Pricing and Scheduling Fact Sheet
1. What is Pricing & Scheduling?
2. How does the market run each day?
3. What are EA, EP1, and EP2?
4. What is SMP?
5. How is SMP calculated?
6. What is Uplift?
7. What is the Shadow Price?
8. What is COD & TOD?
9. How do I submit bids to the SEM?
10. What do I do if my bids are wrong?
11. How do I put a unit under test in the market?
12. How do I extend or decrease unit under test end date?
13. What is an LCF?
14. What is a GCF?
15. What is a GSF?
16. What are the timelines for gate closure?
17. What are the timelines for report publication?
18. How does fuel type affect Generator bids?
19. How are productions costs calculated?
20. When is pumped storage used?
21. When is the interconnector used?
22. When is LR/MIP used?
23. What is PCAP?
24. What is PFLOOR?
The Single Electricity Market(SEM) is a mandatory gross pool. In a given trading period the price per MWH applicable to the purchase of electricity from the pool is equal to the price per MWH applicable to the sale of energy into the pool. This price is known as the system marginal price (SMP) and pricing and scheduling is effectively the process whereby the market operator produces a schedule of half hourly SMPs and market schedule quantities for each unit for a trading day.
Only price making generator units (which are not under test) are represented individually within the MSP software. Non-price making units are scheduled either based on submitted nominations or forecast data in the case of wind units. Once the load met by generation from non-price making units has been removed then price making generator units are scheduled in merit order according to their bids to meet the remaining load.
The MSP software is used to determine what dispatch of units will meet the remaining load requirement with the lowest production costs (whilst also ensuring that each unit is scheduled within its technical capabilities as detailed in their TOD data). In doing this a series of half hourly MW generation values is produced for each generator unit. A series of half hourly system marginal prices which are applicable to all generation and supply during the half hour trading period for which they apply is also produced for the trading day being scheduled.
Three Pricing & Scheduling runs are carried out each day (see ‘What are EA, EP1, and EP2?’) where interconnector nominations are determined and fixed one day ahead of trade date during the EA or Ex-Ante run and system marginal prices as well as market schedule quantities determined during the Ex-Post initial or EP2 run are used for invoicing for the energy market.
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Introduction
The SEM is a gross mandatory pool. Under the pool arrangements the sale and purchase of electricity occurs on a gross basis with all generators paying/suppliers receiving the same price for electricity sold into bought via the pool in a given trading period. Below is a brief overview of how the market runs from initial Commercial Offer Data and Technical Offer Data submissions by participants commencing up to 29 days before trade date until publishing of the Ex Post initial schedule four days after trade date.
1) Before the Trading day
i) Before D-1
• From D-29: Commercial Offer Data and Technical Offer Data for the relevant trading day can be submitted from this point onwards by participants in respect of their generator units.
• 10:00 D-2: the Market Operator(MO) must publish the available transfer capacity (import and export) for each Interconnector.
ii) D-1
• 08:00 D-1: Daily Trading Day Exchange Rate published by MO.
• 10:00 D-1: Commercial Offer Data and Technical Offer Data for the relevant Trading Day must be submitted by this point by Participants in respect of their GeneratorUnits.
• 10:00 D-1: the Interconnector Administrator provides Active Interconnector Unit Capacity Holdings Data to the MO.
• 11:00 D-1: the MO carries out the Ex-Ante Indicative MSP Software Run.
• 11:00 D-1: based on the output of the Ex-Ante Indicative MSP Software Run, the MO supplies Interconnector Unit Nominations to the Interconnector Administrator.
• 12:00 D-1: the Interconnector Administrator provides Modified Interconnector Unit Nominations to the MO.
• 12:00 D-1: the MO issues Modified Interconnector Unit Nominations individually to each Interconnector User.
• 12:00 D-1: the MO issues Aggregated Modified Interconnector Unit Nominations to the System Operator (SO).
• 13:00 D-1: based on the output of the Ex-Ante Indicative MSP Software Run, the MO publishes indicative SMP values.
• 13:00 D-1: based on the output of the Ex-Ante Indicative MSP Software Run, the MO issues Participant specific details of the Ex-Ante Indicative Market Schedule (i.e.MSQ values for Price Maker Generator Units) to each Participant.
