FURTHER INFORMATION:

Current Bilateral Contracts Market

Ireland currently operates a day ahead bilateral contract market pursuant to which generators nominate to the transmission system operator (TSO), on a day ahead basis, the schedule of energy they want to produce and the prices they require. The market rules are set out in the Trading and Settlement Code (Code). A CHP plant is subject to central dispatch under the Grid Code on the same basis as conventional units.

The TSO determines a merit order for dispatch purposes on the basis of the schedules submitted by generators. Initial commercial positions are based on forecasts and therefore imbalances between projected supply and demand often occur. The Settlement System Administrator (SSA) calculates imbalances and market participants are able to initially trade out imbalances amongst themselves. Aggregate imbalances are then settled by the purchase of "Top up" from and sale of "Spill" to ESB.

The holder of a Supply Licence or any centrally dispatched plant must accede to and comply with the Code. However, a non-centrally dispatched plant does not have to accede to the Code unless it wishes to trade electricity. Therefore, a CHP unit, which produces only for its own use and does not "Spill" onto the system, does not have to accede to the Code. The process for acceding to the Code is by application to the TSO and the CER pursuant to Agreed Procedure No. 9.

Since July 2003, CHP suppliers are required to balance only 95% of their demand in their first year of trading, allowing a 5% margin of error in recognition of the difficulty of balancing a supplier's demand on a certain date at a certain time. CHP generators are required to balance 92% of the their rated capacity of sales to CHP suppliers with its CHP tradable quantity, again recognising a CHP generator's outage probability.

New Market Arrangements in Electricity

New Market Arrangements for Electricity ("MAE") are currently being developed by the CER and are required to be implemented in Ireland on or before 19th February 2006.

However, on 16th June 2004 the CER announced that it would delay the implementation of the MAE for a period of approximately 3-4 months to allow for the consideration of changes to the MAE market design and for the introduction of a new market implementation and procurement process. This may therefore require an extension of the implementation deadline. The high level principles of the MAE include:

• A mandatory centralised pool market requiring all electricity to be bought from and sold to the system and market operator (SMO). This will mean that it will no longer be possible for market participants to contract to buy and sell physical electricity from each other. They may only buy and sell electricity from the pool.
• Market participants may manage their exposure to volatility in the pool price for electricity by entering into various forms of hedging arrangements. At their simplest level, these may be contracts for differences between the pool price and an agreed strike price entered into by generators and suppliers.
• The pool will be an energy-only spot market with no payments for capacity. Generators who are not dispatched due to constraints, or because their bids are above the spot price, will not receive any payments in the spot market. The spot market will be cleared and corresponding dispatch schedules determined for half hour trading intervals.
• The market clearing price for each generation node will be the locational marginal price (LMP) at that node. The nodes have not yet been specified but will be designated by the CER. A load weighted average demand price or Uniform Wholesale Spot Market Price (UWSMP) will be calculated for all demand nodes.
• A regime of financial transmission rights will be implemented which will enable generators to hedge differences between the price at their generation node (i.e. their LMP) and the load weighted average demand price (i.e. the UWSMP).

The CER has recently published a decision in relation to the treatment of CHP in the new market arrangements for electricity (MAE). Key elements of this decision are as follows:

• small-scale generators with an MEC of less than 100kVA shall be exempt from the MAE Rules; generators with an MEC of less than or equal to 5MVA will self-dispatch; generators with an MEC greater than 5MVA must register with the SMO as centrally controllable and may be dispatchable if they satisfy the requirements of the Distribution/Grid Code; and generators with an MEC of 30MVA or more must be dispatchable;
• self-dispatched and centrally controllable generators will be required to produce for the SMO a "best-efforts" schedule comprising, at minimum, estimated plant output per trading period from day-ahead up to gate closure;
• grid connected generators and generator sites with an aggregate MEC greater than 5MVA will receive the LMP at its node; distribution-connected generators with a MEC less than or equal to 5MVA will receive the UWSMP; and
• the MAE rules will not insulate generators from negative pricing; therefore, if the spot price becomes negative, generators exporting electricity directly to the pool may be required to pay the negative spot price multiplied by the volume of electricity that they are exporting.