The Development of cross border interconnection and trading

1 Interconnection benefits

There are four main reasons why investment in interconnection between power systems may prove an attractive proposition.

(1) Energy trading;

(2) to import energy from a system with lower marginal incremental costs of production.This could be the export of nuclear energy as from France to the rest of Europe;

(3) Reserve sharing agreements where the provision of emergency support can be shared minimising the spare capacity each country has to maintain in operation.Longer term agreements can reduce the spare generation capacity that each country has to maintain;

(4) Importing green energy from countries where excess renewable capacity is available from time to time like wind energy,solar,hydro or geothermal.This can avoid the need to spill hydro energy or curtail renwable sources that cannot be used locally.

New links may be established on a commercial basis with the capacity auctioned to users wishing to export or import energy though annual,monthly or daily periods.To facilitate investment the UK uses a cap and floor arrangement that limits the level of profits and losses to the link owner.This has reduced risks and encouraged new investment.The link capacity available for trading is usually much smaller than the physical capacity due to wider system network constraints.Extra capacity may be made available nearer the event as the expected future system conditions become clearer.The standard approach to determining the available transmission capacity (ATC) is to first determine the realisable total transmission capacity (TTC) from network studies taking into account security standards.There may be some capacity contracted long term,referred to as already allocated capacity (AAC).It is also usual to provide a transmission reserve margin (TRM) to cater for unplanned incidents.The available capacity is then given by:

The AAC often relates to the provision of firm power supplies from one system to another and is distinct from opportunity traded energy exchanges in that the supply is backed by capacity and contributes to the plant margin in the receiving system.The transmission capacity available through auctions,the ATC,supports shorter term opportunity trading where marginal prices between the connected systems are sufficiently large to more than cover the cost of reserving the transmission capacity.The TRM is usually set by the TSOs managing each system so that the provision of reserve can be shared.

2 Spot trading evaluation

The evaluation of the potential benefit from investment in a new interconnection requires a longer-term comparison of system marginal prices.The evaluation needs to establish a view through a period consistent with the project financing arrangements and may be for 20 years ahead.The analysis requires a prediction of fuel prices,of future system demands and generation new entry and closures.Of particular importance is a comparison of load profiles as this affects short term marginal pricing in each of the coupled systems.This in turn requires an estimate of the marginal price function with respect to the demand profile.The maximum benefit from energy exchanges occurs when the transfer across the interconnector results in marginal prices being equal to each other,sometimes referred to as the ‘equal lambda criterion’.

Fig.1 shows an example of representative marginal price functions for two systems that could be coupled by interconnection.It shows the spot generation level in each system when the two marginal prices equate when meeting a combined demand of 30 GW for a period in time.In this example the interconnection flow is not restricted and the optimum transfer is 3.3 GW as calculated below.

Fig.1 Equal lambda plot

The marginal cost function for the two systems can be represented by polynomials as shown for demand levels ‘D’in expressed in GW i.e.:

If system ‘A’ has a demand of 15 GW and system ‘B’ a demand of 20 GW then th etotal cost of production with the systems isolated is given by;

i.e total production cost for 1 hour = €937500

The minimum cost occurs when marginal prices are equal i.e.

Substituting for Gb

Re-arranging

Re-arranging

It can be seen that enabling the transfer reduces the total production cost for the hour considered from £937500 down to £887523 i.e.by €50,000.The solution can also be found using a linear program formulation with the same result.If the available transmission capacity is restricted to 2 GW then a new solution can be found when the two marginal prices are different as would occur with market splitting.In this case system ‘A’ has a marginal price of €24.2/MWh and system ‘B’ of €27.2/MWh i.e.a difference of €3/MWh.The difference is the charge for use of the link that would cause the minimum cost solution to result in a transfer of 2 GW.

A range of solutions with different link capacity charges are shown in Fig.2.It can be seen that the maximum revenue for the interconnector owner occurs when the charge for use of the link is around €4/MWh with a link transfer around 1.5 GW.For the energy suppliers the optimum transfer would be 3.3 GW with no charge for use of the link.In practice there may be other network security considerations that cause the TSOs to opt for a 2 GW link capacity.This analysis relates to transfers over just one hour.It will be necessary to evaluate a range of joint system demand levels to build up an annual assessment of potential revenues.The assessment will have to be projected through the life of the project taking account of expected new investment in generation and demand growth in the coupled systems.