• 13:00 D-1: based on the output of the Ex-Ante Indicative MSP Software Run, the MO publishes an Ex-Ante Market Schedule Summary.
• 16:00 D-1: Ex-Ante Indicative Operations Schedule produced by SO and published by MO.
2) During the Trading Day
• Dispatch Instructions are issued by the SOs to Generator Units in real time.
3) After the Trading Day
i) D+1
• 16:00 D+1: the MO carries out the Ex-Post Indicative MSP Software Run.
• 16:00 D+1: Daily Ex-Post Indicative Market Schedule Summary published by MO.
• 17:00 D+1: Ex-Post Indicative Market Schedule by Participant issued by MO.
ii) D+4
• 16:00 D+4: the MO carries out the Initial MSP Software Run.
• 16:00 D+4: Daily Initial Market Schedule Summary published by MO.
• 17:00 D+4: Initial Market Schedule by Participant issued by MO.
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EA, EP1 and EP2 refer to the three Market Scheduling and Pricing runs which are performed each day.
The EA or Ex Ante run is carried out one day prior to the trade date which is being scheduled and as such uses entirely forecast wind and load data. A schedule of half hourly SMPs and MW generation is produced for the 30 hour period running from 06:00 am the next day until 12:00 noon the following day (see ‘What is Pricing and Scheduling?’).
The Ex Ante run is performed by the Market Operator by 11:00 D-1 (i.e. one hour after gate closure for the relevant trading day) the interconnector user nominations (IUNs) are determined during the Ex Ante run. Modified interconnector user nominations (MIUNs) are then calculated so that the MIUNs, when considered in aggregate across any interconnector, are consistent with the interconnector technical data for that interconnector. MIUNs are then submitted to each interconnector user in respect of its interconnector units by 12:00 on the day prior to the start of the trading day. The MIUNs determined from the Ex Ante run are fixed and are used as inputs for the Ex Post indicative/initial rather than being re-scheduled.
The EP1 or Ex Post Indicative run is carried out one day after trade date which is being scheduled. As the convention in the market is to operate on a trading day basis which runs from 06:00am to 06:00am whereas our data providers collect data on a calendar day basis the schedule produced from the EP1 run consists of 18 hours of actual wind and load data and 6 hours of forecast data for the 24 hour trading day/ 12 hours of forecast data for the 30 hour optimisation horizon. Neither the EA nor the EP1 schedule of prices are used for invoicing however indicative settlement statements calculated using EP1 SMP values are published.
The EP2 or Ex Post Initial run is carried out four days after the trade date which is being scheduled and as such is able to utilize full sets of actual wind and load data with no forecast values. The system marginal prices (see ‘How is SMP calculated?’) produced in the EP2 run are used to produce initial statements which are published and are also the prices used for weekly invoicing, the SMP determined in the EP2 run for a given half hour trading period is the price applicable to both generators and suppliers receiving/making payments for electricity generated/used in such a trading period.
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This is the System Marginal Price (SMP)
SMP = Shadow Price + Uplift
The SMP is a single island-wide price for each half hour Trading Period. Under the Gross Pool arrangements for Ireland, all Generator Units receive and all
Supplier Units pay the same energy component of price in a Trading Period for electricity i.e. the System Marginal Price (SMP). The SMP is determined via the Market Scheduling and Pricing (MSP) Software for each half hour Trading Period, which is run by the Market Operator.
When the MSP Software calculates the SMP in each Trading Period it calculates:
the cost of the marginal MW required to meet demand in a Trading Period within the context of an unconstrained schedule – this is the Shadow Price component. A generator unit that can increase its generation in order to meet demand is considered to be marginal
operating costs associated with Start Up Costs and No Load Costs that a generator will need to recover – this is the Uplift component.
Thus the resultant formula for the derivation of SMP in a Trading Period is:
SMP = Shadow Price + Uplift
SMP is bounded by a Market Price Cap and a Market Price Floor, which are set by the
Regulatory Authorities. The SMP cannot go beyond these limits and the MSP software will not calculate an SMP beyond these.
