REGULATORS - Let’s support consumers to electrify their homes most economically

Australian electricity regulators are generally focused on regulations to provide customer access for aggregators to deliver VPPs as the primary way to deliver end user load flexibility. But as I suggested in a previous LinkedIn post*, this approach alone does not provide the greatest value for consumers or the greatest load flexibility.

This approach to ‘CER’ (consumer energy resources) - a term which perhaps reveals the intention of using consumers as compliant resources for the grid - does not deliver what most of the 35%+ of consumers with rooftop solar want.

Consumers want to minimise their electricity bills by maximising in-home use of their PV investment and minimising power exports at low feed-in tariff rates. The best way to achieve that is to store surplus generation (in hot water and perhaps also battery(ies)), and/or use more to pre-heat/cool well insulated houses, to reduce consumption in high price periods. When V2H is available, EV batteries come into play for this purpose as a major storage option (6+ times the capacity of a home battery). Consumers would like to have a smart home energy management system (HEMS) to look after meeting their energy services needs and minimise costs, without calling on them to understand details of their energy use or use lots of their valuable discretionary time.

To do this HOME orchestration, their HEMS needs to be able to locally talk to home appliances and batteries (home and car) and other ‘CER’. Implementing this home orchestration should be as simple as getting the HEMS controller out of the box, plugging it in, and with an hour from an electrician to connect everything up (probably when he/she installs the EV charger or heat pump), away you go. Everything is plug and play – everything talks to the system using international standard protocol systems. This is what makes scalability of home electrification with control of energy costs possible, so:

The key to customer agency is plug and play interoperability

This is not rocket science. It is a matter of political/regulator will, to get the job done and enforce it. That is surely what regulators are there for – to protect consumers’ interests.

This could be achieved in 2 stages (implemented in parallel).

1. Regulate against walled gardens. All battery and EV OEMs should be required to provide local device level access for customers’ HEMS to talk to their batteries (including EV’s), without a charging for connectivity, and without requiring a round-trip communications path to their cloud. If this is not done, a HEMS cannot see the battery when taking control action (especially on loss of site internet), and a battery discharge to a VPP is then seen as a standard export of power which the HEMS is programmed to minimise. There should be no such walled gardens permitted. And when the NSW government implements its battery rebates and VPP incentives in November, the VPP incentives should surely only be eligible for batteries which provide local open access according to international standards with fully featured local control functionality, a requirement which has already been regulated in California and 12 other US States to ensure interoperability. And regulators should act now to ensure no new walled gardens are set up by companies which limit CER data access, control and response times. Billing (smart meter) data should also be accessible locally for connection to HEMS and networks to minimise consumer costs of installing parallel metering.
2. Regulate to require all OEMS to utilise standard plug and play interoperability standards, so everything connecting to the home and the grid must be able to communicate using standard protocols which are commonly interpreted and applied.

Please see attached below a paper produced by Grant Stepa, which provides guidance for regulators on changes required to achieve this outcome for the benefit of consumers.

Consumer Energy Resources (CER)

Industry Regulatory, Market and Technical Issues - Brief Summary

Grant Stepa - Aug 29, 2024

Context / Background:

Consumer Energy Resources (CER) are playing an ever increasing and significant role in the evolution of the two-way smart grid in the journey to “Net Zero”.

When referring to CER, this includes both generation and load that sits behind the grid/revenue meter which can be controlled / orchestrated for the financial benefit of the consumer (site/home) and in the provision of grid services (aggregated CER) for grid constraint mitigation, grid infrastructure investment deferral, and for grid security of supply including services such as demand response (DR) and frequency controlled ancillary services FCAS).

CER that typically participates in local orchestration (e.g. via a home energy management system, i.e. a HEMS) and in aggregation for grid services, includes “resources” such as Solar PV, Battery Energy Storage Systems (BESS), Smart Water Heaters, Electric Vehicle Chargers (including Vehicle to Grid – V2G), Pool Pumps, Air Conditioners, Heat Pumps and other load and generation. CER control may be simply intelligent On/Off switching of CER power, or there may be more sophisticated control options such as variable control of power.

