Ove Wolfgang

Simulating equilibrium prices in oligopoly power markets

One of the main objectives of deregulation has been to achieve more efficient power systems. Exercise of market power can significantly increase prices in the power market thereby reducing the efficiency. This makes it important for regulatory bodies to survey and intervene if the market is malfunctioning. In hydropower systems this is extra difficult to reveal because the resource for the supply side is stochastic in its nature. In this paper a method for simulation of the price establishment in power systems is suggested. The characteristics of this model are discussed using the English power market as a case.

Reduction of CO 2 emissions due to wind energy - methods and issues in estimating operational emission reductions

This paper presents ways of estimating CO2 reductions of wind power using different methodologies. Estimates based on historical data have more pitfalls in methodology than estimates based on dispatch simulations. Taking into account exchange of electricity with neighboring regions is challenging for all methods. Results for CO2 emission reductions are shown from several countries. Wind power will reduce emissions for about 0.3-0.4 MtCO2/MWh when replacing mainly gas and up to 0.7 MtCO2/MWh when replacing mainly coal powered generation. The paper focuses on CO2 emissions from power system operation phase, but long term impacts are shortly discussed.

Norwegian pumped hydro for providing peaking power in a low-carbon European power market — Cost comparison against OCGT and CCGT

This paper presents an analysis of the cost of providing peak generation from new OCGT, CCGT and Norwegian pumped hydro plants in a European power system with high penetration of wind and solar power. A method for calculation of the Levelized Cost of Peak Generation (LCPG) is proposed, which builds on the well-established metric Levelized Cost of Electricity (LCOE). Results from a case study shows that building new reversible pumping stations between existing reservoirs in the Norwegian hydro system are economical advantageous over new CCGT and OCGT plants in Northern Europe, taking into account additional costs of subsea cables across the North Sea and corresponding reinforcements of the mainland grid. The study also shows the importance of giving interconnectors access to capacity markets across borders to obtain as low cost as possible for firm capacity in a future European system dominated by variable renewable production.

A market for reserve capacity: experience and simulation

This paper addresses the market for reserve capacity that was introduced in Norway in 2000 as a consequence of a narrowing capacity margin. The new element introduced by this market is a market-based payment for availability. A simulation model is developed to show how this market interacts with the spot and regulating markets and leads to an equilibrium. We study how changed spot demand and changed demand for capacity reserves affect the joint equilibrium and the probability for load shedding.

Value of additional Norwegian hydropower to the European electricity system

The increase of volatile generation from wind and solar power in Europe leads to a higher demand for flexibility in the electrical energy system. As part of the HydroBalance project this paper assesses the potential of Norwegian hydropower to provide this flexibility to the European energy markets by simulating to different scenarios for the expansion of hydropower in Norway. A comparison of the resulting cost reduction of variable system costs with necessary investment costs shows that there is an economic benefit of Norwegian hydropower to the European system especially when providing cross-border balancing.

A methodology to assess the impact of capacity remuneration mechanisms in a detailed power system model

A methodology is proposed to implement a capacity constraint in an iterative investment algorithm, which can be applied to detailed power system models. An additional support for the investment in generation capacity is introduced, in order to fulfil given capacity requirements. The amount of the support is determined based on the generation capacity margin and the surplus of the most profitable power plant. Now, convergence of the algorithm is achieved when the income plus the support equals the long-run marginal cost for the investment assets. The estimated support represents the shadow-cost of the capacity requirement respectively the capacity price. The methodology is applied to a simplified model and a detailed Northern European power system model. In the first case the performance of the methodology is validated against an optimal solution. In the second case the performance is assessed in the case of a real-system analysis. The results report a rather well consistency between the iterative approach and the optimal solution from the simplified LP-model. Furthermore, when applying the methodology to the Northern European model, the capacity constraint can be fulfilled, while a value of the necessary support for generation capacity is estimated.