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									Decision Paper and Response to Comments on the Draft Decision on Wholesale Electricity Trading Arrangements “Wholesale Electricity Trading: A Review of the Spill Floor Price, CRSP and the regulation of ESB Power Generation INC/DEC bidding”

CER/05/220

4th November 2005

Table of Contents
1. 2. 3. 4. 5. Introduction and Background ........................................................................ 3 Spill Price Floor ................................................................................................... 4 Level and Profiling of CRSP ............................................................................. 7 Proposed Arrangements for Green/CHP Energy ...................................... 9 Calculation of ESB Power Generation DEC Price .................................. 11

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Introduction and Background

On 22nd April 2005, the Commission for Energy Regulation („the Commission‟) published a consultation paper reviewing certain existing trading arrangements (namely the spill price floor, capacity related spill payment and regulation of ESB Power Generation bidding). This consultation paper was entitled “Wholesale Electricity: A Review of the Spill Floor Price, CRSP and the regulation of ESB Power Generation INC/DEC bidding” (reference CER/05/071). Under Statutory Instrument No.49 of 2000, the Commission is responsible for the supervision and revision of the rules of the trading regime for wholesale electricity in Ireland, as set out in the Trading and Settlement Code. Further to its consultation, the Commission published a Draft Decision Paper and Response to Comments on the Consultation on Wholesale Electricity Trading Arrangements on 9th September (ref. CER/05/162). In its Draft Decision Paper, the Commission proposed to: 1. 2. 3. Maintain the spill price floor at its current level of €28/MWh; Add €1.70/MWh to the floor price to reflect the incremental cost of carbon; Keep the capacity related spill payment (CRSP) at its current level of €5.94/MWh, except between the hours of midnight and 8.00 am when the CRSP will be set at zero; Amend the trading arrangements for green and CHP market participants such that green and CHP participants can either get the CRSP payment when they spill or keep the right to 100% primary top up; Keep the 350MW limit on spilled energy receiving the CRSP; Allow ESB Power Generation to base its INC and DEC offer prices on the day ahead gas price, rather than the month ahead gas price as is currently the case; and, Require ESB Power Generation to include the incremental cost of carbon in its INC/DEC offer prices.

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The Commission received responses to CER/05/162 from six companies: Airtricity, Aughinish Alumina Ltd., Bord Gáis Energy Supply, ESB Power Generation, Synergen, and Viridian Power and Energy. Respondent‟s comments together with the Commission‟s views and its final Decision are summarised below. The Decision paper is organised by the various categories of issues raised in the Draft Decision Paper, namely the spill price floor, CRSP payments and ESB Power Generation INC/DEC bidding parameters.

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2. Spill Price Floor
The Commission, in its Draft Decision paper, proposed to: 1. Maintain the spill price floor at its current level of €28/MWh; 2. Add €1.70/MWh to the floor price to reflect the incremental cost of carbon; Summary of Comments Received Airtricity welcomed the Commission‟s decision to maintain a spill price floor. But they were disappointed that the Commission had not decided to increase the floor in a more significant manner. In the context of off-peak power in the United Kingdom (the BETTA market) running at between £25-£30/MWh (€37-€44/MWh), Airtricity contended that a modest increase in the spill price floor to €35/MWh would be justified. In addition, introducing day ahead gas prices for determining ESB PG INC and DEC prices would introduce a greater volatility in spill prices. Airtricity propose that such uncertainty would be mitigated by increasing the spill price floor to €35/MWh. Aughinish Alumina pointed out that the Commission‟s decision was inconsistent with the Commission‟s position (in CER/04/112) that the spill price floor should be set at the avoidable fuel cost of the best new entrant (BNE) plant. Applying that methodology in 2006 would result in a spill price floor of €48.40/MWh, with an additional carbon cost of €1.70/MWh (as proposed by the Commission). If the Commission was not minded to continue with the current methodology for calculating the spill price floor, then it should increase the spill price floor to €37.04/MWh. This would represent a fair balance between consumer costs and generator receipts and would be consistent with the decision to amend ESB PG‟s DEC price bidding to reflect day ahead gas prices. Bord Gáis Energy Supply (BGES) were similarly disappointed that the Commission had decided not to increase the floor price to the 2006 BNE avoidable fuel cost of €48.40/MWh. BGES pointed out that independent supplier/generator costs must be recovered one way or another. They state that it is in consumers‟ best interest that they be recovered in a transparent and appropriate manner. ESB Power Generation disagreed strongly with the Commission‟s proposed decision to keep a spill price floor. ESB PG believed it to be the most serious and distorting issue in the Commission‟s Draft Decision. The price floor forces ESB PG to buy energy at a higher price than it costs ESB PG to generate. This cost had increased since the floor price was introduced and would increase further as more independent generation comes onto the system. The price floor also facilitates an unreasonable arbitrage between two sets of administered spill prices in Northern Ireland and the Republic. If the floor

