1

Establishment of the HTSO:Stakeholders’ Workshop

18 October 2000

2

Introduction to the New Industry Structure

3

EU Directive and the Electricity Law• The EU Directive aimed to introduce a degree of competition to the

electricity industry throughout the EU. It takes effect for Greece from February 2001 and envisages, among other things, that:

– competing suppliers have access to supply large consumers– there be accounting separation of the different parts of the industry to achieve

greater transparency of operation– regulatory arrangements be put in place for these new arrangements

• The new Greek Electricity Law elaborated the implementation of the EU Directive for Greece

• The proposed new industry structure applies to the interconnected system, and complies with the requirements of the EU Electricity Directive

4

Key Elements of the New Structure

• Generation: competition is permitted between different generators

• Transmission (wires): remains a natural monopoly in the ownership of PPC

• Distribution (wires): remains a natural monopoly in the ownership of PPC

• Supply (sales to customers): opened to competition, initially to a limited category of “Eligible” Customers

• HTSO: plays a vital role in permitting this structure to work

The key to the new structure is the distinction created between different sectors of the electricity industry:

5

HTSO Goals and Responsibilities

• Central to the new structure is the creation of HTSO - an independent system operation organisation

• HTSO will take over from PPC the responsibility for system planning and operation, including dispatch of generators and operation of the new trading arrangements

• HTSO will be the key institution in ensuring transparency and fairness, so that new entrants to the industry are not discriminated against, and that:

– independent generators can have connection and access rights

– independent suppliers can use PPC-owned lines on reasonable terms to supply consumers

– the pricing of “imbalance” power is transparent and non-discriminatory

6

Overview of the New StructureIndependent Generator

Independent Generator

H.T.S.O

PPCTransmission

PPCTransmission

PPCGenerators

PPCGenerators

Distribution System Operator

PPC Distribution and Supply

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Independent Generators(incl. Inter-connected

Generators)

Independent Supply Co

Non-Eligible CustomersNon-Eligible Customers

Electricity Flow

Renewable Generator

Renewable Generator

7

Overview of the New StructureIndependent Generator

Independent Generator

H.T.S.O

PPCTransmission

PPCTransmission

PPCGenerators

PPCGenerators

Distribution System Operator

PPC Distribution and Supply

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Eligible Customer

s

Independent Generators(incl. Inter-connected

Generators)

Independent Supply Co

Non-Eligible CustomersNon-Eligible Customers

Electricity Flow

Commercial transaction

Renewable Generator

Renewable Generator

8

Unbundling PPC’s Activities• Virtually all of PPC’s present activities will remain within PPC, but a

separation will be required in accounting and regulatory terms between:

– generation– transmission– distribution– supply

• HTSO takes over from PPC the functions of system planning, system development, and system control, (with PPC remaining responsible for actually carrying out development work and physical operation)

• HTSO will also be responsible for granting access to system users, and the operation of the new trading arrangements

9

The Regulatory Arrangements • Establishment of a new regulatory agency for the industry, (the Regulatory

Authority for Energy or “RAE”) is an important part of these new arrangements • RAE will be responsible for regulation of these new competitive activities, under

the auspices of the Ministry of Development• RAE and the Ministry are responsible for:

– issuing authorisations to HTSO, and to the transmission, distribution, generation and supply entities

– approval of the Operating Code and Power Exchange Code– approval of the transmission control agreement– regulation of prices– dispute resolution, etc

• These new regulatory arrangements are crucial to ensuring the effective operation of the new market arrangements – they must ensure that independent generators and suppliers are treated in a fair and non-discriminatory way

10

Installed Capacity Adequacy• Only Authorised Suppliers may sell to consumers and participate

in the trading arrangements

• The Ministry of Development will issue Supply Authorizations, on the recommendation of RAE

• To be authorized to supply, a supplier must:

– Own adequate capacity in the EU

– Own, or contract on a firm basis, additional capacity to meet reserve requirements

– Arrange, on a long-term basis, the necessary interconnector capacity and transmission capacity within Greece

• The law doesn’t specify the exact capacity requirement; this will need to be specified by RAE

11

The Supply Code

• Article 27 of the Electricity Law requires that RAE will prepare Supply Codes covering both Eligible Customers and Non-Eligible Customers.

• The Law says that for Eligible Customers the Supply Code will regulate:– the terms, conditions, and specifications of the supply services of PPC

to Eligible Customers; and– the terms and the specifications of the supply services of other supply

authorisation holders to Eligible Customers.

