Transcript No Slide Title

Establishment of the HTSO:
Stakeholders’ Workshop
18 October 2000
1
Introduction to the New
Industry Structure
2
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
3
Key Elements of the New Structure
The key to the new structure is the distinction created between
different sectors of the electricity industry:
• 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
4
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
5
Overview of the New Structure
Independent
Generators
(incl. Interconnected
Generators)
Independent
Generator
Renewable
Generator
PPC
Generators
H.T.S.O
Independent
Supply Co
Eligible
Customer
s
Eligible
Customer
s
PPC
Transmission
Distribution System Operator
PPC Distribution and Supply
Eligible
Customer
s
Eligible
Customer
s
Non-Eligible Customers
Electricity Flow
6
Overview of the New Structure
Independent
Generators
(incl. Interconnected
Generators)
Independent
Generator
Renewable
Generator
PPC
Generators
H.T.S.O
Independent
Supply Co
Eligible
Customer
s
Eligible
Customer
s
PPC
Transmission
Distribution System Operator
PPC Distribution and Supply
Eligible
Customer
s
Eligible
Customer
s
Non-Eligible Customers
Electricity Flow
Commercial transaction
7
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
8
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 nondiscriminatory way
9
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
10
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.
11
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
12
Key Features of the
System Trading Arrangements
13
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
14
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
Determine
Meter Quantities
Determine SMP
Calculate Settlement
Amounts
Issue Bills &
Statements
Funds
Transfer
Day-Ahead:
0:00
16:00
0:00
Dispatch:
24:00
15
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
16
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 Separated
PJM
New York
England & Wales *
Spain *
Australia
Ontario *
Greece
many others
California
New Zealand
others
ISO/ Transmission
Owner Combined
England & Wales
New Zealand *
Alliance ISO (USA) *
Midwest ISO (USA) *
Norway
others
ISO/Transmission
Owner Separated
Rest of USA
Australia
Ontario *
Spain *
South America
Greece
others
17
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 dayahead, 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
18
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
19
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
Many Prices
Single Price
Argentina
Parts of Australia *
California *
New York/ PJM
New Zealand
Mexico *
Ontario
others
England and Wales *
Spain
New England *
Greece
others
• Determination of SMP designed to be: straightforward, transparent
20
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
21
Net Settlement in
Respect of Ownership
• 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”
22
Participants
Authorized Entities
(“Persons”)
Participants
Exporters
Suppliers
Purchasers
Meter 1 .. Meter N
Other Gens
Generators
Unit 1 ... Unit N
Interface with STA
Offer 1 .. Offer N
Settlement/
Imbalance Calculation
Meter …. Meter
Reading 1 Reading N
Meter …. Meter
Reading 1 Reading N
23
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:
Supplier A
Generator A
Supplier B
Purchaser A
Generator B
Comprising:
Capacity Production Cost
(MW):
(DRS/MWh)
Unit A1
Unit A2
200
200
6,000 Load in Hour 1 (MW):
10,000 Load in Hour 2 (MW):
Purchaser B
Comprising:
Capacity Production Cost
(MW):
(DRS/MWh)
250
350
Unit B1
Unit B2
200
200
5,000 Load in Hour 1 (MW):
12,000 Load in Hour 2 (MW):
• In this example:
– a Dispatch Day only has 2 Dispatch Hours
– transmission and Uplift are ignored
24
250
350
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
A1
A2
B1
B2
MW
200
200
200
200
Offer Price
(DRS/MWh)
6,000
10,000
5,000
12,000
25
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:
Unit ID
MW
B1
A1
A2
B2
200
200
200
200
Total
800
Offer Price
(DRS/MWh)
5,000
6,000
10,000
12,000
Output
Hour 1
Output
Hour 2
200
200
100
0
200
200
200
100
500
700
SMP Hr1
SMP Hr2
(DRS/MWh) (DRS/MWh)
10,000
12,000
• 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)
26
Energy Sales and Purchases
• All energy is sold by Generators, bought by Purchasers and
settled by HTSO:
Hour 1
MW
Price
Hour 2
DRS
(000s)
MW
Price
DRS
(000s)
Total DRS