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price did not exist, customers would benefit from cheaper energy on an allIsland basis. The price floor had also created an adverse impact on system security. To the extent that the system operator (SO) had to take action to avoid undue risks to system security, the SO would incur unnecessary constraint costs to create a reasonable dispatch schedule, adding to costs for all customers. ESB PG‟s view was that the spill floor creates most distortion at night. So, if there was a case for profiling, the floor price should be zero at night. If the Commission were still minded to keep a spill price floor at all, then ESB PG believed that a significant improvement would result from setting it at €20/MWh, or just below the spill price floor in Northern Ireland. ESB PG pointed out that an initial estimate of the actual average cost to ESB PG of meeting CO2 obligations was lower than the Commission‟s proposed €1.70/MWh. Synergen regarded the spill price floor, the level of top up and secondary top up prices, the CRSP and the regulation of ESB Power Generation INC/DEC bidding to be inextricably linked. Synergen supported the proposed Commission decision to keep the spill price floor but was concerned at the internal inconsistencies within the Commission‟s approach, particularly given the significant spread between the real reduction in the spill price floor and increasing top up prices. The combined effect of the Commission‟s proposals on top up and the spill price floor was that the historic differential between the spill price floor and top up prices would be widened in 2006. Within the administered arrangements, two factors would have an impact on the end prices to customers in the competitive sector: the overall level of prices; and the differential between the spill price a generator/retailer receives and the top up price it buys at. This differential will increase the costs of operation to independent generators and suppliers who are exposed to this differential at times when contracted volumes are out of balance with customer volumes. This will inevitably feed through into customer prices. Synergen argued that the Commission‟s proposals would undermine retail competition and increase regulatory risk. In common with other respondents, Synergen pointed out that the application of the Commission‟s methodology, as set out in CER/02/113, would set the spill price floor in 2006 at 48.40 €/MWh (excluding an adjustment for carbon costs). Viridian Power and Energy (VPE) considered the Commission‟s suggestion to remove the CRSP at night, and not to raise the spill price floor above €29.7/MWh, to have the following adverse consequences: 1. the spill price at night is below the BNE generator‟s marginal cost. If the spill price floor is not greater than €35/MWh (or the CRSP allowed at night), new entrant generators will reduce output or shutdown during the night. ESB PG plants, at a lower efficiency and

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with higher emissions, would increase output. The net effect would be a distorted economic dispatch and higher emissions. 2. 3. There would be no change in current North – South flows as the spill price floor is still higher than the Northern Ireland spill price. ESB PG would be gifted significantly higher revenue from the provision of balancing services to the market.

