Weather as Fuel: Inside Australia's Energy Transition and the System Architecture of Virtual Power Plants

In October 2025, the Taiwan Energy Digital Transformation Alliance (TAEDT) organized an Australian Virtual Power Plant (VPP) Study Delegation from October 11 to 16. The delegation—comprising 18 participants, primarily chairpersons and CEOs of TAEDT member companies—travelled to Melbourne for an in-depth exchange focused on virtual power plants, electricity market governance, and digital dispatch systems.

Over the course of the visit, the delegation engaged with 7 institutions that play critical roles in Australia's energy transition, spanning multiple layers of the power system. These included the regulator Australian Energy Regulator (AER); the market and system operator Australian Energy Market Operator (AEMO); the Melbourne Energy Institute (MEI) at the University of Melbourne, representing the policy and systems research domain; and key industry actors such as Enel X and Amber Electric, both central to VPP aggregation and demand-side flexibility; Gentrack, a software integrator serving electricity retailers and market systems; and Relectrify, a specialist in advanced battery and energy storage technologies. Collectively, these visits offered a comprehensive view of how Australia's energy transition and VPP ecosystem operate across regulatory, academic, and market dimensions.

Value Stacking[1] in Practice: How Energy Storage Delivers Revenue, Resilience, and Decarbonization

The first day began with site visits and exchanges with three key organizations: an operational Battery Energy Storage System (BESS) deployed by Enel X Australia, the battery technology company Relectrify, and Enel X's Melbourne office. By engaging directly with live operating environments and frontline technical and operational teams, participants developed a grounded understanding of Australia's energy transition and the evolving role of VPPs under high renewable penetration.

A flagship example was the smart energy storage project adjacent to Broadmeadows Central Shopping Centre in northern Melbourne. Through on-site briefings by Enel X's operations team, participants observed how solar generation, battery storage, and real-time dispatch mechanisms are integrated to transform electricity consumption—traditionally treated as a cost center—into a market-valued flexible energy asset.

Enel X Australia, part of the global Enel Group, plays a central role in the group's smart energy and digital energy services. Its VPP portfolio across Australia and New Zealand aggregates more than 550 sites with over 750 MW of managed capacity, spanning battery storage, backup generation, and controllable loads. Through optimized aggregation and dispatch, corporate users can simultaneously maintain operational stability, participate in electricity markets, generate additional revenue, respond to grid stress, enhance system resilience, and advance decarbonization goals.

The Broadmeadows project—developed in partnership with Vicinity Centres, one of Australia's largest commercial real estate asset managers—features a 1.1 MW / 2.3 MWh storage system. Integrated into Enel X's VPP platform, the asset participates in energy arbitrage in the wholesale market, Frequency Control Ancillary Services (FCAS), and demand charge management, significantly reducing peak electricity costs. Combined with on-site solar PV, the system dynamically optimizes self-consumption, charging and discharging strategies, and market participation based on real-time price signals, load demand, and grid conditions. As a result, the shopping center transitions from a passive electricity consumer to an active node within the power system.

Note:
[1] In the context of virtual power plants, value stacking refers to the practice of enabling a single portfolio of distributed energy resources (DERs) to participate simultaneously in multiple electricity markets or to deliver multiple grid services, thereby maximizing both the economic returns and utilization efficiency of the underlying assets. While the term is conceptually similar to its usage in the marketing domain—where the emphasis is likewise on the accumulation of layered benefits—in power systems, value stacking is inherently characterized by highly technical requirements and complex market dispatch dynamics.

Designed for the Behind-the-Meter Economy: Structural Battery Efficiency Challenges and Relectrify's Breakthrough

The delegation then visited Relectrify, where Product Lead Ben Shepherd addressed a long-standing structural efficiency problem in battery systems. In conventional DC-series architectures—used in both EVs and stationary storage—the performance of the entire system is constrained by the weakest cell. Over time, manufacturing variance, thermal conditions, and uneven degradation amplify cell imbalance, leaving substantial usable capacity stranded within the system.