12

Role of the System Trading Arrangements

• When competing generators and suppliers participate in an integrated power sector there needs to be a common set of rules governing technical and commercial operation

• These common rules are referred to collectively as the System Trading Arrangements, or STA, and they are necessary to:– ensure effective grid discipline through a mix of rules and incentives

– aim to achieve merit order dispatch

– determine the price at which imbalances are traded between the various participants

– ensure a balance between demand and available capacity

13

Key Features of theSystem Trading Arrangements

14

The System Trading Arrangements are Designed to Provide:

• The means by which Participants can:– Use the transmission system

– Buy and sell imbalance energy

• The rules by which HTSO operates the system:– Reliably

– Efficiently

– Fairly

– Transparently

• Market-based incentives for production & investment

• Efficient entry without losing the existing benefits of integration

15

The STA has 5 Steps• Day-ahead forecast

• Real-time dispatch

• Metering and calculation of SMP

• Calculation of Constrained-On/Off Payments & other items

• Billing & funds transfer

Dispatch:Day-Ahead:

16:000:00 0:00 24:00

DetermineMeter Quantities

Determine SMP

Calculate SettlementAmounts

Issue Bills &Statements

FundsTransfer

16

Key Features of the STA(Compared to other Countries)

• Independent ISO/ power exchange

• An Offer-based dispatch

• A single price for imbalance energy in each hour

• SMPs are determined once for each hour (ex-post)

• Regulation of Offer prices

• Uplift

• Net settlement in respect of ownership

• Gross settlement in respect of contracts

17

Independent ISO/ Power Exchange

• The ISO is both ISO (operator of the physical system) and Power Exchange (operator of the commercial system)

• The HTSO is independent of PPC

ISO/ PX Combined ISO/PX SeparatedISO/ Transmission Owner Combined

ISO/Transmission Owner Separated

PJM California England & Wales Rest of USANew York New Zealand New Zealand * Australia

England & Wales * others Alliance ISO (USA) * Ontario *Spain * Midwest ISO (USA) * Spain *

Australia Norway South AmericaOntario * others GreeceGreece others

many others

18

Offer-Based Dispatch• Least-cost, security-constrained dispatch

• Based on offers, not NCC-determined costs

• Offer prices consist of a 3-step function and a start-up cost (Operating Code)

• Offers cannot be changed after a Unit is scheduled day-ahead, except in “genuine” conditions such as forced outages

• Offers must be consistent with registered/declared Info.

• Offer quantity parameters can vary hourly

• Offer price parameters cannot vary hourly - one price function per day

19

SMP Calculated Ex-Post

• SMPs are the prices at which imbalance energy trades

• SMPs set by the marginal Offer accepted in each hour

• There are no forward markets, like in some countries

• Day-ahead SMPs are only forecasts

• However, there is financial commitment from the day-ahead schedule because scheduled offers cannot be changed

20

A Single SMP in each Hour

• Prices are not locational, like in some countries• There is one SMP per hour for all of Greece• However, Settlement Quantities are adjusted by loss factors• SMPs are calculated ex-post, once metering data has been collected and

all actual system information is known

• Determination of SMP designed to be: straightforward, transparent

Many Prices Single Price

Argentina England and Wales *Parts of Australia * Spain

California * New England *New York/ PJM GreeceNew Zealand others

Mexico *Ontarioothers

21

Regulation of Offer Prices• Offers must contain “true” costs

• This is a requirement of the Law

• This requirement, & its interpretation, is overseen by the RAE, not by HTSO

• There is nothing in the codes that specifies this requirement, however:– Offers must be approved and available for audit by the ERA.

HTSO will provide info the RAE as it requires

– It is anticipated that this restriction might not apply to Units in foreign countries

22

• Key feature of the STA: Participants

• The roles of “Participant Purchaser” and “Participant Generator” are always separated.

• The category “Participant Purchasers” comprises:

– Suppliers authorised in accordance with the Greek Electricity Law to sell electricity to final customers in Greece; and

– Exporting Purchasers that purchase electricity in the STA for the purpose of export from Greece to supply customers in another country.

• The category “Participant Generators” comprises:

– Domestic generating entities owning power plants located in Greece, and holding an Electricity Generation Authorisation; and

– Foreign generating entities owning power plants located outside of Greece, where they hold a Greek Electricity Supply Authorisation.