Commission’s Decision The Commission has decided that the spill floor shall remain at €29.70/MWh, in line with its draft decision. It is recognised that the spill price floor remains an important mechanism for the independent sector in terms of revenue certainty at times when spill may be necessary (at night). However, in its consultation paper, the Commission stated its concerns over the opportunities for arbitrage presented by the existence of a floor price, given the current level of this floor (including CRSP). The Commission also has a duty to take into account the cost to final ESB PES customers of maintaining a spill floor mechanism. The Commission has considered all the comments received on this issue. The Commission remains of the view that the spill floor price continues to be an important mechanism for the independent sector, providing a degree of revenue certainty. With this in mind, and the need for regulatory certainty, it has therefore decided that that the spill floor will remain at its current level of €28/MWh for the time leading up to the implementation of the SEM. To reflect the incremental cost of carbon to generators the Commission has decided to add €1.70/MWh to the existing spill floor. Implementation of the Decision The Commission decision on spill price floor will take effect and apply to spilled energy from 1st January 2006.

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3. Level and Profiling of CRSP
The Commission proposed in its Draft Decision paper to: 1. Keep the capacity related spill payment (CRSP) at its current level of €5.94/MWh, except between the hours of midnight and 8.00am when the CRSP will be set at zero; 2. Retain the 350MW limit on spilled energy receiving the CRSP. Summary of Comments Received Airtricity, Aughinish Alumina and Viridian Power and Energy (VPE) were silent on the issue of whether the current level of the CRSP was still appropriate and on the setting of CRSP to zero at night. Bord Gáis Energy Supply (BGES) welcomed the Commission‟s proposed decision to retain the CRSP mechanism. But BGES does not support the Commission‟s view that the CRSP payment encouraged spilling at night when no further capacity was required. BGES argued that if an independent market participant could avoid spilling at night it would do so, particularly as the revenue received did not make it attractive on a trading period basis. BGES believed that a baseload new entrant would need to spill a portion of its energy (almost) regardless of price received so it was incorrect to assume that night-time CRSP incentivised independent market participants with baseload plant to spill energy. The payment of CRSP at night was entirely appropriate since it incentivised baseload capacity to be made available to the market. Setting CRSP to zero at night would reduce an independent market participant‟s ability to recover the costs of being a market (capacity) contributor by receiving adequate system revenues and would only serve to increase regulatory uncertainty for potential (or current) new entrants. ESB Power Generation maintained that there should be no CRSP payment. The spill price should reflect only system avoidable fuel costs. ESB PG agreed that the CRSP should be zero at night. This would improve system security and economic dispatch. Synergen’s view was that CRSP was consistent with the proposed SEM design. It therefore welcomed the CER decision to retain it, but did not agree with the decision to profile it through the removal of CRSP payments overnight. Whilst Synergen acknowledged that there did not appear to be a need for an explicit capacity payment overnight, CRSP will have formed part of generators‟ assumed revenues. The removal of CRSP will further increase the spill/top up price differentials for Independent Power Producers (IPPs). This will inevitably feed through into IPPs‟ decisions on generation prices and generator availability.

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If the Commission‟s proposal is intended to limit spill into the Ireland from Northern Ireland (given low spill prices in Northern Ireland), the Commission should consider Synergen‟s suggestion that Interconnector flows should not be eligible for CRSP, regardless of generation technology. Commission Response/Decision The Commission is not persuaded by the responses to its draft decision to reward capacity with a specific payment at night (CRSP) on the grounds that:   There is no obvious need to reward the provision of capacity at night; Paying CRSP at night worsens the deficiencies of a floor price (dispatch inefficiency, artificial arbitrage, the morning rise problem/constraint costs, higher PES tariffs than in the absence of a floor etc.); The total amount paid for CRSP at night in 2004 was in the region of €2.2 million. This amount is unlikely on its own greatly to affect the running decisions of individual independent generators or suppliers; The Commission is of the view that it remains appropriate to reward capacity with a CRSP payment during the day.

