Vulnerable households and fuel poverty: policy targeting efficiency in Australia’s National Electricity Market

When Australia established its National Electricity Market (NEM) during the 1990s, reforms were focused on maximising economic efficiency. Little thought was given to distributional outcomes. However, by the 2010s sluggish growth in household incomes, sharp rises in electricity prices and material increases in quantities consumed through surging uptake rates of air-conditioning units led to the possibility of (hot climate) fuel poverty. In the NEM’s Queensland region, longstanding customer hardship policy pre-dated the NEM. With the benefit of hindsight, the policy was poorly configured as it focused exclusively on the aged population and was delivered by way of fixed payment. Low income households in the family formation cohort were excluded from the policy despite obvious need. In this article, Queensland’s longstanding customer hardship policy is refined using pre-existing (meanstested) welfare mechanisms in order to target low income households including families, and the payment structure is altered from fixed ($ pa) to variable (% of the bill) while holding the budget constraint constant. Changes to policy targeting produce material improvements in horizontal and vertical efficiency while changes to payment structure further enhance vertical performance, with the incidence and depth of residual fuel poverty reduced

Rooftop Solar PV and the Peak Load Problem in the NEM’s Queensland Region

Over the period 2016-2021 Australia’s National Electricity Market (NEM) experienced an investment supercycle comprising 24,000MW of renewables. One of the more intriguing aspects of the supercycle was a partial shift of investment decision-making from utility boardrooms to family kitchen tables – rooftop solar PV comprised 8,000MW of the 24,000MW total. In NEM regions such as Queensland, take-up rates have now reached ~40% of households, currently the highest take-up rate in the world. At the household level there is a distinct mismatch between peak demand and solar PV output, which tends to suggest any peak load problem will be exacerbated. When the contribution of rooftop solar PV is abstracted to the power system level these results reverse. The partial equilibrium framework of Boiteux (1949), Turvey (1964) and Berrie (1967) has historically been used to define the optimal plant mix to satisfy demand growth. In this article, their partial equilibrium framework is used to define conventional plant ‘dis-investment’ in the presence of rising rooftop solar PV and utility-scale renewables in an energy-only market setting. Queensland’s 4400MW of rooftop solar displaces 1000MW of conventional generation in equilibrium, 500MW of peaking plant and somewhat counterintuitively, 500MW of baseload coal plant – falling ‘minimum system demand’ being a driving factor. The NEM’s energyonly market and its $15,000/MWh price cap proves tractable through to a 50% renewable market share, but relies critically on frictionless coal plant divestment and bounded negative price offers

Merchant renewables and the valuation of peaking plant in energy-only markets

Merchant renewables are a new asset class. With historically high cost structures and low wholesale prices associated with merit order effects, continuity of entry has been reliant on Renewable Portfolio Standards or other policy initiatives such as government-initiated Contracts-for-Differences. But in Australia’s National Electricity Market, sharply falling costs of renewables and volatile wholesale market conditions from coal plant exits has led to a surprising number of merchant intermittent renewable investments. Adding to the merchant renewable fleet are older wind plants whose inaugural long-dated PPAs recently matured. Rolling over PPAs is possible, but not necessarily optimal. In this article, a merchant gas turbine, merchant wind, and an integrated portfolio comprising both plants are valued in the NEM’s South Australian region. Asset valuations reveal surprising results. The modelling sequence shows stand-alone gas turbine valuation metrics suffer from modest levels of missing money, that merchant wind can commit to some level of forward (fixed volume) swap contracts in-spite of intermittent production, but the combined portfolio tightens overall valuation metrics significantly. Above all, the combined portfolio is financially tractable, overcoming the missing money for a gas turbine plant undertaking peaking duties. In a NEM region where intermittent renewable market share exceeds 50%, this suggests the energy-only, real-time gross pool design may yet be deemed suitable vis-à-vis meeting environmental objectives and Resource Adequacy

Merchant utilities and boundaries of the firm: vertical integration in energy-only markets

Resource adequacy in energy-only markets is of continual interest to policymakers due to risks posed by incomplete markets. In Australia, resource adequacy has historically been navigated via energy retailer investment commitments in peaking plant capacity. This in turn has been driven by the National Electricity Market’s (NEM) very high Market Price Cap (AUD $15,000/MWh). The NEM is now rapidly transitioning with sharply rising levels of utility-scale variable renewable energy, world-record uptake rates of rooftop solar PV by households, and ongoing coal plant closures. Ironically however, investment commitments in peaking plant capacity by the NEM’s energy retailers appears to have stalled. This raises the question as to whether the energy retailer model of investing in peaking plant, a pattern which has dominated energy-only markets, has somehow broken down. If so it raises questions of the suitability of the energy-only market design. In this article, peaking plant dynamics are tested using historic NEM data. Specifically, investments in a stand-alone generator, a stand-alone energy retailer and a merged entity are simulated over 16 years of trade under both project finance and corporate financing structures with a focus on credit metrics. Results reveal the canonical merchant peaking plant remains too risky as a stand-alone project financing in an energy-only market. But energy retailer incentives to commit to on-balance sheet financed peaking plant remains, with transaction cost synergies of 13% and investment grade credit quality being contingent on integration

