Capacity Payments Research Articles

Competition and the single electricity market: Which lessons for Ireland?

This paper examines the evolution of the Irish Single Electricity Market in order to comply with the European Target Model for electricity. In particular, this work focuses on the challenges raised by the high concentration in the generation sector of the Irish electricity market. We examine the theoretical and empirical conditions under which forward markets promote competition in the spot and retail markets. We also investigate the impact of market concentration on the new capacity payment mechanism. In order to ensure a competitive outcome for consumers, the regulatory authorities should promote competition in the forward market; moreover, the regulator should extend regulation to the price and quantity that the dominant firm bids for holding new reliability options.

Scheduling and Provision of Secondary Frequency Reserves by Aggregations of Commercial Buildings

Due to thermal inertia, commercial buildings can provide power system frequency reserves with the heating, ventilation and air-conditioning (HVAC) systems. In this paper, we follow up on a recently proposed framework for scheduling and provision of secondary frequency control (SFC) reserves within a building aggregation. We extend this framework with a new reserve scheduling formulation, which is based on a combination of robust and stochastic optimization, to allocate reserve capacities among buildings. The HVAC system setpoints are determined by a model predictive controller, the frequency signal is tracked by heat pump (HP) control with virtually no occupant discomfort, and the tracking quality is evaluated using a dynamic HP model. In simulations, we consider an aggregation of typical Swiss office buildings and compare the robust and stochastic reserve scheduling approaches in terms of performance and complexity. Using the framework, we demonstrate the importance of energy-constrained SFC signals and asymmetric reserves with hourly resolution, and we investigate the sensitivity of reserves on the comfort zone’s width, capacity payments, and HP constraints. Finally, we show that commercial buildings can track SFC signals well and substitute generators in SFC.

The Economic Benefits of Generation Revenue Assessment in Pool-Based Market Model for Restructured Electricity Supply Industry

The electricity supply industry had undergo deregulation and restructuring toward becoming a more transparent and competitive electricity market environment. The pool market model is amongst the most preferred electricity market model. Even though it is a safe option to be more competitive and transparent electricity supply industry, there are issues on the welfare of the generators involved. This paper addresses the pricing issue in the pool market by extending the capacity payment mechanism in the single auction power pool. In the proposed model, the approach of minimum capacity payment involving the efficiency of the generators is introduced. A case study is conducted to illustrate the proposed model. An economic analysis is performed to highlight the merits of the proposed model with the pure pool in term of generation revenue. © 2016 The Authors, published by EDP Sciences.

Capacity Payments in a Cost-Based Wholesale Electricity Market: The Case of Chile

A comparison of the generator revenue and market efficiency implications of an energy and capacity payment market relative to an energy-only market for the cost-based Chilean electricity supply industry finds that, while monthly revenue volatility for generation units is significantly higher for the energy-only market, this is almost entirely explained by an increase in short-term energy price volatility. This increased short-term price volatility provides incentives for market participant behavior that enhances market efficiency and system reliability.

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.

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.

On the feasibility of providing power system spinning reserves from thermal storage

As power systems integrate more intermittent renewable generation, and as extreme weather events become more frequent with climate change, power systems are likely to require increasing amounts of spinning reserves in order to maintain reliable operation. While traditionally spinning reserves have been supplied by generators, demand-side resources can also provide reserves by increasing or decreasing consumption in response to system needs. As a major contributor to peak system loads, air conditioning equipment is a promising source of demand-side spinning reserves. Through building energy modeling and simulation, this paper demonstrates, for the first time, the technical feasibility of providing spinning reserves by curtailing air conditioning systems in commercial buildings, while maintaining occupant comfort by providing cooling from thermal storage. The economic benefits to the building owner are shown to be attractive, primarily due to capacity payments in the spinning reserves market. Furthermore, it is possible for a building equipped with thermal storage to participate in both frequency regulation and spinning reserves markets for more economic benefits as spinning reserves are less frequently deployed.

