Distribution System Operator (DSO) and beyond. Final technical report

N4 Opportunity Assessment

Distribution System Operator and Beyond: Optimising Planning and Regulation for Demand Management and Distributed Energy Resources

Final Technical Report

RACE for Networks

Research Theme N4: DSO and beyond: Optimising Planning and Regulation for DM and DER

ISBN: 978-1-922746-44-3

Industry Report

An Opportunity Assessment for RACE for 2030 CRC

August 2023

Citation s

Cantley-Smith, R., Ben-David, R., Briggs, C., Dwyer, S., Hargroves, C., Kallies, A., Khalilpour, K., Kraal, D. and Liebman, A. (2023). Opportunity Assessment: DSO and beyond: Optimising Planning and Regulation for DM and DER. Prepared for RACE for 2030 CRC.

Project partners

Acknowledgements

Project team

University of Technology Sydney

• Rowena Cantley-Smith (Project Leader)

• Chris Briggs

•

• Scott Dwyer

Kaveh Khalilpour

Royal Melbourne Institute of Technology

• Anne Kallies

Curtin University

• Charlie Hargroves (Project Manager)

Monash University

•

Ariel Liebman

•

Ron Ben-David

•

Diane Kraal

The authors would like to thank the stakeholders involved in the development of this report, in particular the interviewees and the industry reference group members who have given so generously of their time, including Energy Consumers Australia, Western Power, NSW Department of Planning & Environment, SA Department of Energy and Mining, Energy Consumers Australia, and Plico Energy. Whilst their input is very much appreciated, any views expressed here are the responsibility of the authors alone.

Acknowledgement of Country

The authors of this report would like to respectfully acknowledge the Traditional Owners of the ancestral lands throughout Australia and their connection to land, sea and community. We recognise their continuing connection to the land, waters and culture and pay our respects to them, their cultures and to their Elders past, present and emerging.

What is RACE for 2030?

RACE for 2030 CRC is a 10-year cooperative research centre with AUD350 million of resources to fund research towards a reliable, affordable and clean energy future. racefor2030.com.au

Disclaimer

The authors have used all due care and skill to ensure the material is accurate as at the date of this report. The authors do not accept any responsibility for any loss that may arise by anyone relying upon its contents.

GLOSSARY

ACCC Australian Competition and Consumer Commission

ADR Automated demand response

AEM Australian Energy Market

AEMA Australian Energy Market Agreement

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

AES Autonomous energy systems

ARENA Australian Renewable Energy Agency

BEV Battery electric vehicles

C - CEM Consumer energy market

CER Consumer energy resources

CRC Cooperative Research Centre

DEIP Distributed Energy Integration Program

DER Distributed energy resource

DER - AO Distributed energy resource asset owner

DM Demand management

DMIS Demand management incentive scheme

DNSP Distribution Network Service Provider

DRSP Demand response service provider

DSM Demand-side management

DSP Demand-side participation

DSR Demand-side response

DUoS Distribution use of System

ECA Energy Consumers Australia

Energy Ministers Forum for Australia’s Energy Ministers (replaced COAG)

ERF Emissions Reduction Fund

ESB Energy Security Board

ESS Energy storage system

EV Electric vehicle

FCAS Frequency Control Ancillary Service

FCEV Fuel-cell electric vehicles

G2V Grid to vehicle

ICE Internal combustion engine

IEA International Energy Agency

IRG Industry reference group

ISP Integrated system plan

KPI Key performance indicator

LV Low voltage

MV Medium voltage

NECF National Energy Customer Framework

NEL National Electricity Law

NEM National Electricity Market

NEO National Energy Objective

NERL National Electricity Retail Law

NERO National Energy Retail Objective

NERR National Electricity Retail Rules

NREL National Renewable Energy Laboratory

NUoS Network use of System

OA Opportunity assessment

OEM Original equipment manufacturer

PDRS Peak Demand Reduction Scheme

PHEV Plug-in hybrid vehicle

PV Photovoltaics

RACE Reliable Affordable Clean Energy for 2030 CRC

RERT Reliability and emergency trader

REZ Renewable energy zone

RIT - D Regulatory investment test distribution

RIT - T Regulatory investment test transmission

RTPV Rooftop photovoltaic

STPIS Service target performance incentive scheme

TMIS Transmission management incentive scheme

ToU Time of use

TUoS Transmission use of System

V2G Vehicle to grid

V2H Vehicle to home

V2X Vehicle to “x–“ generic term for vehicle to grid, to home, to premises, etc.

VGI Vehicle grid integration

VRP Voltage stability, reliability and power loss

WDRM Wholesale demand response mechanism

WEM/SWIS Western Australian Wholesale Electricity Market/South West Interconnected System

ZLEV Zero and low carbon electric vehicles

1. RESEARCH RESULTS AND DISCUSSION

The growth in uptake of rooftop solar PV continues at pace throughout Australia. Individual and community interest and investment in batteries, EVs and other forms of DER is likewise on the rise. Experiences from both international and several Australian jurisdictions confirm that a high DER, decarbonised energy future in which safety, security, and reliability of power systems, energy efficiency and emissions reductions, and value and benefits to consumers feature equally is achievable. This discussion builds on the findings and discussions set out in the Summary Report. Together they provide a comprehensive discussion of key issues that require further thinking and research that forms an integral part of the various future research projects set out in the roadmap.

1.1. Regulatory barriers and opportunities

The need for regulatory definitions, roles and responsibilities

The current national regulatory framework fails to fully address fundamental issues such as the introduction of a new market participant or institutions DSO and/or DMO with DER orchestration, participation and aggregator roles, functions, and responsibilities into the NEM and NERM. The existing national regulatory DSO definition, for example, sets out the national electricity rules, but fails to adequately provide for the current and emergent high DER market paradigm. Individual jurisdictional responses already in place, such as those in Western Australia, provide practical insights that can be drawn upon to inform the substantial amendments to the current national regulatory arrangements. Further essential regulatory amendments include energy efficiency and DM definitions and a DER definition that details the growing range of DER and DER asset ownership, in particular consumerowned DER.

Ratcheting up the pace of regulatory change driving complexification

The review and analysis to date show a range of current, emergent, and prospective governance, legal, and operational issues arising from the rapid change underway in policy and regulatory framework across the Australian energy market. This includes:

• AEMC approved rules changes that have, or are about to, come into effect 1

• The issuance of guidelines and other related regulatory instruments by the AER 2

1 AEMC: National Electricity Amendment (Regulated stand-along power systems) Rule (effective at of 1 August 2022) https://www.aemc.gov.au/sites/default/files/202202/SAPS%20NER%20amending%20rule%20final%20 2022.pdf. See response by AEMO, e.g., regarding the process and system changes required to implement and support new market and power system arrangements under the Integrating Energy Storage Systems Final Rule Determination: DRAFT IESS implementation strawperson: Integrating Energy Storage Systems project (July 2022) https://aemo.com.au/-/media/files/initiatives/submissions/2021/iess/integrating-energy-storage-systems implementationstrawperson draft.pdf?la=en; AEMO, 2022 Integrated System Plan For the National Electricity Market (June 2022) https://aemo.com.au//media/files/major-publications/isp/2022/2022-documents/2022-integrated-system-plan-isp.pdf? la=en

2 See eg: AER’s consultation initiated on Incentivising and measuring export services performance (commenced 5 August; to be completed December 2022) as part of key obligation on AER under its Access, pricing and incentive arrangements for distributed energy resources Rule change; see AER, Consultation paper Incentivising and measuring export service performance (August 2022) https://www.aer.gov.au/system/files/AER%20-%20Consultation%20paper%2020Incentivising% 20and%20measuring%20export%20service %20performance%20-%20August%202022.pdf; AER, DER integration expenditure guidance note (June 2022) https://www.aer.gov.au/networkspipelines/guidelines-schemes-models-reviews/assessing-distributed-energy-resources-integration-expenditure-guidance-note/final-decision

• Ongoing actions of AEMO concerning ESB Post-2025 reform initiatives, 3 such as flexible demand and advancing the integration of utility-scale renewables and DER into the market 4

• Decisions by the energy ministers, all of which have far reaching consequences for current and future energy markets in Australia 5 and

• Growing levels of re-engagement by federal and state/territory governments in the energy sector, including legislative deviations enacted by several jurisdictions that enable departure from the existing regulatory framework governing the NEM 6

State legislative frameworks are also changing. In addition to the advanced state of DER in WA, 7 other jurisdictions are advancing their policy and regulatory response positions on DER and DM (e.g. Victoria’s recently released DER initiative Harnessing Victoria's Distributed Energy Resources). 8 In a similar vein, NSW’s enactment of the Electricity Infrastructure Investment Act 2020 created a new independent entity the consumer trustee ‘to look after the long-term financial interests of NSW electricity customers to improve the affordability, reliability, security and sustainability of electricity supply … through long-term planning and well-structured procurement processes’. 9

In general terms, the escalating pace of regulatory changes is leading to more, not fewer, questions about the emergent energy market and the extent to which consumer benefits are being recognised, offered and guaranteed. As a consequence, many of the regulatory issues identified in this opportunity assessment involve definition; conceptual and technological considerations remain unresolved. This issue will need to be addressed in any further research projects, especially in light of current and anticipated forthcoming regulatory developments occurring throughout the various participatory jurisdictions of the NEM.

Moreover, the complexification and magnitude of the existing regulatory framework (e.g. policies, laws, regulations, rules, industry codes and so on) present as significant barriers to a successful energy transition that warrant planned, holistic regulatory change. Nowhere is this more pressing than in

3 ESB’s Post-2025 Market and DER Implementation Plan, Integration of distributed energy resources (DER) and flexible demand, https://esbpost2025-market-design.aemc.gov.au/integration-of-distributed-energy-resources-der-and-flexible-demand#delivering-the-derimplementation-plan

4 See e.g., AEMO, NEM market suspension and operational challenges in June 2022 (August 2022 ) https://aemo.com.au//media/files/electricity/nem/market_notices_and_events/market_event_Reports/2022/nem-market-suspension-and-operational-challenges-injune-2022.pdf?la=en; Updated 2021 Electricity Statement of Opportunities (April 2022) https://aemo.com.au//media/files/electricity/nem/planning_and_forecasting/nem_esoo/2022/update-to-2021-electricity-statement-of-opportunities.pdf? la=en. See also AMEO involvement in ESB Post-2025 reform initiatives

5 See eg, Energy Ministers, Meeting Communiques (8 June 2022) and (11 August 2022) https://www.energy.gov.au/government-priorities/energyministers/meetings-and-communiques.

6 See e.g., NSW: Electricity Infrastructure Investment Act 2020; Victoria: National Electricity (Victoria) Act 2005 (amendments introduced in 2020).

7 Energy Transformation Taskforce, DER Roadmap (WA Government, April 2020) https://www.wa.gov.au/system/files/202004/DER_Roadmap.pdf.See also subsequent Report, including: Energy Policy WA, Leading Western Australia’s brighter energy future Energy Transformation Strategy Stage 2: 2021-2025 (WA Government, July 2021), https://www.wa.gov.au/system/files/2021-07/Energy-TransformationStrategy-Stage2-July2021.pdf; Distributed Energy Resources Roadmap April 2022 Two-year Progress Report: April 2022 (WA Government, 2 June 2022), https://www.wa.gov.au/government/publications/distributed-energy-resources-roadmap-two-year-progress-Report

8 Victorian Government, Harnessing Victoria's Distributed Energy Resources (2022) https://www.energy.vic.gov.

au/data/assets/pdf_file/0033/568284/Harnessing_Victorias_Distributed_Energy_Resouces.pdf. See further DELWP, Distributed energy resources, https://www.energy.vic.gov.au/renewable-energy/distributed-energy-resources

9 NSW Government, https://www.energyco.nsw.gov.au/industry/consumer-trustee See also AEMO Services, https://aemoservices.com.au/consumers/our-role-as-consumer-trustee

traditional retail electricity markets and their adverse consequences for consumers. Often referred to as the retailer–distributor–consumer interface, the integration of the accelerating quantity of individually owned and community-owned DER into established power systems is challenging at many levels, including technical, economic and regulatory. Such challenges can be characterised in many ways. Relevant to this opportunity assessment, challenges to the retailer–distributor–customer interface include essential services, the social contract and/or licence. As an essential service, supply of, and access to, energy services have long been critical elements of the social contract between the state and its citizens. The concept of social licence is increasingly being used where private entities, rather than the state, are providing essential energy services. Regardless of the definition such a relationship with energy consumers is one that involves extensive responsibilities that are not always met. Articulated in part by legislative objectives (e.g. the national electricity objective (NEO) and national electricity retail objective (NERO)), these relationships are further proscribed by a range of legal rules (e.g. contract law, torts, and corporations law) that simply add to, rather than decomplexify, the operationalisation of the regulatory framework –

• Consumers’ lack of choice. Consumers face the challenge of a practical lack of choice when it comes to selecting an energy service provider. More often than not, consumer choice is illusory. Most consumers do not have a real choice as they cannot take their business elsewhere, even when prices rise. In a fully contestable market, competition drives price to the middle, averaging out the differences. This means that price-point choice assumptions become irrelevant.

• Inconsistent stakeholder relationships across participatory jurisdictions. The relationship between the key stakeholders differs across participatory jurisdictions. For example, in Victoria the distributors control smart meters, whereas in other jurisdictions the retailers have regulatory oversight.

• Disconnect between distribution networks and customers. Although distribution is central to facilitating and enabling DER and DM, for the most part, DNSPs have no direct relationship with end-users (e.g. end-users interact/engage contractually with retailers, not the assigned distributor). Thus, there is a disconnect between distributors and customers in the context of tariffs where the latter are designed and set for distribution but stated as being created to stimulate or encourage consumer behavioural changes.

Growing lack of national regulatory cohesion

Australian states and territories (the participatory or territorial jurisdictions) are increasingly engaging in activities that deviate from the national regulatory framework, resulting in regulatory fragmentation across the NEM. To date, sub-national legislation has been more agile in responding to the challenges associated with the energy sector’s decarbonisation transition and driving the emission reductions necessary to achieve net zero. However, Australian states and territories are actively setting their own agendas on several matters that directly affect the NEM and NERM. This has already included Victoria’s

decision to only have a limited regulatory engagement with the national energy customer framework (NECF) and national energy retail rules (NERR). Some of these are unsurprising.

Western Australia’s introduction of its own DER Roadmap in 2019/2020 is unremarkable as, based on geography, WA has always operated its own separate electricity market. Western Australia, while party to the Australian energy market agreement (AEMA), does not participate in the NEM. Instead, the regulatory framework for WA’s electricity market is set out in a range of state-based laws and regulations. 10 This includes the WA DER Roadmap and related laws. 11 It also includes the different ways in which networks are approaching solar exports and constraints. The Northern Territory, which, like WA, is not physically connected to the NEM, also operates its own regulatory framework but has adopted some of the NEM rules. However, even within the NEM participating states, both Victoria and NSW legislated in 2020 to coordinate infrastructure investment in renewable energy zones that comprises large-scale renewable energy generation, grid-scale battery and pumped-hydro storage and networks outside the NEM frameworks in order to accelerate and facilitate their own jurisdiction’s energy transition. 12

A notable development in NSW is changes to the electricity regulatory framework effected through the introduction of the Electricity Infrastructure Investment Act 2020 (NSW). 13 In 2021, a subsidiary body of AEMO AEMO Services was appointed to this role by the NSW Minister for Energy, and the EnergyCo (Energy Corporation of NSW) was appointed to the role of infrastructure planner for renewable energy zones (REZs) in NSW. 14 Both Victoria and NSW have also introduced further changes through the creation of REZs. While primarily focusing on the opportunities of grouping renewable energy generation, storage, and transmission into identified geographic locations, the physically connected nature of the electricity systems means that such changes will also impact on distribution and endusers. 15 Future impacts of such changes on the parts of the regulatory framework governing DM and distribution networks will require further consideration

Existing and emergent differences in public/private ownership of assets across jurisdictions are also challenging the structure and content of the existing regulatory framework. Public/private ownership and market participant changes are underway, with several state governments deciding to assume the primary role in generation and/or greater engagement in other parts of the sector (e.g. Victoria and NSW). Others are maintaining public ownership or control of energy assets (e.g. WA). A key impact of this increasing devolution and decentralisation is that multiple jurisdictional models of energy market governance and regulation will need to be contemplated in the research projects set out in the Summary Reports’ research roadmap.

Overall, jurisdictional variance throughout the market is increasing rather than decreasing. This challenges any assumption that the collaborative federalist approach that underpinned the

10 See https://www.wa.gov.au/organisation/energy-policy-wa/wa-energy-legislation

11 See https://www.erawa.com.au/electricity

12 See National Electricity (Victoria) Amendment Act 2020 (VIC) and Electricity Infrastructure Investment Act 2020 (NSW)

13 Electricity Infrastructure Investment Act 2020 (NSW), ibid.

14 See further; EnergyCo, https://www.energyco.nsw.gov.au/; AEMO Services, https://aemoservices.com.au/

15 See e.g., NSW, Renewable Energy Zones, https://www.energyco.nsw.gov.au/renewable-energy-zones; Victoria, Renewable Energy Zones, https://www.energy.vic.gov.au/renewable-energy/renewable-energy-zones

establishment of the interconnected NEM in 1998 will automatically continue into the future. 16 Australian states and territories, through the Energy Ministers Forums, for example, may not shift away from supporting a harmonious national regulatory framework for the NEM, but as decentralised markets evolve, further attention needs to be given to regulatory questions surrounding the nature and scope of the foundational collaborative federalist laws and AEMA that underpin the current NEM and NERM.

1.2. Regulatory opportunities: Transformative, comprehensive reforms

Regulatory challenges can also be seen as transformative opportunities. This opportunity assessment’s clear message is that, while the current regulatory framework is a significant barrier, it can also be amended to become a critical enabler of Australia’s decarbonisation transition and the realisation of net zero emissions. Consequently, the current uncertainties, risks, and challenges resulting from the combined impacts of decentralisation of the power system, accelerating DER uptake, new DER and DM technologies, introduction of a DSO and/or DMO, and decarbonisation imperatives present a once-in-ageneration opportunity for pursuing coordinated and enduring regulatory reforms across the NEM and the NERM.

Further regulatory opportunities identified include an in-depth review of NEM and NERM policy settings, governance and decision-making structures, regulatory frameworks, control strategies, consumer-facing retail business models and network service models, and asset and ownership diversity across the entire supply chain. By far the most significant drivers of all these trends are individual consumer decisions and the confidence consumers have in their ability to make decisions that are indeed in their best interests – that is, that the system can be trusted to deliver them fair choices.

Unlocking the value of such benefits for consumers, whilst also ensuring that the power system remains safe, secure, and reliable is critical to ensuring the much-needed regulatory reforms are fit-for-purpose: a consumer-focused, decentralised, decarbonised high DER future. Securing such outcomes requires further collaborative thinking on how best to reform the existing regulatory framework to avoid or minimise regulatory fragmentation across the nine jurisdictions of the AEM. It also needs to ensure that challenges are managed and transformed into opportunities and benefits.

1.3. Competition and implementation costs

Since the NEM’s inception, the central and legislated objective of its regulatory authorities (sometimes called the ‘market bodies’) has been to promote efficient investment in, and use of, the energy system. With the exception of network regulation (given networks’ status as natural monopolies), the regulatory authorities have equated the promotion of efficiency with the promotion of competition. As a result, competition came to be seen as a regulatory objective in its own right in the contestable parts of the energy supply chain of generation and retail.

Before considering the competitive consequences of DER, DSO and DM, it is worth considering why efficiency was made the central objective of the NEM back in 1998 and whether those conditions remain intact today and going forward.

16 Kallies, A. (2021). The Australian Energy Transition as a Federalism Challenge: (Un)cooperative Energy Federalism? Transnational Environmental Law, 10(2), 211-235. doi:10.1017/S204710252000045X.

In the 1980s and 1990s, when the energy sector was corporatised, disaggregated and privatised, the production, distribution and consumption of energy looked entirely different from how it looks today. Back then, the inputs and outputs of the energy supply chain were largely known with certainty and demand effectively inelastic. In other words, the energy system (and market) comfortably rested in steady-state. There was nothing for regulators to do other than promote the efficient use of known inputs to produce readily identifiable outputs. In this sense, the regulatory task was straightforward. In response, regulators became narrowly focused and proficient taskmasters of the energy markets they oversaw.

Sometime over the past decade, the steady-state nature of the energy system (and market) ended. The so-called ‘energy transition’ had begun. Almost by definition, the energy transition represents a period of great uncertainty for regulators designed to manage the neat steady-state conditions of the 1990s’ energy market. During the transition, it is impossible to know the nature and mix of inputs that will be required to meet the uncertain mix of outputs that energy users (and producers and storers) will require in the future. The energy system and market are now replete with unknowable variables. These unknowable variables include the roles to be played by DER and DM.

It is likely that a new steady-state will emerge one day (though even this observation is open to inquiry). When that will be, and how it will look, is unknowable for now. It would be foolhardy for policy-makers, regulators, researchers or advocates to presume otherwise.

So where does this leave energy regulators and their regulatory frameworks that are focused exclusively on promoting efficiency? How can regulators solely focus on efficiency when they can know neither inputs nor the outputs required? And, therefore, where does it leave the regulators’ previous assumption that their focus on efficiency can be equated with the promotion of competition?

The answers to these questions are far from obvious. Nonetheless, a great deal of regulatory effort remains bound to the assumption that competition is a worthwhile objective in its own right. The dominant regulatory response to many of the new challenges facing the energy system involves growing the regulatory framework to enable market-based solutions to accommodate new technologies, products, services and business models. Little recognition appears to be given to the complexity involved in coordinating all these markets and sub-markets. It simply assumes that cost reflective price signals will smoothly flow up, down and across these markets to coordinate investment and usage decisions that will ultimately prove to be efficient. This regulatory article of faith will be tested by the energy transition, particularly as previously passive consumers are co-opted into becoming market participants who actively trade their consumption, energy production, and stored energy with vastly more sophisticated commercial parties.

Given the emphasis on market-based solutions by the current cohort of regulatory authorities, we must recognise that –

• if price signals are not genuinely cost reflective

• if their transmission between markets encounters frictions

• if market participants (of all sorts) do not respond ‘rationally’ to price signals and

• if market power emerges anywhere in the inter-linked markets,

then the implementation cost of market-based solutions will rise potentially substantially and rapidly. Once again, it is far from obvious who will bear these costs. For example, they may be expressed in terms of higher prices, stranded assets, or both. Those stranded assets may be owned by large corporate entities or small players (eg. households). The political economy associated with these costs, and the potential damage to community confidence in the energy transition, must not be ignored in the design of regulation.

The role, relevance and utility of markets, competition and price signals and therefore the design of regulation will be a central consideration for many of the projects to be progressed under the N4 work stream.

1.4. Identifying and managing DER-induced risks

Responding to the challenges of energy system decentralisation and growing levels of DER requires identification of risks and a greater understanding of how, where, and when high DER penetration induces security, reliability and safety risks across electricity networks. There is no panacea for managing such risks. Managing and integrating high levels of DER into existing power systems requires a suite of responses, including:

• Improving inverter standards (capability, communications, compliance)

• Exploring cost-effective distribution network storage opportunities

• More suitable voltage standards and frequency load shedding arrangements to deal with localised voltage fluctuations and two-way power flows

• Further investigative trials of tariff structure reforms and investment incentives

• Valuing decarbonisation processes and emission reductions, as well as evaluating the success of intended outcomes

• Focused coordinated planning and regulatory reform to facilitate greater DER participation (e.g. adoption and update of new DER, such as EVs) and control over sizeable amounts of individually owned/operated DER devices, and to ensure consumer protections and intra-end user equity.

Further thinking is required on how best to achieve a suitable balance between what appear to be, at first glance, competing technical, economic, environmental and social objectives. From the consumer perspective, for example, this entails matters such as unlocking and ensuring benefits and value to consumers (e.g. lower bills, DER investments, compensation for provision of DER services) and securing consumer protections and engagement (e.g. protection and ownership of customer data and information, public consultation, fora, etc.). From the NEM perspective, it comprises challenges such as identifying, managing and responding to DER-induced risks across power systems to ensure security, stability, and reliability (e.g. load-risk response measures, including improved inverter and voltage standards, transitional emergency response mechanisms, voltage fluctuations and growth in two-way power flow).

1.5. Whose demand is being managed?

The subsequent DM discussion in Work Package 2 highlights a range of considerable benefits flowing from existing industry/system focused DM measures.