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The Commission is aware that setting CRSP to zero at night will not in itself fully rectify the arbitrage issues identified in its original consultation paper. However, it will provide for a more accurate and appropriate signal to be sent to the market concerning the delivery of capacity at time when it is not required and also reduce the incentive with respect to the exploitation of arbitrage opportunities at night across the North-South Interconnector, whilst also reducing overall system costs and the costs to the ESB PES customer. It is not possible to exclude Interconnector trades from CRSP or spill floor payments. The Commission also confirms its decision that the 350MW limit on energy received CRSP shall be retained. Implementation of the Decision The Commission decision on CRSP will take effect and apply to spilled energy from 1st January 2006.

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4. Proposed Arrangements for Green/CHP Energy
The Commission proposed in its Draft Decision paper to amend the trading arrangements for green and CHP market participants such that green and CHP participants can either get the CRSP payment when they spill or keep the right to 100% primary top up. Summary of Comments Received Airtricity claimed that the exclusion hitherto of CRSP from green power spilled to the system has had two anti-competitive and distortionary effects: The payment of an additional capacity element to suppliers of nongreen/CHP power enables such suppliers to bid for North-South Interconnector capacity at a higher price than can be justified by a green/CHP power importer. The non-payment of CRSP ensures that green/CHP suppliers are unable to compete on an equal commercial basis with non-green/CHP suppliers. This, they state, is clearly anticompetitive. Under current green balancing rules, green suppliers have to purchase green power to replace any top-up power bought from the system. This has meant that Airtricity has been forced to import green power at night purely for the purposes of meeting the existing requirements for green balancing. The exclusion from payment of CRSP from green power spilled to meet such balancing requirements has unfairly increased the cost to green/CHP suppliers of meeting their balancing requirements.

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Airtricity therefore welcomed the decision of the Commission that green/CHP participants should be entitled to CRSP. However, Airtricity did not agree with the Commission‟s proposal that green/CHP participants should receive either a CRSP payment for spilled energy or retain 100% access to primary top-up. Full (100%) access to primary top-up was established at the start of the current wholesale trading arrangements. Airtricity claimed that, at that time it was recognised that, if it were to be subject to secondary top-up charges, the variable output from the most prevalent renewable generation technology (i.e. wind) would be unfairly discriminated against. Airtricity argued that CRSP payments should be made available to all energy suppliers, irrespective of the generation technology utilised for any power that is spilled. To do so otherwise was unfairly discriminatory and anticompetitive. In particular, discriminating between non-green/non-CHP power and green/CHP power when such power had identical availability – since it used the same interconnection facilities - could not be objectively justified. For Interconnector imports, the impact in terms of capacity addition to the system is the same, irrespective of the technology that was used to originally produce such power. The benefit in terms of capacity support to the system is identical in both cases.

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Aughinish Alumina welcomed the Commission‟s decision to amend the trading arrangements for CHP and green energy in the way proposed. Aughinish were, however, disappointed that the Commission had proposed that, to receive this payment, CHP and green plant would not also be able to retain access to 100% primary top-up. Aughinish believed that this would be inconsistent with the Commission‟s role in promoting renewables and CHP. Bord Gáis Energy Supply (BGES) supported the Commission‟s proposed decision that CRSP payments should only be paid to green or CHP generators who do not retain 100% access to primary top-up in any way. It was not clear, however, how the decision would be implemented. For example, could a green/CHP generator access CRSP at times that it „opts out‟ of the 100% top-up entitlement; or must a green/CHP generator declare that it will opt for the 100% top-up 1 entitlement at the expense of not receiving CRSP for the year? ESB Power Generation did not agree with the Commission‟s proposal. Because wind created the need for extra capacity margin, it would make no sense to pay CRSP to green participants. Synergen and Viridian Power and Energy (VPE) were silent on the issue of whether green/CHP participants should be paid CRSP. Commission Response/Decision In light of the arguments raised, the Commission is of the view that the trading arrangements for green and CHP energy should be amended such that green and CHP participants receive a CRSP payment for spilled energy. In carrying out the duties imposed on the Commission by the Electricity Regulation Act, 1999 (as amended), the Commission is required to have regard to the need to promote the use of renewable, sustainable or alternative forms of energy. Prior to the opening up of the electricity market to full retail competition in February 2005, green and CHP market participants enjoyed the benefit of having access to the whole retail market (relative to “brown” energy market participants who did not have full market access until February 2005). In light of the expiry of that benefit, and having regarding for the Commission‟s duties with respect to Green and CHP, the Commission has decided to amend the Trading Arrangements such that all green and CHP energy will be entitled to the CRSP. In addition to the above, the Commission views this change as being a suitable measure to facilitate transition to the SEM, where it is anticipated that green and CHP will be entitled to a capacity payment, with such payment to be related to availability. The current rules in relation to balancing will continue to apply for the present. The Commission is currently considering the balancing rules in the context of the introduction of new fuel disclosure measures and may consult further on this issue in the near future. Implementation of the Decision The Commission decision on CRSP will take effect and apply to spilled energy from 1st January 2006.

