Evaluering av energileddet i sentralnettstariffen og bruk av marginaltapssatser

I denne rapporten foretar vi en evaluering av energileddet i sentralnettstariffen og bruken av marginaltapssatser. Vi går først gjennom teorien for optimale overføringstariffer og beskriver hvordan marginaltapssatser beregnes og hvordan disse benyttes i kombinasjon med systempris i dagens nettariff. Vi beskriver også utviklingen i den svenske marginaltaps-tariffen, og vi refererer helt kort utviklingen i PJM-området (USAs østkyst). Ettersom det svenske og det norske systemet tilsynelatende er basert på samme prinsipper, problematiserer vi mangelen på harmonisering, ettersom systemene rent faktisk nå er svært forskjellige. Det er liten tvil om at Statnett har forfinet og forbedret metodene for å beregne marginaltapssatser, samtidig som at flaskehalser fremdeles håndteres ganske forenklet gjennom få og store prisområder på Nord Pool Spot. Vi diskuterer sammenhengen mellom tapstariffen og flaskehalshåndtering, og vi anbefaler at Statnett vurderer å bruke områdepris som avregningspris. Dette vil gjøre det mye enklere for aktørene å ta hensyn til tapskostnadene

Congestion management in the Nordic power market : nodal pricing versus zonal pricing

In the Nordic day-ahead electricity market zonal pricing or market splitting is used for relieving congestion between a predetermined set of price areas. This congestion management method represents an aggregation of individual connection points into price areas, and flows in the actual electricity network are only partially represented in the market clearing. Because of several strained situations in the power system during 2009 and 2010, changes in the congestion management method are under consideration by the Norwegian regulator NVE. We discuss three different congestion management methods – nodal pricing, and optimal and simplified zonal pricing. Four hourly cases from 2010 are used to illustrate the effects of different congestion management methods on prices, surpluses and network utilization

Weight restrictions in the DEA benchmarking modul for Norwegian electricity distribution companies : size and structural variables

We have previously, in report 33/08, looked at possible weight restrictions for the so-called “geography” variables in the DEA model for the distribution networks. In this report we consider weight restrictions for the remaining output variables. Because some cost drivers are represented by proxy variables, in some cases endogenous input variables, the resulting shadow prices are difficult to interpret. Weight restrictions that rely on detailed assumptions about individual prices, such as the proposal in NVE (2008), are therefore problematic. We suggest instead virtual weight restrictions with respect to groups of variables, thereby eliminating the need for detailed assumptions. The virtual restrictions were introduced in report 33/08, and we discuss here how to set the restriction limits. Since one of the main motivations for considering weight restrictions is to limit the effect of the geography variables, we compare the weight restricted model to a two-stage DEA approach where the geography variables are included in the second stage. We also make comparisons with the procedure used by NVE to limit super efficiency

Stochastic Electricity Dispatch: A challenge for market design

We consider an electricity market with two sequential market clearings, for instance representing a day-ahead and a real-time market. When the first market is cleared, there is uncertainty with respect to generation and/or load, while this uncertainty is resolved when the second market is cleared. We compare the outcomes of a stochastic market clearing model, i.e. a market clearing model taking into account both markets and the uncertainty, to a myopic market model where the first market is cleared based only on given bids, and not taking into account neither the uncertainty nor the bids in the second market. While the stochastic market clearing gives a solution with a higher total social welfare, it poses several challenges for market design. The stochastic dispatch may lead to a dispatch where the prices deviate from the bid curves in the first market. This can lead to incentives for selfscheduling, require producers to produce above marginal cost and consumers to pay above their marginal value in the first market. Our analysis show that the wind producer has an incentive to deviate from the system optimal plan in both the myopic and stochastic model, and this incentive is particularly strong under the myopic model. We also discuss how the total social welfare of the market outcome under stochastic market clearing depends on the quality of the information that the system operator will base the market clearing on. In particular, we show that the wind producer has an incentive to misreport the probability distribution for wind

Guarantees of Origin and Competition in the Spot Electricity Market

We study the effect of introducing a market for green energy attributes on the market for the energy itself. In Europe, renewable energy producers receive Guarantees of Origin (GOs) that they can sell to consumers who wish to declare their electricity consumption as “green”. In a model of price competition, we show how the introduction of such a GO market can increase competition in the spot electricity market, leading to reduced electricity prices. In the current market design, the trade of GOs is not restricted by the physical transmission capacity in the spot electricity market. However, since the production capacity of GOs is still limited by the total dispatch of electricity, suppliers have incentives to compete more fiercely in the spot market. This pro-competitive effect disappears if the physical transmission capacity is also imposed on the GO market

End-User Flexibility in the Local Electricity Grid – Blurring the Vertical Separation of Market and Monopoly?