A Site/Home HEMS may use such controls to optimise local use of excess Solar PV production (e.g. to heat water, precool/ preheat homes, charge a battery, charge an EV, run a pool pump etc), or to shift load out of high tariff periods, or to store solar PV energy in a battery for use in high tariff periods. In aggregation grid services can use CER for security of supply such as via a DNSP calling on load in a high solar period for use as a “solar soaker” (e.g. turning on water heating, pool pumps, battery charging etc) and /or for evening Peak Demand Abatement (e.g. turning off unnecessary load and discharging stored battery energy to assist the grid). The Australian Energy Market Operator (AEMO) can use VPP’s of consumer CER to maintain grid frequency (Contingency FCAS) whereby automation of CER control at sites/homes responds to correct grid frequency fluctuations outside normal limits by reducing load / increasing generation or increasing load / reducing generation dependent on the magnitude and direction (up or down) of the frequency excursion requiring correction.

Further, over the past few years DNSPs have been modifying their connection agreements to encompass the mandated control of certain CER (e.g. Solar PV, Batteries, Electric Vehicle Chargers) for network constraint mitigation via “dynamic connections”. This is typically referred to in the market as flexible export limits and/or flexible import limits and in combination as a dynamic operating envelope (DOE). The DNSP requires a 24/7 connection to the site/home and issues export/import limits with the site being required to act on these commands and report compliance or otherwise. The protocol that DNSPs are using in this communications is CSIP-AUS which has its basis in the International 2030.5 protocol. CSIP-AUS was developed by an Australian industry working group led by the ANU under an ARENA funded project. Further details on evolving concerns around dynamic connections particularly in respect to the increased capital and ongoing (“forever”) 24/7 connection costs that are being pushed onto consumers and vendors are detailed in this document.

For CER such as consumer Battery Energy Storage Systems (BESS) to provide the best financial outcomes for consumers, and to provide predictable and firm responses in the provision of grid services, a BESS must be coordinated / orchestrated locally at a site/home with other CER (e.g.by a HEMS).

Unfortunately, some of the BESS vendors, and one dominant OEM player in particular, does not allow (in Australia) the required local interoperable control (e.g. by a HEMS or DNSP Demand Management Server) of their BESS product, restricting all control to be only via their own cloud platform, and only by those entities (typically energy retailers) that have a commercial contract with the OEM. Further, any monetising of the BESS asset (despite being owned by the consumer) is not at the discretion of the consumer and requires a revenue sharing contract (retailer and OEM) to “unlock” certain control functions and required grid response times of the BESS. The consumer has little to no say in this arrangement.

These actions are to the detriment of the consumer financially in several ways including the inability to control the battery locally from say a HEMS to coordinate the BESS with other CER for the consumer’s financial gain, where instead the BESS “fights” with HEMS controlled CER e.g. for resources such as Excess Solar PV to the financial detriment of the consumer. Further in respect to grid services, a BESS enrolled in and responding to a grid service (e.g. a BESS discharge command) will be seen by the local HEMS as an electricity export from the site, and the HEMS thinking it is excess Solar PV, will turn on load thus negating the BESS response. Further as the consumer is “locked in” both technically and commercially to this “walled garden” closed eco system and cannot have their BESS locally controlled, they also cannot churn “their” BESS to the energy market service provider of their own choosing. There are now 10’s of thousands of these closed BESS systems deployed across Australia, which is a significant and growing problem, and as there is no current obligation (on vendors) for BESS CER to support interoperability nor to inform consumers of the “lock in” consequences at the time of purchase (so an informed buying decision can be made). These impacts to consumers and the grid will grow exponentially unless this is stopped.

