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This paper presents a methodology for defining the spot price of temporary water allocation rights for trading zones within the water market in the southern Murray–Darling Basin situated in Australia. The historical spot price is then used to calibrate a stochastic process depicting the dynamics of the water price, allowing the computation of prices of options on the underlying water price with the aim of producing reference prices to catalyse an options trading market. The most suitable stochastic model representing the water price dynamics is selected through comparing the option prices generated from four different models. Using the selected stochastic model, the most liquid trading zone in the Murray–Darling Basin water market (Zone 7) is used to demonstrate how the methodologies developed in the paper are used to calibrate the log‐mean stochastic model representing the stochastic spot price dynamics and compute prices for call and put options on the underlying water spot prices. Sensitivities of the water options prices to market input data can be calculated from the formulae provided in the paper. The results presented in this work can serve as a reference tool by industry practitioners and the farming community in using options for effective risk management of water resources. [ABSTRACT FROM AUTHOR]

Over the period 2016--2021 Australia's National Electricity Market (NEM) experienced an investment supercycle with 16,000MW of new utility-scale renewable plant commitments in a power system with a peak demand of 35,000MW, and the disorderly loss of 5,000MW of synchronous coal-fired plant. This placed strains on system security, most visibly in the distribution of the power systems' frequency, requiring material changes to the NEM's suite of Frequency Control Ancillary Service (FCAS) markets. Utility-scale batteries are ideally suited for FCAS duties, but there is no forward price curve for FCAS markets, nor is there any systematic framework for determining equilibrium prices that might otherwise be used for investment decision-making. In this article, we develop an approach for quantifying long run equilibrium costs and stochastic spot prices in the markets for Frequency Control Ancillary Services, with the intended application being to guide the suitability of utility-scale battery investments under conditions of uncertainty and missing forward FCAS markets. [ABSTRACT FROM AUTHOR]

Australia is facing a historic investment challenge, with an estimated $1.2 to $1.5 trillion in newly invested capital required by 2030 in order to meet 2050 decarbonisation targets. In response policy makers have begun "re-entering" energy markets, which were deregulated and privatised in the 1990's. Public auctions for State-backed 'Contracts-for-Differences' (CfDs) now act as a key policy tool to "prime" energy markets for new variable renewable energy (VRE) capacity. In a phenomenon recently coined "market hybridisation", market participants form long-term investment decisions that are increasingly disconnected from short-run spot pricing dynamics and day-to-day operations. Historically, it has been common practice to underpin VRE projects with some form of power purchase agreement (PPA). However, increasing investor appetites for "semi-merchant" projects (i.e. projects partially exposed to spot prices) has become an emerging trend. This article examines the semi-merchant phenomenon, aiming to explain why the investment model is becoming popular for investors in VRE. Of particular interest are the foregone advantages attributable to highly contracted plant when securing bankable project finance. Results reveal that a revenue mix comprising 70%–80% PPA coverage and 20%–30% merchant exposure appears viable and tractable for investors in utility scale solar — whilst maintaining a typical project finance capital structure of c.60%–70% gearing. By implication, policymakers targeting 4000MW of new solar capacity via CfD auction may need only offer ∼ 3000MW of contracted capacity, thereby reducing taxpayer exposures and protecting scarce government balance sheet resources. [ABSTRACT FROM AUTHOR]