(000s)
Gen A Sells
Gen B Sells
Total Sales
300
200
500
10,000
10,000
3,000
2,000
5,000
400
300
700
12,000
12,000
4,800
3,600
8,400
7,800
5,600
13,400
Purch A Buys
Purch B Buys
Total Purchases
250
250
500
10,000
10,000
2,500
2,500
5,000
350
350
700
12,000
12,000
4,200
4,200
8,400
6,700
6,700
13,400
• In each hour: total sales = total purchases
27
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 A
Generator A Sales
less Purchaser A Purchases
Net Remittance, Supplier A
Total DRS
Supplier B
7,800 Generator B Sales
6,700 less Purchaser B Purchases
1,100 Net Remittance, Supplier B
Total DRS
5,600
6,700
(1,100)
• Supplier B was better off with an imbalance and buying
through the PEC instead of generating to meet its own load
28
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
29
Gross Settlement
in Respect of Contracts: CFDs
Price
Payments from net Generator
to net Purchaser
SMP
CFD Price
Payments from net Purchaser to net Generator
Time
30
System Operation
• Up to Real Time:
– Demand Forecast
– Generation/ Interconnector Scheduling
– generation despatch
• System Services
• Demand Control
• Emergency Measures
31
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
32
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
33
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
34
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
35
Generation Scheduling
SDC1.4 The HTSO publishes
demand forecast for next
dispatch day by 11.00
SDC1.5-1.6
Generators
send
Declarations
and Daily
Offers for next
Dispatch Day
by 12.00
SDC1.8
Exporting
Purchasers
send
Nominations
for next
Dispatch Day
by 12.00.
SDC1.10 The HTSO produces
schedule between 13.00 and
16.00 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
36
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
37
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
Revise
instruction
No
Instruction in line with
Inform HTSO
operating characteristics?
No
Accepted by
Inform HTSO-must be
for safety or
emergency reasons
Gen?
Yes
Synchronising,
desynchronising
times
Active Power
Dispatch
System
Alerts
Reactive
Power
Dispatch
System
Emergency
Conditions
Operating
Mode
Dispatch
38
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
39
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
40
Review of Other Codes and
Agreements
41
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
42
Summary of the
Key Codes and Agreements
E U Directive
Greek Electricity Law
HTSO
Authorisation
Transmission
Control
Agreement
Connection
Agreements
Transmission
Authorisation
Distribution
Authorisation
Supply
Authorisation
Use of
System
Agreements
Generation
Authorisation
Operating
Code
Power
Exchange
Code
Ancillary
Services
Agreements
43
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
44
The Operating Code
45
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
46
Hierarchy of Documents
Legislation
Authorisations
Operating
Code
Power
Exchange
Code
Ancillary
Services
Agreements
Other
documentation
Standards
Policies
Procedures
Safety
Rules
Transmission
Planning
Criteria
Operating Code
Compliance
Test
UCTE
Standards
Reserve Policy
Power System
Restoration
Procedure
Greek
Standards
47
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
48
Operating Code:Contents
•
•
•
•
•
General Conditions
Connection Conditions
Planning Code
Operating Codes (13 no.)
Scheduling & Despatch Codes (3 no.)
49
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
50
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
51
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
52
Operating Codes : OC1 to OC4
•
•
•
•
OC1
OC2
OC3
OC4
Safety Co-ordination
Information Exchange
Metering Code
Demand Forecasts
53
Operating Codes: OC5 to OC8
•
•
•
•
OC5
OC6
OC7
OC8
Demand Control
System Services
Interconnector Management
Generator Maintenance Scheduling
54
Operating Codes: OC9 to OC13
•
•
•
•
OC9
OC10
OC11
OC12
• OC13
Transmission Maintenance Scheduling
Monitoring, Testing and Investigation
Operational Testing
Emergency Control and Power System
Restoration
Small Scale Generator Conditions
55
Scheduling & Despatch Codes:
SDC1 to SDC3
• SDC1
• SDC2
• SDC3
Generation Scheduling
Generation Despatching
Special Scheduling Provisions
56
Agreements
57
The Transmission Control
Agreement (TCA)
• Main points of the TCA are:
Type of Document
Commercial agreement, subject to regulation.
