The Help page for the BM Reports web site is divided into four sections, each of which may be accessed independently, as follows:
This section gives definitions of the many technical terms which are used on this site. The majority of these are formally defined in other documents, and links to these documents are also given. The terms which are defined are as follows:
Glossary of Terms

The majority of the terms used on this web site are formally defined in core industry documentation, the simplified explanations given here are provided to assist users of the site. Every effort has been made to ensure that they are as accurate as possible, but it should be stressed that they are only indicative in nature. For those who wish to study the primary definitions in more detail, the following links are provided:
  • BSC: Items defined within the Balancing and Settlement Code (https://www.elexon.co.uk/bsc-related-documents/) . These items are denoted by BSC. In many cases the definition of the item is to be found in one of the Glossary sections, which are annexes to Section X of the BSC. In other cases a reference is given to the appropriate location within the BSC.
  • GRID CODE: Items defined within the Grid Code (https://www.nationalgrid.com/uk/electricity/codes/grid-code). Some of these items are formally defined in the Glossary and Definitions (GD) section of the Grid Code; but a number of those which relate specifically to the BM are to be found in the Appendices to Balancing Code 1 (BC1). The best description of the BSAD and ABSVD data items is to be found in the BSAD Methodology and ABSVD Methodology, respectively, which are also published on the above web site (within the Balancing Services section of the site, under Transmission Licence Condition C16 Statements).
  • BMRS: The Balancing Mechanism Reporting Service (BMRS) publishes data to fulfil the obligations under Section Q and Section V of the Balancing and Settlement Code (BSC). The User Requirements Specification (URS) provides details of the data reported on BMRS.
 
ABSVD – Applicable Balancing Services Adjustment Data     BSC  Q 6.4
ABSVD (which is displayed on the BMRS report pages as Balancing Services Volume Data) is calculated by the System Operator for each BM Unit and Settlement Period in accordance with Section Q, paragraph 6.4 of the BSC. The derivation of the ABSVD is the subject of a dedicated Methodology Statement (to be found on the System Operator web site as noted above); but the Applicable Balancing Services may conveniently be regarded as those services required by the System Operator for economic operation of the Transmission System, that result in the service provider being exposed to imbalance charges whilst assisting in system balancing. The purpose of calculating the volumes concerned is to enable these volumes to be excluded from the subsequent calculation of imbalance charges.
 
ABV – Accepted Bids Volume     BMRS
The Accepted Bids Volume for a Period is the sum of all the individual Bid-Offer Acceptance Volumes (see BOAL below) for the Bids accepted by the System Operator in the Period.
 
AOV – Accepted Offers Volume     BMRS
The Accepted Offers Volume for a Period is the sum of all the individual Bid-Offer Acceptance Volumes (see BOAL below) for the Offers accepted by the System Operator in the Period.
 
BD - BSAD Defaulted     BMRS
The BSAD Defaulted flag can be used to check if the BSAD was defaulted in the calculations of System Buy Price and System Sell Price for the period in question. If the flag is set to 'T' (true) then no BSAD values were supplied to the BMRS from the System Operator, and so the indicative calculation used default values of zero. If the flag is set to 'F' (false) then BSAD values were supplied and used by the indicative calculation. Under normal circumstances BSAD data is available for the calculations and this flag is consequently set to 'F'.
 
BOAL/BOALF - Bid-Offer Acceptance Level     GRID CODE   BC 2.7
A Bid-Offer Acceptance is a formalised representation of the purchase and/or sale of Offers and/or Bids (see Bid-Offer Data below) by the System Operator in its operation of the Balancing Mechanism. Each Bid-Offer Acceptance is shown on the BMRS as a MW level of operation at the beginning and at the end of the Acceptance (and for any intermediate points which may be necessary). The start and end time of each Acceptance is also shown, from which the Bid-Offer Acceptance Volumes (in MWh) can be calculated. In the example below (which is based on the example in the following entry for Bid-Offer Data), Bid-Offer Acceptance Levels are represented as points A, B, C and D; and the corresponding Bid-Offer Acceptance Volume is then the shaded area. For post P217 Settlement dates Bid-Offer Acceptances (Bid-Offer Acceptance Level Flagged (BOALF)) include an SO-Flag which indicates whether or not the Acceptance was potentially taken for reasons other than balancing the short-term energy imbalance of the Transmission System.

For post P305 Settlement dates Bid-Offer Acceptances (Bid-Offer Acceptance Level Flagged (BOALF)) include an STOR-Flag which indicates whether or not the Acceptance was provided by a STOR provider.

For post P344 Settlement dates Bid-Offer Acceptances (Bid-Offer Acceptance Level Flagged (BOALF)) include the new “RR Instruction Flag”, to indicate whether the file is an RR Instruction or a BM Acceptance, and “RR Schedule Flag”, to indicate whether the data is as the result of an RR Schedule calculation, alongside the existing flags.
 
 
BOD – Bid-Offer Data     BSC   Q 4.1
Bid-Offer Data for a BM Unit and Settlement Period is made up of a series of Bid-Offer pairs; there may be up to five above FPN and up to five below FPN in each set of BOD. A Bid-Offer pair consists of an identifying number (e.g. 1, 2 or –1), a 'band width' in MW, and both an Offer Price and a Bid Price. The Offer Price is the price at which the System Operator may purchase energy within this band; the Bid Price is the price which will be paid for energy accepted from the System Operator within this band.

The diagram below illustrates the way that Bid-Offer bands might be set up in a hypothetical case:
 
BPA – Buy Price Price Adjustment     BSC   Q 6.3
BPA is one of the BSAD items (see below). Its derivation is given in the System Operator's BSAD Methodology Statement as

BPA = ((Aggregated cost of purchases of standing reserve option fees * relevant standing reserve weighting factor) + Aggregated cost of purchases of firm regulating reserve option fees + Aggregated cost of purchases of Forward Contract option fees) / (MWh capability of standing reserve contracts purchased + MWh capability of firm regulating reserve contracts purchased + Contracted MWh associated with options for Forward Contracts purchased)

For the avoidance of doubt, if the denominator of BPA is zero in any Settlement Period, then BPA will be set to zero in that period.
 