• All energy is produced by Generators and sold through the STA

• All energy consumed is bought by Purchasers through the STA

• HTSO nets invoice of each “Person”

Net Settlement in Respect of Ownership

23

Participants

Suppliers Other GensExporters

Purchasers Generators

Authorized Entities(“Persons”)

Unit 1 Unit N...Meter 1 Meter N..

Offer 1 Offer N..

Settlement/Imbalance Calculation

Meter Reading 1

Meter Reading N

….Meter Reading 1

Meter Reading N

….

Interface with STA

Participants

24

Net Settlement: an Example• 2 Suppliers (“Persons”): A & B

– Each Supplier owns generation

– Therefore, each Supplier is a Generator and a Purchaser

• Supplier A’s and Supplier B’s characteristics are:

• In this example:– a Dispatch Day only has 2 Dispatch Hours

– transmission and Uplift are ignored

Capacity (MW):

Production Cost (DRS/MWh)

Capacity (MW):

Production Cost (DRS/MWh)

Unit A1 200 6,000 Load in Hour 1 (MW): 250 Unit B1 200 5,000 Load in Hour 1 (MW): 250 Unit A2 200 10,000 Load in Hour 2 (MW): 350 Unit B2 200 12,000 Load in Hour 2 (MW): 350

Generator A Purchaser AComprising:

Supplier A Supplier BGenerator B Purchaser B

Comprising:

25

Generator Offers• HTSO conducts a least cost Dispatch based on Offers in order to

meet total system load• Offers must reflect variable costs• The complete set of Offers is as follows:

Unit ID MWOffer Price (DRS/MWh)

A1 200 6,000 A2 200 10,000 B1 200 5,000 B2 200 12,000

26

The Merit Order and Dispatch• Total load is 500MW in hour 1 and 700MW in hour 2• The merit order, Dispatch and SMPs are thus:

• SMP is set by the marginal Offer cost of supplying an additional MW to the system:– Unit A2 in hour1 (10,000 DRS/MWh)– Unit B2 in hour 2 (12,000 DRS/MWh)

Unit ID MWOffer Price (DRS/MWh)

Output Hour 1

Output Hour 2

SMP Hr1 (DRS/MWh)

SMP Hr2 (DRS/MWh)

10,000 12,000B1 200 5,000 200 200A1 200 6,000 200 200A2 200 10,000 100 200B2 200 12,000 0 100

Total 800 500 700

27

Energy Sales and Purchases• All energy is sold by Generators, bought by Purchasers

and settled by HTSO:

• In each hour: total sales = total purchases

MW PriceDRS

(000s)MW Price

DRS (000s)

Total DRS (000s)

Gen A Sells 300 10,000 3,000 400 12,000 4,800 7,800 Gen B Sells 200 10,000 2,000 300 12,000 3,600 5,600 Total Sales 500 5,000 700 8,400 13,400

Purch A Buys 250 10,000 2,500 350 12,000 4,200 6,700 Purch B Buys 250 10,000 2,500 350 12,000 4,200 6,700

Total Purchases 500 5,000 700 8,400 13,400

Hour 1 Hour 2

28

HTSO Settles Net of Ownership• HTSO consolidates invoices and remittances of Participant

Generators and Participant Purchasers owned by the same Person:– Supplier A is paid DRS 1,100,000 (50*10,000 + 50*12,000)– Supplier B is charged DRS 1,100,000 (50*10,000 + 50*12,000)

• Supplier B was better off with an imbalance and buying through the PEC instead of generating to meet its own load

Supplier A Total DRS Supplier B Total DRS

Generator A Sales 7,800 Generator B Sales 5,600 less Purchaser A Purchases 6,700 less Purchaser B Purchases 6,700 Net Remittance, Supplier A 1,100 Net Remittance, Supplier B (1,100)

29

Gross Settlement in Respect of Contracts

• Participants can enter into a bilateral financial contract called a Contract for Differences (CFD) to lock in the SMP

• HTSO does not know about CFDs

• A CFD has a strike price and a MW quantity:– SMP > strike price: Generator pays Purchaser

(SMP - strike price) x MW quantity

– SMP < strike price: Purchaser pays Generator(strike price - SMP) x MW quantity

• Both Purchaser and Generator are guaranteed the strike price for the MW quantity