• Evaluate the effect of uncertain operating and market conditions on dispatch planning. • Apply Model Predictive Control (MPC) for dispatch scheduling of CSP plants. • Monte-Carlo simulation is to evaluate the MPC performance for a case-study in Australia. • The plant profitability from electricity sales under spot prices is assessed. The aim at dispatch scheduling for concentrating solar power plants is to utilize thermal storage to maximize profit from electricity generation. The dispatching plan, however, must contend with significant uncertainty in both weather forecasts (particularly solar irradiation) and, in some locations, real-time electricity prices governed by potentially volatile markets. This paper proposes a Model-Predictive Control (MPC) which employs a novel similarity-based forecast for weather variables and exploits the predictions of electricity prices provided by the market operator. A Monte-Carlo simulation is developed to evaluate true performance of the proposed MPC against two benchmarks, with perfect knowledge (PK) forecasts and day-ahead optimized using prototypical weather (DAPW). A case study is performed on a 115 MW Solar Tower plant with 8-hour storage, hypothetically located in South Australia, and operates under either a fixed-price or a real-time spot price scenario. A Monte-Carlo simulation is conducted for 150 tests for January (summer) and August (winter). The results show in fixed-price scenario MPC achieves 82.4 % of optimal profit (i.e. obtained via PK) in January and 72.4 % in August whereas that in DAPW falls to 71.5 % and 56.9 % of optimal, respectively. In the spot market scenario, MPC reaches 71.3 % and 63.6 % of optimal profit in January and August, whereas that for DAPW reaches 61.4 % and 55.1 %, respectively. In conclusion, PK forecast assumption in dispatch planning over-estimates the achievable profit by ∼ 28–40 % particularly in spot market scenario. Moreover, MPC can mitigate the influence of uncertainties on the plant economic performance by 8.5 %–15.5 % compared to DAPW benchmarks. [ABSTRACT FROM AUTHOR]

Global decarbonisation is driving investments in intermittent renewable generation, with most plant entering the market by way of a Power Purchase Agreement. In Australia's National Electricity Market, a surprising number of renewable generators have entered on a merchant basis. To maintain tractable revenues some minimum level of hedging is required, but in an energy-only electricity market with a very high market price cap, merchant intermittent generators require some level of associated firming capacity to ensure spot price exposures can be adequately managed. This article uses unit commitment, battery arbitrage and stochastic discounted cashflow valuation models to compare an Open Cycle Gas Turbine and a battery as firming options for a hypothetical wind farm in the South Australian region of the NEM. Using historic market data from 2010–2020, we find OCGT firming capacity helps the wind farm to generate consistent net cash flows, allowing it to withstand the highs and lows of spot market prices whilst covering required contract-for-difference payments associated with hedging. When battery firming is deployed, the wind farm/ battery portfolio generated higher cash flows at specific times, reflecting participation in price arbitrage under low spot price scenarios. However, battery performance was constrained by costly storage capacity. [ABSTRACT FROM AUTHOR]

In energy-only electricity markets, such as Australia's National Electricity Market (NEM), it has been argued that an increasing penetration of variable renewable energy (VRE) generation is likely to have two effects: (i) more extreme spot prices, with greater instances of both very high and very low prices and (ii) a need to increase the market price cap (MPC) and related price signals for reliability. This article examines the validity of both these effects using spot pricing outcomes in South Australia (SA), which has one of the highest VRE penetrations worldwide. We find partial support for these two effects. While extremely low prices have become more frequent over time, extremely high prices have become less frequent. Spot price volatility has risen, consistent with the hypothesis, but not because prices have become more extreme. Furthermore, these findings are observed for prices in all NEM regions, not just SA. Also, reliability has remained high over the past decade despite the MPC remaining constant in real terms. We provide four reasons why higher VRE penetration need not result in more extreme prices and higher MPCs: (i) greater investment in volatility-dampening, reliability-enhancing technologies like storage and interconnectors; (ii) increased contract cover; (iii) more price-responsive demand; and (iv) emergence of additional ancillary service revenues. These findings have implications for the durability of the NEM's energy-only design given expected further increases in VRE penetration rates across the NEM. [ABSTRACT FROM AUTHOR]

In theory, well designed electricity markets should deliver an efficient mix of technologies at least-cost. But energy market theories and energy market modelling are based upon equilibrium analysis and in practice electricity markets can be off-equilibrium for extended periods. Near-term spot and forward contract prices can and do fall well below, or substantially exceed, relevant entry cost benchmarks and associated long run equilibrium prices. However, given sufficient time higher prices, on average or during certain periods, create incentives for new entrant plant which in turn has the effect of capping longer-dated average spot price expectations at the estimated cost of the relevant new entrant technologies. In this article, we trace generalised new entrant benchmarks and their relationship to spot price outcomes in Australia's National Electricity Market over the 20-year period to 2018; from coal, to gas and more recently to variable renewables plus firming, notionally provided by--or shadow priced at--the carrying cost of an Open Cycle Gas Turbine. This latest entry benchmark relies implicitly, but critically, on the gains from exchange in organised spot markets, using existing spare capacity. As aging coal plant exit, gains from exchange may gradually diminish with 'notional firming' increasingly and necessarily being met by physical firming. At this point, the benchmark must once again move to a new technology set... [ABSTRACT FROM AUTHOR]