BSAD - Balancing Services Adjustment Data     BSC   Q 6.3
Please see the Market Principles section for an explanation of the use of Balancing Services and the provision of BSAD. For pre P217 Settlement dates BSAD comprises of eight items for each Settlement Period (though in a given period some may be zero):

(i) SBVA – Net Buy Price Volume Adjustment (System);
(ii) SSVA – Net Sell Price Volume Adjustment (System);
(iii) EBVA – Net Buy Price Volume Adjustment (Energy);
(iv) ESVA – Net Sell Price Volume Adjustment (Energy);
(v) EBCA – Net Buy Price Cost Adjustment (Energy);
(vi) ESCA – Net Sell Price Cost Adjustment (Energy);
(vii) BPA – Buy Price Price Adjustment; and
(viii) SPA – Sell Price Price Adjustment.

For post P217 Settlement dates BSAD comprises of eight items for each Settlement Period (though 6 are always zero and in a given period the other two may be zero):

(i) BPA – BPA ? Buy Price Price Adjustment; and
(ii) SPA – SPA ? Sell Price Price Adjustment.
Balancing Service Adjustment Data is used in the calculation of Energy Imbalance Prices, i.e. the System Buy Price and the System Sell Price as specified in Section T, Paragraphs 4.4.5 and 4.4.6 of the BSC
 
DCI – Demand Control Instructions      BSC   Q 6.9
A Demand Control Instruction (DCI) is the instruction issued by the Transmission Company for the Demand Control Event as set out in OC6 of the Grid Code. The DCI will comprise of following information:

  • the unique identification number for that Demand Control Instruction;
  • the relevant stage number for the Demand Control Event Stage (which, for the purposes of this paragraph, shall be the first Demand Control Event Stage);
  • the Demand Control Event type flag;
  • the Demand Control Event Start Point;
  • where known, the Distribution System Operator instructed;
  • the Demand Control Event Estimate in MW based on the total Demand Control Level anticipated to be delivered; and
  • SMAF Flag indicating whether or not it’s a system balancing action
  • Amendment Flag

 
DISBSAD - Disaggregated BSAD     BSC   Q 6.3
Please see the Market Principles section for an explanation of the use of Balancing Services and the provision of Disaggregated BSAD. Disaggregated BSAD consists of a number of Balancing Services Adjustment Action items. Each item has an identifier (which is unique within each Settlement Period), a Volume, a Cost,SO-Flag and a STOR-Flag. For some Actions the Cost will be undefined. The SO-Flag indicates whether or not the Action was potentially taken for reasons other than balancing the short-term energy imbalance of the Transmission System. This data is only defined for post P217 Settlement dates and is used in the calculation of Energy Imbalance Prices, i.e. the System Buy Price and the System Sell Price as specified in Section T, Paragraphs 4.4.2 and 4.4.3 of the BSC.The STOR-Flag indicates whether or not the Action was provided by a STOR provider. This data is only defined for post P305 Settlement dates and is used in the calculation of Energy Imbalance Prices, i.e. the System Buy Price and the System Sell Price.
 
DRM – De-Rated Margin     BSC   Q 6.1.25
In respect of each Settlement Period, the Transmission Company shall send to the BMRA the De-Rated Margin Forecast calculated in accordance with the Loss of Load Probability Calculation Statement.
 
EAD - Emergency Acceptance Data      BSC   X2
The BOAL corresponding to an Emergency Instruction. Emergency Acceptance Data is communicated via the System Warnings functionality. If issued for system balancing reasons, the resulting Acceptance will be System Operator flagged. If issued for energy balancing reasons, the acceptance will not be SO flagged.
 
EBCA – Net Buy Price Cost Adjustment (Energy)     BSC   Q 6.3
EBCA is one of the BSAD items (see above). Its derivation is given in System Operator's BSAD Methodology Statement as

EBCA = EBVA * weighted average price of all relevant Balancing Services purchased and sold for energy (i.e. as opposed to system) balancing purposes

This value is non zero only for pre P217 Settlement dates.

 
EBVA – Net Buy Price Volume Adjustment (Energy)     BSC   Q 6.3
EBVA is one of the BSAD items (see above). Its derivation is given in System Operator's BSAD Methodology Statement as

EBVA = max (Aggregated volume of all relevant Balancing Services purchased for energy balancing purposes – Aggregated volume of all relevant Balancing Services sold for energy balancing purposes, 0);
This value is non zero only for pre P217 Settlement dates.
EI - Emergency Instruction      GRID CODE   GD
An instruction issued in respect of a BM Unit by the System Operator in emergency circumstances, for example, due to safety considerations. This instruction may require the BM Unit to operate abnormally. An Emergency Instruction may be issued by the System Operator for system balancing or energy balancing reasons. Emergency Instructions are communicated via the System Warnings functionality and not via the normal pages.
 
ESCA – Net Sell Price Cost Adjustment (Energy)     BSC   Q 6.3
ESCA is one of the BSAD items (see above). Its derivation is given in the System Operator's BSAD Methodology Statement as

ESCA = ESVA * weighted average price of all relevant Balancing Services purchased and sold for energy (i.e. as opposed to system) balancing purposes
This value is non zero only for pre P217 Settlement dates.
 
ESVA – Net Sell Price Volume Adjustment (Energy)     BSC   Q 6.3
ESVA is one of the BSAD items (see above). Its derivation is given in the System Operator's BSAD Methodology Statement as

ESVA = min (Aggregated volume of all relevant Balancing Services purchased for energy balancing purposes – Aggregated volume of all relevant Balancing Services sold for energy balancing purposes, 0);
This value is non zero only for pre P217 Settlement dates.
 
FREQ - (System) Frequency     GRID CODE   GD
The number of alternating current cycles per second (expressed in Hertz) at which a System is running.
 
