Open Energy Networks – a welcome addition to the reform mix

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MHC has been working at the forefront of the emerging distributed energy marketplace for several years, as highlighted by our work on virtual power plants with Simply Energy, EnergyAustralia, Yurika Energy, and GreenSync. Our earlier editions of QSI cover the need for innovation to realise the potential of a distributed energy future and the future grid marketplace and the role of the “platform”. While there has been some progress in this area, we had been concerned by the lack of coordinated stakeholder engagement in Australia, particularly compared to the efforts of electricity sector counterparts in the UK and New York. So, MHC welcomed the joint AEMO/ENA initiative to discuss coordination of distributed energy resources (DERs) through the Open Energy Networks consultation (OpEN). We consider this consultation to be an important step towards developing the regulatory framework and governance arrangements to facilitate optimal operation of DERs.

What’s OpEN all about?

AEMO and ENA are currently conducting a public consultation on the system architecture required to best transition to a two-way grid that allows better integration of distributed energy resources for the benefit of all customers. They have identified three options to support this transition:

  • A single integrated platform operated by AEMO
  • Two-step tiered regulated platforms operated by each DNSP
  • A single or multiple independent ‘DSO’(s)

The single integrated platform would be a distribution-level extension of the centralised markets currently operated by AEMO, namely wholesale supply, ancillary services, and emergency reserve. AEMO would work with DNSPs to develop an appropriate single platform. The platform would resolve local network constraints, effectively coordinating network support across each distribution network, as well as facilitating the participation of optimised DERs in centralised markets.

The two-step tiered regulated platforms would be various distribution-level platforms (one for each distribution network) interfacing with AEMO.  DNSPs could design platforms to best meet their local system requirements, and optimised DERs would communicate directly with their relevant DNSP platform, each of which would be responsible for coordinating network support. DNSPs would provide AEMO with aggregated generator/load positions for each transmission connection point, and AEMO would in turn communicate dispatch targets for each of these points which DNSPs would meet utilising the competing bids of optimised DERs.

The independent ‘DSO’ model could be a variation on either the single integrated platform model or the two-step tiered regulated platforms model, involving an independent party operating the platform rather than AEMO or the DNSPs respectively. The ‘DSO’ would dispatch DERs based on local network constraints (information about which would be provided by DNSPs) and provide aggregated bid to the centralised markets operated by AEMO.

These options, and the advantages and disadvantages of each, are as follows.[1]

MHC took the opportunity to respond to the consultation and our response included three main points:

  1. Don’t forget the customer
  2. Work it through with practical examples
  3. Clarify the functions first, then worry about who will do what

Don’t forget the customer

While the consultation title refers to customer benefits, and the value streams for customers with access to DERs are outlined in part 2, the bulk of the consultation paper is framed in terms of the DERs themselves, as distinct from their prosumer owners, and there is no explicit reference to the majority customer segment that has no access to DERs. From this perspective, the focus of the consultation paper tends towards mitigating technical problems by imposing controls on DERs which would likely restrict their utilisation.

MHC recommends that the Open Energy Networks consultation reframes its analysis from the customer’s perspective. Customers, both prosumers and those without access to DERs, will benefit most from distribution-level markets that facilitate aggregator participation in AEMO’s centralised markets and the network support markets servicing each DNSP’s network. These distribution-level markets, and the latent DER capacity that they stand to unlock, represent the best means of exerting downward pressure on prices for wholesale supply, ancillary services, emergency services, and network support, all of which flow directly through to customers’ tariffs.

Work it through with practical examples

Consider an example involving two orchestrated bundles of DERs (i.e. virtual power plants (VPPs)) operating on the same distribution network of ‘DNSP-A’. VPP-1 is operated by Aggregator-X, VPP-2 is operated by Aggregator-Y, with both aggregators contracting access to DERs owned by various customers on the DNSP-A network. VPP-1 has bid into the wholesale energy market operated by AEMO, VPP-2 has a contract to provide network services for DNSP-A (e.g. an augmentation deferral via a RIT-D process) and also regularly bids into the wholesale energy market as a non-market participant. Some of the DERs that both aggregators have nominated to support their respective bids sit on the same feeder line, the connection point of which does not have the capacity to dispatch all contracted DERs at the same time due to a localised constraint.

Which DERs get dispatched; VPP-1, VPP-2, or a limited amount of both? How is this determined to ensure equitable customer outcomes?

While the paper provides a brief description of some key functions in DER optimisation, it doesn’t link these specifically to the three architecture design options, particularly relating to the functions encompassed by the distribution system operator (DSO). Is the resolution of the market scenario described above a system operation function or a market operation function?

We propose that this scenario requires a distribution market operation (DMO) function, which resolves the prioritisation of VPP-1/VPP-2 DERs. This could be done via pre-secured firm access rights, prescribed hierarchy within distributed energy system market rules, a secondary market bidding system, or some other mechanism. While we consider the commercial function of the DMO will be closely tied to the technical function of the DSO, these two functions are very different.[2]

System operation functions should determine export limits on distribution network feeders to ensure that, regardless of market movements, the system continues to operate within its physical limitations, while the market operation function should ensure prioritisation to achieve the most efficient DER dispatch mix where network feeders are constrained.

This highlights the different perspective reached by approaching this challenge through the application of practical examples to identify what functions are required within the system architecture first, before focussing on responsibilities for these functions.

Clarify the functions first, then worry about who will do what

A useful next step would be to develop a series of detailed use cases for DER trading, clearly defining the functions involved in each of these use cases. Once the functions are clear in relation to real trading situations, it will be easier to canvas options for organising these functions amongst existing and/or new operational entities. It’s difficult, and problematic, to attempt to assign governance responsibilities when the functions to be governed are yet to be determined and fully understood by stakeholders.

You can read our full response here

[1] Based on details provided in the Open Energy Networks Consultation Paper;

[2] This makes the use of the term ‘independent Distribution System Operator (iDSO)’ problematic for the third option discussed in the consultation paper