This report was prepared for the Australian Energy Market Commission.
The Australian Energy Market Commission (AEMC) has asked us to review how demand response (DR) participates in wholesale electricity markets in a range of jurisdictions, in order to inform its own market design developments regarding demand response participation in Australia's National Electricity Market (NEM).
We have studied wholesale DR participation in six wholesale markets that differ in terms of their geographies and regulatory arrangements, offering a broad cross-section of approaches to DR. Half of these markets have an "energy-only" generation investment model (Singapore, Alberta and ERCOT), while the other half have capacity obligations (PJM, ISO-NE and Ontario) complementing their energy markets. Markets with capacity obligations may not be directly comparable to the NEM, but they have attracted the largest amounts of DR resources, which also participate in wholesale energy and ancillary services markets and may thus provide insights applicable to NEM.
Below we describe our observations about DR participation in wholesale energy markets, followed by ancillary services markets, then capacity markets. Note that in the sections that follow, we describe DR performing three functions: energy, ancillary services, and capacity. In contrast, our report is organized so as to distinguish between two different types of jurisdictions, which we refer to as "Energy-Only Markets" and "Markets with Capacity Obligations". DR could potentially provide all three functions in any jurisdiction.
Demand Response and the Energy Function
Perhaps the simplest means of enabling DR in energy markets is to establish liquid wholesale markets with transparent wholesale energy prices, which NEM and the other markets (energy-only markets and markets with capacity obligations) we evaluated already do. This enables the largest customers, who may be direct wholesale market participants, to reduce their consumption and save money when they observe prices rising above the maximum value that they obtain from consuming electricity. Other customers may do the same to the extent they are exposed to wholesale spot prices through retail arrangements. We call this "price-responsive load". Though most customers choose to purchase electricity at a fixed price, we see some price-responsive load, especially in energy-only markets with volatile energy prices. Load reductions attributable to price-responsive load in the energy-only markets we surveyed ranged from about 1% of peak load in Texas to more than 2% in Alberta, although the exact amounts are difficult to determine.
Price-responsive load enhances economic efficiency and supports supply adequacy. It does not, however, do so with perfect precision if wholesale prices are volatile and customers' load reductions do not coincide with times of greatest need. To increase precision, loads would have to submit price-responsive bids and allow the system operator to dispatch1 them in real-time (similar to how generators are dispatched). However, we have observed minimal participation in dispatchable load programs in Alberta and Texas. The lack of customer interest may be explained by the costs to purchase real-time telemetering equipment and the loss of a customer's operational flexibility when the system operator controls its consumption (and charges penalties for deviating) compared to the incremental value available.
We do see substantial amounts of load participating directly in energy markets where DR aggregators (DRAs) are allowed to sell end-users' load reductions as supply, as in PJM and ISO-NE. This supply-side DR model developed first in markets with capacity obligations, where system operators viewed dispatchable loads as a resource they could deploy in emergencies; and where specialized DR providers gained expertise finding and setting up customers with flexible loads, and aggregating them into resources that could compete with generation in capacity markets. We discuss DR performing the "capacity function" in the next section.
As with participation in capacity markets, DR providers' participation in energy markets is also on the supply side: they submit offers to curtail load into day-ahead or real-time markets and earn a market price if they are dispatched. However, the determination of the settlement quantity and price are not as straightforward as for a generator. The quantity is given by the difference between actual consumption during the period in which they are dispatched, and a higher hypothetical baseline level that would have been consumed if the resource had not been dispatched. In US markets, system operators establish baselines according to various methodologies that attempt to estimate the hypothetical consumption, for example based on that customers' historical consumption; Singapore plans to solicit DR providers to nominate their customers' baselines and penalize them if the customer consumes less than the baseline when not dispatched.
As for the settlement price, the locational marginal price would be appropriate if the customer had already bought the power and was now re-selling it. But that is generally not the case: customers only pay for metered load. Therefore the savings in the generation component of the retail price the customer would have paid on the energy not consumed should be deducted from the payment, in order to avoid double counting. Estimating that relevant retail price can be a challenge especially for disparate customers of a DR aggregator, although PJM (and the Midcontinent ISO) have developed ways to do that.
Policymakers may consider enabling supply-side mechanisms to engage the specialized expertise of third party DRAs if they would otherwise face barriers to participating in the market indirectly through agreements with retailers (and sharing some of the value in lowering the retailer's cost to serving the customers' loads). We have not evaluated the extent to which there may be barriers to retailer-DRA cooperation or other barriers to DRA participation in the NEM.2
One final consideration in incorporating demand response into energy markets is how to achieve efficient price formation that supports efficient operations and investments. Ideally, when generation supplies become tight, demand reductions would clear the market and set energy prices at customers' willingness-to-pay. It is important that rules for determining the system price take proper account of DR, particularly under scarcity conditions. In ERCOT, for example, reforms were introduced to prevent dispatch of emergency DR from depressing the system price.
