Effective Market Design for Managing Variability and Uncertainty

Power systems must always maintain balance between supply and demand for electricity within small prescribed tolerances, to maintain system frequency within the narrow bands required for safe and stable operation. This must be managed over time frames ranging from less than a second to years. As more variable renewable generation is added to the system, the degree of flexibility required from the “balance of system” (the other generators and loads) will often increase.

Flexibility in this context is used to refer to aspects such as:

• Fast ramping rates (both up and down). Many thermal units are not designed to ramp rapidly, which can limit their ability to respond to variability in the system.
• Short shutdown and startup times. For many large thermal units a full startup or shutdown of the plant is a significant process, requiring substantial notice (such as 24 hours). This limits their ability to respond flexibly to changes in the system.
• Low minimum loads. Minimum loads (also called turn‐down levels) are the lowest level the plant can be turned down to, without executing a complete shutdown. For many large thermal generators (such as coal and combined cycle gas turbines) this is approximately 50–70% of the capacity of the unit; below this level the boiler cannot be operated in a stable state. This constrains the operation of these plants, and can be particularly problematic in small systems with low overnight minimum loads.

Most power systems have sufficient technical flexibility to integrate high proportions of variable renewables; analysis by the International Energy Agency suggests that existing power systems may be able to integrate 20–63% variable renewables based on a purely hardware point of view^{[2, 11]}. With innovation, the flexibility of existing systems may exceed initial expectations. For example, a recent case study demonstrated that coal plants can become flexible resources; a coal‐fired power station originally designed to operate as a base‐load plant in North America now operates successfully in a highly flexible manner, often undertaking complete shutdown and startup cycles multiple times per day. This was achieved with limited hardware modifications, but extensive modifications to operational practice^[11].

Despite the high degree of technical flexibility available in many power systems, poor market design may limit access to that flexibility in a range of ways^{[3, 5, 6]}. Market design to encourage efficient levels of flexibility needs to be explored in two dimensions^[5]:

1. Operational time frames. Generators (and loads) in the system must be encouraged to offer their flexibility to the market over operational time frames, to economically efficient levels. This includes the design of the wholesale market, and the design of FCAS, as described in more detail below.
2. Investment time frames. The developers of new generators entering the system should be exposed to appropriate market signals to ensure that new capacity is appropriately flexible.

The latter may, but does not always, follow from the former, depending on the interaction of energy spot markets with mechanisms designed to manage investment (such as capacity mechanisms).

Wholesale Market Design to Facilitate Variable Renewable Integration

Balancing of supply and demand is managed over operational time frames firstly through general market design, usually with a real‐time wholesale energy market, in which generators make offers to sell electricity, and retailers (also known as suppliers or load serving entities) make offers to buy electricity. The market settles at the point where demand and supply are balanced, with the price of the marginal generator (the last generator dispatched) typically setting the price for all market participants in that trading interval. The design and operation of this wholesale market can have significant implications for the degree of flexibility that generators and loads willingly offer to the system.

The speed of the market is one of the most important characteristics. Very fast markets that feature short (five‐minute) dispatch intervals can integrate much higher quantities of variable renewables at lower cost^{[5, 6]}. Shorter dispatch intervals allow more frequent re‐dispatch of the whole system, providing near constant access to the full degree of flexibility available from all plants and loads. By contrast, long dispatch intervals artificially “lock in” generators and loads to preset levels for extended periods of time, preventing adjustments that may be possible at very low cost^[5]. These markets must maintain larger quantities of reserves (plant set aside for managing variability and uncertainty within dispatch intervals), thus increasing system costs^{[5, 12]}.

A short delay from gate closure (the time when the last offers and bids are made) to dispatch is also important. A short delay allows incorporation of the most up‐to‐date wind and solar PV forecasts, and therefore more accurate scheduling^{[10, 13, 14]}. This means that smaller quantities of reserves can be maintained, reducing costs^{[15, 16]}. Needless to say, the quality of wind and solar forecasts is also important, in addition to integration of forecasts with the full market dispatch process.

Managing dispatch over larger areas is also of significant benefit. In many markets, significant physical transmission interconnection exists, but supply and demand are balanced over an artificially much smaller area. Aggregating markets (or balancing areas) allows greater per unit smoothing of generation and load variability, access to a larger number of generators and loads for providing flexibility^[17], and sharing of reserves, which reduces costs^{[5, 10]}. In many cases the barriers to aggregation (and thus cost reduction) are political and regulatory in nature, rather than technical^[18].