Within the context of the current dynamic transitional developments across the energy sector, further questions are emerging concerning demand management and existing regulatory measures. This includes the changing nature of what is to be ‘managed’ in the traditional demand-end of the electricity transaction, and the variable roles/functions of existing market stakeholders. As DER continue to grow, this will also entail addressing questions about distributed supply of electricity into the grid and the interface with system stability. Examples include recent regulatory changes that have enabled AEMO or a DNSP to disconnect small-scale distributed solar units (without the owner's permission) to maintain system stability, and the role of network export tariffs (e.g. charging owners of DER for use of the network when exporting their electricity into the grid). These examples show a focus on demand management as a network service where system stability appears to be the primary objective over and above others. The diversity of responses to this issue is also worth mentioning. For instance, pilot projects are underway in which some owners are being paid to enable DNSPs to curtail exports Synergy, for instance, is exploring the opportunity of compensating owners of RTPV solar of DER services of this kind, with export constraints being developed as a value stream for end-users

It is also worth noting the potential challenge for DM resulting from increased demand in the system, either locally or generally. As discussed earlier in this report, the various DM definitions are predicated on the objective of reducing energy demand or load shifting. However, due to low and falling demand in the middle of the day, DM may increasingly also involve increasing electricity demand at certain times in order to manage system reliability. The relationship between DM and DER raises further questions regarding potential impacts on DM of ongoing investment in DER as well as large-scale batteries and local community renewable energy and storage projects (such as neighbourhood batteries). Network costs, and the wholesale and FCAS markets, will also be impacted. Questions such as these warrant further attention in the current regulatory discussions being championed by various Australian governments, energy ministers, the ESB working groups, market institutions and other regulatory bodies.

1.6. Distributed energy resources or consumer energy resources: Whose resources are they?

Existing and emergent DER assets give rise to several findings. Recent commentary from energy market institutions and other bodies is starting to question the accuracy of existing terminology and understandings of DER. For example, it is being suggested that DER should really be called consumer energy resources (CER). In Victoria, it has been noted that some organisations have adopted the term CER to emphasise that these resources are owned by consumers, and to encompass a broad range of technology into the definition. 17

At the very least, a clear distinction needs to be made between DER generally and CER, as in regulatory terms, DER are still largely described in separate, generalised terms. The ESB’s Post-2025 Market Report illustrates this where DER are described broadly as “small-scale rooftop solar, batteries, smart appliances, business equipment and systems, and EVs”. The implicit assumption in the ESB’s post-2025 energy market vision is that consumers will efficiently respond to cost-reflective price signals in a way 17

that optimises the overall operation of the electricity system (and minimises the need for surplus investment). However, this does not always hold true. For example, private or business fleet EV owners may need to use their vehicles for their own purposes. This means that such DER may not be suited to being contracted to provide system services. The appropriate balance between automated and active consumer-controlled demand response warrants urgent attention.

A related question concerns what such a definitional change means in regulatory terms (e.g. the changing nature of demand and supply and their impacts on the retail/distribution and wholesale markets, as well as the changing roles and corresponding responsibilities of current consumers and other market participants in new regulatory settings). This alone suggests an urgent need for a comprehensive rethink and redesign of the prevailing energy regulatory framework. The definition of what a ‘consumer’ is will likely need to be reviewed as the terminology of consumer/producer may not sufficiently capture the new roles end-users assume in the market.

One of the issues from the energy system’s perspective is the lack of visibility of the behaviour of these systems and therefore the demand for orchestration, which in turn raises questions of what type of access to DER is required. This, and the other uncertainties listed below, warrant further consideration and research:

• What is or could be a DER (single, multiple/hybrid)?

• Who owns DER?

• Who can access another party’s DER?

• Does access mean all DER or just one selected DER?

• Who is responsible for DER failure or damage?

• Are Time of Use (ToU) tariffs, which aim to facilitate changes in end-user behaviour, equally effective in the context of rapidly rising quantities of DER? 18

• What would consumers be willing to accept in exchange for the imposition of export limits on their DER (e.g. payment for an agreement to restrict RTPV solar export capacity through measures such as orchestration and dynamic operating envelopes)?

1.7. Who are the stakeholders in the ESB/AEMC/AEMO/AER

two-sided energy market?

A fundamental question concerns who the relevant stakeholders in these dynamic new energy markets are, how their relationships are defined, and what their respective rights and responsibilities are. In response to rising DER, for instance, current end-users are increasingly able to elect to switch between demand and supply roles (e.g. generators, storers and suppliers versus consumers of energy). Likewise, retail and network service providers are increasingly engaging in buying and supplying DER-generated electricity back to the wholesale market, that is, switching roles/functions from facilitating supply to end-users to facilitating supply into the wholesale and FCAS markets. This also highlights several key conceptual and definitional challenges.

For instance, does the ESB’s Post-2025 Market Report’s terminology of ‘flexible demand’ adequately reflect these changing circumstances? As the AER’s final DER integration expenditure guidance note

18 See eg, AEMO’s and WA Distributed Energy Resources (DER) Registers https://aemo.com.au/energy-systems/electricity/der-register; See also AEMO, Renewable Energy Integration – SWIS update (2021) https://aemo.com.au/energy-systems/electricity/wholesale-electricity-marketwem/system-operations/integrating-utility-scale-renewables-and-distributed-energy-resources-in-the-swis

makes clear, the expansion of DER and decentralised energy generation is customer driven. With more and more DER being located, usually on the consumers’ side of the electricity meter, consumers are demonstrating a willingness to assume a small-scale producing role albeit a passive one in the power system. Indeed, PVRT solar capacity is anticipated to double or triple by 2040. 19 Even so, becoming a prosumer does not automatically mean an active engagement with the market beyond exporting surplus electricity. Some DSM discussions are built on assumptions of proactive and engaged prosumers. Others advocate that future high DER markets will be characterised by fully automated demand responses.

1.8. DNSP, tariff design, and the consumer gap

Distribution businesses are responsible for maintaining distribution network safety and reliability, along with planning and designing network extensions and upgrades to meet our customers’ current and future electricity needs under the current pricing proposals. 20 The question of how to support the system planning process to be agile in the face of rapidly changing technology and market conditions is addressed subsequently in this opportunity assessment (see Section 6.5). A key finding highlighted in that discussion is the need to address the ‘consumer gap’. One example is the failure of network pricing and generation signals to reach small to medium business customers and household customers (e.g. network use-of-system (NUoS) charges comprise about 40% of the consumer retail bill). The remaining charges, which relate to wholesale generation, metering, environmental and retail margins are not detailed on these customers’ retail bills.

1.9. The DSO: A new market participant or a new role for an existing one?

As discussed subsequently in this report, the national electricity rules contain a specific definition of a distribution system operator (DSO), which is further defined as a ‘special participant’ (see NER, Ch 10).

The NER also set down a dedicated role for a DSO operating exclusively in the context of power system operating procedures (see NER, Ch 10, and Ch 4– Rule 10). In Australia, experience to date suggests that DNSPs have already integrated the role of DSOs into their operations and registered accordingly with AEMO. Further details are available on the NEM Registration and Exemption List published by AEMO. 21

A number of questions will need to be addressed in regard to this role. First and foremost, is there a need to extend the functions of the DSO in the NER? If there is to be a distinct role for a DSO, independent of the functions of a network, how should the current energy laws be amended to identify this regulated body’s new functions? Should this role and its functions be vested in existing institutions such as AEMO, or should a new entity be created altogether?

Regulatory questions also remain about the future role of aggregators. Over and above related questions concerning the preferable ownership structure and business model for a DSO, several important, related considerations are not highly visible in the current dialogue. These include What does a DSO look like, what does, or should, a DSO do, and how should it be regulated? For instance,

19 AER, DER integration expenditure guidance note (30 June 2022) https://www.aer.gov.au/networks-pipelines/guidelines-schemes-modelsreviews/assessing-distributed-energy-resources-integration-expenditure-guidance-note/final-decision

20 Australian Energy Regulator. Pricing Proposals and Tariffs, https://www.aer.gov.au/networks-pipelines/determinations-accessarrangements/pricing-proposals-tariffs.

21 See AEMO, https://aemo.com.au/energy-systems/electricity/national-electricity-market-nem/participate-in-the-market/registration

should a DSO and its role be similar to that of the system operator of the wholesale market AEMO operating a DER market and bilateral contracts? Or do the existing retail/distribution market and existing consumer contracts dictate a different approach? Moreover, should such an entity’s activities be regulated, and if so, should this be by the AER or jurisdiction-based regulatory bodies such as IPART (NSW) and ESCV (Victoria)?

Against all these uncertainties, there is an even greater lack of clarity as to how any of these changes ultimately benefit consumers. This entails meeting both the current needs and long-term obligations set out in the national energy market objectives. The far-reaching consequences of the energy ministers’ agreement to introduce an emissions mitigation obligation into the market objectives are far from clear in both practical and temporal senses. They also remain opaque in terms of sharing the burden of the responsibility and costs associated with emissions mitigation activities, and the relationship with existing sub-national emissions mitigation measures. These issues are underpinned by an implicit assumption that the access to affordable energy services is still widely understood as essential, regardless of the private/public character of market participants.

1.10. Implications for the future role of a DSO

Questions identified during this opportunity assessment’s research and engagement activities concern the appropriate role of distribution network businesses in this new energy system, include

• How should network services evolve to support, integrate and make use of DER? What role do (real-time) prices play? Are there other feasible orchestration options?

• Who should be responsible for planning and managing the relationship between the distribution network and DER?

• How do we ensure customers investing in DER have the correct information, incentives and support to guide the efficient adoption and use of DER?

• What is the role of the network owners and operators in procuring DER-based and DM-based support services?

• What are the relationships and risk allocation approaches between distribution networks and those entities with direct control of DER (such as customers or their agents) to contribute to a secure, stable, reliable and affordable electricity system for all?

These issues have led many people to propose creating new entities or and/or evolving roles to address these challenges. A key proposal relates to the DSO. Similar to DER, the interpretation of what a DSO is varies, but a common definition from a comparative study undertaken in 2018 is that it is ‘the entity responsible for planning, and operational functions associated with a distribution system that is modernised for high levels of DER’. 22 This definition is considerably wider than the ones provided for in the national electricity rules, in particular in light of the planning functions and the express reference to DER.

Much of the debate in Australia about roles and responsibilities of the DSO has focused on the dispatch or orchestration function, for instance, controlling when DER should be turned on and off or ramped

up and down. However, other equally important issues relate to the distribution network business's role in planning and operating a distributed network with high levels of DER for the benefit of all customers. Further thinking is required on these issues and includes:

• Planning for DER, in particular planning and implementing an optimal mix of DER, DM and network infrastructure

• Providing price signals and other financial incentives to promote efficient development and use of DER and

• Procuring and/or owning DER and the services they can offer to provide network support and to deliver better outcomes for customers.

1.11. A growing chorus: The need for greater focus on consumer realities

Affordability, fairness, equity and comprehensibility are integral components of the energy transition. Even so, it is far from clear whether the vast body of the Australian energy market’s existing regulatory framework including the NEM takes into account consumer realities. Not just the national energy regulatory framework is widely considered to no longer be fit-for-purpose in the face of rising DER and decentralised energy markets. Questions are being raised about the disconnect between the expectations that consumers will actively and constructively support the energy transition, and the likelihood that such widespread changes will actually eventuate. This includes the role they are expected to play in managing their own energy use and if relevant, the behind/at-the-meter generation for their own benefit, as well as supporting and benefitting the system and market participants operating across it.

In a 2022 speech to the ACCC/AER’s Regulatory Conference the Future Regulation of the Energy Sector, ECA’s CEO Lynne Gallagher clearly enunciated the failings of the current regulatory framework. In doing so, she identified the disconnect between the government and industry approaches to the current and proposed developments across the system and the implicit assumptions relied upon concerning the role of consumers in these new and emergent energy market paradigms:

“There are countless numbers of dedicated policy-makers, engineers, economists and people in industry working to ensure that the power system safely and reliably delivers electricity, today and tomorrow. What is yet to receive the same attention is a plan for reshaping demand so that we have a least-cost electricity system as well as one in which the energy bills of households and small businesses are affordable: A plan that reflects the role we are asking consumers to play and creates opportunity for all households and small businesses, rather than deepening inequity.” 23

The sharp rise in energy prices that occurred in 2022 focused attention on key issues directly impacting consumers: affordability, fairness, and equity. For example, the AGL Energy Customer Council recently observed that, while the ESB is currently working to develop an energy framework that ensures Australians maintain access to reliable and adequate supply as the energy markets transform, this approach is not comprehensive. A notable “key component missing from the ESB work stream is active

23 See ECA, Speech to the ACCC/AER Regulatory Conference 2022 – Future regulation of the energy sector (August 8, 2022) https://energyconsumersaustralia.com.au/news/speech-to-the-accc-aer-regulatory-conference-2022-future-regulation-of-theenergy-sector

and vibrant engagement with consumers to create a vision of energy fairness in the new energy world”. 24

1.12 DM and DER funding incentives

Demand management incentives in Australia range from the Australian Energy Regulator’s supply-side DMIS and DMIA offerings to those of other federal supply-side funders, such as ARENA and the Clean Energy Finance Corporation. As discussed in Work Package 1 below, the states and territories vary: the largest states (NSW and Victoria) offer potential demand-side funding incentives for DER from sources such as the Climate Change Fund and the Sustainability Fund, respectively, while the ACT and South Australia offer demand-side incentives, and the remaining sub-national governments offer supply-side funding incentives.

Pre-Albanese Government tax incentives are not specifically either supply or demand-side incentives and offer the R&D tax incentive (which is similar in intent to the DMIA). Then there is the concessional tax treatment for ESICs. The state and territory tax incentives and subsidies focus more on the demandside such as on public charging station infrastructure and direct fiscal support to lower EV costs. Despite the range of DM incentives identified, none had the effect of increasing DER in the form of EVs in Australia. As mentioned above, statistics show that business fleet uptake of ZLEVs in Australia was only 1.2% in 2020 around 400. 25 As to the effectiveness of the new FBT exemptions for EVs, a review is legislated for 2025. It has been noted that, in 2019, the ARENA–funded Distributed Energy Integration Program examined how the DMIS and DMIA network incentives could evolve so that consumers get the best value from the innovations of DER. The report suggests that incentives should focus on the demand side for consumers, and be equitable and affordable. This is why the October Budget 2022-23 inclusion of demand-side, climate-related funding and schemes are important and of interest.

2. THE REGULATORY FRAMEWORK

Regulation is a generic term that includes legislation, regulations and statutory rules, as well as delegated legislation (where decision-making or other powers are given by government to someone else), industry codes and standards, and other regulatory tools created at national, state/territory and local levels. Shaping those regulations are policy frameworks within which regulation is developed and implemented.

The regulatory framework can encourage or hinder the development of DM, DER, and DSO. It can influence their respective roles as contributors to the decarbonisation transition across the national energy market, and constrain or enhance the maximisation of consumer benefits and value associated with such changes. This section of the report provides an overview of the current regulatory environment in which the energy transition is taking place It also provides an overview of the regulatory complexities of the NEM.

24 AGL Energy Consumer Council Open Letter (14 July 2022) https://www.agl.com.au/content/dam/agl-thehub/220714-agl-energy-customercouncil.pdf

25 National Transport Commission

2.1. Definitions

This research is concerned with a number of terms that are defined differently across the regulatory framework, literature, and policy publications. For the purposes of this report, most of the terms used and their definitions are those set out in the NER and the NERR. These are identified and discussed at relevant points throughout this report. The following discussion sets out key theme-based terms and definitions used throughout this report: (i) consumers, (ii) DM, (iii) DER, and (iv) DSO.

Despite the thousands of pages of regulations that comprise the national energy market regulatory framework, energy consumers are not specifically defined.

(i) Consumers: end-users

In the absence of an express statutory definition in the national energy regulatory framework, for the purpose of this report the term ‘end user’ is applied, in a generic sense, to all consumers: households and businesses.

(ii) Australian consumer law and consumers

The regulatory framework for energy consumers is founded on two key sets of laws: (a) the National Energy Customer Framework (NECF) 26, and (b) Australian Consumer Law (ACL). 27 As the main law for consumer protection and fair trading operating throughout Australia, the ACL regulates the sale of

Box 1: Australian Consumer Law, Section 3: Meaning of consumer

Acquiring goods as a consumer

(1) A person is taken to have acquired particular goods as a consumer if, and only if:

(a) the amount paid or payable for the goods, as worked out under subsections (4) to (9), did not exceed:

(i) $40,000; or

(ii) if a greater amount is prescribed for the purposes of this paragraph that greater amount; or

(b) the goods were of a kind ordinarily acquired for personal, domestic or household use or consumption.

Acquiring services as a consumer

(2) A person is taken to have acquired particular services as a consumer if, and only if:

(a) the amount paid or payable for the services, as worked out under Subsections (4) to (9), did not exceed:

(i) $40,000; or

(ii) if a greater amount is prescribed for the purposes of subsection (1)(a) that greater amount; or

(b) the services were of a kind ordinarily acquired for personal, domestic or household use or consumption.

26 See AMEC, The National Energy Customer Framework, https://www.aemc.gov.au/regulation/energy-rules/national-energy-retailrules/regulation.

27 See The Australian Consumer Law, https://consumer.gov.au/

goods and services to consumers. This is complemented by the NECF, which operates to regulate the sale and supply of energy (electricity and gas) to customers in the retail market and contains a range of consumer protections. As discussed subsequently, not all states and territories are party to the NECF. However, both the sale and supply of goods and services to consumers in all Australian jurisdictions are governed by the ACL. Thus, while the term ‘consumer’ is not separately defined in the NEM and NERM regulatory frameworks, it is defined in Section 3 of the Australian Consumer Law in terms of the acquisition of consumer goods and services. 28 This is set out in Box 1.

(iii) Allconsumersarecustomers,butcustomersarenotalwaysconsumers

The term customers is used in two specific contexts that accord with the varying definitions set down in the NER and NERR. Firstly, the term is used in the NER to refer to registered participants who are buying electricity in the wholesale electricity market. More specifically, a customer is defined in the NER as: A person who: 1. engages in the activity of purchasing electricity supplied through a transmission system or distribution system to a connection point, and 2. is registered by AEMO as a Customer under Chapter 2 29 Such customers are not end-user consumers.

Secondly, according to the AEMC, consumers in the ‘energy market normally engage with an electricity or gas retailer who in turn arranges for the delivery of electricity or gas and then bills them for the supply’. 30 Immediately following this explanation, the AEMC uses the term ‘customers’ in setting out the various costs that make up an electricity bill, such as wholesale energy costs (electricity generation), regulated network costs (transmission and distribution), environmental policy costs, and retail costs (operating costs and margins). 31 This switch in terminology accords with the NERR’s classification of customers into two groups of energy consumers: retail customers and distribution customers. 32 Retail customers are further distinguished as either residential customers or business customers. Distribution customers are classified as small and large customers, with a further distinction made between two types of small customers: small market offer, and non-market offer customers. 33 These customers are end-users in the sense that they are final end-users consumers of electricity.

(iv) Demandmanagement

The term ‘demand management’ (DM) has had varying applications since the NEM’s establishment in 1998. Until recently, DM in the NEM framework referred predominantly to the operator’s task of matching supply and demand in the wholesale market and that of networks to manage constraints. With the introduction of the demand management incentive scheme (DMIS) and the demand management innovation allowance (DMIA) into electricity distribution networks, DM now has a broader definition and application. These developments form part of the subsequent discussion in Work Package 2. As explained below, this understanding of DM is different to demand-side management by end-users

28 See Federal Register of Legislation, https://www.legislation.gov.au/Details/C2022C00212/Html/Volume_3#_Toc109308083

29 NER Version 199 Summary, 11 March 2023, https://energy-rules.aemc.gov.au/ner/468.

30 See AEMC, https://www.aemc.gov.au/energy-system/retail/consumers

31 See AEMC, https://www.aemc.gov.au/energy-system/retail/consumers

32 NERR, Div 3, s 6. See Current Version 37, 1 March 2023, https://energy-rules.aemc.gov.au/nerr/464.

33 NERR, Current Version 37, 1 March 2023, https://energy-rules.aemc.gov.au/nerr/464.

(v) Consumeragency:Demand-sideparticipationbyconsumers

From the end-users’ perspective, demand management has long been understood as relating to consumer participation in their own demand decisions, changing the timing of their electricity consumption, and/or reducing the amount of energy consumed in various way (e.g. by peak shifting, electricity conservation, fuel switching, utilisation of distributed generation, and energy efficiency). Behavioural changes in energy consumers’ demand preferences for electricity is reflected in several definitions contained in the regulatory framework, notably demand reduction, demand-side participation (DSP) and demand-side response (DSR). These are set out in Figure 2.1 below.

These terms and definitions in the existing regulatory framework highlight the long-recognised notion that most consumers are free to make their own decisions about electricity consumption. The capacity of end-users to decide how and when to reduce or change their electricity demand consumer agency is an increasingly important objective in the context of increasing DER and actively engaged end-users. Awareness of their growing flexibility and ability to trade this flexibility using new technologies drive the energy transition towards an end user-centric, decentralised electricity market. An important question for the future highly distributed, transitioning market is whether existing definitions sufficiently capture the value of demand management undertaken by end-users. The report further discusses the different perspectives market instruments provide and query whether these sufficiently consider whose demand is being managed and who is responsible for managing it (e.g. demand management of the system, market participants and end-users). These and related matters are explored further later in this report.

Demand reduction

• A change in consumer behaviour to reduce the amount of energy consumed (e.g. switching off lights when they are not needed)

Demand side participation (DSP)

• When consumers make decisions regarding the quantity and timing of their electricity consumption in line with the value they place on using electricity services. If consumers make informed choices about the quantity and timing of their electricity use, they can reduce demand when prices are higher, which can lead to less money being spent on poles and wires as long as reduced demand happens at the right time and place. Demand-side participation options are available to consumers (or to intermediaries acting on behalf of consumers) to reduce or manage their electricity use. Examples include peak shifting, electricity conservation, fuel switching, utilisation of distributed generation and energy efficiency.

Demand side response (DSR)

• An active, short-term reduction in electricity demand by consumers who decide to respond to price signals throughout the day by shifting their electricity use to another period, or to use another type of generation, or to simply not use electricity at specific times.

Figure 2.1. Demand management by end-users

2.2. Distributed energy resources

Distributed energy resources are defined in a number of ways. For example, the Australian Energy Market Commission suggests that a DER is “a small-scale unit of power generation or storage that operates from homes and businesses and is connected to a larger power grid at the distribution level”. 34 According to the Australian Energy Regulator, DER include “rooftop solar, batteries, electric vehicles and energy management systems”. 35 Another key market institution, the Australian Energy Market Operator, defines DER as follows:

“Distributed Energy Resources or DER are consumer-owned devices that, as individual units, can generate or store electricity or have the ‘smarts’ to actively manage energy demand. When aggregated and operating together at scale through micro-grids and virtual power plants (VPPs), these devices have huge potential to exchange consumer value by contributing to a reliable and secure energy supply. Examples of DER devices include:

• Rooftop solar photovoltaic (PV) units

• Wind generating units (at residential or commercial premises)

• Battery storage system

• Hot water systems, pool pumps and air conditioner

• Smart appliances

• Electric vehicles.” 36

In Western Australia, DER is defined in the WA Roadmap as small-scale devices, including rooftop solar systems, batteries, electric vehicles, microgrids and other DM technologies ‘that can either use, generate or store electricity, and form a part of the local distribution system, serving homes and businesses’. 37 Technologies can be used by consumers ‘at their premises to manage their electricity demand (e.g. hot water systems, pool pumps or smart appliances)’. 38 The WA DER Roadmap further categorises DER according to which side of the meter the resources are located, and whether DER is passive or active. It also identifies DER by reference to the services it can provide and the value that can be unlocked across the power system. A brief explanation of these is set out below.

(ii) Behind-the-meter DER

• Located on the consumer side of the meter and operated for the purpose of supplying all or a portion of the consumer’s electricity

• Includes renewable generation (rooftop solar), energy storage, electric vehicles (EVs)

• May be capable of supplying power into the system or providing a demand management service.

(iii) In-front-of-the-meter DER

• Connected directly to the distribution network

• Includes some types of renewable generation (e.g. small solar PV and wind farms)

• Grid-scale batteries (e.g. community batteries).

34 AEMC, What are Distributed Energy Resources, https://new-energy-guide.aemc.gov.au/teach-me-the-basics#what-are-distributed-energyresources

35 AER, DER integration expenditure guidance note (30 June 2022) https://www.aer.gov.au/networks-pipelines/guidelines-schemes-modelsreviews/assessing-distributed-energy-resources-integration-expenditure-guidance-note/final-decision

36 AEMO, https://aemo.com.au/initiatives/major-programs/nem-distributed-energy-resources-der-program/about-the-der-program

37 Energy Transformation Taskforce, DER Roadmap (Western Australia, 2019)6.

38 Ibid.

For WA, the experience to date is that most existing behind-the-meter DER can be described as passive in the sense that it is simply responding to available resources or pre-set internal programming and settings such as rooftop solar PV generation. 39 In contrast, active DER is understood in terms of adaptive/responsive behaviour characteristics, whereby DER adapts/responds to control signals from an external party or system. 40

According to the Victorian Government, “distributed energy resources (DER) are resources owned by consumers to generate, store, manage or sell energy. They include solar photovoltaic panels (solar PV), home or neighbourhood batteries, thermal energy storage (e.g. water heaters), electric vehicles and chargers, smart meters, home energy management technologies, and smart energy devices (e.g. controllable air conditioners).” 41

Similarly, other market bodies Energy Consumers Australia and the Energy Security Board are increasingly describing DER as customer energy resources (CER). The AEMC/ESB Board Chair Anna Collyer has explicitly identified the importance of rebranding DER as CER, and comments that “Work on CER is complex and requires extensive collaboration with stakeholders so we can understand customer preferences and behaviour to ensure the system works for all customers to help us make the best rules that provide the most benefits to the most people.” 42

A range of additional and alternative definitions is used by different stakeholders. For instance, DER has been defined in the literature as ‘localised generation or load assets.’ 43

One of the adverse outcomes of the application of a term such as DER in different contexts and by different stakeholders is that it adds inconsistency and complexity to an already overly complicated regulatory framework. Adopting a singular agreed definition for important terms such as this one across all jurisdictions of the NEM will benefit everyone.

