Roles and Responsibilities

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

regulated balance responsible portfoliomanagers traders power exchange brokers suppliers generators consumers system operators networks $$ $$ $ $ $$$$ MWh MWh $ Roles and Responsibilities interactions

Interfaces

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

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

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

Markets and Pricing Mechanisms

When is which price determined?

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

Basics of the Expected Price

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

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

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

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

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

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

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

Basics of the Spot (or: DAM) Price

Participating in the Spot Market Optimizing the physical delivery contract portfolio Hour 20: Power portfolio content own generation G1 = 150 MWC’ = 100 YTL/MWh G2 = 100 MWC’ = 150 YTL/MWh purchased bilateral contract B1 = 50 MW B2 = 50 MW sold bilateral contract B1 = 25 MW B2 = 50 MW commitments towards not hourly metered customers forecasted load obligation = 50 MW

Spot Piyasaya Katılım Fiziksel Sözleşme Portföyünün Optimizasyonu Saat 20: Elektrik portföy içeriği Kendi üretimi G1 = 150 MWC’ = 100 YTL/MWh G2 = 100 MWC’ = 150 YTL/MWh Alış ikili anlaşma B1 = 50 MW B2 = 50 MW Satış ikili anlaşma B1 = 25 MW B2 = 50 MW Saatlik sayaç ölçümü yapılmayan müşterilere verilen taahhütler için karşılanması gereken tahmini yük = 50 MW

Hour 20: Power portfolio optimization bid price volume Participating in the Spot Market Optimizing the physical delivery contract portfolio

Saat 20: Elektrik Portföyü Optimizasyonu Teklifi fiyat miktar Spot Piyasaya Katılım Fiziksel Sözleşme Portföyünün Optimizasyonu satış alış

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

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

Efficiency Trading into Balance (Example: Consumer)

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

TURK-EL’s operational hours MWh/h hour contracted generation metered generation Case

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

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

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 MCP & output dependent costs 24 hours Alternative 1 24 hours Alternative 2 24 hours (Theory) a not functioning market a functioning market base load units mid load units peak load units MCP & output dependent costs Case