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SMP = Shadow Price + Uplift
Please see Trading & Settlement Code (Appendix N)
When the MSP(Market Scheduling & Pricing) Software calculates the SMP and the MSQ (Market Schedule Quantity) it assumes that there are no unconstrained schedules that may occur in reality – these are used during the scheduling planning by the Transmission System Operators. The MSP Software considers all Price Maker Generator Units that are not Under Test (i.e. are operator as normal) for each Trading Period and calculates the SMP as follows:
1. Determine the Unit Commitment Schedule for each Trading Period in the Optimisation Time Horizon (30 hour period), which denotes whether or not each Price Maker Generator Unit that is not Under Test will be scheduled to run. The Optimisation Time Horizon begins at 6am on a trading date and ends at midday of the following trading date.
2. Based on the Unit Commitment Schedule, determine the Shadow Price (see ‘What is the Shadow Price’) values and the MSQ values for each Price Maker Generator Unit that is not Under Test for each Trading Period in the Optimisation Time Horizon.
3. Calculate Uplift (see ‘What is Uplift’) for each Trading Period in the Optimisation Time Horizon.
4. Calculate SMP for each Trading Period in the Trading Day based on the Shadow Price values plus the Uplift values, within the bounds of the Market Price Floor and the Market Price Cap.
In determining Unit Commitment Schedules and MSQ values, the high-level objective of the MSP Software is to minimise the sum of MSP Production Costs (see ‘How are production costs calculated?’) (being the production costs of each Price Maker Generator Unit that is not Under Test which is scheduled to run) subject to the following constraints:
1. to schedule output by Price Maker Generator Units that are not Under Test to meet demand; and
2. to schedule each Price Maker Generator Unit that is not Under Test within its capacities and technical capabilities.
When calculating Uplift, the high-level objective of the MSP Software is to reflect the
marginal cost of producing or consuming electricity during the Optimisation Time Horizon such that:
1. energy prices should be reflective of underlying market dynamics such that the recovery of Start Up and No Load Costs through SMP should not deviate significantly from the Shadow Prices; and
2. revenue paid through Uplift revenues should be minimised.
I n this graph P1 – P5 are bids in submitted by generators. In this case P5 sets the SMP as this generator is supplying the last MW in order to meet demand and is marginal (i.e. capable of supplying the next MW)
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SMP is set at a level that is sufficient for participants to recover full costs of production. The Uplift element of the SMP pertains to the recovery by Generator Units of their production costs.
Uplift consists of start up costs and no load costs. Start Up Cost represents the cost of starting up the Unit which may be in a cold, warm or hot state. No Load Cost represents the cost of running the Unit at 0MW
See ‘What is SMP?’
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Shadow Prices form the basis of the SMP calculation for each half hour trading period. However, paying for generation at shadow prices will mean that Generator Units will not recover the full costs of production as the Shadow Price does not reflect the start up and no load costs of the Generator Unit.
The shadow price only reflects the cost of supplying an infinitesimal change in demand. As a result, situations can arise where Units do not recover their “full” costs over a continuous period of running.
As a result, there is a further process undertaken to determine System
Marginal Prices (SMPs):
- SMP takes into account No Load and Start Up Costs
- SMP ensures that all Units running will at least meet their costs ofrunning (Price Quantity pairs, Start Up and No Load) across the Trading Day
See ‘What is SMP?’
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COD is Commercial Offer Data submitted by participants and includes:
- Price Quantity Pairs: Incremental price/quantity pairs for generation and demand side unit bids. For generators these values provide a measure of incremental running costs and are net of unit load (i.e. net of “load behind the meter”). These values are net of unit load.
- No-Load Cost: Fixed cost per Trading Period involved in running a generation unit at zero net output. These are not applied to demand side units.
- Nomination Profile: Non-price sensitive generation offer which is a declaration of intended output level for each Trading Period.
Decremental Profile: Decremental price within trading period.
- The quantity aspect of the COD should refer to the Connection Point (The physical point where the Party’s Generator Unit or a constituent of a Supplier Unit as applicable is joined to the Transmission System or the Distribution System as appropriate). (explain).
- Each time a unit goes under test COD must be submitted.
