Energy-only Market Research Articles

Generation Capacity Expansion in a Risky Environment: A Stochastic Equilibrium Analysis

We cast models of the generation capacity expansion type formally developed for the monopoly regime into equilibrium models better adapted for a competitive environment. We focus on some of the risks faced today by investors in generation capacity and thus pose the problem as a stochastic equilibrium model. We illustrate the approach on the problem of the incentive to invest. Agents can be risk neutral or risk averse. We model risk aversion through the CVaR of plants' profit. The CVaR induces risk-adjusted probabilities according to which investors value their plants. The model is formulated as a complementarity problem (including the CVaR valuation of investments). An illustration is provided on a small problem that captures several features of today's electricity world: a choice often restricted to coal and gas units, a peaky load curve because of wind penetration, uncertain fuel prices, and an evolving carbon market. We assess the potential of the approach by comparing energy-only and capacity market organizations in this risky environment. Our results can be summarized as follows: a deterministic analysis overlooks some changes of capacity structure induced by risk, whether in the capacity market or energy-only organizations. The risk-neutral analysis also misses a shift towards less capital-intensive technologies that may result from risk aversion. Last, risk aversion also increases the shortage of capacity compared to the risk-neutral view in the energy-only market when the price cap is low. This may have a dramatic impact on the bill to the final consumer. The approach relies on mathematical programming techniques and can be extended to full-size problems. The results are illustrative and may deserve more investigation.

Assessing the Impacts of Capacity Mechanisms on Generation Adequacy With Dynamic Simulations

There have been many debates over whether the energy-only electricity market will be able to provide a reasonable investment signal. So far, many diverse designs of capacity mechanisms have been proposed in relation to the adequacy problem. Researchers have conducted many qualitative studies of capacity mechanisms, but quantitative studies have largely been ignored. The framework for examining the impacts of market designs on generation adequacy considering various generation technologies have not been maturely developed. This paper focuses on developing this framework and finding out how effective capacity mechanisms are in different market conditions. To cover investment under uncertainty, we will introduce different utility functions representing risk attitudes and apply the expected utility theory to the investment decision. Finally, we will examine the investment decision sensitivity of the risk components such as the risk-attitude, the error of forecast peak load, and the forced outage rate and evaluate the performance of three market designs with dynamic simulations: an energy-only market, a capacity payment model, and a capacity demand curve model.

Long-Term Capacity Adequacy in Electricity Markets: Reliability Contracts vs Capacity Obligations

In this paper, we study the problem of long-term capacity adequacy in electricity markets. Two investment incentive mechanisms, Capacity obligations and Reliability contracts, are analyzed and compared to the benchmark design, the energy-only market. We use the dynamic programming method and real option theory to develop two dynamic models that enable one to assess the optimal market design for ensuring sufficient generation capacity to meet future demand at efficient cost (the deterministic model) and to analyze the optimal timing of investments when uncertainties in future load and fuel prices are considered (the stochastic model). The effects of different factors on investment strategies, such as the pricing of CO2 and differences between construction delays and cost structures of the new technologies, are also analyzed. The numerical results show that: (1) the reliability contract scheme would be the more cost-efficient mechanism, ensuring the long term system adequacy and encouraging earlier and adequate new investments in the system, compared to the capacity obligation method which would result in over-investment and price manipulations; (2) short lead time technology would be preferred with the capacity obligation design, while cost competitive technology would be chosen with the reliability contract scheme; (3) the pricing of CO2 and the taking into account of uncertainties would affect investment strategies but would have no impact on the effectiveness of the reliability contracts scheme.

Generation capacity adequacy in interdependent electricity markets

This paper deals with the practical problems related to long-term security of supply in regional electricity markets with transmission constraints. Differences between regulatory policies and market designs in terms of generation adequacy policies may distort the normal functioning of the neighboring markets, as well as the reliability of supply. We test the effect of heterogeneous regulatory design between two interdependent markets: energy-only market, price-capped market without capacity mechanisms and price-capped markets with forward capacity contracts obligation. We rely on a long-term market simulation model in system dynamics that characterizes expansion decision in a competitive regime. The results show that differences in market designs affect both price and reliability of supply in the two markets. We examine both the short and long terms effect, and how free-riding may occur where capacity adequacy policies are adopted in one market but not the other. The main finding is that the lack of harmonization between local markets in policies to ensure capacity adequacy may lead to undesirable side effects.

