A novel incentive-based demand response model for Cournot competition in electricity markets

This paper presents an analysis of competition between generators when incentive-based demand response is employed in an electricity market. Thermal and hydropower generation are considered in the model. A smooth inverse demand function is designed using a sigmoid and two linear functions for modeling the consumer preferences under incentive-based demand response program. Generators compete to sell energy bilaterally to consumers and system operator provides transmission and arbitrage services. The profit of each agent is posed as an optimization problem, then the competition result is found by solving simultaneously Karush-Kuhn-Tucker conditions for all generators. A Nash-Cournot equilibrium is found when the system operates normally and at peak demand times when DR is required. Under this model, results show that DR diminishes the energy consumption at peak periods, shifts the power requirement to off-peak times and improves the net consumer surplus due to incentives received for participating in DR program. However, the generators decrease their profit due to the reduction of traded energy and market prices

Measuring the impact of market coupling on the Italian electricity market using ELFO++

This paper evaluates the impact on the Italian electricity market of replacing the current explicit auction mechanism with market coupling. Maximizing the use of the cross-border interconnection capacity, market coupling increases the level of market integration and facilitates the access to low-cost generation by consumers located in high-cost generation countries. Thus, it is expected that a high-priced area such as Italy could greatly benefit from the introduction of this mechanism. In this paper, the welfare benefits are estimated under alternative market scenarios for 2012, employing the optimal dispatch model ELFO++. The results of the simulations suggest that the improvement in social surplus is likely to be significant, especially when market fundamentals are tight.Market coupling; market integration; Italian day-ahead electricity market.

Wind Power: The Economic Impact of Intermittency

Wind is the fastest growing renewable energy source for generating electricity, but economic research lags behind. In this study, therefore, we examine the economics of integrating large-scale wind energy into an existing electrical grid. Using a simple grid management model to investigate the impact of various levels of wind penetration on grid management costs, we show that costs of reducing CO2 emissions by relying more on wind power depend on the generation mix of the existing electricity grid and the degree of wind penetration, with costs ranging from $21 to well over$1000 per tonne of CO2 reduced. Costs are lowest if wind displaces large amounts of fossil fuel production and there is some hydroelectric power to act as a buffer. Hydro capacity has the ability to store wind generated power for use at more opportune times. If wind does nothing more than replace hydro or nuclear power then the environmental benefits (reduced CO2 emissions) of investing in wind power are small.Wind power, carbon costs, electricity grids, mathematical programming

Market and Economic Modelling of the Intelligent Grid: End of Year Report 2009

The overall goal of Project 2 has been to provide a comprehensive understanding of the impacts of distributed energy (DG) on the Australian Electricity System. The research team at the UQ Energy Economics and Management Group (EEMG) has constructed a variety of sophisticated models to analyse the various impacts of significant increases in DG. These models stress that the spatial configuration of the grid really matters - this has tended to be neglected in economic discussions of the costs of DG relative to conventional, centralized power generation. The modelling also makes it clear that efficient storage systems will often be critical in solving transient stability problems on the grid as we move to the greater provision of renewable DG. We show that DG can help to defer of transmission investments in certain conditions. The existing grid structure was constructed with different priorities in mind and we show that its replacement can come at a prohibitive cost unless the capability of the local grid to accommodate DG is assessed very carefully.Distributed Generation. Energy Economics, Electricity Markets, Renewable Energy

The Optimal Share of Variable Renewables: How the Variability of Wind and Solar Power affects their Welfare-optimal Deployment

This paper estimates the welfare-optimal market share of wind and solar power, explicitly taking into account their output variability. We present a theoretical valuation framework that consistently accounts for the impact of fluctuations over time, forecast errors, and the location of generators in the power grid on the marginal value of electricity from renewables. Then the optimal share of wind and solar power in Northwestern Europe's generation mix is estimated from a calibrated numerical model. We find the optimal long-term wind share to be 20%, three times more than today; however, we also find significant parameter uncertainty. Variability significantly impacts results: if winds were constant, the optimal share would be 60%. In addition, the effect of technological change, price shocks, and policies on the optimal share is assessed. We present and explain several surprising findings, including a negative impact of CO2 prices on optimal wind deployment

Renewable Electric Energy Integration: Quantifying the Value of Design of Markets for International Transmission Capacity

Integrating large quantities of supply-driven renewable electricity generation remains a political and operational challenge. One of the main obstacles in Europe to installing at least 200 GWs of power from variable renewable sources is how to deal with the insufficient network capacity and the congestion that will result from new flow patterns. We model the current methodology for controlling congestion at international borders and compare its results, under varying penetrations of wind power, with a model that simulates an integrated European network that utilises nodal/localised marginal pricing. The nodal pricing simulations illustrate that congestion - and price - patterns vary considerably between wind scenarios and within countries, and that a nodal price regime could make fuller use of existing EU network capacity, introducing substantial operational cost savings and reducing marginal power prices in the majority of European countries.Power market design, renewable power integration, congestion management, transmission economics

Building Blocks: Investment in Renewable and Non-Renewable Technologies

Over the last several years, there has been a nation-wide intensification of policies directed at increasing the level of renewable sources of electricity.  These environmental policy changes have occurred against a backdrop of shifting economic regulation in power markets that has fundamentally redefined the mechanisms through which investors in power plants earn revenues. Rather than base payments upon costs, revenues in many regions are now based upon fluctuating energy prices and, in some cases, supplemental payments for installed capacity. This paper studies the interaction between these two major forces that are currently dominating the economic landscape of the electricity industry.  Using data from the western U.S., we examine how the large-scale expansion of intermittent resources of generation could influence long-run equilibrium prices and investment decisions under differing wholesale power market designs.  We find that as the level of wind penetration increases, the equilibrium investment mix of other resources shifts towards less baseload and more peaking capacity.  As wind penetration increases, an “average” wind producer earns increasingly more revenue under markets with capacity payments than those that base compensation on energy revenues.   Investment; Renewable Energy; Capacity Markets