Alternative Approaches for Incentivizing the Frequency Responsive Reserve Ancillary Service

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Frequency responsive reserve is the autonomous response of generators and demand response to deviations of system frequency, usually as a result of the instantaneous outage of a large supplier. This article discusses the issues that can occur without proper incentives and even disincentives, and proposes alternatives to introduce incentives for resources to provide frequency responsive reserve to ensure an efficient and reliable power system.

Introduction

The control of electrical frequency of a synchronous interconnection is one of the primary measures to maintaining a reliable and secure power system. Power system operators must hold frequency as close as possible to its nominal level (60 Hz in the United States, 50 Hz in most other areas of the world) by adjusting the generation and load balance. A constant frequency at its nominal level indicates if the aggregate generation and load are in balance. Most large interconnections will generally try to keep frequency to within 50 mHz of the scheduled frequency. The frequency of the interconnection will start to deviate from its nominal level when there is an imbalance between the supply and demand. Any supply or demand imbalance can cause this deviation. Demand and generation can vary over short time scales causing slight frequency deviations from nominal. However, the most common cause of significant deviations is from the sudden loss of a large supplier (e.g., a generator). This loss must be made up by the other resources on the grid to ensure the demand is still met. Frequency responsive reserve is the automatic response to frequency excursions, usually through turbine speed governors and frequency responsive demand response, which adjusts output or consumption to counter frequency deviations. This immediate response is needed to arrest frequency deviations before triggering under-frequency load shedding relays, triggering under- or over-frequency generation protection relays, or reaching unstable frequencies that could ultimately lead to a blackout.

Since the restructuring of the electricity sector, markets have been designed to incentivize competition for providing different services. These complex markets integrate efficient economic principles with the engineering and physics of the power system.1

Few regions in the world have an explicit ancillary service market to procure frequency responsive reserve.

In the United States, restructured markets have evolved toward a common set of market principles.2 In this design, there usually exists a two-settlement system for forward and real-time markets, with co-optimized energy and ancillary services markets, locational marginal pricing for energy, and financial transmission rights markets in place for hedging. Current ancillary services markets include spinning reserve, non-spinning reserve, and regulation.3,4 In the U.S., spinning reserve is reserve that must be online and available within 10 minutes. Non-spinning reserve must also be available within 10 minutes, but can be offline. Although the spinning reserve must come from resources that are synchronized to the grid, there are usually no enforceable requirements for the market participant to provide energy that is directly responsive to frequency, or for speed governors to be in an operational mode. Regulation is a type of ancillary service that is used to correct short-term imbalances in generation and load that happen during normal conditions. Regulation units usually must be equipped with automatic generation control. Since regulation is used to reduce the area control error at the direction of the system operator, it is not required to respond directly to frequency. The time scale for regulation is also longer than that relating to frequency responsive reserve. Few regions in the world have an explicit ancillary service market to procure frequency responsive reserve. One reason is likely because the conventional generating technologies historically had frequency responsive reserve as an inherent feature of the technology since installation. Another reason is likely because most systems, and especially those that are part of large synchronous, interconnected grids, had more response than was needed and, therefore, did not need to incentivize for more response. Both of these reasons may not hold true in future systems, based on current trends.

Recent studies have shown that the frequency response in the United States, and especially in the Eastern Interconnection, has been declining.5 Reasons for this include high governor dead bands, generators operating in modes that do not offer frequency responsive reserve (e.g., sliding pressure mode), governors that are not enabled, a reduced percentage of direct drive motor load, and many other reasons.6,7 Although at low levels today, significant penetrations of electronically coupled renewable resources like wind and photovoltaic solar power can further reduce interconnection frequency response, if they are installed without additional enhancements that can provide frequency response.8 However, the decline in frequency response may also be due to the electricity market design in some areas that may not incentivize frequency response, or in some cases offer disincentives.