Global moves to address this issue not embraced in Australia:

These experiences in Australia are not unique to Australia, and to mitigate the above BTM CER “lock in” issues, there has been a shift in US regulations to recognise local BTM interoperability as a mandatory requirement of CER Energy Generating Units (EGUs) such as Solar PV, V2G, and BESS inverter based generation, to enable local BTM orchestration of CER assets to deliver the best financial outcomes for consumers, to accelerate market competition, to enable CER asset churn independent of OEM alliances, and to ensure orchestrated BTM CER is a responsive, firm, and predictable grid asset.

California is the dominant US market for Solar PV and Battery CER EGUs, and the California Energy Commission (CEC) Solar Equipment Certification List details certifications to date for UL 1741 SB, which now calls up local interoperability compliance via international standard IEEE1547-2018. Specifically, Clause 10 of the IEEE1547-2018 standard defines the required physical interface and open protocols that a CER EGU (BESS) must support. This Clause also contains the requirements for CER EGU (BESS) mandatory control capabilities that the manufacturer must ensure are present.

In fact, most CER EGU (BESS) manufacturers are now promoting this interoperability capability in Australia, and delivering product compliant with this standard, however some of the larger (including the largest) manufacturer(s) are maintaining their proprietary connectivity by software remote disablement of access to the CER EGU (BESS) interoperability capability on equipment shipped to Australia. By restricting Australian consumers from accessing the local, open protocol interoperable capability of their CER EGU asset, these manufacturers are maintaining technical and commercial “lock-in” to the vendor’s walled gardens at the expense of the Australian consumer and grid security of supply. In most cases the consumer is unaware of this risk at the point of sale (there is no regulatory obligation for disclosure) which in the case of a proprietary BESS can leave the Consumer with a stranded CER EGU BESS asset of up to circa $A20k in capital costs.

This situation described above whereby interoperable local access for the BTM orchestration of BESS CER has been software disabled on CER assets delivered to Australia is simply unacceptable and is not consistent with consumer deliverables under the National Electricity Objective (NEO).

Actions required now for grid security of supply, to prevent consumer lock-in, and to increase competition:

● In advance of Australian specific standards based reforms to formally require BESS interoperability, it is recommended that energy market stakeholders (AER, AEMC, AEMO, DNSPs etc.) require BESS equipment manufacturers whose products are represented in Australia to remove any restrictions to accessing the CER EGU BESS interoperability capability as required for UL1741 SB compliance, as defined by Clause 10 of IEEE1547-2018, which beyond defining the required physical interface and protocols that a DER EGU must support, this Clause also contains the requirements for CER EGU BESS mandatory capabilities that the manufacturer must ensure are present.

● It is also recommended that Governments (Federal and State) as a matter of urgency, mitigate consumer “lock in” by supporting the principle of no consumer “lock in” to BESS closed systems, and require BESS to adhere to the above technical specification for interoperability as a prerequisite for participation in any government BESS rebate, low interest loan, peak demand or other like programs.

● As a case in point. The NSW Government announced BESS rebate and Peak Demand Reduction Scheme (PDRS) incentives are to commence on November 1 of this year (2024). Despite multiple representations from industry groups supporting interoperability and open systems, and from consumer advocacy groups, the NSW Government is yet to confirm local interoperability will be a mandatory specification for BESS participation in either scheme. Significantly, in the case of the PDRS which relies on a BESS to respond when called on, on sites with both a closed BESS and a HEMS, the BESS response (as detailed above) will be negated, impacting the firmness and predictability of the PDRS response and in doing so impacting grid security of supply. Further, from a fiscally responsible perspective it puts into question the effectiveness of the program, and hence the best use of public monies if funding is afforded to closed, proprietary BESS.

Finally, as all these BESS are “connected” for software maintenance purposes and required to be internet connected to participate in the PDRS, it is a simple task to “software enable” the local control functionality that has been turned off for all products sold to date in Australia.

