Physical Transmission Rights Research Articles

A bi-level approach for participation of hybrid transmission operating companies in the day-ahead market, considering energy storage systems

This paper presents a new approach for participation strategy of Hybrid Transmission Operating Companies (HTOCs) in the day-ahead energy market. In this paper HTOC refers to private companies that have won physical transmission rights (PTR) and also own energy storage facilities. In the introduced hybrid structure, the HTOC can make profit in two different ways; first, through the flow of transmission lines (the MW-Mile transmission pricing method is used here); and second, through an optimum scheduling of its energy storage system. The optimum charge/discharge pattern of energy storage systems, evaluated in this paper, would also increase the MW-Mile profit of the company. The proposed method is a bi-level optimization model. In the upper level the profit of the HTOC is maximized and in the lower level the market clearing process of the independent system operator (ISO) has been modeled. The uncertain behavior of rival units is modeled using robust optimization (RO) method. The Karush-Kuhn-Tucker (KKT) optimality conditions are implemented to convert the proposed bi-level problem into its equivalent single-level problem. The Big-M method and the strong duality theorem (SDT) are used to linearize the proposed method. To demonstrate the performance of the introduced structure for HTOC, the proposed strategy has been implemented on a standard IEEE 9-bus and 57-bus test systems. The results show that HTOC can achieve a maximum guaranteed profit using storage resource (SR). It is also concluded that the presence of SR has not only increased HTOC's profit but also helped to make the structure more flexible against the uncertain parameters. In addition, the RO as a calculation risk method has been perfectly matched with the implementation of SR as a source of hedging uncertainties in managing the risk.

Long-term transmission rights and dynamic efficiency

Abstract We compare market designs for access regulation of a bottleneck transmission line, and study their impact on investment decisions by an incumbent firm with an existing dirty technology and entrant with an uncertain future low-carbon technology. Nodal pricing, which allocates network access on a short-term competitive basis, distorts investment decisions, as the incumbent preempts the entrant by investing early. Long-term tradable transmission rights restore investment efficiency: the incumbent's investment timing becomes socially optimal. This is the case for financial and physical transmission rights, but it requires the existence of a secondary market for transmission rights.

Evaluating an Interconnection Project: Do Strategic Interactions Matter?

High-Voltage Direct Current (HVDC) merchant transmission lines allow trade across separate power markets and often in different countries. Flows on existing cross-border lines are often assessed as suboptimal, which may be due to the light regulation that often prevails in these cases. This paper studies the impact of market power on HVDC interconnections as a determinant of imperfect arbitrage. We assess the impact of Physical Transmission Rights (PTRs) allocation on the management of an HVDC interconnection between a thermal and a hydroelectricity market, assuming dynamic water management. We use a two-stage game formulated as an Equilibrium Problem with Equilibrium Constraints (EPEC) to model the strategic trade between the New York (US) and Quebec (Canada) systems. The numerical model is calibrated with public data. We find that although the interconnection can create wealth, a high concentration of PTRs can destroy value because of dumping strategies. The impact of trade on local price levels may be of concern and calls for the functional unbundling of traders and generators.

Valuation of physical transmission rights—An analysis of electricity cross-border capacities between Germany and the Netherlands

The purpose of this paper is to discuss market-coherent valuation of physical transmission rights for cross-border capacities between Germany and the Netherlands. Aiming at a fair valuation of these contracts, the most important stylized facts of electricity prices such as mean reversion, spikes and correlations of regional prices have to be considered. We present different approaches to the valuation of physical transmission rights and perform a quantitative analysis of the results. On the one hand various challenges of modeling regional price spreads are analyzed. On the other hand we indicate a structural undervaluation of physical transmission rights in all model constellations, i.e. market prices are below theoretical prices of PTR's flexibility. We discuss several reasons for this undervaluation and finally state that regulatory modifications have to be made to avoid missing incentives for the extension of cross-border capacities.

