A Federal Renewable Electricity Requirement

Rising energy prices and climate change have changed both the economics and politics of electricity. In response, over half the states have enacted "renewable portfolio standards" (RPS) that require utilities to obtain some power from "renewable" generation resources rather than carbon emitting fossil fuels. Reports of state-level success have brought proposals for a national standard. Like several predecessor Congresses, however, the most recent one failed to pass RPS legislation. Before trying one more time, legislators should ask why they favor a policy so politically correct and so economically suspect. Support for a national program largely stems from misleading claims about state-level successes, misunderstandings about how renewables interact with other environmental regulation, and misinformation about the actual benefits renewables create. State RPS programs are largely in disarray, and even the apparently successful ones have had little impact. California's supposedly aggressive program has left it with the same percentage of renewable power as in 1998, and Texas's seemingly impressive wind turbine investments produce only two percent of its electricity. The public may envision solar collectors but wind accounts for almost all of the growth in renewable power, and it largely survives on favorable tax treatment. Wind's intermittency reduces its efficacy in carbon control because it requires extra conventional generation reserves. Computer-generated predictions about a national RPS are generally unreliable, but they show that with or without one the great majority of generation investments for the next several decades will be fossil-fueled. Even without the technological and environmental shortcomings of renewables, the case for a national RPS is economically flawed. Emissions policies are moving toward efficient market-based trading systems and more rational setting of standards. A national RPS clashes with principles of efficient environmental policy because it is a technological requirement that applies to a single industry. Arguments that a national RPS will create jobs, mitigate energy price risks, improve national security and make the United Sates more competitive internationally are in the main restatements of elementary economic fallacies. It is hard to imagine a program that delivers as little in theory as a national RPS, and the experiences of the states indicate that it delivers equally little in practice

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

Financial Risks of Investments in Coal

Analyzes the regulatory, commodity, and construction risks of investing in coal mining and coal-fired power plants. Examines industry analysts' consensus on viable alternatives to coal, including natural gas, solar, wind, and energy efficiency

Melting-pots and salad bowls: the current debate on electricity market design for RES integration

This paper discusses a series of issues regarding the economic integration of intermittent renewables into European electricity markets. This debate has gained in importance following the large-scale deployment of wind farms and photovoltaic panels. As intermittent renewables constitute a significant share of the installed generation capacity, they cannot be kept isolated from the electricity markets. We argue that RES integration is first and foremost an issue of economic efficiency, and we review the main debates and frameworks that have emerged in the literature. we first consider to what extent intermittent resources should be treated the same way as dispatchable resources. we then analyse the different tools that have been proposed to ensure the required flexibility will be delivered: finer temporal granularity and new price boundaries, integration of a complex set of balancing markets, and introduction of tailor–made capacity remuneration mechanisms. Finally we introduce the topic of space redistribution, confronting crosscontinental markets integration to the emergence of a mosaic of local markets

Capacity Market Design: Motivation and Challenges in Alberta’s Electricity Market

Alberta’s electricity market is currently undergoing a period of substantial transition. The province should proceed with caution as it switches from an energy-only electricity market to a capacity market by 2021. Many other jurisdictions have already made the changeover and Alberta can learn from their experiences in order to avoid common mistakes and pitfalls that can arise with the deployment of a capacity market.There were growing concerns that the existing electricity market structure would not attract sufficient investment from conventional generation (e.g., natural gas) due to the increased penetration of zero marginal cost renewable generation. As a result, the Alberta government has chosen to transition to a capacity market. For consumers, a capacity market aims to ensure there is sufficient investment in new generation capacity to “keep the lights on” and reduce price swings in the wholesale market. The capacity market will also help the province meet its goals for attracting investors and transitioning away from its dependence on coal-fired electricity generation.However, a switchover is not as simple as it sounds.In an energy-only market, firms are paid solely based on the provision of electricity in hourly wholesale markets. In capacity markets, electricity-generating firms are also paid for providing generation capacity, reflecting the potential to provide electricity at some point in the future. While capacity markets can help ensure there is a reliable supply of electricity, there are several challenges in the implementation of capacity markets. This paper discusses the motivation for the adoption of capacity markets, highlights challenges regulators face when implementing this market design in the context of Alberta, and summarizes the key trade-offs associated with energy-only versus capacity market designs.Relative to an energy-only market, a capacity market is more complex and requires that regulators specify numerous parameters that are essential to the functioning of the market. An essential, but often controversial component is the formulation of the capacity demand curve. A capacity demand curve for Alberta has to be carefully designed to deal with uncertainties in demand growth, given that Alberta’s electricity demand is closely interconnected with the ups and downs of global crude oil prices.Consideration must be given to the perspective of outside investors who – as in any area of economic interest – are wary about uncertainty. Political and regulatory uncertainty can undermine the success of a capacity market. This potential for investor hesitancy could result in incumbent firms, familiar with investing in Alberta, seizing a larger share of the market in an already historically concentrated environment. It is critical that policymakers establish a clear and well-defined trajectory for the future of Alberta’s electricity market design as a whole, not just its capacity market.The capacity market is not a panacea for the potential downfalls of an energy-only market. There are trade-offs associated with both energy-only and capacity market designs. Energy-only markets are arguably more economically efficient with cleaner price signals. However, with political constraints on electricity price-spikes and the expansion of renewables, there is more uncertainty in an energy-only market’s ability to promote investment. A capacity market provides more certainty in terms of generation resource adequacy, but at a potentially higher cost. Despite these tradeoffs, capacity markets are unambiguously more complex. This places a heavy burden on regulators to carefully and correctly set critical capacity market parameters that can have substantive impacts on prices and the associated economic signals

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

System Costs of Variable Renewable Energy in the European Union. Bruges European Economic Policy (BEEP) Briefings 37/2015

To shift to a low-carbon economy, the EU has been encouraging the deployment of variable renewable energy sources (VRE). However, VRE lack of competitiveness and their technical specificities have substantially raised the cost of the transition. Economic evaluations show that VRE life-cycle costs of electricity generation are still today higher than those of conventional thermal power plants. Member States have consequently adopted dedicated policies to support them. In addition, Ueckerdt et al. (2013) show that when integrated to the power system, VRE induce supplementary not-accounted-for costs. This paper first exposes the rationale of EU renewables goals, the EU targets and current deployment. It then explains why the LCOE metric is not appropriate to compute VRE costs by describing integration costs, their magnitude and their implications. Finally, it analyses the consequences for the power system and policy options. The paper shows that the EU has greatly underestimated VRE direct and indirect costs and that policymakers have failed to take into account the burden caused by renewable energy and the return of State support policies. Indeed, induced market distortions have been shattering the whole power system and have undermined competition in the Internal Energy Market. EU policymakers can nonetheless take full account of this negative trend and reverse it by relying on competition rules, setting-up a framework to collect robust EU-wide data, redesigning the architecture of the electricity system and relying on EU regulators