Diaz, G., Munoz, F. D., & Moreno, R. (2020). Equilibrium Analysis of a Tax on Carbon Emissions with Pass-through Restrictions and Side-payment Rules. Energy J., 41(2), 93–122.
Abstract: Chile was the first country in Latin America to impose a tax on carbon-emitting electricity generators. However, the current regulation does not allow firms to include emission charges as costs for the dispatch and pricing of electricity in real time. The regulation also includes side-payment rules to reduce the economic losses of some carbon-emitting generating units. In this paper we develop an equilibrium model with endogenous investments in generation capacity to quantify the long-run economic inefficiencies of an emissions policy with such features in a competitive setting. We benchmark this policy against a standard tax on carbon emissions and a cap-and-trade program. Our results indicate that a carbon tax with such features can, at best, yield some reductions in carbon emissions at a much higher cost than standard emission policies. These findings highlight the critical importance of promoting short-run efficiency by pricing carbon emissions in the spot market in order to incentivize efficient investments in generating capacity in the long run.
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Kristiansen, M., Munoz, F. D., Oren, S., & Korpas, M. (2018). A Mechanism for Allocating Benefits and Costs from Transmission Interconnections under Cooperation: A Case Study of the North Sea Offshore Grid. Energy J., 39(6), 209–234.
Abstract: We propose a generic mechanism for allocating the benefits and costs that result from the development of international transmission interconnections under a cooperative agreement. The mechanism is based on a planning model that considers generation investments as a response to transmission developments, and the Shapley Value from cooperative game theory. This method provides a unique allocation of benefits and costs considering each country's average incremental contribution to the cooperative agreement. The allocation satisfies an axiomatic definition of fairness. We demonstrate our results for three planned transmission interconnections in the North Sea and show that the proposed mechanism can be used as a basis for defining a set of Power Purchase Agreements among countries. This achieves the desired final distribution of economic benefits and costs from transmission interconnections as countries trade power over time. We also show that, in this case, the proposed allocation is stable.
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Munoz, F. D., Wogrin, S., Oren, S. S., & Hobbs, B. F. (2018). Economic Inefficiencies of Cost-based Electricity Market Designs. Energy J., 39(3), 51–68.
Abstract: Some restructured power systems rely on audited cost information instead of competitive bids for the dispatch and pricing of electricity in real time, particularly in hydro systems in Latin America. Audited costs are also substituted for bids in U.S. markets when local market power is demonstrated to be present. Regulators that favor a cost-based design argue that this is more appropriate for systems with a small number of generation firms because it eliminates the possibilities for generators to behave strategically in the spot market, which is a main concern in bid-based markets. We discuss existing results on market power issues in cost- and bid-based designs and present a counterintuitive example, in which forcing spot prices to be equal to marginal costs in a concentrated market can actually yield lower social welfare than under a bid-based market design due to perverse investment incentives. Additionally, we discuss the difficulty of auditing the true opportunity costs of generators in cost- based markets and how this can lead to distorted dispatch schedules and prices, ultimately affecting the long-term economic efficiency of a system. An important example is opportunity costs that diverge from direct fuel costs due to energy or start limits, or other generator constraints. Most of these arise because of physical and financial inflexibilities that become more relevant with increasing shares of variable and unpredictable generation from renewables.
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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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