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TNT Board Update

This update provides an overview of the current status of the Texas Nodal Team's market design and the economist issues that have been addressed. It also discusses upcoming decision points, cost-benefit considerations, and what comes next in the process.

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TNT Board Update

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  1. TNT Board Update Jim Galvin Facilitator, Texas Nodal Team February 16, 2005

  2. Agenda • Where are we today • Economists impact on design • Decision points to come • Cost Benefit discussion • What comes next?

  3. Where are we today? • Key Issues from Commission Order: • Stakeholder Process • Ensure Bilateral Markets are retained or enhanced • Ensure Reliability is retained or enhanced • Unit and Other Resource Specific pricing; No Portfolio pricing • Direct Assignment of ALL congestion rents • Congestion Revenue Rights for congestion hedging • Day Ahead Energy Market • Market Mitigation • Independent Cost/Benefit Analysis

  4. Where are we today? • Key elements of the Market Design • Resource Specific bidding with Locational Marginal Pricing • Aggregation of Load nodes to Load Zone • Reliability Unit Commitment • Direct Assignment of ALL Congestion Rents • CRRs for Congestion Hedging (options, obligations and Flow-gates) • Integrated Day Ahead Energy Market • Ex-ante Market Mitigation

  5. Where are we today? • Protocols • Multi-round review of each Protocol section impacted by the Market Design • Comment period for stakeholders to provide input and recommendations on each round of review • Decision points taken to the TNT General Sessions for resolution • Protocol filing with the PUCT scheduled for March 18, 2005

  6. Economist Issues History • On November 8, we decided to adopt: • Addition of Co-Optimization of AS and energy in the Day-Ahead Energy Market (DAEM) • Change in the Reliability Unit Commitment (RUC) allocation multiplier • Creation of a demand curve for a small quantity of Responsive Reserve Service • On November 15, we decided to: • Request ROS’s review of Section 6.8.2 Uninstructed Resource Parameters • Adopted an Integrated Day Ahead Energy Market model • Adopt fully funded CRRs, with offer floors, CRRs not sold on radial lines with resource on either end • Adopt alternate settlement for CRR Options • Adopt allocation of CRR Auction Revenues to Loads

  7. Economist Issues • On January 12, we reviewed the remaining economist issues and felt the following issues were addressed by elements of our current market design: • No changes in CRR ownership reporting rules or limits are required • No changes are needed to address Wolak’s cross-subsidy concerns because of the uplifts that would be required to implement • No additional mitigation measures are needed to address physical withholding • No additional requirements of the IMM are needed to restrict virtual trades • No mitigation of Ancillary Services is needed • On February 4, we decided to adopt: • Output Schedule updates up to SCED execution will be limited to Dynamically-Scheduled Resources only. Non–Dynamically Scheduled Resources with Output Schedules may not change them after the close of the Adjustment Period. • Further study of Real-Time Co-Optimization of AS and energy, recognizing Protocol language will not be available prior to the March 18 filing • Changes adopted will be incorporated in the Round 2 Protocol review process.

  8. Economists Issues • We decided not to adopt: • A must-offer in DAEM • ERCOT “pre-commitment” of units in DAEM that it deems required for the following operating day • Any zonal allocation of RUC costs • Allocation of Congestion Revenue Rights to Loads

  9. Economists Issues- Major Impacts • Integrated Day Ahead Energy Market • Day Ahead Energy Market will commence at market open • Most CRRs will be settled in the Day Ahead using SCUC and SCED • NOIEs can take CRRs to real time up to 110% of next day’s peak load • Ancillary Services and Energy Co-optimized • <New Item> Credit Requirements for DAEM

  10. Economists Issues- Major Impacts • Congestion Revenue Rights • CRR mitigation with Offer Floors • No deration of CRRs (Fully Funded, uplift shortfalls pro-rata to CRR holders) • CRR Auction Revenues allocated zonally with CRRs involving source and sink in the same zone, ERCOT wide for all others • <New Item> Credit requirements for Obligations

  11. Decision Points to Come • Co-optimization of Energy and AS in real-time • Concerns expressed with the ability to implement the deployment of a small quantity of Responsive Reserve in SCED to avoid Hockey-Stick bidding • Changing of output schedules up to Real-time (Resolved Feb 4 General Session)

  12. Cost Benefit Study • Posted comprehensive final report November 30 • Filed with the PUCT December 2004 • Approved unanimously by TNT with the following: • TNT neither approves or disapproves the results • Each TNT member reserves the right to take any position on the study

  13. Cost Benefit StudyHistory • TNT formed the Cost-Benefit Concept Group (CBCG) to guide the Cost-Benefit Study effort, selecting through a competitive RFP process TCA/KEMA • The study was conducted throughout 2004 under the direction of the CBCG and TNT Facilitation Team • The CBCG reviewed critical assumptions and provided feedback throughout the study process • ERCOT staff provided input on matters related to the existing market design, current systems, and impacts experienced with the current market design

  14. Cost Benefit Study Elements The study consisted of four elements: • Energy Impact Assessment (EIA)—quantified impacts to the energy market, system dispatch, and energy prices • Backcast—quantified optimized generation dispatch comparing 2003 dispatch results • Implementation Impact Assessment (IIA)—provided quantitative and qualitative treatment of implementation startup costs, ongoing costs, and other impacts for ERCOT and its market participants • Other Market Impact Assessment (OMIA)—provided qualitative treatment of a variety of other measures of impact of market designs not captured directly in the EIA

