Framework for development of enduring UK transmission access arrangements.pdf

7/28/2019 Framework for development of enduring UK transmission access arrangements.pdf

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Centre for Distributed Generation and Sustainable Electrical Energy

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Centre for Distributed Generation and

Sustainable Electrical Energy

Framework for development of enduringUK transmission access arrangements

Interim report

G. Strbac, C. Ramsay, D. Pudjianto

July 2007


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Executive Summary

As part of 2007/08 work programme on the project Access to transmission networksin systems with significant penetration of wind power, carried out by the Centre forDistributed Generation and Sustainable Electrical Energy, this is an interim report that

presents a framework for development of enduring UK transmission accessarrangements.

The current technical, commercial and regulatory framework associated with thetransmission access is fit for the purpose for which they were designed. Namely, theoperation, investment and pricing of the transmission network to support a powersystem dominated by conventional, large-scale, centralised generation plant.Conventional plant will in most instances endeavour to maximise output at times ofpeak prices and peak demand. As peak outputs are broadly correlated with peak flowson the system it is reasonable to correlate generation access requirements at peakdemand with sizing the network to accommodate peak flows, and to conclude that

generation access requirements are directly related to the capacity requirements of thenetwork. Under this regime, Transmission Entry Capacity (TEC) provides firm accessrights to the network and the cost of constraints are socialised through non-locationspecific Balancing Services Use of System (BSUoS) charges1; and the TransmissionNetwork Use of System (TNUoS) charges (with some locational element) are leviedto users in relation to the amount of TEC purchased. For systems with conventionalgeneration this approach, within the context of the GB transmission networkconfiguration and characteristic, may be considered as an appropriate proxy of userrequirements for access, which drives the correct level of investment in infrastructure.

However, the UK generation mix is now materially changing. More than 16GW of

wind generation has applied for connection to the onshore distribution andtransmission network in Scotland and about 8GW of offshore wind in England.Although not all of this generation is expected to be connected this is a verysignificant development. This new type of generation has very different operatingcharacteristics when compared to conventional plant and our analysis demonstratesthat the present access arrangements are inadequate to facilitate a cost effectiveintegration of this generation technology in the overall operation and futuredevelopment of the system. We show that the present access arrangements undulydiscriminate against wind and favour conventional plant, would lead to inefficientoperation of the system and inefficient future investment in the electricitytransmission infrastructure, ultimately leading to an increase in electricity prices seen

by end consumers. Specifically, we demonstrate that it is not economically efficient toinvest in transmission to accommodate simultaneous peak outputs from both wind andconventional generation and that transmission capacity should be shared betweenconventional and wind generation. Furthermore, the analysis has shown that windgeneration utilises this shared capacity less than conventional generation, thereforewind tends to drive less transmission investment. Discrimination between generation-types to reflect these differences in operation characteristics and output is essential ifoptimal decisions are to be made in transmission investment and if cost-reflectivepricing regimes are to be devised.

1 It is important to emphasize that the volume of constraint costs have been relatively small.


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In this context the objectives of this report are:

to review the current transmission access arrangements in light of the presentchallenges of integration of large amounts of wind generation in Scotland andpresent the evidence in support of a radical change in access arrangements

to set out the high level requirements for enduring transmission accessarrangements and

to develop a framework for enduring transmission access that would deliverefficient transmission infrastructure investment for a system with significantcontribution of wind power

to outline the work programme that we intend to carry out over the next severalmonths in support of the Transmission Access Review that was recentlyannounced by BERR and OFGEM.

These aspects of the report are summarised in the following sections:

Need for a radical change in access arrangements:

In our recent study2 we conducted a cost benefit analysis of the need for transmissionnetwork capacity for a future UK electricity system with significant penetration ofwind power. The study demonstrates that in areas with a mix of conventional andwind generation, rather than sizing the network to meet simultaneous peak outputsfrom generation, it is economically more efficient for transmission capacity to beshared between generators (i.e. transmission is not sized to meet simultaneous peaksin output). In this instance conventional generation is constrained off on windy dayswhen wind generation dominates the shared capacity.

In the light of this finding, application of the present regulatory and marketarrangements to a system with significant penetration of wind generation has severalshortcomings which centre on the inability of the present arrangements to allowsharing of capacity:

(i) Inability to deliver economically efficient transmission solutions

In the investment time horizon, the concept of TEC prevents sharing of transmissioncapacity, which is fundamental for achieving efficient investment in transmissionwhere there is significant penetration of non-conventional generation. Broadly, the

present transmission access regime forces all users to acquire long term TEC3 up tothe value of their maximum output. This is clearly inefficient in systems with windgeneration, as it inherently leads to overinvestment in transmission and it underminesthe concept of sharing of transmission assets, demonstrated to be optimal. Ouranalysis shows that the discrepancy in TEC driven solutions for network design andeconomically optimal solutions (that include sharing of capacity) can be verysignificant.

2 Strbac et. al (2007) Transmission Investment Access and Pricing in systems in Wind Generation, Summary Report, DTICentre for Distributed Generation and Sustainable Electrical Energy. Available on www.sedg.ac.uk.

3 Investors in new wind projects require TEC in order for the investment to be financially viable, however this simply reflectsthe fact that there is no other choice available for alternative access arrangements.


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Furthermore, it is important to emphasise that this lack of choice in access alsoextends to inefficiencies in the operational timescale. Generators without long termaccess rights (i.e. TEC) are not allowed to generate at any time, irrespective ofwhether the network is congested or not. In the short-term, this is clearly inefficient asit un-necessarily prevents users from accessing the system and could restrict

competition in generation (ultimately leading to an increase in electricity prices).

(ii)Creation of a discriminatory environment against wind generation anddemand

The TEC concept is designed to reflect the requirements of conventional generationand this is not aligned to the costs imposed by non-conventional generationtechnologies. Our study demonstrates that in exporting areas wind generation tends todrive less transmission investment which is not reflected in the TEC approach todetermining transmission capacity required by new generation. TEC is used as thebasis for the TNUoS charges and hence the present regime overcharges wind power.Furthermore, the TEC concept and related charging arrangements exclude demandand charge this user unequally against generation. This is both inefficient anddiscriminatory (further discussion of the implications of future transmissionarrangements on the demand side are included in section 4).

(iii) Restrictive and inefficient pricing regime

In future systems, transmission network capacity should be shared amongst variousgenerating technologies and hence the network will be occasionally constrained.Users competing for this shared capacity will need the opportunity to exercise a

choice between exposure to the short-term cost of access (during the periods ofconstrained operation) versus purchasing a known-price firm-access product (thatsupports network reinforcement at marginal investment costs) and paying use ofsystem charges. To allow this choice an ex-post short-term market for access isrequired to reveal the value of transmission in real time. Within the present chargingframework this cannot be achieved as this only considers long term access or noaccess at all.

It is important to emphasise that this lack of any short term valuation of access isinherently linked with the way the transmission network is priced, namely long-terminvestment based pricing. This approach intends to charge users based on the long

term investment cost they impose on the network and prevents the application of theprinciple of sharing of transmission capacity which results in inefficiencies.

This approach is also not in line with the pricing of wholesale electricity, which isbased on an ex-post short term generation costs. The current market arrangementsseparate consideration of energy and access and send no locational signals to users ofthe system on their short term impact on the system. This prohibits system users fromtaking appropriate actions to optimise their requirement for transmission.

As a cost reflective short term value of access is unavailable, the present approachdoes not provide access choice to existing and new generators and prevents them frommaking efficient decisions regarding their use of the system in the short and long


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term. This results in inefficient operation of the generation system and inefficientfuture investment in transmission.

