The 2000 MWe cross channel link HVDC connection between the British and French networks has saved both countries from power supply emergencies over the years. It probably sidestepped the need to build two more large nuclear units on both sides of the channel. Now, with the opening up of France’s power grid to commercial competition, the link’s capacity is being put up for competitive bidding, but neither of the owners is an independent private company. How will this work?

The emergence of independently owned commercial transmission lines is a recent product of global electricity industry restructuring. Privately owned submarine HVDC links are an even more recent innovation, but in recent years we have seen commitments to the Moyle Interconnector between Northern Ireland and Scotland in the UK, the Cross Sound Link connecting Connecticut and the Long Island in the USA, and now the Bass Link interconnector between Australia and Tasmania. It is likely that some, if not all, of the Baltic submarine HVDC links, including the recently commissioned Finland – Poland interconnector are likely to be opened up to competitive commercial ownership soon.

The decision to commence building the 2000 MW HVDC link between England and France eventually came in 1981. For the United Kingdom to compete in the lucrative EU power markets cross channel interconnection is imperative, indeed more high capacity links will be needed. The UK National Grid group is known to be investigating links between England and Norway, and England and the Netherlands. A scheme to link the grids in England and Norway via North Sea oil and natural gas rigs, at the same time providing production and drilling rigs with necessary power, is also being actively investigated.

Nobody has tried to privatise a submarine HVDC link as large as 2000 MW capacity before. The ground rules for trading capacity on the England – France cross channel link have now been announced ready for auctioning, to commence just in time to coincide with the inception of NETA (New Energy Trading Arrangements) in the United Kingdom, and the inauguration of France’s initial foray into the deregulated electricity market.

Status of the link

The 2000 MW two dipole, submarine HVDC link between converter stations at Sellindge near Ashford in the UK and Les Mandarins in France, (Figures 1, 2 and 3) commenced full operation in 1985. It was described in some detail in the February 1985 issue of Modern Power Systems. The technology was advanced even by today’s standards.

The project benefited from experience with an earlier 160 MW HVDC link installed in 1961 from Lydd, near Dover in the UK to Echingen near Boulogne in France some 30 km south of the 2000 MW link. This older link used mercury arc rectifier valves. The surface laid cables were frequently taken out of service owing to damage from fishing trawls and anchors before it was finally decommissioned in 1982.

The newer 2000 MW link using modern thyristor converter technology (Figure 4) was intended to return a design availability of over 95 per cent. The four cables were buried in trenches at least 1.5 m deep.

The original studies investigated links of AC or DC systems with individual cables of various capacities from 2000 to 6000 MW over the 45 km crossing. The eventual selection of two independent 1000 MW, ± 275 kV DC links, one installed by the CEGB and the other by EDF, was based on 15 per cent returns for both countries. Even so, the link is not yet fully amortised in spite of virtually constant availability and remarkably high reliability.

The link was a joint venture between the CEGB and EDF, with the costs being equally shared between the two national utilities. Each country was to provide and install all the equipment within its own territory, and each would supply two pairs of submarine cables.

The choice of four cables for each dipole meant that any damage would generally be limited to outage of 500 MW. The British cables were laid in a two stage routine – a trenching operation followed by the cable laying. The French trenched and laid their cables in a single process.

The studies showed that the average equivalent generation capacity for the link would be 1500 MW for both parties at commencement of operation, increasing slightly thereafter. This was considered to be the equivalent of the construction of one of their largest generating stations at about half the cost for both the CEGB and EDF.

The original aim was to exploit the symbiosis available from the difference in load patterns on opposite sides of the Channel. The difference in time zones means that daily peak demands on the two systems occur at different periods of the day. In addition, the link was planned to support trading of electricity between the two utilities, the one buying from the other when its own marginal costs are higher than its opposite number’s.

In practice the link has mainly been used in a more radical mode with total power flow flowing in one direction for long periods depending on the more extreme power supply contingencies in each country.

Availability of the link has generally been high until 1999/00 which was an exceptional year owing to the implications of work on the Channel Tunnel, which resulted in a reduction to some 95.6 per cent. Availability over the last six years is shown in Table 1.

Average availability over the six years of operation for Bipole 1 of 97.49 per cent compares with that for Bipole 2 of 97.24 per cent. Outages between 1994 and 1999 are listed by category in Table 2.

NETA for Europe

The open market electricity industry regimes that the cross channel link will now have to operate under will be radically new on both sides of the Channel. The UK may have been able to build on the experience of its suck-it-and-see power pool and CFD approach, which did at least allow fuel suppliers to take full advantage of the scope for gas tolling and arbitrage opportunities.