Relectrify's solution replaces traditional busbar architectures with cell-level switching, using high-density electronic switching to independently control the engagement or bypass of each cell. This allows the system to dynamically avoid weak cells during charge and discharge, unlocking otherwise inaccessible energy. The architecture not only increases lifetime usable energy but fundamentally reshapes battery degradation economics. Moreover, it enables direct AC waveform generation at the module level, eliminating the need for conventional inverters, reducing system complexity and size, and removing one of the most failure-prone components—electrolytic capacitors[2].

Relectrify validated this approach using second-life EV batteries deployed across Australia and New Zealand, demonstrating effective energy recovery even when cell health variance exceeds 40%. Building on this, its commercial AC1 product integrates 24 modules to deliver 250 kW / 1.2 MWh, achieving more than 20% lifetime energy improvement under a 20-year warranty, significantly enhancing project returns.

Discussions also examined Taiwan's policy context, where large electricity users face storage or renewable deployment obligations. Load curve simulations showed that under Taiwan's peak–off-peak price differentials, AC1-based arbitrage and peak shaving could achieve payback within six years, generating sustained cash flow over a 20-year lifespan—often outperforming standalone solar PV investments. This illustrates how, even before full market liberalization of ancillary services, behind-the-meter economics alone can support viable storage business models.

Note:
[2] Under prolonged operation or exposure to harsh conditions such as elevated temperatures and high operating voltages, the electrolyte within a battery will gradually degrade, volatilize, or decompose. This process leads to an irreversible deterioration of the battery's original electrical characteristics over time, resulting in long-term performance decline.

From Optional Tool to System Necessity: VPPs under High Renewable Penetration

At Enel X, Chair of Enel X Australia and New Zealand Carl Hutchinson illustrated how VPPs and demand-side flexibility have evolved from auxiliary tools into system-critical infrastructure under Australia's high renewable penetration. Operating within an energy-only market without capacity payments, Australia experiences prolonged periods of near-zero prices punctuated by extreme price spikes. This volatility favors fast-responding resources such as batteries and flexible loads, while simultaneously complicating investment risk assessment.

To mitigate this, Australian governments have introduced risk-sharing mechanisms, including the Capacity Investment Scheme, government-backed VPP programs, and demonstration grants—effectively creating "shadow markets" that shift part of the risk from private investors to public balance sheets. While theoretically imperfect, these measures strike a pragmatic balance between political feasibility and investment viability.

Discussions highlighted the gap between resources technically capable of market participation and those actually dispatched due to complex rules and high thresholds. Moreover, Australia's rapid growth in Consumer Energy Resources (CER)[3]—driven by rooftop solar incentives—has created extreme "duck curves," intensifying frequency and reserve challenges unless flexibility is visible, predictable, and controllable. This underpins Australia's policy requiring VPP compatibility for subsidized household batteries.

However, speakers emphasized that beyond technology and regulation, the core challenge is social trust. When households perceive loss of autonomy without clear or predictable benefits, backlash can undermine VPP legitimacy—highlighting the importance of social license alongside technical and economic design.

Note:
[3] Consumer Energy Resources (CER) refer to energy assets owned by electricity consumers—whether households or commercial entities—and located behind the meter. These resources are capable of generating electricity, storing energy, or flexibly adjusting electricity consumption, thereby enabling consumers to actively participate in power system operations and energy markets.

Flexibility over Overbuild: VPPs in System Planning and Governance

On the second day of the visit, the delegation travelled to the Melbourne Energy Institute (MEI) at the University of Melbourne. The meeting opened with an introduction by Professor Richard Sandberg, Executive Director of MEI, who outlined the institute's positioning and scale within the global energy research landscape. He emphasized MEI's role as a cross-faculty, interdisciplinary research platform that brings together expertise from engineering, science, economics, law, and social sciences. Its mission, he noted, extends beyond advancing low-carbon energy solutions to also addressing energy affordability and social justice. MEI's research framework is structured around 4 core pillars—energy systems; power generation and transport; heavy industry and resources; and energy materials—and is supported by long-term collaborations with government, industry, and international academic partners.

