List of BSC Issues

There are growing concerns in the industry about rising electricity losses, especially as shown by Line Loss Factors (LLFs) and the Group Correction Factor (GCF). BSCP128: Production, Submission, Audit & Approval of Line Loss Factors explains how to calculate LLFs. However, many in the industry do not fully understand why LLF and GCF values change.

Even though measures are in place to reduce settlement errors from LLFs and GCF, industry participants believe more could be done to uncover the main reasons for changes in LLF and GCF, which would help predict their future values.

To address the trend in electricity losses, we should:

• Review the LLF methodology to understand what it is, identify possible failure points, and determine if and how to improve its clarity and effectiveness.
• Assess the existing controls for the failure points identified.
• Examine the GCF methodology and consider whether it is still a fair way to share Settlement Error costs.

By reviewing these controls, we can suggest ways to improve current practices, which may lead to changes in the Balancing and Settlement Code (BSC), its related documents, or industry practices.

The current Market-wide Half Hourly Settlement (MHHS) design doesn’t accommodate advanced market segment Metering Point Administration Number (MPANs) where customers have opted out of Half-Hourly billing/Settlement consents. This limitation prevents the exchange of multi-rate meter register readings and meter configuration details among MHHS participants. Consequently, Suppliers face two significant issues. First, accurate billing is hampered as bilaterally obtained readings lack essential meter configuration data, making read-to-register matching impossible and potentially conflicting with Supplier Licence Condition 21B.1-21B.2 regarding read accuracy. Second, a lack of firm knowledge of meter configuration risks Suppliers using incorrect meter registers (e.g., non-cumulative) for Settlement purposes. Furthermore, the baseline MHHS design doesn’t incorporate Standard Settlement Configuration (SSC) or Time Pattern Regime (TPR) mappings for Settlement provisions, meaning crucial meter configuration understanding will be absent from Industry Standing Data.

Energy Theft is a significant contributor to Settlement inaccuracies, directly linked to 018 SVA Risk: ‘Revenue Protection volumes are not settled Risk 18’ . The failure to correctly account for energy theft in Settlement can lead to erroneous or estimated data entering Settlement. It is estimated that the financial impact of unaddressed energy theft exceeds £1 billion annually creating substantial risks for both Suppliers and the wider industry.

The following areas contribute to the inaccurate recording of Settlement Post-Theft:

•   Inadequate reporting: Evidence of tampering is not consistently reported on or documented correctly.

• Incorrect Adjustments: There are failures in recording meter advance adjustments, recalculating meter advances, as well as making accurate estimates, as required by Revenue Protection Services.

• Lack of Industry Awareness: A limited understanding of the Distribution Connection and Use of System Agreement (DCUSA), Balancing and Settlement Code (BSC) and UK Revenue Protection Association (UKRPA) frameworks lead to inconsistent applications of theft resolutions procedures.
• Insufficient Settlement Correction Mechanisms: The current process does not facilitate proactive resolution of Settlements post-theft, which discourages Suppliers from addressing discrepancies.

By improving the alignment between the processes used to track and address energy theft (Revenue Protection) and the Settlement Correction mechanism, the industry can be better incentivised to accurately report and rectify Theft-Related energy discrepancies. Strengthening these measures will support compliance.

Code of Practice (CoP) 1: ‘The Metering of Circuits with a Rated Capacity Exceeding 100 MVA for
Settlement Purposes’ and CoP2: ‘The Metering of Circuits with a Rated Capacity not Exceeding 100
MVA for Settlement Purposes’ currently refer only to the inductive Current Transformers (CTs) and
Voltage Transformers (VTs) of the 61869 series of standards.

However, CoPs 1 and 2 also contain a clause (in 5.1 ‘Metering Equipment’) that allows for individual
items of Metering Equipment to be combined to perform the same task, provided ‘the requirements’ of
the relevant CoP are met.

It is unclear if other types of equipment like Low Power Instrument Transformers (LPITs) could be used
as part of a combination of Metering Equipment that would constitute a Metering System.
Enabling this would allow manufacturers to develop innovative Metering Systems.

