1. Incentive Based Regulation for SO Costs Andrew Mcintosh European Policy Manager Florence School of Regulation Workshop Improving and Extending Incentive-based Regulation in the Energy Sector Florence, 24 November 2006

2. The National Grid Group Transmission Gas Distribution Bus. Dev. & Non Regulated Elec Gas Elec. Dist Finance & Shared Services Elec Metering Gas Grain LNG Property UK US Gas Global Lines – of - Business Approach Elec. Distribution & Generation* US Gen* * Following completion of KeySpan Acquisition Gas UK US UK US Wireless Advantica Wireless HR, IS, Finance, & Proc. Group Functions: HR, IS, Finance, Audit, Public Affairs, Investor Relations, Secretariat & General Council HR, IS, Finance, & Proc.

3. National Grid Electricity Transmission System - England and Wales  Operating voltages 400kV and 275kV  13,786 km OHL; 627 km of underground cable  Approx 330 substations  Maximum demand 54,400 MW  Units transmitted 309 TWh  84 major plants connected

4. Great Britain System Operator Scottish Power National Grid National Grid: GB System Operator Scottish Hydro Electric Transmission Transmission Owners

5. National Grid’s UK regulatory framework Electricity Act Grid Code / BSC / CUSC/SQSS/STC Electricity Transmission Licence National Grid Electricity Transmission Utilities Act Competition Act (OFT) Electricity Safety, Quality & Continuity Regulations Energy Act

6. TO/SO Revenues Transmission System Transmission System Operation System Operation TNUoS charges BSUoS charges Balancing Costs Internal SO Costs CapEx OpEx R.O.R. TO (RPI - X) SO (cost +/- inc) Total recovery set at price control Total recovery reflects costs SO charges recover the actual costs incurred (+/- incentive payment) TO Charges recover a fixed amount of allowed revenue

7.  The average domestic bill is made up of the following components: Balancing Costs in Context Source - Ofgem Approx. split: 75% - TO 25% - SO

8. Internal SO Costs Internal costs comprise:  Incentivised Internal Costs  SO Capex  SO Opex - e.g. staff, IT systems  Non-incentivised Internal Costs  return on RAB (aligned to the TO price control)  Business Rates

9. Incentivised Balancing Costs (IBC) IBC = (CSOBM - NIA) + BSCC + TLA Costs of Bids and Offers in BM Constraints resolution Energy balancing Balancing Services Contract Costs Reactive power Standing and Fast Reserve Warming Frequency Response etc Net Imbalance Adjustment SO is partially exposed to market participant imbalance volume Transmission Losses Adjustment Term related to the cost of energy losses on the system

10. SO Incentive Mechanism National Grid Electricity Transmission 2005/6 SO Incentive Scheme  Outturn below Target SO shares Profit (40% sharing Factor)  Outturn above Target SO shares Loss (20% sharing Factor)  Cap to limit SO profit  Collar to limit SO Loss Cap Collar 40% 20% Rolling ex-post reconciliation in 3 Stages Initial Settlement (SF) End of Scheme Reconciliation Final Reconciliation (RF) Ex-anti Target Cost: Set for the period of the scheme

11. Historic Performance Against SO Incentive Schemes (£m outturn) introduction of incentive scheme NETA BETTA

12. What Happened in the 2005/6 Scheme  A rising trend in balancing costs was apparent in the UK market toward the end of the 2004/5 scheme. Driven by increasing wholesale market volatility.  The ex-anti target set for 2005/6 did not fully anticipate the following:  The extent to which wholesale energy (Gas & Elec) prices would rise during the incentive period. Leading to..  A significant rise in the cost of Balancing Services contracts  High BM Bid and Offer volatility increasing the average cost of residual balancing  The effect of the introduction of BETTA exposing the SO to increased constraint management costs for the Scottish system.  Subsequently the final IBC significantly exceeded Target Cost and the SO (for the first time) absorbed a financial loss on balancing operations.

13. The 2006/7 Scheme  National Grid and Ofgem failed to agree an Electricity SO Incentive Scheme for the 2006/7 (current) year. The reasons for this where as follows:  Agreement could not be reached on the ex-anti Target Cost applicable for the scheme.  A wide gap was apparent in the ex-anti IBC estimates of both parties  There remained a high degree of uncertainty in the wholesale markets  Discussions around achieving greater flexibility in the way scheme was operated/adjusted for externalities could not be concluded in time.  National Grid was not in position to expose its shareholders to an unacceptable risk of financial loss in System Operations  All SO costs are “passed through” conventionally to the market participants this year.

14. Conclusions  National Grid remains strongly supportive of SO incentive mechanisms as the most effective driver of efficient and cost effective system operation.  Extended experience in the UK has proven that significant savings can be achieved for consumers year on year.  Ex-anti setting of Target Costs, whilst an essential driver, can introduce significant (and potentially unreasonable) financial risk for an SO when forward market conditions are uncertain.  A balance needs to be achieved between the need for a robust financial target and the ability adjust for unforeseen and unmanageable external influences over balancing costs.  Scheme design could potentially be improved through the introduction of appropriate ex-post indexation mechanisms combined with an effective and pre-defined target cost adjustment process.

15. Incentive Based Regulation for SO Costs THANKYOU FOR YOUR ATTENTION