Zonal Pricing Research Articles

Cost-Effective Management of Electricity Transmission in an Industrial Region

One of the worldwide modern instruments to increase power efficiency is the price-dependent electricity consumption. It is one of the elements in managing the demand for power consumption. The programs of price-dependent power consumption are globally relevant. However, in Russia, their development is still on a conceptual phase. This paper analyses regional tariffs for the power transmission from the perspective of encouraging consumers to price-dependent demand management for electricity consumption. We examine the structure of final electricity tariffs for various categories of consumers as well as identify the percentage rate for the electricity transmission for each category. We consider the methodology of single-part and two-part tariffs for electricity transmission, their structure, and advantages of application. On the example of Volga Federal District tariffs, we have calculated single-part and two-part tariffs for the power transmission in industrial enterprises in terms of three typical schedules of electricity consumption. To compare the efficiency of the price-dependent demand management for the electricity transmission in different regions of Russia, we have introduced the indicators “coefficient of the transmission tariff†and “integral coefficient of the transmission tariff†. Furthermore, we made calculations for 65 regions of Russia entering the price zones of power wholesale market. As a result of the analysis, we divided Russian regions of Russia according to the indicator of “integrated coefficient of transmission tariff†in 3 administrative groups. For each group, we have developed recommendations on pricedependent demand management for power transmission. The theoretical significance of the research consists in the development of methods for the analysis and selection of the most appropriate industrial enterprise tariff for electricity transmission. In practice, regional authorities can use the developed groups of regions to change the structure of regional tariffs in order to stimulate consumers to price-dependent power consumption. Moreover, the algorithm for calculating tariffs for electricity transmission can be applied by the industrial Russia enterprises in price-dependent demand management of power consumption to choose an optimum tariff and reduce costs on power transmission.

The Impact of Market Design on Transmission and Generation Investment in Electricity Markets

In this paper we propose an equilibrium model in order to analyze the impact of electricity market design on generation and transmission expansion in liberalized electricity markets. In a multi-level structure, our framework takes into account that generation investment and operation is decided by private investors, while network expansion and redispatch is decided by a regulated transmission system operator - as well as the different objectives of firms (profit maximization) and the regulator (welfare maximization). In order to illustrate the possibilities to quantify long term economic effects with our framework, we calibrate our model for the German electricity market. We consider various moderate adjustments of the market design: (i) the division of the market area into two price zones, (ii) the efficient curtailment of renewable production and (iii) a cost-benefit-driven balance between network expansion and network management measures. We then analyze the impact of these market designs on generation and transmission investment in case those design elements are anticipated upon network development planning. The resulting investment and production decisions are compared to a benchmark that reflects the current German electricity market design and to an overall optimal first-best benchmark. Our results reveal that price zones do have a significant impact on locational choice of generators and result in a reduced need for network expansion, but lead to only moderate annual welfare gains of approximately 0.9% of annual total system costs. Anticipation of optimal curtailment of renewables and a cost-benefit-driven use of redispatch operations upon network expansion planning, however, implies a welfare gain of over 4.9% of annual total system costs per year as compared to the existing market design, which equals 85% of the maximal possible welfare gain of the first-best benchmark.

Baltic Power Systems’ Integration into the EU Market Coupling under Different Desynchronization Schemes: A Comparative Market Analysis

Currently, the power transmission system of the Baltic states is synchronized with the Integrated/Unified Power System (IPS/UPS), which includes the Russian grid, and the IPS/UPS provides frequency regulation and system security within the Baltic states. Since joining the European Union (EU) in 2004, the Baltic states have been following the EU’s energy policy targets. The Baltics are presently participating in a European electricity market, i.e., the NordPool market, while they are expected to join the pan-European electricity market—the European target model for power market integration. Moreover, from a power grid perspective, EU energy policies intend to desynchronize the power grid of the Baltic states from the IPS/UPS over the coming years. This paper evaluates these policy trends through market impacts, and it complements existing studies on Baltic-IPS/UPS desynchronization in terms of wholesale electricity prices, generation surpluses, primary reserve adequacy, and redispatch costs. Participation of the Baltic states in the integrated pan-European day-ahead electricity market with zonal pricing was modeled for 2030, followed by a national redispatch, with detailed power grid modeling of Baltic states to solve potential intrazonal congestion. The simulation results imply the superiority of the Baltics’ synchronization to continental Europe, compared to the other schemes.

Weather or not? Welfare impacts of natural gas pipeline expansion in the northeastern U.S.