Many markets have only limited DSP. Because loads are usually not exposed to real‐time market prices, they usually have no incentive to respond to real‐time signals limiting the degree of flexibility they make available to the system. The potential may be very large, and possible in many cases at low cost. For example, the value of DSP potential in the European Union has been estimated at 53 billion euros^[19]. Access to new technology such as advanced metering infrastructure may assist in alleviating some of the many and varied barriers to DSP. However, a shift to full DSP represents a fundamental change in the way electricity markets operate, and a complete paradigm shift in the way that customers interact with their electricity supply. Many of the barriers are likely to be social and regulatory, rather than technical or economic, and thus a concerted effort is likely to be required to unlock this potential.

Ideally, markets are designed to be “technology neutral,” such that renewable technologies fully participate in the wholesale market, and are managed on a level playing field with other technologies. Some markets have applied “priority dispatch” for renewable technologies, such that they are dispatched ahead of other technologies regardless of system conditions at the time. At low levels of penetration, this can effectively assist the entry of renewables. However, at higher penetration levels, the shielding from market price signals becomes problematic, because it inhibits an economically efficient market response. Many renewable generators (such as wind and PV) are extremely flexible, being able to ramp very rapidly from full capacity to complete shutdown with very little notice, but they are unlikely to do so unless they are appropriately incentivized by exposure to the same wholesale price signals as other generators. Because many renewable technologies have very low SRMCs, full participation in the wholesale market without priority dispatch is likely to still result in their full dispatch in most normal circumstances.

“Make Whole” payments, applied in some markets, add complexity to the issue. These payments ensure that generation resources recoup costs by providing out of market payments if necessary. Because the resource is providing a service on behalf of the system and should be compensated to cover costs, these payments are “out of market” and thus may not ensure economic optimality. In addition, they shield market participants (in this case, typically large incumbent thermal units) from important pricing signals, potentially not providing sufficient incentives to provide long‐term flexibility. Some markets have introduced new categories that allow variable renewables to participate more fully in the wholesale market, while recognizing their unique characteristics. For example, the Midcontinent Independent System Operator (MISO) introduced the “Dispatchable Intermittent Resources” category^[20], and the Australian National Electricity Market (NEM) introduced the “Semi‐Scheduled” category^[21]. The New York ISO has also extended its market‐based Security Constrained Economic Dispatch process to optimize the scheduling of wind plants, based on their offers, as it does with other generating resources^[22].

Some system designers have decided that the price signals provided by the market are insufficient to elicit an adequate flexibility response, and have added further incentives. For example, the MISO and California Independent System Operator (CAISO) have both introduced supplementary mechanisms to reward generators for providing ramping services over time frames longer than a single dispatch interval.

Frequency Control Ancillary Services to Facilitate Variable Renewable Integration

FCAS are provided by generating capacity (or demand) that is reserved for responding to variations in the system balance on time periods shorter than a dispatch interval, or that were not forecast at the time of scheduling. In markets with long dispatch intervals and long delays from gate closure to dispatch, much larger quantities of reserves must be maintained. Thus, the design of the wholesale market can significantly affect the cost of providing FCAS.

Some systems have real‐time markets for a range of FCAS that operate alongside the wholesale energy market. Through these FCAS markets, suitably capable generators and loads can submit offers to provide various ancillary services in each dispatch interval, along with their energy offers and bids. This allows generators and loads to flexibly provide the maximum amount of FCAS they have available in any interval, without having to make long‐term commitments.

Dividing FCAS into distinct categories allows a wider range of generators and loads to provide only the particular services that they find cost‐effective. Common categories of FCAS are illustrated in Figure 28.3, and include:

• Type of event. It is common to make a distinction between services that are provided continuously to match supply‐demand discrepancies within a dispatch interval (often termed regulation), and services that involve standing ready to respond if a generator or load suddenly experiences a forced outage (often termed contingency).
• Response time. Services can be further divided by the response time in which they are required to be available. Very fast services (responding within seconds) are often called primary reserves, while slower services (responding in minutes or hours) are termed secondary or tertiary reserves, respectively. Some generators can respond over short time frames but cannot sustain the response for a long period. Other generators can only respond more slowly, but can sustain the response for as long as required. Dividing FCAS into different categories allows these generators to seamlessly integrate, cost‐effectively, providing the required system response in aggregate.
• Raise/lower. Every service can be further divided into “raise” and “lower” components, where these involve adding or subtracting energy from the system.