In summary, the current TEC based approach to transmission investment and pricingcannot facilitate cost effective (and timely) integration of substantial amounts of non-conventional generation into the UK transmission system. Fundamental revision ofthe current TEC based arrangements to reflect the diversity of different generatingtechnologies and to incorporate the short term valuation of transmission is essential ifaccess arrangements for systems with significant contribution from wind energy are tobe cost reflective and transparent.

Fundamental criteria for the development of access options

This report outlines a number of core criteria that should be considered in thedevelopment of enduring transmission arrangements: (i) cost reflectivity, (ii)availability of choice in access arrangements, (iii) reflection of differences in

generation characteristics, (iv) representation of location and time of use, (v) sharingof access between generation technologies, (vi) continuity between short and longterm value of transmission and (vii) flexibility to deal with increased uncertainty infuture generation development.

These are the factors required to create effective and efficient arrangements thatconform to the fundamental economics of a system with a high penetration of windgeneration and provide a level playing field for all system users including demand.

These criteria will be used and elaborated in more detail in the section below thatpresents a market-based approach to access using ex-post, short-run marginal cost(SRMC) based access pricing. The strengths of this market approach are identified

through comparison against the present invest and connect approach and therecently debated connect and manage philosophy.

Enduring access arrangements based on ex-post SRMC access pricing

As discussed earlier, the key requirement for achieving efficient investment in asystem with significant penetration of wind power is an understanding of not only thecost but also the value of transmission in both the short and long term. To achieve thisrequires the creation of an ex-post (overrun) short-term market for access that wouldclear every half hour, consistent with the wholesale electricity market. This ex-postSRMC based access pricing will mimic Locational Marginal Pricing (LMP) concept4

in the British model, whilst maintaining the separation of energy market fromaccessmarket (SRMC transmission access price =LMP Reference Energy Price5). Fromthis ex-post SRMC transmission access price, the market participants (including thesystem operator) can derive appropriate hedging products e.g. trading / auctions ofaccess rights over various time horizons that allow them to balance their position

4 It is important to emphasize that there are no technological obstacles for the implementation of an ex-post spot market fortransmission access. The LMP is implemented, among a number of jurisdictions, in the Nord Pool (zonal prices) and in thelargest Electricity Pool in the world, Pennsylvania, Jersey and Maryland, where ex-post LMPs for more than 50,000 busbars arecalculated every 5 min.

5 From routine calculation of LMPs and from an established Reference Energy Price, SRMC based transmission access prices(overrun prices) can be easily determined for both generators and loads at every busbar (or zone) in the network.


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ahead of real time (as is the case in the wholesale electricity market)6. Given that thechange in access arrangements is driven by the need to integrate wind power costeffectively, and having in mind the variability of wind power over short term timehorizons, it is essential thattrading includes half hourly resolution (as seen in thewholesale electricity market)7. However, it is essential that system users always have

the option to overrun and pay the ex-post SRMC access price that reflects themarginal costs of resolving the constraint caused by the overrun. This ex-post(overrun) price is the key for establishing the value of any ex-ante hedging contractand ultimately the value of existing and future transmission investment8.

This report outlines the high level characteristics of a spot-market for transmissionaccess, based on ex-post SRMC access pricing. The report compares this market casewith the present invest and connect approach and recently discussed connect andmanage philosophy (see figure below)9:

Predict CompetitiveMarket

Ex-postmarket for

access

PHILOSO

PHY

METHOD

FEA

TURES/

REQUI

REMENTS

Adapt existingarrangementsmarginally.

E.g. modify accessproduct for variablegeneration

Provide firm accessfor all generation.

Observe constraintcosts and volume

Invest where need forcapacity is shownDevelop appropriatepricing regime

Derive Short RunMarginal Costs(SRMC) fortransmission

Develop market foraccess andappropriate hedgingproducts

Increasingly market based and transparent arrangements

Observe

Invest thenconnect

Connect andmanage

Framework for development of future transmission access arrangements

The Predict philosophy in the figure above, is broadly in line with the current GBinvest then connect arrangements. Under this approach, all future marketdevelopments and investment requirements are predicted through forecasting users

6 It is important to note that establishment of an effective ex-post short-term access market is the key factor in achievingefficient and optimal enduring arrangements in systems with intermittent renewables; trading of access (or auctions) anddevelopment of long term hedging products is of secondary importance as none of this is meaningful without the derivation of ancost reflective ex-post spot access price.

7 Attempting to draw parallels between the transmission accesses arrangements for gas and electricity may not be appropriate.Trading arrangements limited to months or weeks ahead, as seen in the gas market, are not appropriate in an electricity systemwith a significant penetration of wind power characterised by relatively large short-term forecasting errors driven by thevariability in wind generation output.

8 In an over-invested transmission network, the network will be unconstrained for a significant proportion of time and hencethe short term value of access may be very low. Where constraints are prolonged and corresponding costs are consistently high,with the short term marginal costs of transmission being greater than the marginal cost of transmission reinforcement, this shouldsignal the requirement for long-term investment in new capacity.

9 Although it may be possible to derive different variations and combinations of the options analyzed, these are not elaboratedfurther given the objective of this paper.

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need for transmission over long term (ideally covering the life span of thetransmission assets) including users commitment through purchase of TEC. Thisapproach could be marginally improved through a development of the planningprocess which quantifies the different impact of individual users on the demand fortransmission capacity with a greater level of accuracy. Practically, this would require

a more transparent process to be established between the amount of TEC issued andthe actual transmission capacity required to support it.

In the connect and manage system constraint costs caused by users activity on thesystem will be monitored and observed, and the system operator will act on trends incosts to stimulate long term investment where it is economically optimal. Under thisapproach there is increased transparency in the derivation of the short-term value oftransmission and the need for long term investment, but constraint costs are socialisedand system users are not exposed to the full costs of their actions.

The table below compares the market approach with the two approaches describedabove against the requirements for achieving efficient system operation and

investment.

Future options for developing transmission investment, access and pricingarrangements against identified core performance requirements

Predict costs Observe costs Competitive marketPhilosophy &

Method

RequirementInvest then connect Connect and manage

Ex-post market fo raccess

Cost

reflectivity

Not cost reflective,absence of link

between TEC andTNUoS charge

Proxy for long-termcost reflectivity fromobserved constraint

costs. No signal forshort-term costs

Cost reflective,provided efficient (ex-

post) SRMC for accesscan be established

Access choice Only long term access Not applicable

Full choice between noaccess (i.e. ex-postreal time pricing) tolong term firm access

Reflection ofdifferences ingenerationcharacteristicsand inclusionof demand

Limited ability of TECto discriminatebetween generationtechnologies reducesopportunity to reflectdifferences accurately.Arrangements favourconventionalgeneration andexclude demand

Identification (throughobservation) andincorporation ofspecific technologycharacteristics intoarrangements is

required, but still doesnot allow full inclusionof demand

Different generationcharacteristics anddemand implicitlyincluded in marketapproach (providedappropriate marketproducts are devisedto support activity)

Representationof location andtime of use(TOU)

No short term market,TEC inherently unableto establish linkbetween TOU andimpact on investment.Too inflexible. Long-term locational signalsfrom TNUoS charges

NG observes impact ofshort-term locationaland temporalvariations in use, butthis is not signalled tousers. Long-termlocational signals fromTNUoS charges

Location specificSRMC of transmissionpublished half hourly,equivalent to locationalBSUoS charge.