30

Price

Time

Payments from net Purchaser to net Generator

Payments from net Generatorto net Purchaser

CFD Price

SMP

Gross Settlement in Respect of Contracts: CFDs

31

System Operation

• Up to Real Time:– Demand Forecast

– Generation/ Interconnector Scheduling

– generation despatch

• System Services

• Demand Control

• Emergency Measures

32

Demand Forecasting

• Demand forecasting will be required over different time scales

- Operational Planning

- Programming

- Control

- Post Control

• Will require typical profiles from DSO and Suppliers for defined categories of day type. HTSO will define these day types

• Possible agreements required with external TSOs

33

Interconector Management

• Interconnector management is part of prudent system control

• OC 7 facilitates secure trading with neighbouring utilities

• Trading planned over three day time frame requiring posting of Available Transmission Capacity (ATC) and then allowing Independent and Franchise sectors access

• Reserve sharing and restoration services should be covered by bilateral agreements

34

Generation Scheduling

• HTSO obligation to to schedule and dispatch generation

• HTSO requires accurate and timely information relating to generation and supply

• SDC1 specifies procedures for issuing a generation schedule for a trading day and Demand forecast

• Thus generators receive an indicative dispatch for the following day

• HTSO maintains an operating margin

• Desired flows on interconnections are scheduled

35

Generation Scheduling

• General Requirements

- Demand Forecast

- Declarations by Generators

- Daily Offers

- Communication of Declarations

- Communication of Daily Offers

- ATC for interconnections

- Production of Generation Schedule (GS)

- Procedure in absence of a daily nomination

36

Generation SchedulingSDC1.4

The HTSO publishesdemand forecast for next

dispatch day by 11.00

SDC1.5-1.6Generators

sendDeclarations

and DailyOffers for nextDispatch Day by 12.00

SDC1.8Exporting

Purchaserssend

Nominationsfor next

Dispatch Dayby 12.00.

SDC1.10

The HTSO producesschedule between 13.00 and16.00 for next dispatch day

SDC1.10

The HTSO issuesprovisional running orders and

publishes forecast systemmarginal price for each dispatch

hour of next dispatch day

37

Generation Dispatching

• HTSO Authorisations obligation to dispatch generation to meet demand

• A structured process is required

• SDC2 details the process to be used by HTSO decides the generation dispatch using the generation scheduled provided

• HTSO procedure for communicating dispatch instructions - some details will depend on Market protocols

38

SDC2 SummaryThe HTSO forecasts Demand, sets reserve level and agrees ATC on interconnectors with External System

Operators. HTSO issues dispatch instructions up to real time

The HTSO issues dispatch instructions up to real time

Accepted by

Gen?

Inform HTSO-must be for safety or

emergency reasons

Yes

No

Synchronising, desynchronising

times

Active Power Dispatch

System Alerts

Instruction in line with

operating characteristics? Inform HTSO

No

Revise

instruction

Reactive Power

Dispatch

System Emergency Conditions

Operating Mode

Dispatch

39

System Services

• System services for network control and operation now more formalised (payments and measurements)

• HTSO will manage these services and will specify what services will be provided and by whom

• Generator licences must have a requirement to provide certain services on reasonable terms

• Services include - Frequency control Voltage control Network control Operating Margin and Power System Restoration

40

Emergency Control and Power System Restoration

• OC12 is to ensure that after a partial or total system collapse normal supply is restored to all customers quickly and safely

• Generator licences include a provision to offer black start capability to HTSO ( this can be tested under OC10)

• Various proposed System Alerts are presented

• An up to date Power System Restoration Plan is Required

41

Review of Other Codes and Agreements

42

Why the New Codes and Agreements are Necessary

• Participation by independent generators and suppliers must be permitted on a non-discriminatory and competitive basis

• To ensure this, many things that were previously actions internal to PPC will be established as arms-length commercial transactions

• These changes mean that it is necessary to introduce a number of new Codes, agreements, and other instruments in addition to the Power Exchange Code

• These instruments are required partly for commercial reasons, and partly for regulatory reasons

• Experience elsewhere has demonstrated that these or similar instruments are necessary to make the new industry structure work effectively

