Luke Marshall’s research while affiliated with UNSW Sydney and other places

Purpose of Review To investigate the interaction between restructured electricity market designs, in particular Australia’s National Electricity Market (NEM), and variable renewable generators. In particular, to examine how the expansion of near-zero marginal cost, variable renewable generators may impact participant incentives and market power. Recent Findings The technology transition may significantly impact bidding behaviour in electricity markets such as the NEM. Summary This paper identifies and explores key challenges including the impact of renewables on electricity market power, incentive structures for variable renewables, potential for exercise of market power in the Australia’s electricity market as well as contracting and bidding strategies for variable renewables.

Understanding competition in electricity markets is fundamental to developing good regulatory, market design and associated policy frameworks for the electricity sector. Where and when competition is effective, appropriate market designs can be largely left to run; where it is not, interventions may be needed. Despite the need to monitor competition in electricity markets, there appears to be a gap in the current literature around the competitiveness of the Australian National Electricity Market (NEM). This means that policymakers and researchers may not have enough information to adequately address the policy needs of Australia's electricity sector. This research applies a number of key measures of competition used by regulators and researchers to the NEM's historical market dataset. Using ten years of bidding and dispatch data, a more complete picture of competition in the NEM has been constructed. This research has identified that common measures of competition may either vastly over or under-estimate levels of competitiveness because they do not account for constrained electricity trading between various regional nodes, as in the NEM. This paper implements a simple solution to this problem, termed the network-extended residual supply index (NERSI), which may present a more accurate predictor of market power for regulators and policymakers.

The authors are Australia-based energy researchers who view a close link between access to energy data and the country's transition to a sustainable and just community-based energy future, which they argue is currently hampered by some major incumbent energy sector businesses and politicians. Rooftop solar (PV) panels are popular additions to Australian homes but individuals do not have access to the data about the energy they produce and consume. Access to this data would empower individuals and collectives such as community energy groups, and accordingly could hasten Australia's take-up and implementation of sustainable energy in a sustainable, communal way. The authors provide a series of recommended actions in their manifesto which would lead to this goal.

Local electricity sharing schemes have the potential to play an increased role in the Australian National Electricity Market as the penetration of distributed energy resources (DERs) continues to grow. These models allow participants to share energy between separately owned and operated DERs, however are largely untested. While embedded networks have generally been established for specific circumstances such as shopping centres and airports, there is growing interest in their wider application in providing a framework for local sharing of energy resources. However, the potential operational and commercial implications for key stakeholders (including consumers, network operators and retailers) are not well understood. An example of one such proposal is within the Byron Arts and Industrial Estate through which the community owned retailer, Enova, is seeking to offer a bespoke energy solution to its customers within the estate. In this paper, a new open source software model for assessing technical and commercial outcomes of local electricity sharing is presented. The model is applied to the Byron Arts and Industrial Estate case study which demonstrates the relevance of modelling to support appropriate investment and operational decision-making. 1. Introduction With significant reductions in photovoltaics (PV) and battery energy storage (BES) system costs over recent years, a range of new business and community models are emerging in electricity industries around the world, specifically designed to cater to a new class of consumer: participants that both generate and consume energy from distributed energy resources. These new approaches allow customers to buy and sell energy between each other (rather than from a centralised retailer or generator), and to aggregate their consumption to access a more beneficial interface with networks and electricity markets.

