Resource adequacy reliability and the impacts of capacity subsidies in competitive electricity markets

Motivated by recent interventions by the states of New Jersey and Maryland and the introduction of PJM's Minimum Offer Price Rule (MOPR) for capacity markets, we analyze the impact of subsidized government investments in electrical generation on electricity markets. We extend the model of Joskow and Tirole (2007) to address the interconnected nature of the PJM grid by considering a market with two different locations connected by transmission lines. We assume that these lines are constrained during peak periods in a manner similar to Borenstein et al. (2000). We find that government intervention has a significant potential for adverse effects on grid resource adequacy and reliability. In our analysis, subsidized investment in baseload capacity is never optimal. In the short run government provision of base capacity displaces competitive base capacity, which reduces the private provision of peak capacity. In the long run, the threat of intervention imposes costs on suppliers in the form of an expected regulatory taking. As a result, resource adequacy decreases in both markets. If governments respond to this state of affairs by subsidizing further supply additions, expectations of intervention are reinforced and competitive capacity supply further diminishes. MOPR attempts to mitigate this vicious cycle by screening out non-economic bids for new capacity. To the extent market participants view MOPR as a credible policy, it succeeds in this goal. In this case, subsidized capacity additions do not perturb the efficiency of market outcomes as long as any charges to consumers to support the subsidy are lump sum in nature. In this case, subsidized resources simply succeed in capturing rents from taxpayers.     

Modeling long-term dynamics of electricity markets

In the last decade, many countries have restructured their electricity industries by introducing competition in their power generation sectors. Although some restructuring has been regarded as successful, the short experience accumulated with liberalized power markets does not allow making any founded assertion about their long-term behavior. Long-term prices and long-term supply reliability are now center of interest. This concerns firms considering investments in generation capacity and regulatory authorities interested in assuring the long-term supply adequacy and the stability of power markets. In order to gain significant insight into the long-term behavior of liberalized power markets, in this paper, a simulation model based on system dynamics is proposed and the underlying mathematical formulations extensively discussed. Unlike classical market models based on the assumption that market outcomes replicate the results of a centrally made optimization, the approach presented here focuses on replicating the system structure of power markets and the logic of relationships among system components in order to derive its dynamical response. The simulations suggest that there might be serious problems to adjust early enough the generation capacity necessary to maintain stable reserve margins, and consequently, stable long-term price levels. Because of feedback loops embedded in the structure of power markets and the existence of some time lags, the long-term market development might exhibit a quite volatile behavior. By varying some exogenous inputs, a sensitivity analysis is carried out to assess the influence of these factors on the long-run market dynamics.     

Mothballing in power markets: An experimental study

The deregulation of many electricity markets over the last two decades raises a number of issues, among which: securing adequate investments in capacity, and the possibility of cyclical behavior in capacity, are important for security of supply. A number of policies and market mechanisms aiming for capacity adequacy and market stability exist; in this paper we focus on one of these, mothballing of generation capacity. In electricity markets, mothballing is the possibility for a power generation company to temporarily withdraw generation capacity for a time, often for a year or more. Our hypothesis is that mothballing will help to stabilize markets, but at the same time increase prices. We test this hypothesis using laboratory experiments, with a simplified model of a generic electricity market. We report an experiment with twelve markets, where subjects make investment decisions; half of them had full capacity utilization (T1) and the other half had the option to mothball capacity (T2). The predictions of the effects of mothballing were confirmed in the experimental markets: prices and generation capacity exhibit clear cycles in T1, and damped cycles in the second set of experiments, T2. Furthermore, mothballing leads to higher prices on average.     

Generation adequacy and transmission interconnection in regional electricity markets

The power system capacity adequacy has public good features that cannot be entirely solved by electricity markets. Regulatory intervention is then necessary and established methods have been used to assess adequacy and help regulators to fix this market failure. In regional electricity markets, transmission interconnections play an important role in contributing to adequacy. However, the adequacy problem and related policy are typically considered at a national level. This paper presents a simple model to study how the interconnection capacity interacts with generation adequacy. First results indicate that increasing interconnection capacity between systems improves adequacy up to a certain level; further increases do not procure additional adequacy improvements. Furthermore, besides adequacy improvement, increasing transmission capacity under asymmetric adequacy criteria or national system characteristics could create several concerns about externalities. These results imply that regional coordination of national adequacy policies is essential to internalise adequacy of cross-border effects.     