FPN - (Final) Physical Notification     BSC   Q 3.2 and  GRID CODE   BC1
A Physical Notification is the best estimate of the level of generation or demand that a participant in the BM expects a BM Unit to export or import, respectively, in a Settlement Period. Initial Physical Notifications (IPNs), which are submitted to the System Operator at the day ahead stage, are not displayed on the BMRS or used in Settlement calculations. Final Physical Notifications (FPNs) have to be submitted to the System Operator by Gate Closure for each Settlement Period, and are both displayed on the BMRS and used in Settlement calculations.

Physical Notifications are submitted as a series of point MW values; see the entry for Bid-Offer Data above for a diagrammatic example (in which the FPN values are shown as the red line).
 
FUELHH - (Half Hourly) Generation by Fuel Type     BMRS
National Grid measure system generation connected to the high voltage transmission system in real-time from operational metering. This is used in control timescales to assist with balancing the system and confirming that generators are operating at their expected levels. To provide market participants with information relating to the levels of generation, this metering is aggregated into fuel type categories. The data is provided as half hourly averages in MW.
 
FUELINST - (Instantaneous) Generation by Fuel Type     BMRS
National Grid measure system generation connected to the high voltage transmission system in real-time from operational metering. This is used in control timescales to assist with balancing the system and confirming that generators are operating at their expected levels. To provide market participants with information relating to the levels of generation, this metering is aggregated into fuel type categories. The data is provided as 5 minute average MW values.
 
FUEL TYPE      BMRS
National Grid provide the Primary Fuel Type of each BM Unit in the Excel spreadsheet that can be downloaded from https://www.bmreports.com/bmrs/cloud_doc/BMUFuelType.xls. For more information in this area, see the Ten Year Statement section (https://www.nationalgrid.com/uk/publications/electricity-ten-year-statement-etys) of National Grid's website. The fuel type categorisation by BM Unit is undertaken by the Transmission Company outside the BSC using the primary fuel type of each power station and is not based on the BM Unit registration data held by the Central Registration Agent.
 
IMBALNGC - Indicated Imbalance     GRID CODE   GD
A forecast of Indicated Imbalance in the system is received each day for the following day from the System Operator (please see the section on Forecasts in the Reports Guide for an explanation of when the forecasts are received from the System Operator and published on the BMRS). The Indicated Imbalance forecast for each period is the difference between the sum of the PNs submitted for generation BM Units (i.e. the Indicated Generation), and the National Demand Forecast made by the System Operator.
 
INDDEM - Indicated Demand     BSC   X2
A forecast of Indicated Demand in the system is received each day for the following day from the System Operator (please see the section on Forecasts in the Reports Guide for an explanation of when the forecasts are received from the System Operator and published on the BMRS). The Indicated Demand forecast for each period is the sum of all the PNs submitted for BM Units which are forecast to be importing energy, presented as a single average MW level for the Settlement Period. This figure is derived by the System Operator for submission to the BMRS but is not formally defined in the Grid Code.
 
INDGEN - Indicated Generation     BSC   X2
A forecast of Indicated Generation in the system is received each day for the following day from the System Operator (please see the section on Forecasts in the Reports Guide for an explanation of when the forecasts are received from the System Operator and published on the BMRS). The Indicated Generation forecast for each period is the sum of all the PNs submitted for BM Units which are forecast to be exporting energy, presented as a single average MW level for the Settlement Period. This figure is derived by the System Operator for submission to the BMRS but is not formally defined in the Grid Code.
 
INDO - Initial National Demand Out-Turn     BSC   X2
The Initial National Demand Out-Turn is the average megawatt value of demand for a Settlement Period INCLUDING transmission losses but EXCLUDING station transformer load, pumped storage demand and interconnector demand. The INDO is made available by the System Operator within 15 minutes after a Settlement Period, based on their operational metering. The composition of the Initial National Demand Out-Turn matches that of the National Demand Forecast and so INDO and NDF are comparable. This figure is derived by the System Operator for submission to the BMRS but is not formally defined in the Grid Code.
 
INDOD - Initial National Demand Out-Turn Daily     BMRS
The Initial National Demand Out-Turn Daily is the total of the INDO values in a Settlement Day (divided by two to convert to MWh). This figure is derived by the System Operator for submission to the BMRS but is not formally defined in the Grid Code.
 
INDODHIGH - High Reference Initial National Demand Out-Turn Daily     BMRS
The High Reference Initial National Demand Out-Turn Daily value is the level exceeded on 12% of days based on historical daily values from the past 30 years. The calculation includes indexation to allow for underlying demand growth for historic years.
 
INDODLOW - Low Reference Initial National Demand Out-Turn Daily     BMRS
The Low Reference Initial National Demand Out-Turn Daily value is the level exceeded on 88% of days based on historical daily values from the past 30 years. The calculation includes indexation to allow for underlying demand growth for historic years.
 
INDODNORMAL - Normal Reference Initial National Demand Out-Turn Daily     BMRS
The Normal Reference Initial National Demand Out-Turn Daily value is the level exceeded on 50% of days based on historical daily values from the past 30 years. The calculation includes indexation to allow for underlying demand growth for historic years.
 
ITSDO - Initial Transmission System Demand Out-Turn     BMRS
The Initial Transmission System Demand Out-Turn is the average megawatt value of demand for a Settlement Period INCLUDING transmission losses, station transformer load, pumped storage demand and interconnector demand. The ITSDO is made available by the System Operator within 15 minutes after a Settlement Period, based on their operational metering. The composition of the Initial Transmission System Demand Out-Turn matches that of the Transmission System Demand Forecast and so ITSDO and TSDF are comparable. This figure is derived by the System Operator for submission to the BMRS but is not formally defined in the Grid Code.
 
LoLP –Loss of Load Probability     BSC   Q 6.7, Q 6.8
The Transmission Company shall send any Loss of Load Probability function calculated in accordance with the Loss of Load Probability Calculation Statement to the BMRA not less than three months before it is due to take effect. Not later than 15 minutes following Gate Closure for each Settlement Period, the Transmission Company shall send to the BMRA the Final Loss of Load Probability value applicable to the relevant Settlement Period calculated in accordance with the Static LoLP Function Methodology. The static function shall cease to have effect for all Settlement Periods occurring on or after 00:00 on 1 November 2018.