Good market design principles suggest an approach that is tailored to the specific system, selecting categories of FCAS that allow the maximum number of generators and loads to provide the components that they find economically and technically efficient, without introducing excessive and unnecessary complexity. This will change as the mix of generators and loads evolves over time, making regular review of the FCAS market design worthwhile.

Wind and PV generators would face a significant opportunity cost from providing a contingency raise service, because this would necessitate their curtailment over extended periods of time, and therefore mean lost revenue in the energy market. However, they may find it cost‐effective to provide contingency lower services (being ready to rapidly reduce generation in the rare event of a load suddenly experiencing a forced outage). These generators are technically capable of providing this service^[23] with minimal opportunity cost, meaning that in future markets this service might be provided essentially for free in any period where wind and PV are operating at sufficient levels. Thus, if wind and PV are to participate cost‐effectively in the FCAS market, these services must be divided into different categories^{[24, 25]}.

Similarly, many types of loads may find it cost‐effective to provide contingency raise services. Contingency events are relatively rare (called upon perhaps several times per year) and typically short (less than an hour), such that providing a contingency raise service would simply require demand response units to be available to rapidly reduce consumption in the rare event of a generator suddenly experiencing a forced outage. However, demand response may not be equally able to provide a contingency lower service, because this would require being able to rapidly increase consumption at short notice. Electric vehicle (EV) charging, for example, may be well suited to providing contingency raise services. Owing to the rarity of reserves being called on, the impact on EV battery cycling could be negligible, and customers minimally affected.

Of course, to achieve these benefits it is a prerequisite that renewable generators and loads are freely allowed to participate in providing all types of FCAS, as long as they can demonstrate that they are technically capable of doing so (they are in many cases ^[23]). This is not yet the case in many markets.

Another important aspect of FCAS market design is the manner in which the quantity required of each type of reserve is determined. Many systems apply a “static” approach, based on examination of typical system variability at different times of day, or by season, peak versus off‐peak, and so on^[26]. However, the operation of variable renewable generation at any particular point in time has a significant influence on the degree of system variability, allowing a more dynamic approach that takes into account the system state in a particular dispatch interval^[27–30]. Some systems set the reserve requirement in a completely dynamic fashion based upon system properties such as the time error (closely related to the system frequency)^{[31, 32]}. This allows the reserve requirement to evolve dynamically in real time as the system changes, such that the scheduled reserve in each interval is the minimum required (reducing costs).

The interaction of markets for ancillary services and energy requires careful attention, particularly as the number and sophistication of ancillary services markets increases over time. In some cases, poor consideration of these interactions has led to detrimental perverse incentives. For example, in some eastern US systems, the energy market rules financially penalize generators that deviate from their energy schedules, aiming to provide incentives for generators to operate at their instructed levels. However, many generators are designed to automatically assist in maintaining system frequency during contingency events. If a generator's governor is tuned appropriately, a drop in system frequency will cause it to increase output, assisting in arresting system frequency decline. Despite this being behavior that is helpful to the system, the energy market rules in this example would penalize this generator for deviating from its energy schedule. This has likely contributed to many generators in these markets detuning their governor responses, and exacerbating frequency response issues^[33]. These perverse incentives can be removed by only penalizing deviations from the energy schedule when those deviations are exacerbating frequency problems, such as is implemented in the sophisticated “causer pays” methodology in the Australian NEM^[31].

Investment Signals for Flexibility

In theory, short‐term price signals for generators to provide flexibility to a system also translate into long‐term investment signals. With sufficient foresight, developers of new generation can anticipate when the system is likely to experience a shortfall in flexibility, and therefore where there are opportunities to install new generation that can profitably provide that service. However, this may not eventuate in practice. First, during a period of rapid market transformation developers may struggle to anticipate future market needs, and may underestimate the value of increased flexibility. Second, many markets include explicit capacity remuneration mechanisms (CRMs) that supplement generator revenue. Where capacity payments constitute a large proportion of generator revenue, the design of these CRMs can have significant implications for generator incentives around new technology decisions. It is also possible that some FCAS markets are thin – i.e. even in the face of high price spikes, little additional FCAS are needed to ensure a sufficient supply and mitigate price spikes. If this is the case, a new entry (or entrants) into the market could result in a price collapse that could result in revenue insufficiency for the entrant.