In the Norwegian electricity system, new consumption patterns and changing load profiles increase an already apparent need for reinvestment in the aging network infrastructure. This is very costly, and network operators consider alternative ways of increasing capacity, which are less costly and more flexible. One such option is end-user flexibility. In the paper, we give an overview of the Norwegian electricity market and regulation and the potential of end-user flexibility. We present an investment case provided by a network company, which illustrates that the choice of compensation method to customers have a large impact on the cost and/or revenue cap in the regulatory model. By issuing direct payments for flexibility services, end-user flexibility results in a lower efficiency, although the revenue cap may be higher, while redistribution of network tariffs have a marginal effect on efficiency and the revenue cap. Through redistribution of network tariffs, the network operator can defer investments without a notable change in the revenue cap or change in efficiency. This highlights some of the future challenges that the regulator faces in setting a regulatory framework for end-user flexibility and it challenges the vertical separation that has been a corner stone in the deregulated electricity market

Finding core allocations for fixed cost games in electricity networks

We discuss the cost allocation problem faced by a network operator, where the fixed (residual) cost of the network has to be allocated among its users. Usage-based methods, such as the postage stamp rate method and the MW-mile method, are easy to understand and compute, but may yield cost allocations for which some transactions are subsidizing others. Formally, this is equivalent to allocations outside of the core of the corresponding cooperative cost game. Our main contribution is to present a method, similar to a well-known method for computing the nucleolus, by which several usage-based methods may be combined in order to produce allocations that are in, or as close as possible to, the core. The method is illustrated using a model of an AC power network

Electricity Market Design 2030-2050: Shaping Future Electricity Markets for a Climate-Neutral Europe

Speeding up the energy transition in the European Union (EU) is a major task to quickly reduce harmful greenhouse gas emissions. Market design plays a crucial role in the decarbonization of the European energy system, driving the expansion of both Renewable Energy Sources (RES) and accompanying flexibility sources. In particular, demand flexibility by energy-intensive industrial companies can play a key role. By flexibilizing their production processes, industrial companies can contribute to an increased use of variable RES (in the following referred to as Variable Renewable Energy (VRE)) to lower the CO2 footprint of their products with positive effects on economic competitiveness. Together with other flexibility sources like electric vehicles, the EU can transition to a just, low-carbon society and economy with benefits for all. However, to actually realize these benefits, market design must account for the changing production and consumption characteristics, e.g., the intermittency of VRE. Starting with current challenges of the energy transition that need to be solved with a future market designin the EU, the whitepaper takes alternative market design options and recent technological developments into account, which are highly intertwined. The whitepaper elaborates on the role of, for instance, flexibility, digital technologies, market design with locational incentives, and possible transition pathways in a European context. The “Clean energy for all Europeans” package offers a new opportunity to deepen the integration of different national electricity systems, whereby Transmission System Operators (TSOs) are required to reserve at least 70% of transmission capacities for cross-border trades from 2025 onwards. The corresponding scarcity of transmission capacities on the national level, however, may aggravate congestion to a critical extent, calling for transformational changes in market design involving, e.g., a redefinition of bidding zones close to the network-node level. The present whitepaper can be seen as part of a series of whitepapers on electricity market design 2030 - 2050 [14, 15] and continues the analysis of regionally differentiated prices or Locational Marginal Pricing (LMP) as a means to address congestion problems in future VRE-based electricity systems. Thereby, the whitepaper extends the findings of the previous two whitepapers (where in the latter whitepapers, e.g., a detailed discussion of the pros and cons of LMP can be found) and elaborates on the question how LMP could be implemented in one or several European countries and how possible implementation pathways may look like in a coupled European system. Moreover, the whitepaper describes preparatory steps that are necessary for the introduction of LMP, and – at the same time – create advantages for countries under both, a nodal and zonal market design. All in all, the results and outcomes of the whitepaper shall support the market design transition in Europe and, thus, the integration and activation of flexibility potentials to foster a fast reduction of CO2 emissions through a better use of VRE. Therefore, the whitepaper contributes with concrete policy measures to the overarching vision of a future European electricity market design that bases on low-carbon technologies and enhances welfare and fairness, while ensuring economic competitiveness of Europe. We would like to thank all the partners and are grateful for the financial support from the Federal Ministry of Education and Research as well as the Project Management Jülich. Martin Bichler, Hans Ulrich Buhl, and Martin Weibelzahl (SynErgie) Antonello Monti (OneNet

Evaluation of the StoNED method for benchmarking and regulation of Norwegian electricity distribution companies

We evaluate the StoNED methodology for benchmarking and regulation of network companies, and we compare StoNED to the two-stage DEA method currently used by the Norwegian regulator. We find that the estimated values for the skewness parameter in the second stage of the StoNED procedure can be inconsistent with the assumed positive skewness for the inefficiency term. Setting the skewness parameter to an arbitrary value can have significant consequences for the efficiency levels. This effect is partly neutralized by the revenue calibration performed by the NVE, depending on how the calibration is implemented. Our comparison of results from StoNED and two-stage DEA show that the efficiency scores from the two methods are highly correlated, but that the levels can differ significantly. We also interpret the StoNED coefficient estimates and compare them to the corresponding (dual) DEA estimates. Finally, we illustrate the robustness of the efficiency estimates to noise in data, as exemplified by noisy pension costs

Weight restrictions on geography variables in the DEA benchmarking model for Norwegian electricity distribution companies

The DEA model for the distribution networks is designed to take into account the diverse operating conditions of the companies through so-called “geography” variables. Our analyses show that companies with difficult operating conditions tend to be rewarded with relatively high efficiency scores, and this is the reason for introducing weight restrictions. We discuss the relative price restrictions suggested for geography and high voltage variables by NVE (2008), and we compare these to an alternative approach by which the total (virtual) weight of the geography variables is restricted. The main difference between the two approaches is that the former tends to affect more companies, but to a lesser extent, than the latter. We also discuss how to set the restriction limits. Since the virtual restrictions are at a more aggregated level than the relative ones, it may be easier to establish the limits with this approach. Finally, we discuss implementation issues, and give a short overview of available software