With effect from 00:00 on 1 November 2018 and for all Settlement Periods thereafter, the Transmission Company shall calculate
  • Indicative Loss of Load Probability values in accordance with the Dynamic LoLP Function Methodology.
    • at 1200 hours on each calendar day; and
    • at 8 hours, 4 hours and 2 hours prior to the beginning of the Settlement Period for each Settlement Period during each Settlement Day;
  • Final Loss of Load Probability value for each Settlement Period in accordance with the Dynamic LoLP Function Methodology at the same time as Gate Closure for each Settlement Period.


Note that during the period from 00:00 on 1 May 2018 to 00:00 on 1 November 2018, Transmission company will send the Final LoLP in accordance with the Static LoLP Function Methodology and the indicative LoLPs in accordance with the Dynamic LoLP Function Methodology.
 
MDP - Maximum Delivery Period     GRID CODE   BC1
The Maximum Delivery Period for a BM Unit is one of the Dynamic Parameters listed in Appendix A to BC1 of the Grid Code and displayed in the Dynamic Data pages of the BMRS. It is the time period over which the Maximum Delivery Volume can be delivered.
 
MDV - Maximum Delivery Volume     GRID CODE   BC1
The Maximum Delivery Volume for a BM Unit is one of the Dynamic Parameters listed in Appendix A to BC1 of the Grid Code and displayed in the Dynamic Data pages of the BMRS. It is the maximum number of megawatt hours of Offer (or Bid), that a particular BM Unit may deliver within the associated Maximum Delivery Period.
 
MEL - Maximum Export Limit     GRID CODE   BC1
The Maximum Export Limit for a BM Unit is one of the Export and Import Limits listed in Appendix A to BC1 of the Grid Code. It is the maximum power export level of a particular BM Unit at a particular time. It is submitted as a series of point MW values and associated times.
 
MELNGC - Indicated Margin     GRID CODE   GD
A forecast of Indicated Margin in the system is received each day for the following day from the System Operator (please see the section on Forecasts in the Reports Guide for an explanation of when the forecasts are received from the System Operator and published on the BMRS). The Indicated Margin forecast for each Settlement Period is the difference between the sum of the MELs submitted for that period, and the National Demand Forecast made by the System Operator. The greater the value, the higher the margin between available generation capacity and forecast demand - that is to say, the more spare capacity there is forecast to be in the system.
 
MID - Market Index Data     BSC   T4.4
Market Index Data is a key component in the calculation of System Buy Price and System Sell Price for each Settlement Period. This data is received from each of the appointed Market Index Data Providers (MIDPs) and reflects the price of wholesale electricity in Great Britain in the short term markets. The Market Index Data which is received from each MIDP for each Settlement Period consists of a Market Index Volume and Market Index Price, representing the volume and price of trading for the relevant period in the market operated by the MIDP. The Market Price (the volume weighed average Market Index Price) is used to derive the Reverse Price (SBP or SSP).
 
MIL - Maximum Import Limit     GRID CODE   BC1
The Maximum Import Limit for a BM Unit is one of the Export and Import Limits listed in Appendix A to BC1 of the Grid Code. It is the maximum power import level of a particular BM Unit at a particular time. It is submitted as a series of point MW values and associated times.
 
MNZT - Minimum Non-Zero Time     GRID CODE   BC1
The Minimum Non-Zero Time represents the minimum time that a BM Unit can operate at a non-zero level as a result of a Bid-Offer Acceptance. It is one of the Dynamic Parameters defined in Appendix A to BC1 of the Grid Code and displayed in the Dynamic Data pages of the BMRS.
 
MZT - Minimum Zero Time     GRID CODE   BC1
The Minimum Zero Time is the minimum time that a BM Unit which has been exporting must operate at zero or import, before returning to export; whereas if the BM Unit has been importing, the MZT indicates the minimum time that it must operate at zero or export before returning to import, if action by the System Operator (i.e. a Bid-Offer Acceptance) places it at such a level. It is one of the Dynamic Parameters defined in Appendix A to BC1 of the Grid Code and displayed in the Dynamic Data pages of the BMRS.
 
NDB - Notice to Deliver Bids     GRID CODE   BC1
The Notice to Deliver Bids indicates the length of time between the issuing of a Bid-Offer Acceptance and the time when a BM Unit begins to deliver Bid volumes. It is one of the Dynamic Parameters defined in Appendix A to BC1 of the Grid Code (where it is referred to as NTB) and displayed in the Dynamic Data pages of the BMRS.
 
NDF - National Demand Forecast      GRID CODE   OC 1.6.3
The National Demand Forecast is made by the System Operator. The System Operator National Demand Forecast is based on historically metered generation output for Great Britain. This value INCLUDES transmission losses, but EXCLUDES Interconnector flows and demand from station transformers and pumped storage units. The National Demand Forecast is comparable with the Initial National Demand Out-Turn INDO. All the forecasts are unrestricted, i.e. any notified customer demand management is included in the history.
 
NDFD – National Demand Forecast Day     GRID CODE   OC2.4
The National Demand Forecast Day data is part of the 2-14 day forecast produced each working day by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code. It is produced using the same methodology as the daily National Demand Forecast. The figure published for each day in the 2-14 day forecast is a half hourly average MW value for the peak half hour in the day.
 
NDFW – National Demand Forecast Week     GRID CODE   OC2.4
The National Demand Forecast Week data is part of the 2-52 week forecast produced each Wednesday by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code. It is produced using the same methodology as the daily National Demand Forecast. The figure published for each week in the 2-52 week forecast is a half hourly average MW value for the peak half hour in the week.
 
NDO - Notice to Deliver Offers     GRID CODE   BC1
The Notice to Deliver Offers indicates the length of time between the issuing of a Bid-Offer Acceptance and the time when a BM Unit begins to deliver Offer volumes. It is one of the Dynamic Parameters defined in Appendix A to BC1 of the Grid Code (where it is referred to as NTO) and displayed in the Dynamic Data pages of the BMRS.
 
