Balancing and Settlement Code
Loss of Load Probability Calculation Statement
Effective Date: 29 March 2019
LOSS OF LOAD PROBABILITY CALCULATION STATEMENT
THE METHODS USED TO CALCULATE LOSS OF LOAD PROBABILITY VALUES
1. This statement refers to the Balancing and Settlement Code dated 29 March 2019 and, in particular, to the requirements for a Loss of Load Probability Calculation Statement in Section T 1.6A thereof.
2. This Statement, Version 2.0, is effective from 29 March 2019.
3. The Authority has approved this Statement.
Intellectual Property Rights, Copyright and Disclaimer The copyright and other intellectual property rights in this document are vested in Elexon or appear with the consent of the copyright owner. These materials are made available for you for the purposes of your participation in the electricity industry. If you have an interest in the electricity industry, you may view, download, copy, distribute, modify, transmit, publish, sell or create derivative works (in whatever format) from this document or in other cases use for personal academic or other non-commercial purposes. All copyright and other proprietary notices contained in the document must be retained on any copy you make. All other rights of the copyright owner not expressly dealt with above are reserved. No representation, warranty or guarantee is made that the information in this document is accurate or complete. While care is taken in the collection and provision of this information, Elexon Limited shall not be liable for any errors, omissions, misstatements or mistakes in any information or damages resulting from the use of this information or action taken in reliance on it. |
Version | Date | Description of Changes | Changes Included | Mods/ Panel/ Committee Refs |
1.0 | 05/11/15 | Approved version | P305 | P244/11 |
2.0 | 29/03/19 | 29 March 2019 Standalone Release | P369 | P245/12 |
The Balancing and Settlement Code uses Loss of Load Probability (LoLP) values in the calculation of Reserve Scarcity Prices. This Loss of Load Probability Calculation Statement (the Statement) explains how the National Electricity Transmission System Operator (NETSO) calculates Loss of Load Probability values.
1.1 Scope and Purpose of the Statement
In accordance with BSC Section T 1.6A, the BSC Panel (the Panel) is required to establish and maintain a Loss of Load Probability Calculation Statement.
This Statement sets the method for calculating LoLP values pursuant to the Static LoLP Function Method (‘the Static Method’) and the Dynamic LoLP Function Method (‘the Dynamic Method’) and the method for calculating a Static LoLP Function.
the constant parameters to be used in the determination of LoLP;
where applicable, the range of values used to determine LoLP values and functions; and
the processes to follow for reviewing, updating and publishing parameters that are to be performed by the NETSO on a regular basis.
1.2 Balancing and Settlement Code Provision
Interested parties should read this Statement in conjunction with the BSC and in particular Sections Q and T. The Panel established this Statement in accordance with the provisions of BSC Section T 1.6A. In the event of an inconsistency between the provisions of this Statement and the BSC, the provisions of the BSC shall prevail.
1.3 Main Users of the Procedure and their Responsibilities
The main users of this Statement are:
The NETSO
Generators
Suppliers
Non-physical traders
The remaining sections in this document are:
Section 3 – ‘Common calculation building blocks’
Section 4 – ‘Static Loss of Load Probability’
Section 5 – ‘De-rated margin’
Section 6 – ‘Dynamic Loss of Load Probability’
1.5 Review Procedure for the LoLP Calculation Statement
The Panel may review this Statement from time to time and make changes, subject to the Authority’s approval in accordance with BSC Section T 1.6A.3, 1.6A.4 and 1.6A.5.
The Panel will determine how it intends to review the Statement. Any review of the Statement must include consultation of Parties and other interested parties. The Panel must consider any representations made during the consultation and provide copies of any written representations to the Authority.
Where the Authority approves a revised LoLP Calculation Statement:
such revised Statement shall be effective from such date as the Panel shall determine with the approval of the Authority (and shall apply in respect of Settlement Days from that date); and
the Panel Secretary shall give notice of such date to the NETSO and each Party.
