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Future Market Implementation Requirements - way forward

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  1. Future Market ImplementationRequirements - way forward MWG – April 21st, 2009 - Decision Session #3

  2. Requirements Gathering Process Review MISO BPMs Pull decision points Research RTOs Info Session #1 Info Session #2 Info Session #3 MWG Decision Session Review Protocol Language from previous Decisions

  3. Process • Second Design Session • Review each of the decision points from Information Sessions • Dialogue • Decide which RTO designs best fits the SPP footprint • Staff will then develop protocol language for next MWG Face to Face

  4. Topic Schedule March 30th Canceled due to CHTF April 6th Modeling Pseudo ties and JOU Virtuals Demand Response April 13th BA Functions April 27th Resource Adequacy May 4th Emergency Condition Load Forecast May 11th Settlements I May 26th Settlements II June 1st Reserve Sharing June 8th Credit June 22nd Market to Market June 29th Formulations July 6 Losses July 13th Technical Business Continuity Other Feb 2nd Market Structure Product to be Offered Resources Feb 9th Registration Resource Qualification Market Timeline Feb 23rd Market Functions I March 2nd Market Functions II March 9th Energy Transactions March 23rd Make Whole Payments Market Mitigation

  5. Risk Matrix Why is it important to strive to use of existing designs with limited changes. Challenges in evaluating unknown risks Also need to weigh in changes from current process

  6. Start with an update to the Finsched • Corrected examples that were presented in last Decision Session

  7. Financial Schedule - Reminder • Fischeds shift finacial responsibility for scheduled MWh from buyer to Seller at the specific Source / Sink • Buyer pays congestion where source differs from sink • Day-Ahead or Real-Time Pricing • Internal to RTO portion of the schedule only – does not impact interchange

  8. Finsched Example #1 – Schedule without finsched • Sale of energy from MP#1 to MP#2 internal to the RTO • MP #1 through bilatteral agreement makes a sale of 100MW at $30 to MP #2 • Enter Schedule into Schedule system • How is this settled by the RTO

  9. Finsched Example #1 – Schedule without finsched MP #2 Buys 100MW at $30 Bilaterally MP #1 Sells 100MW at $30 Bilaterally Scheduled in RTO_SS $40 LMP $45 LMP

  10. Finsched Example #1 – Schedule without finsched MP #2 Buys 100MW at $30 Bilaterally MP #1 Sells 100MW at $30 Bilaterally Scheduled in RTO_SS $40 LMP $45 LMP • MP #1 (Seller) charged 100MW * $45 = $4500 for withdrawal • MP #1 (Seller) credited for 100MW * $40 = $4000 for injection • MP #1 and #2 settle price for Bilateral transaction 100MW * $30 = $3000 outside of market • MP #1 could either generate with resource or buy from Market

  11. Finsched Example #2 – Add Financial Schedule • Seleler wants to Buyer to get charged the congestion cost ($45-$40) * 100MW = $500 • Enter a finsched to do this. Both parties need to accept the finsched contract after entered into RTO system • On settlement statement MP #1 would be credited $500 and MP #2 would have $500 charge

  12. Finsched Example #3 – Real World Example • MP #1 schedules power from external source to MP #2’s internal load

  13. Finsched Example #3 – Real World Example SPP Scheduled in RTO_SS $45 LMP MP #2 Buys 100MW at $30 Financial Schedule Financial Schedule Hub $45 LMP $50 LMP

  14. Finsched Example #3 – Real World Example • MP #1 (Seller) charged 100MW * $45 = $4500 for withdrawal at border • MP #1 (Seller) credited for 100MW * $50 = $5000 for injection at Hub • MP #2 (buyer) charged 100MW * $50 = $5000 for withdrawal at Hub • MP #2 (buyer) credited 100MW * $45 = $4500 • MP #1 and #2 settle price for Bilateral transaction 100MW * $30 = $3000 outside of market

  15. Alternative Fin Sched • Define Delivery Point only

  16. March 23rd • Make Whole Payments • Market Mitigation • Real Time Mitigation • Day Ahead Mitigation • Make Whole Payment Mitigation

  17. March 23rd • Make Whole Payments • Market Mitigation • Real Time Mitigation • Day Ahead Mitigation • Make Whole Payment Mitigation

  18. Correction from MWP presentation • It was stated that the DA MWP was calculated on the net between DA and RT revenue. That is not correct. • The markets are separate DA has a MWP and RT has a MWP

  19. Day-Ahead Revenue Sufficiency Guarantee Make Whole Payment Resources that are committed by the RTO in the Day-Ahead market are guaranteed recovery of their Start-Up, No-Load, Energy and Operating Reserve Offers On an hourly basis, the market system determines whether a Resource has met the eligibility requirements to have their production Offer and Operating Reserve Offer guaranteed.

  20. Day-Ahead Revenue Sufficiency Guarantee Make Whole Payment Eligibility • Not change offer from DA case when picked up (All Components of Offer – would include current resource plan at SPP) • Not self committed

  21. Real-Time Revenue Sufficiency Guarantee Eligibility • The Resource must offer flexibly for the Hour • Dispatchable range greater than 1MW • The as-committed (DA or RUC) Offers must remain unchanged when submitted as Real-Time Offers • Ramp greater than .5MW per minute • All ramp rates used in the Real-Time Energy and Operating Reserve Market within the Dispatch Interval must be greater than one-half of one percent (0.5%) of the real-time Hourly Economic Maximum Limit of the Generation Resource per minute.” • Follows dispatch instructions (no Uninstructed Deviation in the hour • Committed by RTO

  22. March 23rd • Make Whole Payments • Market Mitigation • Real Time Mitigation • Day Ahead Mitigation • Make Whole Payment Mitigation