With the rapid development of new natural gas resources in the United States has come a number of proposals for new natural gas transmission infrastructure. We use a unique and fine-grained data set on natural gas spot pricing and gas transmission operations to model how a local pipeline expansion connecting a Marcellus Shale producing area to the main Transco pipeline system would affect flow patterns and zonal gas pricing across the Transco. Our modeling approach is based on arbitrage cost models for constrained energy networks, accounting for the effects of zonal gas transmission rates as mandated by the U.S. Federal Energy Regulatory Commission. Application of our model to a data set of daily gas market outcomes and operating conditions on the Transco between 2012 and mid 2014 suggests that the modeled pipeline expansion would increase overall economic welfare in the spot market for Transco deliveries by $1.7 billion and have positive net social benefits of about $0.4 billion. However, more than 80% of this estimated welfare gain occurs in one season (winter 2014) featuring high gas demand due to colder weather. Thus, the spot market efficiency gains associated with pipeline projects in the Marcellus region may be limited by the frequency of extreme cold weather conditions. To examine the sensitivity of our estimates of welfare gains to different weather conditions, we calculate the expected benefits of the pipeline expansion in terms of historical temperatures from 1992 to 2011, and find that Atlantic Sunrise would have increased welfare by approximately $1.8 billion over a two and half year period, on average.

A new approach to electricity market clearing with uniform purchase price and curtailable block orders

The European market clearing problem is characterized by a set of heterogeneous orders and rules that force the implementation of heuristic and iterative solving methods. In particular, curtailable block orders and the uniform purchase price pose serious difficulties. A block order spans over multiple hours, and can be either fully accepted or fully rejected. The uniform purchase price prescribes that all consumers pay a common price in all the zones, while producers receive zonal prices, which can differ from one zone to another.The market clearing problem in the presence of both the uniform purchase price and block orders is a major open issue in the European context. The uniform purchase price scheme leads to a non-linear optimization problem involving both primal and dual variables, whereas block orders introduce multi-temporal constraints and binary variables into the problem. As a consequence, the market clearing problem in the presence of both block orders and the uniform purchase price can be regarded as a non-linear integer programming problem involving both primal and dual variables with complementary and multi-temporal constraints.The aim of this paper is to present a non-iterative and heuristic-free approach for solving the market clearing problem in the presence of both curtailable block orders and the uniform purchase price scheme. The solution is exact, with no approximation up to the level of resolution of current market data. By resorting to an equivalent uniform purchase price formulation, the proposed approach results in a mixed-integer linear program, which is built starting from a non-linear integer bilevel programming problem. Numerical results using real market data are reported to show the effectiveness of the proposed approach. The model has been implemented in Python, and the code is freely available on a public repository.

Optimal storage and transmission investments in a bilevel electricity market model

This paper analyzes the interplay of transmission and storage investments in a multistage game that we translate into a bilevel market model. In particular, on the first level we assume that a transmission system operator chooses optimal line investments and a corresponding optimal network fee. On the second level we model competitive firms that trade energy on a zonal market with limited transmission capacities and decide on their optimal storage facility investments. To the best of our knowledge, we are the first to analyze interdependent transmission and storage facility investments in a zonal market environment that accounts for the described hierarchical decision structure. As a first best benchmark, we also present an integrated, single-level problem that may be interpreted as a long-run nodal pricing model. Our numerical results show that adequate storage facility investments of firms may in general have the potential to reduce the amount of line investments of the transmission system operator. However, our bilevel zonal pricing model may yield inefficient investments in storages, which may be accompanied by suboptimal network facility extensions as compared to the nodal pricing benchmark. In this context, the chosen zonal configuration of the network will highly influence the equilibrium investment outcomes including the size and location of the newly invested facilities. As zonal pricing is used for instance in Australia or Europe, our models may be seen as valuable tools for evaluating different regulatory policy options in the context of long-run investments in storage and network facilities.

An Optimization Model for the Electricity Market Clearing Problem With Uniform Purchase Price and Zonal Selling Prices

Electricity markets can be designed in different ways. One rule that is sometimes enforced is the uniform purchase price. Under this pricing method, all the consumers pay the same price regardless of the zone they belong to. By contrast, each producer receives its zonal price. This asymmetry in the price paid and received makes the clearing process not easily treatable through standard optimization techniques. Within the framework of marginal pricing, this paper shows how it is possible to formulate the market clearing problem with uniform purchase price and zonal selling prices as a computationally tractable mixed integer linear programming problem. The proposed approach is tested using real data from the Italian day-ahead market, which is actually based on the aforementioned rule.