Renewable Energy Zones in Australia’s National Electricity Market

Australia’s National Electricity Market operates in one of the world’s longest and stringiest transmission networks. The 2016-2020 investment supercycle, in which 13,000 MW of renewables were committed, is slowly revealing the limits of network hosting capacity for renewable plant. In this article, side-effects arising from the supercycle are analysed. The majority sources of renewable investment failure relate to deteriorating system strength, viz. associated connection lags, remediation and curtailment costs. Although a multi-zonal market, the NEMs locational investment signals remain visibly strong. A change to nodal arrangements may refine dispatch efficiency but the bigger policy problem is rapidly diminishing network hosting capacity for new renewables, imperfect regulation and regulatory lag associated with augmentation. Markets participants seek to move faster than regulatory frameworks allow. Renewable Energy Zones (REZ) are examined through both i). a consumer-funded regulatory model and ii). a renewable generator-funded market model. A ‘super-sized concessional mezzanine’ facility is presented as a critical element of REZ capital funding. It forms the means by which to optimise market-based REZ transmission augmentation and moderate sponsor risks of transient underutilisation

Price discrimination and the modes of failure in deregulated retail electricity markets

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

Missing money, missing policy and Resource Adequacy in Australia’s National Electricity Market

From 2012-2017 more than 5000MW of coal plant exited Australia’s National Electricity Market (NEM). The average plant exit notice period was 5.2 months. Exit at scale peaked just as imbalances in the market for natural gas emerged. Compounding matters were Variable Renewable Energy (VRE) plant entry lags due to policy discontinuity in prior periods. By 2016/17, the culmination of coal plant exit, gas market imbalances and VRE entry lags produced more than 20 Lack of Reserve events across the NEM, three blackouts including a black system event in the South Australian region. Spot and forward electricity prices rose to record levels, viz. $90-$130/MWh compared to an historic average of $42.50. In this article, the lead-up to these abnormal trading conditions are traced back to policy decisions a decade earlier in the markets for electricity, natural gas and renewable energy. Lessons for other energy markets undergoing transformation include i). transparency over lumpy plant exit decisions, ii). climate change policy stability, and iii). clear policy limits to gas export capacity vis-à-vis domestic supply

Is the NEM broken? Policy discontinuity and the 2017-2020 investment megacycle

The recent history of Australia’s National Electricity Market (NEM) from 2012-2017 has been problematic with sudden coal plant closures, a tight domestic gas market and sharply rising electricity prices. The supply-side response that followed from 2017-2

Renewable entry costs, project finance and the role of revenue quality in Australia’s National Electricity Market

The cost of capital is among the most important variables determining the feasibility of investment in renewable energy projects. In Australia’s National Electricity Market, the ability of new variable renewable energy (VRE) plant to arrange requisite project finance at favourable rates largely determines project viability. Such financings are typically only achieved when VRE projects are underpinned by long-dated Power Purchase Agreements (PPA), under which prices are guaranteed by an investment-grade counterparty. In this article, we quantify the relationship between PPAs, counterparty credit quality and the cost of capital in the context of Australia’s energy-only wholesale market under conditions of policy uncertainty. Our analysis benefits from the application of confidential data from Australia’s capital markets. We find higher credit quality drives higher gearing, and somewhat counterintuitively, lower expected returns to equity. This in turn produces a lower cost of capital and by implication, higher post-construction VRE plant valuations – an outcome seemingly at odds with Modigliani and Miller’s classic 1958 article. In practice, risk has been repackaged and reallocated

The Levelised Cost of Frequency Control Ancillary Services in Australia’s National Electricity Market

Over the period 2016-2021 Australia’s National Electricity Market (NEM) experienced an investment supercycle, with 16,000MW of new utility-scale variable renewable plant commitments (and an additional 8,000MW of rooftop solar PV) in a power system with a ratcheted peak demand of 35,000MW. The sharp rise in intermittent asynchronous resources and the disorderly loss of 5,000MW of synchronous coal-fired generation plant placed strains on system security – most visibly represented by the rapid deterioration in the distribution of the power systems’ (50Hz) Frequency. This in turn necessitated material changes to the NEM’s suite of Frequency Control Ancillary Service (FCAS) markets. Utility-scale batteries are ideally suited for FCAS duties, but unlike the wholesale electricity market, there is no forward price curve for Frequency Control Ancillary Services, 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 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