Final Report Summary - RES GRID INTEGRATION (Regulated Expansion of Electricity Transmission Networks: the Effects of Fluctuating Demand and RES Generation)
The main goal of this project was to enhance the understanding on how to regulate and expand transmission networks in the light of large-scale renewable-energy-source (RES) integration to electricity systems. The regulation of transmission operation and expansion is widely discussed by regulatory economists. Finding optimal mechanisms is difficult given the specific physical characteristics of electricity networks like negative local externalities due to loop flows obeying the Kirchhoff’s laws. Considering RES-specific issues in network regulation analysis further required to take into account some other complex special objectives and constraints. In particular, the timing of electricity dispatch in RES systems is more frequent and fluctuating than conventional electricity systems, and a renewable-integration process (which substitutes conventional energy with renewable sources) has an effect on the rents from congestion in the network. All these aspects have impacts on transmission investment decisions.
This research project then combined theoretical research on the regulation of transmission expansion with applications to different energy systems, and derived policy implications to help decision makers identify appropriate policies. In order to analyze such issues, we initially relied on the Hogan-Rosellon-Vogelsang (HRV) mechanism which combines merchant and regulatory structures to promote the expansion of networks. Another approach to transmission expansion would be traditional central planning, which may either be carried out within a vertically integrated utility or by a regulatory authority. Another alternative might be traditional cost-of-service regulation. In contrast, transmission decisions could also be determined in a totally decentralized, non-regulated way. The HRV approach lies among these approaches, combining regulation (via price caps), and market incentives via property rights in electricity investment (financial transmission rights, FTRs). In this project we thus analyzed whether the unique variability and unpredictability characteristics of RES had an effect on transmission expansion decisions within the HRV analytical framework, as well as on investment decisions made under other regulatory regimes.
To address these issues, we first analyzed in Schill, Egerer and Rosellón (2014) (second revise-and-resubmit status at Journal of Regulatory Economics) the performance of different regulatory approaches for network expansion in the context of realistic demand patterns and fluctuating wind power. We applied these mechanisms to a stylized model of the Western European transmission network. We explicitly included both an hourly time resolution and fluctuating wind power, which substantially increased the real-world applicability of the approach. We solved the model numerically and compared the economic welfare outcomes, and the optimal levels of network expansion. We found that network extension in Western Europe not only increased social welfare due to diminished congestion, but also led to price convergence and therefore a large redistribution of social welfare. Comparing different regulatory approaches, we found that the combined merchant-regulatory regime led to welfare outcomes far superior to other modelled alternatives.
Further, in Egerer, Rosellón and Schill (2014) (accepted for publication at The Energy Journal) we addressed the rationale for regulation of transmission investment under a renewable integration process characterized by the gradual substitution of conventional power (e.g. coal) with renewable energy sources (e.g. wind). This transition towards a low carbon electricity sector can have temporary or permanent exogenous shocks on transmission requirements. We studied different regulatory regimes for electricity transmission investment in such a context. An independent system operator (ISO) collects nodal-price payments from loads and pays the generators. The difference between these payments is the congestion rent, which is assumed to be transferred to the transmission company (Transco). We modeled then a welfare-maximizing benchmark (WFMax) in which a social planner makes combined decisions on network expansion and dispatch, as well as three different regulatory cases in which we assume the Transco to be unregulated regarding network expansion (NoReg), cost-regulated (CostReg), or price-cap regulated (HRV). We compared these cases to a baseline without any network expansion. The different regulatory cases were analyzed under different stylized cases of changing technology generation over a timeframe of 20 years. We found that incentive price-cap HRV regulation performs satisfactorily under a renewable-integration process only when appropriate price weights in the price-cap formula are used. Ideally constructed quantity weights, brought back from welfare-optimal steady-state equilibrium, generally restored the beneficial properties of incentive regulatory mechanisms under renewable integration. However, we also searched to more down-to-earth weight alternatives. We thus found that, depending on the expected evolution of network congestion, either previous-period (Laspeyres), current-period (Paasche), or average Paasche-Laspeyres quantity weights appear to be appropriate choices. In particular, with the proper handling of weights, excessive network investments (that are usual in renewable integration processes) might not be a problem anymore.