Demand Response and the Ancillary Services Function
In order to accommodate the sudden loss of a large generator or transmission line, electricity systems need to hold operating reserves. Operating reserves have traditionally been provided by generators that produce less than their maximum output so they can increase their output when deployed in a contingency. However, loads can also provide operating reserves by offering to curtail at short notice. This ability to curtail is clearly valuable for the efficient operation of a power system. PJM, Ontario, Singapore, Alberta and ERCOT allow loads to compete with generation to provide contingency reserves. Loads provide a substantial portion of reserves in several of these markets, including approximately half of the responsive reserve requirement in ERCOT.
Allowing loads to provide ancillary services (AS) is beneficial because it can reduce overall costs. Also, in some circumstances, loads may be able to provide services that most generators cannot. For example, while loads can be curtailed via a signal from the system operator, they can also be curtailed automatically using under-frequency relays. Loads curtailed in this manner respond extremely quickly to contingencies, faster even than a generator on governor response. This fast response has enabled some specialized AS products, such in Alberta and ERCOT.
Some markets also allow loads to provide other AS services, such as regulation (direct system operator remote control to balance supply and demand within a dispatch interval). However, while some markets seem to be moving in the direction of allowing loads to provide regulation, we have not seen substantial participation where this is allowed.
In our review we did not come across significant controversies with respect to DR provision of AS. In particular, we did not encounter controversies about DR baselines in AS markets as we did in energy markets. We note that while DR providers may be technically capable of providing both AS and energy, in any given hour they will only be able to provide one or the other.
Demand Response and the Capacity Function in Markets with a Capacity Obligation or Emergency Standby Programs
In jurisdictions with capacity obligations, DR revenues from capacity payments tend to be much larger than payments for energy or AS. Recent policy developments have focused on participation rules for DR providers that are not available year-round, and how to ensure that DR providers respond to dispatch instructions when called. These issues are more important in capacity markets than in energy markets because capacity markets typically provide payments for being available to respond. In an energy-only market, payment is for actual dispatch rather than availability. It may be easier to measure response to a dispatch signal than it is to determine whether a resource is available to be dispatched if called (though note the concerns over baseline methodologies described above).
Although ERCOT is an energy-only market, its Emergency Reserve Service (ERS) program has some similarities with capacity market DR programs. ERS's predecessor was created following an episode in which firm load was shed. Load shedding may be necessary during a supply shortfall, but it does not distinguish between loads with different willingness to be curtailed. ERCOT created the ERS program to increase the efficiency of future load shedding by first curtailing customers with a relatively low value of lost load. ERS shares several characteristics with capacity market DR programs: it procures DR to respond to system emergencies and pays DR providers an availability payment.
In some wholesale markets the market design includes elements which aim to incorporate demand response (DR) programs that existed in some form prior to restructuring and the implementation of an organized wholesale market. In other cases, mechanisms for DR to participate in the wholesale market have evolved over time with the aim of making markets more efficient. For example, in markets with a formal capacity mechanism it may be significantly cheaper to procure a given quantity of capacity from a mix of DR and generator providers than it would be to procure the same quantity from generation only.
DR in wholesale electricity markets can refer to four different ways in which market participants on the demand side can interact with the wholesale market. The first and second ways for DR to participate are part of the energy market design; the third relates to ancillary service (AS) markets; and the fourth relates to capacity markets.
The first avenue for demand side participation is price-responsive load: customers who react to prices by adjusting their demand, but without bidding into the wholesale market. As in any other market, electricity consumers tend to reduce their consumption if prices rise, all else equal. These consumers may be said to have provided DR in the sense that they purchase less electricity when prices are high than they would have done if prices had been lower.
Second, in some markets there are explicit mechanisms for individual consumers, or demand response aggregators (DRAs) acting on behalf of many consumers, to bid or offer3 directly into the wholesale market and thus be dispatched by the system operator in the same way that generation is. This second route for DR to participate may be either: (a) a bid curve (price and quantity pairs) reflecting the customer's willingness to pay for energy, or (b) supply-side participation reflecting the minimum payment needed for the customer to curtail and supply back its energy, effectively participating in the market in a similar way to a generator.4
Third, system operators typically procure a number of different AS products from market participants. These AS products are required to ensure that the system is robust to outages and other unexpected changes in supply or demand. Depending on the nature of the AS product and the technical design, market participants on the demand side may be eligible to supply.
And fourth, some market designs include a mechanism for procuring capacity that is separate from the energy market. Generators and DR providers are paid to be available to generate or curtail load and avoid emergency events over and above revenues that they earn in the energy market.
