E A S T - W E S T E L E C T R I C I T Y I N T E R C O N N E C T O R

Memo to CER Regarding: Interconnector Capacity Allocation and ESB / Market Dominance ~ 9th May 2007 ~

At our meeting on May 3rd, we spoke at length about the issue of dominance and the availability of capacity on our planned East-West Interconnection. At that meeting we outlined our position in relation to ESB as the dominant market player and our views on dominance. For the sake of clarity we have prepared this memo to again outline our position and it examine the issue in a little more detail.

We do recognise that there is a dominance issue that is already being addressed in the market, the introduction of interconnector capacity in to the market may assist in solving the dominance issue but it is a wider market problem. Imera Powers East West Interconnector is as you know a merchant project taking on full market risk. We are seeking EU exemptions to ensure that there is an adequate risk/reward balance for the investment and to ensure that we can operate the assets on a commercially viable basis. Given the risks that are already present in the development of this project, we do feel that any unnecessarily onerous restrictions placed upon us could undermine the project.

There are other market mechanisms being put in place to address ESB dominance that will be far more effective than placing restrictions on the use of capacity on our interconnector.

As we have already demonstrated we intend to allocate capacity in an open and transparent way fully compliant with the draft congestion management guidelines and to implement effective ‘Use it or Lose it’ mechanisms to prevent capacity hoarding, we are also committed to facilitating secondary trading of capacity.

The introduction of interconnector capacity in the short-term will Increase competitive pressure and Interconnection will help to rectify problems of the ESB setting prices outside the competitive range.

At our meeting we discussed the existing arrangements for the North/South and Moyle interconnectors, as we understood it there was a notional threshold of 40% of total capacity could be acquired by any one party should that party wish to access more capacity above this threshold it would trigger a competitive review by the Northern Ireland Regulator. It is unclear if this also applies to the North South Link.

As we pointed out, it is possible under the existing arrangements for ESB to acquire up to 40% of Moyle capacity without any restriction and as no additional capacity is being brought in to the market this could be used to increase its dominant position.

On May 4th Moyle Interconnector Limited published a public consultation paper on its Post SEM Trading arrangements. From November 1st 2007, all Moyle Interconnector capacity will become available to the market.

The proposed Moyle access arrangements Post SEM are as follows:1

Paragraph 2.3. There is no set fixed level of maximum capacity which any bidder may acquire. However in the event of an over subscribed annual auction (held for capacity for periods of one or more years) a notional 40% cap figure for capacity gained at auction does exist. If this 40% cap figure is reached by any bidder at the annual auctions then this is expected to trigger an analysis of the impact on the market environment of the auction outcomes in relation to proportions held by each bidder. This analysis will be carried out by Moyle in consultation with the Utility Regulator. This does not mean that any one participant’s holding would be limited to 40%. The Utility Regulator did not need to place caps on capacity sold at the last annual auctions. It is proposed that the Utility Regulator will not restrict the total level of capacity allocated to one bidder at any monthly or weekly auctions.

1 Moyle Interconnector Trading From - 1 November 2007 : A Consultation Paper by Moyle Interconnector Limited May 2007 http://www.nienergyholdings.com/Download/consultation/Post%20SEM%20proposed%20trading%20arrangements%20consultation% 20070504.pdf

1 As with the current arrangements there does not appear to be any restrictions going forward on ESB accessing significant amounts of capacity on Moyle.

Our Proposal

Our proposal which we consider to be fair and balanced is that in the case of ESB should they wish to consider accessing capacity on the East West Interconnector they would be limited to a maximum of 40% of total capacity on contracts longer than one months duration.

We think that this is sensible as 60% of the capacity would be available to other market participants in the event that ESB fully subscribed to the 40% cap, even in that scenario with the additional capacity being introduced by the interconnector ESB’s market share would still be incrementally reduced.

However, we feel that this mechanism for reducing ESB’s ability to procure capacity would be better served through other means rather than making it a condition imposed through the EU Exemption or licensing process.