Objective
To govern the relationship between the transmission owner
and the HTSO, so as to ensure that the HTSO is able
effectively to control the operation and development of the
inter-connected system.
The “Parties”
1. the HTSO
2. the transmission owner (PPC’s TBU)
Coverage
Operation of the system, maintenance and performance
standards, new connections, procedure for system
development, and fees.
• 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
58
The Connection Agreement
• Main points of the Connection Agreement are:
Type of Document
Commercial Agreement, at regulated terms.
Objective
To ensure that the connection is properly provided,
maintained, modified, etc, at terms that are effieicent and fair
to the connected parties.
The “Parties”
This is proposed to be a three-party agreement:
1. the HTSO
2. the transmission owner
3. the connected party.
Coverage
Construction, maintenance, modifications, and fees.
• A key feature is that if it is a tri-partite document; it will
ensure that all three parties involved are tied adequately
together
59
Transmission Use of System
Agreement
• Main points of the Use of System Agreement are:
Type of Document
Commercial Agreement, at regulated terms.
Objective
To regulate the terms and charges for use of the system.
The “Parties”
1. the HTSO
2. the Users (either a generator or a supplier)
Coverage
Standard terms, including fees as determined by the
regulatory authorities.
• 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
60
Ancillary Services Agreement
• Ancillary services are needed to ensure a stable and reliable power
system
• Main points of the agreement are:
Type of Document
Commercial Agreement
Objective
Provision of all necessary system support services
The “Parties”
1.
the HTSO
2.
generators, and other providers such as interruptible load.
Coverage
Would deal with the definition, scheduling and payment for the
following services:
1.
AGC
2.
Reserve
3.
Reactive Power
4.
Black Start
• 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 61
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:
Type of Document
Regulatory Instrument
Objective
To ensure effective control of entry to the industry and
regulation of behaviour of participants.
The “Parties”
Issued by Ministry of Development/RAE.
To be held by:
1. the HTSO
2. the Transmission Owner
3. the Distribution Owner
4. all Generators, except for smaller exemptions
5. all Suppliers, except for some possible exemptions.
•
Authorisation Regulations will be issued by RAE, governing procedures for
Authorisations
62
Elaboration of the
Power Exchange Code
63
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
64
General Provisions
•
•
•
•
•
•
•
Persons and Participants
Termination
Arbitration
Confidentiality
Type of security
Renewal of security
Breach of security provisions
65
Schedule B
• Schedule B is the core of the PEC - it specifies the ways in
which Participants buy and sell imbalance energy:
B.I.
B.II.
B.III.
B.IV.
B.V.
B.VI.
B.VII.
B.VIII.
B.IX.
B.X.
Conventions
Responsibility for Energy Metering
Other Registration Information and HTSO Responsibilities
Offer, Load and Price Forecasting, Scheduling and Dispatch
Special Provisions Relating to International Trade
HTSO Settlement Responsibilties
Settlement Timelines
Settlement Variables
Determination of Loss Factors
Determination of Meter Quantities
66
Schedule B
B.XI.
B.XII.
B.XIII.
B.XIV.
B.XV.
B.XVI.
B.XVII.
B.XVIII.
B.XIX.
B.XX.
B.XXI.
B.XXII.
B.XXIII.
