1 / 43

Long-Term Resource Adequacy Update: Identified Paths and Next Steps

This update provides a chronology of the Long-Term Resource Adequacy (LTRA) project and outlines the identified paths to address resource adequacy in Ontario's electricity market. The update also highlights the ongoing discussions and next steps of the LTRA Working Group.

stacya
Télécharger la présentation

Long-Term Resource Adequacy Update: Identified Paths and Next Steps

An Image/Link below is provided (as is) to download presentation Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author. Content is provided to you AS IS for your information and personal use only. Download presentation by click this link. While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server. During download, if you can't get a presentation, the file might be deleted by the publisher.

E N D

Presentation Transcript

  1. IMO Day Ahead Market Design Update Market Operations Standing Committee September 22, 2003 Market Evolution Program Long-Term Resource Adequacy Update Jason Chee-Aloy Marjket Operations Standing Committee

  2. Long-Term Resource Adequacy Update Agenda • Long-Term Resource Adequacy Chronology • Identified Paths and Long-Term Resource Adequacy Working Group Update • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 2

  3. Long-Term Resource Adequacy (LTRA) - Chronology • Summer 2002 - Market Participants identified resource adequacy as a high priority issue in response to the IMO Straw-Plan for Market Evolution • Fall 2002 - IMO 2003-2005 Business Plan states resource adequacy as a principle objective in the evolution of Ontario’s electricity market • February 2003 - work commences on the LTRA project • March 2003 - first meeting of the LTRA Working Group (LTRAWG) • Over 25 members (w/ diverse membership) • LTRAWG meets every 2 weeks • June 2003 - Feasibility Assessment published • Identifies Paths/Options to address LTRA • Contains several recommendations but does not champion a single Path/Option • June 2003 - Market Advisory Council supported Feasibility Assesssment recommendations • July 2003 to Present - LTRAWG continuing discussion on specific recommendations to address LTRA Market Operations Standing Committee of the IMO September 22, 2003 Slide 3

  4. Long-Term Resource Adequacy Update Agenda • Long-Term Resource Adequacy Chronology • Identified Paths and Long-Term Resource Adequacy Working Group Update • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 4

  5. Potential Paths to Address Long-Term Resource Adequacy • Path A: Complete the initial market design and structures without an explicit Resource Adequacy Requirement (RAR) • Rely on results of improved energy and ancillary service markets alone (e.g. Pricing Team work, day-ahead market, multi-interval optimization, etc.) • Path B: Create Load Serving Entities (LSE) and assign a RAR to these entities • LSEs required to contract forward capacity requirements through bilateral contracts (different to bilateral contracts for energy) • IMO could administer a resource adequacy auction market (similar to NYISO and PJM) as a complementary element to LSE capacity contracts • Path C: Allow a central agency to procure adequate resources and allocate the resource acquisition costs to loads • IMO administers a resource adequacy auction market and secures forward capacity on behalf of loads (NYISO, PJM and ISO NE are developing) Market Operations Standing Committee of the IMO September 22, 2003 Slide 5

  6. Long-Term Resource Adequacy Working Group Update • Key points from the current discussion: • LTRA encompasses all interrelated aspects of the Ontario electricity market • Recommendations will contain necessary elements that will help Ontario move toward a complete, workable and sustainable approach to addressing LTRA, under a competitive market framework • Elements of the identified Paths (from the Feasibility Assessment) are likely not mutually exclusive • LTRAWG is now focussing on: • The high level detail how an explicit resource adequacy requirement may be workable • Interim/transitional mechanisms that may be required Market Operations Standing Committee of the IMO September 22, 2003 Slide 6

  7. Long-Term Resource Adequacy Update Agenda • Long-Term Resource Adequacy Chronology • Long-Term Resource Adequacy Working Group Update • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 7

  8. Next Steps • LTRAWG continues to meet every 2 weeks • Update to IMO Board on LTRAWG on October 3, 2003 • Update to Market Advisory Council on October 8, 2003 Market Operations Standing Committee of the IMO September 22, 2003 Slide 8

  9. IMO Day Ahead Market Design Update Market Operations Standing Committee September 22, 2003 Market Evolution Program Day Ahead Market Update Leonard Kula Marjket Operations Standing Committee