Pricing electricity derivatives on an hourly basis

The purpose of this paper is to develop a framework for pricing electricity derivatives on an hourly basis. We do not in contrast to most current approaches focus exclusively on spot models which primarily reflect empirical spot price dynamics, but also ensure a straightforward applicability to the valuation of electricity derivatives. We show that a model with a jump and a spike component can be calibrated to both the time-series of hourly spot prices and the cross-section of futures prices, once we allow for time-dependent jump and spike parameters. Furthermore, we illustrate the importance of derivative pricing in electricity markets and present some examples of options on futures and hourly spot-options, such as operating reserves and physical transmission rights.

The Valuation of Long-Term Exchange Options in the German Electricity Market

This paper analyzes the valuation of monthly Physical Transmission Rights (PTRs) on the German-Dutch interconnector. From a …nancial perspective, PTRs are exchange options written on the German and Dutch day-ahead electricity price. We extend the famous exchange option model by Margrabe (1978) and include jumps in the underlying prices. We develop a quasi closed-form solution for our exchange option model and compare its pricing performance to the basic model without jumps for all monthly PTRs between 2001 and 2008. Our results show that the inclusion of jumps signi…cantly reduces the Root Mean Squared Error (RMSE) between model and market prices. We further show that the inclusion of de-spiked prices into both models also improves their pricing performance. Overall, the empirical results show that monthly PTR options are clearly undervalued compared to model prices and even strictly cheaper than the corresponding futures contracts.

Jump Risk Premia in Short-Term Spread Options: Evidence from the German Electricity Market

This paper analyzes the valuation of day-ahead Physical Transmission Rights (PTRs) on the German-Dutch interconnector. From a …nancial perspective, PTRs are options written on the dierence between the German and Dutch hourly elec- tricity prices. We propose a model for the valuation of day-ahead PTR options incorporating the unique characteristics of the underlying spread. We empirically test our model for all PTRs between 2001 and 2008, where we model each hour of the day separately. Overall, especially for calm hours, our approach constitutes an adequate model for the valuation of day-ahead PTR options. Empirical results show a negative or zero market price of jump risk for the turbulent hours 8 to 22. These results correspond to risk-loving or risk-neutral investors and indicate that market participants pay a premium for PTRs during peak hours. This premium is based either on increased hedging demand or on speculation.

Market coupling and the importance of price coordination between power exchanges

In Europe, market coupling stands for a further integration of wholesale trading arrangements across country borders. More specifically, it refers to the implicit auctioning of cross-border physical transmission rights via the hourly auctions for electric energy organized by power exchanges (PEXs) one day ahead of delivery. It therefore implies that the PEXs can optimize the clearing of their day-ahead auctions. Due to verticals in the aggregated order curves, the optimal solution can be settled at different prices. In order for prices to give correct locational signals for network development, generation and consumption, price coordination between exchanges is necessary. The paper illustrates this issue, its relevance and discusses how to deal with it.

An Introduction to Financial Transmission Rights

Financial transmission rights are superior to physical transmission rights, particularly in markets employing locational prices; however, many issues regarding FTR allocation have not yet been resolved.

Transmission Rights and Market Power on Electric Power Networks

We analyze whether and how the allocation of transmission rights associated with the use of electric power networks affects the behavior of electricity generators and consumers with market power. We also examine how the allocation of transmission rights is affected by the microstructure of the markets for these rights. Both financial and physical transmission rights are considered. The analysis focuses on a two-node network where there are cheap generating supplies in an exporting region and expensive generating supplies in an importing region. Extensions to a network with loop flow are developed. Regulatory mechanisms for detecting and mitigating the market-powerenhancing effects of transmission rights holdings are discussed. n There has been considerable controversy over whether competitive electricity systems should be organized around bid-based pools with financial transmission rights or bilateral contracting systems organized with tradeable physical transmission rights (Joskow, 1996). We focus here on one set of issues that have arisen in this controversy. We analyze whether and how the allocation of transmission rights associated with the use of an electric power network affects the behavior of electricity generators and purchasers that have market power. We examine the similarities and differences in this regard between financial and physical rights and compare the welfare properties of each. We also examine how transmission-rights markets with different microstructures allocate rights among generators and consumers and determine rights prices, and we demonstrate that the allocation of rights through the market is endogenous. Our analysis is limited to these issues, and it is not our objective to discuss here the full set of reasons why a physical rights mechanism might be preferred to a financial rights mechanism or vice versa.