France has taken time, much to the chagrin of Brussels and Strasbourg, to benefit from the experiences of privatisation ventures all round the world, which they have been analysing with great interest. If anything, it was probably the French oil and gas suppliers that showed the greatest skill in exploiting fuel arbitrage in the UK electricity supply industry. Having acquired the big fish of London Electricity in the UK, EDF now seem to be willing enough to battle with E.on to buy PowerGen as well as acquiring a 25.01 per cent controlling interest in EnBW. Last year EDF was reported to be negotiating an asset swap with TXU Europe under which EDF would grant TXU access to some power generation in France in return for generation in the UK, real or virtual.

France has not yet fully developed its open market trading system, but the imminent opening up of the French market was a major driver in the plan to auction off the cross channel link capacity. Currently, third parties have been granted provisional access to part of the French national grid, which may indicate some inclination to comply with the EU Electricity Directive, but the access is costed under a provisional tariff introduced in February 1999 by the new TSO Reseau de Transport de l’Electricité (RTE) which is a fully owned subsidiary of EDF.

According to the Director General of France’s CRE (Commission de Regulation de l’Electricité) Thiery Huot, they are waiting for a government decree to approve the vital standard transport tariffs, but under French law the regulator has to wait until the Ministry of Industry issues a decree on grid tariff policy before it can put forward proposals for such tariffs. This was expected before the end of the year 2000.

The system developed by the CRE and submitted to a period of consultation envisaged a “postage-stamp”, or “one point of entry” concept which they are awaiting the opportunity to introduce. The present provisional tariff introduced by the RTE allegedly does not come under the regulation of the CRE because it was instituted before the CRE was formed.

RTE reportedly signed an agreement on 23 January 2001 to share technical knowledge and information with the major US power grid PJM “To help address mutual (sic) goals of power systems and energy market operations”. PJM claims a pooled generating capacity of over 58 000 MW with 200 participants in the market place. RTE director Andre Merlin is quoted as saying “it is a win-win agreement”.

Access in France

Since ESI deregulation in the UK, the agreement on the use of the interconnector could only provide for all of the capacity to be exploited by EDF, since they were still a state entity. National Grid in the UK gained their return on investment from leasing their dipole to France. This agreement will now expire on 31 March 2001.

Blocks of capacity from France to England will be offered for sale by tender. The first tender was to be for three years of capacity in blocks of 50 MW totalling 1500 MW set out in the French IFA (Interconnexion France-Angleterre) rules on 11 December 2000. The tenders have been scrutinised and the results were published on 29 January 2001. Five separate market participants submitted bids totalling 2700 MW. Bids from two separate participants were successful. The price and capacity for each successful bid is shown in Table 3.

Interconnector capacity, both from France to England and England to France, for one year will be auctioned annually. All of the capacity from France to England remaining after the tender process, and all of the available capacity from England to France is to be offered in annual and daily auctions. The 1500 MW of capacity was traded under sealed tenders at a guide price of £44 000 ($64 000). Another 350 MW will be sold in 50 MW blocks under annual auctions and the remaining 150 MW is to be sold in daily auctions of 1MW blocks.

The first annual auction was to be held as this issue went to press on 5 February 2001, and the first daily auction is to be held on 31 March 2001. The operators are selling capacity rights in 1 MW tranches in different categories. Each category is characterised by its direction and its duration ie one Contract Day, one Contract Year or multiple Contract Years.

In tenders, users can bid for blocks of units from France to England, eg in the first tender, blocks of 50 units were bid for with a term of three years. In auctions, units in both directions will be sold for one Contract Year and one Contract Day.

In effect, instead of National Grid and RTE each owning one dipole, both parties will now be conceived as owning one half of each cable split in mid-channel, with each side owning the half closest to its shores. Once the user has acquired units, it is entitled to submit Mid-Channel Nominations to the TSOs for transfers of energy. One unit equates to a transfer of 1 MW calculated at mid-channel. The operators will use mid-channel nominations to determine Deemed Metered Volumes calculated in accordance with the IFA Access Rules, which are used for settlement purposes and are allocated to the users energy accounts.

Owing to technical limitations the ramp rates specified in mid-channel nomination cannot vary by more than 750 MW between two consecutive settlement periods. RTE and NGC are also moving towards a procedure to enable bids and offers in their respective balancing mechanisms to be accepted.

Capacity rights are subject to a “use it or lose it” rule. Two days before the start of each contract day, users with multiple year or annual units will need to give the operators notice of their intended level of use of the interconnector on the forthcoming contract day, taking into account reallocation, contract volumes and bids/offers. To the extent that users indicate that capacity will be unused, and subject to outages, the operators will make the capacity available in the daily auction. The original user will still have to pay for the capacity, but it will not receive any proceeds from the auction.