  10. Day Ahead Market Design Update Agenda • DAM Chronology • DAM Design and Features • DAM Pricing Options • DAM Benefits • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 10

  11. Day Ahead Market (DAM) - Chronology • Fall 2002 - IMO 2003-2005 Business Plan identifies that a DAM is a critical element in creating a more effective, reliable and mature market • January 2003 - work commences on the DAM project • February 2003 - call for DAM Working Group (DAMWG) members • ~ 28 members from all industry sectors (generators, loads, transmitter, distributors, marketers, OEB and OEFC) • meet every ~10 days - 23 meetings to-date • April 2003 - DAMWG recommends further development of a comprehensive DAM • closely aligned with day ahead markets in neighbouring jurisdictions • May 2003 - DAM hi-level design summary prepared • June 2003 - broad stakeholder consensus obtained regarding design direction and plan to continue to develop DAM (Market Advisory Council) • July - Aug 2003 - DAMWG discusses hi-level design concepts and reviews hi-level design strawman Market Operations Standing Committee of the IMO September 22, 2003 Slide 11

  12. Day Ahead Market Design Update Agenda • DAM Chronology • DAM Design and Features • DAM Pricing Options • DAM Benefits • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 12

  13. Day Ahead Market - Initial Options Day Ahead Market (DAM) Evolution Market Operations Standing Committee of the IMO September 22, 2003 Slide 13

  14. Day Ahead Market - Initial Options Day Ahead Market (DAM) Evolution Market Operations Standing Committee of the IMO September 22, 2003 Slide 14

  15. Day Ahead Market - Initial Options Day Ahead Market (DAM) Evolution Market Operations Standing Committee of the IMO September 22, 2003 Slide 15

  16. What Is Meant By A Comprehensive Day-ahead Market? • The DAM WG recommended further development of a Comprehensive DAM (April 2003). • Key features include: • A financial market administered by the IMO, which accepts supply offers and demand bids and clears the market at day-ahead prices. • Creates a 2-settlement system, with the RTM a “balancing” market. • Integrates a 3-part bid process to optimize unit commitment for: • Supplies available to the DAM to meet loads buying in the DAM • Supplies available to the RTM to meet RTM forecast load • A multi-pass process for committing units, arranging DAM schedules, and defining DAM prices, plus indicative schedules for the RTM. • The use of uplifts to cover commitment costs not recovered from market revenues. • The simultaneous optimization of energy and operating reserves, and the optimization of the market over the 24 hour period. Market Operations Standing Committee of the IMO September 22, 2003 Slide 16

  17. DAM - Design And Features • The Proposed DAM would: • Be based on... • supply offers to sell and demand bids to purchase energy • supply offers to sell operating reserves • Be open to all MPs • Include imports and exports • Allow virtual offers and bids • Include an IMO-optimized unit commitment process • Use multiple commitment and/or dispatch passes to optimize results Market Operations Standing Committee of the IMO September 22, 2003 Slide 17

  18. A DAM Functions Before The RTM In A Two-Settlement System Real Time Market Day Ahead Market MPs offer to sell and bid to buy energy in real time. Offers/bids used to define RT schedules and prices IMO uses offers/bids to arrange constrained dispatch 2nd Settlement = Quantity Deviations from DA purchases and sales times RT prices PRT(QRT - QDA) MPs offer to sell and bid to buy energy day ahead. Offers/bids used to define DA schedules and prices DA schedules are financial obligations to buy/sell energy at DA prices 1st Settlement = DA purchases and sales times DA prices (QDA x PDA) + Market Operations Standing Committee of the IMO September 22, 2003 Slide 18

  19. Virtual Supply Offers And Load Bids Add Liquidity To DAM And Converge DAM And RTM Prices Day Ahead Market Real Time Market Participation unavoidable Commitment to buy Q in RTM Commitment to sell Q in RTM Converge to expected RTM prices • Participation voluntary • MPs submit virtual offers to sell Q in DAM = • MPs submit virtual bids to buy Q in DAM = • With virtual offers/bids, DAM prices tend to => Market Operations Standing Committee of the IMO September 22, 2003 Slide 19