1.6 Associated Code Subsidiary Documents
BSCP01 ‘Overview of Trading Arrangements’
‘Imbalance Pricing’ Guidance Note
‘Balancing Mechanism Reporting Agent’ User Requirements Specification
‘Settlement Administration Agent’ User Requirements Specification
1.7 Abbreviations, Acronyms and Definitions
The following is a list of abbreviations and acronyms used in this LoLP Calculation Statement:
Table 1 - List of abbreviations and acronyms
AV | Availability Factors |
BM | Balancing Mechanism |
BMRA | Balancing Mechanism Reporting Agent |
BMRS | Balancing Mechanism Reporting Service |
CCGT | Combined Cycle Gas Turbine |
CR | Capacity Requirement |
DRM | De-rated Margin |
DSBR | Demand Side Balancing Reserve |
FT | Per fuel type |
GCAP | Conventional Generation Capacity |
i | Per BMU |
j | Per Settlement Period |
LLR | Largest Loss Reserve |
LoLP | Loss of Load Probability |
LT | Lead Time |
MW | Megawatt |
NETSO | National Electricity Transmission System Operator as the holder of the Transmission Licence and any reference to "NETSO", "NGESO", "National Grid Company" or "NGC" in the Code or any Subsidiary Document shall have the same meaning. |
OCGT | Open Cycle Gas Turbine |
RRF | Response Remaining Factor |
RSP | Reserve Scarcity Price |
RT | Real Time |
SAA | Settlement Administration Agent |
SBR | Supplemental Balancing Reserve |
STOR | Short Term Operating Reserve |
STX | Station Load |
URRM | Upward Response Reserve Multiplier |
VoLL | Value of Lost Load |
Table 2 - List of subscripts and superscripts
FT | Per fuel type |
i | Per BMU |
j | Per Settlement Period |
RT | Real Time |
“Capacity Requirement” | The capacity (in MW) that consumers and other demand-side participants are expected to export from the Transmission System in a given Settlement Period. |
“Conventional Generation Capacity” | The capacity (in MW) that conventional generators connected to the Transmission System are expected to deliver to the system in a given Settlement Period. Conventional generators are those that are connected to the Transmission System and that rely on non-renewable energy sources. |
“Operational Day” | The period from 0500 hours on one day to 0500 on the following day |
”Reserve Scarcity Price” (RSP) | In respect of a Settlement Period, the price determined in accordance with Section T3.13. The RSP is the product of the LoLP and VoLL It is a price that reflects the value of reserve when it is used based on the prevailing scarcity on the system |
“Value of Lost Load” (VoLL) | Has the meaning given to it in Section T1.12.1. It is an administrative value that represents the price at which a consumer is theoretically indifferent between paying for their energy, and being disconnected.. |
“Transmission System” | means the system consisting (wholly or mainly) of high voltage electric lines owned or operated by transmission licensees within Great Britain, in the territorial sea adjacent to Great Britain and in any Renewable Energy Zone and used for the transmission of electricity |
“Total Wind Generation Forecast” | Forecast of total output (in MW) expected from all wind generators connected to the Transmission System in a given hour, taking account of probability error |
“BMRS Wind Generation Forecast” | Forecast of total output expected from all wind generators connected to the Transmission System in a given hour, as reported on the BMRS |
Full definitions of the above acronyms are, where appropriate, included in the BSC or, where used, in this Statement.
Approved BSC Modification P305 will re-price STOR Actions where the action’s original utilisation price is less than the Reserve Scarcity Price (RSP) calculated for the corresponding Settlement Period. Reserve Scarcity Prices are the product of the Value of Lost Load (VoLL) and Final LoLP value.
P305 specified the use of two methods for calculating LoLP values – a Static LoLP Function Method and Dynamic LoLP Function Method. The NETSO will use these methods at different times such that:
From 5 November 2015 the NETSO will calculate Final LoLP values using the Static Method.
From 1 May 2018 the NETSO will calculate Indicative LoLP values using the Dynamic Method, whilst it continues to calculate Final LoLP values using the Static Method.
From 1 November 2018 the NETSO will calculate Indicative and Final LoLP values using the Dynamic Method.
This Statement describes the two methods for calculating LoLP values.
2.1 Definition of LoLP and Indicative LoLP
A LoLP value is a measure of scarcity in available surplus generation capacity that the NETSO will calculate for each Settlement Period. That is, for a given level of Capacity Requirement (CR) (measured in MW) on the Transmission System the associated LoLP indicates the probability that there will be insufficient Total Generation Capacity (Z) (measured in MW) to meet the CR.
