Cedric De Jonghe

Value of Price Responsive Load for Wind Integration in Unit Commitment

The ability of load to respond to short-term variations in electricity prices plays an increasingly important role in balancing short-term supply and demand, especially during peak periods and in dealing with fluctuations in renewable energy supplies. However, price responsive load has not been included in standard models for defining the optimal scheduling of generation units in short-term. Here, elasticities are included to adjust the demand profile in response to price changes, including cross-price elasticities that account for load shifts among hours. The resulting peak reductions and valley fill alter the optimal unit commitment. Enhancing demand response also increases the amount of wind power that can be economically injected. Further, wind power uncertainty can be managed at a lower cost by adjusting electricity consumption in case of wind forecast errors, which is another way in which demand response facilitates the integration of intermittent renewables.

Short-term consumer benefits of dynamic pricing

Consumer benefits of dynamic pricing depend on a variety of factors. Consumer characteristics and climatic circumstances widely differ, which forces a regional comparison. This paper presents a general overview of demand response programs and focuses on the short-term benefits of dynamic pricing for an average Flemish residential consumer. It reaches a methodology to develop a cost reflective dynamic pricing program and to estimate short-term bill savings. Participating in a dynamic pricing program saves an average consumer 2.32 percent of his initial bill. While this result seems insufficient to justify implementation, it contains only a small proportion of a series of dynamic pricing benefits.

Integrating short-term demand response into long-term investment planning

Planning models have been used for many years to optimize generation investments in electric power systems. More recently, these models have been extended in order to treat demand-side management on an equal footing. This paper stresses the importance of integrating short-term demand response to time-varying prices into those investment models. Three different methodologies are suggested to integrate short-term responsiveness into a long-term model assuming that consumer response can be modelled using price-elastic demand and that generators behave competitively. First, numerical results show that considering operational constraints in an investment model results in less inflexible base load capacity and more mid-range capacity that has higher ramp rates. Then, own-price and cross-price elasticities are included in order to incorporate consumers’ willingness to adjust the demand profile in response to price changes. Whereas own-price elasticities account for immediate response to price signals, cross-price elasticities account for shifting loads to other periods. As energy efficiency programs sponsored by governments or utilities also influence the load profile, the interaction of energy efficiency expenditures and demand response is also modelled. In particular, reduced responsiveness to prices can be a side effect when consumers have become more energy efficient. Comparison of model results for a single year optimization with and without demand response shows the peak reduction and valley filling effects of response to real-time prices for an illustrative example with a large amount of wind power injections. Additionally, increasing demand elasticity increases the optimal amount of installed wind power capacity. This suggests that demand-side management can result in environmental benefits not only through reducing energy use, but also by facilitating integration of renewable energy.

Influence of non-harmonized capacity mechanisms in an interconnected power system on generation adequacy

Insufficient incentives from the market lead to threats to generation adequacy. In order to create more steady investment signals, capacity mechanisms (CMs) are discussed in many European countries. CMs are discussed to complement energy-based market designs and ensure long-term generation adequacy. The introduction of a CM has an impact, both in the implementing but also in interconnected neighbouring countries. Hereby, the participation of non-domestic capacity at the CM through interconnection to enhance generation adequacy is often only limited or not at all possible. Current discussion is mostly based on qualitative studies. The possible joint impacts are discussed applying economic theory and transferred experience from world-wide implementations. This paper introduces an equilibrium model that allows for quantitative studies directly aiming on the possible interaction on interconnected countries with no, different or equal market designs including CMs. Changing market settings and increasing interconnection capacities can be researched to underpin the qualitative discussion. The cross-border effects are studied that arise if harmonization of CM or cross-border participation are neglected. A case study simulates two interconnected countries in a symmetrical set up to trace down the changes in the results to changes of market design and interconnection capacity. Results show that the change of market design in neighbouring countries has a strong impact on domestic generation adequacy. Increased interconnection capacity can have counter-intuitive effects on the overall generation adequacy.