Level 2 Electric Vehicle Supply Equipment (EVSE) is used by consumers and businesses throughout Australia. This equipment can deliver charging rates of up to circa 7.5kW (single phase) and 22kW (three phase). The default local interoperability (control) standards that are typically available on most brands of EVSE include Modbus and OCPP 1.6J. Where enabled, these L2 EVSE can have their power adjusted in real time in a similar fashion to open BESS for optimised solar self-consumption, for tariff arbitrage (charging shifted to low tariff periods) and where dynamic load management is required to ensure that 1 or many L2 EVSE are controlled in orchestration to ensure the power draw is within the constraints of the local wiring system, circuit protection devices and grid connections. Dynamic control is extremely important in multi-tenancy complexes (residential and commercial) which only have one connection point to the grid. Further DNSPs (See point 3) below) are starting to mandate EVSEs be connected to their demand management servers for receipt of 24/7 import limits as a mechanism for grid constraint mitigation, supporting grid security of supply.

The Energy Security Board (ESB) Stakeholders Steering Group (SSG) recommended to Government that all L2 EVSE support local control via the OCPP protocol.

Unfortunately, the above recommendation has not been adopted to date, with the implications of this being similar to the BESS issue described in 1) above, in that the consumer is “locked in” both technically and commercially to particular Manufacturers “walled garden” closed eco systems, whereby the consumer cannot have their L2 EVSE locally controlled, and they cannot churn control of “their” L2 EVSE to the energy market service provider of their own choosing. Further:

1) The L2 EVSE cannot be orchestrated on a site/home with other CER, e.g. by a HEMS, and instead the L2 EVSE and the HEMs will “fight” (e.g. for Solar PV resources) to the financial detriment of the consumer.

2) The L2 EVSE cannot be orchestrated by a local CSIP-AUS gateway that implements (by controlling the EVSE / CER) compliance with a DNSP dynamic connection in conjunction with other CER on a site/home. Sub optimal solutions of relay control to turn the EVSE power On/Off are then the only option to the detriment of the consumer, the grid, and have warranty implications.

3) In Multi-tenancy, (Apartments, Commercial Strata etc) dynamic control of multiple L2 EVSE of different brands is not possible leading to issues with compliance, lock in, and expansion in the number of L2 EVSE that can be deployed as EV penetration increases.

Further DNSPs have been unwilling to mandate minimum interoperability requirements for connection to their networks despite their increasing focus on dynamic connections and CER control. This then complicates the ability to comply with the dynamic connection, forcing additional costs which flow to the consumer, systems integrators and other energy market service providers that are “doing the right thing” in respect to interoperability and open systems.

Finally, whilst most brands of L2 EVSE support open standards for local control such as OCPP, it is a couple of majority players, and one OEM in particular (that has the highest L2 EVSE market penetration) that is maintaining a closed system to the detriment of consumers and the grid. This vendor DOES have a local control protocol which it uses for itself, but refuses to release it for general use.

Action needs to be taken urgently to mandate a requirement that all L2 EVSE have a local control interface and support for (at least) OCPP 1.6J including the smart, and security profiles of the standard.

Distribution Network Service Providers (DNSPs) are starting to implement mandatory dynamic connections for CER control including Solar PV and EVSE. For example, South Australian Power Networks has mandated this for Solar PV, and Energy QLD for EV chargers as defined in the latest Energy QLD connection agreement V4. These requirements are being put in place for minimum and peak demand abatement to avoid or minimise future network infrastructure investment by managing constraint mitigation for grid security of supply.