There are two types of LoLP values - indicative and final. For a given Settlement Period, the NETSO produces Indicative LoLP values from data it has available to it at defined lead times (at midday the day before and 8, 4 and 2 hours) ahead of Gate Closure for the Settlement Period. BSC Parties use Indicative LoLP values as an indication of the level of scarcity anticipated ahead of Gate Closure for a Settlement Period.
For the same Settlement Period, the NETSO produces Final LoLP values from data available to it at Gate Closure. The Final LoLP is the best indication of expected scarcity during the Settlement Period.
The Balancing Mechanism Reporting Agent (BMRA) and Settlement Administration Agent (SAA) use Final LoLP values to produce Reserve Scarcity Prices.
3 Common calculation building blocks
The calculation of Indicative and Final LoLP values using the static and dynamic methods rely on certain common elements – i.e. Conventional Generation Capacity (GCAP), Availability Factors (AV) for different generation fuel types, and Capacity Requirement (CR)).
This Section describes these common ‘building blocks’ in more detail.
The NETSO uses the following data in the calculation of LoLP values, which it takes from the BM system.
Abbreviation/ Acronym/Term | Definition | Units/Range |
BMU | Balancing Mechanism Unit | |
FT | Fuel type – used by the BMU | Per BMU |
PN | Physical Notification - the generation capacity expected to be exported by the BMU to the Transmission System during a Settlement Period | Per Settlement Period per BMU in MW |
MEL | Maximum Export Limit – the maximum level at which the BM Unit may export to the Transmission System | Per Settlement Period per BMU in MW |
MZT | Minimum Zero Time - is the minimum time that a BM Unit which has been exporting must operate at zero or be importing, before returning to exporting | Per Settlement Period per BMU in minutes |
NDZ | Notice to Deviate from Zero – is the time required for a BM Unit to start importing or exporting energy, from a zero Physical Notification | Per Settlement Period per BMU in minutes |
NDF + STX | National Demand Forecast + station load, also referred to as ‘Demand’ | Per Settlement Period in MW |
Demand + Interconnector Export | Transmission system demand forecast is made up of NDF+STX and the interconnector flow where exports are positive | Per Settlement Period in MW |
NBM STOR | STOR provided by non BM units | Per Settlement Period in MW |
W | Total Wind Generation Forecast for GB Transmission System | Per Settlement Period in MW |
Wfcst | BMU Wind Generation Forecast | Per Settlement Period, Per BMU in MW |
WCapacity | Total wind capacity available in Settlement Period | Per Settlement Period in MW |
Wfcst_mape | Mean absolute percentage error of historical Wfcst values | Static input value calculated from historical data |
3.2 Modelling Conventional Generation Capacity (GCAP)
In order to calculate the Conventional Generation Forecast (X), Conventional Generation Capacity (GCAPi) (i.e. excluding wind and other forms of renewable generation) is defined per BMU as follows:
{MELi NDZi < LT+30 minutes AND unit desynchronised before MZTi
MEL, FPN, NDZ and MZT are the averages across the Settlement Period from the latest submission per BMU
For a given Settlement Period, each BMU’s GCAP is used in combination with a corresponding Availability Factor (see below) to calculate a Conventional Generation Forecast (X):
3.2.1 Treatment of NDZ (i.e. Lead Time (LT) + 30 minutes)
When deriving the available capacity of a unit, the MEL is counted for all units that can be synchronised at any point within the relevant Settlement Period (hence the NDZ accounts for the lead time at the start of the period plus 30 minutes to the end).
All MELs count towards GCAPi and therefore the NETSO calculates LoLP regardless of whether generation is behind a constraint boundary and cannot be accessed by the NETSO. This is consistent with the method used by the NETSO in the Capacity Mechanism.
3.2.3 Short Term Operating Reserve (STOR)
Whilst BM STOR is included in the calculation of GCAP, the NETSO subtracts NBM STOR from the CR. This is because NBM STOR can consist of both generation output and demand reduction. Also, the NETSO measures NBM STOR differently to BM STOR (i.e. NBM STOR units do not have MELs or NDZs). Ultimately NBM STOR will reduce overall demand and so the NETSO subtracts it in the calculation of CR – see below.
3.2.4 Supplemental Balancing Reserve (SBR)
The calculation of GCAP excludes the MELs for any relevant Supplemental Balancing Reserve (SBR).