2.3. Distribution system operator

A DSO is separately defined in the NER as “A person who is responsible, under the Rules or otherwise, for controlling or operating any portion of a distribution system (including being responsible for directing its operations during power system emergencies) and who is registered by AEMO as a distribution system operator.”

In the NEM, all registered DSOs 44 are also registered as distribution network service providers and the terms are often used synonymously, although the role of a DNSP is wider than that of a DSO. The rules do not prevent the emergence of independent DSOs.

39 DER Roadmap, above n 241, 17.

40 DER Roadmap, above n 241, 17.

41 Victorian Government, Harnessing Victoria’s Distributed Energy Resources (2022) 5.

42 M Hogath (23 May 2022) Customer versus Distributed: what’s in a word? https://wattwatchers.com.au/customer-versus-distributed/

43 See eg, Ashton, R., Kains, B., Pick, G., Walgenwitz, G. (2021). Distributed energy resources for primary industries - Exploring barriers to deployment. Sydney: Australian Alliance for Energy Productivity for NSW Department of Primary Industries, Glossary, vii https://www.dpi.nsw.gov.au/__data/assets/pdf_file/0003/1321797/energetics-distributed-energy-resources.pdf

44 Defined as ‘special participants’ and registered under this section in the AEMO, NEM Registration and Exemption List, published by AEMO here:https://aemo.com.au/energy-systems/electricity/national-electricity-market-nem/participate-in-the-market/registration

Currently, the NER sets down a dedicated role for a DSO operating exclusively in the context of power system operating procedures (see Box 2 below). 45

The value of outsourcing this very specific role is unclear. Consequently, the question for the Australian system is not only whether we need to redefine a DSO, but also what responsibilities beyond the limited list in Rule 4.10 of the NER should be allocated to it or created and integrated into the regulatory framework of the NEM.

Box 2: Extracts from NER, Ver 199 (11 March 2023), Clause 4.10

CLAUSE 4.10.3

Operating interaction with distribution networks

(a) AEMO and each distribution system operator must maintain effective communications concerning the conditions of its distribution network and the transmission network or other distribution network to which that distribution network is connected and to co-ordinate activities where operations are anticipated to affect other transmission networks or distribution networks.

(b) AEMO must use its reasonable endeavours to give at least 3 days' notice to all affected distribution system operators prior to a transmission network service provider carrying out switching related to a transmission network which could reasonably be expected to affect security of supply to any distribution network.

CLAUSE 4.10.4

Switching of a distributor's high voltage networks

(a) A distribution system operator must use reasonable endeavours to give AEMO at least 3 days' prior notice of plans to carry out switching related to the high voltage network which could reasonably be expected to materially affect power flows at points of connection to a transmission network. The distribution system operator must also notify AEMO immediately prior to carrying out any such switching.

(b) A distribution system operator must provide confirmation to AEMO of any such switching immediately after it has occurred.

CLAUSE 4.10.5

Switching of reactive power facilities

(a) AEMO may instruct a distribution system operator to place reactive plant belonging to or controlled by that distribution system operator into or out of service for the purposes of maintaining power system security where prior arrangements concerning these matters have been made between AEMO and the distribution system operator .

(b) Without limitation to its obligations under such prior arrangements, a distribution system operator must use reasonable endeavours to comply with such an instruction given by AEMO or its authorised agent.

CLAUSE 4.10.6 Automatic reclose

(a) A Network service provider or a distribution system operator may request AEMO to disable or enable automatic reclose equipment in relation to a particular transmission network or distribution network circuit or a feeder connecting its distribution network to a transmission network which has automatic reclose equipment installed on it.

(b) If a distribution system operator makes such a request, then AEMO must use reasonable endeavours to comply with the request as soon as reasonably practical.

(c) AEMO is not responsible for the consequences of automatic reclosure in relation to a circuit or a feeder and the distribution system operator must indemnify AEMO against any loss or damage arising out of AEMO complying with such a request unless the loss or damage is due to the failure by AEMO to comply with the request within a reasonable period of time.

2.4. The national electricity market regulatory framework

The Australian energy market and its constituent markets the national electricity market, the national gas market, and national energy retail market are undergoing wide-ranging reforms. These include the ESB Post-2025 DER Implementation Plan 46 (which is developing a 3-year roadmap for flexible demand and better integration of DER), the AER’s Framework for assessing distributed energy resources integration expenditure, 47 the AEMC’s Access, Pricing and Incentive Arrangements for Distributed Energy Resources Rule determination', 48 and ongoing work by various market institutions and bodies on two-sided markets. The following regulatory framework review sets out key aspects of the regulatory framework within which these and the multitude of other regulatory changes are taking place.

2.5. Market institutions and related bodies: Governance, regulatory, and operational

The following table (Table 2.1) provides an overview of the market institutions and related bodies, briefly indicating their key function/s and legal basis.

Institution Functions Laws

AEMC Rule-making body for the NERR, as it is for the national electricity rules (NER) and national gas rules (NGR); established in 2005 by the South Australian parliament under the Australian Energy Market Commission Establishment Act 2004 (South Australia)

AEMO Statutory body established to replace NEMMCO. Responsible for day-today wholesale NEM operations, including spot market. 49 Further functions in NGM and WA; in 2021, AEMO appointed as NSW Electricity Consumer Trustee. 50

AER Statutory body established under the auspices of the ACCC; initially wholesale market regulation; regulatory functions extended to retail markets as part of NERL, etc. 51

Energy Consumers Australia

Statutory body for consumer interests. Initially established as National Electricity Consumers Advocacy Panel 52

Energy Ministers Main governance body (previously COAG) 53; established in 2020 and replaced in 2022 with the Energy and Climate Change Ministerial Council

AEM Commission Establishment Act

2005; NEL

NEL; Electricity Infrastructure Investment Act

2020 (NSW)

NEL; Competition and Consumer Act

2010 (Cth)

NEL

NEL

46 https://www.energy.gov.au/government-priorities/energy-ministers/priorities/national-electricity-market-reforms/post-2025-marketdesign/der-implementation-plan-design-and-implementationprocess#:~:text=National%20Cabinet%20endorsed%20the%20Post,flexible%20demand%20into%20energy%20markets.

47 https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/assessing-distributed-energy-resources-integrationexpenditure

48 https://www.aemc.gov.au/rule-changes/access-pricing-and-incentive-arrangements-distributed-energy-resources

49 https://www.aemo.com.au/

50 https://www.energyco.nsw.gov.au/index.php/industry/the-consumer-trustee

51 https://www.aer.gov.au/

52 https://energyconsumersaustralia.com.au/

53 https://www.energy.gov.au/government-priorities/energy-ministers

Table 2.1 Overview of key institutions and bodies

ESB 54 Comprises the heads of the AEMC, Australian Energy Regulator, and AEMO, and is chaired by the head of the AEMC. Established in 2017 to –

• Coordinate the implementation of recommendations from the Independent Review into the Future Security of the National Electricity Market (Finkel Review)

• Provide whole-of-system oversight for energy security and reliability to drive better outcomes for consumers

• Advise on post-2025 reforms.

2.6. Central harmonised national legislation and rules

In 1996, the national electricity market (NEM) framework was established in preparation for the official commencement of the NEM in 1998. The legal framework for the NEM is established through the National Electricity (South Australia) Act 1996, which is valid in all states through the operation of enabling legislation. 55 This act contains the main piece of legislation governing the NEM is the National Electricity Law (NEL). 56 These legislative instruments, and related delegated legislation the National Electricity Rules (NER) 57 — articulate the roles and responsibilities of market institutions and participants. National laws for the retail market are discussed below. The key legislative instruments forming the regulatory framework are –

• The National Electricity Market (NEM): National Electricity Law (NEL), National Electricity (SA) Regulations, and National Electricity Rules (NER).

• The National Energy Retail Market (NERM): National Energy Retail Law (NERL), National Energy Retail Regulations, and National Energy Retail Rules (NERR)

National Electricity Rules (NER)

The NER govern the operation of the NEM (including governance, regulatory and day-to-day operational matters) and regulate market participant activities. 58 The NER are updated regularly. The current Version 199 is effective as of 11 March 2023. 59 These rules operate in all Australian jurisdictions, except for WA and the NT. More specifically, the NER govern –

• The operation of the wholesale electricity market 60 —the market arrangements for the commercial exchange of electricity from the electricity producer (generators) through to the electricity retailers

• The economic regulation of the services provided by monopoly transmission and distribution networks

• The way in which the Australian Energy Market Operator (AEMO) 61 manages power system security. 62

54 Note: it is anticipated that mooted plans underway to disband the ESB will have taken effect at or by the time this publication is published.

55 Electricity (National Scheme) Act 1997 (ACT) s 5, Electricity – National Scheme (Tasmania) Act 1999 (TAS) s 6; Electricity – National Scheme (Queensland) Act 1997 (Qld) s 6; National Electricity (Victoria) Act 2005 (Vic) s 6; National Electricity (New South Wales) Act 1997 (NSW) s 6.

56 Contained in schedule 1 to National Electricity (South Australia) Act 1996 (SA)

57 National Electricity (South Australia) Act 1996 (SA) s 34 and pt 7.

58 NER Version 199 Summary, 11 March 2023, https://energy-rules.aemc.gov.au/ner/468.

59 Ibid.

60 AEMC, the https://www.aemc.gov.au/energy-system/electricity/electricity-market

61 See AEMO, https://www.aemo.com.au/

62 See AEMC, https://www.aemc.gov.au/regulation/energy-rules/national-electricity-rules

In terms of regulatory scope, the NER applies to the Australian states and territories with physically connected electricity systems, namely ACT, NSW, Queensland, South Australia, Tasmania and Victoria. These participating jurisdictions are often collectively referred to as the national electricity market. 63 The current NER comprises over 1700 pages of detailed regulatory obligations for market institutions and participants, illustrating the complexities of the NEM’s regulatory framework. Figure 2.2 below provides a brief overview of these complex regulatory arrangements. For the purposes of this N4 OA, Chapter 5A of the NER is worth noting. This chapter of the NER, which sets out the rules regarding electricity connections for retail customers, is relevant to small customers and needs to be read in conjunction with the additional rules governing the national energy retail market (discussed below).

•Ch 2. Registered participants and registration - AEMO

•Ch 2A. Regional structure AEMC/AEMO

•Ch 3. Market Rules – AEMO (spot market, power system security and reliability of supply, ancillary services’ acquisition, market intervention, etc.)

Wholesale

•Ch 4. Power system security

•Ch 8. Administrative functions (e.g. Reliability Panel: Part I –AER’s responsibilities for developing, maintaining and publishing a methodology for calculating values of customer reliability)

•Chs 8.A & 9. Participatory jurisdictional derogations

•Ch 10. Glossary

Distribution Networks

•Ch 5. Network connection access, planning and expansion

•Ch 6. Economic regulation of distribution services - AER

•Ch 7. Metering - AEMO

•Ch 10. Glossary

Retail

•Ch 4.A NER, retailer reliability obligation

•Ch 5.A Electricity connection for retail customers

•Ch 6.B Retail markets

•Ch 10. Glossary

63 AEMC, https://www.aemc.gov.au/energy-system/electricity

Figure 2.2. Overview of the NER

National energy retail markets and energy consumers

The AEMC has provided the following overview of current retail energy market laws and key functions of energy market government and institutional bodies:

“The National Energy Retail Law (NERL) and National Energy Retail Rules (NERR) came into effect on 1 July 2012. The extent to which this law applies in each state and territory depends on the application of legislation passed by each jurisdiction. The National Energy Customer Framework (NECF) has been adopted in Queensland, the ACT, Tasmania, South Australia and NSW.

Development of the national energy customer framework (NECF) was overseen by the Council of Australian Governments (COAG) through the COAG Energy Council (formerly the Ministerial Council on Energy and now the Energy Ministers Meeting), with the purpose of supporting the delivery of a national and efficient energy market as set out in the Australian Energy Market Agreement (AEMA).

Legally, the customer framework consists of a package of reforms that include the National Energy Retail Law, which implements the framework, together with the National Energy Retail Regulations 2012, the National Energy Retail Rules, and various amendments to regulations and rules under the separate wholesale electricity and natural gas regimes. Application acts in each participating jurisdiction set out the specific arrangements of each for transitioning to the NECF and any jurisdiction-specific requirements.” 64

Unlike the wholesale market regulatory framework, the NECF does not apply fully across all NEM participatory jurisdictions. This is shown below in Table 2.2 below.

Table 2.2 Operative scope of the NECF

National energy retail rules (NERR)

The NERR set down the regulatory frameworks governing the sale and supply of energy to residential and small customers, together with the consumer protection measures and basic terms and conditions (contained in model contracts) that govern the relationships between customers, retailers and distributors. 65 Key Elements of the national energy retail rules are set out in the Table 2.3 below. 66

Chapters Key Regulatory Issues

Part 2

Customer retail contracts

Part 3 Customer hardship

Part 4 Relationship between distributors and customers

Part 5

Relationship between distributors and retailers retail support obligations

Part 6 De-energisation (or disconnection) of premises small customers

Part 7 Life support equipment

Part 8 Prepayment meter systems

Part 8A Electricity generation in the distribution system

Part 9 Exempt selling regime

Part 10 Retail market performance reports

Part 11 Customer retail contracts electricity consumption benchmarks

Part 12 National energy retail consultation

Schedule 1 Model terms and conditions for standard retail contracts

Schedule 2 Model terms and conditions for deemed standard connection contracts

Energy market objectives

The current objectives of the NEM and NERL set down the purpose of the national energy laws and inform the nature and scope of the obligations of market institutions and participants. The objectives are central to the rule-making powers of the AEMC, as any rules need to align with the objective.

65 https://www.aemc.gov.au/regulation/legislation

66 Current Version 37, 1 March 2023, https://energy-rules.aemc.gov.au/nerr/464.

Table 2.3. Overview of the NERR

Box 3. Existing legislative objectives

NEL, Schedule 1, Section 7 National electricity objective

The objective of this law is to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers of electricity with respect to –

(a) price, quality, safety, reliability and security of supply of electricity; and

(b) the reliability, safety and security of the national electricity system.

NERL, Section 13 National energy retail objective

The objective of this law is to promote efficient investment in, and efficient operation and use of, energy services for the long-term interests of consumers of energy with respect to price, quality, safety, reliability and security of supply of energy.

The Energy and Climate Change Ministerial Council has recently agreed to include an emissions reduction objective into the NEO. 67 In December 2022, a consultation paper and draft bill, the National Energy Laws Amendment (Emissions Reduction Objectives) Bill 2023, were presented for consideration and feedback. 68 The new proposal is to create the same objective for electricity and gas markets. If the Act is duly passed without further amendment, the new energy market objective in Section 7 of the NEL will read as follows:

“

(1) The objective of this law is to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers of energy with respect to –

(a) price, quality, safety, reliability and security of supply of electricity; and

(b) the reliability, safety and security of the national electricity system; and

(c) the achievement of targets for reducing Australia’s greenhouse gas emissions to Consultation draft which the Commonwealth, a State or a Territory has made a public commitment, including—

(i) Australia’s greenhouse gas emissions reduction targets provided for under the Climate Change Act 2022 of the Commonwealth; and

(ii) other targets for reducing, or that is likely to contribute to reducing, Australia’s greenhouse gas emissions—

(A) stated in a law of the Commonwealth, a State or a Territory; or

67 Australian Government, https://www.energy.gov.au/government-priorities/energy-ministers/priorities/national-energy-transformationpartnership/incorporating-emissions-reduction-objective-national-energy-objectives. See also e.g.,https://www.cleanenergycouncil.org.au/news/explainer-what-is-the-neo-and-reasons-for-changing-it ; https://www.cmtedd.act.gov.au/open_government/inform/act_government_media_releases/rattenbury/2022/emissions-reduction-added-tonational-energy-laws

68 Australian Government, https://www.energy.gov.au/government-priorities/energy-ministers/priorities/national-energy-transformationpartnership/incorporating-emissions-reduction-objective-national-energy-objectives

(B) stated in, or made under, an international agreement to which the Commonwealth, a State or a Territory is a party; or

(C) stated publicly as a matter of policy by the Commonwealth, a State or a Territory.

(2) In this section energy means electricity or gas or both; gas means natural gas within the meaning of the National Gas Law.”

The potential ramifications are far-reaching and warrant further consideration in terms of the regulatory impacts this change will have through the national and sub-national regulatory frameworks currently governing the electricity sector throughout Australia.

2.7. Sub-national electricity market legal frameworks

All registered participants in the NEM are subject to additional state/territory-based regulatory frameworks. As noted in the NER, this includes ‘All laws, regulations, orders, licences, codes, determinations and other regulatory instruments (other than the Rules) … applicable in each participating jurisdiction [as set out in the table below], to the extent that they regulate or contain terms and conditions relating to access to a network, connection to a network, the provision of network services, network service price or augmentation of a network’. 69 Examples of the key regulatory instruments in place at sub-national levels are set out in Table 2.4 below.

Jurisdiction Regulatory Instruments

Australian Capital Territory

• Utilities Act 2000 and all regulations made, and licences (Licences) issued under this Act

• Independent Competition and Regulatory Commission Act 1997 (ICRC Act) and all regulations and determinations made under the ICRC Act

• All regulatory instruments applicable under the Licences

New South Wales

• Electricity Supply Act 1995 (ES Act) and all regulations made, and licences (Licences) issued under the ES Act

• Electricity Infrastructure Act 2020 – this allows NSW Govt to circumvent national regulatory investment test

• Independent Pricing and Regulatory Tribunal Act 1992 (IPART Act) and all regulations and determinations made under the IPART Act

• All regulatory instruments applicable under the Licences

• Commercial Arbitration Act 2010

Queensland

• Electricity Act 1994 and all regulations made, and authorities and special approvals (Licences) granted under this Act

• All regulatory instruments applicable under the Licences

• The Gladstone Power Station Agreement Act 1993 and associated agreements

Table 2.4. Sub-national regulatory instruments

South Australia

• Electricity Act 1996 and all regulations made, and licences (Licences) issued under this Act

• Essential Services Commission Act 2002 (ESCSA Act) and all regulations and determinations made under the ESCSA Act

• All regulatory instruments applicable under the Licences

• The Electricity Pricing Order made under section 35B of the Electricity Act

Tasmania

• Electricity Supply Industry Act 1995 (ESI Act) and all regulations made, and licences (Licences) issued under this Act

• All regulatory instruments under the ESI Act or the Licences (including, without limitation, determinations of the Tasmanian Electricity Regulator under the Electricity Supply Industry (Price Control) Regulations)

• Tasmanian Electricity Code issued under section 49A of the ESI Act

Victoria

• Electricity Industry Act 2000 (EI Act) and all regulations made, and licences (Licences) issued under the EI Act

• Essential Services Commission Act 2001 (ESCV Act) and all regulations and determinations made under the ESCV Act

• All regulatory instruments applicable under the Licences

• The Tariff Order was made under section 158A(1) of the Electricity Industry Act 1993 and continued in effect by clause 6(1) of Schedule 4 to the Electricity Industry (Residual Provisions) Act 1993, as amended or varied in accordance with section 14 of the EI Act

• National Electricity (Victoria) Act 2005 (amendments introduced in 2020)

3. WORK PACKAGE 1: DISTRIBUTED ENERGY RESOURCES

3.1. DER overview

End-users are changing the way they demand, generate, store and use electricity. Enabled by new technologies, end-users employing DER are becoming competitors to traditional, centralised supply. DER are increasingly at least as a partial alternative to the networks' provision of existing services, while adding opportunities for new services. Such changes are being felt across the entire supply chain, with distribution network service providers now facing both challenges and opportunities. Some of these are considered in subsequent work packages.

This work package review and analysis identifies a range of current, emergent, and prospective governance, legal, and operational issues arising out of the DER revolution. It assesses the rapidly changing policy and regulatory framework underway across the Australian energy market. This includes recent rules changes by the AEMC, the issuance of guidelines and other regulatory instruments by the AER, actions by AEMO advancing the integration of utility-scale renewables and DER into the market, and decisions by the energy ministers. In addition to a comprehensive overview of funding schemes for DER, these all have far-reaching consequences for current and future energy markets in Australia.

Following the advanced state of DER in WA, as set out in its recently published 2-year evaluation report on its 2020 DER Roadmap, other jurisdictions are advancing their policy and regulatory response positions on DER. An example is Victoria’s recently released DER initiative, Harnessing Victoria's Distributed Energy Resources.

Regulatory terms, several key definitions, conceptual considerations and technological issues remain unresolved. In terms of demand management, this includes the changing nature of what is to be ‘managed’ in the traditional demand-end of the electricity transaction, and the variable roles/functions of existing market stakeholders. The role for the ongoing enhancement of energy efficiency response incentives for traditional end-users is equally important, as is understanding the potential impacts of the rapid growth in DER together with large-scale batteries and local community renewable energy and storage projects on the wholesale and FCAS markets. We also consider the potential impacts of the forthcoming TMIS (transmission management incentive scheme) on the wholesale market and its interaction with the retail market, especially the DM incentive scheme and DNSPs.

3.2. Challenges and opportunities

Key benefits of DER include lower electricity bills for those who can install or access DER, and decarbonising the energy system. As new technologies emerge, DER capabilities improve, costs fall, and benefits to consumers rise. Further opportunities enabled by DER “include services that help ensure the security and reliability of the power system, and innovative business models that offer new value for

customers.” 70 These new opportunities complement and amplify the benefits of customer investments. 71

At the same time, DER presents a range of challenges to the existing power system and market participants, with potentially adverse impacts on consumers in the form of higher costs and unreliable supply. At the distribution-network-level, these challenges are first and foremost technical and regulatory. Like the regulatory framework, existing networks were established at a time when current substantial levels of generation by end-users, through DER such as rooftop solar PV, was not contemplated. As the amount of generation through DER increases, the physical capacity of networks is being stretched beyond the limits of existing infrastructure, thereby compromising stability and “eroding the security and reliability of the electricity system”. 72

Flat or fixed-rate tariff structures can also be problematic. In circumstances where end-users are supplying large amounts of generation into the distribution network, flat tariff structures fail to incentivise the requisite change in consumer consumption patterns in ways that help keep supply costs at a minimum and ensure the system is stable and secure. 73 Burden/benefit-sharing inequities between end-users who can afford to install DER and those who are unable to do so can also be exacerbated by flat tariff structures, with the latter effectively cross-subsidising the former through lower electricity bills. As observed in the WA DER Roadmap, flat electricity tariff structures are incompatible with a high DER energy system. 74

3.3. Whose energy resources are they?

As discussed earlier, there is a fundamental question as to who the relevant stakeholders in these dynamic new energy markets are. For example, in response to rising distributed energy resources, current end-users are increasingly able to elect to switch between demand and supply roles (e.g. smallscale generators/storage/suppliers vs. small-scale consumers). Likewise, current retail providers are increasingly engaging in buying and supplying DER–generated electricity back to the wholesale market, for instance, by switching roles/functions from facilitating supply to end-users to supply into the wholesale and FCAS markets. This also highlights several key conceptual and definitional issues:

• Does the ESB’s post-2025 market terminology of ‘flexible demand’ adequately reflect these changing circumstances?

• Should DER really be called consumer energy resources (CER), and if so, what does this mean?

Important legal considerations about ownership, control of, and responsibility for existing and emergent DER give rise to several observations. Firstly, recent commentary from energy market institutions and other bodies is starting to question the accuracy of existing terminology and understandings of DER, suggesting that DER should be called CER. At the very least, a clear distinction needs to be articulated between DER generally and CER in particular, as in regulatory terms, DER are

70 Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 6, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

71 Ibid

72 Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 6, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

73 Ibid.

74 Ibid.

still largely described in separate, generalised terms. The ESB’s Post-2025 Market Report illustrates this where DER are described broadly as small-scale rooftop solar, batteries, smart appliances, business equipment and systems, and EVs.

The implicit assumption in the ESB’s post-2025 energy market vision is that consumers will efficiently respond to cost-reflective price signals in a way that optimises the overall operation of the electricity system (and minimises the need for surplus investment). Little to no attention is given to exposing and testing the veracity of this assumption. Private or business fleet EV owners, for instance, may need vehicles for their own purposes that do not suit being contracted to provide services to the grid/network.

A related question concerns what such a definitional change means in regulatory terms (e.g. the changing nature of demand and supply and the impacts of same on the retail/distribution and wholesale markets), as well as the changing roles and corresponding responsibilities of current consumers and other market participants in new regulatory settings. This alone suggests an urgent need for a comprehensive redesign of the prevailing energy regulatory framework. The definition of what is a consumer will likely require a rethink as the terminology of consumer/producer may not sufficiently capture the new roles that consumers assume in the market.