Fig.2 Interconnection revenue ‘v' UoS charge

The optimum solution would be different as the total demand level varies through time.It can be seen from figure 1 that at lower load levels the marginal prices converge and diverge at higher demands.To analyse the benefit of a proposed link throughout the combined system load cycle a composite merit order would be established including the generation of both systems.A dispatch simulation,through a representative set of daily demand profiles,would be used to determine the annual cost of production of the systems coupled compared to being split.The solution would also provide the potential range of transfers to establish an optimal link size.

3 EU strategy

The EU has persistently pressed for a fully integrated internal market spanning Europe mitigating price spreads through cross-border trading.At the same time the need to reduce emissions is recognised with a target of 27% of energy from renewable sources by 2030.UK data for March 2019 already shows a 39% reduction in emissions compared to 1990.To accommodate the intermittency of renewable sources the need for flexible generation operating in parallel is recognised and a ‘within day’ market is planned to manage its operation.The trend towards more de-centralised generation is also taking place across Europe and raises new issues.There is a more active distribution and a consumer side equipped with smart meters and networks wishing to participate,rather than just be a passive user.A number of actions are necessary to facilitate these developments including provision of a new framework with:

(1) Clear price signals for investors;

(2) Regional coordination on energy policy;

(3) Cooperation on the development and management of renewables;

(4) Managing security of supply from a European perspective

Specific developments include:

(1) An EU wide system to support within day trading;(2) A cross-border short term market facilitating trading up to the event;

(3) To enable the exploitation of storage,demand side response and flexible generation through market coupling;

(4) To extend balancing markets to cover larger areas based on network zones rather than national borders.

There is also concern about investment with the market exhibiting long periods of zero- price with generation oversupply in part due to high renewable output across regions.This needs to be offset by allowing high prices at other times to reflect scarcity.It is expected that suppliers and producers should manage volatility on behalf of consumers exploiting demand side response.There is also a need to facilitate longer term contracting to support investment and identify the prime zones for renewable generation.There is a need to incentivise investment in demand side response to support balancing with aggregators playing a coordinating role.The retail side needs to engage with customers with time varying tariffs linked to the wholesale markets.

The EU sponsor projects of common interest (PCIs)for interconnection development where market coupling is enhanced.The target for interconnection capacity is that it should be equal to 10% of a country’s capacity rising to 15% by 2030.The income from congestion charges,for the use of links,should be used to support new investment.The UK has plans to reach the 10% target and uses a cap and floor arrangement for new interconnection.The floor protects investors with a minimum return to de-risk the project.The cap avoids excess profits by sponsors to protect consumers.It is recognised that system operators need to coordinate at regional level to manage interconnection flows.There is also a need to harmonise capacity adequacy assessments and system security and review the need for a capacity mechanism.Given the changing role of distribution system operators there is a need for a better interface to transmission system operators to manage interaction.Progress on realising a fully integrated European wide single market has been slow and the transformation now taking place is likely to hamper harmonisation because of the large increase in the number of players that are largely autonomous.

4 Example of renewable energy exchange

The accepted philosophy is that renewable energy should be fully utilised when it is available i.e.it has priority dispatch that may be facilitated by interconnection.It could apply to surplus wind generation and solar output at times of low load when it may not be possible to de-load local conventional generation to accommodate all the renewable output.This could be because of the need to maintain system security against contingencies or the sudden reduction in renewable output.Scotland exports a lot of wind generation output to England.Ireland also has untapped wind generation potential.Where the local system is reaching the limit of its capacity to absorb more renewable energy it could be exported to a neighboring country rather than curtailing the output.It is also advantageous to maintain loading on nuclear generation because of its low operating costs and emissions.France exports a lot of energy from its nuclear stations around Europe to maintain their units at full load.This could equally apply to hydro power during a rainy period when the output exceeds what can easily be utilised locally.Hydro,coupled with storage,is more flexible and could be used across a border to balance intermittent generation in an adjacent utility.The hydro capacity in Scandinavia could be used to balance intermittent wind generation output in NW Europe.

By way of example Iceland has a lot of untapped geothermal energy that could be used to provide renewable energy to the UK.The length of the link would be about 1000 km and a DC link would be the cheapest option.A typical set of key parameters are as shown in Table1 for a 1000 MW link.

The annual transfer is estimated based on an 85%utilisation allowing for forced and planned outages and is given by:

Net of losses of 6% the delivered energy would be 6,999,240 MWh.

