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Go, R. S., Munoz, F. D., & Watson, J. P. (2016). Assessing the economic value of co-optimized grid-scale energy storage investments in supporting high renewable portfolio standards. Appl. Energy, 183, 902–913.
Abstract: Worldwide, environmental regulations such as Renewable Portfolio Standards (RPSs) are being broadly adopted to promote renewable energy investments. With corresponding increases in renewable energy deployments, there is growing interest in grid-scale energy storage systems (ESS) to provide the flexibility needed to efficiently deliver renewable power to consumers. Our contribution in this paper is to introduce a unified generation, transmission, and bulk ESS expansion planning model subject to an RPS constraint, formulated as a two-stage stochastic mixed-integer linear program (MILP) optimization model, which we then use to study the impact of co-optimization and evaluate the economic interaction between investments in these three asset classes in achieving high renewable penetrations. We present numerical case studies using the 24-bus IEEE RTS-96 test system considering wind and solar as available renewable energy resources, and demonstrate that up to $180 million/yr in total cost savings can result from the co-optimization of all three assets, relative to a situation in which no ESS investment options are available. Surprisingly, we find that co-optimized bulk ESS investments provide significant economic value through investment deferrals in transmission and generation capacity, but very little savings in operational cost. Finally, we observe that planning transmission and generation infrastructure first and later optimizing ESS investments as is common in industry captures at most 1.7% ($3 million/yr) of the savings that result from co-optimizing all assets simultaneously. (C) 2016 Elsevier Ltd. 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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Perez, A. P., Sauma, E. E., Munoz, F. D., & Hobbs, B. F. (2016). The Economic Effects of Interregional Trading of Renewable Energy Certificates in the US WECC. Energy J., 37(4), 267–295.
Abstract: In the U.S., individual states enact Renewable Portfolio Standards (RPSs) for renewable electricity production with little coordination. Each state imposes restrictions on the amounts and locations of qualifying renewable generation. Using a co-optimization (transmission and generation) planning model, we quantify the long run economic benefits of allowing flexibility in the trading of Renewable Energy Credits (RECs) among the U.S. states belonging to the Western Electricity Coordinating Council (WECC). We characterize flexibility in terms of the amount and geographic eligibility of out-of-state RECs that can be used to meet a state's RPS goal. Although more trade would be expected to have economic benefits, neither the size of these benefits nor the effects of such trading on infrastructure investments, CO2 emissions and energy prices have been previously quantified. We find that up to 90% of the economic benefits are captured if approximately 25% of unbundled RECs are allowed to be acquired from out of state. Furthermore, increasing REC trading flexibility does not necessarily result in either higher transmission investment costs or a substantial impact on CO2 emissions. Finally, increasing REC trading flexibility decreases energy prices in some states and increases them elsewhere, while the WECC-wide average energy price decreases.
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