We also think that it is important to precisely define ESB so that other parts of the ESB Group such as ESBIE, Hibernian Wind and ESB International who may wish to access capacity for commercially sound reasons are not commercially disadvantaged by being unable to access it,

Finally, as we have mentioned above we are proposing to implement a non-discriminatory, market-based and efficient methods of allocating transmission capacity, we do recognise the dominance issue and we think we have offered a fair proposal, as a merchant project we must ensure that we minimise any risk of restrictions on the use of capacity and are concerned that any restrictions could harm the commercial viability of the project. We think that it is import for the CER to examine the Moyle proposals as it would be grossly unfair to impose onerous restrictions on a merchant project that carries all the risk, when a competing interconnector that has a regulated revenue safety net does not have any cap on capacity held.

Rory O’Neill - 9th May 2007

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***For your information*** We have been working very closely with Dr. Leonardo Meeus of Leuven University in Belgium, Leonard is also the scientific coordinator of the KU Leuven Energy Institute (EI) and the European Energy Institute (EEI). Since 2006, he is the chairman of the CIGRE Task Force C5-7.1 on generation and network capacity investment incentives in electricity markets. Leonardo has been assisting and advising on interconnection trading, capacity allocation and exemptions etc. He has recently prepared a paper for us examining Eu exemptions. This paper is attached below.

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2 Exemptions based on the Gas and Electricity Directives Case Law

Exemption track record Eight exemptions have been granted by national regulators and are accepted by the European Commission. Seven exemp- tions have been granted for gas infrastructure; only one exemption for electricity infrastructure has received authorization yet. One application (BritNed) is still under consideration.

Name Sector Involved countries Type of infrastructure Date Gate Terminal Gas Netherlands LNG terminal 22-12-2006

Brindisi LNG Terminal Gas Italy LNG terminal 3-5-2005 BBL: Bacton-Balgzand Gas UK, Netherlands Pipeline 21-4-2005 Estlink Electricity Estland, Finland Interconnector 3-3-2005

Dragon LNG Terminal Gas UK LNG terminal 14-2-2005 South Hook LNG Ter- Gas UK LNG terminal 10-12-2004 minal Isle of Grain LNG Ter- Gas UK LNG terminal 10-12-2004 minal North Adriatic LNG Gas Italy LNG terminal 10-12-2004 Terminal BritNed Electricity UK, Netherlands Interconnector Pending

Access regimes Basically, there are two systems to develop an exempted facility: negotiated Third Party Access (nTPA) and own use. These are in contrast with the regulated Third Party Access (rTPA) regime. In an nTPA system the owners don’t use the facility for their own activities, they just own it. In an own use system, the owners have primary capacity rights. However, a combination of systems within one exempted facility is possible. For instance, a facility can be owned by different parties. Some of them can have primary capacity rights (own use), while others don’t and only own a part of it (nTPA). Furthermore, it is possible that only a part of a facility is exempted. For instance, 80% of the capacity is exempted and the remaining 20% is developed in an rTPA regime.

In case of own use infrastructure an exemption gives the possibility to reserve capacity for own use, which is not possible for regulated infrastructure. In an nTPA regime, the exemption allows long-term contracts to underpin the investment and thereby lower the risk.

Note that the BritNed application is exceptional. The interconnector is not meant for own use and there is currently no aim for long-term contracts. The developers main concern is the regulatory risk associated with the project. They expect the income from the interconnector to be volatile with good and bad years. They fear regulatory actions to limit profits in the good years, thereby limiting the possibility to make up the bad years. This would detrimental to the life time profitability of the cable. An exemption guarantees the income to be unregulated. The developers believe that rTPA compliant access to the interconnector will enable them to recover the investment cost.

LNG terminals are often constructed in phases. The timing of the capacity allocation often follows the construction schedule. It is therefore possible that not all the capacity has been allocated yet, like in the Grain project. For the Gate Terminal the final results of the open season have not been published yet.

Name Access Regime

Gate Terminal Own use (*)

Brindisi LNG Terminal Own use, rTPA

BBL: Bacton-Balgzand nTPA

Estlink Own use

3 Dragon LNG Terminal Own use (*)

South Hook LNG Terminal Own use

Isle of Grain LNG Terminal nTPA

North Adriatic LNG Terminal Own use (*), rTPA BritNed rTPA

(*) Not all owners of Gate Terminal and Dragon will be primary capacity owners.