Supporting the externality of intermittency in policies for renewable energy

We analyse the joint problem of supporting renewables and resource adequacy in a liberalised electricity market and present a detailed model-based comparison of two alternative policies. We undertake this in the context of the British market. We show how, ceteris paribus, the progressive replacement of coal with wind imposes extra costs of reserve and evaluate alternative way to meet this, whether through capacity payments funded by customers, or a reliability requirement on wind generators with capital cost or energy feed-in subsidies. We consider the reality of market concentration and the extent to which pragmatic regulation could allow prices to rise above marginal cost to reduce the extent of direct subsidies and complex market designs. We also evaluate the implied cost of carbon reduction in a progressive replacement of coal with wind, when the security is maintained by extra peaking gas. We find that support through capital allowances rather than the energy market is more efficient.     

Policy changes and the dynamics of capacity expansion in the Swiss electricity market

Capacity of supply is a crucial matter in electricity markets as it directly influences reliability of supply, price volatility and blackout risk. In this paper, we analyse the dynamics of capacity expansion in the Swiss electricity market and the impact of different policies such as nuclear phaseout and management of electricity exchanges – imports and exports – policies. This article develops the conceptualization model presented in [Ochoa, P., 2007b. Policy changes in the Swiss electricity market: a system dynamics analysis of likely market responses. Socio-Economic Planning Sciences 41 (4):336–349.]. We build a system dynamics model based on the dynamics of capacity expansion explained in the latter paper and present and analyse different scenarios. We conclude that international electricity exchanges are important for the Swiss market as they help to lower costs and to increase the income of the utility companies; however, we illustrate the need for explicit policies for managing imports and exports of electricity to avoid import dependence from neighbouring countries.     

Dynamic assessment of capacity investment in electricity market considering complementary capacity mechanisms

This paper proposes a decentralized market-based model for long-term capacity investment decisions in a liberalized electricity market. Investment decisions are fundamentally based on total revenues gained by investors. In most electricity markets, the complementary mechanisms are designed to ensure a desired level of reliability while covering investment costs of the suppliers. In such an environment, investment decisions are highly sensitive to expectation of price signals in both of energy market and capacity mechanisms. In this work, the system dynamics concepts are used to model the structural characteristics of electricity market such as, long-term firms’ behavior and relationships between variables, feedbacks, and time delays by appropriately bundling the energy market and capacity mechanisms. The market oriented capacity price as well as non-competitive capacity payments and a proposed hybrid capacity mechanism are linked with the energy market in the model. Such a decision model enables both the generation companies and the regulators gaining perfect insights into the possible consequences of different decisions they make under different policies and market conditions. In order to examine the performance of the electricity market with different capacity mechanisms, a case study is presented which exhibits the effectiveness of the proposed model.     

Electricity markets for energy,flexibility and availability — Impact of capacity mechanisms on the remuneration of generation technologies

Increased shares of Renewable Energy Sources (RES) to fulfill ambitious European policy targets, mothballing or decommissioning of existing units, and absent investments lead to concerns about the system and market adequacy. To restore market adequacy, capacity mechanisms (CMs) are widely discussed and implemented in various types. They are intended to provide sufficient and clearly perceivable long-term price signals for available capacity. As integral part of the market, CMs interact with the other markets. Markets like day-ahead markets are used to trade energy. Imbalance markets or reserve requirements are examples for markets for flexibility. Among others, green certificates are in place to value emission-neutral injection from RES. Resulting altered prices and shifting remuneration have effects on all generation technologies. CMs may affect participating technologies by imposing a capacity demand. A resulting change in the generation mix may also have an impact on non-participating technologies. Two gaps can be identified in the discussion and modeling of CMs in the literature. First, proposed game-theoretic equilibrium models fall short in representing the distinctive features of different types of CMs. Second, most models incorporating CMs found in the literature only focus on the interaction with the energy-based market. Valid assessments of CM need to consider the interaction of remuneration for available capacity and flexibility, and the indirect interaction with the remuneration for emission-neutral RES. Two formulations of a game-theoretic market equilibrium model are proposed which represent specific CMs with its distinctive features, in particular a market-wide centralized capacity market (cCM) and targeted strategic reserves (SRs). Moreover, the equilibrium models explicitly combine the CMs with markets for flexibility and indirect with remuneration for RES. We contribute to the discussion of CMs by quantifying the interactions and shifting shares of remuneration. Based on the interaction between CMs and remuneration for emission-neutral injection, the effect of CMs on non-participating RES is described. We conclude based on the case study results that targeted mechanisms, like SRs, implemented with the single purpose of ensuring availability introduce large inefficiencies in the system by missing on the interaction between availability and flexibility. In contrast, a market-wide cCM provides a beneficial outcome for all technologies. At the same time, it yields a sufficient high reserve margin at lowest cost. It provides clear signals for the different values of energy-output, flexibility, availability and emission-neutral injection.     