In a properly operating energy‐only market, generators are exposed to extremely high prices at times of scarcity, and very low (negative) prices during times of oversupply. In some circumstances, these prices can occur suddenly, creating incentives for generators to rapidly adjust their output. Thus, in this market there is an incentive to install more flexible plant that can respond to these price signals and reap the benefits^[5]. By contrast, in markets where a CRM is applied, the market price cap is typically much lower. This reduces the benefit of flexible operation.

Some markets provide added incentives for flexibility by distinguishing between different kinds of capacity in the capacity payment process. For example, in Spain only generators of certain types are eligible for capacity payments^[34]. In the German market a “focused” capacity market has been proposed, involving multiple tiers of capacity credits that result in differentiated capacity payments depending upon the flexibility of the plant^[35].

Effective Market Design for Investment Signals with Low SRMC Generation

The ideal mechanisms for managing resource adequacy have been debated for decades, without resolution. Creating accurate long‐term investment incentives via an electricity market is challenging, even in the absence of variable renewable generation. Some proponents favor the economically “pure” theory of energy‐only markets, where market participants receive revenue only through the wholesale energy and ancillary services markets^{[41, 42]}. Others remain convinced that energy‐only markets are fundamentally flawed for a variety of subtle reasons, and support the introduction of explicit CRMs^{[43, 44]}. These introduce a more certain revenue stream for investors in firm capacity by providing a payment for capacity availability (MW) in addition to energy supplied to the market (MWh). This can create stronger incentives to invest in new capacity, and may allow investors to acquire capital at a lower cost by reducing risk and uncertainty. They can also support higher generation adequacy and security of supply for the whole system, and allow lower price caps to be introduced in the wholesale market, reducing price volatility and therefore reducing risks for customers and other market participants^[24].

However, given that CRMs represent a regulatory intervention, they also have some drawbacks^[24]. The choice on the amount of reserve margin maintained in the system must be made via a regulatory decision, which can incline the system toward a conservative oversupply of capacity. Some have argued that this may be of benefit, because it may be better to err on the side of oversupply and limit the risk of extended periods of high prices for customers^[45]. Design and implementation of CRMs can also be very complex^[24], and many have required substantial adjustments over time as the market evolves. Care must also be taken regarding coordination with neighboring markets; implementing different market models without care for cross‐border effects can cause distortions and hinder functioning^[24].

There are a wide range of different types of CRMs, and some of the most innovative, such as reliability options, may be remarkably close to properly functioning energy‐only markets in practice. Ultimately, it is likely that most types of market designs can work well if they are implemented well; perceived failures are often related to flawed implementation or excessive government intervention^[46].

Renewables do not undermine the theoretical operation of energy‐only markets and do not fundamentally change the debate, but they are bringing many of the long‐discussed issues to prominence^[7]. With lower wholesale prices occurring more often, an increasing proportion of generator revenues in energy‐only markets will need to be concentrated in rare scarcity periods, exacerbating uncertainty and risks for market participants^[7]. In theory, market participants can manage these risks with increased levels of forward contracting, but there may be reasons why sufficient contracting does not occur.

In many ways, the most challenging aspect of resource adequacy is likely to be related to the rate of change that markets need to manage. All models are likely to struggle during periods of high uncertainty, and with rapidly changing political and regulatory drivers. These characteristics fundamentally make investment decisions very challenging, especially when planning long‐lived and lumpy infrastructure ^[24].

Proponents of energy‐only markets suggest that they could operate successfully, if all the barriers preventing proper market operation were removed, including low price caps, regulated retail prices, and a lack of DSP^[24]. However, the proportion of renewable technologies is rapidly increasing in many markets, and addressing all these issues may take too long, given political orientations and the lengthy processes likely to be involved in increasing DSP. A CRM may assist in maintaining investment incentives in the interim, implemented as a temporary measure with eventual return to an energy‐only market model being the ultimate goal^[24]. However, once introduced, CRM policies may be hard to reverse^[47].

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FURTHER READING

1. Riesz, J., Gilmore, J., and Hindsberger, M. (2013). Market design for the integration of variable generation. In: Evolution of Global Electricity Markets: New Paradigms, New Challenges, New Approaches (ed. F.P. Sioshansi), 757–789. San Francisco: Elsevier.