3.3 Modelling Availability Factors (AV)
When calculating a Conventional Generation Forecast, the NETSO sets common generation Availability Factors (AVFT) for different fuel types, so each BMU will have a corresponding AVi depending on the BM Units main fuel source.
To calculate these common AVFT factors, the NETSO sums the minimum of MEL at Real Time and the forecast MEL at one hour ahead for each BMU that uses a particular fuel type. The NETSO then divides the sum of minimum and forecast MELs by the total of the one hour ahead forecast MELs. This is to ensure that availability figures can never be greater than 1, as nuclear generators can ramp their MEL submissions to signal their availability. This has been calculated per fuel type and averaged across the whole year.
This availability average is calculated as follows:
AV
FT =
x = 1 hour ahead of real time forecasted MEL submission
For a given Settlement Period, each BMU’s GCAP is used in combination with a corresponding Availability Factor (see below) to calculate a Conventional Generation Forecast (X):
The NETSO will use the Availability Factors set out in Table 4 from 5 November 2015 are:
Table 4 - Fuel Type Availability Factors
Fuel type | Availability factors from forecast MEL |
OIL | 0.998 |
OCGT | 0.997 |
NUCLEAR | 0.998 |
HYDRO | 0.988 |
PUMPED STORAGE | 0.998 |
CCGT | 0.989 |
COAL | 0.986 |
The Availability Factors in Table 4 were calculated using data from January to December 2013. The NETSO used data from 2013 to set this first set of Availability Factors as this data was used in the development of LoLP methods as part of Approved Modification P305’s overall development.
The NETSO will revise the factors each year with updated historical data at the same time as generating a new Static LoLP Function and lookup table (see Section 4.4). BSCCo will publish these revised factors alongside the lookup table on the Elexon Portal.
In the instance of a new fuel type, there would be less than a year’s worth of data required to calculate the availability of that fuel type. Therefore in these circumstances the NETSO will determine an appropriate interim factor and notify BSCCo of its method. If this cannot happen then the NETSO will take a weighted average of the availability factors to apply to the new fuel type.
3.4 Modelling Capacity Requirement (CR)
The Capacity Requirement (CR) for a given Settlement Period consists of system demand (Demand + Interconnector Export) plus the largest loss reserve (LLR) minus the volume of NBM STOR. This is calculated using:
CR = Demand + Interconnector Export + LLR – NBM STOR
Demand = NDF + Station Load
NDF: this the NETSO National Demand Forecast (which includes system losses)
Station Load: the internal load of power stations required to supply the needs of their equipment.
Interconnector Export: this is the flow on the interconnector where exports are positive. Calculated by:
Interconnector Export =
= {IFA, BRITNED, MOYLE, EAST_WEST}
= the sum of the interconnector flow with exports positive and aggregated per
Settlement Period.
LLR: Largest Loss Reserve; this is the equation to determine the reserve the NETSO is required to hold to withstand the potential largest loss on the system (typically this largest loss is 1260MW for Sizewell B).
LLR = ((Loss – (NDF+STX)* 1%) / Response Remaining Factor) / Upward Response Reserve multiplier
Response Remaining Factor: 0.68 [this is the amount of response remaining as some has been used already due to deviation in frequency from 50.0Hz and 49.9Hz]
Upward Response Reserve Multiplier (URRM): 0.55 [this models how much frequency response can be delivered from the available headroom]
Loss: 1260 MW is the value currently used as it is the typical largest loss that NG are holding response for.
NBM STOR: is the short term operating reserve available to the control room. As mentioned above in Section 3.2.3, the NETSO measures NBM STOR differently to BM STOR and because ultimately NBM STOR will reduce overall demand, the NETSO subtracts it in the calculation of CR – see above.
The calculation of CR does not take account of Demand Side Balancing Reserve (DSBR).
In addition to determining a Conventional Generation Forecast (X), as described above, the NETSO produces a Total Wind Generation Forecast (W) (measured in MW).
The Total Wind Generation Forecast is a forecast of all expected wind generation each hour. The NETSO bases its Total Wind Generation Forecast (W) on the sum of individual BMU Wind Generation Forecasts (Wfcst) and a related forecast error (Wfcst error term).
