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1 Establishment of the HTSO: Stakeholders’ Workshop 18 October 2000.

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Presentation on theme: "1 Establishment of the HTSO: Stakeholders’ Workshop 18 October 2000."— Presentation transcript:

1 1 Establishment of the HTSO: Stakeholders’ Workshop 18 October 2000

2 2 Introduction to the New Industry Structure

3 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 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 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 6 Overview of the New Structure Independent Generator H.T.S.O PPC Transmission PPC Transmission PPC Generators PPC Generators Distribution System Operator PPC Distribution and Supply Eligible Customer s Independent Generators (incl. Inter- connected Generators) Independent Supply Co Non-Eligible Customers Electricity Flow Renewable Generator

7 7 Overview of the New Structure Independent Generator H.T.S.O PPC Transmission PPC Transmission PPC Generators PPC Generators Distribution System Operator PPC Distribution and Supply Eligible Customer s Independent Generators (incl. Inter- connected Generators) Independent Supply Co Non-Eligible Customers Electricity Flow Commercial transaction Renewable Generator

8 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 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 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 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 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 13 Key Features of the System Trading Arrangements

14 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 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: 16:00 0:00 24:00 Determine Meter Quantities Determine SMP Calculate Settlement Amounts Issue Bills & Statements Funds Transfer

16 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 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

18 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 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 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

21 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 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 23 Participants Suppliers Other Gens Exporters PurchasersGenerators Authorized Entities (“Persons”) Unit 1Unit N...Meter 1Meter N.. Offer 1Offer N.. Settlement/ Imbalance Calculation Meter Reading 1 Meter Reading N ….Meter Reading 1 Meter Reading N …. Interface with STA Participants

24 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

25 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:

26 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)

27 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

28 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, *12,000) –Supplier B is charged DRS 1,100,000 (50*10, *12,000) Supplier B was better off with an imbalance and buying through the PEC instead of generating to meet its own load

29 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 30 Price Time Payments from net Purchaser to net Generator Payments from net Generator to net Purchaser CFD Price SMP Gross Settlement in Respect of Contracts: CFDs

31 31 System Operation Up to Real Time: –Demand Forecast –Generation/ Interconnector Scheduling –generation despatch System Services Demand Control Emergency Measures

32 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 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 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 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 36 Generation Scheduling SDC1.4 The HTSO publishes demand forecast for next dispatch day by SDC Generators send Declarations and Daily Offers for next Dispatch Day by SDC1.8 Exporting Purchasers send Nominations for next Dispatch Day by SDC1.10 The HTSO produces schedule between and for next dispatch day SDC1.10 The HTSO issues provisional running orders and publishes forecast system marginal price for each dispatch hour of next dispatch day

37 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 38 SDC2 Summary The 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 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 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 41 Review of Other Codes and Agreements

42 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 43 Summary of the Key Codes and Agreements E U Directive Greek Electricity Law HTSO Authorisation HTSO Authorisation Transmission Control Agreement Transmission Authorisation Distribution Authorisation Generation Authorisation Supply Authorisation Power Exchange Code Connection Agreements Use of System Agreements Ancillary Services Agreements Ancillary Services Agreements Operating Code

44 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 45 The Operating Code

46 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 47 Hierarchy of Documents Safety Rules UCTE Standards Greek Standards Transmission Planning Criteria Reserve Policy Policies Operating Code Compliance Test Power System Restoration Procedure Procedures Other documentation Operating Code Authorisations Legislation Ancillary Services Agreements Power Exchange Code

48 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 49 Operating Code:Contents General Conditions Connection Conditions Planning Code Operating Codes (13 no.) Scheduling & Despatch Codes (3 no.)

50 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 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 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 53 Operating Codes : OC1 to OC4 OC1Safety Co-ordination OC2Information Exchange OC3Metering Code OC4Demand Forecasts

54 54 Operating Codes: OC5 to OC8 OC5Demand Control OC6System Services OC7Interconnector Management OC8Generator Maintenance Scheduling

55 55 Operating Codes: OC9 to OC13 OC9Transmission Maintenance Scheduling OC10Monitoring, Testing and Investigation OC11Operational Testing OC12Emergency Control and Power System Restoration OC13Small Scale Generator Conditions

56 56 Scheduling & Despatch Codes: SDC1 to SDC3 SDC1Generation Scheduling SDC2Generation Despatching SDC3Special Scheduling Provisions

57 57 Agreements

58 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 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 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 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 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 63 Elaboration of the Power Exchange Code

64 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 65 General Provisions Persons and Participants Termination Arbitration Confidentiality Type of security Renewal of security Breach of security provisions

66 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 67 Schedule B B.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 68 Other Schedules Schedule A: Definitions Schedule C: Form of Address and Contact Details Schedule D: Security Cover

69 69 Summary of Timelines

70 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

71 71 Operational Timeline: Dispatch Day 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 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

73 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 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 75 Calculation of SMP Supply Demand SMP Price (DRS/MW) Quantity (MW) Gen 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 76 Calculation of SMP Price (DRS/MW) Quantity (MW) Gen 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 PLPL SMP (High Demand) High Demand SMP (Low Demand) PHPH

77 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 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 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 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 81 Step 3 Step 2 Step 1 Maximum Dispatch Capability (MXDC) Minimum Dispatch Capability (MNDC) DRS/MWh MW Offer Price Function of a Unit Illustrative Diagram

82 82 Step 3 Step 2 Step 1 Meter Quantity (MQ) DRS/MWh MW SMP PEC/64 Constrained-Off Payments

83 83 Step 2 Step 3 Step 1 Minimum Dispatch Capability (MNDC) DRS/MWh MW SMP PEC/B67 Meter Quantity (MQ) Constrained-On Payments

84 84 How are Settlement Quantities Calculated? Metering Data Settlement Quality Metering Data Meter Quantities Day-Ahead Quantities Transmission Loss Factors Settlement Quantities Distribution Loss Factors

85 85 Settlement Quantities Section XIII Section X Section II Section XI

86 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 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 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 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 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 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 law A A B

92 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 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


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