A DNSP dynamic connection requires compliance with a site export and/or import limit typically measured at the NMI connection point to the site/home. Maintaining the limit requires real time power quality data from the connection point and technology to modify the operation of the CER to ensure compliance with the DNSP dynamically issued limit(s). This is typically carried out by equipment at the consumer site (such as CSIP-AUS gateway device that has been certified by the DNSP) that must receive updates (24/7) from the DNSP Demand Management Server, typically by a protocol called CSIP-AUS (based on the International IEE2030.5 protocol)

This of course burdens consumers with additional capital costs of equipment (Class 1 metering and control equipment) and operational costs associated with implementing and maintaining a real time 24/7 “forever” connection from each consumer site/home to the DNSP server for receipt of compliance limits, to enable control of CER to comply with import/export limits.

Capital costs can exceed $1000 per site and operating costs circa $5 per month per site, with operational costs being “forever” costs. Long term equipment maintenance/ EOL replacement is also an issue.

The capital costs include parallel metering required for measuring site/home connection point net power flow to ensure compliance with DNSP dynamic connections. The parallel metering requirement component of the cost would be largely removed if the AEMC proceeds with rule changes for metering that recognises the consumer as the owner of metering data and enables the consumer local access to their smart meter real time power flow data. The data can then be used by local gateway devices or CER itself to comply with a DNSP dynamic connection limit thus reducing the capital costs of compliance.

Currently consumers are absorbing most of the capital costs and vendors / integrators are absorbing most all of the connectivity / compliance costs, it being difficult to pass all costs on to consumers - especially operational costs. This is not sustainable.

DNSP are subject to regulatory periods (typically 5 years) of budget approval by the AER. DNSPs say they have no scope to contribute to the above costs even though these solutions can be seen as “non-network” solutions for network infrastructure investment deferral or avoidance. To date the AER has failed to address these issues, including how to ensure the DNSPs fairly reward consumers for imposed technology and connectivity costs and use of the Consumers CER as required to maintain mandated CER import / export limits for grid constraint mitigation. As DNSPs are looking to expand the categories of CER that are required to be controlled to include BESS, Water Heating, Pool Pumps, Air Conditioning etc, this situation needs to be addressed so that consumers, integrators and OEMs are not burdened with costs, but rather rewarded for facilitating the integration of CER into the grid that can provide alternatives to network infrastructure investment.

Further, consideration should be given to pausing DNSPs expanding the use of dynamic connections for CER control, until such time as consumer local access to smart meter data is resolved by the AEMC, and the additional capital costs of compliance, along with ongoing equipment maintenance and “forever” 24/7 site

connectivity costs are assessed against the benefits that are currently only accruing to the DNSP. The DNSPs use of CER as a non-network infrastructure deferral / avoidance methodology should be based on a formalised mechanism to pay for kW / kWH use of CER by the DNSPs for constraint mitigation.

In implementing Dynamic Connections as described in 3) above DNSPs are allowing 3 approaches:

In both a) and b) above the control signals to the CER / CER site edge gateway comply with the open standards based CSIP-AUS protocol.

However, in c) above the standards-based control terminates at the OEM cloud.

Where a CER ONLY supports c) above this again creates multiple issues around control and orchestration when multiple CER are required to be controlled on a site for compliance with an export and/or import limit.

Again, this is burdening the consumer and industry with unnecessary costs to ensure compliance with DNSP export/import limits leading to suboptimal technical solutions and financial outcomes for consumers whilst also impacting grid constraint mitigation and security of supply.

Action required. Either DNSPs need to mandate that all CER comply with connectivity options a) and b), even if deployed initially as a proprietary connection c)

and/or

Resolving the significant underlying issues causing this, i.e. the lack of local CER local interoperability, again the main offenders being closed, walled garden BESS, and closed, walled garden EVSE. This being another reason to address recommendations in Points 1) (re BESS) and 2) (re EVSE) to require support for local interoperability be mandated.

Again, as per Point 3) above consideration should be given to pausing DNSPs expanding the use of dynamic connections for CER control, until such time as the above issues are resolved.

The control of Consumer CER for HEMs, for DNSP Dynamic Connections, and for other grid services requires real time power flow information from the connection point of the Site/Home.

