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Evaluation of Historical EECP and Alert Pricing

Evaluation of Historical EECP and Alert Pricing. True North Associates. Perspective. Enhance System Security Mitigate Total Cost Increases to the Greatest Possible Extent Appropriate and Equitable Sharing of Risk. Issues With Proposed Compromise Solution.

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Evaluation of Historical EECP and Alert Pricing

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  1. Evaluation of HistoricalEECP and Alert Pricing True North Associates

  2. Perspective • Enhance System Security • Mitigate Total Cost Increases to the Greatest Possible Extent • Appropriate and Equitable Sharing of Risk

  3. Issues With Proposed Compromise Solution • Administratively set Alert and EECP Pricing Floors extending up to Market Maximum Clearing Price (HCAP) • Impacts on Service Cost • Ability to offer a true ‘Long-Term Solution” within the context of risk management decisions affecting capital investment

  4. Approach Examine BES database and select representative Events between Jan and May 31, 2007 including both Alert and EECP intervals Consideration of Events in 2006 deferred due to presence of discontinued NE CMZ Identify characteristic Market MCPE and MW conditions during Events Determine change in Event costs during Alert and EECP intervals Examination of Five (5) Events shows a loose Correlation between MCPE and MW deployed, with MCPE values roughly between $50 and $100/MWh and UBES ranging up to 3,000 MW. Higher MCPE values are occurring more frequently in recent Events.

  5. Converting Energy To Revenue • Events identified in Paul Wattles’ spreadsheet • Procedures and archival data contained in ERCOT BES Spreadsheets • Total BES Cost based on net resource deployment considering N, S, W, and Houston zones • BES Costs calculated at each interval as: MW i * 0.25 Hour/Interval * MCPE, $/MWh i or $Compromise Plan/MWh • Compromise Plan pricing logic utilized in computing revised total cost • Stages 1 and 2 EECP compromise prices blended 80%/20% • Stage 3 EECP not considered

  6. Affected Intervals

  7. Intervals Considered

  8. Representative Event 3/5/2007 MECP UBES & DBES MW Net MW Cost @ MECP Compromise Cost Stage 2 Alert Stage 3 EECP Intervals Stage 1 Advisory

  9. BES History 3/5/2007

  10. MCPE vs. Compromise Pricing Price Increased Because $MCPE>$Compromise Plan

  11. Change In Revenue MCPE vs. Compromise Pricing

  12. Representative Event 3/7/2007

  13. BES History 3/7/2007

  14. MCPE vs. Compromise Pricing

  15. Change In Revenue MCPE vs. Compromise Pricing

  16. Representative Event 3/8/2007

  17. BES History 3/8/2007

  18. MCPE vs. Compromise Pricing

  19. Change In Revenue MCPE vs. Compromise Pricing

  20. Representative Event 4/3/2007

  21. BES History 4/3/2007

  22. Representative Event 5/7/2007

  23. BES History 5/7/2007

  24. MCPE vs. Compromise Pricing Price Increased Because $MCPE>$Compromise Plan

  25. Change In Revenue MCPE vs. Compromise Pricing

  26. Impact On Alert And EECP Net Costs

  27. Impact On Net EECP Costs

  28. Impact On Average $/MWh Prices

  29. Observations - 1 • BES has been and is being successfully provided based on MCPE pricing • The MCPE engine is presently finding price solutions in and above the range proposed in the Compromise Solution • The proposed ‘Compromise Solution’ increases the cost of BES significantly • The increase will double over the next 2 years, per PUC SR25.605(g) as HCAP increases to $3,000/MWh • The number of Alert and EECP Intervals and their levels of UBES are relatively small and will decrease as new resources are added • The magnitude and distribution of revenues is uncertain under present and future competition

  30. Revenue Still At Cyclical Risk Effect of Adding Capacity “Too Much Reliability” Bust Boom • Magnitude and Duration: Increasing prices is one way to address the problem of ‘Missing Money,’ but higher prices alone will not stabilize revenue or provide the long-term security that large capital investments typically require

  31. Observations - 2 • The Proposed Solution offers neither ERCOT nor Consumers any assurance that needed or desired new resources will be deployed in return for the higher costs it carries • No Contract Structure or Performance Obligations • No Resource Segmentation or Exclusion for Existing Generation Units • No Mitigation Plan Addressing Increased Potential for Collusion or Exercise of Market Power

  32. Elements Of A Long-Term Solution • Develop a balanced approach to satisfy competing interests as cheaply as possible: • Establish regularly updated RA capacity target to ensure reliability • Ensure spot prices (MCPE) are adequate to address issue of missing money and ensure adequate investment • Establish multi-year forward-capacity contracting mechanism for new investments (generation and EILS) to provide greater price stability/ revenue predictability and reduce investor risk • Establish performance-based incentives and penalties • Tie forward contracts to physical assets rather than volatile prices • Require load-following hedges/call options to protect load from high spot prices and mitigate potential exercise of Market Power The Convergence of Market Designs for Adequate Generating Capacity Cramton and Stoft, 2006

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