In the previous studies we found, however, that a combined merchant-regulatory regime for network expansion also leads to a situation in which a substantial portion of the Transco’s income consists of a fixed tariff part. The over-time rebalancing of the two-part tariff carried out by the Transco, so as to expand the network, is such that the fixed fee is considerably higher than the decrease of the variable part. The fixed-tariff part also turns out to be relatively large compared to extension costs, a distributive issue that might be addressed through a proper choice of weight of profits in the welfare criterion. We therefore studied in Herrera and Rosellón (2014) (article in press at Energy Policy) the parameters that a regulator might use to achieve distributive efficiency (a task that had so far not been explicitly analyzed in the economics literature). In particular, we analyzed how different weight parameters affect the distributive characteristics of the incentive price-cap regulation. We found that a regulator's use of ideal (Laspeyres) weights tends to be more beneficial for the Transco (consumers) than for consumers (the Transco).
As described above, we performed applications of the models developed in this project to France, Germany, Belgium and the Netherlands. However, we also analysed such models in the context of other industries, such as natural gas (as in Neumann, Rosellón and Weigt, 2014, second revise-and-resubmit status at Networks and Spatial Economics) and other countries outside Europe (Ruiz and Rosellón, 2012, published at Energy Policy).
It must be mentioned that the above studies were developed under the assumption of existence of a system of nodal prices that provided congestion-rent signals for the network-expansion process. However, during the development of the project, a question arose regarding the feasibility of implementing nodal price systems in markets with a tradition of uniform-pricing schemes (such as Germany).
This motivated us to carry a deep analysis on issues related to implementation of nodal pricing regimes and associated needed financial hedges (financial transmission rights, FTRs). We then firstly put together a series of papers that analyzed these issues in a book published by Springer in its Lecture Note series (Rosellón and Kristiansen, 2013). We were able to attract to this volume some of the most internationally renowned authors in the subject.
Subsequently, we wrote a paper (Kunz, Neuhoff and Rosellón, 2014, accepted to be presented net June at the conference on Energy Industry at a Crossroads: Preparing the Low Carbon Future/TIGER FORUM, 2014, Toulouse, France) where we studied the shift from zonal pricing to smaller zones and nodal pricing so as to improve efficiency and security of the electricity-system operation. Such price changes however also shift profits and surplus between generators and consumers, so that individual actors that may lose might oppose such a reform. The initial allocation of FTRs in a newly created nodal-price system has then been one of the most highly disputed parts of market liberalization processes, as in New Zealand and Australia. In Europe there is nowadays a similar challenge, with considerable dimension of high respective shares that are competing for the pie. In our paper we developed a model to explore how an initial free allocation of FTRs at the time of a transition to nodal pricing could be designed so as to avoid revenue or cost shock. We explored how free allocation of FTRs to generators and loads can be used to mitigate distributional impacts. We researched on the metric to determine the proportion of rights to be allocated by the policy maker, and tested the results in a more realistic setting based on the hourly modelling of the German power system at nodal representation.
This research project then combined theoretical research on the regulation of transmission expansion with applications to different energy systems, and derived policy implications to help decision makers identify appropriate policies. In order to analyze such issues, we initially relied on the Hogan-Rosellon-Vogelsang (HRV) mechanism which combines merchant and regulatory structures to promote the expansion of networks. Another approach to transmission expansion would be traditional central planning, which may either be carried out within a vertically integrated utility or by a regulatory authority. Another alternative might be traditional cost-of-service regulation. In contrast, transmission decisions could also be determined in a totally decentralized, non-regulated way. The HRV approach lies among these approaches, combining regulation (via price caps), and market incentives via property rights in electricity investment (financial transmission rights, FTRs). In this project we thus analyzed whether the unique variability and unpredictability characteristics of RES had an effect on transmission expansion decisions within the HRV analytical framework, as well as on investment decisions made under other regulatory regimes.
To address these issues, we first analyzed in Schill, Egerer and Rosellón (2014) (second revise-and-resubmit status at Journal of Regulatory Economics) the performance of different regulatory approaches for network expansion in the context of realistic demand patterns and fluctuating wind power. We applied these mechanisms to a stylized model of the Western European transmission network. We explicitly included both an hourly time resolution and fluctuating wind power, which substantially increased the real-world applicability of the approach. We solved the model numerically and compared the economic welfare outcomes, and the optimal levels of network expansion. We found that network extension in Western Europe not only increased social welfare due to diminished congestion, but also led to price convergence and therefore a large redistribution of social welfare. Comparing different regulatory approaches, we found that the combined merchant-regulatory regime led to welfare outcomes far superior to other modelled alternatives.