43

Summary of the Key Codes and Agreements

E U DirectiveE U Directive

Greek Electricity LawGreek Electricity Law

HTSOAuthorisation

HTSOAuthorisation

Transmission Control

Agreement

Transmission Control

Agreement

Transmission AuthorisationTransmission Authorisation

Distribution AuthorisationDistribution

AuthorisationGeneration

AuthorisationGeneration

AuthorisationSupply

AuthorisationSupply

Authorisation

Power Exchange

Code

Power Exchange

Code

Connection AgreementsConnection Agreements

Use of System

Agreements

Use of System

Agreements

AncillaryServices

Agreements

AncillaryServices

Agreements

Operating Code

Operating Code

44

Elaborating the Codes and Agreements

• The PEC is explained in more detail later today

• The purpose of this session is to explain briefly the other agreements and documents, including the Operating Code

45

The Operating Code

46

Purpose of Operating Code

• Fundamentally a technical document containing the Rules governing the Operation, Maintenance, and development of the Transmission System

• Gives Users an understanding of the Rules and provides for equitable treatment for all.

• It refers to documents that are not part of the Operating Code e.g. transmission planning criteria, operating policies, interconnection

• It does not address commercial issues - penalties

-violations

-failure of services

• These are dealt with in other agreements

47

Hierarchy of Documents

SafetyRules

UCTEStandards

GreekStandards

Standards

TransmissionPlanningCriteria

Reserve Policy

Policies

Operating CodeCompliance

Test

Power SystemRestorationProcedure

Procedures

Otherdocumentation

OperatingCode

Authorisations

Legislation

AncillaryServices

Agreements

PowerExchange

Code

48

Governance

• The Operating Code is a “living” document - it is subject to changes

• Approved by Ministry -brings it into being

• Modifications, Updates, Derogation requests, will be approved by REA - keeping it alive

49

Operating Code:Contents

• General Conditions

• Connection Conditions

• Planning Code

• Operating Codes (13 no.)

• Scheduling & Despatch Codes (3 no.)

50

General Conditions

• Makes provision for rules of a more general nature making a cohesive document allowing the operation of the transmission System for the benefit of all

• Requirement of HTSO to establish and maintain the OCRP

• Allows derogation rather than changes to design specifications

• General Conditions requires users to comply with the”letter & spirit”

of the code and provides HTSO with its rights • HTSO will act reasonably - “Prudent Utility Practice” It should be

noted that if there a conflict between Operating Code and any other agreement the provisions of the Operating Code will prevail

• If parts of the Operating Code unlawful/invalid the validity of all remaining provisions will not be affected

51

Connection Conditions

• To protect plant certain minimum criteria are met

- technical

- design

- operational

• These are defined in Connection Conditions

• This is to allow stable, secure operation of the transmission system

• Compliance required from all users

• Performance of the transmission system at the connection point to enable new users to design their equipment

• For existing plant derogation will be through REA

52

Planning Code

• Planning code is necessary to allow development of the transmission system

- demand growth

- new connection

- development of existing facilities

• Planning code allows HTSO/User interaction covers

- performance impacts on either side

- information requirements of HTSO to allow

it plan according to criteria and standards

- Prepare Forecast statement

53

Operating Codes : OC1 to OC4

• OC1 Safety Co-ordination

• OC2 Information Exchange

• OC3 Metering Code

• OC4 Demand Forecasts

54

Operating Codes: OC5 to OC8

• OC5 Demand Control

• OC6 System Services

• OC7 Interconnector Management

• OC8 Generator Maintenance Scheduling

55

Operating Codes: OC9 to OC13

• OC9 Transmission Maintenance Scheduling

• OC10 Monitoring, Testing and Investigation

• OC11 Operational Testing

• OC12 Emergency Control and Power System Restoration

• OC13 Small Scale Generator Conditions

56

Scheduling & Despatch Codes: SDC1 to SDC3

• SDC1 Generation Scheduling

• SDC2 Generation Despatching

• SDC3 Special Scheduling Provisions

57

Agreements

58

The Transmission Control Agreement (TCA)

• Other key elements are:– should ensure that the HTSO has the necessary degree of control, and that it can

ensure effective development, maintenance, and physical operation of the inter-connected system

– need not cover assets from the non-interconnected system

• Main points of the TCA are:

59

The Connection Agreement

• A key feature is that if it is a tri-partite document; it will ensure that all three parties involved are tied adequately together

• Main points of the Connection Agreement are:

60

Transmission Use of System Agreement

• Other key features are:– all users could sign a common agreement, and new users would join the

arrangement by signing an accession agreement

– fees for use of the system likely to be set by the regulatory authorities from time to time - the same fees structure would automatically apply to all users, their specific fee being determined according to their type of use