Many uncertainties remain and questions include: What is or could be a DER (single, multiple/hybrid)? Who owns DER? Who can access another party’s DER? Does ‘access’ include all DER or just one selected DER? Who is responsible for DER failure or damage? Are time-of-use tariffs in the context of rapidly changing DER as useful in reality as presumed to date 75 (especially integration of utility scale renewables and DER contemplated by AEMO and WA 76)? What do consumers actually want in terms of connection agreements, export restrictions, compensation for use by external parties?

3.4. Different jurisdictional approaches to planning for DER

Currently, different jurisdictions are taking their own approaches to planning for a high DER future. Current challenges and opportunities, and existing and emergent DER developments in WA and Victoria, are discussed further in the last work package of this report. This includes consideration of the future potential for DER services to extend across the entire power system.

3.5. DER and DM incentives and funding in Australia

Energy market regulators are recognising the potential of DM and DER to reduce costs for consumers and are establishing regulations to support this outcome. However, progress has been slow to establish models that are attractive to consumers. A number of incentive programs support distributed energy resources (DER) in Australia. This section briefly introduces the Australian Energy Regulator’s Demand Management Incentive Scheme (DMIS) and demand management innovation allowance (DMIA) (which will be analysed in more detail in Part 5 of this opportunity assessment), and then broadens to include

75 Kelly Burns, Bruce Mountain, Do households respond to Time-Of-Use tariffs? Evidence from Australia, Energy Economics, Volume 95, 2021, 105070.

76 See eg, AEMO’s and WA Distributed Energy Resources (DER) Registers https://aemo.com.au/energy-systems/electricity/der-register; See also AEMO, Renewable Energy Integration – SWIS update (2021) https://aemo.com.au/energy-systems/electricity/wholesale-electricity-marketwem/system-operations/integrating-utility-scale-renewables-and-distributed-energy-resources-in-the-swis

support programs for energy projects from other federally funded schemes. The section then covers an array of funds and schemes from the states and territories that can be used to support energy projects. It concludes with federal, state and territory taxation incentives and subsidies that can be utilised to support DER.

The DMIS and DMIA

The Australian Energy Regulator’s DMIS and DMIA both took effect on 14 December 2017. 77 The DMIS objective is to provide electricity distribution businesses (the energy supply side) with an incentive to undertake efficient expenditure on non-network options relating to DM. The DMIA objective is to provide distribution businesses with funding for research and development (R&D) in DM projects that have the potential to reduce long-term network costs. 78 Both apply to Victoria, the Australian Capital Territory (ACT), New South Wales (NSW), Queensland, South Australia, Tasmania and the Northern Territory.

Network DM involves avoiding or deferring network upgrades to meet higher peak demand, replacement expenditure, and operating expenditure. Networks can access around AUD1 billion until 2023 for DM where it is cheaper than new capital expenditure. The scope of the DMIS also includes replacement expenditure for aging assets and equipment failure.

The DMIS and DMIA both address the problem of managing DER from the energy supply side; no scheme or funding are available to consumers with demand-side DER problems. The following sections address federal and state-level funding sources and schemes for DER.

Other federal funding sources and schemes for DER

In 2012 ARENA was established to provide funding to projects that advance energy technologies and innovative systems. 79 ARENA’s Distributed Energy Integration Program (DEIP) that began in 2019 examined how network regulations could evolve so that consumers get the best value from innovations in DER. 80 The DEIP Report, published in 2020, summarised the views expressed during consultations, including suggestions on incentives. 81

The DEIP report’s Finding 3 recommended the creation of additional obligations and/or incentives for networks to provide hosting capacity to a level valued by users and to maximise the net market

77 ‘Demand Management Incentive Scheme and Innovation Allowance Mechanism’, Australian Energy Regulator (Web Page, 2022) <https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/demand-management-incentive-scheme-and-innovationallowance-mechanism>.

78 Australian Energy Regulator, ‘Final Decision: Demand Management Incentive Scheme and Innovation Allowance’ (Fact Sheet, 14 December 2017) <https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/demand-management-incentive-scheme-and-innovationallowance-mechanism/final-decision>; Australian Energy Market Commission, Rule Determination: National Electricity Amendment (Demand Management Incentive Scheme and Innovation Allowance for TNSPS) Rule 2019 (5 December 2019) https://www.aemc.gov.au/sites/default/files/2019-12/Final%20Determination.pdf, see also Anna Mortimore, Diane Kraal et al. 2022. Business Fleets and EVs: Taxation changes to support home charging from the grid, and affordability. Fast track project. Sydney: RACE for 2030 CRC.

79 The core grant funding is legislated: Australian Renewable Energy Agency Act 2011 (Cth). For a summary of the energy grants from the Australian federal and state governments since 2009, see Diane Kraal, Victoria Haritos and Rowena Cantley-Smith, ‘Tax Law, Policy and Energy Justice: Re-thinking Biofuels Investment and Research in Australia’ (2020) 35(1) Australian Tax Forum 31, 49–53.

80 Australian Renewable Energy Agency, DEIP: Access and Pricing Work Package (Outcomes Report, June 2020) <https://arena.gov.au/knowledge-bank/deip-access-and-pricing-reform-package-outcomes>.

81 Ibid.

benefits. 82 This was expected to further incentivise networks to improve performance and facilitate consumer engagement. The finding went further to say that “if incentives are developed, they should take account of the multiple value streams DER can offer to networks and wholesale markets”. 83 Thus this finding suggests that incentives should look beyond supply-side network incentives and focus on demand-side incentives for consumers that are equitable and affordable. Indeed, further work on Finding 3 was contracted out by ARENA to Cambridge Economic Policy Associates, who found that the “current economic regulatory framework places incentives on DNSPs [distributed network service providers] to undertake prudent and efficient expenditure in providing their regulated services”, and therefore a specific financial incentive mechanism, is not necessary. 84

The Clean Energy Finance Corporation (CEFC) was set up in 2012 to complement ARENA. The boards of ARENA and the CEFC work closely together on projects concerning Australia’s clean energy transition. 85 In 2019 the former Morrison Government announced an AUD2 billion Climate Solutions Fund (under the then Department of the Environment and Energy) to reduce greenhouse gas emissions for farmers, small businesses and Indigenous communities. This scheme superseded the Abbott Government’s ERF. 86 In the same year, the Morrison Government announced the creation of a Grid Reliability Fund, to be led by the CEFC, to expand grid-related investments with an additional AUD1 billion in capital. 87 Now, many of the Morrison Government initiatives announced in their March 2022 Budget including gas, carbon capture, and storage pipeline projects are being redirected to other federal climate initiatives, as outlined in the federal Budget 2022–23 released in October 2022. Federal and state governments met in early December 2022 to discuss the effects of rising energy cost on Australian consumers due to the war in the Ukraine. As a result of these meetings, by 9 December 2022 both federal houses agreed to place a (supply-side) cap on gas wholesale prices at $12 per gigajoule. The coal wholesale price was capped at $125 per tonne. The federal government has also allocated AUD1.5 billion in funds to help vulnerable consumers via reduced energy bills 88 and the states have matched this funding

Climate-related funding and schemes

The Australian federal government has submitted its Paris Agreement commitment to reduce greenhouse gas emissions by 43% below 2005 levels by 2030 in order to reach net zero emissions by 2050. 89 The Climate Change Act 2022 (Cth) legislates these targets. 90 As part of reaching the lower

82 Ibid 31.

83 Ibid.

84 Cambridge Economic Policy Associates, Feasibility of Export Capacity Obligations and Incentives (Final Report, July 2020) 5.

85 Clean Energy Finance Corporation, ‘CEFC Statement on ARENA Funding’ (Media Statement, 17 September 2020) <https://www.cefc.com.au/media/statement/cefc-statement-on-arena-funding>.

86 Commonwealth Government, Climate Solutions Package (Report, 2019) <https://www.dcceew.gov.au/sites/default/files/documents/climatesolutions-package.pdf>.

87 Clean Energy Finance Corporation, ‘CEFC Welcomes Announcement of $1 Billion Grid Reliability Fund’ (Media Release, 30 October 2019) <https://www.cefc.com.au/media/media-release/cefc-welcomes-announcement-of-1-billion-grid-reliability-fund>.

88 Treasury Laws Amendment (Energy Price Relief Plan) Bill 2022, https://www.aph.gov.au/Parliamentary_Business/Hansard/Hansard_Display?bid=chamber/hansardr/26394/&sid=0023

89 ‘The Paris Agreement’, United Nations Climate Change (Web Page) <unfccc.int/process-and-meetings/the-paris-agreement/the-parisagreement.

90 The Climate Change Act 2022 (Cth) took effect on 14 September 2022.

emissions target, the Albanese Government’s Budget 2022–23 included total climate-related spending of AUD25 billion from 2022–23 to 2029–30. 91

Table 3.1 summarises the major climate-related spending of almost AUD25 billion for a range of projects, of which nine can be characterised as demand-side projects. These projects include:

• The Driving the Nation Fund (AUD275.4 million) that covers delivering EV public-charging infrastructure

• The FBT exemption for EVs, and the 5% import tariff exemptions

• The Community Batteries for Household Solar program (AUD224.3 million)

• Electric bus charging infrastructure in Perth (AUD125 million)

• Solar banks (AUD102.2 million)

• The First Nations Community Microgrids Program (AUD83.8 million)

• The Townsville Hydrogen Hub (AUD71.9 million)

• Energy efficiency grants for small and medium-sized enterprises (AUD62.6 million) and

• Commonwealth EV-fleet leases (AUD39.9 million).

Table 3.1 Value of key climate-related spending measures from 2022–23 to 2029–30 92

Table 3.2 summarises other potential federal sources and schemes for DER that can be accessed by consumers.

Table

Other federal sources and schemes for DER

States: Funding sources and schemes for DER

A selection of the state and territory funding sources and schemes potentially applicable to DER are described in this section

Queensland

In 2022, the Queensland Energy and Jobs Plan committed supply-side funds to its Energy Manufacturing Opportunity Scheme. It aims to attract new investment to manufacturing and assembly businesses that can deliver the components and sub-components of the assets required to deliver generation (wind and large-scale solar) and transmission and storage (pumped hydro energy storage and grid-scale batteries). 93 The Queensland Department of State Development, Infrastructure, Local Government and Planning does not offer demand-side incentives.

New South Wales

The NSW Government set up a Climate Change Fund in 2007 under the Energy and Utilities Administration Act 1987 (NSW) that featured what could be described as demand-side incentives. 94 For instance, in 2020–21 the fund helped 197 schools in NSW to establish mini powerplants as DER, with battery storage systems installed to support new energy efficient air conditioning, fresh air ventilation and solar PV systems. 95 The NSW Energy Efficiency Savings Scheme has just added a peak demand reduction scheme, which will enable projects that reduce peak demand to generate certificates and revenue. 96 New South Wales tenders for storage capacity to complement the development of renewable energy zones are open to demand management.

Victoria

The long-established Victorian Sustainability Fund receives funds from landfill levies that are then redistributed as grants to support programs and initiatives that include demand-side climate change programs. 97 In 2020–21 funds were committed to projects that generated 3,400 kW in renewable energy generation capacity in Victorian households, businesses and commercial and industrial sites. 98 The Sustainability Fund provides for various demand-side energy upgrade programs, such as solar and

93 ‘Manufacturing Queensland’s Super Grid in Queensland’, Queensland Government (Web Page, 24 October 2022) <https://www.statedevelopment.qld.gov.au/industry/manufacturing-queenslands-super-grid-in-queensland>.

94 ‘NSW Climate Change Fund’, NSW Government (Web Page, 2022) <https://www.energy.nsw.gov.au/nsw-plans-and-progress/governmentstrategies-and-frameworks/taking-action-climate-change/nsw>.

95 NSW Government Department of Planning and Environment, NSW Climate Change Fund Annual Report 2020–21 (January 2022) 5, 17.

96 ‘Peak Demand Reduction Scheme’, https://www.energy.nsw.gov.au/nsw-plans-and-progress/regulation-and-policy/energy-securitysafeguard/peak-demand-reduction-scheme.

97 See Environment Protection Authority Victoria (Website) <https://www.epa.vic.gov.au>.

98 State of Victoria Department of Environment, Land, Water and Planning, 2021–22 Sustainability Fund Activities Report: Investing in a More Sustainable Future (Report, 2022) 27.

battery rebates for homes and business premises, zero-emission vehicle (ZLEV) purchase subsidies, neighbourhood battery programs, and heating and cooling upgrades. 99

South Australia

South Australia launched its newly restructured Department of Energy and Mines (DEM) in 2021. 100 The DEM programs include educational material for consumers about power usage, savings and efficiency. It does not provide incentives, despite stating that it will modernise the national electricity market and influence national energy policy. 101 In terms of business consumers, the DEM is supporting demand-side programs, such as the Tesla and electricity retailer Energy Locals initiative to develop South Australia’s virtual power plant, a network of potentially 50,000 solar and Tesla Powerwall home battery systems across South Australia. 102

Northern Territory

The Northern Territory established the federal Northern Australia Infrastructure Facility (NAIF) in 2016. The NAIF provides up to AUD5 billion in low-interest loans to encourage supply-side, private-sector investment in economic infrastructure. 103 The NAIF applies to projects across northern Australia, generally above the Tropic of Capricorn. NAIF funds have been provided to build a new solar photovoltaic generation facility at the Fortescue Metals Group’s Chichester Hub iron ore operations. 104 There are no specific funding incentives for consumer households to transition to DER.

Tasmania

Tasmania has established the Tasmanian Renewable Energy Action Plan to meet its 2022 target of 100% self-sufficiency in renewable electricity generation through wind resources and extensive hydroelectricity schemes. It aims to increase the supply-side renewable energy output by 200% based on the 2022 renewable energy figures. The plan is to achieve this through hydro-power and wind to electrolyse water to produce hydrogen and oxygen for domestic use and export. 105 There are no specific funding incentives for consumer households to transition to DER.

99 ‘Distributed Energy Resources’, Victoria State Government (Web Page, 21 October 2022) <https://www.energy.vic.gov.au/renewable-energy/aclean-energy-future/distributed-energy-resources>.

100 ‘About Energy & Mining’, Government of South Australia Energy & Mining (Web Page) <Error! Hyperlink reference not valid. https://www.energymining.sa.gov.au/about>.

101 Government of South Australia Department for Energy and Mining, DEM Annual Report 2020–21 (Report, September 2021) 7.

102 ‘Solar and Batteries’, Government of South Australia Energy & Mining (Web Page) <https://www.energymining.sa.gov.au/consumers/solarand-batteries>.

103 ‘About NAIF Finance’, Northern Australia Infrastructure Facility (Web Page, 2022) <https://naif.gov.au/about-naif-finance/naif-key-facts>.

104 ‘Alinta Energy Chichester Solar Gas Hybrid Project’, Northern Australia Infrastructure Facility (Web Page, 2022) <https://naif.gov.au/what-wedo/case-studies/alinta-energy-pty-ltd>.

105 Renewables, Climate and Future Industries Tasmania (Website) <https://recfit.tas.gov.au/home>.

The ACT’s 2014 Next Gen Energy Storage Program provides a demand-side rebate for battery purchase and installation for homes and businesses within the state. New battery systems need to be coupled with solar panels, connected to the electricity grid, and new (i.e. not previously supported by the program) in order to receive funding. 106

Western Australia

In Western Australia, the government is supporting clean energy and renewables projects with two funds: the Renewable Hydrogen Fund, which supports capital works projects and feasibility studies, 107 and the Clean Energy Future Fund, which supports investment-ready, innovative, clean energy projects of high public value. 108 The emphasis is currently on supply-side incentives rather than funding incentives for consumer households to transition to DER. Table 3.3 summarises potential state and territory sources and schemes for DER that can be accessed by the community.

106 ‘Next Gen Energy Storage Program’, ACT Government (Web Page, 2021) <https://www.climatechoices.act.gov.au/policy-programs/next-genenergy-storage>.

107 ‘Western Australian Renewable Hydrogen Fund’, WA.gov.au (Web Page, 22 August 2022) <https://www.wa.gov.au/government/publications/western-australian-renewable-hydrogen-fund>.

108 ‘Clean Energy Future Fund’, WA.gov.au (Web Page, 14 September 2022) <https://www.wa.gov.au/service/environment/environmentinformation-services/clean-energy-future-fund>.

Table 3.3 States and territories funding sources and schemes for DER

Tax Incentives—federal

FBT Exemption for Business Fleet EVs

The Treasury Laws Amendment (Electric Car Discount) Bill 2022 was passed by the federal parliament on 28 November 2022. It amends the fringe benefits tax (FBT) legislation to exempt cars from FBT that are zero or low emissions vehicles that employers make available for the private use of employees. 109 There is a sunset clause, which means that the FBT exemption will apply only to ZLEVs after April 2025, thus revoking the tax exemption for hybrid vehicles. The FBT exemption will apply from 1 July 2022.

Research and development tax incentive

Tax incentives can be used to reduce the cost of DER projects from an investor perspective. Mechanisms include reduced tax rates, waiving certain taxes for equipment, or revenues from energy sales. Since 2011, the R&D taxation concession for the benefit of the wider Australian economy has been available for application to eligible business expenditure and resulted in a tax offset to reduce income tax liability. 110 The R&D concession can apply to organisations engaged in DER innovations.

The legislation refers to core R&D activities 111 , which include experimental activities for the development of new and improved products, processes, materials, services and devices. A number of specific activities are excluded, for instance, market research and sales promotion, management studies and surveys, research in social sciences, arts or humanities, legal and associated administrative activities, reproduction of existing products or systems, and development or modification of computer software for internal administration.

A number of changes were introduced to the R&D tax incentive, effective from 1 July 2021. 112 These include that, if a qualifying organisation exceeds AUD150 million of eligible expenditure, the tax offset claimable on the excess amount is limited to the entity’s corporate income tax rate. Table 3.4 shows that corporate income tax rates vary according to the size of an organisation’s turnover. A summary and example of changes to tax offsets are set out in Box 4. below.

109 Fringe Benefits Tax Assessment Act 1986 (Cth). See also Treasury Laws Amendment (Electric Car Discount) Bill 2022, Parliament of Australia https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Economics/TLABElectricCarBill.

110 The R&D tax incentive is legislated under the Income Tax Assessment Act 1997 (Cth) div 355.

111 Ibid s 355-25.

112 The Treasury Laws Amendment (A Tax Plan for the COVID-19 Economic Recovery) Act 2020 (Cth).

Box 4. Summary of the changed tax offsets

Effective from 1 July 2020; vary depending on the size of the organisation

a) A refundable tax offset at the company tax rate plus an 18.5% premium (i.e. 25% + 18.5% = 43.5%) for the first AUD150 million of eligible expenditure for qualifying organisations with a total turnover of less than AUD50 million

b) A non-refundable tax offset at the company tax rate for the first AUD150 million of eligible expenditure for all other qualifying organisations. In addition, the corporate tax rate plus a premium of 8.5% for R&D expenditure up to 2% of total expenses. Unused, non-refundable tax offset can be carried forward to later years

c) For all other qualifying organisations, a non-refundable tax offset rate for R&D expenditure over 2% of total expenses is at the company tax rate plus a premium of 16.5%. For example:

XY Ltd incurred R&D expenditure of AUD140 million and Reports expenses of AUD3.9 billion in its tax return. The R&D tax offset of AUD58.86 million is calculated as:

1. AUD140 million x company tax rate of 30% = AUD42 million

2. R&D premium: (AUD3.9 billion x 2%) [= AUD78 million] x 8.5% [= AUD6.63 million] + ((AUD140 million - AUD78 million) x 16.5% [AUD10.23 million]) = AUD16.86 million

Early-stage innovation companies: tax incentives

The federal government also supports early-stage innovation by companies through specific tax incentives under the National Innovation and Science Agenda. 113 Tax legislation covers concessional tax treatment for qualifying early-stage innovation companies (ESICs). 114

Tax concessions are available to early-stage companies that are developing new or significantly improved innovations for commercial return (e.g. microgrids). The purpose of the tax policy and legislation is to encourage innovation by aligning the tax system and business laws with a culture of entrepreneurship and risk taking. These tax concessions provide eligible investors with –

113 See ‘Tax Incentives for Early-Stage Investors’, The Treasury (Web Page) <https://treasury.gov.au/national-innovation-and-science-agenda/taxincentives-for-early-stage-investors>.

114 Income Tax Assessment Act 1997 (Cth) div 360.

• A 20% non-refundable carry-forward tax offset on share investments (with an offset cap of AUD200,000) in qualifying ESICs and

• An exemption from capital gains tax for share investments in an ESIC held for at least 12 months but less than 10 years.

Tax incentives and subsidies states and territories

Tax Incentives and subsidies for EVs

The summary below is of state and territory support for (distributed) energy resources in the form of EVs. 115

South Australia, New South Wales, Western Australia and Tasmania have active or budgeted policies to directly support uptake of EVs. By contrast, Victoria introduced an EV road-user charge in 2021. South Australia is investing up to AUD13.4 million to leverage approximately AUD25 million of private investment for a state-wide EV charging network. Priority areas are fast-charging stations across selected sites, including shopping plazas and town centres in metropolitan, regional and remote areas. Rapid and ultra-rapid-powered highway charging stations are expected to provide up to 100–350 km of range extension in 10 minutes. 116 The South Australian Government is currently calling for proposals from charge point operators to apply for grant funding to develop sections of the network (2022–24).

New South Wales supports BEVs, PHEVs (plug-in hybrid electric vehicles) and FCEVs (fuel-cell electric vehicles) through stamp duty exemptions for new cars under AUD78,000 from September 2021, as well as cash rebates of AUD3,000 for 25,000 new EV buyers. NSW also considered an EV road-user charge (similar to Victoria), but decided to postpone any implementation until either 2027 or whenever new EVs make up 30% of new vehicle purchases. There is investment in charging infrastructure on major NSW highways and commuter corridors, and the NSW 2021–22 Budget provided for additional charging infrastructure in areas with limited off-street parking, in commuter car parks, and in regional tourist areas. The NSW Government Budget contains targets to electrify its fleet. It claims EVs will comprise 50% of new government passenger fleet vehicles by 2025–26. 117

Western Australia supports EVs through an EV fund of AUD20 million. Key areas of proposed action include the creation of an EV–charging infrastructure network north from Perth to Kununurra, along the south-west coast to Esperance, and east to Kalgoorlie. 118

In 2021 Tasmania announced an EV ChargeSmart Grants Program, providing AUD600,000 for EV fastcharging stations in regional areas and at key tourism destinations. 119

115 Ibid 139.

116 ‘Modern Energy’, Government of South Australia Energy & Mining (Web Page) <https://www.energymining.sa.gov.au/industry/modernenergy>.

117 NSW Government, Budget 2021–22 (22 June 2021) <https://www.budget.nsw.gov.au/sites/default/files/2021-06/4.%20ReviewBP1%20Budget%202021-22.pdf>.

118 Government of Western Australia, State Electric Vehicle Strategy for Western Australia: Steering Towards a Clean Energy Future (Report, November 2020) 10 <https://www.wa.gov.au/system/files/2020-11/State_Electric_Vehicle_Strategy_for_Western_Australia_0.pdf>; Government of Western Australia, ‘WA Accelerates towards Longest EV Fast Charging Network’ (Media Statement, 17 August 2021) <https://www.mediastatements.wa.gov.au/Pages/McGowan/2021/08/WA-accelerates-towards-longest-EV-fast-charging-network.aspx>.

119 Tasmanian Government, ‘Tasmania’s Electric Vehicle Future Charging Ahead’ (Media Release, 4 August 2021) <https://www.premier.tas.gov.au/site_resources_2015/additional_releases/tasmanias_electric_vehicle_future_charging_ahead>

Victoria introduced a road-user charge to be levied on plug-in-type electric and hydrogen vehicles (zero and low emission vehicles, ZLEVs) from July 2021. 120 Direct EV assistance to owners of ZLEVs is provided via an AUD100 registration concession as well as an AUD3,000 ZLEV purchase subsidy for 20,000 vehicles purchased on or after 2 May 2021. 121 The state has an EV policy roadmap and is calling for businesses and other organisations to install EV charging stations across the state, with AUD5 million in funding to expand Victoria’s network of fast chargers. 122

The ACT claims to have Australia’s most generous financial incentives for the purchase and registration of ZLEVs. A two-year waiver of registration and interest-free loans (up to AUD15,000) for ZLEVs to help cover the purchase price, applied to acquisitions on or after 24 May 2021. 123

Queensland and the Northern Territory offer reduced registration for EVs. 124 Australian states and territories do not subsidise EV home charging equipment, although some states indirectly provide rebates for solar panels. 125

3.6. DERs and EVs

Background on a recent RACE for 2030 project for EVs

A RACE for 2030 project on business fleets and EVs and taxation support published in 2022 126 investigated the necessity of tax changes to accelerate the uptake of battery electric vehicles (BEVs) by business fleets.