  20. The Day Ahead Market Includes A Unit Commitment Process For DAM and RTM Day Ahead Market Real Time Market • MPs submit 3-part price offers: • (1) Incremental energy • (2) Start-up costs • (3) Minimum generation costs • IMO optimizes commitment and commits units for: • DAM bid-in load • Forecast RT load • Bid Production Cost Guarantee (BPCG) - Generators made whole if DAM revenues don’t cover full bid-in costs IMO-committed units from DA unit commitment are available for dispatch to meet RT loads IMO arranges security-constrained economic dispatch from supply offers and demand bids Market Operations Standing Committee of the IMO September 22, 2003 Slide 20

  21. DAM Uses Multiple Passes To Commit Units And Define Dispatch Schedules And Prices Pass 1 Commit units to meet DAM bid-in load Pass 2 Commit units to meet RT forecast load (Optional) Pass 3 Optimize dispatch/define schedules to meet DAM bid-in load Pass 4 Dispatch to indicate schedules/prices for RT forecast load Market Operations Standing Committee of the IMO September 22, 2003 Slide 21

  22. Proposed DAM Uses Multiple Passes To Define Commitments For DAM And RTM Pass 1 and Pass 2 optimize unit commitment using 3-part offers/bids Pass 1 Pass 2 IMO optimizes commitment and commits units to meet bid-in DA load Constrained pass Physical Suppliers Physical Loads Exports/Imports Virtual offers/bids IMO optimizes and commits more units to meet forecast RT load Constrained pass Physical Suppliers Physical Loads Exports/Imports No Virtuals Results Market Operations Standing Committee of the IMO September 22, 2003 Slide 22

  23. Committed Units Are Used To Define Schedules And Prices For DAM (and RTM) Given the units committed in Passes 1 & 2, Passes 3 & 4 define schedules and prices Pass 3 Pass 4 IMO optimizes dispatch over 24 hours for bid-in load Defines DAM schedules and nodal prices Constrained Pass IMO optimizes dispatch for forecast RT load Defines indicative schedules & prices for RTM Constrained pass Market Operations Standing Committee of the IMO September 22, 2003 Slide 23

  24. Committed Units May Not Recover Bid Costs From Market. Uplifts Are Needed Principle: Those on whose behalf the commitment costs were incurred pay the associated uplift Pass 1 Pass 2 Committed units entitled to bid-cost payment guarantee Uplift paid primarily by all physical RT loads Uplift based against DAM revenues Committed units entitled to bid-cost payment guarantee Uplift for these units paid by net RT loads (those who chose not to participate in DAM) Uplift based against DAM revenues Market Operations Standing Committee of the IMO September 22, 2003 Slide 24

  25. Efficient Results Need Consistent Schedules and Price Formation Between DAM And RTM Day Ahead Market Real Time Market Schedules From constrained dispatch. Based on all units with closed breakers or able to close breakers within 5-minutes Prices From constrained dispatch. Based on all units with closed breakers or able to close breakers within 5-minutes Schedules From Pass 3 = constrained, Includes all committed units Prices From Pass 3 = constrained Limited to committed units and quick start units OK OK Market Operations Standing Committee of the IMO September 22, 2003 Slide 25

  26. Moving Import & Export Trades To The DAM Should Reduce IOG Payments And Uplifts Day Ahead Market Real Time Market DAM is hourly Imports offer to sell into DAM Exports bid to buy from DAM Imports/Exports are cleared in the DAM and settled at the DAM prices No intertie offer guarantee payments are needed for DAM import/exports RTMs are 5-minutes Imports offer to sell into RTM Exports bid to buy from RTM Imports/exports are cleared in the pre-dispatch, but settled at RTM prices IMO must pay intertie trades at their offers if RTM prices are not enough to cover offer prices for pre-dispatch schedules Market Operations Standing Committee of the IMO September 22, 2003 Slide 26

  27. Imports And Exports • The procedures proposed for the IMO to schedule imports and exports in the DAM are generally similar to the procedures that it uses to schedule internal generation and loads in the RTM. • Imports In The Reliability Commitment • When it is necessary to commit additional generating capacity to ensure that the IMO will be able to meet its load forecast: • Only the commitment costs of slow-starting generation will be considered when determining whether it should be committed. • In cases when the offer for an import is less than the commitment costs of internal generation, selecting the imports can reduce the cost of committing additional units to cover forecast load. • The IMO will charge net real-time load for the cost of committing these imports. • Committing these imports can reduce the amount that real-time load needs to pay in these circumstances. Market Operations Standing Committee of the IMO September 22, 2003 Slide 27