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5. Calculation of ESB Power Generation DEC Price
In its draft decision, the Commission stated that it was minded to:   Continue to regulate ESB PG‟s INC/DEC bids; Instruct ESB PG to base its INC and DEC bids for its gas plant on a day-ahead gas price index in accordance with a specific direction by the Commission; Instruct ESB PG through Direction to include in its INC/DEC bids the incremental cost of carbon.

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Summary of Comments Received Airtricity claimed that the Commission‟s proposal for the use of day ahead gas prices, rather than month ahead prices, for setting ESB PG INC and DEC prices was at variance with the philosophy adopted by the Commission in setting BNE prices, where an average of gas prices over four months had been used. Whilst Airtricity had reservations regarding the impact that this change may have on the volatility of INC and DEC pricing, it urged the Commission, if this proposal was adopted, to review this decision in six month‟s time to ensure that there were no unintended impacts. Airtricity agreed that carbon costs should be included in ESB PG bids for INC/DEC bidding. However Airtricity believed that, in common with experience in other markets, the full cost of carbon should be reflected in bidding. To do otherwise would blunt the economic signal of the EU Emissions Trading Scheme (ETS). Aughinish Alumina made no comment on the proposed decision. Bord Gáis Energy Supply (BGES) agreed that the electricity market was not ready to allow unregulated bidding by the dominant generator portfolio plants and was disappointed at the Commission‟s proposed decision to allow ESB PG to use day-ahead instead of month-ahead gas prices in calculating INC/DEC bids. BGES argued that regulated bidding should use known price references to provide for a level of certainty for other market participants. Spill was an important pricing component for independents. It was essential that there was a basic methodology in place which demonstrates how regulated numbers were calculated. ESB Power Generation proposed that it should be allowed to bid freely into the market for baseload plant, where there was now sufficient baseload capacity to allow for normal competition. This could be achieved by allowing specified plant to qualify for free bidding. ESB PG supported the Commission‟s proposed decision to allow ESB PG to base its INC/DCE prices on day ahead gas prices.

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Synergen welcomed the Commission‟s proposed decision to maintain the existing restrictions on ESB PG‟s bidding. However, Synergen was disappointed by the Commission‟s decision to allow ESB PG to base its INC and DEC prices on day ahead gas prices. Synergen had the following concerns:  There was no analysis of the impact of such a change. Whilst Synergen in its submission to CER/05/071 noted that the ESB PG proposal lacked meaningful analysis no further data has been published. Synergen re-iterated that it was not clear that the daily gas price represented a more representative value for the avoidable fuel cost of ESB PG gas plant. For a move to daily gas prices to be reasonable in the context of the existing arrangements, it would be necessary to demonstrate that ESB PG are exposed to such prices for a substantial element of their gas-fired generation providing balancing services in the current bilateral market. It was unclear that this was the case. Synergen noted that the Commission states that “ . . . there is a close correlation between month-ahead and day-ahead prices. If it is assumed that this is the case, it could be considered therefore that there is no real difference in changing to the proposed new methodology”. If the change was not material, why make the change? The Commission also claimed that the day ahead gas price was volatile and thus presented a more accurate pricing signal. This contradicted the preceding argument that there was no material difference in the two prices.