At the energy systems level, Professor Pierluigi Mancarella, Chair and Director of MEI's Energy Systems Program, highlighted that as the share of renewable energy and distributed energy resources (DER) continues to rise rapidly, the central challenge facing power systems is no longer simply "how much electricity to generate," but rather "how to balance the system in real time under conditions of high uncertainty." Australia's experience demonstrates that large-scale deployment of rooftop solar, wind power, and distributed storage leads to pronounced price volatility in electricity markets, with negative prices occurring frequently. This phenomenon, he stressed, does not indicate market failure; instead, it reflects the reality that as the marginal cost of energy approaches zero, the true sources of value shift toward flexibility and system services.

Against this backdrop, virtual power plants are widely regarded as a core architectural component of the next-generation power system. The discussion clearly distinguished between the roles of commercial VPPs and technical VPPs. Commercial VPPs operate as market participants, aggregating distributed resources to provide energy and ancillary services, while technical VPPs are managed by distribution-level system operators (DSOs) to ensure that all commercial activities remain within the physical constraints of the grid, including voltage limits, thermal capacity, and operational security. This dual-layer structure is increasingly viewed as a foundational institutional arrangement for the stable operation of future distributed power systems.

Professor Mancarella further emphasized that as traditional large synchronous generators progressively retire, the importance of reactive power and voltage support will rise significantly. In response, Australia has introduced grid connection requirements mandating that rooftop solar inverters be capable of dynamically absorbing or injecting reactive power to manage voltage issues under high penetration conditions. Australian scholars noted that reactive power will not remain merely a technical consideration; it is likely to evolve into a system service with explicit economic value. When integrated through VPPs and localized electricity market mechanisms, such services could help prevent large-scale blackouts similar to those recently experienced in parts of Europe due to insufficient reactive power[4] support.

From an investment and planning perspective, another key lesson from Australia is the principle of "using flexibility as a substitute for excessive grid expansion." Conventional grid planning has traditionally been based on worst-case scenarios, resulting in substantial upfront investment and heightened risks of stranded assets. Through stochastic planning[5] and multi-scenario modelling, research indicates that effective mobilization of demand-side and distributed flexible resources can significantly reduce overall system costs and risks, potentially saving tens of billions of Australian dollars in transmission and distribution investments. This approach is also regarded as highly relevant for investors, offering a more robust framework for risk management amid the deep uncertainty inherent in the energy transition.

During the exchange, Professor George Hsu, Director of TAEDT, shared the alliance's development experience, describing how it connects government, industry, academia, and research institutions while focusing on distributed energy resources, microgrids, and behind-the-meter virtual power plants. Through policy recommendations, special publications, and international engagement, the alliance seeks to advance institutional and market reforms. Both sides expressed strong consensus that despite differing institutional contexts, Taiwan and Australia face highly similar challenges in areas such as high renewable penetration, feeder congestion, voltage control, and market design. As a result, significant potential exists for future collaboration in research, demonstration projects, and policy dialogue.

Note:
[4] In power systems, reactive power capability refers to the ability of electrical assets—such as generators, power converters, or compensation devices—to absorb or supply reactive power (Q) in response to grid requirements, in order to maintain voltage stability and power factor balance.
[5] Stochastic planning is a mathematical and computational framework for decision-making under conditions of uncertainty. Unlike conventional deterministic planning, which assumes that all parameters are known with certainty, stochastic planning explicitly treats future unknowns—such as electricity demand, price volatility, or weather conditions—as random variables, and uses probability distributions to simulate a range of possible future scenarios.

When Data Becomes the Battleground: Energy IT under Five-Minute Settlement

Under conditions of high renewable energy penetration and rapidly increasing market complexity, the energy transition has long ceased to be a matter of simply “installing more solar panels or batteries.” Instead, it has become a comprehensive transformation spanning IT architecture, data governance, institutional design, and the reconfiguration of customer relationships. At the meeting, Andrew Cogger, Client Solution and Innovation Leader for Asia-Pacific at Gentrack, opened by noting that the energy sector is simultaneously undergoing five structural shifts: the full digitization of customer interactions, the rapid growth of distributed energy resources, an explosion in data volumes, increasing product differentiation, and ever-tightening regulatory requirements. Under these conditions, the traditional utility system logic—historically centered on "meter reading, billing, and payment collection"—is no longer capable of supporting today's market environment.