• Main points of the Use of System Agreement are:

61

Ancillary Services Agreement

• Other key features are:– these services would be provided on the basis of medium-term contracts, and

the first tranche of contracts would be at regulated terms– new contracts could be procured by open competitive tender, if there is

sufficient competition in the generation market– the costs of the agreements would be recovered by HTSO through Uplift

• Ancillary services are needed to ensure a stable and reliable power system

• Main points of the agreement are:

62

The Authorisations• The Law requires that, with some smaller exceptions, all domestic

participants in the electricity industry must obtain authorisations from the Ministry of Development, on the basis of opinions from RAE

• Main points of the authorisations are:

• Authorisation Regulations will be issued by RAE, governing procedures for Authorisations

63

Elaboration of the Power Exchange Code

64

The Power Exchange Code

• The PEC specifies the commercial functioning of the STA– Enables HTSO to fulfil its obligations under the Law

– Regulates Participants’ energy trading

– Allows calculation & settlement of payments for imbalance energy and Ancillary Services

– Specifies how settlement & billing is conducted

• PEC consists of 5 parts:– General Provisions

– Schedules A - D

65

General Provisions

• Persons and Participants

• Termination

• Arbitration

• Confidentiality

• Type of security

• Renewal of security

• Breach of security provisions

66

Schedule B• Schedule B is the core of the PEC - it specifies the ways in

which Participants buy and sell imbalance energy:

B.I. Conventions

B.II. Responsibility for Energy Metering

B.III. Other Registration Information and HTSO Responsibilities

B.IV. Offer, Load and Price Forecasting, Scheduling and Dispatch

B.V. Special Provisions Relating to International Trade

B.VI. HTSO Settlement Responsibilties

B.VII. Settlement Timelines

B.VIII. Settlement Variables

B.IX. Determination of Loss Factors

B.X. Determination of Meter Quantities

67

Schedule BB.XI. Determination of Day-Ahead Quantities

B.XII. Determination of System Marginal Prices

B.XIII. Determination of Energy Charges and Energy Payments

B.XIV. Determination of Constrained-On and Off Payments

B.XV. Ancillary Services

B.XVI. Other Charges and Payments

B.XVII. Determination of Uplift Charges

B.XVIII. Settlement of Transmission Charges

B.XIX. Settlement Statements

B.XX. Invoices

B.XXI. Compliance

B.XXII. Suspension Procedures

B.XXIII. Information Management

68

Other Schedules

• Schedule A: Definitions

• Schedule C: Form of Address and Contact Details

• Schedule D: Security Cover

69

Summary of Timelines

Dispatch:Each Dispatch Hour(24 Dispatch Hoursin a Dispatch Day)

Day-Ahead:HTSO sends out Day-AheadSchedules to generators andPublishes SMPs

Day-Ahead

20:000:00 0:00 24:00

Dispatch Day After the Dispatch Day

DetermineMeter Quantities

Determine SMP

Calculate SettlementAmounts

Issue Bills &Statements

FundsTransfer

70

Operational Timeline: Day-Ahead• Generators make Offers for Units

• HTSO produces forecast load, and then forecasts schedules: “unconstrained” and “constrained”

• Unconstrained schedule ignores transmission constraints

• Both schedules ignore generator contracts

• Unconstrained schedule: forecast SMPs

• Constrained schedule: units are committed

HTSO publishes loadforecasts

Deadline for submission of Offers intoDay-Ahead Schedule

Last time an invalid Offer canbe re-submitted

HTSO publishes forecast SMPsand sends out schedules to Participants

13:00

HTSO calculates the schedules forthe following Dispatch Day

HTSO calculates the forecast SMPs

12:0011:00 16:000:00 24:00

71

Operational Timeline: Dispatch Day

HTSO begins determination of hourly schedule

HTSO determineshourly schedule

A Dispatch HourTime horizon of hourlyschedule

D-hourD-hour - 2 hours0:00 24:00

• The dispatch is a full re-optimization (least-cost, security-constrained)

• Doesn’t take account of:– Energy contracts of participants– Day-ahead forecast

• Dispatch Instructions are issued by the HTSO to Units– Synchronization– Base Point Instructions– Reserve Activation– Other Instructions

• Does take account of:– Offers (Offers can’t change from day-ahead)