Currently, secondary parallel Class 1 meters must be installed by the Consumers Energy Market Service Provider (at a considerable cost to the consumer) as the National Electricity Rules precludes access to the smart meter by other than the Metering Coordinator / Metering Data Provider (MC/MDP). There has been much representation to the AEMC on this matter and there is a possibility that this may be resolved by current rule changes both underway and proposed, that will enable consumers (or their representatives) to access real time power data locally from the smart meter.

However, access to just data is not enough and to ensure a commercially and technically neutral market for CER products and services the smart meter platform should be an enabler of CER technology and services and not a competitor to the providers of CER technology and services. Market distortion is already occurring in the provision of products and services for orchestration of CER to the benefit of the meter coordinator (MC) / metering data provider (MDP) and Retailers, and not to the benefit of consumers, DNSP constraint mitigation, grid services and a robust competitive CER product and services market. This is occurring as the MC/MDP are developing products and services embedded in / attached to the smart meter that only they can access with the consumer paying for the “sunk cost” of this deployment. Further they are developing products with integrated on market meters precluding any other energy market services providers from accessing these products (due to inadvertent NER protection afforded to the MC/MDP) ensuring lock in of both consumers and retailers to the MC / MDP products and services.

The competitive landscape in the provision of CER products and services is thus collapsing due to the privileged access the MC/MDP have to the metering platform (smart meter) and metering platform communications pathways (4/5G connection to the site). Access / use of the metering platform outside of the “intended” NER purposes of settlement, billing and platform maintenance is currently enabled via a loophole in the NER but only to the benefit of the MC/MDP. This loophole needs to be quickly closed such that any role the metering platform has with CER is not to the technical or commercial advantage of any one entity as it currently is for the MC/MDP. Further the NER must not enable technical or commercial interference (by the MC/MDP) with other entities using the metering platform as an enabling mechanism for CER control and orchestration such as through the authorised (by the consumer) use of the consumers metering data (including local real time data).

As such, the accelerated smart meter rollout determination (currently paused) and the proposed rule change request for FOC local access to smart meter data (by the consumer) which is to include real time data, needs to encompass these principles, but otherwise restrict the metering platform to its original intended purpose (of settlement, billing and platform maintenance) to ensure a robust, technically and commercially neutral market for CER products and services that can leverage (locally accessible) metering data, so the market is not forced to compete with the metering platform “custodians?” (i.e. the MC/MDP) and their current privileged access to, and use of the smart meter in the delivery of CER products and services. If the current situation continues there will be no open market for behind the meter CER products and services as the MC/MDP will dominate this space under the protection of the NER.

With the move to electric vehicles supporting Vehicle to Home/Load/Grid capabilities (V2H, V2L, V2G – collectively V2X) it is not enough to rely on simply ensuring that the EVSE (Charging / Discharging Equipment) supports standards-based interoperability per Point 2) above. Standards and regulations must be developed to ensure that the consumer can select an energy market service provider of their own choosing to monetise their electric vehicle asset without technical or commercial interference from vehicle manufactures (as is the current issue with closed, walled garden BESS (Per point 1)). Standards and regulations are needed to ensure that V2X capabilities are fully open at the vehicle level such that Vehicle OEMs are not able to restrict / modify access to features sets and/or say delay vehicle battery response times to their own competitive advantage to ensure consumers are “locked in” to only the OEM supplying some or all V2X services.

The Australian / New Zealand Standard AS4777 details certification requirements for inverter-based grid connected energy generation systems including Solar PV Inverters and AC coupled Battery Energy Storage Systems (BESS) as deployed across the National Electricity Market (NEM) and Western Electricity Market

(WEM). This standard is “called up” in the National Electricity Rules (NER), and under the various state-based regulations, and within DNSP connection agreements.

The AS4777 standard (as do most standards) has both informative and mandatory product compliance clauses.