Are the British electricity trading and transmission arrangements future-proof?

In Great Britain, electricity is traded in an energy-only market that relies upon bilateral trading until shortly before real time. The GB System Operator also uses bilateral trading to respond to changes in demand and generation and resolve transmission constraints. Prices are not explicitly spatial, although well-placed generators can charge the system operator more for their output. This paper argues that these arrangements are not well-suited for the challenges of accommodating nearly thirty percent of intermittent wind generation, often located far from demand. The market design already implemented in the north-eastern United States is likely to be more efficient.

The large-scale integration of wind generation: Impacts on price, reliability and dispatchable conventional suppliers

This work examines the effects of large-scale integration of wind powered electricity generation in a deregulated energy-only market on loads (in terms of electricity prices and supply reliability) and dispatchable conventional power suppliers. Hourly models of wind generation time series, load and resultant residual demand are created. From these a non-chronological residual demand duration curve is developed that is combined with a probabilistic model of dispatchable conventional generator availability, a model of an energy-only market with a price cap, and a model of generator costs and dispatch behavior. A number of simulations are performed to evaluate the effect on electricity prices, overall reliability of supply, the ability of a dominant supplier acting strategically to profitably withhold supplies, and the fixed cost recovery of dispatchable conventional power suppliers at different levels of wind generation penetration. Medium and long term responses of the market and/or regulator in the long term are discussed.

Long-term Capacity Adequacy in Electricity Markets: Reliability Contracts VS Capacity Obligations

In this paper, we study the problem of long-term capacity adequacy in electricity markets. Two investment incentive mechanisms - Capacity obligations and Reliability contracts - are analyzed and compared to the benchmark design, the energy-only market. We use the dynamic programming method and real option theory to develop two dynamic models that enable one to assess the optimal market design for ensuring sufficient generation capacity to meet future demand at efficient cost (the deterministic model) and to analyze the optimal timing of investments when uncertainties in future load and fuel prices are considered (the stochastic model). The effects of different factors on investment strategies, such as the pricing of CO2 and differences between construction delays and cost structures of the new technologies, are also analyzed. The numerical results show that: (1) the reliability contract scheme would be the more cost-efficient mechanism, ensuring the long term system adequacy and encouraging earlier and adequate new investments in the system, compared to the capacity obligation method which would result in over-investment and price manipulations; (2) short lead time technology would be preferred with the capacity obligation design, while cost competitive technology would be chosen with the reliability contract scheme; (3) the pricing of CO2 and the taking into account of uncertainties would affect investment strategies but would have no impact on the effectiveness of the reliability contracts scheme.

Generation Adequacy via Call Options Obligations: Safe Passage to the Promised Land

In contrast to the controversial LICAP, the author's plan relies on standard hedging instruments that a mature energy-only market can support without regulatory intervention. Unlike payments for an artificial capacity product, for which there is no natural demand, energy call options provide intrinsic value to customers, since the generators who are paid for such options must pay back any windfall profits. This amounts to a risk trading arrangement where the consumers assume some of the investment risk, in exchange for reducing their price risk.

Investment Incentives and Electricity Market Design: the British Experience

There is no academic consensus on which electricity market design provides the least distorting investment incentives. Theory suggests that "energy-only market" can allow capacity cost recovery by generators. However, separate payments for capacity or reserve obligations do not need to rely on infrequent price spikes to remunerate reserve capacity. Three years after the controversial change from the compulsory British Electricity Pool with capacity payments to the decentralised energyonly New Electricity Trading Arrangements (NETA), we contrast the two market designs in terms of investment incentives, analyse NETA's balancing market failures, and review the case for regulatory support for investment.