Imported energy can of course be traded-on. Although users cannot assign their capacity rights, this is not, apparently, intended to prevent a user from subcontracting use to other energy market participants on the condition that the user indemnifies the operators against any claims by the person using the interconnector under the contract. Users can elect to bid and pay in either euros or £stg except for the daily auctions for which all prices will be in euros.

In addition to the prices bid for capacity, users will pay a charge per unit per contract-day, representing a pass-through of the charges by NG’s interconnectors business for connection to and use of the NG transmission system. Users will also pay a use-of-system charge for using the RTE transmission system as detailed in their Contrat d’Exportation.

Users will be responsible for the costs of imbalances incurred in the wholesale electricity markets in accordance to the Balancing and Settlement codes and national settlement arrangements. All users will have to be a party to the balancing and settlement code and any use of the interconnector will have to be linked to a Contrat de responsible d’equilibre in accordance with the RTE settlement arrangements which are currently in the process of being developed. IFA access rules and draft contracts can be viewed on RTE’s web site (in French and English). Useful examples of how procedures on both sides of the channel will work are given in Powerpoint files on the RTE and National Grid web sites.

For transfers from mainland Europe to England and Wales the user will need:

• French grid access contract for exports

• Balancing responsibility contract

• French grid access contracts for exports towards IFA.

For transfers from England and Wales to mainland Europe users will need:

• French grid access contract for an import from IFA

• Balancing responsibility contract

• French system access contracts for exports

This system allows for:

• The taking into account of losses (the user will take into account losses on the French half of the link up to Les Mandarins)

• The taking into account of risk management on power exchanges between TSOs – firm blocks in the case of UTCE exchanges, non-firm in the case of IFA.

Example – 100 MW from the mainland to England and Wales for one day:

• On D-1 the user nominates an import of 101 MW from say, Switzerland to France (this value will be taken into account for the French settlement)

• On D-1 he nominates an export towards IFA of 100 MW (from mid-channel towards IFA)

• RTE converts the 100 MW mid-channel nomination into a 101.17 MW nomination in Les Mandarins, which will be taken into account for the French settlement

In the settlement stage:

• Ex post: the user has an imbalance of 0.17 MW which will be taken into account for the settlement of the balancing responsibility contract which was designated at the contractual stage

• Deviations will be evaluated at the French system selling/buying prices resulting from the French balancing system

• The user bears the energy part of unplanned unavailability risk of the capacity. – therefore, if after an incident, the real time transit is reduced to 50 MW by the interconnector administrator, it is this 50 MW value, Deemed Metered Volume, which will be used in place of the mid-channel nomination when calculating the settlement.

This example is illustrated graphically in Figure 5.

Access in the UK

For flows from England to France some 1400 MW will be traded under annual auctions, with 600 MW available under daily auctions. But who qualifies to bid?

Traders need to sign an IFA user agreement and satisfy a few key criteria in the IFA access rules which can be perused via the OFGEM. All users will need to demonstrate adequate financial standing, they are required to have in place the necessary IT software and communications interfaces, and they will have to accord to certain agreements. This done, they then have to acquire an eligibility notice before bidding.

The agreements are set out in Rules B2 and E8 of the IFA Access Rules, and all of these agreements have to be in place before any capacity acquired may be used.

To participate in the daily auctions a communications link with an auction system established jointly by National Grid and RTE is required, and for operational purposes users will have to establish the same EDT (electronic data transmission) as the BSC (balancing and settlement code) signatories before they will be able to use their capacity.

Transmission system access requires a Use of System Agreement (see Figure 6) which gives a user the right to use the transmission system under the following obligations:

• Pay charges for use of the system

• Be party to the balancing and settlement code

• Abide by the Grid Code

• Supply data to National Grid

• Become a party to the Framework Agreement

Use-of-system charges include:

• Use of system – generation and demand

• Connection charges – based on capacity purchased

• Balancing services

This is shown in Figure 7. A map of interconnector trading routines is shown in Figure 8.

Credit cover will be needed to establish financial status unless the prospective user has an approved credit rating such as Moody’s P1 or Standard and Poors A-1.

A guide price of £44 000/MW/year has been set to ensure that all players are equally placed in assessing the uncertainties associated with a closed auction process of bidding too high or too low. Participants may bid above or below the guide price, but the system operators reserve the right to reject low bids.

The charges levied by National Grid’s Transmission Business for Connection will be passed through all interconnector users equally. The charge is expected to amount to approximately £1.7 million for the year 2001/2, and assuming 2000 MW of capacity is sold, this equates to £850/MW/year or £2.3/MW/day. If more than 2000 MW of capacity is sold, eg if some capacity is sold in both directions, then at the end of the year a reconciliation will take place to ensure that the revenues recovered match the connection charges.