Based on a capital cost of €2.5m euros/km the transmission capital cost per year is given by:

Dividing by the delivered energy gives a transmission cost per unit of €37.74/MWh or $42.89/MWh (based on the exchange rates shown in table 1).Energy prices in Iceland of $43/MWh have been quoted based on a 20year contract(as of 2016).The delivered energy cost would be $45.74/MWh taking account of line losses.Adding the transmissionand energy costs gives a total delivered cost of $88.64/MWh or £62.93/MWh without a profit margin.This compares favorably with UK subsidised on shore wind power feed in tariffs of £95/MWh and nuclear at £92.5/MWh with off shore wind power at £155/MWh.The price also compares favorably with expected future CCGT generation costs at£50/MWh based on a CO2 price of £30/t.The results of the analysis of this potential link are as shown in Table2.

Table1 Icelandic link parameters

Icelandic Link link length 1000 km cost/km 2500 k Euros Capital cost 2500 million Euros capacity 1000 MW project life 20 years interest rate 0.085 per unit utilisation 0.85 per unit losses 6 percent exchange rates 1 US$ = 0.88 Euros 1 US$ = 0.71 pounds 1 Euro = 0.81 pounds

Table2 Delivered energy cost (2016)

images/BZ_65_1284_1810_1637_2407.png7446000 MWh/yr 0.85 util 6999240 MWh/yr net of losses 264 million €/yr 37.74 €/MWh delivered 42.89 $/MWh deliered 43 $/MWh at source 45.74 $/MWh delivered 88.64 $/MWh trans+energy 62.93 £/MWh trans+energy

5 Limits on renewable generation

The There is a limit on the proportion of renewable generation that can be managed in operation of a local power system.This arises for a number of reasons:

(1) Alternative generation needs to be available for when the wind does not blow and there is little solar rediation;

(2) The power system requires a proportion of synchronous generation providing inertia that supports frequency management within limits following disturbances;

(3) A proportion of generation able to provide reactive power is necessary to maintain voltage control and avoid voltage collapse;

(4) Fast acting backup generation is required to be available for dispatch to balance sudden changes in wind and solar generation;

(5) The gas grid needs to be able to respond to sudden changes in demand when a lot of gas fired generation needs to start up to replace sudden falls in renewable output.

Scotland has suggested that it can operate with a very high proportion of renewable generation but only by relying on support through the interconnectors with England.A new £1bn HVDC link is planned from the Clyde to North Wales as much to support Scotland at times of low renewable output as enable exports of renewable energy from Scotland to England.Apart from the high cost of subsidies,that UK consumers bear,this would constrain the proportion of renewable generation that could be in operation in England.In turn GB relies on support from Europe in its assessment of its generation capacity needs.There is a danger of assuming support at times of low wind output when many countries across Europe may be experiencing light winds and low output.There are often low wind levels associated with very cold conditions,lasting for several days,and massive storage capacity would be required to begin to balance supply and demand.In Ireland the proportion of non-synchronous generation is approaching 50% and is considered just viable based on practical operating experience.Consideration also needs to be given to managing black starts from DC interconnectors as they cannot commutate into a dead network unless based on VSC technology.Germany also has a high proportion of wind generation but because of its extensive interconnection with its European neighbors a lot of the intermittency is effectively exported causing unwelcome disturbances to neighboring networks.

6 Cross border trading optimisation

To optimise energy exchange across Europe the EU introduced a trading platform called EUPHEMIA,an Electricity Market Integration Algorithm.It is designed to effect market coupling of seven power exchanges and calculates the transfer energy allocation and prices to maximise the overall welfare rather than for a particular participant.Buyers and sellers of energy submit orders and the algorithm allocates exchanges to maximise the overall benefit.The allocation takes account of transmission limitations based on the ATC and any ramping limitations and can include flow tariffs.

The output includes details of orders accepted or declined and the net position together with the market clearing price for each bidding area and period.Bidders can introduce constraints and submit block orders.To facilitate computation the orders in each area are aggregated to produce piecewise linear curves processed initially with integer constraints relaxed using a mixed integer quadratic algorithm.Where bids of equal prices occur,allocation is based on a merit order.