Agent-Based Modeling for Studying the Impact of Capacity Mechanisms on Generation Expansion in Liberalized Electricity Market

This paper presents an approach to solve the long-term generation expansion planning problem of the restructured electricity industry using an agent-based environment. The proposed model simulates the generation investment decisions taken by a particular agent (i.e. a generating company) in a market environment taking into account its competitors’ strategic investment. The investment decision of a particular company is modeled taking into account that such company has imperfect foresight on the future system development hence electricity prices. The delay in the construction of new plants is also explicitly modeled, in order to compute accurately the yearly revenues of each agent. On top of a conventional energy market, several capacity incentive mechanisms including capacity payment and capacity market are simulated, so as to assess their impact on the investment promotion for generation expansion. Results provide insight on the investment cycles as well as dynamic system behavior of long-term generation expansion planning in a competitive electricity industry.

Capacity Adequacy and Revenue Sufficiency in Electricity Markets With Wind Power

We present a computationally efficient mixed-integer program (MIP) that determines optimal generator expansion decisions, as well as periodic unit commitment and dispatch. The model is applied to analyze the impact of increasing wind power capacity on the optimal generation mix and the profitability of thermal generators. In a case study, we find that increasing wind penetration reduces energy prices while the prices for operating reserves increase. Moreover, scarcity pricing for operating reserves through reserve shortfall penalties significantly impacts the prices and profitability of thermal generators. Without scarcity pricing, no thermal units are profitable, however scarcity pricing can ensure profitability for peaking units at high wind penetration levels. Capacity payments can also ensure profitability, but the payments required for baseload units to break even increase with the amount of wind power. The results indicate that baseload units are most likely to experience revenue sufficiency problems when wind penetration increases and new baseload units are only developed when natural gas prices are high and wind penetration is low.

Capacity payments to secure electricity supply? On the future of Germany’s power market design

Although the objectives of the Energiewende (energy transition) are broadly accepted in Germany, the practical ways of achieving them remain highly contentious. In particular, the question of whether and how security of supply can be guaranteed over the course of this profound transformation of the energy system is currently the subject of controversy in the scientific and public debate. Recently, calls for additional payments to power plant operators for providing generation capacity have grown increasingly loud. But the introduction of capacity payments of this sort could have far-reaching consequences for the future organisation of Germany’s electricity supply. Therefore, the political decision on this issue - which is scheduled for this year - should not be made without a sound scientific analysis. Basically, measures aimed at guaranteeing security of supply must address the possible causes of capacity shortages as broadly as possible. When designing such measures, besides security of supply, additional objectives such as cost-effectiveness and the environmental and social acceptability of electricity supply should also be taken into account. Capacity payments only partially meet these requirements. Moreover, once introduced, they are difficult to adapt, or revise even, to suit changing framework conditions. This is particularly problematic in view of the current lack of clear evidence for future security of supply problems. Therefore, introducing capacity payments at this point in time would not appear to be constructive. It would make more sense to introduce instead a mix of measures which would strengthen the electricity market, create conditions for feeding in electricity from renewable energy sources as and when required, and set incentives for the expansion of grid capacity, storage systems and demand side management. Should security of supply still appear uncertain under these changed framework conditions, the introduction of a strategic reserve, which would be held by the regulatory authority or the transmission system operator, is recommended - not, however, the creation of an entirely new, additional market segment in the form of a capacity market.

Scenarios of Resource Adequacy in ERCOT: Mandated Reserve Margin, Impact of Environmental Regulations and Integration of Renewables

Among four different scenarios that were evaluated relative to a reference case using an economic dispatch model, the one mandating a 13.75 percent reserve margin leads to the lowest average wholesale price of electricity, even with the estimated cost of capacity payments added. However, design details of a capacity market can certainly lead to higher prices and inadequate capacity at times. The environmental regulations cause significant retirements and uncertainty in the market, resulting in low reserve margins and high prices. If all built, planned renewables capacity will help resource adequacy, especially if peak contribution improves.