Inflow shortages in deregulated power markets — Reasons for concern?

In many countries hydropower constitutes a large share of the electricity producing capacity. In the earlier regulated electricity markets, production capacities exceeded demand due to security of supply concerns. The present deregulated markets base investments upon profitability alone, and security of supply issues are claimed to be less important. Market operators trust the pricing mechanism in competitive markets to clear. Then low inflow constitutes a less problem. Several markets, both under regulated and deregulated regimes, have faced serious droughts. Some of them have experienced problems with market clearance (Chile, Brazil, California) while other markets functioned well (The Nordic market). Important features to the market response are the flexibility of demand, the pattern of inflow shortage, the storage capacities, the possibility of trade between regions with different production technologies, and the market design and concentration. We apply an empirical based market model to simulate the effects under two inflow shortage scenarios in an international market with combined hydro and thermal capacities and restricted transmission capacities. We compare the scenarios with actual events and show that the model and the real market outcome are comparable. The simulations do not reveal any problems with the functioning of the market, which should calm down the anxiousness about security of supply in deregulated markets with stochastic energy supply.     

Regulation and development of the Argentinean gas market

Gas markets are becoming increasingly important around the world and the long-term evolution of these markets is of strategic importance for many countries. This makes it essential to understand how regulation and intervention in these markets affects the long-term prospect for the secure supply of gas. We use Argentina as a case to illustrate some of the issues and consequences of gas regulation. Argentina is a country that has had a significant increase in the use of gas over the years, and where a potential gas deficit looms large in the present and the future. Based on a simulation model developed to understand the supply of gas in Argentina, we discuss how regulation will influence the long-term supply of gas in both Argentina and surrounding countries. Using the model, we develop a series of scenarios to highlight the consequences of different current and possible future interventions in the market by the Regulator. Finally, we discuss short-term regulatory options to reduce the impact of a gas deficit, and the possibility of securing the long-term supply of gas in Argentina.     

The electricity generation adequacy problem: Assessing dynamic effects of capacity remuneration mechanisms

Following liberalization reforms, the ability of power markets to provide satisfactory incentives for capacity investments has become a major concern. In particular, current energy markets can exhibit a phenomenon of investment cycles, which generate phases of under and over-capacity, and hence additional costs and risks for generation adequacy. To cope with these issues, new mechanisms, called capacity remuneration mechanisms (CRM), have been (or will be) implemented. This paper assesses the dynamic effects of two CRMs, the capacity market and the strategic reserve mechanism, and studies to what extent they can reduce the investment cycles. Generation costs and shortage costs of both mechanisms are also compared to conclude on their effectivity and economic efficiency. A simulation model, based on system dynamics, is developed to study the functioning of both CRMs and the related investment decisions. The results highlight the benefits of deploying CRMs to solve the adequacy issue: shortages are strongly reduced compared to an energy-only market. Besides, the capacity market appears to be more beneficial, since it experiences fewer shortages and generation costs are lower. These comparisons can be used by policy makers (in particular in Europe, where these two CRMs are mainly debated) to determine which CRM to adopt.     