LPITs can provide the following benefits compared to conventional CT/VTs:

• Small and light weight: a major benefit especially for Offshore substations
• Improved personal safety: no dangerous voltages if the secondary winding of the current
  measuring element is left ‘open-circuit’
• Accurate at harmonics
• Very good linearity: convenient calibration at low voltage and current test points

To prevent double-counting in the Balancing Mechanism (BM), Modification P344,  requires Suppliers and Virtual Lead Parties (VLPs) to notify their Supplier Volume Allocation Agent (SVAA) of Meter System ID (MSID) Pairs (both Import and Export MSIDs). This creates challenges for Suppliers who may have different Import and Export Suppliers at a single site, leading to compliance issues. Additionally, the current AMSID registration process, with its three-stage manual validation, is inefficient for bulk updates and restrictive with regard to automation.

The proposed solution aims to streamline asset registration by using APIs and reducing manual steps for efficient updates. It also clarifies BSC rules on MSIDs to prevent double-counting, potentially allowing separate management of Import and Export MSIDs or giving a single BSP control over both.

Applicable Balancing Services Volume Data (ABSVD) is provided by NGESO to Settlement, in order to ensure that Lead Parties’ Energy Imbalance positions are adjusted to reflect ancillary services that the assets within their BM Units provide to NGESO. The original ABSVD process (introduced by Modification Proposal P71) was intended to work with BM Units for which the Lead Party was both Balance Responsible Party (BRP, liable for Energy Imbalance) and Balancing Service Provider (BSP, providing ancillary services to NGESO). But, more recently, Modifications P344 and P354 have provided mechanisms for NGESO to submit ABSVD where the customer’s BSP (an independent aggregator) is different to their BRP (the electricity supplier).

The contract between Elexon and the Energy Networks Association (ENA) currently passes the operational costs for the Radio Teleswitch Service (RTS) through the BSC as ‘BSC Costs.’ These costs amount to approximately £3.5 million, with around 1 million RTS devices (Radio Teleswitches and Radio Telemeters) in use. Under the existing arrangement, all BSC Trading Parties contribute to these costs based on their Funding Share.

However, Ofgem wishes to explore ways to incentivise Suppliers to promptly replace RTS meters. Ofgem has requested Elexon revisit a solution proposed in Issue 108. This solution aims to target RTS cost recovery specifically toward the relevant Suppliers. Additionally, considerations should be made regarding the reporting provided to impacted parties and publishing the relevant information in the interests of transparency.

At the May 2023 Performance Assurance Board (PAB) meeting, Elexon presented the findings report for an Assurance Information Request (AIR) on SVA Risk 005 (Fault Resolution). The PAB responded with questions around some of these findings, specifically around: The reporting of alarm flags through Hand Held Reads (HHR); Differing approaches to dealing with several types of alarm flags and which alarm flags the Half-Hourly Data Collectors (HHDCs) choose to report on; and General concerns around HHDC non-compliance with the BSC.

Elexon reviewed the findings report for an Assurance Information Request on SVA Risk 005. The Performance Assurance Board (PAB) responded with questions around HHDC obligations and general concerns around HHDC non-compliance. Elexon further reviewed party responses and concluded that three of the five concluded findings were compliant with the BSCP502 but are not adequate for purpose and required an additional review. 

Elexon considers that leaving this issue unresolved could lead to impacts on Settlement, this could lead to a further occurrence of this issue happening and a high materiality impact if left unresolved.

The Supplier Meter Registration Agent (SMRA) is a vital service under the Market Wide Half Hourly Settlement (MHHS) Target Operation Model (TOM) and the need to process messages and issue notifications within defined timescales is integral to enable downstream activities to take effect.

Service Level Agreements (SLAs) for SMRAs arrangements were added to the BSC as part of version 3.0 of the Retail Energy Code implementation, having originally been a part of the Master Registration Agreement. These SLAs are self-policed with the SMRAs distributing Service Credits to participants if not met and are not part of the BSC Performance Assurance Framework.

Whilst the concept of SLAs is still required, the current mechanism set out in Annex K-1 and BSCP501 is no longer appropriate due to the implementation of the MHHS Target Operating Model (TOM), with faster response times required. The MHHSP TOM does not address the concept of SLAs in relation to liquidated damages, therefore, BSCCo has raised Issue 111 to consider the best future approach.