Active load shifting of the electricity demand unlocks a variety of benefits. Examples of such advantages include the increased stability of energy systems, reduced electricity costs and financial savings in the transmission as well as generation infrastructure. Although the technology necessary for demand response has been extensively studied for individual appliances or at the micro-grid level, evaluations of its nationwide impact are scarce. Yet governments and policy-makers require quantitative assessments in order to understand the underlying value and derive appropriate policies. For this purpose, this paper utilizes real-world data from the German-Austrian electricity market in order to calculate ex post the impact of demand response on electricity spot prices and load. As a result, we find that a 25% adoption rate of the available potential for load shifting could have decreased nationwide electricity expenses by approximately €500 million, or 6%, in 2014. At the same time, we observe that the price volatility rises under this scheme and thus impairs non-flexible electricity customers. This observation entails significant implications in terms of designing effective policies. [ABSTRACT FROM AUTHOR]

Australian Electricity Market has experienced high price volatility since the deregulation in early 1990s. In this exploratory and preliminary analysis of 2010 data from South Australian electricity market we identify and exhibit a number of phenomena which, arguably, contribute to (A) high cost of electricity supply to consumers and (B) volatility in spot prices. These phenomena include: (i) Distinct bidding patterns of some generators occurring in trading intervals corresponding to periods of low, medium and high spot prices, (ii) Low correlation between electricity demand and spot prices on days when spot price spikes are observed, (iii) Failure of the lottery model and associated Markowitz-type optimisation approaches to adequately explain the shifting structure of generators' bids and (iv) Unexpectedly high contribution to the consumers costs and risks from the relatively small number of trading intervals where spot price spikes were observed. [ABSTRACT FROM AUTHOR]

Abstract: This paper presents the details of a theoretical study of the economic advantages of using large-scale energy storage to complement a wind farm in a base-load dominated electricity grid. A computer model is developed which simulates the operation of several energy storage systems when used with the 190-MW Portland Wind Farm (PWF) located in Portland, Victoria, Australia. A variety of operating strategies are compared with the results of a dynamic programming model which finds the maximum possible revenue which a given system can generate for a set of input conditions. Three energy storage systems are modelled and costed: Pumped Seawater Hydro Storage (PSHS), Compressed Air Energy Storage (CAES), and Thermal Energy Storage (TES). It is found that CAES is the most profitable storage medium, requiring a capital expenditure of A$140M and generating a rate of return (ROR) of 15.4%. The ROR for PSHS was 9.6%, and for TES was 8.0%. Therefore, a significant investment opportunity exists for the installation of an energy storage system in this wind farm. It is therefore highly recommended that CAES is investigated further with the aim of introducing large-scale energy storage to PWF and other similar wind turbine installations. [Copyright &y& Elsevier]

High levels of variable solar and wind must be balanced with alternative generation, storage, transmission and demand management to ensure continuous availability of electricity. The cost of balancing has been disputed, which militates against mass deployment of solar and wind to mitigate climate change. Australia is installing solar and wind 10 times faster than the global per capita average which constitutes a natural experiment in the real cost of balancing. The National Electricity Market (NEM) and the state of South Australia have reached combined solar and wind energy penetrations of 24% and 70% respectively and are tracking towards 40% and 100% respectively in 2024–25. Investment in new balancing infrastructure is predominantly in pumped hydro (without new dams on rivers), batteries and transmission. The current (2021) and market futures (2024) spot price for electricity in the NEM and South Australia is about AUD$40 (∼US$30) per Megawatt-hour. This suggests that the balancing cost of high levels of solar and wind is modest. • Australia constitutes a natural experiment in balancing solar/wind. • The Australian Electricity Market is tracking towards 50% renewables in 2024. • South Australia reached 70% solar/wind and is tracking towards 100% in 2024. • The market futures (2024) spot price for electricity is US$30 per Megawatt-hour. • New balancing infrastructure is off-river pumped hydro (no new dams) and batteries. [ABSTRACT FROM AUTHOR]