Against this backdrop, Gentrack positions its G2 platform as an end-to-end energy operations system. Its core value does not lie in any single technology component, but in the integration of customer relationship management, product design, billing and revenue management, distributed energy integration, data analytics, and regulatory reporting within a unified cloud-based architecture. The discussion emphasized that the true difficulty of the energy transition does not lie in whether virtual power plants can be technically implemented, but rather in whether VPPs can be embedded within an operating framework that is scalable, regulatorily compliant, and understandable and trustworthy from the customer's perspective.

Australia was repeatedly cited as a critical reference case. With the introduction of five-minute settlement, the volume of billing and settlement data generated by a single electricity meter has surged from "one record per month" to nearly 9,000 records per year, placing extreme demands on billing systems, data processing capacity, and real-time performance. Gentrack stressed that without cloud-native, horizontally scalable architectures, retailers would be unable to cope with this data deluge—let alone implement real-time pricing, dynamic product design, or VPP revenue-sharing mechanisms. This reality underscores why energy IT is no longer a back-office support function, but has become core infrastructure directly shaping market competitiveness and profitability.

In the context of virtual power plants, the meeting offered a highly concrete end-to-end process perspective. Gentrack explained that the journey from a household with no solar installation to becoming a market-dispatchable VPP participant involves numerous interconnected stages: system design, equipment installation, processing of government subsidy certificates, metering and communications, asset monitoring, integration with dispatch platforms, billing and revenue allocation, customer service support, and regulatory reporting. A failure at any single point can render the entire VPP business model unviable. As such, a VPP should not be understood as a standalone technology product, but rather as a highly integrated ecosystem of industry collaboration.

The discussion compared 2 contrasting yet equally successful VPP business models in Australia. At one end is the "energy-as-a-service" model led by large energy retailers, under which retailers finance and install solar and battery systems for households, while customers pay a fixed electricity price without needing to understand market operations. At the other end is a highly market-oriented, customer-driven model, in which users are directly exposed to five-minute wholesale prices and actively participate in market arbitrage through their batteries. The former prioritizes simplicity and stability to build trust, while the latter emphasizes transparency and autonomy to achieve high engagement. Both models demonstrate that the success or failure of VPPs often hinges less on technology itself than on customer relationship design.

The discussion also delved into the deeper institutional structure of Australia's electricity system. Generation, transmission, distribution, retail, and metering services have been fully unbundled, with each role connected through highly standardized data and financial processes. Electricity meters are owned and managed by independent metering coordinators, with retailers paying annual fees and relying on certified data provided by these entities for billing and market settlement. While complex, this institutional arrangement creates the regulatory space necessary for VPPs, demand response, and innovative retail products, and further highlights the critical role of IT platforms in facilitating multi-party data exchange.

In dialogue with the Taiwanese context, participants from Taiwan noted that while electricity prices in Taiwan remain relatively low and retail competition is limited, recent years have seen a distinct—and increasingly urgent—demand dynamic driven by extreme weather events, blackout risks, and heightened awareness of energy security. If Taiwan is to pursue a distributed energy model centered on resilience, backup capacity, and user participation, it will inevitably face the same fundamental challenge: how to align technology, institutions, billing mechanisms, and trust simultaneously.

Direct Market Access for Consumers: Redefining Retail through Amber Electric

During the visit, the delegation was personally received by Amber Electric Chief Executive Officer Dan Adams, who delivered an in-depth briefing and engaged in extensive discussion with the group. At just 38 years of age, Adams exemplified the new generation of Australian energy entrepreneurs, demonstrating a sophisticated understanding of electricity market structures and digital transformation.

Amber Electric is an energy retail and management company widely recognized for its innovative business model. Backed by investment from Gentrack, Amber's core philosophy is to dismantle the traditionally closed structure of retail electricity markets and enable residential and commercial customers to connect directly to the wholesale electricity market. Through real-time pricing mechanisms and digital platforms, Amber helps customers increase consumption when prices are low and export electricity generated from their own solar installations or stored in batteries back to the grid when prices are high. This approach not only reduces overall electricity costs, but also improves the effective utilization of renewable energy.