- COD gate closes at 10.00 D-1
- Gate is open 28 days in advance of the trade day
- Standing data must be submitted – to provide cover in the instance that bids are not submitted on time
Participants submit their COD via the Market Participant Interface (MPI) as follows:
Open your Internet Browser and login to the MPI here: https://market.allislandmarket.com/mi_webapps/
- Select Registration in the Main Menu dropdown box:
- Select organisation name\
- Navigate to Facilities Tab\
- Choose unit\The COD screen will appear as below
COD screen:
Technical Offer Data
Data submitted by a market participant that describes the technical capabilities and limits of generators and demand side units.
- Participants submit request to change primary data set with alternative data set.
- This is reviewed by Market Operator.
- Enter Data through the MPI and gate is open 28 days in advance of the trade day
- See list of TOD fields that can be changed.
- Participants shall not submit Commercial Offer Data or Technical Offer Data in respect of any Interconnector Residual Capacity Unit.
- TOD gate closes at 09.50 D-1
- Standing data must be submitted – to provide cover in the instance that bids are not submitted on time
Log into the Market Participant Interface (MPI) https://market.allislandmarket.com/mi_webapps/
Go to Registration Tab and select MP List\ Facilities\ Choose unit\
Scroll down to
General TOD screen:
List of TOD fields:
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Participants submit their bids to the market via the Market Participant Interface (MPI).
- Login to MPI
- Select Trading from the Main Menu Drop down
- Ensure the your digital certificate is selected and password entered
Bids are entered differently depending on the resource type of the generator.
For resource type: Variable Price Taker Generator, Predictable Price Taker Generator or Unit Under Test, the following screen will appear:
Go to Main menu Tab and select trading
In the Sub Menu, select:
- Activity: Energy market
- Data Type: Generation Offers
- Select Trade Date.
- Enter External ID (If applicable).
- Click the REFRESH LIST button.
- Select a resource from Select Resource drop down menu.
- Expand Forecast Details section and enter the Avail Profile details
- Expand Price Taker Details section and enter Nomination and Decremental prices.
For resource type: Variable Price Taker, Predictable Price Maker Generator or Unit Under Test, the following screen will appear:
Go to Main menu Tab and select trading
In the Sub Menu, select:
9. Activity: Energy market
10. Data Type: Generation Offers
11. Select Trade Date.
12. Enter External ID (If applicable).
13. Click the REFRESH LIST button.
14. Select a resource from Select Resource drop down menu.
15. Expand Forecast Details section and enter the Avail Profile details
16. Expand Price Maker Details section and enter Start Up cost, No load Cost and Price Quantity Curve.
The commercial offer data(COD) should be entered as follows:
Price Quantity Pairs:
A total of 10 Price Quantity Pairs can be submitted, please ensure these Prices and Quantities shall each be strictly monotonically increasing.
No Load Cost:
- Cost of running at 0 MW
- Submitted in £/€ per hour
Start Up Costs:
- At least 1 field must be entered, up to 3 allowed
- Cost of starting up in hot, warm and cold states
- Will be in £ or €
Nomination Profile:
One Nomination Profile(MW) for each interval range i.e. Start Hour, Start Int, End Hour and End Int (1:1 -24:2)
Decremental Profile:
One Decremental Price (€) for each interval range i.e. Start Hour, Start Int, End Hour and End Int (1:1 -24:2)
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- Please ensure these Prices and Quantities are strictly monotonically increasing (i.e are in increasing order)
- If bids are not submitted in this fashion, a error message will occur not allowing you to proceed.
- You must go back and start from the beginning.
- After submitting bids please run market query to ensure all bids entered have successfully completed.
- If you are having a problem please contact SEMO – Markethelpdesk@sem-o.com
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To put a unit under test in the market participants must:
Discuss with the Transmission System Operator (TSO) your intentions to put unit under test.
Submit Nomination profile to TSO and enter the request in the Market Participant Interface(MPI) as follows
Location in MPI:
Log into the Market Participant Interface here (https://market.allislandmarket.com/mi_webapps/) using digital certificate and password
Select Registration and pick organisation name\ Navigate to Facilities Tab\ Choose Facility Name (resource unit)\
Enter Data:
- Effective Date
- Start Date
- End Date
Press Submit
Submit start date and end dates relating to the trading days the unit will be under test.