  28. Transmission Rights Settlements • Once the DAM is implemented, TRs will need to be settled in the DAM. • Transmission rights could be options or obligations (still to be discussed in detail). • DAM schedules are obligations. • Settling TRs in the DAM will maintain revenue adequacy for the IMO. • The FTRs and the DAM schedules otherwise would constitute competing sets of claims on RTM congestion rents. Market Operations Standing Committee of the IMO September 22, 2003 Slide 28

  29. Day Ahead Market Design Update Agenda • DAM Chronology • DAM Design and Features • DAM Pricing Options • DAM Benefits • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 29

  30. A Day Ahead Market Based Upon Uniform Pricing? • The Comprehensive Day Ahead Market was expected to comprise a constrained schedule of resources and a uniform price methodology to determine prices • for the DAM and RTM to converge, require consistent methods in DAM and RTM to determine schedules and prices • the current real-time market determines schedules on a constrained basis • the current real-time market determines price using a uniform pricing methodology • The DAM WG examined the implications of employing a uniform pricing methodology in the DAM. Market Operations Standing Committee of the IMO September 22, 2003 Slide 30

  31. “Uniform” Pricing Is Misnamed. It Has Locational Differences, But The Wrong Ones • A so-called “uniform” pricing system must pay different prices to generators at different locations whenever there is congestion. • During congestion, the value of energy necessarily varies at different locations, because transmission constraints prevent some cheaper generation from getting to some loads. • Lower-cost generators at some locations must be “constrained off” to relieve constraints, while at other locations . . . • Higher-cost generators must be “constrained on” to meet load. • The IMO cannot manage congestion in a market without paying different prices to generators at different locations relative to the congestion. • Otherwise, generators would not follow dispatch instructions. • During congestion, uniform prices must therefore be augmented by side payments that vary by location, depending on the extent and location of the congestion and the prices that generators offer. Market Operations Standing Committee of the IMO September 22, 2003 Slide 31

  32. “Locational” Prices Under Uniform Pricing Are Not Efficient and Not “Market” Prices • Although generators at different locations are paid different prices under uniform pricing whenever there is congestion, the resulting prices are not true market-clearing prices and are not efficient. • Generators paid “constrained-off” payments are usually paid more than their energy is worth (they are paid not to run or produce less). • And they have an incentive to adjust their offers to maximize the side payments they receive for not running or producing less. • Generators paid “constrained-on” side payments are often not paid as much as their energy is worth. They’re paid “as bid.” • So they have an incentive to adjust their offers to maximize the side payments to try to capture the market value, but they have to guess and will often be wrong, yielding inefficiency – there is no transparent market price. Market Operations Standing Committee of the IMO September 22, 2003 Slide 32

  33. A Uniform Pricing System Is Problematic • The current uniform pricing system is the root source of several problems. It creates price incentives that may: • Encourage supply and demand-side investments at the wrong locations. • Discourage supply and demand-side investments at the right locations. • Every US ISO that has tried uniform pricing had to develop extensive non-market mechanisms to counteract the undesired incentives from uniform pricing. Eventually, each such US ISO concluded that it must replace uniform pricing with nodal locational marginal pricing for generators. Market Operations Standing Committee of the IMO September 22, 2003 Slide 33

  34. Uniform Pricing “Simplicity” Is A Myth • A uniform pricing system is always more complex than the alternative of settling generators at their respective nodal prices. • Requires a complex set of side payments that are non-transparent -- This complexity will be magnified with a DAM, as shown in the July 28 presentation to the DAM WG. (Only 8 of 64+ cases were shown.) • Experience in other markets has shown that some generators can be encouraged to manipulate their offer prices to maximize the side payments. • This problem will substantially increase with a DAM if based on uniform pricing. (See, California ISO web site re Enron practices) • Extensive administrative rules will be needed to monitor, limit and counteract this behaviour • Conclusion of DAM working group (August 19, 2003): • A Day Ahead Market under a uniform pricing regime would be costly to implement and maintain, complex and confusing, and is not recommended Market Operations Standing Committee of the IMO September 22, 2003 Slide 34