On the technical side, Amber integrates rooftop solar PV and residential battery systems, leveraging its proprietary SmartShift technology to automatically determine optimal charging and discharging times. This allows customers to respond to market price signals without the need for constant manual intervention. At the same time, Amber is actively expanding into smart electric vehicle charging and Vehicle-to-Grid (V2G) applications, and participates in multiple innovation demonstration projects supported by the Australian Renewable Energy Agency (ARENA), continuing to explore the evolving role of electric vehicles within the power system.

From a business model perspective, Amber has adopted a subscription-based strategy that differs fundamentally from traditional electricity retailing. Customers pay a flat software service fee of AUD 25 per month, rather than having costs embedded in electricity volumes or price margins. This structure ensures a high level of transparency in both revenue streams and cost calculations, aligning Amber's incentives more closely with customer objectives and placing consumer control at the center of its operations.

Under this model, Amber has grown into one of Australia's largest virtual power plant operators, currently managing more than 26,000 distributed energy assets associated with smart EV charging and V2G applications. Some customers have even recorded negative electricity bills as a result of actively participating in grid dispatch and market transactions, fundamentally challenging conventional assumptions about electricity costs.

Amber's products and technologies have begun to be adopted by electricity companies in several European countries, including the United Kingdom and Germany. This international uptake demonstrates that Amber's business logic—centered on digital platforms, real-time pricing, and active customer participation—has received tangible validation and recognition in global markets.

Visibility, Predictability, Controllability: Governing the High-DER Grid

The meeting was jointly hosted by the Australian Energy Market Operator (AEMO) and the Australian Energy Regulator (AER). From the outset, it was explicitly framed not as a presentation-based briefing, but as an experience- and problem-oriented dialogue. Drawing on more than 40 years of experience in the power sector, Mike Davidson, Senior Engineer at AEMO, opened the discussion by stating unequivocally that Australia's power system is at an unprecedented inflection point. This turning point, he emphasized, is not the result of technological failure, but rather of the system's structural design having been pushed to its limits by a successful energy transition.

He noted that Australia has rapidly evolved from a system once dominated by several dozen or a few hundred large synchronous generators into an electricity network comprising millions of distributed energy resources (DER/CER). These resources are predominantly located at the distribution and behind-the-meter levels and are highly decentralized. Historically, the system AEMO was most familiar with—and best equipped to operate—was one in which assets were fully visible and controllable through SCADA at the transmission level. Today, however, the forces that most strongly influence system stability have largely migrated beyond AEMO's traditional control boundaries.

Since 1 October 2021, Australia has formally implemented the Five-Minute Settlement (5MS) regime, a reform widely regarded as a critical institutional response to high renewable energy penetration. Under 5MS, the previous mismatch—five-minute dispatch combined with thirty-minute averaged settlement—was replaced by synchronized five-minute dispatch and settlement intervals. This change enables market prices to reflect system conditions in near real time, delivering more precise and temporally sensitive price signals.

This institutional design has significantly enhanced the competitiveness of fast-responding resources, particularly flexible assets such as energy storage and demand response. These resources can now participate in the market based on speed and precision, rather than being obscured by slower, long-duration averaged settlement mechanisms. This, Davidson stressed, is one of the key conditions underpinning the stable operation of power systems with high shares of renewable energy.

Davidson highlighted a central concept repeatedly referenced throughout the discussion: "Weather as fuel." In Australia's operational reality, this is no longer a metaphor, but an everyday condition of the power system. During periods when renewable penetration reaches record highs, generation output is determined directly by wind conditions and solar irradiance rather than by fuel supply. As a result, system requirements for inertia and system strength are increasingly decoupled from traditional generation structures.

Natural gas has long been regarded as an important transitional fuel in this context—not because of its energy output, but because of its ability to provide critical system services, particularly inertia. Even during periods of very high renewable output, gas-fired units may continue operating at minimum levels, not to compete in the energy market, but solely to support system stability.

However, this role is changing rapidly. As synchronous condensers are progressively deployed, the inertia and system strength previously supplied by gas-fired generators are increasingly being replaced by non-fuel-based assets. Synchronous condensers provide inertia simply by remaining in rotation, without consuming fuel or participating in energy market bidding. This marks the first time that system stability can be structurally decoupled from the act of electricity generation itself.