Robust resource adequacy planning in the face of coal retirements

We investigate the resource adequacy requirements of the PJM Interconnection, and the sensitivity of capacity procurement decisions to the choice of reliability metric used to measure resource adequacy. Assuming that plants fail independently, we find that PJM's 2010 reserve margin of 20.5% was sufficient to achieve the stated reliability standard of one loss of load event per ten years, with 0.012 expected loss of load events per year. PJM could reduce reserve margins to 13% and still achieve adequate levels of reliability as measured by the 2.4 Loss of Load Hours metric and the 0.001% Unserved Energy metric, which are used by other U.S. and international systems. A reserve margin of 13–15% would minimize long-run system costs. Reducing reserve margins from 20.5% to 13% in 2010 would have reduced PJM's capacity procurement by 11 GW, the same amount of coal capacity that PJM has identified as at high risk of retirement. We also investigate the risk posed by correlated failures among generators, a risk traditionally not modeled by system planners. We illustrate that three types of correlated failures may increase outage risks: natural gas supply disruptions, reduced reliability among generators during winter months, and the simultaneous shutdown of multiple nuclear generators for regulatory reasons.     

Pricing of reserves: Valuing system reserve capacity against spot prices in electricity markets

This paper models the interdependencies between markets for secondary reserve capacity and spot electricity to derive the pricing of reserves under equilibrium conditions. Starting with the indifference condition between offering in both markets, the reservation price is derived from the opportunity cost consideration and the unit commitment conditions in a fundamental interrelated market framework. The reserve market examined compares widely to the German market for secondary reserves, but the general approach may also be used to investigate other reserve markets. The approach explores and formalizes the influence of reserve capacity on the spot market supply function. A numerical solution procedure is provided to this non-trivial case of market interaction. The model is used to estimate the expected reservation price development over the last years in Germany.     

Dynamic model for market-based capacity investment decision considering stochastic characteristic of wind power

This paper proposes a decentralized market-based model for long-term capacity investment decisions in a liberalized electricity market with significant wind power generation. In such an environment, investment and construction decisions are based on price signal feedbacks and imperfect foresight of future conditions in electricity market. System dynamics concepts are used to model structural characteristics of power market such as, long-term firms’ behavior and relationships between variables, feedbacks and time delays. For conventional generation units, short-term price feedback for generation dispatching of forward market is implemented as well as long-term price expectation for profitability assessment in capacity investment. For wind power generation, a special framework is proposed in which generation firms are committed depending on the statistical nature of wind power. The method is based on the time series stochastic simulation process for prediction of wind speed using historical and probabilistic data. The auto-correlation nature of wind speed and the correlation with demand fluctuations are modeled appropriately. The Monte Carlo simulation technique is employed to assess the effect of demand growth rate and wind power uncertainties. Such a decision model enables the companies to find out the possible consequences of their different investment decisions. Different regulatory policies and market conditions can also be assessed by ISOs and regulators to check the performance of market rules. A case study is presented exhibiting the effectiveness of the proposed model for capacity expansion of electricity markets in which the market prices and the generation capacities are fluctuating due to uncertainty of wind power generation.     

The effect of ethanol policies on the vertical price transmission in corn and food markets

This paper analyzes the impact of ethanol policies on price transmission along the food supply chain. We consider the US corn sector and its vertical links with food and ethanol (energy) markets. We find that ethanol is a source of imperfect price transmission in the food supply chain. Ethanol, however, alters price transmission only under a binding blender's tax credit and only from food to corn (not vice versa). Our results indicate that ethanol weakens the response of corn and food prices in terms of their level changes to shocks occurring in agricultural (corn and food) markets. The results are robust to different assumptions on the model parameters. Although market power has previously been identified as a source of imperfect price transmission in the food supply chain, our findings show that in the presence of ethanol, the imperfect price transmission may occur even if markets are perfectly competitive. This warrants careful evaluation of markets before any policy intervention.     