Al low sharing

of capacity

No sharing of capacity

possible

The managed

approach facilitates

Sharing of capacity

implicitly included in


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sharing of capacity market approach

Continuitybetween longand short termvalue oftransmission

No direct/transparentlink between long andshort term value, bothare based on NG

prediction of userrequirement

Increasedtransparency on linkbetween long andshort term value as NG

and regulator observeshort term costs

Correct market designshould allow continuitybetween long and

short term value

Able to dealwithuncertainty ingenerationdevelopment

No, inflexible approachmakes it difficult torespond to unpredictedchanges in generationdevelopment

Yes, to an extent.Connect and manageallows someresponsiveness. Butsome market proxyarrangements are stillinflexible to change

Yes, dealing withuncertainty ingenerationdevelopment is implicitin a market approach

From the analysis summarised in the table above, we conclude that the option basedon predicting market and system conditions and the invest then connect approach, is

inherently inappropriate for systems with significant penetration of wind generationand a mix of generation technologies. The TEC based approach does not offersufficient choice in access (generators without long term access cannot generate) andhence it does not allow sharing of capacity, cannot differentiate between generationtypes and maintains the current situation of excluding demand from having an activerole in the transmission investment and access framework. Under this option, theinability to differentiate adequately between generation technologies means thatpricing arrangements are not cost reflective and non-conventional generation ischarged disproportionately to its true impact on the system.

The option of connect and manage which allows full access to all users of the

system does improve the cost reflectivity of the system. This approach allows thecosts that users impose on the system to be observed, so there can be some reflectionof time of use of the system and differentiation between generating technologies. Italso inherently allows sharing of transmission capacity. There is an increasedtransparency of the process in determining the need for additional capacity, howeverthere is the danger that under this approach, without timely investment inreinforcement constraint costs could escalate and remain high for unacceptably longperiods. It is important to consider the changes in volumes of the short term constraintcosts over a number of years, given that this should be compared with transmissioninvestment costs (that will be active over a 40 year time horizon). Hence the patternsof decommissioning of existing plant and commissioning of new plant (and demand)

within transmission boundaries will also be an important consideration under thisapproach. There is also no explicit method for the involvement of demand in thesearrangements. Clearly, this option has considerable advantages over the Predictphilosophy and may be appropriate as an interim solution before the enduring marketbased access arrangements are developed and implemented.

The approach based on a competitive market philosophy is the only option able todeliver an optimal system and fully cost reflective prices for all system usersincluding demand. As discussed earlier, in order to provide users with a full choice ofaccess options that is critical for delivering efficient investment, a cost-reflective ex-post, real-time spot market for access is essential. From this spot price (derived from

the SRMC based access price), a spectrum of efficient hedging products for access


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could be developed for trading of access ahead of real time (similar to forward andpower exchange markets). Trading will facilitate sharing of capacity, and thedevelopment of longer term products would allow users to hedge against the risk ofexposure to spot access prices and ultimately to signal the need for investment inadditional capacity. When the market participants purchase sufficient amounts of long

term firm access this action can justify network reinforcement10

.As this ex-post SRMC based access pricing will mimic Locational Marginal Pricing(LMP) concept in the British model it will be essential to consider Location MarginalPricing concept as an important alternative and candidate for the development offuture market based energy and transmission arrangements.

The key feature of the ex-post spot market for access approach that differs from theconnect and manage option is that the market for access delivers a locational (i.e.nodal/zonal) BSUoS charge (levied against use of system over and above TEC) thatprovides cost reflective allocation of the short term costs of transmission access11.Whilst these costs may be observed in the connect and manage option, they will not

be made transparent to users.

In systems with significant penetration of wind energy, the value of access totransmission network for generation in highly export-constrained areas (e.g. Scotland)will increase. Under a location specific approach for pricing short-term access, thiswill lead to a reduction in energy prices in these areas, particularly during periods ofsignificant wind generation output (i.e. on windy days). There is the potential forprices to drop to the extent that previously latent demand response may be activated,increasing demand for the cheap electricity and possibly displacing gas which wouldhave been otherwise burned (e.g. possibly in industrial processes that use CHP). In thelonger term, if economically optimal, this demand side fuel switching could also

displace the need for transmission investment

12

.In summary, in order to solve the long term transmission investment problem and tofacilitate cost effective integration of wind energy in the UK, there is a need forradical shift in the approach to transmission access pricing from long term investmentbased network pricing to ex-post SRMC access pricing. Our discussion also concludesthat a part of the radical change should also include the incorporation of demand inaccess arrangements.

Future work to develop enduring arrangements should focus on quantitative analysisof the merits of the market approach versus a possible interim solution of connectand manage and an evaluation of the practical issues behind development and

implementation of a full market for transmission access including LMP. The work-programme of the Centre for DG & SEE will include the following activities:

10Successful implementation of market based arrangements may require that the evergreen access rights of existing generatorsare phased out, and in this context it may be appropriate and important to examine international experiences.

11 With this in mind, the option of basing transmission development on observed costs and the connect and manageapproach, although not ideal, has many positive points. It could be quick to implement and could be an interim solution on theway to a full competitive market for access that would get new wind generation connected to the system in a timely manner.

12 In Denmark for example, there are significant initiatives to increase demand side participation to manage cross-bordertrades and instead of exporting wind energy on windy days to Norway at zero marginal price, to encourage local demand to usethis electricity and displace usage of gas. Similar opportunities may exist in Scotland and it is important that demand participantsunderstand the access related value of their consumption.


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Evaluate the economic impact of the integration of wind energy in the UKsystem on wholesale energy prices, transmission investment, constraint costsand access prices for alternative future development scenarios

Elaboration and discussion of technique for determining ex-post SRMC oftransmission access and related market structure for trading of access.

Quantitative evaluation of options for future transmission access arrangements

Ex-post market design, exploration of access products and options for accesstrading, such asbilateral or open auctions, including the participation of thesystem operator13.

Analysis of the impact of demand response to high energy price differentialscaused by transmission constraints

Analysis of issues associated with approaches to transmission investment,access and pricing, including: separation of energy from access, merchant

versus monopoly investment, financial versus physical transmission rights andevergreen property rights for transmission access

13 Possible options for access trading including release of capacity in the short term by the system operator are presented byLewis Dale of National Grid at the Transmission Working Group meeting on 18 July 2007.


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Table of Contents

1 Introduction and background to the report......................................................... 12

2 Assessment of the current access arrangements in GB: the need for change.... 13

2.1 Summary of the current arrangements (BETTA) ........................................... 13

2.2 Economically efficient transmission investment in systems with windgeneration........................................................................................................ 14

2.2.1 Background..........................................................................................................142.2.2 Integration of wind generation.............................................................................142.2.3 Shared transmission capacity between conventional and wind generation..........14

2.3 Inefficiencies of the present transmission access arrangements..................... 17

2.3.1 Shortcomings of the TEC approach for long-term investment and pricing.........172.3.2 Implications of the inflexibility of TEC, access choice and need forvaluing transmission............................................................................................18

2.3.3 Unequal treatment of demand and generation.....................................................202.3.4 Implications of inefficient market and regulatory arrangements.........................20

3 Requirements for future transmission arrangements......................................... 22

3.1 Cost reflectivity............................................................................................... 22

3.2 Access choice.................................................................................................. 23

3.3 Reflection of differences in generation characteristics and inclusion of

demand............................................................................................................ 233.4 Representation of location and time of use..................................................... 23

3.5 Sharing of access between system users......................................................... 24

3.6 Continuity between short term and long term costs........................................ 24

3.7 Flexibility to deal with uncertainty in future generation development........... 24

4 Case for ex-post market based enduring transmission access arrangements..... 26

4.1 Predict Philosophy: Invest then connect......................................................... 26

4.2 Observe Philosophy: Connect and manage..................................................... 27

4.3 Competitive Market Philosophy: Ex-post market for access.......................... 28

Implications for demand......................................................................................... 30

4.4 Summary of options for future transmission arrangements............................ 31

5 Conclusions and Future work............................................................................ 35


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1 Introduction and background to the report14

The UK generation mix is now materially changing with more than 16GW of windgeneration applications for connection to the onshore distribution and transmissionnetwork in Scotland and about 8GW of offshore wind in England. Although not all of

this generation is expected to be connected this is a very significant development. Thecurrent market and regulatory frameworks that support the optimal and cost reflectiveoperation of the system were devised for a system without this significant penetrationof renewable generation. As the adoption of non-conventional generation acceleratesand the generation mix and system operation undergoes material change, the currentregulatory framework will not be equipped to facilitate the development of an optimalcost effective transmission system.