– Full capacity of Units

– Transmission constraints

– Actual load and all other constraints

72

Operational Timeline: Dispatch Hour• New Base Point Instructions issued to all Units every 5 minutes

• Ancillary service instructions issued continuously

• Least-cost, security-constrained dispatch HTSO issuesBase-PointInstructions

HTSO issuesother DispatchInstructions

Dispatch Instructions forthe Dispatch Hour

Start ofD-Hour

End ofD-Hour

0:30 0:500:400:05 0:250:15 0:35 0:45 0:550:10 0:20

73

Settlement Timeline: Before the Dispatch Day

• At least 1 month before the Dispatch Day– Transmission Loss Factors are determined

– Distribution Loss Factors are determined– (losses are accounted for in the STA, not in transmission prices)

• The day before the Dispatch Day– Day-Ahead Quantities are determined (PEC & Operating Code)

– Generation Schedule produced (“constrained schedule”) - (Op. Code)– (generation schedule not used in Power Exchange Code, except in assessment

of penalties for unavailability)

• On the Dispatch Day– Dispatch Instructions (Operating Code)

74

Settlement Timeline: Dispatch Day to Calculation Day

• On the day after the Dispatch Day, Metering Data sent to HTSO

• On the Calculation Day (5 days after Dispatch Day) HTSO determines:– for each Dispatch Hour/Participant:

• Settlement-Quality Meter Data on or before the Calculation Day

• Meter Quantities

• A Settlement Quantity

– the SMP for each Dispatch Hour

– for each Participant:

• Energy Payments/ Energy Charges• Constrained-On/Off Payments

75

Calculation of SMP

SupplyDemand

SMP

Pri

ce (

DR

S/M

W)

Quantity (MW)

Gen

1

Gen

2

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

76

Calculation of SMPP

rice

(D

RS

/MW

)

Quantity (MW)

Gen

1

Gen

2

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

100 MW

Low Demand

PL

SMP (High Demand)

High DemandSMP (Low Demand)

PH

77

Calculation of SMP• Ex-post simulation of least-cost dispatch, using actual: metered load, interconnector

flows, Unit Offers, Unit Constraints and Unit availability

• SMP is the system marginal cost resulting from the simulation (from the marginal flexible Offer)

• SMP is calculated independently for each hour

• Transmission constraints are ignored, so as to get a single price for Greece in each hour

• In theory:

– All Units that were dispatched had offer prices < SMP

– All that weren’t had offer prices > SMP

• In practice there may be inconsistencies (e.g. because of transmission constraints)

– If so, there may be constrained-on/ constrained-off payments

• If load is involuntarily curtailed because load exceeds available generation, SMP = VOLL

• If other failures occur, SMP can be determined with estimated data or by interpolation

78

Constrained-On/Off Payments

• Units scheduled day-ahead are committed to their offer, if called upon by the HTSO

• Normally, – if a Unit is scheduled, the Offer price < SMP

– if a Unit is not scheduled, then Offer price > SMP

• But it might not always work like this (e.g. transmission constraints)

• Generators incur a cost in these situations

• Hence, Constrained-Off Payments and Constrained-On Payments may be made by the HTSO

79

Constrained-Off Payments

• If Unit output is below that consistent with SMP, then a Unit may be paid a Constrained-Off Payment

• In principle: – (SMP - Offer price) * (Max Output - Actual Output)

• In practice:– Each component of this formula is defined in detail in the Power

Exchange Code

– See following illustrations

80

Constrained-On Payments

• If Unit output is above that consistent with SMP, then a Unit may be paid a Constrained-On Payment

• In principle: – (Offer price - SMP) * (constrained-on capability)

• In practice:– Each component of this formula is defined in detail in the Power

Exchange Code

– See following illustrations

• Units may receive additional Constrained-On Payments if necessary to recover start-up costs

81

Ste

p 3

Ste

p 2

Ste

p 1

Maximum Dispatch Capability(MXDC)

Minimum Dispatch Capability(MNDC)

DRS/MWh

MW

Offer Price Function of a Unit

Illustrative Diagram

82

Ste

p 3

Ste

p 2

Ste

p 1

Meter Quantity(MQ)

DRS/MWh

MW

SMP PEC/64

Constrained-Off Payments

83

Ste

p 2

Ste

p 3

Ste

p 1

Minimum Dispatch Capability(MNDC)

DRS/MWh

MW

SMP

PEC/B67

Meter Quantity(MQ)

Constrained-On Payments

84

How are Settlement Quantities Calculated?