Up to 47% of fleet vehicles are home-garaged 127, providing an opportunity for business fleet BEVs to be home charged using smart meters and to optimise CO2 emissions reduction. Road transport internal combustion engine vehicles (ICEVs) contributed to 18.3% of Australia’s carbon dioxide (CO2) emissions

120 ‘Hybrid or Electric Vehicle Registration Discounts’, Vic Roads (Web Page, 16 June 2021) <https://www.vicroads.vic.gov.au/registration/registration-fees/concessions-and-discounts/hybrid-vehicle-registration-discount>; ‘Zero Emissions Vehicles’, Victoria State Government (Web Page, 16 September 2022) <https://www.energy.vic.gov.au/renewable-energy/zero-emissionsvehicles>; ‘ZLEV Road User Charge’, Vic Roads (Web Page, 20 July 2022) <https://www.vicroads.vic.gov.au/registration/registration-fees/zlevroad-user-charge>; Ben Zachariah, ‘Victoria Passes Road-User Tax for Electric Vehicles, Industry Reacts’, Drive (Web Page, 26 May 2021) <https://www.drive.com.au/news/victoria-passes-road-user-tax-for-electric-vehicle-owners-industry-reacts>.

121 State of Victoria Department of Environment, Land, Water and Planning, Victoria’s Zero Emissions Vehicle Roadmap (Report, May 2021) <https://www.energy.vic.gov.au/__data/assets/pdf_file/0014/521312/Zero-Emission-Vehicle-ZLEV-Roadmap-FINAL.pdf>.

122 Hon Daniel Andrews, Premier of Victoria, ‘Getting More Electric Vehicle Chargers across Victoria’ (Media Release, 24 June 2021) <https://www.premier.vic.gov.au/getting-more-electric-vehicle-chargers-across-victoria>.

123 ‘Cars and Vehicles’, ACT Government (Web Page, 2021) <https://www.environment.act.gov.au/cc/zero-emissions-vehicles>.

124 ‘Shifting to Zero Emission Vehicles’, Queensland Government (Web Page, 1 July 2022) <https://www.qld.gov.au/transport/projects/electricvehicles/hitting-the-road>; ‘Registration Fees: Electric Vehicle Registration’, NT.gov.au (Web Page, 1 July 2022) <https://nt.gov.au/driving/rego/fees/registration-fees#electric_vehicle>.

125 See ‘Solar Panel (PV) Rebate’, Solar Victoria (Web Page, 24 August 2022) <https://www.solar.vic.gov.au/solar-panel-rebate>.

126 Anna Mortimore, Diane Kraal, Lee K-H., Klemm C., Akimov A., Business Fleets and EVs: Taxation Changes to Support Home Charging from the Grid, and Affordability (Final Report, RACE for 2030 project, 2022), <https://issuu.com/racefor2030/docs/race_for_2030_bevs_and_fleets_Report_final?utm_campaign=320481_BEVs%20media%20release&utm_m edium=email&utm_source=RACE%20FOR%202030%20Limited&dm_i=6RTZ,6VA9,1S3CE3,QGKW,1%3E>

127 Australasian Fleet Management Association (‘AfMA’) and AGL Energy Ltd, Survey: Electric Vehicles in Business Fleets (Report, 2020).

in 2020. 128 As 40% of light vehicles sold in Australia in 2020 were purchased by businesses 129, fleet cars are an obvious source for CO2 reductions. A bill passed by federal parliament in November 2022 covers changes for employer-provided electric vehicles that include a full exemption from fringe benefits tax. 130

Nexus between this project on regulation for DM and DER and EVs

The critical difference between the research on business fleets and EVs and taxation support is the identification of short-term and long-term tax changes and other fiscal incentives. Together, these demand-side incentives address affordability arising from the price premium on BEVs, current tax barriers inherent in establishing home charging of fleet vehicles, the use of fleet EVs to store energy, and the use of charging meters to make use of off-peak rates, avoid grid congestion, and counter the lack of business site-charging facilities. With respect to RACE research on business fleets and EVs and taxation support and its nexus to this current project on regulation for DM and DER, both are addressing the EV needs of consumers regarding how to use and store DER that is both affordable and lowers CO2 emissions.

As a result of this collaborative RACE report on EVs and tax and additional pressure from other constituents, in July 2022 a federal parliamentary bill concerning a full exemption of electric vehicles from fringe benefits tax (FBT), the ‘Treasury Laws Amendment (Electric Car Discount) Bill 2022’, was read and accepted in the House of Representatives. The subsequent law, which received royal assent in December 2022, applies to battery, hydrogen fuel cell and plug-in hybrid (with some restrictions) electric cars for the FBT exemption.

128 Almost one-fifth of Australia’s emissions are from transport: see Department of Industry, Science, Energy and Resources, Australian Government, Quarterly Update of Australia’s National Greenhouse Gas Inventory: June 2020 (Report, November 2020). The Deep Decarbonization Pathways Initiative Reports that 23% of all energy-related global emissions is from the transport sector: see ‘Deep Decarbonization Pathways for Mobility’, IDDRI (Web Page) <www.iddri.org/en/project/deep-decarbonization-pathways-mobility>.

129 FCAI, ‘VFACTS December 2020: New Vehicle Sales Figures’ (2020); Department of Industry, Science, Energy and Resources, Australian Government, Future Fuels Strategy: Powering Choice (Discussion Paper, February 2021) 15 (‘Future Fuels Discussion Paper’).

130 See ‘Treasury Laws Amendment (Electric Car Discount) Bill 2022 [Provisions]’, Parliament of Australia (Web Page) <https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Economics/TLABElectricCarBill>.

4. WORK PACKAGE 2: MAXIMISING CUSTOMER VALUE FROM EXISTING DEMAND MANAGEMENT REGULATORY INCENTIVES

One key enabler of DER is demand management, that is, incentivising customers to reduce, change or shift how they use electricity as an alternative to investing in new or replacement electricity supply infrastructure. Energy market regulators around the world have recognised that demand management is often beneficial for customers, but that establishing effective regulation for electricity utilities to implement cost-effective demand management can be difficult. This aspect of the N4 research theme will seek to clarify and streamline processes relating to the DMIS and develop opportunities to apply it the DSO model, including by investigating options to enhance, tap, and maximise the value of customer benefits associated with –

• Managing minimum net demand

• Increased reliability

• Avoided energy at risk

• Reduced rooftop solar curtailment and

• Increased solar hosting capacity.

The research approach developed in this theme will help to inform the design of customer-focused regulation driven by the need for the enablement of DER uptake and potentially managing growth in peak demand in response to EV uptake. As the B4 Opportunity Assessment undertook an assessment of data on DM market potential and barrier and solution analysis, this will not be repeated as part of this assessment.

4.1. What is demand management?

Energy demand can be managed in various ways. Referred to as demand-side management (DSM) or demand management (DM), the key purpose of incentives of this kind is to change the shape and timing of consumption, either by avoiding end-use consumption or by improving energy supply efficiencies. Moreover, demand-side management of final consumption can be distinguished from demand management incentives that aim to improve the efficiency of energy supply required to meet end user demand:

“In its most basic form, investments are made in energy efficiency that lead to avoided energy consumption (for demand-side interventions such as improved vehicle efficiency) or avoided energy losses (for supply-side interventions such as improvements to the efficiency of electricity distribution). Delivering the same level of energy service (lighting, heating, transport etc.) while using less energy has a value related to the cost of the energy saved.” 131

The following discussion explores these two aspects of demand management and the contribution of energy efficiency incentives to emissions reductions and achieving net zero by 2050.

4.2. Managing final demand: Improving energy efficiency to avoid or reduce end-use consumption

From the end user's perspective, energy efficiency incentives have long been an integral part of energy demand management. Demand-side interventions, such as energy efficiency targets, energy efficient heating/cooling and other residential and business appliances, roofing insulation, double-glazing, and a range of additional energy efficiency building standards and construction practices all focus on incentivising the avoidance of energy consumption or uptake of more efficient technology and services by end-users. The management of energy demand through measures such as these usually entail a ‘step-down’ in end-use energy demand.

From the consumer–end user perspective, demand management has an entirely different meaning to that used by others. To date, the most common way in which consumers manage their own demand is through behind-the-meter actions that alter end user consumption patterns to reduce energy bills by:

• Reducing the overall demand for grid-supplied electricity in several ways, for instance, by buying energy efficient appliances (whitegoods, TVs, aircon/heaters), retrofitting/upgrading existing housing/buildings to improve energy efficiency (insulation, double-glazing, ceiling fans, split/reverse cycle aircon), installing solar hot water systems, etc.

• Providing small-scale RE generation for on-site consumption and/or feed-in to the grid/network (e.g. rooftop PV solar) and

• Employing small-scale battery storage for on-site consumption and/or feed-in to the grid/network, home/business batteries and EVs.

4.3. Managing demand in the NEM: Improving energy efficiency in electricity networks

The current regulatory framework for the national electricity market includes five mechanisms specifically designed to manage demand, either immediately in response to challenges or looking forward:

• Wholesale demand response mechanism 132

• Emergency demand response under the Australian Reliability and Emergency Reserve Trader (RERT) scheme 133

• Demand management innovation allowance mechanism (Transmission) (DMIAM) 134

• Ancillary services such as frequency control ancillary services (FCAS)

• Demand management incentive schemes (DMIS)

• Demand management innovation allowance (DMIA) 135 and

132 Australian Energy Market Commission, Rule determination: Wholesale demand response mechanism (11 June 2020)

https://www.aemc.gov.au/sites/default/files/documeznts/final_determination_-_for_publication.pdf

133 Reliability and Emergency Reserve Trader (RERT), https://aemo.com.au/en/energy-systems/electricity/emergency-management/reliability-andemergency-reserve-trader-rert

134 AER, Demand Management Innovation Allowance Mechanism (DMIAM) https://www.aer.gov.au/networks-pipelines/guidelines-schemesmodels-reviews/demand-management-innovation-allowance-mechanism-transmission

135 AER, Demand management incentive scheme and innovation allowance mechanism Final Decision (14 December 2021)

https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/demand-management-incentive-scheme-and-innovationallowance-mechanism .

• Individual jurisdictional schemes, such as the NSW Peak Demand Reduction Scheme (PDRS). 136

The first four of these manage demand in the wholesale electricity market; the last operates in the retail/distribution/end-user market.

Incentive-based regulatory measures such as these have been introduced to improved outcomes for consumers by providing incentives on networks to become more efficient over time 137 The AER is currently undertaking a review of the incentive schemes and guidelines for regulated electricity and gas networks to ensure they remain relevant and fit-for-purpose. 138 The AER also points out that this review forms part of strategic objectives during 2020–25 to improve its approach to regulation by being more efficient and focusing on outcomes that matter most to consumers. 139 The following discussion explores these within the context of this project.

Wholesale demand response mechanism

The National Electricity Amendment (Wholesale demand response mechanism) Rule 2020 No. 9 has been designed to enable opportunities for more active demand-side participation in central dispatch at low cost and with greater transparency. 140 This enables aggregators as well as retailers to bid demand management into the NEM as an alternative to supply to meet peak demand at lower cost. Since commencing in late 2021, consumers are able to sell demand response in the wholesale market, either directly or through specialist aggregators, for the first time. 141 Given the historical rarity of demand-side participation of this kind in the wholesale market, the wholesale demand response mechanism represents a significant reform for the NEM. 142 Moreover, as noted by the AEMC –

“Under this mechanism, consumers will be able to actively participate in central dispatch and be rewarded for the value they provide to the system. In addition, this mechanism will capture the benefits of greater demand-side participation and share these benefits with all consumers. This final rule allows for new technologies, particularly those brought about by increased digitalisation, to be valued within the market framework. This is an important step on a path toward a two-sided market.” 143

136 Peak Demand Reduction Scheme (NSW), https://www.energy.nsw.gov.au/nsw-plans-and-progress/regulation-and-policy/energy-securitysafeguard/peak-demand-reductionscheme#:~:text=The%20Peak%20Demand%20Reduction%20Scheme%20(PDRS)%20was%20established%20in%20September,which%20bega n%20in%20November%202022

137 AER, Review of expenditure incentive schemes: Discussion paper (December 2021) 20, available at https://www.aer.gov.au/networkspipelines/guidelines-schemes-models-reviews/review-of-incentive-schemes-for-regulated-networks

138 ibid. See also e.g., AER, Capital Expenditure Sharing Scheme (CESS), which provides ‘electricity distribution network service providers (DNSPs) and transmission network service providers (TNSPs) (collectively, NSPs) with an incentive to undertake efficient capex during a regulatory control period’; AER, Position paper - Review of incentive schemes: Options for the Capital Expenditure Sharing Scheme (11 August 2022) https://www.aer.gov.au/system/files/incentive%20review%20%20CESS%20position%20paper.pdf

139 AER, Review of incentive schemes for regulated networks, https://www.aer.gov.au/networks-pipelines/guidelines-schemes-modelsreviews/review-of-incentive-schemes-for-regulated-networks

140 AEMC, National Electricity Amendment (Wholesale demand response mechanism) Rule 2020 No. 9, available at https://www.aemc.gov.au/rule-changes/wholesale-demand-response-mechanism

141 AEMC, Wholesale demand response mechanism final rule: Information (11 June 2020), https://www.aemc.gov.au/sites/default/files/documents/information_sheet_-_for_publication.pdf.

142 Ibid.

143 Ibid.

In reaching its final determination, the AEMC made a more preferable electricity rule that allows large customers to provide demand response to DRSPs and, in turn, enables them to offer this into the wholesale market. 144 As a consequence, in addition to enabling greater demand-side participation, the AEMC’s final rule has introduced a new market participant category, a demand response service provider (DRSP). A DRSP can be a separate entity or an existing large customer. Once registered with AEMO, a DRSP can contract with large customers to provide demand response by reducing load or exporting with behind-the-meter generation and pay for this demand management service. 145

Of note is the AEMC’s observation on the expected end date for of this mechanism is that

“The Commission considers that moving to a two-sided market will assist the NEM in effectively evolving and transitioning to the future power sector, and that will provide enduring consumer benefits. A two-sided market is characterised by the active participation of the supply and demand side in dispatch and price setting. Moving to a two-sided market should enable the transition to a reliable and secure future NEM that is characterised by increasingly variable supply and more flexible, price-responsive demand. With these expanded opportunities, a move to a two-sided market will be essential. The growing number of consumers equipped to actively participate in the market will eventually lead to the market outgrowing this particular wholesale demand response mechanism. In the meantime, the mechanism will be important for enabling a greater level of demand-side participation in the wholesale market.” 146

Emergency demand response: Australian reliability and emergency reserve trader (RERT) scheme

The emergency demand response functions by providing on-demand capacity to the market operator to manage contingencies. Under the Australian Reliability and Emergency Reserve Trader (RERT) Scheme, additional capacity is contracted to reduce demand when the electricity grid is under extreme pressure. Rule changes were enacted in 2020 to improve access and reduce the cost of RERT. 147

Ancillary services: FCAS

The wholesale market operator, AEMO, can also use the FCAS process to balance generation and load to maintain safe operation of the power system (e.g. prevent deviations in the power system frequency to avoid “instability or, at extreme levels, cascading failure and blackouts”) 148 The FCAS process “provides a fast injection of energy or fast reduction of energy to manage supply and demand” by enabling purchase of ancillary services by AEMO to “maintain frequency and ensure the stability and reliability of the grid”. 149

More specifically, FCAS can contribute to demand management by providing frequency and voltage control at lower cost than centralised generation. There are currently eight markets for FCAS that can

144 Ibid.

145 Ibid.

146 Ibid.

147 See further discussion, AEMC, Amendments to the RERT Guidelines August 2020, https://www.aemc.gov.au/market-reviewsadvice/amendments-rert-guidelines-august-2020.

148 ARENAWIRE, What is Frequency Control Ancillary Services? (10 August 2017) https://arena.gov.au/blog/what-is-frequency-control-ancillaryservices

149 Ibid.

be used to manage rises/drops in frequency. 150 These fall into two categories: regulation, and contingency frequency control services. 151

4.4. Demand management incentive scheme (DMIS)

One of the potentially most significant regulatory reforms to tap the potential of DM and DER in Australia is the DMIS adopted by the Australian Energy Regulator in 2017, which was introduced above. The AER has estimated that, if fully adopted, the DMIS could lead to AUD1 billion in investment over five years in cost effective demand management, which is cheaper than new capital expenditure. 152 The scope of the DMIS also includes aging assets and risk of equipment failure and therefore replacement expenditure.

However, the adoption of the DMIS has been relatively slow, and there appears to be widespread uncertainty about how to identify and quantify customer benefits and how to receive regulatory approval for projects. This uncertainty has likely been exacerbated by the almost complete reduction in peak-demand growth across distribution networks since the Global Financial Crisis in 2008 and the rise of rooftop PV and the DER revolution. It is also important to consider the interactions between the DMIS and other relevant schemes, including, in particular, the Service Target Performance Incentive Scheme (STPIS) and the wholesale demand response mechanism (WDRM). In addition, the new access and pricing rule change has made specific changes to the definition of DMIS in the Rules (NER 6.6.3) to make it clear that the incentive now applies to schemes to manage peaks in export as well as maximum demand.

4.5. Sub-national DM programs

In terms of programs, demand management has been incorporated into the NSW Energy Savers Scheme to create an incentive for peak demand reduction activities, and the South Australian Retailer Energy Productivity Scheme also includes some eligible demand management activities (e.g. ‘solar sponge’ water heating). Consequently, there is an extensive body of contemporary grey literature on demand management regulation in Australia (discussion/issue papers, associated research and engagement between regulatory agencies and stakeholders).

4.6. Outcomes of DM regulatory reforms

To date, the results from these regulatory reforms have mostly been modest –

150 See further discussion in AEMO, Guide To Ancillary Services In The National Electricity Market (November 2021) https://aemo.com.au//media/files/electricity/nem/security_and_reliability/ancillary_services/guide-to-ancillary-services-in-the-national-electricity-market.pdf

151 Regulation frequency control services are described in AEMO, ibid (p6), those services ‘provided by generators on Automatic Generation Control (AGC). The AGC system allows AEMO to continually monitor the system frequency and to send control signals out to generators providing regulation in such a manner that the frequency is maintained within the normal operating band of 49.85Hz to 50.15Hz’. By contrast, contingency frequency control services are those which enable AEMO to meet its obligations under NEM frequency standards to ‘ensure that, following a credible contingency event, the frequency deviation remains within the contingency band and is returned to the normal operating band within five minutes’

152 AER, Submission to Rule change request Demand management incentive scheme and innovation allowance for transmission network service providers Consultation Paper (2019).

• The RERT has expanded and broadly functions as intended as emergency demand response 153, albeit at very expensive prices in recent intervals. 154

• There have been very low levels of network demand management under the DMIS. In 2019–20, just AUD500,000 of expenditure was submitted and approved across four distribution network service providers. 155

• To date, only 5 MW of demand management capacity has been registered under the WDR. Demand management aggregators and consumer bodies have argued that the product specifications and monitoring and evaluation requirements exclude most potential sources of demand flexibility 156, and detailed modelling has found that many loads are excluded under the design of the WDR. 157 The inclusion of peak demand in the NSW ESS has not been in operation long enough to form any assessment.

Further regulatory reform is currently under consideration, in particular the development of a capacity mechanism by the Energy Security Board that would include demand management. This is an extremely important development because, as Brown et al. (2019) noted in a review of international demand response mechanisms for the AEMC, “jurisdictions with capacity markets consistently attract the most demand response participation, and demand response resources there earn the vast majority of their resources”. 158

4.7. Who has responsibility for demand management?

Consequently, there are a range of actors with responsibility for demand management:

• AEMC/AER: Demand management studies have identified a range of regulatory barriers, especially noting that price signals often either do not exist or are muted/distorted. Regulatory institutions have a fundamental role in establishing a framework for the growth of cost-effective demand management.

• Electricity retailers and networks (transmission and distribution): Electricity retailers have responsibility for setting prices and are often the contracting parties under current arrangements.

• Intermediaries (aggregators, advisers, etc.): Aggregators and advisers will play an increasingly important role as price signals become more common. For example, aggregators can now bundle and sell demand management into the wholesale electricity market.

• End-users/consumers: Once demand management moves beyond its primary role at present (emergency), it would be actively engaged through various parts of the electricity system by energy users in response to price and non-price signals, with varying degrees of automation.

153 AEMC, Enhancement to the Reliability and Emergency Reserve Trader, Rule determination, 2 May 2019.

154 See eg, AEMO, quarterly RERT cost reporting, available at https://aemo.com.au/en/energy-systems/electricity/emergencymanagement/reliability-and-emergency-reserve-trader-rert/rert-reporting.

155 AER, Decision: Approval for Demand Management Incentive Scheme (DMIS) incentives for electricity distributors in 2019-20 (April 2021) 5.

156 See eg, PIAC, Submission to the Wholesale Demand Response Participation Guidelines – Issues Paper (29 April 2021).

157 See Lance Hoch et al, Phase 1- WDRM Baseline Methodology Analysis Results and Recommendations (2020) and Phase 2 – Baseline Methodology and Participant Testing (prepared for the Australian Energy Market Operator).

158 Toby Brown et al, International Review of Demand Response Mechanisms in Wholesale Markets (prepared for the Australian Energy Market Commission, June 2019); also Liu, Y. (2017) ‘Demand Response and Energy Efficiency in the Capacity Resource Procurement: Case studies of forward capacity markets in ISO New England, PJM and Great Britain’, Energy Policy, 100, 271-282.

4.8. What is the current scale of the DM market and cost of DM in Australia and overseas?

A substantial body of reports has found that there is significant untapped potential to improve the efficiency, security and reliability of the energy system by making greater use of demand management/flexibility. 159 Information on the current scale of demand management is often poor (or commercial in confidence) but in general appears limited. Even so, it is possible to make the following observations 160:

• Emergency demand management under the RERT, 1422 MW (5223 MWh) was contracted from 2019–21, with a benefit-cost ratio of almost 2:1.

• Information on the current level of retailer demand response and wholesale-exposed customers appears limited. Under the WDR, there is only one registered participant and around 65 MW of registered capacity, so it is relatively small-scale.

• The networks applied for just AUD500,000 in 2019–20 under DMIS.

• FCAS demand management is estimated at 180 MW.

• Just under 1 GW of demand management capacity is estimated to exist in the industrial sector. Costs vary across different types of demand management (as does information quality). The RACE for 2030 B4 Opportunity Assessment produced a table summarising costs, quantity, and peak demand potential. This table is reproduced below.

159 (AEMO 2017; AEMC 2018; CSIRO; Commonwealth of Australia 2017; ISF 2018; RACE for 2030 CRC 2021).

160 All of the following are detailed in the RACE for 2030 B4 Opportunity Assessment, Brinsmead et al, (2021). Flexible demand and demand control. Final report of opportunity assessment for research theme B4. RACE for 2030 CRC.

Table 4.1 DM market and cost

4.9. What is Australian industry current practice and best practice for DM?

As Australia does not in general have well-functioning markets and systems for demand management, best practice tends to be exhibited by case studies or particular actors. Several case studies are set out below and illustrate various opportunities for engaging in demand management.

Case study: IKEA - Cold Storage Tank

IKEA’s Tempe store in inner Sydney is a 40,000 square meter ‘big box’ retail facility that combines warehouse, retail, offices and a café and operates 7 days a week for extended hours. Electricity is used for air-conditioning (primarily cooling), lighting, operation of a restaurant, office equipment, charging forklift batteries, and operating a variety of equipment such as hydraulic waste compressors. The site hosts a 990 kw solar PV system, a back-up generator, electric vehicle forklifts, a building management system, and 1.8 megaliters of cold-water tank storage. The electric chiller cooling capacity is supported by the chilled water storage (maximum storage of around 22,000 kWh refrigeration) that replaces or supplements chiller operation in the day.

Optimising the use of the cold storage tanks, on-site monitoring and controls, management of discretionary loads, and even occasional use of the back-up generator could deliver significant demand response benefits. Simply upgrading the chiller controls to spread discharge over the whole day instead of finishing in the early afternoon delivers a high IRR in excess of 40% with a quick payback period of one year.

However, an additional 200 to 250 kW of solar PV to charge the cold tank has a higher NPV Using chiller controls and the cold tank is a cheaper form of storage than batteries. Additionally, as battery prices fall, a 100 kWh battery would add further value. Upgrading the batteries of the 18 forklifts as their replacement falls due could offer further cheap storage.

IKEA’s power demand tends to peak in the late afternoon, which is when rates can increase as costreflective tariffs come in to reflect demand (as people return home, turning on power, and solar output drops off). Increasing flexibility will equip the company to better manage its electricity costs in response to tariff changes, but also to earn revenue as the rules are being changed to reward businesses that can change their demand profile or export during peak times or support the operation of the electricity network.

Source: ISF, Renewable Energy and Load Management, Factsheets arena.gov.au/knowledge-bank/?keywords=Renewable+Energy+and+Load+Management&y=

Case study: V&C F oods

V&C Foods (South Coast Stores) in Nowra has engaged Minus40 to design its refrigeration system for a new cold store. The new facility will have offices, a butchery, and a retail area, as well as cold room and freezer room storage. The plant has been designed with energy optimisation in mind, reclaiming heat from the refrigeration cycle to heat water for various processes in the facility, as well as using other integrated technologies and optimised control for energy and operational savings.