Determination of Day-Ahead Quantities
Determination of System Marginal Prices
Determination of Energy Charges and Energy Payments
Determination of Constrained-On and Off Payments
Ancillary Services
Other Charges and Payments
Determination of Uplift Charges
Settlement of Transmission Charges
Settlement Statements
Invoices
Compliance
Suspension Procedures
Information Management
67
Other Schedules
• Schedule A: Definitions
• Schedule C: Form of Address and Contact Details
• Schedule D: Security Cover
68
Summary of Timelines
Determine
Meter Quantities
Determine SMP
Calculate Settlement
Amounts
Issue Bills &
Statements
Day-Ahead:
HTSO sends out Day-Ahead
Schedules to generators and
Publishes SMPs
0:00
20:00
Day-Ahead
Funds
Transfer
Dispatch:
Each Dispatch Hour
(24 Dispatch Hours
in a Dispatch Day)
0:00
24:00
Dispatch Day
After the Dispatch Day
69
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
0:00
HTSO publishes load
forecasts
11:00 12:00 13:00
Deadline for submission of Offers into
Day-Ahead Schedule
Last time an invalid Offer can
be re-submitted
HTSO calculates the schedules for
the following Dispatch Day
HTSO calculates the forecast SMPs
HTSO publishes forecast SMPs
and sends out schedules to Participants
16:00
24:00
70
Operational Timeline: Dispatch Day
•
•
The dispatch is a full re-optimization (least-cost, security-constrained)
• Does take account of:
Doesn’t take account of:
– Energy contracts of participants
– Day-ahead forecast
•
–
–
–
–
Offers (Offers can’t change from day-ahead)
Full capacity of Units
Transmission constraints
Actual load and all other constraints
Dispatch Instructions are issued by the HTSO to Units
–
–
–
–
0:00
Synchronization
Base Point Instructions
Reserve Activation
Other Instructions
D-hour - 2 hours
HTSO begins determination of hourly schedule
HTSO determines
hourly schedule
A Dispatch Hour
D-hour
Time horizon of hourly
schedule
24:00
71
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 issues
Base-Point
Instructions
HTSO issues
other Dispatch
Instructions
0:05
0:10
0:15
0:20 0:25
0:30 0:35
0:40
0:45
0:50
0:55
End of
D-Hour
Start of
D-Hour
Dispatch Instructions for
the Dispatch Hour
72
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)
73
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
Meter Data Sent
Dispatch Day
End of DDay + 1
End of DDay + 2
Calculation Day
End of DDay + 3
End of DDay + 4
End of DDay + 5
74
Price (DRS/MW)
Calculation of SMP
Demand
Supply
SMP
Gen 2
Gen 1
100 100 100 100 100 100 100 100 100 100 100 100 100 100
MW MW MW MW MW MW MW MW MW MW MW MW MW MW
Quantity (MW)
75
PL
SMP (High Demand)
High Demand
SMP (Low Demand)
Low Demand
100 100 100 100 100 100 100 100 100 100 100 100 100 100
MW MW MW MW MW MW MW MW MW MW MW MW MW MW
Gen 2
PH
Gen 1
Price (DRS/MW)
Calculation of SMP
Quantity (MW)
76
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
77
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
78
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
79
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
80
Illustrative Diagram
Offer Price Function of a Unit
Step 3
Step 2
Step 1
DRS/MWh
MW
Minimum Dispatch Capability
(MNDC)
Maximum Dispatch Capability
(MXDC)
81
Constrained-Off Payments
DRS/MWh
SMP
Step 3
Step 2
Step 1
PEC/64
MW
Meter Quantity
(MQ)
82
Constrained-On Payments
DRS/MWh
Step 2
Step 1
SMP
Step 3
PEC/B67
MW
Minimum Dispatch Capability
(MNDC)
Meter Quantity
(MQ)
83
How are Settlement Quantities
Calculated?
Metering Data
Settlement Quality
Metering Data
Meter Quantities
Distribution Loss
Factors
Day-Ahead
Quantities
Transmission Loss
Factors
Settlement Quantities
84
Para 58
Accounting for Energy Sales and Purchases
Para 55
Energy Payments
(and Settlement Quantities for Gens)
Para 56
Energy Charges
(and Settlement Quantities for Purch's)
Para 42
Determination of Meter Quantities
Para 45
Determination of Day-Ahead Quantities
Para 41
Determination of SettlementQuality Metering Data
Operating Code
Section XI
Section X
Section XIII
Settlement Quantities
Section II
Para 43
Netting of Settlement Quality
Meter Data
Para 6
Interrogation of Meters (et al)
Other provisions of Section II
and Operating Code
85
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
86
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 nonmandatory and most mandatory services through bilateral
Ancillary Services Agreements with HTSO:
–
–
–
–
–
Automatic Generation Control
Operating Reserve
Contingency Reserve
Reactive Power
Black Start
87
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
88
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 subaccount
– Costs may be amortised prior to allocation to Uplift sub-account
89
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
90
Special Units: Renewables/ Co-Gen
DRS/MWh
B
Price according to law
SMP
A
A
time
• 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
91
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
92
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
93