  35. Day Ahead Market - Pricing Options Day Ahead Market (DAM) Evolution Market Operations Standing Committee of the IMO September 22, 2003 Slide 35

  36. Nodal Pricing Is Simpler, More Efficient • For Generators: Unlike uniform prices, the nodal prices make intuitive sense to generators – they are consistent with the generators’ offers. • If not dispatched, the nodal prices were below the offer • If partially dispatched, the nodal prices are consistent with the offer • If fully dispatched, the nodal prices will be at least as high as and possible higher than the offer. • For Dispatchable Loads: Nodal pricing provides correct incentives for price-responsive demand • Sends correct price signals about the value of demand-side responses at different locations • For the IMO: Unlike uniform prices (even with side payments), nodal prices are consistent with the actual dispatch. • So the price signals are consistent with what the IMO needs the generators to do to maintain reliable operations. • So complex rules for side payments aren’t needed for reliability. Market Operations Standing Committee of the IMO September 22, 2003 Slide 36

  37. Nodal Pricing For Generators Can Coexist With ‘Uniform Pricing’ Applied To Loads • The nodal pricing framework used in US ISOs continues to settle most loads at “zonal” prices, which are averages of nodal prices for each utility’s service area. • This construct could be used in Ontario if it wishes to continue charging all consumers the same price for energy, as today. In this scenario, ‘uniform prices’ could be the weighted average price of all load nodes. • It should be understood that any averaging scheme introduces some inefficiency and inherently involves cost shifts. For reliability purposes, this is not a serious problem, except for those customers/loads that could participate in price-responsive demand opportunities. Market Operations Standing Committee of the IMO September 22, 2003 Slide 37

  38. Day Ahead Market - Nodal Price Model • Need to assess the impact of a nodal pricing solution before making recommendations: • Market Participants • While the DAM WG agrees that Uniform Pricing in a DAM is not workable, more analysis of nodal pricing is needed: • pricing impact - historical and going-forward • broad Market Participant education and stakeholdering • Impact upon DAM design • DAM based upon nodal pricing is simpler • System of transmission rights for internal congestion required • Impact upon RTM design • RTM would need to be settled on nodal basis - settlement system changes Market Operations Standing Committee of the IMO September 22, 2003 Slide 38

  39. Day Ahead Market Design Update Agenda • DAM Chronology • DAM Design and Features • DAM Pricing Options • DAM Benefits • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 39

  40. Day Ahead Market - Benefits • Improved point of convergence for forward products • DAM provides a transparent and predictable price that converges on the RTM price • Lower volatility - DAM price volatility lower than RTM price • Greater liquidity - DAM explicitly allows non-dispatchable load bids and ‘virtual’ participation • Price convergence - ‘virtual’ participants in DAM encourage price arbitrage between DAM and real-time market • DAM price better than RTM price as an index - facilitates forward price curve development  contracting • Experience in other markets... • Contracting in PJM and NY > 50% of market • PJM futures activity setting volume records on NYMEX Market Operations Standing Committee of the IMO September 22, 2003 Slide 40

  41. Day Ahead Market - Benefits • Improved reliability • Allows for direct participation of all loads in market • Additional opportunity for demand-side response • Improved commitment process • Allows IMO to commit sufficient resources to meet forecast demand • Drivers to ensure committed resources ‘show-up in real-time’ • Utilizes 3-part offer construct and provides BPCG • Imports and exports priced and scheduled day-ahead • Moves transactions from RTM to DAM and reduces intertie trading uncertainty • Should reduce number of failed intertie transactions • Should reduce Intertie Offer Guarantee (IOG) uplift payments Market Operations Standing Committee of the IMO September 22, 2003 Slide 41

  42. Day Ahead Market Design Update Agenda • DAM Chronology • DAM Design and Features • DAM Pricing Options • DAM Benefits • Next Steps Market Operations Standing Committee of the IMO September 22, 2003 Slide 42

  43. DAM - Next Steps • Assess Impact of Nodal Pricing • The DAM WG will continue to address DAM-related issues, including those related to nodal pricing • Need to determine appropriate vehicle to stakeholder issues related to impact of nodal pricing in RTM • Complete DAM High Level Design Strawman Market Operations Standing Committee of the IMO September 22, 2003 Slide 43

More Related