Charges for transmission network use-of-system (generation) will be allocated to all users purchasing capacity for importing electricity into England and Wales. For 2001/2 the charge is estimated to be £1.3 million, and assuming 2000 MW of import capacity is sold, then this equates to £650/MW/year or £1.84/MW/day.

The tariff for 2001/2 was due to be published by National Grid at the end of January 2001. This is a tariff based on forecast demand and generation, and at the end of each year a reconciliation process will take place to reflect the actual values.

Are traders in the UK ready? During January 2001 power trading concerns in Britain were planning to meet at the end of the month to attempt to break a deadlock over contract terms which has paralysed the forward electricity market ahead of wholesale trading reforms. On 31 January 31 power traders from 20 companies including Dynegy, El Paso Energy, Enron, Innogy and Scottish Power, signed an industry pact on trading procedures despite continuing disagreement over contract terms in the forward market. They needed to agree on standard trading terms set out in the GMTA (grid trade master agreement). The key issue seems to be the allocation costs in physical contracts to be traded under NETA. This does not seem to worry National Grid in respect of the timetable for the opening up of the IFA, which is designed for compatibility with both NETA in the UK and whatever arrangements RTE eventually come up with in France.

NETA goes live

The UK’s delayed NETA (New Energy Trading Arrangements) are now due to ‘Go live’ on 27 March 2001, but OFGEM is not prepared to confirm this at the time of writing. This may be because the deadline for finalising the three year contract bids had to be delayed for a week. The new key dates schedule announce by National Grid and RTE is shown in Table 4.

OFGEM point out that the “NETA Go Live” day has been viewed by some as the most important date associated with the implementation of the new trading arrangements. It represents the point in time at which pool trading ceases and the new balancing and settlement arrangements begin to operate in England and Wales. OFGEM state, however, that it is important to recognise that the implementation of NETA is part of an ongoing process, with the Go Live day representing one point in a continuum of change that is already well advanced and will continue well beyond the go live date itself.

The final stage of testing, the Pre-Production phase, is due to run from 5 February until the middle of March. During Pre-Production, there will be a full simulation of NETA systems involving key participants and real data. Only if Pre-Production succeeds in its testing of both the central NETA systems and those of participants will the decision be made to move to Go Live on 27 March.

Callum McCarthy, OFGEM ceo, said on 31 January “The programme is on schedule against the demanding timetable which we set in October last year. We can therefore move forward to the final series of tests, pre-production. We need to have completed these tests successfully before a decision to Go-Live can be made. The next weeks will therefore be critical, and will continue to require full hearted commitment from all the many organisations which are working hard to introduce NETA as soon as possible. Our objective remains to see a more competitive market, which I am confident NETA can achieve, with the pressure for lower prices that that will bring.”

Further afield

HVDC links and “special facilities” are at present excluded from the provisional EU tariff charges for transmission of electricity across national borders of two euros per MWh, but agreement on the new rules for harmonising cross border electricity tariffs in Europe is proving just as controversial and difficult to conclude as the disputes in England and France. As ever, the key issue is over who should pay for the charges.

The new rules were due to come into force in October 2000, but the commission rejected the proposals from France, Belgium and Germany to charge electricity exporters two euros/MWh. At a recent conference EU internal markets official Katrien Prins predicted that the first transnational regime would be in force by April 2001.

The dues from the proposed cross border fees are expected to amount to some 200 million euros/annum, most of which would be accrued by the Swiss system operators on power transferred through the Lauffenburg international electricity exchange hub.

There are many areas of uncertainty, particularly in respect of how great the economic impact of the new trading systems now emerging in Europe will be, but it already appears that the biggest casualties will be the environmentally friendly technologies of chp and renewable energies. Also, it seems even more unlikely under this regime that new, more efficient and advanced electricity generation technologies will be able to penetrate the market. The prospects for embedded generation and distributed power generation also now appear to be greatly diminished.

It is a regime which is likely to increase the emphasis on redeveloping the transmission networks and load flow patterns to suit the competitive market forces, as can be seen from what is happening in the USA.

But we will have something approaching true market forces in the industry. To survive, if you cannot sell your power in the market you want to exploit, you have to be big enough to buy the distribution system. Could we end up with two vertically integrated electricity supply companies in Europe?

We have to hope that the piece-meal or state-by-state approach to deregulation that Europe is now taking does not follow the same pattern as that in the USA. to the extent that we encounter the same kind of chaos as experienced in California. The potential for this level of tribulation would appear to be just as great in some parts of Europe.

Table 1. Availability of the cross channel link
Table 2. History of outages
Table 3. Successful bids for first three year contracts
Table 4. Deferred key dates for capacity auction