One of the mandatory requirements is that inverter based products, including AC Coupled BESS have an external local interface conforming to Demand Response Mode Zero (DRM0) whereby the BESS can be locally and safely shut down (e.g. by a residential HEMS or Commercial BMS) via activation of this DRM0 interface to perform the “Safety Grid Disconnect” function as defined in AS4777, being mandatory for the issuance of a BESS product compliance certificate under AS4777.

However, certain (large) BESS OEMs have disabled this capability on product deployed in Australia and have not provided the necessary documents (as required by the AS4777 standard) nor provided the required product markings to indicate both compliance, and the physical location of the DRM0 interface on the BESS. Even though they have provided a certificate of compliance to the Clean Energy Council (CEC).

This inability to locally access / activate the AS 4777 mandatory DRM0 interface on a BESS has not only implications for the local orchestration of CER, but also has significant safety implications, as a BESS DRM0 interface is used by a Home Energy Management System (HEMS) to safely control the “grid disconnect” function of the BESS via the DRM0 interface, for instance due to the HEMs receipt of a residential smoke alarm trigger (A smoke alarm at the BESS location being a required of the NSW Government PDRS due to commence November 1st 2024). On commercial sites there is a similar use of DRMO by the site Building Management System (BMS) which for instance may use the DRM0 interface to shut down the BESS when a fire alarm system alert is received by the BMS.

The lack of compliance with the mandatory DRM0 requirement under AS4777 goes beyond a mechanism for basic control and presents an OH&S risk to both persons and property.

As it is the same OEMs that have deactivated the Demand Response Mode Zero (DRM0) BESS external control that have also disabled BESS local interoperability per the issue raised in previous Point 1) above, one can only conclude that those vendors who do not comply with this mandatory requirement of AS4777 for DRMO “Safety Grid Disconnect”, are doing so to maintain their total control over the product from their cloud based platforms.

Unfortunately, beyond safety considerations, this also has further cost, complexity and warranty implications as DNSPs that are specifying a mandatory dynamic connection (via their CSIP-AUS Demand Servers for grid constraint mitigation) that also require local BESS control (via interoperability and/or DRM0), are unwilling to address this situation, and have even gone as far to suggest that HEMS providers / integrators implement dumb On/Off relay control to abruptly (without a proper shutdown) disconnect the power supply to the battery at the switchboard to ensure compliance with the DNSP dynamic connection.

As AS4777 is called up in the NER, the AER have been approached by multiple parties on multiple occasions with the above issue, however the AER have indicated they “have no policing and enforcement powers” for standards that are called up in the National Electricity Rules. Their suggestion was to approach DNSPs, the Clean Energy Council (CEC - custodian of the certification certificates) and State Based Regulators with the issue.

The feedback from DNSPs has been an unwillingness to investigate and defect non-compliant BESS. Indications (unwritten) are that the DNSP unwillingness to address the issue is due to OEM influence and potential legal challenges for which they believe there would be no Government support (refer AER comments above).

Unfortunately, despite multiple entities also reporting the issue to State-based regulators (e.g. Office of the Technical Regulator in South Australia, Department of Fair Trading in NSW etc) they too have been unwilling / unable to act after reported “interaction” with the OEMs, whose equipment does not conform to the mandatory DRM0 requirement of the AS4777 standard. OEMs that benefit from maintaining a totally closed BESS product (a walled garden) that cannot be locally controlled.

Finally, in the case of the CEC who maintains the list of certificates of compliance to AS4777. Despite reporting the non-compliances, the CEC was unwilling to investigate / confirm the non-compliances and simply blindly continues to point to an OEM supplied certificate as proof of compliance. It is not lost on industry that the CEC is a member organisation and that the OEMs in question have held senior representative positions on relevant committees and even the CEC Board.

The above is a growing safety and compliance issue that requires Government action to bring about the required compliance of these BESS products with AS4777.

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