NDZ - Notice to Deviate From Zero     GRID CODE   BC1
The Notice to Deviate from Zero expresses the notification time required for a BM Unit to change its consumption or production level from a zero PN level, as the result of a Bid-Offer Acceptance. It is one of the Dynamic Parameters defined in Appendix A to BC1 of the Grid Code and displayed in the Dynamic Data pages of the BMRS.
 
NIV - Net Imbalance Volume     BMRS   in accordance with  BSC   T4.4
The System Sell/Buy Price information for each Settlement Period includes the Net Imbalance Volume. The Net Imbalance Volume represents the sum of all of the system and energy balancing actions for the Settlement Period (including pre-Gate Closure actions reported in BSAD), netted off to give the energy imbalance of the overall system.
 
NONBM - NONBM STOR Instructed Volume     BMRS   
The volume of Short Term Operating Reserve instructed by the Transmission Company outside of the balancing mechanism in order to increase generation or reduce demand.
 
P194 - Revised Derivation of the Main Imbalance Price     BMRS   in accordance with  BSC   T4.4
Modification P194, introduced on 2 November 2006, retained the mechanism introduced by P78 but further restricts the amount of priced balancing actions considered within the Main System Price calculation by employing a process known as PAR Tagging. This process selects the set of most expensive priced actions which are not De Minimis, Arbitrage, CADL or NIV Tagged whose combined volume does not exceed a defined upper limit (the Price Averaging Reference volume). A more detailed description is given within the BMRA URS.
 
OCNMFD2   BSC    Q 6.1.4 and GRID CODE OC2.4
The daily peak half hour MW value of Generating Plant Demand Margin for each day from the 2nd to the 14th day following the current Operational Day.
 
OCNMFW2   BSC    Q 6.1.2 and GRID CODE OC2.4
The weekly peak half hour MW value of Generating Plant Demand Margin for each week from the 2nd to the 52nd week following the current week.
 
Total Output Usable   BSC   Q 6.1 and GRID CODE OC2.4
Total Output Usable is the national total generation and interconnector capacity that is expected to be available, and is provided by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code. This data is available over a range of forecast periods:

NOU2T14D     2-14 days ahead (daily peak half hour MW value)

NOU2T49D     2-49 days ahead (daily peak half hour MW value)

NOU2T52W     2-52 weeks ahead (weekly peak half hour MW value)

NOUY1     1 year ahead (weekly peak half hour MW value)

NOUY2     2 years ahead (weekly peak half hour MW value)

NOUY3     3 years ahead (weekly peak half hour MW value)

NOUY4     4 years ahead (weekly peak half hour MW value)

NOUY5     5 years ahead (weekly peak half hour MW value)
 
Output Usable by Fuel Type   BSC   Q 6.1 and GRID CODE OC2.4
The data reported refers to the Bidding Zones active at the time of forecast. Output Usable by Fuel Type is Total Output Usable apportioned by Fuel Type. This data is available over for the following forecast periods:

FOU2T14D     2-14 days ahead (daily peak half hour MW value)

FOU2T52W     2-52 weeks ahead (weekly peak half hour MW value)
 
Output Usable by Fuel Type and BM Unit   BSC   Q 6.1 and GRID CODE OC2.4
The data reported refers to the Bidding Zones active at the time of forecast. Output Usable by Fuel Type and BM Unit represents the Total Output Usable apportioned by both Fuel Type and BM Unit, and therefore represents the expected capacity for individual BM Units and interconnectors. This data is available over for the following forecast periods:

UOU2T14D     2-14 days ahead (daily peak half hour MW value)

UOU2T52W     2-52 weeks ahead (weekly peak half hour MW value)
 
Zonal Output Usable   BSC   Q 6.1 and GRID CODE OC2.4
This data represents the Total Output Usable apportioned to System Zones and is provided by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code. This data is available over a range of forecast periods:

ZOU2T14D     2-14 days ahead (daily peak half hour MW value)

ZOU2T49D     2-49 days ahead (daily peak half hour MW value)

ZOU2T52W     2-52 weeks ahead (weekly peak half hour MW value)

ZOUY1     1 year ahead (weekly peak half hour MW value)

ZOUY2     2 years ahead (weekly peak half hour MW value)

ZOUY3     3 years ahead (weekly peak half hour MW value)

ZOUY4     4 years ahead (weekly peak half hour MW value)

ZOUY5     5 years ahead (weekly peak half hour MW value)

 
Original Acceptance Volume    
This represents the initial value of the Acceptance Volume before any System Stack processing has been carried out on it.
 
Original Priced Acceptance Volume    
This value represents the amount of the associated Acceptance Volume which was not excluded from the System Price Stacks by De Minimis Tagging, Arbitrage Tagging and/or NIV Tagging, and which was Classified as Second-Stage Unflagged and therefore not subject to the Replacement Price.
 
P217 - Revised Derivation of the Main Imbalance Price BMRS in accordance with BSC T4.4    
Modification P217, introduced on 5 November 2009, modified the previous mechanism for calculating the Main System Price by introducing the following concepts:
  • Disaggregated BSAD (Balancing Service Adjustment Actions);
  • The SO-Flag to indicate where System Actions that are potentially taken for reasons other than balancing the short-term energy imbalance of the Transmission System;
  • The Classification of System Actions;
  • The Re-pricing of System Actions.
A detailed description is of the P217 indicative System Price Calculation is given within the BMRA URS.
 
PAR - Price Averaging Reference Volume     BMRS   in accordance with  BSC   T4.4
The Price Averaging Reference Volume is used to define a limit on the total volume of priced actions which are not De Minimis, Arbitrage, CADL or NIV Tagged that can be used to calculate the Main Price. The value of PAR is reported on the website.
 
PABV – Priced Accepted Bids Volume     BMRS   in accordance with  BSC   Annex T-1
For pre P217 Settlement dates the Priced Accepted Bids Volume is defined as the sum of the volumes of all Priced Bids accepted for the period which are not De Minimis Acceptance volumes and not Arbitrage Accepted Bids and not NIV Tagged Bids (for an explanation of the meaning of these terms, please see section 5.4 of the BMRA URS).