Capacity remuneration mechanisms and the transition to low-carbon power systems

Market designs in their current form are facing challenges triggered by the increase of injection from renewable energy sources (RES). Insufficient remuneration of conventional generators in an energy-only market may lead to inadequate generation mixes to cover peak demands and balance intermittent RES injection. Various corrective actions to the market designs are discussed, amongst them capacity remuneration mechanisms (CRMs). In this paper, a model is applied to compare the outcome of an energy-only market, strategic reserves and a capacity market. The comparison is done based on total cost paid to the electricity generators, installed capacities and occuring load shedding. The total costs are split up into energy-based payments (e/MWh), subsidies for RES and capacity-based payments (e/MW). The results show that origin of remuneration change with the chosen market design and lead to different generation mixes. Total cost increase with a CRM. However, taking into account load shedding, the increase of cost must be weighted with indirect costs of energy non-served.

Asymmetry of information and demand response incentives in energy markets

The price set in electricity markets is given by the intersection of supply and demand during a given time period. The demand-side has traditionally been a price taker while the supply-side actively adjusts the output of the market clearing unit to fluctuations in consumption. Currently, there is a transition toward active demand participation that can adequately respond to market conditions. However, private knowledge of demand adjustments, such as the impact of modifying behavior or the availability to do so, creates asymmetry of information between the active supply side and the passive demand. This paper proposes a revelation mechanism that will prompt the demand-side to choose the best option for themselves among a menu of incentives. Rational behavior of consumers implies that demand will only shift when the benefit of doing so is higher than the costs of modifying consumption patterns. Given differences among demand participants and the objectives of the market operator, an analysis of the rationale of each market agent shows the feasible options for demand incentives. This study enables the design of appropriate market mechanisms aimed to discover customer categories and determine the adequate incentives for each case.

Power flow control and its effect on flow-based transmission cost allocation

In a transmission system with HVDC lines or other power flow controlling devices, it is possible to control the active power flow in the lines and indirectly also in other parts of the system. The active control of the power flow through a grid can affect flow-based transmission cost allocation methods as they are based on the DC load flow model. This study investigates the effect of such power flow control on flow-based transmission cost allocation methods. Particularly, three cost allocation schemes: postage stamp, marginal participation and Aumann-Shapley, are compared in a transmission system with power flow control, using HVDC as power flow controlling device, and without power flow control. The results are presented for a 14 bus test system.

Market barriers for harmonised demand-response in balancing reserves: Cross-country comparison

Electricity systems require flexibility to maintain their operations. This can be provided by demand response (DR). Therefore, markets are evolving to be more open to DR. However, there still exist barriers for DR participation. These can be categorised into product, economic, technical and consumer barriers. On the other hand, there is a trend towards harmonising national electricity markets so that international exchange could be possible. As these two trends can counteract each other, problems may arise. The interaction of these two trends is discussed while looking at two forms of reserves across four countries: Belgium, the Netherlands, Germany and France. In this way, different product characteristics can be found. Hence, it is recommended that harmonisation should focus on DR first, with an emphasis on aggregation possibility, before trying to converge other characteristics and potentially strengthen other barriers.

The implications of two German price zones in a european-wide context

As German TSOs are faced with the threat of north-south transmission line overloading, the option of a national bidding zone reconfiguration in the form of a separate northern and southern bidding zone is investigated. By imposing a limit on north-south transactions during market clearing, less redispatch actions are necessary afterwards, as such resulting in more efficient congestion management. However, through market coupling, a national bidding zone reconfiguration also has an impact on neighbouring electricity markets. This paper analyzes the altered interactions between electricity markets caused by the introduction of two German prices zones by means of a cost-minimizing dispatch model. Besides modifying the market outcome within Germany, this market design change also impacts consumers and producers in other European countries. Therefore, a national bidding zone reconfiguration should always be analyzed in a European wide context.

The Effect of Welfare Distribution and Cost Allocation on Offshore Grid Design

Innovative offshore grid designs such as integrating offshore wind farms (OWFs) with interconnectors are gaining popularity. Adequate investment in these designs requires aligning the interest of stakeholders through an appropriate cost allocation method. The aim of this paper is twofold. First, it shows how welfare distribution can influence a stakeholders offshore grid design choice. Second, it evaluates the effect of various cost allocation schemes in aligning diverse stakeholder interests toward efficient grid design. The results confirm that an investment in an efficient offshore grid design may not be guaranteed as long as the chosen cost allocation method ignores the welfare distribution effect. Most methods fail in this regard. Even when they provide cost incentives, they do not always ensure cooperation. Cognizant of this limitation, this study proposes a method that allocates costs in proportion to the incremental net benefit (PINB) of each stakeholder. This method reflects both the distribution of welfare and cost savings.