There is a problem with modelling trading based on assuming a single transfer limit on AC links between adjacent trading areas in that the physical flows follow routes determined by the network impedances rather than traded exchanges between the two areas.Loop flows will occur in adjacent networks that will use the ATC of other interconnectors as well as disturb the planned flows within the networks subject to the loop flows.This problem can be managed by formulating definitions of interconnected physical flows in a ‘Flow model’ that forms a constraint based on network analysis.This introduces complexity that may make some optimum solutions appear counter intuitive as illustrated in the example in Fig.3 that shows a three-area system with different market clearing prices (MCPs) with a flow from ‘B’ (with MCP of €63/MWh) to ‘C’ (with MCP of €60/MWh) that appears counter intuitive.

In this example there are constraints on the area net exchanges and an overall flow constraint given by:

constraint 0.25*nex a -0.5*nex b -0.25 nex c ＜= 125 Table3 shows two solutions that both meet the constraints.The first is based on no exchange from the higher priced area ‘B’ with a cost saving of just €3750/hr while the second solution enables a flow from area ‘B’ resulting in a higher cost saving of €4500/hr even though there is a transfer from the higher priced area ‘B’ to ‘C’.The complex nature of the constraint in this example illustrates the broader issue of trading across borders with associated loop flows through meshed networks.

Fig.3 Area traded exchanges

Table3 Optimum exchanges

exchanges €/MWh cost €/hr nex a 250 45 11250 nex b 0 65 0 nex c -250 60 -15000 0-3750 constraint 0.25*nex a -0.5*nex b -0.25 nex c ＜= 125 limit ＜=125 exchanges €/MWh cost €/hr nex a 400 45 18000 nex b 300 65 19500 nex c -700 60 -42000 0-4500

7 Predicting cross border flows

In evaluating future investments in generation or interconnection it is necessary to predict market prices.In an interconnected system like the UCTE system,spanning Europe,this will be influenced by future energy exchanges that will affect price relativities between countries.The process involves:

(1) predicting prices for each country node isolated based on a dispatch type simulation;

(2) estimating interconnector flows based on initial price differentials;

(3) revising nodal prices based on the change in the net demand altering the marginal plant and prices;

(4) repeating the process until stable conditions are realised.

The initial flows can be estimated using a simplified system model derived from analysis of the interconnected system using historic data.The recorded energy exchange can be reduced to an average flow for a year along each route and the associated nodal transfers.

The interconnector flows shown in the table are derived from the nodal voltage differences times the admittance.The nodal voltages can be translated into an equivalent nodal price shown in €/MWh.These representative nodal prices are based on a function of each nodal voltage with the highest voltage translated into the lowest price.Future flows can then be estimated by converting the predicted set of price differentials into equivalent nodal voltages and using the admittance matrix to translate these into flows.Each route has a transfer limit and if it becomes congested a constraint price will be added to restrict the nodal transfer.In being based on recorded flows the mechanism reflects the physical aspects of the interconnected network.

These can be used to determine the impedance matrix for all routes and hence the admittance matrix.By substituting the nodal transfers into each column the set of determinants can be found.These can be used to estimate a set of relative nodal voltages as illustrated in Table4.

The pattern of flows consistent with this model (and recorded flows) is shown in Fig.4 together with nodal transfers.In this example it can be seen that France is the largest exporter with an average transfer of 8650 MW.This enables high load factors to be maintained on the high volume of French nuclear generation capacity.In contrast Italy is shown as a big importer that reduces the use of local expensive oil-based generation.Ireland is not directly connected to Europe but links through the UK network.Its energy prices are amongst the highest in Europe when the capacity cost is included.Consideration is being given to establishing a direct link from Ireland to Europe to facilitate price convergence.