For example if the unit is going under test from the 06th to the 15th, the unit will be under test from 6am on the 06th until 5.59am on the 16th.
If the test is for 1 day only, Test Start Date = Test End Date.
Ex Ante pricing schedule is run ONE DAY BEFORE the TRADE DATE.
Effective Date should be D-2.
Process:
Market participates must submit request through MPI, giving five working days notice.
SEMO controller will accept or reject request in MPI at D-4.
The under test flag will appear in market systems at 6am the day AFTER it has been accepted.
When a unit is under test – a nomination profile must be submitted - as the unit is treated as a price taker. Nomination profiles cannot be submitted, until the under test flag is active.
If bids/offer COD is submitted for the trade dates when the unit is under test, it will be rejected.
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Changes to Unit under test dates must be requested via the MPI and must meet the following criteria:
- Request must be submitted D-2 from test end date as per the trade and settlement code.
- The end date and effective date is required to be equal.
- The Ex-Ante for the prior date must be completed before new request is accepted.
- The TSO must approve any changes.
Participants enter change requests as follows:
Log into the Market Participant Interface here (https://market.allislandmarket.com/mi_webapps/) using digital certificate and password
Registration Tab and pick organisation name\ Navigate to Facilities Tab\ Choose Facility Name (resource unit)\
Enter Data:
o Effective Date
o Start Date
o End Date
Press Submit
Examples:
Extending End Date
Original Request: New Request: Extend to 20/02/10
Effective Date: 04/02/10 Effective Date: 16/02/10
Start Date: 06/02/10 Start Date: 16/02/10
End Date: 15/02/10 End Date:20/02/10
Can only be accepted in SEMO market system after Ex-Ante for Trade Date 15/02/10 has been completed.
Reducing End Date
Original Request: New Request: Reduce to 10/02/10
Effective Date: 04/02/10 Effective Date:1002/10
Start Date: 06/02/10 Start Date:1002/10
End Date: 15/02/10 End Date:10/02/10
Can only be accepted in SEMO market system after Ex-Ante for Trade Date 09/02/10 has been completed.
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Limited Communication Failure occurs when a participant’s (but not all participants’) system cannot communicate with the Market Operator system. This results in the participant’s inability to submit their required data e.g. they can’t submit commercial offer data.
If a participant cannot re-establish communication to the market operator system the participant will follow the Limited Communication Failure (LCF) process as per the latest version of Agreed Procedure 7 "Emergency Communication" - which can be found at http://www.sem-o.com/MarketDevelopment/Pages/MarketRules.aspx .
The entire LCF form must be completed and faxed to the Market operator as early as possible before 10 am (day ahead market gate closure) on the day prior to the trade date to which the data relates to. For example bids and offers for trade date 18/05/2010 MUST be received by the market operator before 10 am on 17/05/2010. If any data is received after the closure of the gate, this data will not be processed, and default (standing) data will be utilised automatically.
The LCF forms are in the Emergency communication pack, which can be found here: http://www.sem-o.com/Publications/MarketParameters/Emergency Communications Pack.zip. There are separate forms for different types of data transaction:
1) Commercial offer data (COD) for generator units
2) Commercial offer data (COD) for interconnector units
3) Technical offer data (TOD)
4) Settlement reallocation agreements
The participant must print out the official LCF form and Manually enters the bids on the form. It is imperative that the relevant form is fully completed and is legible. It must contain the username and password of an authorised person otherwise the LCF form will be rejected. The password must match the password supplied to SEMO by an authorised Person (link to Query management factsheet). The LCF form must be sent to the LCF fax number: +353 1 2370035 before 10:00 AM and followed up with a phone call on the operations hotline: +353 87 226 7856.
If no LCF form with valid password is received before gate closure, then standing bids will be used. For this reason it is very important than all participants have standing bids entered for each of their generators.
A flowchart of the LCF process is shown below:
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General Communication Failure (GCF) occurs when the normal communication interfaces between the market operator and all participants are unavailable. This results in the inability of all participants to submit their required data e.g. they can’t submit commercial offer data.
