Implementation of DCUSA Changes

The following sets out 2 issues regarding the implementation of DCUSA changes:

1) Insufficient Lead Times for implementation of Changes

Currently certain DCUSA changes do not have sufficient lead times from Authority decision approval to implementation. Industry parties require a minimum of 6 months lead times from Authority decision approval to implementation for DCUSA modifications which have systems impacts.

A recent example of this is DCP 409 ‘Change to Credit cover calculations to include Last Resort Supply Payment’ which was rejected by the Authority on the 03/03/2023, Had this change been approved, the Implementation date proposed and consulted on for DCP 409 was “Next scheduled release or within one month of the Authority Decision, whichever is the sooner”.

Whilst we understand the proposer’s preference for this change to have a short implementation date to achieve maximum benefit; it did have a system impact to DNO’s and consequently a subsequent financial and resource impact.

Due to the short lead time proposed (which could be less than 6 months), DNO’s such as ENWL have felt forced to take the decision to pre-emptively make changes to Durabill (a shared DNO billing system) and individual internal systems to enable effective implementation management of the change and to avoid the risk of non-compliance had the Authority decision been in favour of the CP.

The alternative was to wait for the Authority decision and approval from Ofgem and then instruct St Clements Services (the DNOs Durabill Service Provider) to make the changes to Durabill, however, the necessary changes to Durabill could not be completed in such a short timescale.

Our proposed remedy: sufficient lead times for implementation of changes via adjustments to the implementation of DCUSA change to include an improved approach to decision making regarding implementation dates and minimum lead in times from the point of Authority approval. As this type of work is funded by customers’ bills, we would prefer not to have been in this position again, particularly considering the current energy and cost of living crisis, ahead of Ofgem decisions.

In the example above, it meant that we have moved the risk onto customers as a result of the timescales chosen for the DCUSA change. We have a licence obligation to comply with DCUSA, so we would not take a path that would mean we certainly would not comply (i.e., our licence steers us to having to start making changes ahead of Ofgem decisions where that is only way to comply).

Whilst this issue is heightened with changes that require system amendments, we would like to discuss possible alternative solutions to how industry parties currently manage DCUSA change implementation dates.

It is our understanding that the dates should then be reviewed at each Working Group as a standard agenda item and the website reflected accordingly. We have included a proposed alternative solution below to the allocation of Implementation dates, but we would welcome the chance to review alternative solutions with the Group, as well as a review of best practice approaches taken with other codes.

2) Implementation of Change with an interim and incomplete solution.

DCP 383 “Provision for Distributors to Move Meters for Service Alterations” was approved by the Authority as an interim solution and in absence of agreed upon associated market messaging (dataflows). Following implementation of the interim solution in February 2022 a DCUSA Working Group was then required to design the associated market messages (dataflows) that would enable communication of data between suppliers and DNOs. The associated market messages were approved and implemented for use 12 months after the interim solution was implemented in February 2023 (with the requirement for mandatory compliance by June 2023).

Some suppliers have chosen to wait for the new market messages to be in place before allowing DNO’s to move meters. This has resulted in delayed, confusing and a piece meal approach to industry and its customers receiving the benefits from the change.

At the voting stage for this change the full design solution was not agreed, instead it was clarified that:

•  This was an interim solution before moving to a final solution
• No changes had been raised to implement the new dataflows/market messages
• Costs for new dataflows/market messages were unknown
• No photos to help identify in scope / out of scope meters had been provided
• There were going to be lists of:
  • Suppliers that did not wish Distributors to move their meters
  • Suppliers that would allow Distributors to move meters and would be happy to use the interim solution
  • Suppliers that would allow Distributors to move meters, but not until an approved data flow/market message is in place.

Our proposed remedy: only full solutions are discussed/approved by the DCUSA change control governance/forums and submitted for Authority approval (where appropriate) – We would welcome a review of best practice approaches for other codes as part of developing a solution.

Our understanding is that other codes do not allow the solution to be designed after the CP implementation and this creates uncertainty and risk.