.J.Rubo, J.F. Puerta, J.Arceluz and J. Marn, Margnal Prcng of Transmsson Servces: An Analyss of Cost Recovery IEEE Transactons on Power Systems, vol. 10,, pp , Feb [4] Natonal Grd plc The Statement of the Use of System Chargng Methodology Effectve from 1 Aprl 2006, Aprl 2006 [5] F.D. Galana, A.J. Conejo, and H.A. Gl, Transmsson network cost allocaton based on equvalent blateral exchanges, IEEE Transactons on Power Systems, vol. 18, pp , Nov [6] J. Balek, Topologcal generaton and load dstrbuton factors for supplement charge allocaton n transmsson open access, IEEE Transactons on Power Systems., vol. 12, pp , Aug [7] W. Y. Ng, Generalzed generaton dstrbuton factors for power system securty evaluatons, IEEE Trans. Power App. Syst., vol. PAS-100, pp , Mar [8] H.A. Gl, F.D. Galana and A.J. Conejo, Multarea Transmsson Network Cost Allocaton, IEEE Transactons on Power Systems, vol. 20, pp , Aug [9] G.W. Ault, I.M. Elders, J.R. McDonald R. Tumlty, and G.M. Burt Electrcty Network Scenaros for, SuperGen Future Network Technologes Consortum, Tech Rep. EPSRC/SGFNT/TR/ , July 2006: networks.org.uk/publcatons/publcatons_softcopes/epsrc-sgfnt- TR scenaros-report-July2006.pdf [10] I.M. Elders, G.W. Ault et al Electrcty network scenaros for the Unted Kngdom n 2050 n Future Electrcty Technologes and Systems, T. Jamasb, W.J. Nuttall, M.G. Polltt, Eds, Cambrdge, UK: Cambrdge Unversty Press, 2006, pp

10 > Paper TPWRS < 10 [11] Ofgem Transmsson Prce Control Revews: Intal Proposals, ref 104/06. London; Offce of Gas and Electrcty Markets, June 2006: ltatondecsonsresponses/documents1/ amend.pdf [12] Natonal Grd plc, 2006 GB Seven Year Statement avalable onlne at: [13] Natonal Grd plc, Consultaton document regardng the applcaton of the Transmsson Use of System chargng methodology for determnng the generaton chargng zones for the prce control perod begnnng 2007/08, September [14] Natonal Grd plc, Informaton Paper: Condton 5 Publcaton of Long-Term Tarffs, November 2005: 874B-DE18C35ACCB0/5269/Condton5LongTermTarffs.pdf [15] Natonal Grd plc, Informaton Paper: Condton 5 Publcaton of Long-Term Tarffs, September 2006 : Graham Ault (M 1998) receved hs Bachelors n Electrcal and Mechancal Engneerng (1993) and PhD n Electrcal Power Systems (2000) from the Unversty of Strathclyde, Glasgow, UK. Snce 1996 has been researchng n the feld of power system plannng and economcs focusng on future power system archtectures, dstrbuted generaton and utlty asset management. He s currently a Senor Lecturer at Strathclyde. Ian Elders receved hs BEng degree n electronc and electrcal engneerng and PhD n electrcal power engneerng from the Unversty of Strathclyde, Glasgow, UK n 1994 and 2002 respectvely. He s currently a Senor Research Fellow wthn the Insttute of Energy and Envronment at Strathclyde. He has prevously undertaken research n collaboraton wth SW Electrcty, Natonal Grd and GE Harrs Energy Control Systems. Rchard Green receved the degrees of BA (now MA), M. Phl and PhD n economcs, all from the Unversty of Cambrdge, UK, n 1988, 1989 and 1995 respectvely. He s Professor of Energy Economcs at the Unversty of Brmngham, UK, and Drector of the Insttute for Energy Research and Polcy there. He was prevously Professor of Economcs at the Unversty of Hull, and a Senor Research Offcer at the Unversty of Cambrdge. He has held vstng postons at the World Bank, the Unversty of Calforna and MIT. Hs man research nterests are n the economcs and regulaton of the electrcty supply ndustry.