Cycles in deregulated electricity markets: Empirical evidence from two decades

In this article, we discuss the “cycle hypothesis” in electricity generation, which states that the introduction of deregulation in an electricity system might lead to sustained fluctuations of over- and under-capacity. The occurrence of cycles is one of the major threats for electricity markets as it affects the security of supply, and creates uncertainty in both the profitability of electricity companies and in consumer prices. We discuss the background for these cycles using analogies with other capital-intensive industries, along with evidence from the analysis of behavioral simulation models as well as from experimental electricity markets. Using data from the oldest deregulated markets we find support for the hypothesis in the case of the English and Chilean markets, based on an autocorrelation analysis. Evidence from the Nordpool market is more ambiguous, although we might be observing the first half of a cycle in generation capacity. Comparing a simulation of the English market performed in 1992 with the actual performance we can observe that the qualitative behavior of the model is consistent with the actual evolution. Finally, we discuss possible mechanisms for damping cycles in electricity generation, such as mothballing, capacity payments, and reliability markets.     

A regional energy paradox—the case of Central Norway

Central Norway is expected to have a gap of 8 TWh in 2010 because of heavy investments in energy-intensive industries. The region has two landing sites for natural gas and a considerable potential for wind power to cover the gap. Small-scale hydropower and upgrading of existing hydropower plants also constitute a regional energy potential. Paradoxically, the most realistic investment prospect seems to be extensive investments in new transmission lines to cover the supply deficit. The aim of this paper is to present a problem of regional supply security and public intervention to illustrate and discuss the challenges of arriving at long-term capacity adequacy in deregulated electricity markets.     

Re-examining uranium supply and demand: New insights

In this paper, we derive a simultaneous system of equations which aims at analysing the uranium supply and demand. In addition to reviewing and updating previous studies dealing with the uranium market analysis, in particular Amavilah (1995), the contribution of the paper lies in putting attention to some questions which are still either controversial or unanswered. They are especially related to the controversial hypothesis of the interdependence between uranium market and other commodities markets, both, with respect to the demand side, i.e. oil and coal markets, and the supply side, i.e. gold market. The paper also casts lights on electricity and uranium price effects on uranium demand as well as on the simultaneous interdependencies that may exist between nuclear consumption and nuclear installed capacity.     

Electricity market design for generator revenue sufficiency with increased variable generation

We present a computationally efficient mixed-integer program (MIP) that determines optimal generator expansion decisions, and hourly unit commitment and dispatch in a power system. The impact of increasing wind power capacity on the optimal generation mix and generator profitability is analyzed for a test case that approximates the electricity market in Texas (ERCOT). We analyze three market policies that may support resource adequacy: Operating Reserve Demand Curves (ORDC), Fixed Reserve Scarcity Prices (FRSP) and fixed capacity payments (CP). Optimal expansion plans are comparable between the ORDC and FRSP implementations, while capacity payments may result in additional new capacity. The FRSP policy leads to frequent reserves scarcity events and corresponding price spikes, while the ORDC implementation results in more continuous energy prices. Average energy prices decrease with increasing wind penetration under all policies, as do revenues for baseload and wind generators. Intermediate and peak load plants benefit from higher reserve prices and are less exposed to reduced energy prices. All else equal, an ORDC approach may be preferred to FRSP as it results in similar expansion and revenues with less extreme energy prices. A fixed CP leads to additional new flexible NGCT units, but lower profits for other technologies.     

Current challenges of Germany’s energy transition project and competing strategies of challengers and incumbents: The case of direct marketing of electricity from renewable energy sources

Electricity generated by renewable energies (RES-E) already accounts for 25% of Germany’s electricity supply. This has led to recent discussions for a better market integration of RES-E. The paper examines how competing actors and their ideas on market integration developed new services for direct marketing according to their respective origins and tried to shape the regulatory framework. The paper analyses this process and explains the current shape of the field of direct marketing. Medium-sized structured actors, who favoured RES-E integration via the conventional wholesale power markets, and who formed early close coalitions with RES-E power producers at the same time, have been most successful in terms of market shares. Moreover, they have been very successful for different reasons in building-up coalitions with governance units and influencing the field rules and routines. Based on those findings, the paper will conclude with some policy advices for the future adjustment of the current regulative frameworks. As long as there is no evidence of how RES-E can be integrated most effectively and efficiently, policies should maintain a competition between different direct marketing strategies to find out which strategies serve the best in terms of achieving a successful energy transition.