  23. March 23rd • Make Whole Payments • Market Mitigation • Real Time Mitigation • Day Ahead Mitigation • Make Whole Payment Mitigation

  24. Market Mitigation • Review Mitigation methodologies but are going to ask Market Monitoring to com back to MWG with recommendation. • Initial Recommendation in July time frame • Final in the September time frame taking into consideration CHTF conclusions

  25. Mitigation

  26. SPP Market Monitoring Thoughts • Investigate if current methodology can be extended • Consider DA impacts • Consider Ancillary Service Capacity and opportunity costs • Review and study difference between • Impact and Conduct Test • 3 Pivotal Supplier • Current SPP Methodology

  27. March 23rd • Make Whole Payments • Market Mitigation • Real Time Mitigation • Day Ahead Mitigation • Make Whole Payment Mitigation

  28. Decision session talking points • Make Whole payment • Market Monitoring will investigate and come back to MWG with recommendation on the monitoring and capping methodology. They plan to take into consideration any congestion hedging decision

  29. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  30. Modeling • Do we use the Future Markets project to revamp the modeling process? • What are the goals – how much would we be willing to spend to make it better

  31. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  32. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  33. MISO Commercial Model • Market Participant (MP) – Financially responsible party • Asset Owner (AO) – Usually a company (but not necessarily). Settlement statements are netted at this level • Commercial Pricing Node (CPnode) – Energy is settled at this level. A CPnode can be either a EPode or a APnode. Types of CPnodes include: • Load Zone • Resource • Load Hub • Interface • Elemental Pricing Node (EPnode) – Bus level • Aggregated Pricing Node (APNode) – Two or more EPnodes aggregated together using predetermined weighting factors Portal Security and roles is assigned at the AO Level

  34. SPP JOU Registrations In the SPP EIS Market there are two options for handling the registration of Joint Owned Units (JOU’s). • Owners of a JOU may agree to register the unit on their own as separate Resource settlement locations. • One owner can take responsibility for registering the unit’s settlement location. Each owner will be able to submit offers for the unit in to the SPP EIS market. The registration of an ownership share as a separate Settlement Location results in the JOU being treated as any other Resource, meeting the requirements for Resource Plans, Ancillary Service Plans, Scheduling, and metering. For JOUs, there can only be one designated Meter Agent. Each Market Participant must designate the same Meter Agent. If only one owner registers the entire unit, that owner will be the only party allowed to submit offers for that Resource, and is responsible for all the requirements associated with a Resource, and will be solely financially responsible for EIS charges.

  35. Issues with Pseudo Tie Methodology • If the SCUC commits portions totaling less than economic minimum, what should happen?

  36. MISO - Combined Cycle CTs A Combined Cycle CT is normally offered as a single (aggregate) unit; however, the component CTs and/or steam turbine (ST) with an alternate steam or thermal source may be offered as separate. When the Combined Cycle CT is offered as a single aggregate unit, it will be associated with a single aggregated CPNode. The LMP for this aggregated CPNode is calculated as the weighted average of the LMPs of the individual unit EPNodes. In the Day-Ahead Market, a Combined Cycle CT’s aggregate Resource Offer consists of the same information required for any Generation Resource. If an aggregate Offer for a Combined Cycle CT does not exist, individual CT or ST Offers are used. If the Combined Cycle Resource was not committed in the Day-Ahead Energy and Operating Reserve Market or any RUC process, the MP may elect to change its Offer from aggregate to single unit or vice versa. However, once the Resource is committed, no further changes in modeling are allowed for that Operating Day.

  37. SPP – Combined Cycle CT • No special handling at this time • Registered as single unit at Aggregate Pnode • If running steam side only, still priced at combined bus

  38. MISO – Cross Compound Resource A Cross Compound Resource consists of a high-pressure turbine/Generator and a low-pressure turbine/Generator connected to separate electrical Nodes in the Network Model. The Cross Compound Resource will have an EPNode and corresponding CPNode for each Generator and if desired, a third CPNode will be defined representing the aggregate of the two. Since the two Generators usually must operate in a coordinated fashion, a single Resource Offer must be submitted to represent the combined output of the two Generators.

  39. Commercial and Network Model

  40. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  41. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  42. Reserve Zones In and earlier Information and Decision sessions we have already placed our stick in the mud on this topic: • We will have zones defined with Network model based on likely transmission constraints (not likely to be existing BA boundaries) • Definition of the calculation methodology for zonal A/S requirements and boundary creation will be a task for CBA and ORWG

  43. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  44. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  45. Hubs Similar recollection on Hubs • We will require the market software to support one or more hubs • We will define at least one hub for trading purposes in the future markets. • MWG said that we would define the number and location of actual hubs at a future meeting

  46. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  47. April 6th • Commercial and Physical Modeling • JOUs and Combined Cycles • Reserve Zone definition and requirements • Hub definition • Virtuals • Supply, Demand • Who can participate • Demand Response • What flavors supported • FERC Order 719 compliance

  48. What is a Virtual Transaction • Submission of bids to buy or offers to sell, either Load or supply, for the FINANCIAL purchase or sale of energy in the DA market. • STRICTLY FINANCIAL TRANSACTIONS • Can be in addition to physical purchases or delivery of energy. • Does not compromise physical commitment of energy Resources for system reliability.

  49. Virtual Transactions can…… • Provide an additional hedging mechanism for MP’s with physical Load and Generation. • Provides opportunity to other “Participants” to: • Increase market stabilization • Even without “actually” owning physical Load or Generation. • Physical energy is neither supplied nor consumed. • NO effect on RT physical energy consumption or physical commitment of Generation. • Assists in bringing Price Convergence between DA and RT markets.