GCF Procedure
1) The market operator will notify all parties using Part 1 of the Emergency Communication Form from the Emergency Communication Pack; http://www.sem-o.com/Publications/MarketParameters/Emergency Communications Pack.zip. A market message will also be sent via email by the market operator to all parties informing them of the GCF.
2) All impacted parties will then acknowledge receipt of the GCF notification by completing Part 2 of the Emergency Communication Form and faxing it back to the market operator, Fax number: +353 1 2370035.
3) The market operator will complete Part B of the Transaction Notification Form Form from the Emergency Communication Pack (http://www.sem-o.com/Publications/MarketParameters/Emergency Communications Pack.zip) and fax it to all parties. Indicating the Alternative Communication Method.
4) All parties will then switch to the alternative communication method upon recipt of the Transaction Notification form.
5) The Market Operator will give a best estimate of when normal communication channels will return using Part 3 of the Emergency Communication Form.
6) When the GCF has been resolved the Market Operator will inform all parties using Part 4 of the Emergency Communication Form. A market message will also be sent by email to all parties from the market operator to this affect.
A more detailed step by step procedure can be found in Agreed Procedure 7 "Emergency Communication" – located here http://www.sem-o.com/MarketDevelopment/Pages/MarketRules.aspx
A flowchart of the GCF/GSF process is shown below:
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A General System Failure (GSF) occurs when the Market Operator’s isolated market system is not fully functional. This results in the market operators inability to meet it’s publication deadline requirements under the trading and settlement code. For example it would not be possible for the market operator to calculate and publish the system marginal price for a given trade date.
GSF Procedure
1) The Market Operator(MO) will Complete Part 1 of the Emergency Communication Form and notify impacted Parties of the General System Failure and list which of the following deadlines have been missed or are about to be missed e.g. calculation or publication of System Marginal Price.
2) The MO will inform market participants whether or not Administered settlement has been invoked.
3) All impacted parties will then acknowledge receipt of the GSF notification by completing Part 2 of the Emergency Communication Form (Emergency Communication Pack; http://www.sem-o.com/Publications/MarketParameters/Emergency Communications Pack.zip) and faxing it back to the market operator, Fax number: +353 1 2370035.
4) The MO will complete Part B of the Transaction Notification Form Form from the Emergency Communication Pack (http://www.sem-o.com/Publications/MarketParameters/Emergency Communications Pack.zip) and fax it to all parties. Indicating the Alternative Communication Method.
5) All parties will then switch to the alternative communication method upon recipt of the Transaction Notification form.
6) The MO will give a best estimate of when the market operator isolated system will become available using Part 3 of the Emergency Communication Form.
7) When the GSF has been resolved the market operator will inform all parties using Part 4 of the Emergency Communication Form by fax.
8) All parties will acknowledge receipt of notification of return to normal Communication Channels by faxing Part 5 of the Emergency Communication Form to the market operator.
9) Any changes to the settlement calendar will be faxed to all impacted parties.
A more detailed step by step procedure can be found in Agreed Procedure 7 "Emergency Communication" - which can be found at http://www.sem-o.com/MarketDevelopment/Pages/MarketRules.aspx
A flowchart of the GCF/GSF process is shown below:
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Gate closure for Commercial Offer Data (COD) is 10:00 am on the day prior to the trade day. E.g. bids for trade date 07/05/2010 would need to be submitted before 10:00 am on 06/05/2010. COD can be submitted up to 28 days before gate closure.
Gate closure for Technical Offer Data (TOD) is 09:50 am on the day prior to the trade day. E.g. Technical offer data changes such as ramp rates for trade date 07/05/2010 would need to be accepted into the market systems before 09:50 am on 06/05/2010. However in order to facilitate Transmission System Operator (TSO) approval of the TOD changes participants have to submit TOD by 12:00 pm two days prior to the trade date.
TOD can be submitted up to 28 days before gate closure.
Gate Closure Time Earliest Submission Possible
COD 10:00 a.m. day before Trading Day 28 days before gate closure
TOD 09:50 a.m day before Trading Day 28 days before gate closure
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The Ex-Ante Indicative Market chedule quantities (MSQ’s), indicative system marginal prices (SMP’s) and indicative shadow prices are published by 13:00 one day before the trade date.