The growing adoption of distributed energy resources (DERs) across Australia may represent the start of a transition of Australia's power system from a centralised generation model towards an interconnected set of embedded microgrid systems. In these systems, local trading of coincident generation and consumption is being explored, with the idea that this would encourage consumer engagement, provide more choice, and incentivise reduced use of networks (via increased balancing of loads and generation locally). However coincidence of generation and load over short time frames, and hence network benefit, can be difficult to determine using existing metering systems. There are many sites undergoing trials to determine how energy flows can be efficiently monitored and accounted for in microgrid systems. At the current time, commercial metering is generally performed on time scales greater than thirty seconds, with most metering systems measuring net flows on half-hourly intervals. This represents a barrier to accurate accounting, since the time at which nodes generate and consume energy within a wide metering period is not known. As a result, end-users may face effective penalties or avoid charges that would accrue to their generation or consumption profile under more accurate accounting. Accurate accounting for the economic benefits of embedded microgrids that result from either reductions in external network use or contributions to improved reliability, rely on sub-second level timing, and cannot be commercially factored (or incentivized) without corresponding metering. In this paper, the coincidence of generation and consumption in a micro-grid setting is examined over different timeframes using a software based simulation, and the impact of different time intervals for accounting is explored using an algorithmic theoretical approach. It is found that there are predictable trends in the way that metering time periods impact the accuracy of 'peer to peer' accounting. For the limited dataset tested, the inaccuracies were found to be small relative to overall energy consumption, however further work is required to determine whether this can be generalized across the majority of schemes.

This paper aims to revisit the way that distributed energy resources (DERs) interact with the present structures of the Australian National Electricity Market (NEM), and consider opportunities to improve the interface between centralized and distributed resource operation and investment. The NEM was established with the stated aim of facilitating efficient operation of and investment in electricity systems across the Eastern Australian States through more competitive, market oriented arrangements. It was, however, designed at a time when DERs did not have a significant impact on the electricity system. Distributed photovoltaic (PV) and battery storage systems, among other DER technologies such as 'smart' building management systems and appliances, may represent welcome new sources of competition in wholesale and retail markets, yet it is unclear whether present NEM arrangements provide a coherent or comprehensive interface between utility scale and decentralized end-user decision making. For example, utility scale PV systems reside within a wholesale market that requires them to participate in scheduling and provides dynamic pricing of both energy and ancillary services. By contrast, residential PV systems sit within retail market arrangements that utilize net metering of household demand and generation, and provide effectively fixed volumetric tariffs. The two markets do interact, of course-household PV systems can in aggregate influence wholesale prices by reducing the overall supply of energy provided by that market. And wholesale prices do eventually impact on residential tariffs that drive the case for residential PV uptake. However, this interaction would seem to lack coherence and comprehensiveness. These factors already appear to be impacting market and customer outcomes at the current deployment of approximately 5GW of rooftop PV. Some forecasts predict that the system will need to support up to 19 GW in the coming two decades. This raises important questions around whether incentives from the NEM's wholesale and retail structures are facilitating efficient investment and operation in this space and, if not, what might be done. In this paper, existing NEM wholesale and retail market arrangements are examined in the context of growing DER penetrations, to provide a preliminary assessment of whether they provide a suitable framework for coordinating efficient operational dispatch and investment across both utility scale and distributed energy options, and energy consumer decision making more generally. A number of key challenges are identified in present arrangements, and possible opportunities to improve key aspects of them are presented.

While the components of utility-scale photovoltaic (PV) power stations are moving rapidly down their respective cost curves, the investment context for such plants is generally still untenable in most electricity markets. While part of the challenge lies in electricity market arrangements that do not appropriately price the environmental impacts of fossil fuel generation, another difficulty is that operators of utility-scale PV generators are unable to appropriately de-risk the value of output from their highly variable and somewhat unpredictable power plants. Securing financing for prospective utility-scale PV projects is challenging, in part, due to a lack of available strategies to mitigate revenue risk in restructured electricity markets. Currently available energy market derivatives-including swaps and options-are intended to mitigate revenue risks for base load and dispatchable peaking generators, as well as counterpart retailers and large industrial loads. This paper examines whether unconventional contracting strategies might be used to de-risk utility-scale PV plants and provide financial products that are appropriate to these plants yet still attractive to retailers. Additionally, it investigates the benefits of adding a dispatchable energy storage component to take advantage of market movements.