By investing in highly efficient chillers, additional cold storage is not necessary at the site. Efficient chillers also mean that the electricity connection capacity to the site is minimised, avoiding an expensive network upgrade for a larger substation to power the site. Capturing some of the heat produced by the refrigeration cycle through a hot water heat exchanger means that most of the heating requirements of the facility can be serviced without the need for electrical heating. The following areas can make use of the reclaimed hot water –

• Evaporator defrost cycle

• Freezer sub-floor heating

• Retail sub-floor heating

• Domestic hot water

• Office space heating

If the site was an established site with less efficient refrigeration, it could be a candidate for phasechange material for cold storage in the freezer rooms. A 60–80 kW north facing PV system, combined with the sites loads and operational profile, could be expected to earn a return in the order of 13%.

Source: ISF, Renewable Energy and Load Management, Factsheets: arena.gov.au/knowledge-bank/?keywords=Renewable+Energy+and+Load+Management&y=

Case study: Goodman Fielder

The Goodman Fielder plant at Erskine Park includes two facilities with shared plant for steam, hot water and compressed air, including –

• A baked frozen bread plant which produces pre-baked frozen bread. Cooling is delivered by large refrigeration chillers, which are the dominant plant electrical loads (two 220 kW ammonia chillers and a 38.5 kW chiller for delivering chilled water). There are also two 103 kW chillers for the factory HVAC system (and associated cooling towers) for the whole factory.

• A liquids factory which mixes and cooks a range of liquid products, such as sauces and dressings. This comprises a less intensive load, largely associated with mechanical mixing and blending, as well as a 150 kW ammonia unit for a chilled water circuit.

The load profile indicates that demand on Monday mornings is extremely peaky, with up to 200 kVA jumps (largely a result of the cooling plant being restarted after a weekend shutdown and clean). Not much energy is consumed when the total plant load exceeds 450 kVA, so there are opportunities to reduce peak demand under the current network tariff.

Adding a cold storage tank will improve the returns on a planned investment in rooftop solar. A relatively short amount of storage time is needed to use solar power to lop the peaks. This better suits a cold tank storage than a battery, which comes in modular units. Returns in excess of 14% could be expected from a modest-sized cold tank in combination with a solar PV system of 450 kW. A short duration electricity tariff that reflects system costs would significantly improve returns.

Source: ISF, Renewable energy and load management, Factsheets: arena.gov.au/knowledge-bank/?keywords=Renewable+Energy+and+Load+Management&y=

4.10. What are plausible, potential benefits and costs of DM for customers in terms of bill reduction and carbon emission abatement?

Demand management entails costs and benefits for consumers: across the NEM for consumers that do not implement demand management, and at a site-level for those consumers that do implement demand management. At the NEM-level, demand management can reduce bills for all by –

• Avoiding investment in new generation or storage

• Avoiding deployment of high-cost generation or storage when the supply-demand balance is tight and

• Increasing network utilisation: Synapse Energy/NERA has estimated that the potential for peak demand reduction is up to 6 GW. 161

The RACE for 2030 B4 Opportunity Assessment estimated 1000 MW of demand would reduce electricity bills by AUD455 million p.a. but recommends that ‘detailed research should be conducted to develop more rigorous estimates’. The largest source of bill savings per 1000 MW is in the wholesale market ($290 million), followed by networks ($100 million), RERT ($35 million) and FCAS ($30 million).

The B4 Opportunity Assessment authors noted that their estimates were conservative relative to some other, more detailed, modelling estimates. In the most recent modelling analysis commissioned by ARENA (with the input of AER and AEMC) and undertaken by Synapse Energy, the savings were found to dramatically increase with the increasing ambition of the energy transition scenario used (see Table 4.2).

SOW 1: Baseline c ase $1 billion $6 billion

SOW 2: High EV u ptake $3 billion $5 billion

SOW 3: Electrification $4 billion $5 billion

SOW 4: High DER u ptake 163 $8 billion $18 billion

The key findings from the study are that –

• A high DER scenario most closely matches current investment trends as it reflects the assumptions of the ISP Step Change scenario. Therefore, the headline finding is the potential range of $8 billion to $18 billion in savings.

• The value of demand flexibility increases as more renewable energy is added to the system and electrification increases, and there are greater opportunities for arbitrage and offsetting of supply variations and shortfalls.

• The largest demand-side resource is flexible charging of EVs either through deferred charging or V2G services due to the low marginal costs. Under a scenario with accelerated EV uptake (80% of new sales by 2030), savings of $3-5 billion for consumers offset the rises in electricity prices that would otherwise occur due to increased demand.

At the site-level, there is a range of costs for consumers (operational time, Capex, etc.), who will implement demand management where the benefits are cost effective:

• Less exposure to electricity price movements and spikes

• Lower energy bills, and the opportunity to earn revenue whilst providing system services

• Greater scope to install on-site renewable energy.

The scope savings at a site level vary by sector. ClimateWorks has estimated the volume of demand management capacity available across different sectors based on savings of 5-15% and 20-30%. 164

163 State of world modelling 4 is listed in the NEM report as high Variable Renewable Energy (VRE) (behind-the-meter solar, large scale solar and batteries) as opposed to DER. This difference is acknowledged by the authors in the adjusted table which has been formatted to fit within the context of this research.

164 RACE for 2030 B4 OA, 41.

Table 4.2 Summarised state of world model results (pg. 111 Table 4.7) from Valuing Load Flexibility in the NEM report prepared by NERA for ARENA 2022 162

162 NERA Economic Consulting, Valuing Load Flexibility in the NEM, February 2022, arena.gov.au/knowledge-bank/valuing-load-flexibility-in-thenem.

4.11. International experiences: Demand management

International reviews find market design and regulation have a heavy influence on the volume of demand response/management. 165 In a review of European nations, the Smart Energy Demand Coalition 166 identified four key criteria for evaluating demand management regulation –

• Access to markets for demand management: Is there equitable access to the different categories of markets for demand management?

• Service provider access to markets : Is there a level playing field for demand management providers (e.g. aggregators operating separately to electricity retailers; low barriers to entry)?

• Product specifications which enable the range of demand - side resources : Are there barriers to different types of demand-side resources in the product specifications (e.g. oversized minimum bids, extended duration of availability requirements)?

• Measurement and verification (M&V) regimes : There is a delicate balancing act between a measurement and verification regime that ensures that demand management is additional and not enacting requirements that create barriers to certain types of load management. For example, the baseline methodology, the communication requirements, and frequency of interval readings can exclude the aggregation of smaller loads.

4.12. What is the role of technology in facilitating and maximising consumerfocused DM?

Technology plays a crucial role in consumer-focused demand management. Demand management refers to influencing the demand for a product or service to optimise customer satisfaction while maximising profit. 167 In a consumer-focused approach, the focus is on meeting the needs and preferences of the customer while maintaining efficient operations.

Among the various ways that technology can enhance demand management efforts, one may refer to customer relationship management (CRM). CRM systems provide businesses with a centralised platform to manage customer interactions and gather data on behavioural variables. These systems enable companies to track customer preferences, purchase history, and other relevant information that models consumer behaviours. By analysing such data, businesses can customise their marketing strategies, offer targeted promotions, and identify upselling or cross-selling opportunities. 168 CRM requires intensive data collection, and technology can help. Technology enables data collection and systematic analysis of vast amounts of data related to consumer behaviour, preferences and purchasing patterns. Businesses can gain valuable insights into consumer-demand trends, seasonal variations, and customer segmentation through various tools and techniques, such as CRM systems, data analytics, and artificial intelligence. This data-driven approach helps companies to make informed decisions about pricing, promotions and product development. 169

165 Liu, Y. (2017) ‘Demand Response and Energy Efficiency in the Capacity Resource Procurement: Case studies of forward capacity markets in ISO New England, PJM and Great Britain’, Energy Policy, 100, 271-282.

166 Smart Energy Demand Coalition (2017) Explicit Demand Response in Europe: Mapping the Markets (2017, Brussels).

167 Mentzer, J. T., Moon, M. A., Estampe, D., & Margolis, G. (2007). Demand management. Handbook of global supply chain management, 65-85.

168 Anshari, Muhammad; Almunawar, Mohammad Nabil; Lim, Syamimi Ariff; Al-Mudimigh, Abdullah (2019). "Customer relationship management and big data enabled: Personalization & customisation of services". Applied Computing and Informatics. 15 (2): 94–101.

169 Sapsford, R., & Jupp, V. (Eds.). (1996). Data collection and analysis. Sage.

Since the rise of e-commerce and online platforms, businesses have transformed how they interact with consumers. Modern online marketplaces, social media platforms, and company websites can now directly communicate with customers in real time and get instant feedback. They can also offer personalised recommendations. These platforms expedite demand management by providing businesses with a direct network to promote products, gather customer insights, and engage in customer–centric marketing. Technology also empowers high-level demand forecasting models that help companies to estimate future demand based on historical data, market trends and external factors. Truthful demand forecasts allow companies to optimise their inventory levels, ensure they have the right products available at the right time, minimise stockouts, and avoid excess inventory.

Mobile applications and devices for the Internet of Things (IoT) provide businesses with additional touchpoints to engage with consumers. Apparatus for the IoT, such as sensors, actuators, gadgets, appliances or machines are programmed for specific applications and can transmit data over the internet or other networks. Companies can leverage these technologies to offer mobile shopping experiences, push notifications, location-based promotions, and even gather real-time data through connected devices. These technologies enhance convenience, accessibility, and the ability to capture consumer demand in real time. Technology empowers businesses to reach consumers through various digital marketing channels, such as search engine marketing, social media advertising, influencer marketing, and targeted display advertising. These channels offer precise targeting options, performance tracking, and the ability to measure and optimise real-time marketing campaigns. Businesses can effectively stimulate and manage consumer demand by reaching the right audience with compelling messages.

Technology facilitates and maximises consumer-focused demand management by providing businesses with valuable data insights, personalised experiences, direct communication channels, and sophisticated forecasting capabilities. Leveraging technology effectively allows companies to understand consumer preferences, align their offerings with market demand, and optimise their overall business performance. 170

With the above-mentioned technological advancements in energy markets, power utilities are now able to eradicate the critical challenges of maintaining power standards, real-time balances of supply and demand, and sufficient capacities. The challenges that the utility industry often faces in modern energy markets comprise the followings 171:

• Providing reliable energy to consumers in the growing demand economies

• Improving sectoral productivity

• Enhancing people’s prosperity

• Decarbonising the sector using cleaner energy sources

• Integrating the power grids

• Enhancing the network's reliability and resilience and

• Becoming increasingly dynamic with the penetration of intermittent centralised bulk and distributed renewable energy sources.

170 Koul, Bharti; Singh, Kanwardeep; Brar, Y.S.; (2021). “Chapter 4 - An introduction to smart grid and demand-side management with its integration with renewable energy”. Advances in Smart Grid Power System. Pg 73-101

171 esb-post2025-market-design.aemc.gov.au/integration-of-distributed-energy-resources-der-and-flexible-demand

In this regard, demand management has been perceived chiefly as a means of reshaping energy use that benefits the electric network. By switching consumption to cheaper times, selling back power to the grid when needed, or turning on solar panels and storage, consumers can avoid grid power altogether. Utility companies can improve resource management by using more detailed, customer-specific models based on more timely and detailed data. By transforming raw data into relevant information and analytics, these capabilities provide the control room with highly accurate and reliable information. As a result, with appropriate technology and security settings, digital advances can secure communication between home appliances (smart homes), business equipment, and systems.

The following benefits can be achieved using innovative technologies in demand management –

• Peak shavings may allow for deferring network upgrades to ensure that customers do not pay beyond what is known as natural entropy, which is needed for a sustainable energy system

• Improved service reliability by enabling demand to turn off non-essential loads in response to a network appeal and

• Demand management programs may reward customers who participate in them with payments for reducing demand. 172

Technological issues have been raised as being critical to the evolution of policy and business models. Policies and business models must evolve with the technologies to ensure that they are deployed most efficiently. Therefore, technology must address the following points in particular:

• Expand the availability of dynamic pricing to a broader array of consumers to enhance the value of demand response and

• Implement all new load-consuming technologies that can shift or limit load based on events and prices.

4.13. Which DM regulatory incentives maximise customer value, and how can we measure/evaluate the customer value effectiveness of DM?

To date, the primary purpose of existing DM regulatory incentives is not to maximise customer (i.e. end user) value in a direct energy price sense. Rather, it is to ensure that AEMO is able to control frequency and voltage requirements, for example, so that the power system can operate safely, securely, and reliably. This has implicit advantages for end-users, not least by avoiding blackouts. In a similar vein, the Smart Energy Demand Coalition usefully distinguishes between explicit and implicit demand response schemes. 173 An explicit demand response scheme may involve payments made to incentivise consumers to engage in demand response. By contrast, an implicit demand response may be one where price signals, such as varying tariffs that reflect the value of electricity, drive the desired change in demand. Both are required in order to fully harness different types of consumers with capacity to engage in demand management.

172 www.evoenergy.com.au/emerging-technology/demand-management

173 Smart Energy Demand Coalition (2017) Explicit Demand Response in Europe: Mapping the Markets (2017, Brussels).

Several other questions that raise DM issues are discussed in the other work packages. This includes further discussion on regulatory reform opportunities that currently exist to fully exploit the potential for DM to meet multiple desirable customer and business outcomes, including sharing the potential economic benefits of DM, as well as the relationship between DER and DM and how this is recognised in the existing regulatory framework of the national electricity market.

5. WORK PACKAGE 3: ANALYSIS OF DISTRIBUTION SYSTEM OPERATOR FUNCTIONS TO ENHANCE CUSTOMER OUTCOMES

Complementing the central independent system operator role with localised distribution system operator (DSO) roles may help to facilitate a reliable, affordable clean energy transition. Various parties have been proposed to take on aspects of a DSO role, including DNSPs, AEMO, and new independent entities. However, characterising this role as an independent system operator imposes a specific system architecture rather than asking the more fundamental question: What is the appropriate allocation of risk in a disaggregated supply chain? Key DSO functions beyond DER control/dispatch need to be considered and elaborated, including DER and DM planning, investment, procurement, ownership and operation. This work package explores the various definitions of the DSO role as the language associated with this role is still unclear and somewhat contested. The design of the DSO function and associated regulatory constructs need to be carefully considered. Regard should be had for the validity of ring fencing, both on the customer side (What can be owned and operated by a regulated entity?) and for the wholesale market side (Can DNSPs own and/or operate generation and storage assets that participate in the wholesale markets?).

This work package reviews the role and responsibilities of a DSO. It reviews the current state of discussion on DSO models and their implementation and impact on innovation and consumers. It further considers the role of accountability and KPIs a decision-maker should consider for future DSO models, as well as its potential functions in the Australian context, including for autonomous systems, in system planning, and in harnessing DER and DM.

5.1. An Introduction to DSO models and benefits/risks to consumers, competition and implementation

The functions and roles of a DSO are expanding rapidly in a modern electricity market. Traditionally, distribution system operation included mostly network planning as well as ensuring reliable operation of the distribution system by managing outages and maintenance. Now, the rise of DER requires a rethink of the role. Recent assessments, for example by Energy Networks Australia 174 and OFGEM 175 , identify a number of new functions associated with contemporary and future distribution network operation. These include long-term planning, including of DER and required new investment, gridoperational services using both DER and DN assets, data management and sharing, coordination with aggregators, retailers and transmission system operators, as well as potentially managing distribution services markets. A review of the different models of distribution operation is provided against this background.

The current model in the NEM is discussed in Part 3 of this report. The following section reviews models and examples from other jurisdictions and the discussion in Australia to date.

Different models for DSO are discussed in different contexts. These include ownership and organisational models, as well as questions of separating regulated from competitive services associated with network operation in the regulatory framework.

DSO organisational models: Ownership and unbundling

The entities responsible for distribution network operation differ widely in scale, ownership and unbundling models. These differences are often historically determined. A study comparing EU DSO models 176 found that DSO numbers in member states range from single DSOs through several big or medium-scale DSOs down to the German model with a large number (880 in 2011) of DSOs of all sizes. 177

The ownership models for DSO are mixed. Both private and public ownership models exist, with public DSOs either municipally owned, co-op-owned, or owned by often corporatised but public entities. 178 It should be noted that EU regulation expressly preserves the right for Citizen Energy Communities to operate distribution networks in their area of operation. 179

While in the US, many DSOs are vertically integrated with supply/retail functions 180, EU regulation requires at least the unbundling of DSOs that serve more than 100,000 customers. 181 Ownership unbundling is not required at this stage.

In the UK, there is ongoing discussion about the separation of the traditional passive network operation (DNO) from DSO functions. 182 Similar discussions have been part of the Open Energy Networks Project in Australia. The Australian Open Energy Networks envision a model with two new roles: the DSO, who will ‘plan and actively operate distribution assets to support the optimal use of DER for the benefits of all consumers’, and the distribution market operator (DMO), who ‘manages the distribution market and optimises the provision of services and energy from DER within operating envelopes provided by the DSO’. While the former role is envisioned to remain with the DNSP, the latter is suggested to be undertaken by AEMO. 183 Notably, this model has already been adopted in the WA Roadmap as set out in 6.7 below.

176 Nikoleta, Andreadou; Flammini, Marco, Vitiello, Silvia, ‘Business Models for Electricity Distribution in Europe: Evidence from the JRC DSO Observatory 2018’ (CIRED 2019 Proceedings comprise papers presented at the 25th International Conference and Exhibition on Electricity Distribution (CIRED 2019) held in Madrid, Spain, 3-6 June 2019).

177 Pereira, G. I., Pereira da Silva, P., & Soule, D. (2020). Assessment of electricity distribution business model and market design alternatives: Evidence for policy design. Energy & Environment, 31(1), 40–59.

178 Ibid. Lowder, Travis, and Kaifeng Xu. 2020. The Evolving U.S. Distribution System: Technologies, Architectures, and Regulations for Realizing a Transactive Energy Marketplace. Golden, CO: National Renewable Energy Laboratory. NREL/TP-7A40-74412; Lonergan, K & Sansavini, G, (2022) ‘Business structure of electricity distribution system operator and effect on solar photovoltaic uptake: An empirical case study for Switzerland’, Energy Policy, 160, 112683.

179 Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast), article 16.

180 Lowder, Travis, and Kaifeng Xu. 2020. The Evolving U.S. Distribution System: Technologies, Architectures, and Regulations for Realizing a Transactive Energy Marketplace. Golden, CO: National Renewable Energy Laboratory. NREL/TP-7A40-74412

181 Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast), article 35.

182 Ofgem, Position Paper on Distribution System Operation: Our Approach and Regulatory Priorities (2019) and NERA Economic Consulting, An Assessment of Alternative DSO Governance Models Prepared for Scottish and Southern Electricity Networks (23 March 2022).

183 Energy Networks Australia, Open Energy Networks Project: Position Paper (2020) 26-27.

DSO models: Innovation, sustainability and consumer impact

Evidence of the impact of different models of DSOs on innovation is scarce. Some authors have considered unbundling distribution from supply as potentially hindering smart grid innovation. 184 One study raises that, without changing incentive models based on return on capital, networks have little incentive to innovate. 185

On ownership models, American studies found that publicly owned utilities had better sustainability outcomes than their privately owned counterparts. 186 They were also perceived to better manage customer engagement. 187 European studies showed mixed outcomes. 188

The Open Energy Networks Project identified that the consumer voice will need to be considered in any future DSO models. The express elevation of citizen energy in the last energy directive signifies the identification of a lack of consideration of consumer interest in engagement and in following alternative models of electricity provision.

Implementation costs

Little analysis of the costs of changing between models has been undertaken to date. A Scottish study on the costs and benefits of separating DSO and DNO functions in the UK context considered costs outweighing benefits. 189 The Open Energy Networks Project considered 4 models of market frameworks in the distribution system (Table 5.1)

While the IDSO model was considered too costly, all three other models showed comparable costs and benefits. However, it was considered that the community voice, in particular, would need to be better integrated into any model selection for the future.

184 Eg Rønne, A., 2013. Smart grids and intelligent energy systems: a European perspective. In: M.M. Roggenkamp et al. eds., 2013. Energy networks and the law. Oxford: Oxford University Press, 141–160.

185 Pereira, Guillermo Ivan, et al. "Technology, business model, and market design adaptation toward smart electricity distribution: Insights for policy making." Energy policy 121 (2018): 426-440.

186 Eg, Traxler, Albert Anton, Daniela Schrack, and Dorothea Greiling. "Sustainability Reporting and management control–A systematic exploratory literature review." Journal of Cleaner Production 276 (2020): 122725.

187 Stephens, Jennie C., et al. "Framing of customer engagement opportunities and renewable energy integration by electric utility representatives." Utilities Policy 47 (2017): 69-74.

188 Lonergan, K & Sansavini, G, (2022) ‘Business structure of electricity distribution system operator and effect on solar photovoltaic uptake: An empirical case study for Switzerland’, Energy Policy, 160, 112683 and Pereira, Guillermo Ivan, et al. "Technology, business model, and market design adaptation toward smart electricity distribution: Insights for policy making." Energy policy 121 (2018): 426-440.

189 NERA Economic Consulting, An Assessment of Alternative DSO Governance Models Prepared for Scottish and Southern Electricity Networks (23 March 2022).

Table 5.1 Roles and responsibilities and defined in the OpEN distribution market frameworks

Conclusion

Further research on the respective costs and benefits for moving to a DSO model with or without separate DMO function is urgently required. Evidence from international studies shows that distribution system operation models differ greatly between and within states for a number of reasons, central among them being differences in geography and consumer base. Australia is in a similar situation, with vast differences between rural and urban consumer bases. Consideration of whether different models may be needed for different types of distribution systems should be included in future studies.

5.2. Accountability for a future DSO

Regulatory reforms will have to take account of, and be embedded into, the overlapping regulatory frameworks for the electricity sector at state and national levels. On the national level, the NEL and NER apply to any participants connected to the shared network. In addition, licensing requirements at the state-level ensure safety and security of the electricity sector participants. The respective regulators, the Australian Energy Regulator (AER) and state regulators such as Essential Services Commission Victoria and IPART in NSW, are the main accountability bodies.

A number of considerations will need to flow into assessing regulatory reforms. These include:

• What functions a DSO/DMO could undertake, and to what degree these functions would transcend the current scope of activities a distribution network service provider can undertake. The first part of this question will need to be assessed together with consumer advocates, who can provide insights into the needs of consumers and the shortcomings of the current system. It will also require technology experts, who can advise on the capabilities of potential operators. Depending on the answer, any reforms will then require assessment of the suitability of the current framework, in particular the unbundling requirements of the Australian regulatory frameworks, for innovative solutions to better manage DER/DM integration.

• The introduction of a DMO/DSO will impact on the roles and responsibilities of incumbent market participants; these may need to be redrawn.

• In addition, accountability mechanisms will need to be assessed, in particular which bodies are accountable, what are they accountable for, and to whom they are accountable.

Current and proposed reforms interfacing with this research topic include:

• The 2022 Integrated System Plan 190, in which AEMO identifies an expanded role for distribution networks in order to unlock DER. Under Section 7.5.2, the ISP states that:

“Customer and grid-connected DER is now a fundamental component of the electricity system, and emerging export constraints in some areas of the distribution network need to be managed accordingly. Detailed technical and engineering studies are required to estimate the prevalence of constraints and their impacts on customers, particularly at times of high and low demand. According to some, DNSPs are best placed to coordinate the assessments of distribution network constraints due to their local knowledge. The AER is currently developing a framework for assessing DER integration expenditure.

Adopting the same set of inputs, assumptions and scenarios can help align distribution, transmission, and supply-side investments. AEMO will continue to collaborate with DNSPs on the future capability of distribution networks to provide two-way flows and how that evolving capability might impact on DER forecasts.”

• The Energy Security Boards Post-2025 vision is working on the integration of distributed energy resources and flexible demand. 191 As part of this work, the ESB considers “evolved roles and responsibilities that will be introduced for traders (aggregators/retailers), distribution networks, and the system and market operator.”

• More specific pilots underway that may provide model solutions include AEMO’s Project Edge 192 and Ausgrid’s Project Edith. 193

5.3. KPIs for a future DSO

A question raised in the IRG was What KPIs should the DSO seek to maximise, including consumer, environmental, and financial outcomes with further integration of DER?

The answer to this question will partially depend on how we define the roles and responsibilities of a DSO. At the moment, regulatory frameworks are developed with reference to the national electricity objective, which in the literature 194 has been identified as a potential barrier to developing a more sustainable regulatory framework. In other words, KPIs are currently linked to the regulatory functions of a DSO, which in turn are determined by a regulatory framework that still does not explicitly value a sustainable energy system. In the current framework, this means that regulatory functions of network providers are linked to efficient and secure delivery of energy. In a transiting electricity system, we need to reconsider which outcomes a modern energy system is expected to deliver. For example, consumers with generation capability (prosumers) may value flexibility over security of supply. The consumer voice will be central for developing suitable KPI for distribution networks in a modern energy system.