The Ex-Post indicative market schedule quantities (MSQ’s), indicative system marginal prices (SMP’s) and indicative shadow prices are published by 16:00 one day after the trading date.
The Ex-Post initial market schedule quantities (MSQ’s), initial system marginal prices (SMP’s) and initial shadow prices are published by 17:00 four days after the trading date.
Gate Closure Time
EA 13:00 day before Trading Day
EP1 16:00 day after Trading Day
EP2 17:00 four days after Trading day
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The SEM does not differentiate between generators by fuel type. Rather the generators are classified into the following generator types (or resource types):
1. Predictable Price Maker (PPMG)
2. Variable Price Maker (VPMG)
3. Predictable Price Taker (PPMG)
4. Variable Price Taker (VPTG)
5. Autonomous Price Taker (APTG)
6. Interconnector
What type of information is submitted as a bid is dependent on the Generator Type.
PPMG and VPMG submit:
a. Price Quantity (PQ) pairs
b. Start Up Cost
c. No Load Cost
PPTG submit:
a. Nomination Profile
b. Decremental Price
c. PQ pairs, Start Up Cost, No Load Cost
VPTG submit:
a. Nomination Profile
b. Decremental Price
APTG do not submit bids
Interconnectors submit:
PQ pairs
Maximum Import Capacity
Maximum Export Capacity
For more detail on how each Generator type submits bids, please see How do I submit bids.
Each type of unit is scheduled on the basis of:
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Generator production cost is the total cost a generator unit incurs in producing exported electricity and is calculated on a half hourly basis by the MSP software.
The production cost for a given generator consists of incremental operating cost, no-load cost and the start-up cost of the generator,
Operating cost - the cost associated with producing exported power at a particular MW generation level.
No Load Cost - the cost associated with a unit being on and exporting but not including the cost associated with this exported power)
Start Up Cost – the cost of bringing a Generator Unit to a Synchronised state, from a Cold, Warm or Hot state.
These values are Commercial Offer Data inputs specific to a particular generator and generator units are permitted to submit up to three (warm, cold and hot) start-up costs.
It is worth noting that within the MSP software transmission losses and distribution losses are not taken into consideration.
Generator production costs are calculated on a half hourly trading period basis and, although incremental operating cost and no load cost are continuous while a unit is on, start up costs are only incurred whenever a generator is switched on.
Recovery of production costs (if not recovered through shadow price as is common with start up costs) is spread throughout a generator’s on period via the addition of uplift to shadow price to calculate SMP (see ‘How is SMP calculated?’).
MSP production cost is the total production cost associated with all generation in the market for the thirty hour optimisation horizon and is calculated using the formula detailed in section N 19 in appendix N of the trading and settlement code. It is this value which is optimised/minimised in the MSP software in order to produce an efficient set of market schedule quantities to meet the total system load.
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Pumped storage units are predictable price making generators (PPMGs) and as such are scheduled using the economic commitment engine in the MSP software. Pumped storage units submit PQ pairs, start up costs and no load costs equal to zero and as such effectively they make no bids but rather adopt a price for a given half hour trading period from the marginal price making unit which has set the price in that trading period.
Since there are no submitted prices the scheduling of pumped storage units is performed by the MSP to minimise the total MSP production cost over all scheduled generator units across the thirty hour optimisation horizon while ensuring that the pumped storage units maximum and minimum storage capacity (which are Technical Offer Data submissions) are not breached. In the cases where total production costs for the market are equal for alternate schedules for a group of generator units which includes a pumped storage unit the MSP software will schedule the units randomly without any tie-break criteria being used, see the Trading and Settlement Code paragraph N49.
Although pumped storage units do not submit prices they do submit a target reservoir level for the end of the trading day and as well as a target reservoir level percentage. The target reservoir level is used as a lower limit for the reservoir level at the end of the trading day so that, where feasible, the MSP software shall ensure that the reservoir level at the end of the trading day is greater than or equal to this limit. Target reservoir level multiplied by target reservoir level percentage provides a similar lower limit for reservoir level at the end of the optimisation horizon which is also observed by the MSP software.
