• Energy Research

Deregulated energy markets were founded on the Merchant Power Producer, a stand-alone generator that sold its production to the spot and short-term forward markets, underpinned by long-dated project finance. The initial enthusiasm that existed for investment in existing and new merchant power plant capacity shortly after power system deregulation has progressively dissipated, following an excess entry result. In this article, we demonstrate why this has become a global trend. Using debt-sizing parameters typically used by project banks, we model a benchmark plant, then re-simulate its performance using live energy market price data and find that such financings are no longer feasible in the absence of long-term Power Purchase Agreements.

Abstract The recent history of Australia's National Electricity Market (NEM) from 2012 to 2016 was characterised by coal plant closures, tightening domestic gas market and sharply rising electricity prices. The supply-side response that followed from 2016 to 2021 could only be described as an investment supercycle – 16,000 MW of plant commitments comprising $26.5 billion across 135 (mostly) Variable Renewable Energy (VRE) projects. We examine causes and the effects of the supercycle. Underlying causes included disorderly plant exit and climate change policy discontinuity in prior periods. Adverse effects in the post-entry environment included connection lags, system strength-related VRE production constraints, ex-post remediation costs, system frequency careering outside normal operating bands, and rising system operator interventions. Market institutions were caught out and subsequently focused on market re-design and resource adequacy reforms. Yet analysis contained in this article reveals the NEM's most pressing problems relate to real-time power system security, not fundamental market design or resource adequacy issues. Resolution requires the establishment of ‘missing markets’ (i.e. fast frequency, additional operating reserves, ramping, system strength and inertia), and urgently, to restore power system resilience. Key insights for other jurisdictions are climate change policy continuity and policies which serve to defuse the risk of disorderly coal plant exit.

On Australia’s east coast over the period 2013–2016, we forecast that aggregate demand for natural gas will increase three-fold, from 700 PJ to 2100 PJ per annum, while our forecast of system coincident peak demand increases 2.4 times, from 2790 TJ to 6690 TJ per day. This extraordinary growth is being driven by the development of three Liquefied Natural Gas plants at Gladstone, Queensland. In this article, we present our dynamic partial equilibrium model of the interconnected gas system and produce forecasts with daily resolution. We find that absent additional supply-side development, unserved load events will remain more than a theoretical possibility in the short-term due to inter-temporal spatial constraints. In the long-term, with appropriate policy settings in place, additional supplies will be brought to market, albeit at higher than historical prices.

Abstract Energy-only markets have an inherently unstable equilibrium, even under ideal conditions, because participants are unable to optimise VoLL events. The addition of intermittent renewable generation is thought to make conditions harder. In this article, optimal VoLL events in an islanded NEM region is modelled by substituting high price caps for Boiteux capacity charges, then analysing the impact of adding progressively more Variable Renewable Energy (VRE) – up to 35% market share. Spot market conditions prove stable and tractable provided thermal plant exit and adjust perfectly. But VRE asset allocation is important; absent highly elastic demand or ultra-low cost storage, solar PV market share has economic limits because the technology rapidly cannibalises itself. Furthermore, as VRE rises in imperfectly interconnected regions, a tipping point appears to exist where hedge markets enter an unstable zone through shortages of ‘asset-backed’ firm intra-regional swaps and caps. Government-initiated CfDs for VRE need to be designed carefully to ensure any instability is not exacerbated by extracting contracts from an already shortening hedge market.

Few decisions made by firms receive more consistent annual attention by the board of directors than dividend policy. For 60 years, financial economists have focused on deriving an optimal dividend policy. Energy utilities have been through a decade-long harvest period, but are now re-entering an above-trend investment growth phase. Utility dividend policies therefore require careful re-evaluation.

In Australia’s National Electricity Market (NEM), 170+ renewable and battery storage projects reached financial close from 2016-2022, totalling 24GW and $46 billion. With an investment supercycle, not all projects arrive smoothly. Some investors experienced entry frictions from system strength constraints, adverse movements in Marginal Loss Factors and network congestion. Whether these outcomes – which impacted ~20% of entrants – represented workable results in a properly functioning market due to investment error, or arose because of market design defects requiring policy attention, is an open question. An issue that NEM policy advisors are seeking to reform is the non-firm, open access regime. Policy focus is warranted. The ratio of maximum to average wind output is ~3x while solar PV is 4x. Consequently as renewable market share increases, rising levels of curtailment are predictable through excess generation and negative price events, network congestion, or both. But care must be taken with access reform because well-intended ‘intuitive policy prescriptions’ can produce the exact opposite effects by constraining REZ asset productivity, compounding complexity and slow renewable entry rates – the critical variable being the difference between average and marginal curtailment rates. Malalignment between access policy and over-the-counter forward market conventions may distort entry, raise consumer prices and harm welfare.

In Australia, as with Great Britain, governments have shown rising concern with the health of competitive residential electricity markets. A core concern is the practice of price discrimination and the rising dispersion of prices. The State of Queensland implemented Full Retail Contestability in 2007, but held a regulated price cap in place until 2016, when it finally deregulated its residential electricity market. Almost simultaneously, the two jurisdictions that pioneered retail price deregulation, Great Britain and Victoria, were questioning their prior policy decision. Queensland makes for a fascinating case study because Southeast Queensland comprises a fully deregulated retail market while Regional Queensland is a regulated monopoly – with common input costs across both zones. Consequently, a regulated monopoly with a uniform tariff and 640,000 customers forms a very large control group, which can be directly compared to the competitive market of more than 1.3 million customers – making such analysis globally unique. Analysis of Queensland market conditions concludes the policy is welfare enhancing. To be clear, rising electricity prices are a problem, but price discrimination is not. The deregulated competitive market is, perhaps unsurprisingly, better at regulating the overall average tariff and consumer welfare has been enhanced by $184 million per annum – with some consumer segments very materially better off. However, certain modes of failure remain, viz. an inter-consumer misallocation problem and lack of transparency vis-à-vis the anchoring of discounts – known as the “discounts off what?” problem. Resolving the inter-consumer misallocation problem is relatively straight forward via ensuring energy retailers (voluntarily) move vulnerable customers onto a Benchmark-equivalent or suitably discounted tariff. Due to the non-linearity of tariffs and the rising mix of discrete metered loads, the latter can be best solved by producing a weighted average of Standing Offers, and using this as the benchmark.

Feed-in Tariffs (FiT) for residential photovoltaic solar technologies are available in most Australian jurisdictions. Financial incentives under FiT are in addition to those provided by the Small-Scale Renewable Energy Scheme which forms part of the national 20% Renewable Energy Target. Little attention has been paid to the welfare impacts of FiT on retail electricity prices and social policy objectives. Our analysis indicates that current FiT are a regressive form of taxation. By providing estimates of household impact by income groupings, we conclude that wealthier households are beneficiaries and the effective taxation rate for low income households is three times higher than that paid by the wealthiest households.