Table4 European flow model

relative prices-6.5E+10 Austria Belgium France Germany Italy Lux NetherlandsPortugal CZ Spain Switz UK Poland DK Austria -3E+10 0 0 0 454 -180 0 0 0 551 0 -368 0 0 0 0.46 32 Belgium -2.9E+10 0 0 1004 0 0 -41 -107 0 0 0 0 0 0 0 0.44 32 France -1.8E+11 0 -1004 0 -2191 -2437 0 0 0 0 -1008 -1010 -1001 0 0 2.85 20 Germany -6E+10 -454 0 2191 0 0 -373 -1761 0 998 0 -814 0 114 240 0.93 30 Italy 1.14E+11 180 0 2437 0 0 0 0 0 0 0 2562 0 0 0 -1.75 43 Lux 4.75E+10 0 41 0 373 0 0 0 0 0 0 0 0 0 0 -0.73 38 Netherlands -2.1E+10 0 107 0 1761 0 0 0 0 0 0 0 0 0 0 0.32 33 Portugal 7.47E+10 0 0 0 0 0 0 0 0 0 203 0 0 0 0 -1.15 40 CH -1.1E+11 -551 0 0 -998 0 0 0 0 0 0 0 0 695 0 1.77 25 Spain 9.85E+09 0 0 1008 0 0 0 0 -203 0 0 0 0 0 0 -0.15 35 Switzerland -2.7E+09 368 0 1010 814 -2562 0 0 0 0 0 0 0 0 0 0.04 34 UK -1.1E+11 0 0 1001 0 0 0 0 0 0 0 0 0 0 0 1.65 26 Poland -1.6E+11 0 0 0 -114 0 0 0 0 -695 0 0 0 0 0 2.50 22 Denmark -1.3E+11 0 0 0 -240 0 0 0 0 0 0 0 0 0 0 1.93 25 nodal injections -456 -856 8650 -141 -5179 -414 -1868 -203 853 -805 371 -1001 809 240 1.08E-12 determinates flow on 100 MVA base = voltage differential ＊ admittance Voltages derived

Fig.4 European Typical Average MW Flows

The process provides an indication of the average annual energy flows around Europe that is useful to support initial investment analysis and expected utilisation of proposed new generation.

8 Interconnection technology options

The connection of remote renewable energy sources like hydro becomes more economic using DC over longer distances greater than about 500 km.Although the capital costs are higher than AC equivalents the losses in transmission can be lower.With lengths of 1000 km DC line losses may be 6-8% compared to equivalent AC line losses of 12-20%.The convertor station losses partly offset this saving but the use of DC is viable for transmission from remote generation sites to demand centres.However,the investment costs of DC are higher than AC because of the high cost of the terminal convertor stations.The overall link economic assessment is improved with a high load factor that may be realised with a hydro installation but less so with an intermittent source like wind or solar.To be viable the installation needs to be based on sites with the highest levels of renewable output like off-shore wind or solar from desert locations or a mixture of energy sources.The Three Gorges Project in China uses a 1000 km line linking the hydro site to Guangdong province.Brazil has a 2500 km line linking hydro plants on the Amazon to Sao Paulo.More flexibility can be realised if the hydro site has some storage potential.Other advantages of DC are the ability to control the transfer and easier options to route the circuit.

The VSC (Voltage source convertor) is popular in that it can be turned on and off and does not rely on the AC system to provide the commutating voltage as with CSC(Current source convertors).This feature is important in facilitating a black start of networks following major shutdowns.The terminal stations can be more compact and require less harmonic filtering.They maintain a constant polarity and are much easier to deploy in a multi-terminal HVDC system.The ongoing development of DC circuit breakers will advance the scope to establish intercontinental DC networks.There is currently a large-scale multi-terminal HVDC system in operation,the 2000 MW CSC HVDC three terminal Quebec-New England transmission link.However,the terminals are connected linearly and operate primarily in single mode,either importing or exporting power.The UK has looked at options to exploit high levels of wind availability in the sea between England and Ireland with a DC network as illustrated in Fig.5.The proposed scheme would capture energy from off-shore sites,with high wind speeds,in the sea between England,Scotland and Ireland.

Fig.5 A study of UK offshore wind and interconnection

9 Cross border trading auction

Transmission facilitates operation of the market in enabling wholesale trade between generators and suppliers largely independent of their location.This maximises the liquidity in the market and promotes competition.In general,the larger the consumption in the interconnected market the greater the liquidity and competition.It enables traders for the most part to regard the grid as infinite.In some circumstances constraints on the network may become active when the difference between the generation and demand in an area of the system exceeds the interconnecting transmission capacity with the rest of the system (having allowed for security requirements).Several approaches are used to deal with this situation:

(1) Split the market and let zonal prices separate until transfers match the capacity available (the Nordpool trading area is designed to split when constrained);

(2) Ignore constraints in market operation - let TSO resolve constraints in real time and share costs through uplift - ex-poste;

(3) Explicitly charge for use of the inter-connector to manage transfer through bilateral contracts or by an auction(Europe).

The market would be split by the Market Operator when it is apparent that interconnecting flows would be exceeded.This has the advantage that those customers within a constrained zone bear the additional costs as opposed to the cost being spread amongst all users through uplift.

