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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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