More specifically, this theme will require a closer look at the current regulation determining DNSP income streams in particular tariffs and the regulatory investment test employed by AER for distribution network investment and whether these achieve outcomes required for a highly distributed and renewable energy system of the future.

A number of relevant current projects, reports and plans are underway in the area of the reforms which require careful monitoring and can inform the research. These include:

191 https://esb-post2025-market-design.aemc.gov.au/integration-of-distributed-energy-resources-der-and-flexible-demand

192 https://aemo.com.au/en/initiatives/major-programs/nem-distributed-energy-resources-der-program/der-demonstrations/project-edge

193 https://www.ausgrid.com.au/About-Us/News/Project-Edith

194 Cantley-Smith, R (2009), ‘A changing legal environment for the national electricity market' in Wayne Gumley and Trevor Daya Winterbottom (eds), Climate Change Law: Comparative, Contractual and Regulatory Considerations (Lawbook Co, 2009) 15; Kallies, A. (2016). A barrier for Australia’s climate commitments? Law, the electricity market and transitioning the stationary electricity sector. UNSW Law Journal, 39 , 154 –1582; Wright, g. (2011) ‘The National Electricity Market and the Environment: Are We Heading in the Right Direction?’ (2011) 4 National Environmental Law Review 43.

• The ESB Post-2025 DER Implementation Plan, which is developing a 3-year roadmap for flexible demand and better integration of DER

• The AEMC’s 2021 195 rule change of Determination on the Access, Pricing and Incentive Arrangements for DER and

• The AER ongoing network tariff reform. 196

Benchmarking for Opex and Capex has been looked at in the past by both the ACCC (2012) 197 and the Productivity Commission (2013) 198 and is employed in the AER capital expenditure assessments. 199

5.4. DSO and harnessing DM and DER

The IRG specifically raised the question of how to harness DM and DER through a DSO to minimise costs while sustaining urban grids and islanding rural grids. Before suggesting specific reforms, we need to assess what a DSO should be doing and how these activities can be incentivised and regulated. Any solutions will need to carefully consider –

• What the relation of a DSO is to the network and to retailers

• Whether there should/could be community participation

• How we ensure that the function of a DSO do not lead to consumer lock-in and potential exploitation of a monopoly position and

• Who would be best placed to be a DSO (ownership/business models).

This theme should also consider ring-fencing requirements in Australia, which currently require separation of any network activities from contestable services unless exemptions apply. Please note that this is also considered in RACE for 2030 Project N3 ‘Local DER Solutions’ (OA).

Relevant reforms include the Australian Energy Regulator (AER) updated Electricity Distribution Ringfencing Guideline, which now also addresses stand-alone power systems (SAPS). The AEMC introduced updated rules for stand-alone power systems. 200 Further, embedded network reviews on state 201 and NEM level networks 202 need consideration. Comparative research can further assist with answering this question. In particular the US, with its wide range of state models, provides examples of newer, more active roles for DSOs. For example, New York State’s REV initiative seeks to provide distribution network utilities with outcome-based incentives based on inter alia customer engagement, peak load reduction, affordability, and energy efficiency. 203 A range of projects currently underway seeks to redefine the role of a distribution utility. 204

195 https://www.aemc.gov.au/rule-changes/access-pricing-and-incentive-arrangements-distributed-energy-resources

196 https://www.aer.gov.au/networks-pipelines/network-tariff-reform

197 https://www.accc.gov.au/system/files/Working%20paper%20no.%206%20%20-%20Benchmarking%20energy%20networks.pdf

198 https://www.pc.gov.au/inquiries/completed/electricity/Report

199https://www.aer.gov.au/system/files/AER%20capex%20assessment%20outline%20for%20electricity%20distribution%20determinations.pdf

200 https://www.aemc.gov.au/news-centre/media-releases/new-rules-allow-distributors-roll-out-stand-alone-power-systems-nem

201 eg, Victoria https://engage.vic.gov.au/embedded-networks-review

202 https://www.aemc.gov.au/market-reviews-advice/updating-regulatory-frameworks-embedded-networks

203 See e.g.: MIT (2016) 172.

204 New York State, ‘Reforming the Energy Vision (REV)’ (New York State) <https://rev.ny.gov/> accessed 5 February 2020. Notably, these are not unbundled utilities, but they provide both distribution and supply services.

5.5. DSO and system planning

The DSO’s definition includes a planning function. This theme therefore also needs to consider the future of the system-planning process and how it can be designed to be agile in the face of rapidly changing technology and market conditions. This requires the assessment and proposal of changes to the current system-planning process. Network planning is currently driven by a process of annual reviews with a 5-year forward-planning period. Distribution network businesses must already develop and document a demand-side engagement strategy and have an obligation to engage with non-network providers and consider non-network options in accordance with this strategy (introduced by AEMC 2012). 205 In addition, networks have responsibilities to engage with connected networks and undertake joint planning activities.

At an overarching level, AEMO is generating integrated system plans (ISP) with a 20-year planning horizon. The most recent (2022) plan, published in June 2022, has a planning horizon to 2050 to reflect Australia’s 2050 net zero emissions target. The ISP is a whole-of-system plan and includes consumer-led DER investments, including consumer storage, generation and demand-side responses. While the plan assumes five-fold growth in distributed energy resources, it is short on detail on how the actual integration will work. Instead, it assumes an increasing level of coordination and refers to the ESB Post2025 DER Implementation Plan. Concrete ISP project commitments are at the level of transmission and considered not to be sensitive to changes in DER uptake or to distribution network constraints.

Regulatory reform will have to target both the current planning frameworks for distribution networks, as well as taking a whole-of-system perspective. Relevant reforms and projects in this space include the ESB Post-2025 DER Implementation Plan, with a range of reforms planned. The Plan has a focus on an expanded role of distribution networks but is still light on detail (other than enhanced consumer involvement). This project will have to consider whether these reforms may impact the ability to look at DSO/DMO solutions. Also of relevance are the AER Framework for Assessing Distributed Energy Resources Integration Expenditure 206 and the AEMC’s rule change on Access, Pricing and Incentive Arrangements for DER. 207

5.6. What is the role and function of innovative technologies such as autonomous energy systems in distribution systems, and who is responsible for such systems?

By introducing innovative technologies such as autonomous energy systems (AES), demand management has been transformed from a manual to a more precise, automated and streamlined process, owing to the availability of detailed, near-real-time data. Highly electrified, heterogeneous energy systems with AES can be operated intelligently and robustly. Using this technology, distributed resources will be managed effectively and data from these systems will be able to flow effectively.

205 https://www.aemc.gov.au/rule-changes/distribution-network-planning-and-expansion-framew

206 https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/assessing-distributed-energy-resources-integrationexpenditure

207 https://www.aemc.gov.au/rule-changes/access-pricing-and-incentive-arrangements-distributed-energy-resources

Besides improving the operational aspects of the distributed energy system, intelligent distributed systems may also increase forecasting accuracy, which may enhance the level of customer convenience to a significant extent. Existing grid reliability must be improved to integrate intermittent renewable energy sources. This process may defer large capital expenditures such as transmission and distribution infrastructure. Power utilities can leverage demand response as a strategic asset by utilising this enhanced forecasting and dispatching capability.

According to the National Renewable Energy Laboratory (NREL 2022), innovative technologies will be used to enhance distributed energy systems as follows:

• Efficient and cost - ef fective approaches to streamline the use of variable renewable generation and innovative technologies

• Real - time operations to balance load/demand and generation/supply every second and make the best use of asynchronous data and control to accommodate changing conditions and delays in communications

• Robust tolerance to disturbances, faults, outages, and failures in both cyber and physical networks

• Interoperability with the integration of decisions, devices, platforms, and data with the aid of standard-based protocols and

• Scalability to control hundreds of millions of energy resources across the grid, renewables, storage, mobility, buildings, inverters, and microcontrollers from communities to neighbourhoods to regions. 208

Developing a robust model as an instrumental tool is vital to make a proper decision that benefits all distributed system participants. Before applying optimal solutions over a set of well-specified goals, such a robust model must consider the interrelationships between the cellular building blocks within the system. As a result, management, optimisation and forecasting methods would be integral components of cooperative and competitive operations. Properly curating and applying system operation information will require advanced data analytics. Complex system theory optimises system performance by simulating various possible outcomes. These models will use big data analytics information to stipulate predictions and simulations. To apply regime-switching approaches, the model uses some control and optimisation procedures or algorithmic computational responsiveness . 209

With regards to who should be responsible for autonomous energy systems, we noticed that there is no focused literature. However, this falls in the institutional economics of the energy system. In the institutional economics of energy systems, such a role is envisaged under an independent regulatory authority. An independent regulatory authority would be responsible for the cohesive and (socially) efficient performance of the system. The responsibility of such a regulatory authority will, however, be limited to overseeing the inter-dependencies of all free choices made by decentralised individual decision-makers (i.e. all stakeholders). In other words, the regulatory authority will ensure that every individual decision-maker will be accountable for their external costs and benefits. This will make certain that the non-market component of the system will also send adequate signals and incentives to producer, prosumers, or consumers.

208 National Renewable Energy Laboratory. 2017. Basic Research Needs for Autonomous Energy Grids Summary Report of the Workshop on Autonomous Energy Grids: September 13–14, 2017 (Technical Report NREL/TP-5D00-70428).

209 Ibid

Before suggesting specific reforms, it is necessary to properly assess what a DSO should be doing and how these activities can be incentivised and regulated. Any solutions will need to carefully consider

• What the relation of a DSO is to the network and to retailers

• Whether there should/could be community participation

• How we ensure that the function of a DSO does not lead to consumer lock-in and potential exploitation of a monopoly position and

• Who would be best placed to be a DSO (ownership/business models).

This theme should also consider ring-fencing requirements in Australia. These currently require separation of network activities from contestable services, unless exemptions apply. Please note that this is also considered in RACE for 2030 Project N3 ‘Local DER Solutions’ (OA). The bigger current and proposed reforms mentioned in earlier particularly the ESB work programs will also have an impact on this theme. These include –

• The AEMC’s 2021 210 rule change of Determination on the Access, Pricing and Incentive Arrangements for DER

• The AER ongoing network tariff reform 211

• The AER–updated Electricity Distribution Ring-fencing Guideline, which now also addresses standalone power systems (SAPS)

• The AEMC introduced updated Rules for Stand-Alone Power Systems 212 and

• Embedded network reviews on state 213 and NEM-level. 214

Benchmarking for Opex and Capex has been looked at in the past by both the ACCC (2012) 215 and the Productivity Commission (2013) 216 and is employed in the AER capital expenditure assessments. 217

210 https://www.aemc.gov.au/rule-changes/access-pricing-and-incentive-arrangements-distributed-energy-resources

211 https://www.aer.gov.au/networks-pipelines/network-tariff-reform

212 https://www.aemc.gov.au/news-centre/media-releases/new-rules-allow-distributors-roll-out-stand-alone-power-systems-nem

213 eg, Victoria https://engage.vic.gov.au/embedded-networks-review

214 https://www.aemc.gov.au/market-reviews-advice/updating-regulatory-frameworks-embedded-networks

215 https://www.accc.gov.au/system/files/Working%20paper%20no.%206%20%20-%20Benchmarking%20energy%20networks.pdf

216 https://www.pc.gov.au/inquiries/completed/electricity/Report

217 tps://www.aer.gov.au/system/files/AER%20capex%20assessment%20outline%20for%20electricity%20distribution%20determinations.pdf

6. WORK PACKAGE 4: OVER THE HORIZON

This fourth work package explores what energy transitions are as yet over the horizon. Ensuring that the rapid evolution of DER and two-sided markets meet energy customers’ demand is critical to the success in transitioning to a secure, affordable, clean energy future. Customer-centred reform opportunities for regulation of networks services entails a large number of considerations, including:

• the nature and scope of the existing policy, governance and legal framework regulating the demandside of the NEM

• community expectations and engagement pathways

• current trust levels

• best practice participatory models

• evidence-based public policy-making approaches

• different customer types, consumer interactions and expectations

• the fair distribution of benefits

• factors affecting interest and acceptance of the technology

• consideration of the interaction of DM, DER and DSO, and lessons from commercial and industry experiences, as well as

• regulatory, commercial, and technical factors affecting customer-focused DM and DER uptake/access decisions of consumers.

Questions arising in this context include how existing regulations concerning the planning and provision of networks services can be reformed to ensure full integration of consumer-owned resources within the energy system, how can customers (consumers and communities) be placed at the centre of the DER-driven energy transformation currently underway in the NEM, and how do/can different types of consumers participate in, and benefit from, DER, DM and DSO. Put another way, this work package considers how the existing energy transition paradigm can be reimagined in terms of network management and regulatory frameworks to ensure future beneficial, customer-focused outcomes. This requires a review of policy settings, regulatory frameworks, applicable law, control strategies, consumer-facing retail business models and network service models, and asset and ownership diversity across the entire supply chain.

6.1. Regulatory state of flux

Key dimensions of the rising pace of changes across the regulatory framework have been set out earlier in this report. Further to those dimensions, meeting outcomes of ESB stakeholder working groups and market institutions’ recent and current reviews show that many aspects of the energy market transition are yet to be determined. This state of flux is evidenced in the AEMC’s review into to standards and compliance 218, the AER’s review into dynamic operating envelopes, and the ongoing tension between maintaining DOEs or extending the distribution physical network. As noted at a ESB Stakeholder working group’s meeting 219, there are considerable social licence barriers that are yet to be dealt with. This dynamic state of regulatory change presents as a significant barrier to future projects and warrants

218 AEMC Standards Governance Review, current, exp release late Sept 2022. See also ESB, CER Stakeholder Working Group Meeting Notes Friday 29th July (1:00pm-3:00 pm AEDT) https://www.datocms-assets.com/32572/1660280442-20220729-cer-swg-session-6-meeting-notes.pdf

219 Ibid.

careful monitoring and evaluation, as well as ongoing, collaborative dialogue with all stakeholders–government, industry, and consumers.

6.2. Jurisdictional differences in DER approaches

It is not at all clear that the current network regulatory construct that applies in the NEM is fit-forpurpose under the DER energy transition. The regulatory framework governing Western Australia's SWIS shares many similarities with the NEM but is also subject to extensive developments being driven by the WA Government. As discussed below, this includes the WA Roadmap, which was introduced over two years ago in 2020

Australia followed the UK in its building 220block regulation design and has kept this essentially unchanged since the NEM's beginnings in 1998. In contrast, the UK revised its original frameworks in 2010 into a more dynamic and innovation-centric framework known as RIIO (Revenue using Incentives to deliver Innovation and Outputs). This framework explicitly incorporated innovation and changed regulatory determination periods. In addition, the UK has moved to Totex regulation rather than focusing on Capex and Opex separately. To date, this distinction between capital and operational expenditure has incentivised regulated entities to favour capital expenditure (i.e. building assets) over operational expenditure (i.e. entering network support agreements).

6.3. Long-term objectives

A key question concerns whether a regulatory framework that focuses on a narrow view of efficiency in terms of long-term costs per unit of energy delivered matches the consumer view of the services provided. Evidence suggests that consumers see the supply of energy much more broadly. In addition to reliability and cost/kWh or total energy bills, this encompasses attributes such as environmental impacts, independence, and contribution to the community. Aspects of the latter include a recognition of the essential nature of electricity services and the importance of ensuring affordable access for vulnerable customers.

Australia is well overdue for consideration of reforms, starting at first principles. This should include consideration of the various efforts in the reform space around the world and in Australia, such as RIIO and the Energy Security Board's work. Western Australia's reform work may also show possible ways forward as it is applying a different model and a more agile process. The opportunity to learn from the WEM/SWIS experience provides an exciting new context for our policy and regulatory reform research program. Another source of insight should be the New York REV reforms, which provide a leading international context. A very important source of input into the literature review and industry scan is the work going on in the ARENA Distributed Energy Integration Program (DEIP), and in particular its Access and Pricing Reform Package. 221 Finally, opportunities for lower cost to manage regulatory paradigms could also be explored as the overhead of managing the legal and modelling costs of constant regulatory processes may be costing consumers more than necessary.

220 Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 7, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

221 ARENA, https://arena.gov.au/knowledge-bank/deip-access-and-pricing-reform-package-outcomes/.

6.4. System planning process for future markets

Currently, states are focusing considerable attention on the development of renewable energy zones, a project whereby state governments work together with the AEMO to designate zones to facilitate the development of renewable energy as well as targeted investment in grid infrastructure. The REZs seek to facilitate more timely connection of new renewable energy projects, including investment in network infrastructure. The REZ process has been associated with several developments. 222 For example, there is a notable re-engagement of the state as an active participant in electricity markets. This is occurring through funding provision 223, or, as is the case in Victoria, through the reinvigoration of the State Electricity Commission. 224 The REZ process also supports the process of transitioning towards more distributed and regionalised electricity generation. It signals a willingness of state governments to divert from the national framework and invest directly in their own energy futures. These divestment processes should be followed closely, as they will have flow-on impact for the distribution and supplyend of the electricity system, which is the main focus of this work.

6.5. DNSP, tariff-design and the consumer gap

One of the questions asked by this opportunity assessment is how to support the system planning process to be agile in the face of rapidly changing technology and market conditions.

Distribution businesses are responsible for maintaining distribution network safety and reliability, along with planning and designing network extensions and upgrades to meet our customers’ current and future electricity needs under the current pricing proposals. 225 Distributors provide the AER with their Capex and Opex plans and forecast based on how they see the future over the next 5 years. They then provide their proposed costs to the AER for its assessment. Invariably, the AER’s final decision decreases the distributor’s costs and provides the distributors their allowed revenue over the 5 years with a price path (cpi-x). Once approved by the AER, the distributors recover their allowed revenue via their legacy-controlled and ancillary tariffs under a revenue price cap. 226

Network use-of-system charges (NUoS) are distribution use-of-system (DUoS) and transmission use-ofsystem (TUoS) charges; and determined by the AER under separate pricing proposals carried out every 5 years. Transmission cost drivers are location based and different to distribution cost drivers. Under the current arrangements, distributors design cost-reflective tariffs on behalf of transmission companies. Future regulatory frameworks should address this misalignment. In some instances, TUoS prices have increased significantly, but it is the distributor who faces the complaints from customers.

222 See e.g., Victorian Renewable Energy Zones Development Plan: Directions Paper (February 2021) https://www.energy.vic.gov.au/__data/assets/pdf_file/0028/580618/Victorian-Renewable-energy-zones-development-plan-directions-paper.pdf; DELWP (Victorian Government), Renewable energy zones: Building Victoria’s next-generation energy grid, https://www.energy.vic.gov.au/renewable-energy/renewable-energy-zones.

223 For example through tendering of long-term service agreements on NSW, see https://www.energyco.nsw.gov.au/renewable-energyzones/whats-involved-renewable-energy-zone

224 See State Government of Victoria. State Electricity Commission, https://www.vic.gov.au/state-electricity-commission-victoria

225 Australian Energy Regulator. Pricing Proposals and Tariffs, https://www.aer.gov.au/networks-pipelines/determinations-accessarrangements/pricing-proposals-tariffs.

226 See, eg, AEMC, Network Regulation, https://www.aemc.gov.au/energy-system/electricity/network-regulation.

NUoS charges comprise about 40% of the consumer retail bill, and the remaining charges relate to wholesale generation, metering, environmental and retail margins. Small to medium business customers and household customers do not see these charges on their retail bills, hence, network pricing and generation signals do not get through to these customers. However, network charges but not generation charges are shown on large customers’ bills, but their tariff structures vary with energy, demand, and capacity charges.

In summary, consumer bills do not clearly reflect network tariffs. This is not only an issue of retailers appropriately depicting and communicating network tariffs to consumers. The large number of different network tariffs impacts the ability of retailers to appropriately reflect these to the consumer and for consumers to adapt their behaviour in a way that benefits networks.

Distributors manage their networks to meet peak demand kW, not kWh. A typical load duration curve shows peak demand occurring only a few hours in the year and usually on a hot day. However, retail tariff structures are based on kWh for residential and small business customers. In other words, consumers have an incentive to reduce overall usage rather than peak demand.

In addition, tariffs charge on usage, but networks are incentivised to build for peak demand. This, in turn, drives a focus on network augmentation, with the resulting higher network costs being borne by all consumers. Many DNSPs are now trialling cost-reflective tariffs with the aim to avoid or reduce the need for network investment. Cost-reflective tariff structures incentivise customers to invest in energy solutions and behave in ways that minimise network demand peaks or solar export peaks. Exportlimiting devices will give distributors more control over reverse flow on their network. This is currently in place for large customers.

Cost-reflective tariffs, such as ToU for example, seek to incentivise customers to charge their EVs outside peak demand times and instead during the day to soak up excess solar energy in the system, or overnight. These tariffs can also encourage uptake of new technologies such as automated smart night charging. In Victoria, consumers applying for an EV connection point are already automatically put on a ToU tariff. However, elasticity of demand for household consumers is limited, and evidence of consumers changing behaviour in response to tariffs remains unclear. 227 At the same time, challenges for distribution network providers are mounting, rapid, and often localised changes to demand due to consumer investment into solar PV, batteries and EVs, with limited visibility for distribution businesses on when and where these investments occur.

6.6. Planning for a high DER future: Challenges and opportunities

As discussed in the first work package in this report, key benefits of DER include lower electricity bills for those who can install or access DER and decarbonising the energy system. As new technologies emerge, DER capabilities improve, costs fall, and benefits to consumers rise. Further opportunities enabled by DER include services that help ensure the security and reliability of the power system, and

227 Patricia Lavieri and Carmen Bas Domenech, Milestone 3 - Literature Review: Electric Vehicle Uptake and Charging: A Consumer-focused Review – V02, prepared for Energy Networks Australia (ENA) The Australian Power Institute (API) Centre for New Energy Technologies (C4NET), Large-Scale Network and System Integration of Electric Vehicles: A TechnoEconomic Perspective.

228

innovative business models that offer new value for customers. These new opportunities “complement and amplify the benefits of customer investments.”

At the same time, DER presents a range of challenges to the existing power system and market participants, with potentially adverse impacts on consumers in the form of higher costs and unreliable, insecure supply. At the distribution network level, these challenges are first and foremost technical.

Technical challenges

In the WA context, technology integration is defined as the ‘technical capabilities of DER itself, as well as the network and power system operators’. 229 In this sense, technology integration ‘relates to the type and performance of devices, effects on the power system, network infrastructure and management, and system operations’. 230 Like the regulatory framework, existing networks were established at a time when current substantial levels of generation by end-users through DER such as rooftop solar PV was not contemplated. As the amount of generation through DER increases, the physical capacity of networks is being stretched beyond the physical limits of existing infrastructure, thereby compromising stability and “eroding the security and reliability of the electricity system”. 231 As noted in the WA DER Roadmap, despite the constant improvements in DER and its enabling technology, “the existing market framework does not adequately facilitate the required visibility, performance standards, and management capabilities for DER to become active in the electricity system”. 232

The WA DER Roadmap, discussed below, identifies a range of barriers to integration of DER technology. A descriptive list of these barriers is set out in the Table 6.1 table below.

Tariff structures

Flat or fixed-rate tariff structures can be problematic. In circumstances where end-users are supplying large amounts of generation into the distribution network, flat tariff structures fail to incentivise the requisite change in consumers’ consumption patterns in ways that help keep supply costs at a minimum and ensure the system is stable and secure. 233 Burden and benefit sharing inequities between end-users who can afford to install DER and those who are unable to do so can also be exacerbated by flat tariff structures, with the latter effectively cross-subsidising the former through lower electricity bills. As observed in the WA DER Roadmap discussed below, flat electricity tariff structures are incompatible with a high DER energy system. 234

228 Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 6, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

229 ibid 40,

230 Ibid.

231 ibid 6,

232 Ibid, 45.

233 Ibid

234 Ibid

Facilitating DER participation

Ensuring that customers can engage in DER participation is both a challenge and an opportunity. In terms of opportunity, DER provides those customers who are able to provide services that support the power system and/or network and access markets that provide value. In WA, this is said to include potential participation in the WEM (including energy, ESS and capacity) as well as aggregation and orchestration of multiple DER to provide distribution network support. 236 Even so, the WA Roadmap

235 This Table is from the WA DER Roadmap See Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 46, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

236 Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 40, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

Table

Examples of barriers to DER technology integration

makes the point that, while customer DER participation will see more active participants in the energy chain, it is still assumed that in most cases, aggregators will take the primary role in delivering these outcomes (e.g. “Customers will have simple set-and-forget arrangements with their aggregator who in turn orchestrates the DER and monetises the services”). 237

Regulatory responses and challenges

To date, the proposed regulatory responses to physical network constraints resulting from the rise in DER include –

• Imposing export restrictions/prohibitions on behind-the-meter DER 238

• Limiting the the size and number of rooftop solar PV systems end-users can install on the network 239 and

• Investing in costly network infrastructure expansion. None of these are necessarily good outcomes for consumers. 240 The approaches being taken by WA and Victoria are explored further subsequently.