Name Facility Owners Primary Capacity Rights

Gate Terminal Koninklijke Vopak (? %) , Neder- RWE (± 20%), landse Gasunie (? %), RWE (10%), others under negotiation others possible after ‘open season’ Brindisi LNG Terminal BG Italia (100%) BG (80%), rTPA (20%) BBL: Bacton-Balgzand Gasunie BBL (60%), Ruhrgas (? %), E.ON Ruhrgas BBL (20%), Fluxys Gasunie Trade& Supply(? %), BBL (20%) Wingas (? %) Estlink Eesti Energia (39.9%), Latvenergo Eesti Energia (? %), Latvenergo (? (25%), %), Lietuvos Energija (25%), Pohjolan Lietuvos Energija (? %), Pohjolan Voima (6.06%), Helsingin Energia Voima (? %), Helsingin Energia (? %) (4.04%) Dragon LNG Terminal 4Gas (20%), Petrogas (50%), Petrogas (30%), BG (50%) BG (50%) South Hook LNG Terminal Qatar Petroleum (70%), Exxon Mobil Phase 1: South Hook Gas Company (30%) (100%) Isle of Grain LNG Terminal Grain LNG Phase 1: BP/Sonatrach (100%) Phase 2: Centrica, Gaz de France, Sonatrach Phase 3: open season North Adriatic LNG Terminal Qatar Petroleum (45%), Exxen Mobil Edison (80%), (45%), rTPA (20%) Edison Gas (10%) BritNed National Grid, Although exempted, rTPA access TenneT regime

It is important to differentiate between primary capacity rights and the secondary market for capacity. Although third party access for primary capacity conditions can be organized differently between the various facilities, the secondary market for capacity is in all the cases based on a Use-it-or-lose-it principle. Holders of primary capacity are not allowed to hoard capac- ity. Everyone can participate in the secondary market.

Primary Capacity Allocation: open season As mentioned above, there are different ways to allocate the primary capacity. The most common system is an open season, a tailor-made auction system. The exemption cases without open season are facilities built for own use.

Name Open Season?

Gate Terminal Yes

Brindisi LNG Terminal No

BBL: Bacton-Balgzand Yes

Estlink Unknown (*)

Dragon LNG Terminal Yes

South Hook LNG Terminal No

Isle of Grain LNG Terminal Yes

4 North Adriatic LNG Terminal No (**)

Britned No

(*) Not to our knowledge. There might however been an open season to attract interested parties. (**)As only the owner holds the capacity rights, we assume no open season.

Although an open season is believed to be a good way to allocate primary capacity, there is no such thing as ‘the one and only way to run an open season’. There are, however, general guidelines in the way open seasons are run in this context. In what follows the ERGEG 2 view is presented. Next, several aspects from previous cases are discussed.

ERGEG’s view ERGEG has started a public consultation on open season procedures. Although the consultation document is mainly fo- cused on the gas market, the content can also apply on the electricity market. ERGEG’s scope is broader than only possible exempted infrastructure. Also regulated infrastructure can use an open season procedure, for instance in exploring the mar- ket need for more infrastructures.

In their draft guidelines ERGEG broadly defines an open season as “a two step process; an open assessment of market demand for a specific proposal (first step) and a subsequent phase of capacity allocation (second step)”. The main concern for ERGEG is that an open season procedure is non-discriminatory and transparent and that the result is efficient. If these criteria are met an open season can be seen as a competitive tool used for the long-term allocation of capacity and can be accepted as a market-based allocation mechanism.

The first step of an open season consists of a proposal to the market. The proposal should give an idea of the intended ca- pacity available for the market and for the cost associated with the project. This notice to the market should allow potential bidders to analyze the proposal. This first step should inform potential bidders about how the open season will continue, especially how in the end capacity will be allocated. The project developer has the possibility to express the conditions for later bids, e.g. minimum lot size. In this first phase the open season can be tailored to the situation. The procedure is really open in the sense that bidders can do proposals to enhance the project to better fulfill their needs. This first step is not bind- ing to the developer. He can amend the capacity of the project and he can continue with the project even if not enough de- mand showed up in this first phase. The first step can conclude with the signing of non-binding Letters of Intent with inter- ested parties.