This new generation has very different operating characteristics when compared to theconventional plant and our analysis demonstrates that the present access arrangementsare inadequate to facilitate a cost effective integration of this generation in the overalloperation and future development of the system.

There is a clear need to undertake the development of new enduring arrangements fortransmission that are capable of creating an inclusive framework for all newgeneration entering the network15.

The next step in development of these enduring arrangements must be to identify thefundamental criteria that define optimal and efficient (market based) arrangements forsystems with a significant penetration of renewable generation. Once defined, thesecriteria can be used as a metric of performance against which the currentarrangements and any future options can be measured.

In this context the objectives of this report are:

to review the current transmission access arrangements in light of the presentchallenges of integration of large amounts of wind generation in Scotland andpresent the evidence in support of a radical change in access arrangements(Section 2)

to set out the high level requirements for enduring transmission accessarrangements ( Section 3) and

to develop a framework for enduring transmission access that would deliverefficient transmission infrastructure investment for a system with significantcontribution of wind power (Section 4)

to outline the work programme that we intend to carry out over the next severalmonths (Section 5).

14 As part of 2007/08 work programme on the project Access to transmission networks in systems with significantpenetration of wind power, carried out by the Centre for Distributed Generation and Sustainable Electrical Energy, this is aninterim report that presents a framework for development of enduring UK transmission access arrangements.

15 There are also a number of short term practical problems inhibiting the integration of renewable generation, (e.g. tacklingproperty rights to transmission access for incumbent generators and addressing concerns over market power). These challengesalso require attention as part of the overarching assessment of transmission arrangements. However, without a framework fornew and enduring transmission arrangements, and a metric for assessing the impact and efficacy of these arrangements themateriality of these challenges is difficult to quantify. As such, exploration of these issues is out of the scope of this paper, whichfocuses on the development of enduring transmission arrangements to support the cost effective integration of new generationtechnologies, primarily wind.


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2 Assessment of the current access arrangements inGB: the need for change

2.1 Summary of the current arrangements (BETTA)

Privatisation and liberalisation of the electricity sector in the UK led to developmentof competitive markets in generation and supply, but the activities of transmission anddistribution although privatised were identified as natural monopoly functions andmaintained as separate, regulated entities. The British Electricity Trading and

Transmission Arrangements (BETTA)16 approach maintains the situation adopted byNETA of decoupling energy and transmission access.

Under BETTA, there is unconstrained (non-location specific) electricity trading incompetitive wholesale electricity markets based on half hourly ex-post BalancingMechanism. Transmission access for generation is linked to transmission investmentand administered through the Transmission Entry Capacity (TEC) product, so all

generators wishing to connect and export to the transmission system must holdTEC17. Connection is on the basis of invest then connect, so necessary networkreinforcements are made before connection is allowed and TEC is then issued (theSystem Operator cannot issue more TEC than there is transmission capacityavailable).

For generators, TEC represents the maximum allowable output from any givengenerator, at any point in time and provides the generator with guaranteed, long-termfirm access rights for transmission. Generators holding TEC will be compensated bythe System Operator if they cannot access transmission up to their purchased TECcapacity.

For the System Operator, TEC is used as a proxy to determine transmission capacityrequirements (and corresponding investment) to accommodate new generation intothe network (i.e. optimise constraints while ensuring adequate security levels). Long-term network reinforcement costs are recovered through Investment Cost RelatedPricing (ICRP) that indicates the marginal cost of connection for generation (based on

TEC) and derives a locational cost element of the Transmission Network Use ofSystem (TNUoS) charge, an additional non-locational element is then added forrevenue recovery.

In the short term (real time operation) transmission availability and constraintsresulting from contracts formed in the electricity market are managed through thebalancing mechanism. The system constraint costs (the discrepancy between theamount paid to generators constrained on, and paid out by those which are constrainedoff) are separated from energy imbalance costs (where generators have over/underproduced according to their contracted volumes). The resulting Balancing Service Use

16Until April 2005 the electricity wholesale market in Scotland operated under different arrangements from those in Englandand Wales. Introduced in the Energy Act 2004, the British Electricity Transmission Trading Arrangements (BETTA) replaced theprevious arrangements by unifying the markets and transmission systems of England and Wales with Scotland. BETTAintroduced a single wholesale electricity market for Great Britain with a single transmission system operation (National Grid)independent of generation and supply. The interconnector between England and Scotland became part of the overarching GBtransmission system, and Scottish generators (and demand) had unrestricted access to the markets in the South.

17 There is no equivalent product for demand (i.e. Transmission Exit Capacity), demand access and charges are based on anex-post assessment of usage.


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of System (BSUoS) charges include the cost of losses and are shared equallythroughout all market participants according to their traded volumes.

2.2 Economically efficient transmission investment in systems with

wind generation

2.2.1 Background

There are currently 16GW of onshore wind applications in Scotland and a further8GW of offshore-wind applications in England. The current challenge for connectionand integration of wind generation in Scotland is an example of the materiality ofrenewables disrupting the equilibrium of the existing arrangements (designed for aconventional power system). The impact and implications of integration of significantlevels of wind generation into the system raise some of the key challenges outlinedearlier. Firstly, how to make timely short-term connections of renewables on to thesystem, and secondly, how to address the longer-term issues on the development of

enduring arrangements to create a cost-reflective environment for new (non-conventional) generating technologies? This section discusses fundamental economicsof investment, access and pricing of transmission systems with wind and conventionalgeneration,

2.2.2 Integration of wind generation

Wind generation is significantly different to conventional generating technologies forwhich the current arrangements were devised. The current arrangements weredeveloped on the basis that generation technology would be operating at maximumoutput during times of peak system operation (i.e. peak demand, coincident with peakprices). In context of transmission planning and pricing there is an assumption that all

conventional generation operates during system peak, therefore it has been reasonableto design transmission on the basis that during peak demand conditions all generationwill require full access to the network.

Wind however, is dependent on the weather conditions to generate and correlationbetween peak demand conditions and output are very weak18. Output from windgeneration is very variable (intermittent), and it can be predicted to a certain degree,but forecasts for generation become increasingly accurate closer to real time.

These differences in operating characteristics, time of use of the system etc. have afundamental impact on the way in which wind generation uses the system and drivesinvestment in transmission. At present this is not reflected in the commercial and

regulatory arrangements that govern transmission investment, access and pricing.