Optimal Siting of Wind Farms in Wind Energy Dominated Power Systems

Electricity from renewable energy (RE) sources gained in significance due to green-friendly governmental initiatives in the form of either direct subsidizes, tax incentives or tradable certificates. Thereby, RE generators are incentivized to maximize energy feed-in or the remuneration from governmental subsidizes, meanwhile neglecting any market interaction. Consequently, wind farms are clustered in windy regions. Along with the governmentally initiated integration of RE generation into power markets, the siting of RE generators will change. In wind power dominated power systems that fully integrate RE generators into power markets, wind farms will compete against each other and try to maximize their market value. Hence, wind speed correlations with other wind farms will become increasingly important when choosing a site in a uniform or zonal pricing system. To quantify the impact of market integration on future wind farm siting, an approach is developed that takes into account the local wind potential of a certain site, wind speed correlations to other sites and their installed capacities. An optimization that minimizes the normalized sum of wind power correlations to all other sites and their respective normalized installed wind power capacity is performed. To achieve a predefined minimum energy output, the average wind yield is considered as an additional constraint. The outcome is an optimal wind farm site in a wind energy dominated system. Running this for a given wind power expansion scenario enables decision makers to foresee the spatial development of wind farm installations. To demonstrate the model’s applicability, a case study is performed for Germany. Thereby, wind speed data for four years from the European reanalysis model COSMO-REA6 is used. The results indicate that a full market integration of RE generators will space out more evenly new wind farms. Thereby, wind farms can economically benefit from the non-simultaneity of wind speed.

New High Voltage Interconnections with Islands in the Mediterranean Sea: Malta and Sicily. Analysis of the Effects on Renewable Energy Sources Integration and Benefits for the Electricity Market

The present paper shows the benefits coming from the operation of the recent electrical high voltage (HV) interconnections between Sicily, Malta and mainland Italy. These new interconnections allow zonal prices of electricity considerably lower than in the past, ensuring greater flexibility to the system and a better integration of Renewable Energy Sources (RES). After briefly illustrating the two high-voltage electrical systems (Sicily and Malta), and having provided a description of the interconnection cable with Malta and its protection devices, the authors hypothesized two modes of operation (Sicily-Malta system islanded or interconnected to the rest of Europe). For the first case (islanded) some simulations are performed through the use of an electric network model realized in the Neplan® environment, and for the second case an analysis of one year real data was made. The results of the simulation, thanks to the use of a power flow tracing method, show that this new interconnection between the two islands (Sicily and Malta) allows an important improvement in the integration and dispatching of the power generated by RES of the Sicilian territory, better operation of traditional Sicilian generation units, lower electricity zonal prices and a significant reduction in emissions from obsolete fuel oil thermal units located in Malta.

Quo Vadis? (Un)scheduled electricity flows under market splitting and network extension in central Europe

The increasing role of intermittent renewable generation demands for an efficient spatial exchange of electricity. However, the technical characteristics of electricity transmission reduce the available cross-border capacity due to unscheduled flows in a zonal pricing framework. Using the detailed unit commitment and dispatch model stELMOD for the European system, we analyze the development of unscheduled flows under different market and network design scenarios for 2020. We apply ACER's flow definition to decompose commercial schedules and physical flows into unscheduled flows and its fractions, i.e. loop and unallocated flows. Our analysis reveals that unscheduled flows increase on average by 47% from 14.7 GW in 2013 to 21.7 GW in 2020 mainly driven by higher cross-border trade capacities and increasing renewable generation. These unscheduled flows, which affect adjacent countries through e.g. a reduction of tradeable cross-border capacity, can be effectively reduced through a delimitation of bidding zones or HVDC network expansion. Thus, even if a discussion of national impacts of national and European policies is inevitable, they can have substantial implications on adjacent regions through the interconnected electricity system. Therefore, a system-wide view should complement national perspectives to ensure an efficient system development with increasing shares of intermittent renewable generation.

A spatial electricity market model for the power system: The Kazakhstan case study

Kazakhstan envisions a transition towards a green economy in the next decades, which poses an immense challenge as the country's economy and energy system depends heavily on hydrocarbon resources. Here, it lacks inclusive and transparent tools assessing technical, economic, and environmental implications resulting from changes in its electricity system. We present such a tool: our comprehensive techno-economic unit-commitment model determines the hourly least-cost generation dispatch, based on publicly available data on the technical and economic characteristics of the system. It accounts for particularities of the Kazakh electricity system by representing combined heat and power, and endogenously determining line losses. Model results examine two typical weeks: winter (annual peak load) and summer (hour of lowest annual load) presenting regionally and temporally disaggregated results for power generation, line utilization, and nodal prices. In an application to market design, the paper compares nodal and zonal pricing as two possible pricing schemes in Kazakhstan for the envisioned strengthening of the day-ahead market. The model analyze the current Kazakh electricity system and can be easily expanded to assess the sector's future development. Possible applications include investment in generation and transmission infrastructure, policy assessment for renewables integration, carbon pricing, emission reduction, and questions of market design.