The NETSO calculates the Total Wind Generation Forecast (W) by first determining individual BMU Wind Generation Forecasts (Wfcst) using its own wind forecast system. The NETSO’s wind forecast system depends on the receipt of weather data and metered volumes from generation sites. The system processes the weather data every 6 hours to produce 48 hourly forecasts. The system blends the weather based forecasts with actual metered data to improve the accuracy of the forecasts. These individual BMU forecasts are summed together to produce a GB forecast.
The error distribution of Wind Generation Forecasts (Wfcst error term) more closely resembles a Laplace distribution than a normal distribution. Therefore the NETSO determines the final Total Wind Generation Forecast (W) using a Laplace distribution with the location parameter equal to the median of relevant BMU Wind Generation Forecasts (Wfcst) and a scale parameter equal to the mean absolute percentage error of the sum of historical Wfcst values:
Wj ~ L(location = median of Wfcst_ij values, scale factor = Wfcst error term)
Wj: is the Total Wind Generation forecast for a given Settlement Period (j)
Wfcst error term = Wfcst_mape × Wcapacity
Wfcst_mape = is the mean absolute percentage error of the sum of all BMU Wind Generation Forecasts
Wcapacity = total national wind generation capacity
Whilst each Total Wind Generation Forecast covers an hour period, the same forecast is used for each Settlement Period that makes up that hour period.
The binomial distributions of X and Laplace distribution W can then be combined statistically, such that Z = X + W.
3.6 Common lead times for publishing values
For each Settlement Period, the NETSO may be required to produce Indicative LoLP, Final LoLP and forecast De-rated Margin values at specific lead times ahead of the commencement of that Settlement Period.
These specific lead times are:
at 1200 hours on each calendar day the NETSO shall send values applicable to all Settlement Periods for which Gate Closure has not yet passed occurring within the current Operational Day and the following Operational Day;
at 8 hours, 4 hours and 2 hours prior to the beginning of a Settlement Period the NETSO shall send values applicable to that Settlement Period; and
at 1 hour prior to the beginning of a Settlement Period the NETSO shall send a value applicable to that Settlement Period.
4 Static Loss of Load Probability Function Method
The Static LoLP Function Method (the ‘Static method’) of calculating LoLP values uses a pre-determined mathematical function (and lookup table) to convert a value of de-rated margin into a LoLP value. The NETSO derives a mathematical function from the historical relationship between these two variables.
4.2 Method for calculating static LoLP values from de-rated margin
The Static method calculates Final LoLP values by using a forecast of de-rated margin (see Section 5), which the NETSO converts to LoLP using a pre-determined Static LoLP Function and lookup table.
4.3 Frequency of calculating and publishing Final LoLP values
For each Settlement Period until 31 October 2018, the NETSO will calculate and send to the BMRA a Final LoLP value in accordance with the Static Method at the specific lead time set out in 3.6(c) above – i.e. at Gate Closure.
If a Gate Closure forecast of de-rated margin is not available, the NETSO will use the most recent forecast of de-rated margin instead. For example, the 2 hour ahead forecast or if that is not available the 4 hour ahead forecast, etc.
If no forecast of De-rated Margin is available, the NETSO will report the Final LoLP value to the BMRA as ‘null’.
4.4 Creation of Static LoLP function and lookup table
The NETSO generates a Static LoLP function by determining a relationship between historical values of LoLP and de-rated margin. This relationship is represented by using a normal cumulative density function to fit a smooth curve to the historical data. As a result this curve contains all the assumptions of the dynamic model (such as wind and demand forecast accuracy). At publication of this Statement, the Static function is defined as:
LoLP = 1 – Normal cumulative density function (DRMj, µ, σ2)
DRM: is the De-rated Margin – see Section 5 below;
Based on this mathematical relationship, the NETSO produces a lookup table that enables Parties to determine LoLP values based on a de-rated margin value. A copy of this lookup table is publicly available which Parties can find on the Elexon Portal. The NETSO and BSCCo will work together to ensure the lookup table is maintained and contains up-to-date details, including any revisions to the definition of the Static function.
From the graph above it is clear that at 0MW of de-rated margin (note that at this point the only margin remaining is reserve for response which cannot be depleted) the LoLP value is 0.5. This is because when there is expected to be no de-rated margin available at Gate Closure there is statistically a 50:50 chance that there will be sufficient generation during the Settlement Period to meet demand i.e. because demand could reduce or generation increase or vice versa.