  15. Cost Benefit Study EIA Findings • EIA indicates for the Nodal Change Case an average annual savings of $76 M per year ($565 M 10-year net present value) in reduced generation costs • EIA indicates measurements of a shift in value from generator segment to load segment

  16. Cost Benefit Study IIA Findings • Estimated Total Cost range summing all segments and ERCOT of $108M to $156M for the nodal change case • ERCOT costs estimated at $55M to $71M • Replication Change Case demonstrates a cost to ERCOT of $53M to $67M, to Market • Nodal Light Case $52M to $66M

  17. Cost Benefit Study IIA Findings • Why are the differences in the Change Cases minimal? • Likely, there is no change in hardware needs in each Change Case • Commercial Systems cannot be replicated from other markets based on our aggregation of load and retail market • Even a replication would need specialization • Important to note that quantifying the reduced risk of a replicated system is hard to do, but worth consideration

  18. Cost Benefit Study OMIA Findings • Important notes from the OMIA: • Increased complexities • Shift of risk from Load to TCR holders • Unexpected market outcomes • Better information for the System Operator • More transparency • Better Market Oversight

  19. Cost Benefit Study Back CastFindings • Dispatch patterns between actual 2003 and simulated 2003 did not differ significantly • Combined Cycle resources appeared to generate more in simulation and Gas Fired plants less. • Resulting change indicated savings of $1 Billion in the simulated vs. actual

  20. Cost Benefit Study Conclusion • Quantitative results indicate savings in generation costs • Quantitative benefits indicate benefit when compared to implementation costs • Qualitative analysis demonstrate positive and negative aspects of change • Many of the qualitative aspects appear to impact the smaller players more so than the larger ones

  21. What is next?-Protocols • Protocols for the Nodal Change Case are near completion of more than 2 full rounds of revisions • Protocols outline the Market Design elements and theories • Settlement algorithms will undergo further analysis and market training after Protocols are filed • Protocols targeted to be filed by March 18

  22. What is next?-Protocols • Board will be asked to approve for filing to the PUCT the draft TNT Protocols • Protocols are a product of the stakeholder review and input that address the design elements for the Nodal Market that will meet the elements of PUCT Order

  23. What is next?-Protocols Draft Motion for March Board Meeting for Board review and comment: WHEREAS, the Public Utility Commission of Texas has directed ERCOT to use a stakeholder process to develop a wholesale market design that complies with the market elements set forth by Commission Rule (PUCT Subst. R. 25.501) and to prepare an independent cost benefit analysis of such design and alternatives (such analysis was provided to the Commission in December of 2004);   WHEREAS, ERCOT has sponsored a stakeholder process (Texas Nodal Team - TNT) in compliance with the Commission's rule, providing independent facilitation to participating stakeholders; WHEREAS, the Texas Nodal Team has reached consensus of the stakeholder participants on a market design and draft Protocols in compliance with the Commission's rule; WHEREAS, ERCOT is required to file with the Commission draft Protocols that would support the TNT-developed market design by March 18, 2005; NOW THEREFORE BE IT RESOLVED, that the Board directs ERCOT Staff to file the draft Protocols developed by the TNT process in compliance with the Commission's rule. By this action, the Board makes no endorsement of the final TNT market design or draft Protocols, or other alternatives for market design that the Commission may consider.

  24. What is next?-Implementation Plan • While Protocols are commented on at the PUCT, ERCOT can create an implementation plan to focus on the following: • Project timeline • Development of RFP(s) • In-depth current system analyses • Training preparation • Simulation and studies (i.e. Competitive Test, CRR simulations)

  25. What is next?-Implementation Plan • Implementation plan will allow for general pre-project tasks (RFPs, Vendor evaluations etc.) to take place while PUCT reviews filed protocols • Implementation Plan will provide budget forecast for TNT implementation • Implementation Plan will include stakeholders to ensure a smooth transition into TNT implementation

  26. Questions

  27. 1,000 MW 800 MW 200 MW A B A B $30 $15 $30 $15 333 1/3 MW 200 MW $30/MWh $15/MWh 333 1/3 MW 400 MW 600 MW 666 2/3 MW 600 MW Limit 600 MW Limit $60 $45/MWh C C Load = 1,000 MW Load = 1,000 MW Thermal Limit on B-C Exceeded System Re-dispatched to Respect Thermal Limit Dollar figures are the generator energy bids at each bus.

  28. Energy Settlement • 800 MW * $15/MW = $12,000 (paid) • 200 MW * $30/MW = $ 6,000 (paid) • 1000 MW * $45/MW = $45,000 (charged) • Congestion Rent = $45,000 – ($12,000 + $6,000) = $27,000

  29. Re-dispatch Costs • Generation costs (ignoring limits) = 1000 MW * $15/MW = $15,000 • Generation costs (respecting limits) = (800 MW * $15/MW) + (200 MW * $30/MW) = $18,000 • Re-dispatch costs = 200 MW * ($30/MW - $15/MW) = $3,000

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