Price Convergence within and between the Italian Electricity Day-Ahead and Dispatching Services Markets

In the paper we study the convergence of prices in the electricity markets, both at the day-ahead level and for the dispatching services (such as balancing and reserves). We introduce two concepts of price convergence, the convergence of zonal prices within each market (within convergence), and the converge of prices in a given zone between the two markets (between convergence). We provide an extensive analysis based on Italian data of within and between convergence. The zonal time-series of the prices are evaluated, seasonally adjusted and tested to assess their long-run properties. This evaluation induces us to focus on the behavior of the three largest and most interconnected continental zones of Italy (North, Center-North and Center-South). The fractional cointegration methodology used in the analysis shows the existence of long-run relationships among the series used in our study. This signals the existence of price convergence within markets, even though for the dispatching services market the evidence is less robust. The analysis also shows the existence of price convergence between markets in each zone, even though the evidence is more clearly affirmed for the North (the largest Italian zone), less so for the other two zones. Results are interpreted on the basis of the characteristics of the markets and the zones.

Forecasting the results of financial investments

Methods are offered for determining the price levels for fixing profits in forecasting the results of investments in world financial markets, based on the analysis of price time series taking into account current financial indicators and the market situation. These methods allow an adequate assessment of a number of indicators of strength and quality of the price zones of the supply/demand in order to find the most probable opportunities for profitable investment, it is highly probable to forecast the size of the potential profit in each individual investment, and also to determine the average yield of trade and investment activities in general, taking into account a variety of investment transactions for a long time distance. Recommendations are developed on the practical application of the methods considered taking into account the current market situation. The ways of further researches of the mentioned problems are outlined taking into account the mentioned problem moments.

On the effects of storage facilities on optimal zonal pricing in electricity markets

This paper analyzes the effects of storage facilities on optimal zonal pricing in competitive electricity markets. In particular, we analyze a zonal pricing model that comprises consumers, producers, and storage facilities on a network with constrained transmission capacities. In its two limit cases, our zonal pricing model includes the reference nodal pricing model as well as the uniform pricing model with storage. To the best of our knowledge we are the first to analyze zonal pricing in the presence of storage. As our numerical results show, storage facilities do not only reduce the inter-temporal price volatility of a market, but may considerably change the inter-regional price structure. In particular, the inter-regional price volatility may increase in the presence of storage, which may imply a complete reconfiguration of optimal zonal boundaries as compared to the no-storage case. However, market participants may have an incentive to keep or implement a sub-optimal zonal design. Thus, storage facilities will in general challenge optimal congestion management with common heuristic approaches to configure optimal price zones (e.g., the use of congested transmission lines of a nodal pricing system) not always suggesting optimal zonal configurations. Therefore, we propose a model extension that allows policy makers to determine welfare maximizing zonal configurations, which account for the complex inter-regional price effects of storage facilities. Especially with regard to increasing storage investments, such a model may help to (at least partially) handle the described inefficiency problems regarding sub-optimal zonal designs that may challenge European or Australian zonal electricity markets in the near future.

Optimal price zones of electricity markets: a mixed-integer multilevel model and global solution approaches

Mathematical modelling of market design issues in liberalized electricity markets often leads to mixed-integer nonlinear multilevel optimization problems for which no general-purpose solvers exist and which are intractable in general. In this work, we consider the problem of splitting a market area into a given number of price zones such that the resulting market design yields welfare-optimal outcomes. This problem leads to a challenging multilevel model that contains a graph-partitioning problem with multi-commodity flow connectivity constraints and nonlinearities due to proper economic modelling. Furthermore, it has highly symmetric solutions. We develop different problem-tailored solution approaches. In particular, we present an extended Karush-Kuhn-Tucker (KKT) transformation approach as well as a generalized Benders approach that both yield globally optimal solutions. These methods, enhanced with techniques such as symmetry breaking and primal heuristics, are evaluated in detail on academic as well as on realistic instances. It turns out that our approaches lead to effective solution methods for the difficult optimization tasks presented here, where the problem-specific generalized Benders approach performs considerably better than the methods based on KKT transformation.