2.2.3 Shared transmission capacity between conventional and windgeneration

When addressing transmission system reinforcement to accommodate the connectionof new generation, consideration of the cost-benefit implications of connection may

justify the installation of additional network capacity to allow efficient utilisation of

18 Oswald Consulting (2006) Effects of 20GW of distributed wind on the UK electricity system: An engineering assessmentcarried out for the Renewable Energy Foundation, http://www.ref.org.uk/images/pdfs/ref.wind.smoothing.08.12.06.pdf


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low marginal cost generators19. Decisions taken to reinforce transmission can bejustified if the savings in the marginal reduction in generation costs (marginal cost ofconstraints) is greater than the marginal transmission network investment cost.

Our recent study20 in this area developed an investment optimisation methodology(using a simplified GB transmission model, Figure 1) that, through simulation andoptimisation of the system operation across an annual time horizon, balances theannual generation costs and annuitised investment costs in order to analyse the needfor transmission system reinforcements.

The methodology illustrates that in areas dominated by wind power, with limitedscope to constrain-off conventional generation (on windy days), the optimal capacityof transmission should be equal to the installed capacity of wind power, given that itis generally significantly more costly to curtail wind than invest in transmission.However, in areas with a mix of conventional and wind generation, costs ofconstraints could be lowered significantly (determined by the fuel cost differentialsbetween generation constrained locations). Hence the optimal network capacity built

should be shared between wind and conventional generation, with conventionalgeneration being constrained off on windy days when wind output dominatescapacity.

TB2

TB1

TB3

TB4

TB5

TB6

TB7

TB8 TB9

TB10

TB11TB12

TB13

TB14

1

2

3

4

5

6

7 8

10

9

11

12

13 14

Figure 1: Simplified Great Britain (GB) transmission system

To illustrate the outcome of a CBA for transmission requirements in the case ofconnection of wind in Scotland, 10GW of wind is connected in locations in Scotlandin the GB model outlined above. The results for economically optimal transmissioncapacity at each of the 14 boundaries are presented inTable 1. The analysis assumesthat no conventional plant will be decommissioned in Scotland (worst case scenario)

19 The application of cost-benefit analysis techniques to determine transmission investment relies on a range of assumptionsthat may be open to debate, including future generation technology distributions, fuel costs, projection of future constraint costsand their variations in time and space, and network reinforcement costs.

20 Strbac et. al (2007) Transmission Investment Access and Pricing in systems in Wind Generation, Summary Report, DTICentre for Distributed Generation and Sustainable Electrical Energy. Available on www.sedg.ac.uk.

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and that constraint costs are reasonably cost reflective. The total installed capacity ofgeneration (conventional plus wind) in Scotland is fixed at 19.5GW, and local load isset at 6.5GW.

Under these conditions, building additional capacity at the Cheviot Boundary(boundary number 5 between England and Scotland) to accommodate peak outputwould indicate the construction of more than 10GW of capacity (total generationcapacity less local demand). However, fromTable 1 it is observed that economicallyoptimal network capacity across this boundary (boundary number 5) should be set at5.4GW. This result provides clear evidence that it is not economically efficient toinvest in transmission to accommodate simultaneous peak outputs from both wind andconventional generation and that transmission capacity should be shared betweenconventional and wind generation. In other words, on windy days the capacity oftransmission corridor between Scotland (S-SPTL) and England (UN-E&W) isprimarily used to transport wind power, while on non-windy days, this capacity wouldbe used to export energy from conventional plant.

BoundaryNo.

From To Capacity (MW)

1 NW-SHETL N-SHETL 2437

2 N-SHETL S-SHETL 3571

3 S-SHETL N-SPTL 4110

4 N-SPTL S-SPTL 3564

5 S-SPTL UN-E&W 5357

6 UN-E&W NE-E&W 4935

7 NW-E&W NE-E&W 1942

8 NE-E&W NE-E&W 2218

9 N-E&W M-E&W 787010 MW-E&W M-E&W 4798

11 ME-E&W M-E&W 4459

12 M-E&W SE-E&W 8434

13 SW-E&W SE-E&W 2781

14 SE-E&W SE-E&W 1438

Table 1: Economically efficient transmission capacities associated with key system boundariesfor 10GW wind power in Scotland and 3GW in England

This example will change if wind generation is the primary source in an area, forexample in the proposed Beauly-Denny transmission connection. Here, wind is theonly source of exporting power, so it becomes economically viable to install

transmission to accommodate (almost) the full peak output of wind generation andprevent curtailment of a zero-marginal cost generator.

The cost-benefit approach illustrates that economically efficient transmissioninvestment is made when the opportunities for sharing of transmission betweendifferent generating resources are recognised.

Additional analysis has shown that the contribution of wind generation to use of thisshared capacity is less than conventional generation, therefore wind will also tend todrive less transmission investment and corresponding TNUoS charges for windshould be lower. Discrimination between generation-types and location to reflectthese differences in operation characteristics and output is essential if optimal

decisions are to be made in transmission investment and if cost-reflective pricing


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regimes are to be devised for accurate reflection of generation costs imposed on thesystem.

2.3 Inefficiencies of the present transmission access arrangements

The analysis above highlights the economics of transmission system development forsystems with wind and conventional generation, and outlines the framework requiredto create a cost reflective regulatory environment for a future UK system that willinclude other generation technologies such as wind power. At present, the regulatoryarrangements and invest then connect philosophy dictate that new (wind) generationcannot be connected until the necessary system reinforcements have been made.However, the current frameworks for transmission investment, access and pricinghave been developed for systems with conventional generation, as such; they are notoptimised to reflect the requirements of non-conventional generation as outlinedpreviously and are fundamentally incapable of making an accurate assessment of thetransmission capacity requirements for these technologies.

This section explores these market and regulatory inefficiencies through evaluation ofthe current arrangements namely: Transmission Entry Capacity (TEC), TransmissionNetwork Use of System (TNUoS) charges and Balancing Service Use of System(BSUoS) charges.

2.3.1 Shortcomings of the TEC approach for long-term investment andpricing

Although the concept of Transmission Entry Capacity (TEC) is attractive in principle,and an appropriate proxy for systems consisting of conventional generation, the keyproblem of the present implementation and interpretation of this instrument is itsinflexibility and lack discrimination between generating technologies. This results in a

lack of consistency with the transmission investment process, transmission networkpricing and adverse impacts on the efficiency of generation system operation.

For wind, the TEC associated with an individual generator will not be directly linkedwith the need for transmission capacity on the main interconnected system,particularly in systems which feature a diversity of generation technologies, ascapacity can be shared. It is clear that different (non-conventional) generationtechnologies may drive different levels of investment in the main transmissionnetwork through variation in output over time that is not correlated to either demandor generation from other sources. This variation cannot be reflected in the value of

TEC which is a static measurement, allocating a fixed volume of capacity throughout

its duration.The process of converting TEC into investment capacity decisions is also not clear.The present approach to assessing the need for transmission capacity between largeareas does not adequately take into account the effect of diversity in output andcorresponding requirement for transmission capacity, which is fundamental toachieving efficient development of the network. Gross treatment of accessrequirements (i.e. summing of TEC to determine access requirements) fails torecognise the significant diversity in output of generating technologies, and theopportunities for wind (and demand) to share transmission capacity with conventionalgeneration.


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The absence of a link between TEC for wind/non-conventional generation andrequirement for transmission investment means the concept of TEC, in its presentformat, cannot provide the basis for optimal transmission reinforcement whenevaluating the impact and requirements of non-conventional generation. Given thatthe TEC allocated to wind is not directly applicable in determining the impact that the

user makes on long-term marginal transmission investment cost, using TEC as thebasis for the generation TNUoS charge for systems with significant penetration ofnon-conventional generation is also flawed and will fail to achieve cost reflectivity.

