Energy-only Electricity Market Research Articles

Firming merchant renewable generators in Australia’s National Electricity Market

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.

Effect of Loss of Load Probability Distribution on Operating Reserve Demand Curve Performance in Energy-Only Electricity Market

In energy-only electricity markets, the operational reserve demand curve is a scarcity pricing mechanism adopted to address the shortage of reserves and incentivize the generators. It is constructed based on the assumption of the normality of loss of load probability, which is estimated from reserve error data. In this Letter, the historical record of reserve error is collected and analyzed to test the assumption and find the fittest probability distribution. It is found that the normal distribution is generally not as good as other distributions like log-logistic, general gamma, and Weibull. Using a dynamic simulation framework, the installed reserve margins with different distributions are evaluated over a fifty-year period, demonstrating that the choice of distribution could significantly impact the subsequent pricing calculations and therefore the reserve margin in an energy-only electricity market. This work is of potential importance and immediate relevance to system reliability and resource adequacy in power systems.

Stochastic electricity dispatch: A challenge for market design

We consider an energy-only electricity market where some generation and/or load is uncertain, and where there are flexibility costs, i.e. some conventional power plants have to be scheduled well before real time in order to participate in the dispatch, while for others, additional cost incurs if generation plans have to be adjusted close to real time.In practice, electricity markets are often organized with sequential market clearing, and in this paper, we consider two sequential markets, for instance representing a day-ahead and a real-time market. We compare the outcomes of 1) a stochastic market clearing model, i.e. an integrated model that takes into account both markets and the uncertainty, to 2) a myopic market clearing model, where the first market is cleared based only on given bids, and not taking into account neither the uncertainty nor the bids to the second market.Compared to previous literature, our main contribution is that we compare the two different market models with respect to both efficiency and allocation of surplus, and thus the incentives they imply for the market participants. We discuss what information is needed in market agent bids and how that information can be manipulated.While the stochastic market clearing gives a solution with a higher expected social welfare, it poses several challenges for market design. The stochastic dispatch may lead to a dispatch where the day-ahead prices deviate from the bid curves to the first market. This can lead to incentives for self-scheduling, in that it may require market participants to accept prices that deviate from the marginal costs or benefits corresponding to the scheduled quantities. Our analysis shows that the intermittent producer has an incentive to deviate from the system optimal plan in both the myopic and stochastic model, and this incentive is particularly strong under the myopic model. We also discuss how the expected social welfare of the market outcome under stochastic market clearing depends on the quality of the information that the system operator will base the market clearing on. In particular, we show that an intermittent producer may have an incentive to misreport the probability distribution for its generation.

Vertical integration in energy-only electricity markets

Australia’s electricity market blueprint involved the vertical and horizontal restructuring of State Electricity Commissions and the creation of multiple merchant generators and retailers. State governments progressively exited the merchant market by privatising their retailers and generators but the combination of an energy-only market design and the exit of government from the merchant market introduced an entirely new risk—the presence of investment-grade credit. Investment-grade credit is an essential precondition for meeting physical and systemic energy market security objectives and maximising welfare. In this article we model a Pure Play Retailer, a Pure Play Generator, and a Vertically Integrated Firm (‘Gen-tailer’) in Australia’s energy-only electricity market using market data over a 10 year period to 2013/14. We find Pure Play businesses are unable to sustain investment-grade credit metrics whereas the Vertical Firm does in all years, despite the wild commodity price cycle contained within our data set. The starting premise of industrial organisation is that vertical arrangements are an organisational form of last resort. Our findings explain why vertical reintegration of retail and generation became an enduring trend from the mid-2000s.

Estimating the value of electricity storage in an energy-only wholesale market

Price volatility and increasing renewable energy generation have raised interest in the potential opportunities for storage technologies in energy-only electricity markets. In this paper we explore the value of a price-taking storage device in such a market, the National Electricity Market (NEM) in Australia. Our analysis suggests that under optimal operation, there is little value in having more than six hours of storage in this market. However, an inability to perfectly forecast wholesale prices, particularly extreme price spikes, may warrant some additional storage. We found that storage devices effectively provide a similar service to peak generators and are similarly dependent on and exposed to extreme price events, with revenue for a merchant generator highly skewed to a few days of the year. As a consequence of this finding, and in contrast to previous studies, the value of storage was found to be relatively insensitive to the round trip efficiency. We also found that the variability of revenue and exposure to extreme prices could be reduced using common hedging strategies, such as those currently used by peak generators. We present a case study that demonstrates storage technologies using such strategies may have a competitive advantage over other peaking generators in the NEM, due to the ability to earn revenue outside of extreme peak events. Similar to traditional peak generators, a main driver for storage options in an energy-only electricity market is extreme prices, which in turn is dependent on capacity requirements. However storage technologies can receive additional revenue streams, which may be improved by increased integration of renewable energy.

Assessing the Impacts of Capacity Mechanisms on Generation Adequacy With Dynamic Simulations

There have been many debates over whether the energy-only electricity market will be able to provide a reasonable investment signal. So far, many diverse designs of capacity mechanisms have been proposed in relation to the adequacy problem. Researchers have conducted many qualitative studies of capacity mechanisms, but quantitative studies have largely been ignored. The framework for examining the impacts of market designs on generation adequacy considering various generation technologies have not been maturely developed. This paper focuses on developing this framework and finding out how effective capacity mechanisms are in different market conditions. To cover investment under uncertainty, we will introduce different utility functions representing risk attitudes and apply the expected utility theory to the investment decision. Finally, we will examine the investment decision sensitivity of the risk components such as the risk-attitude, the error of forecast peak load, and the forced outage rate and evaluate the performance of three market designs with dynamic simulations: an energy-only market, a capacity payment model, and a capacity demand curve model.

A Price-Based Approach to Generation Investment Planning in Electricity Markets

A generation planning framework is developed for a competitive, energy-only electricity market. The framework developed combines decentralized merchant investment plans stemming from market signals and technological preferences, with centralized resource planning concepts to decide optimal time-ordered investment decisions. The investment decisions maximize the new entrants' net surpluses and minimize the consumer interruption cost, accounting for many uncertain variables and technical details. The optimal plan given by the main centralized framework represents the system planner's solution derived from the set of decentralized plans. An illustrative case study is given in the paper, applying the proposed framework to the Queensland region of the National Electricity Market of Australia.