Market Power Under Nodal and Zonal Congestion Management Techniques

Contrary to the common thought that nodal pricing provides more opportunities for a strategic player to exert market power than the zonal model, we show that in the latter one because of the need for re-dispatch or counter-trading, another extra place is created letting more gaming possibilities. Therefore, if proper market power mitigation approaches are not utilized in both day-ahead and re-dispatch markets, then zonal pricing may be more susceptible to market power, especially in zonal model which is based on available transfer capacity (ATC), strategic player’s profit and social welfare can be very volatile. In general, the more network constraints are incorporated in day-ahead market (100% in nodal and almost zero in ATC), the more social welfare is attainable. Hence, nodal model is acquitted from the more market power denunciation.

Renewable energy curtailment: A case study on today's and tomorrow's congestion management

This work aims at contributing to the development of congestion management in power systems facing a strong expansion of renewable electricity generation. We address a comparatively new but increasingly important challenge to electricity markets with a uniform price zone: Renewable curtailment due to grid constraints. Our goal is to provide a model framework suitable to investigate the impact of expanding the grid operator's flexibility under varying congestion management regimes. We aim to expose the limitations of the current regime and to present a favorable alternative. For our analysis, we develop an optimal power flow program to replicate the current congestion management regime for distribution grids with high penetration of distributed generation in Germany. Furthermore, we introduce district heating as additional flexibility option and investigate the impact under different approaches to congestion management. Our results suggest that introducing additional flexibility, while keeping the current congestion management regime, bears significant risk to increase the cost of congestion management. Adjusting the regime to take into account economic criteria, as outlined in this work, eliminates this risk and grants direct control on the trade-off between curtailment and cost.

The Effect of Increased Transmission and Storage in an Interconnected Europe: An Application to France and Ireland

A longstanding goal of the European Union (EU) is to promote efficient trading between price zones via electricity interconnection to achieve a single electricity market between the EU countries. This paper uses a power system model (PLEXOS-EU) to simulate one vision of the 2030 EU electricity market based on European Commission studies to determine the effects of a new interconnector between France and the Single Electricity Market of Ireland and Northern Ireland (SEM). We use the same tool to understand the effects of investment in storage, and the effects of the interaction between storage and additional interconnection. Our results show that both investments in interconnection and storage reduce wholesale electricity prices in France and Ireland as well as reduce net revenues of thermal generators in most scenarios in both countries. However, France is only marginally affected by the new interconnector. Renewable generators see a modest increase in net revenues. The project has the potential for a positive impact on welfare in Ireland if costs are shared between countries and remain below 45 million €/year for the scenarios examined. The owners of the new interconnector between France and SEM see increased net revenues in the scenarios without storage. When storage is included in the system, the new interconnector becomes less profitable.

Redispatch index for assessing bidding zone delineation

This work addresses the problem of assessing to which extent a bidding zone delineation requires redispatching actions after the clearing of energy markets. Such issue arises in particular when policy makers review the organisation of electricity markets and question the design of uniform price zones. To avoid relying on arbitrarily-defined sensitive parameters, the authors propose a metrics based on information that is sufficient to perform nodal pricing for the whole region under consideration. The metrics is illustrated with a realistic model of the West-European power system considering two application cases, namely (i) selecting a clustering technique to define candidate bidding zones, and (ii) selecting candidate splitting and merging options for pre-existing bidding zones. Results show that the proposed index provides a consistent order of magnitude of the redispatching needs subsequent to market clearing, although it requires no specific user-defined parameters.

Hybrid pricing in a coupled European power market with more wind power

In the European electricity market, the promotion of wind power leads to more network congestion. Zonal pricing (market coupling), which does not take the physical characteristics of transmission into account, is the most commonly used method to relieve network congestion in Europe. However, zonal pricing fails to provide adequate locational price signals regarding scarcity of energy and thus creates a large amount of unscheduled cross-border flows originating from wind-generated power. In this paper, we investigate the effects of applying a hybrid congestion management model, i.e., a nodal pricing model for one country embedded in a zonal pricing system for the rest of the market. We find that, compared to full nodal pricing, hybrid pricing fails to fully utilize all the resources in the network and some wrong price signals might be given. However, hybrid pricing still outperforms zonal pricing. The results from the study cases show that, within the area applying nodal pricing, better price signals are given; the need for re-dispatching is reduced; more congestion rent is collected domestically and the unit cost of power is reduced.