The second option for dealing with internal network constraints is to establish the total market solution and then,in the event,let the grid operator instruct generation so as to manage constraints.In this case the generator may receive‘constrained off’ payments related to lost profit or ‘constrained on’ payments based on the generators bid into the market.

A third option is to charge for use of interconnection if the demand for capacity by traders across the route exceeds the capacity.This can be realised through auctions where traders bid to reserve capacity a year or perhaps months ahead of the event.Prices are established competitively and have to be recovered by users from the proceeds of the trades.The volumes traded reduce nearer the event as positions become clearer and the available transmission capacity is confirmed.Table5 shows the results of a typical auction in NW Europe related to interconnectors between the Netherlands (Tennet),Belgium (Elia),and Germany(RWE and E.On).

Table5 Trading Auction

images/BZ_70_213_425_1193_535.pngELIA TenneT 328 328 4.70 TenneT ELIA 328 327 0.11 RWE Transportnetz TenneT 356 356 7.14 TenneT RWE Transportnetz 356 35 0.07 E.ON Netz TenneT 216 216 7.02 TenneT E.ON Netz 215 216 0.01

It shows the MWs available for reservation in both directions,the capacity obtained and the prices paid in€/MW.It can be seen that interconnector capacity from RWE and E.On in Germany to the Netherlands attracts a premium of around €7/MW consistent with the Netherlands being a net importer from Germany as illustrated in figure 4.The Netherlands is also shown to import from Belgium albeit at a lower premium of €4.7/MW of transmission capacity.The prices for export capacity from the Netherlands are a small fraction of a Euro and notional.

10 Conclusion

The expansion of interconnection capacity in Europe is targeted to be 10% of generation capacity rising to 15% by 2030.The objective is to facilitate cross border trading resulting in price convergence.It will also provide benefit in enabling reserve sharing and in managing the intermittency of renewable generation through flexibility sharing.This should lead to the ability to accommodate a higher proportion of renewable intermittent generation.But,the analysis of interconnection investment will need to show returns that will only be realized if utilization levels are reasonably high.

There is a danger in crediting interconnection capacity with a contribution to the area plant margin.There is no guarantee of availability of generation or link capacity unless it is backed by firm capacity contracts.Adverse weather may affect wide areas influencing the availability of generation in neighboring countries,at the same time,reducing any spare capacity.

The evaluation of the potential benefit of trading across a proposed new link needs to be based on a comparison of expected marginal prices through the life of the link.This in turn requires an analysis for each system of future demand,fuel prices and generation additions and closures.In some instances where the plant mixture is very different there may be clear opportunities e.g.exploiting Norwegian hydro to balance wind intermittency; using spare French nuclear capacity to displace the use of oil in Italy; a link from Iceland to the UK to export spare geothermal energy.

An analysis using a composite merit order for the potentially coupled systems can be used to establish the optimal link size and potential benefit.The respective profiles of demand will also be relevant in evaluating potential within day trading opportunities.The process is made more complicated with interconnected networks with associated loop flows.The availability of VSC DC transmission affords a degree of control to manage transfers in interconnected networks.

From an investment perspective it’s the long-term potential for energy trading rather than within day trading that will determine the likely return for sponsors.This can be reviewed by an analysis of historic energy flows and an understanding of their rationale.The process provides an indication of the average annual energy flows around Europe that is useful to support initial investment analysis and expected utilisation of proposed new generation.

Interconnection can also support the wider use of renewable generation.There are technical constraints on the proportion of non-synchronous generation in operation at any one time.These relate to ensuring system reserve capability to cater for changes in renewable output and managing frequency changes following sudden loss of generation.The non-synchronous renewable generation does not contribute to the system inertia that slows the initial frequency change.The rapidly falling frequency may cause other generation to trip initiating a cascade in loss of capacity.In Ireland a proportion of non-synchronous generation of up to around 50% is considered just viable based on practical operating experience but may result in black start problems.The availability of additional interconnection to England would enable more renewable generation to be installed in Ireland and Scotland with the excess energy exported.

The EU sponsorship of interconnection development is based on the perceived potential improvement in market coupling.But,progress on realising a fully integrated European wide single market has been slow and the transformation now taking place in the industry is likely to hamper harmonisation because of the large increase in the number of players that are largely autonomous.