2.3.2 Implications of the inflexibility of TEC, access choice and need forvaluing transmission

Further to the implications of TEC on long-term transmission investment and pricing,TEC may also impact efficiency of generation operation for generators that purchase acertain amount of TEC that is lower than their installed capacity. In this instance agenerator would be prevented from generating in excess of their purchased TECallocation, irrespective of whether the network is congested or not. This is clearlyinefficient, as these users are unnecessarily prevented from accessing the transmissionnetwork (and hence the energy market) when the short-term marginal cost of usingthis transmission capacity is minimal (close to zero).

In addition, limitation of access products to TEC does not provide sufficient choicefor participants, or the opportunity to balance a long-term access position against shortterm availability of transmission capacity. Most new wind generation projects requirea guarantee of firm access (i.e. TEC) to secure investment backing. However, as thereis no alternative to TEC and access is a pre-requisite for financial support, long-termfixed access is the only option for new projects. Development of alternatives to TEC

e.g. products that offer firm access over a range of timescales (from intra-day to longterm access to transmission) could provide more choice to developers and investors,whilst still giving an assurance of access.

Optimal capacity

1000 MW

Max output

700 MW

Max output

800 MW

Figure 2: Example with conventional & wind generation sharing transmission capacity

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Figure 2 provides a simple example to illustrate the inappropriateness of a singleinflexible TEC product in a system with wind and conventional generation andhighlight the need for valuing transmission through access choice.

In this example a conventional generator with maximum output of 800MW isconnected to the same busbar as a wind farm with a peak output of 700MW. Thetransmission line connecting this busbar to the rest of the system has been optimallysized at 1000MW (i.e. under a given set of parameters for cost of constraints,investment etc this line has been optimally sized to accommodate both generators).

This sizing implies that it is not optimal to size transmission to meet peak output fromboth generators and that the plant connected at the busbar should share transmissioncapacity. Under the current arrangements both the conventional generator and thewind farm must apply for TEC before they can be connected to the system and bothwill want to purchase TEC to accommodate close to their peak capacity (a total of1500MW). However, the optimal capacity for the line is 1000MW and the SystemOperator will not allocate more TEC than there is capacity. To build additional

capacity to accommodate maximum TEC for both parties would lead to economicallyinefficient constraint-free transmission.

The solution is that wind and conventional generation be allowed to share thecapacity, but the limited TEC product will not allow this. To allow optimal allocationof capacity requires new products that facilitate trading of short term access betweenparties to permit cost effective sharing of transmission capacity.

For example, wind generator, given its zero marginal cost and high value ofRenewable Obligation Certificates (ROCs), may prefer long term access and in anaction purchase, say full 700MW of firm access. Assume that the conventionalgenerator purchased the remaining 300MW of firm access. Clearly, charges for the

use of system will be based on these capacities. However, in operation, on non-windydays (say wind power output less than 200MW), the conventional generator will berunning at full capacity of 800MW without a need to purchase any access (assumingthat this situation is perfectly predictable), as the ex-post access price will be zero,given that the network will not be congested. On windy days, the output of theconventional generator will be limited by the difference between the line capacity(1000MW) and the output of the wind farm. Given relatively low load factors ofwind, say 30%, the conventional generator, in this example, will be able to achieveload factor of close to 80% of the plant rated at 800MW, while paying TNUoScharges for only 300MW.

If on the other hand, we assume that the conventional generator holds firm accessrights of 800MW and wind generator holds the remaining 200MW, on a windy day,with a potential wind power output of 700MW, the conventional generator may sell(via auction or bilaterally) 500MW of access rights to wind generator. Although theshort term marginal cost of access will be equal to the fuel price differential of thecheapest generator that was constrained on (in the importing area) and theconventional generator that is constrained off, the short term value of this accessrights may be higher and reach the cost of curtailing wind output.

This example illustrates that the value of firm access rights to transmission may behigher for wind than for conventional generation.


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2.3.3 Unequal treatment of demand and generation

In principle, whilst the system is dominated by conventional generation, the TEC andTNUoS approach uses a methodology which generates optimal network a costreflective charge for generation. However, even for a conventional system, thisapproach is not wholly efficient as the method treats generation and demanddifferently. Generation and demand in the same location have equal but oppositeeffects on the system. Yet at present, different methods are used for calculatinggeneration and demand requirement for transmission access and contribution toinvestment costs. There is no TEC equivalent for demand, so demand has noopportunity to stipulate how much access they require, or any autonomy to releaseaccess for generation (through increasing local demand)if this becomes economicallyfavourable.

Regarding TNUoS and pricing of long-term access, overall charge is weighted 27/73on generation and demand users with demand responsible for the greater share. Toencourage demand to take an active role in network investment and operation, cost

reflective charging should reflect the physical system and allow all users of the systemto receive and react to appropriate price signals that reflect their impact on the system.

This means treating demand and generation equally, allowing demand to stipulateaccess requirements, exposing them to cost reflective charges, and allowing fullparticipation in any market based arrangements.

2.3.4 Implications of inefficient market and regulatory arrangements

The current market arrangements separate consideration of energy and access andsend no locational signals to users of the system on their short term impact on thesystem. This prohibits system users from taking action to optimise their requirementfor transmission. In the longer term, the current TEC based approach to transmission

investment and pricing cannot facilitate cost effective and timely integration ofsubstantial amounts of non-conventional generation into the UK transmission system.Fundamental revision of the concept of TEC (that could include its removal as anoption) to reflect the diversity of different generating technologies is essential iftransmission access and related arrangements for wind are to be cost reflective andtransparent. The analysis in the previous section demonstrates that the presentregulatory and market arrangements have two major flaws:

(iv) inability to deliver economically efficient transmission solutions in bothshort and long term

(v) discrimination against non-conventional generation in favour of

conventional generation

Regarding (i) the present transmission access regime forces all users to acquire longterm TEC for all their output in order for investors to consider their projects to befinancially viable, as there is not any other choice available. This leads to inefficientinvestment in transmission capacity as this fundamentally undermines the concept ofsharing of transmission assets, which is shown to be economically optimal. As costreflective short term value of access is unavailable this regime does not providechoice for (new) generators and prevents them from making efficient decisionsregarding their location and use of the system in the short and long term. This resultsin inefficient operation of the generation system and inefficient investment in

transmission. This has the ultimate consequence of increasing the cost to the end


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consumer which demonstrates that the present access framework is inherentlyinefficient when it comes to a system with significant penetration of wind energy.

Furthermore, given that wind generation tends to drive less transmission investment inexporting areas, the present TNUoS charging regime overcharges. Furthermore, the

TEC concept and related charging arrangements exclude demand and charge this userunequally against generation. This is both inefficient and discriminatory (furtherdiscussion of the implications of transmission arrangements on the demand side areincluded in section 4).

The following section outlines the key requirements of systems with a significantpenetration of new, non-conventional generation for development of appropriatearrangements in transmission investment, access and pricing.


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3 Requirements for enduring transmission accessarrangements

Under the current framework, National Grid must demonstrate the requirement fortransmission investment in additional capacity for approval by the Regulator.

Justification of investment should be made using a robust methodology thatdetermines the need for reinforcement according to the impact of all users (generationand demand) on the system. The following section outlines the key requirements for ageneric methodology to determine the need for transmission investment.