Further, in Egerer, Rosellón and Schill (2014) (accepted for publication at The Energy Journal) we addressed the rationale for regulation of transmission investment under a renewable integration process characterized by the gradual substitution of conventional power (e.g. coal) with renewable energy sources (e.g. wind). This transition towards a low carbon electricity sector can have temporary or permanent exogenous shocks on transmission requirements. We studied different regulatory regimes for electricity transmission investment in such a context. An independent system operator (ISO) collects nodal-price payments from loads and pays the generators. The difference between these payments is the congestion rent, which is assumed to be transferred to the transmission company (Transco). We modeled then a welfare-maximizing benchmark (WFMax) in which a social planner makes combined decisions on network expansion and dispatch, as well as three different regulatory cases in which we assume the Transco to be unregulated regarding network expansion (NoReg), cost-regulated (CostReg), or price-cap regulated (HRV). We compared these cases to a baseline without any network expansion. The different regulatory cases were analyzed under different stylized cases of changing technology generation over a timeframe of 20 years. We found that incentive price-cap HRV regulation performs satisfactorily under a renewable-integration process only when appropriate price weights in the price-cap formula are used. Ideally constructed quantity weights, brought back from welfare-optimal steady-state equilibrium, generally restored the beneficial properties of incentive regulatory mechanisms under renewable integration. However, we also searched to more down-to-earth weight alternatives. We thus found that, depending on the expected evolution of network congestion, either previous-period (Laspeyres), current-period (Paasche), or average Paasche-Laspeyres quantity weights appear to be appropriate choices. In particular, with the proper handling of weights, excessive network investments (that are usual in renewable integration processes) might not be a problem anymore.
In the previous studies we found, however, that a combined merchant-regulatory regime for network expansion also leads to a situation in which a substantial portion of the Transco’s income consists of a fixed tariff part. The over-time rebalancing of the two-part tariff carried out by the Transco, so as to expand the network, is such that the fixed fee is considerably higher than the decrease of the variable part. The fixed-tariff part also turns out to be relatively large compared to extension costs, a distributive issue that might be addressed through a proper choice of weight of profits in the welfare criterion. We therefore studied in Herrera and Rosellón (2014) (article in press at Energy Policy) the parameters that a regulator might use to achieve distributive efficiency (a task that had so far not been explicitly analyzed in the economics literature). In particular, we analyzed how different weight parameters affect the distributive characteristics of the incentive price-cap regulation. We found that a regulator's use of ideal (Laspeyres) weights tends to be more beneficial for the Transco (consumers) than for consumers (the Transco).
As described above, we performed applications of the models developed in this project to France, Germany, Belgium and the Netherlands. However, we also analysed such models in the context of other industries, such as natural gas (as in Neumann, Rosellón and Weigt, 2014, second revise-and-resubmit status at Networks and Spatial Economics) and other countries outside Europe (Ruiz and Rosellón, 2012, published at Energy Policy).
It must be mentioned that the above studies were developed under the assumption of existence of a system of nodal prices that provided congestion-rent signals for the network-expansion process. However, during the development of the project, a question arose regarding the feasibility of implementing nodal price systems in markets with a tradition of uniform-pricing schemes (such as Germany).
This motivated us to carry a deep analysis on issues related to implementation of nodal pricing regimes and associated needed financial hedges (financial transmission rights, FTRs). We then firstly put together a series of papers that analyzed these issues in a book published by Springer in its Lecture Note series (Rosellón and Kristiansen, 2013). We were able to attract to this volume some of the most internationally renowned authors in the subject.
Subsequently, we wrote a paper (Kunz, Neuhoff and Rosellón, 2014, accepted to be presented net June at the conference on Energy Industry at a Crossroads: Preparing the Low Carbon Future/TIGER FORUM, 2014, Toulouse, France) where we studied the shift from zonal pricing to smaller zones and nodal pricing so as to improve efficiency and security of the electricity-system operation. Such price changes however also shift profits and surplus between generators and consumers, so that individual actors that may lose might oppose such a reform. The initial allocation of FTRs in a newly created nodal-price system has then been one of the most highly disputed parts of market liberalization processes, as in New Zealand and Australia. In Europe there is nowadays a similar challenge, with considerable dimension of high respective shares that are competing for the pie. In our paper we developed a model to explore how an initial free allocation of FTRs at the time of a transition to nodal pricing could be designed so as to avoid revenue or cost shock. We explored how free allocation of FTRs to generators and loads can be used to mitigate distributional impacts. We researched on the metric to determine the proportion of rights to be allocated by the policy maker, and tested the results in a more realistic setting based on the hourly modelling of the German power system at nodal representation.