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Viridian Power and Energy (VPE) did not agree with the Commission‟s proposal to change the current practice for regulation of ESB PG INC/DEC pricing, for the following reasons: 1. The current month ahead indices were those proposed by ESB PG and agreed with other market participants after extensive consultation and public meetings. There was no evidence to indicate that the current indices were creating any problems. The major contributors to changes in ESB PG fuel purchases day ahead and within day recently surely stemmed from ESB PG‟s erratic and unreliable availability together with changes in weather patterns. Variations in independents‟ use of topup do not vary significantly from projected month ahead volumes by comparison with these other factors. If it is the Commission‟s view that the day ahead and month ahead prices were very similar, why not leave the current arrangements as they were? The day ahead price was not reflective of the within day fuel variations that ESB PG must manage and thus cannot be argued to be an accurate signal.

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Market participants seek to reduce uncertainty in projecting prices. The change from month ahead to day ahead increases risk to new entrants without providing any benefits to customers.

Commission Response and Decision The Commission remains of the view that the measures proposed in its draft decision are appropriate and has therefore decided that they shall be implemented. The Commission believes that in light of the significance of ESB PG in the overall generation sector in Ireland, it remains appropriate that ESB PG‟s bids remain regulated for the foreseeable future. With respect to ESB PG bids for gas plant being based on a day-ahead rather than a month ahead price, the Commission is of the following opinion: 1. In the absence of the ability to vary bids across the day, that bidding on the basis of day-ahead gas prices is the most appropriate proxy (in the present gas environment) and is preferable to month-ahead gas price bidding used to date. This is because efficiency is enhanced by setting prices as close to real time as possible; Bidding on the basis of day ahead prices will provide a more accurate signal of which plant should run and when. This is important not only for the efficiency of merit order dispatch; but also given the role which ESB PG plant plays in the setting of the spill price; In the case of a gas price spike, ESBPG‟s INC/DEC prices will rise in step as these are closer to real time now (with day ahead bidding) and therefore better reflect market volatility. Spill prices will in this scenario be based on higher INC/DEC prices and, other things being equal, will push up the top up price. This is because (to avoid arbitrage) the rules state that if the spill price is above the pre-determined top up price, the top up price is raised to equal the spill price. In these circumstances, if an IPP (for arbitrage reasons) decides to bid such that it will not be called to run (given a gas price spike), it will be required to buy from ESBPG at top-up prices that reflect day ahead gas prices to meet its contracted obligations. In addition, if ESBPG is forced to sell greater amounts of top-up, it will do so at a price that will be closer to the price at which it may need to buy gas in the spot market. Within-day gas spike rises could still provide the potential for arbitrage as the rule change proposed for ESBPG‟s INC/DEC bids will not solve that problem. However, overall, the changes should provide a more accurate economic signal to the market.

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The gas bids will be referenced to a published, known index and will, therefore remain transparent. The Commission hereby directs that the gas price is determined by the daily quote of the „Heren Day-Ahead Index‟ as published in ESGM Reports [Stg. p/th]1.
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NBP+1 Heren Daily Indices

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The following table illustrates which prices will be applied in a typical week (with no bank holidays in the UK or Ireland). Electricity Nominations made on Monday Tuesday Wednesday Thursday Friday (for Weekend & Monday) Use Gas “Day Ahead” Price of (Publication Day) Friday Monday Tuesday Wednesday Thursday

In the case of bank holidays, the most recently published quotation available at the time of nomination will be applied. Implementation of the Decision The Commission decision on ESB PG bidding will apply from 1 st January 2006 and will be reviewed after six months.

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