6.7. Planning for a high DER future: The WA DER Roadmap

WA has been proactive in responding to the accelerated uptake of DER and related technology advancements with the establishment of a focused regulatory framework to support the integration of DER into the state’s power system. In 2019, as part of the state’s aim to harness the potential for cleaner, more affordable energy and be a leader in sustainable energy, the energy transformation taskforce was established to implement the WA Government’s Energy Transformation Strategy. In 2020, a central component of the Strategy WA’s Distributed Energy Resource Roadmap (WA DER Roadmap) was formally released. The WA DER Roadmap was developed as a key enabler of WA’s transition to a decentralised, democratised, and highly data driven power system. 241

Potential DER services to extend across the entire power system

An important aspect of WA’s DER Roadmap is that it recognises the potential valuable services offered by DER across the power system. As shown in the examples set out in the Table 6.2 below, identifying and understanding the range of services DER can provide can ‘unlock the potential value of DER across the power system, facilitating higher levels of DER penetration and encouraging new business models to emerge’. 242

ibid 46, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

238 AEMC, Access, pricing and incentive arrangements for distributed energy resources, Rule determination, 12 August 2021.

239 Individual limits are set by the DNSP.

240 Energy Transformation Taskforce, DER Roadmap (December 2019) (WA Government, released April 2020) 7, https://www.wa.gov.au/system/files/2020-04/DER_Roadmap.pdf

241 ibid. See also AEMO, Integrating Utility-scale Renewables and Distributed Energy Resources in the SWIS (March 2019) https://www.aemo.com.au/-/media/Files/Electricity/WEM/Security_and_Reliability/2019/Integrating-Utility-scale-Renewables-andDER-in-theSWIS.pdf

242 Ibid.

A whole-of-power-system approach

Discussion of DER services in the WA Roadmap demonstrates a whole-of-power-system approach, an understanding that transcends the propensity in the NEM regulatory framework to ‘silo’ sections of the electricity system and participants into distinct, separate markets. For example, in addition to identifying potential DER benefits and services for customers and networks, the roadmap also recognises the inherent connections with the wholesale power system, generator and retailers that warrant considering in the face of the DER-led changing paradigm. This is shown in Figure 6.1 below.

243 Source: DER Roadmap, above n 241, 19.

Express recognition of consumers’ energy resources

Consumers appear to be at the heart of the WA DER Roadmap. Consumer engagement in DER is understood as scaling from passive through to active. Consumers can engage with, and benefit from, DER. WA energy consumers are also understood as having a variety of roles in the new DER paradigm. For instance, consumers may engage in consumption of behind-the-meter generation, with any excess exported to the market stored for later use (by own battery) or exported to a community battery (where such exist). Under the WA DER Roadmap, consumers’ current ability to provide passive network support (e.g. inverter settings automatically operate to support network as required) can become more active forms of engagement, usually through an aggregator (e.g. to provide and receive compensation for network services, participate in the WEM, participate in a new distribution system market via market operator, or engage in transactive energy markets with other end-users). 244

DMO and DSO in WA’s DER Roadmap

WA’s DER Roadmap is predicated on the high DER future. In this future energy market –

• A DSO is seen as ‘a natural evolution of Western Power’s role as network service provider’ and

• A DMO is viewed as ‘a natural evolution of AEMO’s role as market operator’. 245

The WA Roadmap explains the current and future role of a DSO and DMO in the following terms.

“Distribution system operator (DSO)

A Distribution System Operator, or DSO, with visibility of power flows and DER on the network, will be required to manage the network within technical limits, identify when network issues emerge,

244 See Energy Transformation Taskforce, DER Roadmap: Information Sheet (December 2019) https://www.wa.gov.au/system/files/2020-04/DERinfosheet.pdf

245 See WA DER Roadmap, above n 241, 44-45.

Figure 6.1 DER potential benefits and services

and act to manage these issues. To do this, the DSO will need to see the flow of power across the distribution network in real time.

Where an issue on the network emerges, the DSO may communicate with DER aggregators in real time and request assistance to mitigate. In such cases, DER may provide a service to the network business and, accordingly, consumers via their aggregators would expect to be compensated for the network services they provide.

There is also the requirement to ensure the DSO interacts with the broader system (i.e. at a transmission network level) to avoid any action on the distribution network compromising system security. Where a distribution network issue has emerged and a DER aggregator has been instructed to alleviate the issue, these instructions must be communicated with AEMO as the whole of system operator. This ensures that the power system at all levels remains secure.” 246

“Distribution market operator (DMO)

In the SWIS, AEMO as the market operator operates and settles the wholesale energy market and its various components, including energy, ESS and capacity. Where DER are participating in the market to provide these services, AEMO would be dispatching DER in line with the registration requirements of the market, along with large-scale registered facilities. This ensures the security and reliability of the whole electricity system and enables co-optimised dispatch of distributionlevel DER.

As the number of installations that can provide network services become more widespread, there may be the need to create a market for the provision of network services, as well as system services. Therefore, as the role of DER evolves in the energy supply chain, the DMO would –

• Administer platforms to enable access for aggregators to market trading for energy, capacity and ESS (such as voltage and frequency control)

• Operate and manage the platform to ensure that participants meet registration requirements and provide information transparency, dispatch reconciliation and market settlement and

• Interface with the DSO to ensure distribution network issues are resolved in a coordinated manner. Importantly, a market operator is independent of any market participant, network or resource owners (suppliers) so that

- The market is operated in a manner that is fair and impartial

- DER (and other resources) can be utilised in the most efficient and least-cost manner and

- All trading (including any third-party activities and customer trading) at the distributionlevel is aligned with the market and power system security and reliability objectives.” 247

Regulatory barriers and gaps

The WA Roadmap reiterates the comments made earlier in this report that existing regulatory frameworks are no longer fit-for-purpose. Existing regulatory and policy frameworks in Western Australia have been developed to meet the requirements of the traditional electricity supply model and have not accounted for the capabilities and consequences of DER. As a result, they present barriers to achieving DER integration in the SWIS.

An overview of the range of barriers and gaps in WA’s existing regulatory frameworks that have been identified in its DER Roadmap are set out in the Table 6.3 below.

248 Energy Transformation Taskforce, WA DER Roadmap, Appendix A: Regulatory Settings Summary (December 2019) https://www.wa.gov.au/government/distributed-energy-resources-roadmap

Table 6.3. Barriers in DER regulatory settings: WA example 248

6.8. Victoria’s approach to harnessing DER

Like its WA counterpart, the Victorian Government has recognised the escalation in DER taking place throughout Victoria and developed suitable responses. In 2022, the Government released its vision for a high DER future: Harnessing Victoria's Distributed Energy Resources 249 It states that –

“Integrating DER into our electricity grid enables Victorians to harness the full benefits of solar photovoltaic (PV), batteries and EV growth. The more integrated distributed energy resources we have, the lower our emissions and electricity prices, and the greater our energy security and consumer market participation.”

250

The Victorian Government recognises the challenges of integrating new DER technologies to the old electricity system: a system with infrastructure, markets and regulation designed for a few coal generators, absent small-scale renewables and consumer market participation 251 The Victorian DER approach is based on several principles and objectives. The objectives of the Victorian DER Roadmap are described in terms of guiding the government’s investment to prepare Victoria for a DER dominant future, namely:

• Helping all householders access the benefits of DER

• Driving innovations through place-based initiatives

• Future proofing consumer protections for our transforming energy system

• Supporting business and jobs to harness the opportunities of DER

• Transforming our public and private buildings and

• Preparing our grid for DER integration and consumer access to markets. 252

The Government’s actions and responses in this space will also be guided by the principles set out in Figure 6.4.

DER uptake in Victoria

Many Victorians use distributed energy resources to generate, store, manage and sell their energy. This includes solar panels, home batteries, electric vehicles and controllable air conditioners.

The use of distributed energy resources is increasing. It is expected that –

• by 2025, solar panels on homes and businesses will deliver up to 60% of our energy demand at times

• within the next decade, the energy in small-scale batteries will increase 8-fold

• by the mid-2030s, electric vehicle use will increase by more than 1600%.

Victorian Government, https://www.energy.vic.gov.au/renewable-energy/distributed-energy-resources

249 Victoria Department of Environment, Land, Water and Planning, Harnessing Victoria's Distributed Energy Resources (2022) https://www.energy.vic.gov.au/renewable-energy/distributed-energy-resources

250 Ibid 9.

251 Ibid

252 Ibid 10.

The Victorian DER approach also states that it places consumers at the centre of its energy transition. This includes consultations with consumers and stakeholders about ensuring that consumer protections feature in the high DER future. This is discussed further below

6.9. Customer protection and engagement in a high DER future

Both the WA and Victorian approaches to DER integration emphasise the importance of end-use protections.

The discussion and response to date is most advanced in WA. The WA Roadmap recognises that the obligation to protect consumers encompasses “frameworks that provide customers with safe, reliable and fairly priced electricity, ensure their privacy and data are protected, and make available clear and comprehensive information to assist customer decisions. It includes customer protection obligations on third parties with innovative business models, requirements of parties holding customer data, and customer engagement and education to keep customers informed”. 254

To meet such aims, it is suggested that the WA customer protection framework must be able to adapt to the continuing transformation of the energy system and ensure that existing protections are not eroded in a high DER future. Key challenges and opportunities identified in this space include the following: 255

• Access to information : Limitations to information availability and customer education may prevent customers from taking up options to manage their energy use and reduce costs.

253 253 Victoria Department of Environment, Land, Water and Planning, Harnessing Victoria's Distributed Energy Resources (2022) 9, https://www.energy.vic.gov.au/renewable-energy/distributed-energy-resources

254 Ibid, 40.

255 Ibid, 49.

Figure 6.4 Victorian DER Roadmap guiding principles 253

• Regulatory gaps : The growth of VPPs, embedded networks and microgrids, while providing new opportunities, is outpacing the regulatory frameworks that are in place to ensure customers have equivalent protections, regardless of their energy service provider.

• New licen s ing/regulation regime for new business models : The continued development of DER technology is likely to lead to an emergence of new business models providing energy services to customers. It is essential that appropriate customer protections are retained, and that licensing or other regulatory arrangements applying to new business models ensure that market fees, hardship schemes and exemptions are appropriately applied. This includes where customers may be part of embedded networks, VPPs or microgrids.

Another important consideration is data ownership. Customer data access, sharing and ownership arrangements require further consideration to ensure appropriate regulatory protections for customer rights and data are in place. Likewise, the current electricity supply regulatory and licensing schemes in WA warrant further attention to ensure sufficient protections to customers are in place as new business models emerge.

Both the WA and the Victorian DER Roadmaps recognise the importance of preventing end-user inequities in a high DER future. For example, the WA DER Roadmap provides that the full capabilities of DER can provide benefits and value to all customers, which must flow to all customers, both with and without DER. 256

In Victoria, the government has recognised that different consumers renters, community housing tenants, homeowners and rental providers should also be supported in DER participation. Government subsidies are being provided to facilitate household generation, storage, management and selling of energy, for example, providing financial support that places households at the centre of the energy transition by helping them to access the latest technology in solar, electric vehicles and temperature control. 257

The Victorian Government is reviewing feedback to its consultation on DER and consumer protections. As of December 2022, the government’s review process has only just commenced. Further projects in this theme and other related RACE for 2030 themes will require the outcomes of this process to be reviewed and analysed to identify regulatory barriers and opportunities that result.

257 See further discussion in Victorian Government, Protections for consumers of Distributed Energy Resources Consultation paper (2022)

ANNEX 1: RESEARCH FRAMING QUESTIONS

Research framing questions: Contributing to final report and research roadmap

The framing questions for this report are founded on those articulated in the original consumer-focused work packages set out at the start of this opportunity assessment, which includes foundation issues concerning DER and regulatory challenges. A brief overview of each is set out in Tables 7.1, 7.2, 7.3 and 7.4 below.

A further set of questions were identified as being important considerations within the context of this OA during the first IRG. These are set out subsequently in Table 8.1 below. These questions have been addressed in an integrated manner in this report.

All questions have been further refined throughout the ongoing research into current regulatory changes unfolding at national and sub-national levels. These informed both the desk top literature reviews and discussions in meetings (small group consultations and IRG workshops). These various forms of engagement have informed this final report and the future research opportunities laid down in the roadmap.

Research framing questions: Tables

The following tables set out the research framing questions for this project. These have been synthesised into the list of questions identified and addressed in the body of the draft (interim) and final reports. Tables 7.1-7.4 contain research questions (RQ) that have been extracted from the OA project plan; Table 8.1 subsequently sets out the linkages between the project’s initial research questions and those which resulted from the IRG meeting feedback.

RQs Distributed energy resources (DER)

WP1 - RQ1

WP1 - RQ2

How should network services evolve to support, integrate, and make use of DER?

Who should be responsible for planning and managing the relationship between the distribution network and DER, e.g. should a new entity be created (e.g. a DSO) or existing roles modified to fulfil these new responsibilities?

WP1 - RQ3

WP1 - RQ4

How do we ensure that customers investing in DER have the correct information, incentives, and support to guide the efficient adoption and use of DER?

What is the role of the network owners and operators in procuring DER and DM-based support services, e.g. dispatch/orchestration functions (controlling when DER should be turned on/off or ramped up/down?), planning and operating a distribution network with high levels of DER for the benefit of end-users?

WP1 - RQ5

What are the relationships and risk allocation approaches between distribution networks and those entities with direct control of DERs (such as customers or their agents) to contribute to a secure, stable, reliable and affordable electricity system for all?

Table 7.1 Work Package 1: Distributed energy resources

RQs

WP2 - RQ1

WP2 - RQ2

WP2 - RQ3

WP2 - RQ4

WP2 - RQ5

Maximising customer value from existing demand management regulatory incentives

What is the fundamental role of DM and who is responsible for this? 1, 2, 5, 6

What is the current scale of the DM market and cost of DM in Australia and overseas?

What is Australian industry current practice and best practice for DM?

What is the relationship between DER and DM and how is this recognised in the existing regulatory framework of the NEM? 1, 5, 6

What are the plausible potential benefits and costs of DM for customers in terms of bill reductions and carbon emission abatement?

with

WP2 - RQ6

What DM regulatory incentives maximise customer value, and how can we measure/evaluate the customer value effectiveness of DM?

WP2 - RQ7

WP2 - RQ8

What is the role of technology in facilitating and maximising consumer-focused DM?

What regulatory reform opportunities exist to fully exploit the potential for DM to meet multiple desirable customer and business outcomes, including sharing the potential economic benefits of DM?

WP2 - RQ9

Cross-linkage to Work Package 3: How would these issues be addressed (e.g. What is best practice consumer-focused DM and what regulatory reform opportunities exist to support development of this)?

Table 7.2 Work Package 2: Demand management

Linkages

IRG Mtg Qs

Move to WP 3

RQs Analysis of distribution system operator functions to enhance customer outcomes Linkages with IRG Mtg Qs

WP3 - RQ1

What is the fundamental role of a DSO and who is responsible for this?

How can we identify a DSO, its role and functions within the Australian energy market context?

WP3 - RQ2

WP3 - RQ3

WP3 - RQ4

What is the relationship between DER, DM and DSO?

What is the range of business and ownership models for funding and operating distribution systems?

How do we measure and enhance customer (consumer and community) outcomes across the range of DSO models? This includes consideration of how different DSO roles can shift the organisational relationship between Capex and Opex expenditure to optimise customer outcomes?

WP3 - RQ5

What is the role and function of innovative technologies such as autonomous energy systems in distribution systems, and who is responsible for such systems?

WP3 - RQ6

WP3 - RQ7

WP3 - RQ8

How can innovative technology enhance customer outcomes and how does a customer know they are getting value for money?

What are the costs and benefits of the DSO model versus the counter-factual?

How would these issues be addressed in WP 4? Move to WP4

Table 7.3 Work Package 3: Distribution system operator

RQs

WP4 - RQ1

Customer - centred review of reform opportunities for regulation of networks services and the role of DER, DM and DSO in energy transitions over the horizon

How can current regulations concerning the planning and provision of networks services be reformed to ensure full integration of consumer-owned resources within the energy system?

All

WP4 - RQ2

What is best practice consumer-focused DM, and what regulatory reform opportunities exist to support development of this?

1, 5, 6

WP4 - RQ3

WP4 - RQ4

What is the role of social licence in facilitating customercentred regulatory reforms of DER, DM and network services?

How do we put customers (consumers and communities) first in the DER-driven energy transformation currently underway in the NEM?

1, 3, 4, 5, 6

1, 4, 5, 6

WP4 - RQ5

WP4 - RQ6

How do different types of consumers participate in, and benefit from, DER, DM and DSO?

How can the existing energy transition paradigm be reimagined in terms of network management and regulatory frameworks to ensure future beneficial customer focused outcomes?

1, 3, 4, 5, 6

All

WP4 - RQ7

What are the challenges in identifying the roles, functions, and structures (institutional, technical, regulatory, physical, commercial etc.) to deliver consumer-focused, value for money in future energy transitions?

WP4 - RQ8

Who is best placed to deliver such outcomes? All

Table 7.4 Work Package 4: Over the horizon

ANNEX 2: STAKEHOLDER ENGAGEMENT AND FEEDBACK

Overview

As discussed in earlier progress reports, the first industry reference group (IRG) meeting was held 23 May 2022 via MS Teams to discuss the N4 Opportunity Assessment. The purpose of that meeting was to discuss specific areas for inclusion in the project’s research to inform the final report and roadmap.

The 2nd IRG meeting was held on 7 December 2022 via MS Teams to discuss the N4 Opportunity Assessment draft final report and roadmap. The purpose of that meeting was to discuss specific feedback on the draft final report, the research roadmap and possible future research projects. A survey was conducted and follow up consultations held with key stakeholders in the following weeks to elicit further feedback on research priorities and projects.

A brief overview of these meetings is set out below.

In addition to the above, various team members engaged in small group meetings with parties from project partners and key stakeholders, including consumer bodies and market institutions.

A key consideration of both IRG meetings and small group consultations’ discussions was identifying issues that needed to be included in the current research in order to develop project proposals that will garner strong industry, government, and consumer support for future funded projects that provide meaningful contributions to this and related areas of RACE for 2030’s thematic research.

Throughout the project, meetings were also held with RACE representatives and feedback provide incorporated into the research activities of the N4 OA Team, final report and roadmap.

As agreed with the project partners and key stakeholders in stakeholder engagement, the feedback set out in this report has been anonymised.

First IRG meeting

The first successful collaborative IRG meeting for this project was held on 23 May 2023. The objective of this first workshop was to introduce the project team, the OA project’s key themes and questions, and to seek industry and government feedback on specific areas of interest and priority. This resulted in a stimulating discussion, with highly informative insights from key players in the eastern NEM jurisdictions and WA. The latter was particularly helpful in highlighting the extensive work already undertaken on managing and regulating distributed energy resources in WA’s separate energy market.

Key feedback from first IRG

Overall, there was broad consensus that the energy market and regulatory framework are rapidly changing, with the finalisation and expected release of several government initiatives occurring at, or in the weeks and months immediately following this IRG meeting.

A further set of questions were identified as being important considerations within the context of this OA during the first IRG. These are set out subsequently in Table 8.1 below. These questions, which enhanced the research framing questions set out above, have been addressed in an integrated manner in this final report.

IRG Qs Additional Scoping Questions from 1 st IRG Cross Refs

IRG - RQ1.

How can the benefits of user-driven (passive/active) DER and DM be understood, recognised, and valued, in order to increase uptake with aligned interests?

See Tables 7.1-7.4 above; See also N1 OA

IRG - RQ2.

What is the role of technology (hard/soft/service) in transparently facilitating and maximising user-focused demand management (considering access and control)?

See Tables 7.1-7.4

above; See also B4 OA

IRG - RQ3.

What regulatory framework can be used to ensure the functions of the DSO/DMO can be undertaken with appropriate accountability?

See Tables 7.1-7.4 above

IRG - RQ4.

What KPIs should the DSO seek to maximise including consumer, environmental, financial outcomes with further integration of DER?

IRG - RQ5. How can we harness DM and DER through a DSO to minimise costs while sustaining urban grids and islanding rural grids?

IRG - RQ6.

How do we support the planning process to be agile in the face of rapidly changing technology and market conditions?

Second IRG meeting

See Tables 7.1-7.4 above; See also new NEO and NERO

See Tables 7.1-7.4 above

Tables 7.1-7.4 above

The 2nd industry reference group meeting was held on 7 December 2022 via MS Teams. Several members of RACE for 2030 also attended. The primary purpose of this meeting was to discuss the N4 Opportunity Assessment draft final report and roadmap. The discussion’s focus was the provision of specific feedback on the draft final report, the research roadmap and IRG interest in possible future funded research projects. A survey was conducted and follow up consultations held with key stakeholders in the following weeks to elicit further feedback on research priorities and projects. The anonymised outcomes from the survey responses are set out below. A summary collating these and responses from further feedback provided after this meeting are set out next.

Key feedback from 2nd IRG and related consultations with project partners and key stakeholders

An online survey conducted at the 2nd IRG comprised questions founded on the research roadmap set out in the draft final report. These results from the IRG feedback and subsequent meetings with project partners and other key stakeholders provided insights into the priorities for future funded research projects. These have been collated and are set out below according to topics and short-term, medium-term, and long-term priorities for project partners and key stakeholders interested in potential future funded research under this RACE theme.

Together, the expressions of interest in the range of issues offer considerable insights into the directions for future research and funding under this RACE theme.

Interest for future funded research projects: Overview

In general terms, the IRG responses and subsequent meetings discussing the research roadmap with project partners and other key stakeholders demonstrated strong support and interest for several proposed future funded projects. The most positive responses were provided for the following:

Short term

• Mapping out changes required in the regulatory framework to integrate grid and transport planning to accommodate electrification

• Undertaking a comprehensive, comparative DER regulatory review across Australia (federal/states/territories)

• Identifying opportunities for regulatory reform and redesign for a consumer centric energy market that articulates how benefits of user-driven (passive/active) DER and DM can be understood, recognised, and valued, in order to increase uptake with aligned interests and consumer protections

• Consumer-centric energy market-focused DSO business models that support continual integration of DER/CER/DM, promote agile planning, ensure transparency and accountability

• Regulatory reforms (draft/introduce/enact) reflecting adopted DSO model, legislative provisions for DSO role/functions, agile planning, transparency and accountability measures.

Medium term

• Review of DUoS/TUoS fees based on grid usage to encourage localised energy flows and to decouple DER utilisation from transmission network costs

• Regulatory reform mapping for behind-the-meter DER to ensure value and benefits for consumers

• Regulatory reforms that support recognition of consumer energy resources (CER) flexible demand and the transition to fully integrated CER/DER/DSO/DM markets

• Exploring beneficial regulatory changes required to build trust with consumers, ensure fair outcomes across different consumers, and enable greater uptake of automated demand response.

Long Term

• Investigating the role of DM mechanisms such as the DMIS in supporting DER integration and provision of DER services (e.g. EVs) in future energy markets.

The proposed projects that garnered the least interest for future funding were the proposals to conduct a deep dive into appropriate DSO-level roles and responsibilities to streamline associated structures, and an investigation into evolving social contract considerations between consumers and energy policy-makers

More specific responses were given on the following issues drawn from the draft final report’s research roadmap. The responses with the highest ranked interest are set out in terms of short-term, medium-term, and long-term research projects.

Consumer benefits and value

Consumer centric energy market

Short term

• Identifying high leverage sandbox options to demonstrate DM and DERs

• Identify potential regulatory reforms to recognise ERs and achieve flexible demand

• Identifying the nature and scope of the growing jurisdictional differences emerging throughout NEM

Medium term

• Informing the transition to fully integrated CER/DER/DSO/DM markets

• Integrating impacts of new technologies on CER/DER/DM/DSOs and other aspects of future NEM

• Investigating amendments to recognise CER and value of end-users’ flexible demand.

Long Term

• Foresighting future policy and regulatory changes to support ongoing integration of consumer-centric energy market technologies

Customers, trust and automated demand response (ADR)

Short term

• Exploring beneficial regulatory changes to build trust, ensure fair outcomes, and enable greater uptake of ADR

DER: Comprehensive regulatory reforms review and fit-for-purpose: distribution network planning

Short term

• Investigating options to support the planning process to be agile in the face of rapidly changing technology and market conditions

• Re-engagement and active role of state government in the energy sector, focused on the retail-distribution interface

Medium term

• Proposing amendments to recognise the changing nature of end-users, including definitions, participants, ownership, and roles and responsibilities

Long term

• Foresighting future policy and regulatory changes to support ongoing integration of DER technologies evaluation of DER-related regulatory changes

Distribution system operator

The DSO of the future and changing retail market

Short term

• Investigate regulatory reforms and frameworks to consider legislative roles and functions for spot markets.

Medium term

• Investigate DSO business models for a consumer-centric energy market that support DM/CER/DERs and promote agile planning, transparency and accountability

• Investigate the development of a retail DER/CER market

• Investigate KPIs for DSOs to maximise consumer value through further integration of DERs

Demand management

New technologies, access and control

Short term

• Exploration of the role of technology in transparently facilitating and maximising user-focused DM

Regulatory reform to enhance long-term benefits across retail-distribution-consumer interface

Short term

• Comprehensive review of the efficacy of existing regulatory DM mechanism, focusing on challenges and range of regulatory reforms to promote increased uptake of DM.

Opportunity Assessment Project title