The method of Energy Contract Volume Notification (ECVN) submission has remained the same since New Electricity Trading Arrangements (NETA) go-live in March 2001 with Section P of the BSC allowing for 20 minutes from submission to acknowledgement (after which an ECVAA System Failure is declared). The current practice of notification can put Trading Parties and their counterparties at financial risk, particularly when notifying close to the Submission Deadline. This is because the rejection feedback can be close to or after the Submission Deadline leaving insufficient time to make a correction.

The current solution is underpinned by ageing technology from submission, authentication, acknowledgment and reporting. Elexon operates to a 15 minutes service level rather than the 20 minutes ECVAA System Failure point for acknowledgement, this service level has been met in eight of the past 12 months. Customer feedback has indicated a preference for a reduced service level that is relevant to trading in real time and therefore requiring immediate acknowledgement of their trades. This may increase competition by increasing liquidity in trades closer to the Submission Deadline.

Many domestic customers are installing solar photovoltaics (PV) in their homes, allowing them to both consume the energy generated and export excess energy to the grid. However, the current Boundary Point Settlement metering system measures electricity Import and Export on an instantaneous basis. This means that even if a household generates and consumes equal amounts of energy over a period, they can still incur charges due to momentary imbalances between generation and consumption. As a result, customers may face higher bills and complexities in energy management. The current system also poses challenges in accurately reflecting the true energy surplus or deficit over a given settlement period.

The contract between Elexon and the Energy Networks Association (ENA) to pass the operational costs for the Radio Teleswitch Service (RTS) through the BSC as ‘BSC Costs’ is due to expire on 31 March 2024. The BSC pass-through operational costs are currently circa £5 million and there are circa 1 million RTS devices (Radio Teleswitches and Radio Telemeters) in use.

This Issue sought to review BSC Section N to identify which areas and associated processes are currently pain points experienced by the Industry. It aimed to identify solutions to address these to improve efficiency and the user experience for these processes.

The Credit Committee has requested that Elexon review the Credit Cover arrangements with industry experts through an Issue Group. This is in response to key concerns about credit being sufficient to protect the market from Supplier Failure while also not being an onerous burden on market participants. 

Issue 105 was raised to explore the consequential impacts of the P448 Alternative Modification and make a recommendation as to whether further industry change is required.

The contract between Elexon and the Energy Networks Association (ENA) to pass the operational costs for the Radio Teleswitch Service (RTS) through the BSC as ‘BSC Costs’ is due to expire on 31 March 2023. The BSC pass-through operational costs are expected to rise from c.£1.5m to c.£5m. Therefore, Elexon wishes to re-establish industry support for passing RTS costs through the BSC from April 2023 onwards, and confirm how the costs should be apportioned (for example Suppliers/Generators). It’s worth mentioning that since the BSC acts as a pass-through intermediary, Elexon has no control over the RTS cost, which is set through an ENA/BBC contract.

The Proposer believes that there would be value in reviewing existing controls for Settlement error prevention. It is critical to the Proposer that we address these problems prior to the Settlement timetable being shortened by Market-wide Half Hourly Settlement (MHHS) as the opportunities to readdress will be reduced thereafter.

A stakeholder survey conducted by Elexon identified a number of key issues/possible areas for improvement in the BSC Change process. The Issue Group  reviewed the BSC Change process to identify possible ways in which these key issues could be addressed or the BSC Change Process could be improved.

CP1584 ‘Allow non-BSC Parties to raise Change Proposals, add a CP withdrawal process and remove BCA/PACA concept’ was raised by Elexon on 1 August 2023 as a result of Issue 102.

Issue 101 intends to define the requirements and principles for the on-going Data Integration Platform (DIP) arrangements that can be included in a subsequent BSC Modification, including the ongoing governance, funding and operation of the DIP.

National Grid Electricity System Operator’s Distributed ReStart project seeks to enable distribution-connected Plant to participate in an updated version of Electricity System Restoration (currently defined as Black Start in the BSC).