A group of Gas Distribution Network Operators, Biomethane project developers and trade association representatives met at the end of August. There had previously been a couple of forums for discussing biomethane connection issues (e.g. the Energy Market Issues for Biomethane (EMIB) and the “biomethane campaign group”) but neither had met for quite some time.
The meeting was convened to review progress to date, see what lessons had been learned and to explore whether there were any issues that needed working on. It had come about following a suggestion made by John Baldwin of CNG services to Matt Hindle of the Energy Networks Association, at UK Biomethane Day.
John felt that many of the “easy” projects had been done, and that a more innovative approach might be needed for the future wave of RHI projects. Now would be a good time to take stock, during the hiatus whilst developers wait for the RHI reforms. In future there will also be less flexibility to locate projects where there is grid capacity available, as the feedstock restrictions will create an incentive to be where the wastes and residues are located.
Various network operators participated at the meeting (Scotia Gas Networks, Northern Gas Networks, Cadent (formerly National Grid Gas Distribution) Northern Gas Networks and Wales & West Utilities.) Each gave an overview of where there are capacity problems and what they are doing about it. Cadent seems to have made most progress in developing “heat maps”. It is developing a red, amber, green map (green is where capacity is available, red is where reinforcement is needed). Eventually developers will be able to search the status of their desired location by postcode.
Other network operators were considering such maps. Most network operators will consider a number of options when it comes to connecting new capacity, (for example profiling systems to manage pressures to allow headroom, installing compression equipment, installing CNG fuelling stations) and the group took away an action to come up with a checklist of things to consider, which should be helpful for project developers. They agreed there are lots of areas to think about, including contractual issues and who pays for network reinforcement issues. Cadent was considering whether socialising of network reinforcement costs (something for which is there is currently no facility) might be desirable in the long run.
It is clear that there are a number of projects that have been put on hold with the delay to the implementation of the RHI decisions. Each network operator gave an idea of what is currently connected on their network, how many projects have accepted connection offers and have had connection offers made.
It is clear that quite a number of projects have commissioned connections (and secured a tariff for RHI purposes), but not yet started commenced regular injection. These will need to be re-commissioned, and network operators expressed some concern that this will take place at the same time as the backlog of projects on hold will want to ramp up development, which may have resource implications.
In response to a question from the chair about feedback on the network operators’ performance in connecting projects, developers commented that the process could be quicker and more uniform in some of the detail. An example of discrepancies was given – a developer could buy a grid entry unit (GEU) for one network, which in reality would probably work on any of the networks, but because each has subtle differences in specifications, GEUs are no longer interchangeable. Could this be resolved so that one specification could be issued for all?
Work has previously been done on a common specification, but it seems it was not detailed enough and it’s in the detail where the discrepancies are found. Views differed on whether a common specification could be achieved after around 6 months effort, or hit obstacles such that it could never be fully achieved. Even so, it would be good if the deviations were at least set out clearly, with an explanation as to why they exist. In any event there was a will to meet and see if greater commonality could be achieved, which is welcome. Developers suggested this could be done on on-going testing requirements too.
It seems that operating requirements have become onerous. One developer commented that their Grid Entry Unit costs more to maintain than the CHP, even though it has no moving parts in it.
There seemed to be agreement that with more experience of connecting and operating injection facilities and more sharing of operating data some requirements could be dropped. Proposals previously put to Ofgem will be looked at again in light of greater experience, and all in all it seems there is plenty of scope to bring costs down.
The differences in cost between different networks seems to be mostly accounted for because of differences in operating /ownership models, which is obviously not good as far as customers are concerned. Where costs have been contested in the past, historically the regulator has decided.
There are operational advantages to some of the ownership issues. For example if the project developer owns the odorisation equipment, and it goes down, there may be greater likelihood of it being fixed sooner, allowing the project to resume injection more rapidly. There is no compensation available if a plant is constrained off the grid through failure of equipment owned and maintained by the network.
When it comes to propoanation, it was hoped that the Future Billing project (see BIOSURF December 2016 newsletter item) may help, but even if the pilot is successful, the benefits would be a long time coming. There is a concern that with increasing volumes of LNG added to the mix, the average CV of gas on the network will increase, to the detriment of the biomethane industry which will find itself having to add more propane.
By Gaynor Hartnell, REA