There are a number of core criteria that should be considered in the development ofenduring and efficient arrangements for any future transmission arrangements. Theseare the factors required to create efficient cost effective arrangements that conform tofundamental market principals and provide a level playing field for all system usersincluding non-conventional generation and demand. Any new arrangements fortransmission investment, access and pricing should be tested against the high-level

criteria presented here and described below in more detail

21

: Cost reflectivity

Access choice

Reflection of differences in generation characteristics

Representation of location and time of use

Sharing of access between different generation technologies and inclusion ofdemand

Continuity between short and long term value of transmission

Flexibility to deal with uncertainty in future generation development

3.1 Cost reflectivity

In the context of electrical power systems (both transmission and distribution), costreflectivity is concerned with sending price signals to individual users of the networkwith respect to the costs they impose on network operation and/or development. Thiswill ensure that in the short-term, the system is efficiently operated without cross-subsidy between users and that, in the long-term, it follows the path of least costdevelopment (efficient investment).

Regarding network operation and expansion, this requires some form of coordinationbetween generation and network development as the optimisation of the network inisolation from generation would almost certainly not meet the above objective.Historically, vertical integration of conventional utilities seemed necessary for asufficient level of coordination to be achieved. In the competitive environment, the

21 There are also a number of additional practical criteria against which new arrangements should also be measured such as:set up requirements, complexity of new arrangements, liquidity, buy-back risks, user price certainty and other factors.Characterisation of these additional practical criteria is outside the scope of this report which focuses on building an initialframework for new enduring transmission arrangements. However, once the framework for new arrangements has been agreed,subsequent quantitative analysis should include consideration of these practical issues as a measurement for the suitability of anynew approaches.


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necessary coordination of investing in generation and network assets is to be achievedthrough efficient network pricing mechanisms.

Economic efficiency is achieved by sending cost reflective price signals to users ofthe network so as to influence their future decisions with regard to their location in thenetwork and patterns of network use. As well as sending signals to networkowners/investors on the need for- and location of new network investments, i.e.encourage efficient network investment and discourage over (or under) investment.

3.2 Access choice

In future systems, transmission network capacity should be shared amongst variousgenerating technologies and hence the network will be occasionally constrained.Users competing for this shared capacity will need the opportunity to exercise achoice between exposure to the short-term cost of access (during the periods ofconstrained operation) versus purchasing a known-price firm-access product andpaying use of system charges. To allow this choice an ex-post short-term market for

access is required to reveal the value of transmission in real time. Within the presentcharging framework this cannot be achieved as this only considers long term access orno access at all.

3.3 Reflection of differences in generation characteristics and

inclusion of demand

To achieve cost reflectivity and provide choice, commercial and regulatoryarrangements must be designed to recognise and reflect different generationcharacteristics between technologies. In the past, the generation mix has beendominated by large-scale centralised generation that has allowed generalisation and

the development of generic arrangements to suit one technology type. Future systemsare likely to be composed of many different generating technologies, for whichgeneric arrangements are no longer suitable as they fail to recognise the uniqueparameters that dictate the demand for transmission capacity imposed by newgeneration Failure to discriminate between generation technologies is in itselfdiscriminatory against new, non-conventional generation.

The recognition and inclusion of demand in any arrangements is also of criticalimportance. Demand has an equal but opposite impact on the system as generation, sothe access requirements of demand are a potential resource that can be released byeffective market arrangements. Although historically demand has had little

engagement in the market and is perceived to be relatively inelastic, under futurescenarios with significant penetration of wind power the differential in cost of accessacross the system could be significant, and the driver for demand to participate mayincrease. To allow this response and participation it is important that new enduringarrangements complete the market and allow demand to make a contribution tooptimal development and operation of the transmission network.

3.4 Representation of location and time of use

The impact of generation on the system is also governed by its location on the systemand the timing of output. For conventional generation this output is generallypredictable, and coincident with system peak. For intermittent, inflexible technology


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such as wind, its location on the system and its timing of use of the system is lesspredictable. To capture the real impact of wind on the system requires a frameworkable to distinguish location and time of use of the system throughout the day anddesign network investment and related charging structures accordingly.

3.5 Sharing of access between system usersIf consideration of location and time of use of the system is made for all generation(and demand), then account can be taken for the same transmission resource beingused by different generators at different times. Economically optimal accessarrangements will evaluate the cost of constraints against the cost of building newtransmission to meet the peak capacity requirements of all users in a constrained area.Where constraint costs are low, and in locations with diversity of generationtechnologies and demand, the resulting diversity in output will permit economicsharing of capacity, which should be reflected in any new transmission arrangements.

3.6 Continuity between short term and long term costs

The short term value of transmission access capacity is derived from the costs ofbalancing system constraints caused by insufficient transmission capacity to allow thefulfilment of energy contracts between generation and demand in different locationsacross the system. Long term value of transmission is driven by the requirement fornetwork reinforcement and the need for additional investment in capacity tocounteraction network constraints. The long and short term value of transmission islinked such that consistently high value of transmission in the short term shouldtranslate to activity in the long-term to invest and build additional capacity.

Conversely, construction of transmission infrastructure as part of a long term

investment strategy should also impact the short term value of transmission, e.g.investment in network reinforcement in a heavily congested are should lower the shortterm value of transmission by reducing constraints

Because there is continuity between long and short term value of transmission,revealing the short term value of transmission is a key aspect of providing additionalevidence on the need for transmission investment, and indicating the costeffectiveness of sharing transmission between system users. Additionally, the impactof intermittent generation such as wind, which can only accurately forecast its output(and transmission access requirements) very close to real time (i.e. intra-day, less than4 hours ahead of real-time). The short term value of transmission is highly relevant tothese system users as their usage of capacity and impact on the system is difficult to

quantify accurately away from real time and the short term value of transmission.

3.7 Flexibili ty to deal with uncertainty in future generation development

There is 16GW of onshore and 8GW of offshore wind with outstanding applicationsfor connection to the GB transmission system. The exact materiality of all theseapplications is unknown; experience would suggest that only a proportion of theapplications for connection will result in connection of new generation (because ofrejection of planning permission, loss of investment backing etc). However the exactamount of new generating capacity that will make it on to the GB system in the short


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term is uncertain, and as the planned connections exceed all previous historicaldevelopments, there is little experience to draw on to determine a likely outcome.

In addition to this new generation uncertainty, there is a similar level of uncertainty onthe side of retirement and decommissioning of existing plant. Together these twofactors place several GW of uncertainty on development of the future system over thecoming few years.

Any new arrangements developed for the evolving system will have to not only takeinto account the different generating characteristics of new technologies, and thelocational and temporal aspects of generation but also the fact that the exact natureof the generation mix (and demand landscape) subject to some considerableuncertainty. For the development of enduring transmission arrangements it istherefore desirable that they are sufficiently flexible to allow any future uncertainty tobe factored into the approach without compromising cost reflectivity.


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4 Case for ex-post market based enduringtransmission access arrangements

This section of the report outlines the high level characteristics of a spot-market fortransmission access, based on ex-post short term marginal cost pricing and it

compares this market based approach with the present invest and connect approachand recently discussed connect and manage philosophy (see figure below)22:

PredictCompetitive

Market

Ex-postmarket for

access

PHILOSOPHY

METHOD

FEATURES/

REQUIREMENTS



Provide firm accessfor all generation.