Development of Performance-Based Two-Part Regulating Reserve Compensation on MISO Energy and Ancillary Service Market

FERC Order 755 requires each RTO/ISO to use market-based mechanisms to select and compensate frequency regulation resources based on a two-part payment methodology, i.e., a capacity payment to keep the capacity in reserve and a performance payment to reflect the amount of work each resource performs in real-time in response to the system operator's dispatch signal. This paper discusses how MISO enhanced its market rules to implement a market-based regulation performance payment. The market enhancement includes four key areas: quantifying the movement of regulation, modifications to the market clearing processes, performance accuracy measurement, and performance-based two-part regulation compensation.

Winners and losers of market coupling

The integration of electricity markets creates new challenges to the regulators in their commitment to guarantee security of supply at affordable prices. Even at a national level, designing policies for electricity markets is an extremely complex task; but this is exacerbated in the case of market coupling, since different policies may be applied at the two ends of an interconnector. Furthermore, investors will make decisions based on their profitability, which depends among other things on the possibility of importing (exporting) from (to) neighboring countries, and will not necessarily coincide with the aims of the regulators or the consumers. We use simulation to analyze different scenarios of interconnection and capacity payments in two case studies: Colombia – Ecuador and Great Britain – France. These two cases exhibit important differences in terms of resources and complementarity between the countries, which lead to quite different outcomes for the same policies. The simulation results show that the potential benefits of market coupling are strongly related to complementarity. However, identifying the policies that should be implemented in order to achieve those benefits is far from obvious. In particular, large generation investment requirements and significant storage capacity in the region may lead to counterintuitive outcomes for certain policies.

Consumption Schedule Leveling by Implementation of Two-Rate Capacity Payment

In order to ensure consumers' motivation for daily schedule leveling, the article suggests the two-rate capacity payment implementation on the wholesale power energy and capacity market (WPECM) in case of industrial generation growth. Special attention is given to the real power system model research. As follows from results of economic effect calculation, it is profitable for consumers to regulate their consumption. Undoubtedly, the present analysis can't give completely reliable result in the question of the price change in case of two-rate capacity payment implementation. But it becomes possible to achieve a definite result in consumers' motivation growth.

Robustness of Capacity and Energy-Only Markets - A Stochastic Dynamic Capacity Investment Model

We present a multi-feature stochastic dynamic capacity investment model that includes realistic investor behavior. The long-term investment model includes features, such as strategic bidding of generators, price elasticity of demand, and ramping constraints. It incorporates an iterative procedure of finding a sensible electricity price forecast closely depicting real-world investor behavior in a single computable model.Using this model, we assess the robustness and the total bill of generation of a capacity market compared to an energy-only market as capacity markets are increasingly considered worldwide due to rising feed-in from renewables. To estimate unplanned unavailabilities, we analyze a novel data set of the European Energy Exchange describing unplanned unavailability incidents. Applying the model to the Great Britain market, we find that capacity markets are more robust to unplanned unavailabilities of conventional generation in terms of the total bill of generation and price volatility. At the same time, capacity markets induce additional costs through capacity payments. Therefore, we jointly analyze the total bill of generation and the robustness with different levels of reserve margins. Our results show that there is a promising area of efficient trade-offs between the two targets affordability and reliability in the range of reserve margins between 0 and 15%.

Rethinking how to support intermittent renewables

Few intermittent renewable power projects would have been deployed if specific policy instruments had not been implemented. Common policy instruments include the feed-in tariff, the feed-in premium and the quota system. Based on a numerical analysis, this paper shows that these specific policy instruments do not necessarily facilitate the deployment of valuable energy sources because they ignore the cost of intermittency. A valuable intermittent energy source is defined here as a source of energy which requires little financial support and which limits the need for capacity payments in order to ensure the security of supply. Based on insights from the numerical analysis, a new policy instrument is suggested: a multiplicative premium. This type of policy instrument would be a least cost approach to securing a certain quantity of intermittent generation.