Within Australia's energy-only market, where no capacity payments exist, gas generators that are pushed out of the market by low prices but are still required for system security can only be retained through administrative directions and cost-based compensation. In operational practice, market and system operators therefore seek to remove all resources that can feasibly exit the market, retaining only the minimum number of gas units necessary purely to maintain system strength.

At certain times, South Australia has been able to export more than 200 MW of electricity to Victoria relying almost entirely on rooftop solar generation, against an interconnector capacity of 500 MW. During such periods, aside from a very small number of gas units performing system security functions, nearly all other resources exit the market. As the number of synchronous condensers increases, the minimum operational requirement for gas generation continues to decline—from two units in the past to just one today—and this trend is ongoing.

Another set of core concepts repeatedly emphasized during the meeting were Visibility, Predictability, and Controllability. Davidson stated clearly that regardless of whether a resource participates in the market, if its behavior has the potential to affect system security, it must be technically visible to the system operator, behaviorally predictable, and subject to constraint or control when necessary. This is not a question of market efficiency, but a fundamental prerequisite for whether the power system can continue to operate. Without these three capabilities, the simultaneous operation of large volumes of rooftop solar and storage—driven by economic incentives—could rapidly escalate into voltage instability, frequency deviations, or even systemic collapse.

Davidson further explained that AEMO's formal operational remit currently ends at the transmission system boundary, and that it does not directly possess real-time models or control authority over distribution networks. As distributed resources increasingly become the dominant system component, however, this division of responsibilities is becoming untenable. The meeting made clear that AEMO, AER, and rule-making bodies are jointly advancing a critical direction: establishing new responsibility boundaries and coordination mechanisms at the transmission–distribution interface. Under this approach, distribution system operators (future DSOs) would be responsible for aggregating large volumes of distributed resources within their networks into technically feasible and behaviorally predictable equivalent nodes, which AEMO can then incorporate into system-wide dispatch and security assessments.

At its core, this concept treats the entire distribution area as a "technical virtual power plant." Its primary function is not to pursue market revenues, but to ensure that downstream behaviors are physically safe. Only once this condition is met can market-based VPPs, aggregators, and end-user resources be permitted to participate further in energy and service transactions.

At the technical level, the meeting examined in detail the capabilities that DER will be required to provide in the future, including fault ride-through, frequency and voltage support, reactive power control, dispatchability and start–stop controllability, and even system restoration following a black-start event. Davidson acknowledged that these capabilities were previously required only of large generators. In a high-DER environment, however, if distributed resources cannot assume comparable responsibilities, the system will not be operable. Accordingly, Australia has progressively introduced grid connection standards and technical requirements mandating that newly connected inverter-based resources provide these functions. For certain highly localized services—such as distribution-level voltage control—mandatory technical standards are applied, rather than relying on market mechanisms.

From a regulatory perspective, AER added that all of these changes are unfolding under conditions of profound uncertainty. In hindsight, regulators' greatest regret has not been that they acted incorrectly, but that they did not act quickly enough. Had certain tools and frameworks been introduced earlier, the market and technological transition might have been smoother. As a result, Australia has increasingly emphasized working groups, regulatory sandboxes, and pilot programs, allowing industry participants to experiment within controlled environments and gradually feed lessons learned back into formal rules. Policy and regulatory frameworks are also subject to review on a five-year cycle.

The most critical message of the meeting lay in an unusually candid admission: Australia is simultaneously operating one of the world's most complex high-renewable electricity systems while rewriting its governance architecture in real time through learning-by-doing. Virtual power plants, DER aggregation, and future DSO frameworks remain under construction, with no definitive blueprint. Davidson remarked that the process is akin to rebuilding an aircraft engine while in flight—every adjustment must be made with extreme caution, because the cost of failure is not market inefficiency, but public safety and social trust.

The meeting concluded with a clear and sobering message: in an era of high distributed energy penetration, power systems cannot be sustained by markets alone, nor by technology alone. Only by honestly acknowledging risk at the institutional level, establishing enforceable technical boundaries, and clearly allocating governance responsibilities can the energy transition truly move toward long-term sustainability.