A. DEMAND RESPONSE IN THE ENERGY MARKET
Electricity customers, especially smaller customers, often pay retail prices that do not follow short-term movements in the wholesale price as it changes with supply, demand, and other fundamentals. Larger electricity consumers may pay prices that are linked to the wholesale price. The latter may therefore be able to respond to short-term price signals and adjust their consumption accordingly. This route for DR to participate in the energy market is sometimes referred to as price-responsive load because it does not depend on any specific wholesale mechanism or market design beyond the normal price mechanism. This impact of prices on the level of demand is not directly apparent to the system operator in the same way that it would be if consumers or retailers were bidding a "demand curve" into the wholesale market in the same way that generators offer a "supply curve." In these markets, the system operator dispatches generators to meet a forecast of demand but few (or sometimes no) loads are formally dispatched. The system operator's demand forecast may include an estimate of the extent to which load may respond to price.
In some jurisdictions, the market design allows customers to participate directly in the wholesale energy market by submitting a schedule of quantity and price bids for demand-side dispatch, similar to how generators submit quantity and price offers for supply-side dispatch. However, we observe very limited participation.
Some jurisdictions also provide specific mechanisms for DR to "sell back" energy as supply. Market participants on the demand side may be paid to reduce their consumption, with such payments being independent from and additional to any benefits derived by purchasing a reduced quantity of electricity. DR is paid to reduce consumption, and such payments are separate from the regular settlement process through which the consumer pays for energy consumed (either directly or through a retailer).
B. DEMAND RESPONSE IN CAPACITY AND ANCILLARY SERVICES MARKETS
Some wholesale electricity market designs incorporate a mechanism to pay capacity resources to be available to provide energy. Other market designs, including Australia's National Electricity Market (NEM) are "energy only" and do not have explicit capacity mechanisms. Where there is a capacity mechanism, often both generators and demand-side resources are able to participate. In several of the markets we studied, this route for DR to participate in the wholesale market is very significant in terms of the total revenues available to DR. Although the NEM does not have a capacity mechanism, we have included capacity mechanisms in our study because this is often the dominant route for DR integration (often leading to energy market participation as a side-product) and because some design questions addressed in respect of capacity mechanisms may also be relevant for designing a mechanism for DR to participate in energy-only markets.
All wholesale electricity market designs incorporate mechanisms for the system operator to procure various kinds of AS. The system operator requires AS to manage generator outages, other unexpected changes in supply or demand, and to keep the system in balance in real time. In some markets the technical specification of (some) AS products permits DR to provide AS.
C. OUR STUDY
In Australia's NEM there are no explicit mechanisms to require market participants on the demand side to participate in the wholesale energy market, although some can participate voluntarily. Large price-sensitive loads (greater than 30 MW) can opt to become "scheduled loads". Scheduled loads are required to submit price-quantity bids and to comply with dispatch orders. Since there are costs of complying with technical, bidding and dispatch requirements, most loads remain unscheduled. A notable exception is Snowy Hydro which has some pumps that are scheduled. Snowy Hydro recently put forward a Rule Change Request to make it compulsory for price sensitive large loads to bid into the electricity market.5 We also understand that there is currently no route for DR to provide AS in Australia.
We understand that a Rule change proposal has been put forward that would permit loads, as well as demand response aggregators (DRAs), to participate in the NEM on the supply side. The Australian Energy Market Commission (AEMC) asked us to review how wholesale markets in a range of jurisdictions have been designed to facilitate DR participation.
We have studied the ways in which DR participates in electricity markets in six different jurisdictions. The aim of our study is to document how these jurisdictions have integrated DR into wholesale markets, including energy markets, markets for ancillary services, and markets for capacity. In some jurisdictions the market design has permitted demand-side participation for many years. We seek to identify any recent trends or lessons learned that may be relevant to ongoing work to improve the design of the NEM. Where there are ongoing debates over the optimal design of mechanisms to integrate DR, we have described the options under consideration. In section II we introduce the six markets we have studied, and provide an overview of the market design and the type and extent of DR participation. Section III describes the DR programs in the three energy-only markets and Section IV similarly elaborates on DR programs in the three markets with capacity mechanisms. Finally, in section V we draw out key observations across the six markets.
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1 We use the term "dispatch" to mean the process by which the system operator directs a resource to operate in a certain way (eg, directs a generator to produce a certain quantity in a particular time interval). In some jurisdictions the term "schedule" is used.
2 Another consideration for enabling DR aggregators to participate as suppliers in the energy market is that they could be dispatched and settled nodally, whereas price-responsive load faces only zonal prices. Nodal dispatch could provide end-users with more localized price signals and give the system operator more control.
3 Conventionally, bids would refer to a bid to purchase electricity (i.e., load) and offers would refer to an offer to sell electricity (i.e., generators). As we explain below, in some markets DR "offers" a reduction in demand into the wholesale market and is therefore similar to generation.
4 DR participating on the supply side is sometimes termed "negawatts".
5 Whitby, Roger, Executive Officer, Trading (Snowy Hydro Ltd.) to John Pierce, Chairman (Australian Energy Market Commission), re Proposed rule change: Demand Side Obligations to Bid into Central Dispatch, June 10, 2015.
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