Metering Data

Settlement QualityMetering Data

Meter QuantitiesDay-AheadQuantities

Transmission LossFactors

Settlement Quantities

Distribution LossFactors

85

Settlement Quantities

Para 55Energy Paym ents

(and Settlem ent Quantities for Gens)

Para 56Energy Charges

(and Settlem ent Quantities for Purch's)

Para 43Netting of Settlem ent Quality

M eter Data

Para 6Interrogation of M eters (et al)

O ther provisions of Section IIand Operating Code

Para 41Determ ination of Settlem ent-

Quality M etering Data

Para 42Determ ination of M eter Quantities

Operating Code

Para 45Determ ination of Day-Ahead Quantities

Para 58Accounting for Energy Sales and Purchases

Sec

tion

XII

IS

ecti

on X

Sec

tion

II

Sec

tion

XI

86

Uplift• Other costs incurred by the HTSO in operating the physical and

commercial systems• Uplift consists of:

– Ancillary Services– HTSO administration charges– Interconnector net costs– Special Unit costs– Constrained-On Payments and Constrained-Off Payments– Losses adjustments– Additional charges (other items)

• Uplift is accounted for and settled through the PEC• Uplift is recovered from Purchasers

• It is pro-rated over monthly MWh consumption

87

Ancillary Services• Services required to maintain a stable and secure Transmission System

• HTSO procures and uses Ancillary Services and passes the costs of procurement on to Purchasers through Uplift

• Ancillary Services may be mandatory and non-mandatory

• Payments are made to Ancillary Services Providers for all non-mandatory and most mandatory services through bilateral Ancillary Services Agreements with HTSO:– Automatic Generation Control

– Operating Reserve

– Contingency Reserve

– Reactive Power

– Black Start

88

Ancillary Services• While PPC is the dominant provider, payments for Ancillary

Services will be at cost based regulated prices• In the long run, some form of competitive contracting for

Ancillary Services is envisaged• Scheduling and Dispatch

– Providers declare their availability by 12:00 day-ahead– HTSO schedules Ancillary Services providers in the day-ahead

Generation Schedule– HTSO can modify the schedule anytime up until the Dispatch Hour

• Providers may be entitled to Constrained-On/Off Payments in addition to payments made through Ancillary Services Agreements

89

Uplift

• Ancillary Services– HTSO’s payments made through Ancillary Services Agreements

are recovered via Ancillary Services sub-account

– Constrained-On/Off payments made to ancillary service providers are recovered via Constrained-On/Off payments sub-account

• HTSO Administration Charges– Allowed costs are recovered via HTSO administration charges

sub-account

– Costs may be amortised prior to allocation to Uplift sub-account

90

Uplift

• Interconnector net costs– Net costs of deviations from scheduled interconnector flows and

the subsequent offsetting or paying back of previous deviations

– Direct costs incurred in managing interconnector deviations

• Special Unit costs– Additional payments made by HTSO to qualifying renewable

generators/ co-generators. Such Units that are Participants receive:

• Special payment specified in the Law, less

• Energy Payments made under PEC

91

Special Units: Renewables/ Co-Gen

• Special Units paid A minus B in accordance with Law (in addition to SMP)• HTSO also makes payments to people who are not Participants (i.e. on the non-

Interconnected islands)– These payments are based on cost, not SMP

• Total costs are accounted for by the HTSO in a special account• These costs are spread over total load through an authorized recovery rate

– Participants: recovery through Uplift from Purchasers– Non-Participants: recovery through distribution operator

DRS/MWh

time

SMP

Price according to lawA A

B

92

Uplift

• Constrained-On/Off Payments

• Losses adjustments– Mainly net payments received by HTSO due to marginal

Transmission Loss Factors

• Energy Charges less Energy Payments

• less net costs of deviations from interconnector schedules

• Additional charges– Rounding errors

– Cost of HTSO credit facilities not due to a Person’s default

– Payment default

– Net cost of Special Participant

93

What Charges and Payments are Settled Under the PEC?

• Energy

• Uplift– Ancillary Services– HTSO administration charges– Interconnector net costs– Special Unit costs– Constrained-On Payments and Constrained-Off Payments– losses adjustments– additional charges (other items)

• Transmission– under Transmission Connection Agreements– under Transmission Use-of-System Agreements– under Transmission Control Agreement