Observe constraintcosts and volume

Invest where need forcapacity is shown

Develop appropriatepricing regime

Derive Ex-PostShort Run MarginalCosts (SRMC) fortransmission

Develop market(auction) for accessand appropriatehedging products

Increasingly market based and transparent arrangements

Observe

Invest thenconnect

Connect andmanage

Framework for development of future transmission access arrangements

4.1 Predict Philosophy: Invest then connect

The Predict philosophy in the figure above, is broadlyin line with the current GB invest then connectarrangements. Under this approach, all future marketdevelopments and investment requirements arepredicted through forecasting users need fortransmission over long term (ideally covering the lifespan of the transmission assets) including userscommitment through purchase of TEC. This approachcould be marginally improved through a development

of the planning process which quantifies the differentimpact of individual users on the demand fortransmission capacity with a greater level of accuracy.However, there is uncertainty over how much TEC willbe required to reflect the actual capacity requirementsof system users, particularly in areas with a mix ofconventional and non-conventional generation such aswind. Practically, this would require a more transparent

FEATURES/

REQUIREMENTS



Invest thenconnect

PHILOSOPHY

METHOD

Predict

22Although it may be possible to derive different variations and combinations of the options analyzed, these are not elaboratedfurther given the objective of this paper.

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process to be established between the amount of TEC issued and the actualtransmission capacity required to support it.

Where economically optimal, sharing of transmission capacity is desirable, but thefixed TEC product is incapable of delivering this outcome. The restrictive nature of

TEC means that differences in e.g. location and time of use of the system for differentsystem users cannot be taken into account with any accuracy. In addition, limitation ofaccess products to TEC does not provide sufficient choice for participants. Most newgeneration projects require a guarantee of firm access to secure investment backing.As there is no alternative to TEC, and access is a pre-requisite for financial support,all new schemes must purchase a long-term access product, regardless of itsappropriateness for their needs. Development of alternatives to TEC e.g. products thatoffer firm access over a range of timescales (from intra-day to long term access totransmission) could offer more choice to developers and investors, whilst stillproviding an assurance of access.

4.2 Observe Philosophy: Connect and manage

The philosophy of observing network constraint costs andvolumes is linked to the connect and manage method ofsystem operation and investment. This method allowsconnection of all new entrants to the system prior toreinforcement. Investment in new transmission is thenmade by observation of actual trends in system constraintcosts and volumes and construction of new infrastructureis then undertaken with an understanding of where

observed constraint costs indicate that it is (economically)optimal to do so. This approach implicitly allows thesharing of capacity between generation technologies witha diverse use of the system, and provides a moretransparent view of the criteria for system expansion andreinforcement.

In the connect and manage system constraint costscaused by users activity on the system will be monitoredand observed, and the system operator will act on trendsin costs to stimulate long term investment where it is

economically optimal. Under this approach there is increased transparency in the

derivation of the short-term value of transmission and the need for long terminvestment, but constraint costs are socialised and system users are not exposed to thefull costs of their actions. There is an increased transparency of the process indetermining the need for additional capacity, however there is the danger that underthis approach, without timely investment in reinforcement constraint costs couldescalate and remain high for unacceptably long periods.

Provide firm accessfor all generation

Observe constraintcosts and volumes

Invest where needfor capacity is shown

Redevelop costreflective pricingregime

Connect andManage

Observe

PHILOSOPHY

METHOD

FEATURES/

REQUIREMENTS

Under this regime, TNUoS charges and system security standards could be updated toreflect the new connect and manage approach and to recognise the influx of non-conventional generation. TEC is no longer required as all generation is given fullaccess at all times. Participants would be charged according to their actual use of the

system, i.e. proportionally to the capacity their connection drives. Transmission

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investment proposal (decisions) would be still made by National Grid and approvedvia the Regulator; however, this activity is now justified via the observed constrainedcosts in the system, rather than on forecasts of future network conditions.

Under this method, the System Operator has an appreciation of the short and longterm value of transmission in different locations across the network that can assist indevelopment of an optimal investment strategy. However, the pricing signals providedto users of the system will be similar to the present arrangements; locational TNUoSsignals will indicate the long term costs of using the system (albeit with a new costreflective methodology), and short term BSUoS charges socialised across systemusers.

In the process of developing enduring market based transmission accessarrangements, the connect and manage option can possibly serve as an interimsolution but further work is required to examine such proposition quantitatively.

4.3 Competit ive Market

The alternative to the above market proxy solutions is to

is a

et for access

Philosophy: Ex-post market for access

FEATURES/

REQUIREMENTS Derive Short RunMarginal Costs

(SRMC) fortransmission

Develop market foraccess andappropriate hedgingproducts

Ex-postaccessmarket

PHILOSOPHY

METHOD

CompetitiveMarket

pass transmission investment decisions over tocompetitive markets and use cost reflective locationalaccess price signals to indicate to users their impact onthe system and guide optimal development of thenetwork. Under this philosophy, capacity investment,expansion and access is all coordinated by theestablishment of an ex-post short term market for accessthat, driven entirely through efficient short marketsignals, e.g. Locational Marginal Pricing (LMP)23.

As highlighted previously, under BETTA thereseparation of energy from access, such that energy can bebought and sold anywhere in the network withoutconsideration for locational constraints. To maintain thisseparation of energy and access requires theestablishment of a spot market for access.

The development of a separate markmaintains the overarching structure of BETTA and does not disrupt the energymarkets, but it removes the requirement for prediction or observation of the need fortransmission investment and access and puts users of the network in the centre of the

investment decision making process..As discussed earlier, the key requirement for achieving efficient investment in asystem with significant penetration of wind power is an understanding of not only thecost but also the value of transmission in both the short and long term. To achieve thisrequires the creation of an ex-post (overrun) short-term market for access. From thisex-post spot-price for access, the market participants (including the system operator)can derive appropriate hedging products e.g. trading / auctions of access rights over

23 The LMP model is implemented, among a number of jurisdictions, in the Nord Pool (zonal prices) and in the largestElectricity Pool in the world, Pennsylvania, Jersey and Maryland, where ex-post LMPs for more than 50,000 busbars arecalculated every 5 min.

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various time horizons that allow them to balance their position ahead of real time (asis the case in the wholesale electricity market)24. Given that the change in accessarrangements is driven by the need to integrate wind power cost effectively, andhaving in mind the variability of wind power over short term time horizons, it isessential that trading includes half hourly resolution (as seen in the wholesale

electricity market)25

. Furthermore, it is essential that system users always have theoption to overrun and pay the ex-post short term access price that reflects the marginalcosts of resolving the constraint caused by the overrun. This ex-post (overrun) price isthe key for establishing the value of any ex-ante hedging contract and ultimately thevalue of existing and future transmission investment26.

To generate a market for access requires derivatio ofn a spot price for access, i.e.

SRMC transmission = LMP Reference Energy Price

The derivation o rice illustrates

nder non-peak

arket for access, it may also be desirable to

pricing based on the short run marginal costs (SRMC) of transmission. These pricesare implicit within the LMP calculation which determines the cost of energy includingthe locational element. To derive the short run costs of access separate from theenergy costs requires the decomposition of this LMP calculation into its component

parts whereby:

f a short term marginal cost for access from the LMP pthat, in principle, it should be possible to mimic LMP locational price signals in theBritish model, whilst maintaining the separation of energy and access.

Identification of the short term value of access should highlight that unetwork conditions additional transmission access can be facilitated at very low (closeto zero) marginal cost. During congested periods, the SRMC of transmission willreflect the value of the network. Network users exposed to SRMC will be able tobalance their exposure between the short term and longer term through consideration

of hedging facilities, contract trading and actions of access and investment. Whereconstraint costs are consistently high, and the SRMC of transmission is greater thanthe marginal cost of transmission reinforcement this should signal the requirement forlong-term investment in new capacity.

In the context of developing a spot mconsider the principles behind the LMP approach. Under the LMP ma

Framework for development of enduring UK transmission access arrangements.pdf

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