The need for incentivizing frequency responsive reserve was one of the principal recommendations of an IEEE Task Force report on generation governing concerns.9 Little attention has been given to frequency responsive reserve incentives since this initial report, and no U.S. region currently has a market for this service.10 As regions begin to understand the need for a reliable frequency responsive reserve and create the standards to guide this need, it will become more important to ensure incentives are in place to assist the individual resources. In this article, we discuss the issues and possible solutions of ensuring incentives are available for resources to provide frequency responsive reserve. In our analysis, we focus on independent system operator (ISO) and regional transmission organization (RTO) regions, which already have restructured energy and ancillary services markets. However, in non-restructured areas (i.e., regulated utility areas), it is equally important for the balancing area operator to offer incentives for this response. Section II gives an overview of all of the mechanisms needed for reliable frequency control. In Section III, we give an overview of market design principles and discuss a possible flaw in the current market design where frequency response may be disincentivized. Next, Section IV describes potential changes to the existing market designs to eliminate disincentives and provide incentives for frequency responsive reserve. Section V provides a conclusion.

The need for incentivizing frequency responsive reserve was one of the principal recommendations of an IEEE Task Force report.

Section snippets

Frequency Control Overview

Frequency control is utilized with a variety of mechanisms. When a disturbance occurs, there is a set of standards and procedures that guide how balancing areas should respond. In North America, part of the response guidance is based on the North American Electric Reliability Corporation (NERC) Disturbance Control Standard (DCS).11 In Europe, the way in which

Markets and Incentives

A well-designed electricity market can be difficult to design and must carefully consider the alignment of the market incentives with the needs of the power system.24 Unintended consequences can occur, reducing the effectiveness of the market or causing undesired impacts in separate related markets. The objective of a market is to elicit an incentive for providers to supply the desired product in an economically efficient manner. The

Market Designs Modifications to Incentivize the Frequency Responsive Reserve Ancillary Service

We now discuss some potential resolutions and new or modified market designs to provide alternative levels of incentives, with varying levels of market design effort. There are two, usually conflicting goals, in market design. The more complexities that are included to characterize the responses of the market participants and system will better reflect what is needed as the desired response. It should also limit market participant gaming. However, the more complex the market design, the more

Conclusions

This article discusses the needs for introducing incentives and eliminating disincentives for resources on the electricity grid to provide frequency responsive reserves. In some areas, especially in the Eastern Interconnection of the United States, the frequency response has been in a constant decline for the past 20 years. Given that load and generation have been increasing during this time, this trend should not occur. If the trend continues, the system may be at risk of under-frequency load

Erik Ela is an Engineer with the National Renewable Energy Laboratory specializing in power system operations, market design, and the integration of renewable and emerging technologies into power systems. He previously worked with the New York ISO developing and improving products for operations and market design.

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Erik Ela is an Engineer with the National Renewable Energy Laboratory specializing in power system operations, market design, and the integration of renewable and emerging technologies into power systems. He previously worked with the New York ISO developing and improving products for operations and market design.

Aidan Tuohy is Senior Project Engineer with the Electric Power Research Institute specializing in research on planning and operations with large amounts of variable generation connected to the bulk electricity system. He has a Ph.D. in the area of operational and policy issues for systems with significant wind penetration from University College Dublin.

Michael Milligan is a Principal Researcher with the National Renewable Energy Laboratory. He is co-lead for the North American Electricity Reliability Corporation Integrating Variable Generation Task Force on probabilistic methods. He has published more than 140 papers, reports, and book chapters.

Brendan Kirby is a private consultant to the National Renewable Energy Laboratory and other clients. He has 36 years of electric utility experience and has published over 150 papers, articles, and reports on ancillary services, wind integration, restructuring, the use of responsive load as a bulk system reliability resource, and power system reliability.

Daniel Brooks manages the EPRI Power Delivery and Utilization sector's Grid Operations & Planning research groups. His work has included wind integration studies, T&D losses assessments, bulk system load modeling, DG interconnection studies, and PHEV integration studies. Before joining EPRI, he worked for Electrotek Concepts managing and conducting similar studies.

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