It should be noted that a consequence of this definition is that adding together the Priced and Unpriced Accepted Bids Volumes, PABV and UABV, does not necessarily give the total volume of Bids accepted for the Period, because any De Minimis, Arbitrage Accepted or NIV Tagged Bid volumes will not be included.
For post P217 Settlement dates the Priced Accepted Bids Volume is defined as the sum of the volumes of all Bids accepted for the period which are not De Minimis Acceptance volumes and not Arbitrage Accepted Bids which have not been Classified as Second Stage Flagged (i.e. which are not eligible to be re-priced). It should be noted that a consequence of this definition is that adding together the Priced and Unpriced Accepted Bids Volumes, PABV and UABV, does not necessarily give the total volume of Bids accepted for the Period, because any De Minimis or Arbitrage Accepted Bid volumes will not be included.
 
PAOV – Priced Accepted Offers Volume     BMRS   in accordance with  BSC   Annex T-1
For pre P217 Settlement dates the Priced Accepted Offers Volume is defined as the sum of the volumes of all Priced Offers accepted for the period which are not De Minimis Acceptance volumes and not Arbitrage Accepted Offers and not NIV Tagged Offers (for an explanation of the meaning of these terms, please see section 5.4 of the BMRA URS).

It should be noted that a consequence of this definition is that adding together the Priced and Unpriced Accepted Offers Volumes, PAOV and UAOV, does not necessarily give the total volume of Offers accepted for the Period, because any De Minimis, Arbitrage Accepted or NIV Tagged Offer volumes will not be included.
For post P217 Settlement dates the Priced Accepted Offers Volume is defined as the sum of the volumes of all Offers accepted for the period which are not De Minimis Acceptance volumes and not Arbitrage Accepted Offers which have not been Classified as Second Stage Flagged (i.e. which are not eligible to be re-priced). It should be noted that a consequence of this definition is that adding together the Priced and Unpriced Accepted Offers Volumes, PAOV and UAOV, does not necessarily give the total volume of Offers accepted for the Period, because any De Minimis or Arbitrage Accepted Offer volumes will not be included.
 
PDC - Price Derivation Code     BMRS   
The System Sell/Buy Price information published on the BMRS for each Settlement Period includes a Price Derivation Code which denotes the way in which SBP and SSP were derived by the calculation. The code is a character from 'A to L' and each code is explained below:

Code Description

SBP = Main Price

A SSP = Reverse Price
B SSP Capped to SBP
C SSP Defaulted to SBP
D SSP & SBP Defaulted to Market Price
E SSP & SBP Defaulted to Zero
P SSP = SBP

SSP = Main Price

F SBP = Reverse Price
G SBP Capped to SSP
H SBP Defaulted to SSP
I SSP & SBP Defaulted to Market Price
J SSP & SBP Defaulted to Zero
N SBP = SSP

No Main Price

K SSP & SBP Defaulted to Market Price
L SSP & SBP Defaulted to Zero
Note that Codes: D, E, I, and J are only applicable to pre P217 Settlement dates.

Note that post P305 Settlement dates ONLY Codes P, N, K and L are applicable and other Codes are not applicable.
 
POWER PARK MODULES - Power Park Modules     GRID CODE   GD
Generation derived from an intermittent power source (e.g. solar, wind, tidal, wave) with a single point of connection onto the GB Transmission System (or Distribution System if embedded) and with operational metering. The current set of Power Park Modules is available in an Excel spreadsheet that can be downloaded from http://www.bmreports.com/bsp/staticdata/BMUFuelType.xls
 
QAS - Balancing Services Volume     BSC   T4.3
The Balancing Services Volume is a volume which is received from the System Operator, which represents the volume of energy (MWh) associated with the provision of Applicable Balancing Services for each relevant BM Unit and Settlement Period. This volume is added to the total accepted bid and offer volumes for the relevant BM Unit when performing the Settlement calculations. Balancing Services has the meaning given to that term in the Transmission Licence, and Applicable Balancing Services refers to the Balancing Services in respect of which the System Operator submits Applicable Balancing Services Volume data.
 
QPN - Quiescent Physical Notification     GRID CODE   BC1
The Quiescent Physical Notification is a series of MW values and associated times expressing the volume of generation or demand expected to be generated or consumed (as appropriate) by an underlying process that forms part of the operation of a particular BM Unit. QPN values are not used in Settlement, but if submitted to the System Operator are deducted from Physical Notifications to determine a net operating level to which the Dynamic Data of a BM Unit apply at a particular time. Submission of QPNs is optional.

See also Final Physical Notification
 
 
Re-priced Acceptance Volume     GRID CODE   BC1
This value represents the amount of the associated Acceptance Volume which was not excluded from the System Price Stacks by De Minimis Tagging, Arbitrage Tagging and/or NIV Tagging, and which was Classified as Second-Stage Flagged and therefore subject to the Replacement Price.
 
RDRE - Run Down Rate Export     GRID CODE   BC1
Run Down Rate(s) Export express the rate of decrease in active power production for a particular BM Unit which is exporting power within a particular operating range. There can be up to three of these for a given BM Unit. They are part of the Dynamic Data.
 
RDRI - Run Down Rate Import     GRID CODE   BC1
Run Down Rate(s) Import express the rate of increase of active power consumption for a particular BM Unit which is importing power within a particular operating range. There can be up to three of these for a given BM Unit. They are part of the Dynamic Data.
 
RSP – Reserve Scarcity Price     BSC    T 3.13
Reserve Scarcity Price (RSVP), in respect of each Settlement Period, the Reserve Scarcity Price shall be calculated as:
RSVPj = LoLPj * VoLL
  • If there is no Final Loss of Load Probability available for a Settlement Period then the Final Loss of Load Probability shall be the most recently calculated Indicative Loss of Load Probability for that Settlement Period.
  • If there is no Indicative Loss of Load Probability or Final Loss of Load Probability available for a Settlement Period then the Final Loss of Load Probability shall be NULL and the Reserve Scarcity Price shall be calculated as RSVPj = 0
 
RURE - Run Up Rate Export     GRID CODE   BC1
Run Up Rate(s) Export express the rate of increase in active power production for a particular BM Unit which is exporting power within a particular operating range. There can be up to three of these for a given BM Unit. They are part of the Dynamic Data.
 