Generation Investment Evaluation Model in Electricity Market with Capacity Mechanisms

This paper proposes a new explicit approach for a generating company to evaluate investments in a liberalized electricity market with capacity mechanisms. The investment framework consists of two levels of investment problems. The upper problem consists of an optimization problem which models the expected future investments from all the companies in the market over the lifetime of the investment plant that the company is evaluating. A ‘prototype’ of future investments and a retirement schedule are defined using dynamic programming. The lower problem corresponds to the profit evaluation of the new investment plant for each year against the ‘prototype’ investment schedule obtained in the upper problem. The capacity mechanism is included both in the prototype future system expansion formulation as well as in the net revenue calculation of the new plant. Two types of capacity mechanisms have been modeled in the investment framework, i.e. capacity payment and capacity market. The model has been tested using a test system based on Great Britain’s Seven Years Statement. Three types of investment technologies have been evaluated, i.e. nuclear, coal and CCGT. Results show that in the capacity payment proportional to the LOLP, a higher VOLL on average increases the investments from all the companies in the prototype system expansion. On the other hand, a steeper demand curve for the ICAP market results in more investments in the prototype expansion schedule. Comparing the three investment alternatives, a nuclear power plant which has a longer lifetime is the most riskiest and the most affected by the uncertainty in capacity payment and capacity market followed by the coal and the CCGT plants.

Capacity payment impact on gas-fired generation investments under rising renewable feed-in — A real options analysis

We assess the effect of capacity payments on investments in gas-fired power plants in the presence of different degrees of renewable energy technology (RET) penetration. Low variable cost renewables increasingly make investments in gas-fired generation unprofitable. At the same time, growing feed-in from intermittent RETs amplifies fluctuations in power generation, thus entailing the need for flexible buffer capacity—currently mostly gas-fired power plants. A real options approach is applied to evaluate investment decisions and timing of a single investor in gas-fired power generation. We investigate the necessity and effectiveness of capacity payments. Our model incorporates multiple uncertainties and assesses the effect of capacity payments under different degrees of RET penetration. In a numerical study, we implement stochastic processes for peak-load electricity prices and natural gas prices. We find that capacity payments are an effective measure to promote new gas-fired generation projects. Especially in times of high renewable feed-in, capacity payments are required to incentivize peak-load investments.

The EU internal electricity market: Done forever?

Taking a quarter-century to build Europe's internal market for electricity may seem an incredibly long journey. The aim of achieving a Europe-wide market might be reached, but it has involved – and continues to involve – a process subject to many adverse dynamics. The EU internal market may derail greatly in the coming years from the effects of a massive push for renewables, as well as a growing decentralization of the production-consumption loop. Moreover, a serious concern is the risk of a definitive fragmentation of the European electricity market due to uncoordinated national policy initiatives with respect to, for example, renewable support and capacity payments.

Rethinking How to Support Intermittent Renewables

Intermittent renewable energy sources, including solar and wind power, typically remain more expensive than conventional power sources. As a consequence, few intermittent power projects would have been deployed if specific policy instruments had not been implemented. Existing policy instruments facilitating the deployment of intermittent renewable energy technologies include the feed-in tariff, the feed-in premium and the quota system. Based on a numerical analysis, it is shown that these specific policy instruments do not necessarily facilitate the deployment of valuable energy sources because they ignore the cost of intermittency. A valuable intermittent energy source is defined here as a source of energy which requires little financial support and which limits the need for capacity payments in order to ensure the security of supply. Based on insights from the numerical analysis, a new policy instrument is suggested: a multiplicative premium. This type of policy instrument would increase the likelihood that valuable intermittent energy assets are deployed in priority.