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Bergen, M., & Munoz, F. D. (2018). Quantifying the effects of uncertain climate and environmental policies on investments and carbon emissions: A case study of Chile. Energy Econ., 75, 261–273.
Abstract: In this article we quantify the effect of uncertainty of climate and environmental policies on transmission and generation investments, as well as on CO2 emissions in Chile. We use a two-stage stochastic planning model with recourse or corrective investment options to find optimal portfolios of infrastructure both under perfect information and uncertainty. Under a series of assumptions, this model is equivalent to the equilibrium of a much more complicated bi-level market model, where a transmission planner chooses investments first and generation firms invest afterwards. We find that optimal investment strategies present important differences depending on the policy scenario. By changing our assumption of how agents will react to this uncertainty we compute bounds on the cost that this uncertainty imposes on the system, which we estimate ranges between 3.2% and 5.7% of the minimum expected system cost of $57.6B depending on whether agents will consider or not uncertainty when choosing investments. We also find that, if agents choose investments using a stochastic planning model, uncertain climate policies can result in nearly 18% more CO2 emissions than the equilibrium levels observed under perfect information. Our results highlight the importance of credible and stable long-term regulations for investors in the electric power industry if the goal is to achieve climate and environmental targets in the most cost-effective manner and to minimize the risk of asset stranding. (C) 2018 Elsevier B.V. All rights reserved.
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Fernandez, M., Munoz, F. D., & Moreno, R. (2020). Analysis of imperfect competition in natural gas supply contracts for electric power generation: A closed-loop approach. Energy Econ., 87, 15 pp.
Abstract: The supply of natural gas is generally based on contracts that are signed prior to the use of this fuel for power generation. Scarcity of natural gas in systems where a share of electricity demand is supplied with gas turbines does not necessarily imply demand rationing, because most gas turbines can still operate with diesel when natural gas is not available. However, scarcity conditions can lead to electricity price spikes, with welfare effects for consumers and generation firms. We develop a closed-loop equilibrium model to evaluate if generation firms have incentives to contract or import the socially-optimal volumes of natural gas to generate electricity. We consider a perfectly-competitive electricity market, where all firms act as price-takers in the short term, but assume that only a small number of firms own gas turbines and procure natural gas from, for instance, foreign suppliers in liquefied form. We illustrate an application of our model using a network reduction of the electric power system in Chile, considering two strategic firms that make annual decisions about natural gas imports in discrete quantities. We also assume that strategic firms compete in the electricity market with a set of competitive firms do not make strategic decisions about natural gas imports (i.e., a competitive fringe). Our results indicate that strategic firms could have incentives to sign natural gas contracts for volumes that are much lower than the socially-optimal ones, which leads to supernormal profits for these firms in the electricity market. Yet, this effect is rather sensitive to the price of natural gas. A high price of natural gas eliminates the incentives of generation firms to exercise market power through natural gas contracts. (C) 2020 Elsevier B.V. All rights reserved.
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Inzunza, A., Munoz, F. D., & Moreno, R. (2021). Measuring the effects of environmental policies on electricity markets risk. Energy Econ., 102, 105470.
Abstract: This paper studies how environmental policies, such as renewable portfolio standards (RPS) and carbon taxes, might contribute to reducing risk exposure in the electricity generation sector. We illustrate this effect by first computing long-term market equilibria of the Chilean generation sector for the year 2035 using a risk-averse planning model, considering uncertainty of hydrological scenarios and fossil fuel prices as well as distinct levels of risk aversion, but assuming no environmental policies in place. We then compare these risk-averse equilibria to generation portfolios obtained by imposing several levels of RPS and carbon taxes in a market with risk-neutral firms, separately. Our results show that the implementation of both policies can provide incentives for investments in portfolios of generation technologies that limit the risk exposure of the system, particularly when high levels of RPS (35%) or high carbon taxes (35 $/tonCO2) are applied. However, we find that in the case of a hydrothermal system, the resulting market equilibria under RPS policies yield expected generation cost and risk levels (i.e. standard deviation of costs) that are more similar to the efficient portfolios determined using a risk-averse planning model than the ones we find under the carbon tax.
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Munoz, F. D., Pumarino, B. J., & Salas, I. A. (2017). Aiming low and achieving it: A long-term analysis of a renewable policy in Chile. Energy Econ., 65, 304–314.
Abstract: We use an Integrated Resource Planning model to assess the costs of meeting a 70% renewables target by 2050 in Chile. This model is equivalent to a long-term equilibrium in electricity and renewable energy certificate (REC) markets under perfect competition. We consider different scenarios of demand growth, resource eligibility (e.g., large hydropower), and transmission system configuration. Our numerical results indicate that the sole characteristics of the available renewable resources in the country and reductions in technology costs will provide sufficient economic incentives for private investors to supply a fraction of renewables larger than 70% for a broad range of scenarios, meaning that the proposed target will likely remain a symbolic government effort. Increasing transmission capacity between the northern and central interconnected systems could reduce total system cost by $400 million per year and increase the equilibrium share of non conventional renewable energy (NCRE) in the system from 45% to 52%, without the need for any additional policy incentive. Surprisingly, imposing a 70% of NCRE by 2050 results in a REC price lower than the noncompliance fine used for the current target of 20% of NCRE by 2025, the latter of which represents the country's maximum willingness to pay for the attributes of electricity supplied from NCRE resources. (C) 2017 Elsevier B.V. All rights reserved.
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Munoz, F. D., van der Weijde, A. H., Hobbs, B. F., & Watson, J. P. (2017). Does risk aversion affect transmission and generation planning? A Western North America case study. Energy Econ., 64, 213–225.
Abstract: We investigate the effects of risk aversion on optimal transmission and generation expansion planning in a competitive and complete market. To do so, we formulate a stochastic model that minimizes a weighted average of expected transmission and generation costs and their conditional value at risk (CVaR). We show that the solution of this optimization problem is equivalent to the solution of a perfectly competitive risk averse Stackelberg equilibrium, in which a risk-averse transmission planner maximizes welfare after which risk-averse generators maximize profits. This model is then applied to a 240-bus representation of the Western Electricity Coordinating Council, in which we examine the impact of risk aversion on levels and spatial patterns of generation and transmission investment. Although the impact of risk aversion remains small at an aggregate level, state-level impacts on generation and transmission investment can be significant, which emphasizes the importance of explicit consideration of risk aversion in planning models. (C) 2017 Elsevier B.V. All rights reserved.
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Villalobos, C., Negrete-Pincetic, M., Figueroa, N., Lorca, A., & Olivares, D. (2021). The impact of short-term pricing on flexible generation investments in electricity markets. Energy Econ., 98, 105213.
Abstract: The massive growth in the integration of variable renewable energy sources is producing several challenges in the operation of power systems and its associated markets. In this context, flexibility has become a critical attribute to allow the system to react to changes in generation or demand levels. Thus, it is critical for market signals at both short and long term scales to include flexibility features, to align agents' incentives with systemic flexibility requirements. In this paper, different pricing schemes for short-term markets are studied, based on various relaxations of the unit commitment problem, including convex-hull approximations, with the aim of representing operational flexibility requirements in a more explicit way. Extensive simulations illustrate the performance of the proposed schemes, as compared to conventional ones, in terms of the capability of the system to properly incentivize flexibility attributes, resulting in better agents' cost recovery and more variable renewable energy utilization. The results show that short-term pricing schemes considered improve the long-term signals for flexible investments but additional changes to market design are still required. Thus, there is a need to revisit historical practices for pricing rules by incorporating additional flexibility-related attributes into them. Several alternatives are discussed and policy recommendations based on these considerations are provided.
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