After the market test in the first step, the second step of an open season allocates the capacity. The allocation mechanism is not subject to the result in the first step (however, this should be explained in the first step). Both a pro rata allocation and an auction are possible. The former will be used when the first step resulted in an oversubscribed capacity. National legislation can add extra requirements. Not only long-term but also shorter capacity can be booked. Existing and future users should be treated equally. After the allocation, pro-forma agreements should be signed. The level of detail depends on the project development.

ERGEG believes regulators have to oversee any open season procedure in order to guarantee the goals of the procedure will be met. According to ERGEG several elements should be published in public: - the investment decision (capacity, route, timing,…) - names of the shippers and their percentage of the capacity - tariff - contract duration. Regulators can request more information to be made public.

Open season: analysis of real cases

1. An open season procedure is used to allocate capacity. However, it is possible for parties who obtained long-term contracts to join in the ownership of the infrastructure. For instance, the Gate Terminal project was originally owned by Koninklijke Vopak and Nederlandse Gasunie. RWE took a participation in the project of 10% after getting long- term contracts in the open season. This option was also available in the Dragon project.

2. Open seasons are used to allocate capacity. However, the capacity available has not to be fixed in advance of the open season. Open seasons allow to gauge the market and to determine the capacity by using the open season results.

3. After the first stage an open season results (probably) in several interested parties, who might sign a Letter of Intent. It is not necessarily true that all these parties in the end sign a long-term contract. For instance, the first announce- ment of the BBL projected resulted in 18 interested parties. Only 6 signed a Letter of Intent to commit capacity. Finally, 3 companies agreed on contracting long-term capacity. A similar process is found in the Dragon project, starting with 28 parties in the first round and ending up with 2 long-term contracts signed.

2 European Regulators’ Group for Electricity and Gas

5 4. As LNG terminals are often built in phases the capacity is also allocated in phases. It is however possible to agree contracts for the first phase and thereby granting an option for capacity in a next phase.

5. As long as the open season procedure is performed in a non-discriminatory and transparent way and there is no detriment to the competition, the outcome has a chance to be acceptable, even in cases where one party obtains 100% of the available capacity. This was the case in the first phase of the Grain project where BP/Sonatrach re- ceived primary capacity rights for the full capacity.

6. As mentioned earlier, BritNed is exceptional in a sense that there is no own use and no nTPA system. The capacity will be made available in a system like for regulated infrastructures. There are no long-term commitments (i.e. > 1 year) what so ever in the application made by BritNed.

However, in the public consultation period following on the initial views 3 of the regulator, Centrica suggested long- term allocation as a good way to manage the risks. Centrica proposes an open season process with several re- strictions for the resulting contracts: o no more than a certain proportion of the capacity can be made available for long-term contracts (e.g. 1/3 of the capacity) o limits on how much capacity one party can obtain o strong use-it-or-lose-it provisions

E.ON reacted in the public consultation period on a reserve price provision in the BritNed application. The reserve price should cover the electrical losses, but there is no confirmation in the application according to E.ON that the reserve price is limited to these losses.

Exemption duration There is a difference between electricity and gas cases with respect to the exemption duration. Gas infrastructure is in gen- eral exempted for the specific duration of the long-term capacity contracts. For instance, the European Commission amended the decision of the regulators for the BBL pipeline in order to limit the exemption duration to the length of the con- tracts. This resulted in a shorter exemption period than requested.

There are only two electricity cases of which one has not been approved yet. Conclusions about suitable duration can not be made at the moment.

Name Duration Comments

Gate Terminal 20 years 25 years asked, but amended by the Dutch regulator Brindisi LNG Terminal 20 years (*)

BBL: Bacton-Balgzand 10 or 15 years, de- Originally 15 years, but amend- pending on the part ment made by the European of the capacity con- Commission: duration no longer sidered than the specific duration of the long-term contracts Estlink 2006-2009/2013

Dragon LNG Terminal 20 years

South Hook LNG Terminal 25 years

Isle of Grain LNG Terminal 20/25/20 years for the three phases North Adriatic LNG Terminal 25 years (*)

BritNed 25 years asked Centrica proposes a shorter pe- riod (e.g. 10 years) (*) Based on the length of the contracts.

3 Ofgem’s final views are not published yet.

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