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Interconnector units are Predictable Price Making Generator units whose generation is scheduled and fixed one day ahead of trade date during the Ex Ante MSP run, the steps involved in scheduling interconnector units in the market are as follows;
1) The Interconnector Administrator(IA) provides Active Interconnector Unit Capacity holdings data to the market operator by 10:00 am the day before trade date. This data defines the maximum import and export capacities for each interconnector unit for each trading period which is used during the Ex Ante MSP run to set interconnector user nominations which are supplied to the interconnector administrator by 11:00 am the day before trade date.
2) Using the Moyle Interconnector Trading System (MITS) the IA determines Modified Interconnector User Nominations (MIUNs) and provides them to the Market Operator by 12:00 the day ahead of trade date. MIUNs are effectively the interconnector capacity available to each interconnector unit and they are determined using MITS to allocate interconnector flows between the interconnector units in proportion to their holdings.
3) The MIUNs produced during the Ex Ante MSP run are fixed for the trading day in question and as such no IUNs are produced during the Ex Post indicative or Ex Post initial runs.
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LR or Lagrangian Relaxation is the default solver algorithm used in the SEM to determine what generator unit commitment is required to meet the system load (see ‘How are production costs calculated?’ ‘What is pricing and scheduling?’). There is an alternate solver available to the market operator known as MIP or mixed integer programming however the MIP solver is only used under certain, specific, pre-defined conditions as described below. Both solvers are certified for use in the market.
Every run of the MSP software is performed, in the first instance, using the LR solver. Should the schedule of shadow prices include a shadow price equal to PCAP or PFLOOR or a system marginal price spike of above €500 and less than PCAP in any half hour trading period then the trading day in question will be scheduled again using the MIP solver so that the two schedules produced can be compared. How to determine which solver should be published is summarised in the below table.
Optimal Production Costs Price Event Publication
Scenario 1 yes lower n/a MIP
Scenario 2 no lower removed MIP
Scenario 3 no lower not removed LR
Scenario 4 n/a higher or equal n/a LR
Whether the price event has been removed and which schedule results in the lowest MSP production costs over the day are the major criteria in deciding which schedule is published. Whether or not the MIP solver has found an optimal solution is also taken into consideration where an ‘optimal’ solution means the MIP solver has identified the schedule which results in the lowest possible MSP production costs.
Where the shadow price from an initial LR run in any trading period is equal to PCAP or PFLOOR and no participant has bid in at this level it is an indication that one of the constraints set out in the trading and settlement code (see paragraph N 17.4 of the trading and settlement code). These include, under and over generation events, breach of interconnector ramp rates and breach of energy limits for energy limited generators) has been breached by the MSP software in order to find a solution. Breaching any of these constraints means that the LR solution is infeasible. When LR produces an infeasible solution and MIP produces a feasible solution then MIP will be published regardless of production costs or any of the other measures laid out in the table above. If both solutions are found to be infeasible then the comparative rules laid out in the table above will be used to determine which solution will be published.
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PCAP is the maximum allowed shadow price and system marginal price (see, ‘What is the shadow price?’ and ‘How is SMP calculated?’) in any half hour trading period. It is a parameter which is set in the MSP software so that should the running of the MSP software result in a shadow price higher than PCAP (usually due to a system constraint breach such as an over-generation or under-generation event, breach of interconnector ramp rates or a breach of energy limits for energy limited generator units, see paragraph N 17.4 of the trading and settlement code) for a particular trading period then the shadow price for this trading period will automatically be set equal to PCAP (currently set at €1000). As such PCAP is also the maximum allowable bid for price making generators.
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PFLOOR is the minimum allowed shadow price and system marginal price (see, ‘What is the shadow price?’ and ‘How is SMP calculated?’) in any half hour trading period. It is a parameter which is set in the MSP software so that should the running of the MSP software result in an shadow price lower than PFLOOR (usually due to a system constraint breach such as an over-generation or under-generation event, breach of interconnector ramp rates or a breach of energy limits for energy limited generator units, see paragraph N 17.4 of the trading and settlement code) for a particular trading period then the shadow price for this trading period will automatically be set equal to PFLOOR (currently set at - €100). As such PCAP is the minimum allowable bid for price making generators. It is worth noting that negative bid data typically refers to interconnector units exporting electricity to the BETTA market.
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