RURI - Run Up Rate Import     GRID CODE   BC1
Run Up Rate(s) Import express the rate of decrease in active power consumption for a particular BM Unit which is importing power within a particular operating range. There can be up to three of these for a given BM Unit. They are part of the Dynamic Data.
 
SBP - System Buy Price     BSC   T4.4
The System Buy Price is derived from Bid-Offer Acceptances, BSAD and Market Index Data. The Price Derivation Code can used to check how the price was derived.

The basic formula for computing the System Buy Price (SBP) for the settlement Periods before P217 is effective is:

SBP =  total cost of priced accepted offers + Energy Buy-Price Cost Adjustment (EBCA)          +   Buy-Price Price Adjustment (BPA)
 total volume of priced accepted offers + Energy Buy-Price Volume Adjustment (EBVA)


For Settlement Periods on and after P217 is effective, the same basic formula is used where SBP is the Main Price (where SBP is the reverse price SBP= Market Index Price), but with Disaggregated BSAD now combined with Acceptance data into a single set of System Buy Actions:

SBP =  total cost of System Buy Actions         +  Buy-Price Price Adjustment (BPA)
 total volume of System Buy Actions
 
SBVA – Buy Price Volume Adjustment (System)     BSC   Q 6.3
SBVA is one of the BSAD items (see above). Its derivation is given in the System Operator's BSAD Methodology Statement as

SBVA = max (Aggregated volume of all relevant Balancing Services purchased for system balancing purposes – Aggregated volume of all relevant Balancing Services sold for system balancing purposes, 0)
This value is non zero only for pre P217 Settlement dates.
 
SEL - Stable Export Limit      GRID CODE   BC1
Stable Export Limit is a positive megawatt value, expressing the minimum stable operating level at which a particular BM Unit can export power to the transmission system. It is part of the Dynamic Data.
 
SIL - Stable Import Limit     GRID CODE   BC1
Stable Import Limit is a negative megawatt value, expressing the minimum stable operating level at which a particular BM Unit can import power from the transmission system. It is part of the Dynamic Data.
 
SPA – Sell Price Price Adjustment     BSC   Q 6.3
SPA is one of the BSAD items. Its derivation is given in the System Operator's BSAD Methodology Statement as

SPA = (Aggregated cost of negative reserve option fees + Aggregated cost of sales of Forward Contract option fees) / (Aggregated volume of negative reserve contracts + Contracted MWh associated with options for Forward Contracts sold)

For the avoidance of doubt, if the denominator of SPA is zero in any Settlement Period, then SPA will be set to zero in that period.
 
SPLD – Forecast Surplus Day     GRID CODE   OC2.4
This data is also known as OCNMFD - Forecast Daily National Surplus based on OC2. It is part of the 2-14 day forecast produced each working day by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code.

The Surplus is calculated by comparing the forecasts of Output Usable, which are submitted by the generators in accordance with OC2, against the Transmission System Demand Forecast Day (TSDFD) data which is produced by the System Operator.

An allowance for Operational Planning Margin (OPMR) is added to the TSDFD figure for each half hour, and the difference between the resulting total and the forecast of Output Usable is the Surplus figure, as shown in the diagram.

OPMR is the amount of extra generation over and above forecast demand required to meet a Loss of Load Expectation of one occasion per year. It is based on:
  • The day ahead forecasts supplied by generators and the standard deviation of these forecasts.
  • The System Operator's demand forecasts and the standard deviation of these forecasts.
N.B. OPMR is not defined further in this Glossary as it is not data which is displayed on the BMRS.

The Surplus figure published for each day in the 2-14 day forecast is thus a half hourly average MW value for the half hour in the day which is forecast to have the highest demand.
 
SPLW – Forecast Surplus Week     GRID CODE   OC2.4
This data also known as OCNMFW - Forecast Weekly National Surplus based on OC2. It is part of the 2-52 week forecast produced each Wednesday by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code.

The process used to calculate the Surplus is analogous to that used to calculate the Forecast Surplus Day (SPLD) figures in the 2-14 day forecast.

The Surplus figure published for each week in the 2-52 week forecast is thus a half hourly average MW value for the half hour in the week which is forecast to have the highest demand.

SSP - System Sell Price      BSC   T4.4
The System Sell Price is derived from Bid-Offer Acceptances, BSAD and Market Index Data. The Price Derivation Code can be used to check how the price was derived.

The basic formula for computing the System Sell Price (SSP) for Settlement Periods before P217 is effective is:

SSP =  total cost of priced accepted bids + Energy Sell-Price Cost Adjustment (ESCA)         + Sell-Price Price Adjustment (SPA)
 total volume of priced accepted offers + Energy Sell-Price Volume Adjustment (ESVA)
For Settlement Periods on and after P217 is effective, the same basic formula is used where SSP is the Main Price (where SSP is the reverse price SSP= Market Index Price), but with Disaggregated BSAD now combined with Acceptance data into a single set of System Sell Actions:

SSP =  total cost of System Sell Actions           + Sell-Price Price Adjustment (SPA)
 total volume of System Sell Actions
 
SSVA – Sell Price Volume Adjustment (System)     BSC   Q 6.3
SSVA is one of the BSAD items (see above). Its derivation is given in the System Operator's BSAD Methodology Statement as

SSVA = min (Aggregated volume of all relevant Balancing Services purchased for system balancing purposes – Aggregated volume of all relevant Balancing Services sold for system balancing purposes, 0)
This value is non zero only for pre P217 Settlement dates.
 
STOR – Short Term Operating Reserve      BSC   Section Q 5.3
Short Term Operating Reserve (STOR) is needed because at certain times of the day the Transmission Company needs reserve power in the form of either generation or demand reduction to be able to deal with actual demand being greater than forecast demand and/or plant unavailability. Where it is economic to do so, Transmission Company will procure part of this requirement ahead of time through STOR.
The Buy Actions or Balancing Services Adjustment Actions could be provided by the STOR provider. BMRS will use the STOR flag in the BOALF and disBSAD will be used to identify STOR provider actions. In addition, BMRS will receive the STOR availability window information. For the STOR flagged actions (offers and disaggregation BSADs), if it is falling under the STOR availability window, it will be treated as a STOR action.
 