4.5 Review of Static LoLP function and look-up table
Until 1 November 2018, by the fifteenth working day of each December, the NETSO will produce and send to the BSCCo a revised Static function and lookup table.
To do this, the NETSO will record historical values of LoLP using is Dynamic Method (see Section 6) and de-rated margin (see Section 5), for the calendar year that has just passed. The NETSO will add this historical data to any existing historical data used to calculate Static LoLP Functions(s). The NETSO will use this enlarged data set to determine an updated relationship between LoLP and de-rated margin and generate an updated Static LoLP Function and lookup table.
Upon receipt from the NETSO, the BSCCo will publish the revised Static LoLP Function and lookup table on the Elexon Portal by the end of the same December. This is to give BSC parties three months’ notice before the revised function and lookup table take effect on 1 April each year.
The NETSO will produce values of de-rated margin at specific lead times ahead of a Settlement Period. The NETSO uses De-rated Margin values to calculate LoLP values in accordance with the Static LoLP Function Method – see Section 4.
5.2 Method for calculating De-rated Margin values
For a given Settlement Period, the NETSO will calculate the de-rated margin value by determining the Combined Generation Forecast and subtracting the Capacity Requirement (CR). This can be represented using:
De-rated Margin (DRMj) = Zj – CRj
Zj: is the Combined Generation Forecast (Z)
Xj: is the Conventional Generation Forecast
GCAPij: is the Generation Capacity of a conventional generator – see 3.2
AVi: is an Availability Factor – see 3.3
Uj: is the sum of BMU Wind Generation Forecasts for that Settlement Period as reported on BMRS - see 3.5 above
CRj: is the Capacity Requirement – see 3.4
It should be noted that the calculation of De-rated Margin uses the sum of BMU Wind Generation Forecasts (Uj) rather than the Total Wind Generation Forecast (Wj) which is used for calculating a LoLP value using the Dynamic Method.
5.3 Frequency of calculating and publishing De-rated Margin values
For each Settlement Period, the NETSO will calculate and send to the BMRA forecast De-rated Margin values at specific lead times ahead of the Settlement Period commencing.
In particular, the NETSO will calculate De-rated Margin values in accordance with 3.6 (a), (b) and (c).
6 Dynamic Loss of Load Probability Function Method
The Dynamic LoLP Function Method (the ‘Dynamic method’) will be used by the NETSO to produce Indicative LoLP values from 1 May 2018 and Final LoLP values from 1 November 2018.
6.2 Method for calculating dynamic LoLP values
For a given Settlement Period, the dynamic model uses a direct relationship between the available generation (Z) and the Capacity Requirement (CR) and is defined as:
Combined Generation Forecast (Zj)
Xj: is the Conventional Generation Forecast
GCAPji: is the Generation Capacity of a conventional generator – see 3.2
AVi: is an Availability Factor – see 3.3
Wj: is the Total Wind Generation Forecast – see 3.5 above.
CR: is the Capacity Requirement
It should be noted that the calculation of a LoLP value using the Dynamic Method uses the Total Wind Generation Forecast (Wj) rather than the sum of BMU Wind Generation Forecasts (Uj) which is used for calculating a De-rated Margin value.
6.3 Frequency of calculating and publishing Final and Indicative LoLP values
For each Settlement Period from 1 May 2018, the NETSO will calculate and send to the BMRA Indicative LoLP values in accordance with the Dynamic method at the specific lead times set out in 3.6 (a) and (b) above.
For each Settlement Period from 1 November 2018, the NETSO will calculate and send to the BMRA Final LoLP values in accordance with the Dynamic method at the specific lead time set out in 3.6 (c) above – i.e. at Gate Closure
If for whatever reason the NETSO cannot produce an Indicative or Final LoLP value, it will report a ‘null’ value for that lead time. If no Indicative or Final LoLP value is received by the BMRA for a particular lead time, the BMRA will consider the value for that lead time to have been reported as ‘null’.
If the NETSO reports a Final LoLP value as ‘null’ to the BMRA, the BMRA will use the most recent Indicative LoLP as the Final LoLP. For example, the 2 hour ahead Indicative LoLP or if that is not available the 4 hour ahead Indicative LoLP, etc.
