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Roles and Responsibilities

Roles and Responsibilities. Roles and Responsibilities stakeholders in the market. network owners system operator(s) regulators. Infrastructure. brokers power exchange(s). Market Places. generators consumers suppliers traders. Market Participants. portfolio managers

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Roles and Responsibilities

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  1. Roles and Responsibilities

  2. Roles and Responsibilities stakeholders in the market network owners system operator(s) regulators Infrastructure brokers power exchange(s) Market Places generators consumers suppliers traders Market Participants portfolio managers balance responsible Service Providers

  3. Roles and Responsibilities interactions regulated generators MWh $ $ $ $ $ $ $ power exchange brokers traders networks system operators balance responsible suppliers $ portfolio managers $ $ $ MWh consumers

  4. Interfaces

  5. Overview Interfaces Generators and large- scale industry • Procurement ancillary services: • Automatic frequency control • Reactive power • Power reserves Purchase/sale Real Time Market (RTM) and financial settlement Transmission capacities for DAM Transmission System Operator (TSO) Transmission and System Services DAM trade Schedules Balancing Mechanism Power Exchange Financial settlement of net Imbalances DAM trade Schedules Balance Responsible Participants Charges for transmission and system services Metered data Bids/offers Trade confirmation Volume in bilateral contracts Financial settlement of individual Imbalances All spot market participants Grid owners, industry and generators connected to the main grid Market Participants Grid owners

  6. TSO How to maintain sufficientshort term reserves? (example) Option based market for short term power reserves Market for Short Term Reserve Capacity > 2700 MW Activated within 15 minutes - 48 hours Fast Reserves The Real Time Markets Price Activated within 15 minutes MW Reserves Reserves are required both in the spot market and the real time market Instantaneous disturbance reserves ca. 1200 MW Instantaneous frequency reserves 600 MW per 0,1 Hz Spot Market

  7. Balance Responsibility general description SO 0 +10 -15 +5 BRG1 BRG2 BR1 +10 BR2 +3 BR3 +5 BR4 -8 BR5 -8 BR6 -7 BR7 0 BR8 +5

  8. Markets and Pricing Mechanisms

  9. When is which price determined?

  10. The Electricity Market Reform Timeline of Participation more than one day ahead one day ahead real-time dispatching according to the commitments hedging against the price risk and optimizing the financial part of the power portfolio optimizing the physical part of the power portfolio scheduling own generation for real-time Long-term Security of Supply and Incentive for Investment Generation Optimization System Security and Reliability

  11. Basics of the Expected Price

  12. Marginal Generation Costs Load Scenarios low consumption high consumption diesel short run marginal cost oil gas coal nuclear wind hydro installed capacity

  13. Fundamental Factors For example Consumption MWh/h consumption one year time

  14. Marginal System Costs Based on a Consumption Pattern $/MWh system marginal costs one year time

  15. Market Price Based on a Marginal System Costs $/MWh market price one year time

  16. expected system marginal costs expected market price Market Expectancy Based on Input expected consumption $/MWh and MWh/h next year time

  17. Market Expectancy Scenarios worst case scenario “high” $/MWh expected market price “normal scenario” worst case scenario “low” next year time

  18. Derivatives Cash Flow - Hedging HEDGING $/MWh cash flow from seller to buyer Reference Price higher than Contract Price Contract Price cash flow from buyer to seller Reference Price lower than Contract Price contract delivery period time

  19. Basics of the Spot (or: DAM) Price

  20. Participating in the Spot MarketOptimizing the physical delivery contract portfolio • Hour 20: Power portfolio content • own generationG1 = 150 MW C’ = 100 YTL/MWhG2 = 100 MW C’ = 150 YTL/MWh • purchased bilateral contractB1 = 50 MWB2 = 50 MW • sold bilateral contractB1 = 25 MWB2 = 50 MW • commitments towards not hourly metered customersforecasted load obligation = 50 MW

  21. Spot Piyasaya Katılım Fiziksel Sözleşme Portföyünün Optimizasyonu • Saat 20: Elektrik portföy içeriği • Kendi üretimiG1 = 150 MW C’ = 100 YTL/MWhG2 = 100 MW C’ = 150 YTL/MWh • Alış ikili anlaşma B1 = 50 MWB2 = 50 MW • Satış ikili anlaşmaB1 = 25 MWB2 = 50 MW • Saatlik sayaç ölçümü yapılmayan müşterilere verilen taahhütler için karşılanması gereken tahmini yük = 50 MW

  22. Participating in the Spot MarketOptimizing the physical delivery contract portfolio Hour 20: Power portfolio optimization bid price 0 100 101 150 151 5000 volume 25 25 -125 -125 -225 -225

  23. Spot Piyasaya Katılım Fiziksel Sözleşme Portföyünün Optimizasyonu Saat 20: Elektrik Portföyü Optimizasyonu Teklifi fiyat 0 100 101 150 151 5000 miktar 25 25 -125 -125 -225 -225 satış alış

  24. 1 3 2 Participating in the Spot MarketOptimizing the physical delivery contract portfolio MCP = 180 YTL/MWh Volume = Sale of 225 MWh

  25. satış alış 1 3 2 Spot Piyasaya Katılım Fiziksel Sözleşme Portföyünün Optimizasyonu PTF = 180 YTL/MWh Miktar = 225 MWh Satış

  26. Efficiency Trading into Balance (Example: Consumer)

  27. Imbalance Settlement Invoicing Negative and Crediting Positive Imbalances (Example: Consumer)

  28. Case TURK-EL’s operational hours MWh/h 400 285 contracted generation 00-01 metered generation 00-01 hour 00-01

  29. Case TURK-EL’s settlement due to the metered values ??? 15 MWh Imbalance 100 MWh BM contract 00-01 TURK-EL is invoiced for this imbalance: the Imbalance Volume multiplied with the Imbalance Price 400 MWh contracted 00-01 285 MWh metered generation 00-01

  30. Theory Basic Theory of Output and Costs Cost (based on optimum output) / Price price > minimum average cost operational profit minimum average cost Break-Even Point: P = minimum average cost variable cost < price < minimum average cost covering output dependent costs and reducing output independent cost losses output dependent cost Minimum Price to be achieved short-term: P = output dependent cost price < output dependent cost operational losses 0

  31. Case Hourly Contracts and their Impact on Strategies • The hourly based bids • Each hour requires a separate bid. This implies that the output dependent costs of a unit can be “in the price” during some hours and “out of the price” in others. • Base load units should be bid at “0”-prices in those hours they are needed to be scheduled • Mid load and peak load units should “take care” of eventual start and stop costs in their bid-price Alternative 2 (Theory) Alternative 1 peak load units MCP & output dependent costs MCP & output dependent costs MCP & output dependent costs mid load units base load units 24 hours 24 hours 24 hours a functioning market a not functioning market

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