Tagged Acceptance Volume     BSC   Q 6.3
This value represents the amount of the associated Acceptance Volume which was excluded from the System Price Stacks by De Minimis Tagging, Arbitrage Tagging, NIV Tagging and/or PAR Tagging.
 
TEMP - Temperature      BMRS
Actual weather data is received by National Grid from their weather data provider for 6 weather stations around Britain. This data is used to calculate the actual GB average of all measured temperatures as at 12:00 local time on the previous day. This calculated average temperature is the temperature used within National Grid as part of the electricity demand forecasting process. The value is in degrees Celsius. If data from a particular weather station is unavailable on a given day, the transmission company will temporarily substitute this with data from another station.
 
TEMPHIGH - High Reference Temperature      BMRS
The High Reference Temperature is similar to TEMPNORMAL except that it has a 12% chance of being exceeded. The value is in degrees Celsius.
 
TEMPLOW - Low Reference Temperature      BMRS
The Low Reference Temperature is similar to TEMPNORMAL except that it has a 88% chance of being exceeded. The value is in degrees Celsius.
 
TEMPNORMAL - Normal Reference Temperature      BMRS
Normal Temperature is the daily average UK temperature which was exceeded on 50% of days during a 30 year historic period. The value is in degrees Celsius.
 
 
 
TRIAD - Triad Season      GRID CODE   GD
A Triad Season is a period of four months: November to February inclusive.
 
TSDF - Transmission System Demand Forecast      GRID CODE   OC 1.6.2
The Transmission System Demand Forecast is made by the System Operator. The System Operator Transmission System Demand Forecast is based on historically metered generation output for Great Britain. This value INCLUDES Interconnector flows and demand from station transformers and pumped storage units. The Transmission System Demand Forecast is comparable with the Initial Transmission System Demand Out-Turn ITSDO). All the forecasts are unrestricted, i.e. any notified customer demand management is included in the history.
 
TSDFD – Transmission System Demand Forecast Day     GRID CODE   OC2.4
The Transmission System Demand Forecast Day data is part of the 2-14 day forecast produced each working day by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code. It is produced using the same methodology as the daily Transmission System Demand Forecast. The figure published for each day in the 2-14 day forecast is a half hourly average MW value for the peak half hour in the day.
 
TSDFW – Transmission System Demand Forecast Week     GRID CODE   OC2.4
The Transmission System Demand Forecast Week data is part of the 2-52 week forecast produced each Wednesday by the System Operator as required by section 4.1.2 in Operating Code 2 of the Grid Code. It is produced using the same methodology as the daily Transmission System Demand Forecast. The figure published for each week in the 2-52 week forecast is a half hourly average MW value for the peak half hour in the week.
 
UABV – Unpriced Accepted Bids Volume    BMRS  in accordance with BSC  Annex T-1
For pre P217 Settlement dates the Unpriced Accepted Bids Volume for a period is the sum of the volumes of all Bids accepted for the period which have had their priced acceptance volumes set to zero because they do not form part of a continuous acceptance duration in excess of the Continuous Acceptance Duration Limit, CADL (at present set to 15 minutes) or they relate to an Excluded Emergency Acceptance. This volume is calculated by subtracting the total volume of priced accepted Bids (i.e. those which have not had their acceptance volumes set to zero) from the total volume of Bids accepted in the period. For a more detailed explanation of the calculations involved, please see section 5.4 of the BMRA URS.
For post P217 Settlement dates the Unpriced Accepted Bids Volume is defined as the sum of the volumes of all Bids accepted for the period which are not De Minimis Acceptance volumes and not Arbitrage Accepted Bids which have been Classified as Second Stage Flagged (i.e. which are eligible to be re-priced). It should be noted that a consequence of this definition is that adding together the Priced and Unpriced Accepted Bids Volumes, PABV and UABV, does not necessarily give the total volume of Bids accepted for the Period, because any De Minimis or Arbitrage Accepted Bid volumes will not be included.
 
UAOV – Unpriced Accepted Offers Volume    BMRS  in accordance with BSC  Annex T-1
For pre P217 Settlement dates the Unpriced Accepted Offers Volume for a period is the sum of the volumes of all Offers accepted for the period which have had their priced acceptance volumes set to zero because they do not form part of a continuous acceptance duration in excess of the Continuous Acceptance Duration Limit, CADL (at present set to 15 minutes) or they relate to an Excluded Emergency Acceptance. This volume is calculated by subtracting the total volume of priced accepted Offers (i.e. those which have not had their acceptance volumes set to zero) from the total volume of Offers accepted in the period. For a more detailed explanation of the calculations involved, please see section 5.4 of the BMRA URS.
For post P217 Settlement dates the Unpriced Accepted Offers Volume is defined as the sum of the volumes of all Offers accepted for the period which are not De Minimis Acceptance volumes and not Arbitrage Accepted Offers which have been Classified as Second Stage Flagged (i.e. which are eligible to be re-priced). It should be noted that a consequence of this definition is that adding together the Priced and Unpriced Accepted Offers Volumes, PAOV and UAOV, does not necessarily give the total volume of Offers accepted for the Period, because any De Minimis or Arbitrage Accepted Offer volumes will not be included.
 
VoLL – Value of Lost Load    BSC Section T 1.12
"Value of Lost Load" (VoLL) shall be £3,000/MWh. With effect from 1 November 2018 and for all Settlement Days thereafter, for the purposes of the Code the VoLL shall be £6,000/MWh. The VoLL will be reviewed from:
  • from time to time; and/or
  • upon the request of the Authority
 
WINDFOR – Wind Generation Forecast    BMRS  
A forecast of generation for all Power Park Modules. This daily forecast provides values for 4 different times of day (04:30, 10:30, 16:30, 22:30) and each forecast includes 49 values covering the period from 21:00 on the current day (D) to 21:00 D+2.